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Home My WebLink About20131005.tiffSTATE OF COLORADO John W. Hickenlooper, Governor Christopher E. Urbina, MD, MPH Executive Director and Chief Medical Officer Dedicated to protecting and improving the health and environment of the people of Colorado 4300 Cherry Creek Dr. S. Denver, Colorado 80246-1530 Phone (303) 692-2000 Located in Glendale, Colorado http://www.cdphe.state.co.us Weld County Clerk & Recorder 1402 N 17th Ave Greeley, CO 80631 April 19, 2013 Dear Sir or Madam: Laboratory Services Division 8100 Lowry Blvd. Denver, Colorado 80230-6928 (303) 692-3090 Colorado Department of Public Health and Environment On April 21, 2013, the Air Pollution Control Division will publish a public notice for Kerr-McGee Gathering LLC — Lancaster Plant, in the Denver Post. 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-B1 4300 Cherry Creek Drive South Denver, Colorado 80246-1530 Attention: Clara Gonzales Regards, Clara Gonzales Public Notice Coordinator Stationary Sources Program Air Pollution Control Division Enclosure 7heic i2 w 51/1/3 PL, Kb -dam 2013-1005 NOTICE OF A PROPOSED MAJOR NSR CONSTRUCTION PERMIT WARRANTING PUBLIC COMMENT Website Title: Kerr-McGee Gathering LLC — Lancaster Plant — Weld County The Colorado Air Pollution Control Division has declared that the following proposed construction activity warrants public comment. Therefore, the Air Pollution Control Division of the Colorado Department of Public Health and Environment, hereby gives NOTICE, pursuant to Sections 25-7-114.5(5) and 25-7-114.5(6), C.R.S. of the Colorado Air Pollution Prevention and Control Act, that an application to the Division has been received for an emission permit on the following proposed project and activity: Applicant: Kerr-McGee Gathering LLC P.O. Box 173779 Denver, CO 80217-3779 Facility: Lancaster Plant 16270 WCR 22 Fort Lupton, CO Kerr-McGee Gathering LLC has applied for a Major New Source Review Construction Permit for the Lancaster Plant in Weld County, CO. The plant consists of a cryogenic facility with one (1) reciprocating internal compression engine, two (2) mole sieve generation gas heaters, four (4) amine sweetening units each with a heater, a thermal oxidizer for each amine unit, two (2) facility process flares and associated fugitive emissions. This project is a PSD major modification only for greenhouse gases. No innovative control technology system was proposed for this project. An impact analysis for pollutants/averaging periods with PSD increments was not conducted since this project is not a major modification for any pollutants with established PSD increments. The Colorado Air Pollution Control Division (the Division) has determined that the proposed activities will show compliance with all applicable Colorado Air Quality Control Commission (AQCC) regulations and ambient air quality standards, and proposes to approve and issue the permit described in this notice. A copy of the application, including supplemental information, the Division's analysis, and a draft of Permit 12WE1492 have been filed with the Weld County Clerk's office. A copy of the draft permit and the Division's analysis are available on the Division's website at www.colorado.gov/cdphe/AirPublicNotices. Based on the information submitted by the applicant, the Division has prepared the draft permit for approval. Any interested person may contact Stephanie Chaousy of the Division at 303-692-2297 to obtain additional information. Any interested person may submit written comments to the Division concerning 1) any innovative technological system for pollution control if proposed by the applicant (note that a hearing by the Commission will be held on such system if requested by any interested person), 2) the air quality impacts of the source or modification, and 3) alternatives to the source or modification. Comments are solicited on the ability of the proposed project/activity to comply with applicable standards, regulations and requirements; the sufficiency of the preliminary analysis; any innovative technological systems for pollution control; the control technology required for the source or modification; air quality impacts of the source or modification; alternatives to the source or modification; any other appropriate air quality considerations; and whether the permit application should be approved or denied. Any interested person may submit a written request to the Division for a public comment hearing before the Colorado Air Quality Control Commission (Commission) to receive comments regarding the concerns listed above as well as the sufficiency of the preliminary analysis and whether the Division should approve or deny the permit application. The hearing would be held pursuant to section 1.7.0 of the AQCC's procedural rules to receive comments regarding any innovative technological system for pollution control, the sufficiency of the preliminary analysis and whether the Division should approve or deny the permit application. If requested, the hearing will be held before the Commission 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, but at least sixty days after receipt by any Federal Land Manager of notice and the permit application required pursuant to Regulation 3, Part D, Section XIII.A. No comments were received from the Federal Land Managers regarding visibility, AQRV and increment consumption during their review period specified in Colorado Regulation No. 3, Part D, Section XIII.A. 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: Denver Post on PUBLISHED: April 21, 2013 April 19, 2013 Form APCD-100 Colorado Department of Public Health and Environment Air Pollution Control Division Oil & Gas Industry Construction Permit Application Completeness Checklist Ver. September 22, 2008 Company Name: Ken -McGee Gathering LLC Colorado Department of Public I -earth and Environment Source Name: Lancaster Plant Date: 4/17/2012 Are you requesting a facility wide permit for multiple emissions points? Yes No In order to have a complete application, the following attachments must be provided, unless stated otherwise. If application is incomplete, it will be returned to sender and filing fees will not be refunded. Attachment Application Element Applicant APCD A APEN Filing Fees /1 ❑ Air Pollutant Emission Notice(s) (APENs) & B �1 ❑ Application(s) for Construction Permit(s) — APCD Form Series 200 C Emissions Calculations and Supporting Documentation �1 ❑ D Company Contact Information - Form APCD-101 11 ❑ E Ambient Air Impact Analysis /1 ❑ ❑ Check here if source emits only VOC (Attachment E not required) F Facility Emissions Inventory — Form APCD-102 /1 ❑ ❑ Check here if single emissions point source (Attachment F not required) Process description, flow diagram and plot plan of emissions unit and/or G /� ❑ facility ❑ Check here if single emissions point source (Attachment G not required) H Operating & Maintenance (O&M) Plan — APCD Form Series 300 /1 ❑ Check here if is for true minor emissions source or application a general ❑ permit (Attachment H not required) I Regulatory Analysis /1 ❑ Check here to APCD to ❑ request complete regulatory analysis (Attachment I not required) Send Complete, Application to: Colorado Department of Public Health & Environment APCD-SS-B1 4300 Cherry Creek Drive South Denver, Colorado 80246-1530 Check box if facility is an existing Title V source: /1 Send an additional application copy Check box if refined modeling analysis included: ■ Send an additional application copy Page 1 of 1 APCD-100-App CompleteChecklist_doc Attachment A WGR Operating LP PO Box 1330 Houston, TX 77251-1330 IIIIIIIIIIIIIIII I1III IIIIIIIIIIIIIIIIIIIIIIIIIII_IIIIIIIIII 00140 CKS 6A 12101 - 0742103390 NNNNNNNNNNNN 1015100004502 X392D1 C COLORADO DEPT OF PUBLIC HEALTH & ENVIRONMENT 4300 CHERRY CREEK DR S, APCD SS B1 DENVER CO 80246-1530 VENDOR NO: 0003405436 PAGE: 1 of 1 DATE: April 10, 2012 TRACE NUMBER: 742103390 CHECK NUMBER: 742103390 AMOUNT PAID: $1,070.30 ACCOUNTS PAYABLE INQUIRIES: (800) 370-9867 • DOCUMENT # VENDOR INV #1 INVOICE DATE REMARKS TOTAL AMOUNT PRIOR PMTS & DISCOUNTS NET AMOUNT 1900000150 CKRQ040512 04/05/12 FT. LUPTON CRYOGENICE PLANT PERMITAPPLICATION $1,070.30 TOTALS $1,070.30 PLEASE DETACH BEFORE DEPOSITING CHECK WGR Operating LP PO Box 1330 Houston. TX 77251-1330 $0.00 $1,070.30 $0.00 $1,070.30 PAY COLORADO DEPT OF PUBLIC HEALTH & TO THE ENVIRONMENT ORDER OF: 4300 CHERRY CREEK DR S, APCD SS B1 DENVER, CO 80246-1530 PAY EXACTLY "•" CHECK NUMBER 742103390 April 10, 2012 1,070 DOLLARS AND 30 CENTS JPMorgan Chase Bank, Dearborn Dearborn, Michigan SECURITY FEATURES INCLUDED: SEE DETAILS ON BACK 74-1292 724 CHECK AMOUNT $**1,070.30** AUTHORIZED REPRESENTATIVE OF THE COMPANY lin7L, 210339011• a:07241 29 27i: 75866474 211' Attachment B .- Internal Combustion En L Ca aa .r1 1.4 Coo 0 L o 04 F Ate MCI F O F Eml as 1�1 Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit # & AIRS ID] 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] en 14 V Facility Equipment ID: nested Action (check applicable request boxes) Section 02 — Re Section 01 — Administrative Information Request for NEW permit or newly reported emission source Request for coverage under GENERAL PERMIT number GP02 (Natural Gas Only) Request MODIFICATION to existing permit (check each box below that applies) Change company name Transfer of ownership ❑ ❑ Change fuel or equipment a, w '—I "0 O eV en d en 3 in o ai E 'b C O O 44:41 OU UU .4) - Zv w Kerr-McGee Gathering LLC Company Name: Lancaster Plant Source Name: 16116 WCR 22 Source Location: Fort Lupton, CO Change permit limit Request PORTABLE source permit Request APEN update only (check the box below that applies) N a N O 00 hi O U a N P. O. Box 173779 Mailing Address: la U 0 O. I- 7) 0 o 0. L 4-4 .a o E ... VS = V) 'o V O a L w vs U ao C C .V) =IAJ d v) U E CI) O C '. C. ›. 3 '4 E is C •0 4) a)4, a CU H a O Q O u C coml O +-+ C .� cd 'v O > .O ..: V w EPA Tier 2 certified Caterpillar C18 diesel emergency generator ❑ ❑ O .. Ts O - a. r3 44Z Denver, CO 80217-3779 720-929-6028 Phone Number: Jennifer L. Shea 720-929-7028 Fax Number: nadarko.com Jennifer.She E-mail Address: Section 03 — General Information A co For new or reconstructed sources, the projected startup date is: For existing sources, operation began on: 7 days/week 1.7 O s N Normal hours of source operation: General description of equipment purpose: o 'O "O C s.et . o E ar W a] U o C �go Q L .c U d 4) C A 0 a n' E Ii) �' C >cu o he C al ' = - " C .C �' w 'as' E'N eo I. o,� com ca s_ r—i VD en eat aCi 5 a L. so = +-, a) i " 1.. V 4 oC LOW U ^ O Ces_-in. C t E o E rs > > �.w r O a) 0A C �. O O C C d 44-‘O C oU 4) A 0. •_ > .0 C Q Cd O > � Sio � 0 ti •�oo w�A O U C O" •.�.�n. L. ..� o 4.' .O Q) 5 w U C$d O w O o _o a U CV In O � 1.0 ca Z w O C4 .i en Ain .Y.J. 4) Net L el 14 00 p? O CA U r qU o > QetA For guidance on how to complete this APEN form: o _ O in E E 0o Cn�N- .-. vi t MMM € .r N N N V ON C\ O1 NO Vr \O 'O v r r C3 O O O en en en O v APEN forms: httn://www.cd he.state.co.us/a U Application status: h A F Date engine construction commenced: Date the engine was ordered: Date of any reconstruction/modification: Date the engine was relocated into Colorado: C 0 ❑ O z z b Cy a d o U �- ..o tOcel a 'Oo > 44. 3� ine Information Section 04 — En U Engine displacement: cci Engine date of manufacture: O Cu ti. L d Cu U Manufacturer: z❑ U ct a i > a O a len C U a 0 O � o y E E O 0.. ❑ ❑ O U C U C OA C W !I2 C a O1 0 C' 0 a) N Ct U H I]? E E ( y 4O V o ed 4-4 g 00 00 C' Engine Brake Specific Fuel Consumption @ 100% Load: Combustion: U 2 cn o I U z X O .4 O4 N Cn ❑ ❑ ai U '0 a; U U .c.r2 — O O O O • Q.o. E a eg eel 04 'C .O 0 0 as O 0 Cn 0 0 ' 2 t2.. O o o 0 . . 0 0 O UU 2013-04-05 GEN3 APEN.doc v Ic O O In What is the maximum number of hours this engine is used for emergency back—up power? 1 O N Aft U C a u� uogsngmo3 leuaa3ul AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — Reci 0 0 N me- Emission Source AIRS ID: 12WE1492 Permit Number: U m a) 0. I E w O a) a) a) • O • C C C Ct a ) 'C 4- ^a) 3.. cn al O , CO L.. U O r+ u cu Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Easting or Longitude (meters or degrees) UTM Zone (12 or 13) M Horizontal Datum (NAD27, NAD83, WGS84) Moisture (%) Velocity (ft/sec) StZ Flow Rate (ACFM) 4,552 Temp. (°F) ON 1/40 O' Stack Discharge Height Above Ground Level (feet) O so Stack Base Elevation (feet) Operator Stack ID No. M W U C O L O Vertical with obstructing raincap ❑ II rn 4) .C U C v 0 O Ext tion Information Section 06 — Fuel Consum Seasonal Fuel Use (% of Annual Use) 1 O a. a) en 25 Cl) O 0 in, 25 c. th 25 V w u A to N Sulfur Content (% wt.) es ae z Fuel Heating Value (Btu/lb, Btu/gal, Btu/SCF) pc 7 c CA en OO a Annual Fuel Consumption (gal/yr or MMSCF/yr) Requested Permit Limit 19,950 gal/yr Actual Reported for Calendar Year d Z Fuel Use Rate @ 100% load (SCF/hr, gal/hr) 39.9 gal/hr Fuel Type Ce CA : a O z cn a) L• U 0 C O C) O T.) (tea, cd 3 "O 4) O. O. a• 4) a .61 In Section 07 — Emissions Inventory Information & Emission Control Information O N N 0 O N b0 u O .0 S w 0 4 .0 en C y V >`, L C 4J OS u et u Ct I_ w L OSi OS OS .V u u t lb C O i C V O 2 u LL C O N w Estimation Method or Emission Factor Source AP -42, Table 3.4-2 AP -42, Table 3.4-2 AP -42, Tb. 3.4-1 S.. es 4.. c c t Manufacturer Manufacturer AP -42 Table 3.4-3 AP -42 Table 3.4-3 AP -42 Table 3.4-3 AP -42 Table 3.4-3 Requested Permitted Emissions Controlled (Tons/Year) s!w!ulw ap s!w!uiw ap de minimis U, E .C .E eV 'v s!w!u!w ap Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Uncontrolled (Tons/Year) ^' O s a v) .-; 1/40 N 0 d .0 0.2 0 4) .C 0 4) .0 0 y Molaq Controlled (Tons/Year) is Actual Calendar ' Uncontrolled (Tons/Year) Emission Factor C = �„� .O- = i - = I -t140 - LLtoI4 1� d g/hp-hr r .C a. w lb/MMBtu Ib/MMBtu Ib/MMBtu = - Uncontrolled Basis O O in O _ O• "'� 5.56 _ O O M O la O-`` 4 OO N in O N tri N VD O OO OO N n 0_` 4 N. N Control Efficiency (% Reduction) Control Device Description Secondary aw Pollutant 0.4 o ' O O O r"Qaenz> OD I Formaldehyde 4) >1 '0 t. 0 4 C o U " Q IBenzene vi O nci :r rn O b .o .y c 0 co) 4) ed a� 4., 2 V 4) 0 Ct. /-. y O us d COI a) w y N U, 5— C w O on 0.1 r, 8 44 g a• c4 105 g al O a) b w Q., o L7 in • b 0 U U ... cCS 0. a) 5-E b U) C 0 re* •aaq cd 0 a) Sc a) v C O I w —is 174 a) U .a a) •.C C w CC U I Section 08 —A U as .- E U '0 a) Cl i~ 0 • G Cn U 0 U) h 54- I a) U I.. 1--• ale cNi i.. a C a a) a) U O w resentative Jennifer L. Shea I O an 1 a) Name of Legally Authorized Person (Please print) a) I- a) a w O 0 0 -a en w v M O N a) a (APEN) & Application for Construction Permit — General AIR POLLUTANT EMISSION NOTICE a O to O N r Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit # & AIRS ID] 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] In N uested Action (check applicable request boxes) Section 02 — Re Section 01— Administrative Information Request for NEW permit or newly reported emission source Request PORTABLE source permit Request MODIFICATION to existing permit (check each box below that applies) Change company name I. 0) ..C ...� O ❑ Transfer of ownership ❑ ❑ Change fuel or equipment Change permit limit ❑ ❑ 4 C ea rad ea r.+ H Cr Request APEN update only (check the box below that applies) ZOO 0 en o UU Z (73 Kerr-McGee Gathering LLC Company Name: Lancaster Plant Source Name: a O U 16116 WCR 22 Source Location: O 0 Fort Lupton, CO N O 0O 0 N P. O. Box 173779 Mailing Address: O C .C...," C O N N C) w a O .CO CO C) C) b C a) cd U 7, O C .— CO CO C) C4. O 4) O. 4, CA a) O �i s U O W � C. O 0 • - 0 0 '0 O C1 O. ❑ ❑ Denver, CO 80217-3779 720-929-6028 Phone Number: Jennifer L. Shea Person To Contact: R C O 0 720-929-7028 Fax Number: Jennifer.Shea@Anadarko.com E-mail Address: Train 1 mole sieve regeneration gas heater. ii Section 03 — General Information For existing sources, operation began on: O a) O f}. O O z0 7 days/week et -c O Assumed 84 % efficiency h L u C L . 0 )! z O es L 'o s... u 401 ea u CO ea C O ea L C a) L u u ▪ y 6) O E 4J CO O a. g o n. a. a' aJ O C 0 a U CO a) a) C C7 a 0 > O o � O (am U *1 C rs C O E inst La eQ O Q,0. 1. "O ea L _O O U " C O O\ esi Ira L w a u a) u ea 3 b4 C O Cu a. ral eU C O C t O d 6 .a w O a. C eU E ea d 0 ea L O O U .C O eV on. 1. en Q I- Q 1/4O L NO U 00 L 0 4)V .C a V a`) o > en O C O a A For guidance on how to complete this APEN form: 0 CO O 0 O 00 N O\ \O en O M rn ob 0 U C CO tCS APEN forms: Application status: 3 O Q3 O O z ❑ a) cri a. C a) Ii 2 X g .C C3 O w d a O "J tu .O C a.) ,O. 3 Q' ..- > • ment Information & Material Use w /Manufacturin Section 04 — Processin C a) C- a- aJ 4- O C •4•:: U CO u Q O z .70 a) cn 6 z 13 O Manufacturer: Design Process Rate (Specify Units/Hour) I Annual Requested Permitted Level- (Specify Units) Actual Level (For Data Year) Description iii cd cts a Finished Products: LOther Process: CO O L O • Q cd Q O cn X U IZ U a. O C .fl O. O t-. O .I O. O. b 0 O CA eu Ir O 0 U 2013-04-05 FTL E-2015 APEN.doc N O 0 Emission Source AIRS ID: 12WE1492 Permit Number: 0 CO a a) cc 0. a) a) 4-4 0 a) cu a) a) a) a. os GG 0 Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Easting or Longitude (meters or degrees) UTM Zone (12 or 13) 13 Horizontal Datum (NAD27, NAD83, WGS84) v. ,O o 0 '- O tn > •-- Flow Rate (ACFM) Ee-, w H Discharge Height Above Ground Level (Feet) TBD Base Elevation (feet) Operator Stack ID No. In 0 N W O Other (Describe): C C O N I- O O C O u a) -C U a) 4- O O C O I- Width (inches) = Other: Length (inches) = O Exhaust Opening Shape & Size (check one): tion Information ment & Fuel Consum Section 06 — Combustion E O z ct Ultra LowNOx ZEECO USA, LLC Manufacturer: In r. O W Company equipment Identification No.: Seasonal Fuel Use (% of Annual Use) Sep -Nov 25 a Jun -Au: 25 Mar -M 25 Dec -Feb 25 Percent by Weight in I.. a" V) Fuel Heating Value (Indicate: Btu/lb, Btu/gal, Btu/SUF) 1020 Btu/scf Annual Requested Permitted Level2 (Specify Units) 255.6 MMSCF/yr (84% efficiency) Actual Level (For Data Year) Design Input Rate (106 Btu/hr) 25 Fuel Type Natural Gas 2Requested values will become permit limitations. Requested level should consider process growth over the next five years. Information Section 07 — Emissions Inventory Information & Emission Control W cn 4g1 O I. U -o 2 O U U O ti 0) CV Sc ccdd F-. n C C CA 6! O .O cc C. O s O V .O U, C O y H Data year for actual calendar yr C u Sc as os d u O s. O fat V1 Estimation Method or Emission Factor Source AP -42 Tb 1.4-2 AP -42 Tb 1.4-2 AP -42, Tb 1.4-2 t... a) a w g 2 Manufacturer Manufacturer Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted Emissions4 Controlled 1Tons/Year) Nin. N N tn Uncontrolled (Tons/Year) ,-r .--i ' O N in 1(1 N e4 Ufi Actual Calendar Year Emissions3 Controlled (Tons/Year) Uncontrolled (Tons/Year) Emission Factor Units Ib/MMSCF lb/MMSCF lb/MMSCF irel i a ACt i a lb/MMBtu Uncontrolled Basis tip I- VP [- Vp C C C• ON G C • Control Efficiency (% Reduction) Overall Collection Efficiency Control Device Description Secondary Primary Pollutant V H a N a O v) xOM 0 > OD H O • y a) O yen eu � n submitted with this application is complete, true and correct. el -a o C 'O O n) v c g0 O 4...-k a 0 ▪ ton. C a) a 03 L' Q >> V) U S i V) Clia ac, .0— (L) L. al .C t = O .O •y -o tn 41 w o • a G ▪ N a) u c t4 et ` U E• tu O N O y'O c0 U .t .0 = C CA cQ 3 0 a CZ L w p a� ese Z N C ' C3 • w • .iii eu resentative Staff EHS Re Jennifer L. Shea ✓ -1 C Name of Legally Authorized Person (Please print) I) 2013-04-05 FTL E-2015 APEN.doc CO O N Emission Source AIRS ID: 9 [Leave blank unless APCD has already assigned a Dermit # & 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] I1 Facility Equipment ID: uested Action (check applicable request boxes) Section 02 — Re Section 01 — Administrative Information Request for NEW permit or newly reported emission source Request PORTABLE source permit Request MODIFICATION to existing permit (check each box below that applies) Change company name a) 0 O Transfer of ownership ❑ ❑ Change fuel or equipment Change permit limit ❑ ❑ Request to limit HAPs with a Federally enforceable limit on PTE Request APEN update only (check the box below that applies) ZOO 0 a. M Company Name: Kerr-McGee Gathering LLC 4.0 C a) U) Gn Ct c Source Name: 16116 WCR 22 Source Location: C 0 In Fort Lupton, CO 4) •• O cti o Co c a) E tt a N C 00 P. O. Box 173779 Mailing Address: O 0 H 4) I-. w U) C 4) 44)) its 0 C 4) v O ,O cn (24 a) O .> I- O. L CO ts. O .y tu O a)) 0O O O. ❑ ❑ Denver, CO 80217-3779 720-929-6028 Phone Number: Jennifer L. Shea Person To Contact: 720-929-7028 Fax Number: nadarko.com Jennifer.She E-mail Address: Train 2 mole sieve regeneration gas heater. Section 03 — General Information 0) O L7 Sc.)) 4, 0 O. 5$ Cn a) U L. CO .b O O ti I., For existing sources, operation began on: 7 days/week c a O .C Ner N Assumed 84 % efficiency H L a, C L O O L c In cc OA as a) 1.0 N U, O A. O. O g C 4) aa , . O 'a, a) a o O C O a • c.) x 4) 73 I- C) ° zo c a) C L C 4.1 'v C c .C Cc te rr. C a w O 4.4 d t c C. Cc L O O U U cm d C O nthi 4.0 L C O C O c o a) o E O- co g C Q) -O -5 a)VI }, a) 41 1.• • U a.o scccl Entri C U 13 E `o a• In a) a) a, Co C) . •O 1 0 a)' — 0 H U C 48 g3 0 U, y .... it O. '— C O\ N In b9 L a U a) U c t 3 bD C O Cc E Cn t CC C C) C O L .> C Cc C) O C a) cc O. 4.98 O "C c L _o O U r O L en 0 _ a tie LN aU00 OCI iO U = • ua, • $ QUA For guidance on how to complete this APEN form: O In C O\ M O M I.• O vt- re) en I N en en O O en M c O c O APEN forms: htto://www.cdnhe.state.co.us/a s U v. V) tO Cn hc.statc.co.us/a C) 5 Application status: htt C Q� O O 2 O 4) cd C E C • z C d a •a �es zE E 4- co I a° o a; .O . 4-4 C 4) O.'o u N Zn .C .--, _4- 3~ ment Information & Material Use W /Manufacturin Section 04 — Processin O z z N O Manufacturer: Design Process Rate (Specify Units/Hour) Annual Requested Permitted Level (Specify Units) Actual Level (For Data Year) Description 'i 4) a Finished Products: Other Process: 4i U❑ In Cn .O I - O 4 O. 4- O. Cg b w O a O U a CT O 0 .y, U Q) U cg a. 0 'a N Cc U A E 4-r 4) o. U O e`a ref rn A cn 41 ti 6' A Q. Check box to request copy of draft permit prior to public notice. 2Requested values will become permit limitations. Requested level should consider process growth over the next five years. 2013-04-05 FTL E-2016 APEN.doc 0 a) bc a C N O 00 O 12WE1492 Permit Number: F-� L O OD cto cd C�d 'G ' O 5-. Q ca co Fr O i-+ O a) .4. O 4.4 Clo CA N c3 Q E Ca O s In V) Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Easting or Longitude (meters or degrees) UTM Zone (12 or 13) M rl Horizontal Datum (NAD27, NAD83, WOS84) Moisture (%) .4" U U O j Flow Rate (ACFM) C. , i Discharge Height Above Ground Level (Feet) TBD Base Elevation (feet) Operator Stack ID No. I O N al ❑ Other (Describe): O A 0 ¢ U C 00 O Cd u 0 0 co 0 v u .C u y.r O t4 -1 0 C O •U 0) H Width (inches) = Other: Length (inches) = Exhaust Opening Shape & Size (check one): ment & Fuel Consumption Information Section 06 — Combustion E A F■ Ultra LowNOx 0 ZEECO USA, LLC Manufacturer: O w Company equipment Identification No.: Seasonal Fuel Use (% of Annual Use) O 0. 25 (1) oA C Q C C 25 cd th 25 .0 a) w 0 A v, N Percent by Weight Q Sulfur Fuel Heating Value (Indicate: Btu/lb, Btu/gal, Btu/SCF) 1020 Btu/scf Annual Requested Permitted Level (Specity Units) 255.6 MMSCF/yr L (84% efficiency) Actual Level (For Data Year) Design Input Rate (106 Btu/hr) en el Fuel Type Natural Gas C Cd E trz C ••I L 0 C .7 C O E C 10•1 t C a) C •ma h N _O .Is u a, Ct N O O N oc ... Data year for actual calendar y os yyu Estimation Method or Emission Factor Source AP -42 Tb 1.4-2 AP -42 Tb 1.4-2 AP -42, Tb 1.4-2 Manufacturer Manufacturer Manufacturer Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted Emissions4 Controlled (Tons/Year) H 0 C A (� O .-1 O I -I '.. O N in N N V, Actual Calendar Year Emissions3 Controlled (Tons/Year) Uncontrolled (Tons/Year) Emission Factor CA lb/MMSCF Ib/MMSCF Ib/MMSCF = 045 lb/MMBtu = 045 Uncontrolled Basis r O O O O 0.04 Control Efficiency (% Reduction) Overall Collection Efficiency Control Device Description Secondary E p. Pollutant O Un xON DOA U co; 0 y _y 00 y en yca C Q' O U Co 74) 0 c A �a a .- y O v cn CZ 0 td H 0 ct w � Fs b u O 3 E HU col 4) g 1aA—. 0 41) 0 •VJ Jr 3-0 0 N y a y 'v pri C n .► licant Certification - I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. Ate resentative Staff EHS Re Jennifer L. Shea I) a) Name of Legally Authorized Person (Please print) a) A Cd A O. O Na) Ct tto 1-4 O 4- O 2013-04-05 FTL E-2016 APEN.doc AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — General O O N [Leave blank unless APCD has already assigned a permit # & AIRS ID] 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] In I x Facility Equipment ID: C) Yt O .Q Ca 4.) Cr L CC cat C.)) 4) r C.) I- Q as a Section 02 — Re Section 01 — Administrative Information 4.) u L 0 H C 0 4) C d es L 0 C. 4) L C L a> a. N M Request PORTABLE source permit UU z Kerr-McGee Gathering LLC Company Name: Lancaster Plant Source Name: Request MODIFICATION to existing permit (check each box below that applies) 16116 WCR 22 Source Location: Change company name Transfer of ownership ❑ ❑ Change fuel or equipment Change permit limit ❑ ❑ Fort Lupton, CO a C a� CO d u L w au fam �a L O C 3 x tea CT O Request APEN update only (check the box below that applies) N C 00 O a N P. O. Box 173779 Mailing Address: O 4) o a L. 0 c O • 4) a a. o cn 4.) 5 0 N .0 C1,2 •0 >, E C) u W y -C o o g 0 oaa)) 407; t L. ❑ ❑ Denver, CO 80217-3779 720-929-6028 Phone Number: Jennifer L. Shea Person To Contact: 720-929-7028 Fax Number: nadarko.com Jennifer.She E-mail Address: Amine regeneration heat medium heater for Amine 1, Train 1 (A-1). Section 03 — General Information For new or reconstructed sources, the projected startup date is: Assumed 78% efficiency. 1-4 arEle L w �C es 4- cc L d U 4- H L 4, C Ct = O C a) 3 O St N w I 3 L 4, 4. cues c �r � 0 o a) ,C E C4 L St 405 o ‘D 0 CIO o 0 o P.O o 0 Cn U a 0 or Wa tx L. 0 General description of equipment and purpose: 4- C U C .L > C PC C ea s ea 4) fas w O 4- C C) E Ca a 4) A cc L 0 O 0 L 4- C O C O 0 a, 0 4) 4-'b `0 C •` E a W O O 4) cd �yj�, � U C Cd,C a C .v_ a a) NW E•l c In 'o (As V) O U _ L ` y vi 0 4 C• 3 ax a) �-.O u.0 a VI It Cr C 4 CA 4) O .C r4,,, 4) O L.M L. a anc A� 'r1 I c E ,�, `c a) ' ci > U C e L N y 4• 'C3 E d "'I U Cl° 00 oA02LO u o a y 0 (n y U '.r 0 C)-.a(/Ds . O 'w. 1,3 S _ L 4) $ �oa,a) F- - 4UdMvA For guidance on how to complete this APEN form: L.. 0 In O " t .-• M en en g ON CA CA -0 ‘..0 N.0 \0-0 000 on on on > 0 CO C O O A. 7. g o L, � 0< o CA .CICCI C C) if; ,4-1 O C5?). C 3a na" Qv� ¢ Q O z cn a) cCV I.O.. c 4- .% a c Z Fid .E o. o o 4) r .O N EL a•0 •E 0 3 ment Information & Material Use .r a 0 z c .V WI 2 /Manufacturin Section 04 — Processin a -J C 4) a w 0 C 0 Q. a) A Manufacturer: (1) L" Cd C C4 CA 4,_ U • C oa got) U 4) u a. A� a b EC b 42 sr, a a v ) 0 >" fag O iA Ly "acat ct') Other Process: ,U O U a U y � O O `OCL .Q to to ii Imo O O O O U Cr. Cr' ce-. 4) O O msd U U El El 2013-04-05 FTL H-6051 APEN.doc N O C) to Cd o I o a? CO N ct tio•ICI � d •VJ Cal �M E Ate �.r 1�1 O O 1�1 12WE1492 Permit Number: Section 05 — Emission Release Information (Attach a separate sheet with relevant information in the event of multiple releases; provide datum & either Lat/Long or UTM) Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Easting or Longitude (meters or degrees) M -o NO O N 13 Horizontal Datum (NAD27, NAD83, WGS84) I2 O Velocity (ft/sec) Flow Rate (ACFM) Ew Ev —INS Discharge Height Above Ground Level (Feet) TBD Base Elevation (feet) Operator Stack IDNo. In O 1/4.0 ❑ Other (Describe): Width (inches) = O Horizontal 0 Down 0 Other: Length (inches) = Vertical 0 Vertical with obstructing raincap ® Circular: Inner Diameter (inches) = C 0 Cd u u 4) 0 tl.. O 0 U a_, Exhaust Opening Shape & Size (check one): uonutuaoiui uol;awnsuo3 long a8' luaus Section 06 — Combustion Eaui O z HC2-50.0-H-SF Sigma Thermal Manufacturer: Company equipment Identification No.: Seasonal Fuel Use (% of Annual Use) Sep -Nov 25 Jun -Aug 25 Mar -May 25 Dec -Feb 25 Percent by Weight 7 Ash I.. a U) Fuel Heating Value (Indicate: Btu/lb, Btu/gal, Btu/SCF) 1020 Btu/scf Annual Requested Permitted Level'` (Specify Units) 660.6 MMSCF/yr (78% efficiency) Actual Level (For Data Year) Design Input Rate (1 0613tu/hr) O .O Fuel Type Natural Gas a) u iss to In In O C. O .b O cn H Cr C4 cri tprt tu 0 ate) .D 734 aa). N C) a. a (94 Information a. - 4•d U C O C r..l E C II. C L rC+ C a) c to C .O .= E N C ii U Cl)C) O .. N 0 O dL w u O .a Ca a C. two L' i -C .0 0 U H C O VJ cO L W d B al •' 4.14 O I.. at u 4) C al C.) U 0 -d I.- 0 C.) Ctl t.•r O so cn E HI u et y G4 •g U O cn 71 H g Estimation Method or Emission Factor Source Manuf I w a g AP -42, Tb 1.4-2 Manufacturer AP -42 Tb 1.4-2 Manufacturer Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted Emissions4 Controlled (Tons/Year) Uncontrolled (Tons/Year) t: 10•11 N. PS 0.2 vi en oo v? m Actual Calendar Year Emissions' Controlled (Tons/Year) Uncontrolled (Tons/Year) Eil— mission Factor MC M i G M." 7 M i .O lb/MMSCF lb/MMBtu ‘Ts cn i .O 0 M Q Uncontrolled Basis in a O in a a v . a 'a' O 5.5 !t O Control Efficiency (% Reduction) Overall Collection Efficiency Control Device Description Secondary E a Pollutant en H a N a O v) O z> O O v to • 0 N O d O d 0 w C U O U ice. CCQ .0 • a) aa . v0 C Cc CLa U E O U C aJ g.0 ��•• y tc k-. U te.. 4J cs O U 0CI E O cn cn .E., .• Tel g N 2 C .0 •vi -0 3 Oa) 'y Q. y `C cv a) rn -a g a tu G4 1--� M get resentative Staff EHS Re Jennifer L. Shea O an u C) L i. V C C1) imp L a) O. 4.0 Can u a a cc to S. t Is 5; `Id Is nee H C .r Is S E to. C .C Ct 4) a) .C as C u C C E W C rr CC Cu SC Is u C) 3. I Q Name of Legally Authorized Person (Please print) et Q a. U) 0 0) 0 i. ram 4) CI -1 O U 0 z 0 N a) cid 00 AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — General W O U, O N Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit # & AIRS ID] 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] If) 1/4O Facility Equipment ID: uested Action (check applicable request boxes) Section 02 — Re Section 01— Administrative Information Request for NEW permit or newly reported emission source Request PORTABLE source permit Request MODIFICATION to existing permit (check each box below that applies) Change company name U) r O O Transfer of ownership ❑ ❑ Change fuel or equipment Change permit limit ❑ ❑ Request to limit HAPs with a Federally enforceable limit on PTE Request APEN update only (check the box below that applies) 0❑❑ O N M Sq .a C C en 0 vi o b o •0 U U U U 0.4 zc W N Kerr-McGee Gathering LLC Company Name: Lancaster Plant Source Name: 16116 WCR 22 Source Location: Fort Lupton, CO P. O. Box 173779 H O 0 Q. C 1-' a) o o CO CO 4) 0 COI .C C >, 3 C 4" U) W7.CO 0 0 U N cd H a in O y C) TO O U 0. 0. ❑ ❑ Denver, CO 80217-3779 720-929-6028 Phone Number: Jennifer L. Shea Person To Contact: 720-929-7028 Fax Number: nadarko.com Jennifer.She E-mail Address: Amine regeneration heat medium heater for Amine 2, Train 1 (A-2). Section 03 — General Information .C' C) .0) U 00 N "C co a N H 1.. 0 d C' d r.+ C L d C as L 0 h L C C L O .C 0 C O a U N 0 ls 0 a e so till E 0 0 . C a a. "C C U 0. 0 a) 0 0 U c o = O e., En L. U C 0 4) 0 0 Iii y.l ao 1- C O WU PC a C Q Qs in C ,o cas .— o 0. 0 oU 4— C C as O E cis C O co C. D Q 0 L _0 O U o U) O E O. C7 CLI g QJ U g 0 U a ts vfl ca = d 0 1 [ U vn 's s 3 Ea� o C. a• Q) N > —I I-tu s. �� C v g' 0 U) > a .`3 0 p V. U 0..5 11) Sa 14.4 c0 CA ' 4 E- N' - O 4- Os N In EA L 0 a U d U Ua I on C O as E H .C as 4- C a) C O C s ea 0 w O C C t C. d O 0 -10 ca 1- 0 O U s 0 0 an a I Ci V0 GO > 164 .C r Ua O C O C ` a) I''G For guidance on how to complete this APEN form: L 0 O oen en en I I I t- N N N ea• .--. D O O en en en .i as O 0 R7 0 0 O O z O N C) 0 a) E a z CE In C_ V 'Ea Qj C Z E .- �� 40. 0. 0 u e CC U) 5 U ment Information & Material Use 'a /Manufacturin Section 04 — Processin To 0) 0 z To .0 0 Manufacturer: Design Process Rate (Specify Units/Hour) Annual Requested Permitted Level2 (Specify Units) Actual Level (For Data Year) Description I Raw Materials: Finished Products: Other Process: 03 C) Q• 0 U U • . 0. 0 0 s 16 O 0 CL 4-6 ii II 00 0 •0 .1) v it C E 0. O C) w 0 4- N N H ..C Aci o. G• U 0. .O 2Requested values will become permit limitations. Requested level should consider process growth over the next five years. 2013-04-05 FTL H-6052 APEN.doc N w O ctI a FORM APCD-200 V C z z C !�1 CA 1�1 w z N C a O CO O Emission Source AIRS ID: 12WE1492 Permit Number: Section 05 — Emission Release Information (Attach a separate sheet with relevant information in the event of multiple releases; provide datum & either Lat/Long or UTM) Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Easting or Longitude (meters or degrees) UTM Zone (12 or 13) 13 Horizontal Datum (NAD27, NAD83, WGS84) Moisture (%) Velocity (ft/sec) Flow Rate (ACFM) 6. vF H Discharge Height Above Ground Level (Feet) TBD Base Elevation (feet) Operator Stack ID No. N 0 0 Other (Describe): 0 eC x❑ O Width (inches) = 0 Vertical with obstructing raincap El Direction of outlet (check one): Other: Length (inches) = Exhaust Opening Shape & Size (check one): tion Information ment & Fuel Consum Section 06 — Combustion E 0 z sa HC2-50.0-H-SF U O Sigma Therma Manufacturer: Company equipment Identification No.: Seasonal Fuel Use (% of Annual Use) 0 Z 25 l U) :n ao 0 ¢ lin N cd th 25 .O Q) U E) in N Percent by Weight i w IBI ,CA Fuel Heating Value (Indicate: Btu/lb, Btu/gal, Btu/SCF) 1020 Btu/scf Annual Requested Permitted Level'` (Specify Units) 660.6 MMSCF/yr (78% efficiency) Actual Level (For Data Year) Design Input Rate (106 Btu/hr) 0 1/4O Fuel Type Natural Gas C .— Cu E a O L r.+ O �C 03 E w C G )-4 H O H O C .0 u u cn N 0 N v O 41 CO s ce co u t S C S u C 0 .2 ees 'a.. C y F Estimation Method or Emission Factor Source AP -42, Tb 1.4-2 Manufacturer AP -42 Tb 1.4-2 Manufacturer 1 Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted Emissions4 Uncontrolled Controlled (Tons/Year) (Tons/Year) P NWI 0.20 00 13.5 Ib/MMBtu lb/IVIMBtu V+r Ib/MMSCF I b/MMBtu In un 0 In O Overall Control Collection Efficiency Efficiency (% Reduction) Pollutant Cn `" O O O O fA _ O y 0 0 'U M Y O L pr.O O u •_ cca 4) a� R. •3 0 W g o km y .r a° eti co, O 4) E W a) ai c° .V U U U °n, 3 2O oU O u io = Bca 0 .b .61) •0.9 • C SC 64) 4.1 W O N �a d lC Q a) C ¢rr resentative Staff EHS Re Jennifer L. Shea a co Name of Legally Authorized Person (Please print) 2013-04-05 Fit H-6052 APEN.doc N 4. O N a) a AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — General rco C U, C N r Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit # & AIRS ID] 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] In O Facility Equipment ID: uested Action (check applicable request boxes) Section 02 — Re Section 01 — Administrative Information Request for NEW permit or newly reported emission source t N M I- Kerr-McGee Gathering LLC ai 8 cs z 00• U Request PORTABLE source permit Lancaster Plant Source Name: Request MODIFICATION to existing permit (check each box below that applies) Ira C O U 16116 WCR 22 Source Location: Change company name a. a) a O Transfer of ownership ❑ ❑ 4) 4-0 A' . 0 4) t5 a 1340 U U ❑ ❑ O en 0 W Fort Lupton, CO Portable Source Home Base: Request to limit HAPs with a Federally enforceable limit on PTE d C .- •O C C.. O 4.0 ce 4) ea a) s O. r.+ 0 O o c ao S O U .a E ° �+ s a) sg C > • R. a E V o Z C U W CO O 4. a O •' U N "C ct y •.. a O 0 a) Z = '^ o a) aaa a TZ do iet 4.0 tz4 a) CO ❑ ❑ 4-4 N co co O N P. O. Box 173779 Mailing Address: Denver, CO 80217-3779 720-929-6028 Phone Number: Jennifer L. Shea Person To Contact: 720-929-7028 Fax Number: Jennifer.Shea@Anadarko.com E-mail Address: Amine regeneration heat medium heater for Amine 3, Train 2 (A-3). Section 03 — General Information cc F - ti For new or reconstructed sources, the projected startup date For existing sources, operation began on: U U,, CIO 00 .C a) a h ce- I .5 cc 4) I co cla C 4, an a) L 0 co) L 4) C U C o r Is I L 4) Is co 4) a) s 3Egn ct c) E cc 4, C ct et 'O L — o a o s N Normal Hours of Source Operation: General description of equipment and purpose: Is C 4a C O L wU Po a cc ac o C :Co� 4) .a L Ca.. ° oU C ° � O E z L O oL eu AQ O •C cc L O O U 1^ a) t4 O V C Ct V U O C C 4) C +°+ V > Os 69) s L w 4) co U U to .O CC 5 .C °; — O 3 bD O a) o £ ce L 0 oq w cto .O° s O r.+ L 5— tC — U For guidance on how to complete this APEN form: 2- O oo In N — — en en en N N N C7N ON cc, en en en co co O en en en ao 0" > U A� O •- b r" C U aVi C .5 a-. t, O Q � C t cc O C O co G U 4! APEN forms: httn://www.cd Application status: http://www.cdphe.state.co.us/ap/ss/sspcpt.html 0 Q5 O O z O ment Information & Material Use /Manufacturin Section 04 — Processin O a) 5 a• 4) O C O a. I U vJ 4) A •O z 6 z U 'Ti O Manufacturer: C O I- a. U CO U A C 3 ) cci Other Process: 0$ U U co U N .G cn O O 0 0 .a .Q ii 0 0 U U If additional ��space is required, please attach a separate list of equipment, materials and throughputs. 'Requested values will become permit limitations. Requested level should consider process growth over the next five years. 2013-04-05 FTL H-6053 APEN.doc N O 00 co 0.4 O N i U C AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — General r 0 to O O N Emission Source AIRS ID: 12WE1492 Permit Number: Section 05 — Emission Release Information (Attach a separate sheet with relevant information in the event of multiple releases; provide datum & either Lat/Long or UTM) Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Easting or Longitude (meters or degrees) UTM Zone (12 or 13) 13 Horizontal Datum (NAD27, NAD83, WGS84) Moisture (%) Velocity (ft/sec) Flow Rate (ACFM) w a)......., Discharge Height Above Ground Level (Feet) TBD Base Elevation (feet) Operator Stack ID No. en In O W ❑ Other (Describe): O Horizontal O Down O Other: Length (inches) = Direction of outlet (check one): Exhaust Opening Shape & Size (check one): tion Information ment & Fuel Consum Section 06 — Combustion E HC2-50.0-H-SF C, 'O O Sigma Thermal Manufacturer: M In 1/40 Company equipment Identification No.: Seasonal Fuel Use (% of Annual Use) O Z ow in ''a U :n DO O Q C O 25 7-1 ezt tc N U 0 U 25 Percent by Weight vs vs 7) Fuel Heating Value (Indicate: Btu/lb, Btu/gal, Btu/SCF) 1020 Btu/scf Annual Requested Permitted Level'' (Specify Units) 660.6 MMSCF/yr (78% efficiency) Actual Level (For Data Year) Design Input Rate (1 06 I3tu/hr) 0 vp Fuel Type Natural Gas CC O cn cn O w Q. O N Cr vi 0 cci C.) Q. O .I.d E 1. L U C vs .414 ea C O E N.0 t C C C) C vs C ,o vs vs .E N C V 41 a W 4ti O C O a) U O 0 ct C.. C O .y U -o CD N C O 0 U C O cn H C) Q Estimation Method or Emission Factor Source w ca a AP -42, Tb 1.4-2 Manufacturer [ AP -42 Tb 1.4-2 Manufacturer Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted Emissions Controlled (Tons/Year) Uncontrolled (Tons/Year) N . N • .r 0.20 13.5 00 .-i is M...0 il O N Actual Calendar Year Emissions3 Controlled (Tons/Year) ® Emission Factor Documentation attached Data year for actual calendar yr. emissions below & throughput above (e.g. 2007): Uncontrolled (Tons/Year) Emission Factor aN lb/MMBtu Ib/MMSCF lb/MMBtu Ib/MMSCF lb/MMBtu Uncontrolled Basis it O O O tin O O O 1/41:! a, o O 5.5 0.04 Control Efficiency (% Reduction) Overall Collection Efficiency Control Device Description Secondary as E .E.' a Pollutant a.) I-4 O a N a X xON VOC O U Vf O y E Vf N Q � . � -a U C H .fir.. Cy1 R � '0 a Q. _aa a 3 0 N r^+ 0 CO II sc. y O 7,.-1 to QJ to N � V ^3 Qi L as t U OQ, 3 2 O 0 • co Q1 E ESL It a 0 ca .0 U .0 4-4 0 . N Ca V Sa e licant Certification - I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. Section 08 —A resentative Staff EHS Re Jennifer L. Shea en C In C) Name of Legally Authorized Person (Please print) Y CI Q y Authorized to Supply Data 0-8 4--�0 C) I- bA 2013-04-05 FTL H-6053 APEN.doc w O C) b1) a AIR POLLUTANT EMISSION NOTICE CD O N r Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit # & AIRS ID] 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] 41) 1/4O Facility Equipment ID: uested Action (check applicable request boxes) Section 02 — Re Section 01 — Administrative Information Request for NEW permit or newly reported emission source Request PORTABLE source permit a a Cu C4 -c 0 a) so E as O a .0 > s. a) 0 .� v a) Ca) ao ac Iwo v C❑ D H d o E a. o H a) U O w w DI) C y a C7 O 0 ❑ Transfer of ownership Change permit limit Request to limit HAPs with a Federally enforceable limit on PTE Vi a 0 O a C 1... O O O E C a O C C `u E a) O t ¢ *W 0 0 Tu. C x ca U U .c E S ..= `) .c e. a , V O .0 LO o " a y is Q O O U N 'C a 0 CL o >- a.)zc "'•0 IA ° a) A ._ Ct Q u a o. t)2 a) ❑ ❑ ®❑❑ O I N M 5M Company Name: Kerr-McGee Gathering LLC Lancaster Plant Source Name: acs 0 U 16116 WCR 22 Source Location: C C 0 0) Fort Lupton, CO a) aNi N w 0 CO a) a) E cx 0 a a N C 00 •0 O U N P. O. Box 173779 Mailing Address: Denver, CO 80217-3779 720-929-6028 Phone Number: Jennifer L. Shea Person To Contact: 720-929-7028 Fax Number: nadarko.com Jennifer.She E-mail Address: Amine regeneration heat medium heater for Amine 4, Train 2 (A-4). Section 03 — General Information L F For new or reconstructed sources, the projected startup date is: a) N V) 7 days/week as N 0 C3 en tr. 0 a) oF, O 0 5, o V vD c 0 w c°= 0 o wz 60 MMBtu/hr amine heat medium heater with low nox burners to regenerate amine for A-4. Assumed 78% efficiency. a; Cn (0(��,, O. C a) CL - a) O O CL 0 b a) c O . — .•. = so c Q O Ts .- '- .= A -fl M a o oU C C a� Co t � o O. as o Q O b Cu L O O U 0 O o Cb O 'C O 00 In O. in v t� W a) ,-4. M M M ea) 46 Q. �, N N N d a a) � � � E , �+-'� c 000 > O O 5L �� . oa cd W c �O W .y cal cd s N ❑ i- = VI S.. .�.S o ca 4. CI 3 aci Q x .t V _ V o a u r O O F cQ o cL Sc- a» E '- w o M 0 •> o a) C 2. OD 49 A $ Q w ho 00 E �4 0 o N cb U c tL N 'O O Q ts cn '- 0 ell ti -t 0 w0m L0 CC C Co.C •C) C h 0 CA a) U Ct • O o ..C "C V y 'C•3 C C = s v �' c U C > a GO ft ea O a, C 5 p '- E E- aa):.� r--.U4vM.1 c.r.. Qv) 0 4) U E Cu O O he.state.co.us/a U APEN forms: htt rn O 4- 4- a) s -v u Application status: ha ;4- = O O z 4-aI0 C Ct C °c vD c W as zE .0 •ccz v o a) tri to Ccu E � . '0 C r o • N > � G ment Information & Material Use .a /Manufacturin Section 04 — Processin G z 570 I 0 z o 0 Manufacturer: Design Process Rate I (Specify Units/Hour) Annual Requested Permitted Level2 (Specify Units) Actual Level (For Data Year) Description - � . a) a2 -b u Ca COa. U IOther Process: U o Ccti U_ •- t3. 0 0 0 0 'C. E v 0 0 00 0 a- a. O I- 0 0 .C -C U El a a to 2 'v N CC y Q) CC G C G a a c u 0 u It aa) to Ca St C) a, a. a 2 V C) C O 'q 'a It t«, 1- . should consider process growth over the next five years. 'Requested values will become permit limitations. Requested leve 2013-01-25 FTL H-6054 APEN.doc w O on Cu a AIR POLLUTANT EMISSION NOTICE N CD Emission Source AIRS ID: 12WE1492 Permit Number: Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Fasting or Longitude (meters or degrees) UTM Zone (12 or 13) M Horizontal Datum (NAD27, NAD83, WGS84) Moisture (%) Velocity (ft/sec) Flow Rate (ACFM) � Eta- c, ... L, Discharge Height Above Ground Level (Feet) TBD Base Elevation (feet) Operator Stack ID No. et en C O Other (Describe): 0 U 00 •U 0 .174 O 4) > Direction of outlet (check one): Width (inches) = Other: Length (inches) = Exhaust Opening Shape & Size (check one): Consumption Information ment & Fue Section 06 — Combustion E A F 0 HC2-50.0-H-SF Sigma Thermal Manufacturer: Oth Company equipment Identification No.: Seasonal Fuel Use (% of Annual Use) SZ not4-das 04 '' C C N Mar -May 25 U O in Percent by Weight qsy w. C V) Fuel Heating Value (Indicate: Btu/lb, Btu/gal, Btu/SCF) 1020 Btu/scf Annual Requested Permitted Level2 (Specify Units) 660.6 MMSCF/yr (78% efficiency) Actual Level (For Data Year) Design Input Rate (106 Btu/hr) Cr) Fuel Type Natural Gas 0 tn 0 0 a) C U O •ts ti O w C O a) CD C-. 0 I Estimation Method or Emission Factor Source w w AP -42, Tb 1.4-2 1 a) i. ca w g 2 AP -42 Tb 1.4-2 Manufacturer Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted Emissions4 Controlled (Tons/Year) Uncontrolled (Tons/Year) N. N 0.20 ifl TN C10 13.5 'S O N Actual Calendar Year Emissions' Controlled (Tons/Year) I Emission Factor Documentation attached Data year for actual calendar yr. emissions below & throughput above (e.g. 2007): Uncontrolled (Tons/Year) Emission Factor in Ib/MMBtu lb/MMBtu Ib/MMSCF Ib/MMBtu U U) Ib/MMBtu Uncontrolled Basis in O O If) O O OCO It • G 5.5 0.04 Control Efficiency (% Reduction) Overall Collection Efficiency Control Device Description Secondary s a Pollutant E-' aN p. O to p Z O > O V fn O .N ich E �o o O y as° U • y 0 O ✓ -1O . c c y "" C7 3 0 0= w O w E 'a 0 • .c c yCn O ▪ H W :r va � U wo t O R V 0 0. O ch • ye 0. g t• t O 41) 'O • y • ut •� V) cn .O -0 e � c•-• p O ya =� E� ii c � - n .► Co▪ ) L u Cr Ct u L a; Is Cl s O C.) •O .-, Is Ca 0. O. Ca CO ▪ -r pm Is Is s G O Is C:1 4.4 . O .14 14 u C u O t1+ Ca s •C Ca CC u Cl C) L u C *40 ea L u U l.d O Ca .- Section 08 —A resentative Staff EHS Re Jennifer L. Shea en C N in a) H 472 Name of Legally Authorized Person (Please print) erson Legally Authorized to Supply Data O 2013-01-25 FTL H-6054 APEN.doc O N Cl a CO O 0 O Cr) r Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit t# & AIRS ID] 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] Facility Equipment ID: uested Action (Check applicable request boxes) Section 02 — Re Section 01 — Administrative Information Request for NEW permit or newly reported emission source yet M Request MODIFICATION to existing permit (check each box below that applies) 0 0 UU U zv Kerr-McGee Gathering LLC Company Name: Lancaster Plant Source Name: Change company name Transfer of ownership ❑ ❑ Change process or equipment Change permit limit ❑ ❑ C 16116 WCR 22, Fort Lupton Source Location: 0 0 Sn Request to limit HAPs with a Federally enforceable limit on PTE N N O 00 a) b 0 0. I- N P. O. Box 173779 Mailing Address: Request APEN update only (check the box below that applies) Denver, CO 80217-3779 Revision to actual calendar year emissions for emission inventory 720-929-6028 Phone Number: Person To Contact: L , a e , w us > T 0 -z o pW A. U 0 Q C. x 0 ay aCn •CCfr C E o OD — Zn y L as 'fl _+ C Q) O 0. 3 >, o is a , o C i bp •LQ. .C H U 0 E in Z,—, .5 >, L 3 en is 4) sps C a 0 E .... C L W C N N LT.,•- C U :° O K N " o E -o a w 2 Q S 720-929-7028 Fax Number: Jennifer.Shea@Anadarko.com U) U) 8 W Section 03 — General Information For new or reconstructed sources, the projected startup date is: For existing sources, operation began on: c- a E.0 0 3 Inw pQ E o 4) O w E E o -a 'i' 1- Eti h a a H 4- in bAt C Cd cc :� o bA C E C Q Normal Hours of Source Operation: General description of equipment and purpose: 3 3 0 0 2-1 .C CC 00 QQ ❑ ❑ zz ❑ ❑ 0 >- 0 I he.state.co.us/a CV a+ C 4) C C C O C 0? OF a) R. 0 c a� A E a L7 ► Does this facility have a design capacity less than 2 long tons/day of H,S in the acid gas? Provide documentation. C a C 0 L C LTA '.a C Ct s Cl w O C a E L at 0. a '0 L _o 0 U .f.?. O a..cn W 0 C a) cd 0. o U cis C E• dA H .0 aO N C o o Cis .C 3 U �' o a. N U O b Tcs C7 0 U 0 C F O 0 o' N rte. fin L w a U .C u Cu ,C 4- b0 a _o Cd E w en og C a C O L C Z 4- ea a Cho Cp, O C a E L Ca a a L 0 C U Z O a > •L IM A..y a 1/4a 0 o 00 >, Q L dU w U o C o eta A For guidance on how to complete this APEN form: 0 Its M N a' M O M 4, 0 00 1/40 C N M O M In t -- en Cl a O M � 5 0 co O v ti 0 .0 U U E 0 0 C reS APEN forms: h Application status: http://www.cdphe.state.co.us/ap/ss/sspcpt.html ment Information Section 04 — Amine Sweetening Unit Eaui m H Cn 00 z C s. N C O C C C) .o O 2 Manufacturer: 0 10 Reboiler Rating: a A ❑ N A ❑ Q 0. P O a 0 C In O In c o ' c 0 a. � U Q � ~ 0 ❑f3.3 a, a) a O 0 C ,0 a�0) Calendar year actual: • C .CC CE 00 000 C' an O 1/40 33 0 0 0 O 0 00 gml 00 U) C. Cd CO a ti a 0 f4) In 0) in o L ice. Loi ti U) h a 0. a, Rich Amine Feed: Lean Amine Stream: 00 \o In In Mole loading CO2: N O Mole loading H2S: d' wt. % amine: 0 0 0 0 O Cd in 0. In C\ Sour Gas Input: I C N a H C U) Zn a a a C z N In a) E H Cd N a 0 1/4O O COcn Cn 2 a a• o U C U ea e a O 0 O 0 Q.Q 06 lt Cd at U4 b O O 0. CI) SU Cr Cr CU L v fi 0 .G CU CU .C .C U 0 Zn U) U 0 C 0 trici a0 a < V) C 0 ,N U E C `'•.° 4Ci L .C 0 i- o N .0 CV a) ^ O 0 U c/51 N a) w g OD � x r+. o en 4 C U O ii a v o .o 0 ax E 0 a) U U ¢¢ C tV a C 0 'A M to CU �+ O 4) 4) Cl M) •..., E O O I •4 E y N a CJ 111 swis two V O .in •■S a F 440 S V C z ct I�1 E-4 H 1-4 d 44, Emission Source AIRS ID: 12WE1492 Permit Number: Section 06 Stack (Source, if no combustion) Location (Datum & either Lat/Long or UTM) Section 05 — Stack Information (Combustion stacks must be listed here) Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Easting or Longitude (meters or degrees) UTM Zone (12 or 13) 13 Horizontal Datum (NAD27, NAD83, WGS84) Moisture (%) F U '3y U Flow Rate (ACFM) Ew -o F- Stack Discharge Height Above Ground Level (feet) Stack Base Elevation (feet) Operator Stack ID No. H O d Other (Describe): O 0 ❑ Width (inches) = U 0 N 0 ❑ Cl U ® .. C C 4 U 4) C v N_ s ez u 4-0 U 4 tl 0 .C O .2 OD .E O O4 O 0 o •U a) Q W Circular: Inner Diameter (inches) = Section 07 — Control Device Information (Indicate if a control device controls the flash tank and/or regenerator emissions) l o Type: Thermal Oxidizer Make/Model/Serial #: TBD VOC & 1 -TAP Control Efficiency: Requested: 99 % Manufacturer Guaranteed: 99 % Minimum temp. to achieve requested control: 1400 °F Waste gas heat content: 30 Btu/scf Description: Describe Any Other: ...11lllata 'sat J' OLWIII IA! W"ilti "■ walla Sa0 V Wales Fs ■"■ F" !11 V-1. Uallata Wat TV III I Wall" V W II "rn/ • WTwf1 • n •_ • ••• • • . n a •nmen. • • ❑ ci ► l ❑ /s/ Type: Make/Model: Temperature (°F): Maximum: Average: Requested VOC & HAP Control Efficiency: °/l! Size: Make/Model: Requested VOC & HAP Control Efficiency: Annual time that VRU is bypassed (emissions vented): ❑ ❑ Section 08 — Emissions Inventory Information & Emission Control Information N I O N I- C O C) O Ut es O Ut O O L Z y se Ta 011 H C E L L 'fl C U C u C CJ C 4 F C 1°C Cs Cs s U GC C O C' C U v O ,0 v w C H Estimation Method or Emission Factor Source AP -42 1.4-1 +10% Simulation/AP-42+10% .11 AP -42 1.4-1 +10% AP -42 1.4-3+10% AP -42 1.4-3+10% Simulation + 10% Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted Emissions3 Controlled (Tons/Year) , Cr: N 3.6 O de minimis s!uuliquW ap to �.. O Uncontrolled (Tons/Year) O• •Co I-- N • M O ktolaq It Cn Actual Calendar Year Emissions2 Controlled (Tons/Year) Uncontrolled (Tons/Year) Emission Factor Units lb/MMscf lb/MMscf lb/MMscf v cos : r to., to lb/MMscf Uncontrolled Basis O O ^' N 1-I 84 N O O C in O Control Efficiency (% Reduction) Identify in Section 07 Control Device Description Primary Secondary Pollutant 0 z 0 > 0 Benzene U C as a f Ethylbenzene U O O x n -Hexane U U L L O U V C CC U L Ca a E 0 U C U a CC CO) at NC O .o y E H O C C O 0•o .) U ct En sos 'fl .[ HI o icnu .C E6 'ca Ts' O C Ly O U .OO C c ,O O .O .y Cti Asem E toiU w C ... s CC ; p, i ++ P4 8 tn pica ,g U Ctl L .o ct s Cu), 1 4 C to 5en 0 3b 'E .- U w o a N y cts *C •s U rj To g. u °a o\ tos U cr U resentative Staff EHS Re Jennifer L. Shea en O N C) • Name of Legally Authorized Person (Please print) C) 4-0 A y Authorized to Supply Data to 0-1 C) O w 0 2 CC U 0 'n w N 4- N Cd a 2 r a z w a a Q w 0 I- 0 z z 0 U) co 5 w I - z Q I - r J J 0 0_ rea w al m a is w 0 0 Nw Q M ii w I- re U 9 z 0 z (See reverse side for guidance on completing this form) i r D Number: cc a 12WE1492 Permit Number: Kerr-McGee Gathering LLC Company Name: N O U a _ -O C O U 42 CO C/� L L. ) C Co J Plant Location: 720-929-6028 Phone Number: Jennifer L. Shea Person to Contact: 720-929-7028 Fax Number: Jennifer.Shea@Anadarko.com mui Q) L. V -o .Fs E 1 w Controlled Actual Emissions (lbs/year) O) CO CO O N 10.8 (wit Uncontrolled Actual Emissions (lbs/year) O 1,644 (no TO) Emission Factor Source uogelnuais Simulation Emission Factor (Include Units) 0.40 Ib/MMSCF uncontrolled 0.0002 lb/MMSCF controlled 0.04 Ib/MMSCF controlled Control Equipment / Reduction (%) % for Ifatreat trols H2S I when usted with ?ates SO2) herma Reporting BIN Q Chemical Name Sulfur Dioxide Hydrogen Sulfide Chemical Abstract Service (CAS) Number 19 O r --- 7783064 c.‘! 0 iii a) Q a Q co co co D 46 Q o E L. 0 ct >- co o ^ W U CO O N CO O U) 'sr a) C co co 0 a a O N L O .C 45 Q Ct O) Q) J 0 L. ) Q) O Q) L 4-5 ) U) U) Staff EHS Representative Jennifer L. Shea December 4. 2006 Form Revision Date: AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — Amine Sweetenin O 1 to N r Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit # & AIRS ID] 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] ity Equipment ID: nested Action (Check applicable request boxes) Section 02 — Re Section 01 — Administrative Information Request for NEW permit or newly reported emission source .0 a C Sc 0 U 0 -G t U CS ee Ce Sc L. C) 0 O 4.0 Cl) 0" Change company name a) .5 Transfer of ownership ❑ ❑ Change process or equipment Change permit limit CO Request to limit HAPs with a Federally enforceable limit on PTE Request APEN update only (check the box below that applies) El DO M Company Name: Kerr-McGee Gathering LLC Source Name: Pc C 0 U 16116 WCR 22, Fort Lupton Source Location: "0-3 U t-- 00 P. O. Box 173779 Mailing Address: Denver, CO 80217-3779 a O a. 1. $ O E V Q. 0 4o cis O y .r yOy O Cd o o Wp� 0 Q • O U C u, j • � o E a o 0 U O '0 C44) r7 0 0 L C! C C) L CI) C d ea L ca O. C) fez H Ce L C) c C) N -C 0 Cur 4.4 C) S -O C ca ❑ ❑ 4.3 .. Li -oz so 720-929-6028 Phone Number: Jennifer L. Shea Person To Contact: 720-929-7028 Fax Number: Jennifer.Shea@Anadarko.com E-mail Address: Section 03 — General Information For new or reconstructed sources, the projected startup date is: For existing sources, operation began on: V H rn a� cis N O) L 0 a) c CS et; e O L' dl).0 'Sc .3 U N 0 Q o d 44 N O t ie .C 73 Xey fa eel 4-i 04 -as C so .0 N N Cl c, E 4) -w E o 4.1 a? E" Cex N y. C h C CO d C%.1C) PO CA to ed .C C) H C E c Qcv > Normal Hours of Source Operation: General description of equipment and purpose: c 5 x C C ❑ ❑ zz ❑ ❑ CA CA E El /attainmaintain.html he.statc.co.us/a U -c Cu C) C CO C 0 C G7 b 45 Cu L V 0. 0 45 V 0.. V CA • C ae a 0 L •; C -C C Cu s Cu C) Sc 1 0 C C) E Ca C. C) 0 Ca L 0 O V 4s O e71 N U) I -� S., L w u Ce Sc v s .as C 0 7:i E w cts C) C O L C Sc ea cn Ce O C O s.. O SQLtn d — o L. C L O a. V 00 Cgl i 0 Q V u C UQ�G For guidance on how to complete this APEN form: 0 In O co N MI en en aN cr. 000 M en en C:qtn v ca tb t; o •� I U U E -c I APEN forms: h he.state.co.us/a .0 U Application status: htt Unit Eauinment Information Section 04 — Amine Sweetenin C,, O I- a Cu L cip N C 0 C C Manufacturer: ral A 1/4O Reboiler Rating: a ❑ N C O C C If O N U) 70 U a. 4.4 O V) Design Capacity: Sweet Gas Throughput: Calendar year actual: O E E Met W OO 10 er U) 10 V) ,--( O 10 1,3 I 0 00 N bA Cd Cd Cl) O. o. M O U) 001 0 In O a a 0. CA CA P. a a U Rich Amine Feed: Lean Amine Stream: 00 10 */) Mole loading H2S: V) wt. % amine: N O O O it as Cd E E E en 01 t) O fr. Sour Gas Input: .N .N O 10 0 -14 Q Z w -O cr for to issuance. U U 4e5 U .0 0. 0 L O -1-•-a 00 0 00 0 U U O" 0 O. 0 w 0 0 .0.0 U 0 U U tit C 0 -, N U E ca t) 4-. E .T Ft ckt u N w O v xz u tu a) w o c t co)ikt O U •E E tu y UCL N E •E O c O g 'Es E a. w O 4-I C -a 10 : Ca O v, a ax 0 a a) o a) cs 4 O O U O 03 03 Q¢Q� MEMO 2013-04-05 FTL A-2 APEN.doc FORM APCD-206 C owl co °+4 o a) CI? Ca •- tit) E o O 4.4 int CO N a C fe rO, ‘.. trsi G cti Afe �j F-+ h, TT� r./ FBI CA H E Di4 O E O 4 Emission Source AIRS ID: 12WE1492 Section 06 —Stack (Source, if no combustion) Location (Datum & either Lat/Long or UTM) Section 05 — Stack Information (Combustion stacks must be listed here) e Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Fasting or Longitude (meters or degrees) UTM Zone (12 or 13) M 4.4 Horizontal Datum (NAD27, NAD83, WGS84) Moisture (%) Velocity (ft/sec) Flow Rate (ACFM) u° Stack Discharge Height Above Ground Level (feet) Stack Base Elevation (feet) Operator Stack ID No. N 0 Q Vertical with obstructing raincap U .C) Other (Describe): O Q ❑ Width (inches) _ Ct 0 .y .me Ca L _ O L. w u 0• +' N C W ❑ L O O C CC r.+ .C CM u rte-+ N O U u U C) O O cd • • cis U b C C O Cd E w as C.) L C O U N C u Circular: Inner Diameter (inches) = Exhaust Opening Shape & Size (check one): to y: Requested: 99 % Manufacturer Guaranteed: 99 % uested control: 1400 "F Waste gas heat content: 30 Btu/scf es 0 No Pilot burner rating: 8.0 MMBtu/hr ntrol of: atreat system to control acid gas vent prior to ATO-2. Sulfatreat will remove o+ H2S prior to combustion. Emissions will be routed to F-2 if TO is down n Device used for cc hermal Oxidizer HAP Control Efficienc: to achieve requ light? ® Yi system used for co Any Other: Suof 95/ ® Combustio Type: T VOC & Minimum t Constant pi O Closed loo Description O Describe O Condenser used for control of: Type: Make/Model: Temperature (°F): Maximum: Average: Requested VOC & HAP Control Efficiency: 3/0 O VRU used for control of: Size: Make/Model: Requested VOC & HAP Control Efficiency: Annual time that VRU is bypassed (emissions vented): Section 08 — Emissions Inventory Information & Emission Control Information O a 0 N C . C CQ ♦r O O. s L .C ar V1 Ct tit 0 a .o H C O CA C) L Ca C d ers 1.4 v cv s. w d ca A N Estimation Method or Emission Factor Source AP -42 1.4-1 +10;70-1 C?ieZ .- + N Z O E C,) AP -42 1.4-1 +10% AP -42 1.4-3+10% AP -42 1.4-3+10% O .— C . O E I= Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted Emissions3 Controlled (Tons/Year) O` t: 1O M vO ‘O de minimis siuuu!w op in .--. a Uncontrolled (Tons/Year) O; t: 350.7 '0 1/40 o a o a Jo et lei Actual Calendar Year Emissions2 Controlled (Tons/Year) Uncontrolled (Tons/Year) Emission Factor w CA CA S Ib/MMscf 9►. u h .O Ib/MMscf Ib/MMscf lb/MMscf Uncontrolled Basis O 0 imm. "I N .ti 84 w•I N G G t7 0 C 0.56 Control Efficiency (% Reduction) Identify in Section 07 Control Device Description Primary Secondary Pollutant O 4 O > O U Benzene a) C O F Ethylbenzene J Xylene n -Hexane C) L L CJ 'C C N L Ca 4J Ca E O u CA O Ca u _ cQ CM r Pt • vi as O ▪ r E go thCA o C u H c • .O Ct C0 E 'U CQ III as ch = 't7 O acol O g N E a)loos c� C a CI v45 O .C Ct. tiU o 'I y u Cu) u� g A � C eg .C O u ~ .fl .cn ^ c O .0 S W 3 •o win C 0 ▪ 'o E 2 C! N 7 CS di tI_ O1 resentative Staff EHS Re Jennifer L. Shea N ger U Ct a a) 45 E-' Name of Legally Authorized Person (Please print) 45 cd Q C4 0 • N ..C >, n (1) O I- Crs O sei C.) as ._ ) 2013-04-05 FTL A-2 APEN.doc O N 00 CC! A. 2 O z W O O w O H 0 z z O � O 2� W .E' H Z Q U o Ja c J O g O- L O Ce m D Q 0, a) w` Q3 CO ) a) a) Q ie 0 0 mow/ LL Ce w I- O I z 0 z 123/0057/064 (A-2) D Number: co Q 12WE1492 Permit Number: Kerr-McGee Gathering LLC Company Name: a) 13 O O a N a) 720-929-6028 L C op E U z a) 0 0 C as Plant Location: Jennifer L. Shea Person to Contact: 720-929-7028 Fax Number: Jennifer.Shea@Anadarko.com cn a) TLt V 13 .Ct E Controlled Actual Emissions (lbs/year) 0 Co co O N 10.8 (wit Uncontrolled Actual Emissions (lbs/year) 0 1,644 (no TO) Emission Factor Source C O to C o :,_, c5 u) CJ) Emission Factor (Include Units) 0.04 b/MMSCF controlled 0.0002 lb/MMSCF controlled Control Equipment / Reduction (%) % for Ifatreat trols H2S when usted with gates SO2) D% hermal Reporting BIN Q Chemical Name Sulfur Dioxide Hydrogen Sulfide Chemical Abstract Service (CAS) Number in 0) 0 Nt- il- N- 7783064 O N Data Applies: Q 0 -2 O as >- a) cU 0 as U M O N 0 L C U 0) C a CC CO Y ) a) 0 (73 CU a a Ca O N 0 C Q 1/41 CO a) J C W 0 4- O _ a) _215 (.7). J Staff EHS Representative Jennifer L. Shea Form Revision Date: December 4. 2006 I• AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — Amine Sweetenin CD O 5- U) O N 01) O N O L 0 C 3 -v U C w I- u • 073 N n N Ii G -- w C E •.C a A C, s a w OC b Ccc' 0.0 d Emission Source AIRS ID: 12WE1492 Permit Number: M Q Facility Equipment ID: uested Action (Check applicable request boxes) Section 02 — Re Section 01— Administrative Information Request for NEW permit or newly reported emission source d 0. 41 ea C4 s Is O d .O O .O s co Ca a> C. d s v Is ar C. co O 0 a lac Change company name I. a> O O Transfer of ownership ❑ ❑ Change process or equipment Change permit limit ❑ ❑ Request APEN update only (check the box below that applies) 0 O Company Name: Kerr-McGee Gathering LLC Lancaster Plant Source Name: 16116 WCR 22, Fort Lupton Source Location: O I U N N O cc b O N P. O. Box 173779 Mailing Address: Denver, CO 80217-3779 0 C C .O cel u aU) b C U U d F c> U, O 0 O. L. O I OD O W y c .73 O U . 14 >4 aEi U Uri 'O O a2 L d O L C O -z W 0 < L 4. a> C CO U O b0 H L CA U CC O at 3 a, N cu C .01 ca F4) y Etu y L h ca a, x N O E U s i+ -a C ❑ ❑ C 'a 720-929-6028 Phone Number: Jennifer L. Shea Person To Contact: 720-929-7028 Fax Number: nadarko.com Jennifer.She E-mail Address: Section 03 — General Information CO 0 rt. .d P.. U) 4- U, U) O U, E C O U O 0 C 4" O w 1 a> C .E 4) a, h d C .cc a> s Is L O d C O C a'a OA L. o u .� L 3 0. CD M 4-0Q Sc Q o 5. = N .C k O AO Ca it y cc 1/4O y .�L to C .O E — esi O 3 w IN a> Cw om 3 y N L E 'O E N „ CA rn Da H C a. Ir CC 41411O 3 c o bu c CU to •E _ N Q > General description of equipment and purpose: 0 0 O 0 ❑ ❑ zz ❑ ❑ in en 00 t C E C cc he.state.co.us/a tt Sc ► Will this equipment be operated in any NAAQS nonattainment area? C C) C O L .; a 'v C 0 .C a.. arts. a> .- — O Z ao oU C C O O O c. AQ O .a CS L O 0 U o ,c 0 E ati LO 00 g Hi _ wm cd c � � C U E Ia. U >°�3 ac 'S .- a) 'O .' o ._ a) t"oo V Ccu C1. cod a) "''a 0 Ems-' 0) .. O O ON N L w a v .C Cd CC Sc C _o CS E w Ua Is c d C O ScCid CS m x C~ O C a> t O. d G Sc c L 0 0 U Fog v 4 Sc 4' O U Acu �c U0 L Q �U s.• ssu U S= a, er For guidance on how to complete this APEN form: O 'n M N as 1/4O M O e Air Pollution Control Division: O co M N 1O M O M Small Business Assistance Pro In M N O` 1O en M O cA .O R O so he.state.co.us/a O APEN forms: h t Application status: htt Section 04 — Amine Sweetening Unit Eauinment Information E - z CS U C 0 C C U) O Manufacturer: to u O N A O Vo Reboiler Rating: a Q ❑ N 0 O y P. a O 0 C ccs rn Calendar year actual: E E CT CD In N o0 rte. w O O O 00 In Mole loading CO2: cd o cn 0 0 U C O z O O NN covut If) PI 4::: O IS a a a O at al C I-64 C4 Irrit a o. O b a 0. o. a o o u a u F • F- E"i 4> F- H H Mo OA cal .cO cO act al a a. a 04 a. 0. O en co In ON CA a 0 0 0 a a a U) Rich Amine Feed: Lean Amine Stream: wt. % amine: 0 C. tn s- CCS O C. c z for to issuance. O O .0 x U U s U a) U 0 U S O L. O 2 O x O x U U s U 00 y a O Cn UU' 0 g a O 023 NI .o N w a zx 412 CB U o c 0 v' U E� r-IU" O c cz vii CO "C) U731 •c Gr' .C 5 r.) o ( o o g 8 a 3 0.) Oa 17 °O_� CA O � u O o'er, a X O. U O U co i-.. U rO. 0000 0000 2013-04-05 FTL A-3 APEN.doc N w O 14 0-4 C N O LA tO .rte.+ O CID •rat- LA CO ¢ O I Li M Li N a O.. .j.d V rn L Vl O v V L. b °ocn 12WE1492 Permit Number: Section 06 —Stack (Source, if no combustion) Location (Datum & either Lat/Long or UTM) Section 05 — Stack Information (Combustion stacks must be listed here) 2 N .. o'- Velocity (f/sec) Flow Rate (ACFM) te, w uV h Stack Discharge Height Above Ground Level (feet) Stack Base Elevation (feet) Operator Stack ID No. M O Q Other (Describe): 4-4 O N I- O O ❑ its u J C O a a> u •_ O emu, a C) a) tttuto u a 4a C3 � s o N .S4 o c Q w Width (inches) = a) i 0 Circular: Inner Diameter (inches) = Section 07 — Control Device Information (Indicate if a control device controls the flash tank and/or regenerator emissions) of: Still Vent and Flash Tank Rating: 16.7 MMBtuthr Make/Model/Serial #: TBD Requested: 99 % Manufacturer Guaranteed: 99 control: 1400 °F Waste gas heat content: 30 Btu/scf f: Sulfatreat system to control acid gas vent prior to ATO-3. Sulfatreat will remove 95%+ H2S prior to combustion. Emissions will be routed to F-3 if TO is down ❑ �d for control dizer fficiency: eve requested 0 Type: Thermal Oxi VOC & HAP Control E Minimum temp. to achi /,1 ❑ ►,1 Type: Make/Model: Temperature (°F): Maximum: Average: Requested VOC & HAP Control Efficiency: °�° Size: Make/Model: Requested VOC & HAP Control Efficiency: Annual time that VRU is bypassed (emissions vented): ❑ ❑ Section 08 — Emissions Inventory Information & Emission Control Information O N N O N bD V V O a a Sc L s H Cyr 0 u C O E L S a V S u It V It L Ct as A Estimation Method or Emission Factor Source AP -42 1.4-1 +10% ISimulation/AP-42+10% AP -42 1.4-1 +10% AP -42 1.4-3+10% AP -42 1.4-3+10% Simulation + 10% Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted7 Emissions3 Controlled (Tons/Year) lz M 1/4.0 de minimis de minimis a Uncontrolled (Tons/Year) a; 350.6 ‘o 0 a) .O nnolaq J 17'SI Actual Calendar Year Emissions2 7.) Ii U E4 Uncontrolled (Tons/Year) 7---- Emission Factor CaV) C Ib/MMscf Ib/MMscf o lb/MMscf o Vi .O u Cl) F. .O Uncontrolled Basis p O ` 84 N 0 In Control Efficiency (% Reduction) Identify in Section 07 Control Device Description Secondary a. 0 Pollutant x 0 Z DOA 0 Benzene 1 w c C -6 Ethylbenzene Xylene n -Hexane vi C O • y uo i 6 C 0- O C U C y o C `c v II O C y .r u• a) la O 1v g C - .y E a0) ai e° u 7 � U N V 0 2A Cacn • o g a 5 O u h C 'in ti) En .o •E cn o .ti 0. 'v ii information contained herein and information submitted with this application is complete, true and correct. resentative Staff EHS Re Jennifer L. Shea en O 0 4- Name of Legally Authorized Person (Please print) a) V N O 1 O M O N N O N 4) O1) Ct 0. 5 0 Z W O 0 Q W U H 0 z Z 0 cn W H Z a I J 0 N. a w m a I- 0 ce w Q ce ce I U I z 0 Z (See reverse side for guidance on completing this form) 123/0057/065 (A-3) D Number: Q 12WE1492 Permit Number: Kerr-McGee Gathering LLC Company Name: a) O U N -C3 C) C 0 U Lancaster Plant 0 Ct J (t3 0 720-929-6028 Phone Number: Jennifer L. Shea Person to Contact: 720-929-7028 Fax Number: Jennifer.Shea@Anadarko.com E-mail Address: Controlled Actual Emissions (lbs/year) O Co co O (Ni 10.8 (wit Uncontrolled Actual Emissions (lbs/year) O (no TO) Emission Factor Source O co Simulation E Emission Factor (Include Units) O w 0.40 lb/MMSCF uncontrolled 0.0002 lb/MMSCF controlled o ho . 2 L o2E no Control Equipment / Reduction (%) )5 % for ulfatreat ntrols H2S nd when busted with :mates SO2) ;% hermal Reporting BIN Q Chemical Name Sulfur Dioxide Hydrogen Sulfide Chemical Abstract Service (CAS) Number L O 9 7783064 N 0 N 4) Calendar Year for which Actual Data App 0 N 0 (13 st- U (I) CD 0 Q M 0 N Z1: 0 C Staff EHS Representative ('3 Ri C > -o Q U) O a) N O Q c13 a) C 0 0 Q) F- a Co 4- its Q a 0 4- W N C O 4- Q ('3 N J 0 1/2. 0- 0 Q) (6 z December 4, 2006 Form Revision Date: AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — Amine Sweetenin Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit # & AIRS ID] 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] 4 Facility Equipment ID: uested Action (Check applicable request boxes) Section 02 — Re Section 01 — Administrative Information Request for NEW permit or newly reported emission source Request MODIFICATION to existing permit (check each box below that applies) Change company name Transfer of ownership ❑ ❑ Change process or equipment Change permit limit O 0❑ ❑D N M O Ch ¢U Z c Kerr-McGee Gathering LLC Company Name: Lancaster Plant Source Name: "C a C 0 U 16116 WCR 22, Fort Lupton Source Location: U C44 O en N C 00 U •0 0 N P. O. Box 173779 Mailing Address: Denver, CO 80217-3779 Revision to actual calendar year emissions for emission inventory D ❑ 720-929-6028 Phone Number: Jennifer L. Shea Person To Contact: 720-929-7028 Fax Number: nadarko.com Jennifer.She E-mail Address: L E d z 4,0 le 1 CU 7.4 C • .o bA 1„L el d � c 3 >, .--. N �+ C R ea et 0. Fa, � H E +u+ t L cn C cia N .C x O E C s "C C as Section 03 — General Information For new or reconstructed sources, the projected startup date C C 6 .C 0 Cs s- e.) 0.0 •L s 0 O s L s = >i Cp4H cn x b° a V 3 w N 0 0.e °) a)> 3 E L cd 40.+ 0.E) N DJ) 7.3 II N Alt lt O 4 O 0 0 to 4-. O 0 C O it _ .C O u L w O a L N 0 O 74 E Ut C) s .1.. 0 d-1 C C it .0 E O OS a, .41 it C Z y cc "C C CC u Cc H C 6) General description of equipment and purpose: Don't know Don't know ❑ ❑ 0 0 zz ❑ ❑ 00 C C co C o C�3 he.statc.co.us/a .C ► Will this equipment be operated in any NAAQS nonattainment area? ► Does this facility have a design capacity less than 2 long tons/day of H2S in the acid gas? Provide documentation. C C C C "C C CC s ♦-. cc C C Lim O 4- C a, E CC C. C cc L O 0 U a Q C O L C 0 O O •Q 45-0) • C. w .O U «1 .0 Co U 1-4 44-4 r V1 f-" O 4- 0\ In I CA L W U a) s u C bA C O 4 E w 4- et .v C C O L U. C s w S Cr Ofti PC cl.. O 4- C co S as 0. co Cc O O U lat A Q s 4- _ O C L. Ain ca Q vet 00 H For guidance on how to complete this APEN form: 0 In Cr) N ON M O M .10 C 0 C 0 0 a a 0 00 M N ON M O M 0 C) v y it it it U C N cit Co in N r1 N 0\ O M he.statc.co.us/a V s hc.statc.co.us/a Section 04 — Amine Sweetening Unit Eauinment Information C O C a C a -o 0 Manufacturer: 1/40 Reboiler Rating: ❑ N 0 2 0 ❑ O? F 0, .C C O to Design Capacity: Sweet Gas Throughput: Calendar year actual: C CCc at caS 04.1 0 P. 0 0 \0 t() 00 N ..r on al ct 0. .0. .0. 0 in CS ON o 1.4 Smt O O IPS 0 O 0 a a, a 45' C Rich Amine Feed: Lean Amine Stream: 00 '.O V) to Mole loading CO2: 0 a it wt. % amine: O try 1--I 4.0 0 0 0 r-1 U C 0 z 0 0 w I.U. o as as as 0 0 E H E cc cc 0. O. P. en C\ Sour Gas Input: 0.. C a z Flash Tank: a; 0 a • 0 C .0 rn C 0 O 0 0 •04-..� .. tad cad -0.0 O O 0 0 U U C) Cr' 0 0 .0 a V U U 00 0 0.. w C O U, h C) cd a C i g -8 b E a o o t U ,E O H 0.0 v4 ••-• U U C C 0 a) U g U O H n (1,3szi N w CU zC �x � a' 4-. cgd >41 one 0 ya y `'.3 "Cr X w � U (� E " gC -o U = U U L� 60 C 'o 0 -o o E0) U 4- U U U 0000 FORM APCD-206 • - co w .te' • � role E co I tai Ech a r o u 4n rC O • n et a ICI CA Emi 4 Emission Source AIRS ID: 12WE1492 Permit Number: Section 06 —Stack (Source, if no combustion) Location (Datum & either Lat/Long or UTM) 0 4) ate) 4J pa E 0 U) .0 O C O w et L w 4-4 U L C U C) in Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Easting or Longitude (meters or degrees) UTM Zone (12 or 13) M Horizontal Datum (NAD27, NAD83, WGS84) U O ta C) A o < LLB'' I- o 0z0 Oct wtt 0 Q O Vertical with obstructing raincap O U •E IZI Direction of stack outlet (check one): Circular: Inner Diameter (inches) = Exhaust Opening Shape & Size (check one): Section 07 — Control Device Information (Indicate if a control device controls the flash tank and/or regenerator emissions) i Iii O Type: Thermal Oxidizer Make/Model/Serial #: TBD VOC & HAP Control Efficiency: Requested: 99 % Manufacturer Guaranteed: 99 Minimum temp. to achieve requested control: 1400 Waste gas heat content: 30 Btu/scf Description: Describe Any Other: V Yisati GAL J, Jtfr.l. tV GVALtS V. 401%.1l3=4167 •Gut Ni iv. LV Al trw• V7u{1Ati Gat ..all; G.i1V.V II A -A/ . Wia,.• I • n .•• • r. . .•..-.A • ❑ ,1 ❑ -1 Type: Make/Model: Temperature (°F): Maximum: Average: Requested VOC & HAP Control Efficiency: Size: Make/Model: Requested VOC & HAP Control Efficiency: Annual time that VRU is bypassed (emissions vented): Section 08— Emissions Inventory Information & Emission Control Information N 0 N .• N O O N bD aT O It i• C. Z OS L h bt 0 d h C O H L ce C U u cc u ca L C.I ca cc C Estimation Method or Emission Factor Source AP -42 1.4-1 +10% Simulation/AP-42+10% AP -42 1.4-1 +10% AP -42 1.4-3+10% AP -42 1.4-3+10% Simulation + 10% Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted Emissions3 Controlled (Tons/Year) ON N 3.6 \D c) siw�u�W ap siw!uiw ap la cam c Uncontrolled (Tons/Year) Os 350.7 O az Atolaq Ili Actual Calendar Year Emissions2 Controlled (Tons/Year) Uncontrolled (Tons/Year) Emission Factor .� u FFF v U lb/MMscf Ib/MMscf 1�U Uncontrolled Basis CO O a•N rl Il 0O 84 rl Cl C O £00'0 \O In C Control Efficiency (% Reduction) Identify in Section 07 Control Device Description b O U E a Pollutant xOfl DOA U IBenzene 4) C H Ethylbenzene U 4) XC Q) x vi O 'Eoo U O 1 VI O C as O U y O O (11 CC) 43) CI. N 0 it � O p w CPI Ca .c • E O •o cii o cn eg c C) V1 C O col col 3W b Ito C 0 - •- b E V, a u u moo. eV e.. a C., Ca L O U C ca u C L I. r•a C) a E O •r • X4.1 Ct U •may a C 47 s 'C 4� S E C U) C S E X1-1 C 00 .� L cIa 4a r.+ O tons C • M E N e C S C • C S Qa CJ 4-6 ett �.d C • Q a' O resentative Staff EHS Re Jennifer L. Shea 4) S Name of Legally Authorized Person (Please print) 4) A e of Person Legally Authorized to Supply Data 01) V) 2013-04-05 FTL A-4 APEN.doc 2 C z W 0 0 a W U H O z z O � LO CO W -4• !) ' !— Z E < U O D N J " J -a O e A L i� O Ce w Q co a) ((IT; J CO < a) (Sn �-- O 0 NW Lim N� Y� W I U z 0 z 123/0057/066 (A-4) D Number: Cl) Q 12WE1492 Permit Number: Kerr-McGee Gathering LLC Company Name: Q N C) C O U C 0- Ct U C _J Plant Location: 720-929-6028 Phone Number: Jennifer L. Shea Person to Contact: 720-929-7028 Fax Number: Jennifer.Shea@Anadarko.com E-mail Address: Controlled Actual Emissions (lbs/year) CA CO CO 0 N 10.8 (with TO) Uncontrolled Actual Emissions (lbs/year) 0 k4 (no TO) Emission Factor Source Simulation Simulation Emission Factor (Include Units) 0.40 Ib/MMSCF uncontrolled 0.0002 Ib/MMSCF controlled 0.04 Ib/MMSCF controlled Control Equipment / Reduction (%) % for Fatreat rols H2S I when isted with gates SO2) )% hermal Reporting BIN Q Hydrogen Sulfide Chemical Name Sulfur Dioxide Chemical Abstract Service (CAS) Number LO 0 ict- - 7783064 CJ O N C) a a Q Co Co 0 Q 0 CO a) Co 0 Reporting Scenario (1, 2 or 3): CO CD V J .Q) co 0 Co I. C6 0 a CO O - o N O L Signature of Person Lega Staff EHS Representative Jennifer L. Shea Ct CO 0 a Q (/) 0 a) N O Q Title of Person Lega C L a (f) CCo a) 0 - Co Co 0 Q a U) O a) N C O Q O) C O 0 4- a) Co z December 4, 2006 Form Revision Date: onent Leak Emissions AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — Fu tG O N Emission Source AIRS ID: 2 [Leave blank unless APCD has already assigned a permit # & 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] Facility Equipment ID: nested Action (Check applicable request boxes) Section 02 — Re Section 01 — Administrative Information Request for NEW permit or newly reported emission source i jfl U DC O a, a) to dnn N O 0 4' O V S 'Do Change company name Change process or equipment 0 Transfer of ownership Change permit limit Request APEN update only (check the box below that applies) 00 O I— 0,0 cj 0 UU zN Kerr-McGee Gathering LLC Lancaster Plant Source Name: .fl 0 U 16116 WCR 22 Source Location: C.) a) 11-4 O M O 0 co ai Fort Lupton, CO N O co O p.. P. O. Box 173779 Mailing Address: Denver, CO 80217-3779 O 0 V) 0E) t- 0 U) O C) So C a) ≤d U 03 a Cad 0 C 0 L� ❑ ❑ 720-929-6028 Phone Number: Jennifer L. Shea Person To Contact: 720-929-7028 Fax Number: nadarko.com Jennifer.She U) U) 0 .o E W Expansion fugitive emissions Section 03 — General Information A H For new or reconstructed sources, the projected startup date is: 0 N CA C O .y aQ tik .r as as W N C .•r L C O C �oa 4. C cc a. L 4. 013 u C cc C C O C. O U a) U) a) b C) U 0 4-4 Ct 4' C a) C)) O C O 0. U y 0 •o 1 CO 4' C C O L C .O C CC s 4' cc C O w O 4' C C ca d U A 0 CC L O O V o a, o E .L 0. L .0 4 5 O red .r %. .^ o Cn C U N . +-r E >' O Q O 4. O C' In L w u a) Z u aC s 4' C O CC E L w 4' ca 4' C C C O L .≥ C W 04 4' `CI w O 4' C mod) E cc a d A .O ac L O 0 V Sc O d s"... en A I it L NO OD I L' (A c,U VCU; Vo a'to o For guidance on how to complete this APEN form: 0 N '0 M O M Air Pollution Control Division: b.. 0 oo in — en en I I N N ON ON NO VD O O e e Small Business Assistance Program (SBAP): he.state.co.us/a -O v APEN forms: h rn Ca he.state.co.us/a Application status: htt 3 5,3 7-3 ❑ ❑ ❑ z0 0 ❑ ❑ ❑ en cid 4' C a, fCr. a ea zcd E .E -0 cC 0 0 O ti .o cr Ca, .- U a. 3 a) `O 3 4I Information L O ca Section 04 — Re Is this equipment subject to NSPS 40 CFR Part 60, Subpart KKK? Is this equipment subject to NESI-IAP 40 CFR Part 63, Subpart HH? 40 CFR Part 60, Subpart OOOO Subpart that applies to this equipment: List any other NSPS or NE Section 05 — Stream Constituents n -Hexane (wt %) 0 vi 0 c, o\ o CaC c . >-, X O 14 C o O n O Ethylbenzene (wt. %) O CO 0 '1: O (% '4A+) auanioi O "fie 0 5.5 0 Benzene (wt. %) O .N� O O N O oe • 22,100 2 CT 2 0 L I U) Cc l", Heavy Oil (or Heavy Liquid) Light Oil (or Light Liquid) Water/Oil Check box to request copy of draft permit prior to issuance. Check box to request copy of draft permit prior to public notice. ®® Ca C 0 cC U U C 0 Ca ti .E. t O 0. ti 0 W m C C) C CO To .b v So C 72, x a, Sc to U C a) a a cd cn 2013-04-05 FTL FUG3 APEN.doc 5- O N rao Att C onent Leak Emissions AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — Fu 0 Emission Source AIRS ID: 12WE1492 Permit Number: & Control Information rX Section 07 —Leak Detection & Re Section 06 — Location Information (Provide Datum and either Lat/Long or UTM) pei 0. 0. C1 Q' \' e o'o `" w U > > 0 •" 4 O �� > 2 0 0etts OD 0 \ 0 o°Ot'-• ` 0 •• b 3 ° U U on c cn CL ❑ o 2a 0 E Method of Collection for Location Data (e.g. map, GPS. GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Easting or Longitude (meters or degrees) I UTM Zone (12 or 13) M P, Horizontal Datum (NAD27, NAD83, WGS84) Section 08 — Emission Factor Information 0 _o C? .0 L 0 v w C h H E z v O C: a. O E � U w. y et CD a 4.16-- In au t.., y ^ui U it .5. O OD C se 1.4 ,Or a�7 �. o i _s o o ego w y :Elj0 o� 4. 0 V) � Q f.L V) 4.1 0 O v coa E N V 0 d a L 0 0 Catwo v. 0 O a N_ tV .= N �U c 75 F Water/Oil shun W luno� M shun •3.3 iluno3 (pinbri lggl'I .to)1!O 1gfri V .; 821 719 33 O In en 28 Heavy Oil (or Heavy Liquid) �I Q) 4- 0 LC C 0 488 45 15 vD ON it Units Cl) CC (7cw W O O U 1630 744 1487 78 Equipment Type Connectors Flanges Open -Ended Lines Pump Seals N > ) O Estimated Count O C 0 a rg U p tits E a. 0 O o co) 0 .c. •� 0 O CC a. a. o w o C 0 F --I L 7 C rd CN G ~ N C o 0 0 W .0 F 0 4g 0 U Estimation Method or Emission Factor Source EPA 453/R-95-017 Tables 2-4 & 5-3 + 10% Variance Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. I Requested Permitted Emissions3 Controlled (Tons/Year) OIli M 0 - 1-•� de minimis O 1'Z Uncontrolled (Tons/Year) *f? C, 10 0 .0 Cr; ____.1f) Actual Calendar Year Emissions2 Controlled (Tons/Year) Uncontrolled (Tons/Year) Emission Factor Identify in Section 08 Uncontrolled Basis Control Efficiency (% Reduction) Identify in Section 07 Control Device Description c� b O U O C4 E 4--` tits = o a DOA Benzene 0 o = o F, Ethylbenzene C o X' IL n -Hexane o: 0 0 U U VI w C _ 0 'a .cti •3 cn y .11 b 0 Q I N G 0 C)) O • CT •r M. 0 O. a. 0 .0 •--� U • y00 '0 w 0 C cn ,3 0 cat 8o 1U O 70. Ho 4.1 O •— v U% 0 0 n0 °) ccn O • CA `" O ca U N B' UU eC C 0 C Oct' V1 ,t, .o C U 0 Cl, ) a a O y c. Ott d.• U V L L O C) 0 cc as L 4- as E O C 04 03 .C 'C as 4- H C O cc E w C �C R C .C) L as a) OS C 6% C 4- cc E W cc rird `V as U 1, s 1 cis U 4- cc • 'to u as resentative Staff EHS Re Jennifer L. Shea en N H Name of Legally Authorized Person (Please print) son Legally Authorized to Supply Data Cl n 2013-04-05 FTL FUG3 APEN.doc AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — General co co O O N r Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit # & AIRS ID] 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] W Facility Equipment ID: uested Action (check applicable request boxes) Section 02 — Re Section 01 — Administrative Information U v L 0 wit tit C O 0 as 0 L is E 3 L a, a) C ci. L U O L 0 CA L Das W d z a 0 Q~ H V) CP CD Cr' Cr Cg C4 U C. C. O Cu Sc •ice O C .0 K O .0 -C u 0 a) u as s U a) C. C U 0 CD iro 0 Change company name L a) .a N O Transfer of ownership ❑ ❑ Change permit limit ❑ Request to limit HAPs with a Federally enforceable limit on PTE Request APEN update only (check the box below that applies) ®❑❑ O a) .74 Co N a) C a 3 an o ei o v) 0 C '0 U U a) zc w Kerr-McGee Gathering LLC Company Name: Lancaster Plant Source Name: 16116 WCR 22 Source Location: Fort Lupton, CO (:= Go C) 0 U a N PO Box 173779 Mailing Address: O C C) C ..-. 0 •N ++ COa) LL cS o U a• � .- 0 U) U 0 0 I- .a >, c C) W o_ CU y d > E 0 C O O co .y Ct .> t O imits or previously ❑ ❑ Denver, CO 80217-3779 720-929-6028 Phone Number: Person To Contact: 720-929-7028 Fax Number: nadarko.com Jennifer.She E-mail Address: Train I process flare .. H 4.O z Section 03 — General Information MO .- 52 weeks/year 00 s 4.1 O w O bA tri Cu L h CuA H H O U 0 L C. •0 C L CC) N 0 a. 0 Cu L H Cu Ca Ca i- a C. CO r a tn O w 0 CA C ,- C 3- c. Sc C) L Cu C d U O L C. d Cfl .y H L _ General description of equipment and purpose: C as C O L • a C fa 0 " ACA x A O o• U C 'Sc 0) O to L ..-i elS -61 0 d 0 St Cu L 0 0 U O a) .-. ^d O c ts▪ ..� 6( bp -46 . a) U Cn ._. •• tU in .fl C rA a) a E ^ • O o. ' an > 112 o > w .cn "" 0 0 u. U C Q' tit o • it 0 . tr :a xU ' c (— 'Cr .. 4- L (4- a u ar Sc U Cu 4- .tin C 0 Cu E tits :.C - R Sc D 0 C en Atn .S LN 0 U� L AUa C� M aCi QetQ For guidance on how to complete this APEN form: 0 In M N M 0 M O oc,nE izt•�s N as as w O O C APEN forms: htto://www.cdnhe.state.co.us/a Application status: http://tnvw.cdphe.state.co.us/ap/ss/sspcpt.html • C 0 0 o 0 O 0 a) 'v 4.)v oo Tel 4 a; u a) a) 3 ten> ment Information & Material Use w /Manufacturin Section 04 — Processin 0 z C .0 O z w -0 0 2 Manufacturer: a) 04 O a o O C a� eat 0 • A cn C •U a) 85.4 MMscf/yr C ed ¢0 w C 0 0. U U) a) Q Process & purge gas Other Process: Check box to request copy of draft permit prior to issuance. Check box to request copy of draft permit prior to public notice. 00 > O • 5 CL Vo ' OC O g 0. c • O U -o 5. y C1. Q o N O 0 .. C (11 aCr 1.54 t it a,.4-• a a o U N .fl tA a N C •O ▪ 0 C▪ CS 41) 2013-04-05 LAN F-2 APEN.doc N 4-. O .--. a) on a FORM APCD-200 AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — General CD CO N Emission Source AIRS ID: 12WE1492 Permit Number: I-- L O 00 O cd 411.1 E a) O Q N a) a) a) S.. a) E 4-. O O czt 4-4 a) a) ..r .E a) Lt a) a) a) tt tad O rn cC C ,O w U d (/) Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Easting or Longitude (meters or degrees) UTM Zone (12 or 13) M Horizontal Datum (NAD27, NAD83, WGS84) Moisture (%) C) OU O �o Flow Rate (ACFM) N 'C N U ca O Discharge Height Above Ground Level (Feet) 40 Base Elevation (feet) Operator Stack ID No. r F-2 r ❑ Other (Describe): C N O O Width (inches) = O Other: Length (inches) = f U C$ O OA C U II Oth• e 3 � A U ❑ C u U z Direction of outlet (check one): Exhaust Opening Shape & Size (check one): tion Information E U) C V ment & Fue Section 06 — Combustion E A gla A cia E4 H Manufacturer: Company equipment Identification No.: Seasonal Fuel Use (% of Annual Use) Sep -Nov 25 25 Jun -Aug 25 25 Mar -May 25 N Dec -Feb 25 in ei 7ercent by Weight .C Sulfur Fuel Heating Value (Indicate: Btu/lb, Btu/gal, Btu/SCF) 1020 Btu/scf 1275 Btu/scf Annual Requested Permitted Level' (Specify Units) 1.22 MMBtu/hr 10.9 MMBtu/hr Actual Level (For Data Year) Design Input Rate (106 Btu/hr) el N O' O Fuel Type Natural Gas Process Gas next five year V O O ob to CA O O. cn 8 O u cr C4 fa. O aui =Requested values wi Information Section 07 — Emissions Inventory Information & Emission Control N O N n O O N O .O Cd O. Sc 0.0 O .C O T• 5. C O L CC C d u C 3 It C2 L V C w C Cit V d Sc O i Cu C d D V O A ♦O.. V a w Ft z Estimation Method or Emission Factor Source AP -42 1.4-2 AP -42 1.4-2 Mass Balance a w O E- AP -42x22% voc TCEQ Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested Permitted Emissions4 Controlled (Tons/Year) M M O M %.0 4D Uncontrolled (Tons/Year) M O 0.3 O M `'G it Actual Calendar Year Emissions3 Controlled (Tons/Year) Uncontrolled (Tons/Year) Emission Factor Units U .C lb/MMscf y, et 00 .a 1 b/MMBtu co .C Uncontrolled Basis 7.6 O O 00 en G co O 0.2755 Control Efficiency (% Reduction) Overall Collection Efficiency Control Device Description Secondary E a Pollutant 7) O f1000 P. a, En Q Z Q OD N O • y U, u O 4-• • O ar4 C' O U C U O `n .o ,c d .d C0 .a Q d � cn • CA .S Q C!S H al a U en cd tt O y . o .U, cn C �'N .� 3 � u - 4-4 C • u y (I) C.0.. u `n u u information contained herein and information submitted with this application is complete, true and correct. resentative Staff EHS Re Jennifer L. Shea en nip N Name of Legally Authorized Person (Please print) 2013-04-05 LAN F-2 APEN.doc O i AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — General CO ILO O N Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit # & AIRS ID] 12WE1492 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] M w Facility Equipment ID: uested Action (check applicable request boxes) Section 02 — Re Section 01 — Administrative Information Request for NEW permit or newly reported emission source Request PORTABLE source permit Request MODIFICATION to existing permit (check each box below that applies) ® ❑ ❑ M 0 0 vi zrA Company Name: Kerr-McGee Gathering LLC Lancaster Plant Source Name: 16116 WCR 22 Source Location: Change company name I. a) O ❑ Transfer of ownership ❑ D Change fuel or equipment Change permit limit ❑ ❑ U U Fort Lupton, CO Request to limit HAPs with a Federally enforceable limit on PTE a. a Cu Cu s w 0 d .o p! O .O co s a u U s u >i C O C) Cu V a. -4404 W Q H C. a 0 N O Go 0. N PO Box 173779 Mailing Address: U) a O C) I-. O. I.. O E a) c1. tu os s U C g I E W O N E a) 'tri o a ❑ ❑ Denver, CO 80217-3779 720-929-6028 Jennifer L. Shea Person To Contact: 720-929-7028 Fax Number: adarko.com Jennifer.Shea E-mail Address: Train 2 process flare Section 03 — General Information For new or reconstructed sources, the projected startup date is: i t C 4- O' O w O bD _ 4- L U) ti b0 CO U) u O L C L N O 4.. O bA 4- L co) b0 C) bQ L O. L el 0 tit O LI L 0 t Cl a) cfs In O. (s) WI IA H N•Q C O O .o '++ o 0 (ISO 0 o vi O (:) O U Of o -x X � S Lr O C14 General description of equipment and purpose: C a) C L C C .C 4- <a a ._ s O l... C U E a d A .O Cu L O O U O O •Q W .O U U cd co 5 Cn C 0 rns 3 � >` o O. srs cr u c) (4-1c) r O tn <44 O 0 I. V O. 'CI O C cC C3' C eu O O a In L W U u w .DJ) C O Cu tom h Z • 444 -40+ C Iv C O L C S w O 4- C a) E a A .O Cu L 0 O U ch U a t 4- O d L n A a I L vet NO U00 iii O In en N O' \O M O M 0 0 C O a O a 0 R Q I-. O 00 M N O' M O M t-- en N as vD M O M .,c vi E Cu O O he.state.co.us/a APEN forms: h Application status: htt 4-0 C O N • r• 3 •I s ment Information & Material Use /Manufacturin Section 04 — Processin 4- C U 0. cr U 0 C s. U U O O z z O Manufacturer: N tu a n. O its 85.4 MMscf/yr C O a co c) A Process & purge gas U os h 0. lb 0 Cu w E a C .0. 0 4) tn ... N U 'd Cr' tu tn v 13 N Other Process: 2013-04-05 LAN F-3 APEN.doc N 4- O bA CZ a O N am Att U O AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — General CD O 10 O N Emission Source AIRS ID: 12WE1492 Permit Number: Section 05 — Emission Release Information (Attach a separate sheet with relevant information in the event of multiple releases; provide datum & either Lat/Long or UTM) Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) UTM Northing or Latitude (meters or degrees) UTM Easting or Longitude (meters or degrees) UTM Zone (12 or 13) M al Horizontal Datum (NAD27, NAD83, WGS84) Moisture (%) Velocity (ft/sec) 0 VO Flow Rate (ACFM) a 1/44"N N a 0. O E Ii -fl.) v O Discharge Height Above Ground Level (Feet) 40 Base Elevation (feet) Operator Stack ID No. M ❑ Other (Describe): C 0 0 Ct U Direction of outlet (check one): Width (inches) = Other: Length (inches) = O M Exhaust Opening Shape & Size (check one): tion Information ment & Fuel Consum Section 06 — Combustion E O H Manufacturer: M I w Company equipment Identification No.: Seasonal Fuel Use (% of Annual Use) 0 2 in [ sZ U C/) Jun -Aug 25 N Mar -May 25 25 U V U O in 25 Percent by Weight ¢t C C) Fuel Heating Value (Indicate: Btu/lb, Btu/gal, Btu/SCF) 1020 Btu/scf 1275 Btu/scf Annual Requested Permitted Level'` (Specify Units) 1.22 MMBtu/hr 10.9 MMBtu/hr Actual Level (For Data Year) Design Input Rate (106 Btu/hr) N . C' o Fuel Type Natural Gas Process Gas Information 30. 023 O U O O Cc E w C H C a) S C O .- H H N O V a) U) ..C .. N O O (14 Ca4 ai 0 .0 CC 'C tht s CJ 0 .0 CI) C 0 CO ca 4.. ►A' Estimation Method or Emission Factor Source AP -42 1.4-2 AP -42 1.4-2 Mass Balance a LU U E-. AP -42x22% voc I a w U F- Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. 1 Requested Permitted Emissions4 Controlled (Tons/Year) M O M Oa O M h 'O i-• A Uncontrolled (Tons/Year) Actual Calendar Year Emissions' Controlled (Tons/Year) Uncontrolled (Tons/Year) Emission Factor Units lb/MMscf � X .C Ib/MMBtu PI O Ib/MMBtu Uncontrolled Basis ‘JD r 7.6 II O M no O £0.0 0.2755 Control Efficiency (% Reduction) Overall Collection Efficiency Control Device Description Secondary a Pollutant TSP O a h o.4 X CO xOINI DOA OD CJ V L O C.) .O C Cl L a? a) 0 O Cl V a Cl now at .O C ▪ o Vl .Lr N• . rU , vo co) 2 O i', O • C ate) 7.7; CO C CoC) `" .o .- O U . w tcg �? .9 • a p 0 ▪ o .C ei 434 a) .C � E . 173 VI 0 sig j O C C O ✓ .0 C C O Cl.C C L 00 CS U ti 'C U U Cu 'Co - t Cl C. 2 0 >> o L • u U ^t .Q g V en .0 C a ~ tU C C O rn Cl C. ) t L a p U oC a C CO H ty O U � — U � 0 d C ar. 00 r resentative Staff EHS Re Jennifer L. Shea a) Name of Legally Authorized Person (Please print) a) Ct A A I O O a) on � U) 2013-04-05 LAN F-3 APEN.doc 0 n cc! a Attachment C The Lancaster Plant PSD Net Emission Increase Calculation December 19, 2012 (updated March 12, 2013) I. Introduction As pertaining to Regulation 3, Part D, Section II.A.2, a project is a major modification for a regulated NSR pollutant if it causes a significant emission increase (Step 1) and a significant net emissions increase (Step 2). This document explains the logic and determinations utilized to develop the Lancaster Plant (Lancaster) project PSD applicability analysis. Kerr McGee Gathering LLC (KMG) updated this analysis to incorporate the NSR Reform provisions (2002 rules) which were approved into Regulation 3, Part D. Process Description The Fort Lupton Gas Plant (Fort Lupton) and Platte Valley Gas Plant (Platte Valley) are currently operating at maximum capacity and no increased throughput or processing capabilities are expected at either plant with the start-up of Lancaster. Fort Lupton is currently bottlenecked by the refrigeration plant which is also operating at maximum capacity. Any gas sent to the refrigeration plant is dehydrated in the north and south dehydration units and there is no improvement scheduled for Foil Lupton's existing refrigeration plant. Plane Valley is currently bottlenecked by the residue compression used to send gas to the discharge pipeline. There are no plans to increase compression capacity at the plant. A new 24" inlet pipeline will be constructed concurrent with the commencement of the train of Lancaster to deliver gas to the proposed plant along with gas off the existing high pressure (HP) pipeline. Fort Lupton units 36 and 37 are scheduled to be shutdown with the start-up of Lancaster Train 1 and Unit 35 will be shutdown with the start-up of Train 2. Units 36 and 37 boost inlet gas from 100 psi to about 200 psi and discharge directly into the intermediate pressure (IP) pipeline. As development of the basin continues and new formations are produced, the function of these units is no longer required. Unit 31 and 35 currently boosts inlet gas from about 100 psi to 1100 psi and discharges into the HP pipeline. Five additional inlet 3,750 -hp electric motors driving reciprocating compressor will be installed as part of this project to feed the HP pipeline. This additional compression eliminates the need for Units 31 and 35. II. Step 1— Significant Emission Increase Calculation KMG utilized the actual to potential test as defined in Regulation 3, Part D, Section II.B.2 to determine if a significant emission increase of a regulated NSR pollutant is projected to occur. All new equipment proposed for Lancaster was included in the calculation as shown in Table 1 below. As pertaining to Regulation 3, Part D, Section II.A.24.e, fugitive emissions were not included in Step 1 since Lancaster is not a source category listed in Section II.A.24.a.(i). Page 1 Table 1: Lancaster Plant Step 1 PSD AppNcabiNty Determination Unit ID NON CO VOC CO2e SOZ PM 2.5 Lancaster Project C-4100 Solar C40612,000 -hp Electric Drive Motor, Residue - - - - - - C-4200 Solar 040612,000 -hp Electric Drive Motor, Residue - - - - - - C-4300 Solar 040612,000 -hp Electric Drive Motor, Residue - - - - - - C-4400 Solar 040612,000 -hp Electric Drive Motor, Residue - - - - - - C-5110 3,000 -hp Motor, Refrig - - - - - - C-5210 3,000 -hp Motor, Refrig - - - - - - C-5310 3,000 -hp Motor, Refrig - - - - - - C-5410 3,000 -hp Motor, Refrig - - - - - - C-5510 3,000 -hp Motor, Refrig - - - - - - C-5610 3,000 -hp Motor, Refrig - - - - - - ENG 105 3,750 -hp Motor, Inlet Compression - - - - - - ENG 106 3,750 -hp Motor, Inlet Compression - - - - - - ENG 107 3,750 -hp Motor, Inlet Compression - - - - - - ENG 108 3,750 -hp Motor, Inlet Compression - - - - - - ENG 109 3,750 -hp Motor, Inlet Compression - - - - - - E-2015 Mole Sieve Regeneration Gas Heater with Ultra Low NON Burners 5.2 5.2 2.5 15,252 0.1 1.0 E-2016 Mole Sieve Regeneration Gas Heater with Ultra Low NON Burners 5.2 5.2 2.5 15,252 0.1 1.0 H-6051 Heat Medium Heater with Low NON Burners 13.5 13.5 1.8 39,421 0.2 1.7 H-6052 Heat Medium Heater with Low NON Burners 13.5 13.5 1.8 39,421 0.2 1.7 H-6053 Heat Medium Heater with Low NOx Burners 13.5 13.5 1.8 39,421 0.2 1.7 H-6054 Heat Medium Heater with Low NOx Burners 13.5 13.5 1.8 39,421 0.2 1.7 A-1 150 MMSCFD Amine Treater (Controlled with ATO-1) 7.9 6.6 3.6 94,121 1.1 0.6 A-2 150 MMSCFD Amine Treater (Controlled with ATO-2) 7.9 6.6 3.6 94,121 1.1 0.6 A-3 150 MMSCFD Amine Treater (Controlled with ATO-3) 7.9 6.6 3.6 94,121 1.1 0.6 A-4 150 MMSCFD Amine Treater (Controlled with ATO-4) 7.9 6.6 3.6 94,121 1.1 0.6 F-2 F-2 Lancaster Plant Process Flare 1 7.3 14.6 1.6 6,220 0.03 0.32 F-3 F-3 Lancaster Plant Process Flare 2 7.3 14.6 1.6 6,220 0.03 0.32 GEN3 Caterpillar 839 -hp Diesel Emergency Generator 2.6 0.2 0.0 172 1.5 0.1 Lancaster Project Emission Increase 113.1 120.2 29.9 577,286 6.7 11.8 PSD Significance Threshold 40.0 100.0 40.0 75,000 40 10.0 Step 2, Net Emission Increase Determination Required? Yes Yes No Yes No Yes The new emission units proposed for Lancaster will cause a significant emission increase of NOx, CO, PM2_5 and CO2e emissions. Therefore, as required by Regulation 3, Part D, Section I.A.2, KMG will determine if the proposed project will result in a significant net emission increase for NOx, CO, PM2.5 and CO2e in Step 2 below. III. Step 2 — Significant Net Emission Increase Calculation To determine if Lancaster will cause a significant net emission increase, one must sum any increase in actual emissions from the proposed project and any other increases and decreases contemporaneous with the proposed project as pertaining to Regulation 3, Part D, Section II.A.26. These increases and decreases are known as Step 2 in the PSD applicability determination. Contemporaneous Period The contemporaneous period for this project was defined as required by Regulation 3, Part D, Section II.A.26.b. The Lancaster Plant project consists of two trains with a phased construction period. Train 1 is Page 2 expected to start operation on January 1, 2014 and Train 2 is expected to start operation on January 1, 2015. Therefore, KMG defined the contemporaneous period as January 1, 2009 to January 1, 2015. Contemporaneous Emissions As shown in the net emission increase calculation of Table 2 below, there were nineteen (19) increases and decreases that occurred in the defined contemporaneous period. Five (5) of the identified emissions decreases listed below were deemed not credible as defined in Regulation 3, Part D, Section II.A.26.f.(ii) due to the fact that the old level of actual emissions did not exceed the new emission level (PTE). An updated Title V permit was never issued for the modification requested below. The facility is operating under the permit shield of the July 3, 2002 9.5OPWE013 Title V permit. 1. ENG 33, 123/0057/004, 6/30/2009 submitted Title V modification to decrease horsepower. 2. ENG 36, 123/0057/005, 6/30/2009 submitted Title V modification to decrease horsepower. 3. ENG 37, 123/0057/006, 6/30/2009 submitted Title V modification to decrease horsepower. 4. ENG 35, 123/0057/007, 6/30/2009 submitted Title V modification to decrease horsepower. 5. North Dehy, 123/0057/021, 12/21/2011 construction permit issued to decrease thermal oxidizer combustion temperature. Nine (9) of the identified emissions increases listed below, calculated the projected actual emissions utilizing the source's potential to emit (PTE) emissions as required by Regulation 3, Part D, Section II.A.36.a. These new (9) new sources started up or are expected to start-up during the contemporaneous period. 1. ENG 103, 123/0057/026 — Began operation on 2/15/2009. New permit issued on 10/4/2011 to increase fuel use. 2. South Dehy, 123/0057/027 — Began operation on 3/12/2009. 3. GEN2, 123/0057/029 — Began operation on 9/28/2011. 4. ENG 104, 123/0057/028 — Began operation on 10/1/2011. 5. PLVGEN, 123/0057 — APEN submitted on 1/30/2012. 6. H-ST2, 123/0057 — APEN exempt heater (Regulation 3, Part A, Section II.D.1.k) began operation on 11/5/2012. 7. S009, 123/0057/056 — Amine unit thermal oxidizer began operation on 11/8/2012. 8. H-ST3, 123/0057 — APEN exempt heater (Regulation 3, Part A, Section II.D.1.k) not yet built. 9. H-ST4, 123/0057 — APEN exempt heater (Regulation 3, Part A, Section II.D.1.k) not yet built. One (1) of the identified emissions decrease listed below, calculated baseline actual emissions as defined in Regulation 3, Part D, Section II.A.4.b by selecting the highest annual average based on a consecutive 24 month period, except Section II.A.4.b.(iv) does not apply for contemporaneous increases and decreases as stated in Regulation 3, Part D, Section II.A.26.a.(ii). The baseline actual emissions were calculated for the removal of Unit 102 based on 1/1/2005 to 12/31/2006 actual emissions. 1. ENG 102, 123/0057/024 — Engine shutdown on 4/30/2009. Page 3 One (1) of the identified emissions decrease listed below, was not included in the contemporaneous emissions because fugitive emissions as defined in Regulation 3, Part D, Section II.A.24.e, shall not be included in determining for any of the purpose of Part D, whether it is a major source. Lancaster is a gas processing facility and is therefore, not one of the named categories in Regulation 3, Part D, Section II.A.24.a.(i) or a source category as of 8/7/1980 regulated under Section 111 or 112 of the Federal Act. 1. FUG, 123/0057/018 — Decreased fugitive emissions in Permit 00WE0583 from actual component count. One (1) of the identified emissions increase listed below, calculated projected actual emissions utilizing the source's potential to emit (PTE) emissions as defined in Regulation 3, Part D, Section II.A.36.a.. The baseline actual emissions were calculated as defined by Regulation 3, Part D, Section II.A.4.b by selecting the highest annual average based on a consecutive 24 month period, except Section II.A.4.b.(iv) does not apply for contemporaneous increases and decreases as stated in Regulation 3, Part D, Section II.A.26.a.(ii). The baseline actual emissions were calculated based on the sources 12/1/2010 to 11/31/2012 actual emissions. The net emission increase = projected actual emissions (PTE) - baseline actual emissions. 1. S021, 123/0057/053 - On 7/20/2012 requested to increase gas to flare volumes and modify emissions. Permit has not been issued. Four (4) of the identified emissions decreases listed below calculated baseline actual emissions (BAE) as defined by Regulation 3. Part D, Section II.A.4.b by selecting the highest annual average based on a consecutive 24 month period. One consecutive 24 month period was selected for each regulated NSR pollutant. The period selected for NOx was 4/1/2008 to 3/31/2010 and the period selected for CO, PM2.5 and CO2, was 1/1/2003 to 12/31/2004. The CO BAE for ENG 35, ENG 36 and ENG37 were adjusted as per Regulation 3, Part D, Section II.A.4.b.(iii) due to controls installed in 2007 as required by the May 17, 2007 KMG Consent Decree. 1. ENG 31, 123/0057/013 as 1/1/2015. 2. ENG 35, 123/0057/007 - 1/1/2015. 3. ENG 36, 123/0057/005 - 1/1/2014. 4. ENG 37, 123/0057/006 - 1/1/2014. — Engine will be removed upon start-up of Lancaster Train 2, estimated Engine will be removed upon start-up of Lancaster Train 2 estimated as Engine will be removed upon start-up of Lancaster Train 1 estimated as Engine will be removed upon start-up of Lancaster Train 1 estimated as One (1) contemporaneous emissions decrease not included in the analysis was the control of the Platte Valley amine unit with a thermal oxidizer (123/0057/043). The emissions off the still vent of the amine unit were questioned during a 12/23/2010 CDPHE inspection. The unit was installed in 1997 and was never found to be out of compliance during the fourteen (14) years it had operated. The previous owner was asked to perform an emissions test which was completed on 4/21/2011 after the ownership transfer to KMG. Results were submitted to KMG on 7/18/2011 and a permit application to control the amine unit was submitted on 2/5/2012 after engineering design was completed. The amine unit was controlled on Page 4 11/8/2012 and to date, not final construction permit has been issued for the source. Therefore, KMG did not include this emissions decrease as a contemporaneous source. Net Emission Increase Calculation The net emission increase was calculated as required by Regulation 3, Pail D. Section II.A.26 by summing the increase in actual emissions of NOx, CO, PM2.5 and CO2, from the proposed Lancaster project (Step 1) and the emissions increases and decreases within the defined contemporaneous period (Step 2). As shown in Table 2 below, the proposed Lancaster project will not cause a significant net emission increase in NOx, PM,_5 and CO emissions but will cause a significant net emission increase in CO2, emissions. Therefore, since the proposed project results in a major modification for CO2e, a BACT analysis for Greenhouse gases is required. Page 5 Table 2: Lancaster Plant: (Step 1 + Step 2) Net Emission increase Calculation Unit ID AIRS ID Permit # Contemporaneous Change Date NOx CO COZe PM: 5 Contemporaneous emissions increases and decreases from 112009 to 112015 (Step 2) ENG 103' 123/0057/026 07WE0798 Added Unit 103; Increase Fuel Use on 10/4/11 211812009 30.4 7.6 18519.4 1.4 South Dehy' 123/0057/027 07WE0799 Started up 3/12/2009 311212009 3.13 6.3 2728.6 0.03 ENG 1022 123/00571024 03WE1152 Engine Shutdown 413012009 -13.9 -9.9 -5788.4 -0.5 ENG 333 123/0057/004 11WE730-1 De -rated from 2166 -hp to 2046 -hp 613012009 ENG 363 123/00571005 11WE730-2 De -rated from 2166 -hp to 2046 -hp 6/3012009 ENG 373 123/00571006 11WE730-3 De -rated from 2166 -hp to 2046 -hp 613012009 ENG 353 123/00571007 11WE132 De -rated From 1859 -hp to 1756 -hp 6/3012009 FUG° 123/0057/018 00WE0583 Emissions decrease due to component count 8/4/2010 GEN2' 123/00571029 10WE1587 Started up 9/28/11 9/28/2011 0.6 U. U N U A i + i EU 104' 123/00571028 10WE1071 Started up 10/1111 10/1/2011 32.0 8.0 20575 0 1 4 North Dehy3 123/0057/021 01WE0764 Decrease combustion temperature 12121/2011 r PLVGEN' 123/0057 APEN Only Added PLV PLC Genset 1130/2012 0.0 1.2 N/A i i. u H-ST21 123/0057 Exempt Added 5 MMBtulhr Condensate Stabilizer 11/5/2012 1.8 4.2 3660.5 0.23 S009' 123/00571043 12WE1277 Platte Valley Amine Unit Theraml Oxidizer 111812012 6.5 5.5 7076.4 0.50 H-ST3' 123/0057 Exempt Add 5 MMBtulhr Condensate Stabilizer TBD 1.8 4.2 3660.5 0.23 H -S141 123/0057 Exempt Add 5 MMBtulhr Condensate Stabilizer TBD 1.8 4.2 3660.5 0.23 S0215 123/0057/053 02WE0927 Increase Platte Valley Gas to Flare TBD 7.8 15.7 5017.1 0.0 ENG 31` 123/0057/013 97WE0180 Remove engine upon Train 2 start-up 1/1/2015 -15.7 -42.3 -3345.8 -0.5 ENG 35` 123/0057/007 11WE132 Remove engine upon Train 2 start-up 1/1/2015 -51.4 -12.6 -5106.0 -2.1 ENG 36` 123/0057/005 11WE730-2 Remove engine upon Train 1 start-up 1/1/2014 -67.3 -14.2 -6231.8 -2.5 ENG 37` 123/0057/006 11WE730-3 Remove engine upon Train 1 start-up 1/1/2014 -81.5 -13.6 -5981.9 -2 Proposed Modification Project Emissions (Step 1) E-2015 NA 12WE1492 Mole Sieve Regeneration Gas Heater with Ultra Low NOR Burners 1/1/2014 5.2 5.2 15252.3 1.0 E-2016 NA 12WE1492 Mole Sieve Regeneration Gas Heater with Ultra Low NOR Burners 1/1/2015 5.2 5.2 15252.3 1.0 H-6051 NA 12WE1492 Heat Medium Heater with Low NOx Burners 1/1/2014 13.5 13.5 39421.2 1.7 H-6052 NA 12WE1492 Heat Medium Heater with Low NON Burners 1/1/2014 13.5 13.5 39421.2 1.7 H-6053 NA 12WE1492 Heat Medium Heater with Low NOx Burners 1/1/2015 13.5 13.5 39421.2 1.7 H-6054 NA 12WE1492 Heat Medium Heater with Low NON Burners 1/1/2015 13.5 13.5 39421.2 1.7 _ A-1 NA 12WE1492 150 MMSCFD Amine Treater (Controlled with ATO-1) 1/1/2014 7.9 6.6 94121.3 0.6 A-2 NA 12WE1492 150 MMSCFD Amine Treater (Controlled with ATO-2) 1/1/2014 7.9 6.6 94121.3 0.6 A-3 NA 12WE1492 150 MMSCFD Amine Treater (Controlled with ATO-3) 1/1/2015 7.9 6.6 94121.3 0.6 A-4 NA 12WE1492 150 MMSCFD Amine Treater (Controlled with ATO-4) 1/1/2015 7.9 6.6 94121.3 0.6 F-2 NA 12WE1492 F-2 Lancaster Plant Process Flare 1 1/1/2014 7.3 14.6 6220.0 0.3 F-3 NA 12WE1492 F-3 Lancaster Plant Process Flare 2 1/1/2015 7.3 14.6 6220.0 0.3 GEN3 NA 12WE1492 Caterpillar 839 -hp Diesel Emergency Generator 11112014 2.6 0.2 171 5 0 1 Step 1 + Step 2 -31.0 84.4 615,730 7.8 PSD Significance Threshold 40.0 100.0 75,000 10 Step 2, Does project cause a significant pet emission increase? No No Yes No ' Emission increase reflecting potential to emit emissions as defined in Regulation 3, Part D, Section II. A. 36. a Z Emissions increase calculated using highest annual average based on 24 consecutive months as per II.A.4.b, except II.A.5.b.(iv) does not apply as per II. A. 26.a.(ii). (January 2005 to December 2006) 3 Emissions decrease is not credible since the old level of actual emissions does not exceed the new level of emissions as per Regulation 3, Part D II.A.26.f.(ii). ° Fugitive emissions not included; gas plant is not a named sources as per Reg 3, Part D, Section II.A.24 6 Net emission increase = projected actual emissions as defined in Regulation 3, Part D, Section II. A.36. a (PTE) - baseline actual emissions as defined in Regulation 3, Part D, Section II.A.4.b, except II.A.4.b.(iv) does not apply as per II.A.26.a.(ii). Used 12/112010 to 1113012012 to calculate baseline actual emissions. `Baseline actual emissions calculated as defined in Regulation 3, Part D, Section II.A.4.b. Consecutive 24 -month period defined as NOx =4/2008-3/2010; CO, PMZ.5 and CO2e 1/2003 to 1212004; BAE adjusted for period prior to 2007 to reduce CO by 58% on ENG35, 36 and 37 to reflect controls installed per KMG consent decree. Page 6 Fort Lupton Gas Plant Actual Emissions for Netting Analysis 0B EE I Il,S@' 9@IIii;II �I VilggVIIII;IllgifilizilgIIIVIIIIVII 9 �� f �a =�= �« 'oi l!'!lIIIlI�l1��I!! �i:��E °�e ��e�� s�-:i��eiii::�lB��IIIIIIIaII ��:!! 9S 19 LS :� i@ Elinli@�ilni iiP9 i[ilFii 9l riai-1i-iErit rl n +iDi8i3[- II III! 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PS§Ni:� el0p0Q.0002�ny 1Sw�:a� n - O - 00Q0 F5$ Y0 Dn-00•Nnn 11••0V 0 AedNiist�o8 0Q04nN0• 3g 3g 828829= Singsasaia;tana$o8R$7 Z$rie 878$3888 o.0anfN'dann^-205}0 7i8$R8P$PSaSRR9k840g D' <-- N. C Ea T g 2 4-N h N N h N N N N n h f N f N n n Ned n N n N n N n 0 N N no" 01 N nnn NNN n N N N N N NC* N N- N N N N -- N N A4-0000000 Ned N NN N - -- in n d ej-n Lancaster Plant Actual to Potential Emission Increase from a Modification WY .; C lLancaster flint Proposed Emissbns <7 a fe, O M O t^. O r: N % r V m d N 9 L) C a d D— 000o O O O O 0 O O 0 O P m N m • 00 0 O 0 O 0 0 C 0 0 0 0 0 0 0 0 0 0 0 G 0 0 C 0 0 G 0 0 C . . o O 664 r f _ .- Lo- n 9 el 9 0 G li p 4 90'0 - 9 c m 9 8 a , ? Z Q 4 0 Io S Z V ? 0 0 0 0 N 0 0 N 0 0 N 0 0 N 0 0 0 0 0 0 0 0 0 c - . a CO 0 V td cO CO ei L CO ri r r i Total HAPS - - 0 0 0 o 0.03 r, 0 0 0,03 0 el 0 r O r-- 0 0 o - O p O r IC g r' r '1 all Y O 5 a a ^^--^ O I` A N! A r 8$$ 0 0 0 3 0 11 0 07 0 H 0 r _( O Q .71_ K N H f O N O00000-, N N N N ll 0 O 0O 0 in -= 0 9 O 9O94° a a m 94 rJ - - N 0 N �i N N Y'1 39,421 N f t0+) 39,421 N f g.15; eq^ m m rq' at _ a, O H (0 O N ,6 o f 4 tnf ei ip O :ring O el G. 1 "L.1C.n 3.6 3.6 3.6 .0 n 5.2 N WI in u] 13.5 o m 03 IQ lC <V 0.2 Sri H (D r .Y 4 /7 10 Q xN 9)f) N Y9 H9 ei �(i ei in � 4'i Q) 1� Cl I. a h a) h en h Cn 1� al N h r IQ CIIQ4 (Q .-(7 q 0 t Ia C R 03 P m3 C €0 C 03 03 C C 03 R m3,0 P P m0 K •3 C 03 P I,31A C I,2 C C 03 C 0, C 02 c0 C C m0 C I,20, C C 8 03 8 m 8 c0 C (0 8 C 02 03/0 C C C W C /a ITotal EmmaIons from Modltcatlon aRI CO 888888888888888888888888888889iR a a a a a a a a¢ a a a a a a a a a a a a a a a a a a a a nPi REMOVE 0 Solar 0406 12,000 -hp Electric Drnre Motor, Residue Solar C406 12,000 -hp Electric Drive Motor, Residue Solar C406 12,000 -hp Electric Drina Motor, Residue Solar C406 12,000 -hp Electric Drhe Motor, Residue cr b P ei 3,000 -hp Motor, Refrig 3,000 -hp Motor, Refrig 3,000 -hp Motor. Rettig 3,000 -hp Motor, Refry cc b P 3,750 -hp Motor, Inlet Compression 3,750 -hp Motor, Inlet Compression 3,750 -hp Motor, Inlet Compression 3,750 -hp Motor, Inlet Compression 3,750 -hp Motor, Inlet Compression Mole Sieve Regeneration Gas Heater with Uta Low NOx Burners Mole Sieve Regeneration Gas Heater with Uta Low NOx Bunters Heat Medium Heater with Low NOx Burners Heat Medium Heater with Low NOx Burners Heat Medium Heater with Low NOx Burners Heat Median Hester with Low NOx Bumers 150 MMSCF D Amine Treater (Contoled with ATO-1) 150 MMSCFD Amine Treater (Controlled with ATO-2) 150 MMSCFD Amine Treater (Contoled with ATOM) 0 I - Y 8 t 1 Ts I- g 0 in F-2 Lancaster Rant Process Flare 1 F-3 Lancaster Pal Process Flare 2 Caterpillar 839 -hp Diesel Emergency Generator Plant Fugitives Waukesha L7042 954 -hp Fairbanks Morse MEP 10 38O8750-15S1S 1756 -hp Fairbanks Morse 38DS8MEP-12 2046 -hp Fairbanks Morse 38D8780.28S1 S 2046 -hp O 949Z 0 � 8 O 0 9 0 0 Z O 0 O 0 Ivi 0 0 `2 O 0 A O 0 22 0 0 O ENG 105 ENG 106 I ENG 107 I ENG 108 co 0 w in (?4,1,888844.k w iD w= r h t 42') t 3 t _ T Q ILL LL rPz) ffi 0 5 LL Iii 41; j w In el 3 w l, j w el j w )veld )al5F3Uef 2013-03-12 LAN Factity Emissionsxlsx COLORADO GREENHOUSE GAS (GHG) FORM & CALCULATION TOOL Reason for Submittal: GHG Syn Minor Plant AIRS ID: 123+0057 Permit Number(s): 12WE 1492 O CE cc U) Z 16116 WCR 22 Source Location: 0 c 2 C7 C Y 2 c0 d 8 Report Major GHG Src Fort Lutpon, CO Co m d m 5 J 2 (n B O Brief Facility Description: Gas Processin CO2 Equivalent (tons per year) vs , 7 N _7 cD O 2 CO ai CAD CI c� 2 co Cl cD N corn 01 o) OD 23 [ 39.383 cD N to 00 co t� °p op to 2 co t2 OJ M Nie4 co :.c: Cl t0 2 C co 9J ch to T N UP N 'Q Tr ry (D N V' to Tr < Q) .- I- O O Lc) r) 00 to `. t a S J 15,237 CD C7 el N tri --co CD CD NCO} 00 tT CD 23 t��p 00 O co (D M N 39,383 CO 23 tc�+��y ej Q) et, CD CJ N tt((�� u) to c0 O O el to u) to06 co co N up 85.585 co N C4 O el �? to CO N 1[7 O in Ln 6,214 N [ 6,214 N V to 944 1- .- O O u: en N co In Potential To Emit (tons per year) P_c 15,237 O O [ 15,237 I O O tco rrn? A r O pep r. M r O t )) rm? M r O el r. M O OD t�l? a0 CO tu) co O O cl �? 2 OD tul co. O O LI) �? 2 Go ul a0 O O l u. 2 a0 tu, a0 O O C N co O O V N to O O L.Ts. O O 0 n r- a 2 g 15,237 NO O O 15,237 X382n0`oanO2r116 0 0 n CI 0 0 n ch 0 0 n N) 0 0 dnO n C7 0 0 jN`.2ORN co to CO 0 0 wi l(J co- 0 ONNcRgRC4 0 co 24 to a0 0 0 tD a0 0 s 0 C N c0 ' 0 O 0 6,213.87 :2Oi2 0 0 4 W11SHO 4 0 0 N in C C _gym CDoa 0 CC o000000g0oggoobg000gogoggoogooggooggo*b000000 o00000000000000000000000000000000000000000000 �p �p GHG Control Method Description mm%a �D7 O T.) 005 ct a O l N^ 0 N 0 N 0 c''1 N 0 el N 0 co N 0 M^^ 21 0 21 O 07._,_ NeD O .— N 0l£ .— ,_ N O c:-) ^ _ N O c:-) ^ 1— N^ r N =. 7 GHG Emitted: Chemical Name (Select from drop -down list) Carbon dioxide I Methane j Nitrous oxide I Carton dioxide , Methane Nitrous oxide 12 x b U 4) 2 Nitrous oxide [ Carbon dioxide Methane [ Nitrous oxide I Carbon dioxide Methane I Nitrous oxide j Carbon dioxide a) 2 Nitrous oxide Carbon dioxide Carbon dioxide Methane Nitrous oxide Carbon dioxide 32 x 'C 0 Methane I Nitrous oxide Carbon dioxide 32 x 'C C. O Methane Nitrous oxide Carbon dioxide Carbon dioxide a) 2 Nitrous oxide 32 x '00 0 [ Methane Nitrous oxide j Carbon dioxide [ Methane Nitrous oxide 4 x 'C 2 O Methane Carbon dioxide y 2 § Nitrous oxide Brief Equipment Description E-2015 Gas Heater E-2015 Gas Heater E-2015 Gas Heater IE-2016 Gas Heater E-2016 Gas Heater E-2016 Gas Heater H-6051 Heat Medium Heater IH-6051 Heat Medium Heater IH-6051 Heat Medium Heater IH-6052 Heat Medium Heater IH-6052 Heat Medium Heater IH-6052 Heat Medium Heater H-6053 Heat Medium Heater H-6053 Heat Medium Heater IN -6053 Heat Medium Heater IH-6054 Heat Medium Heater H-6054 Heat Medium Heater H-6054 Heat Medium Heater A-1. Amine Treater 1 Train 1 IA-TO1, Train 1 Thermal Oxidizer 1 IA -T01, Train 1 Thermal Oxidizer 1 IA -T01, Train 1 Thermal Oxidizer 1 A-2, Amine Treater 2 Train 1 A-TO2, Train 1 Thermal Oxidizer 2 IA-TO2, Train 1 Thermal Oxidizer 2 A-TO2, Train 1 Thermal Oxidizer 2 IA -3. Amine Treater 3 Train 2 j A-TO3, Train 2 Thermal Oxidizer 3 A-TO3, Train 2 Thermal Oxidizer 3 A-TO3, Train 2 Thermal Oxidizer 3 A-4, Amine Treater 4 Train 2 IA-TO4, Train 2 Thermal Oxidizer 4 IA-TO4, Train 2 Thermal Oxidizer 4 IA-TO4, Train 2 Thermal Oxidizer 4 IF -2 Process Flare, Train 1 IF -2 Process Flare, Train 1 IF -2 Process Flare, Iran 1 F-3 Process Flare, Train 2 F-3 Process Flare, Tran 2 IF -3 Process Flare. Train 2 FUG3, Fugitives IFUG3. Fugitives GEN3 Generator (GEN3 Generator GEN3 Generator G O (n a CC Cr Jennifer. Shea _-9Anadaiko.com Email Address 720-929-7028 720-929-6028 Phone Nurnbe Person to Contact: Jennifer L Shea Jennifer L. Shea Date of Signature Signature of Person Legally Authorized to Supply Data Name of Person Legally Authorized to Supply Data (Please Prnt) resentative Staff EHS R Title of Person Legally Authorized to Supply Data C 0 d a` le � E W L • Y r a) g .0 000��D ]+ W V s2 co O O • a7 a' u0 a7 i. s � pU L a a d c r a CC if) i9 2 m y Va DW 17 aa) D O S'- to 8) as • s o 2 w 0 C yO J2 2 o m N 5 gts C c 8- d .G t o g m y 3 O o a Vy co N H J nyN N V a) C.) C.) N u 1- W r O z FORM APCD-500 • Fort Lupton Gas Plant Engine Detail Sheet Source ID Number Source Description Engine Usage Engine Make Engine Model Serial Number Manufacture Date Date in Service Maximum Rating Fuel Heating Value Heat Rate Engine Heat Rate Engine Heat Rate PTE Emissions Caterpillar C18 DITA TBD TBD TBD 839 GEN3 Lancaster Plant Diesel -Powered Standby Generator Engine Power Emergency Generator - EPA Tier 2 Potential operation Displacement Potential fuel usage BHP 18.390 Btu/lb 5.86 MMBtu/hr 6988 Btu/hp-hr lb/hp-hr 0.38 Stack ID Stack Height Stack Diameter Exit Velocity Exit Temperature Volume Flow Rate 500 3.0 19950 39.9 GEN3 hr/yr L/cyl Gal/yr Gal/hr 10 ft 0.67 ft 215.4 ft/s deg F ft3/min 969 4,552 Pollutant Emission Factor I Rating Operating Hrs Estimated Emissions I Source of Emission Factor (lb/MMBtu) I (g/hp-hr) (hp) (hrs/yr) (Ib/hr) I (tpy) NOx CO VOC SOx PM10 PM2.5 HAPs HCHO Benzene Acrolein 1.75 5.56 839 500 10.3 2.6 Manuf. Data 0.11 0.35 839 500 0.6 0.2 Manuf. Data 0.00 0.01 839 500 0.0 0.0 Manuf. Data 1.01 3.20 839 500 5.9 1.5 AP -42. Table 3.4-1 0.057 0.18 839 500 0.3 0.1 AP -42, Table 3.4-2 0.056 0.18 839 500 0.3 0.1 AP -42, Table 3.4-2 7.89E-05 7.76E-04 7.88E-06 Acetaldehyde 2.52E-05 Propylene 2.79E-03 *Used HC emission factor 0.00025 0.00246 0.00002 0.00008 0.00884 839 839 839 839 839 500 500 500 500 500 CO2e Emission Calculations Conversions: 1 Metric Ton = 2204.62 lbs 1 kg = 0.001 metric tons Pollutant kg/mmbtu metric ton/yr tpy CO2 53.02 155 171.33 CH4 0.001 0 0.00 N2O 0.0001 0 0.00 CO2e = 172 CO2, = CO2 + (CH4*21) + (NCO*310) 0.00 0.005 0.000 0.000 0.016 0.00 0.00 0.00 0.00 0.00 AP -42. Table 3.4-3 AP -42, Table 3.4-3 AP -42, Table 3.4-3 AP -42, Table 3.4-3 AP -42, Table 3.4-3 DIESEL GENERATOR SET CAT® Image shown may not reflect actual package. FEATURES STANDBY 550 ekW 688 kVA 60 Hz 1800 rpm 480 Volts Caterpillar is leading the power generation marketplace with Power Solutions engineered to deliver unmatched flexibility, expandability, reliability, and cost-effectiveness. FUEL/EMISSIONS STRATEGY • EPA Certified for Stationary Emergency Application (EPA Tier 2 emissions levels) DESIGN CRITERIA • The generator set accepts 100% rated load in one step per NFPA 110 and meets ISO 8528-5 transient response. UL 2200 / CSA - Optional • UL 2200 listed packages • CSA Certified Certain restrictions may apply. Consult with your Cat® Dealer. FULL RANGE OF ATTACHMENTS • Wide range of bolt -on system expansion attachments, factory designed and tested • Flexible packaging options for easy and cost effective installation SINGLE -SOURCE SUPPLIER • Fully prototype tested with certified torsional vibration analysis available WORLDWIDE PRODUCT SUPPORT • Cat dealers provide extensive post sale support including maintenance and repair agreements • Cat dealers have over 1,800 dealer branch stores operating in 200 countries • The Cat® S•O•Ss" program cost effectively detects internal engine component condition, even the presence of unwanted fluids and combustion by-products CAT ® C18 ATAAC DIESEL ENGINE • Utilizes ACERTTM Technology • Reliable, rugged, durable design • Field -proven in thousands of applications worldwide • Four -stroke -cycle diesel engine combines consistent performance and excellent fuel economy with minimum weight • Electronic controlled governor CAT GENERATOR • Matched to the performance and output characteristics of Cat engines • Load adjustment module provides engine relief upon load impact and improves load acceptance and recovery time • UL 1446 Recognized Class H insulation CAT EMCP 4 CONTROL PANELS • Simple user friendly interface and navigation • Scalable system to meet a wide range of customer needs • Integrated Control System and Communications Gateway SEISMIC CERTIFICATION • Seismic Certification available • Anchoring details are site specific, and are dependent on many factors such as generator set size, weight, and concrete strength. IBC Certification requires that the anchoring system used is reviewed and approved by a Professional Engineer • Seismic Certification per Applicable Building Codes: IBC 2000, IBC 2003, IBC 2006, IBC 2009, CBC 2007 • Pre -approved by OSHPD and carries an OSP-0084-10 for use in healthcare projects in California STANDBY 550 ekW 688 kVA 60 Hz 1800 rpm 480 Volts FACTORY INSTALLED STANDARD & OPTIONAL EQUIPMENT CST System Standard Optional Air Inlet • Light Duty Air Filter • Service indicator I ] Single element air filter I ] Dual element air filter I ] Heavy-duty dual element air filter with precleaner I ] Air inlet shut-off Cooling • Radiator package mounted • Coolant level sight gauge • Coolant drain line with valve • Fan and belt guards • Cat® Extended Life Coolant* I ] Radiator duct flange I ] Low coolant level sensor Exhaust • Dry exhaust manifold • Stainless steel exhaust flex fittings with split -cuff • Exhaust flange outlets I I Industrial I I Residential f 'Critical Mufflers I I Manifold and turbocharger guards I I Elbows and through -wall kits Fuel • Primary fuel filter with integral water separator • Secondary fuel filters • Fuel priming pump • Flexible fuel lines • Fuel cooler* *Not inlcuded with packages without radiators I I Integral single wall fuel tank base I I Integral dual wall UL fuel tankbase I I Sub -base dual wall UL listed fuel tank base I ] Manual transfer pump I I Fuel level switch Generator • Class H insulation • Class H temperature rise • VR6 voltage regulator with 3 -phase sensing with load adjustment • IP23 Protection I I Oversize generators I I Internal excited (IE) I I Permanent magnet excitation(PMG) I I Cat digital voltage regulator (CDVR) with kVAR/PF control I I Anti -condensation space heaters I I Coastal Insulation Protection (CIP) I I Reactive droop Power Termination • Power Center houses EMCP controller and power/control terminations (rear mounted) • Circuit breaker, UL listed, 3 pole (80% & 100% Rated) • Circuit breaker, IEC compliant, 3-4 pole (100% Rated) • Segregated low voltage wiring termination panel • IP22 protection • Bottom cable entry I I Power Center mounting option (right side) I I Multiple circuit breaker options I I C.B. Shunt trips I I C.B. Auxiliary contacts Governor • ADEMT"^ A4 I ] Load Share Module Control Panels • EMCP 4.1 (mounted in Power Center) • Speed adjustment • Voltage adjustment • Emergency stop pushbutton I ] EMCP 4.2 I ] Right-hand mounted Power Center I ] Local annunciator module (NFPA 99/110) I ] Remote annunciator module (NFPA 99/110) I ] Digital I/O module Lube - • Lubricating oil • Oil drain line with valves • Oil filter and dipstick • Fumes disposal • Lube oil level indicator • Oil cooler I ] Oil temperature sensor I ] Manual sump pump Mounting • Formed steel narrow base frame • Linear vibration isolation -seismic zone 4 I I Oil skid base I I Formed steel wide base frame Starting/Charging • 24 volt starting motor • 24 volt, 45 amp charging alternator I I Jacket water heater with shut-off valves I I Engine block heater I I Ether starting aid I I Battery disconnect switch I I Battery chargers (5 or 10 amp) I I Oversize batteries I I Batteries with rack and cables General • Paint - Caterpillar Yellow except rails and radiators gloss black • Flywheel housing - SAE No. 0 I ] UL 2200 package I I CSA Certification [ 1 EU or CE Certificate of Conformance I I Weather protective enclosure I I Sound attenuated protective enclosure I I Seismic Certification per Applicable Building Codes: IBC 2000, IBC 2003, IBC 2006, IBC 2009, CBC 2007 2 January 15 2013 10:11 AM STANDBY 550 ekW 688 kVA 60 Hz 1800 rpm 480 Volts SPECIFICATIONS CST CAT GENERATOR Frame size LC6114G Excitation Self Excitation Pitch 0.6667 N umber of poles 4 N umber of bearings Single bearing N umber of Leads 012 Insulation UL 1446 Recognized Class H with tropicalization and antiabrasion - Consult your Caterpillar dealer for available voltages IP Rating Drip Proof IP23 Alignment Pilot Shaft Overspeed capability 125 Wave form Deviation (Line to Line) 2% Voltage regulator Three phase sensing Voltage regulation Less than +/- 1/2% (steady state) Less than +/-' % (w/ 3% speed change) CAT DIESEL ENGINE C18 ATAAC, I-6, 4 -Stroke Water-cooled Diesel Bore 145.00 mm (5.71 in) Stroke 183.00 mm (7.2 in) Displacement 18.13 L (1106.36 in3) Compression Ratio 14.5:1 Aspiration Air -to -Air Aftercooled Fuel System MEUI Governor Type Caterpillar ADEM control system CAT EMCP 4 SERIES CONTROLS EMCP 4 controls including: - Run / Auto / Stop Control - Speed and Voltage Adjust - Engine Cycle Crank - 24 -volt DC operation - Environmental sealed front face - Text alarm/event descriptions Digital indication for: - RPM - DC volts - Operating hours - Oil pressure (psi, kPa or bar) - Coolant temperature - Volts (L -L & L -N), frequency (Hz) - Amps (per phase & average) - ekW, WA, kVAR, kW -hr, %kW, PF (4.2 only) Warning/shutdown with common LED indication of: - Low oil pressure - High coolant temperature - Overspeed - Emergency stop - Failure to start (overcrank) - Low coolant temperature - Low coolant level Programmable protective relaying functions: - Generator phase sequence - Over/Under voltage (27/59) - Over/Under Frequency (81 o/u) - Reverse Power (kW) (32) (4.2 only) - Reverse reactive power (kVAr) (32RV) - Overcurrent (50/51) Communications: - Four digital inputs (4.1) - Six digital inputs (4.2 only) - Four relay outputs (Form A) - Two relay outputs (Form C) - Two digital outputs - Customer data link (Modbus RTU) (4.2 only) - Accessory module data link (4.2 only) - Serial annunciator module data link (4.2 only) - Emergency stop pushbutton Compatible with the following: - Digital I/O module - Local Annunciator - Remote CAN annunciator - Remote serial annunciator 3 January 15 2013 10:11 AM STANDBY 550 ekW 688 kVA 60 Hz 1800 rpm 480 Volts TECHNICAL DATA CST Open Generator Set - - 1800 rpm/60 Hz/480 Volts DM8517 EPA Certified for Stationary Emergency Application (EPA Tier 2 emissions levels) Generator Set Package Performance Genset Power rating @ 0.8 pf Genset Power rating with fan 687.5 kVA 550 ekW Fuel Consumption 100% load with fan 75% load with fan 50% load with fan 151.1 L/hr 118.2 L/hr 86.0 Uhl- 39.9 Gal/hr 31.2 Gal/hr 22.7 Gal/hr Cooling System' Air flow restriction (system) Air flow (max @ rated speed for radiator arrangement) Engine Coolant capacity with radiator/exp. tank Engine coolant capacity Radiator coolant capacity _ 0.12 kPa 804 m3/min 81.8 L 20.8 L 61.0 L 0.48 in. water 28393 cfm 21.6 gal 5.5 gal 16.1 gal Inlet Air Combustion air inlet flow rate 46.3 m3/min 1635.1 cfm Exhaust System Exhaust stack gas temperature Exhaust gas flow rate Exhaust flange size (internal diameter) Exhaust system backpressure (maximum allowable) 520.6 ° C 128.9 m3/min 203 mm 10.0 kPa 969.1 ° F 4552.1 cfm 8 in 40.2 in. water Heat Rejection Heat rejection to coolant (total) Heat rejection to exhaust (total) Heat rejection to aftercooler Heat rejection to atmosphere from engine Heat rejection to atmosphere from generator 180 kW 595 kW 141 kW 77 kW 32.6 kW 10237 Btu/min 33838 Btu/min 8019 Btu/min 4379 Btu/min 1854.0 Btu/min Alternator' Motor starting capability @ 30% voltage dip Frame Temperature Rise 1445 skVA LC6114G 130 ° C 234 ° F Lube System Sump refill with filter 34.0 L 9.0 gal Emissions (Nominal)' NOx g/hp-hr CO g/hp-hr HC g/hp-hr PM g/hp-hr 5.56 g/hp-hr .35 g/hp-hr .01 g/hp-hr .033 g/hp-hr For ambient and altitude capabilities consult your Cat dealer. Air flow restriction (system) is added to existing restriction from factory. - Generator temperature rise is based on a 40° C (104° F) ambient per NEMA MG1-32. Some packages may have oversized generators with a different temperature rise and motor starting characteristics. 3 Emissions data measurement procedures are consistent with those described in EPA CFR 40 Part 89, Subpart D & E and ISO8178-1 for measuring HC, CO, PM, NOx. Data shown is based on steady state operating conditions of 77°F, 28.42 in HG and number 2 diesel fuel with 35° API and LHV of 18,390 btu/lb. The nominal emissions data shown is subject to instrumentation, measurement, facility and engine to engine variations. Emissions data is based on 100% load and thus cannot be used to compare to EPA regulations which use values based on a weighted cycle. 4 January 15 2013 10:11 AM STANDBY 550 ekW 688 kVA 60 Hz 1800 rpm 480 Volts RATING DEFINITIONS AND CONDITIONS CST Meets or Exceeds International Specifications: AS1359, CSA, IEC60034-1, ISO3046, ISO8528, NEMA MG 1-22, NEMA MG 1-33, U L508A, 72/23/E EC, 98/37/E C, 2004/108/EC Standby - Output available with varying load for the duration of the interruption of the normal source power. Average power output is 70% of the standby power rating. Typical operation is 200 hours per year, with maximum expected usage of 500 hours per year. Standby power in accordance with ISO8528. Fuel stop power in accordance with ISO3046. Standby ambients shown indicate ambient temperature at 100% load which results in a coolant top tank temperature just below the shutdown temperature. Ratings are based on SAE J1349 standard conditions. These ratings also apply at ISO3046 standard conditions. Fuel rates are based on fuel oil of 35° API [ 16° C (60° F)] gravity having an LHV of 42 780 kJ/kg (18,390 Btu/lb) when used at 29° C (85° F) and weighing 838.9 g/liter (7.001 lbs/U.S. gal.). Additional ratings may be available for specific customer requirements, contact your Cat representative for details. For information regarding Low Sulfur fuel and Biodiesel capability, please consult your Cat dealer. 5 January 15 2013 10:11 AM STANDBY 550 ekW 688 kVA 60 Hz 1800 rpm 480 Volts DIMENSIONS CST Package Dimensions Length 4237.4 mm 166.83 in Width 1536.0 mm 60.47 in Height 2165.8 mm 85.27 in Performance No.: DM8517 Feature Code: C18DE96 Gen. Arr. Number: 2476121 Source: U.S. Sourced January 15 2013 21372656 NOTE: For reference only - do not use for installation design. Please contact your local dealer for exact weight and dimensions. (General Dimension Drawing #3728295). www.Cat-ElectricPower.com 2013 Caterpillar All rights reserved. Materials and specifications are subject to change without notice. The International System of Units (SI) is used in this publication. CAT, CATERPILLAR, their respective logos, "Caterpillar Yellow," the "Power Edge" trade dress, as well as corporate and product identity used herein, are trademarks of Caterpillar and may not be used without permission. 6 Fort Lupton Gas Plant Lancaster Plant Mole Sieve Regeneration Gas Heater 1 and 2 Train 1 and Train 2 Heater Data Make: Manufacturer: Model AIRS ID: Source ID Heat Output Efficiency: Heat Input: Operation: Fuel Heat Value: Mole Sieve Regeneration Gas Heater with Ultra Low NOx Burners ZEECO USA, LLC 35M Megafire TBD E-2015 & E-2016 (MMBtu/hr) Fuel Use 255.6 MMscf/yr (decimal) 21.7 MMscf/mo* 29.8 (MMBtu/hr) *based on 31 -day month (hr/yr) (Btu/scf) 25.0 0.84 8760 1020 Emission Calculations Pollutant NOx CO VOC PM10/PM2.5 SO2 CH2O Benzene Toluene Emission Factors Emissions Source 1 lb/MMscfI Adjusted I Ib/MMscf* lb/MMBtu lb/hr lb/mo* I tpy manuf. • 0.04 1.2 886 5.2 manuf. 0.040 1.2 886 5.2 manuf. _ 0.019 0.6 421 _ 2.5 AP -42 7.6 7.6 , 0.0075 0.2 165 , 1.0 AP -42 0.6 0.6 0.0006 0.02 13 0.1 AP -42 � 0.075 0.075 0.000 0.002 2 0.010 AP -42 0.0021 0.0021 0.0000 0.0001 0 0.0003 AP -42 _ 0.0034 0.0034 0.0000 0.0001 0 0.0004 * Emission factor conversion based on footnote "a" of AP -42 Table 1.4-1 to convert from 1,020 Btu/scf to the above Fuel Heat Value in units of Btu/scf. * lb/mo based on 31 -day month CO2e Emission Calculations Conversions: 1 Metric Ton = 2204.62 lbs 1 kg = 0.001 metric tons Pollutant kg/mmbtu metric ton/yr tpy ton/mo* CO2 53.02 13,823 15,237 1,294 CH4 0.001 0.26 0.29 0 N2O 0.0001 0.03 0.03 0 CO2e = 15,252 1,295 CO2 = CO, 4- (CH4*21) + (N,O'310) * ton/mo based on a 31 -day month 1 2 Owner: ANADARKO Petroleum Co. Owner Ref.: E-2015 Fin' -3 Purchaser: EXTERRAN Energy Solutions, L.P. Purchaser Ref.: OPP-45907 & 4 Manufacturer: TULSA HEATERS INC. Till Ref.: P12-7994 / SHO2500.LP 25x 13 Rev 5 Service: Regen Gas Unit No: Utility 6 Number: One Location: Lancaster Cryo Plant 7 Process Duty: 24.82 MMBTU/ hr Heater Type: Standard HOrizontal (SHO) Heater s Total Duty: 24,82 MMBTU/ hr w/ High Efficiency Convection Section 9 and Forced Draft Combustion System 10 11 PROCESS DESIGN CONDITIONS 12 13 Heater Section - - - RADIANT CONVECT/ON CONVECTION TOTAL 14 Operating Case - - - Design Case Design Case Design Case Design Case 15 Service - - - Regen Gas Regen Gas Service "b" 16 Heat Absorption MMBTU/hr 16.05 8.77 0.00 24.82 Corr 17 Process Fluid - - - HC Vapor HC Vapor 18 Process Mass Flow Rate, Total Lb/hr 78,100 78,100 19 Process Bulk Velocity (allow. /cat.) ft/s - - - / 43 - - - / 24 / 20 Process Mass Velocity (min./cat.) Lb/s (:2 - - - / 60 - - - / 86 / 21 Coking Allowance (dP calcs) in 22 Pressure Drop, Clean (allow. /calc.) psi < 10 / 8 > i [All 23 Pressure Drop, Fouled (allow. / cat.) psi c / > / 24 Average Heat Flux (allowable) BTU/ hr (t2 12,000 25 Average Heat Flux (calculated) BTU/ hrft2 11,300 26 Maximum Heat Flux (allowable) BTU/ hr112 27 Maximum Heat Flux (calculated) BTU/hr (12 20,340 18,300 15.1 28 Fouling Factor, internal hr h2 °F/ BTU 0.001 0.001 29 Corrosion or Erosion Characteristics - - - 30 Max. Film Temperature (allow. I cat.) °F / 711 / 395 / 31 32 33 Inlet Conditions: Temperature °F 290 120 34 Pressure psig 844 847 35 Mass Flow Rate, Liquid Lb/hr 0 r36 Mass Flow Rate, Vapor Lb/ hr 78,100 37 Weight Percent, Liquid I Vapor wt%° 0% / 100% / 38 Density, Liquid / Vapor Lb/ ft3 0.00 / 3.53 / 39 Molecular Weight, Liquid / Vapor Lb/ Lbrnole / 21.6 / 461 Viscosity, Liquid / Vapor cp 0.000 / 0.014 / 41 Specific Heat, Liquid/ Vapor BTU/ Lb °F 0.000 / 0.620 / 42 Thermal Conductivity, LiquidNapor BTU/hr ft °F 0.000 / 0.022 / 43 Surface Tension, Liquid dyne/ cm / / 44 45 Outlet Conditions: 46 Temperature °F 600 290 47 Pressure psig 839 844 481 Mass Flow Rate, Liquid Lb/hr 0 49 Mass Flow Rate, Vapor Lb/hr 78,100 50 Weight Percent, Liquid/ Vapor wt% 0% / 100% 51 Density, Liquid/ Vapor Lb/1t3 0.00 / 1.35 / 52 Molecular Weight, Liquid/ Vapor Lb/Lbrnole / 21.6 / 53 '' Viscosity, Liquid/ Vapor cp 0.000 / 0.020 / 54 Specific Heat, Liquid/ Vapor BTU/ Lb °F 0.000 / 0.753 / 55 Thermal Conductivity, LiquidNapor BTU/hr ft °F 0.000 / 0.045 / 56 Surface Tension, Liquid dyne/cm / / 57 58 59 60 61- u-- 62 fiev.01 16 -Feb -12 UPGRADED to ULTRA LOW NOx EMISSIONS TLC COX VPS VPS 63 ; Rev.00 11 -Jan -12 Issued vv/ Millet Proposal TLC COX 64 revision _ date description by chk'd appv'd Lancaster Cryo Plant II TULSA .::::: 'IF; ..: R R AN . H, HEATERS FIRED HEATER DATA SHEET AMER/CAN ENGINEERING SYSTEM of UNITS ANADARKO INC. P12-7994ReV.0) SHO - Superior Quality, Flexibility, Dependability & Modularity This document contains confidential inforination, which is proprietary to Th I. This document shall -NTRdS- Pg 1 of 9 not be used, reproduced or disclosed without the prior written consent of That. Owner Ref.: E-2015 THI Red,: P12-7994 2 3 a s 7 a 12 13 14 15 17 18 19 20 21 22 a 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 441 461 63 64€ COMBUSTION DESIGN CONDITIONS Overall Performance: Operating Case Service Excess Air mot% Calculated Heat Release (WV) MMBTU/ ht Guaranteed Efficiency HR% Calculated Efficiency Radiation Loss Flow Rate, Combustion Gen./Imported Flue Gas Temperature Leaving Section Flue Gas Mass Velocity Lb/sec lt2 Fuel(s) Data: LHV BTU/scf LHV BTU/Lb P @ Burner pstg T @ Burner "F MW Lb/ Lbmole p @ 77? aF cp 11 @ ??? °F cp Atomizing Media Atom. Media P & T Components: N S Ash Ni Va Na Fe H2 O2 N2 t Ar CO CO2 CH4 C2H6 C2H4 C3H8 C3H6 C4H10 C4H8 C5H12 C5H10 C6+ H2S SO2 NH3 H2O spare Design Mol. Wt. 884 19, 299 30 100 17.39 wt �v wt% --- wt% - - - ppm ppm ppm ppm - - - mot% 0.00 mot % 0.00 mot% 0.20 rnol°% 0.00 mot% 3.80 mol% 94.29 mot% 1.40 mot% 0.00 mol% 0.14 mol% 0.00 mol% 0.04 mo!% 0.00 mot % 0.00 mat % 0.00 mot% 0.00 mot % 0.05 rnol% 0.00 mot% 0.00 mol% 0.07 more 0.00 Clearances: ... for Gas Firing: ... from burner CL ... to Tube CL, API it to Tube CL, calc. ft to Refrac., cafe. ft Vertical per THI Design 5.53 4.50 RADIANT CONVECTION CONVECTION Design Case Design Case Design Case Bogen Gas HR% HR% Lb/ hr 28,942 OF 1,490 Regen Gas Service "b" '0 460 0.350 Design Burner Design: Fuel Oil OEM Type Quantities Model No.1 Model No.2 Windbox Location Pilot Design: Type Model Ignition Heat Release - TOTAL Design Case 20.0% 28.35 84.4% 87.4% 2.00% 28,942 Ftnt Rev ZEECO USA, LLC foil ULTRA Lo wNOx firth Gen. Low NOx [01) 4 Model 1 and 0 Modell Burners [011 ZEECO USAt LLG Cylindrical (011 None [01J yes ... w/parallel blade registers End Wall Center ... Horizontally Fireo Continuous Self-Inspirating by O.E.M. Electric requires else.i_gn.system > 9O000 Sumer Performance: Minimum Heat Release Design Heat Release Maximum Heat Release Burner Turndown Volumetric Ht. Release Draft @ Arch Draft @ Burner Combustion Air T @ Burner Flue Gas T @ Burner Guaranteed Emissions: Basis of Guarantee NOx Emissions SOx Emissions CO Emissions UHC Emissions VOC Emissions SPM10 Emissions Noise Emissions BTU/ br on ... Design RFG MMBTU/hr MMBTU/ hr MMBTU/ hr Max:Min BTU/ hr ff3 MH2O inH2O OF Lb/MMBTU Lb/MMBTU Lb/MMBTU Lb/MMBTU Lb/MMBTU Lb/MMBTU dBA Cli alt Model 1 Modell 1.75 7 10 8.75 5.00 13,140 0.10 5.70 60 [011 [011 (01/ [01J [01J [01] (01) 1,490 (01J <-- Combined --> 3.0% O2, dry JLHV) 0.040 33 ppm [01] no quote [01] 0.040 50 ppm (oil 0.007 15 ppm [01 0.019 15 ppm (0 1J 0.013 14 ppm [0t] 85.0 Combustion System Features: BMS Functions Yes; per NFPA w,' EESLP Upgrades Comb. Controls Yes; via parallel control of CA DMPR & FG TCV Duty Controls Yes; via conventional PID control of Outlet T Main & Pilot Trai► Yes; per 831.3 & NFPA w/ EESLP Upgrades Local Panel Yes; NEMA 4X w/ EESLP Upgrades FD System Yes; One Chicago Blower fan, or tech. equivalent Firing Test Not Required a tar Horizontal per THI Design a69 4.50 n / a 24.08 Firebox Size Est. Flame Size Net Clearance Net Clearance 11' 0" H x 11 ' 0" W x 24' 1" L Note: H & W are based on tube centerlines 2' 3" Diameter x 17' 0" Long 3' 4" NET Tube Clearance in Hot & Vert plane 7' 0" NET Refractory Clearance in Axial plane [0f] [01J [011 [01] [01J AMERICAN ENGINEERING SYSTEM of UNITS TULSA HEATERS INC. FIRED HEATER DATA SHEET P12-7994-HTRds- Rev.01 Page 2 of 9 Fort Lupton Gas Plant Lancaster Plant Heat Medium Fired Heater 1-4 Train 1 and Train 2 Heater Data Make: Manufacturer: Model: Description Heat Output Efficiency: Heat Input: Operation: Fuel Heat Value: Heat Medium Heater with Low NOx Burners Sigma Thermal HC2-50.0-H-SF H-6051. H-6052, H-6053 & H-6054 (MMBtu/hr) (decimal) 60.00 0.78 76.9 (MMBtu/hr) (hr/yr) (Btu/scf) 8760 1020 Fuel Use 660.6 56.1 MMscf/yr MMscf/mo* *based on 31 -day month Emission Calculations Pollutant NOx CO VOC SO2 CH2O PM10/PM2.5 Benzene Toluene Emission Factors Emissions Source 1 lb/MMscf I Adjusted Ib/MMscf` lb/MMBtu l lb/hr lb/mo* py tpy manuf. 0.04 3.1 2289 13.5 manuf. 0.04 3.1 1 2289 13.5 AP -42 5.5 5.5 0.005 0.4 309 1.8 AP -42 0.6 0.6 0.001 0.05 IAP-42 34 0.20 0.075 0.075 0.000 0.006 4 0.02 manuf. 0.005 0.38 286 1.7 AP -42 0.0021 0.0021 0.0000 0.0002 0 0.00 AP -42 0.0034 0.0034 0.0000 0.0003 0 0.00 * Emission factor conversion based on footnote "a" of AP -42 Table 1.4-1 to convert from 1,020 Btu/scf to the above Fuel Heat Value in units of Btu/scf. * lb/mo based on 31 -day month CO2e Emission Calculations Conversions: 1 Metric Ton = 2204.62 lbs 1 kg = 0.001 metric tons Pollutant kg/mmbtu metric ton tpy ton/mo* CO2 53.02 35,727 39,383 3,345 CH4 0.001 0.67 0.74 0.06 N2O 0.0001 0.07 0.07 0.01 CO2, = 39,421 3,348 CO2, = CO2 + (CH4*21) + (N,O*310) * lb/mo based on 31 -day month 5 I GMA �� THERMAL Quotation # STQ120139 SYSTEM DESIGN DATA Thermal Fluid System Datasheet Customer Name Anadarko Petroleum Project Name Lancaster Plant Date completed March 1, 2012 Project Location Weld County, CO Revision number A Sales Engineer Charlie Wadlington Heat Input 48 MMBTU/hr Heater Model Number HC2-50.0-H-SF Heater Type HC2 Heater Configuration Horizontal System Flow Rate 3,000 gal /min. Fluid Pressure Drop 25 lb / in2(d) Heater Flow Rate 3,000 gal /min. Flue Gas Pressure Drop 3.8 in W.C. System Bypass 0 gal /min. Average Heat Flux 8,969 Btu /hr/ft2 Heater Bypass 0 gal/min. Radiant Zone Heat Flux 23,686 Btu/hr/ft2 Thermal Fluid Paratherm HR Maximum Film Temperature 451 °F Process Supply Temperature 360 °F Inner Coil Velocity 11 ft/sec Heater Outlet Temperature 360 °F Outer Coil Velocity 8 ft/sec Process Return Temperature 292 °F Thermal Efficiency 88% % LHV Basis Heater Coil Design Temperature 750 °F Heater Coil Design Pressure 250 lb /in2(g) Fuel Type Gas Selected Burner Make Maxon Combustion Air Preheat No Burner Model Selected Kinedizer LE -16 Efficiency with Preheat N/A % LHV Basis Steady State Firing Rate (HHV Basis) 60,064,285 Btu / hr Oxygen Trim No Burner Design Margin 10% Fully Metered /Cross Limited No Design Firing Rate (HHV Basis) 66,070,713 Btu / hr Low NOx Required Yes Combustion Air Design Temperature 60 °F BMS Type Standard Available Fuel Pressure From Customer 10 lb/in2(g) Combustion Control Type Standard Design Fuel Flow Rate 65,200 (std)ft3 / hr Control Panel Location Skid Mounted Minimum Firing Rate 3.75 MMBTU/hr NOx Required (if any) 33 ppm Fuel Train Location Skid Mounted CO Required (if any) 149 ppm Fuel Train / BMS Code Compliance NFPA87-11 Gas Consumption @ Steady State 59,272 (stdjft3 / hr Fuel Train Size 2 in. Air Consumption @ Steady State 9,323 (act)ft3 / min Fuel Train Type Sigma Thermal Standard Gas Consumption @ High Fire 65,200 (std)ft3/hr hr Fuel Train Construction NPT Air Consumption @ High Fire 10,256 (act)ft3 / min Flue Gas Velocity 54 ft/sec Exhaust Gas Flow Rate 22,083 (act)ft3 /min Exhaust Gas Temperature 485 °F Stack Diameter 36 in Stack Height 40 ft Estimated User& Piping Pressure Drop 30 lb/in2(g) Pump Model RSY200-330 Pump Configuration 1 x 100% Motor Size 200 hp Calculated Total Pump Flow Required 3000 gal /min. Line Size 10 in Calculated Total System Pressure Drop 65.0 lb/in2(d) Valve Specification Sigma Thermal Standard Selected Pump Make KSB Valve Type Bellows Seal Globe Thermal Fluid Piping Design Temperature 460 °F Thermal Fluid Piping Design Pressure 150 lb/in2(g) Total Estimated System Volume 5,613 gal Tank Type Sigma Thermal Standard Calculated Expansion Volume 896 gal Nitrogen Blanket Pressure (if applicable) 5 lb/in2(g) Expansion Tank Size 5000 gal Drain Tank Size Maximum Ambient Temperature 100 °F Control Panel Area Classification Class I Div. II Minimum Ambient Temperature -20 °F Skid Area Classification Class I Div. II Elevation (above mean sea level) 5,055 ft Wiring Standards Per Customer Specification Motor Requirements Standard Efficiency TEFC Electrical Code of Construction NEC Instrumentation Per Customer Specification Control Panel Certification UL Motor Sta rters By Others Primary Voltage 460V/ 3/ 60Hz Minimum Electrical Enclosures Rating 4X Control Voltage 120V/1/60Hz Paint Colors Per Customer Specification Overall Paint Specification Per Customer Specification 1 MAXON' A Honeywell Company 201 East 18th Street Muncie. Indiana 47302-4124 PO. Box 2068 Muncie, Indiana 47307-0068 Tel: 765.284-3304 Fax: 765.286.8394 www.maxoncorp.com Charlie, The KinedizerLe Burner will produce no more .005 #/million Btu's of PM2.5(condensable & filterable) for the stated conditions of firing at 68.4 MM BTU/HR at high fire and 62.2 MM BTU/Hr at steady state conditions. Larry Hyland Manager -Technical Sales Support Maxon A Honeywell Company 201 E 18th Street Muncie. IN Fort Lupton Gas Plant Lancaster Plant Amine Treater Vent Stack Emissions - Train 1 Source ID A-1, A-2, A-3 & A-4 AIRS ID TBD Source Description 150 MMSCFD Anne Treating System. Train 1 (2 each) and Train 2 (2 each) Potential operation 8760 hrs/yr Amine Simulation Results (4/12112 CO2e Emission Calculations Conversions Molar Volume to Molar Mass 379.3lscf/lb-mole ;HG Calculation Acid Gas Flash Gas Pollutant scf/yr tons/yr scf/yr tons/yr CO2 1470992420 85319.89 4.57E+06 265 CO2e (tpy)= 85.585 CO2e (ton/mo)'= 7,269 'Calculation method from API 2009 GHG Compendium 5-12 'co: (tpy)= [scftyrj / [scf/1b-mole] ' @+w1 r (Ibc.tnl 'toNmo baser on 31 -day month VOC Emission Calculations Conversions Molar Volume to Molar Mass .37:9.3 scf/lb-mole IOC Calculation Acid Gas Flash Gas Pollutant _ scf/yr tons/yr scf/yr tons/yr Propane 2.14E+05 12 1_85E+06 108 n -Butane 1.18E+05 9 7_03E+05 54 i-Butane 4.44E+05 34 8.15E+05 62 n -Pentane i 1.39E+04 1 1.12E+05 11 i-Pentane 1.54E+04 1 1.24E+05 12 n -Hexane 1.60E+04 2 1.08E+05 12 Uncontrolled VOC ' 1.1 Factor = 350.6 Ib/mo' VOC x 99% Control Efficiency 3.5 596 'Ib/mo based on 31 -day month Acid Gas Flash Gas Flowrate (MMscfd) 4_410 0.1205 Pressure (psiq) 8 60 Temperature (°F; 120 156 Composition Mol% Mol% lb/lb-mole Nitrogen 8.651E-05 0131 28.01 CO2 91.390 10.381 44 Hydrogen Sulfide 1.355E-02 1.880E-03 34.08 Methane 1.349E-01 63.8671 16.04 Ethane 3.728E-02 11.9473 30.07 Propane 1.327E-02 4.2115 1 44.1 3' n -Butane 7.359E-03 15973 58.12 i-Butane 2.760E-02 1.854 58.12 n -Pentane 8.631E-04 0.2542 72.15 i-Pentane 9.570E-04 i 02818 72.15 n -Hexane 9.955E-04 0.2445 86.17 Water 8.373E+00 5.228 Total 100 0 100.0 Fort Lupton Gas Plant Lancaster Plant Amine Treater Thermal Oxidizer Emissions, Train 1 and Train 2 Source ID AIRS ID Source Description Potential operation "stream will be routed to emergency flare when TO is down. A -T01, A-TO2, A-TO3, A-TO4 TBD Train 1 and Train 2 Thermal Oxidizer to Control Amite Treater (A1-4) 8760 hrs/yr Combustion Emission Calculations Conversions Molar Volume to Molar Mass T 379.3 scf/tb-mole Component Formula Heat of Combustion [Btu/lb] Amine still vent and flash gas (IMRtri Heat Content [Btu/hrj methane CH4 21502 146.0866 3141153 ethane C2H6 20416 52.9853 1081747 propane C3H8 19929 27.4193 546440 n -butane C4H10 19665 14.3605 282400 isobutane C4H10 19614 22.0340 432174 n -pentane CSH12 19499 2.7294 53221 isopentane C5H12 19451 3.0258 ASS n-tiexane C6H14 19200 3.2044 61525 Total (Btu/hr) = 5657517 I Btu/scf = 30.0 Heat Input Total Heat Input (MMBtuYhr) hra/yr TO Burner Heat Rating (MMBtu9u1 from Amine Still Vent and Flash Gas (MMBtulhrl Auxiliary Fuel Gas (MMBtu/hrl 8.00 5.7 3.00 16.7 8760 Pollutant Ib/MMscf Ib:MMBtu lb/hr ton/vr' NOx 100 0.10 1.63 7.9 CO 84 0.08 1.37 6.6 TOC 11 0.01 VOLT 1.1 0.00 0.02 0.09 PM (Total) 7.6 7.45E-03 0.12 0.6 S02 0.6 5.88E-04 0.01 0.05 CH2O 0.075 7.35E -0S 0.00 0.0 Benzene 0.0021 206E-06 0.00 0.0 Toluene 0.003 3.33E-06 0.00 0.0 • AP -42 emission factors, Tables 1.4-1, 1.4-2 and 1.4-3 ' Total emissions (Ipy) • 1.1 factor ' Assumed VOC = 10 % wt of fuel gas Rowrate (MMscfd) Pressure (psig) Temp erature (W) Amine Simulation Results (4/12/12) Acid Can¢ Flash Gas 4 410 0 1?QS 8 60 '0 156 Oortpoaiart Mot% Mol% Ih(b-mote Nitrogen 8.651E-05 0.131 28.01 _ CO2 91.390 10.381 44 Hydrogen Sulfide 1.355E-02 1.880E-03 34.08 Methane 1.349E-01 63.8671 16.04 _ Ethane 3.728E-02 11.9473 30.07 1 Propene 1.327E-02 4.2115 44.1 n -Butane 7.359E-03 1.5973 58.12 i-Butane 2.760E-02 1.854 58.12 n -Pentane 8.631E-04 0.2542 7115 1 1 -Pentane 9.570E-04 02818 7115 n -Hexane 9.955E-04 0.2445 1 86.17 Water Total Ib/mo' 1337 11_3 1 102 CO2e Emission Calculations Conversions: 1 Metric Ton = 1 kg = 2204.62 lbs 0.001 metric tons Pollutant C0 CH, kg mmbtu 53.02 0.001 metric ton/yr 7,737 0.15 tpy 8,528.21 0.16 N.O 0.0001 0.01 CO,. = CO„ =002+ (CH.'211 +(PPk.0•310) 0.02 Ib/mo 8,537 8.373E+00 1 5.228 100.0 100.0 502 Emission Calculations s nnversinn Molar Volume to Molar Mass 379.3 scf/9)-mole 502 Atomic Weight 64.05 amu li2S Atomic Weight_ 34.08 amu Acid Gas Control % 95.00 % Pollutant Acid as Flash Gas Ih/hr tpy IMr tpy H2S 2.238E+00 9.801E+00 8.482E-03 3.715E-02 502 18.4 0.07 Emission Factors' Uncontrolled Units Emission Factors' Controlled Units H2S 0.40 Ib/MMSCF 0.0002 Ib/MMSCF SO2 0 lb/MMSCF 0.04 Ib/MMSCF Uncontrolled Emissions' lb/hr lb/ma tpy Controlled Emissions' Ib/hr lb/m0 tpy H2S 2.5 1.838 10.8 0.00 0.9 0.01 SO2 0 0 0 0.23 172.7 1.02 • Total emissions x 1.1 factor • lb/mo based on a 31 -day month N i R O C R b c ae � a a e nLL c c a! EZ LL J Q hilt LFAAg ttg 8r4o.-aaa F8 O N Q m m � r ON 00N00 N 0 N pa m V r N O r O Q m c511§ Lpg! M M N N M CD 00000000 p^^p^pp^hp^0 E E O O O O O O 8 8H 8 Uttcontroled VOC HAPs Berton Toluene E-Beistene Xylanes n -Hexane tpy tpy tpy tpy tpy tpy 13.01 118 007 009 001 0.03 030 547 0.00 0.00 000 0.00 000 000 32.41 9.82 0.85 1 80 013 1.31 2.95 0.02 0.00 0.00 000 000 000 000 1.46 013 0-01 0 01 0.00 0.00 003 0.00 0.00 0.00 000 000 000 000 2.00 0.81 0.04 0.11 0.01 0.08 0.18 000 0.00 0.00 000 000 0.00 000 4.10 124 0.08 0 23 002 0.17 0 37 007 000 0.00 000 0.00 0.00 000 0.00 000 000 000 0.00 000 000 0.00 000 0.00 000 0.00 0.00 0.00 0.00 0.00 0.00 000 0.00 0.00 0.00 0.00 0.00 0.00 000 000 0.00 000 0 00 000 0.00 000 000 000 000 069 006 0.00 000 0.00 000 002 1.65 0.50 0.03 009 001 007 0.15 0.04 0.00 0.00 0.00 000 0.00 0.00 0.82 006 0.00 0.00 000 0.00 0.01 076 023 0.02 004 000 003 007 0 00 000 0.00 000 000 0.00 0.00 80.6 162 1.0 2.6 0.2 1.9 4.6 I Ig88V888!88888888so8 1 !g08,888B88888888888808 s. 8888880808888808888 C il W lin O goon000ro- O pgg8cs liY V iiip taro 0 0 r 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 606 O 0 p 000 0 p8 O Op O O O p O O O O 666 p O p8 O O o O O o 0 0 o o o o o o o 0 0 0 0 0 0 000 -0.- 0 M 0000 0Oa 00 R 0 000,080000,0,00. 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o8o80808888ci 888888g8 1 0 01 0{ 7 0- O m 0 0 0 0 0 0 0 0 0 m M 0 00Q00000000 O, 000000, 000 00"1 OOGOOOC C 00 CC 000000 O O N0 0 0 O O h O O O O O a M I f N 0 0 ovo00ryoo00000cocno. t7.--0 r' ONON000000Or 0000 30.5 7.1 0.6 1.2 x_0.1 09 2.1 4 1Ug^888F888888888888M88* LE 08g2888V8888888888'88V88- 5O e�i000000dboo0000660000 g888Y:8888888888888iZ88q Equ%,nsrtt Emission Source % % % % % % % % Hours ot Control Type Facto Court 002 CH4 VOC HAP Benzene Toluene E -Benzene Xylenes n -Hexane Operation Factor (bhrkource) % Valve►GesNapor 0 00992 1361 6% 57% 22% 2.00% 0.12% 0 • tit, 0 01 ';, 0 05% 0.50% 8760 7000% Verve,GasNapor 000992 126 0% 0% 100% 0.00% 000% 0004 0.00% 0 00% 000% 8760 7000% Valves Light Liquids 0.0055 1359 0% 0% 99% 30.00% 2.00% 5.50% 0A0% 4.00% 900% 8760 81.00% Velma- Heavy Liquids 0.000019 198 0% 0% 100% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 8760 0.00% Others -Gas 0.0194 78 6% 57% 22% 2.00% 0.12% 0.15% 0.01% 0.05% 0.50% 8760 0.00% Others -Heavy Oil 0.0000705 4 0% 0% 100% 0.00% 000% 0.00% 000% 0.00% 000% 8760 0.00% Others -Lots LKlux's 0.0185 28 0% 0% 99% 3000% 200% 5.50% 0.40% 4.00% 900% 8760 0.00% Compressor Seals 0.0194 0 6% 57% 22% 2.00% 0.12% 0.15% 001% 0.05% 0.50% 8760 0.00% Purrp Seats -Light Liquids 002868 33 0% 0% 99% 30.00% 2.00% 5.50% 0.40% 4.00% 9.00% 8760 45.00% Pump Seals -Heavy Liquids 0.00113 15 0% 0% 100% 0.00% 000% 0.00% 0.00% 0.00% 000% 8760 0.00% Pump Seals -Water ,Ud 0.0000529 3 0% 0% 100% 0.00% 0.00% 0.00% 0.00% 0.00% 000% 8760 0.00% Sturm* Connections 0.000243 0 6% 57% 22% 2.00% 0.12% 0.15% 001% 0.05% 0.50% 8760 0.00% Open -Ended Lines - Gas 000441 0 6% 57% 22% 2.00% 0.12% 0.15% 0.01% 0.05% 0.50% 8760 0.00% Open -Ended Lnes- Lpt Lq 0.00309 0 0% 0% 99% 30.00% 2.00% 5.50% 0.40% 4.00% 9.00% 8760 0.00% Open -Ended Lnes- Hvy Up 0.00031 0 0% 0% 100% 0.00% 0 00% 0.00% 0.00% 0.00% 000% 8760 0.00% Comecbrs-Gas 000044 1630 6% 57% 22% 2.00% 012% 0.15% 001% 0.05% 0.50% 8760 0.00% Comecbrs-141 Lip. 0.000463 821 0% 0% 99% 3000% 2.00% 5.50% 0.40% 4.00% 900% 8760 0.00% Camecbrs - Heavy Lit. 0.00002 488 0% 0% 100% 0.00% 0.00% 0.00% 0.00% 0.00% 000% 8760 0.00% Flrtpes-GasNepor 0.00086 744 6% 57% 22% 2.00% 0.12% 0.15% 0.01% 0.05% 050% 8760 0.00% FlargesUriUpds 0000243 719 0% 0% 99% 3000% 200% 550% 0.40% 4.00% 9.00% 8760 0.00% Fiances -Heavy Loa uds 0.00000086 45 0% 0% 100% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 8760 0.00% Toile 7650 Includes 10% Emission Variance Fecal Fort Lupton Gas Plant F-2 and F-3 Lancaster Plant Process Flare 1 and 2 Source ID Number AIRS ID Source Description Flare Make Flare Model Serial Number Date in Service Flare Configuration Fuel Heating Value Flare Pilot Rating Flare Purge Gas Rate Purge Gas Heat Rate Process Gas to Flare Process Gas Heating Value Process Gas Heat Rate % VOC Content of Process Gas F-2 and F-3 Unknown Flare Unknown Air -Assisted 1020 Btu/scf 0.5 MMBtu/hr 707 scf/hr 0.721 MMBtu/hr 75.0 MMscf/yr 1275.0 Btu/scf 10.9 MMBtu/hr 22 0 SCC Source Location Zone: Horizontal: Potential Operation Potential Fuel Usage Stack Height Stack Diameter Exit Velocity Exit Temperature Volume Flow Rate 8760 hr/yr 10.5 MMscf/yr 40 ft 30 in 60.0 fUs 1000 deg F 17,671 ft3/min Combustion Emission Calculations Heat Input MMBtu/hr hrs/yr r 12.14 8760 Pollutant Ib/MMBtu1 lb/hr ton/yr lb/mo* NOx 0.138 1.67 7.3 1246 CO 0.2755 3.34 14.6 2488 PM2.5 (total)'' 0.01 0 07 0.3 54 VOC2 0.03 0.37 1.6 278 'NOx and CO emission factors from TCEO Used AP -42 THC emission Factor of 0.14 ILYMMBtu • % VOC Content of oas 3 AP -42 Table 1.4-2 PM Total emission factor: 7.6 Ib/MMSCF / 1275 Btu/scf = lb/MMBtu lb/mo is based on a 31 -day month CO2e Emission Calculations Conversions: 1 Metric Ton = 2204.62 lbs 1 kg = 0.001 metric tons Pollutant kg/mmbtu metric ton tpy CO2 53.02 5,637 6,213.87 CH4 0.001 0.11 0.12 N,O 0.0001 0.01 0.01 CO2e (tpy) = 6,220 CO2e (ton/mo)" = 528.27 * ton/mo based on a 31 -day month CO2e = CO2 + (CHs 21) + (N_O 310) SO2 Emission Calculations Conversions: Inlet H2S Concentration 4 ppm Molar Volume to Molar Mass 379.3 set/lb-mole SO2 Atomic Weight 64.05 amu H2S Atomic Weight 34.08 amu Pollutant H2S Process Gas lb/yr 2918E+01 tpy 1 459E-02 . SO2 0 03 Total SO2 emissions (tpy)' I * Total emissions * 1.1 factor 0.03 ZINKE. ;JOHN ZINK COMPANY LLC III. SYSTEM DESCRIPTION JOHN ZINK AZDAIR AIR -ASSISTED FLARE (PLA-42) Most hydrocarbon -containing gas streams smoke when burned unless sufficient oxygen is mixed into the combustion zone. Smoke is produced by the cracking and polymerization reactions taking place in the flame core, where there is a high flame temperature and insufficient oxygen for complete combustion. Adequate aeration of the combustion zone reduces or eliminates smoke. With high-pressure gases sufficient air for complete combustion may be induced into the flame by a combination of jetting action and thermal draft. With low pressure gases, when the jetting action may be negligible and the thermal draft alone is insufficient to entrain enough air for complete combustion, smoke is produced. The problem of burning low-pressure gas smokelessly is usually solved by either aspirating air into the flame using an external (pressure) energy source such as steam, or mixing gas directly with air. Although steam injection is very effective at reducing smoke, such a system is not very suitable for flaring at remote locations where a large steam supply is not available. Air injection often provides the solution. Air can be supplied to the flare by a low-pressure fan. In the Azdair Air -assisted Smokeless Flare, primary air for combustion is supplied via a low-pressure fan, mounted at the base of the stack. The air required for smokeless flaring is supplied as a central core within the gas flame, and is designed to provide good mixing of the air and gas which produces a stable, smokeless flame. The Azdair is designed for duties where low-pressure gases are required to burn smokelessly when process steam is unavailable. The Azdair can also give lower radiation levels than a pipeflare for the same gas flow and conditions. Due to the premixed primary air supplied by the air blower, the combustion efficiency PF 32211 -AO January 16, 2013 5 The information in this document is confidential and may constitute proprietary information, trade secrets, or other privileged information. Therefore, it must not he disclosed to any person or entity without the written consent of John Zink Company, LLC. JOHN ZINIC c,JOI-IN ZINI< COMPANY LLD increases and the quantity of incandescent carbon, the main source of heat radiation, reduces. The goal of an efficient air assisted flare design is to maximize the air / gas mixing surface area. Conventional air assisted flares route the gas through the inner annulus of the flare tip mixing head while the air is routed through the outer annulus. This is a poor use of the flare tip cross-sectional area, which creates an outer ring of air around the periphery of the flare tip. The Azdair flare tip routes the gas through the outer annulus and the air through the inner annulus. This maximizes the air / gas surface mixing area, and also makes efficient use of the ambient air by creating a thin film of gas around the outer periphery of the flare tip diameter. This efficient air / gas mixing head arrangement allows the Azdair flare tip to produce more smokeless capacity per given volume of forced air than the conventional air assisted s itFkri�;y; flare design. -P, .,f The outer gas annulus of the Azdair flare tip also helps prevent air ingress into the mixing head at low gas flow rates. Conventional air assisted flare tips are much more likely to allow burning inside the tip mixing head at low gas flow rates. This leads to overheating and distortion of the mixing head and subsequent failure of the flare tip. MOAN Ft w TP 145 FEET TALL SELF SUPPORTED FLARE STACK Ail*. OF . iVot3:; HEM) The John Zink self supported flare stack provides a structural support for the flare tips and piping as required. The stack is designed to resist dead load, live load, wind loads and seismic loads as required by the applicable codes and guidelines. The structural design also incorporates consideration of dynamic effects such as vortex shedding and ovaling vibration. PF 32211 -AO January 16, 2013 6 The information in this document is confidential and may constitute proprietary information, trade secrets, or other privileged information. Therefore, it must not be disclosed to any person or entity without the written consent of John Zink Company, LLC. INKS ®JOHN ZINK COMPANY LLC The riser is manufactured in sections suitable for shipment and assembly, and match marked for field welding. The proper lifting lugs are attached to the top of each section. Each riser section must be welded in a vertical position and is not designed for single point lifting. A detailed description of the stack is included in attached data sheet. JOHN ZINK IN/NDPROOFTm HIGH PERFORMANCE PILOT The John Zink WindPROOF Pilot is the best that pilot technology has to offer, with a combination of fuel efficiency and stability in adverse weather conditions. The WindPROOF Pilot stands up to the most severe winds and rain with the long lasting performance of our other pilot models. Stable in winds up to a velocity of 160 mph in all positions around the flare tip, the WindPROOF Pilot consist of a tip and tip windshield, ignition and fuel piping, a mixer and strainer assembly, and a mixer windshield. The WindPROOF is stable in the worst conditions while' consuming as little as 45 SCFH of fuel gas. Also included are one integral thermowells for thermocouple pilot detection. The WindPROOF can burn a wide variety of fuels without adjustment. WindPROOF was designed and tested at the only pilot test facility of its kind in the world. At John Zink's International Research and Development Center, we use full scale testing to push our flare products to extraordinary limits. Det Norske Veritas (DNV), the worlds most widely respected product verification and Certification Company, witnessed John Zink Company's test of the WindPROOF pilot and verified that the WindPROOF remained lit under test conditions that exceeded 160 mph winds and 30 inches of rainfall per hour. PF 32211 -AO January 16, 2013 7 The information in this document is confidential and may constitute proprietary information, trade secrets, or other privileged information. Therefore, it must not be disclosed to any person or entity without the written consent of John Zink Company, LLC. JOHN ZINKe st_1O1-1N ZINI< COMPANY Ike AUTOMATIC / MANUAL FLAME FRONT GENERATOR IGNITION SYSTEM The John Zink Automatic Flame Front Generator (FFG) ignition system provides reliable pilot ignition, supported by over 40 years of experience. The FFG combines ignition fuel and compressed air at a mixing tee with the ignition gas mixture flowing through an ignition line to the pilot tip. After filling the ignition line with the air -fuel mixture, an electrical spark is initiated at the mixing tee. After ignition, a point source of flame travels through the ignition line and ignites the pilot gas at the pilot tip. Each pilot is ignited in sequence. The figure below depicts a typical three pilot automatic ignition system control panel. OFF ON AUTO MAN 2 N 1W PANEL IGNITION MANUAL PILOT POWER MODE IGNITION SELECT PILOT PILOT FAILURE PROVED After performing tests with simulated pipelines and examining existing systems, John Zink has determined that the FFG ignition system can be located in excess of 1,000 feet from the pilot. This placement variability offers operational flexibility and increased safety. Each pilot is equipped with a thermocouple which monitors the pilot flame. In addition, the FFG panel includes a local alarm light and personnel signal contacts for remote alarm systems. The automatic relight feature provides constant flame monitoring via a type K, 310 stainless steel sheathed thermocouple. Unmanned and immediate initiation of the ignition sequence is made in the unlikely event pilot flame is lost. Pressure regulators are provided for both gas and air to maintain gas -air ratios for proper ignition, and solenoid valves allow automatic reignition of the pilot. Manual ignition of each pilot is possible, if necessary. PE 32211 -AO January 16, 2013 8 The information in this document is confidential and may constitute proprietary Information, trade secrets, or other privileged information, Therefore, it must not be disclosed to any person or entity without the written consent of John Zink Company, LLC. Attachment D Form APCD-101 Colorado Department of Public Health and Environment Air Pollution Control Division Company Contact Information Form Ver. September 10. 2008 Company Name: Ken -McGee Gathering LLC Colorado Department of Public Health and Environment Source Name: Lancaster Plant Permit Jennifer L. Shea Contact': Address: P.O. Box 173779 Street Denver CO 80217 City State Zip Phone Number: (720)929-6028 Fax Number: (720)929-7028 E-mail: Jennifer.Shea@.anadarko.com Billing Contact: (Permit Feest3 Same as above Address: Street City State Zip Phone Number: Fax Number: E-mail: Compliance Contact': Jennifer L. Shea Address: P.O. Box 173779 Street Denver I CO I 80217 City State Zip Phone Number: (720)929-6028 Fax Number: (720)929-7028 E-mail: Jennifer.Shea@anadarko.com Billing Contact: Annual Fees14 Same as above Address: Street I I City State Zip Phone Number: Fax Number: E-mail: Check how would you like to receive your permit fee invoice? Mail: ■ E-mail: Fax: ■ Footnotes: 1 The permit contact should be the point of contact for technical information contained in the permit application. This may be a company representative or a consultant. 2 The compliance contact should be the point of contact for discussing inspection and compliance at the permitted facility. 3 The billing contact (Permit fees) should be the point of contact that should receive the invoice for fees associated with processing the permit application & issuing the permit. (Reg. 3, Part A, Section VI.B) 4 The billing contact (Annual fees) should be the point of contact that should receive the invoices issued on an annual basis for fees associated with actual emissions reported on APENs for the facility. (Reg. 3, Part A, Section VI.C) Page 1of1 Form APCD-101-Company Contact Info doc Attachment E AMBIENT AIR IMPACT ANALYSIS Kerr-McGee Gathering LLC (KMG) did not perform an air impact analysis as the emission estimates are below modeling threshold listed in Table 1. "Modeling Threshold of the Colorado Guideline" and per CDPHE PS 10-01 memo issued September 20, 2010. Attachment F C m E 8 W �o -co- , o =a 2E 3O 4 UC a O Ea a a 0 O a U j g E ' - • _ = G o O 1111 "1"1"1"1"IIIIII111111111111111111110 0 IlllIllllllllllillllllfli I IIIIII CO • IIIIIIIIII ? • � IIII x�$IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII • ILIIu!uunllHHIIIIHHIIIIIIIIIuiuIiu$ i • I1• kIIIIIIIleell • XIIIIIIIIIIIIIIIIIIII II IIIII 11111111 o � 111111111111uIuuIu111111111111111111 IIIIIIIIII _ IIIIIIIIIIIIIIIIn1IIIIIIIILIIIIIIII =1111111111 .---- -0000 P� mNNo-- Nw mqo Illllp II In - a — o70000 wf?� gbNtpNY pp .- ' ' n.1 •-• ore en o a8 o Y`o tos ° O1 'IN^IIIm ,-- A ao d � I{ N NII I� (s.- t Ad � ^. 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N 0 . . - } Z i 4 a; \:#: - \ | i 8 0_;; : § |2 \ , I C& dsnsa SIMMS /4 T4. <a 5 MMBIih i | I |I i | § ; s.30COO PtMwtisd CotCsratl.Tinle ( i | S ! 3 17 M6satr Hrw for Proms Tian 2 ATV j -l2\S� iifli |!,| 221 fK ( s{(.-! f||§ ! k&ji # § a ! .2 | | Q § f||f||I| al!!3l336 Attachment G Lancaster Plant Process Description The Lancaster gas processing plant will receive third party gas from the Kerr-McGee Gathering LLC pipeline system. The CO, is removed from the inlet gas stream utilizing four (4) 150 MMSCFD amine treaters. Each amine train will utilize thermal oxidizers to control emissions. The gas stream is then dehydrated using a molecular sieve. The molecular sieve beds are regenerated using dry gas that has been heated by the regeneration gas heater. The dry gas is then run through the cryogenic unit to super -cool the gas and removes natural gas liquids. The cryogenic unit is supplemented by six (6) 3,000 hp electric motor driven propane refrigeration compressors. The residue gas from the cryogenic unit is then compressed utilizing four (4) 12,000 hp electric motor driven compressors to deliver the gas to the residue pipeline. The produced NGL's are transported from the facility via a pipeline. Fort Lupton units 36 and 37 are scheduled to be shutdown with the start-up of Lancaster Train 1 and Unit 35 will be shutdown with the stall -up of Train 2. Units 36 and 37 boost inlet gas from 100 psi to about 200 psi and discharge directly into the intermediate pressure (IP) pipeline. As development of the basin continues and new formations are produced, the function of these units is no longer required. Unit 31 and 35 currently boosts inlet gas from about 100 psi to 1100 psi and discharges into the HP pipeline. Five additional inlet 3,750 -hp electric motors driving reciprocating compressor will be installed as pail of this project to feed the HP pipeline. This additional compression eliminates the need for Units 31 and 35. r N n II< 11 11-02-PF-1105 Ip t 1 of 1 MNCASTER PLANT PROCESS FLOW OMORAM MIRE 1REA7P16 TRNN?A _ "....---...\v• 1 ® o I ®. x 52 i I a in .V —t 4 2 w z v 'S -1n s i v I i et v • '� I 8 g o 6 SE Samuel Engineering. Inc. let nsSCen POMMY ....w >m.Ha,10 recoc aquae CODPW Pee mrue/ee . Ell LQ o Tr I a X 11J •1455/146 a 0 x k x ��J i a 1 4$ • I 1 111111 I o w - _I 111111 > # p r 4 ' I ;Hi N V I to M 2 I > i in w -% `. .> i> s� `. t W ^ I .> ��> ``> t0. I W a W <;> LL C-Ewr ` MAINE 0 Q r. 8 C J _; iT1 1 I I REVISIONS f r A. E I Q V• a. tsl__. in 1 -- t t t IIi11 1 1 1 1 1 I v .. s '03 in f C _ - ,� o ' V-1415 IE CONTACT N to �I'1'1 I t > 1 �J I Q O r 11{ G coin •< ! aw z I 5 4 --- 411 i -ii ,� St r- O L. a $ L- © .4...g 4 `r i . n z - W et r " a x HARGE PUMP to t i Li., W - cal t z I a. a _� I / $ LL C.J I)] t� _ i o in a o o - I NI .ne". rI a - ,--U W W r ` - �� N _ y REFERENCE DRAWINGS I W z > cn I LL o \ I ` I a IE : g R I> 1 N n f 134111 an tntni I, :I't r ° n 0 .- r t ; $ i ici o LL q. Q 8 a7 S # S S e a't 2 0 a :LANCASTER PLANT PROCESS F_CN OIAGRAN AMINE TREATING IRAN 2B rTh V-1650 -Fl ux ACC' z 3 a L� a % 1 Z n --, / Ln 1O Q J ^ O o a . s 8 �' ri ir : SE Samuel Engineering, Inc. Wa +qM JnW1..s JMC F.f%ALJWI ~Kan aFFM.OOJMIAGE OOKi^ •,. +:L ��.wu z L g Q i'� I a wIa Qa � a OS R O 8 / I Z x a a O az m < ~�` / I I IIIIII o \ I I i I l I > ® N r S 5 r. FL - _ reS : F I: -+-{/ + I < `' , to I VII a Y I L 1 Oa g ay, 6 S o **� T O ^ CO z Q 2 L--- J tl I � 4 _ -ut � _. 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M • r > : -r p y LI C z v = if) > < a try N. in M I �q v 1 Q--$ M I I U Q W in a -/\ Po o 44 cn in > Is. o M Nj to co rn a n > • Cr .«. W CO M I I WW CD 4.:.. N, a a m / r pQ in 0 M 7 Ire -' • - • • 0 - vs I 0 M � �F 8 �rn E-3325 UPPER SIDE I o To Irn I w I w O EMETHANIZER Ia I <� `> `� `> `. `> `� `> pl O �. Laos nit 0 4 01 01 • it REFERENCE D9A'A19G6 M M Q o I U a R' 0 O :p M Q o a �µ a i LI Rs « o u^ D -rg --, a Li0 R $ 2 y� DWG{ P If ti in z$.s ta,s Itrn4w C's c -ti s F Nrirl1 tW14YaC �~ o z / 2 ( ; 71 $ 54 o© )71 / 2 0 § Si | �' �9 �) 2 \ 2 /! \ x a! y — U �CC ) L. , : LANCASTER PLANT PROLE SS FLOW DIAGRAM ETHANE REJECTION CRYO TRAIN 2 ILI ■ \ | _ 0 \ -.. \g� . ■ \ o% 43- /7 [ ° ! ® § 2 ■ / t _n•• ANADARKO. d +t•. 2GE 0619 19400 • fl* F T. LUPTON, CO 'c+. 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IL. a 0.4 sera. avas ••I I REFERENCE DRAWINGS 4 /%4 'l 'it Cl Q II< { 7 O t r 11 s e .1 r. 0 rre 4 N Q ® w , LAVCASTER PLANI PROCESS FLOW WORMY HOT OS. SYSTEM TRAIN Li J 0 a O ,0. d E r 'j E E iw Z s EgW nail Al 011 l$ 'S I to V W D w iiti!! I ft 2 /oi`\ N D \ \ 4I i NI 3 a n' 0 i • - w o M W R AN Q. �,� /8a\ 1•e O K n i a :m 1 • • le O ' �' CI ni C.O .�._ �1 - k4 C t X 4. r C" tats t,.• 1 lnik. :1 r:u r, ;I +. r f� a a Q* a l�L N 4 I i ,-. W I:1 �_ id $$ X S 4. ^ / ` 6 �1 ^ y — H 0 S d Wa ►•• ii. r-- ►•• • es I 11 © L O R Zyy� 2 3, I•°s s 9p 10 gs I d 3 • C' 1 EN in U) ; Ez -O p Q B © r a � aII J J CI \ 12 I O Pn I I W r Sig 5S g_a � ` 1 ! � / ' 11 ! i i ! i I' <�; ;L ® I _I Il _] L t L Lm I a I � C: C:1_ B LIn �� II L, to in L �� 1 U p E • . 7 • • • • T at 0 • > r I 1t11 O Or W \01 1 \ ( - C Y .aa C Pi ►�• ►•• t. in InP > Pi ►•� II• * ►•� O > KF° if71 iuo f11 > O �' o 0 Oa it, I I 0 w i i 1 \ 1! 1 \ l! II ►•• .p• 0 —� O� -- ►.• 0 ,: ,: ,. • ' PEFERERCE DRAWINC5 -• ,\ SS I 8 8 w ,\ 8 B a 44. ti C" , 1 t'./1 t 1$; I. I at x U' L. U, a C) fb 2 0 r ' S * 2 I i W LL 4- r? g LANCASTER PLANT PROCESS FLOW DIAGRAM THERMAL OXIDIZER I FLARE TRAIN 2 to rn I a o N tD t J ) �� I c cn 2 tot A146.0AFOCO .,t• 2061940 AnadaaPill w, IL V; t pit y: ii -I J •. I J OM cnk 0 S I \ N I J .s"ia /C-.._ \ 1 0 o o o I- Q 0 M i O i- o N 0 M M 0 N V 1 Will •� I. g pt E ,, • 7. c 0 ,s SI Cl J Q7 al) W I rn W / hi' I / A \ V t� A \ / VH O rn O 1� i I I \:1 \ / V \ / V / I < Y 5 ...a -elite a nee ,J, O O ' •J M M Q, I ai I '-• a w w s O HN_ 0 MN Q7 O H o M w Th O V /\ 8 0 N Q1 Jb/\ m /\ /\ ' g n V /\ ,g 0 ; � J m /\ J /\ ; 8 It >' 0. raM.. r. s so i R E F ER E ICE DIIAWING li 'l 41 Ij.'1 i 14. I.1 t'i1 o OD O � ff 11 -01 -GL -0002 c LANCASTER RAM PLOT PUN CRYO3EJC UNIT 1 S It' ANAOARKO ^ 2061940 � tarty. FT. LUPTON. CO Polrioum Co'poration C •C � C �� (;!,6 2 v. W=O 0 _' vA a F• H: p� 9 W.1 ,,,,,,z,3FA Srp; •:r 1 .JIY.•ii'i SS tit e 11 AMOSY - J III O au:•r[•J 1....-.1 i _.:'.Ip -to !® I1 O -1 is I, — _ I — I. l 1 1 I f l l l 1 1 ...-.. el r = C gg' 0 • ..._.. _ E,= E, a• A00•K7 i �' y o,� 3 i • 1$E y L' _its .n s QI ii I ❑ " a !(� 1 I I J. I I I .01104Ca l r 4—..! ° -� — t _ o J rc � —_ l _ r� I 1 1 I r 1 I 1 r • 1 r �� -- u !: z _ _nay —-� = I -,r.I ..�,i t Hill- I I J1 III III lllil 4 ': MOM aQ r y 41 3 o o C i l / . .. i.- . O • t �j-� .- Or L l : P < 1, <. i f - -- r _... ..'1 �r�1i •••. I l l l r i frrTnitC 1 —• o f -- •I f 1 co a.'r : = :1 .. r aimawl wanal 1 A SID. r.'3 it 0 REFERENCE DRAWINGS if 1. h $ E 3 t i > i i i i > t t t M it aP dl9Cr•irlt Mete lDld 0-&11.0 64•130 aII He? .17 tolt01 at'inii 1'i=` i Attachment H Form APCD-306 Colorado Department of Public Health and Environment Air Pollution Control Division Operating and Maintenance Plan Template for Amine Sweetening Systems Ver. September 10, 2008 Colorado Department of Public Health and Environment The Air Pollution Control Division (Division) developed this Operating and Maintenance Plan (O&M Plan) for amine sweetening systems that are permitted at a synthetic minor facility in the State of Colorado. An O&M Plan for each type of amine sweetening system configuration. as described in Section 1. shall be submitted with the permit application. One O&M Plan may be used for multiple amine sweetening systems at one facility if each are controlled and monitored in the same manner. If the O&M Plan template is completed correctly. the Division will approve the O&M Plan and a construction permit will be issued with the requirement to follow the O&M Plan as submitted. If the template is not completed correctly. the Division will work with the facility to make corrections. Once a construction permit is issued. the facility operator must comply with the requirements of the O&M Plan upon conunencement of operation. Operators are not required to use this template. Independent case specific O&M Plans may be developed and submitted for approval with the permit application. However, the Division encourages the use of this template to expedite the permit application approval process. Submittal Date: 04/05/2013 Section 1 - Source Identification For new permits some of this information (i.e. Facility AIRS ID. Facility Equipment ID. Permit Number, and AIRS Point ID) may not be known at the time of application. Please only, fill out those fields that are known and leave the others blank. Company Name: Kerr-McGee Gathering LLC Facility Location: 16166 WCR 22. Foil Lupton. CO Facility Name: Lancaster Plant Facility AIRS ID (for existing facilities) 123/0057/ Units Covered by this O&M form Facility Equipment ID A-1 A-2 A-3 A-4 Permit Number 12WE1492 12WE1492 12WE1492 12WE1492 063 4 064 4 065 066 AIRS Point ID Amine Type Used a MDEA MDEA MDEA MDEA a Amine types include MEA, DEA. TEA, MDEA, and DGA Emission Points and Control Status: Check the appropriate boxes indicating whether the dehydration system(s) are equipped with a flash tank and whether or not the flash tank (if present) and still vent emissions are controlled or rec►rled or vented to atmosphere. P1 Flash Tank ® Still Vent P1 Controlled/Recycled ® Controlled/Recycled n Vented to atmosphere ❑ Vented to atmosphere Section 2 - Maintenance Schedules Check one of the following: Facility shall follow manufacturer recommendations for the operation and maintenance of equipment and control devices. These schedules and practices, as well as any maintenance records showing compliance with these recommendations, shall be made available to the Division upon request. Page 1 of 4 2013-04-5 A-1 to A-4 O&M.doc Colorado Department of Public Health and Environment Air Pollution Control Division • Facility shall follow individually developed maintenance practices and schedules for the operation and maintenance of equipment and control devices. These schedules and practices. as well as any maintenance records showing compliance with these recommendations, shall be made available to the division upon request and should be consistent with good air pollution control practices for minimizing emissions as defined in the New Source Performance Standard (NSPS) general conditions. Section 3 - Monthly Emission Modeling or Calculations The following box must be checked for O&M plan to be considered complete. The source will calculate emissions based on the methods and emission factors provided in the permit application and approved by the division, as reflected in the construction permit. Please see the operation and maintenance plan guidance document for further details and examples of emission calculations. Section 4 — General Monitoring Requirements Table 1 below details the schedule on which the source must monitor each of the listed operating parameters depending on the requested permitted emissions at the facility. Check the appropriate box based on the facility -wide permitted VOC emissions. Table 1 Parameter Monitoring Frequency Emissions Permitted Facility ≥ 80 tpy VOC Emissions Permitted Facility < 80 tpy VOC ❑ Lean Amine Circulation Rate Daily Weekly Gas Inlet Temperature Weekly Monthly Gas Inlet Pressure Weekly Monthly Volume of Gas or NGL Processed Monthly Monthly Tables 2 and 3 outline the methods by which the source may monitor the lean amine recirculation rate and the gas or NGL processed, respectively. hi Tables 2 and 3 the source must chose one primary monitoring method and, optionally, up to two backup monitoring methods. Table 2 Primary Back-up Lean Amine Recirculation Rate Monitoring Method ►1 Amine flow meter(s) — including flow from all pumps Record strokes per minute and convert to circulation rate — pump make/model and stokes per ❑ ❑ minute/ circulation rate relationship must be made available to the division upon request Assume maximum design pump rate b must be made available to the division upon — pump request make/model and circulation rate specifications ❑ ►�� b Note: if you are requesting to permit at a rate lower than the maximum design pump rate then this option should not be used as it will create de facto non-compliance. Table 3 Primary Back-up Volume of Gas or NGL Processed Monitoring Method Metered Outlet Compressor Suction Compressor Discharge ►�I /1 Inlet ❑ ❑ ❑ ❑Other: ❑ ❑ Metered ❑ Inlet ❑ Outlet n Compressor Suction n Compressor Discharge ❑Other: ❑ /1 Assume maximum design rate` s )ecifications shall be made available to the division upon request ❑ ❑ Other (to be approved by the division): attach method explanation and sannle calculations Note: if you are requesting to permit at a rate lower than the maximum contactor design rate then this option should not be used as it will create de facto non-compliance. Page 2 of 4 2013-04-5 A-1 to A-4 O&M.doc Colorado Department of Public Health and Environment Air Pollution Control Division Section 5 - Emission Control or Recycling Equipment Monitoring Requirements Table 4 below details the monitoring frequency for control equipment depending on the type of control equipment used and the requested permitted emissions at the facility. Check the appropriate box for "Monitoring Frequency" based on the facility - wide permitted VOC emissions. In addition, indicate still vent and flash tank emissions controls by checking the appropriate boxes. Table 4 Emissions Recycling Control Method or Still Vent Flash Tank Parameter Monitoring Frequency Permitted Facility ❑ Permitted Facility Emissions Emissions ≥ 80 tpy VOC < 80 tpy VOC Thermal Oxidizer. • CombustionChamberDaily Temperature Weekly Combustor or Flare Pilot Light Monitoring e Daily Weekly ❑ ❑ Method 22 Readings Daily Weekly Recycled System Vapor or Closed (Including Recovery Units) Loop To be determined by the source and approved by the division f ❑ ❑ Re-routed to Reboiler Burner - To be determined by the source and approved by the division g ❑ ❑ a Minimum Thermal Oxidizer Combustion Chamber Temperature If the facility uses a thermal oxidizer to control emissions then the minimum combustion chamber temperature shall be: Select one of the following options from Table 5: Table 5 1400 ° F ° F Based on manufacturer specifications. Specifications must be submitted with ❑ the permit application and made available to the Division upon request Based on testing performed. The test data shall be submitted and attached to the O&M Plan ❑ e Pilot Light Monitoring Options If the facility uses a Combustor or Flare then the source must indicate the method by which the presence of a pilot light will be monitored in Table 6. One primary method for Pilot Light Monitoring must be checked and. optionally, up to two backup methods can be checked. Table 6 Primary Back-up Monitoring Method ❑ / 1 Visual Inspection ❑ ❑ Optical Sensor Auto -Igniter Signal r ❑ ❑ ❑ Thermocouple f Recycled or Closed Loop System Monitoring Plan In the space provided below please provide a brief description of the emission control or recycling system, including an explanation of how the system design ensures that emissions are being routed to the appropriate system at all times, or during all permitted runtime. Page 3 of 4 2013-04-5 A-1 to A-4 O&M.doc Colorado Department of Public Health and Environment Air Pollution Control Division g Reboiler Burner Control Monitoring Plan In the space provided below please provide a brief description of the emission control system. including an explanation of how the system design ensures that emissions are being held or rerouted when the reboiler is not firing. Section 6 - Recordkeeuinu Requirements The following box must be checked for O&M plan to be considered complete. Synthetic minor sources are required to maintain maintenance and monitoring records for the requirements listed in sections 2, 3.4 and 5 for a period of 2 years. If an applicable Federal NSPS, NESHAP or MACT requires a longer record retention period the operator must comply with the longest record retention requirement. Section 7 - Additional Notes and O&M Activities Please use this section to describe any additional notes or operation and maintenance activities. Amine still vent and flash tank emissions will be routed to the plant emergency flare when the thermal oxidizer is down. Each amine unit (A-1, A-2, A-3 and A-4) still vent outlet will be equipped with a sulfatreat system to remove H2S from the stream. The equipment will achieve a minimum of 95% H2S removal efficiency. The sulfatreat vessels will be re -charged according the the manufacturer's recommended schedule. Note: These templates are intended to address operation and maintenance requirements of the State of Colorado for equipment operated at synthetic minor facilities. If the facility or equipment is subject to other state or federal regulations with duplicative requirements, the source shall follow the most stringent regulatory requirement. Page 4 of 4 2013-04-5 A-1 to A-4 O&M.doe Attachment I Lancaster Plant Cryogenic Plant Regulatory Analysis Section LO - State Regulations Regulation 3, Part A, Section II The fifteen newly proposed electric drive motors are not subject to APEN reporting requirements. The four 60 MMBtu/hr amine regeneration heat medium heaters, two 25 MMBtu/hr mole sieve regeneration gas heaters, two 150 MMSCFD Train 1 amine treatment systems each controlled with a thermal oxidizer. two 150 MMSCFD Train 2 amine treatment systems each controlled with a thermal oxidizer, two process flares, emergency generator, and plant fugitives are subject to APEN reporting requirements. Regulation 3, Part B, Sections I and II The four 60 MMBtu/lr amine regeneration heat medium heaters, two 25 MMBtu/hr mole sieve regeneration gas heaters, two 150 MMSCFD Train 1 amine treatment systems each controlled with a thermal oxidizer, two 150 MMSCFD Train 2 amine treatment systems each controlled with a thermal oxidizer, two process flares, emergency generator, and plant fugitives are subject to this regulation and required to obtain a construction permit prior to construction. The operation of these units will be limited as requested on the Air Pollutant Emissions Notice or in the permit application. Regulation 3, Part C The facility is currently operating as a major source with respect to the Title V Operating Permit Program. The facility will be required to submit a Title V Permit application modification for the proposed project within 12 months of startup. Regulation 3, Part D The facility is an existing major stationary source and is therefore subject to this Part. The net emission increase was calculated as required by Regulation 3, Part D, Section II.A.26 by summing the increase in actual emissions of NOx, CO, PM2_5 and CO2, from the proposed Lancaster project (Step 1) and the emissions increases and decreases within the defined contemporaneous period (Step 2). The proposed Lancaster project will not cause a significant net emission increase in NOx, PM2_5 and CO emissions but will cause a significant net emission increase in CO2, emissions. Therefore, since the proposed project results in a major modification for CO2e, a BACT analysis for Greenhouse gases is required. Regulation 3, Part L TT On October 21, 2010, 40 CFR Parts 51, 52, 70 and 71, Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule was adopted into Regulation 3, Part I.TT. The second step of the tailoring rule went into effect on July 1, 2011. Under the rule all new and existing sources that have the potential to emit at least 100,000 tpy CO2e will be subject to the PSD and title V requirements. Also, sources that have the potential to emit at least 100,000 tpy CO2e and undertake a modification that increase net emissions of GHGs by at least 75,000 tpy CO2e will also be subject to PSD requirements. The existing facility has a potential to emit at least 100,000 tpy CO2e and the proposed modification is greater than 75,000 tpy CO2e, therefore this project must submit a PSD permit application for GHGs. A BACT analysis for GHGs is included in Attachment J of the application. Regulation 6 Regulation 6 incorporates by reference the EPA's New Source Performance Standards (NSPS). NSPS applicability can be found in Section 2.0. Page 1 of 4 Regulation 7, Section XII The facility is located in the 8 -hour Ozone Control Area; therefore this facility is subject to Section XII of this regulation. The proposed project does not include product storage tanks, natural gas driven engines or a glycol dehydration system. All residue gas and produced natural gas liquids will be transported off - site via a pipeline, gas will be dehydrated with a molecular sieve and natural gas will be compressed with electric drive engines. Therefore, Section XII.C, XII.H and XVI will not apply to the proposed modification. As pertains to Section XII.G.1, the proposed modifications will be subject to the LDAR requirements in Subpart KKK and therefore comply with Section XII.G.1. Regulation 8 Regulation 8 incorporates by reference the EPA's National Emission Standards for Hazardous Air Pollutants (NESHAPs). NESHAP applicability can be found in Section 3.0 and Section 4.0. Section 2.0 - 40 CFR 60 - New Source Performance Standards (NSPS) Subpart A - General Provisions The General Provisions of the federal NSPS apply to any stationary source that contains an affected facility to which an NSPS applies. The proposed modification is subject to multiple NSPS, therefore. various portions of this Subpart will apply. Subpart Dc — Standards of Performance for Small Industrial, Commercial, Institutional Steam Generating Units Standards of Performance for Small Industrial, Commercial, and Institutional Steam Generating Units, applies to steam generating units having a maximum design heat input capacity less than or equal to 100 MIMBtu/hr but greater than or equal to 10 M IBtu/hr that are constructed, reconstructed or modified after June 9, 1989. A steam generating unit is defined in Section 60.41c as "a device that combusts any fuel and produces steam or heats water or heats any heat transfer medium". The proposed natural gas feed 60 MMBtu/hr amine heat medium heaters and 25 MMBtu/lr mole sieve regenerator heaters are subject to this Subpart. Natural gas is the sole fuel for both heaters and therefore, the sources are subject to the reporting and record keeping requirements of 60.48c. Subpart HIT - Standards of Performance for New Stationary Engines Subpart IIII applies to owners and operators of stationary compression ignition (CI) internal combustion engines. The proposed project includes one 670 -hp emergency diesel generator that will operate a maximum of 500 hours per year. The proposed engine will be subject to the emission standards of 60.4205(b), the operating requirements of 60.4207(b) and the compliance requirements of 60.4211. Subpart Kb- Standards of Performance for Volatile Organic Liquid Storage Vessels Subpart Kb applies to each storage vessel with a capacity greater than or equal to 75 cubic meters used to store volatile organic liquids (VOL) for which construction, reconstruction, or modification is commenced after July 23, 1984. There are no storage tanks proposed in this modification, therefore Subpart Kb does not apply. Page 2 of 4 Subpart LLL - Standards of Performance for Onshore Natural Gas Processing: 502 Emissions Subpart LLL applies to onshore natural gas processing plants that have gas sweetening units. The proposed modification includes four 150 MMSCFD amine gas sweetening units which will be subject to this subpart. All units will have a design capacity of less than 2 long tons per day of H2S in the acid ga.s and therefore will only need to comply with the recordkeeping requirements of 60.647(c). Subpart JJJJ- Standards of Performance for Stationary Spark Ignition Internal Combustion Engines Standards of Performance for Stationary Spark Ignition Internal Combustion Engines applies to manufacturers, owners and operators of stationary spark ignition (SI) internal combustion engines (ICE). This applies to engines that were ordered from the manufacturer after June 12, 2006 and are manufactured after July 1, 2007 and are greater than or equal to 500 hp or manufactured after July 1, 2008 and are less than 500 hp, and engines that are modified or reconstructed after June 12, 2006. The proposed modification includes ten electric drive motors and one diesel feed emergency generator, therefore, Subpart JJJJ does not apply. Subpart KKK- Standards of Performance for Equipment Leaks of VOC from Onshore Natural Gas Processing Plants Standards of Performance for Equipment Leaks of VOC from Onshore Natural Gas Processing Plants apply to affected facilities in onshore natural gas processing plants that commenced construction, modification or reconstruction after January 20, 1984. A natural gas processing plant is defined in the Subpart as any site "engaged in the extraction of natural gas liquids from field gas". The proposed modification will extract NGL from the field gas and is therefore subject to the LDAR requirements of this Subpart and State Regulation 7. Subpart 0000- Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution These standards of performance are applicable to natural gas wells, centrifugal compressors using wet seals, reciprocating compressors, pneumatic controllers, storage vessels, sweetening units, hydraulically refractured gas wells and equipment leaks that commence construction, modification or reconstruction after August 23, 2011. The proposed modification includes reciprocating compressors driven by electric motors that would be applicable to the requirements of this subpart. The Lancaster Plant is a gas processing facility and therefore the equipment leaks would be subject to the requirements of this subpart. Section 3.0 - 40 CFR 61 - National Emission Standards for Hazardous Air Pollutants Subpart V — National Emission Standards for Equipment Leaks (Fugitive Emission Sources) National Emission Standard for Equipment Leaks (Fugitive Emission Sources) applies to sources that are intended to operate in volatile hazardous air pollutant (VHAP) service. Based on engineering judgment, historical and recent gas composition and facility process it can be predicted that the percent VHAP content will never exceed 10 percent by weight; therefore Subpart V is not an applicable regulation for the facility. Section 4.0 - 40 CFR 63 - National Emission Standards for Hazardous Air Pollutants Subpart HH - National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities. Page 3 of 4 National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities applies to glycol dehydration units, storage vessels with potential for flash emissions, and ancillary equipment operating in volatile hazardous air pollutant (VHAP) service that is located at a facility which is a major source or area source of HAPs. VHAP service is defined in the Subpart as "a piece of ancillary equipment or compressor either contains or contacts a fluid which has a total VHAP concentration equal to or greater than 10 percent by weight". The proposed modification is located at a major source of HAPs, but does not include any glycol dehydration units, storage vessels with potential for flash emissions and equipment will not operate in VHAP service. Therefore, Subpart HH will not apply. Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines. National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines (RICE) establishes national emission limitations and operating limitations for HAPs emitted from stationary reciprocating internal combustion engines, and requirements to demonstrate initial and continuous compliance with the emission limitations and operating limitations. The facility is a major source of HAPs: therefore, the facility is subject to major source ZZZZ requirements. The proposed modifications include ten electric drive motors and once diesel feed emergency generator which are not subject to the requirements of this Subpart. Section 5.0 - 40 CFR 98 — Green House Gas Reporting Subpart A General Provisions applies to a facility that contains any source category (as defined in subparts C through JJ of this part) that is listed in this paragraph (a)(2) in any calendar year starting in 2010 and that emits 25,000 metric tons CO2e or more per year in combined emissions from stationary fuel combustion units, miscellaneous uses of carbonate, and all source categories that are listed in this regulation. The facility is subject to the reporting requirements of Subpart C and Subpart W. Page 4 of 4 Attachment J Kerr-McGee Gathering LLC Lancaster Plant Cryogenic Plant Project Greenhouse Gases Best Available Control Technologies (BACT) Analyses (Updated 3/26/2013) Table of Contents Facility Information 1 Process Description 1 Emission Sources 2 BACT Analysis Methodology 3 BAG Evaluation for Sources 5 Appendix A — Economic Analysis for CCS A Appendix B — RBLC Information Summary B Facility Information: The Lancaster Plant will be adjacent to the Fort Lupton Gas Plant which is in Weld County, CO at Northwest 1/4, Section 14, Township 2 North, Range 66 West. The coordinates are: Latitude: 40°, 16.14'N Longitude: 104°, 45.08'W The street address is: 16116 WCR 22 Ft. Lupton, CO 80621 The existing facilities currently operate under a number of construction permits as well as Title V operating permits. A recent acquisition of assets formerly owned by EnCana also brought the Platte Valley Station into the single facility complex. Process Description: The new 600 million standard cubic feet per day (MMscfd) cryogenic plant will be located adjacent to the existing Fort Lupton Facility which includes gathering compression and existing refrigeration plant. The plants will receive third party gas from the Ken McGee Gathering pipeline system in the Wattenberg Field, remove CO2 via amine treating, dehydrate the gas through the use of molecular sieve beds, extract natural gas liquids (NGL) through the use of the gas sub -cooled process (GSP) and SCORE cryogenic cooling processes and then re -compress the residue gas stream for sales. Inlet gas will be compressed with five (5) 3,750 -hp electric motor driven reciprocating compressors that will discharge to a high pressure pipeline that feeds the Lancaster Plant. The CO2 is removed from the inlet gas stream utilizing four (4) 600 gpm amine treaters. The amine treaters incorporate a thermal oxidizer per unit to control emissions. The gas stream is then dehydrated using a molecular sieve. The molecular sieve beds are regenerated using dry gas that has been heated by the regeneration gas heater. The dry gas is then rum through the cryogenic unit to super -cool it and remove natural gas liquids (NGL). The cryogenic units are supplemented by six (6) 3,000 hp electric motor driven propane refrigeration compressors. The residue gas from the cryogenic units is then compressed utilizing four (4) 12,000 hp electric motor driven compressors to deliver the gas to the transportation pipeline. The produced NGLs are also transported from the facility via a pipeline. The primary reason for treating the inlet gas with amine is to ensure that the NGLs meet pipeline specifications. The inlet gas has about 2.7 mole % CO2. Treating the feed gas avoids issues with liquid treating, such as amine carry over and meeting the pipeline water specification. Because the amine units are designed to remove CO2 from the natural gas, the generation of CO2 (GHG) is inherent to the process, and a reduction of CO2 emissions by process changes would only be achieved by a reduction in the process efficiency, which would result in natural gas that would not meet pipeline quality specifications and leave CO2 in the natural gas for emission to the atmosphere at downstream sources. The amine units do also emit methane (GHG) at the point of amine regeneration, due to a small amount of natural gas becoming entrained in the rich amine. Emission Sources: The proposed project triggers Prevention of Significant Deterioration (PSD) permitting thresholds for greenhouse gases, but does not trigger PSD for any criteria pollutants. The primary sources of GHGs proposed at the 600 MMscfd plant will be: C-4100 Solar 12,000 -hp Electric Drive Motor, Residue C-4200 Solar 12,000 -hp Electric Drive Motor, Residue C-4300 Solar 12,000 -hp Electric Drive Motor, Residue C-4400 Solar 12,000 -hp Electric Drive Motor, Residue C-5110 3000 -hp Electric Motor, Refrigeration Compression C-5210 3000 -hp Electric Motor, Refrigeration Compression C-5310 3000 -hp Electric Motor, Refrigeration Compression C-5410 3000 -hp Electric Motor, Refrigeration Compression C-5510 3000 -hp Electric Motor, Refrigeration Compression C-5610 3000 -hp Electric Motor, Refrigeration Compression ENG 105 3750 -hp Electric Motor, Inlet Compression ENG 106 3750 -hp Electric Motor, Inlet Compression ENG 107 3750 -hp Electric Motor, Inlet Compression 3750 -hp Electric Motor, Inlet Compression ENG 108 ENG 109 3750 -hp Electric Motor, Inlet Compression E-2015 Mole Sieve Regeneration Gas Heater with Ultra -Low NOx Burners E-2016 Mole Sieve Regeneration Gas Heater with Ultra -Low NOx Burners H-6051 Amine Regeneration Heat Medium Heater -Low NOx Burners H-6052 Amine Regeneration Heat Medium Heater -Low NOx Burners H-6053 Amine Regeneration Heat Medium Heater -Low NOx Burners H-6054 Amine Regeneration Heat Medium Heater -Low NOx Burners A-1 150 MMSCFD Amine Treater (Controlled with ATO-1) A-2 150 MMSCFD Amine Treater (Controlled with ATO-2) A-3 1.50 MMSCFD Amine Treater (Controlled with ATO-3) A-4 150 MMSCFD Amine Treater (Controlled with ATO-4) F-2 Vertical Process Flare F-3 Vertical Process Flare Caterpillar 839 -hp Diesel Emergency Generator GEN3 Plant Fugitives FUG 3 Kerr McGee Gathering - Lancaster Cryogenic Project GHG BACT Analysis Page 2 The proposed project triggers PSD for the estimated GHG emissions as it is estimated to emit 578,235 tons per year (tpy) CO2 equivalent (CO2e) including fugitive emissions. The net CO2 emissions will be 557,569 tpy however, as four existing engines will be removed as part of this project. The CO2e emissions are estimated by applying the global warming potential (GWP) of each GHG pollutant. The GWP for each pollutant is: CO2: 1 CH4: 21 N2O: 310 For example this means one ton of methane would equate to 21 tons of CO2e. Detailed calculations can be found in the calculations section of the permit application. UNIT CO2e tpy C-4100 - C-4200 - C-4300 - C-4400 - C-5110 - C-5210 - C-5310 - C-5410 - C-5510 - C-5610 - ENG 105 - ENG 106 - - ENG 107 - ENG 108 - ENG 109 E-2015 15,252 E-2016 15,252 H-6051 39,421 H-6052 39,421 H-6053 39,421 H-6054 39,421 A-1 94,121 A-2 94,121 A-3 94,121 A-4 94,121 F-2 6,220 F-3 6,220 GEN3 172 FUG 3 949 TOTAL 578,235 Kerr McGee Gathering - Lancaster Cryogenic Project GHG BACT Analysis Page 3 BACT Analyses Methodology: As of January 2, 2011, GHG is a regulated criteria pollutant under the PSD major source permitting program codified in Title 40 Code of Federal Regulations (CFR) Part 52 when they are emitted by new sources or modifications in amounts that meet the Tailoring Rule's set of applicability thresholds. For PSD purposes, GHGs are a single air pollutant defined as the aggregate group of the following gases: carbon dioxide (CO2), nitrous oxide (N2O), methane (CH4), and hydrofluorocarbons (HFCs). The PSD regulations do not prescribe a procedure for conducting BACT analyses. Instead, EPA has consistently interpreted the BACT requirement as containing two core criteria: 1. The BACT analysis must include consideration of the most stringent available technologies, i.e., those that provide the "maximum degree of emissions reduction." 2. Any decision to require as BACT a control alternative that is less effective than the most stringent available must be justified by an analysis of objective indicators showing that energy, environmental, and economic impacts render the most stringent alternative unreasonable or otherwise not achievable. EPA has developed what it terms the "top -down" approach for conducting BACT analyses and has indicated that this approach will generally yield a BACT determination satisfying the two core criteria. Under the "top -down" approach, progressively less stringent control technologies are analyzed until a level of control considered BACT is reached, based on the environmental, energy, and economic impacts. The top -down approach shall be utilized in this BACT analysis. The five basic steps of a top -down BACT analysis are listed below: 1. Identify all available control technologies with practical potential for application to the specific emission unit for the regulated pollutant under evaluation; 2. Eliminate all technically infeasible control technologies; 3. Rank remaining control technologies by effectiveness and tabulate a control hierarchy; 4. Evaluate most effective controls and document results; and 5. Select BACT, which will be the most effective practical option not rejected, based on economic, environmental, and/or energy impacts. Kerr McGee Gathering - Lancaster Cryogenic Project GHG BACT Analysis Page 4 BACT Evaluation for Sources: Step 1: Identify Control Options The following are potentially applicable control technologies for controlling GHG emissions associated with the Ermines: 1. All the new compressor engines at this facility will be run on electric power resulting in no GHG emissions from these sources. Therefore, no further analysis is necessary for the engines. 2. The 839 -hp diesel emergency generator will operate a maximum 500 his/yr limited to emergency situations only. The generator will meet all emissions, operating and compliance requirements of NSPS Subpart FM for stationary compression ignitions ICEs. All manufacturers recommended maintenance will be performed as required. The following are potentially applicable control technologies for controlling GHG emissions associated with the Amine Vents: 1. Proper Design and Operation: The amine units are designed to include a flash tank, in which gases (i.e., including CO2 and methane) are removed from the rich amine prior to regeneration, thereby reducing the amount of waste gas created. The amine units at this facility shall be constructed and operated for optimal performance; 2. Amine Unit Flash Tank Off -gas Recovery System: The amine unit flash tank off - gases shall be routed to the proposed thermal oxidizer. 3. Routing Amine Unit Regenerator Vent to a Thermal Oxidizer: This control device will reduce the methane emissions by 99% and will convert those emissions to CO2, which has a lower GWP; 4. Routing Amine Unit Regenerator Vent to a Flare: This control device will reduce the methane emissions by 98% and will convert those emissions to CO2, which has a lower GWP; 5. Carbon Capture and Storage (CCS): This involves capturing CO2, transporting it as necessary, and permanently storing it instead of releasing it into the atmosphere. The process involves three main steps: • Capturing CO2 at its source by separating it from other gases; • Transporting the captured CO2 to a suitable storage location (typically in compressed form); and • Storing the CO2 away from the atmosphere for a long period of time, for instance in underground geological formations, or within certain mineral formations. ■ In the project two CCS approaches were looked at: acid gas injection well and enhanced oil recovery (EOR) The following are potentially applicable control technologies for controlling GHG emissions associated with the Heaters: 1. Fuel Selection: The heaters at the site shall be fired on pipeline quality natural gas. This results in 28% less CO2 production than fuel oils (see 40 CFR Part 98, Subpart C, Table C-1, which is included in Appendix E, for a comparison of the GHG emitting potential of various fuel types); Kerr McGee Gathering - Lancaster Cryogenic Project GHG BACT Analysis Page 5 2. Efficient Heater Design: New burner design improves the mixing of fuel, creating a more efficient heat transfer. At the new facility, new burners shall be utilized. Burner management systems shall be utilized on the heaters, such that intelligent flame ignition, flame intensity controls, and flue gas recirculation optimize the efficiency of the devices. 3. Periodic tune-ups and maintenance for optimal thermal efficiency: Maintenance shall be performed routinely per vendor recommendations or the facility's maintenance plan. The components shall be serviced or replaced as needed. The heaters shall be timed once a year for optimal thermal efficiency; 4. Oxygen trim control: Combustion devices operate with a certain amount of excess air to reduce emissions and for safety consideration. An inappropriate mixture may lead to inefficient combustion. Regular maintenance of the draft air intake systems of the heaters can reduce energy usage. Draft control is applicable to new or existing process heaters and is cost effective for process heaters rated at 20 to 30 M1VIBtu/hr or greater. The heaters will have air and fuel valves mechanically linked to maintain the proper air to fuel ratio. The following are potentially applicable control technologies for controlling GHG emissions associated with the Process flares: 1. The process flares will be designed according to best engineering practices and API Standards 521 and 537. Both flares will utilize a burner management system, a pilot monitoring system and a combustion air blower to optimize combustion. The following are potentially applicable control technologies for controlling GHG emissions associated with the Overall Facility: 1. Overall efficiency of facility; 2. Existing Fort Lupton equipment permanent shutdowns; 3. Compliance with NSPS Subpart KKK for fugitive equipment. Step 2: Eliminate Technically Infeasible Control Options At the current time acid gas injection wells for this location appear to be technically infeasible. There are no known acid gas injection wells operating in the Denver-Julesberg (D -J) Basin. The current consensus is that acid gas injection wells would not sequester the CO2, but rather the CO2 would migrate to other producing wells creating a recycle of CO2. Step 3: Characterize Control Effectiveness of Technically Feasible Control Options The efficiency improvement/GHG reduction technologies are ranked* below: • Use of electric -driven engines (100%); • Install amine unit flash tank off -gas recovery systems (100%); • Routing the amine unit vents to a thermal oxidizer (99% for methane, and generates CO2); • Routing the amine unit vents to a flare (98% for methane, and generates CO2); Kerr McGee Gathering - Lancaster Cryogenic Project GHG BACT Analysis Page 6 • Efficiencies within the plant (variable); • Hours of operation limitation emergency generator (94.3%) • Fuel selection (28% when comparing natural gas and No. 2 Fuel Oil); • Burner management systems on the heaters, with intelligent flame ignition, flame intensity controls, and flue gas recirculation (10-25%); • Burner management systems on process flares, with a pilot monitoring system and combustion air blowers (10-25%); • Efficient heater design (10%); • Annual time -ups and maintenance (1-10%); • Oxygen trim control; • CCS (not a feasible option for the Project due to technical, environmental, and economic reasons, as discussed in Step 4). *The following documents were used to identify any available control efficiencies including some vendor specifications: i) Available and Emerging Technology for Reducing Greenhouse Gas Emission from the Petroleum Industry dated October 2010 and ii) Energy Efficiency Improvement and Cost Saving Opportunities hies for the Petrochemical Industry: An ENERGY STAR Guide for Energy Plant Manager, Document Number LBNL-964E, dated June 2008, Step 4: Evaluate Most Effective Control Options As part of this project the following options that were listed in Step 1, shall not be proposed for implementation as BACT: 1. The routing of amine unit regenerator vent to a flare (98% control), because a more efficient technology (thermal oxidizer, with 99% efficiency) will be addressed. 2. Amine flash tank off -gas recovery. The amine flash tank off -gas will be routed to the thermal oxidizer to aid in combustion of the regenerator vent gas. 3. CCS is not considered to be feasible, based upon its lack of readily available technologies and negative environmental and economic impacts. However, per EPA guidance, EPA has identified CCS as an add-on control technology that must be evaluated as if it were technically feasible. The amine flash tank off -gas will be routed to the thermal oxidizer for combustion rather than recycled to the plant inlet. Due to the low Btu and the cooling effect of the CO2 in the amine regenerator vent gas stream, additional Btu content (assist gas) will need to be added to aid in combustion in the thermal oxidizer. If the flash gas were to be routed back to the plant inlet, additional compression would be needed and the energy required would negate the potential savings on the flash gas. The design will utilize the high Btu flash gas to help supply some of the additional Btu need to offset a portion of the pipeline gas utilized for the remaining assist gas. The emerging CCS technology is an "end of pipe" add-on control method comprised of three stages (capture/compression, transport, and storage). CCS involves separation and capture of CO2 from the exhaust gas, pressurization of the captured CO2, transmission of CO2 via Kerr McGee Gathering - Lancaster Cryogenic Project GHG BACT Analysis Page 7 pipeline, and injection and long term geologic storage of the captured CO2. CCS can also consist of use of CO2 in Enhance Oil Recovery (EOR) opportunities. The goal of CO2 capture is to concentrate the CO2 stream from an emitting source for transport and injection at a storage site or location utilizing EOR. CCS requires a highly concentrated, pure CO2 stream for practical and economic reasons. Extracting CO2 from exhaust gases requires equipment to capture the flue gas exhaust and to separate and pressurize the CO2 for transportation. Extracting CO2 from the exhaust gases of the heaters and thermal oxidizers would require equipment to capture the flue gas exhaust and to separate and pressurize the CO2 for transportation. The exhaust stack streams will be low pressure, basically atmospheric pressure. The streams would also be emitted at high temperatures. The CO2 separation would require the removal of all other pollutants from the streams. The process would require compression to increase the pressure from atmospheric to pipeline pressures. The process would also require the reduction of the temperature of the streams by several hundreds of degrees prior to separation, compression, and transmission. Basically an entire plant similar to what is being proposed in this project (smaller in size) would have to be constructed to remove the CO2. This process would add even more GHG emissions and large costs to the project. This option is not environmentally, nor economically feasible. Even if we assumed there was a feasible way to separate the CO2 from the combustion streams, there would be several logistical issues that need to be resolved including obtaining right of way (ROW) and National Environmental Policy Act (NEPA) efforts for a pipeline to transport the CO2 to a location that would be available to receive and handle a continuous long term stream of CO2. The geological formations available near this proposed site are not technically feasible to store the CO2 as mentioned previously. In addition EOR is not feasible at any large scale level in the D -J Basin due to its geology and multiple owner/operators in the area. There may be some single well CO2 EOR projects forthcoming in this area, but nothing of the magnitude that would be able to handle the continuous supply of CO2 that would be produced from this project. Since different owner/operators are located in close proximity, large scale EOR is not feasible. The exhaust streams from the heaters and thermal oxidizers would have to be cooled, compressed, and treated prior to being able to enter a pipeline. A conservative estimate on the cost of equipment that could possibly be installed for these purposes was assumed to be $50,000,000. The nearest identified area utilizing EOR with CO2 is approximately 300 miles from the Plant. At a cost of $80,000 per inch mule to install a 12" pipe line, the total cost for the pipeline alone would be approximately $288 million ($80,000 x 12 x 300). Detailed engineering was not done on horsepower requirements to boost the gas along the approximately 300 miles of pipeline because a definitive route was not chosen. However, we could estimate it take 80,000 horsepower (including horsepower required at the site to get the gas up to a pipeline pressure, intermediate pipeline booster compression, and end point injection compression). The cost of that additional horsepower would be approximately $200,000,000. There would also need to be additional surface equipment (i.e. separators, dehydrators, storage tanks, etc.) at the booster sites and all equipment would have to be able to handle the acid gas (CO2). The cost of the additional surface equipment was not estimated Kerr McGee Gathering - Lancaster Cryogenic Project GHG BACT Analysis Page 8 in this exercise. Even excluding a portion of the cost, the engine cost and pipeline cost would equate to a $151/ton cost of control based on CO2e emissions from the proposed equipment except the process flares and fugitives sources. There is a high likelihood that the remote booster stations would not be able to utilize electric compression, therefore it will have negative impact on the environment. Hence the use of CCS to reduce GHG emissions is not economically or environmentally feasible for this project, and the timing required for ROW issues and NEPA analyses would extend the project start date out by years. In addition there is no assurance that any available CO2 pipeline or FOR area would even have the capacity to handle the CO2 from this project. Step 5: Establish BACT After discussion in the previous sections, the proposed BACT for this project would include: En ines- r Electric motors on compressor engines o 84,750 hp of electric driven compression r Emergency generator o Limit hours of operation to 500 hrs/yr o Follow NSPS Subpart Ha requirements o Follow manufacturer recommended maintenance Amine Vents - r Routing off -gases to thermal oxidizer for combustion o Thermal Oxidizers utilize combustion air preheaters and acid gas heat exchangers Heaters and Process Flares - r Design, operation, and management criteria as specified in Steps 1 & 3 Overall Facility - r Efficiencies o Engine shutdowns Compliance with NSPS Subpart KICK as applicable o LDAR to reduce fugitive leaks The thermal oxidizers proposed to control emissions from the amine vents will utilize combustion air preheaters as well as an acid gas heat exchanger to minimize additional fuel requirements. The engineering design firm has estimated that the preheaters and heat exchangers will reduce assist gas requirements by approximately 11 MIVIBtn/hr. That efficiency relates to an avoided amount of 5,637 tpy of CO2e for each thermal oxidizer. Kerr-McGee Gathering is committing to 84,750 horsepower of electric compression as part of this project. The choice of electric compression will eliminate GHG emissions from the compression needs of the plant. Based on Caterpillar data on recent 3600 series engines, CO2 emissions from natural gas fired engines are approximately 450 grams per horsepower - Kerr McGee Gathering - Lancaster Cryogenic Project GHG BACT Analysis Page 9 hour. That would equate to 368,267 tpy of CO2e from 84,750 horsepower of natural gas fired engines. Not to mention there would be overall energy efficiencies by utilizing electric compression in this project. As part of the overall project, four natural gas fired engine at the existing Fort Lupton plant will be permanently shut down (EU-31, EU-35, EU-36 and EU-37). The nnntime restrictions on the engines will reduce up to 20,666 tpy of CO2e. Total quantifiable CO2e reductions of 394,570 tpy are proposed as part of the BACT as well as numerous reductions that are not as easily quantifiable, such as maintenance and operation conditions on the heaters. Overall the proposed project will treat 600 MMscfd of gas with only a modest increase in CO and VOC emissions with a reduction in NOx emissions. While there is a proposed 557,235 tpy emission increase in GHG emissions in the project (including fugitives), it is effectively removing the CO2 from the gas stream that would ultimately have been emitted at some point downstream of this facility. The overall avoided and reduced GHG emissions for the project are greater than 50% of the proposed total net GHG emissions. Kerr McGee Gathering - Lancaster Cryogenic Project GHG BACT Analysis Page 10 APPENDIX A Economic Analysis for CSS Kerr McGee Gathering - Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B Best Available Control Technology Control Cost Analysis Worksheet (Based on Office of Air Quality Planning and Standards, EPA, OAQPS Control Cost Manual, Fourth Edition, EPA 450/3-90-006, January 1990, Section 2.3.2) Targeted Emission Reference No. without Control (TPY) with Control (TPY) Pipeline 564846 0 Booster Stations CO2 Removal Equipment Reference No. Interest Rate (i) Control System Life (n) I, Capital Recovery Factor (CRF) • Capital Investment (P) . Annual Maintenance Cost Capital Recovery Cost (CRC) Realized Economic Benefit I Pipeline 0.08 _ 20 0.102 _ $288,000,000 $2,589,600 $29,333,436 SO Compression 0.08 _ 10 0149 _ $200,000,000 $15,000,000 $29,805,898 SO CO2 Removal Equipment 0.08 15 i U.117 $50,000,000 $2,500,000 $5,841,477 $0 "n" is the control system economic life, typically thought to be 10-20 years. "i" is the considered the annual pretax marginal rate of return on private investment (i.e., what it may cost you to borrow the money). "P" is the capital investment required to install the controls (i.e., equipment purchase cost, installation/retrofit cost, engineering, etc.). Annual Maintenance Cost is the yearly costs to maintain the control effectiveness (i.e., cleaning, testing, etc). CRC = CRF ` P CRC = Capital Recovery Cost (Annualized cost of control over the life of the control) CRF = Capital recovery Factor P = Capital Investment CRF = ill+i)n/(1+i)n-1 i = Annual Interest Rate n = Economic life of the control Total Annual Cost (TAC) = Annual Maintenance Cost + Capital Recovery Cost - Realized Economic Benefit Cost to Control = TAC / (Targeted Emission Volume Without Control - Targeted Emission Volumn with Control) Reference Number TAC (5) Cost to Control ($/Ton) Pipeline $85,070,411 _ 1151 Booster Stations CO2 Removal Equipment APPENDIX B RBLC Information Summary Kerr McGee Gathering - Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B Previous Page 1 Report Date: 04/12/2012 INDEX OF CONTROL TECHNOLOGIES DETERMINATIONS NOTE: Draft determinations are marked with a " * " beside the RBLC ID. Company Name RBLC ID Country Permit Date(Est/Act) Process Process Description Type OTTUMWA GENERATING STATION COGENERATION PLANT SABINE PASS LNG TERMINAL PORT DOLPHIN ENERGY LLC EM -HOLY CROSS DRILLING PROJ NINEMILE POINT ELECTRIC GENERA DIRECT REDUCTION IRON PLANT USA *IA -0101 USA *LA -0256 USA *LA -0257 USA *FL -0330 USA *FL -0328 LA -0254 USA LA -0248 USA 01/12/2012 ACT 12/06/2011 ACT 12/06/2011 ACT 11.110 Boiler #1 15.210 COGENERATION TRAINS 1-3 (1-10. 2-10. 3-10) 17.130 EMERGENCY GENERATOR 15.200 Combined Cycle Refrigeration Compressor Turbines (8) 19.390 Wet/Dry Gas Flares (4) 19.390 Marine Flare 50.999 Acid Gas Vents (4) 15.100 Simple Cycle Generation Turbines (2) 17.130 Generator Engines (2) 15.100 Simple Cycle Refrigeration Compressor Turbines (16) 50.999 Fugitive Emissions 12/01/2011 ACT 99.999 Fugitive GHG emissions 11.310 Boilers (4 - 278 mmbtu/hr each) 11.310 Power Generator Engines (3) 10/27/2011 ACT 13.220 08/16/2011 ACT 01/27/2011 ACT 17.110 17.110 17.110 17.110 17.110 42.000 Boiler Emergency Fire Pump Engine Emergency Engine Crane Engines (units 3 and 4) Crane Engines (units 1 and 2) Main Propulsion Engines Storage Tanks 17.110 EMERGENCY DIESEL GENERATOR 17.210 99.009 99.009 11.310 15.210 EMERGENCY FIRE PUMP UNIT 6 COOLING TOWER CHILLER COOLING TOWER (CHILL CT) AUXILIARY BOILER (AUX-1) COMBINED CYCLE TURBINE GENERATORS (UNITS 6A &6B) 81.900 DRI-101 DRI Unit #1 Iron Oxide Day Bins Dust Collection 81.290 DRI-111 - DRI Unit #1 Acid Gas Absorption Vent 81.900 DRI-102 DRI Unit #1 Iron Oxide Screen Dust Collection 81.900 DRI-202 DRI Unit #2 Iron Oxide Screen Dust Collection 81.900 DRI-105 DRI Unit #1 Furnace Feed Conveyor Baghouse 81.900 DRI-205 DRI Unit #2 Furnace Feed Conveyor Baghouse 81.900 DRI-103 DRI Unit #1 Coating Bin Filter 81.900 DRI-203 DRI Unit #2 Coating Bin Filter 81.900 DRI-104 DRI Unit #1 Iron Oxide Fines Handling 81.900 DRI-204 DRI Unit #1 Iron Oxide Fines Handling 99.009 DRI-113 - DRI Unit #1 Process Water Cooling Tower 99.009 DRI-213 - DRI Unit #2 Process Water Cooling Tower 99.009 DRI-114 - DRI Unit #1 Clean Water Cooling Tower 99.009 DRI-214 - DRI Unit #1 Clean Water Cooling Tower 81.290 DRI-117 - Briquetting Mill 99.190 DRI-118 - DRI Barge Loading Dock 81.290 DRI-115 - Product Screen Dust Collection 81.290 DRI-116 - Screened Product Transfer Dust Collection 81.290 DRI-107 - DRI Unit No. 1 Furnace Dust Collection 81.290 DRI-207 - DRI Unit No. 2 Furnace Dust Collection 11.310 DRI-109 - DRI Unit #1 Package Boiler Flue Stack 11.310 DRI-209 - DRI Unit #2 Package Boiler Flue Stack 81.290 DRI-112 - DRI Unit No. 1 Product storage silo Dust Collection 81.290 DRI-212 - DRI Unit No. 2 Product storage silo Dust Collection 19.390 DRI-210 - DRI Unit No. 1 Hot Flare 19.390 DRI-110 - DRI Unit No. 1 Hot Flare 81.200 DRI-208 - DRI Unit #2 Reformer Main Flue Stack 81.200 DRI-108 - DRI Unit #1 Reformer Main Flue Stack 81.290 DRI-206 - DRI Unit No. 2 Upper Seal Gas Vent 81.290 DRI-106 - DRI Unit No. 1 Upper Seal Gas Vent 81.290 DRI-211 - DRI Unit #1 Acid Gas Absorption Vent 81.900 DRI-201 DRI Unit #2 Iron Oxide Day Bins Dust Collection BASF FINA NAFTA REGION OLEFINS PRYOR PLANT CHEMICAL RUMPKE SANITARY LANDFILL CPV ST CHARLES TX -0550 USA OK -0135 USA OH -0330 USA MD -0040 USA 02/10/2010 ACT 50.003 N-11, REACTOR REGENERATION EFFLUENT 50.003 N-10. CATALYST REGENERATION EFFLUENT 50.003 N-18. DECOKING DRUM 02/23/2009 ACT 61.999 COOLING TOWER #2 61.012 PRIMARY REFORMER 62.014 NITRIC ACID PLANT #1 62.014 NITRIC ACID PLANT #3 61.999 CONDENSATE STEAM FLASH DRUM -AMMONIA PLT 4 61.999 COOLING TOWER #1 13.310 NITRIC ACID PREHEATERS #1. #3. AND #4 61.999 CARBON DIOXIDE VENT 61.012 AMMONIUM NITRATE PLANTS #1 AND #2 61.999 GRANULATOR SCRUBBERS #1. #2. AND #3 13.310 BOILERS #1 AND #2 62.014 NITRIC ACID PLANT #4 12/23/2008 ACT 29.900 ENCLOSED COMBUSTORS (4) 29.900 MUNICIPAL WASTE LANDFILL 29.900 OPEN FLARE 99.150 PAVED ROADWAYS AND PARKING AREAS 29.900 CANDLESTICK FLARE (5) 11/12/2008 ACT 99.999 COOLING TOWER 17.210 INTERNAL COMBUSTION ENGINE - EMERGENCY GENERATOR 17.210 INTERNAL COMBUSTION ENGINE - EMERGENCY FIRE WATER PUMP 13.310 BOILER 15.110 COMBUSTION TURBINES (2) 13.310 HEATER ACTIVATED CARBON FACILITY LA -0148 USA 05/28/2008 ACT 11.110 MULTIPLE HEARTH FURNACES / AFTERBURNERS NUCOR DECATUR LLC AL -0231 USA AIR PRODUCTS BAYTOWN I I RUMPKE SANITARY LANDFILL. INC Previous Page I • _ TX -0481 USA OH -0281 USA 99.009 COOLING TOWERS TWO (2) ELECTRIC ARC FURNACES AND THREE (3) 06/12/2007 ACT 81.210 LADLE METALLURGY FURNACES WITH TWO (2) MELTSHOP BAGHOUSES 13.310 VACUUM DEGASSER BOILER 13.310 GALVANIZING LINE FURNACE 81.290 VACUUM DEGASSER 11/02/2004 ACT 99.999 PARTS WASHER 50.007 FUGI'I _ I _ VES (4) 64.003 MSS PROCESS STEAM VENT 64.003 PROCESS STEAM VENT 19.800 EMERGENCY GENERATOR TANK 64.003 MSS-NONCONDENSIBLES (PROPYLENE VENTING) 19.310 FLARE (NORMAL OPERATION) 64.003 RECTISOL VENT 19.800 EMERGENCY GENERATOR 42.005 DIESEL FUEL TANK 13.390 BOILER STACK (START UP) 11.390 BOILER STACK (HIGH BTU FUEL) 50.005 COOLING TOWER 50.005 SUPPLEMENTARY COOLING TOWER 11.390 BOILER STACK 06/10/2004 ACT 29.900 PORTABLE TUB GRINDER 29.900 LANFILL ROADWAYS 29.900 LEACHATE STORAGE BASIN 29.900 LEACHATE AERATION BASIN 29.900 FUGITIVE EMISSIONS FROM LANDFILL AND GAS COLLECTION SYSTEM 17.210 PORTABLE ENGINE 4.68 MMBTU/H 29.900 NEW SOLID WASTE DISPOSAL WITH LANDFILL GAS GENERATION 17.210 PORTABLE ENGINE 0.58 MMBTU/H 29.900 LOAD -IN. LOAD -OUT, TURNING. AND WIND EROSION 29.900 PORTABLE SCREENER 29.900 EXISTING SOLID WASTE DISPOSAL WITH LANDFILL GAS GENERATION Kerr-McGee — Lancaster Plant 12WE1492 Issuance 1 Summary of Preliminary Analysis & Prevention of Significant Deterioration Review Air Pollution Control Division Stationary Sources Program Colorado Department of Public Health and Environment December 2012 Permit Number: 12WE1492 Issuance 1 AIRS ID: 103/0057 Points 031, 057 through 069 Application Completeness Date: November 30, 2011 (for initial application) Revised application received April 18, 2012 Applicant: Kerr-McGee Gathering LLC Location: 16116 WCR 22, Fort Lupton, CO. Weld County. Permit Engineer: Stephanie Chaousy, P.E. Reviewer: Chris Laplante Kerr-McGee — Lancaster Plant 12WE1492 Issuance 1 Table of Contents I. PROJECT DESCRIPTION 3 II. PROJECT LOCATION 4 III. MAJOR MODIFICATION AND NETTING ANALYSIS 4 IV. APPLICABLE REGULATIONS 7 V. BACT & RACT ANALYSIS 8 VI. CONCLUSION AND PROPOSED ACTION 16 Kerr-McGee — Lancaster Plant 12WE1492 Issuance 1 I. PROJECT DESCRIPTION Kerr-McGee has submitted a request to modify their Ft. Lupton Gas Plant to include a new cryogenic plant referred to as the Lancaster Plant. The original request for modification was received November 30, 2011 and requested to add a 300 MMSCFD cryogenic Plant. Kerr- McGee submitted a revised request received April 18, 2012 to increase the cryogenic plant capacity to 600 MMSCFD. Also, as part of this modification, Kerr-McGee is requesting to remove three inlet compression engines at the existing Ft. Lupton facility. The inlet compression modifications are requested due to the changing compression needs and gathering efficiencies. The application was considered administratively complete on November 30, 2011. The application is deemed complete as of the day of receipt since the Division did not notify the applicant that the application was incomplete within sixty calendar days of receipt (Regulation No. 3, Part B, Section III.B.4). The Division analyzed the operations to ensure that all pollutant emitting activities are appropriately accounted for as part of this stationary source. The facility currently includes both the Ft. Lupton Gas Plant and Platte Valley Station (formerly the Encana Ft. Lupton plant). These facilities are now under common control since Kerr-McGee acquired assets formerly owned by EnCana on March 1, 2011. All three (3) plants, including the proposed Lancaster Plant, are under common ownership, are contiguous or adjacent and part of the same major group for industrial coding. The Division also reviewed exploration and production operations owned by Kerr McGee within the area of these plant operations. There is one well pad with one active well the Warner 5-14 (AIRS ID 123-4747-001) located approximately 100 feet from these plants which is scheduled to be plugged and abandoned prior to the commencement of operation of the new Lancaster plant. In addition, the Warner John C GU1 well is located within a quarter mile of the proposed Lancaster plant but only produced 15 bbls in 2012 and is a de minimus source not subject to Air Pollutant Emissions Notice (APEN) reporting. Furthermore, the Warner John C GU1 well is not dependent on the Fort Lupton Complex being operational since gas enters a pipeline that has the option of being sent to multiple compressor stations and gas plants. Therefore, this well pad is not considered to be part of the stationary source under review. The Division considers the current source determination for this facility to be accurate and the proper pollutant emitting activities are included in this analysis. The existing facility includes both the Ft. Lupton Gas Plant and Platte Valley Station. These facilities are now under common control since Kerr-McGee acquired assets formerly owned by EnCana on March 1, 2011. The plants, including the proposed Lancaster Plant, are contiguous or adjacent to each other and the plants are all part of the same major group for industrial coding. The facility is an existing major stationary source for carbon monoxide (CO), volatile organic compounds (VOC) and oxides of nitrogen (NOx) in an ozone nonattainment area The new 600 MMSCFD cryogenic plant will receive third party gas from the Kerr-McGee Gathering pipeline system in the Wattenberg Field. remove carbon dioxide (CO2) via amine treating, dehydrate the gas through the use of molecular sieve beds, extract natural gas liquids (NGL) through the use of the gas sub -cooled process (GSP) and SCORE cryogenic cooling processes and then re -compress the residue gas stream for sales. Inlet gas will be compressed with five (5) 3,750 -hp electric motor driven reciprocating engines that will discharge to a high pressure pipeline that feeds the Lancaster Plant. The CO2 will be removed from the inlet gas stream utilizing four (4) 150 MMSCFD amine treaters, each with a lean amine recirculation rate of 600 gallons per minute (gpm). Emissions from each amine units will be routed to a thermal oxidizer for control of VOCs and methane (CH4). The amine system will include four (4) heaters for amine regeneration heat medium. Each amine regeneration heater will have a design output rating of 60 MMbtu/hr. The gas stream will then be dehydrated Kerr-McGee — Lancaster Plant 12WE1492 Issuance 1 using a molecular sieve. The molecular sieve beds will be regenerated using dry gas that has been heated by a regeneration gas heater. The proposed plant will include two mole sieve regeneration gas heaters, each with a design output rating of 25 MMBtu/hr. Emissions from maintenance activities will be routed to two process flares. The dry gas will then run through the cryogenic unit to super -cool it and remove NGL. The cryogenic unit will be supplemented by six (6) 3.000 hp electric motor driven propane refrigeration compressors. The residue gas from the cryogenics unit will then be compressed utilizing four (4) 12,000 hp electric motor driven compressors to deliver the gas to the transportation pipeline. Additionally, one (1) 839 horsepower diesel -fueled emergency generator will be located at the plant. The Division views the requested permit changes to be a physical change and a change in the method of operation. As such, the project needs to be reviewed to determine if a major modification is triggered under the Prevention of Significant Deterioration (PSD) rules. This review includes determining the emission increases associated with this project to establish if a significant emission increase will occur for any regulated New Source Review (NSR) pollutant. The revised construction permit will include all applicable requirements, including BACT requirements, emission limitations, production limitations, monitoring/testing requirements, and other applicable state and federal requirements. II. PROJECT LOCATION The proposed Lancaster Cryogenics Plant will be located adjacent to the Fort Lupton Gas Plant and Platte Valley Station. The plant is located in Weld County, CO at Northwest 1/4, Section 14, Township 2 North, Range 66 West. The street address is 16116 WCR 22, Ft. Lupton, CO 80621. The geographic coordinates for this facility are as follows: Latitude: 40°, 16.14'N Longitude: 104°, 45.08'W This facility is located in an area designated by the EPA as a non- attainment area for ozone. The area is designated as attainment for all other pollutants, including CO. III. MAJOR MODIFICATION AND NETTING ANALYSIS The Lancaster gas plant will be built at a location that is currently an existing major stationary source and has the potential to emit more than 100,000 tons/yr of carbon dioxide equivalent (CO2e). Kerr McGee's proposed Lancaster gas plant expansion project will involve the installation of new equipment as listed in Table 1 of the project emissions increase analysis referenced below. The equipment will be installed in two phases. Kerr-McGee — Lancaster Plant 12WE1492 1 X192 Issuance 1 Table 1: Lancaster Plant Step 1 PSD Applicability Determination Urns ILA NO-. CO VOC CO2e SO2 PM 2 5 Lancaster Project C-4100 Solar 640612,000 -hp Electric Drive Motor, Residue - - - - - - C-4200 Solar C406 12,000 -hp Electric Drive Motor, Residue - - - - - C-4300 Solar 040612,000 -hp Electric Drive Motor, Residue - - - - - C-4400 Solar 640612,000 -hp Electric Drive Motor, Residue - - - - - C-5110 3,000 -hp Motor, Ref rig - - - - - C-5210 3,000 -hp Motor, Rettig - - - - - - C-5310 3,000 -hp Motor, Ref rig - - - - - - C-5410 3,000 -hp Motor, Rettig - - - - - C-5510 3.000 -hp Motor, Ref rig - - - - - - C-5610 3,000 -hp Motor, Ref rig - - - - - ENG 105 3,750 -hp Motor, Inlet Compression - - - - ENG 106 3,750 -hp Motor, Net Compression - - - - - ENG 107 3,750 -hp Motor, Inlet Compression - - - - - - ENG 108 3,750 -hp Motor, Inlet Compression - - - - - - ENG 109 3,750 -hp Motor, Inlet Compression - - - - - - (-2015 Mole Steve Regeneration Gas Heater with Ultra Low NOx Burners 5.2 5.2 2.5 15,252 0.1 1.0 (-2016 Mole Sieve Regeneration Gas Heater with Ultra Low NOx Burners 5.2 5.2 2.5 15,252 0.1 10 H-6051 Heat Medium Heater with Low NOx Burners 13.5 13.5 1.8 39,421 0.2 1.7 H-6052 Heat Medium Heater with Low NOx Burners 13.5 115 1.8 39,421 0.2 17 H-6053 Heat Medium Heater with Low NOx Burners 13.5 13.5 18 39,421 0.2 t7 H-6054 Heat Medium Heater with Low NOx Burners 115 13.5 1.8 39,421 0.2 1.7 A-1 150 MMSCFD Amine Treater (Controlled w ith ATO-1) 7.9 6.6 3.6 94,121 1.1 0.6 A-2 150 MMSCFD Amine Treater (Controlled with ATO-2) 7.9 6.6 3.6 94,121 1.1 0.6 A-3 150 MMSCFD Amine Treater (Controlled with ATO-3) 7.9 6.6 3.6 94,121 1.1 0.6 A-4 150 MMSCFD Amine Treater (Controlled with ATO-4) 7.9 6.6 3.6 94,121 1.1 0.6 F-2 F-2 Lancaster Plant Process Flare 1 7 3 14.6 16 6,220 0.03 0.32 F-3 F-3 Lancaster Plant Process Flare 2 7 3 I 14.6 1.6 6,220 0.03 0.32 GEN3 Caterpillar 839 -hp Diesel Emergency Generator 2.6 0.2 0.0 172 1.5 0.1 Lancaster Project Emission Increase 113.1 120.2 23.9 6.7 11.8 577,286 PSD Significance Threshold 40.0 100.0 40.0 75,000 40 10 0 Step 2, Net Emission Increase Determination Required" Yes Yes No Yes No Yes Kerr McGee indicated that the proposed plant expansion does not include any modifications to existing equipment, nor is there expected to be increases in emissions from non -modified existing equipment due to de -bottlenecking or increased utilization. Therefore, the calculated project emissions increase analysis is based solely on the new emissions units that will be installed. As new emissions units, the applicant analyzed the potential to emit (PTE) (based on requested permitted emissions) from each emissions unit to determine if the project would be considered a significant modification for any regulated pollutant. Based on the PTE analysis completed the emission increases from the project alone would exceed the significant emissions increase thresholds for NOx, CO and PM2.5 as defined in Regulation 3. Part D, Section II.A.42. See Table 1 above for details. In addition, this project would be subject to regulation for greenhouse gases (GHG) since the project emissions increase is greater than 75,000 tons CO2e per year which is significant as defined in Regulation 3, Part A, Section I.B.44.c. Based on the conclusion the proposed project would be a significant increase in emissions for NOx, CO, PM2.5 and CO2e, Kerr McGee provided a net emissions increase analysis with the application. The net emissions increase analysis follows the provisions of Regulation 3, Part D, Section II.A.26. In addition, baseline actual emissions (BAE) were determined based on the definitions contained Regulation 3, Part D, Section II.A.4. Kerr McGee established a 5 year contemporaneous period for each of the two phases of the project. Phase 1 is scheduled to begin operation January 1, 2014 and phase 2 is scheduled to begin operation January 1, 2015. Therefore, the combined contemporaneous period for the two phases encompassed the time period from January 1, 2009 (5 years prior to commencement of operation of phase 1) to January 1, 2015 (the commencement of operation of phase 2). Table 2 in the permit application netting analysis outlines the detailed contemporaneous emissions increases and decreases that have and will occur during the contemporaneous period. The Division worked with Kerr McGee to Kerr-McGee — Lancaster Plant 12WE1492 Issuance 1 ensure that all contemporaneous changes are appropriately identified in this analysis. Only those creditable emissions increases or decreases were counted in the net emissions calculations. Since this project will occur over two phases the Division analyzed each phase to determine if a significant net emissions increase will not occur during either phase. Phase 1 project emissions include the first processing train installation plus the diesel emergency generator. Contemporaneous emissions accounted for in this part of the netting analysis include those changes that occurred and are creditable during the five year time period from January 2009 to January 2014. Phase 2 project emissions include all new emissions units proposed for processing trains 1 and 2 as well as the diesel emergency generator. Contemporaneous emissions accounted for in this part of the netting analysis include those changes that occurred and are creditable during the five year time period from January 2010 to January 2015. The results of this analysis (emissions in tons/yr) are summarized in the tables below. Phase 1 NOx CO CO2e PM2.5 Project Emissions 57.9 60.5 288,727 6.0 Contemporaneous Emissions Increases 85.9 56.8 64,898 4.0 Contemporaneous Emissions Decreases -162.7 -37.7 -18,002 -5.4 Net Emissions Change -18.9 79.6 335.623 4.6 Significant Level 40 100 75,000 10 Are the net emissions increases significant? No No Yes No Phase 2 NOx CO CO2e PM2.5 Project Emissions (Sum Phase 1 & Phase 2) 113.2 120.8 577,283 11.9 Contemporaneous Emissions Increases 52.3 43.0 43,650 2.6 Contemporaneous Emissions Decreases -216.0 -82.7 -20,665 -7.5 Net Emissions Change -50.5 81.1 600.268 7.0 Significant Level 40 100 75,000 10 Are the net emissions increases significant? No No Yes No Through the course of the review of the netting analysis submitted with the original application, the Division sought corrections in several areas to ensure accuracy. Several important corrections of note include: 1. Proper accounting for both filterable and condensable PM2.5 emissions from new emissions sources and subsequent addition of a PM2.5 netting analysis to the application. 2. Correcting the baseline actual emissions (BAE) for three of the engines that will be removed from service as part of this project. The emission reduction credits for carbon monoxide (CO) were adjusted downward by 58% at the request of the Division since the two year period from 2003-2004 used to represent BAE predated emissions control requirements that came in 2008. These corrections were made in accordance with Regulation 3, Part D, Section II.A.4.b.(iii). As a result, Kerr McGee will shut down an additional engine (EU-31) to net out of a significant modification for CO. Corrections to the netting analysis were addressed in the revised netting analysis submitted on March 12, 2013. As indicated in the above tables. the Division determined the net emissions increase of regulated pollutants from both phases of this project will be below the significant modification thresholds for NOx. CO and PM2.5 as established in Regulation 3, Part D, Section II.A.42. Therefore, neither Prevention of Significant Deterioration (PSD) nor Non -attainment Area New Source Review Kerr-McGee — Lancaster Plant 72W E1492 Issuance 1 (NANSR) review requirements apply for these pollutants. In addition, the Division determined the net emissions increase of CO2e exceeds the significant threshold of 75,000 tons per year and renders the project subject to regulation for GHG. Therefore, the application Kerr McGee submitted for the Lancaster gas plant expansion project only addressed PSD review requirements for GHGs alone. IV. APPLICABLE REGULATIONS Public Notice: This application is subject to public comment for the following reasons (Regulation No. 3, Part B, III .C): . Projected controlled increase in emissions exceed 25 tons per year. • The Cryogenics Plant is subject to a BACT determination. In addition, any interested person may submit a written request for a public comment hearing to be held pursuant to section 1 .7.0. of the commission's procedural rules to receive comments regarding the foregoing concerns, the suffciency of the preliminary analysis, and whether the division should approve or deny the permit application. Best Available Conirol Technology (BACT): As discussed above, the Division agrees with Kerr-McGee's analysis that the proposed modification will not result in a significant net increase in emissions for NOx, CO, VOC, SO2, and PM2.5 (Regulation No. 3, Part D, VI .A. 1 ). The Division also concludes Kerr-McGee's application is subject to PSD review for GHGs because the project would lead to an emissions increase of GHGs for a facility as described at 40 CFR § 52.21 (b)(49)(iv). Under the project, increased GHG emissions will have a mass basis over zero tpy and carbon dioxide equivalent (CO2e) emissions are calculated to exceed the applicability threshold of 75,000 tpy (Kerr-McGee calculates CO2e emissions from the proposed project of 577,288 tPY) The Division is the permitting authority for regulated NSR pollutants including GHGs. Thus, the permit will address GHGs as well as criteria pollutants. Since GHGs are emitted above the significance levels, a BACT review is required for GHGs. See Section IV below for the BACT Analysis. Source Impact Analysis: Regulation No. 3, Part D, VI .A.2 would require the owner or operator of the proposed source or modification to demonstrate to the Division that allowable emission increases from the proposed source or modifcation in conjunction with all other applicable emissions increases or reductions (including secondary emissions) will not cause or contribute to concentrations of air pollutants in the ambient air in violation of: • Any state or national ambient air quality standard in any baseline area or air quality control region; • Any applicable maximum allowable increase over the baseline concentration in any area. However, consistent with EPA guidance, the Division has not required the applicant to model emission impacts or conduct ambient monitoring for GHGs, and we have not required any assessment of impacts of GHGs in the context of the additional impacts analysis or Class I area provisions. This approach is based on the fact that no National Ambient Air Quality Standards (NAAQS) or Increment standards exist for GHGs. Additionally, since the net emissions increase of NOx, SOx, CO and PM2.5 are less than significance thresholds, a source impact analysis is not required per the provisions of Regulation 3, Part D, Section VI.B. 1 .b. MACT and NSPS: The proposed equipment will be subject to several federal regulations including: . NSPS IIII applies to emergency stationary compression ignition reciprocating internal diesel combustion engines with a 2007 model year and later and with a displacement of Kerr-McGee - Lancaster Plant 72W H A92 Issuance 1 less than 30 liters per cylinder. This facility has one ( 1 ) Caterpillar 4-stroke rich burn diesel emergency generator that is subject to this subpart. • NSPS Dc applies to steam generating units having a maximum design heat input capacity less than or equal to 100 MMBtu/hr but greater than or equal to 10 MMBtu/hr that are constructed, reconstructed or modified after June 9, 1989. This facility has two (2) heaters that have a design input rating at 30 MMBtu/hr and four (4) heaters with a design heat input rating at 77 MMBtu/hr and all six heaters have a construction date (TBD) after June 9, 1989. Therefore, these heaters are subject to this subpart. . NSPS OOOO applies to each sweetening (amine) unit and each sweetening unit followed by a sulfur recovery unit manufactured after August 23, 2011 . The four (4) amine units at this facility are not subject to NSPS OOOO because these sources will have a design capacity less than 2 long tons/day HZS in the acid gas based on the information submitted in the application. This source will be required to keep for the life of the equipment an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H2S expressed as sulfur. No other requirements apply to the amine units. • NSPS OOOO applies to equipment Leaks of VOC from onshore natural gas processing plants. Affected facilities at onshore natural gas facilities (any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids (NGLs) or both) after August 23, 2011 . This facility is considered a natural gas processing plant with a construction date after August 23, 2011 . Therefore, it is subject to this subpart. • MACT ZZZZ includes requirements for emergency stationary reciprocating internal combustion engines (RICE). Since the one (1 ) generator onsite is an emergency generetor, it is subject to this subpart. . For MACT DDDDD, the six (6) heaters fall under the Maximum Achievable Control Technology (MACT) source category of Industrial, Commercial and Institutional Boilers and Process Heaters. Since the Division has not yet adopted this Federal rule into Regulation 8, there is no requirement to comply in the permit, but this subpart is referenced in the "Notes to Permit Holder' section of the permit. • MACT HH is required if a facility is considered major for HAPS when summing up the HAPS from all HAP emitting units at the faciliry. This facility is considered major for HAPS when summing up all the emitting sources; however, the Lancaster Cryogenic Plant does not include any glycol dehydration units or storage vessels with potential to flash emissions. However, since it is an affected facility and it is major for HAPS, the Cyrogenic Plant is subject to the equipment leak standards under MACT HH. V. BACT & RACT ANALYSIS Best Available Control Technology (BACT) has been defined in Colorado's Regulation No. 3, Part D, II .A.8 as "An emission limitation (including a visible emissions standard) based on the maximum degree of reduction of each regulated NSR pollutant that would be emitted from any proposed major stationary source or major modification that the Division or Commission, 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 the best available control technology result in emissions of any pollutant that would exceed emissions allowed by the applicable standards in the Code of Federel Regulations, Title 40, Parts 60 and 61 (Regulation No. 6, Part A, and Regulation No. 8, Part A) as in effect on the effective date of this clause, but not including later amendments, unless such amendments are specifically incorporated by reference in accordance with the provisions of Colorado Revised Statutes section 24�-103 (12.5)." Since GHGs are emitted above the significance levels, a BACT review is required for GHGs. Note that the Division has applied the policies and prectices reflected in the EPA document Kerr-McGee — Lancaster Plant 72W E1492 Issuance 1 entitled "PSD and Title V Permitting Guidance for Greenhouse Gases" (March 2011 ). Consistent with that guidance, we have not required the applicant to model or conduct ambient monitoring for GHGs, and we have not required any assessment of impacts of GHGs in the context of the additional impacts analysis or Class I area provisions. Instead, the Division has determined that compliance with the BACT analysis is the best technique that can be employed at present to satisfy the additional impacts analysis and Class I area requirements of the rules related to GHGs. For the BACT analysis, conVol technologies were evaluated using EPA's "top-down" 5-step analysis procedure to make the BACT determination. This procedure ensures that each determination considers the most stringent control technologies available, and presents a reasoned justifcation for the BACT determination, considering energy, environmental and economic impacts and other costs. EPA has published industry specific white papers that summarize information on control techniques and measures to mitigate greenhouse gas emissions for specifc industrial sections. EPA has not yet published a white paper specific to oil and gas industry. The Division has reviewed certain white papers to help inform this evaluation where appropriate. The Division has also reviewed recent GHG BACT permits issued by EPA Region 6 for similar oil and gas facilities. Applicable Emission Units The majority of the GHG emissions associated with the project is from combustion sources (i.e., engines, regeneretors, heaters, flare, and thermal oxidizers) and the amine units. The piping component leaks (i.e. , fugitive emissions) and diesel emergency generator contribute a small amount of GHGs. Stationary combustion sources primarily emit CO2, and small amounts of nitrous oxide (N2O) and methane (CH4). The amine units emit CO2. Within the permit application, Kerr-McGee provided a 5-step top-down BACT analysis for each GHG emission source. The BACT analyses and other technical information in Kerr-McGee's application are incorporated into this analysis and technical review document. The following equipment is subject to this GHG PSD Permit: . Fifteen ( 15) Compressor Engines • Six (6) Heaters . Four (4) Amine Units • Four (4) Thermal Oxidizers • Two (2) Flares • Fugitives • One (1 ) Diesel Generetor. Compressor Engines As part of this project, Kerr-McGee is proposing to install five 3,750-hp electric drive inlet gas compressors (ENG 105, ENG 106, ENG 107, ENG 108 and ENG 109), four 12,000-hp electric drive residue compressors (C-4100, C-4200, C-4300, and C-4400) and six 3,000-hp electric dnve refrigeration compressors (C-5110, C-5210, G5310, C-5410, C-5510, and C-5610). Kerr-McGee identifed in their BACT analysis that the engines will comply with BACT by using electricity instead of natural gas. Kerr-McGee identified the use of electric driven engines as the primary control technology identified in step 3 of the BACT analysis giving a 100% reduction in GHG emissions over a gas fired engine. Since Kerr-McGee is proposing to operate all of the new compressor engines on electric power, no GHG emissions result from these sources. Thus, the Division does not consider the engines to be GHG emission units and therefore the electric compressor engines are not subject to BACT. Kerr-McGee - Lancaster Plant 72W H A92 Issuance 1 Heaters The proposed Cryogenics Plant will include four amine regenerator heat medium heaters (H- 6051 , H-6052, H-6053, and H-6054), each design rated for an output at 60 MMBtu/hr, and two molecular sieve gas heaters (E-2015 and E-2016), each design rated for an output at 25 MMBtu/hr. The heaters at the site will be fired on pipeline-quality natural gas. The gross calorific value (GCV) of the natural gas is determined semiannually in compliance with 40 CFR Part 98.34(a)(6). According to EPA's GHG Mandatory Reporting Rule, natural gas generally has a homogeneous nature and a low variability in the characteristics of the fuel. The GCV analysis will be used to determine compliance with the BACT limit on a 12-month rolling basis. Step 3 of the BACT analysis is where the applicant ranks the technically feasible options by control effectiveness. Step 3 of Kerr-McGee's BACT analysis identified fuel selection as the highest ranked control option for heaters based on a 28% reduction in GHG emissions when using natural gas in lieu of No. 2 fuel oil. This control percentage is derived from GHG emissions estimates based on the emission factors in 40 CFR Part 98 Subpart C, Table C-1 for various fuel types. All of the new heaters will be equipped with next generation ultra-low-NOx burners (NGULNB) and burner management systems. Step 3 of the BACT analysis identified that a bumer management system with intelligent flame ignition, flame intensity controls, and flue gas recirculation as the second highest renked control option for heaters based on 10 — 25% reduction in GHG emissions. Specifically, the heaters will be equipped with Low-NOx staged/quenching (flue gas recirculating) burners capable of ineeting 0.04 Ib-NOx/MMBtu with additional excess O2 (i.e. , requiring a larger combustion air blower). The heaters will be equipped with a burner management system with intelligent flame ignition, flame intensity controls, and flue gas recirculation. While a search of EPA's RACT/BACT/LAER Clearinghouse did not identify a GHG control for natural gas-fired heaters, the Division did review EPA Region 6 Final Statement of Basis for GHG PSD Preconstruction Permit for Energy Transfer Company (ETC), Jackson County Gas Plant dated March 2012. In the Statement of Basis, EPA Region 6 concluded that a NOX emission factor of 0.036 Ib-NOx/MMBtu qualifed as a NGULB. Since Kerr-McGee is proposing to comply with an equivalent NOx emission rate, the Division considers these heaters to be equipped with the most effcient heater design and burner management system. The heaters will be tuned annually for thermal effciency. Annual tune-ups and maintenance can result in up to a 10% reduction in CO2 emissions, as identified in the BACT analysis. The heaters' air and fuel valves will be mechanically linked to maintain the proper air to fuel ratio. Thus, controlling the air/fuel ratio reduces CO2 emissions and is considered as part of BACT. The Division has determined that for this source, annual tune-ups, routine maintenance, and controlling the air to fuel ratio are BACT for the heaters. As explained above, the Division is determining for these emissions units that good combustion practice (i .e. NGULNBlquenching) along with a burner management system is BACT for regeneretors and heaters for CO2, N2O, and CH4. The heaters shall have a BACT limit based on the CO2 from the natural gas GCV analysis divided by the measured daily natural gas output for the Cyrogenic Plant in Million Standard Cubic Feet (MMSCF). This approach will provide a Ib of CO2/MMSCF limit. Compliance is based on a 365-day rolling averege. The BACT limit for the Cyrogenic Plant is 1 ,716.9 Ibs CO2/MMSCF. The Cryogenic Plant consists of heaters E-2015 (AIRS ID 057), E-2016 (AIRS ID 058), H-6051 (AIRS ID 059), H-6052 (AIRS ID 060), H-6053 (AIRS ID 061 ), and H-6054 (AIRS ID 062). Startup and shutdown emissions are authorized. All heaters have associated startup and shutdown emissions addressed in this application. The emission rate during start-up and shutdown are identical to normal operation . This is determined for this facility as BACT. The Division has also reviewed GHG BACT limits and controls for similar heaters at other similar oil and gas facilities. To date, there are three similar facilities that have established GHG BACT Kerr-McGee - Lancaster Plant 12W E1492 Issuance 1 control device for heaters as energy efficiency/ good design and combustion practices. The plants are ETC Jackson County Gas Plant (Permit Number PSD-TX-1264-GHG), Enterprise Products Operating, LLC Mont Belvieu Complex (Permit Number PSD-TX-1286-GHG), and Energy Transfer Partners, Lone Star NGL Mont Belvieu Gas Plant (Permit Number PSD-TX- 93813-GHG). Thus, the BACT limits discussed above are consistent with BACT determinations for similar emission units at similar facilities. An initial stack test demonstration will be required for CO2 emissions from each emission unit. An initial stack test demonstration for CH4 and N2O emissions is not required because the CH4 and N2O emission are less than 0.01 % of the total CO2e emissions from the heaters and are considered a de minimis level in comparison to the CO2 emissions, making initial stack testing unnecessary. Amine Units The proposed Cryogenics Plant will include four amine units (A-1 , A-2, A-3, and A-4), each design reted to process 150 MMscf per day of natural gas. A primary purpose of the amine units is to remove CO2 from the natural gas. The generation of CO2 (GHG) is inherent to the process, and a reduction of CO2 emissions by process changes would only be achieved by a reduction in the process efficiency, which would result in natural gas that would not meet pipeline quality specifications and leave CO2 in the natural gas for emission to the atmosphere at downstream sources. The amine units do also emit methane (GHG) at the point of amine regeneration, due to a small amount of naturel gas becoming entreined in the rich amine. The amine units are each designed to include a flash tank, in which gases (i.e. , including CO2 and methane) are removed from the rich amine stream prior to regeneration, thereby reducing the amount of waste gas created. The amine unit flash tank off gases and the amine unit still vents (also referred to as the regenerator vent) will all be routed to thermal oxidizers to control CH4 emissions. The highest renked control technology in Step 3 for the amine units was Carbon Capture and Storage (CCS). Note that Kerr-McGee had identifled CCS as the lowest renked control technology but since the control option would result in 100% control, the Division considers CCS as the highest ranked control option. Step 4 of the BACT analysis is where the applicant evaluates the most effective controls. Kerr-McGee stated that CCS technology was deemed not feasible due to technical, environmental, and economic reasons identified in Step 4 of the analysis. The CCS process involves capturing CO2, transporting it as necessary, and then permanently storing it instead of releasing it into the atmosphere. The process requires: . Capturing CO2 at its source by separating it from other gases. • Transporting the captured CO2 to a suitable storage location (typically in compressed form) and • Storing the CO2 in underground geological formations or within certain mineral formations. Two possible storege methods were evaluated including acid gas injection and enhanced oil recovery (EOR). Kerr-McGee discussed in Step 4 of the BACT analysis that geological formations near the proposed site are not technically feasible to store CO2. EPA guidance and other recent EPA reviews of GHG BACT for similar sources support that geologic storage (acid gas injection) is currently commercially unavailable. Kerr-McGee discussed that EOR is also not feasible at any large scale level in the Denver-Julesburg Basin due to geology of the basin and multiple owners/operetors in the area. Kerr-McGee stated that there may be some single well CO2 EOR projects in the near future but the projects would not be able to handle the continuous supply of CO2 generated from this proposed plant. Kerr-McGee estimated that the next nearest area utilizing EOR with CO2 would be approximately 300 miles from the proposed site. Assuming the EOR site is feasible, Kerr-McGee then estimated the cost to trensport the CO2 along 300 miles of pipeline. The cost analysis included the pipeline cost at $80,000 per inch mile Kerr-McGee — Lancaster Plant 72W E1492 Issuance 1 to install a 12-inch pipeline with a total capital cost of $288 million. Kerr-McGee also estimated cost to compress the CO2 and maintain pressure along the pipeline at a total capital cost of $200 million. Kerr-McGee noted that this cost did not include additional surface equipment that is typically required at each booster station such as separators, dehydrators, and storage tanks. Kerr-McGee also estimated cosis to separate and concentrate the CO2 stream at $50 million (for amine units only). The cost to control for CCS is then approximately $151 per ton CO2 removed. Kerr-McGee also noted that the booster stations required along the pipeline would most likely not be able to utilize electric compression due to their remote locations. Kerr-McGee estimated that it would require approximately 80,000 hp to increase the CO2 stream to pipeline pressure at the site, intermediate pipeline booster compression and endpoint injection compression . This compression could result in signification criteria pollutant emissions and GHG emissions. The additional CO2 removal equipment that would be required at the Lancaster Plant for capturing the CO2 would also cause a negative environmental impact by increasing criteria pollutant and GHG emissions for the project. Thus, Kerr-McGee stated that CCS was not selected because it had a negative environmental impact. Since CCS requires a highly concentreted, pure CO2 stream for practical and economic reasons, the analysis, as discussed above, focused primarily on the amine units which would have the most pure and concentreted CO2 streams. Kerr-McGee noted in Step 4 of the BACT analysis that routing other GHG sources to a CCS system, such as the heaters and the thermal oxidizers, would require even more processing to separete and purify the CO2 since the streams would contain lower concentretions of CO2 than the amine streams. The heater and thertnal oxidizer emission streams would also be at essentially atmospheric pressure and higher tempereture which would require more steps to cool and then compress. Thus, utilizing CCS for the other sources would increase the costs as well as increase criteria pollutant and GHG emissions. Since Kerr-McGee considered CCS infeasible due to economic, environmental and energy impacts for the amine units, it would also be infeasible for the heaters and thermal oxidizers. The Division agrees that CCS is eliminated from consideration for the amine units and the other emission units because the costs associated with it are economically unreasonable and because of the negative environmental and energy impacts. The highest ranked control technology in Step 3 for the amine units was installing a flash tank off- gas recovery system which Kerr-McGee estimated as 100% control assuming that the flash tank off-gas is recycled back to the plant inlet. Kerr-McGee stated in Step 4 of the BACT analysis that if the flash tank off-gas is routed to the plant inlet, additional compression would be needed which would require additional energy and potentially negate the off-gas recovery system. The Division considers routing the flash tank off-gas back to the plant inlet as common industry practice and is not aware of a significant compression need for this step. Thus, the Division does not consider additional compression to be a valid concern for this control option. Kerr-McGee also stated that sending the flash gas to the thermal oxidizer will aid in combustion of the amine still vent emissions. The amine still vent emissions stream will have a very low heat content and thus additional assist gas will be required to properly combust it. By routing the flash tank off-gas to the same control device as for the still vent, Kerr-McGee will utilize the high heat content of the flash gas and then minimize the amount of assist gas required to combust the still vent emissions. For these reasons, Kerr-McGee is proposing to route the flash tank off-gas to a thermal oxidizer instead of the plant inlet. The Division agrees that routing the flash tank off-gas to the inlet would cause additional criteria pollutant emissions because additional supplemental fuel would have to be routed to the thermal oxidizer. Further, the Division is unclear that routing the flash tank off-gas to the plant inlet results in an ultimate reduction of GHG emissions since a primary purpose of the plant is to remove CO2 from the gas. Since the CO2 would be recycled back to the plant inlet, it would still have to ultimately be removed at some point within the process or the process efficiency would be KerrvMcGee - Lancaster Plant 72W H A92 Issuance 1 reduced. Thus, the Division considers it appropriate to apply the same BACT control to the flash tank as to the still vent. Routing the amine unit flash tanks and still vents to a thermal oxidizer is considered BACT for CO2 and CH4 for the amine units. This was the second highest ranked control technology in Step 3 of the BACT analysis for the amine units giving a 99% reduction in methane emissions. Further, by routing to a thermal oxidizer, the CH4 emissions will be converted to CO2, which has a lower GW P. Routing the amine unit regenerator vent to a flare was renked third in step 3 of the BACT analysis for the amine units giving a 98% reduction in emissions of CH4 while genereting CO2 emissions. Thus, the Division is detertnining for this site that the use of a thermal oxidizer for control of CH4 is BACT for the amine units (AIRS ID 063, 064, 065 and 066). The Division has also reviewed GHG BACT limits and controls for amine units at other similar oil and gas facilities. To date, there are two similar facilities that have established GHG BACT control device for amine units. For ETC Jackson County Gas Plant (Permit Number PSD-TX- 1264-GHG), BACT for the amine unit was determined to be routing the flash tank back to the plant inlet and routing the still vent to a thermal oxidizer. For Energy Transfer Partners, Lone Star NGL Mont Belvieu Gas Plant (Permit Number PSD-TX-93813-GHG), BACT for the amine units was routing the still vent and flash tank to a thermal oxidizer. Thus, the BACT limits discussed above are consistent with BACT determinations for similar emission units at similar facilities. An initial stack test demonstration will be required for CO2 emissions from each emission unit. Testing for CH4 emissions and destruction efficiency in the thermal oxidizer is discussed in the following section. Thermal Oxidizers Each amine unit (including flash tank and still vent) will have emissions routed to a thermal oxidizer. The process-related CO2 emissions from each amine unit will flow through the thermal oxidizers to the atmosphere, and the hydrocarbon emissions, including methane, will be oxidized to form combustion-related emissions, including GHGs. The oxidizers have a 99% DRE (Destruction and Removal Effciency) for hydrocarbon compounds, so 1 % of the methane will pass through the oxidizers uncombusted, as process-related GHGs. In addition, the oxidizers will fire pipeline quality natural gas (i .e., generating combustion-related GHGs), at a maximum rate of 11 .0 MMBtu/hr (supplemental plus burner), as needed to maintain a combustion chamber temperature of at least 1 ,400°F. An initial stack test will be required to demonstrate that the thermal oxidizer achieves a minimum CH4 and VOC emissions reduction of 99% from each unit. In reviewing GHG BACT requirements for similar sources, annual compliance testing is commonly required to confrm that the requested minimum desiruction efficiency for CH4 is achieved. Since Kerr-McGee is also claiming 99% control of VOC at 1 ,400 °F, the Division is requiring more frequent on-going testing, semi-annual basis, to ensure that the minimum required destruction efficiency for VOC can be achieved at the varying operating rates of the units and at the proposed minimum combustion temperature while also maintaining compliance with the requested synthetic minor emission limits for VOC, NOx, 5O2, and CO. The testing requirements for VOC, NOx, SO2 and CO are not considered a BACT requirement. The compliance testing for CH4 is included in the permit requirements for compliance testing for the other pollutants to streamline the permit conditions and allow for a more straight-forward compliance schedule. The source will be required to measure CH4 and VOC concentrations in the thermal oxidizer inlet and exhaust streams to demonstrate a minimum destruction efficiency of 99% by weight at a minimum combustion chamber temperature of 1 ,400 °F unless an alternate combustion zone temperature is demonstrated to achieve 99% destruction efficiency through testing. Kerr-McGee — Lancaster Plant 72W E1A92 Issuance 1 Kerr-McGee's BACT analysis identified proper thermal oxidizer operation and annual tune-ups as BACT for the thermal oxidizers. The Division is determining for this site that good combustion practices and periodic compliance testing is BACT for CH4 control for thermal oxidizers. Kerr-McGee also identified in the BACT analysis that the thermal oxidizers will utilize combustion air preheaters and acid gas heat exchangers. This practice does not increase the thermal oxidizer effciency but it does reduce the potential GHG emissions by reducing the required heat duty (fuel fring rete) which can reduce overall plant energy requirements. The Division has also reviewed GHG BACT limits and controls for thermal oxidizers at ETC Jackson County Gas Plant (Permit Number PSD-TX-1264-GHG), Enterprise Products Opereting, LLC Mont Belvieu Complex (Permit Number PSD-TX-1286-GHG), and Energy Trensfer Partners, Lone Star NGL Mont Belvieu Gas Plant (Permit Number PSD-TX-93813-GHG). Each of these facilities identified BACT as periodic maintenance to help maintain the efficiency of the thermal oxidizer along with tempereture monitoring and routine pertormance testing to ensure proper operation. Thus, the BACT limits discussed above are consistent with BACT determinations for similar emission units at similar facilities. Flares The proposed Cryogenics Plant will have two flares (F-2 and F-3) that will control emissions from plant maintenance activities and purge gas from the two treins, generating combustion-related GHGs. Each flare has 95% destruction and removal efficiency (DRE), so 5% of the methane in the maintenance activities and purge gas will pass through the flare as process-related GHG emissions. Each flare also combusts pipeline quality naturel gas, through its pilot, which has a fring rete of 0.5 MMBtu/hr, generating a small amount of combustion-related GHGs. Kerr-McGee's BACT analysis identified proper flare operetion as BACT for the flares. By using flow and composition monitors, the source can accurately determine the optimum amount of natural gas required to maintain adequate VOC destruction in order to minimize naturel gas combustion and the resulting CO2. This optimization will also ensure the minimum methane destruction efficiency of 95% is met. Flow rate and gas composition analyzers shall be used to continuously monitor the combined waste gas stream sent to the flare to determine the quantity of natural gas required to maintain a minimum heating value of 300Btu/scf. The flow rate and gas composition analyzer shall continuously record the molecular weight and mass flow rate of the flare gas. The Division is determining for this site that good combustion practices and demonstrating initial and ongoing compliance in accordance with 40 CFR Part 60. 18 is BACT for CO2 and CH4 control for flares. This BACT determination is consistent with BACT for flares at similar natural gas processing facilities. Fugitives Emissions from leaking components (process fugitives referred to as FUG3) associated with the proposed project include methane, a GHG. The additional methane emissions from process fugitives have been conservatively estimated to be 949 tpy as CO2e. Fugitive emissions of methane are negligible, and account for less than 0.2% of the project's total CO2e emissions. The only identified control technology for process fugitive emissions of CO2e is use of a leak detection and repair (LDAR) program. LDAR programs vary in stringency as needed for control of VOC emissions; however, due to the negligible amount of GHG emissions from fugitives, LDAR programs would not be considered for control of GHG emissions alone. As such, evaluating the relative effectiveness of different LDAR programs is not warranted. Although technically feasible, use of an LDAR program to control the negligible amount of GHG emissions that occur as process fugitives would most likely be cost prohibitive. However, if an Kerr-McGee — Lancaster Plant 72W E1492 Issuance 1 LDAR program is being implemented for VOC control purposes, it will also result in effective control of the small amount of GHG emissions from the same equipment components. Kerr- McGee stated in the BACT analysis that the plant would follow NSPS KKK. With the final issuance of NSPS OOOO, the Cryogenics Plant will in fact be subject to NSPS OOOO instead of NSPS KKK. The LDAR requirements under NSPS OOOO are more stringent than NSPS KKK. Due to the negligible amount of GHG emissions from process fugitives, the only available control , implementation of an LDAR program, could potentially be economically infeasible, and then BACT would be determined to be no control . However, since the facility will be subject to the LDAR program as required under NSPS OOOO to control VOC emissions, the Division concurs with Kerr-McGee's assessment that following NSPS OOOO requirements is an appropriate control of GHG emissions for fugitives (AIRS ID 067). As noted above, LDAR programs would not normally be considered for control of GHG emissions alone due to the negligible amount of GHG emissions from fugitives, and while the existing LDAR program is being imposed in this instance, the imposition of a numerical limit for control of those negligible emissions is not feasible. Diesel Emergency Generator Kerr-McGee is proposing to install one 839 bhp diesel-fired emergency generetor as part of this project. The generetor will be limited to 500 hours of operation per year. Kerr-McGee identifed GHG control technology options as complying with NSPS Subpart IIII and implementing good combustion practices and maintenance. Although Kerr-McGee did not identify CCS as a possible control option, the Division recognizes that CCS is not economically feasible, as discussed above, for dilute CO2 emission sources such as the emergency generetor. Additionally, another common potential control technology for GHG is to use low carbon fuels. However, this option is not feasible for the emergency generator since the generetor is intended for emergency use and a non-volatile fuel , such as diesel , must be used during emergency operetions. The only feasible control options then are complying with NSPS IIII and implementing good combustion prectices and maintenance. Good combustion practices for compression ignition engines include appropriate maintenance and operation as specified by the manufacturer. The Division is determining for this site that complying with NSPS IIII and following manufacturer's specifcation to ensure good combustion practices is BACT for CO2 and CH4 control for the emergency generetor. This BACT determination is consistent with GHG BACT for emergency generators at other sites (specifically Chevron Phillips Chemical Company, LP, Cedar Bayou Plant, Permit # PSD-TX-748-GHG). RACT (Regulation No. 3, Part B, III.D.2.a) The proposed Lancaster Plant will be located in an area designated by the EPA as a non- attainment area for ozone and the proposed equipment will emit ozone pre-cursors, including NOx and VOC. Since the proposed equipment does not qualify as a major modification for NANSR, the proposed equipment is subject to minor source RACT requirements per Regulation 3, Part B, Section III .D.2.a. The proposed equipment that would emit NOx and VOC include: • Six (6) Heaters • Four (4) Amine Units • Four (4) Thermal Oxidizers . Two (2) Flares • Fugitives . One ( 1 ) Diesel Generator. As discussed in the BACT Analysis above, all of these units are also subject to BACT for GHG and the BACT control options will ultimately reduce NOx and VOC emissions as well. Kerr-McGee — Lancaster Plant 72W E1492 Issuance 1 For the heaters, the selected BACT control option is to implement low-NOx burners along with good combustion practices. The selected control options, while minimizing CO2 emissions, will also minimize NOx emissions and thus satisfy minor source RACT. The selected BACT option for the four amine units is to route emissions to a thermal oxidizer achieving 99% reduction of inethane. This control will also result in 99°/o reduction of VOC and thus satisfes minor source RACT. Maintenance activities are routed to flares for 95% control of methane and VOC, which will satisfy RACT. Additionally, the source will implement good combustion practices for the thermal oxidizers and flares to satisfy BACT; these requirements will also reduce NOx generated due to combustion. The proposed plant will be subject to leak detection and repair requirements specified in Regulation 7, Section XII .G, which specifies RACT. The facility will follow 40 CFR 60 Subpart OOOO in lieu of following 40 CFR 60 Subpart KKK. The diesel generator will comply with 40 CFR 60 Subpart IIII which satisfes minor source RACT. The permit will specify the requirements that the source must follow to comply with minor source RACT. VI. CONCLUSION AND PROPOSED ACTION Based on the information supplied by Kerr-McGee, our review of the analyses contained in the Permit Application, and our independent evaluation of information, it is our determination that the proposed facility would employ BACT for GHGs under the terms contained in the dreft permit. Therefore, the Division is proposing to issue Kerr-McGee a PSD permit for GHGs for the facility, subject to the PSD permit conditions specifed therein. This permit is subject to review and comments. A fnal decision on issuance of the permit will be made after considering comments received during the public comment period. Attachment A Construction Permit Application Preliminary Analysis Summary Section 1 — Applicant Information Company Name: Kerr-McGee Gathering LLC Permit Number: 12WE1492 Source Location: Lancaster Plant (16270 WCR 22, Fort Lupton, CO 80217) Point031 : Dieselgenerator Point 057: Amine Heater Point 058: Amine Heater Point 059: Amine Heater Point 060: Amine Heater Point 061 : Amine Heater Point 062: Amine Heater Equipment Description Point 063: Amine sweetening unit Point 064: Amine sweetening unit Point 065: Amine sweetening unit Point 066: Amine sweetening unit Point 067: Fugitive emissions Point 068: Process Flare Point 069: Process Flare AIRS ID: 123-0057 Date: February 29, 2012; Second Review: May 4, 2012 Review Engineer: Stephanie Chaousy, PE Control Engineer: Chris Laplante Section 2 — Action Completed Grandfathered Modification APEN Required/Permit Exempt X CP1 Transfer of Ownership APEN ExempUPermit Exempt Section 3 — Applicant Completeness Review Were the correct APENs submitted for these saurces? X Yes No Are the APENs signed with an original signature? X Yes No Were the APENs filled out completely? X Yes No Did the applicant submit all required paperwork? X Yes No Did the applicant provide ample information to determine emission rates? Yes X No If you answered "no" to any of the above, when did you mail Please refer to Section 14 for email an Information Re uest letter to the source? communica[ions. Page 1 On what date was this application complete? Original Application: 11 /30/2011 Supplementary Application : 4/17/2012 Section 4 — Source Description AIRS Point Equipment Description One ( 1 ) Caterpillar, Model C18 DITA, Senal Number To Be Determined, diesel , turbo- 031 charged, 4-stroke compression ignition (CI) engine, site rated at 839 horsepower at 1800 RPM. This engine is equipped with no controls. This emergency generetor is to be used for electrical power generation during power failure. Mole sieve regeneration gas heater equipped with ultra low NOx bumers. The heater is 057 design rated for an output capacity of 25 MMBtu/hr and an assumed thermal efficiency of 84°/o. This heater is fueled by natural gas. Mole sieve regeneration gas heater equipped with ultra low NOx burners. The heater is O58 design rated for an output capacity of 25 MMBtu/hr and an assumed thermal efficiency of 84%. This heater is fueled by natural gas. Amine heat medium heater equipped with ultra low NOx burners used to regenerate 059 amine for Point 063. The heater is design rated for an output capacity of 60 MMBtu/hr and an assumed thermal efficienc of 78%. This heater is fueled b natural as. Amine heat medium heater equipped with ultra low NOx burners used to regenerate 060 amine for Point 064. The heater is design rated for an output capacity of 60 MMBtu/hr and an assumed thermal efficienc of 78%. This heater is fueled b natural as. Amine heat medium heater equipped with ultra low NOx burners used to regenerate 061 amine for Point 065. The heater is design rated for an output capacity of 60 MMBtu/hr and an assumed thermal efficienc of 78%. This heater is fueled b natural as. Amine heat medium heater equipped with ultra low NOx burners used to regenerate 062 amine for Point 066. The heater is design rated for an output capacity of 60 MMBtu/hr and an assumed thertnal e�cienc of 78%. This heater is fueled b naturel as. One ( 1 ) Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 150 MMSCF per day (make, model, serial number: TBD). This emissions unit is equipped with three (3) total amine pumps, 2 operate at once with one as a backup with a total combined design capacity of 601 gallons per 063 minute. This system includes a natural gas/amine contactor, still vent and a flash tank. The still vent emissions are routed to a sulfa-treat system and then to a thermal oxidizer. The flash tank emissions are routed to thermal oxidizer. The thermal oxidizer has a minimum destruction and removal efficiency (DRE) of 99%. The still vent and flash tank are routed to the plant process flare (Point 068) when the thermal oxidizer is down. One ( 1 ) Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 150 MMSCF per day (make, model, serial number: TBD). This emissions unit is equipped with three (3) total amine pumps, 2 operate at once with one as a backup with a total combined design capacity of 601 gallons per 064 minute. This system includes a natural gas/amine contactor, still vent and a flash tank. The still vent emissions are routed to a sulfa-treat system and then to a thermal oxidizer. The flash tank emissions are routed to thermal oxidizer. The thermal oxidizer has a minimum destruction and removal efficiency (DRE) of 99°/o. The still vent and flash tank are routed to the lant rocess flare Point 068 when the thermal oxidizer is down. One (1 ) Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 150 MMSCF per day (make, model, serial number: TBD). This emissions unit is equipped with three (3) total amine pumps, 2 operate at once with one as a backup with a total combined design capacity of 601 gallons per 065 minute. This system includes a natural gas/amine contactor, still vent and a flash tank. The still vent emissions are routed to a sulfa-treat system and then to a thermal oxidizer. The flash tank emissions are routed to thermal oxidizer. The thermal oxidizer has a minimum destruction and removal efficiency (DRE) of 99%. The still vent and flash tank are routed to the lant rocess flare Point 069 when the thermal oxidizer is down. Page 2 One (1 ) Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 150 MMSCF per day (make, model, serial number: TBD). This emissions unit is equipped with three (3) total amine pumps, 2 operate at once with one as a backup with a total combined design capacity of 601 gallons per 066 minute. This system includes a natural gas/amine contactor, still vent and a flash tank. The still vent emissions are routed to a sulfa-treat system and then to a thermal oxidizer. The flash tank emissions are routed to thermal oxidizer. The thermal oxidizer has a minimum destruction and removal efficiency (DRE) of 99%. The still vent and flash tank are routed to the plant process flare (Point 069) when the thermal oxidizer is down. 067 Fugitive component leak emissions. Maintenance activities and purging of gas. Activities are controlled by an elevated open 068 process flare. Purge gas prevents low flashback problems to the flare and keeps the flame stable. The purge gas and pilot gas used is sales gas and helps the flare maintain a minimum re uired ositive flow throu h the s stem . Maintenance activities and purging of gas. Activities are controlled by an elevated open 069 Process flare. Purge gas prevents low flashback problems to the flare and keeps the flame stable. The purge gas and pilot gas used is sales gas and helps the flare maintain a minimum re uired ositive flow throu h the s stem . Is this a portable source? Yes X No Is this location in a non-attainment area for any criteria X Yes No pollutant? If "yes", for what pollutant? PM ,o CO X Ozone Is this location in an attainment maintenance area for Yes X No an criteria ollutant? If "yes", for what pollutant? (Note: These pollutants are subject to minor source PM�o CO Ozone RACT per Regulation 3, Part B, Section III. D.2) Is this source located in ihe 8-hour ozone non- attainment region? (Note: If "yes" the provisions of X Yes No Regulation 7, Sections XII and XVII.C may apply) Section 5 — Emission Estimate Information AIRS Point Emission Factor Source 031 NOx, VOC and CO: Manufacturer PM and SOx: AP-42, Table 3.4-1 and Table 3.4-2 057 NOx, VOC and CO: Manufacturer PM and SOx: AP-42, Table 1 .4-1 058 NOx, VOC and CO: Manufacturer PM and SOx: AP-42, Table 1 .4-1 059 PM, NOx and CO : Manufacturer VOC and SOx: AP-42, Table 1 .4-1 060 PM, NOx and CO: Manufacturer VOC and SOx: AP-42, Table 1 .4-1 061 PM, NOx and CO: Manufacturer VOC and SOx: AP-42, Table 1 .4-1 062 PM, NOx and CO: Manufacturer VOC and SOx: AP-42, Table 1 .4-1 VOC, PM, S02 and HAPS: ProComp Process Simulator Version 8. 1 . 1 .2 (Cryogenic plant 063 requires a different modeling set-up). This is a DOW Chemical Company Model (Gas Treating Chemical Group program) NOx and CO: AP-42, Table 1 .4-1 VOC, PM, S02 and HAPS: ProComp Process Simulator Version 8. 1 . 1 .2 (Cryogenic plant Q� requires a different modeling set-up). This is a DOW Chemical Company Model (Gas Treating Chemical Group program) NOx and CO: AP-42, Table 1 .4-1 065 VOC, PM, S02 and HAPS: ProComp Process Simulator Version 8. 1 . 12 (Cryogenic plant re uires a different modelin set-u . This is a DOW Chemical Com an Model Gas Page 3 Treating Chemical Group program) NOx and CO: AP-42, Table 1 .4-1 NOx and CO: AP VOC, PM, SO2 and HAPS: ProComp Process Simulator Version O66 $ � � 1 .2 (Cryogenic plant requires a different modeling set-up). This is a DOW Chemical Company Model (Gas Treating Chemical Group program ) NOx and CO: AP-42, Table 1 .4-1 067 EPA-453/R-95-017, Table 2-4 O68 NOx and CO emission factors from TCEQ. VOC emissions were estimated with AP-42. Please see Section 14 for calculations. 069 NOx and CO emission factors from TCEQ. VOC emissions were estimated with AP-42. Please see Section 14 for calculations. Did the applicant provide actual process data for the emission inventory? Yes X No Basis for Potential to Emit IPTEI AIRS Point Process Consumption/ThroughpuUProduction 031 19,950 gal/yr 057 30 MMBtu/hr ' 8760 hr/yr = 262,800 MMBtu/yr / 1020 Btu/scf = 257.6 MMscf/yr 058 30 MMBtu/hr ' 8760 hr/yr = 262,800 MMBtu/yr / 1020 Btu/scf = 257.6 MMscf/yr 059 76.9 MMBtu/hr " 8760 hr/yr = 673,644 MMBtu/yr / 1020 Btu/scf = 660.6 MMscf/yr O60 76.9 MMBtu/hr " 8760 hr/yr = 673,644 MMBtu/yr / 1020 Btu/scf = 660.6 MMscflyr 061 76.9 MMBtu/hr ' 8760 hr/yr = 673,644 MMBtu/yr / 1020 Btu/scf = 660.6 MMscf/yr 062 76.9 MMBtu/hr ' 8760 hr/yr = 673,644 MMBtu/yr / 1020 Btu/scf = 660.6 MMscf/yr 063 54,750 mmscf per year, natural gas throughput, 601 gallons per minute lean amine circulation rate 064 54,750 mmscf per year, natural gas throughput, 601 gallons per minute lean amine circulation rate 065 54,750 mmscf per year, natural gas throughput, 601 gallons per minute lean amine circulation rate 066 54,750 mmscf per year, natural gas throughput, 601 gallons per minute lean amine circulation rate Equipment Type Gas Heavy Oil (or Light Oil (or Water/Oil Heavy Liquid) Light Liquid) Connectors 1630 488 821 --- 067 Flanges 744 45 719 --- Open-Ended Lines --- --- --- --- Pump Seals --- 15 33 3 Valves 1487 196 1359 --- Other 78 4 28 --- Purge gas= 1 .22 MMBtu scf 8760 hr = 10.48 MMSCF/yr hr 1020 btu 1 yr O68 process gas= 10.9 MMBtu scf 8760 hr = 74.89 MMSCFlyr hr 1275 btu 1 yr Total throughput = 85.37 MMSCF/yr Purge gas= 1 .22 MMBtu scf 8760 hr = 10.48 MMSCF/yr hr 1020 btu 1 yr 069 process gas= 10.9 MMBtu scf 8760 hr = 74.89 MMSCF/yr hr 1275 btu 1 yr Total throu h ut = 85.37 MMSCF/ r Basis for Permitted Emissions (Permit Limits) AIRS Point Process Consumption/ThroughpuUProduction Page 4 031 19,950 gal/yr 057 30 MMBtu/hr ' 8760 hr/yr = 262,800 MMBtu/yr ! 1020 Btu/scf = 255.6 MMscf/yr 058 30 MMBtu/hr ' 8760 hr/yr = 262,800 MMBtu/yr / 1020 Btu/scf = 255.6 MMscf/yr 059 76.9 MMBtulhr ' 8760 hr/yr = 673,644 MMBtu/yr / 1020 Btu/scf = 660.6 MMscf/yr O60 76.9 MMBtu/hr ' 8760 hr/yr = 673,644 MMBtu/yr / 1020 Btu/scf = 660.6 MMscf/yr 061 76.9 MMBtu/hr " 8760 hdyr = 673,644 MMBtu/yr ! 1020 Btu/scf = 660.6 MMscf/yr 062 76.9 MMBtu/hr ` 8760 hr/yr = 673,644 MMBtu/yr / 1020 Btu/scf = 660.6 MMscf/yr 063 54,750 mmscf per year, natural gas throughput, 601 gallons per minute lean amine circulation rate 064 54,750 mmscf per year, natural gas throughput, 601 gallons per minute lean amine circulation rate 065 54,750 mmscf per year, natural gas throughput, 601 gallons per minute lean amine circulation rate 066 54,750 mmscf per year, natural gas throughput, 601 gallons per minute lean amine circulation rate Equipment Type Gas Heavy Oil (or Light Oil (or Water/Oil Heavy Liquid) Light Liquid) Connectors 1630 488 821 --- 067 Flanges 744 45 719 --- Open-Ended Lines --- --- --- --- Pump Seals --- 15 33 3 Valves 1487 196 1359 --- Other 78 4 28 --- Purge gas= 1 .22 MMBtu scf 8760 hr = 10.48 MMSCF/yr hr 1020 btu 1 yr 068 process gas= � 10.9 MMBtu � scf � 8760 hr � = 74.89 MMSCF/yr hr 1275 btu 1 yr Total throughput = 85.37 MMSCF/yr Purge gas= 1 .22 MMBtu scf 8760 hr = 10.48 MMSCF/yr hr 1020 btu 1 yr 069 process gas= 10.9 MMBtu scf 8760 hr = 74.89 MMSCF/yr hr 1275 btu 1 yr Total throu h ut = 85.37 MMSCF/ r Does this facility have control devices? X Yes No AIRS Point Process Control Device Description % Reduction Granted o� H2S by Sulfa-treat system (still vent) 95 063 02 VOC and HAPS by Thermal Oxidizer (still vent and flash 99 tank) oi H2S by Sulfa-ireat system (still vent) 95 064 02 VOC and HAPS by Thermal Oxidizer (still vent and flash 99 tank) o� H2S by Sulfa-treat system (still vent) 95 065 02 VOC and HAPS by Thermal Oxidizer (still vent and flash 99 tank) o� H2S by Sulfa-treat system (still vent) 95 066 02 VOC and HAPS by Thermal Oxidizer (still vent and flash 99 tank) 067 0� Fugitives (LDAR) VOC and HAP: 55.5 Page 5 Section 6 - Emission Summa tons er ear PM2.51 Single To[al Point NO, VOC CO pM70 SOz HzS COse HAP HAP 031 2.6 --- 0.2 0. 1 1 .5 -- --- -- --- 057 52 2.5 5.2 1 .0 0. 1 -- 15252 -- --- 058 5.2 2.5 5.2 1 .0 0. 1 -- 15252 --- --- 059 13.5 1 .8 13.5 1 .7 0.2 -- 39421 --- --- 060 13.5 1 .8 13.5 1 .7 0.2 -- 39421 -- --- 061 13.5 1 .8 13.5 1 .7 0.2 -- 39421 -- --- 062 13.5 1 .8 13.5 1 .7 0.2 -- 39421 --- --- 063 7.9 350.0 6.6 0.6 20.3 0.01 94122 � 5.4 (n- � 5.4 PTE: hexane 064 7.9 350.0 6.6 0.6 20.3 0.01 94122 15.4 (n- � 5.4 hexane 065 7.9 350.0 6.6 0.6 20.3 0.01 94122 � 5.4 (n- � 5.4 hezane 066 7.9 350.0 6.6 0.6 20.3 0.01 94122 � 5.4 (n- � 5.4 hexane 067 --- 68.5 --- -- --- -- 949 4 5jn 10.2 hexane) O68 7.3 1 .6 14.6 0.3 --- -- 150 -- --- 069 7.3 1 .6 14.6 0.3 --- -- 150 -- --- 031 2.6 --- 02 0. 1 1 .5 -- --- --- --- 057 5.2 2.5 5.2 1 .0 0. 1 -- 15252 --- --- 056 52 2.5 52 1 .0 0. 1 -- 15252 --- --- 059 13.5 1 .8 13.5 1 .7 0.2 -- 39421 --- --- O60 13.5 1 .8 13.5 1 .7 02 -- 39421 --- --- 061 13.5 1 .8 13.5 1 .7 0.2 -- 39421 --- --- 062 13.5 1 .8 13.5 1 .7 0.2 -- 39421 --- --- Uncontrolledpoint 063 7.9 350.0 6.6 0.6 20.3 0.01 94122 � 5.4 (n- � 5.4 soufce Efl'lissions hexane @Requested 064 7.9 350.0 6.6 0.6 20.3 0.01 94122 � 5.4 (n- � 5.4 Process rates: hexane 065 7.9 350.0 6.6 0.6 20.3 0.01 g4122 � 5.4 (n- � 5 4 hexane 066 7.9 350.0 6.6 0.6 20.3 0.01 94122 15.4 (n- � 5 4 hexane 067 --- 68.5 --- -- --- -- 949 4.5 (n- 10.2 hexane) O68 7.3 1 .6 14.6 0.3 --- -- 150 -- --- 069 7.3 1 .6 14.6 0.3 --- -- 150 --- --- 031 2.6 --- 0.2 0. 1 1 .5 -- --- --- --- 057 52 2.5 52 1 .0 0. 1 -- 15252 --- --- 058 5.2 2.5 5.2 1 .0 0. 1 -- 15252 -- --- 059 13.5 1 .8 13.5 1 .7 02 -- 39421 --- --- 060 13.5 1 .8 13.5 1 .7 0.2 -- 39421 --- --- 061 13.5 1 .8 13.5 1 .7 02 -- 39421 --- --- 062 13.5 1 .8 13.5 1 .7 0.2 -- 39421 --- --- 063 7.9 3.6 6.6 0.6 1 . 1 0.01 94122 02 (n- 0 2 Controlled point hexane) source emission 064 7.9 3.6 6.6 0.6 1 . 1 0.01 94122 02 {o- 0 Z rate: hexane 065 7.9 3.6 6.6 0.6 1 . 1 0.01 94122 0'z �°" 02 hexane) O66 7.9 3.6 6.6 0.6 1 . 1 0.01 94122 0'2 �° 0.2 hexane 067 --- 30.5 --- --- --- -- 949 2 1 (" 4.8 hezane) 068 7.3 1 .6 14.6 0.3 --- -- 150 --- --- 069 7.3 1 .6 14.6 0.3 --- -- 150 --- --- Newly Total 2.5 �n- APEN Reported 113.2 60.3 120.2 11 .9 6.9 0.04 565925 hexane) 5'2 emissions: Page 6 Section 7 — Non-Criteria / Hazardous Air Pollutants Uncontrolled tueme ControlledEmission Pollutant CAS # BIN Emission Rate em�ss�o�s Ib f reponable? Rate (Ibly�) Points 063-066 EACH n-hexane 110543 C 30878 Yes 309 Point 067 Benzene 71432 A 2008 Yes 938 Toluene 108883 C 5238 Yes 2460 Ethylbenzene 100414 C 380 No 178 Xylenes 1330207 C 3716 Yes 1749 n-Hexane 110543 C 8973 Yes 4194 Note: Regulation 3, Part A, Section II. B.3.b APEN emission reporting requirements for non-criteria air pollutants are based on potential emissions without credit for reductions achieved by control devices used b the o erator. Section 8 —Testing Requirements Will testing be required to show compliance with any emission rate or regulatory X Yes No standard? If "yes", complete the information listed below AIRS Point Process Pollutant Regulatory Basis Test Method 031 01 Opacity Regulation No. 1 , Section II.A. 1 & 4 EPA Method 9 057 p� NOx, CO, Re ulation No. 3, Part B. , Section I II.G.3 Stack Test CO2, PM2S 9 � 058 01 NOx, CO, Re ulation No. 3, Part B., Section I II.G.3 Stack Test CO2, PM2.5 9 � 059 01 NOx, CO, Re ulation No. 3, Part B., Section I II.G.3 Stack Test CO2, PM2.5 9 � 060 01 NOx, CO, Re ulation No. 3, Part B., Section I II.G.3 Stack Test CO2, PM2S 9 � 061 01 NOx, CO, Re ulation No. 3, Part B., Section I II.G.3 Stack Test CO2, PM2S 9 � 062 01 NOx, CO, Re ulation No. 3, Part B., Section I II.G.3 Stack Test CO2, PM2.5 9 � 063 01 VOC, HAPS Regulation No. 3, Part B., Section III .G.3 Stack Test 063 01 VOC, HAPS Regulation No. 3, Part B, Section III.E.) Annual sour gas anal sis 064 01 VOC, HAPS Regulation No. 3, Part B., Section III .G.3 Stack Test 064 01 VOC, HAPS Regulation No. 3, Part B, Section III.E.) Annual sour gas anal sis 065 01 VOC, HAPS Regulation No. 3, Part B., Section III .G.3 Stack Test 065 01 VOC, HAPS Regulation No. 3, Part B, Section III.E.) Annual sour gas anal sis 066 01 VOC, HAPS Regulation No. 3, Part B., Section III .G.3 Stack Test 066 01 VOC, HAPS Regulation No. 3, Part B, Section III.E.) Annual sour gas anal sis 067 01 VOC, HAPS State only requirement Extended gas analysis 067 01 VOC, HAPS State onty requirement Component hard count Section 9 — Source Classification Are these new previously un-permitted X Yes No sources? Page 7 What is this facility classification? True Synthetic X Major Minor Minor Classification relates to what X Title V X PSD X NA NSR X MACT programs? Is this a modification to an existing stationary X Yes No source? Synthetic If "yes" what kind of modification? Minor X Minor for X Major for SO2 and GHG VOC Section 10 — Public Comment Does this permit require public comment per CAQCC Regulation 3? X Yes No For Reg. 3, Part B, III.C. 1 .a (emissions increase > 25 tpy)? X Yes No For Reg. 3, Part B, III.C. 1 .c.iii (subject to MACT)? X Yes No For Reg. 3, Part B, III.C. 1 .d (synthetic minor emission limits)? X Yes No For Reg. 3, Part D, Section IV (Projects subject to PSD) X Yes No Section 11 — Modeling Is modeling required to demonstrate compliance with National Ambient Yes X No Air Quality Standards (NAAQS)? A source impact analysis is not required as the proposed modification is not signif cant for any criteria pollutant (Regulation 3, Part D, Section VI . B. 1 .b) and therefore not subject to modeling requirements under Regulation 3, Part D, Section VI .A.2. Page 8 Section 13 — Aerometric Information Retrieval S stem Codin Information Manufacturer 0257716lgal NOx No (converted to 0 Ib/ al Manufacturer 0.01621b/gal CO No (convertedto 0 Ib/ al Manufacturer 0.00051b/gal VOC No (converted to 0 Ib/ al AP�2, Table 0.14831b/gal SOx No 3'4-1 0 (convertedto Ib/ al AP�2, Table 0.00841b/gal PM2.5 No 3'4-2 0 (convertedto Ib/ al AP-42, Table 01 Diesel Engine 0.00821blgal PM10 No 3'4-2 0 031 (convertedto Ib/gal) AP-42, Table 0.00001 Ib/gal Forma�dehyde % No 3.43 p 50000 (convertedto Ib/ al AP-42, Table 0.000004 Acetaldehyde 3.43 Ib/gal /75070 N° (converted to � Ib/ al AP-42, Table 0.000001 Acrolein/ No 3.43 p Ib/gal 107028 (converted to Ib/ al AP-42, Table 0.000111bIgal Benzene/ No 3.43 p 71432 (converted to Ib/ al SCC 20200104 — Distillate oil (Diesel) Reciprocating: Congeneration 19�38 VOC No Manufacturer 0 Ibs/mmscf 40.8 NOx No Manufacturer 0 01 Heater Ibs/mmscf 057 40.8 CO No Manufacturer 0 Ibslmmscf 7.61b/mmscf PM10/PM2.5 No AP'42� Table p 1 .4-2 SCC 31000404 — Process heaters; Natural gas 19'38 VOC No Manufacturer 0 Ibslmmscf 40.8 NOx No Manufacturer 0 01 Heater Ibslmmscf 058 40'8 CO No Manufacturer 0 Ibs/mmscf 7.616/mmscf PM10/PM2.5 No AP�2, Table p 1 .4-2 SCC 31000404 — Process heaters; Natural gas 5.51bs/mmscf VOC No '4P�2, Table p 1 .4-2 40.8 Manufacturer Ibslmmscf NOx No (converted to 0 Ib/mmsd 01 Heater 40 8 Manufacturer 059 Ibslmmscf CO No (converted to 0 Ib/mmsd Manufacturer 5. 1 Ib/mms�� PM10/PM2.5 No (converted to 0 Ib/mmsd SCC 31000404 — Process heaters; Natural gas i Page 10 5.51bs/mmsd VOC No AP-42, Table p 1 .4-2 40.8 Manufacturer Ibslmmscf NOx No (converted to 0 Ib/mmscf) 07 Heater 40 8 Manufacturer 060 Ibslmmscf CO No (converted to 0 Ib/mmscf Manufacturer 5. 1 Ib/mmscf PM10/PM2.5 No (converted to 0 Ib/mmscf SCC 31000404 — Process heaters; Natural gas 5.51bs/mmscf VOC No AP-42, Table p 1 .4-2 40.8 Manufacturer Ibslmmscf NOx No (converted to 0 Ib/mms 01 Heater 40.8 Manufacturer 061 Ibslmmscf CO No (converted to 0 Ib/mmsd Manufacturer 5. 1 Ib/mmscf PM10/PM2.5 No (converted to 0 Ib/mmsd SCC 31000404 — Process heaters; Natural gas 5.51bs/mmscf VOC No AP�2, Table p 1 .4-2 40.8 Manufacturer Ibs/mmscf NOx No (converted to 0 Iblmmscf 01 Heater 40 8 Manufacturer 062 Ibs/mmscf CO No (converted to 0 Iblmmscf Manufacturer 5. 1 Ib/mmscf PM10/PM2.5 No (converted to 0 Ib/mmsd SCC 31000404 — Process heaters; Natural gas � 2.�9 VOC No Process g9 Ibs/mmscf Simulator 100 NOx No AP�2, Table p Ibs/mmscf 1 .4-1 84 Ibs/mmscf CO No '4P�2, Table p 1 .4-1 01 Amine Unit 0.61blmmscf SO2 No AP'42, Table p 063 � .4-2 0.395 H2S No Mass Balance 95 Ib/mmscf 7.61b/mmscf PM10/PM2.5 No '4P�2. Table p 1 .4-2 0.56 n-hexane No Process 99 Ibslmmscf Simulator SCC 31000305 — Gas Sweetening ; Amine process 12.79 Process Ibs/mmscf VOC No Simulator g9 100 AP-42, Table Ibs/mmscf NOx No � 4 � 0 84 Ibs/mmscf CO No AP'42, Table p 1 .4-1 01 Amine Unit 0.616/mmscf SO2 No AP-42, Table p 064 � '4-2 0.395 H2S No Mass Balance 95 Ib/mmscf 7.61b/mmscf PM10/PM2.5 No '4P�2, Table p 1 .4-2 0.56 n-hexane No Process 99 Ibs/m � � Simulator SCC 31000305 — Gas Sweetening ; Amine process 12.79 Process Ibs/mmscf VOC No Simulator 99 100 AP�2, Table Ibs/mmscf NOx No � 4 � 0 84 Ibs/mmscf CO No '4P�2, Table p 1 .4-1 01 Amine Unit 0.61b/mmscf SO2 No AP-42, Table 0 065 � .4-2 0.395 H2S No Mass Balance 95 Ib/mmscf 7.61b/mmscf PM10/PM2.5 No AP�2, Table p 1 .4-2 0.56 n-hexane No Process 99 Ibs/mmscf Simulator SCC 31000305 — Gas Sweetening ; Amine process � 2.�9 VOC No Process g9 Ibs/mmscf Simulator 100 NOx No AP�2, Table p Ibs/mmscf 1 .4-1 84 Ibs/mmscf CO No '4P�2, Table p 1 .4-1 01 Amine Unit 0.61b/mmscf SO2 No AP-42, Table p 066 � .4-2 0.395 H2S No Mass Balance 95 Ib/mmscf 7.61b/mmscf PM10/PM2.5 No '4P�2, Table p 1 .4-2 0.56 n-hexane No Process 99 Ibs/mmscf Simulator SCC 31000305 — Gas Sweetening ; Amine process �� Fugitive VOC Leak VOC Yes EPA-453/R-9�r017, NA 067 Emissions Table 2� SCC 31000220: All Equip. Leak Fugitives (Valves, flanges, connections, seals, drains) TCEQ � �z.4 NOx No ��onverted p Ibs/mmscf from Ib/MMBtu TCEQ �� Maintenance activities 344.2 CO No ��onverted p 068 and purging gas Ibslmmscf from IbJMMBtu 37.4707 Engineering Ibslmmscf VOC No Calculation � 7.61blmmscf PM10/PM2.5 No AP'42, Table p 1 .4-2 SCC 31000205-Flares TCEQ � �2'4 NOx No �converted p Ibs/mmscf from Ib/MMBtu TCEQ 01 Maintenance adivities 344.2 CO No �converted p 069 and purging gas Ibs/mmscf from Ib/MMBtu 37.4707 Engineering Ibs/mmscf VOC No Calculation � 7.616/mmsd PM10/PM2.5 No AP�2, Table p 1 .4-2 SCC 31000205-Flares Page 12 Section 14 — Miscellaneous Application Notes Facility-wide APCD Form 102 (Facility-wide inventory) I sent an email on 3/6/12 with severel discrepancies between the Operetor's facility inventory and the Division's history form. Mostly I wanted to send this email so that the Operator can stay updated with their facility inventory and to know the status of their ui ment. Ultimatel , this became a valuable instrument when reviewin KMG nettin anal sis. AIRS Point 031 Diesel Engine A permit will be issued because this source requires an APEN, and requires a permit because the permittable uncontrolled CO and NOx emissions are greater than 5 TPY (permit threshold). Operator provided a revised APEN via email on 1/15/13. This APEN did not show revised emissions (per iheir revised calculation sheet). My calculations matched their calculations (except for PM; I don't think they used the total particulate emission factor, but the diHerence is 0.04 TPY) so I redlined the original APEN per the changes they made and the changes in the emissions section. Process limit for this source is 19,950 gallyr. The emission factors in (Ib/mmbtu) and (g/hErhr) need to be conveRed so that it matches the process limit in the permit. NOx = I 5.56 g I I Hp-hr I 1000000 I m btu I - 0257716/gal Hp-hr 453.593 6988 btu gal � CO (0.35 g/hp-hr) = 0.016216/gal VOC (0.01 g/h�rhr) = 0.0005 Ib/gal SOX (3.20 g/hp-hr) = 0. 1483 Ib/gal Formaldehyde = � 0.0000789 Ib � 0. 1469 mmbtu � = 0.00001 Ib/gal MMBtu Gal � Benzene (0.000776 Ib/mmbtu) = 0.00011 Ib/gal Acrolein (0.00000788 Ib/mmbtu) = 0.000001 Ib/gal � Acetaldehyde (0.00002521b/mmbtu) = 0.0000041b/gal PM2.5 (0.57 Ib/mmbtu) = 0.0084 Ib/gal PM10 (0.056 Ib/mmbtu) = 0.0082 Ib/gal Monthly emission limits will not be required in the permit because it is to be used as an emergency backup generetor and since we will not know when or how lon an emer enc activit will occur, we will not limit this source monthl . AIRS Point 057 & 058 Mole Sieve Regeneretion gas heaters A permit will be issued because this source requires an APEN, and requires a permit because the permittable total facility uncontrolled CO and NOx emissions are greater than 5 TPY (permit threshold). There was a Division concern on how the PM2.5 was calculated (which was noticed during the netting review (January 2013)). PM2.5 consists of condensable and filterable partides and there are emission fadors for either and combined. We didn't know if the manufacturer emission factor provided on the application was either or both (and it should be both condensable and filterable). Because KMG could not provide manufacturer guarantee that this emission factor included Iboth filterable and condensable PM2.5 emissions, they decided to use AP-42, Table 1 .4-2 for PM (total). Converting emission factors from Ib/MMBtu to IbIMMscf VOC = (0.019 Ib/mmbtu) ' ( 1020 btu/scfl = 19.38 Ib/MMscf NOx = (0.04 Ib/mmbtu) ` ( 1020 btu/scf) = 40.8 Ib/MMscf CO = 0.04 Ib/mmbtu ' 1020 btu/scf = 40.8 Ib/MMscf Page 13 AIRS Point 059-062 Amine Heaters A permit will be issued bxause this source requires an APEN, and requires a permit bxause the permittable uncontrolled CO and NOx emissions are greater than 5 TPY (permit threshold). There was a Division concern on how the PM2.5 was calculated (which was noticed during the netting review (January 2013)). PM2.5 consists of condensable and filtereble partides and there are emission facrors for either and combined. We didn't know if the manufadurer emission factor provided on the application was either or both (and it should be both condensable and filterable). KMG provided a manufacturer guarantee on 2/6/13, however, the emission factor was higher than what was originally included on the APEN (it increased from 2.04 Ib/mmscF to 5. 1 Ib/mmsd). Since this emission fador was guarenteed for both condensable and filtereble at a higher fador, we agreed to the manufadurer emission fador for PM2.5 of 5. 1 Ib/mmscF. This change did increase the PM from the original application from 0.63 TPY to 1 .7 TPY. Converting emission factors from Ib/MM6tu to Ib/MMscf NOx = (0.04 Ib/mmbtu) ' ( 1020 btu/scf) = 40.8 Ib/MMscf CO = (0.04 Ib/mmbtu) ' (1020 btu/scf) = 40.8 Ib/MMsd PM = 0.00516/mmbtu ` 1020 btu/sc = 5. 1 Ib/MMsd Page 14 AIRS Point 063-066 Amine Unit A permit will be issued bxause the uncontrolled VOC emissions are greater than 5 TPY (permit threshold). The table below summarizes the inputs to the process simulation used to calculate the PTE for this equipment. TABLE 7 Parameter Inlet Gas Rich Amine Lean Amine Flash Tank Feed Stream Pressure sia 953 si 952 1052 72 Tempereture (°F) 110 156 128 156 To better understand how the emissions were calculated, I generated my own excel spreadsheet using information from the ProComp simulation model and the internet (for molecular mass of components). I copied my excel worksheet into this word document. Columns (1 ) and (2) camefrom ihe ProComp simulation model Columns (3) and (4) were calculated from (1 ) and (2) using molar volume to molar mass constant and hours of operation Columns (5) and (6) is the emissions for each amine unit (the simulation model was for BOTH units; divided results by 2 for each individual source review) Column (7) is adding the flash gas and acid gas together (columns (5) and (6)) Column (8) is the molxular mass for each component (via intemet) Column (9) is TPY of each component. Shaded components are VOC emissions. Molar volume to molar mass = 379.3 scf/Ib-mole Hoursofopreration/ year = 8760 hr/yr Column (1) (2) (3) (4) (5) (6) (7) (8) (9) Flash Acid Gas Flash Gas A<id Gas sd/yr Molecular Gas (Ib- (16- Flash Gas Acid Gas (sd/yr) each (scf/yr� each ([otal for Mass TPY Component mol/hr) mol/hr) (sct/yr) (scf/yr) amine unit amine unit each unit) (g/mol) (mtal) Water 1.3848 81.0895 4601231 2.69E+08 230E+06 1.35E+08 1.37E+08 18.02 3254 UcarsolAP-314 0.00016 0.000184 516.276 610.5735 2.55E+02 3.OSE+02 5.63E+02 0 Carbon Dioxide 2.7561 885.1044 9157605 2.94E+09 4.58E+06 1.47E+09 1.48E+09 43.99 85534 Hydrogen Sulfide 0.00037 0.098445 1242.48 327100.1 6.21E+02 1.64E+05 1.64E+05 33.99 7 Nitrogen 0.03448 0.000836 114572 2778.375 5.73E+04 1.39E+03 5.87E+04 28.02 2 Methane 16.8776 13045 5.6E+07 4334420 2.SOE+07 2.17E+06 3.02E+07 16.03 638 Ethane 3. 1585 0.3602 1E+07 1196825 5.25E+06 5.98E+05 5.85E+06 30.05 232 Propane 1. 1128 0.1282 3697465 425966 1.85E+06 2.13E+05 2.06E+06 44.06 120 n-Butane 0.4221 0.071112 1402498 236281.6 7.O1E+05 1.18E+05 8.19E+05 57.08 62 iso-Butane 0.4899 0.2666 1627775 8858233 8.14E+05 4.43E+05 1.26E+06 58.12 96 n-Pen[ane 0.06717 0.008338 223177 27705.4 1.12E+05 1.39E+04 1.25E+05 72.15 12 iso-Pentane 0.07447 0.009245 247436 30717.07 1.24E+05 1.54E+04 1.39E+05 72.15 13 n-hexane 0.06461 0.009615 2146S1 31948.45 1.07E+05 1.60E+04 1.23E+05 86.11 14 VOC + 1.1 SF= 349 Does this amine unit have a reboiler? Yes If Yes, what is the reboiler reted? 60 mmbtWhr The source has a design rete greater than 5 mmbtu/hr, it does not meet categorical exemptions and requires an APEN (Point 034). VOC uncontrolled emission fador (mass balance): (350 TPY ' 2000 Ib/T) / 54750 mmscf/yr = 12.79 Ib/mmscf n-hexane = (15.44 TPY ' 2000 Ib/T) / 150 MMSCFD / 365 days/yr = 0.56 Ib/mmscf H2S = 21644 Ib/ r ! 54750 MMSCF/ r = 0.395 Ib/mmscf Page 15 AIRS Point 063-066 Amine Unit (continued) Sent an email on 3!1/12 with the following questions. Jennifer Shea with Kerr-McGee wrote me back on 3/6/12: 1 . For the amine sweetening units: I didn't see a gas analysis for the inlet stream. I want to verify what was used in the simulation model is specific to the faciliry. Yes, buf I'm not sure which analysis the engineering team used. I will ver'rfy. 2. Are the pumps on the amine units electric or gas? E/ectric 3. How is ProComp simulation modeling progrem similar/different from ProMax simulation modeling progrem? 1 believe ProComp is a proprietary software used by our 3i° party engineering consuRant (or maybe even fhe Amine und manufacfurerJ. I wou/d assume it would be of equal or better ca/iber fhan ProMax since we are basing our entire system design on it. 4. I calculated an uncontrolled VOC emission factor for the amine units. If you agree with my calculations, I can just redline the APEN: VOC uncontrolled emission fador (mass balance): (350 TPY ' 2000 Ib/T) / 54750 mmscflyr = 12.79 Ib/mmsd. That sounds reasonab/e. An email conversation started on 11 /15/12 after KM requested to not send the still vent emissions to the flare bxause of the additional fuel it would need to burn such a low amount of emissions. Please see below: KM (email 10/25/12): Just to follow up to our conversation. I have attached the calculations for the thermal oxidizer showing our Btu/sd of both the flash gas ( 1006 Btu/sc� and amine still vent gas (3 Btu/sc�. In our original application we proposed sending both flash and still vent gas to the flare as back-up in case the TO went down. After further design analysis, we discovered that If we sent our amine still vent gas to the flare, we are going to have to add a significant amount of additional fuel to burn gas ihat is 3 Btu/scf. We would need to get ihat gas up to about 450 Btulscf to burn it in the flare. In order to accomplish this, we would need to add a valve that would open and send 4.5 MMSCFD of residue gas along with the still vent gas every time the thermal oxidizer goes down. I ran some rough calculations that are detailed in the red box of the attached spreadsheet. Just for comparison, for a 24=hr event to vent the still vent emissions to atmosphere, we would see 0. 17 tons/24hr VOC compared to 0.3 tons NOx, 0.6 tons CO and 0. 1 tons VOC if we have to send the still vent emissions to the process flare if the ihermal oxidizer goes down. I also asked the engineer why all ihis additional gas is required for the process flare and not the thermal oxidizer. He said the TO is designed to handle lower Btu gas with waste gas preheaters, refractory equipment and insulation that is not designed into the flare. Basically, the flare isn't as "smart" or equipped to handle this spec of this gas. Please let me know if the Division would accept the flare as back-up control for only the flash gas. We also don't want to delay the permit in any way, so if this is going to affect permit review timing. please let me know. Division (email 11115112): The Division internally discussed Kerr-McGee's proposal of the amine unit's still vents venting to the atmosphere during thermal oxidizer downtime and we do not believe this design will meet Regulation 3, Part B, Section III.D2 minor source RACT requirements in a non-attainment area. Therefore, we would like to stay with the original concept for the amine units. We were also wondering if any changes need to be made to the netting analysis to account for the supplemental fuel needed at the flare during thertnal oxidizer downtime. KM (email 17I15/72): KMG is achieving RACT requirements of Regulation 3 for the amine unit still vent emissions by controlling them with the thermal oxidizer (99% destrudion efficiency). Below, we are just requesting our voluntary back- up control system to be the onsite process flare for the flash gas. We would like to be able to vent the acid gas if the thermal oxidizer goes down due to the very low Btu content of this gas. Our acid gas venting would have to occur for one month to even reach 5tpy of VOCs. I was also not aware of a "back-up" RACT requirement for sources. We do not permit for malfunction and upset conditions, so I don't think any changes need to be made to the netting analysis. Division (email 11175112): These emissions are not resulting from upset or malfunction situations. As you described these are routine monthly downtime events for the thermal oxidizec Therefore, the emissions must be permitted and all emissions need to be evaluated under RACT. If a source is controlled at all times, we consider that meeting minor source RACT requirements. The sulfa-treat system is used to control the H2S emissions of the still vent which reduces the SO2 emissions from ihe � thermal oxidizer below the 40 ton SO2 significance level, therefore, not requiring modeling for 5O2. Page 16 AIRS Point 067 Fugitive VOC Leak Emissions A permit will be issued bxause the uncontrolled VOC emissions are greater than 5 TPY (permit threshold). Sent an email on 5/10/12 with these questions. Jennifer Shea with Kerr-McGee wrote me back on 5/10/12: 1. For the fugitive APEN (recently submitted): it is listed that the VOC wt% is 22,100. I believe thaYs a typo and should be 22.1 . I can redline the APEN accordingly. The APEN is actua/ 22'� "comma" f00% because we have hvo sets of vapor fugdives for valves, one with a mixed gas of 22'� VOC and another wdh f 00% VOC. See attached calc sheet. 2. For the fugitives (recently submitted): The APEN is showing light oil wunt for valves of 1359 and heavy oil for valves of 196. However, the calculation sheet has them reversed. Which one is correct? If they need to be reversed (calculation sheet is cortect), I calculated an unconholled VOC with 10% S.F. of 63.9 TPY and controlled at 29. 1 TPY. 1 am showing both the same. The 4116/12 APEN shows 1359 for light liquid valves and so dces my calc sheeL Same with heary liquids — 196 on both the APEN and ca/c sheet. I reviewed fugitives again on 5/14/12 and changed the "gas valves" to two separete entdies (per comment #1 ). I calculated the same as Kerr- McGee. AIRS Point 068 & 069 Maintenance and purging of gas This flare does not meet exemption bxause the process gas reting is greater than 5 MMBtu/hc The source requires a permit because uncontrolled total facility CO emissions is greater than 10 TPY (and Facility overall). � Emission fador is from AP-42, where the emission factor of 0. 14 Ib/mmbtu is multiplied by the % VOC content of gas. The process flare will handle gas from all pressure relief valves during upset conditions, emergency vent valves and will handle all blowdowns to the flare during routine maintenance activities. During any emergency shutdowns of the thermal � oxidizer, the gas from the amine unit waste stream shall be sent to these points as well . However, I believe a different emission factor should be used that ties the maintenance and purging activities to the VOC emissions. Therefore, the VOC emission factor is: VOC = ( 1 .6'2000)/85.4 mmsd/yr = 37.4707 Ib/mmscf During review of another KMG project, the separation of purge and process gas was discussed because KMG said that they are metering all the process and purge gases and the emission limit in the permit covers all adivities to the flare. Therefore, the permit throughput limit was combined and the maintenance activities condition was removed from the permit. PM2.5 was not included on the APEN. I calculated PM2.5 emissions using the PM(total ) emission facta from AP-42, Table 1 .4-2: Naturel as = 7.6 Ib 1 .22 mmbtu Scf 8760 hr 1 T = 0.038915 PM2.5 mmsd hr 1020 btu 1 yr 2000 Ib TPY Process gas = � 7.6 Ib � 10.9 mmbtu � Scf � 8760 hr � 1 T � = 0.2845798 PM2.5 mmscf hr 1275 btu 1 yr 2000 Ib TPY Total PM2.5 = 0.324 TPY Converting emission factors from Iblmmbtu to Ib/mmsd will consist of combining the process and natural gases: Natural gas ratio = 1 .22 / (1 .22 + 10.9) = 10.07% Process gas retio = 10.9 / ( 1 .22+10.9) = 89.93% To find the retio of heating value: (1020`0. 1007) + ( 1275'0.8993) = 1249.32 btu/sd NOx = 0. 138Ib/mmbtu ' 1249.32 btWsd = 172.4Ib/mmsd CO = 0.27551b/mmbtu ' 1249.32 btWsd = 344.21b/mmscf Facility Review Points 032-037: When Kerr-McGee resubmitted on April 17, 2012, I thought all the APENs in the new application were new points. However, the new application included some modifications ro previously submitted APENS (from the 11/30/11 application). So, these points were accidentalty r�assigned hvo point numbers. I suggested canceling the other point numbers since the new point numbers have the most cunent APEN. I worked with Jonathan Brickey on 5/14/12 to clarify this situation. Application was submitted to the FLMs on October 19, 2012. The FLMs have 30 days after the Division determines that the application is complete to review and consider any possible adverse impact findings on visibility or air quality related values. The cover letter said that the Division would notify them when the application is considered complete. However, the application was considered complete before it was sent to the FLM. I emailed EPA and National Parks on 11/15/12 to tr and clari the correct review eriod, since the were not aware of the adual com letion date. Page 17 5TATE OF COLORADO , -oF � co�o.... E F COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT „� `�"�' '$' AIR POLLUTION CONTROL DIVISION * - � i * � TELEPHONE: (303) 6923150 ` �"""`� ' ' � f876 � CONSTRUCTION PERMIT PERMITNO: � ZWE � 492 Issuance 1 DATE ISSUED: �SS�EOTo: Kerr- McGee Gathering LLC THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS: Natural gas processing facility, known as the Lancaster Plant, located in 16270 WCR 22, Ft. Lupton , CO, 80621 in Weld County, Colorado. THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING : Facility AIRS Description Equipment ID Point One ( 1 ) Caterpillar, Model C18 DITA, Serial Number To Be Determined , diesel , turbo-charged 4-stroke compression GEN3 031 ignition (CI) engine, site rated at 839 horsepower at 1800 RPM. This engine is equipped with no controls. This emergency generator is to be used for electrical power eneration durin ower failure. Mole sieve regeneration gas heater equipped with ultra low E-2015 057 NOx burners. The heater is design rated for an output capacity of 25 MMBtu/hr and an assumed thermal efficiency of 84°/o . This heater is fueled b natural as. Mole sieve regeneration gas heater equipped with ultra low E-2016 058 NOx burners. The heater is design rated for an output capacity of 25 MMBtu/hr and an assumed thermal efficiency of 84%. This heater is fueled b natural as. Amine heat medium heater equipped with ultra low NOx burners used to regenerate amine for Point 063. The heater H-6051 059 is design rated for an output capacity of 60 MMBtu/hr and an assumed thermal efficiency of 78%. This heater is fueled by natural as. Amine heat medium heater equipped with ultra low NOx burners used to regenerate amine for Point 064 . The heater H-6052 060 is design rated for an output capacity of 60 MMBtu/hr and an assumed thermal efficiency of 78%. This heater is fueled by natural as. AIRS ID: 123/0057 Page 1 of 34 NGEngine Version 2009- 1 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division Facility AIRS Description Equipment ID Point Amine heat medium heater equipped with ultra low NOx bumers used to regenerate amine for Point 065. The heater H-6053 061 is design rated for an output capacity of 60 MMBtu/hr and an assumed thermal efficiency of 78%. This heater is fueled by natural as. Amine heat medium heater equipped with ultra low NOx burners used to regenerate amine for Point 066. The heater H-6054 062 is design rated for an output capacity of 60 MMBtu/hr and an assumed thermal efficiency of 78%. This heater is fueled by natural as. One ( 1 ) Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 150 MMSCF per day (make, model , serial number: TBD). This emissions unit is equipped with three (3) total amine pumps, 2 operate at once with one as a backup with a total combined design capacity of 601 gallons A-1 063 Per minute. This system includes a natural gas/amine contactor, still vent and a flash tank. The still vent emissions are routed to a sulfa-treat system and then to a thermal oxidizer. The flash tank emissions are routed to thermal oxidizer. The thermal oxidizer has a minimum destruction and removal efficiency (DRE) of 99%. The still vent and flash tank are routed to the plant process flare (Point 068) when the thermal oxidizer is down . One ( 1 ) Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 150 MMSCF per day (make, model , serial number: TBD). This emissions unit is equipped with three (3) total amine pumps, 2 operate at once with one as a backup with a total combined design capacity of 601 gallons A-2 064 Per minute. This system includes a natural gas/amine contactor, still vent and a flash tank. The still vent emissions are routed to a sulfa-treat system and then to a thermal oxidizer. The flash tank emissions are routed to thermal oxidizer. The thermal oxidizer has a minimum destruction and removal efficiency (DRE) of 99°/o. The still vent and flash tank are routed to the plant process flare (Point 068) when the thermal oxidizer is down. AIRS ID: 123/0057 Page 2 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division Facility AIRS Description Equipment ID Point One ( 1 ) Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 150 MMSCF per day (make, model , serial number: TBD). This emissions unit is equipped with three (3) total amine pumps, 2 operate at once with one as a backup wfth a total combined design capacity of 601 gallons A-3 065 Per minute. This system includes a natural gas/amine contactor, still vent and a flash tank. The still vent emissions are routed to a sulfa-treat system and then to a thermal oxidizer. The flash tank emissions are routed to thermal oxidizer. The thermal oxidizer has a minimum destruction and removal efficiency (DRE) of 99%. The still vent and flash tank are routed to the plant process flare (Point 069) when the thermal oxidizer is down . One ( 1 ) Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 150 MMSCF per day (make, model , serial number: TBD). This emissions unit is equipped with three (3) total amine pumps, 2 operate at once with one as a backup with a total combined design capacity of 601 gallons A-4 066 Per minute. This system includes a natural gas/amine contactor, still vent and a flash tank. The still vent emissions are routed to a sulfa-treat system and then to a thermal oxidizer. The flash tank emissions are routed to thermal oxidizer. The thermal oxidizer has a minimum destruction and removal efficiency (DRE) of 99%. The still vent and flash tank are routed to the plant process flare (Point 069) when the thermal oxidizer is down . FUG3 067 Fugitive component leak emissions. Maintenance activities and purging of gas. Activities are controlled by an elevated open process flare. Purge gas F-2 068 Prevents low flashback problems to the flare and keeps the flame stable. The purge gas and pilot gas used is sales gas and helps the flare maintain a minimum required positive flow throu h the s stem. Maintenance activities and purging of gas. Activities are controlled by an elevated open process flare. Purge gas F-3 069 Prevents low flashback problems to the flare and keeps the flame stable. The purge gas and pilot gas used is sales gas and helps the flare maintain a minimum required positive flow throu h the s stem. Point 031 may be replaced with another engine in accordance with the temporary engine replacement provision or with another Caterpillar C18 DITA engine in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment A. AIRS ID: 123/0057 Page 3 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division 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 se , TO THOSE GENERAL TERMS AND CONDITIONS INCLUDED IN THIS DOCUMENT AND THE FOLLOWING SPECIFIC TERMS AND CONDITIONS: REQUIREMENTS TO SELF-CERTIFY FOR FINAL AUTHORIZATION 1 . YOU MUST notify the APCD no later than fifteen days after commencement of the permitted operation or activity bv submittinq a Notice of Startup (NOS) form to the APCD. The Notice of Startup (NOS ) form may be downloaded online at http://�wvsv. colorado . gov/cs/Satellite/CDPHE-APICBONI1251596800297 . Failure to notify the APCD of startup of the permitted source is a violation of AQCC Regulation No. 3, Part B , Section III.G . 1 and can result in the revocation of the permit. 2. Within one hundred and eighty days (180) after commencement of operation , compliance with the 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. (Reference: Regulation No. 3, Part B , III . G .2). 3. This permit shall expire if the owner or operator of the source for which this permit was issued : (i) does not commence consiruction(modrfication or operation of this source within 18 months after either, the date of issuance of this construction permit or the date on which such construction or activity was scheduled to commence as set forth in the permit application associated with this permit; (ii) discontinues construction for a period of eighteen months or more; (iii) does not complete construction within a reasonable time of the estimated completion date. The Division may grant extensions of the deadline per Regulation No. 3, Part B, III . F.4 . b. (Reference: Regulation No. 3, Part B, III . F.4 . ) 4. The operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self-certification process. ( Reference: Regulation No. 3, Part B , Section III . E.) 5. The manufacturer, model number and serial number of the subject equipment shall be provided to the Division within frfteen days (15) after commencement of operation . This information shall be included on the Notice of Startup (NOS ) submitted for the equipment. (Reference: Regulation No. 3, Part B , III . E. ) 6. The operator shall retain the permit final authorization letter issued by the Division after completion of self-certrfication, with the most current construction permit. This construction permit alone does not provide final authority for the operation of this source. EMISSION LIMITATIONS AND RECORDS 7. Emissions of air pollutants shall not exceed the following limitations (as calculated in the Division's preliminary analysis). (Reference: Regulation No. 3, Part B , Section II.A.4) Monthly' Limits: Pounds er Month Tons per Facility AIRS P Month Emission Equipment ID Point NO■ SOZ VOC CO PMZ,5 HzS CO2eZ Type E-2015 057 886 13 421 886 170 --- 1 ,295 Point AIRS ID: 123/0057 Page 4 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division E-2016 058 886 13 421 886 170 --- 1 ,295 Point H-6051 059 2289 34 309 2289 289 --- 3,348 Point H-6052 060 2289 34 309 2289 289 --- 3,348 Point H-6053 061 2289 34 309 2289 289 --- 3,348 Point H-6054 062 2289 34 309 2289 289 --- 3,348 Point A-1 063 1337 181 610 1123 102 2 7,994 Point A-2 064 1337 181 610 1123 102 2 7,994 Point A-3 065 1337 181 610 1123 102 2 7,994 Point A-4 066 1337 181 610 1123 102 2 7,994 Point FUG3 067 --- --- 5185 --- --- --- 81 Fugitive F-2 068 1246 --- 278 2488 54 --- 528 Point F-3 069 1246 --- 278 2488 54 --- 528 Point Footnotes: 1 : Monthly limits are based on a 31 -day month. 2: CO2e is carbon dioxide equivalent in tons per year. CO2e is the total sum of the mass of each greenhouse gas emission multiplied by global warming potential for each greenhouse gas. The greenhouse gas emissions from these sources include CO2, CH4 and N2O . Annual Limits: Facility AIRS Tons per Year Emission Equipment ID Point NOx SOZ VOC CO PM2,5 HZS CO2eZ Type GEN3 031 2.6 1 . 5 --- 0.2 --- --- 238 Point E-2015 057 5.2 0. 1 2.5 5.2 1 .0 --- 15,252 Point E-2016 058 5.2 0. 1 2.5 5.2 1 .0 --- 15,252 Point H-6051 059 13.5 0.2 1 .8 13.5 1 .7 --- 39,421 Point H-6052 O60 13.5 0.2 1 .8 13.5 1 .7 --- 39,421 Point H-6053 061 13.5 0.2 1 .8 13.5 1 .7 --- 39,421 Point H-6054 062 13.5 0.2 1 .8 13.5 1 .7 --- 39,421 Point A-1 063 7.9 1 . 1 3.6 6.6 0.6 0.01 94, 121 Point A-2 064 7.9 1 . 1 3.6 6.6 0.6 0.01 94, 121 Point A3 065 7.9 1 . 1 3.6 6.6 0.6 0.01 94, 121 Point AIRS ID: 123/0057 Page 5 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division A-4 066 7.g 1 . 1 3.6 6.6 0.6 0.01 94, 121 Point FUG3 067 --- --- 30.5 --- --- --- 949 Fugitive F-2 068 7.3 --- 1 .6 14.6 0.3 --- 6,220 Point F3 069 7.3 --- 1 .6 14.6 0.3 --- 6,220 Point See "Notes to Permit Holder #4 for information on emission factors and methods used to calculate limits. During the first twelve ( 12) months of operation , compliance with both the monthly and yearly emission limitations shall be required . After the first twelve (12) months of operation , compliance with only the yearly limitation shall be required . Compliance with the emission limits in this permit shall be determined by recording the facility's annual criteria pollutant emissions, (including all HAPs above the de-minimis reporting level ) from each emission unit, 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 or at a local field office with site responsibility, for Division review. Rolling twelve-month total limitations shall apply to all emission units, requiring an APEN , at this facility. 8. Point 031 : The owner or operator shall calculate, on a monthly basis, the amount of CO2 emitted from combustion using equation C-1 in 40 CFR Part 98 Subpart C, default fuel specific high heat value (HHV) and default CO2 emission factor in Table C-1 , and actual monthly diesel consumption volume. 9. Point 031 : The owner or operator shall calculate CH4 and N2O emissions from combustion on a monthly basis using equation C-8 in 40 CFR Part 98 Subpart C, default CH4 and N2O emission factors contained in Table C-2, default fuel specific high heat value (HHV) from Table C-1 , and actual monthly diesel consumption volume. 10. Point 031 : The owner or operator shall calculate the CO2e emissions based on the procedures and Global Warming Potentials (GWP) contained in Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1 . 11 . Points 057, 058, 059, 060, 061 , 062, 063, 064, 065 and 066: The owner or operator shall calculate, on a monthly basis, the amount of CO2 emitted from fuel and waste gas combustion using equation C-2a in 40 CFR Part 98 Subpart C, default natural gas CO2 emission factor in Table C-1 , measured actual heat input (HHV), and measured actual monthly natural gas flow volume. 12. Points 057, 058, 059, 060, 061 , 062, 063, 064, 065 and 066: The owner or operator shall calculate CH4 and N2O emissions from fuel and waste gas combustion on a monthly basis using equation C-9a of 40 CFR Part 98 Subpart C, default CH4 and N2O emission factors for natural gas contained in Table C-2, measured actual heat input (HHV) and measured actual monthly natural gas flow volume. 13. Points 057, 058, 059, 060, 061 , 062, 063, 064, 065 and 066: The owner or operator shall calculate the CO2e emissions based on the procedures and Global Warming Potentials (GWP) contained in Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1 . AIRS ID: 123/0057 Page 6 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division 14. Points 063, 064, 065 and 066: The owner or operator shall calculate CO2 emissions from acid gas sweetening, on a monthly basis, using equation W-3 consistent with 40 CFR Part 98, Subpart W [98233(d )(2)] along with the most recent measured waste gas sampling composition and monthly measured waste gas flow volume. 15. Points 063, 064, 065 and 066: Total CO2e emissions from each point shall be based on the sum of GHG emissions from waste gas combustion, calculated as per Conditions 11 , 12, and 13 � CO2 emissions from the amine unit acid gas sweetening as calculated per Condition 14. The sum of GHG emissions generated from waste gas combustion and CO2 emissions generated from the amine units acid gas sweetening shall be compared to the CO2e limits listed in this section above to demonstrate compliance. 16. Points 063, 064, 065 and 066: The owner or operator shall calculate uncontrolled VOC and H2S emissions on a monthly basis using the most recent measured waste gas sample composition and monthly measured waste gas flow volume. A control efficiency of 99%, based on maintaining the minimum temperature requirements specified in Condition 23 . m), shall be applied to the uncontrolled emissions. 17. Points 063, 064, 065 and 066: Emissions from the still vent are routed to a sulfa-treat system to reduce H2S emissions. Emissions from the amine unit flash tank, reclaimer still vent and regenerator still vent (after the sulfa-treat unit), shall be collected and controlled by a thermal oxidizer in order to reduce the emissions of volatile organic compounds and H2S to the level listed in this section , above. Operating parameters of the sulfa-treat system and thermal oxidizer are identified in the operation and maintenance plan for this unit. (Reference: Regulation No.3, Part B, Section III . E. ) 18. Point 067: The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent gas and liquids analyses, as required in the Compliance Testing and Sampling section of this permit. The operator shall maintain records of the results of component counts and sampling events used to calculate actual emissions and the dates that these counts and events were completed . These records shall be provided to the Division upon request. 19. Points 068 and 069: The owner or operator shall calculate CO2e emissions, on a monthly basis, using equations and procedures outlined in 40 CFR Part 98, Subpart W 98.233(n ) along with the measured flare gas composition and monthly measured flare gas flow volume. 20. Points 068 and 069: Emissions from maintenance activities and purge gas shall be collected and controlled by a flare in order to reduce the emissions of volatile organic compounds to the level listed in this section , above. Operating parameters of the flare are identified in the operation and maintenance plan for this unit. Flare combustion efficiency shall be a minimum of 95%. (Reference: Regulation No.3, Part B , Section III . E . ) PROCESS LIMITATIONS AND RECORDS 21 . This source shall be limited to the following maximum processing rates as listed below. Monthly records of the actual processing rate shall be maintained by the applicant and AIRS ID: 123/0057 Page 7 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division made available to the Division for inspection upon request. (Reference: Regulation 3, Part B, II.A.4 ) Process/Consumption Limits Facility AIRS Monthly EquilpDment point Process Parameter Annual Limit Lida s(31 Y ) GEN3 031 Consumption of diesel gas as a fuel � 9.950 ___ gallons/year E-2015 057 Natural Gas Combusted 255.6 2171 MMscf/yr MMscflmonth E-2016 058 Naturel Gas Combusted 255.6 21 .71 MMscf/yr MMscf/month H-6051 059 Natural Gas Combusted 660.6 56. 1 MMscf/yr MMscflmonth H-6052 060 Natural Gas Combusted 660.6 56. 1 MMscf/yr MMscflmonth H-6053 061 Natural Gas Combusted 660.6 56. 1 MMscf/yr MMscf/month H-6054 062 Natural Gas Combusted 660.6 56. 1 MMscf/yr MMscflmonth A-1 063 Natural Gas Throughput 54,750 4,650 MMscf/yr MMscflmonth A-2 064 Natural Gas Throughput 54,750 4,650 MMscf/ r MMscf/month A-3 065 Natural Gas Throughput 54,750 4,650 MMscf/yr MMscf/month A-4 066 Natural Gas Throughput 54,750 4,650 MMscf/yr MMscf/month F-2 pgg+ Natural gas combustion - Process and g5.4 MMSCFlyr 7'3 Purge Gas MMSCF/month F-3 069* Natural gas combustion - Process and g5.4 MMSCF/yr 7'3 Purge Gas MMSCF/month 'Note: The process flare will handle gas from pressure relief valves during upset conditions, emergency vent valves and will handle all blowdowns to the flare during routine maintenance activities. During any emergency shutdowns of the thermal oxidizer, the gas from the amine unit waste stream shall be sent to these points as well . During the first twelve (12) months of operation , compliance with both the monthly and yearly emission limitations shall be required . After the first twelve (12) months of operation , compliance with only the yearly limitation shall be required . Compliance with the yearly throughput limits shall be determined on a rolling twelve (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 consumption of natural gas and keep a compliance record on site or at a local field office with site responsibility, for Division review. 22. Points 063, 064, 065 and 066: These units shall be limited to the maximum lean amine recirculation pump rate of 601 gallons per minute each. The lean amine recirculation rate for each unit shall be recorded weekly in a log maintained on site and made AIRS ID: 123/0057 Page 8 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division available to the Division for inspection upon request. (Reference: Regulation No. 3 , Part B, II .A.4). BEST AVAILABLE CONTROL TECHNOLOGY (BACT) REQUIREMENTS 23. The equipment and activities at this facility are subject to the requirements of the Prevention of Significant Deterioration (PSD) Program . Best Available Control Technology (BACT) shall be applied for control of Greenhouse Gases (GHG ). BACT shall be as follows: a) For purposes of BACT, total CO2e emissions from the emission units covered under this permit shall not exceed the annual emission limits contained in condition 7, based on a rolling twelve month total. EmerqencV Generator b) Point 031 : The owner or operator shall comply with the requirements in New Source Pertormance Standards of Regulation No. 6, Part A, Subpart IIII for Stationary Compression Ignition Intemal Combustion Engines (CI ICE). Heaters c) Points 057, 058, 059, 060, 061 and 062: Fuel for the heaters shall be limited to natural gas with a fuel sulfur content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr S/100 dscf). The fuel used in the heaters shall be sampled initially and at least once per every six months as required in Conditions 45 and 55 to determine the fuel gross calorific value (GCV) [high heat value ( HHV)]. d ) Points 057, 058, 059, 060, 061 and 062: The owner or operator shall install and maintain an operational non-resettable elapsed flow meter for the heaters. The flow meters shall be calibrated at a minimum frequency of at least once per every twelve months. e) Points 057, 058, 059, 060, 061 and 062 : The flow rate of the fuel combusted in these natural gas-fired combustion emission units shall be measured and recorded using an operational non-resettable elapsed flow meter at each inlet. f) Points 057, 058, 059, 060, 061 and 062: The heaters will be equipped with low- NOx staged/quenching (flue gas recirculating ) burners with burner management systems that include intelligent flame ignition and flame intensity controls. g ) Points 057, 058, 059, 060, 061 and 062: The heaters shall be tuned for thermal efficiency at a minimum frequency of at least once per every twelve months. h ) Points 057, 058, 059, 060, 061 and 062: The owner or operator shall pertorm cleaning of the burner tips, at a minimum of, once per every twelve months. i) Points 057, 058, 059, 060, 061 and 062: The owner or operator shall install , operate, and maintain an automated air/fuel control system which is part of the burner management system. j) Points 057, 058, 059, 060, 061 and 062: The owner or operator shall calibrate and perform preventative maintenance on the air/fuel control analyzers at least once per every three months, at a minimum. Amine Units and Thermal Oxidizers AIRS ID: 123/0057 Page 9 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division k) Points 063, 064, 065 and 066: The flash tank and still vent from each amine unit shall be routed to a thermal oxidizer for combustion . The thermal oxidizer shall have a minimum destruction and removal efficiency (DRE) of inethane (CH4) of 99%. I) Points 063, 064, 065 and 066: Each thermal oxidizer shall have an initial stack test and ont�oing compliance testing to verify destruction and removal efficiency (DRE) of at least 99% for CH4 . m) Points 063, 064, 065 and 066: The combustion temperature of the thermal oxidizer used to control emissions from the amine unit shall be greater than 1400 ° F, or the temperature established during the most recent stack test of the equipment that was approved by the Division . The approved operating temperature shall be maintained at all times that any amine unit emissions are routed to the thermal oxidizer in order to meet the emission limits in this permit. n ) Points 063, 064, 065 and 066: The owner or operator shall install and maintain a temperature recording device with an accuracy of the greater of t0.75 percent of the temperature being measured expressed in degrees Celsius or t2.5°C (+/- 36.5° F). o) Points 063, 064, 065 and 066: The thermal oxidizers' combustion temperature shall be continuously monitored and recorded when amine unit waste gas is directed to the oxidizers. The temperature measurement devices shall reduce the temperature readings to an averaging period of 6 minutes or less and record it at that frequency. p) Points 063, 064, 065 and 066: For burner combustion fuel, the volume of natural gas fuel usage (scf) shall be measured and recorded using an operational non-resettable elapsed flow meter at each thermal oxidizer. q ) Points 063, 064, 065 and 066: The volumetric flow rate of the waste gas combusted shall be measured and recorded using an operational non-resettable elapsed flow meter at each thermal oxidizer. r) Points 063, 064, 065 and 066: Waste gas from each amine unit will be sampled and analyzed initially and at least once every three months for composition as specified in Conditions 48 and 57. The sample data will be used to calculate GHG emissions as specified in Condition 14. s) Points 063, 064, 065 and 066: Periodic maintenance shall be completed to maintain the efficiency of the thermal oxidizer and shall be performed at a minimum of once per every twelve months or more often as recommended by the manufacturer specifications. t) Points 063, 064, 065 and 066: Oxygen analyzers shall continuously monitor and record oxygen concentration when waste gas is directed to the thermal oxidizers. It shall reduce the oxygen readings to an averaging period of 6 minutes or less and record it at that frequency. u ) Points 063, 064, 065 and 066: The oxygen analyzers shall be quality-assured at least once every six months using cylinder gas audits (CGAs) in accordance with 40 CFR Part 60, Appendix F, Procedure 1 , § 5. 12, with the following exception : a relative accuracy test audit is not required once every four quarters AIRS ID: 123/0057 Page 10 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division (i .e. , two successive semiannual CGAs may be conducted). The CGAs must be performed at least thirty (30) days apart. Fuqitives v) Point 067: The owner or operator shall implement the leak detection and repair (LDAR) requirements in New Source Pertormance Standards of Regulation No. 6, Part A, Subpart OOOO for fugitive emissions of inethane . Flares w) Points 068 and 069: The owner or operator shall install, operate, and maintain a flow rate and composition analyzer for each flare to monitor and record the volume of waste gas combusted by the flare. The flow rate and composition analyzer shall continuously record the molecular weight and mass flow rate of the flare gas. The flow rate and composition analyzer shall reduce the readings to an averaging period of 6 minutes or less and record it at that frequency. x) Points 068 and 069: The flare shall be air assisted . y) Points 068 and 069: The owner or operator shall install, operate, and maintain an air blower equipped with a variable frequency drive (VFD) motor to supply air to maximize the air/gas mixing surtace area for proper combustion . A signal verifying the supply of air to the waste gas stream prior to combustion shall be continuously monitored and recorded at least once every six minutes or less and recorded at ihat frequency. z) Points 068 and 069: The flares shall be equipped with a flame ignition system and thermocouple to monitor presence of a pilot flame. The ignition system shall send a remote alarm during pilot light outages and be capable of automatically relighting the pilot. Manual ignition of the pilot shall also be possible. aa) Points 068 and 069: Flare shall have a minimum destruction and removal efficiency (DRE) of 95%. bb) Points 068 and 069 : The owner or operator shall record the inlet waste gas heat input (HHV) in MMBtu/hr during flare operation . The records must include daily CH4 emission levels as measured by the in-line gas analyzer (Gas chromatograph or equivalent with inlet gas flowrate) and the calculations based on the actual heat input for the CO2, N2O, and CH4 emissions. These records must be kept for five years following the date of each event. cc) Points 068 and 069: The flare shall be designed and operated in accordance with 40 CFR 60 . 18 including specifications of minimum heating value of the waste gas, maximum tip velocity, and pilot flame monitoring. An infrared monitor is considered equivalent to a thermocouple for flame monitoring purposes. 24. Points 057, 058, 059, 060, 061 and 062: On or after the date of initial startup, the owner or operator shall not discharge or cause the discharge of emissions from the sum of all the heaters associated with the Lancaster Plant (AIRS Points 057 through 062) in excess of 1 ,716.9 Ibs CO2/MMSCF natural gas output from Lancaster Plant on a 365- day rolling average. To determine this BACT emission limit, the owner or operator shall calculate the limit based on the measured input mass rate of CO2 from the natural gas GCV analysis required in Conditions 8 and 55 (note that mass emission rate must be converted from metric tons to pounds) and divide by the measured daily natural gas output from the Lancaster Plant (MMSCFD). AIRS ID: 123/0057 Page 11 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division 25. The owner or operator shall maintain the following records for a period of 5 years: a) Operating hours for all emission sources. b) Diesel usage for the emergency generator. c) The volume of natural gas fuel usage for all combustion sources, using continuous fuel flow monitors. d ) Annual fuel gas sampling results, quarterly waste gas sampling . e) Daily natural gas processing output rate for the plant. f) Leak detection and repair (LDAR) program monitoring results, as well as the repair and maintenance records. g ) Records, data, measurements, reports, and documents related to the operation of the facility, including , but not limited to, the following: all records or reports pertaining to significant maintenance pertormed on any system or device at the facility; the occurrence and duration of any startup, shutdown , or malfunction , annual tuning of heaters; all records relating to pertormance tests and monitoring of combustion equipment; calibrations, checks, duration of any periods during which a monitoring device is inoperative, and corresponding emission measurements; and all other information required by this permit recorded in a permanent form suitable for inspection . AIRS ID: 123/0057 Page 12 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division STATE AND FEDERAL REGULATORY REQUIREMENTS 26. The requirements of Colorado Regulation No. 3, Part D shall apply at such time that any stationary source or modification becomes a major stationary source or major modification solely by virtue of a relaxation in any enforceable limitation that was established after August 7 , 1980, on the capacity of the source or modification to otherwise emit a pollutant such as a restriction on hours of operation (Colorado Regulation No. 3, PaR D, Sections V.A.7.B and VI. B .4). With respect to this Condition , Part D requirements may apply to future modifications if current emission limits for the following emission units are modified to equal or exceed the following threshold levels. Increases in permit limits for any of these emissions units will require evaluation of the original project net emissions increase to ensure the significant modification thresholds are not exceeded: Facility Emissions - tons per year Equipment AIRS Equipment pollutant signircant �p Point Description Modiflcation Current Threshold permit Iimit2 839 bhp Diesel GEN3 031 Emergency Generator E-2015 057 z5 MMbtu/hr heater E-2016 058 25 MMbtu/hr heater H-6051 059 60 MMbtu/hr heater H-6052 060 60 MMbtu/hr heater H-6053 061 60 MMbtu/hr NOx 40' 113.2 heater VOC 40 29.9 H-6054 062 60 MMbtu/hr CO 100' 120.2 heater pM2.5 10' 11 .8 A-1 063 � 50 MMscfd SO2 40 6.7 Amine Unit A-2 064 150 MMscfd Amine Unit A-3 065 � 50 MMscfd Amine Unit A-4 066 150 MMscfd Amine Unit FUG3 067 Fugitives F-2 068 Flare F-3 069 Flare AIRS ID: 123/0057 Page 13 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division 1 : Based on net emissions increase analysis. 2: Values listed represent the sum of all individual limits for equipment listed in the table. 27. The permit number and AIRS ID number shall be marked on the subject equipment for ease of identification . (Reference: Regulation Number 3, Part B, III . E. ) (State only enforceable). 28. Visible emissions shall not exceed twenty percent (20%) opacity during normal operation of the source . During periods of startup, process modrfication , or adjustment of control equipment visible emissions shall not exceed 30% opacity for more than six minutes in any sixty consecutive minutes. (Reference: Regulation No. 1 , Section II .A. 1 . & 4 . ) 29. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) 30. Point 031 : This engine is subject to the New Source Pertormance Standards requirements of Regulation No. 6, Part A, Subpart IIII , Standards of Pertormance for Stationary Compression Ignition Internal Combustion Engines (CI ICE ) including, but not limited to, the following: a) Owners and operators of 2007 model year and later emergency stationary CI ICE with a displacement of less than 30 liters per cylinder must comply with the emission standards for new nonroad CI engines in 40 CFR 60.4202, for all pollutants, for the same model year and maximum engine power for their 2007 model year and later stationary emergency CI ICE, as applicable. b) All fuel used shall meet the following specifications: o Sulfur content shall not exceed 15 ppm. o Have a minimum cetane index of 40 or Have a maximum aromatic compound content of 35% by volume. Compliance shall be demonstrated by maintaining copies of the fuel specifications provided by the supplier on-site or in a readily accessible location and made available to the Division for inspection upon request. c) All engines and control devices must be installed , configured , operated, and maintained according to the specifications and instructions provided by the engine manufacturer. d ) If the engine is equipped with a diesel particulate filter, the filter must be installed with a backpressure monitor that notifies the owner or operator when the high backpressure limit of the engine is approached . Records shall be kept of any corrective action taken after the backpressure monitor has notified the owner or operator that the high backpressure limit is approached . e) If the engine is used for emergency purposes, a non-resettable hour meter must be installed prior to start-up. (Reference: NSPS IIII , § 60.4209 (a)) f) This engine shall not be used for any purpose except emergency power generation and for the purpose of maintenance checks and readiness testing, provided that the tests are recommended by Federal, State or local government, the manufacturer, the vendor, or the insurance company associated with the engine. Maintenance checks and readiness testing of such units is limited to 100 hours per year. There is no time limit on the use of emergency stationary ICE in emergency situations. The owner or operator may petition the Administrator for AIRS ID: 123/0057 Page 14 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division approval of additional hours to be used for maintenance checks and readiness testing, but a petition is not required rf the owner or operator maintains records indicating that Federal, State, or local standards require maintenance and testing of emergency ICE beyond 100 hours per year. Emergency stationary ICE may operate up to 50 hours per year in non-emergency situations, but those 50 hours are counted towards the 100 hours per year provided for maintenance and testing. The 50 hours per year for non-emergency situations cannot be used for peak shaving or to generate income for a facility to supply power to an electric grid or otherwise supply non�mergency power as part of a financial arrangement with another entity. For owners and operators of emergency engines, any operation other than emergency operation, maintenance and testing, and operation in non-emergency situations for 50 hours per year, as permitted in this section , is prohibited . (Reference: NSPS IIII , § 60.4211 (f)) 31 . Point 031 : 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 e�ent 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 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 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. 32. Point 031 : This source is subject to the requirements of: • Regulation No. 8, Part E , Subpart III. FFFF: National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines (RICE) of 40 C.F. R. Part 63, Subpart ZZZZ, and • Regulation No. 8, Part E, Subpart I.A, National Emission Standards for Hazardous Air Pollutants for Source Categories: General Provisions, 40 CFR Part 63 including , but not limited to, the following: • §63.6590 Applicability o §63.6590(b)(1 ) - An affected source which meets either of the criteria in paragraph (b)( 1 )(i) through (ii) of this section does not have to meet the AIRS ID: 123/0057 Page 15 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division requirements of 40 CFR Part 63 Subpart ZZZZ and of Subpart A except for the initial notification requirements of §63.6645(f). • (i) The stationary RICE is a new or reconstructed emergency stationary RICE . • §63.6645 Notifications o §63.6645(� - If you are required to submit an Initial Notification but are otherwise not affected by the requirements of this subpart, in accordance with §63 .6590(b), your notification should include the information in §63.9(b)(2)(i ) through (v), and a statement that your stationary RICE has no additional requirements and explain the basis of the exclusion (for example, that it operates exclusively as an emergency stationary RICE if it has a site rating of more than 500 brake HP located at a major source of HAP emissions). 33. Points 057, 058, 059, 060, 061 and 062 : These sources are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A Subpart Dc, Standards of Pertormance for Small Industrial-Commercial-Institutional Steam Generating Units including , but not limited to, the following : a) The owner or operator of the facility shall record and maintain records of the amount of fuel combusted during each month (40 CFR Part 60.48c(g)). b) Monthly records of fuel combusted required under the previous condition shall be maintained by the owner or operator of the facility for a period of two years following the date of such record (40 CFR Part 60.48c(i )). In addition , the following requirements of Regulation No. 6, Part A, Subpart A, General Provisions, apply. c) At all times, including periods of start-up, shutdown , and malfunction , the facility and control equipment shall, to the e�ent 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 d ) 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 gases discharged to the atmosphere. (§ 60. 12) e) Written notification of construction and initial startup dates shall be submitted to the Division as required under § 60.7. f) Records of startups, shutdowns, and malfunctions shall be maintained , as required under § 60.7 . AIRS ID: 123/0057 Page 16 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division 34 . Points 057, 058, 059, 060, 061 and 062 : Particulate emissions shall be limited as per: Regulation 6 , PaR B , II . C .2 . 35. Points 063, 064, 065 and 066: The amine units addressed by AIRS ID 063, 064 , 065 and 066 are subject to the New Source Pertormance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Pertormance for Crude Oil and Natural Gas Production , Transmission and Distribution including, but not limited to, the following: • §60.5365 — Applicability and Designation of Affected Facilities o §60.5365(g)(3) - Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (HZS) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in §60.5423(c) but are not required to comply with §§60.5405 through 60 .5407 and §§60.5410(g ) and 60 .5415(g). • §60.5423 - Record keeping and reporting Requirements o §60.5423(c) - To certify that a facility is exempt from the control requirements of these standards, for each facility with a design capacity less that 2 LT/D of HZ S in the acid gas (expressed as sulfur) you must keep, for the life of the facility, an analysis demonstrating that the facility's design capacity is less than 2 LT/D of HZ S expressed as sulfur. 36. Point 067: This source is subject to the requirements of 40 CFR, Part 63, Subpart HH - National Emission Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities including, but not limited to, the following : • §63.769 — Equipment Leak Standards �� §63.769(b) - The requirements of §63 .769 do not apply to ancillary equipment and compressors for which the owner or operator is subject to and controlled under the requirements specified in 40 CFR part 60, subpart OOOO. o §63.775(e) - Ancillary equipment and compressors subject to and controlled under 40 CFR part 60, subpart OOOO shall submit the periodic reports specified in §63 .775(e)( 1 ) and (2 ). 37. Point 067: The fugitive component leak emissions addressed by AIRS ID 067 are subject to the New Source Pertormance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: • §60.5365 Applicability - The group of all equipment, except compressors, within a process unit for which you commence construction , modification or reconstruction after August 23, 2011 is an affected facility per §60.5365(fl. • §60.5400 Standards - The group of all equipment, except compressors, within a process unit must comply with the requirements of §60.5400 and §60.5401 . • §60.5410 - Owner or operator must demonstrate initial compliance with the standards using the requirements in §60.5410(�. AIRS ID: 123/0057 Page 17 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division • § 60 .5415 - Owner or operator must demonstrate continuous compliance with the standards using the requirements in §60.5415(fl. • § 60.5421 - Owner or operator must comply with the recordkeeping requirements of §60.5421 (b). • § 60.5422 - Owner or operator must comply with the reporting requirements of paragraphs (b) and (c) of this section in addition to the requirements of § 60.487a(a), (b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii). 38. Point 067: The reciprocating compressors grouped with the fugitive emissions addressed by AIRS ID 067 are subject to the New Source Pertormance Standards requirements of Regulation No. 6, Part A, Subpart 0000, Standards of Pertormance for Crude Oil and Natural Gas Production , Transmission and Distribution including, but not limited to, the following: • §60.5385(a) — Owner or operator must replace the reciprocating compressor rod packing according to either paragraph §60.5385(a)(1 ) or (2). o §60.5385(a)(1 ) - Before the compressor has operated for 26 ,000 hours. The number of hours of operation must be continuously monitored beginning upon initial startup of your reciprocating compressor affected facility, or October 15, 2012, or the date of the most recent reciprocating compressor rod packing replacement, whichever is later. o §60.5385(a)(2) - Prior to 36 months from the date of the most recent rod packing replacement, or 36 months from the date of startup for a new reciprocating compressor for which the rod packing has not yet been replaced. • §60.5410 — Owner or operator must demonstrate initial compliance with the standards as detailed in §60.5410(c). • §60.5415 — Owner or operator must demonstrate continuous compliance with the standards as detailed in §60.5415(c). • §60.5420 - Owner or operator must comply with the notification , reporting, and recordkeeping requirements as specified in §60.5420(a), §60.5420(b)(1 ), §60.5420(b�(4), and §60.5420(c)(3�. 39. Point 067: This source is subject to Regulation No. 7, Section XII . G . 1 (State only enforceable). To comply with Regulation No. 7, Section XII .G . 1 , the source shall follow the leak detection and repair (LDAR) program as provided at 40 C. F. R. Part 60, Subpart 0000 in lieu of following 40 C. F. R. Part 60, Subpart KKK. 40. Points 068 and 069: The operator shall continuously monitor and record the total volumetric flow rate of the gas stream being routed to each flare. By the end of each month , the total volumetric flow for the previous months' data shall be calculated , and a new twelve-month total shall be calculated and recorded based on the previous twelve months' data. 41 . This facility is located in an ozone non-attainment or attainment-maintenance area and subject to the Reasonably Available Control Technology (RACT) requirements of Regulation Number 3, Part B , III . D2.a . : Facility AIRS Meeting RACT Requiremenis by: AIRS ID: 123/0057 Page 18 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division Equipment Point ID GEN3 031 Complying with 40 C . F. R PaR 60, SubpaR IIII as per Condition 29 E-2015 057 E-2016 058 H-6051 059 Implementing good combustion practices as per H-6052 060 Conditions 23 .f) H-6053 061 H-6054 062 A-1 063 A-2 064 Installing control device as per Condition 17 A-3 065 A-4 066 FUG3 067 Implementing LDAR program as per Condition 39 F-2 068 Installing control device as per Condition 20 F-3 069 OPERATING & MAINTENANCE REQUIREMENTS 42 . Points 031 , 063, 064, 065, O66 and 067: Upon startup of these points, the applicant shall follow the operating and maintenance (O&M) plan and record keeping format approved by the Division , in order to demonstrate compliance on an ongoing basis with the requirements of this permit. Revisions to your O&M plan are subject to Division approval prior to implementation . (Reference: Regulation No. 3, Part B , Section III.G.7. ) 43. Points 063, 064, 065 and 066: The inlet gas temperature and inlet gas pressure to the amine contactor shall be measured and recorded weekly. COMPLIANCE TESTING AND SAMPLING Initial Testinq Requirements 44. Point 031 : The owner or operator shall demonstrate compliance with Condition 28, using EPA Method 9 to measure opacity from this source. The opacity shall be measured and interpreted as an average of the readings taken over fifteen ( 15) second intervals for a total of six (6) minutes. (Reference: Regulation No. 1 , Section II .A. 1 & 4 ) 45. Points 057, 058, 059, 060, 061 and 062: The owner or operator shall complete the initial fuel sampling for gross calorific value (GCV) [high heat value (HHV)] of the fuel used in the heaters as required by this permit and submit the results to the Division as AIRS ID: 123/0057 Page 19 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division part of the self-certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B , Section III . E. ) 46. Points 057, 058, 059, 060, 061 and 062: A source initial compliance test shall be conducted on each heater to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits contained in this permit. 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 Division 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 compliance 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 . , Section III.G .3) Oxides of Nitrogen using EPA approved methods. Carbon Monoxide using EPA approved methods. PM25 (filterable and condensable) using EPA approved methods. Carbon dioxide using EPA approved methods. 47. Points 063, 064, 065 and 066: The owner or operator shall complete the initial annual sour gas analysis testing required by this permit and submit the results to the Division as part of the self-certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B , Section III . E. ) 48. Points 063, 064, 065 and 066: The owner or operator shall complete the initial amine unit waste gas sampling required by this permit and submit the results to the Division as part of the self-certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B , Section III . E.) 49. Points 063, 064, 065 and 066: A source initial compliance test shall be conducted on emissions points 063, 064, 065 and 066 to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits specrfied in Condition 7 in this permit. The operator shall also demonstrate the thermal oxidizer achieves a minimum destruction and removal efficiencv (DRE) of 99. 0°/o for VOC and CH4 . The operator shall measure and record , using EPA approved methods, VOC and CH4 mass emission rates at the thermal oxidizer inlet and outlet to determine the destruction efficiency of the thermal oxidizer (ProMax/Amine Calc/GlyCalc models shall not be used to determine the flow rate or composition of the waste gas sent to the thermal oxidizer for the purposes of this test). The natural gas throughput, lean amine circulation rate, MDEA concentration, and sulfur content of sour gas entering the amine units shall be monitored and recorded during this test. The operator shall also measure and record combustion zone temperature during the initial compliance test to establish the minimum combustion temperature. 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 Division 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 compliance 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 AIRS ID: 123/0057 Page 20 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division the allowable number of operating hours for that averaging time (Reference: Common Provisions Section II . C and Regulation No. 3 , Part B . , Section III . G .3) Sulfur Dioxide using EPA approved methods Oxides of Nitrogen using EPA approved methods Volatile Organic Compounds using EPA approved methods Carbon Monoxide using EPA approved methods PMZ 5 (filterable and condensable) using EPA approved methods. Methane using EPA approved methods Carbon Dioxide using EPA approved methods. 50. Point 067: Within one hundred and eighty days ( 180) after commencement of operation , the permittee shall complete the initial extended gas analysis of gas samples and extended natural gas liquids analysis of liquids that are representative of inethane (CH4), carbon dioxide (CO2), volatile organic compound (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas and liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. The operator shall submit the results of the gas and liquids analyses and emission calculations to the Division as part of the self-certification process to ensure compliance with emissions limits. 51 . Point 067: Within one hundred and eighty days ( 180) after commencement of operation , the operator shall complete a hard count of components at the source and establish the number of components that are operated in "heavy liquid service", "light liquid service", "water/oil service" and "gas service". The operator shall submit the results to the Division as part of the self-certification process to ensure compliance with emissions limits. 52. Points 068 and 069: The owner or operator shall complete the initial gas sample of the gas routed to the flares to determine the concentration of Hydrogen Sulfide, VOC, Benzene, Toluene, Ethylbenzene, Xylene and n-Hexane contents, and heat value in the gas stream. The owner or operator shall submit the results as part of the self- certification process to ensure compliance with emission limits. 53. Points 068 and 069: The owner or operator shall demonstrate compliance with Condition 10 using EPA Method 9 to measure opacity from the flare. (Reference: Regulation No. 1 , Section II.A.5). Periodic Testinq Requirements 54. Point 031 : Replacements of this unit completed as Alternative Operating Scenarios may be subject to additional testing requirements as specrfied in Attachment A. 55. Points 057, 058, 059, 060, 061 and 062 : The fuel gross calorrfic value (GCV) [high heat value (HHV)] of the fuel used in the heaters shall be determined , at a minimum, once per every six months by the procedures contained in 40 CFR Part 98 .34(a)(6) and records shall be maintained of the semiannual fuel GCV for a period of five years. Upon request, the owner or operator shall provide a sample and/or analysis of the fuel that is fired in the heaters. 56. Points 063, 064, 065 and 066: The operator shall measure the emission rate(s) for the pollutants listed below at least once every six months in order to demonstrate AIRS ID: 123/0057 Page 21 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division compliance with the emissions limits contained in this permit. Periodic testing shall be conducted at a minimum of at least thirty (30) days apart. The ooerator shall also demonstrate the thermal oxidizer achieves a minimum destruction and removal efficiencv ( DRE) of 99. 0% for VOC and CH4. The operator shall measure and record, using EPA approved methods, VOC and CH4 mass emission rates at the thermal oxidizer inlet and outlet to determine the destruction and removal efficiency of the thermal oxidizer (process models shall not be used to determine the flow rate or composition of the waste gas sent to the thermal oxidizer for the purposes of this test). The natural gas throughput, lean amine circulation rate, MDEA concentration, and combustion zone temperature shall be monitored and recorded during this test. 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 Division 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 compliance 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 . , Section III.G .3) Sulfur Dioxide using EPA approved methods Oxides of Nitrogen using EPA approved methods Volatile Organic Compounds using EPA approved methods Carbon Monoxide using EPA approved methods PMz 5 (filterable and condensable) using EPA approved methods. Methane using EPA approved methods Carbon Dioxide using EPA approved methods. 57. Points 063, 064, 065 and 066: Amine unit waste gas will be sampled and analyzed from each amine unit including an extended gas analysis at least once every three months for composition in accordance with 40 CFR 98233(d)(6) and 98234(b). The sample shall be analyzed for CO2, CH4, VOC, Benzene, Toluene, Ethylbenzene, Xylene n-Hexane, and H2S content. The sampled data will be used to calculate GHG , VOC and H2S emissions to show compliance with the emission limits specified in Condition 7. 58. Points 063, 064, 065 and 066: The operator shall sample the inlet gas to the plant on an annual basis to determine the concentration of hydrogen sulfide (HzS ) in the gas stream . The sample results shall be monitored to demonstrate that each amine unit qualifies for the exemption from the Standards of Pertormance for Crude Oil and Natural Gas Production , Transmission and Distribution (§60.5365(g )(3)). 59. Point 067: On an annual basis, the permittee shall complete an extended gas analysis of gas samples and an extended natural gas liquids analysis of liquids that are representative of inethane (CH4), carbon dioxide (CO2), volatile organic compounds (VOC ) and hazardous air pollutants (HAP ) that may be released as fugitive emissions. This extended gas and liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. 60. Point 067 : This facility is subject to the leak detection and repair (LDAR) requirements of 40 C. F . R Part 60, Subpart OOOO. AIRS ID: 123/0057 Page 22 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division 61 . Points 068 and 069: The owner or operator shall sample the gas routed to the flares, on an annual basis, to determine the content of Hydrogen Sulfide, VOC, Benzene, Toluene, Ethylbenzene, Xylene and n-Hexane contents. The most recent sample results shall be used to calculate actual emissions of criteria pollutants and hazardous air pollutants. ADDITIONAL REQUIREMENTS 62. The operator shall have 30 days after commencement of operation of the associated phase processing trains to cancel the following permits/points and permanently remove them from service. Removal of this equipment is required to maintain a synthetic minor modification status per Regulation 3 Part D: Existing Existing Permit No. Emission Point New Emission Point 11WE132 � 23/0057/005 Engines are cancelled upon startup of new and 006 Lancaster Plant Train I . 11WE132 123/0057/007 Engine is cancelled upon startup of new Lancaster Plant Train II. 97WE0180 123/0057/013 Engine is cancelled upon startup of new Lancaster Plant Train II. 63. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, II .C) a) Annually whenever a significant increase in emissions occurs as follows: For any criteria pollutani: For sources emitting less than 100 tons per year, a change in actual emissions of five (5) tons per year or more, above the level reported on the last APEN; or For volatile organic compounds (VOC) and nitrogen oxides sources (NO,) in ozone nonattainment areas emitting less than 100 tons of VOC or NO, per year, a change in annual actual emissions of one ( 1 ) ton per year or more or five percent, whichever is greater, above the level reported on the last APEN ; 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 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; or d ) Whenever a permit limitation must be modified ; or AIRS ID: 123/0057 Page 23 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division e) No later than 30 days before the existing APEN expires. f) Point 031 : Within 14 calendar days of commencing operation of a permanent replacement engine under the alternative operating scenario outlined in this permit as Attachment A. The APEN shall include the specific manufacturer, model and serial number and horsepower of the permanent replacement engine, the appropriate APEN filing fee and a cover letter explaining that the permittee is exercising an alternative-operating scenario and is installing a permanent replacement engine. 64. 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 provisions of this construction permit must be incorporated into the operating permit. The application for the modification to the Operating Permit is due within one year of commencement of operation of the equipment or modification covered by this permit. GENERAL TERMS AND CONDITIONS: 65. This permit and any attachments must be retained and made available for inspection upon request. The permit may be reissued to a new owner by the APCD as provided in AQCC Regulation No. 3, Part B, Section II . B upon a request for transfer of ownership and the submittal of a revised APEN and the required fee. 66. If this permit specifically states that final authorization has been granted , then the remainder of this condition is not applicable. Otherwise, the issuance of this construction permit does not provide "final" authority for this activity or operation of this source . Final authorization of the permit must be secured from the APCD 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 III .G . Final authorization cannot be granted until the operation or activity commences and has been verified by the APCD as conforming in all respects with the conditions of the permit. Once self-certification of all points has been reviewed and approved by the Division , it will provide written documentation of such final authorization . Details for obtaining final authorization to operate are located in the Requirements to Self- Certify for Final Authorization section of this permit. 67. 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 applicanYs agents. It is valid only for the equipment and operations or activity specifically identified on the permit. 68. 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 25-7-114 .5(7)(a), C. R.S. 69. Each and every condition of this 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 ab initio. This permit may be revoked at any time prior to self-certification and final authorization 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 or condition of the permit. If the Division denies a permit, conditions imposed upon a permit are contested by the applicant, or the Division AIRS ID: 123/0057 Page 24 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division revokes a permit, the applicant or owner or operator of a source may request a hearing before the AQCC for review of the Division's action . 70. Section 25-7-114.7(2)(a), C. R. S. requires that all sources required to file an Air Pollution Emission Notice (APEN ) must pay an annual fee to cover the costs of inspections 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. 71 . Violation of the terms of a permit or of the provisions of the Colorado Air Pollution Prevention and Control Act or the regulations of the AQCC may result in administrative, civil or criminal enforcement actions under Sections 25-7-115 (enforcement), -121 (injunctions), -122 (civil penalties), -122 . 1 (criminal penalties), C. R.S . By: Stephanie Chaousy, P .E. Permit Engineer Permit Histo Issuance Date Description Issuance 1 This Issuance Addition of fourteen (14) permitted sources for a cryogenic plant. Sources located at a major facility. AIRS ID: 123/0057 Page 25 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division Notes to Permit Holder at the time of this permit issuance: 1 ) The permit holder is required to pay fees for the processing time for this permit. An invoice for these fees will be issued after the permit is issued. The permit holder shall pay the invoice within 30 days of receipt of the invoice. Failure to pay the invoice will result in revocation of this permit (Reference: Regulation No. 3, Part A, Section VI.B.) 2) The production or raw material processing limits and emission limits contained in this permit are based on the consumption rates requested in the permit application. These limits may be revised upon request of the permittee providing there is no exceedance of any specifc 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. 3) This source is subject to the Common Provisions Regulation Part II, Subpart E, A�rmative Defense Provision for Excess Emissions During Malfunctions. The permittee shall notify the Division of any malfunction condition which causes a violation of any emission limit or limits stated in this permit as soon as possible, but no later than noon of the next working day, followed by written notice to the Division addressing all of the criteria set forth in Part II . E. 1 . of the Common Provisions Regulation. See: htto://www.cdohe.state.co. us/reaulations/airreas/100102aacccommon�rovisionsrea . �df. 4) The following emissions of non-criteria reportable air pollutants are estimated based upon the process limits as indicated in this permit. This information is listed to inform the operator of the Division's analysis of the specific compounds emitted if the source(s) operate at the permitted limitations. Uncontrolled Emission Are the Controlled AIRS Rate emissions Emission Point Pollutant CAS # BIN (Ib/yr) reportable? Rate (Ib/yr) 063-066 Hexane 110543 C 30,878 Yes 309 EACH Benzene 71432 A 2008 Yes 938 Toluene 108883 C 5238 Yes 2460 067 Ethylbenzene 100414 C 380 No 178 Xylenes 1330207 C 3716 Yes 1749 n-Hexane 110543 C 8973 Yes 4194 5) The emission levels contained in this permit are based on the following emission factors: Point 031 : Emission Factors - Uncontrolled EF Source Uncontrolled CAS Pollutant Ib/MMBtu g/hp-hr NOx --- 5.56 Manufacturer CO --- 0. 35 Manufacturer VOC --- 0.01 Manufacturer PM2.5 0.057 --- AP-42, Table 3.4-2 PM10 0.056 --- AP-42, Table 3.4-2 SOx 1 .01 --- AP-42, Table 3.4- 1 50000 Formaldehyde 0.0000789 --- AP-42, Table 3.4-3 75070 Acetaldehyde 0.0000252 --- AP-42, Table 3.43 107028 Acrolein 0.00000788 --- AP-42, Table 3.4-3 71432 Benzene 0.000776 --- AP-42, Table 3.4-3 AIRS ID: 123/0057 Page 26 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division 'Note that these emission factors are based on manufacturer's specifications for steady state operating conditions. Emission standards requirements per 40 CFR 60 Subpart IIII are based on a weighted cycle averege. Emission factors are based on a fuel use rate of 39.9 gallons/hr, a Brake-Specific Fuel Consumption Factor of 6,988 Btu/hp-hr, a heating value of 0. 1469 MMBtu/gal and a site-rated horsepower value of 839 HP and a fuel heat value of 18,390 Btu/Ib. Greenhouse Gas Emission Factors Pollutant kg/MMBtu Global W(Gm�P; Potential Source CO2 7325 1 40 CFR 98 Sub art A and C CH4 0.003 21 40 CFR 98 Sub art A and C N2O 0.0006 310 40 CFR 98 Sub art A and C Emissions for this point are based on an engine heat rate of 6,988 btu/hp-hr and maximum rating of 839 bhp. Points 057 and 058: Emission Factors - Uncontrolled EF Source Uncontrolled CAS Pollutant NOx 0.041b/MMBtu Manufacturer CO 0.041blMMBtu Manufacturer VOC 0.0191b/MMbtu Manufacturer PM10 7.61b/MMscf AP-42, Table 1 .4-2 PM2.5 7.6 Ib/MMscf AP-42, Table 1 .4-2 Emissions for these points are based on a fuel heating value of 1 ,020 btu/scf. Greenhouse Gas Emission Factors Pollutant kg/MMBtu GWP Source CO2 53.02 1 40 CFR 98 Subpart A and C CH4 0.001 21 40 CFR 98 Subpart A and C N2O 0.0001 310 40 CFR 98 Subpart A and C Emissions for these points are based on a heat content of 1 ,020 Btu/scf and a heat input rating for each heater of 29.8 MMBtulhr. Points 059, 060, O61 and 062: Emission Factors - Unconirolled EF Source Uncontrolled CAS Pollutant NOx 0.041blMMBtu Manufacturer CO 0.041b/MMBtu Manufacturer VOC 5.5 Ib/MMscf AP�2, Table 1 .4-2 PM10/PM2.5 0.00S lb/MMBtu Manufacturer Emissions for these points are based on a fuel heating value of 1 ,020 btu/scf. Greenhouse Gas Emission Factors Pollutant kg/MMBtu GWP Source CO2 53.02 1 40 CFR 98 Subpart A and C CH4 0.001 21 40 CFR 98 Subpart A and C AIRS ID: 123/0057 Page 27 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division Pollutant kg/MMBtu GWP Source N2O 0.0001 310 40 CFR 98 Sub art A and C Emissions for these points are based on a heat content of 1 ,020 Btu/scf and a heat input rating for each heater of 76.9 MMBtWhr. Points 063, 064, 065 and 066: Emissions from the amine unit result from venting of acid gas (still vent overhead) and flash tank emissions to the thermal oxidizer. Additionally, emissions result from combustion of supplemental fuel required to combust the acid gas (still vent overhead) emissions at the thermal oxidizer. Actual VOC, HAP and H2S emissions from venting of still vent acid gas and flash tank emissions shall be calculated based on most recent waste gas sampling and most recent monthly waste gas flow volume. Controlled emissions are based on a thermal oxidizer control efficiency of 99%. SO2 emissions resulting from the control/combustion of H2S emissions in the waste gas are based on mass balance and assuming 99% of the H2S is converted to SO2. Additional combustion emissions (from both supplemental fuel and waste gas) are calculated using the following emission factors and volume of total gas combusted. Total gas combusted is the sum of most recent waste gas flow volume plus most recent supplemental fuel volume plus burner volume. Total actual emissions for each point are then based on the sum of emissions calculated for controlled waste gas plus combustion (including supplemental fuel and waste gas). Emission Factors - Uncontrolled EF Uncontrolled Source CAS Pollutant �b/MMscf total gas combusted" NOx 100 AP-42, Table 1 .4-1 CO 84 AP-42, Table 1 .4-1 VOC 1 . 1 AP-42, Table 1 .4-2 SO2 0.6 AP-42, Table 1 .4-2 PM10 7.6 IblMMscf AP-42, Table 1 .4-2 PM2.5 7.6 Ib/MMscf AP�2, Table 1 .4-2 'Total gas combusted equals waste gas volume plus supplemental fuel volume plus fuel volume to bumer. Greenhouse Gas Emission Calculations far Amine Units The owner or operator shall calculate CO2 emissions from each amine unit, on a monthly basis, using equation W-3 consistent with 40 CFR Part 98, Subpart W [98.233(d)(2)] along with the most recent waste gas sampling composition and most recent monthly waste gas flow volume. The owner or operetor shall calculate GHG emissions from combustion at each thermal oxidizer based on procedures in 40 CFR 98 Subparts A and C along with the most recent monthly fuel gas and waste gas flow volumes. Total CO2 emissions shall be based on the sum of CO2 emissions from the amine unit plus GHG emissions from combustion at each thermal oxidizer. Greenhouse Gas Emission Factors for Thermal Oxidizer Combustion Pollutant kg/MMBtu GWP Source CO2 53A2 1 40 CFR 98 Subpart A and C CH4 0.001 21 40 CFR 98 Subpart A and C N2O 0.0001 310 40 CFR 98 Subpart A and C GHG emissions from combustion are based on a heat content of 1 ,020 Btu/scf and a total heat input for each thermal oxidizer of 16.7 MMBtu/hr. Point 067: Equipment Type Gas Heavy Oil (or Light Oil (or Water/Oil Heavy Liquid) Light Liquid) AIRS ID: 123/0057 Page 28 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division Connectors 1630 488 821 --- Flan es 744 45 719 --- O en-Ended Lines --- --- --- --- Pum Seals --- 15 33 3 Valves 1487 196 1359 --- Other 78 4 28 --- VOC Content (wt%) 22%, 100% 100% 99% 100% Benzene (wt%) 0. 12% --- 2. 0% --- Toluene (wt%) 0. 15% --- 5. 5% --- Ethy/benzene (wt%) 0. 01 % --- 0.4% --- Xylenes (wt%) 0. 05% --- 4. 0% --- n-hexane (wt%) 0. 5% --- 9. 0% --- CO2 Content (wt%) 6% --- --- --- CH4 Content (wt%) 57% --- --- --- 'Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms, hatches, instrument meters, polish rods and vents TOC Emission Factors (kg/hr-component): Component Gas Service Heavy Oil Light Oil Water/Oil Service Connectors 2.0E-04 7.5E-06 2. 1 E-04 1 . 1 E-04 Flanges 3.9E-04 3.9E-07 1 . 1E-04 2.9E-06 Open-ended Lines 2.0E-03 1 .4E-04 1 .4E-03 2.5E-04 Pump Seals 2.4E-03 NA 1 .3E-02 2.4E-05 Valves 4.5E-03 8.4E-06 2.5E-03 9.8E-OS Other 8.8E-03 3.2E-05 7.5E-03 1 .4E-02 Source: EPA-453/R95-017 Note that the emission limits included in this permit are derived by multiplying the equipment counts in the table above by a factor of 1 . 1 to accommodate other minor changes to the facility and to provide a conservative estimate of facility-wide emissions. Compliance with emissions limits in this permit will be demonstreted by using the TOC emission factors listed in the table above with representative component counts, multiplied by the VOC content from the most recent gas and liquids analyses. For CO2e emissions, the TOC emission factors listed in the table above with representative component count will be multiplied by the CH4 and CO2 content from the most recent gas analysis. CO2e emissions are then calculated based on procedures in 40 CFR 98 Subpart A. Points 068 and 069: Emission CAS Pollutant Factors - Uncontrolled EF Source Uncontrolled 0. 138 NOx Ib/MMBtu TCEQ CO 02755 TCEQ Ib/MMBtu VOC 0.03 Ib/MMBtu AP-42 THC Emission Factor ' 22% VOC AIRS ID: 123/0057 Page 29 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division Emission CAS Pollutant Factors - Uncontrolled EF Source Unconirolled PM2.5/PM10 7.61b/MMscf AP-42, Table 1 .4-2 NOx and CO emissions are based on the annual requested process gas heat rate of 12. 14 MMbtu/hr. Compliance with the CO2e emissions limits in this permit will be demonstrated by using equations and procedures outlined in 40 CFR Part 98, Subpart W 98.233(n) along with the measured flare gas composition and monthly measured flare gas flow volume. Flare combustion efficiency is 95%. 6) Points 057, 058, 059, 060, 061 and 062: These reboilers are subject to 40 CFR, Part 63, Subpart DDDDD—National Emission Standards for Hazardous Air Pollutants for Industrial , Commercial, and Institutional Boilers and Process Heaters. This rule has not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 6. A copy of the complete subpart is available on the EPA website at: http://www.epa.qov/ttn/atw/boiler/reconsideration redline strikeout compared2fnl.pdf 7) In accordance with C. R.S. 25-7-114. 1 , each Air Pollutant Emission Notice (APEN) associated with this permit is valid for a teRn of five years from the date it was received by the Division. A revised APEN shall be submitted no later than 30 days before the five-year term expires. Please refer to the most recent annual fee invoice to determine the APEN expiration date for each emissions point associated with this permit. For any questions regarding a specific expiration date call the Division at (303)-692-3150. 8) This facility is classified as follows: Applicable Status Requirement Operating Permit Major Source of NOX, VOC, CO, and HAP PSD Major Source of CO, CO2e NANSR Major Source of NOX and VOC MACT ZZZZ Major Source Requirements Apply MACT HH Major Source: Applicable NSPS Dc Applicable NSPS OOOO Applicable 9) Full text of the Title 40, Protection of Environment Electronic Code of Federal Regulations can be found at the website listed below: http://ecf r.g poaccess.gov/ Part 60: Standards of Pertormance for New Stationary Sources NSPS 60. 1 -End Subpart A — Subpart KKKK NSPS Part 60, Appendixes Appendix A — Appendix I AIRS ID: 123/0057 Page 30 of 34 c �lora J� Dep� ir*ient c Public Health and Environment Air Pollution Control Division Part 63: National Emission Standards for Hazardous Air Pollutants for Source Categories MACT 63. 1 -63.599 Subpart A - Subpart Z MACT 63.600-63. 1199 Subpart AA — Subpart DDD MACT 63. 1200-63. 1439 Subpart EEE — Subpart PPP MACT 63. 1440-63.6175 Subpart QQQ — Subpart YWY MACT 63.6580-63.8830 Subpart ZZZZ — Subpart MMMMM MACT 63.8980-End Subpart NNNNN — Subpart XXXXXX 10) An Oil and Gas Industry Construction Permit Self-Certification Form is included with this permit packet. Please use this fortn to complete the self-certification requirements as specifed in the permit conditions. Further guidance on self-certification can be found on our website at: htto:l/www.cdohe.state.co.us/ao/oi laasoermitti na.html AIRS ID: 123/0057 Page 31 of 34 Coh ,� �do D paRmei t or Public Health and Environment Air Pollution Control Division ATTACHMENT A: ALTERNATIVE OPERATING SCENARIOS STATIONARY (CI) ENGINE October 1 , 2011 2. Alternative Operating Scenarios The following Alternative Operating Scenario (AOS) for the temporary and permanent replacement of Stationary (CI ) engines has been reviewed in accordance with the requirements of Regulation No. 3., Part A, Section IV.A, Operational Flexibility- Alternative Operating Scenarios, Regulation No. 3, Part B, Construction Permits, and Regulation No. 3, Part D, Major Stationary Source New Source Review and Prevention of Significant Deterioration, and it has been found to meet all applicable substantive and procedural requirements. This permit incorporates and shall be considered a Construction Permit for any engine replacement performed in accordance with this AOS, and the permittee shall be allowed to perform such engine replacement without applying for a revision to this permit or obtaining a new Construction Permit. 2. 1 Engine Replacement The following AOS is incorporated into this permit in order to deal with an engine breakdown or periodic routine maintenance and repair of an existing onsite engine that requires the use of either a temporary or permanent replacement engine. "Temporary" is defined as in the same service for 90 operating days or less in any 12 month period. "PermanenY' is defined as in the same service for more than 90 operating days in any 12 month period. The 90 days is the total number of days that the engine is in operation. If the engine operates only part of a day, that day shall count as a single day towards the 90- day total . The compliance demonstrations and any periodic monitoring required by this AOS are in addition to any compliance demonstrations or periodic monitoring required by this permit. All replacement engines are subject to all federelly applicable and state-only requirements set forth in this permit (including monitoring and record keeping. The results of any all tests and the associated calculations required by this AOS shall be submitted to the Division within 60 days. Results of all tests shall be kept on site for five (5) years and made available to the Division upon request. The permittee shall maintain a log on-site and contemporaneously record the start and stop date of any engine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the engine(s) that are replaced during the term of this permit, and the manufacturer, model number, horsepower, and serial number of the replacement engine. 2. 1 . 1 The permittee may temporarily replace an existing engine that is covered by this permit with a different engine without modifying this permit. so long as the temporary replacement engine complies with all permit limitations and other requirements applicable to the existing engine. Calculation of emissions from the temporary replacement engine shall be made as set forth in section 2. 1 .3. 2. 1 .2 An Air Pollutant Emissions Notice (APEN) that includes the specifc manufacturer, model and serial number and horsepower of the permanent AIRS ID: 123/0057 Page 32 of 34 Coh ,� �do D paRmei t or Public Health and Environment Air Pollution Control Division replacement engine shall be filed with the Division for the permanent replacement engine within 14 calendar days of commencing operation of the replacement engine. The APEN shall be accompanied by the appropriate APEN filing fee, a cover letter explaining that the permittee is exercising an alternative operating scenario and is installing a permanent replacement engine and an analysis of any new applicable requirements for the replacement engine as required by Condition 2.2. This submittal shall be accompanied by a certification from the Responsible Official indicating that "based on the infortnation and belief formed after reasonable inquiry, the statements and information included in the submittal are true, accurete and complete". This AOS cannot be used for permanent engine replacement of a grendfathered or permit exempt engine or an engine that is not subject to emission limits. The permittee shall agree to pay fees based on the normal permit processing rate for review of information submitted to the Division in regard to any permanent engine replacement. 2. 1 .3 Compliance of the replacement engine with the applicable emission limitations of the original engine shall be monitored by one of the following methods: 1 ) Manufacturer certifed emission factors showing compliance. 2) Stack tests of same make and model showing compliance. This would only be considered if the test was done under similar conditions to Colorado (i.e. at altitude). 3) Stack tests on the engine. 2.2 Applicable Regulations for Permanent Engine Replacements 2.2. 1 NSPS for stationary compression ignition internal combustion engines: 40 CFR Part 60, Subpart IIII . A permanent replacement engine that is ordered after July 11 , 2005 and manufactured after April 1 , 2006 or is modifed or reconstructed after July 11 , 2005 is subject to the requirements of 40 CFR Part 60, Subpart IIII. An analysis of applicable monitoring, recordkeeping, and reporting requirements for the permanent engine replacement shall be included in any request for a permanent engine replacement. Note that under the provisions of Regulation No. 6. Part B, section I.B. that Relocation of a source from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation No. 6 (i .e. , the date that the source is first relocated to Colorado becomes equivalent to the date of manufacture for purposes of determining the applicability of NSPS IIII requirements). 22.2. MACT for Stationary Reciprocating Internal Combustion Engines:40 CFR Part 63, Subpart ZZZZ. Any permanent replacement engine located at either an area or major source is subject to the requirements of 40 CFR Part 63, Subpart ZZZZ. An analysis of applicable monitoring, recordkeeping, and reporting requirements for the permanent engine replacement shall be included in any request for a permanent AIRS ID: 123/0057 Page 33 of 34 Coh ,� �do D paRmei t or Public Health and Environment Air Pollution Control Division engine replacement. 2.3 Additional Sources The replacement of an existing engine with a new engine is viewed by the Division as the installation of a new emissions unit, not "routine replacemenY' of an existing unit. The AOS is therefore essentially an advanced construction permit review. The AOS cannot be used for additional new emission points for any site; an engine that is being installed as an entirely new emission point and not as part of an AOS-approved replacement of an existing onsite engine has to go through the appropriate Construction/Operating permitting process prior to installation. AIRS ID: 123/0057 Page 34 of 34 WGR Operating LP RqGE: 1 of 1 � PO Boz 1380 ' . . Hous[oq TX 77251-1330 � DATE:April 10,2012 � � � . TRACE NUMBER:742103390 � � CHECK NUMBER:742703390 � � � � � AMOUNTPAID:$1,070.30 � � . ACCOUNTS PAYABLE INQUIRIES:(800)370-9867 ��u��nu��u�i��un��n��i�n��u��m��u� . . � � . 0�E40 [KS 6A 12101 - pP421d339� NNNNNNNNNNNN 1p151000045@ %392D1 C � COLORADO DEPT OF PUBLIC HEALTH& =' ENVIRONMENT = 4300 CHERRY CREEK DR S, APCD SS 61 - DENVER CO 80246-1530 - � = VENDOR N0:0003405436 � . � � . � � . � DOCUMEMM �. VENDORINV#/ REMARKS . INVOICEDATE T�TA� PRIORPM75 7900000750 CKRQ040512 /+MOUM� � &DISCOUNTS AMOUNT � FT.LUPTON CRYOGENICE PLANT PERMITAPPLICATION 04/�5/12 $7,070.30 . � $0.00 $7,070.30 TOTALS � � . . . . $1,07030 $0A� � - $1,070.30 � �� , r---•_ ,� . . f �,_ AF'Ft-8 2Q7� , �., . � � � « � �� _ � je �_�' t / � � �.�'��. �S��..�i."�v�`JL� . G.�..'�V1t� �� t/l�/�� REOEPOSf7�NGCHECK �-1 , J WGR Operating LP � � � � � � I�� PO Box 7s3o . � CHECK � 7412s2 I, Houston,TX77251-133o NUMBER 7421O339O �Z4 April 1Q 2012 PAY COLORADO DEPT OF PUBLIC HEALTH& ' TOTHE ENVIRONMENT � � � - � � oRDeR OF: q300 CHERRY CREEK DR S,APCD SS 61 � � � DENVER,CO80246-7530 � �� CHECKAMOUNT �� **Z � O�O . 3O�F�F � � 1,070 DOLlA1�S AND 30 CENTS � JPMorgan Chase Bank,Dearbom � � � esE�„q,n,�„�qEs . � �� ti/,(� .� �� * wcwoEtt (/S.�'—�• earborn,Michigan I see oelu�s aH ence . . AUTHORIZED REPRESENTATIVE OF TFIE COMPANY � i�' 742i03390��• �:072412927i; 75H664742u• _ _ _. __ __ _ ._ _ ____ _ _ __ _ _ � 4/3/1a State.co.us Executi�e Branch Mail-RE:DRAFT BACT Conditions for Lancaster � � c h& l�'Y State � Colorsdo - - . .. � - . �. � . ., . . � . .. . . __.._— ----...__.. ---...--. _ ___..__.... -- -_._._ .....----------- -------- RE: DRAFT BACT Conditions for Lancaster --- Shea, Jennifer<Jennifer.Shea@anadarko.com> � � ------ To: "Money -CDPHE, Carissa" <carissa.money@state.co.us> � - � Tue, Apr 2, 2013 at 4:42 PM Cc: "Bracken, Korby" aKorby.Bracken@anadarko.com>, "stephanie.chaousy@state.co.us" <stephanie.chaousy@state.co.us>, "christopher.laplante@state.co.us" <christopher.laplante@state.co.us>; "mark.mcmillan@state.co.us" <mark.mcmillan@state.co.us>, "Carter, Micah" �Micah.Carter@anadarko.com> - � Ni Carissa, . - As we discussed on the phone today,the Flare condition 23.y requires that a flow meter be installed to monitorfhe air being added as assist gas. Just to clarify things, I<MG is requesting to replace the existing language witfi the following: y. Points 068and 069: The owneroroperatorsha�l install, operate,and maintein an air blowerequipped with a variable frequency drive (VFD) motor to supply ai r to maximize the ai r/gas mixing surface area for proper combustion. A signal verifying the supply of airto the waste gas stream priorto combustion shail be continuously monitored and reduced ta an averaging period of 6 minutes.or less and recorded at that frequency. Also, in condition aa, itstates thatthe flares are equipped with a burnermanagementsystem, however, afterequipment selection we discovered a burner management system was not required forthis flare. Can we adjust the language as follows: aa. Points 068 and 069: The flare shall be equipped with a flame ignition system and thermocouple to monitor presence of a pilot flame. The ignition system shall send out a remote alarm during pilot light outages and be capable ' of automaticaily relighting the pilot. Manual ignition of the pilot shall also be �ossible. .'� Let me know if these changes wprk foryou. I also attached a great description of our process flares. � Thank you, lennifer Shea � Siaff EHS Representative � � � . ANADARKO PETROLEUM CORPORATION � ' Direct: (720J 929-6028 � GeIL (303) 979-0040 � '��. . . . _ .. .. ..._ ... .. ._ _ .. __ . .._. . � � � . ��. . . _,.._. ._.._. .. ... _..._ _.. . . .._.__. .__ .._.. ._ ..._ . . .._.__ .._..._. .__... _. � . .. . . ._.._...._... .. . .. . _ __._. om: Shea, ]ennifer Sent: Tuesday, March 26, 2013 5:04 PM . � . . � '. To: 'Money- CDPHE, Carissa' � � � Ce: Bracken, Korby; stephanie.chaousy@state,co,us; christopher.laplante@state.co.us; mark,mcmillan@state,co.us; Carter, Micah Subject: RE: DRAFI- BACT Conditions for Lancaster . - � '�. https://mail.google.coMmail/u/0/?ui=2&ilyda5742cbb2&Nev�pt&search=inbox&th=l3dccea392fe247e � � � 1/4 _..___... . � 4l3/13 State.co.us Er.ecutl�e Branch Mail-RE:DRAFT BACT Condltions for Lancaster � Hi Carissa, � � Thanl<s for sendingthis over. The head engineerforthe Lancaster Plant is on vacation all this week so i have not had a chance�to - review with him yet. There are a few items I need to discuss with him tyour responses to#19-21) before i can provide an answer. � �Can I get back to you on these by the end of riext week? � � � IstheDivisionwillingtofurtherdiscussthermaloxidizertestingfrequency?�Allstreamsgoingtoeachthermaloxidizeraregoing to be very similar in composition (one inletwill just be split up between each train based on inlet volumes), so testing each thermal oxidizer on a semi-annual basis if we are consistently showing 99%+desiruction efficiency seems redundant. Would the Division be willingto add in at least some language that would aliow us to reduce testing frequency upon Division approval? Same with sampling under condition 38. Since our i��et streams to the each amine unitwill be the same composition, results � from quarteriy sampling on each amine unit waste gas stream will also be very similar. Is there anyway the Division would be willingtoworkwith us on eithersamplingfrequency or perhaps quarterly samplingwhile alternating amine unitwaste gas streams? � . - � . . I'd be happy to discuss over the phone if that is easier—sometimes trying to explain something in an email doesn't mme across corredly. � . � . Everything else looked good. . � � - �I Thanksforyourtimeonthis, � � � Jennifer Shea � Staff EHS Represertaiive. � � � ANADARKO PETROLEUM CORPORATION � �� Direct: (720) 929-6028 � CeIL (303) 919-004� . � From: Money- CDPHE, Carissa (mailto:carissa.money@state.co.us] • 4 AM � Sent: Thursday, March 21, 2013 11.1 To: Shea,Jennifer I Cc; Bracken, Korby; stephanie.chaousy@state.co,us; christopherJapiante@state.co,us; mark.mcmillan@state.co.us; Carter, Micah ' Subject: Re: DRAFT BACT Conditions for Lancaster I�� Jennifer, . � . � � Attached please find the Di�nsion's response to comments on the draft BACT conditions for Lancaster. These changes will be incorporated� into the draft permit which you will be able to re�iew in its entirety prior to public comment. Note that I am requesting additional feedback ! regarding two comments, the monitoring frequency for the in-line gas analyzer on the flares and description of the flare burner managemenY �, system. Please pro�nde�this information by 3/29/2013 so that we�can incorporate all comments prior to the next round of retiew. If you � ha�any questions, please let me know. . � � I ?J4 �� https://mail.google.cortJmaillul0/?ui=2&il�da5742cbb2&tiev�pt&search=inbo�th=l3dccea392Fe247e � 05 � p? aoJOi-IN Z1NK COMPANY LLC III. Svsr�nn DEsc�i�� JOHN �itdKAZDAIR,q►t�_ASSIS'fED FLARE {PLA-42) Most hydrocarbon-containing gas streams smoke when burned unless sufficient oxygen is mixed into the combustion zone. Smoke is produced by #he cracking and palymerization reactions taking place in the flame core, where there is a high flame temperature and insufficient oxygen for complete combustion. Adequate aeration of fhe combustion zone reduces or eliminates smoke. Wifh high-pressure gases sufficient air for complete combustian may be induced into the flame by a combination of jett{ng action and thermal draft. Wifh (ow pressure gases, when fhe jetting acfion may be negligible and the thermal draft alone is insufficient to entrain enough air for complete cambustion, smoke is produced. The problem of burning low-pressure gas smokelessly is usually solved by either aspirafing air into the flame using an external (pressure) energy source such as steam, or mixing gas directly with air. Although steam injection is very effective at reducing smake, such a system is not very suitable for flaring at remote locatipns where a farge steam supply is nof available. Air injection often provides the solution. Air can be supplied to the flare by a low-pressure fan. In the Azdair Air-assisted Smokeless Flare primary air � � �4 ��, �� for combustion ts supplied via a� low-pressure fan �≥€�{ � ' ` w�� twa�<≤`��,�r` � , mounted at the base of the stack. The air required for , ;i�„��,�;-�^ "`��f�� `��,�'" smokeless flaring ls supplled as a central core within r��'z��i�Pw�"�' ��'��`�: � the gas flame, and is designed to provide good mixtng ��?�' � MU��,' �'�.�� "�� rr��r +�D�� of the air and gas which produces a stable, smokeless ��.��.�, ��,-�, flame. �-�� ,�u �� ,-�� .��;��-��H ��°`�'�`" The Azdair is designed for duties where low-pressure � �� gases are requirec! Eo burn smokelessly when process i� steam is unavailable. The Azdair can also give lower radiation levels than a pipeflare for the same gas fiow and conditinns. Due to the premixed primary air �!, suppfied by ₹he air blower, the combusf(on efficiency PF 32211-A0 January 16, 2013 5 The information in this document is confidential and may constitute proprietary information, trade secrets,or ' olher privileged information. Therefore, it must not be disclosed to any person or enlity wifhout the written � consenf of John Zink Company, LLC. � . , _ _ _ . , __ � o � �,JOHN ZINK COMPANY LLC increases and khe quantify of incandescent carbon, the main source of heat radiation, reduces. The goal o# an efficient air assisted flare desfgn is to maximlze the air / gas mixing surface area. Conventional air assisted flares route the gas through the inner annulus of the flare tip mixing head while the air Is rauted through the outer annulus. This is a poor use of the flare tip cross-sectional area, which creates an outer ring of air around the periphery of the flare tip. The Azdair flare tip roufes the gas through the outer annulus and the air through the inner annulus. This maximizes the atr l gas surFace mixing area, and also makes efficient use of the ambient air by creating a thin film of gas around the outer periphery of the flare Eip diameter. This efficient air / gas mixing head arrangement allows the Azdair flare , tip to produce more smokeless �«��Y„NR capacity per yiven volume of forced u+s , � , air than the conventional air assisted siHE�N- _ #(are design. _ ,. �" ;� The outer gas annulus of fhe Azdair �,� I o hel s revent air ingress -��'� flare ti als p p � � : ��= � J ''+ p F'`J' "�� -:� _ into the mixing head at low gas flow _ ��;ir �-, rates. Conventiona! air assisted flare r��, �` : ' tips are much more likely to allow � ��,��oF n�uW H�_nU burning inside the tip mixing head at - : i eads to cns nuu " low gas flow rates. This I � J� . +.�t�.,�„,�,ft ��i , overheating and distortion of the j ; � d subse uent failure I mixing head an q of the flare tip. �� "�`" . - nzonn�Fi.we ta� -. 145 �EET TALL SELF SUPPORTED FLAFtE STACK The John Zink self supported flare stack provides a struc#ural support for the flare tips and piping as required. The stack is designed to resist dead load, live load, wind loads and seismic loads as required by the applicabie codec effec�ts'suc'h as The strueturai design also incorporates consideration of dynam ' altn vibration. tex sheddin and ov g vor 9 I PF 32211-A0 January 16, 2013 6 � The information in this document is confldential and may constitute proprietary information, trade secrets, or � other privileged informafion. Therefore, It must not be disclosed to any person or entity without the written consent of John Zink Company, LLG - - . . . . . . —_— —— 0 �, �JOHN ZiNK COMPANY LLC The riser is manufactured in sectians suitable for shipment and assembly, and match marked for field welding. The proper lifting �ugs are attached to the fop of each section, Each riser section must be welded in a verticaJ posrtion and is nat desfgned for single point lifting. A defailed description of the stack is included in attached data sheet. JOHN ZiNK Vi/lNDPROOFTM HIGH �ERFORMANCE PILO7 The John Zink iNindPROOF Pilot is the best that pilo₹ technology has to offer, with - � a combination of fuel efficiency and �� + sfability in adverse weather conditions. The WrndPROOF Pilot stands up to the �� most severe winds and rain with the fong � �,;:" lasting perFormanoe of our other pilot ��1,,' models. � �,�.�, ,'��. Stable in winds up to a ve(ocity of 16Q � 'y mph in all positions around the flare tip, , �1�, the WindPROOF Pifot consist of a tip and ,, , tip windshield, ignition and fuel piping, a mixer and strainer assembly, and a mixer �� a windshield. The WindPROOF is stable in � , the worst conditions while consuming as litt(e as 45 SCFH of fuel gas. Also ( included are one integral thermowells far � thermocouple pilo₹ detectian. The ' WindPROdF can burn a wide variety of fuels without ad)ustmenf. WindPROOF was desfgned and tested at the only pilot test facility of its kind in the world. At Jahn Zink's International Research and Development Center, we ; use full scale testing to push our flare products Yo extraordinary )imits. Det , Norske Veritas (DNV), the worlds most widely respected product verification and ' Certification Company, witnessed John Zink Company's test of the WindPROOF pilot and verified that the WindPROOF remained lit under test conditions that exceeded 160 mph winds and 30 inches of rainfall perhour. PF 32211-A0 January 16, 2013 'I The information in thls document ls confdentlal and may constitute proprletary information, trade secrets, or other priviieged (nformaUon. Therefore, It must not be disclosed to any person or entity without the written consent of John Zink Company, LLO. � ' _i �. � o � �JO}-[N Z(NK COMPAIVY LLC AU�ONIA7IC t Mp.NUAL FLA{VIE �RONT GENEF2ATOR IGNITION SYSTEM The John Zink Automatic Flame Front Generafor (FFG) ignition system provides reliabie pilot ign{iion, supported by over 40 years of experience. The FFG combines ignition fue4 and compressed air at a mixing tee with the ignition gas mixture flowing through an ignition Ilne to the pilot tip. After filling the ignition line with the air-fuel mixture, an electrical spark is initiated at the mixing tee. Af#er ignition, a point soures of flame #ravels through the ignition line and ignites the pilot gas at the pilot tip. Each pilot is ignited in sequence. The figure below depicts a typical three pilot automatic ignition system controf paneL 0FF 0N AUT0 MAN 2 � � � 1 "' 3 PANEL IGlJITION MANUAL PILOT POWER MODE IGNITION SELECT � � PIL07 PILOT FAILURE PROVEb After erforming tests with simulated pipelines and examining existing systee s p John Zink has determined that the �FG ignition system can be located in exc . ' nal flexibilit t. This lacement variabi�ity offers ope ratio Y i of 1, 040 feet from the pilo p ' and increased safety. Each pilot is equipped with a thermocouple which monitors the pilot fiame. ln addition, the FFG panel includes a local alarm light and personnel signal contacts for remote alarm systems. The automa#ic relight feature provides constant flame ' less steel sheathed thermocouple. Unmanned monitoring via a type K, 3 10 stain and immediate initiation of the ignition sequence is made in the unlikeiy event p ilot flame is lost. Pressure regufators are provided for bofh gas and air to maintain gas-air ratios for proper ignition, and solenoid valves allow auEomat�c reignition of the pilot Manual ignition of each pilot is possible; if necessary. �' PF 32211-AO January 16,2013 $ ' The information in this document is confdentiat and may constitute propriatary Information,trade secrets, or I olher pnvileged Information. Therefore, it must not be disclosed to any person or enlity wifhout the written consent of John Zink Company,LLO. - _ -_ _ _ _ 3/21Y13 � � State.co.us E�cuti�e Branch Mail-Re:DRAFT BACT Conditions for Lancaster � � r -y,� � S'% SafB ��`� �� COIOYBlIO . i . '� � . . � ... . ., e. �*t;. � . Re: DRAFT BACT Conditions for Lancasfer `� Money-CDPHE, Carissa <canssa.money@state.co.us> � � � � — To: "Shea, Jennifer" <Jennifer.Shea@anadarko.com> � � � Thu, Mar 21, 2013 at 11:13 AM Cc: "Bracken, Korby" <Korby.Bracken@anadarko.com>, "stephanie.chaousy@state.co.us" <stephanie.chaousy@state.co.us>, "christopher.laplante@state.co.us" <christopher.laplante@state.co.us>, "mark.mcmillan@state.co.us" <mark.mcmillan@state.co.us>, "Carter, Micah" <Micah.Carter@anadarko.com> Jennifer, . � Attached please find ihe Division's response to comments on the draft BqCT conditions for Lancaster. These changes will be incorporated into the draft permit which you will be able to re�iew in its entirety prior to public comment Note that I am requesting additional feedback� regarding two commenis, the monitoring frequency for the in-line gas analyzer on the flares and description of ihe fiare burner management system. Please provide this information by 3/29/2013 so that we can incorporate all comments pnor to the next round of re�iew. If you ha� any questions, please let me know. � � � Thank you, � � . � . Carissa � � On Fri, Jan 11, 2013 at 3:08 PM, Shea, Jennifer cJennifer.Shea@anadarko.com>wrote: � Carissa, . � � Attached are the comments to the draft Lancaster permit. I also attached updated emission calculation sheet since the Division's short term emissions calculations did not match I<MGs. Please let me Imow if you have any questions. � Jennifer Shea � Staff EHS Representative ANADARKO PETROLEUM CORPORATION � ' Direct (720) 929�6028 � �eIL (303) 979-0040 � ' � From: Money- CDPHE, Carissa [mailto:carissa.money@state.co.us] � � � Sent: Friday,January 04, 2013 2:03 PM � � To: Shea,Jennifer � - ' Cc: Bracken, Korby; stephanie.chaousy@sfate.co.us; christopher.laplanEe@state.co.us; mark.mcmillan@state.w.us � . Subject: DRAFT BACT Conditions for Lancaster - � � � ,�'' . Jennifer, � '� �Attached please find draft permit conditions addressing the GHG BACT requirements for the.proposed Lancaster facility. Note that some I references to other conditions in the permit may be incorrect since Pm only including ihe BACT requirements. Please provide commenis . by 1/1 V2013. If you have any questions, let me know. � � � Thank you, _ . � Carissa Money � . . , https://mail.google.com/mail/W0/?ui=2&ik=da5742cbb2&Hev�r-pt&search=sent&th=13d8df13185c80f8 � � 1/2 _ _. _ _. ._. .. __ _. . _... _ .. _.. _. ._ �'.. � Response to KMGs Comments on Draft Permit 12WE1492 Issuance 1 (BACT Conditions) 1. Equipment Description (pgl) - Engine is a diesel wmpression ignition (CI) engine, not a reciprocating internal combustion. Division Response: Modified equipment description as requested. Note that KMG continues to mark the incorrect ignition source on the APEN. The Division red-lined the APEN as well. 2. Equipment Description (pg2 - 3) Points 063 - 066: This is not an emergency flare, but rather the process flare (F2) Division Response: Modified equipment description as requested 3. Monthly Emission Limit Table (all points) -fmissions not correct. See updated calculation sheets showing Ib/mo and ton/mo calcs Division Response: Adjusted monthly emission limits due to rounding differences. Note that the Division requested KMG's spreadsheet to enable a more efficient review of emission calculations. KGM did not provide their spreadsheet which requires the Division to create a separate spreadsheet for emissions, resulting in minor rounding differences. For future applications for complex sources, the Division recommends providing an active spreadsheet to allow for a more efficient application review process. 4. Annual Emission Limit Table - GEN3 should be 139 ton/year of CO2e. Division Response: Subsequent to providing comments on the draft permit, KMG requested to revise the size and model of diesel emergency generator; this change affected aIl emission values. Emission limits have been updated based on KMG's latest request, except for CO2e. KMG's CO2e emissions are based on an incorrect emission factor (for natural gas). The Division calculates 238 tpy CO2e using the emission factor in 40 CFR 98 Subpart W for Distillate Fuel Oil No.l and this value will be updated in the permit. S. Annual Emission Limit Table Al-A4 — Requested to adjust 5O2 and VOC emissions Division Response: Adjusted limits as requested 6. Condition 22: The simulation was completed at 601 gal/minute, however the valve controlling ' the amine recirculation is only accurate to +/- 10%. This would normally be a significant � difference, however due to the large circulation rate, KMG is requesting to modify this value to ' 660 gal/min to account for control valve accuracy. � Division Response: The amine recirculation rate corresponds to the rate used in the process simulation for establishing emissions limits. The limit of 601 gal/min will remain as per the draft permit. 7. Condition 23.i: The air/fuel control system is part of the burner management system. ' Division Response: Added clarifying text. 8. Condition 23.j: KMG is request to decrease the frequency of preventative maintenance on the air intake system to once per every twelve months to be consistent with the other preventative maintenance required by this equipment. Division Response: The maintenance frequency is consistent with other GHG BACT requirements for similar sources. Condition wiil remain as per the draft. 9. Condition 23.k; Do you mean CH4e with GHG warming potential or just CH4? Division Response: The condition requires a minimum destruction efficiency of inethane of 99%. 10. Condition 23.1: Strike-out"that occurs at feast once every six months." No need to repeat if the freqency is stated in Condition 37. Allows for less errors if any changesare made to other conditions. Division Response: The on-going compliance testing is required to demonstrate compliance with the BACT requirement for 99% removal of inethane. The BACT requirements, including frequency, must be clearly stated in the BACT permit conditions. Since construction permits include a section for testing and the testing is also required for VOC control, it is mentioned in the testing section of the permit as welL Condition will remain as per the draft to ensure the BACT requirements are clearly identified. 11. Condition 23.1: Do you mean CH4e with GHG warming potential or just CH4? Division Response: The condition requires a minimum destruction efficiency of inethane of 99%. 12. Condition 23.m: Strike-out�bperating." Division Response: Replaced "operating temperature"with ��combustion temperature:" 13. Condition 23.0: Do you mean combustion temperature? Division Response: Yes, changed to"combustion temperature." 14. Condition 23.0: What does the Division define as continuous? Division Response: Since a reading is required once every six minutes or less, then the temperature must be monitored at least once every six minutes. 15. Condition 23.0: What is the basis for an average every 6 minutes? KMG would like to propose 15 minutes averages to reduce the quantity of ineasurement points while still maintaining accurate records. This would be similar to what is required by Subpart ZZZZ. Division Response: Since these are BACT requirements, MACT conditions are not necessarily the appropriate reference. This monitoring frequency is based on GHG BACT permits for thermal oxidizers at similar sources. The condition will remain as per the draft. 16. Condition 23.r: Strike-out"initially and at least once every three months." Again, by just referring to the other conditions this will eliminate errors if any future changes to those conditions occur. Division Response: The BACT requirements, including frequency, must be clearly stated in the BACT conditions. Si�ce construction permits include a section for, it is mentioned in the testing ll remain as er the draft to ensure the BACT section of the permit as well. Condition wi p requirements are clearly identified. 17. Condition 23.t: What does the Division define as continuous? Division Response: Since a reading is required once every six minutes or less, then the temperature must be monitored at least once every six minutes. 7 Would like to ro ose 15 18. Condition 23.t: What is the basis for an average every 6 minutes. KMG p P reduce the uantity of ineasurement points while still maintaining accurate a es to q minutes aver g , records. This would be similar to what is required by Subpart ZZZZ es onse: Since these are BACT requirements, MACT conditions are not necessarily Division R p ' monitorin fre uency is based on GHG BACT permits for thermal the appropriate reference. This 9 q � rces. The condition will remain as perthe draft. ' ilar sou oxidizers at sim nal zers can not continuously record molecular 19. Condition 23.w: The gas chromatograph a y . and anal ze data. What does the � record weight. They need approximately 20 minutes to Y Division mean by continuous? Division Response: The sampling frequency is consistent with other GHG BACf requirements � for similar sources. Please provide supporting documentation such as instrument specifications or vendor documents that specify monitoring frequency capabilities. 20. Condition 23.y: Delete condition. Is this meant for the purge gas? All gas going to the flare will ; be metered at one location and therefore, would be handled by condition w. , Division Response: No, this condition is not for the purge gas. This condition requires that the source monitor the volume of air that is sent to the flare as assist gas. The condition will remain as per the draft. 21. Condition 23.aa: Replace"intelligent flame ignition and flame intensity controls"with "pilot light monitoring system and combustion air blowers." Division Response: This condition is based on GHG BACT requirement5 for similar sources. Please provide more clarification as to the difFerence between the systems (e.g., pilot light monitoring system versus an intelligent flame ignition system) and the combustion efficiency of both systems. 22. Condition 28; Add"to the amine contactor." Division Response; Modified as requested. Z3. Condition 3L KMG would like to remove the requirement to test at +/- 10% of maximum circulation rate and throughput. Due to fluctuations in inlet volumes and the uncertainty of the inlet volumes upon plant start-up, Anadarko may not have enough gas to test at maximum permitted operating parameters: Test are scheduled at least 30 days in advance and we cannot control inlet volumes on the day of testing. The required periodic testing for the four thermal oxidizers should provide sufficient verification of compliance during operational fluctuations. In addition, a VOC destruction efficiency should be a minimum of 99% regardless of throughput volumes and circulation rate.] Division Response: Modified as requested. The sentence has been deleted. 24. Condition 36: KMG proposed that this analysis shall be competed every twelve months. Fuel gas for the fired equipment is taken from our sales residue gas out of the tail end of the facility. We see very little fluctuation in the Btujscf of this gas since it has to meet pipeline specification. An annuai analysis will provide an accurate representation of the actual operating scenario. Division Response: The sampling frequency is consistent with other GHG BACT requirements for similar sources. Condition will remain as per the draft. 25. Condition 37: KMG would like to propose semi-annual tests for the first hvo consecutive compliant emissions tests. After that, annual tests unless a test results in emissions above permit thresholds, when testing would revert back to semi-annual for two consecutive compliant emission tests. Division Response: The amine units and thermal oxidizers are significant sources of VOC and GHG emissions and this project is subject to GHG BACT. Additionally, KMG is requesting a � stringent control efficiency of 99% for VOC and methane at a minimum operating temperature of 1400 °F. Emissions from these sources also vary based on operating rate and it cannot be presumed that a control efficiency demonstrated at a low operating rate establishes an equivalent control e�ciency at a higherJoad. For these reasons, the Division is requiring on- going semi-annual testing. The condition will remain as per the draft. 26. Condition 37: KMG would like to remove the requirement to test at +/- 10% of maximum circulation rate and throughput. Due to fiuctuations in inlet volumes and the uncertainty of the inlet volumes upon plant start-up, Anadarko may not have enough gas to test at maximum permitted operating parameters. Test are scheduled at least 30 days in advance and we cannot control inlet volumes on the day of testing. The required periodic testing for the four thermal oxidizers should provide sufficient verification of compliance during operational fluctuations. In addition, a VOC destruction efficiency should be a minimum of 99% regardless of throughput volumes and circulation rate. � Division Response: Modified as requested. 27. Condition 38: Replace"once every three months"with "every 12 months." Subpart W would only require an annuaf sample, therefore, KMG proposes an annuai sample from each stream. Division Response: Subpart W specifies requirements for GHG Mandatory Reporting Rule and outlines options for calculating GHG emissions. Subpart W does not specify BACT requirements. The sampling frequency is consistent with other GHG BACT requirements for similar sources. Condition will remain as per the draft. I . _ ._ _ . _ -5/21/13 State.co.us Executiuz Branch Mail-�RE:DRAFT BACT Conditions for Lancaster . � y�� State (�� v � af � � � . . . ��' [olorado .�r,�,�h6 . .. .. < -. , . , .. --- __.__._ __.—_.._-----�-�-�-- . _------ .__..__... .. ....._. ... ..___:.----._-----------------� RE: DRAFT BACT Conditions for Lancaster _. _ . ._ ---------------- -- ----- _ _ __ __------- Shea, Jennifer<Jennifer.Shea@anadarko.com> �� ` To Money-CDPHE, Carissa" �carissa.money@state.co.us> � � . � �Fri, Jan 11, 2013 at 3:08 PM Cc: 'Brecken, Korby" <Korby.Bracken@anadarko.com>, "stephanie.chaousy@state.co.us" <stephanie.chaousy@state.co.us>, "christopher.lap�ante@state.co.us" <christopher.lapiante@state.co.us>, "mark.mcmillan@state.co.us" <mark.mcmillan@state.co.us>, "Carter, Micah" aMicah.Carter@anadarko.com> � . � . Carissa, . � Attached are the comments to the draft Lancaster permit. I also attached updated emission calculation sheet since the Division's� short.term emissions calculations did not match KMGs. Piease let me know if you have any questions. � lennifer Shea � Staff EHS Representative . ANADARKO PETROLEUIvI CORPORATION . . Dired: (720) 929-6028 � GeIL (303) 979-0040 � � � � � From: Money- CDPHE, Carissa [mailto:carissa�.money@state.co.us] Sent: Friday,January 04, 2013 2:03 PM � � To: Shea, Jennifer � . � .. Cr. Bracken, Korby; stephanie.chaousy@state.co.us; christopher.laplante@state.co.us; mark,mcmillan@state.to.us Subject: DRAFT BACT Conditions for Wncaster � �� Jennifer, � � Attached please find draft permit conditions addressing the�GHG BACT requirements for the proposed Lancaster facility. Note that some �� refefenCes to other Conditions in the permit may be incorrect since 1'm only including the BACT requirements. Please-proNde comments by 1/11/2013. If you ha�t any questions, let me know. � . � Thank you, . . � . Carissa Money � � � ' Oil and Gas PermittingSupervisor � �� Air Poliution Control Division � � . . � Colorado Department of Public Health and Environment . 4300CherryCreekDriveSouth � Denver, CO80246-1530 � � off i ce:303.692,3229 �. emaiL carissa.money@state.co.us https://mail.google.com/mail/u/0/?ui=2&ik=da5742cbb2&�nev�pt&ca[=Cabinet%2FKerr McGeeHambert&search=cat&th=13c2ba840feebda4 � 1/2 3/21/13 Stffie.co.us Executi�e Branch Mail-RE:DRAFT BACT Conditions for Lancaster � Q Anadarko Confidentiality Notice: This electiori'_c transmission and any attached docume�ts or other writings are incenced only for thc pzrsor � or entity to which it i.s addressed and may contei_n i.r.formation t`,at is � � privileged, confidential or otherwise nrocec�ec from disclosu're. If you � have received this communicatioa in errox, plsase inunediatzlt noti•`_y � sender by return e-mail and destroy the convnunication. Any disclosure, copying, distribution or the takirg of a,y act'_on cor,cermng ths con�ents of this communication cr any atta�hme�ts by anyone other. char. t�= named recipient is strictly Prohibited. � � �2 attachments �� 2013A7-0412WE1492 LANC Draft.pdf . 234K � 2013A1-17 LAN Emissions.pdf . 32K �� _ - t&cat=Cabinet%2FKerr McGee Nambert&search=cat&ih=13c2ba840feebda4 . tiz � � 'UW0/?ui=2&il�da5742cb62&Nev�rp �� https://mail.google.corcJmai �� ,a�� , .� , � . . � j � ti �� i<' � . r �i �'�' .�t � �1 � � � . � l t' �" '� � `'-1 �' � _.�j' '' '� _ STATE OF COLORf�DO pF'Cp�p !�4'=' •-_�P COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT NO"o AIR POLLUTION CONTROL DIVISION � TELEPHONE: (303) 692-3150 ��.` *�eas• COIVST'Rl1CTION PERMIT PERMITNO: �2WE�492 � � DATEISSUED: ISSUanCe 1 �SS�EOTo: Kerr-McGee Gathering LLC THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS � Natural gas processing facility, known as the Lancaster Plant, located in 16116 WCR22, Ft. Lupton, CO, 80621 in Weld County, Colorado. THE SPECIFIC EQUIPMENT OR ACTNITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING: . Facility AIRS Equipment ID Point Description One (1)Caterpillar, Model C15ATAAC, �Number To Be Determined, diesel,turbo-charged, 4SR '� procating GEN3 031 �nternal combustion engine, site rated at 670 horsepower at 1800 RPM. This engine is equipped with no controls. This emergency generator is to be used for electrical power generation during power failure. Mole sieve regeneration gas heater equipped with ultra low E-2015 057 NOx burners. The heater is design rated for an output capacity of 25 MMBtu/hr and an assumed thermal efficiency of 84%. This heater is fueled by natural as. Mole sieve regeneration gas heater equipped with ultra low E-2016 058 NOx burners. The heater is design rated for an output capacity of 25 MMBtu/hr and an assumed thermal e�ciency of 84%. This heater is fueled b natural as. Amine heat medium heater equipped with ultra low NOx burners used to regenerate amine for Point 063: The heater H-6051 059 is design rated for an output capacity of80 MMBtu/hr and an assumed thermal efficiency of 78%. This heater is fueled by natural as. Amine heat medium heater equipped with ultra low NOx burners used to regenerate amine for Point 064. The heater H-6052 060 is design rated for an output capacity of 60 MMBtu/hr and an assumed thermal efficiency of 78%. This heater is fueled by natural as. AIRS ID: 123l0057 Page 1 of 21 NGEngine Version 2009-> �'�� Summary of Comments on 12WE1492.CP1 - DRAFT BACT CONDITIONS Page: 1 -.: Number:1 Author zjys6 � Subject:Sticky Note Date:1/11/2013 8:53:05 AM �Engine is a diesel mmpression ignition(CI)engine,not a reciprocating internal combustion. � _ _ . __ . _ _ _ � . :„ _` 1 � � iC� � eYY� . �, G�j l� olora�Jta,yDep�`�tr�eriC c��Public Health and Environment ''� � rt � I r E+ �{ �6 i°F �� Air Pollution Control Division � f lm. f � . \�� ,f�1�—'i ..f�:. - — _.. . 1�.v � c_i.�_.. v . . Facility AIRS Equipment ID Point Description Amine heat medium heater equipped with ultra low NOx burners used to regenerate amine for Point 065. The heater H-6053 061 is design rated for an output capacity of 60 MMBtu/hr and an assumed thermal efficiency of 78%. This heater is fueled by natural as. Amine heat medium heater equipped with ultra low NOx burners used to regenerate amine for Point 066. The heater H-6054 062 is design rated for an output capacity of 60 MMBtu/hr and an assumed thermal efficiency of 78%. This heater is fueled by natural gas One (1) Methyldiethanolamine (MDEA)natural gas sweetening system for acid gas removal with a design capacity of 150 MMSCF per day(make, model, serial number: TBD). This emissions unit is equipped with two (2) electric amine recirculation pumps with a total design A-1 063 capacity of 601 gallons per minute. This system includes a natural gas/amine contactor, still vent and a flash tank: All emissions are rauted to a thermal oxidizer with a minimum destruction efficiency of 99%o, The sf 1 t and flash tank are routed to the plant emergency fla�en the thermal oxidizer is down. One (1) Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 150 MMSCF per day(make, model, serial number; TBD). This emissions unit is equipped with two (2) electric amine recirculation pumps with a total design A-2 064 capacity of 601 gallons per minute. This system includes a natural gas/amine contactor, still vent and a flash tank. All emissions are routed to a thermal oxidizer with a minimum destruction efficiency of 99%. The Z nt and flash tank are routed to the plant emergency�hen the thermal oxidizer is down. One (1) Methyldiethanolamine (MDEA) naturai gas sweetening system for acid gas removal with a design capacity of 150 MMSCF per day (make, model, serial number. TBD). This emissions unit is equipped with two(2) , electric amine recirculation pumps with a total design ' A-3 065 capacity of 601 gallons per minute. This system includes a natural gas/amine contactor, still uent and a flash tank. All emissions are routed to a thermal oxidizer with a minimum destruction efficiency of 99%. The s�t and flash tank are routed to the plant emergency fl r� en the thermal oxidizer is down. AIRS ID: 123/0057 Page 2 of 2� Page: 2 �:.� Number:1 Author.zjys6 Subject:Sticky Note Date:1/11/2013 8:54:09 AM This is not an emergency flare,but rather the process flare(F2) � ., Number:2 Author:zjys6 Subject:Sticky Note Date:1/il/2013 8:54:06 AM � . � This is not an emergency flare,but rather the process flare(F2) _: Number:3 Author:zjys6 Subject:Sticky Note Date:1/11/2013 8:54:18 AM � �This is not an emergency flare,but rather the process flare(F3) ' �,1� \ 1 � (. t I �L:IRt � •�� . �' t' � olora Jl Dep ,trnent d'Public Health and Environment i.,: ' -_s� �. �,�. ,�, l �_v _r '.',Y ,� '}; ti Air Pollution Control Division r,�� . �, r �� _� v'� . Facility AIRS Description Equipment ID Point One (1) Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a tlesign capacity of 150 MMSCF per day (make, model, serial number: TBD). This emissions unit is equipped with two (2) electric amine recirculation pumps with a total design A-4 066 capacity of 601 gallons per minute. This system includes a natural gas/amine contactor, still vent and a flash tank. All emissions are routed to a thermal oxidizer with a minimum destruction efficiency of 99°/o. The s��i�t and flash tank are routed to the plant emergency fIL.'�'�vhen the thermal oxidizer is down. FUG3 067 Fugitive emission leaks. F-2 068 Maintenance activities and purging of gas. Activities are controlled b a flare. F-3 069 Maintenance activities and purging of gas: Activities are controlled b a flare. Point 031 may be replaced with another engine in accordance with the temporary engine replacement provision or with another Caterpillar C15 ATAAC engine in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as 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.5. (25d-101 et sea), TO THOSE GENERAL TERMS AND CONDITIONS � INCLUDED IN THIS DOCUMENT AND THE FOLLOWING SPECIFIC TERMS AND CONDITIONS: � REQUIREMENTS TO SELF-CERTIFY FOR FINAL AUTHORIZATION 1. YOU MUST notify the APCD no later than fifteen days after commencement of the permitted operation or activity bv submittinq a Notice of Startup (NOS) form to the APCD. The Notice of Startup (NOS) form may be downloaded online at www.cdphe.state co us/ao/downloadforms htmL Failure to notify the APCD of startup of the permitted source is a violation of AQCC Regulation No. 3, Part B, Section III.G.1 and can result in ihe revocation of the permit. 2. Within one hundred and eighty days (180) after commencement of operation, compliance with the conditions confained 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. (Reference: Regulation No. 3, Part B, IILG.2). 3. This permit shall expire if the owner or operator of the source for which this permit was ! issued: (i) does not commence construction/modification or operation of this source ' within 18 months after either, the date of issuance of this construction permit or the date on which such construction or activity was scheduled to commence as set forth in the permit application associated with this permit; (ii) discontinues construction for a period of eighteen months or more; (iii) does not complete construction within a reasonable � time of the estimated completion date. The Division may grant extensions of the AIRS ID: 123/0057 Page 3 of 21 I Page: 3 �::.Number 1 Author:zjys6 Subject:Sticky Note Date:1/11/2013 8:5433 AM � This is not an emergenty flare,but rather the process flare(F3) � 4'�'�� i �f olora�J�;,Dep��trpent c� Public Health and Environment hi � , � � + , ,s , �; , Air Pollution Control Division . r_�� .,:,� . !� ._....�_s �_�.�_._ . ., r � � deadline per Regulation No. 3, Part B, III.F.4.b. (Reference: Regulation No. 3, Part B, III.F.4.) 4. The operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self-certification process. (Reference: Regulation No. 3, Part B, Section III.E.) 5. The manufacturer, model number and serial number of the subject equipment shall be provided to the Division within fifteen days (15) after commencement of operation. This information shall be included on the Notice of Startup (NOS) submitted for the equipment. (Reference: Regulation No. 3, Part B, III.E.) 6. The operator shall retain the permit final authorization letter issued by the Division after completion of self-certification, with the most current construction permit. This construction permit alone does not provide final authority for the operation of this source. EMISSION LIMITATIONS AND RECORDS 7. Emissions of air pollutants shall not exceed the following limitations (as calculated in the Division's preliminary analysis). (Reference: Regulation No. 3, Part B, Section II.A.4) Monthly' Limits: Facility AIRS Pounds per Month � Tons per � � Month Emission EquipmentlD Point Nax SO� VOC CO CO2e"°`ez Type � GEN3 031 --- --- --- Not PoiM a licable � E-201 �1 057 884 17 425 884 1,295 Point E-2016 QZ 058 884 17 . 425 884 1,295 Point H-6051 �3 059 2294 34 306 2294 3,348 Point H-6052 Q4 060 22g4 34 306 2294 3,348 Point � . � H-6053 Q 5 061 2294 34 306 2294 3,348 Point � H-6054 Q6 062 2294 � 34 306� 2294 3,348 Point A-1 � � 063 1342 170 595 1121 7,994 Point , A-z QS 064 1342 170 595 1121 7,9g4 Point A3 Q9 065 1342 170 595 1121 7,994 Point �� A-4 � 066 1342 170 � 595 � 1121 7,994 Point � FUG3 Q 067 --- --- 5181 --- 81 Fugitive F-2 Q 068 1240 --- 272 2480 528 Point ' � F-3 Q 069 1240 --- 272 2480 528 Point ' 1: Monthly imrts are based on a 31-day month. AIRS ID: 123/0057 Page 4 of 21 Page: 4 ,:.:. Number.1 Author:zjys6 Subject:Sticky Note Date:1/11/2013 10:42:07 AM � � E-2015 and E2016 Emissions not mrrect. See updated cakulation sheets showing Ib/mo and ton/mo caks. � NOx=886 Ib/mo � � 5O2=13 lb/mo .� . VOC=421 1b/mo . � CO =886 16/mo . . ., Number:2 Author:zjys6 Subject:Sticky Note Date:1/11/2013 9:0534 AM E-2015 and E2016 Emissions not correct. See updated calculation sheets showing I6/mo and ton/mo calcs. � NOx=8S6 16/mo � � . . SO2=131b/mo � � . . � VOC=421 lb/mo �� - � � CO=886 lb/mo . �_.. Number:3 � Author zjys6� �Subject:Sticky Note � Date:1/11/2013 9:10:14 AM � � H-6051,H-6052, H-6053,H-6054 Emissions�are incorrect. Attached updated emissions calculation sheet. NOx=2289 Ib/mo SO2 = 34 Ib/mo. � � VOC= 309 Ib/mo . � CO=2289 16/mo � �;: Number:4 Author.zjys6 Subject:Sticky Note Date:1/11/2013 9:10:15 AM H-60ri,H-6052,H-6053,H-6054 Emissions are incorrect. Attached updated emissions calculation sheet. NOx=2289 Ib/mo . . . � , SO2= 341b/mo � � VOC=309 Ib/mo � CO=2289 Ib/mo . - -�. Numbec 5 Author:zjys6 Subject:Sticky Note Date:1/11/2013 9:10!17 AM � � � H-6051,H-6052,H-6053, H-6054 Emissions are incorrect. Attached updated emissions calculation sheet . � . NOx=2289 Ib/mo 5O2=3416/mo . . . � . VOC=309 Ib/mo . . . . � CO=22S9 Ib/mo � . . � :-..Number:6 Author.zjys6 � Subjed:Sticky Note Date:1/11/2013 9:1020 AM H-6051,H-6052,H-6053,H-6054 Emissions are incorrect. Attached updated emissions calculation sheet. NOx=2289 16/mo � 5O2 =34 Ib/mo � � � VOC=309 I6/mo � . CO=Z289 Ib/mo � . � � .�..,Number:7 Author:zjys6 Subjed:STicky Nofe Date:1/11/2013 10:33:48 AM � �Al-4 Emissions were not correct. Updated spreadsheets attached and details below: � � � NOx=1337 Ib/mo , � � � 5O2 = 173 Ib/mo . � , VOC= 15+596=610 Ib/mo . CO =1123 Ib/mo . � � .��Number:8 Author:iys6 Subject:5tickyNote Date:l/11/20131033:53AM , Al�-4 Emissions were not correct. Updated spreadsheets attached and details below: � NOx=1337 Ib/mo �� SO2 = ll3 Ib/mo . . � VOC=15+596=610 Ib/mo . � � GO = 1123 Ib/mo � � � �� :-.. Number.9 Author:zjys6 Subject:Sticky Note Date:1/11j2013 10:34:06 AM � � Al-4 Emissions were not correct. Updated spreadsheets attached and details below: . NOx= 1337 Ib/mo . � , 5O2=173 Ib/mo � . . . . VOC= 15+596= 610 Ib/mo � � � CO=1123 Ib/mo � � � rom a e 4 continued on next a e � mments f p g Co p g �i- -r G! �� F � olora J�,pep��trPent c�+Public Health and EnvironmenY � C�_f (,,= �K' 'ti;,.�i "� �r, Air Pollution Control Division ��, . ��., ` ,a,. F' .� �.j � . . �.,_ �^�, � deadline per Regulation No. 3, Part B, III.F.4.b.� (Reference: Regulation No. 3, Part B, III.F.4.) 4. The operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self-certification process. , (Reference: Regulation No. 3, Part B, Section III.E.) 5. The manufacturer, model numberand serial number of the subject equipment shall be � provided to the Division within fifteen days (15) after commencement o#operation. This information shall be included on the Notice of Startup (NOS) submitted for the , equipment. (Reference: Regulation No. 3; Part B, III.E.) s. The operator shall retain the permit final authorization letter issued by the Division after completion of self-certification, with tlie most current construction permit. This ' construction permit alone does not provide final authority for the operation of this source. , EMISSION LIMITATIONS AND RECORDS ' 7. Emissions of air pollutants shall not exceed the following limitations (as calculated in the Division's preliminary analysis). (Reference: Regulation No. 3, Part B, Section II.A.4) i Monthly' Limits: �� Pounds er Month Tons per ��, � Facility AIRS p Month Emission . �' Equipment ID Point NO, SOZ VOC CO CO2eNate2 Type �� . GEN3 031 .-- ___ _— �___ a Noable Point . � . E-201� 057 884 � 17� 425 884 1,295 Point ��. E-2016 Q 058 884 17 425 . 884 1,295 Point �� H-6051 Q 059 . 2294 34 306 2294 3,348 Point . H-6052� O60 2294 � 34 306 2294 3,348 PoiM � � I H-6053� 061 2294 34 306 2294 3,348 . Point �� H-6054� 062 � 2294 34 306 � 2294 � 3,348 Point � � A-1 �Q 063 1342 170 595 1121 7,994 Point � - ', A-2 � 064 1342 170 595 1121 7,994 Point . �� A3 Q 065 1342 170 595 1121 7,994 Point I A-4 �10 066. 1342 170 595 1121 7,994 Point �' � FUG3 Q11067 --- --- 5181 --- 81 Fugitive � F-2 �1z 68 1240 --- 272 2480 528 Point ��.. � p_3 �13 069 1240 -- 272� 2480 � 528 Point 1: Monthly imds are based on a 31-day month. AIRS ID: 123/0057 Page 4 of 21 __ _ _ . . _ . :.:..Number.10 Author,zjys6 Subject:Sticky Note Date:1/11/2013 1034:11 AM Al-4 Emissions were not correct. Updated spreadsheets attached and detads below' � NOx=1337 Ib/mo � � SO2 = 173 Ib/mo VOC=15+596= 610 Ib/mo � - . � � CO= 1123 Ib/mo � � -•. Number:11 Author,zjys6 Subject Sticky Note Date:1/ll/2013 1037:14 AM � '��, - for Fugitives, � � '�� VOC= 5185 Ib/mo . � � � . .-� Number:12 Author.zjys6 SubjecT.Sticky Note Date:1/11/2013 10:41:46 AM - F-2 and F-3 emissions were incorrect Updated calculation sheets are attached . NOx =1246 16/mo . VOC=278 Ib/mo '�. CO=24SS Ib/mo � i - Numbec 13 Author zjys6 �Subject:Sticky Note Date:1/11/2013 10:42:01 AM - � F-2 and F-3 emissions were mcorrect. Updated calcula4on sheets are attached. � � NOx= 1246 Ib/mo . � . . ' : VOC =278 Ib/mo .. CO =2488 Ib/mo � I I'I � 7,` ` ``�'�' ( � }��I' F; ' � . �., , �ti � olore 1��Dep ,tr{ient c"Public Health and Environment � � {,j ( ��ti, '" �`' �.`�� t, Air Pollution CoMrol Division � . ._.i ^ ,. � . ��'-�`..� ��.�_ . 2: CO2e is carbon dioxide equivalent in tons per year. CO2e is the total sum of the , mass of each greenhouse gas emission multiplied by global warming potential for each greenhouse gas. The greenhouse gas emissions of concern include CO2, CH4 and N20. Annual Limits: � � Tons per Year � - � � Facility AIRS Emission ' Equipment ID Point NO, SOz VOC CO � � NO2e Type GEN3 � 031 2.1 12 --- 0.2� 193 �1 Point j E-2015 057 5.2 0.1 2.5 5.2. 15,252 Point lE-2016 . 058 52 0.1 2.5 5.2 15,252 Point H-6051 059 13.5 02 1.8 13.5 39,421 Point H-6052 O60 � 13.5 0.2 1.5 13.5 39,421 Point � �'�, H-6053 061 13.5 � 02 1.8 13.5 39,421 . Point ''�, � H-6054 062 13.5 02 1.8 13.5 39,421 Point A-1 � 063 7.9 1.0 QZ 3. Q3 6.6 94,121 Point A-2 064 7.9 1.0 QS 3.5 �4 6.6 94,121 Point A-3 O65 7.9 1.0 �6 3.5 �� 6.6 94,121 Point � . A-4 066 7.9 1.0 g 3.5 � 9 6.6 94,121 Point � FUG3 067 --- --- 30.5 � �-- 949 Fugitive �. � � � F-2 068 7.3 --- 1.6 14.6 6,220 Point I � F3 069 7.3 --- 1.6 14.6 6,220 Point � . �� See "Notes to Permit Holder #4 for information on emission factors and methods used to I, ' � calcu/ate limits. � I During the first twelve (12) months of operation, compliance with both the monthly and yearly emission limitatibns shall be required. After the first twelve (12) months of ', operation, compliance with only the yearly limitation shall be required. , Compliance with the emission limits in this permit shall be determined by recording the I, facility's annual criteria pollutant emissions, (including all HAPs above the de-minimis ! reporting level) from each emission unit, on a rolling (12) month total. By the end of , each month a new twelve-month total is calculated based on the previous twelve I months' data. The permit holder shall calculate monthly emissions and keep a compliance record on site or at a local field office with site responsibility, for Division , review. This rolling twelve-month total shall apply to all emission units, requiring an APEN, at this facility. S. Point 031: The owner or operator shall calculate, on a monthly basis, the amount of ' CO2 emitted from combustion using equation C-1 in 40 CFR Part 98 Subpart C, default AIRS ID: 123/0057 Page 5 of 21 _ __ _ __ __ _ _ _ Page: 5 �:_ Number:1 Author:zjys6 SubjecT Sticky Note Date:1/11/2013 10:43:01 AM � � Should be 139 ton/year of CO2e . . I� --. Number:2 � Author.zjys6 Subject:Sticky Note Date:1/11/201310:4736 AM � Emissions should be as follows � � 1.02 tpy from still vent and flash tank amine unit mnversion from H2S to SO2 through the TO at 95%H2S control. 0.05 tpy cbmes from TO combustion emissions. � � � 1.02 +0.05= 1.1 tpy SO2 - - . � � � . ,�� Number:3 Author zjys6 Subject:Sticky Note Date:1/11/2013 10:49:59 AM � . '� Amine umt stack emissions of 35 tpy assuming 99%VOC DRE of TO+TO combustion emission of 0.09 tpy. . 3.5 +0.09= 3.6tpyVOC � , . .. Number 4 Author:zjys6 Subject:Sticky Note Date:1/11/2013 10:50:15 AM � I Amine unit stack emissions of 35 tpy assuming 99%VOC DRE of TO+TO combustion emission of 0.09 tpy. ' 3.5 +0.09= 3.6tpyVOC � � � -..�Number.5 . Author.zjys6 Subject:Sticky Note Date:1/11/2013 10:45:03 AM � � � II � Emissions should be as follows: � . . ��.. lA2 tpy from still vent and flash tank amine unit conversion from H25 to 5O2 through the TO at 95%H2S mntroL ' 0.05 tpy comes from TO combustion emissions. .� 1.02 + 0.05 =11 tpy 5O2 �'� .:.. Numbec 6 Author:zjys6 Subject:Sticky Note Date:1/11/2013 10:48:05 AM � Emissions should be as follows . �.. . lA2 tpy from still vent and flash tank amine unit conversion from H2S to SO2 through the TO at 95%H25 controL . '� 0.05 tpy comes from TO mmbustion emissions. , �! 1.02 + 0.05= 1.1 tpy 5O2 . � _ � '�.� �. Number:7 Author.zjys6 Subject:Sticky Note Date:1/11/2013 10:50:ll AM � � � � � Amine unrt stack emissions of 3.5 tpy assuming 99%VOC DRE of TO+ TO combustion emission of 0.09 tpy. � - � 3.5 + 0.09= 3.6tpyVOC � . -...Number.8 Author.zjys6 Subject:Sticky Note Date:1/11R013 10:48:07 AM '��. Emissions should be as follows: - . � '�,. 1.02 tpy from still vent and flash tank amine unit conversion from H2S to 5O2 through the TO at 95%H25 control. , 0.05 tpy comes from TO combustion emissions. � '�. 1.02 + 0.05= 11 tpy 5O2 . � ��. ,�. Number:9 Author.zjys6 Subject:Sticky Note Date:1/11/2013 10:50:18 AM ' � Amine unit stack emissions of 3.5 tpy assuming 99%VOC DRE of TO+TO mmbustion emission of 0.09 tpy. 35 + 0.09 =3.6 tpy VOC � .. '`'` � � `. <� 4 ;ky � , -��i S; � � f olora,rf I Dep ��trpent c Public Health and Environment C'_J,� '��—! � tl �� Air Pollution ConErol Dlvision ."u ��":._� r . � � �_�., `.'._ fuel specific high heat value (HHV) and default CO2 emission factor in Table C-1, and i actualmonthly diesel usage volume. 9. Point 031: The owner or operator shall calculate CH4 and N2O emissions from , combustion on a monthly basis using equation C-8 in 40 CFR Part 98 Subpart C, default CH4 and N2O emission factors contained in Table G2, default fuel specific high heat value (HHV) from Table C-1, and actual monthly diesel usage volume. ' 10. Point 031: The owner or operator shall calculate the CO2e emissions based on the procedures and Global Warming Potentials (GWP) contained in Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1. �1. Points 057, 058, 059, 060, 061, 062, 063, 064, 065 and 066: The owner or operator shall calculate, on a monthly basis, the amount of CO2 emitted from combustion using , equation G2a in 40 CFR Part 98 Subpart C, default natural gas CO2 emission factor in ' Table C-1, measured actual heat input (HHV), and measured actual monthly natural gas flow volume. 12. Points 057, 058, 059, 060, 061, 062, 063, 064, 065 and 066: The owner or operator shall calculate CH4 and N2O emissions from combustion on a monthly basis using equation C-9a of 40 CFR Part 98 Subpart C, default CH4 and N2O emission factors for natural gas contained in Table C-2, measured actual heat input (HHV) and measured actual monthly natural gas flow volume. � 13. Points 057, 058, 059, 060, 061, 062, 063, 064, 065 and 066: The owner or operator ', shall calculate the CO2e emissions based on the procedures and Global Warming ' Potentials (GWP) contained in Greenhouse Gas Regulations, 40 CFR Part 98, Subpart ' A, Table A-t i 14. Points 063, 064, 065 and 066: The owner or opetator shall calculate CO2 emissions, i on a monthly basis, using equation W3 consistent with 40 CFR Part 98, Subpart W ' [98.233(d)(2)] along with the most recent measured waste gas sampling composition and monthly measured waste gas flow volume. 15. Points 063, 064, 065 and 066: Total CO2e emissions from each point shall be based �I on the sum of GHG emissions from combustion, calculated as per Conditions 11, 12, ' and 13 Qlus CO2 emissions from the amine unit as calculated per Condition 14. The sum of GHG emissions generated from combustion and CO2 emissions generated from the amine units shall be compared to the CO2e limits listed in this section above to demonstrate compliance. 16. Points 068 and 069: The owner or operator shall calculate CO2e emissions, on a monihly basis, using equations and procedures outlined in 40 CFR Part 98, Subpart W , 98.233(n) along with the measured flare gas composition and monthly measured flare gas flow volume. Flarebombustion efficiency is 95%. 17. Points 057, 058, 059, 06Q 061 and 062: The heaters are not expected to have GHG emissions in excess of the allowed emission rates during periods of startup, shutdown, ' or maintenance. �.,, � Q 1 �� . . ' 18. AIRS ID: 123/0057 Page 6 of 21 Page: 6 ,�. Number:1 Author,zjys6 Subject:Sticky Note Date:1/11/2013 1136:49 AM � Was this intentionaliy left blank? � „. f` 1 �1'_ �r -, 1 `� Ie” 4?� �� f � olora)6;Dep -tment c Public Health and Environment „� -., ,, � � ,i � ',,';�, ��; �'-�� [i Air Pollution Controi Division �: I�� i — il . ... _ �� _ � ._ _ ._. ,_� . 19. Points 063, 064, 065 and 066: Emissions from the amine unit flash tank, reclaimer still vent, and regenerator still vent shall be collected and controlled by a thermal oxidizer in order to reduce the emissions of volatile organic compounds to the level listed in this section, above. Operating parameters of the thermal oxidizer are identified in the operation and maintenance plan for this unit. (Reference: Regulation No.3, Part B, Section III.E.) 20. Point 067: The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent gas and liquids analyses, as required in the Comptiance Testing and Sampling section of this permit. The operator shall maintain records of the results of component counts and sampling events used to calculate actual emissions and the dates that these counts and events were completed. These records shall be provided to the Division upon request. PROCESS LIMITATIONS AND RECORDS 2�. This source shall be limited to the following maximum processing rates as listed below. Monthly records of the actual processing rate shall be maintained by the applicant and made available to the Division for inspection upon request. (Reference: Regulation 3, ' Part B, II.A.4) Proeess/Consumption Limits �. � Facility .� A�RS � Monthly �. Equipment Process Parameter Annual Limit �Limits (31 � �p Point � � days) � � � GEN3 031 Consumption of diesel gas as a fuel 18,300 __ - gallons/year � E-2015 057 Natural Gas Combusted 255.6 � 2171 � � � MMscf/ r MMscf/month . � � E-2016 058 Natural Gas Combusted 255:6 �21.71 � MMscf/ r � MMscf/month � H-6051 � 059 Natural Gas Combusted � 660.6 56.1 MMscf/yr MMscf/month H-6052 � 060 Naturel Gas Combusted 660.6 56.1 � . � MMscf/yr MMscf/month H-6053 061 Natural Gas Combusted 660.6 56.1 . . � MMscf/ r MMscf/month H-6054 062 Natural Gas Combusted 660.6 56.1 MMscf/yr MMscf/month A-1 063 Natural Gas Throughpu[ � 54,750 �4,650 MMscf/yr MMscf/monih , � A-2 064 Natural Gas Throughput 54,750 4,650 . MMscf/ r MMscf/month . � �A3 065 Natural Gas Throughput- - 54,750 4,650 �� MMscf/ r MMscf/month �� A-4 066 NaturalGas Throughput 54,750 � 4,650 � MMscf/ r MMscf/month � F-2 068 Natural Gas Combusted . $��Z 6.9 � MMscN r MMscf/month - . �� F3 069 Natural Gas Combusted 81.2 . 6.9 MMscf/ r MMscf/month AIRS ID: 123/0057 Page 7 of 21 y � i ��} _w�� k�� ti ( �n olora��,,Dep� t ent c,Public Health and Environment � ��_� r � r�' �t �;''�l �,� Air Pollution Conirol Division �� , � e '�_:� ` �'4 `_' �;,. � During the first twelve (12) months of operation, compliance with both the monthly and yearly emission limitations shall be required. After the first twelve (12) months of operation, compliance with only the yearly limitation shall be required. Compliance with the yearly consumption limits shall be determined on a rolling twelve (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 consumption of natural gas and keep a compliance record on site or at a local field office with site responsibility, for Division review. 22. Points 063, 064, 065 and 066:�e units shall be limited to the maximum lean amine recirculation pump rate of 601 � ons per minute. The lean amine recirculation rate shall be recorded weekly in a log maintained on site and made available to the Division for inspection upon request. (Reference: Regulation No. 3, Part B, II.A.4). BEST AVAILABLE CONTROL TECHNOLOGY (BACT) REQUIREMENTS ' 23. The equipment and activities at this facility are subject to the requirements of the Prevention of Significant Deterioration (PSD) Program. Best Available Control Technology (BACT) shall be applied for control of Greenhouse Gases (GHG). BACT has been determined to be as follows a. For purposes of BACT, total CO2e emissions from the emission units covered under this permit shall not exceed the annual emission limits contained in condition 7, based on a rolling tweive month totaL Emerqencv Generator b. Point 031: The owner or operator shall comply with the requirements in New Source Performanee Standards of Regulation No. 6, Part A, Subpart IIII for Stationary Compression Ignition Internal Combustion Engines (CI ICE). Heaters c. Points 057, 058, 059, 060, 061 and 062: Fuel for the heaters shall be limited to natural gas with a fuel sulfur content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr S/100 dscf). The fuel used in the heaters shall be sampled initially and at least once per every six months as required in Conditions 29 and 36 to determine the fuel gross calorific value (GCV) [high heat value (HHV)]. d. Points 057, 058, 059, 060, 061 and 062: The owner or operator shall install and maintain an operational non-resettable elapsed flow meter for the heaters. The flow meters shall be calibrated at a minimum frequency of at least once per every ', twelve months. e. Points 057, 058, 059, 060, 061 and 062: The flow rate of the fuel combusted in these natural gas-fired combustion emission units shall be measured and recorded using an operational non-resettable elapsed flow meter at each inlet. f. Points 057, 058, 059, 060, 061 and 062: The heaters will be equipped with low- ' NOx staged/quenching (flue gas recirculating) burners with burner management systems that include intelligent flame ignition and flame intensity controls. ' AIRS ID: 123/0057 Page 8 of 21 _.__ _ _ _ . _ . _ Page: 8 ,��.: Number:1 Author:zjys6 Subject:5ticky Note Date:1/11/2013 12:12:37 PM � � The simulation was completed at 601 gal/minute,however the valve controlling the amine recirculation is only accurate to+/-10%. This would normally be a significant difference,however due to the large circulation rate,KMG is requesting to modify this value to 660 gal/min to aaount for mntrolvalve accuracy. � � � �V` � -� � � ��, � i, a olora;d� ,Dep<,trnent e Public Health and Environment , f f .:, � i � ' Air Pollution Control Division , � .—, i ' ,�—F,; � ,_,. _ .... ;..,: � __ g. Points 057, 058, 059, 060, 061 and 062: The heaters shall be tuned for thermal efficiency at a minimum frequency of at least once per every twelve months. h. Points 057, 058, 059, 060, 061 and 062: The owner or operator shall perform cleaning of the burner tips, at a minimum of, once per every twelve months: i. Points 057, 058, 059, 060, 061 and 062: The owner or 1 ator shall install, operate, and maintain an automated air/fuel control system� ' j. Points 057, 058, 059, 060, 061 and 062: The owner or operator shall calibrate and perform preventative maintenance on tF�e�y'/fuel control analyzers at least once per every three months, at a minimum.� Amine Units and Thermal Oxidizers k. Points 063, 064, 065 and 066: The flash tank and still vent from each amine unit shall be routed to a thermal oxidizer for combustion. The thermal oxid' shall have a minimum removal and destruction efficiency of inethane (CH4�3 99%. I. Points 063, 064, 065 and 066: EachShermal oxidizer shall have an initial stack test, and on-going compliance testing�n.� �..... ... !�.-.-. -..-- -._., _:.. ..._.�_, as specified in Conditions 32 5 7 to verify destruction and removal efficiency (DRE)of at least 99%for CH4� m. Points 063, 064, 065 and 066: The 6�eratiia� temperature of the thermal oxidizer used to control emissions from the amine unit shall be greater than 1400 °F, or the temperature established during the most recent stack test of the equipment that was approved by the Division, at all times that any amine unit emissions are routed to the thermal oxidizer in order to meet the emission limits in this permit n. Points 063, 064, 065 and 066: The owner or operator shall install and maintain a temperature recording device with an accuracy of the greater of ±0.75 percent of ihe temperature being measured expressed in degrees Celsius or±2.5°C. o. Po�'qts 063, 064, 065 and 066: The thermal oxidizers'�chaust temperature shall beLbntinuously monitored and recorded when amine unit waste gas is directed to the oxidizers. The temperature measurep�,ent devices shall reduce the , temperature readings to an averaging period ofU minutes or less and record it at '�, � � that frequency. , p. Points 063, 064, 065 and 066: For burner combustion, natural gas fuel usage (sc� is recorded using an operational non-resettable elapsed flow meter at each thermal oxidizer. ', q. Points-063, 064, 065 and 066: The flow rate of the waste gas combusted shall ', be measured and recorded using an operationaF non-resettable elapsed flow ', meter at each thermal oxidizer. ' r. Points 063, 0 065 and 066: Waste gas from each amine unit will be sampled and analyzed io as , specified in Conditions 31 and 35. The sample data will be used to calculate ', GHG emissions as specified in Condition 14. AIRS ID: 123/0057 Page 9 of 21 __ . _ _ _ __ _ _ _ ___ Page: 9 .,- Number:1 Author.zjys6 Subject:Sticky Note Date:1/11/2013 12:31:12 PM � � � The air/fuel control rystem is part of the burner management system. �,�Number.2 Author.zjys6 Subject:Sticky Note Date:1/11/2013 2:5626 PM � KMG is request to decrease the frequency of preventative maintenance on the air intake system to once per every twelve months to be consistent with ihe other preventative maintenance required by this equipment � -. Number.3 Author.zjys6 Subject:Sticky Note Date:1/11/201312:35:13 PM Do you mean CH4e with GHG warming potential orjust CH4? . �f�Number:4 Author.zjys6 Subject:Cross-Out Date:1/ll/2013 12:3727 PM � � No need to repeat if the freqency Is stated in Condition 37. Allows for less errors if any changes are made to other conditions. �..-. Number.5 Author.zjys6 Subject:Sticky Note Date:1/11/2013 1235:46 PM � - Do you mean CH4e with GHG warming potential orjust CH4? � - '��Number:6 Author:zjys6 Subject:Cross-Out Date:1/11/2013 12:38:49 PM � combustion . �.�p�Number:7 Author zjys6 � Subject:Comment on TeM �Date:1/11/2013 1239:43 PM � I Do you�mean combustion temperature? '� Iy�Number.8 Author zjys6 Subject Comment on Texf Date:1/11/2013 12:45:06 PM '� What does the Division define as continuos? � �.T�Number:9 Author:ijys6 Subject:Comment on Text Date 1/11/2013 125:43 PM � '�� What is the basis for an average every 6 minutes? KMG would like to propose 15 minutes averages to reduce the quantity of ineasurement '��' points while still maintaining accurate records. This would be similar to what is required by Subpart ZZZZ. � �'�. � ��.�Number:10 � Author.zjys6 Subject:Cross-Out Date:1/11/2013 12:44:02 PM . � Again,byjust referring to the other mnditions this will eliminate errors if any future changes to those conditions occur. . �. i . ✓t .Y p ' ! ��:,� {l� . �' �� olor��Jf Dep} �trrent e�Public Health and Environment r� � � �i � k�_r,"�', I I Air Pollution Control Division ,;::-�n 1!�,—.� � �''�' �`�'�. � 1�,_ s. Points 063, 064, 065 and 066: Periodic maintenance will help maintain the efficiency of the thermal oxidizer and shall be performed at a minimum of once per every twelve months or more often as recommended by the manufacturer specifications. t. Points 063, 064, 065 and 066: Oxygen analyzers shall �ntinuously monifop and record oxygen concentration when waste gas is directed to the therm�l, , oxidizers. It shall reduce the oxygen readings to an averaging period of LZJ minutes or less and record it at that frequency. u. Points 063, 064, 065 and 066: The oxygen analyzers shall be quality-assured at least once every six months using cylinder gas audits (CGAs) in accordance with 40 CFR Part 60, Appendix F, Procedure 1, § 5.1.2, with the following exceptionr a relative accuracy test audit is not required once every four quarters (i.e., two successive semiannual CGAs may be conducted). The CGAs must be performed at least thirty (30) days apart. Fuqitives v. Point 067: The owner or operator shall implement the leak detection and repair (LDAR) requirements in New Source Performance Standards of Regulation No. 6, Part A, Subpart OOOO for fugitive emissions of inethane. Flares w. Points 068 and 069: The owner or operator shall install, operate, and maintain a flow rate and composition analyzer for each flare to monitor the waste gas ,r,ombusted by tHe fiare. The flow rate and composition analyzer shall Lbntinuously record the molecular weight and mass flow rete of the flare gas: x. Points 068 and 069: The flare shall be air assisted. Points 068 and 069: n ` ' ' • �" y. � � �� r „a,�,.a ,. ...,. T1 o-fl9w �� z. Points 068 and 069: The flare shall utilize automatic damper actuators or variable frequency drives on the air supply system. aa. Points 068 and 069: The flares shall be equipped with burner management systems that include' .�5 bb. Points 068 and 069: Flare shall have a minimum destruction and removal efficiency (DRE) of 95%. cc. Points 068 and 069: The owner or operator shall record the inlet waste gas !, heat input (HI-IV) in MMBtu/fir during flare operation. The records must include hourly CH4 emission levels as measured by the in-line gas analyzer (Gas , chromatograph or equivalent with inlet gas flowrate) and the calculations based ' on the actual heat input for the CO2, N2O, and CH4 emissions. These records ; must be kept for five years following the date of each event. dd. Points 068 and 069: The flare shall be designed and operated in accordance j with 40 CFR 60.18 including specifications of minimum heating value of the ' AIRS ID: 123/0057 Page 10 of 21 ' _ _ . _ _ _ _ __ _ _ Page: 10 � 'uNumber:1 Author:zjys6 Subject:Comment on Text Date:1/11/2013 12:46:56 PM What does the Division define as continuous? I r;Number.2 Author.zjys6 Subject:Comment on Text Date:1/11/2 013 12 6:12 PM -��What is the basis for an average every 6 minutes? KMG would like to propose 15 minutes averages to reduce the quantiry�of ineasurement points while still maintaining accurate remrds. This would be similar to what is required by Subpart ZZZZ. ��'I Number:3 Author.zjys6 Subject:Comment on Text Date:1/11/2013 2:57:06 PM � �� The gas chromatograph analyzers can not continuously record molecular weight. They need approximately 20 minutes to�record and analyze data. What does the Division mean by continuous? ��Number:4 Author.zjys6 Subject:Cross-Out Date:1/il/2013 2:14:08 PM� � � Is ihis meant for the purge qas? All gas going to the flare will be metered at one location and therefore,would be handled by condition w. .. � I��Number.5 Author,zjys6 Subject:Inserted Text Date:1/ll/2013 2:14:53 PM � ''�� — pilot light monitoring system and combustion air blowers. � ��' `v 1, 71' Vt /� F, V �'f'. '�'i 1 �4 r� {�olora�J Dep trnent c'�Public Health and Environment i Fi k �� = r` ��;�_r,r � �a Air Pollution Control Division }��—z �— E C�!: r�l ,.,",�.:, � . _ _ __-, 4.�_ ._. waste gas, maximum tip velocity, and pilot flame monitoring. An infrared monitor is considered equivalent to a thermocoupie for flame monitoring purposes. 24. Points 057, 058, 059, 060, 061 and 062: On or after the date of initial startup, the owner or operator shall not discharge or cause the discharge of emissions from the sum of all the heaters associated with the Cryogenics Plant (AIRS Points 057 through 062) in excess of 1,716.9 Ibs CO2/MMSCF on a 365-day rolling average. To determine this BACT emission limit, the owner or operator shall calculate the limit based on the measured input mass rate of CO2 from the natural gas GCV analysis required in Conditions s and 36 (note that mass emission rate must be converted from metric tons to pounds) and divide by the measured daily natural gas output from the Cryogenic Plant (MMSCFD). 25. The owner or operator shall maintain the following records for a period of 5 years a. Operating hours for all emission sources. b. Diesel usage for the emergency generator. c. The natural gas fuel usage for all combustion sources, using continuous fuel flow monitors. d. Annual fuel gassampiing results, quarterly waste gas sampling. e. Daily natural gas processing rate for the plant. f. Leak detection and repair (LDAR) program monitoring results, as well as the ' repair and maintenance records. g. Records, data, measurements, reports, and documents related to the operation of the facility, including, but not limited to, the following: all records or reports pertaining to significant maintenance pertormed on any system or device at the facility; the occurrence and duration of any startup, shutdown, or malfunction, annual tuning of heaters; all records relating to performance tests and monitoring of combustion equipment; calibrations, checks, duration of any periods during which a monitoring device is inoperative, and corresponding emission measurements; and all other information required by this permit recorded in a permanent form suitable for inspection. h. All records required by this Permit shall be retained for not Iess than 5 years following the date of such measurements, maintenance, and reports. ' STATE AND FEDERAL REGULATORY REQUIREMENTS �.. � 26. XXXX . . � . . � . OPERATWG & MAINTENANCE REQUIREMENTS 27. Points 031, 063, 064, 065, 066 and 067: Upon startup of these points, the applicant ' shall follow the operating and maintenance (O&M) plan and record keeping format approved by the Division, in order to demonstrate compliance on an ongoing basis with the requirements of this permit. Revisions to your O&M plan are subject to Division approval prior to implementation. (Reference: Regulation No. 3, Part B, Section III.G ) 1 28. Points 063, 064, 065 and 066: The inlet gas temperature and iniet gas pressure� be measured and recorded weekly. AIRS ID: 123/0057 Page 11 of 21 I, _ _ _ _ Page: 11 � ;.. Number.1 Author.zjys6 � Subject:Sticky Note Date:1/11/2013 2:16:13 PM � � to the amine mntactor . . 41.�: � "x / p l':u��~�� ti . ' , � f;�olor�"�Il Dep �trrent cl public Health and Environment �� ,-, � �+� �� Air Pqllution Control Division � 4,..,�6��4�� -.��≥��?, �"�.., COMPLIANCE TESTING AND SAMPLING Initial Testinq Requirements 29. Points 057, 058, 059, 06Q 061 and 062: The owner or operator shall complete the initial fuel sampling for gross calorific value (GCV) [high heat value (HHV)] of the fuel used in the heaters as required by this permit and submit the results to the Division as part of the self-certification process to ensure compliance with emissions limits (Reference: Regulation No. 3, Part B, Section IILE.) 30. Points 057, 058, 059, 060, 061 and 062: A source initial compliance test shall be conducted on each heater to measure the emission rate(s)for the pollutants listed below in order to demonsirate compliance with the emissions limits contained in this permit. 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 Division 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 compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up 4o the monthly or annual averaging time by multiprying the test resulis by the allowabie number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section II I.G.3) Oxides of Nitrogen using EPA approved methods. Carbon Monoxide using EPA approved methods. Carbon dioxide using EPA approved methods. 31. Boints 063, 064, 065 and 066: The owner or operator shall complete the initial amine unit waste gas sampling required by this permit and submit the results to the Division as part of the self-certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) 32. Points 063, 064, 065 and 06fi: A source initial compliance test shall be conducted on emissions points 063, 064, 065 and 066 to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits specified in Contlition 7 in this permit. The operator shall also demonstrate the thermal oxidizer achieves a minimum destruction efficiencv of 99 0% for VOC and CH4. The operator shall measure and record, using EPA approved methods, VOC and CH4 mass emission rates from the thermal oxidizer inlet and outlet to determine the destruction efficiency of the thermal oxidizer(ProMax/Amine CalclGlyCalc models shall not be used . - � to determine the flow rate or cqq�position of the waste gas sent to the thermal oxidizer ' for ihe purposes of this test). ��a ` ` � $ ' �g�-{� �—m,��„-�-;�=��'.. The natural gas throughput, lean amine circulation rate, and sulfur content of sour gas entering the amine units shall be monitored and recorded , during this test. The operator shall also measure and record combustion temperature I during the initial compliance test to establish the minimum combustion temperature. The test protocol must be in accordance with the requirements of ihe Air Poilution Control Division Compliance Test Manual and shall be submitted to the Division 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 compliance 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 ; AIRS ID: 123/0057 Page 12 of 21 � :pav � � V� �t� �I L�� 1.: . 4 � r, oloraJi��Dep trnent a Public Health and Environment �� j� �, � � �� }I � �$, Air�oflution Controi Division � � e� � � f ��',. ri�i-.v mL��y . � �.�J:�iu-i _ ..�. W .a . the allowable number of operating hours for that averaging time (Reference: Common Provisions Section II.C and Regulation No. 3, Part B., Section III.G:3) Sulfur Dioxide using EPA approved methods Oxides of Nitrogen using EPA approved methods Volatile Organic Compounds using EPA approved methods Carbon Monoxide using EPA approved methods Methane using EPA approved methods Carbon Dioxide using EPA approved methods. 33. Point 067: Within one hundred and eighty days (180) after commencement of operation, the permittee shall complete the initial extended gas analysis of gas samples and extended natural gas liquids analysis of liquids that are representative of inethane (CH4), carbon dioxide (CO2), volatile organic compound (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas and liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. The operator shall submit the results of the gas and liquids analyses and emission calculations to the Division as part of the self-certification process to ensure compliance with emissions limits. 34. Point 067: Within one hundred and eighty days (180) after commencement of operation, the operator shall complete a hard count of components at the source and establish the number of components that are operated in "heavy liquid service", "light Iiquid service", "waterloil service" and "gas service". The operator shall submit the results to the Division as part of the self-certification process to ensure compliance with emissians limits. Periodic Testinp Requirements 35. Point 031: Replacements of this unit completed as Alternative Operating Scenarios may be subject to additional testing requirements as specified in Attachment A. 3s. Points 057, 058, 059, 060, 061 and 062: The fuel gross calorific value (GCV){high heat value (HHV)] of the fuel used in the heaters shall be determined, at a minimum, once per every �(�b the procedures contained in 40 CFR Part 98.34(a)(6) and records shall be maintaine7 of the semiannual fuel GCV for a period of five years. Upon request, the owner or operator shall provide a sample and/or analysis of the fuei that is fired in the heaters 37. Points 063, 064, 065 and 066: The operator shall measure the emission rate(s)for the pollutants listed below at least once every six months z rder to demonstrate compliance with the emissions limits contained in this permi�riodic testing shall be conducted at a minimum of at least thirty (30) days apart. The operator shall also demonstrate the thermai oxidizer achieves a minimum destruction efficiencv of 99.0%for VOC and CH4. The operator shall measure and record, using EPA approved methods, ' both the VOC and CH4 mass emission rates from the still vent outlet and flash tank outlet and the thermal oxidizer outlet to determine the destruction efficiency of the thermal oxidizer (process models shall not be used to determine the flow rate or ' co�q osition of the waste gas sent to the thermal oxidizer for the purposes of this test). ThdJ 0 AIRS ID: 123/0057 Page 13 of 21 --_ Page: 13 u'Numbec 1 Author:zjys6 � Subject:inserted Text Date:1/11/2013 22937 PM � � � KMG proposed that this analysis shall be mmpeted every twelve months. Fuel gas for the fired equipment is taken from our sales residue gas out of the tail end of the facility. We see very little fluctuation in the Btu/scf of this gas since it has to meet pipe�ine specification. An annual analysis will provide an accurate representation of the actual operating scenario. � "� Number:2 Authoc zjys6 Subject:Sticky Note Date:1/11/2013 230:53 PM � KMG would like to propose semi-annual tests for the first two mnsecutive mmpliant emissions tests. After that,annual tesis unless a test results � in emissions above permit thresholds,when testing would revert back to semi-annual for two consecutive compliant emission testa � I_�JNumber:3 Author.zjys6 SubjecY Cross-Out Date:1/11/2013 232:10 PM � � � KMG would like to remove the requirement m test at+/-10%of maximum circulation rate and throughput. Due to fluctuations in inlet volumes and the uncertainty of the inlet volumes upon plant start-up,Anadarko may not have enough gas to test at maximum permitted operating . parameters. Test are scheduled at least 30 days in advance and we cannot control inlet volumes on the day of testing. The required periodic testing for the four thermal oxidizers should provide sufficient verification of compliance during operational fluduations. In addition,a VOC destruction efficiency should be a minimum of 99%regardless of throughput volumes and circulation rate. �� ,�,, � „ � Y `� � h olora Ji Dep trnent o Public Healih and Environment �� h ��,`, ,, �' Air Pollution Control Division I �''—� ' �;. F —�+ I' � ;, �� . i ; . ,�..r.....,:-. ... ", r_._ . �::n .1.'�: .....:�: ��st The natural gas throughput, lean amine circulation rate shall be monitored and recorded during this test. 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 Division 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 compliance 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., Section III.G.3) Sulfur Dioxide using EPA approved methods Oxides of Nitrogen using EPA approved methods Volatile Organic Compounds using EPA approved methods Carbon Monoxide using EPA approved methods Methane using EPA approved methods Carbon Dioxide using EPA approved methods. 38. Points 063, 064, 065 and 066: Amine unit waste gas will be sampled and analyzed from each amine unit at least once eve�krree+ne+�fl��r composition in accordance with 40 CFR 98.233(d)(6) and 98.234(b). The sampled data will be used to calculate GHG emissions to show compliance with the CO2e emission limits specified in Condition 7. 3s. Point 067: On an annual basis, the permittee shall complete an extended gas analysis of gas samples and an extended natural gas liquids analysis of liquids that are representative of inethane (CH4), carbon dioxide (CO2), volatile organic compounds (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas and liquids analyses shail be used in the compliance demonstratio� as required in the Emission Limits and Records section of this permit. 40. Point 067: This facility is subject to the leak detection and repair (LDAR) requirements of 40 C.F.R Part 60, Subpart OOOO. ADDITIONAL REQUIREMENTS 4L i GENERAL TERMS AND CONDITIONS: a2. This permit and any attachments must be retained and made available for inspection upon request. The permit may be reissued to a new owner by the APCD as provided in AQCC Regulation No. 3, Part B, Section II.B upon a request for transfer of ownership and the submittal of a revised APEN and ihe required fee. ' a3. If this permit specifically states that final authorization has been granted, then the remainder of this condition is not applicable. Otherwise, the issuance of this construction permit does not provide "final" authority for this activity or operation of this source. Final ' authorization of the permit must be secured from the APCD 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 III.G. Final authorization cannot be granted until the operation or activity commences AIRS ID: 123/0057 Page ta of 21 _ _ _ __ _. _ __ __ _ Page: 14 ;�Number:1 Author:zjys6 Subject:Cross-Out Date:1/11/2013 2:32:02 PM � ��Number 2 Author:zjys6 Subject:Inserted Text Date:1/11/2013 2:54:13 PM every 12 months. Subpart W would only require an annual sample,iherefore, KMG proposes an annual sample from each stream. !� � � � �1 �` (� olora� Dep trpent c Public Health and Environment i fa �n �„ /' � � , r °� Air Pollution Control Division . e.r'_., �F �'l. � �::"_ �� . '..., cryogenic plant. Sources located at a major facility. ' AIRS ID: 123/0057 Page 16 of 21 — _ _ _ __ � �� , TABLE 1.4-2. EMISSION FACTORS FOR CRITERIA POLLUTANTS AND GREENHOUSE GASES FROM NATURAL GAS COMBUSTIONe Emission Factor Pollutant (Ib/106 scfl Emission Factor Rating COz" � 120,000 A ' Lead 0.0005 D N2O(UnconYralled) 2.2 E NZO(Controlled-low-NOX burner) 0.64 E PM (Total)` 7.6 D � PM (Condensable)° 5.7 D PM (Filterable)` 19 B SOZd 0.6 A TOC ]1 B Methane 2.3 B VOC SS C " Reference 11. Units are in pounds of pollutant per million standard cubic feet of natural gas fired. Data n ral as combustion sources. To convert from Ib/]06 scf to k 10�m' multi 1 b 16. To are for all atu g �/ , P Y Y convert from lb/106 scf to Ib/MMBtu, divide by 1,020. The emission factors in this table may be converted to other natural gas heating values by multiplying the given emission factor by the ratio of the specified heating value to tl�is average heating value. TOC=Total Organic Compounds. VOC=Volatile Organic Compounds. b Based on approximately 100% conversion of fuel carbon to COZ. COZ[]b/10�scf] _(3.67) (CON) (C)(D), where CON=fractional wnversion of fuel carbon to COz, C=carbon content of fuel by weight (0.76), and D=density of fuel, 4,2x10' lb/106 sc£ ` All PM(total, condensible, and filterable) is assumed to be less than.l.0 �nicrometer in diameter. ' Therefore,the PM emission factors presented here may be used to estimate PM�o, PMz 5 or PM� emissions. Total PM is the sum of the filterable PM and condensible PM. Condensible PM is the , particulate matter collected using EPA Method 202 (or equivalent). Filterable PM is the particulate matter collected on, or prior to,the filter of an EPA Method 5 (or equivalent) sampling train. , ° Based on 100% conversion of fuel sulfur to SOz. ', Asswnes su]£ur content is natural gas of 2,000 grains/10�sc£ The SOZ emission factor in this table can be converted to other natural gas sulfur contents by multiplying the SO2 emission factor by the ratio of ' the site-specific sulfur content(grains/106 scfl to 2,000 grains/106 sc£ .� , ; _ � � � , ahv � - � t �e �Ib � 7.Li2� v�r��-� � S�� G rL�Uv„ � - -- � d - " _.__ ___— ' _-__ ---I - � ' � � f�r�r�� sc�- , k�r- -- r��, �F�� ,�� UD_. _ ,_ , ` � l� �b � ��='H�M,� `"'^ � '-`�S � �� -_ , - r -�_ �` -�- -L 2 � 5 r�k„� � 7 � �Q�� v�vv�S,�� .r � � __�� '� � �. �r <i c �j � S� `� � �`I � ��tV'1 �,A �l '� �� n.��,�, �= �� ,��'��`b 1� �-�� r� . a�:�� _ � .— _� 1.4-6 EMISSION FACTORS 7/98 ___ __ _ . _ _ _ __ __ __ _ _ _. _ _ ___ �� r, � , �..M��c. n ;',��ylr � I T � � ——_1 _ ' _ . r� 7��"�� `�;� � ( '�''2_ � t�o� � � � . �.iCr,— � + 3�}`t ? t?,` `i�, — � � SL� � .. . c�: — � , 4`it�L t ;';, "?i t.3 = iU, ^4`� i�1 � � A� ( , — , �e, _ ��,_yr,v��Sc�� ,�_��_-,�� ( r� � � I , �— , �-- _ — ��i'1�{��{.. � ' �'`(1�� . j ��,'a,� �f!C.�i iJ . . � `-� � �� A��' A Honeywe{I Corrs�any . 201 East 181h Street Muncia lndiena 47302-A124 P.O. Box ZOEB M�ncie,Intllana. 47307�0068 � . � _ . Te1:765284-3304 Fax:765286.e394 . ' � www.maxoncorp.com � � � � � � � � � Charlie, The KinedizerLe Burner will produce no more .005 #/million Btu's of PM2.5(condensable & filterable) for the stated conditions of firing at 68.4 MM BTU/HR at high fire and 62.2 MM BTU/Hr at steady state conditions. Larry Hyland Manager-Technical Sales Support Maxon R Honeywell Company 201 E 18th Street Muncie, IN 9 . �l`t�v C.tlG 9.$1.L 4.� =��i � 'E-.,��rr�kF;l"�e_CT+. � S'G'^,. _f Ua' �' GL. � � � . . , --- . \ , , . � . � j '_ �l f J � � . . p � �y'�� p i - , �[ p ...�� 7 � CL�€? 3.��)e [ 14' ��.�. LL`rj/tcU¢-v�n�UY,.s t*� �!�'�L�l L � '� L f �Y�� . • , � � , . � r .�.-.. ... ._. Equipment Emission Detaol Fort Wpton�EU-31�S/N 250451�AIRS ID: 123/0057/013-1/1/2003 to 1/31/2003 }��t'L' �'�W��,�4'i" �" �`'!%t"' . Report Date: Wednesday, February 6,2013 1:54 PM � Records 1 to 30 of 155, Page 1 of 6 Type Categoty Compound Emission Period� Amount Units Estimated Emission Calculation Actual Standard '��,-yv�si�U-��L- ;j�ts��'�'�' Carbon Monoxide � ��,t:�t`�:� ' . 1/1/2�03 to 1/1/2003 231.88 Ib/day� �` 152{Ib/mmBtu}�'151�6129{mcf/day}_*'� ioo5.z{stu/scf}*�r�cP}�i000{mct}� 1/2/2003 to 1/2/2003 231.88 Ib/day � 1.52(Ib/mmBtu}* 151.6129{mcf/day}* 1006.2{Btu/scf}*(1{scf}/S000{mcf}) 1/3/2003 to 1/3/2003 231.88 Ib/day � 152{Ib/mmBtu}* 151.6129{mcf/day}* . 1006.2{Btu/scf}*(1{scf}/S000{mcf}) . � 1/4/2003 to i/4/2003 � 231.88 Ib/day � � 1.52{Ib/mmBtu}* 151.6129{mff/day}* - iooez{stu/s�}+�i{s�t}/ i000{mcF}� . i 1/5/2003 to 1/5/2003� 231.88 Ib/day � 1.52{Ib/mmBtu}* 151.6129{mcF/day}* p � i 1�--�.� ��" � �' � F- �`-�'� �� 1006,2{Btu/scf}*(1{scf}/1000{mcf}) � 1/6/2003 to 1/6/2003 231.88 Ib/day � 1.52{Ib/mmBtu}* 151.6129{mcF/day}* �r`v UC_ 4r., � .�..�.':L- 1006.2(Btu/scf}*(1{scF}(1000{mcf}) 1/7/2003 to 1/7/2003 231.88 Ib/day �' �1.52{ib/mmBtu}* 151.6129{mcryday}* �� `��`vti 'l%�.�"� � � 1006.2{Btu/scf}*(1{scf}/1000{mcf}) ... .. . ' 1/8/2003 to 1/8/2003 231.88 Ib/day $� 1.52{Ib/mmBtu}* 151.6129{mcF/day}* '_�-��- . � � d006.2{Btu/scf}*(1{scf}/S000{mcf}) . i/9/2003 to 1/9/2003 231.88 Ib/day � 1.52{Ib/mmBtu}* 151.6129{mcf/day}.* 1�06.2{Btu/scf}*(1{scF}/1000{mcf}) 1/10/2003 to 1/10/2003 �231.88 Ib/day '� 1.52{Ib/mmBtu}* 151.6Y29{mcF/day}* � 1006.2{Btu/scf}*(1{scf}/1000{mcf}) 1/11/2003 to 1/11/2003 231.88 Ib/day _ � 1.52{Ib/mmBtu}* 151.6129(mcF/day}* 1006.2{Btu/scf}* (1{scf}/1000{mcfy) � � 1/1Z/2003.to 1/12/2003 231.88 Ib/day � 1.52{Ib/mmBtu}* 151.6129{mcf/day}* ioo6.z<stu/scr}��i{scf}/i000{mcr}� � 1/13/2003 to 1/13/2003 . 231.88 Ib/day � � 1.52{Ib/mmBtu}* 151.6129{mcf/day}* � . � 1006.2{Btu/scf}*(1{scF}/1000(mcf}) � 1/14/2003 to 1/14/2003 231.88 Ib/day r 1.52{Ib/mmBtu}* 151.6129{mcF/day}* � � 1006.2{Btu/scf}*(1{scF}/1000{mcF}) � . 1/15/2003 to 1/15/2003 231.88 Ib/day � 1.52(Ib/mmBtu}* 151.6129{mcfi/day}* iaos.z{scu/sc�}_�i<scr}/i000{mcr}� 1/16/2003 to 1/16/2003 231.88 Ib/day ,� 1.52{Ib/mmBtu}* 151.6129{mcf/day}* � � � �� 1006.2{Btu/scf}*(1{scf}/1000(mcf}) 1/ll/2003 to 1/17/2003 231,88 Ib/day � �� 152{Ib/mmBtu}* 151.6129(m6/day}* 3006.2{Btu/scf}*(1{scf}/1000{mcf}) . 1/18/2003 to 1/18/2003 231.88 Ib/day � 1.52(Ib/mmBtu}* 151.6129{mcf/day}* � 1006.2(Btu/scf}*(1{scfy/1000(mcf}) � � 1/19/2003 to 1/19/2003 231.88 Ib/day � 1.52{Ib/mmBtu}* 151.6Y29{mcf/day}* � ' ioo5.z{stu/scf}*�i{scry/iaoo{mcr}� 1/20/20�3 to 1/20/2003 231.88 ib/day � 1.52(Ib/mmBtu}* 151.6129{mcryday}* � . 1006.2{Btu/scF}*(1{scf}/S000{mcf}) 1/21/2003 to 1/21/2003 231.88 Ib/day �" 1.52{Ib/mmBtu}* 151.6129{mcf/day}* 1006.2(Btu/scf}*(1{scf}/1000(mcf}) � 1/22/2003 to 1/22/2003 231.88 I6/day ]� 152{Ib/mmBtu}* 151.6129{mcf/day}* � - � � 1006.2{Btu/scf}*(1{scf}/1000{mcf}) . . 1/23/2003 to 1/23/2003 231.88 Ib/day � 1.52{Ib/mmBtu}* 151.6129{mcf/day}* - � 1006.2{Btu/scf}*(1(scf}/ 1000{mcf}) 1/24/2003 to 1/24/2003 231.88 Ib/day � 1.52{Ib/mmBtu}* 151.6129{mcF/day}* � ioo5.z{stu/scr�_�i{scr}/i000{mcr}� . 1/25/2003 to 1/25/20D3 231.88 ib/day �" 1.SZ{ib/mmBtu}*151.6129{mcf/day}* 1006.2{Btu/scf}*(1{scf}/S000{mcf}) � 1/26/2003 to 1/26/2003 231.88 Ib/day � 1.52{Ib/mmBtu}* 151.6129{mcfi/day}* � . � 1006.2{Btu/scf}*(1{scf}/1000{mcf}) � 1/D/2003 to 1/D/2003 231.88 Ib/day � r -1.52{Ib/mmBtu}* 151.6129{mcryday}* � � 1006.2{Btu/scf}*(1{scf}/ S000{mcf}) � 1/28/2003 to 1/28/2003 231.88 Ib/day �. 1.52{Ib/mmBtu}*151.6129{mcF/day}* 1006.2{Btu/scf}*(1{scf}/1000{mcf}) 1/29/2003 to 1/29/2003 231,88 Ib/day � � 1.52{Ib/mmBtu}*151.61Z9{mcF/day}* 1006.2{Btu/scf}*(1{scf}/ 1000{mcf}) 1/30/2003 to 1/30/2003 231.88 Ib/day � � 1.52{Ib/mmBtu}* 151.6129{mcF/day}* 1006.2{Btu/scf}*(1{scF}/1000{mcf}) Equiprnent Ernission Detail Fort Lupton,EU-31,S/N 250451,AIRS ID: 123/0057/013-1/1/2003 to 1/31/2003 � Report Date: Wednesday, February 6, 2013 1:54 PM Records 59 to 86 of 155, Page 3 of 6 - Type Category Compound Emission Period Amount Units Estimatetl Emission Calculation . Actual � Standard � . � �-��.v��}'`tc*-'._'w'�^� t_,Y". Nitrogen Oxides 1 . 1/28/2003 to 1/28/2003 105.26 Ib/day � � 0.9{Ib/mmBtu}*151.6129{mcF/day}* iooe.z{atu/scr}*�i{scr}/i000{mcf}> 1/29/2003 to 1/29/2003 105.26 Ib/day . �� .69{Ib/mmBtu}* 151.6129{mcf/day}* rooe.z{stu/scr}*�i{scr}/ iooa{mcr�� . 1/30/2003 to i/30/2003 105.26 Ib/day �� 0.69{Ib/mmBtu}* 151.6129{mcf/day}* � � � 1006.2{Btu/scf}*(1{scf}/1000{mcf}) 1/31/2003to 1/31/2003 105.26 Ib/day � � 0.69(Ib/mmBtu}* 151.6129{mcf/day}* 1006.2{Btu/scF}*�i{scr}/i000{mcf}�. . Nitrogen Oxides TotaL• . 3,263.11 (105.26 average) . . � � PM10 _.�n..��i ��`�.�;'t i .4,�l��rL'��..�Le..;. � 1/1/2003 to 1/1/2003 2.96 ib/day ],� 0}'61941{Ib/mmBtu}* 151.6129{mcryday}* � � Loo9.z{stu/scP}*(1{scFj/ l000{mcf}) . i/2J2003 to 1/2/2003 2.96 Ib/day ].� 0.01941{Ib/mmBtu}* 151.6129(mcf/day}* ioo5.z{stu/scr}��i{scr}/i000<mcr�� 1/3/2003 to 1/3/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* � 1006.2{Btu/scf)*(1{scf}/ 1000{mcf}) 1/4/2003 to 1/4/2003 Z.96 Ib/day� j� 0A1941{Ib/mmBtu}* 151.6129{mcf/day}* iooe.z{atu/scF}_�i{scr}�i000{mcr}� . 1/5/2003 to 1/5/2003 � 2,96 Ib/day �' 0A1941{Ib/mmBtu}* 151.6129{mcf/day}* � 1006.2{Btu/scf}*(1{scf}/1000{mcF}) 1/6/2003 to 1/6/2003 � 2.96 Ib/day ]� 0.01941(Ib/mmBtu}* 151.6129{mcf/day}* � � 1006.2{Btu/scf}*�i{sa}/ ioaa{mcF}� . � 1/7/2003 to 1/7/2003 2,96 Ib/day� � 0.01941{Ib/mmBtu}* 151.6129{mcryday}* ioo6.z{etu/scr}*�i{scr}/i000{mcF}� . . 1/8/2003 to 1/8/2003 2.96 Ib/day ' � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* 1006;2{Btu/scf}*(i{scF}/1000{mcf}) . 1/9/2003 to 1/9/2003 � 2.96 Ib/day � 0.0194Y{Ib/mmBtu}* 151.6129{mcf/day}* � � ioo5.z{ecu/scr�*�i{scr}/i000{mcr�� 1/10/2003 to 1/10/2003 � 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* � 1006.2{Btu/scf}*(1{scf}/ S000{mcf}) , . . -1/il/2003.to 1/11/2003 � 2.96 Ib/day � . 0.01941{Ib/mmBtu}* 151.6129{mcyday}* 1006.2{Btu/scf}*(1{scf}/1000{mcf}) 1/12/2003 to 1/12/2003 2.96 Ib/day . � 0.01941{Ib/mmBtu}* 151.6129(mcf/day}* ioos.z<ecu�scF}*�i {scF}/ i000{mc�}� � 1/13/2003 to 1/13/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcyday}* ioo5.z{etu/scr}*�i{scr}/i000{mcr}� 1/14/2003 to 1/14/Z003 � 2.96 Ib/day � � 0.01941{Ib/mmBtu}* 151.6129{mcryday}* 1006.2{Btu/scf}*(1{scf}/ 1000{mcf}) � i/15/2003 to 1/15/2003 � 2.96 Ib/day � 0.01941(Ib/mmBtu}* 151.6129{mcf/day}* - 1006.2{Btu/scf}*(1.{scfi}/1000(mcf}) . 1/16/2003 to 1/16/2003 2.96 Ib/day �f 0.01941 {Ib/mmBtu}* 151.6129{mcf/day}* � � � 1006.2{Btu/scf}*(1{scf}/1000{mcf}) � 1/17/2003 to 1/17/2003 2.96 Ib/day� � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* � � . � � 1006.2{Btu/scf}*(1{scf}/ l0W{mcf}) � 1/18/2003 to 1/18/2003 � 2,96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* ioo5.z{ecu/scF}_�i{scf}/i000{mcr�) . 1/19/2003 to 1/19/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcF/day}* � 1006.2{Btu/scf}*�(1{scf}/1000{mcfy) � 1/20/2003 to 1/20/2003 � 2.96 Ib/day J� 0.01941{Ib/mmBtu}* 151.6129{mcryday}* 1006.2{Btu/scf}*(1{scf}/1000{mcf}) 1/21/2003 to 1/21/2003 2.96 Ib/day �' 0.01941{Ib/mmBtu}* 151.6129(mcf/day}* 1006.2{Btu/scf}*(1{scf}/ 1000{mcF}) � 1/22/2003 to 1/22/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcQday}* � � 1006.2{Btu/scf}*(1{scf}/ 1D00{mcf}) � 1/23/2003 to i/23/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcryday}* � . � � 1006.2{Btu/scf}*(1{scf}/ S000{mcf}) 1/24/2003 to 1/24/2003 2.96 Ib/day - J..� 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* 1006.2(Btu/scf}*(1{scf}/1000{mcf}) I Equipment Emassion Detail � �� Fort Lupton,EU-31,S/N 250451,AIRS ID: 123/0057/013-1/1/2003 to 1/31/2003 Report Date:Wednesday, February 6, 2013 1:54 PM � Records 87 to 114 of 155, Page 4 of 6 Type Category Compound Emission Period Amount Units Estimated Emission Calculation � Actual�� Standard . . . � � . PM10 1/25/2003 to 1/25/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* . � 1006.2{Btu/scf}*(1{scf}/ 1000(mcf}) � 1/26/2003 to 1/26/Z003 2.96 Ib/day ,� 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* . � 1006.2{Btu/scf}*(1{scf}/ 1000{mcf}) 1/27/2003 to 1/27/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcF/day}* � 1006.2{Btu/scF}* (1{scF}/ S000{mcf}) � � 1/28/2003 to 1/28/2003 2.96. Ib/day j� 0.01941{ib/mmBtu}* 151.6129{mcryday}* . 1006.2{Btu/scf}*(1(scf)/1000{mcf}) 1/29/2003 to 1/29/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 15i.6129{mcf/day}* . 1006.2{Btu/scf}*(1{scf}/ 1000{mc@) � � 1/30/2003 to 1/30/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* . 1006.2{Btu/scF}*(1{scf}/ 1000{mcf}) � � . 1/31/2003 to 1/31/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* � . 1006.2{Btu/scf}*(i{scf}/ 1000{mcf}) . � PM10 Total: 91J9 (2.96 average) � � " � -f;:�-�t1_�; '�.r.��l>� ��'�:`�;c. � PM2.5 ��'. � 1/1/2003 to 1/I/2003 2.96 Ib/day � 0.1�1941{Ib/mmBtu}* 151.6129{mcF/day}* � 1006.2{Btu/scf}*(1{scF}/ 1000{mcf}) 1/2/2003 to 1/2/2003 2.96 Ib/day � O.D1941�{Ib/mmBtu}* 151.6129{mcf/day}* � � - . � 1006.2{Btu/scf}* (1{scf}/ 1000{mcF}) � 1/3/2003 to 1/3/2003� � 2.96 Ib/day � 0.01941{Ib/mmBtu)* 151.6129{mcf/day}* � . 1006.2{Btu/scF}*(1{scf}/ S000{mcf}) 1/4/2003 to 1/4/2003 Z.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* � � - 1006.2{Btu/scf}*(1{scf}/ S000{mcf}) � i/5/2003 to 1/5/2003 2.96 Ib/day � 0.01941(Ib/mmBtu}* 151.6129{mcf/day}* � 1006.2{Btu/scf}*(1{scf}/�1000{mcf}) . - � 1/6/2003 to 1/6/2003 � 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* . � . � 1006.2{Btu/scf}*(1(scf}/ 1000{mcf}) � . 1/7/200320 1/7/2003 2.96 Ib/day . � 0.01941{Ib/mmBtu}* 151.6129{rncF/day}* ioo5.z{stu/sc�*(i{scF}/ i000{mcr}� � 1/S/2003 to 178/Z003 2.96 Ib/day � 0.01941{�b/mmBtu}* 151.6129{mcf/day}* � . 1006.2{Btu/scf}*(1{scf}/ 1000{mcF}) 1/9/2003 to 1/9/2003 2.96 Ib/day ]� 0.01941{ib/mm8tu}* 151.6129{mcf/day}* . � 1006.2{Btu/scF}* (1{scF}/ 1000{mcF}) � 1/10/2003 to 1/10/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129(mcf/day}* iooe.z{stu/s�}*(i{scr}/ i000{mcr}) � 1/ll/2003 to 1/11/2003 2.96 Ib/day . ,� 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* . � � � � � 1006.2{Btu/scf}*(1{scF}/1000{mcf}) .� 1/12/2003 to 1/12/2003 � 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcF/day}* � � 1006.2{Btu/scf}*(1{scF}/ 1000(mcF}) . � 1/13/2003 to 1/13/2003 . 296 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcryday}* � 1006.2{Btu/scf}*(1{scF}/ S000{mcf}) � �- - 1/14/2003 to 1/14/2003 2.96 Ib/day � OA1941{Ib/mm6tu}* 151.6129{mcF/day}* � . . 1006.2{Btu/s[f}*(i{scFj/iooa tmcF}� - 1/15{2003 to 1/15/2003 L96 Ib/day � � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* � 1006.2{Btu/scf}*�(1{scf}/ S000{mcf}) 1/16/2003 to 1/16/2003 Z.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* . 1006.2{Btu/scF}*(1{scf}/ S000{mcf}) 1/llj2003 to 1/17/2003 Z.96 Ib/day ]� 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* � 1006.2{Btu/scf}*(1{scF}/ 1000{mcf}) �1/18/2003 to 1/18/2003 2.96 ib/day j- 0.01941(Ib/mmBtu}* 151.6129{mcf/day}* � . � 1006.2{Btu/scf}*(1{scF}/1000{mcf}) � � 1/19)2003 to 1/19/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* � � . 1006.2{Btu/scf}* (1{scF}/ 1000{mcF})� . � �� 1/20j2003 to 1/20/2003 2.96 Ib/day r 0.01941{Ib/mmBtu)* 151.6129{mc%day}* � � � 1006.2{Btu/scf}*(1{scF}/ 1000{mcf}) 1/21J2003 to 1/21/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* � iooe.z{ecu/sct}*�i{scf}/ i000{mc�) Equipment Emission Detail .Fort Lupton,EU-31,S/N 250451,AIRS ID: 123/0057/013- 1/1/2003 to 1/31/2003 Report Date: Wednesday, February 6, 2013 1:54 PM Records 115 to 142 of 155, Page 5 of 6 Type Category Compound Emission Period Amount Units Estimated Emission Calwlation Actual Standard � � PMZ.5 . 1/22/2003 to 1/22/2003 2.96 ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* 1006.2{Btu/scf}*(1{scfi}/1000{mcf}) � 1/23/2003 to 1/23/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* SS1b129{mcf/day)* � � � 1006.2{Btu/scf}*(1{scf}/ 1000{mcf}) . 1/24/2003 to 1/24/2003 2.96 Ib/day ]J 0.01941{Ib/mmBtu}* 151.6129{mcryday}* . 1006.2{Btu/scf}*(1{scf}/1000{mcf}) 1/25/2003 to 1/25/2003 2.96 Ib/day � OA1941(Ib/mmBtu}* 151.6129{mcf/day}* � � � 1006.2{Btu/scF}*(1{scF}/ 1000(mcF}) 1/26/2003 to 1/26/Z003 . 2.96 Ib/day � 0.01941{Ib/mmBtu}�* 151.6129{mcf/day}* 1006.2{Btu/scf}*(1{scf}/ 1000{mcf}) � 1/27/2003 to 1/27/2003 2.96 Ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* �. 1006.2{Btu/scf}*(i{scF}/1000{mcf�) 1/28/2003 to 1/28/2003 � 2.96 Ib/day � ]� 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* ioos.z{stu/scr}*�i{scf}/ i000{mct}� � 1/29/2003 to 1/29/2003 2.96 Ib/day � � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* � ioo6.z<stu/scr}*�i<scf}/ i000<mc�� 1/30/2003 to 1/30/2003 Z.96 ib/day � 0.01941{Ib/mmBtu}* 151.6129{mcf/day}* � 1006.2{Btu/scf}*(1{scf}/.1000{mcf}) . 1/31/2003 to 1/31/2003 . 2.96 Ib/day � 0.01941(Ib/mmBtu}* 151.6129{mcf/day}* . � 1006.2{Btu/scf}*(1{scf}/1000{mcf}) PM2.STotal: 91J9 (2.96average) , _E��,a,,l��:..�"5�` VOC ' �., �^ - 1/1/2003 to 1/1/2003 4i.95 Ib/day � 0.2�5(Ib/mmBtu}*151.6129{mcfi/day}* - 1006.2(Btu/scf�*(1(scf}/ 1000{mcf}) 1/2/2003 to 1/2/2003 41.95 Ib/day � �.275{Ib/mmBtu}* 151.6129{mcf(day}* 1006.2{Btu/scf}*(1{scf}/ 1000{mcf}) � 1/3/2003 to 1/3/2003 41.95 Ib/day � 0.275{Ib/mmBtu)* 151.6129{mcF/day}* .. - � 1006.2 tBtu/scf}*(1{scfi}/1000{mcf}) 1/4/2003 to 1/4/Z003 41.95 Ib/day � O.Z75{Ib/mmBtu}* 151.6129{mcf/day}* aoo6.2{scwscfj*�i{scr}/ i000{mcr}� � 1/5/2003 to 1/5/2003 41.95 Ib/day . � 0.275(Ib/mmBtu}* 151.6129(mcf/day}* 1006.2{Btu/scf}*(1{scf}/1000{mcf}) � 1/6/2003 to 1/6/2003 41.95 Ib/day � ,� 0.275{Ib/mmBtu}.* 151.6129{mcf/day}* � 3006.2{Btu/scf}*(1{scf}/1000{mcf}) � . 1/7/2003 to i/7/2003 � 41.95 Ib/day j� 0.275{Ib/mmBtu}* 151.6129{mcryday}* - � 1006.2{Btu/scF}*�i{scr}/i000{mcr}� 1/8/2003 to 1/8/2003 41.95 Ib/day � 0.275{Ib/mmBtu}* 151.6129{mcF/day}* • � 1006.2{Btu/scf}*(1{scF}/ 1000{mcf}) .� � �1/9/2003 to 1/9/2003 41,95 tb/day �� 0.275{Ib/mmBtu}* 151.6129(mcf/tlay}* � � 1006.2�{8tu/scf}*(l�{scFj/S000{mcf}) � �� 1/10/2003 to 1/10/2003 41.95 Ib/day jv 0.275{Ib/mmBtu}*151.6129{mcf/day}* ioo5.z{atu/scr�*�i{scF}/i000{mcf}� � � 1/11/2003 to 1/11/2003 � 41.95 Ib/day � 0.275{Ib/mmBtu}*151.6129{mcf/day}* . 1006.2{Btu/scf}*(1{scfi}/ 1000{mcf}) 1/12/2003 to 1/12/2003 41.95 Ib/day � 0.275{Ib/mmBtu}* 151.6129{mcf/day}* � � . � 1006.2{Btu/scf}*(1{scF}/1000{mcF}) � . 1/13/2003 to 1/13/2003 41.95 Ib/day � 0.275{Ib/mmBtu}*151.6129{mcf/day}* � 1006.2{Btu/scf}*(1{scF}/1000{mcf}) . 1/14/2003 to 1/14/2003 41,95 Ib/day [� 0.275{Ib/mmBtu}*151.6129{mcryday}* � � 1006.2{Btu/scf}*(1{scF}/1000{mcf}) 1/15/2003 to 1/15/2003 41.95 Ib/day �`" �.275{Ib/mmBtu}*151.6129{mcF/day}.* � 1006.2{Btu/scf}*(1{scf}�/1000(mcF}) � 1/16/2003 to i/16/2003 41.95 Ib/day � 0.275{Ib/mmBtu}*151.6129(mff/day}* 1006.2{Btu/scf}*(1{scf}/ S000{mcf}) . � 1/17/2003 to 1/17/2003 41:95 Ib/day � 0.275{Ib/mm8tu}*151.6129{mcF/day}* 1006.2{Btu/scf}*(i{scf)/1000{mcf}) . 1/18/2003 to 1/18/2003 41.95 Ib/day � � 0.275{Ib/mmBtu}* 151.6129{mcf/day}* . - 1006.2{Btu/scf}*(1{scf}/ 1000{mcf}) .. ...__ .. ..__..__. . � � � Equipment Emission Detail Fort Lupton,EU-31,S/N 250451,AIRS ID: 123/0057/013-4/1/2008 to 4/30/2008 . Report Date: Wednesday, February 6,2D13 1:55 PM ' Records 1 to 29 of 150, Page 1 of 6 Type Category � Compound Emission Period Amount Units Estimated Emission Calwlation � Actual � � � Standard . . . �• Carbon Monoxide � / . 4/1/2008 to 4/1/2008 203.63 Ib/day � 1.$2{Ib/mmBtu}* 133.i4{mcf/day}* 1006.2 � {Btu/scf}*(1{scf}/ 1000{mcF}) . 4j2/2008 to 4/2/2008 207.09 �b/day �' 1.52{Ib/mmBtu}* 135.407{mcf/day}* 1006.2 � . {Btu/scF}*(1{scf}/ 1000{mcf}) _ 4/3/2008 to 4/3/2008 220.28 Ib/day � � 1.52{Ib/mmBtu}* 144.03101{mcf/day}* 1006.2{Btu/scf}*(1(scf}/ 1000{mcf}) 4/4/2008 to 4/4/2�08 211.49 Ib/day f 1.52{Ib/mmBtu}* 138.282{m6/day}* 1006.2 � {Btu/scf}*(1{scF}/ 1000{mcf}) � 4/5/2008 to 4/5/2008 211.28 �Ib/day � 1.52{Ib/mmBtu}* 138.Y4101{mcf/day}* � � � � 1006.2{Btu/scf}*(1{scf}/ 1000{mct}) 4/6/2008�to 4/6/2008 � 206.20- Ib/day � 1.52{Ib/mmBtu}* 134.825{mcF/day}* 1006.2 � � {Btu/scf}*(1{scf}/ 1000{mcf}) � . 4/7/2008 to 4/7/2008 213.77, Ib/day � i.52{Ib/mmBtu}* 139.77{mcf/day}* 1006.2 � {Btu/scfj*(1{scF}/ S000{mcf}) � � 4/8/2008 to 4/8/2008 215.69� Ib/day r 1.52{Ib/mmBtu}* 141.03{mcf/day}* 1006.2 . . {Btu/scF}*(1{scF}/ 1000{mcf}) 4/9/2006 to 4/9/2008 198.99� Ib/tlay � 1.52{Ib/mmBtu}* 130.105{mcf/day}* 1006.2 . {Btu/scf}*(1{scF}/S000(mcf}) ' � 4/10/2008 to 4/10/2008 199.47�. Ib/day � �1.52{Ib/mmBtu}* 130.423{mcf/day}* 1006.2 � {Btu/scf}*(1(scf}/ 1000{mcf}) 4/11/2008 to 4/11/2008 207.22` Ib/day jW 1.52{Ib/mmBtu}* 135.48801(mcf/day}* � . 1006.2(Btu/scf}*(1{scf}/ 1000{mcf}) � : 4/12/2008 to 4/12/2008 207,09� Ib/day � 152{Ib/mmBtu}* 135.40199{m6/day}* � � 1006.2{Btu/scf}*(1{scF}/1000{mcf}) 4/13/2008 to.4/13/2008 207.06�� Ib/day jW 1S2{Ib/mmBtu}* 13538699{mcF/day}* � . � 1006.2{Btu/scf}*(1{scf}/ 1000(mcf}) � � 4/14/2008 to 4/14/2008 � 215.37. Ib/day � � 1.52{Ib/mmBtu}� 140.819{mcf/day}* 1006.2 {Btu/scf}*(i{scfy/ S000{mcf}) � . 4/15/2008 to 4/15/2008 220.18 � Ib/day � 1.52 Qb/mmBtu}* 143.962{mcf/day}* 1006.2 {Btu/scF}*(1{scf}/ 1000{mcF}) 4/16/2008 to 4/16/2008 204.22 �Ib/day � 1.52{Ib/mmBtu}* 133.527{mcf/day}* 1006.2 � . � {Btu/scF}*(1{scf}/ 1000{mcf}) � 4/17/2008 to 4/ll/2008 209A2 . Ib/day � 1.52{IIi/mmBtu}* 136.66901{mcf/day}* . 1006.2{Btu/scf}*(1{scf}/1000{mcf}) � - 4/18/2008 to 4/18/2008 189.82. Ib/day � ].� 1.52{Ib/mmBtu}* 124114{mcf/day}* 1006.2. � � {Btu/scf}*(1(scf}/ 1000{mcf}) . 4/19/2008 to 4/19/2008 � 207.98- Ib/day � 1.52{Ib/mmBtu}* 135.989{mcF/day}* 1006.2 � {Btu/scF}*(1 {scf}/1000(mcf}) � � 4/20/2008 to 4/20/2008 202.45, Ib/day � � 152 LIb/mmBtu}* 13Z.368{mcf/day}* 1006.2 {Btu/scF}*(1{scf}/ 1000{mcf}) 4/21/2008 to 4/Zl/2008 206.39 � Ib/day � 1.52{Ib/mmBtu}* 134.944{mcf/day}* 1006.2 {Btu/scf}*(1 {scf}/ 1000{mcf}) 4/22/2008 to 4/Z2/Z008 . 200.97 � Ib/day � 152{Ib/mmBtu}* 131.4{mcf/day}* 1006.2 � � {Btu/scF}*�(1{scfy/1000(mcf}) 4/23/2008 to 4/23/2008 208,46 � Ib/day � 1.52{Ib/mmBtu}* 136.299{mcf/day}* 1006.2 � {Btu/scf}*(1{scf}/ 1000{mcf}) 4/24/2008 to 4/24/2008� 219.87 � Ib/day � 1.52{Ib/mmBtu}* 143J5999{mcf/day}* 1006.2{Btu/scf}*(1{scf}/1000{mcf}) � � 4/25/2008 to 4/25/2008 211.55 , Ib/day _ � 1.52{Ib/mmBtu}* 138.32001{md/day}* � 1006.2{Btu/scf}*(1{scf}/1000{mcf}) � 4/26/2008 to 4/26/2008 � 207.14. Ib/day J� 1.52{Ib/mmBtu}* 135.436{mff/day}* 1006.2 � � � {Btu/scf}*(1 {scF}/ 1000{mcf}) 4/27/2008 to 4/27/2008 206.65 � Ib/day � 1.52(Ib/mmBtu}*135.11301{mcryday)* � � 1006.2{Btu/scf)*(1{scF}/1000{mcF}) 4/28/2008 to 4/28/2008 19838 �Ib/day � 1.52{Ib/mmBtu}*129.711{mcf/day}* 1006.2 . . � {Btu/scf}*(1{scf}/1000(mcF}) 4/29/2008 to 4/29/2008 . 201,65 Ib/day . ]V 1.52{ib/mmBtu}*131.84599{mcryday}* . � � � 1006.2{Btu/scf}*(1{scF}/1000{mcf}) � �� t z�)� 1 � � �, � 1.��i��,i�'�li 0- (�� z .'�ti��L�'-L`li �'��/6,1. � f"u� '(- . �'"� _ � -�:�}�,-�, _ _ _ _ Equipment Emission Detail Fort Lupton,EU-31,S/N 250451,AIRS ID: 123/0057/013-4/1/2008 to 4/30/2008 . Report Date: Wednesday, February 6,2013 1:55 PM � Records 58 to 85 of 150, Page 3 of 6 Type Category Compound Emission Period Amount Units Estimated Emission Calculation Actual Standard � p Nitrogen Oxides � � . ' \ � 1� v„4/28/2008 to 4/28/2008 90.06 Ib/day �" � 0.�{Ib/mmBCu}* 129J11{mcQday}* 1006.2 �� 'tN��'� � t1-�YaP.w�-Q�v i� . �� {Btu/scF}*(1{scF}/1000{mcf}) � s '��'�,� 4/29/2008 to 4/29/2008 � 91.54 Ib/day �` 0.69{Ib/mmBtu}* Y31.84599{mcf/day}* . ��'��'�� . "�` 1006.2{Btu/scf}*(1{scf}/1000{mcf}) . 4/30/2008 to 4/30/2008 . 98.29 16/day ]� 0.69{Ib/mmBtu}*141,57201{mcf/day}* . � � � 1006.2{Btu/scF}*(1{scf}/ 1000{mcf}) Nitrogen Oxides Total: 2,830J7 (94.36 average) . � PM10 // 4/1/2008 to 4/1/2008 2.60 Ib/day r �.01�1'41{Ib/mmBtu}* 133.14{mcfi/day}* � � 1006.2{Btu/scf}*(1{scf}/S000{mcf}) � 4/2/2008 to 4/2/2008 2.64 Ib/day � 0.01941{Ib/mmBtu}* 135.407{mcf/day}* . � � 1006.2{Btu/scF}*(1{scF}/ 1000{mcf}) .� 4/3/2008 to 4/3/2008� 2.81 Ib/day J�' �.01941{Ib/mmBtu}* 144.03101{mcF/day}* � � � 1006.2{Btu/scf}*(1{scf}/1000{mcf}) - 4/4/2008 to 4/4/2008 . 2J0 Ib/day � 0.01941{Ib/mmBtu}* 138.282{mcf/day}* � 1006.2{Btu/scf}*(1(scf}/1000{mcf}) 4/5/2008 to 4/5/2008 2.70 Ib/day � 0.01941(Ib/mmBtu}* 138.14101{mcf/day}* � � 1006.2{Btu/scf}*(1(scf}/1000{mcf}) . 4/6/2008 to 4/6/2008 Z63 Ib/day � 0.01941{Ib/mmBtu}* 134.825{mcf/day}* � 1006.2{Btu/scf}*-(1{scf}/ 1000{mcf}) 4/7/2008 to 4/7/2008 2J3 Ib/day � 0.01941{Ib/mmBtu}* 139.77{mcfi/day}* � 1006.2{Btu/scf}*(1{scF}/1000{mcf}) 4/8/2008 to 4/8/2008 2.75 Ib/day � 0.01941{Ib/mmBtu}* 141.03{mcf/day}* � . 1006.2{Btu/scf}*(1{scf}/ 1000{mcf}) 4/9/2008 to 4/9/2008 2.54 Ib/day � r 0.01941(Ib/mmBtu}* 130.105{mcf/day}* . . � � 1006.2{Btu/scf}*(1{scF}/1000{mcf}) � 4/10/2008 to 4/10/2008 2.55 Ib/day � 0.01941{Ib/mmBtu}* 130.423{mcf/day}* � 1006.2{Btu/scF}*(1{scf}/1000{mcf}) 4/11/2008 to 4/11/2008 2,65 Ib/day � 0.01941{Ib/mmBtu}* 135.46$01{mcfi/day)* 1006.2{Btu/scf}*�i{scE}� i000{mcF}� � 4/12/2008 to 4/12/2008 2.64 Ib/day ]� 0.01941{Ib/mmBtu)* 135.40199{mff/day}* iooe.z{etu/sct}*�i{scr}/ioao{mcr}> � 4/13/2008 to 4/13/2008 � 2.64 Ib/day j�� 0.01941{Ib/mmBtu}*135.38699{mcF/day}* ioo6.z<stu/scr}*�i{scF}�i000{mcr}� 4/14/2008 to 4/14/2008 2J5 Ib/day � 0.01941{Ib/mmBtu}* 140.819{mcf/day}* . 1006.2{Btu/scf}*(1{scf}/1000{mcf}) 4/15/2008 to 4/15/2008 2.81 Ib/day � 0.01941{Ib/mmBtu}* 143.962(mcf/day}* . 1006.2{Btu/scf}*(1{scf}/1000{mcf}) 4/16/2008 to 4/16/2008 2.61 Ib/day � 0.01941{Ib/mmBtu}* 133.527{mcF/day}* 1006.2{Btu/scf}*(1{scf}/ 1000{mcf}) 4/17/2008 to 4/ll/2008 � 2.67 Ibjday �� 0.01941{Ib/mmBtu}* 136.66901{mcf/day}* 1006.2{Btu/scf}*(I(sct}/1000{mcf}) � 4/18/2008 to 4/18/2008 2.42 Ib/day � 0.01941{ib/mmBtu}' 124.114{mcf/day}* � 1006,2{Btu/scf}*(1{scf}/1000{mcf}) 4/19/2008 to 4/19/2008 . 2.66 Ib/day �. ]� 0.01941{Ib/mmBtu)* 135.989{mcryday}* � 1006.2{Btu/scf}*�i{scr}/i000{mcf}� � 4/20/2008 to 4/20/2408 2.59 Ib/day � 0.01941(Ib/mmBtu}* 132.368{mcF/day}* 1006.2{Btu/scF}*(1{scf}/1000{mcf}) 4/21/2008 to 4/Zl/2008 . 2.64 Ib/day � � 0.01941{Ib/mmBtu}* 134994{mcf/day}* � . � 1006.2{Btu/scf}*(1{scf}/ 1000{mcf}) 4/22/2008 to 4/22/2008� 2.57 Ib/day J�:' 0.01941(Ib/mmBtu}* 131.4{mcf/day}* � iooe.z{ecu/scf}*�i{scr}/ i000{mcr}) � 4/23/2008 to 4/23/2008 2.66 Ib/day � 0.01941{ib/mmBtu}* 136.299{mcf/day}* . � 1006.2{Btu/scf}*(1{scf}/1000{mcf}) 4/24/2008 to 4/24/2008 2.81 Ib/day � . 0.01941{Ib/mmBtu}* 143.75999{mcryday}* 1006.2{Btu/scF}*(i{scF}/1000(mcf}) � � . 4/25/2008 to 4/25/2008 2J0 la/day � 0.01941{Ib/mmBtu)* 13832001{mcf/day}* i � � . 1006Z{Btu/scf}*(1{scF}/ S000{mcF}) 'I __._ _. . . .. .._ . ...._ .._.__ . _�_. � l Equipment Emission Detail Fort Lupton,EU-31,5/N 250451,AIRSID: 123/0057/013-4/1/2008to 4/30/2008 Report Date: Wednesday, February 6,2013 1:55 PM � Records 86 to 113 of 150, Page 4 of 6 . Type Cate9ory Compound Emission Period Amount Units � Estimated Emission Calculation Actual Standard � � PM10 4/26/2008 to 4/26/2008 � 2.65 Ib/day � r 0.01941{Ib/mmBtu}* 135.436{mcf/day}* � 1006.2{Btu/scf}*(1{scf}/1000{mcf}) 4/27/2008 to 4/27/2008 2.64 Ib/day � ]� 0.01941{Ib/mm8tu}* 135.11301{mcf/day}* � 1006.2(Btu/scf}*(1{scf}/ S000{mcf}) � 4/28/2008 to 4/28/2008 Z.53 Ib/day � 0.01941{Ib/mmBtu}* 129.711{mcryday}* � ' 1006.2{Btu/scf}*(1{scf}/1000{mcf}) 4/29/2008 to 4/29/2008 � 2.58 Ib/day � 0.01941{Ib/mmBtu}* 131.84599{mcF/day}* � � - 1006.2{Btu/scf}*(1(scF}/ 1000{mcf}) � 4/30/2008 to 4/30/2008 276 �b/day � 0.01941{Ib/mmBtu}* 141.57201{mcFjday}* � . 1006.2�{Btu/scf}*(1{scF}/ 1000{mcfy) � PM30 TotaL• � � 79.63 �(2.65 average) �i � PMZ.S � �+�4 . 4/1/2008 to 4/1/2008 2.60 Ib/day � 0.019�Yi{Ib/mmBtu}* 133.14 tmcF/day}* � . � 1006.2{Btu/scF}* (1{scF)/ S000{mcf}) � - 4/2(2008 to 4/2/2008 2.64 Ib/day � 0.01941{Ib/mmBtu}* 135.407{mcf/day}* . � � 1006:2(Btu/scf}*(1{scF}/ S000{mcf}) . 4/3/2008 to 4/3/2008 2.81 Ib/day � 0.01941{Ib/mmBtu}* 144.03101{mcf/day}* � � . 1006.2{Btu/scf}*(1{scf}/ 1000{mcf}) 4/4/2008 to 4/4/2008 2.70 IbJday � 0.01941{Ib/mmBtu}* 138.282{mcf/day}* � 1006.2{Btu/scf}*(1(scf}/1000{mcf}) 4/5(2008 to 4/5/2008 2J0 Ib/day � 0.01941{Ib/mmBtu}* 138.14101{mcf/day}*� . � � 1006.2{Btu/scf}*(1{scf}/ 1000{mcF}) 4/6/2008 to 4/6/2008 2.63 Ib/day (- 0.01941{Ib/mmBtu}* 134.825{mcf/day}* . . 1006.2{Btu/scf}*(1{scF}/ S000(mcfy) � 4/7/2008 to 4/7/2008 . L73 Ib/day ��. 0.01941{Ib/mmBtu}* 139.77{mcF/day}* � � � 1006.2(Btu/scf}*(1{scF}/ S000{mcf}) � 4/8/2008 to 4/8/2008 - 2J5 Ib/day (- 0.01941{Ib/mmBtu}* 141.03{mcf/day)* . . � � . 1006.2{Btu/scf}*(1{scF}/ 1000{mcf}) � 4/9/2008 to 4/9/2008 2.54 Ib/day � 0.01941{Ib/mmBtu}* 130105{mcf/day}* . 1006.2{Btu/scf}*(1{scf}/ S000{mcf}) 4/10/2008 to 4/10/2008 2.55 Ib/day � 0.01941{Ib/mmBtu}* 130.423{mcf/day}* � � � 1006.2{Btu/scf}* (1{sct}/1000{mcf}) 4/11/2D08 to 4/11/2008 2.65 Ib/day � 0.01941{Ib/mmBtu}* 135.48801{mcF/day}* � . � � 1006.2<Btu/scf�*(1{scf}/ 1000{mcF}) 4/12/2008 to 4/12/2008 � 2.64 Ib/day � OA1941{Ib/mmBtu}* 135.40199{mcF/tlay}* iooe.z{etu/scr}*(i{sct}/ i000<mcf}) . 4/13/2008 to 4/13/2008 � -2.64 ib/day � 0.01941{ib/mmBtu}* 13538699{mcf/day)* � � � 1006.2{Btu/scf}*(1{scF}/1000{mcf}) 4/14/2008 to 4/14/2008 2.75 Ib/day � 0.01941{Ib/mmBtu}* 140.819{mcf/day}* 1006.2{Btu/scf}*(1(scf}/ 1000{mcf}) � � 4/15/2008 to 4/15/2008 2.81 Ib/day � 0.01941{Ib/mmBtu}* 143.962{mcf/day}* � 1006.2(8tu/scf}*(1{scf}/ 1000{mcFy) � 4/16/2008 to 4/16/2008 2.61 Ib/day � 0.01941{Ib/mmBtu}* 133.527{mcryday}* ioo5.z{ecu/scf}*�i{scr}/ i000{mcF}� - 4/ll/2008 to 4/17/2008 2.67 Ib/day � -0.01941{ib/mmBtu}* 136.66901{mcF/day}* � � � 1006.2{Btu/scf}*(1{scf}/ 1000{mcF}) 4/18/2008 to 4/18/2008 2.42 Ib/day [- 0.01941{Ib/mmBtu}* 124.114{mcf/day}* �� - . 1006Z{Btu/scf}*(1{scf}/ S000{mcF}) � 4/19/2008 to 4/19/2008 2.66 Ib/day � 0.01941{Ib/mmBtu}* 135.989{mcf/day}* � 1006.2{Btu/scf}�*(1{scF}/ 1000{mcf}) � 4/20/2008 to 4/20/2008 2.59 Ib/day r 0.01941{Ib/mmBtu}* 132368{mcf/day}* � � 1006.2{Btu/scf}*(1{scf}/ S000{mcf}) � � � 4/21/2008 to 4/21/2008 2.64 Ib/day (� 0.01941{Ib/mmBtu}* 134.944{mcf/day}* * 1000 m 1006.2{Btu/scf} (1{scF}/ { cF}) 4/22/2008 to 4/22/2008 2.57 Ib/day . � 0.01941{Ib/mmBtu}* 131.4{mcF/day}* . � � 1006.2{Btu/scf�*(1{scF}/ 1000{mcf}) . 4/23j2008 to 4/23/Z008 2.66 Ib/day � 0.01941{Ib/mmBtu}* 136.299{mcf/day}* iooa.z{atu/scr}*(i{scF}/ i000<mcr}� EC�U9p111e11t EPT99SS901'9 De�dif � Fort Lupton,EU-31,5/N 250451,AIRS ID: 123/0057/013-4/1/2008 to 4/30/2008 - Report Date:Wednesday, February 6,2013 1:55 PM � . - Records 114 to 141 of 150, Page 5 of 6 Type Category Compound Emission Period Amount Units Estimated Emission Calculation Actual . Standard �� PM2.5 4/24/2008 to 4/24/2008 2.81 Ib/day � 0.01941{Ib/mmBtu}* 143.75999{mcf/day}* � � 1006.2{Btu/scf}*�i{scF}/i000{mcf}� � i 4/25/2008 to 4/25/2008 2J0 Ib/day � 0.01941{Ib/mmBtu}* 13832001{mcf/day}* t { �� n�� - �� < 1006.2{Btu/ecF}*(1{scF}/ 1000{mcF}) ``�1,l ` ��4��¢�A8 Co 4/26/2008 � 2.65 Ib/day � �' OA1941(Ib/mmBtu}* 135.436{mcryday}* iw1tQ�� ioo6.z{stu/scr}*�i{sa}/i000{mc�}> � ��%��,t;y� �^lr 4/27/2008 to 4/Z7/2008 2.64 Ib/day. � 0.01941{Ib/mmBtu}* 135.11301{mcf/day}* � �� 1006.2{Btu/scf}*(1{scF}/1000{mcf}) r. ;'� �t�� C)1�✓ 4/28/2008 Co 4/28/2008 � 2.53 Ib/day �° 0.01941(Ib/mmBtu}* 129.7ll{mcf/day}* ��-� ; ioo5.z{stu/scF}*�i{scf}/i000{mcr}� � - , 4/29/2008 to 4/29/2008 � 2.58 �Ib/day �' 0.01941{Ib/mmBtu}* 131.84599{mcQday}* � 1006.2{Btu/scF}*(1{scf}/ i000{mcf}) . 4/30/2008 to 4/30/2008 276 Ib/day � 0.01941{ib/mmBtv}* 141.57201{mcf/day}*. . � 1006.2{Btu/scf}*(1{scf}/ 1000{mcf}) � PM2.57oWL• � 79.63 (2.65average) � . � VOC 4/1/2008 to 4/1/2008 36.84 Ib/day ,�` 0.2�5{Ib/mmBtu}* 133.14{mcf/day}* 10062 , � � � {Btu/scf}*(1{scf}/ 1000{mcf}) � 4/2/2008 to 4/2/2008 37.47 Ib/day � 0.275{Ib/mmBtu)* 135.407{mcF/day}* 1006.2(Btu/scf}*(1{scf}/ 1000{mcf}) � 4/3/2008 to 4/3/2008 39.85 Ib/day ;� 0175{Ib/mmBtu}* 144.03101{mcf/day}* 1006.2{Btu/scF}*(1{scF}/1000{mcf}) 4/4/2008 to 4/4/2008� 38,26 Ib/day � O.DS{Ib/mmBtu}* 138.282{mcf/day}* . � . � � 1006.2{Btu/scf}*(1{scf}/1000{mcf}) _ 4/5/2008 to 4/5/2008 3822 Ib/day � 0.275{Ib/mmBtu}* 138.14101{mcf/day}* . � � � 1006.2{Btu/scf�*(1{scf}/1000{mcf}) � . � 4/6/2008 to 4/6/2008 37.31 Ib/day � � 0.275{Ib/mmBtu}* 134.825{mcf/day}* - � 1006.2{Btu/scf}*(1{scF}/ S000{mcf}) 4/7/2008 to 4/7/2008 . 38.68 Ib/day {"' 0.275{Ib/mmBtu}* 139J7{mcf/day}* 1006.2 {Btu/scf}*(1{scf}/ S000{mcf}) � � � 4/8/2008 to 4/8/2008 39AZ Ib/tlay � � 0.275{Ib/mmBtu}* 141.03{mcf/day}* 1006.2 � � {Btu/scF}*(1{scf}/1000{mcf}) 4/9/2008 to 4/9/2008 � 36.00 Ib/day �� 0.275 Qb/mmBtu}* 130.105{mcF/day}* iooa.z{atu/sct}*�i{scf}/i000<mc�}> . 4/SO/2008 to 4/10/2008 36.09 Ib/day � 0.275{�b/mmBtu}* 130.423{mcf/day}* � � 1006.2{Btu/scf}*(1{scfi}/ S000{mcf}) . 4/11/2008 to 4/11/2008 37.49 Ib/day � 0.275(Ib/mmBtu}* 135.48801{mcryday}* � . � � 1006.2{Btu/scF}*(1{scf}j S000{mcF}) 4/12/2008 to 4/12/2008 37,47 Ib/day � 0.275{Ib/mm6tu}*135.40199{mcryday}* . i006.2{Btu/scf}*(1{scf}/1000{mcfy) 4/13/2008 to 4/13/2008 37.46 Ib/day � 0.275(Ib/mmBtu}* 135.38699{mcf/day}* . � 1006.2{Btu/scf}*(1{scf}/1000{mcF}) � 4/14/2008 to 4/14/2008 38.97 Ib/day j� 0.275{Ib/mmBtu}*140.819{mcf/day}* . � 1006.2{Btu/scf}*(i(scF}/ 100Q{mcf}) . � � 4/15/2008 to 4/15/2008 � 39.84 Ib/day � 0.275(Ih(mmBtu}*143.962{mcf/day)* 1006.2{Btu/scF}*(1{scf}/ S000(mcf}) 4/16/2008 to 4/16/2008 36.95 Ib/day � 0.275{Ib/mmBtu}*133.527{mcf/day}* � � 1006.2{Btu/scf}*(1{scf}/1000{mcF}) 4/17/2008 to 4/17/2008 37.82 Ib/day ].� OZ75{Ib/mmBtu}*136.66901(mcF/day}* 1006.2{Btu/scf}*(1{scf}/1000{mcf}) � 4/18/2008 to 4/18/2008 3434 Ib/day jy 0.275{Ib/mmBtu}*124.114{mcf/day}* ioo5.z{stu/scr}*�i{scF}/ i000 tmcf}� 4/19/2008 to 4/19/2008 37.63 �b/day � 0.275{Ib/mmBtu}*135.989{mcf/day}* � 1006.2{Btu/scf}*(1{scf}/1000{mcF}) 4/20/2008 to 4/20/2008 36.63 Ib/day j� 0.275{�b/mmBtu}*132.368{mcf/day}* � � 1006.2{Btu/sct}*(1{scF}/ 1000{mcF}) � 4/21/20p8 to 4/21/2008 37.34 Ib/day � ]W O.DS{Ib/mmBtu}*134.944(mcF/day}*� � - �� 1006.2{Btu/scf}*(1{scF}/ 1000{mcf}) • Kerr-McGee/Anadarko Pei� ole'L�� C� rp6� ation��; I Cu[, }� `�� Permit No. 97WE0180 , � � k r�oloraa> DeK �rf"nent�rf Public Health and Environment � Issuance 1 i � � � �'�� f '" "� � d �; Air Pollution Control Division �s��r� t ��t� ��i f � W. � _b � �. �� . 4) The emission levels contained in this permit are based on the following emission factors: Points 013 and 030: Emission Factors - Emission Factors— Uncontrolled Controlled CAS Pollutant Ib/MMBtu %bh -hr Ib/MMBtu /bh -hr NOx 4.4092 16.0000 0.6889 L�, 2.5000 CO 7J162 28.0000 1.5157 � 5.5000 VOC 0.2756 1.0000 02756 ✓ 1.0000 5000 Formaldeh de 0.0239 0.0869 0.0239 0.0869 67561 Methanol 0.0031 0.0111 0.0031 0.0111 75070 Acetaldeh de 0.0009 0.0033 0.0009 0.0033 107028 Acrolein 0.0026 0.0095 0.0026 0.0095 71432 Benzene 0.0032 0.0116 . 0.0032 0.0116 106990 1,3-Butadiene 0.0007 0.0024 0.0007 0.0024 108883 Toluene 0.0006 0.0020 0.0006 0.0020 Emission factors are based on a Brake-Specific Fuel Consumption Factor of 8000 Btu/hp-hr, a site-rated horsepower value of 954, and a fuel heat value of 908 Btu/scf. Emission Factor Sources: CAS Pollutant Uncontrolled EFSource Controlled EF Source NOx Manufacturer's Data Manufacturer's Data CO Manufacturer's Data Manufacturer's Data VOC Manufacturer's Data No Control 5000 Formaldeh de Manufacturer's Data No Control 67561 Methanol AP-42; Table 3.2-3 (7/2000); No Control Natural Gas 75070 Acetaldehyde Previous Issuance of this No Control Permit 107028 Acrolein AP-42; Table 3.2-3 (7/2000); No Control Natural Gas 71432 Benzene Previous Issuance of this No Control Permit 106990 1,3-Butadiene AP-42; Table 3.2-3 (7/2000); No Control Natural Gas 108883 Toluene AP-42; Table 3.2-3 (7/2000); No Control Natural Gas 5) In accordance with C.R.S. 25-7-114.1, the Air Pollutant Emission Notice (APEN) associated with this permit is valid for a term of five years. The five-year term for this APEN expires on February 9, 2016. A revised APEN shall be submitted no later than 30 days before the five-year term expires. 6) This facility is classified as follows Applicable Requirement Status Operating Permit Major Source of NOX, VOC, CO, and HAP PSD Major Source of CO AIRS ID: 123/0057/013 and 030 Page 11 of 18 Table 3.2-3. iJNCONTROLLED EMISSION FACTORS FOR 4-STROKE RICH-BURN ENGINESa (SCC 2-02-002-53) Emission Factor (1b/MMBtu)b Emission Factor Pollutant (fuel input) Rating Criteria Pollutants and Greenhouse Gases NOx°90 - 105%Load 2.21 E+00 A NOx�<90% Load 2,27 E+00 C CO° 90 - 105°/o Load 3.72 E+00 A CO°<90%Load 3 S 1 E+00 C C�2d 110 E+02 A SO2� 5.88 E-04 A TOCf 3.58 E-01 C Methaneg 2.30 E-01 C VOCh 2.96 E-02 C � rV� � PM10 filterable ''� s��2<^t�.��_ ��r �.'i��cx�'��,�vin� . � ) 9.50 E-03 E _ �r; PM2.5 (fiiterable)� 9.50 E-03 g �,��ri u k �: u� ��4 __ � ;`, �c��t i PM Condensable 9.91 E-03 E ��'�h4q��,� Trace Organic Compounds 1,1,2,2-Tetrachloroethane� 2.53 E-0S C 1,1,2-Trichloroethane� <1.53 E-0S E 1,1-Dichloroethane <1.13 E-0S E 1,2-Dichloroethane <1.13 E-0S E 1,2-Dichloropropane <1.30 E-0S E 1,3-Butadiene� 6.63 E-04 D 1,3-Dichloropropene <1.27 E-05 E Acetaldehyde�'"' 2.79 E-03 C Acrolein�'"' 2.63 E-03 C Benzenel 1.58 E-03 B Butyr/isoburyraldehyde 4.86 E-0S D Carbon Tetrachlorida <1.7I E-0S E 7/00 Stationary Internal Combustion Sources 3.2-15 ___ _- _ �� ,� � r �� E,F �� .�� . � � � �� 1 � � „��. , ,�i, �_ , t � Equi�sment Erv�issiora Detail ��'' �� -`��a.. � Fort Lupton,EU-35,S/N 38DS8750-45S1510,AIRS ID: 123/0057/007-4/1/200S to 4/30/2008 Report Date: Wednesday, February 6,2013 1:56 PM � Records 1 to 20 of 180, Page 1 of 30 Type Category Compound Emission Period Amount Units Estimated Emission Calculation � Actual Standard Carbon Monoxide � j � 1 �;�� 4/1/2008 to 4/1/2006 � 161.04 Ib/day V� � 0.71{Ib/mmBtu}*225.42599{mcfi/day}* . _ . -� -� �--- i � � - 1006.2{Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � � {mntrolled}_ 'Y',(1-O), 1) � -� � �„�. �\� �� -1�',' 4/2/2008 Co 4/2/2008 160.91 Ib/day � OJl{Ib/mmBw}�225.242(mcfi/tlay}* 1006.2 f��` � '�` � ��z � (BCu/scF}*(1(scF}/ lOW{mcf})*If('Y' . (controlled}_'Y',(i-0), 1) ' � r��' ; -, �\ 4/3/2008 to 4/3/2008 190.49 Ib/day � OJl{Ib/mmBtu}*266.63699{mcryday}* �i'w' Y . �� lu�f,��, . � �, - I . 1006.2{Btu/scf}*(1{scf}/1000{mcf})*If('Y' � (wntrolled}_'Y', (1-0), 1) � �f_, 2,., � � , �� 4/4/2008 to 4/4/2008 179.09 Ib/day �. 0.71{Ib/mmBtu}*250.688{mcQday}* 1006.2 � �- r , �{'i,� � ' ��.G 'i� {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' ' {controlled}='Y',(1 -0), 1) + ��('� � - �;'"( G�u� ��L'-��z '4/5/2008 to 4/5/2008 169.50 Ib/day �; OJl{Ib/mmBtu}*237.258{mcf/day}* 10062 . .,, � � {Btu/scF} (1(scf}/ 1000{mcf}) If('Y' �� i {mntrolled} ='Y',(1-0), 1) � ,,. '/ ��i�)i«;' - i'� '; �4/6/2008 to 4/6/2008 158.45 Ib/day � OJl{Ib/mmBtu}*221J95{mcF/day}* 1006.2 ! � `�` ' " " ' � � � � {stu/sct}*(1{sct}/ 1000{mc�})*iF('Y' � � ' � {controlled}_ 'Y',(1-0), 1) �� --� � ��"-��---�� ---' 4/7/2008 to 4/7/2008 182.98 Ib/day ,� . OJS{Ib/mmBtu}*25613599{mcf/day}* ` iooe.z{etu/scr}��i{scr}/i000{mcf}�*if��r � � (controlled}='Y',(1-0), 1) � 4/8/2008 to 4/8/2008 18637 Ib/day � OJS{Ib/mmBtu}*260.88199{m6/day}* � � 1006.2{Btu/scf}*(1{scf}/ 1000{mcF})*If('Y' � . (controlled}='Y',(1-0),�1) 4/9/2008 to 4/9/2008 � 139J5 Ib/day � OJi{Ib/mmBtu}* 195.612{mcryday}* i006.2 {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � � � {controlled} ='Y',(1-0), 1) 4/10/2008 to 4/10/2008 188.29 Ib/day ,�' 071{Ib/mmBtu}*263.56699{m6/day}* . � � 1006.2{Btu/scfy'(1{scf}/1000{mcf})*If('Y' � � {mntrolled} ='Y',(1-0), i) � 4/11/2008 to 4/11/2008 1B6.24 Ib/day � OJS{Ib/mmBtu}*260.70001{mcryday}* . ioo5.z<stu/scr}*�i{scFy/i000{mc��*ir��r� � (controlled}= 'Y',�(1-0), 1) 4/12/2008 to 4/12/2008 � 16910 Ib/day � OJl{Ib/mmBtu}*236J03{mcf/day}* 1006.2 � . {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � � � . � {controlled}= 'Y',(1 -0), 1) � . . . 4/13/2008 to 4/13/2008 174.22 Ib/day � OJl{Ib/mmBtu}*243.862{mcf/day}* 1006.2 {Btu/scf}*(1{scf}/ 1000{mcF})*If('Y' 4/14/2008.to 4/14/2008 185.00 Ib/da {�ontrolled} ='Y',*(1-0), 1) * y � OJl{Ib/mmBtu} 258.951{mcf/day} 10061 � � {Btu/scF}-*(1{scf}/ 1000 tmcfy)*If('Y' {controlled} ='Y',(1-0), 1) � � . 4/15/2008 to 4/15/2008 184.67 Ib/day � 0.71(Ib/mmBtu}*258.49701{mB/day}* � . 1006.2{Btu/scf}* (1{scf}/1000{mcf})*If('Y' � � � {controlled} ='Y',(1-0), 1) 4/16/2008 to 4/16/2008 162.58 Ib/day � 0.71{Ib/mmBtu}*227,575{mcf/day}* ].006.2 {Btu/scF}*(i{scf)/ 1000{mcF})*If('Y' � {wntrolled}='Y',(1-0), 1) � 4/17/2008 to 4/17/2008 172.57 Ib/day � 0.71{Ib/mmBtu}*241.55701{mcf/day}* . . 1006.2{Btu/scf}*(1{scf}/1000{mcf})*If('Y' � � {controlled}='Y',(1-0), 1) 4/18/2008 to 4/18/2008 151.91 Ib/day � 0.71(Ib/mmBtu}*212.634(m6/day}*�1006.2 - � . (Btu/scF}*(1{scf}/ S000{mcf})*If('Y' . {controlled}='Y',(1-0), i) 4/19/2008 to 4/19/2008 � 166.51 Ib/day ,� OJl{Ib/mmBtu}*233.075{mcryday}* 1006.2 � - (Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' . {controlled}= 'Y', (i -O), 1) 4/20/2008 to 4/20/2008 142.97 Ib/day � � OJS{Ib/mmBtu}*200.129{mcf/day}*1006.2 . : {Btu/scf}*(1{scf}/ S000{mcf})*If('Y' � {controlled}='Y', (1-0), 1) . ....__._._.. . � _ — Equipment Emission Detail � Port Lupton,EU-35,S/N 3SD58750-45SiS10,AIRS ID:123/0057/007-4/1/2008 to 4/30/2008 Report Date:Wednesday, February 6, 2013 1:56 PM � � Remrds 40 to 59 of 180, Page 3 of SO � Type Category Compound Emission Period� Amount Units Estimated Emission Calculation � Actual �Standard � - �, - � . NitrogenOxides , / �b � 4/10/2008 to 4/10/2008 . 326.20 Ib/day r 1.2�{Ib/mmBtu}*263.56699{mcf/day}* . 1006.2{Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � . {controlled}_'Y',(1-0), 1) - 4/11/Z008 to 4/11/2008 322.65 Ib/day � 1.23{Ib/mmBtu}*260.70001{mcf/day}* 1006.2{Btu/scf}*(1{scF}/ S000{mcf})*If('Y'� {controlled}='Y',(1-0), 1) 4/12/2008 to 4/12/2008 �292.95 Ib/day � 1.23{Ib/mmBtu}*236.703{mcf/day}* 1006.2 . � � {Btu/scf}*(1{scf}/ 1000(mcf})*If('Y' . � 4/13/2008 to 4/13/20D8 301.81 Ib/da {controiled}= 'Y',*(1-0), 1) . * y � 1.23{Ib/mmBtu} 243.862{mcf/day} 1006.2 � - {Btu/scf}*(1{scf}/1000{mcf})*If('N � � �� (controlled)= 'Y',(1-0), 1) 4/14/2008 to 4/14/2008 320.48 Ib/day � 1.23{Ib/mmBtu}*Z58.951{mcF/day}* 1006.2 � . � {Btu/scF}*(1�{scf}/1000{mcf})*If('Y' � {controlled}='Y',(1-0), 1) .4/15/2008 to 4/15/2008 31992 Ib/day f�` 1.23{Ib/mmBtu}*258.49701{mcf/day}* . - 1006.2{Btu/scF}*�i{scr}/i000{mc�}�•ir��r � ��.�'Zj��`'`� � {conCrolled}='Y',(1�-0), 1) � , '� � 4/16/2008 to 4/16/2008 281.65 Ib/day j" . 1.23{Ib/mmBtu}*227.575{mcF/day}* 1006.2 � � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' N;p �r �; v ��,il) � {controued}_�r,�i-o�, i� � '�� I �. 4/17/2008 to 4/17/2008 298.96 Ib/day �' 1.23{Ib/mmBtu}*241.55701{mcf/day}* �� `��f t Q��"�� ioo5z{stu/scr}*�i{scF}/i000{mcr}�*iF��r � 1�J �h�U-S�'U�� . {controlled}='Y',(1�-0), 1) � � 4/18/2008 to 4/18/2008 26316: Ib/day � 1.23{Ib/mmBtu}*212,634{mcf/day}* 1006.2 � � � . {Btu/scf}*(I{scf}/ 1000{mcf})*If('Y' � � ,{controlled}_ 'Y',(1-0), 1) � � � 4/19/2008 to 4/19/2008 288.46 Ib/day � 1.23(Ib/mmBtu}*233.075{mcf/day}* 1006.2 . � � . (Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � {controlled}_ 'Y',(1 -0), 1) � � 4/20/2008 to 4/20/2008 247.68 Ib/day (,� .1.23{Ib/mmBtu}*200129{mcF/day}* 1006.2 {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' {mntrolled}='Y',(1-0),1) 4/21/2008 to 4/21/200S 273.84 Ib/day � 1.23(Ib/mmBtu}*221.26199{mcF/day}* � , 1006.2{Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' . .tcontrolled)='Y',(1-0), 1) 4f22/Z008 to 4/22/2008 260.03 Ib/day � � 1.23{Ib/mmBtu}*210.1{mcf/day}* 1006.2 � � . {Btu/scF}*(1{scf}/ 1000{mc )*If('Y' � (controlied}='Y',(1-0), 1) . 4/23/2008 to 4/23/2008 262.46 Ib/daV � 1.23{Ib/mmBtu}*212.07{mcf/day}* 1006.2 � . . {Btu/scf}*(1{scf}/1000(mcf})*If('Y' 4/24/2008 to 4/24/2008 334.21 16/da {controlled}_'Y',*(1-0), 1) * y � 1.23{Ib/mmBtu} 270.04001{mcf/day) . � � � 1006.2{Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' {controiled}='N,(1-0), 1) . 4/25/2008 to 4/25/2008 330.20 Ib/day j� L23{Ib/mmBtu}.*266.80399{mcf/day}* �" 1006.2{Btu/scf}*(1{scfy/1000{mcf})*If('Y' . . , � � {contralied} ='Y', (1-0), 1) 4/26/2008 to 4/26/2008 317.62 Ib/day � 1.23{Ib/mmBtu}*256.633(mcf/day}* 1006.2 . . {Btu/scf}*(1(scf}/ 1000{mcf})*If('Y' . - {contralled} ='Y', (1-0), i) . . 4/27/2008 to 4/27/2008 289A2 Ib/day � 1.23{ib/mmBtu}*233.528{mcf/day}* 1006.2 � � � � � {Btu/scf}*(1{scF}/S000(mcf})*If('Y' � � {controlled} ='Y', (1-0),.1) � - . 4/28/2008 to 4/28/2008 305.77 Ib/day �' SZ3{Ib/mmBtu}*247.063{mcF/day}* 1006.2 {Btu/scf}*(1(scf}/ 1000{mcf)) *If('Y' � - {contralled} ='Y', (1-0), 1) 4/29/2008 to 4/29/2008 304.26 Ib/day � � i.23{Ib/mmBtu}*245.838{mcryday}* 1006.2 � � {Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' . {cantrolled}='Y',(1-0), 1) . _._ . . __. . . __.. � � � � � ..._ . .. ..._. . __. . .. . . _ ... . ... .. .. . . . . ._. . __.. __. . Equipment Emission Detail Fort Lupton,EU-35,S/N 38D58750-4551S10,AIRS ID: 123/0057/007-4/1/2008 to 4/30/2008 - Report Date: Wednesday, February 6, 2013 L56 PM � Remrds 79 to 97 of 180, Page 5 of 10� Type Category Compound Emission Period Amount Units Estimated Emission Calculation � Actual . � � � Standard _ . � `;.�� PM l�� 4/19/2008 to 4/19/2008 � 12.90 Ib{day � O.OSS{Ib/mmBtu}*233.075{mcf/day}* � . 1006.2{Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' . � . � � {controlled}='Y',(1-0), 1) � 4/20/2008 to 4/20/2008 11.08 Ib/day � � 0.055{Ib/mmBtu}*200129{mcf/day}* . . . 1006.2{Btu/scf}*(1{scf}/ S000(mcf})*If('Y' � � � {controlled}= 'Y', (1-0), 1) � - � 4J21/2008 to 4/21/2008 12.24 Ib/day (� 0.055{Ib/mmBtu}*221.26199{mcf/day}* 1006.2{Btu/scf}* (1(scF}/ 1000(mcf})*If('Y' � � {controlled}='Y',(1-0), 1) 4/22/2008 to 4/22/2008 11.63 Ib/day � 0.055{Ib/mmBtu}*210.1{mcf/day}* 100fi.2 � � � � {Btu/scf}*(1{scf}/1000{mcf})*If('Y' � {controlled}_ 'Y', (1-0), 1) � 4/23/2008 to 4/23/2008 11J4 Ib/day � 0.055{Ib/mmBtu} *212.07{mcf/day}* 1006.2 � {Btu/scF}*(1(scf}/ 1000{mcf}) *If('Y' . � {controlled}= 'Y', (1 -0), 1) . 4/24/2008 to 4/24/2008 14.94 Ib/day � 0.055{Ib/mmBtu}*270.04001{mcf/day)* � � . � i006.2{Btu/scf}*(1{scF}/ 1000{mcf})*If('Y' � � � � {controlled}='Y',(1-0), 1) 4/25/2008 to 4/25/2008 14J7 Ib/day � 0.055{Ib/mmBtu}*266.80399{mcf/day}* 1006.2{Btu/scf}*(1{scf}/ 1000(mcf}).*If('Y' � � � � . , {controlled}_ 'Y', (1-0), 1) � � 4/26/2008 to 4/26/2008 14.20 Ib/day � 0.055(Ib/mmBtu}*256.633(mcf/day}* . 1006.2{Btu/scF}*(1{scF}/ 1000{mcf})*If('Y' � � {controlled}='Y',(1-0), 1) 4/27/2008 to 4/27/2008 12.92 Ibjday � 0.055{Ib/mmBtu}*233.528{mcf/day}* � � � 1006.2{Btu/scf}*(1{scF}/ 1000{mcf})*If('Y' � . _ � � {coMrolled} ='Y',(1-0), 1) � � � 4/28/2006 to 4/28/2008 13.67 Ib/day � � 0.055{Ib/mmBtu)*247.063{mcf/day}* . . 1006.2{Btu/scf}*(1{scF}/ 1000(mcf})*If('Y' . {controlled}= 'Y', (1 -0), 1) � � 4(29/2008 to 4/29/2008 13.60 Ib/day � 0.055{Ib/mmBtu}*245.838{mcF/day} * � � . 1006.2(Btu/scf}*(1(scf}/ 1000{mcf})*If('Y' � {controlled}='V',(1-0), 1) � � � 4/30/2008 to 4/30/2008 14.59 Ib/day �. OA55{Ib/mm8tu}*263.55701{mcf/day}* . � . iooe.z{etu/scF}* �i{scr}/ i000{mcr}�*iF��r� {mntrolled}='Y',(1-0), 1) � PM TotaL � 398.67 (13.29 average) � . PM10 y� �`�� . � 4/1/2008 to 4/1/2008 12.46 Ib/day � 0.055{Ib/mmBtu}*225.42599(mcF/day}* iooe.z{etu/sc�}*(i{scf}/ i000{mcr}�*ir��r � _ {mntroiled}= 'Y', (1-O), 1) � - 4/2/2008 to 4/2/2008 12.47 Ib/day � 0.055{Ib/mmBtu}*225.242{mcF/day}* � � 1006.2{Btu/scF}* (1{scf}/ 1000{mcF})*If('Y' � � � {controlled} ='Y',(1-0), i) 4/3/2008 to 4/3/2008 14.76 Ib/day � 0.055{Ib/mmBtu}*266.63699{mcf/day}* � . 1006.2{Btu/scf}*(1{scf}/ 1000{mcF})*rf��r � {controlled}_'Y',(1 -0), 1) 4/4/2008 to 4/4/2008 13.87 Ib/day � 0.055{Ib/mmBtu}*250.688{mcF/day}* . . 1006.2{Btu/scf}*(1{scF}/ 1000{mcf})*If('Y' � {controlled}= 'Y', (1-0), 1) � � � 4/5/2008 to 4/5/2008 13.13 �Ib/day r � 0.055{Ib/mm8tu}*237.258{mcryday}* � � � . 1006.2{Btu/scF}* (1{scf}/ 1000{mcF})*If('Y' � . {controlled}='Y',(1-0), 1) � . 4/6/2008 to 4/6/2008 12.27 Ib/day � 0.055{Ib/mmBtu}*221J95{mcf/day}* � . � � . 1006.2{8tu/scf}*(1{scF}/ 1000{mcf})�*If('Y' � � {controlled}='Y',(1-0), 1) � 4/7/2008 to 4/7/2008 � 14.11 Ib/day � 0.055{Ib/mmBtu}*256.13599{mcf/day}* . � � 1006.2{Btu/scf)*(1{scf}/ S000{mcf})*If('Y' _ {mntrolled}_ 'Y', (1-0), 1) � Equipment Emission Detail Fort Lupton,EU-35,S/N 38DS8750-4551S30,AIRS ID: 123/0057/007-4/1/2008 to 4/30/2008 Report Date: Wednesday, February 6, 2013 1:56 PM - Records 137 to 155 of 180, Page 8 of 10 Type Category Compound Emission Period Amount Units Estimated Emission Calculation� � Actual � `� Standard . t 6�^'�� l�.fi"7�e`�,u3 '�:--�-,, `tf�.4n1 47-�� PM2.5 �Sfif 4/17/2008 to 4/17/2008 11.74 Ib/day� � 0.04831{Ib/mmBtu}*241.55701{mcf/day}* . � . � 1006.2{Btu/scf}*(1{scf}/1000{mcf})*If('Y' � {mntrolled} _'Y',(1-0), 1) . 4/18/2�08 to 4/18/2008 � 10.34 Ib/day j� 0.04831{Ib/mmBtu)*212.634{mcryday}* � � � . 3006.2{Btu/scf}*(i{scf}/1000{mcf})*If('Y' � � {controlled}=.'Y',(i-0), 1) . 4/19/2008 to 4/19/2008 11.33 Ib/day ,� 0.04831{Ib/mmBtu}*233.075{mcf/day}* � 1006.2{Btu/scf}*(1{scf}/ S000(mcf})*If('Y' � {controlled}='Y',(1-0), Y) � 4/20/2008 to 4/20/2008 � 9J3 Ib/day � 0.04831{Ib/mmBtu}*200.129{mcf/day}* iooe.z{stu/sc�}*�i{scr}/i000{mcr}��tf��r {contralled}='Y',(1-O), 1) � � 4/21/2008 to 4/21/2008 � lOJ6 Ib/day � 0.04831{Ib/mmBtu}*221.26199{mcf/day}* . . � 1006.2{Btu/scf}*(1{scF}/1000{mcf})*If('Y' � {controlled}='Y', (1-O), 1) 4/22/2008 to 4/22/2008 � 10.21 Ib/day � 0.04831{Ib/mmBtu}*210.1{mcf/day}* ioo6.z{stWscF}*�i<scf}/i000{mcr}�*iF��r � {controlled}='Y',(1 -0), 1) 4/23/2008 to 4/23/2008 10.31 Ib/day � 0.04831{Ib/mmBtu}*212.07{mcf/day}* 1006.2{Btu/scf}*(1{scF}/1000{mcf})*ir��r {controlled}='Y',(1 -0), 1) - 4/24/2008 to 4/24/2008 13.13 Ib/day � 0.04831{Ib/mmBtu)*U0.04001{mcf/day}* � ioo5.z{stu/scF}*�i{sct}/ iaoo{mc�}�*if��r . {controlled}='Y',(1-0), 1) . 4/25/2008to 4/25/2008 1L97 Ib/day ]� 0.04831{Ib/mmBtu}�*266.80399{mcF/day}* . . � . � 1006,2{Btu/scf}*(1{scF}/ 1000{mcF})*If('Y' - {mntrolled}='Y', (1 -0), 1) . 4/26/2008 to�4/26/2008 12.47 Ib/day � 0.04831{Ib/mmBtu}*256.633{mcf/day}* . � � 1006.2{Btu/scf}*(1(scF}�/1000{mcf})*If('Y' {controlled}='Y', (i -0), 1) 4/27/2008 to 4/27/2008 11.35 Ib/day � 0.04831{Ib/mmBtu}*233.528{mcf/day}* 1006.2{Btu/scf}*(1{scF}/ S000{mcf})*If('Y' � {mntrolled}='Y', (1 -0), i) 4/28/2008 to 4/28/2008 � 12.01 Ib/day �' 0.04831{ib/mmBtu}*247.063{mcf/day}* � � 1006.2{Btu/scf}*(1{scF}/1000{mcF})*If('Y' {controlled}='Y',(1-0), 1) 4/29/2008 to 4/29/2008 11.95 Ib/day � 0.04831{Ib/mmBtu}*245.838{mcf/day}* � � 1006.2{Btu/scf}*(1{scf}/1000{mcF})*If('Y' {controiled}='Y',(1 -0), 1) 4/30/2008 to 4/30/2008 12.81 Ib/day � 0.04831{Ib/mmBtu}*263.55701{mcF/day}_ � � . � 1006.2{Btu/scf}*(1 {scF}/ 1000{mcf})*If('Y' . {controlfed}='Y',(1 --0), 1) . . PM2.5 TOWL•� 350.11 (11.67 average) , , VOC ., ! Y�`s:L'.�>��u�S�f�'�- x.��`,��.a(u�;,. �Y[�}� . 4/1/2008 to 4/1/2008 61.24 Ib/day � 0.27{ib/mmBtu}*225.42599{mcf/day}* . 1006.2{Btu/scf}*(1{scF}/1000{mcf})*If('Y' (controlled}= 'Y',(1-0), 1) 4/2/2008 to 4/2/2008 61,19 Ib/day � 0.27{Ib/mmBtu}*225.242{mcF/day}* 1006,2 �{Btu/sct}*(1{scf}/ 1000{mcf})*If('Y' � {controlled}= 'Y',(1-0), 1) � 4/3/2008 to 4j3/20D8 . � R.44 Ib/day � O.Z7{Ib/mmBt�u}*266.63699{mff/day}* � � 1006.2{Btu/scf}*(1{scf}/ 1000{mcfy)*If('Y' � {controlled}= 'Y',(1—0), 1) 4/4/2008 to 4/4/2008 . 68.11 � Ib/day � 0.27{Ib/mmBtu}*250.688{mcf/day}* 1006.2 � {Btu/scf}*(1 {scf}/ 1000{mcf})*If('Y' � � ` � {mntroiled)='Y',(1-0), 1) � 4/5/2008 to 4/5/2008 64.46 Ib/day � 0.27{Ib/mmBtu}*23AZ58{mcryday}* 1006.2 � {Btu/scf}*(1{scf}/ S000{mcf})*If('Y' _ � �{controlled}='Y',(1-0), 1) Equipenent Emission Detail � . Fort Lupton,EU-35,5/N 38DS8750-4551510,AIRSID: 123/0057/007-4/i/2008to4/30/2008 Report Date: Wednesday, February 6,2013 1:56 PM � Records 156 to 175 of 180, Page 9 of 10 Type Category Compound� Emission Period Amount Units Estimated Emission Calwlation � � . Actual Standard � - VOC 4/6)2008 to 4/6/2008 60.26 Ib/day � 0.27{Ib/mmBtu}*221.795{mcF/day}* 1006.2 {Btu/scF}*(1{scf}/ 1000(mcF})*If('V � � {controlled}_'Y',(1 -0), 1) � � 4/7J2008 to 4/7/2008 69.59 Ib/day � 0.27(Ib/mmBtu}*256.13599{mcF/day}* � 1006.2{Btu/scf}*(i{scrj/ i000{mcf}�*if��r � {controlled}='Y', (1-0), 1) 4/8/2008 to 4/8/Z008 70.87 Ib/day � 0.27{Ib/mmBtu}*260.88199{mcf/day}* � , . 1006.2{Btu/scf}* (1{scF}/ 1000{mcf})*If('Y' � . . {controlled}='Y',(1-0), 1) � � . 4/9/2008 to 4/9/2008 53.14 Ib/day � 0.27{Ib/mmBtu}* 195.612{mcf/day}* 1006.2 . � - . (Btu/scF}W(1{scf}/ 1000{mcf})*If('Y' . . � {controlled} ='Y',(1 -0), 1) � 4/10/2008 to 4/10/2008 71.60 Ib/day � 0.27{Ib/mmBtu}*263.56699(mcF/day}* 1006.2{Btu/scf}*(1{scF}/ 1000{mcf})*If('Y' � {controlled}_ 'Y', (1-0), 1) � 4/11/2008 to 4/11/2008 . 70.83 Ib/day � 0.27{ib/mmBtu}*26070001{mcf/day}* 1006.2{Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' � {controlled}.= 'Y', (1-0), 1) � 4/12/2008 to 4/12/2008 64.31 Ib/day � O.D{Ib/mmBtu}*236J03{mcF/day)* 1006.2 � {Btu/scF}*(1{scf}/ 1000{mcF})*If('Y' � . � . (controlied}_'Y',(1 -0), 1) �. � � 4/13/2008 to 4/13/2008 66.25 Ib/day � 0.27{Ib/mmBtu}*243.862{mc4/day}* 1006.2 � � � {Btu/scf}* (1{scf}/ 1000{mcf})*If('Y' � (mntrolled}='Y', (1-0), 1) 4/14/2008 to 4/14/2008 7035 Ib/day r 0.27{Ib/mmBtu}*258.951(mcf/day}* 1006.2 � � {Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' {controlied)='Y', (1 -0), I) � 4/IS/2008 to 4/15/2008 70.23 Ib/day . � 0.27(Ib/mmBtu}*258.49701{mcf/day}* � � 1006.2{Btu/scf}*(1{scF}/ 1000{mcf})*If('Y' � . {controlled}='Y', (1-0), 1) - 4/16/2008 to 4/16/2008 61.83 Ib/day � O.Z7{Ib/mmBtu}*227.575{mff/day}* 1006.2 � {Btu/scf}*�(1{scf}/ 1000{mcF})*If('Y' � {controlled} ='Y',(1-0), 1) . 4/ll/2008 to 4/17/2008 . 65.62 Ib/day � O.D{Ib/mmBtu}* 241.55701{mcf/day)* � . 1006.2{Btu/scF}* (1{scF}/ 1000{mcf})*If('Y' � . � {controlled}='Y',(1-0), 1) � . 4/16/2008 to 4/16/2008 57.77 Ib/day � 0.27{IblmmBtu}*212.634{mcyday}* 1006.2 . � {Btu/scf}*(1{scf}/ 1000{mcf))*If('Y' . � {conirolled)='Y', (1-0), 1) . � " 4/19/2008 to 4/19/2008 �6332 Ib/day � 0.2Z{Ib/mmBtu}*233.075{mcf/day}* 1006.2 � . {Btu/scF}* (1{scf}/ 1000{mcF}) *If('Y' - � � {controlled}_ 'Y', (1-0), 1) � � 4/20/2008 to 4/20/2008 54.37 Ib/day � 0.27{Ib/mmBtu}*200.129{mcryday}* 1006.2 . {Btu/scf}*(1{scfy/ S000{mcf})*If('Y' � - � � � {contralled} ='Y',(1-0), 1) � 4/21/2008 to 4/21/20�8 60.11 Ib/day j- 0.27{Ib/mmBtu}*221.26199{mcf/day}* � � � � 1006.2{Btu/scf}*(1{scF}/ 1000{mcf})*If('Y' � {mntrolled} ='Y', (1-0), 1) � - 4/22/2008 to 4/22/Z008 57.08 Ib/day {� 0.27{Ib/mmBtu}*2101{mcryday}* 1006.2 � � {Btu/scF}* (1{scf}/ 1000{mcf})*If('Y' . � {controlled}='Y',.(1-0), 1) � . - 4/23/2008 to 4/23/2008 57.61 Ib/day � 0.27{Ib/mmBtu}*Z12.07{mcryday}* 1006.2 � � (Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' � .� � . � {controlled}='Y',(1 -D), 1) � 4/24/2008 to 4/24{2008 7336 Ib/day � O.D(Ib/mmBtu}*270.04001{mcF/day}* � � � 1006.2{BtuJscf}*(1{scF}/ 1000{mcF})*If('Y'- � {controlled}='Y', (1-0), 1) � � � � � 4/25/2006 to 4/25/2008 72.48 Ib/day . � 0.27{Ib/mmBtu}*266.80399{mcf/day}* � � 1006.2{Btu/scf}* (1{scf}/ 1000{mcf})*If('Y' {controlled} ='Y',(1 -0), 1) � N , € g c 5_ u E y � O d g. _ , a. o.ia Sy^ v � a � m N o v N o" O .� � a �,� y U � � n' � � '° �.' 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PM2.5 (filterable) 3.84 E-02 C i,CC��;'�y '�' a L(��`?.� � . PM Condensable� 9.91 E-03 E ..��,:+,;j zE�."'_'y i � . €�:,iy� Trace Organic Compounds n;��,�''rU. � � 1,1,2,2-Tetrachloroethana 6.63 E-0S C 1,1,2-Trichloroethanek 5.27 E-0S C 1,1-Dichloroethane 3.91 E-0S C 1,2,3-Trimethylbenzene 3.54 E-0S D 1,2,4-Trimethylbenzene L ll E-04 C 1,2-Dichloroethane 422 E-0S D 1,2-Dichloropropane 4.46 E-0S C 1,3,5-Trimethylbenzene 1.80 E-0S D 1,3-Butadienek 8.20 E-04 D 1,3-Dichloropropenek 438 E-0S C 2,2,4-Trimethylpentana 8.46 E-04 B 2-Methylnaphthalenek 2.14 E-0S C Acenaphthenek 1.33 E-06 C 7/00 Stationary Intemal Combustion Sources 3.2-7 . / � �.� � -l�i! �( f �� .�.��vi 1 f I . _ _ J�\� i .<� � , Equipment Emission Detail � � Fort Wpton, EU-36,S/N 38DS7S0-2451512,AIRS ID: 123/0057/005-4/1/2008 to 4/30/2008 � Report Date: Wednesday, February 6, 2013 1:58 PM � Records i to 20 of 180, Page 1 of 10 Type Categoty Compound Emission Period Amount Units Estimated Emission Calculation � � � Actual . � � � `�z:v! 5 a- �J � � Standard . � L � �� °� �E\ `� \ � Carbon Monoxide ��; � � . 4/1/2008 to 4/1/2008 � 83J7 Ib/day � 0.65{Ib/mmBtu}*304.949{mcryday}* 1006.2 � {Btu/scF}*(1(scf}/ 1000{mcf})*If('Y' --. {controlled}='Y',(1-0.56{%}), 1) � i --- ��---� � �� 4/Z/2008 to 4/2/2008 , 75.73 Ib/day � 0.65{Ib/mmBtu}*275.674{mcf/day}* 1006.2 � � � �—,, ; � � � �'�`t . {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � � �"''.�� r �t( f �*"1 �� {mntrolled}='Y', (1-0.58{%}), 1) II ' "- � 4/3/2008 to 4/3/2008 � 11.89 Ib/day - � 0.65{Ib/mmBtu}*43.297{mcf/day}* 1006.2 i � Y`f t �� ,1�y��, {Btu/scf}*(1{scF}/ S000(mcF})*If{'Y' � UL�L-� �� i (controlled}_'Y',(1-0.58{%}), 1) � _ � �,� 4/4/2008 to 4/4/2008 73.05 Ib/day � 0.65{Ib/mmBtu}*265.942(mcryday}* 1006.2 j),�,p i a « �� V�'C � {scu/scr}*�i{scr}/ i000{mcr}�=if(�r I j {controlled}_'Y', (1-0.58{%}), 1) . 1 ��i Q�J"''/V�i !',�� 5 �� 4/5/2008 to 4/5/2008 85.55 Ib/day . �" 0.65{Ib/mmBtu}*311.43399{mcQday}* � =u _ ioo5.z{etu/scr}*�i{scr}/ i000{mcF}�*rf��r , .— , �, ��,."._ _— -----�� {controlled}='Y',(1-0.58{%}), 1) �, - 4/6/2008 to 4/6/2008 8535 Ib/day � � 0.65{Ib/mmBtu}*310J15{mcf/day}* 1006.2 '�,, � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y'� '�, � . � {controlled}='Y',(1-0.58{%)), 1). ��', � . . 4/7/2008�to 4/7/2008 � � � 84.98 Ib/day � Ob5{Ib/mmBtu}*30937299{mcF/day}* '�, 1006.2{Btu/scf}*(1{scF}/S000{mcf})*If('Y' � '�.. � � � � (wntrolled}='Y', (1-0.58{%}), i) � '. 4/8/2008 to 4/8/2008 80.88 Ib/day � 0.65(Ib/mmBtu}*294:435{mcf/day}* 1006.2 �. {Btu/scf}*(1{scf}/ S000(mcf})*If('Y' I . � {mntrolled}='Y',(1-0.58{%}), 1) 'I � . 4/9/2008 to 4/9/2008 � 12.09 �Ib/day � 0.65{Ib/mmBtu}*44.008{mcf/day}*�1006.2 I � �� {Btu/scf}*(1(scf}/1000{mcf})*If('Y' , � � � {controlled}='Y',(1-0.58{%}), 1) � ' .4/10/2008 to 4/10/2008 4835 Ib/day � 0.65{Ib/mmBtu}* 176.031{mcryday}* 1006.2 � � {Btu/scf}*(T{scf}/1000{mcf})*If('Y' � � {controlled}='Y',(i-0.58{%}), 1) � 4/11/2008 to 4/11/2008 � 76.48 Ib/day J� 0.65{Ib/mmBtu}*278.AS199{mcf/day}* . � � - 1006.2{Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' . . � . � {controlled}_'V', (1-0.58(%}), 1) 4/12/2008 to 4/12/2008 77.01 Ib/day � 0.65{Ib/mmBtu}*280367�{mcfi/day}* 10061 � � � {Btu/scT}*(1{scF}/ 1000{mcf}) *If('Y' {controlled}='Y', (1-0.58{%}), 1) � � � 4/13/2008 to 4/13/2008 7717 Ib/day � 0.65{Ib/mmBtu}*280.92899{mcryday}* � . � 1006.2{Btu/scf}* (1{scf}/ S000{mcf})*If('Y' � {controlled}='Y',(1-0.58{%}), 1) �� . 4/14/2008 to 4/14/2008 67.18 Ib/day � 0.65{Ib/mmBtu}*244.559{mcF/day}* 1006.2 � {Btu/scf}*(1{s[f}/ 1000{mcf})*If('Y' {controiied}_�r,(i-o.ss{�io}�, i) �� 4/15/2008 to 4/35/2008 83.96 Ib/day � 0.65{Ib/mmBtu}*305.647{mcf/daY}* 1006.2 ' {Btu/scF}*(t{scf}/ 1000{mcf})*If('Y' � (mntrolled}_'Y',(1 -0.58{%}), 1) � 4/16/2006 to 4/16/2008 8337 Ib/day � 0.65{Ib/mmBtu}*303.49301{mcryday}* � , 10062{Btu/scf}*(1{scf}/1000{mcf})*If('Y' II . � � � � {controlled}='Y',(1-0.58{%}), 1) . � 4/ll/Z008 to 4/17/2008 8034 Ib/day . �..� 0.65{Ib/mmBtu}*29Z48599{mcf/day}* - 1006.2{Btu/scf}*(1{scf}/1000{mcf})*If('Y' � � {controlled}='Y',(1-0.58{%}), 1) 4/18/2008 to 4/18/2008 77.40 Ib/day � 0.65{Ib/mmBtu}*281.77701{mcf/day}* � � . - 1006.2{Btu/scf}*(1(scfy./1000{mcf})*If('Y' , . {controlled}='Y', (1-0.58{%)),�1) � �' 4/19/2008 to 4/19/2008 78.61 Ib/day � 0.65(Ib/mm6tu}*28616101{mcf/day}* . ' . � 1006.2{Btu/scF}*(1{scF}/1000{mcf})*If('Y' {controlled}='Y',(1-0.58{%}), 1) � 4/20/2008 to�4/20/2008 80.18 Ib/day �r 0.65(Ib/mmBtu)*291.879{mcf/day}* 1006.2 . - � {Btu/scf}*(1{scf}/1000{mcf})*If('Y' �� . {controlled}='Y',(1-0.58{%}), 1) � ..___.__.... ___ ....._ .... . ... .. .. _ ...... . . .. ... . ..._. . ___.._ . . ._.. .. . . �� i ; � �� Equiprrsent Emission Detail . Fort Lupton,EU-36,5/N 38D8780-24S1512,AIRS ID: 123/0057/005-4/1/2008 to 4/30/2008 � Report Date: Wednesday, February 6,2013 1:58 PM � Records 40 to 59 of 180, Page 3 of 10 Type Category Compound Emission Period Amount Units � Estimated Emission Calwlation � Adual Standard � � i'i'1;7� �:i;b�J.s° �+-(,_� �:�G �.u!'`\i � Nitrogen Oxides . �1j � 4/SO/2008 to 4/10/2008 240.89 Ib/day � 1 36{Ib/mmBtu}* 176.031{mcf/day}* 1006.2 � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' {controlled}_ 'Y',(1-0), 1) 4/11/2008 to 4/11/2008 380.99 Ib/day � 1.36{Ib/mmBtu}*278,41199{mcf/day}* � . 1006.2{Btu/scf}*(1(scF1/ 1000�{mcf})*If('Y' � {controlled}_ 'Y',(1-0), 1) . 4/12/2008 to 4/12/2008� 383.66 ib/day � 1.36{Ib/mmBtu}*280367{mcF/day}* 1006.2 - . (Btu/scf}*(1(scf}/ 1000{mcf})*If('Y' . � � {mMrolled}='Y',(1-0), 1) � 4/13/2008 to 4/13/2008 384.43 Ib/day � 136{Ib/mmBtu}�*280.92899{mcf/day}* . � 1006.2{Btu/scf}*(1(scf}/ 1000{mcf})*If('Y' � -�� {cantrolled}='Y',(1-0), 1) I, � � 4/14/2008 to 4/14/2008 334.66 Ib/day � 1.36{Ib/mmBtu}*244.559{mcfi/day}* 1006.2 ' � . . . . � . {Btu/scF}*(1{scf}/ S000{mcf}) *If('Y' � . {contralled)='Y',(1 -0), 1) 4/15/2008 to 4/15/2008 418.26 Ib/day � 136{Ib/mmBtu}*305.647{m6/day}* 1006.2 � � {Btu/scF}*(1{scf}/ 1000(mcf}) *If('Y' �� {controlled}_ 'Y',(1-0), 1) 4/16/2008 to 4/16/2008� 41531 Ib/day j� 136{Ib/mmBtu}*303.49301{mff/day}* � 1006.2{Btu/scf)*(1{scf}/ S000{mcf})*If('Y' ''�, � {controlled}_ 'Y',(1-0), 1) � 4/D/2008 to 4/ll/2008 400.25 Ib/day � 136{Ib/mmBtu}*292.48599{mcf/day}* � . . 3006.2{Btu/scf}*(1{scf}/1000{mcF})*If('Y' �, � . {controlled}='Y;(1-0), 1) �'�� 4/18/2008 to 4/18/2008 � 385.59 Ib/day . � 1.36{Ib/mmBtu}*281.77701{mcF/day}* ''�, 1006.2{Btu/scf}*(1{scf}/S000{mcf})*If('Y' '�. � . {controlled}='Y',(1-0), 1) . � � 4/19/2008 to 4/19/2008 391.59 Ib/day � 136.{Ib/mmBtu}*286.16101(mcryday}* . � . 1006.2(Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' �� . � � � {controlled}='Y',(1-0), i) � ��. 4/20/2008 to 4/20/2008 399.42 Ib/day . � . 136{Ib/mmBtu)*291.879{mcF/day}* 1006.2 '�. . {Btu/scF}*(1{scf}/ S000(mcf})*If('Y' '�, � � . {contralled}_ 'Y',(1-0), 1) '��, . 4/21/2008 to 4/21/2008 392.53 Ib/day � 136{Ib/mmBtu}*286.844{mcryday}* 1006.2 '�, {Btu/scF}*(1{scf}/ 1000{mcfy)*If('Y' � '��, . {contralled}='Y',(1-0), 1) � �'�, � 4/22/2008 to 4/22/2008 418.60 Ib/day � 136{Ib/mmBtu}*3059{mcryday}* 1006.2 ''�, � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' '��, � � � {controlled}_ 'Y',(1-0), 1) � �',, 4/23/Z008 to 4/23/2008 389J3 Ib/day � 136{Ib/mmBtu}*284J97{mcf/day}* 1006.2- '� � {Btu/scf}*(1<scf}/ 1000{mcf})*If('Y' �� . {controlled}='Y',(1 -0), 1) . 4/24/2008 to 4/24/2008 133J3 Ib/day � 136(Ib/mmBtu)*97J28{mcryday}* 1006.2 �, , � � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' '�. � � {contmiled}= 'Y',(1-0), 1) � - 4/25/2008 to 4/25/2008� . 430.08 Ib/day � � 136{Ib/mmBtu}*314.284{mcF/day}* 1006.2 � . � � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � � � � � (rontrolled}='Y',(I-0), 1) �'�,, . . 4/26/2008 to 4/26/2008 424J9 Ib/day � 136{Ib/mmBtu}*310.42401{mcF/day}* I, � � 1006.2{Btu/scF}*(1{scf}/1000{mcf})*If('Y' ', � � (mntrolled}='Y',(1-0), 1) � � , 4/27/2008 to 4/27/2008 429.69 Ib/day � 136{Ib/mmBtu}*314{mcf/day}* 1006.2 '. � {Btu/scFy*(1 {scF}/ S000{mcf})*If('Y' � � � (controlled}='Y',(1-0), 1) �, 4/28/2008 to 4/28/2008 42830 Ib/day J� 1.36{Ib/mmBtu}*312.988{mcf/day}* 1006.2 ' � � {Btu/scF}*(i{scf}/ S000(mcf})*If('Y' �. � � {controlled}='Y',(1 -0), 1) . 4/29/2008 to 4/29/2008 432.68 Ib/day �� 136{@/mmBtu}*316.19{mcryday}* 1006.2 ' {Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' '� � {mntrolled}='Y',(1-0), 1) � � �� . _.. ___ _. _. .. . ____._.._.. .... . ....._..__.__... . .._ . . . .___ .... . .. .. .. ..__ . Equipment Emission Detail . Fort Lupton,EU-36,S/N 38DS780-2451S12,AIRS ID; 123/0057/005-4/1/2008 to 4/30/2008 � Report Date: Wednesday, February 6,2013 1:58 PM Records 79 to 97 of 180, Page 5 of 10 - Type Category Compound Emission Period Amount Units Estimated Emission Calculation � � Actual � Standard I,...._(.5,.,��.i.._ ;n��"�F.1 ti�`%. �PM i;J . � 4/19/2008 to 4/19/2008 1612 Ib/day � � 0.056(Ib/mmBtu}*286.16101{mcryday}* � 1006.2{Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � . {mntrolled}= 'Y', (1-0), 1) � 4/20/2008 to 4/20/2008 16.45 Ib/day j� 0.056{Ib/mmBtu}*291.879{mcF/day}* � � 1006.2{6tu/scf}*(1{scf){S000{mcf})*If('Y' � � {contralled}= 'Y', (1-0), 1) - - 4/21/2008 to 4/21/2008 � .16.16 Ib/day � 0.056{Ib/mmBtu}*286.844{mcf/day}* � � 1006.2(Btu/scf}*(1{scf}/ S000{mcf})*If('Y' � � . {controlled}='Y', (1-0), 1) . . � 4/22/2008 to 4/22/2008 � 17.24 .Ib/day � 0.056{Ib/mmBtu}*305.9(mcF/day}* 1006.2 �. : . � {Btu/scf}*(1 {scf}/ 1000(mcf})*If('Y' � � {mMrolled}='Y', (1-0), 1) . 4/23/2008 to 4/23/2008 16.05 Ib/day � . 0.056{Ib/mmBtu)*284.797{mcf/day}* � 1006.2{Btu/scf}*(1{scf}/ 1000(mcf})*If('Y' � � {mntrolled}='Y', (1-0), 1) 4/24/2008 to 4/24/2008 5.51 Ib/day � 0.056(Ib/mmBtu}*97.728{mcf/day}* 1006.2 � . � . {Btu/scF}*(1{scf}/ 1000{mcF})*If('Y' � � {controlled}= 'Y',(1-0), i) . . 4/25/2008 to 4/25/2008 llJl Ib/day � 0.056{Ib/mmBtu}*314.284{mcf/day}* . 1006.2{Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � _ � {contralled}= 'Y',(1-0), 1) � 4/26/2006 to 4/26/2008 17.49 Ib/day � 0.056{Ib/mmBtu}*310R2401{mcf/day}* . 1006.2(Btu/scf}*(1{scf}/1000{mcf})*If('Y' � {controlled}= 'Y', (1-0), 1) � 4/27/2008 to 4/27/2008 - 17.69 Ib/day f OA56{Ib/mmBtu}*314{mcryday}* 10062 � {Btu/scf}*(1{scF}/ 1000{mcf})*If('Y' � � � {mntrolled}= 'Y',(1-0), 1) 4/28/2008 to 4/28/2008 17.64 Ib/day � 0.056{Ib/mmBtu}*312.988{mcF/day}* � � . � 1006.2{Btu/scf}*(1{scF}/1000{mcf})*If('Y' � . {mntrolled}='Y', (1-0), 1) � � � � 4/29/2008 ro�4/29/2008 ll.82 Ib/day J-. 0.056{Ib/mmBtu}*316.19{mcF/day}* 1006.2 � � {Btu/scf}* (1{scf}/ 1000{mcf))*If('Y' � � {mMrolled}='Y', (1-0), 1) � 4/30/2008 to 4/30/2008 1592 Ib/day � 0.056{Ib/mmBtu}*282,539{mcryday}* ioo5.z{atu/sc�}*�i{scr}/iaoo{mcr7�=rF��r . � {contmlled)='Y', (1-0), 1) � PM Total: 451.19 (15.04 average) - i.� i — — �� , 3(��Ep! PM10 � � 4/1/2008 to 4/1/2008 � 17.18 Ib/day � 0.056(Ib/mmBtu}*304.949{mcF/day}* . 1006.2{Btu/scf}*(1�{scf}/ S000{mcf})*If('Y' {controiled}= 'Y',(1-0), 1) � 4/2/2008 to 4/Z/2008 15.53 Ib/day � 0.056{Ib/mmBtu}*U5.674{mcf/day}* � � 1006.2{Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' . (controlled}= 'Y',(1-0), 1) - . � 4/3/2008 to 4/3/20D8 2.44 Ib/day � 0.056{Ib/mmBtu}*43.297{mcfi/day}* 1006.2 - . � (Btu/scf}*(1{scf}/ S000{mcf})*If('Y' ��, . � (controlled}='Y', (1-0), 1) � 4/4/2008 to 4/4/2008 14.99 Ib/day � � 0.056{Ib/mmBtu}*265.942{mcryday}* � � 1006.2{Btu/scf}* (1{scF}/1000{mcF})*If('Y' . {controlled}= 'Y', (1-0), 1) 4/5/2008 to 4/5/2008 17.55 Ib/day � 0.056{Ib/mmBtu}*311.43399{mcf/day)* 1006.2{Btu/scf}*(1{scF}/1000{mcf})*If('Y' � � {mntrolled}='Y', (1-0), 1) 4/6/2008 to 4/6/2008 17.51 Ib/day � 0.056{Ib/mmBtu}*310J15{mcf/day}* . � 1006.2{Btu/scf}*(1{scf}/1000{mcf})*If('Y' � {controlled}='Y', (1-0), 1) � ' 4/7/2008 to 4/7/2008 ll.43 Ib/day � 0.056{Ib/mmBtu}*30937299{mcryday)* I, . 1006.2{Btu/scf}*(1{scf}/1000{mcf})*If('Y' �'� . . {wntrolled} = 'Y', (1-0), 1) � Equipment Emission Detail Fort Lupton,EU-36,S/N 38D87S0-2451512,AIRS ID: 123/0057/005-4/1/2008 to 4/30/200S Report Date: Wednesday, February 6, 2013 1:58 PM Records 137.to 155 of 180, Page 8 of SO Type Category Compound Emission Period Amount Unitr Estimated Emission Calculation Actual � _ ( Standard . � �`(�'-`°�� i �u?"�s'-44d ": Lc�4cT..;��1�,�.�'�, 1 ..� PM25 � '�;� � ��, . 4/ll/2008 to 4/17/2008� 14.22 Ib/day � 0.04831{Ib/mmBtu}*292.48599{m6/day}* ��.. 1006.2{Btu/scf}*(1{scF}/ S000{mcf})*If('Y' , ' � � {controlled}='Y',(1-0), 1) � , . 4/18/2008 to 4/18/2008 13J0 Ib/day � 0.04831{Ib/mmBtu}*281.77701{mcf/day}* �, � 1006.2{Btu/scf}*(1{scF}/ 1000{mcf})*df('Y' �', � � {controlled}='Y',(1-0), 1) . 4/19/2008 to 4/19/2008 13.91 Ib/day � 0.04831{Ib/mmBtu}*286.16101{mcf/day}*� � � 1006.2{Btu/scf}*(1{scf}/ 1000{mcF})*If('Y' � � � � {controlled}_ 'Y',(1-0), 1) � 4/20/2008 to 4/20/Z008 14.19 Ib/day � 0.04831{Ib/mmBtu}*291.879{mcf/day}* ' 1006.2{Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' . . {controlled} ='Y',(1-0), 1) . � 4/21/2008 to 4/21/2008 � 13.94 Ib/day � 0.04831{Ib/mmBtu}*286.894{mcf/day}* 1006.2{Btu/scf}*(Y{scf}/ 1000{mcf})*If('Y' � . � {controlled}='Y',(1-0), 1) � 4/22/2008 to 4/22/2008 14.87 Ib/day �..- 0.04831{Ib/mmBtu}*305.9{mcryday}* . . 1006.2(Btu/scf}*�i{scF}/ i000{mcr}�*rr��r � � {mntrolled} ='Y',(1-0), 1) � � 4/23/2008 to 4/23/2008 �.13.84 Ib/day . � 0.04831{Ib/mmBtu}*284J97{mc%day}* , � � . 1006.2(Btu/scf}*(1{scf}/ 1000{mcF})*If('Y' ' � . (controlled}='Y',(1-0), 1) � 4/24/2008 to 4/24/2006 . 4J5 Ib/day � � 0.04831{Iti/mmBtu}*97728{mcf/day)* . 1006.2{Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � � � {controlled}='Y',(1 -0), 1) � 4/25/2008 to 4/25/2008 15.28 Ib/day � 0.04831{Ib/mmBtu}*314.284{mcf/day}* � iooe.z{scu/scF}*�i{scf}/ioao{mcr}�*if��r . {controlled}='Y',(1-0), 1) . 4/26/2008 to 4/26/2008 . � 15.09 Ib/day � 0.04831�{Ib/mmBtu}*310.42401{mcF/day}* � 1006.2{Btu/scf}*(1{scf}/1000{mcf})*If('Y' ! . . � {controlled}='Y',(1 -0), 1) � � . 4/27/2008 to 4/27/2008 . 15.26 Ib/day � 0.04831{Ib/mmBtu}*314{mcf/day}* 1006,2 � . {Btu/scf}*(1{scf}/ 1000{mcf}) *If('Y' . {controlled}='Y',(1-0), 1) 4/28/2008 to 4/28/2008 15.21 Ib/day � 0.04831{Ib/mmBtu}*312.988[mcf/day}* 1�06.2{Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � . � � {controlled}='Y',(1-0), 1) � � 4/29/2008 to 4/29/2008 1537 Ib/day � 0.04831{Ib/mmBtu}*316.19{mcf/day}* � � � 1006.2{Btu/scf}*(1{scf}/S000{mcF})*If('Y' � {controlled}='Y',(1 -0), 1) � � . � 4/30/2008 to 4/30/2008 13J3 Ib/day � 0.04831(Ib/mmBtu}*282.539{mcryday}* � . � 1006.2{Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � {controlled}='Y',(1-O), 1) � ' PM2.5 Total: 389.23 (12.97 average) , VOC �,r°1�i'�,��U" ,� O z,I �L D�� , � 4/1/2008 to 4/1/2008 82.85 Ib/day � � . 0.27{Ib/mmBtu}*304.949{mcf/day}* 1006.2 � � . � {Btu/scF}*(i{scf}/ 1000{mcf})*If('Y' {controlled}_'Y',(1-0), 1) 4/2/2008 to 4/2/2008 � 74.89 Ib/day � 0.27�{Ib/mmBtu}*275.674{mff/day)* 1006.2 � ,. � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' ' � � {controlled}='Y',(1 -0), 1) � 4/3/2008 to 4/3/2008 11.76 Ib/day �' 0.27{ib/mmBtu}*43.297(m6/day}* 1006.2 � {Btu/scfi}*(1{scf}/ 1000{mcf})*If('Y' . {controlled}='Y',(1 -O), 1) �. � 4/4/2008 to 4/4/2008 72.25 Ib/day � 0.27{fb/mmBtu}*265.942{mcF/day}* 1006.2 �. - {Btu/scF}*(I{scf}/ 1000{mcf})*If('Y` � � {controlled} _ 'Y',(1-0), 1) . �. � 4/5/2008 to 4/5/2008 84.61. Ib/day � 0.27.{ib/mmBtu}*311.43399(mcf/day}* ' . 1006.2{Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' . � {controlled}='Y',(1-0), 1) ___. . ._. . .. ____ .._.. . __-__. . . . _. .___. . .. .. ..__.__. .. . Equipment Emission Detail ' �Fort Lupton,EU-36,S/N 38D8780-24SiS12,AIRS ID: 123/0057/005-4/1/2008 to 4/30/2008 . Report Date:Wednesday, February 6,2013 1:58 PM � � � � � Remrds 156 to ll5 of 180, Page 9 of 10 � Type Category Compound �Emission Period .Amount Units Estimated Emission Calculation Actua� Standard . - � � VOC 4/6/2008 to 4/6/2008 84.41 Ib/day ]— 0.27{Ib/mm8tu}*310.715{mcF/day}* 1006.2 � {Btu/scF}*(1{scf}/ 1000(mcf})*If('Y' . - {controlled}= 'Y',(1-O), 1) � 4/7/2008 to 4/7/2008 . 84A5 Ib/day � O.D{Ib/mmBtu}*309.37299{mcryday}* . 3006.2{Btu/scf}*(1(scf}/ 1000{mcf})*If('Y' . . � (controlled}= 'Y',(1-0), 1) �. � 4/8/2008 to 4/8/2008 79.99 Ib/day � O.D{Ib/mmBtu}*294.435 tmcf/day}* 1006.2 {Btu/scF}*(1{scF}/ S000{mcf})*If('Y' � {controlled} ='Y', (i-0), 1) . . � 4/9/2008 to 4/9/200S� 11.96 Ib/day � 0.27{Ib/mmBtu}*94,008{mcF/day}* 1006.2 {Btu/scF}*(1{scF}/ 1000{mcf})*If('Y' - {controiled}='Y', (1-0), 1) .4/10/2008 to 4/10/2008 47.82 Ib/day � 0.27{Ib/mmBtu}* ll6.031{mcf/day}* 1006.2 � (Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � � � {mntrolled}='Y',(1-0), 1) - � 4/11/2008 to 4/11/2008 75.64 Ib/day (— 0.27{Ib/mmBtu}*278.41199{mcf/day}* . . � 1006.2{Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' � � {controlled} ='Y', (1-0), 1) 4/12/2008 to 4/12/2008 . 76.17 Ib/day f O.D{Ib/mmBtu}*280.367{mcfi/day}* 1006.2 � � . � {Btu/scf}*(1{scf}/ 1000{mcf}) *If('Y' � {controlled} ='Y', (1-0),1) � 4/13/2008 to 4/13/2008 7632 Ib/day � O.Z7{Ib/mmBtu}*280.92899{m6/day)* � �. � 1006.2{Btu/scf},*(1{sct}/ S000{mcf})*If('Y' . � {controlled}='Y', (1-0), 1) �, 4/14/2008 to 4/14/2008 66.44 Ib/day � 0.27{ib/mmBtu}*244.559{mcf/day}* 1006.2 � � (Btu/scF}*(1(scf}/ 1000{mcf})*If('Y' ,. . {mntrolled} = 'Y', (1-0), 1) '��.. 4/15/2008 to 4/15/2008 � 83.04 Ib/day � �0.27{Ib/mmBtu}*305.647{mcf/day}* 1006.2 ''�.. � � {Btu/scf}*(1(scf}/ 1000{mcf})*If('Y' � ''�, � {controlled}='Y',(1-0), 1) '' � 4/16/2008 to 4/16/2008 . 82.45 Ib/day � 0.27(Ib/mmBtu}*303.49301{mcf/day}* I 1006.2{Btu/scf}*(1{scf}/ 1000.{mcf})*If('Y' � .{controlled} ='Y',(1-O), 1) � 4/17/2008 to 4/17/2008 79.46 Ib/day � 0.27{Ib/mmBtu)*292.48599{mcF/day}* � 1006.2{Btu/scF}*(1{scf}/1000{mcf})*If('Y' - {mntrolled}='Y', (1-0), 1) 4/18/2008 to 4/18/2008 76.55 Ib/day � 027{Ib/mmBtu}*281.77701{mcf/day}* - 1006.2{Btu/scf}* (1{scf}/.1000{mcf})*If('Y' . C�ontrolled}='Y', (1-O), 1) , - 4/19/2008 to 4/19/2008 77J4 ib/day � 0.27{Ib/mmBtu}*Z8616101(mcf/day}* 1006.2{Btu/scf}*(1{scf}/1000{mct})*If('Y' � {controlled}='Y', (1-0), 1) . � 4/20/2008 to 4/20/2008 � 79.30 Ib/day � 0,27{Ib/mmBtu}*291.879{mcf/day}* 1006.2 {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � {controlled}='Y',(1.-0), 1) � . 4/21/2008 to 4/21/2008 77.93 Ib/day j- 0.27{Ib/mmBtu}*286.844{mcF/day}* 1006.2 � . � (Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' (mMrolled}='Y', (1-0), 1) � 4/22/2008 to 4/22/2008 83.11 Ib/day � 0.27{Ib/mmBtu}*305.9{mcf/day}* 1006.2 � � � {Btu/scF}*(1{scf}/ 1000(mcf})*If('Y' (controlled}='Y',(1-O), 1) 4/23/2008 to 4/23/2008 � 77.37 Ib/day � 0.27{Ib/mmBtu}*Z64J97{mcf/day}* 1006.2 {Btu/scf}*(1(scf}/ S000�{mcf})*If('Y' . {wntrolled} ='Y', (1-0), 1) I � 4/24/2008 to 4/24/2D08 26.55 Ib/day � O.D{Ib/mmBtu}*97J28{mff/day}* 1006.2 � II � . {Btu/scf}*(1{scF}J 1000(mcf})*If('Y' . I � � . {controlled}='Y', (1-0), 1) . 4/25/2008 to 4/25/2008 85.38 Ib/day r 0.27{Ib/mmBtu}*314,284{mcf/day}* 1006.2 � . � {Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' � {controlled} ='Y',(1-0), 1) . � � ' � � �, � `. ��,'_ti?z 3�l �� rt l` '� '<:�� UjF> � r t ` __---__� Equiprnent Emission Detail � Fort Lupton,EU-37,S/N 38D87S0-2851512,AIRS ID: 123J0057/006-4/1/2008 to 4/30/2008 � Report Date: Wednesday, February 6,2013 2:02 PM Records 1 to 20 of 144, Page 1 of 8 Type Category Compound Emission Period Amount Unitr Estimated Emission Calculation � c Actual � � -��1 3�Z4:��'l d- ��2 f � i �.G�� -'i Standard ��r�" ` Carbon Monoxide � � <<� �ii 4/1/2008 to 4/1/2008 . 188.21 Ib/dayy;t � 0.6�{ib/mmBtu}*287.777{mcF/day}* 1006.2 . � . {Btu/scf}*(1{scf}/ 1000(mcf})*If('Y' {controlled}='N,(1-0), 1) � . 4/2/2008 to 4/2/2008 � �181.69 Ib/day � 0.65{Ib/mmBtu}*277J96{mcf/day}* 1006.2 � . {Btu/scf}*(1{scF}/S000{mcf})*If('Y' � . � � � � {controlled}_ 'Y', (1-0), 1) � 4/3/2008 to 4/3/2008 20112 Ib/day � 0.65{Ib/mmBtu)*307.508{mcfi/day}* 1006.2- - "� ,.__,___---��, . � . {Btu/scF}*(1{scF}/ 1000{mcf})*If('Y' � --�� - {controlled)='Y', (1-0), 1) � ( � r �`, I �� {�v�` _i , 4/4/2008 to 4/4/2008 31.31 Ib/day �' 0.65{Ib/mmBtu}*47.87(mcf/day}* 1006.2 1, �� t ` ' ? � � � � {Btu/scfi}*(1{scf}/ 1�00{mcf})*If('Y' � � {controlled}='Y', (1-0), 1) I ' ��'�,.�,� u �s� �%��` �� 'i 4/8/2008 to 4/8/2008 186.45 Ib/day �I� 0.65{Ib/mmBtu}*285.073{mcf/day}* 1006.2 I ��}�� {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � , „ r � ' . {controlled)='Y',(1-0), 1) . �Ir, �°�� `•i%`- �" . 1 4/9/2008 to 4/9/2008 204.44 Ib/ddy � 0.65(Ib/mmBtU}*312.583{mcryday}* 1006.2 __. _ -� �,_—�--- � {Btu/scF}*(1{s�f}/ 1000{mcf})*If('Y' � . - � . {controlled}='Y', (1-0), 1)� � 4/10/2008 to 4/SO/2008 77J0 Ib/day � 0.65{IbfmmBtu}* 118.808{mcf/day}* 1006.2 , � {Btu/scf}*�(1{scf}/10�0{mcf})*If('Y' {controlled} ='Y',(1 -0), 1) i � . 4/14/2008 to 4/14/2008 6139 Ib/day � � 0.65{Ib/mmBtu}*223.504{mcF/day}* 1006.2 I, . {Btu/scF}*(1{scf}/1000{mcf})*If('Y' I� � {controlled} ='Y', (i -0.58{°/a}), 1) � 4/15/2008 to 4/15/2008 S1J3 Ib/day � . 0.65{Ib/mmBtu}*Z97.521{mcfi/day}* 1006.2 � ��, � � � {Btu/scf}*(1{scf}/ S000{mcf})*If('Y' ' . � � {controlled}='Y',(1 -0.58{%}), 1)�� 4/16/2008 to 4/16/2008 79.93 _Ib/day � 0.65{Ib/mmBtu}*290.974{mcf/day}* 1006.2 � (Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' ��, � {controlled}='Y',(1 -0.58(%}), 1) . '�, 4/17/2008 to 4/17/2008� 57.20 Ib/day � 0.65{Ib/mmBtu}*208.235{mcF/day}* 1006.2 �, � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' �, . � � � � {controlled}= 'Y',(1-0.58{%}), 1). '�, 4/18/2008 to 4/18/2008 � . 77.11� Ib/day � 0.65{Ib/mmBtu}*280.919{mcF/day}* 1006.2 I . . {Btu/scf}*(i{scFy/ 1000{mcf})*If('Y' '��. �. � � {mntrolled}='Y', (1-0.58{%}), 1) ' � 4/19/2008 to 4/19/2008 78.63 Ib/day � � 0.65{Ib/mmBtu}*286.253{mcf/day}* 1006.2 ��.. � � {Btu/scf}*(1{scf}/ 1000{mcF})*If('Y' ', � (mntrolled}='Y',(1-0.58{%}), 1) � 4/20/2006 to 4/20/2008 83.63 Ib/day . � 0.65{Ib/mmBtu}*304.455{mcF/day}* 1006.2 '�� {Btu/scf}*(i�{scf}J 1000{mcf})*If('Y' . � {controlled}='Y',(1-0.58{%}), i) � �I � � 4/21/2008 to 4/21/2008 83.26 Ib/day {"" 0.65{Ib/mmBtu}*303112{m6/day}* 10062 � {Btu(scf}*(1{scf�/ 1000{mcf})*If('Y' . . {controlled}= 'Y',(1-0.58{%}), i) 4/22/2008 to 4/22/2008 86.47 Ib/day ].J 0.65{Ib/mmBtu}*314.8{mcf/day}* 1006.2 {Btu/scf}*�(1{sc@/ 1000{mcf})*If('Y' , � � . � � {mntrolled}= 'Y',(1-0.58{%}), 1) . . 4/23/2008 to 4/23/2008 75.34 Ib/day � 0.65{Ib/mmBtu}*274.254{mcF/day}* 1006.2 , �� . {Btu/scf}*(1{scf}/ 3000{mcf})*If('Y' � � � � . {controlled}='Y',(1-0.58{%}), 1) ; . 4/24/2008 to 4/24/2008 54.00 Ib/day � 0.65{Ib/mmBtu}* 196.595{mcF/day}* 1006.2 �� . . � � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � . {controlled}= 'Y',(i --0.58{%}), 1) . 4/25/2008 to 4/ZS/2008 86.21 Ib/day � 0.65{Ib/mmBtu}*313.839{mcf/day}* 1006.2 � � {Btu/scf}*(1{scF}/1000{mcf})*If('Y' {mntrolled}='Y', (1-0.58{%}), 1) '. � 4/26/2008 to 4/26/2008 8510 Ib/day � 0.65{Ib/mmBtu}*309.806{mcryday}* 1006.2 �i {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' I � � . {controlled}='Y', (1-0.58{%}), 1) I Equipment Emmssion Detail Fort Lupton,EU-37,S/N 38D87S0-2851S12,AIRS ID: 123/0057/006-4/1/200S to 4/30/2008 Report Date: Wednesday, February 6,2013 2:02 PM � � Records 40 to 58 of 144, Page 3 of 8 . Type Category Compound Emission Period � Amount Units Estimated Emission Calculation Actual � �� ! � 1'� � G C,, Standard � � . �yi,a,. ?�2i}�v- ! Nitrogen Oxides � ��.�, 4/22/2008 to 4/22/Z008 � 430.78 Ib/day � 1.�${Ib/mmBtu}*314.8{mcf/day}* 1006.2 {Btu/scf}* (1(scf}/ 1000{mcF})*If('Y' � � {controlled}='Y',(1-0), 1) � 4/23j2008 to 4/23/2008 37530 Ib/day � 1.36{Ib/mmBtu}*274.254{mcpday}* 1006.2 � � � {Btu/sct}*(1{scF}/ 1000{mcf})*If('Y' � � . � {mntrolled}='Y',(1-0), 1) � 4/24/2008 to 4/24/2008 269.03 �Ib/day� � 1.36{Ib/mmBtu}* 196.595{mcF/day}* 1006.2 � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � . {controlled)_ 'V',(1-0), 1) '. � � . 4/25/2008 to 4/25/2008 429.47 Ib/day � 136{Ib/mmBtu}*313,839{mcf/day}* 1006.2 . � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' I, . {controlled}='Y',(i-0); 1) . . 4/Z6/2008 to 4/26/2008 423.95 Ib/day ].� 1.36{ib/mmBtu}*309.806{mcryday}* 1006.2 . {Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' � {controlled}='Y',(1-0), 1) 4/27/2006 to 4/27/2008 433.34 Ib/day � 136{ib/mmBtu}*316.667{md/day}* 1006.2 , � � � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' '�� {controlled}_ 'Y',(1-0), 1) II � � 4/28/2008 to 4/28/2008 � 429.86 Ib/day (� 1.36{Ib/mmBtu}*314.124{mcf/day}* 1006.2 � � {Btu/scF}*(1{scf}/ 100D{mcf})*If('Y' � � . . . (controlled}='Y',(1-0), 1) 4/29/2008 to 4/29/2008 434.53 Ib/day J� 1.36{ib/mmBtu}*317.542{mcryday}* 1006.2 � � � � {Btu/scF}*(1{scf}/ 1000{mct})*If('Y' � {controlled}='Y',(1-0), 1) 4/30/2008 to 4/30/Z008 385.10 Ib/day � 1.36{Ib/mmBtu}*281,418{mcF/day}* 1006.2 - {Btu/scF)*(1{scf}/ 1000{mcf})*If('Y' � {controiled)= 'Y',(1-0), 1) - , Nitrogen Oxides Total: 8,855J2 (368.99 average) � � . - p � �� PM . . a�t�"�`?'` � E"b� ��7� s� ��'L-��'�l l.�g � �� 4/1/2008 to 4/1/2008 16.22 �b/day � 0.0�Ib/mmBtu}*287,777{mcf/day}* '�, . � � . � 1006.2{Btu/scF}*(i{scF}/1000{mcF})*If('Y' '�, {controlled}.='Y',(1-0), 1) 4/2/2008 to 4/2/2008 15.65 Ib/day � 0.056{Ib/mmBtu}*277.796{mcF/day}* ��, � 1006.2{Btu/scfy*(1{scf}/1000(mcf})*If('Y' � � {mntrolled}='Y',(1-0), 1) � 4/3/2008 to 4/3/2008 17.33 Ib/day � 0.056{Ib/mmBtu}*307.508{mcf/day}* . � � � � 1006.2{Btu/scf}*(1{scf}/�1000{mcf})*If('Y' � - � {controlled}='Y',(1-0); 1) 4/4/2008 to 4/4/2008 2.70 Ib/day j- 0.056{Ib/mmBtu}*47.87{mcfi/day}* 1006.2 . {Btu/scf}*(1(scf}/ 1000{mcf})*If('Y' � . {controlled}='Y',(1-0), 1) . � � � 4/8/2008 to 4/8/2008 16.06 Ib/day � 0.056{Ib/mmBtu}*265.073{mcfi/day}*. � - � 1006.2{Btu/scf}*(1{scF}/1000{mcF})*If('Y' � � � � {mntrolled}='Y',(1-O), 1) � 4/9/2008 to 4/9/2008 ll.61 Ib/day � 0.056{Ib/mmBtu}*312.583{m6/day}* � � 1006.2{Btu/scf}*(1(scF}/ 1000{mct})*If('Y' , � � {mntrolled}='Y',(1-0), 1) �'�. � 4/10/2008 to 4/10/Z008 6.69 Ib/day � 0.056{Ib/mmBtu)* 118.808{mcF/day}* � I � � 1006.2{Btu/scf}*(1{scf}/ 1000{mcF})*If('Y' '. � {controlied}= 'Y',(1-0), i) ', 4/14/2008 to 4/14/2008 . 12.59 Ib/day � 0.056{ib/mmBtu}*223.504{mcf/day}* � 1006.2{Btu/scf}*(1{scf}/ lODO{mcf})*If('Y' ��. � {controlled}_ 'Y',(1-0), 1) � � . 4/15/2008 to 4/15/2008 16J6 Ib/day � 0.056{Ib/mmBtu}*297521{mcf/day}* � � 1006.2{Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' . � {controlled}='Y',(1-0), 1) � 4/16/2008 to 4/16/2008 16.40 Ib/day � 0.056{Ib/mmBtu}*290.974{mcf/day}* � � � 1006.2{Btu/scf}*(1{scf}/1000{mcf})*If('Y' . {controlled}='Y',(1-0), 1) . .. ..__ _.. .. .._ .. ... . .. __ _ Equipment Emission Detail � Fort Lupton,EU-37,5/N 38D8780-2851512,AIRSID: 123J0057/006-4/1/2008to4/30/2008 , Report Date:Wednesday, February 6,2013 2:02 PM Records 78 to 96 of 144, Page 5 of 8 � Type Category Compound Emission Period Amount Units Estimated Emission Calculation Actual � . �. � Standard . ;-- h:t'�cia S��u��y}j � PM10 %� . �� 4/9/2008 to�4/9/2008 17.61 Ib/day J� OA56{Ib/mmBtu} *312.583(mcf/day}* � iooe.z{eru/sc�}*�i{scr}/ i000<mcr}�*tF��r . {controlled}='Y', (1-0), 1) 4/10/2008 to 4/10/2008 6.69 Ib/day �` 0.056 Qb/mmBtu}* 118.808{mcf/day}* � � 1006.2(Btu/scF}*.(1{scf}/ S000{mcf})*If('Y' � {controlled}='Y',(1-0), 1) � 4/14/2008 to 4/14/2008 12.59 Ib/day � OA56{Ib/mmBtu}*223.504{mcf/day}* � 1006.2{Btu/scf}*(1{scf}/ S000{mcf})*If('Y' � {mntrolled}_ 'Y',(1-0), 1) � 4/15/2008 to 4/15/2008 16J6 Ib/day j� 0.056{Ib/mmBtu}*297.521{mcF/day}* � � . � . � � 1006.2{Btu/scF}*(1{scF}/ 1000{mcf})*If('Y' � � {mntrolled}='Y',(1-0), 1) 4/16/2008 to 4/16/2008� 16.40 Ib/day 'j� 0.056{Ib/mmBtu}*290.974{mcf/day}* � 1006.2{Btu/scF}*(1{scF}/1000{mcf})*If('Y' . {controlled}='Y', (1-0), 1) . 4/ll/2008 to 4/17/2008 11.73 Ib/day � � 0.056{Ib/mmBtu}*208.235{mcF/day}* � � 1006.2{Btu/scf}*(1(scf}/ 1000{mcF})*If('Y' . � � {controlled}= 'Y',(1-0), 1) - I 4/18/2008 to 4/18/2008 15.83 Ib/day f 0.0%{ib/mmBtu}*280.919(mcF/day}* ', � 1006.2{Btu/scf}*(1{scf}/1000{mcf})*If('Y' ''� (mntrolled}=N', (1 -0), 1) 4/19/2008 to 4/19/2008 1613 Ib/day (� - 0.056{Ib/mmBtu}*286.253�{mcryday}* �,. 1006.2{Btu/scf}*(1{scf}/1000(mcF})*If('Y'� {mntrolled}='Y', (1-0), 1) . � 4/20/2008 to 4/20/2008 17.16 Ib/day � �0.056(Ib/mmBtu}*304.455{mcryday}* � � 1006.2{Btu/scf}*(1{scf}/1000{mcfj)*If('Y' '�� {controlled}= 'Y',(1-O), 1) 4/21/2008 to 4/21/2008 17.08 Ib/day � 0.056{ib/mmBtu)�*303.112{mcf/day}* � �. � 1006.2(Btu/scf}*(1{scF}/ 1000{mcf})*If('Y' . {controlled}='Y',(1-0), 1) �- 4/22/2008 to 4/22/2008 � 17J4 Ib/day J- 0.056{Ib/mmBtu}*314.8{mcf/day)* 1006.2 I � � {Btu/scf}*(1(scf}/ 1000{mcF})*df('Y' - {controlled}='Y', (1-0), 1) � 4/23/2008 to 4/23/2008 15.45 Ib/day � 0.056{Ib/mmBtu}*U4.254(mcf/day}* � 1006.2{Btu/scf}*(1{scfi}/ 1000{mcf})*If('Y' � . � {tontrolled}='Y',(1-0), 1) � 4/24/2008 to 4/24/2008 11.08 Ib/day J�' 0.056{Ib/mmBtu}* 196.595{mcf/day}* � � - 1006.2{Btu/scf}*(1{scF}/ 1000{mcf})*If('Y' {controiled}= 'Y',(1-0), 1) � 4/25/2008 to 4/25/2008 � 17.68� Ib/day j4 0.056{Ib/mmBtu}*313.839{mcf/day}* � _ 1006.2(Btu/scf}*(1{scf}/�1000{mcf})*If('Y' � {controlled}='Y', (1-0), i) � 4/26/2008 to 4/26/2008 � 17.46� Ib/day f 0.056{Ib/mmBtu}*309.806{mcryday}* � � � � 1006.2{Btu/scf}*(1{scf}/1000{mcF})*If('Y' � (mntrolled}= 'Y',(1-0), 1) � 4/27/2008 to 4/27/2008 17.84 Ib/day � 0.056{Ib/mmBtu}*316.667{mcf/day}* ioo5.z{stu/scr�•�i{scF}/i000{mcr}�*iF��r � � {controlled}= 'Y',(1-O), 1) � � 4/28/2008 to 4/28/2008 17J0 Ib/day r 0.056{Ib/mmBtu}*314124{mcf/day}* . . 1006,Z{Btu/scf}*.(1{scF}/1000 tmcF})*If('Y' � � � {contmlled}='Y', (1-0), 1) 4/29/2008 to 4/29/2008 ll.89 Ib/day � 0.056{Ib/mmBtu}*317.542{mcf/day}* � 1006.2{Btu/scf}*(1{scf)/1000{mcf})*If('Y' , {controlled}= 'Y',(1-0), 1) � '� � 4/30/2008 to 4/30/2008 15.86 ib/day � 0.0%{Ib/mmBtu}*281.418(mcf/day}* � 1006.2{Btu/scF}*(1{scF}/S000{mcF})*If('Y' � . {controlled}='Y', (1�-0), 1) . . � PM10 Total: 364.65 (15.19 average) Equipment Ernission Detail Fort Lupton,EU-37,S/N 38D8780-28S1512,AIRS ID; 123/0057/006-4/1/2008 to 4/30/2008 � Report Date:Wednesday, February 6,2013 2:02 PM � - Records 117 to 135 of 144, Page 7 of 8 Type Category Compound Emission Period Amount Units Estimated Emission Calculation � � Actual . r�..?3�� ti,�,Ll1�,.�� .��n,:�� Standard � 1''��" . ' � PM25 , . 4/27/2008 to 4/27/2008 1539 Ib/day � 0.�831{Ib/mmBtu}*316.667{mcf/day}* � � 1006.2{Btu/scf}*(1{scF}/1000{mcF})*If('Y' - - {controiled}= 'Y',(i-0), 1) � 4/28/2008 to 4/28/2008 15.27 ib/day . � 0.04831.(Ib/mmBtu}*314.124{mcF/day}* 1006.2{Btu/scf}*(1{scF}/ 1000{mcf})*If('Y' � {mntrolled}_ 'Y',(i-0), i) � 4/29/2008 to 4/29/2008 15.44 Ib/day � 0.04831{Ib/mm8tu}*317.542{mcf/day}* � , � � 1006.2(Btu/scf}*(1{scf}/ 1000{mcF})*If('Y' � . {mntrolled}= 'Y',(i-0), 1) � � � 4/30/2008 to 4/30/2008 13.68 Ib/day j.� . 0.04831{Ib/mmBtu}*281.418{mcf/day}* 1006.2{Btu/scf}*(1{scf)/ S000{mcf})*If('Y' . PM2.5 Total: 314.57 (13.11 average) {controlled}='Y',(1-0), 1) �. '� � � � � � voc J� ;�;t,��` C��. ��?��1��a, � �- � � . 4/1/2008 to 4/1/2008 78.18 Ib/day �. 0.25 Qb/mmBtu}*287J77{mcfi/day}* 1006.2 � . � . {Btu/scF}*(1{scF}/ 1000{mcf})*If('Y' {controlled}_'Y',(1-0),�1) 4/2/2008 to 4/2/2008 75.47 Ib/day � 0.27{Ib/mmBtu}*277J96{mcF/day}* 1006.2 . � {Btu/scf}*(1{scF}/ S000{mcf})*If('Y' � {controlied}_ 'Y',(1-0), 1) � 4/3/Z008 to 4/3/2008 � 83.54 Ib/day � 0.27{Ib/mmBtu}*307.508{mcfJday}* 1006.2 � � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' � . � � . � {controlled}='Y',(1 -0), 1) 4/4/2008 to 4/4/2008 � 13.01 Ib/day � 0.27{Ib/mmBtu}*47.87(mcf/day}* 1006.2 � � {Btu/scF}*(1(scf}/ 1000{mcf})*If('Y' � {controlled}='Y',(1-0), 1) � � 4/8/2008 to 4/8/2008 77.45 Ib/day ]� 0.27(Ib/mmBtu}*285.073{mcF/day}* 1006.2 � . � . � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' . � � {mntrolled}.='Y',(1-O), 1) � � . . 4/9/2008 to 4/9/2008 � 84.92� Ib/day �' 0.27{Ib/mmBtu}*312.583{mcf/day}* 1006.2 � � � {Btu/scf}*(1{scf}/ 1000(mcf})*If('Y' � {controlled}='Y',(1-0), 1) . 4/30/20D8 to 4/10/2008 32.28 Ib/day � 027{Ib/mmBtu}* 118.808{mcfi/day}* 1006.2 � {Btu/scfi}*(1{scf)/ 1000{mcf})*If('Y' . � {controlled} ='Y',(1-0), i) . 4/14/2008 to 4/14/2008 � 60J2 Ib/day � 0.27{Ib/mmBtu}*223.504{mcfi/day}* 1006.2 � � - {Btu/scF}*(1{scfy/.5000(mcf})*Tf('Y' {controlled}= 'Y',(1-0),.1) . 4/15/2008 to 4/15/2008 80.83 Iblday � 0.27{Ib/mmBtu}*297,521{mcf/day}* 1006.2 � {Btu/scf}*(1{scf}/1000(mcf})*If('Y' . � � . {mntrolled}= 'Y',(1-0), 1) 4/16/2008 to 4/16/2008 79.05 Ib/day � 0.27{Ib/mmBtu}*290.974{mcf/day}* 1006.2 � � . {Btu/scF}*(1{scf}/ 1000{mcf})*If('Y' � {controlled}= 'Y',(1-0), 1) 4/ll/2008 to 4/17/2008 56.57 Ib/day . � 0.27{Ib/mmBtu}*208.235{mcf/day}* 1006.2 . � {Btu/scf}*(1{scf}/ 1000{mcf})*If('Y' . � {controlled}_ 'Y',(1-0), 1) � � 4/18/2008 to 4/18/z008 7632 Ib/day � O.0{Ib/mmBtu}*280.919{mcf/day}* 1006.2 . . � , {Btu/scfi}*(i{scF}/ 1000{mcf})*If('Y' � (controlled}= 'Y',(1 -0), 1) � 4/19/2008 to 4/19/2008 77J7 � Ib/day ;� 027{Ib/mmBtu}*286.253{mcf/day}* 1006.2 . � � {Btu/scf}*(1(scf}/1000{mcf})*If('Y'� � � � {controlled}='Y',(1-0), 1) � � 4/20/2008 to 4/20/2008 82J1 Ib/day J� 0.27{Ib/mmBtu}*304.455{mcF/day}* 1006.2 . . {Btu/scF}*(1{scf}/ S000{mcf})*If('Y' . . � � {controlled}='Y',(1-0), 1) � � 4/21/2008 to 4/21/2008 82.35 Ib/day � 0.27{Ib/mmBtu}*303:112{mcf/day}* 1006.2 � � . � � . � .{Btu/scf}*(1{scf}�/S000{mcf})*If('Y' {controlled}= 'Y',(1-0), 1) . . 4/4/15 � � � State.co.us Er.ecuti�e Branch Mail-RE:Lancaster comments � ',�5�� State .. . . � . �� . � . . . . . . . . af - -� ,s;'� v Colorado �� ' RE: Lancaster comments Shea, Jennifer<Jennifer.5hea@anadarko.com> Fri, Jan 25, 2013 at 2:40 PM �. To: "Chaousy -CDPHE, Stephanie" <stephanie.chaousy@state.co.us> Cc: "carissa.money@state.co.us" <carissa.money@state.co.us>, Christopher Laplante-CDPHE <christopher.laplante@state.co.us>, 'Bracken, Korby" <Korby.Bracken@anadarko.com>, "Carter, Micah" <Micah.Carter@anadarko.com> � � Stephanie, � � � � � i ; Responsesbelow. Iwillrespondtoyouratheremailsshortly. I . � Jennifer Shea � Staff EHS Reprezentative � . � � ANADARKO PETROLEUM CORPORATION . � Direct: (720) 929-6028 � Cell: (303) 919-0040 � From: Chaousy- CDPHE, Stephanie [mailto:stephanie.chaousy@state.co.us] Sent: Thursday,7anuary 24, 2013 2:52 PM . � � To: Shea,]ennifer � Cc: carissamoney@state.co.us; Christopher Laplante - CDPHE Subject: Lancaster commentr . . . . Hello Jennifer, . � - I have a few comments for you regarding the email you sent 1/15/13 with new APENS for the generator 3 and amine units. 1. The generator: �The APEN KM submitted to the Di�ision on 1/15/13 did not have Section 08 re�ised. The APEN submitted is still � reflecting the original emissions and�emission factors. KM's calculation sheet (and the Divsion's)shows SOx at 1.48 TPY, NOx at 2.57 TPY and CO at 0.16 TPY. I redlined the APEN accordingly, but wanted to make sure your files reflected the same changes. I must have � missed that, sorry. Updatetl APEN attached. � � �I 2. The generator: I calculated the PM emissions a little higher than KM. I used the"total particulate" emission factor in AP-42, Table 3.4- '�, 2 for the particulate since that is the total sum of the filterable and condensable particulate. My calculations were 0.1 TPY of PM (only ��, 0.04 TPY difference for each PM10 and PM2.5). My g/hp-hr con�rsion was not calculating correctly, so you are correct. Changes '�, re8ected in attached APEN.along with updated fuel consumption in Section 6, so be sure to redline what you have. 3. The amine units: the APEN addendum shows that the TO is controlling at 100%for H25. KM has agreed that the TO will be . controliing emissions at 99% and therefore, there will be some H2S from these amine units. The H2S calculations should be: Hydrogen sulfde= (21644 Ib/yr)* 0.05 = 1082.2 Ib/year*0.01 (TO) = 10.82 Ib/yr H2S ' 1.1 (safety factor)= 11.90 Ibtyr= 0.006 TPY. H2S . ��. � will be a permitted limit in the permit, so would KM prefer 0.01 TPY for the limit to gi�a little cushion? I updated the APEN NCR Addendum to include 10.8 Ib/yr of H2S. � � � 4.�I was wondering if you had an update regarding the emission factors for the heaters. Chris pro�nded some guidance in an email sent on � . . 1/16/13 regarding emission factors, and i was just wondering if there was an update yet. Are you talking�about the PM2.5 emission . factors? I induded the updated emissions for PM2.5 on ihe 1/16/13. I have attached the updated heater APENs reflecting those changes since I did noi indude updated APENs with the netting. , � � https://mail.g oog Ie.corrJmai I/?ui=2&ik=7faca29a38&Ne�rpt&cat=Lancaster&search=cat&th=13c73a869a3ba91 c 1/3 _.__. . ._. .. . . �. ..._ . _._. . __.. ._. .. . . _ ...: . . _... ._... . . . . . ._.. _. : .. . . . . 4/M13 State.co.us Executi�e Branch Mail-RE:Lancaster comments . ' . Thank you, � � � . , Stephanie Chaousy, P.E � , � � Oil and Gas Permitting Engineer - Department of Public Health and Envronment � � � 303-692-2297 . � www.colorado.govlcdphe . Anadarko Co��fidentiality Notice: T'his electronic transmission and any attached documents or cther writinqs are intended only for tn=_ person . or entity to which it is addres�zd and may contzin information trat is � � privileged, confidential o= ctherwise pro'�ected from disclosure. If you . � have received thi_s commun.icati.ce in err.or., please immediate].y notify . se�der by rroturn e-mail and destroy the communication. Any disclosore, � copying, distxibution or the taking o£ any action concerning the concents of [his communication or any attachmcnLs by anyo�2 othei than Yr,c � ' named recipient is strictly prohibited�. � . a,.m.._ . _......__ ...,._._..._.. ._.__...__.. ..... .__�a._ �, _ ....._ .__._ �I 14 attachments � 2013-01-25 LAN GEN3 APEN.pdf � � 749K ��2013-01-25 LAN A-4 APEN Addendum.pdf . I�� 231 K *aa� 2073-01-25 LAN A-1 APEN Addendum.pdf �, 230K ,�a„ 2013-01-25 LAN A-2 APEN Addendum:pdf - �,., 231 K I �� 2013-01-25 LANA3 APEN Addendum.pdf _ li � 233K �� 2013A1-25 LAN E-2016 APEN.pdf � � I� � 738K . '.��, � 2013-01-25 LAN E-2015 APEN.pdf � II 733K a,�, 2013-01-25 LAN E-2015-6 Emission Caics.pdf � � ', 13K � � � � ��.. � � 2013-01-25 LAN H-6054 APEN.pdf � � �� 742K � 2013-01-25 LAN W-6051 APEN.pdf � � � 737K �i � 2013-01-25 LAN H-6051-4 Emission Calcs.pdf '��.. 13K � 2013-07-25 LAN H-6052 APEN.pdf . li,, 744K � 2013-01-25 lAN H-6053 APEN.pdf � , � � j 741 K https://mail.google.com/mail/?ui=2&ik=7faca29a38&Ne�pt&cat=Lancaster&search=cat&th=13c73a869a3ba91c. � y3 II � M4/13 State.co.us E�cuti�e Branch Mail-�RE:Lancaster commerrts � . . � 2013A1-25 LAN APCD-102.pdf � ' 79K �� https://mail.google.coMmaii/?ui=2&ik=7faca29a38&Nev�pt&cat=Lancaster&search=cat&th=13c73a869a3ba91c � 3/3 ' �..__ ... . .. ....:. . . ... . __... . �-1i,�� u 6 i� o � �_� � a�g� g .., € ��S „�3eF� s . .��,�. . . $z s"e �:"aFF,s �� z � . ' ' "za��a"' � . 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" � a � y .o � F" a �, � 'z 9 U Y ��m � t] w � c� z d d � n' g k'n m � m m v^� Fort Lupton Gas Plant Lancaster Plant Mole Sieve Regeneration Gas Heater 1 and 2 Train 1 and Train 2 Heater Data Make: Mole Sieve Regeneration Gas Heater with Ultra Low NOx Burners Manufacturer: ZEECO USA, LLC Model 35M Megafire AIRS ID: TBD Source ID E-20�5 & E-2016 Heat Output 25.0 (MMBtu/hr) Fuel Use 255.6 MMscf/yr Efficiency: 0.84 (decimai) 21.7 MMscf/mo` Heat Input: 29.8 (MMBtu/hr) 'based on 37-day month Operation: 8760 (hdyr) �� Fuel Heat Value: 1020 (Btu/scfl I Emission Calculations Emission Factors Emissions Pollutant Source Ib/MMscf Adjusted Ib/MMBtu Ib/hr Ib/mo* tpy Ib/MMscf" NOx manuf. 0.04 1.2 886 52 CO manuf. 0.040 1.2 886` 52 ' VOC manuf. 0.019 0.6 42t 2.5 ' PM10/PM2.5 AP-42 7.6 7.6 0.007 0.2 ` 165 1A ' SOZ AP-42 0.6 0.6 0.001 0.02 13 0.1 CH2O AP-42 0.075 0.075 0.000 0.002 2' 0.010 Benzene AP-42 0.0021 0.0021 0.0000 O,OOOT 0 0.0003 ! Toluene AP-42 0.0034 0.0034 0.0000 0.0001 0 0.0004 " Emission factor conversion based on footnote "a" of AP-42 Table 1.4-1 to convert from 1,020 Btu/scf to the above Fuel Heat Value in units of Btu/scf. " Ib/mo based on 31-day month CO2e Emission Calculations Conversions � 1 Metric Ton = 2204.62 Ibs 1 kg = 0.001 metric tons Pollutant kg/mmbtu metric tpy ton/mo� ton/ r COz 53.02 13,823 15,237 1,294 ' CHa 0.001 026 0.29 0 ., I Nz0 0.0001 0.03 0.03 0 COZQ = 15,252 1,295 � COze=COz+(CHq`21)+(NzO"310) � � "ton/mo based on a 31-day month _ _ -- —_ _ __ . . . — _ ___ O � 9 9 � � � � p ro � N �i Z ° : o [' ," �['' � 7". O O� Vl E _. .4 f?J a� o °' m °° °i � W .v'-� � � = � v ° � G p �; R � ,� � � W �� e MMM � � � .� z �a � � � � . 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F" 0. w �' z ' ,p . . ai i fa W m U �._: � N m 4 � ,. ,-, ii :�� . r/� ..... ..:.: v� _ .__ � _..�. .:. : v� �n Fort Lupton Gas Plant � Lancaster Plant Heat Medium Fired�Heater 1-4 � � ?rain 1 and Train 2 � � � � Heater Data Make; � Heat Medium Heater with Low NOx Bumers � Manufacturer. � Sigma Thermal � . . � Model: HC2-50.0-H-SF . Description H-6051, H-6052, H-6053& H-6054 Heat Output 60.00 (MMBtu/hr) Fuei Use 660.6 MMscftyr Efficiency: 078 (decimal) 56.1 MMscf/mo* Heat Inputi 76.9 (MMBYWh�� 'based on 31-day mon[h Operation: 8760 (hr/yr) Fuel Heat Value: �� 1020 (Btu/sc� - � Emission Calculations . � � � Emission Factors Emissions . Pollutant- Source Ib/MMscf Adjusted Ib/MMBtu Ib/hr Ib/mo` tpy Ib/MMscf' NOX manuf. 0.04 3.1 2289 13.5 CO manuf. 0.04 3.d 22S9 13.5 VOC AP-42 5.5 5.5 0.005 0.4 309' 1.8 SO2 AP-a2 0.6 0.6 0.001 0.05 34 ' 020 CHzO AP-42 0.075 0.075 0.000 0.006 4 ' 0.02 PM10/PM2.5 manuf. 0.005 0.38 286 1.7 Benzene AP-42 0.0021 0.0021 0.0000 0.0002 0 0.00 . Toluene AP-42 0.0034 0.0034 0.0000 � 0.0003 � . ��0 � . 0�.00. * Emission factor conversion based on footnote"a"of AP-42 Table 1.4-1 to convert from 1,020 Btu/scf to the above Fuel Heat Value in units of Btu/scf. " Ib/mo based on 31-day month CO2e Emission Calculations Conversions:� � . � 1 Metric Ton = 2204.62 Ibs � . � � � 1 kg = 0.001 metric tons � . Pollutant k /mmbtu metric ton tp tonlmo* � � C02 53.02 �35,727 39,383 3,345 , CHq � O.OOT 0.67 0.74 0.06 . N20 0.0001 0.07. 0.07 0.01 � COZQ= 39,421 3,348. � . COze=COi+(CHa*21)+(NzO*310) � * Ib/mo based on 31-day month � � � . - � 4/4/43" ' . State.co.us Executi�e Branch Mail-RE:Form 102 . � � , .� � 5#ate .. .. . .. . � . . : �� . : �.. . .n.N'. O ' �olorado � -- - -----. __._._------ ---- -- RE: Form 102 _ -----------_.—,---- Shea, Jennifer<Jennifer.Shea@anadarko.com> y � � Tue, Jan 15, 2013 at 2:56 PM To: "Chaousy -CDPHE, Stephanie" <stephanie.chaousy@state.co.us> � . Cc: "McMillan, Mark (Mark.McMillan@dphe.state.co.us)" <Mark.McMillan@dphestate.co,us>, "Jackie Joyce-�CDPHE Qackie.joyce@state.co.us)" <jackie.joyce@state.co.us>, "Laplante, Christopher 5. (Christopher.Laplante@dphe.state.co.us)" . <ChristophecLaplante@dphe.state.co.us>, "Money, Carissa D." <Carissa.Money@dphe.state.co.us>, "Carter, Micah" <Micah.Carter@anadarko.com>, "Bracken, Korby" <Korby.Bracken@anadarko.com> Stephanie, � I update the 102form to include the previously requested PM changes and update the 5O2 emissions on the form. I also included � updated Amine unit APENs since we will have no uncontrolled 5O2 emissions since it is�only a product of combustions created by� the control system. 1 induded H2Son the NCR APEN form since we will only have uncontrolled H25. I induded the calculation � sheets again foryour reference. The two generators are also on�the form 102. . � I�'i � We also need to update the emergency diesel generator(GEN3, Emergency generator). Upon review of the BACTconditions we 'I realized our horsepower is higherthan originally stated. I attached an updated APEN along with other documentation. The �, nettinganalysishasminimalemissionschanges, butincludedtheupdatesforyourreference. Carissa—CO2eemissionschanged . '�, slightlybutthatshouldn'taffectanythingelse. � � Jennifer Shea I Staff EHS Representative � ANADARKO PETROLEUM CORPORATION . . Dired: (720) 929-6028 � CeII: (303) 979-0040 � . � From: Chaousy- CDPHE, Stephanie [mailtostephanie.chaousy@state,co.us] � Sent: Friday,lanuary 11, Z013 5:19 AM . . To: Shea, ]ennifer � Subject: Re: Form 102 . �. . � Jennifer, . The APEN addendum KM pro�nded shows sulfur dioxide with uncontrolled emissions of 40,677.5 ib/yr and controlled of 2,033.9 Ib/yr. If S02 is created because of the control deu�ce, ihe it should be reviewed checked if it is greater than 1 TPY. in the case that I ha��on my � desk, SO2 is defnitely.greater than 1 TPY and will require a permit limit.�Please retiew what you ha�e pro�ided and let me know if there needs to be any changes. I belie�what you pro�nded me before (4/16/12) is correct . � Thanks, Stephanie https://mail.google.com/mail/?ui=2&ilr7faca29a38&New<pt&cat=Lancaster&search=cffi&th=13c4036e37b8ad44 � �/3 .__ ____. .__. _._ .. . . . . .._.. _.. ... . . .. . . . .__-------._.... .... ___ ....... _.. . . .. 4/4/13 � . � � State.co.us Executiee Branch Mail-RE:Form 102 . , On Wed, Jan 9, 2013 at 5:02 PM, Shea, Jennifer<,7ennifec5hea@anadarko.com>wrote: � , Stephanie, � � � I See response below. I haven't lool<ed at the Iast two, but will send you updated 102 Form. One of these is already induded in , . the netting, but I will sort it out and get back to you tomorrow. � � � From: Chaousy- CDPHE, Stephanie [maiito:stephanie.chaousy@state.co.us] � � . � Sent: Wednesday, January 09, 2�13 50:05 AM � � � To: Shea,]ennifer Su6ject: Form 102 � Hi Jennifer, � � Just reHewing the reNsed Form 102 recei�d in Decembec A few things . � � 1. For the new amine units: I still show 40,67Z5 Ib/yr of 502 on the APEN (com2rting to 20.3 TPY). The re�nsed form is showing 10.9 � TPY. I think we went back and forth on ihis for a bit, since technically: there is not uncontrolled S02 since S02 is only the product of combustion when the amine gas (H2S + H20)is sent to[he TO (conirol de�nce). I think we had decided to just put ihe uncontrolled H2S . emissions here in place of the S02 emissions? I don't think there should technicaliy be any unconirolled 502 emissions on the 102 form since it is only created because of controls. - 2. Point 054: KM submitted an APEN for a permit-exempt mitsubishi engine on 2/1/12. It is exempt, bu4 not listed on form 102 or the netting. � � � 3. Point 055 is not listed on the form (John Deere diesel engine, Platte Valley (S022). it was also not included in the netting. A new application was received for this point on 3/22/12 � I justwanted to let you know for FYI and to add to ihe netting. � Thanks, Stephanie Chaousy, P.E. � � . . Oil and Gas Permitting Engineer , Department of Public Health and Environment . . . � 303-692-2297 . � www.colorado.goulcdphe � � Anadarko Confidentiality Notice: 7his electron�c transmission and any . attached documents or other v,�ritings are intended only foz Che person � .oz entity to c�hich it is addressed and may contain infozmation that is . privileged, confidential or otherwise protected $om disclosure. II you � � have received this communication in error, please immediacely notify . sender by retur� e-mail and destroy the communication. Any disclosure, � https:Omail.g oog Ie.coMmail/?ui=2&ik=7faca29a38&vewr-pt&cat=Lancaster&search=cat&th=13c4036e3768ad44 ?J3 4/4/'3 " State.co.us Executi�Branch Mail-RE:Form 1D2 � , conying, distributio� cx the raking of ar�y acr-�-_on concerning th= contents . . of this communication or any attachments by anyone othex than Cne � r.amed xeciplenL i: str'sctly prohibit;a:d. . � � ' � Stephanie Chaousy, P.E . Oil and Gas Permitting Engineer Department of Public Health and Enu�ronment � � � � 303-692-2297 . . . . www.colorado.gou(cdphe � Anadarlm Confidenti.aiiCy Notice: 7his eiecCronic tsansmSssion snd any att>ched documents or other writings are intended only for th? p=rson - . or ent.ity t.o whi.ch. it is add.ressed and may co�cain informaTion t.hat is . pri.vil.eged, confidenti.al, or otner.wi.se orotected from di.scl.osur.e. If you have received this communica+ion in error, please i.mmediately notif'y � sender by retur�� e-mail zc�d destroy the commun'�_cation. Any disclosure, � ' � � conyinq, d:�.st.ri.nu[ion or the taking o₹ any acti.on concerning the conSents � � of this connuni.r,ation or any attachments by anyone other than thz named xecipient i,=, stricCly prohibited. � � � .._ . _....._.._.. ..._......_ .. __..___' ... .......... . . ._.........� . ......_,�. 5 attachments . � �r� 2013-01-15 LAN GEN3 APEN.pdf � � . � � 763K -�i,_ 2013-01-05 GEN3 Cat Specification Sheet.pdf � � 74K v� 2013A1-15 A-b to A-4 APENS.pdf � � � 4266K � � . ta� 2013-01-15 LAN APCD-102 Form.pdf. � . 28K s�� 2013-01-15 LAN Emission Calc Sheets.pdf . 96K https://mail.google.com/mail/?ui=2&ik=7fzca29a38&viev�pt&cat=Lancaster&search=cat&th=13c4036e37b8ad44 � . 3/3 .. _ __---- . . . ..- __.. ' � . . . ._.... ._.... . _._.._ _.. _. ....__.. ... . . . .. _..._.._ . . Fort Lupton Gas Plant Lancaster Plant Mole Sieve Regeneration Gas Heater 1 and 2 Train 1 and Train 2 Heater Data Make: Mole Sieve Regeneration Gas Heater with Uftra Low NOx Burners Manufacturer. ZEECO USA, LLC Model 35M Megafire AIRS ID: TBD Source ID E-2015 & E-2016 Heat Output 25.0 (MMBtu/hr) Fuel Use 255.6 MMscf/yr Efficiency: 0.84 (decimal) 21.7 MMscf/mo" Heat Input: 29.8 (MMBtu/hr) *based on 31-day month Operation: 8760 (hr/yr) Fuel Heat Value: 1020 (Btu/sc� Emission Calculations Emission Factors Emissions Pollutant Source Ib/MMscf Adjusted Ib/MMBtu Ib/hr Ib/mo` tpy Ib/MMscf* NOx manuf. 0.04 1.2 886 52 CO manuf. 0.040 1'2 886 52' VOC manuf. 0.019, 0 6' 421 ' 2:5 PM10/PM2.5 AP-42 7.6 7.6 0.007 02 165 1.0 SOz AP-42 0:6 0.6 0.001 0.02 ` 13 -0 08 CHZO AP-42 D:075 0.075 0.000 0:002 2 0.010 Benzene AP-az 0.0021 0.0021 0.0000 0.0001 0 -0.0003 Toluene AP-42 0.0034 0.0034 0.0000 '0.0001 0 0.0004 * Emission factor conversion based on footnote "a"of AP-42 Table 1.4-1 to convert from 1,020 Btu/scf to the above Fuel Heat Value in units of Btu/scf. ' Ib/mo based on 31-day month CO2e Emission Calculations � Conversions: � .. � 1 Metric Ton = 2204.62 Ibs 1 kg = 0.001 metric tons Pollutant kg/mmbtu metric tpy ton/mo* ton/ r COz 53.02 13,823 15,237 1,294 CH4 0.001 026 029 0 N20 0.0001 0.03 0.03 0 CO2e= 15,252 1,295 COze=COz+(CHq*21)+(NzO*310) � � � "ton/mo based on a 31-day month Fort Lup4on Gas Plant � Lancaster Piant Heat Medium Fired Heater 1-4 . � � Train 1 and Train 2 Heater Data . Make: Heat Medium Heater with Low NOx Burners � � Manufacturer: SigmaThermal Model: HC2-50.0-H-SF Description H-6051, H-6052, H-6053& H-6054 � Heat Ouy ut 60.00 (MMBtu!>r) Fuel Use 660.6 MMscf/yr Effcienc : 0.78 (decimai 56.1 MMscf/mo� . Heat lnput �76.9 (MMBtu/hr) � 'based on 31-day month Operation: 8760 (hrtyr) Fuel Heat Value: 1020 (Btu/sc� Emission Calculations Emission Factors Emissions Pollutant � Source Ib/MMscf Adjusted �b/MMBtu Ib/hr Ib/mo` ipy Ib/MMscf' NOx manuf. 0.04 3.1 2289 ' 13:5 CO manuf. 0.04 3.1 2289 13.5 VOC aP-a2 5.5 5.5 0.005 0.4 309 1.8 SOZ AP-42 0.6 ' 0.6 0.001 A.05 ` 34 0.20, CHZO AP-42 0.075 0.075 0.000 0.006 4 0.025 PM10/PM2.5 manuF. 0.005 D.38 28fi 1.68' Benzene AP-a2 0.0021 0.0.021 0.0000 0.0002 0 O.OOD7 Toluene AP-42 0.0034 0.0034 0.0000 0.0003 0 0.0011 "Emission factor conversion based on footnote"a" of AP-42 Table 1.4-1 to convert from - 1,020 Btu/scf to the above Fuel Heat Value in units of Btu/scf. � � � *Ib/mo based on 31-day month � � . � � CO2e Emission Calculations Conversions: 1 Metric Ton= 2204.62 Ibs � � 1�kg= 0.001 metric tons � � . Pollutant kg/mmbtu metric ton tp ton/mo* - COZ 53A2 35,727 39,383 3,345 � . CH4 0.001 0.67 074 0.06 . � N20 � 0.0001 0.07 0.07 0.01 � COZQ= 39,421 3,348 COze=COz+(CHy*21)+(Nz0"310) � . � *Ib/mo based on 31-day month FoH LuptomGas Plant � � Lancaster Plant Amine Treater Vent Stack Emissions-Train 1 � � � Source ID A-7,A-2,A3&A-4 � . AIRS ID TB� . . Source Oescription �50 MMSCFD Amine Treaiing System,Train i(2 each)antl Train 2(2 each) � - Potential operation 8760 hrstyr � � Amine Simulation Results 41t2/'12) CO2e Emission Calculations - Acitl Gas Plash Gas Conversions Flowrate(MMscftl) �4,4W �0.�205 Pressare(psi9) B b0� . . � Molar Volume(o Mola�Mass 379.3 scf/Ib-mole Tem eraNre(°F) 120 � 156 � Composition �.�INoI%� � � �Mol%�' .Ilbllb-molc GHG Calculation Acid Gas Flash Gas Nilrogen 8.651E-OS � . 0.131 28.01 Pollutant scf/yr tons/y� sci/yr tons/y� CO2 9L3�J0. �10.381 44 C0p 1q70992420 85319.69 4.57E+06 265 � HytlroqenSulfitle .'1.355E-02 1.880E-03 34.08 . Methane �. �.349E-Ot G3,B671 �� 16.04 COip�tpy�= 65�685 Ethane �3.728E-02 11.9Ai3 30.07 COie([onlmo)'= 7,269 Propana ��1,327E-02�� . 42'115 44.1 �camwa�ionmemoarcompvimoscHccompe�a�ums.iz � n-Butane 7.35�JE03 � ib973 58.12 •co,ppy�=�snryry�scnin.mole]��mw�ipbvron� � i-Butane �2760E-�2� � 1.85A 58.12 •�ommoeaseoo�aieaymo�m n-Pentane 8.631E�09. 02542 ]2,15 . _ i-Pentane 9.570E�04 . 02818 ]2.15 VOC Emission�Calculations � � n-Hexane 9.9,�'i5E-OA�. 024A5 . 86.1� � Water 8.373C-+00�� 5228 Conversions � Tolal � 100.0 100.0 Molar Volume to Molar Mass 379.3 scf/Ib-mole VOC Calculation Acid Gas Flash Gas � PolWtant scf/ r tons/ r scf/ r ions/ r � � Pro ane 2.14E+05 12 �.85E+06 108 n-Butane � L18E+05 9 Z03E+05 54 � � � i-Butane 4.44E+05 34 8.15E+05 62 � n-Pentane iB9E+04 1 t'12E+05 it � i-Pentane 1.54E+04 1 t2qE+05 12 n-Hexane 1.60E+04 2 1,08E+05 �2 Uncontrolled VOC 1.1 Factor = 350.6 Ib/mo' � VOC z 99%Control Efficiency 3.5 596 "Ib/mo based on 31-day month . I Port Lup�on Gas Plan� . � LanwsMrPlantFmineTreaterThermalOxldizerEmissions,TrainlantlTrain2 � � Source ID � A-T01.P-TO$H-T03.A4D4 . . AIRSID TBD � SourceDescriplion TrsinlantlTrain2ThermalOxid-¢ettoContmlAmineTreater(AU4) Polentialopera�ion 8]60 htsryi "sVeam vnll be mu�etl to emergency�are wM1en TO Is tlown. � CombustlonEmissionCalculations � NmineSimulationResultz�011LII1 . . HqtlGas Fla5hGas � conversions Floma�eirai:asr.r<p e!m oizos � MoleNolumeloMolarMess � 3)93sc/lih-mole Presaure(pslol E 6� � TemeraWr5PF) �2G �56 Hoo�ai' Rminostillwnt � Compa.ition IdoPG Idol% Ib!IWinole. � Combustlon entl9mhges�� NeotConlaN � � . ComPenonf Fo�mule 181uIItiY: Qdl�rl... �BiWM1r] .�'. . .. . metM1ane CHd 21502 �66.0866 3141153 Nlim�en 065fE�05 0.131 2BOt e�M1ane C2H6 20616 52.9853 100194] W2 B1390 tU391 44 pmpane C3HB t9929 29.4193 546d40 HtlmenSulfitla 1,JSSE-02 1890E03 3008 . n-bu�ane C4H10 19665 143605 202C0� Idnt�ane � 1:300E01 B3.BW1 1E.D4 � Isobutane C4H10 19614 22.0340 4321]4 EIDana 1]20E�02 1L9Ai3 30.W n-pen�ane CSHt2 19d99 2]294 53221 Pmpaoe 1.3PEOJ A2115 -04.1 Isopen�ane CSN12 19d51 30258 56855 n-Butane i359E-0J 199%3 58d2 n-Hexapa C6H14 19200 32044 61525 bBNene 2IBOE02 1BSd 58.4 Total(BNIhr= 565]519 o-Pentane O6]tE-09 025M12 ]2.15 B�Waf= 3�.0 i-PenYnne B.Si0E0E �2ft10 ]215 � rvHnxane 4NSSE�00 02h45 B6t] . � Heatlnput Wutei N3]3G'00� 52?0 TOBumerHea� RamNmineStill AuxiliaryFuel TetalHea�lnput hn�y� � Ra�ing VenlantlFla5F Gas �MMBiulh�� Toial 1000 1�09 �MMB[ulM1r� Gas�MMe[ulb�� (MMB�u/hQ BO0 5.] 3.00 16] W60 - Pollu�anl Ib/MMscf IbIMMBW Ib0/ �onl i Iblmo' � � NOx 100 0.10 1.83 )9 133] CO 04 OA6 13) fi6 N23 'roc n � a.a� 8srnn"sa5 �5�1° "t"kNtY;i d ^ryil?b"�R voc t.t o.ao 002 oos u � � PM otal) J6 P.45E.03 O.t2 06 102 � 502 0.8 � S BBE-04 0.01 0.05 B � CH2O 0,0I5 4.35E-05� 0.00 00 1 g¢nzene� 04021 1.Q6E-ae 0.00 0.0 0 . Taluene 0.403 9.03E-08 0.00 �0 0 'AP22emissionlactors,Tables14d,1.6-2�antl16-3 � - � 'Tolelemisslons(Ipy)'1 1(acto� . °pssumetlVOC=10%xM1offuel e � CO3e Emission Calculations Conversi iMe�ncTons� 22�4ffi Ihs f kg= 0001 meLiclons � � Pallu�ani k ImmbW melric[onl� � � COz SJ02 >,939 8,52821 � cH, 000� � o.�s ota Nz0 0.0001 0�1 002 Iblmo CO�p= 0,53� ]25 " � C -C +CH�21�NO]ID 502 Em n Glculalons � . . Canveaions� � � MolallolumeloMolarMess 3993 scfllb-mole S02 qfomlc We1 01 64 05 amu . . H25 Fllomlc Wei M1� 3C.06 amu . NCItlGesConVol% 9500% lmitlGas FlaskGas � Pollulant IbIM1r t Ih/hr t . � H25 2238E+00 8.001E+40 9.482E-03 3]i5E02 �� 502 i8.4 O.W � Emission Faqors' Emission Factors' . U wntmll tl U 'ts Conrollea Uni1s H25 0.40 IbIMM5CF 0 IbIMMSCF . . 502 0 IbIMM5CF 0.04 IbIMMSCF . Unronhalletl Emissians' Con�rolletl Emissions' Iblht Iblmo 1 Iblhr Iblmo t � � H25 25 1830 108 0.00 0 600 . S02 4 0 0 023 1]2] 102 . 'Total emissiens x 1 d faclor 'Iblmobasetlone3l-tlaymonlF � . � � � Fort Lupton Gas Plant F-2 and F-3 Lancaster Plant Process Flare 1 and 2 . Source ID Num6er � F-2 and F-3 SCC � � AIRS ID Unknown � Source Location Zone: � � Source Description Flare HorizontaP � � Flare Make Unknown Potential Operetion 8760 hdyr Flare Model Potential Fuel Usage 10.5 MMscf/yr � Serial Number Date in Service Stack Height 40 ft � Flare Confguration AirvAssisted Stack Diameter � 30 in Fuel Heating Value. 1020 BtWscf Exit Velocity 60.0 ft/s � Flare Pilot Rating 0.5 MMBtu/hr Etit Temperature 1000 deg F Flare Purge Gas Rate . 707 scf/hr Volume Flow Rate 17,671 ft'/min Purge Gas Heat Rate OJ21 MMBtWhr - Process Gas fo Flare 75.0 MMscftyr � Process Gas Heating Value 1275.0 BtWscf � Process Gas Heat Rate � � 10.9 MMBW/hr � %VOC Content of Process Gas 220 Combustion Emission CalcWations � � Heat Input � MMBtu/hr hrslyr � 12.14 8760� � Pollutant Ib/MMBtu' Ib/hr tonl r Ib/mo* NOx 0.138 1.67 7.3 1246 � CO 0.28 3.34 14.6 2488 VOC 0.03 0.37 L6 278 � 'Nrnanacoem��sionrecmrsrmm'rcea . . � °Used�1P12THCemisslonFaclor t0161bIMM8N'%VOCCon�entofpes 'INmo is basetl on a 31day mon�h CO2e Emission Calculations - Conversions: . 1 Metric Ton= � 2204.62 Ibs . . � i kg= 0.001 metric tons � Pollutant k /mmbtu � metric[on t � ��s � 53A2 5,637 6,213.87 � - � . �Hn 0.001 0.11 0.12 Nz0 0.0001 0.01 0.01 � COze([py)= 6,220 . COze(ton/mo)*= 52827 `ton/mo based on a 31-day month � � . � COz,=COi+(CHa2p+(NzO'310) � � . � 502 Emission Calculations . Conversions: � - . . � � Inlet H2S Concentration 4 ppm Molar Volume to Molar Mass 379.3 scNlb-mole . 502Atomic Weicht 64.05 amu � �H25AfomicWeiqht � 3408amu � Pollutant Process Gas . Ib/ r t H2S 2.918E+01 1.459E-02 . S02 0.03 � Total S02 emissions(tpy)' � 0.03 � � ` otal emissions 1.1�factor i 0o N.� �;,,,. �:� • ��:.� iyqPm�� aum eox exo voc xns eenune ioi�ena e enaene xyiennv nxanvnv oo��ion xylene nv �Na�as ir ee m ee�ykLq�u�qn Wn�Enmare �n.Ense� � p rs b W ryAm vnqnrem�'aeWOmenimue�muac+n�uersU�ona p+�N�sl�n<5'M�ssat� . — ForY Lupton Gas Plant Engine Detail Sheet Source ID Number GEN3 Source Description Lancaster Plant Diese6Powered Standby Generator Engine Engine Usage Power Emergency Generator-EPA Tier 2 Engine Make Caterpillar Potential operation 500 hrtyr Engine Model C18 DITA Displacement 3.0 L/cyl Serial Number TBD Potential fuel usage 19950 Gal/yr Manufacture Date TBD 39.9 Gal/hr Date in Service TBD Stack ID GEN3 Maximum Rating 839 BHP Stack Height 10 ft Fuel Heating Value 18,390 Btu/Ib Stack Diameter 0.67 ft Heat Rate 5.86 MMBtu/hr Exit Velocity 215.4 ft/s Engine Heat Rate 6988 BtWhp-hr Exit Temperature 969 deg F Engine Heat Rate 0.38 Ib/hp-hr Volume Flow Rate 4,552 ft'/min PTE Emissions Pol lutant Emission Factor Rating �pH st�ng Estimated Emissions Source of Emission Qb/MMBtu) (g/hp-hr) (hp) (hrs/yr) (Ib/hr) (ipy) Factor NOx 1.75 5.56 839 500 1028 2.57 Manuf. Data CO 0.11 0.35 839 500 0.65 0.16 Manuf. Data VOC 0.00 0.01 839 500 0.02 0.00 Manuf. Data SOx 1.01 320 839 500 5.92 1.48 AP-42, Table 3.4-1 PM10 0.06 0.13 839 500 024 0.06 AP-42, Table 3.4-2 PM2.5 0.06 0.13 839 500 . 024 0.06 AP-42, Table 3.4-2 . � HAPs HCHO 7.89E-OS 0.00025 839 500 0.00 0.00 AP-42, Table 3.4-3 Benzene 776E-04 0.00246 839 500 0.005 0.00 AP-42, Table 3.4-3 Acrolein 7.88E-06 0.00002 839 500 0.000 0.00 AP-42, Table 3.4-3 Acetaidehyde 2.52E-05 0.00008 839 500 0.000 0.00 AP-42, Table 3.4-3 Propylene 2.79E-03 0.00884 839 500 0.016 0.00 AP-42, Table 3.4-3 *Used HC emission factor CO2e Emission Calculations Conversions:� � � � . 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', Z � ai � N � ¢. s u°`� o ' O � � o o ai °�' m cn `� °� s i Z � z � V � � aZi E u� c� � � o > Z C o � Q �ENz � � 'C ,-�' ,� � � _ m J � — a� � � o o � � = E o. �, o '� � m cn co � � � � � € I d o m a�`� � U Q U � � � <A � Z u°. d U d � W �fESEL GENERATOR SET � ♦ �r�-r- S T A Iti D � Y � ��, �,� , i '�" m��' 550 ek�/ 6�8 k�/A �� y �� :E ��'� 60 Flz 1�0(l r�r� 4.�0 i/oBt� r �� ,�;; Caterpillar is leading the power generation '..�'x "-- marketplace with Power Solutions engineered to deliver unmatched flexibility, expandability, reliability, and cost-effecYiveness. . . Image shown may not � � refiect actual package. � � � � . - FE�Tl1RES FUEL/EMISSIONS STRATEGY CAT�C78 ATAAC DIESEL ENGINE • EPA Certified for Stationary • Utilizes ACERTT"^Technology Emergency Application • Reliable, ru (EPA Tier 2 emissions levels) 9ged, durable design • Field-proven in thousands of applications DESIGN CRITERIA worldwide •The generator set accepts 100% rated load in one ° Four-stroke-cycle diesel engine combines step per NFPA 11D and meets ISO 8528-5 transient consistent performance and excelle�t fuel response. economy with minimum weight • Electronic controlled governor UL 2200 (CSA- Optional � UL22001isted packages CATGENERATOFi • CSA Certified ° Matched to the performance and output Certain restrictions ma a I characteristics of Cat engines y pp Y� ° Load adjustment module provides engine relief Consult with your CatOO Dealer. upon load impact and improvesload acceptance FULL RANGE OF ATTACHMENYS and recovery time � Wide range of bolt-on system expansion ° UL 1446 Recognized Class H insulation ' attachments, factory designed and tested I • Flexible packaging options for easy and cost CAT EMCP 4 CONTROL PANELS effective instailation • Simple user friendly interface and navigation • Scalable system to meet a wide range ot SINGLE-SOURCE SUPPLIER customer needs • Fully prototype tested with certified torsional • �ntegrated Control System and Communications vibration analysis avaiiable Gateway WORLDWIDE PRODUCT SUPPORT SEISMIC CERTIFICATION ° Cat dealers provide extensive post sale support • Seismic Certification available ' including maintenance and repair agreements ' Anchoring details are site specific, and are I ^ Cat dealers have over 1,800 dealer branch stores dependent on many factors such as generator set operating in 200 countries size, weight, and concrete strength. , • The CatOO S•O•Ss'" program cost effectively detects IBC Certification requires that the anchoring ; internal engine component condition, even dhe system used is reviewed and approved by a presence of unwanted fluids and combustion Professional Engineer i by-products • Seismic Certification per Applicable Building � Codes: IBC 2000, BC 2003, BC 2006, IBC 2009, ' CBC 2007 � Pre-approved by OSHPD and carries an OSP-0084-10 for use in healthcare projects in California STANDBY 550 ekW 688 kVA � � . � � 60 Hz 1800 rpm 480 Volts FACTORY INSTALLED STANDARD & OPTIONAL EQUIPMENT � Standard O tional � S stem []Single element air filter Air Inlet - •Light Duty Air Filter . � •Service indicator [] Dual element airfilter . []Heavy-dutY dual element air filter with precleaner []Air inlet shut-off � Cooling �:�- � - �•.Radiatorpackagemounted �� f]Radiatorductflange - � � ��•�Coolant level sight gauge - .. � f 1�Low:coolant level sensor � � •�Coolant drain line witHvalve . � � . � � . � � - �•Fan and 6elt guards - �� . � �•CatO Extended Life Coolant* � � ��- � � � �� Exhaust •Dry exhaust manifold []Industrial []Residential [1 Critical Mufflers - ��•Stainless steel exhaust flex fittings with split-cuff []Manifold and turbocharger guards •Exhaust flange outlets (1 Elbows and through-wall kits Fuel . •Primary fuel filte�with integral water separator f]Integral single wall fuel tanli base -� � � � ' •Secondary fuel filters �. . . � l]Integral dual�wall UL fuzl tankbase � � � •Fuel priming pump� � � . . � f)Sub base dual wall UL listed fuel tank base � � � � •Plexitilefiue(lines � � � � . � []Manual transfeFpump . � �� •Fuel cooler" � ' � []Fuel levelswitch ' � �� *Nofinicuded�with packages without radiators � � Generator •Class H insulation [1�versize generators •Class H temperature rise l]Internal excited (IE) •VR6 voltage regulator with 3-phase sensinq with load [1 Permaneni magnet excitation(PMG) . � � � adjustment � [1 Cat digital voltage regulator(CDVRI with kVAR/PF •IP23 Protection control []Anti-condensation space heaters � [7 Coastal insulation Protection(CIP) - []Reactive droop :PowerTermination •Powet�Center houses EMCP controller and � � f]Power Center mounting option Iright side)� � . � � � � � . power/conVol terminations(rearmountedY � ��[1 Multiple circuit breaker options ��. � � � � •Circuitbreaker,VLlisted,3pole:180%&�100%Rated) [1C.B.Sfi.unttrips � - •Circwt breaker,IEC compliant,3�-4 pole(100%Rated) .(1 C.B.Auxiliary.contacts � � :•Segregated low voltage wiring termination.panel � . . � . �. . � ..� . .,IP22 protection.� � .. . .. . � . .. . .. . � -•8ottom cable entry� . � � � Govemor � - •ADEMT"^A4 � . []Load Share Module � . � Control Panels �•EMCP�4.1.(mounted in Power Center) � � �� . �� [1 EMCP 4.2 � �� . .. . � � � . . � � � .t-hand mounted Power Center R ih . . . . � [1 9 . . ad'ustment. � � � . . . . . . •Speed � . .. . . . Local.annunciator module WPPA 99/110). 11 �� . � •.Voltage�adjustmen4� �� •Emergency stop��pushbutton . . .� I]Remote annunciatot module INFPA 99/110) . � . � . . . . . odule . . . . .. . �� (]Digital I/O m � �� Lube •Lubrlcating oil � [1 Oil femperature sensor . •Oil drain line with valves � ( 1 Manual sump pump �� Oil filterand dipstick � � •Fumes disposal � � •Lu6e oil level indicator � •Oil cooler : . � Mounting : . � •Formed steel narrow 6ase frame� .. � � � I 1 Oil skid base .,� � � �.� •Lineer vibration isolation-seismidzone 4 . � []Formed steel wide base�freme � � � �� ]Jacket water heater with shut-off valves ' Starting/Charging •24 volt starting momr �]Engine block heater� � � . . •24 volT,45 amp charging altemator � ��Ether starting ald � ' � � []BatterY disconnect switch �. - . [] Battery chargers(5 or 10 ampl � . � []Oversize 6atteries � � �i � . - . []Batteries with rackand cables � � - . �� General�, •Paint-Caterpillar Yellow except�rails and radiators [�1 UL 2200 package � gloss black '� [1 CSA Cartification :..� ��. •Flywheel housing-SAE No.0 � []�EU or CE Certificate of Conformance �� !]Weather pro4ective enclosure .- � � � �� . []�.Sound attenuated proteotive enclosure �. . ! � � � � f]Seismic Certification per.ApplicableBuildmg Codes�� ' -� ��IBC 2000,.IBC 2003,I8C 2006�,�IBC 2009,CBC 2007 < �'i z January 15 2013 10:11 AM ' S7`AIVD�� 5�0 ekV1/ 6�8 ki/�. � 60 Hz 7800 rpm 480 Volts � � � � a7rElr��ils�G IQ1tls . . CAT GENERAYOR CAT EMCP 4 SERIES CONTFiOLS Framesize................................... ............LC6114G � . """""•�•�� EMCP 4 controls including: � Excitation........................................................Self Excitation -Run/Auto/Stop Control � Pitch.................................................. .0.6667 � . """""�•��•��•��•�� Speed and Voltage Adjust � Number of poles.............................. � . . """""'��•�� • - Engine Cycle Crank � � . ............ Number of bearings...................................... Single bearing -24-volt DC operation � Number ot Leads................... . . . � . .012 -Environmental sealed front face � . . . ........... . ..... ................. Insulation.,....�:................ UL 7446 Recognized Class H with -Text aiarm/event descriptions tropicalization and antiabrasion -Consult your Caterpillar dealer for available voltages Digital indication for. . IP Rating........................................................Arip Proof IP23 -RPM - . Alignment.............................................................Pilot Shaft -DC volts � Overspeed capability........................................................725 � - Operating hours . . Wave form Deviation (line to �ine).................................2%o -Oil pressure (psi, kPa or bar) � . Voltage regulator............................ Three hase sensin -Coolant tempereture � .... p g Voltage�regulation..,..,....,.Less�than�+/- 1/2% (steady state) -Volts (L-L&L-N�,frequency(Hz) Less than +/- Yz°/p (w/3%o speed change) � -Amps(per phase &average) . -ekW, kVA, kVAR, kW-hr, %kW, PF(4,2 only) � CAT DIESEL ENGINE Warning/shutdown with common LED indication of: C78 ATAAC, I-6,4-Stroke Water-cooled Diesel - Low oil pressure � � Bore.........:.....�..............,........................,.145.00 mm (5J1 in) -High coolant temperature . ��,. Stroke....................................................... 783.00 mm (7.2 in) . -Overspeed . . . . �'. Displacement.........................................18.13 L.(1106.36 in') -Emergency stop � � Compression Ratio.,.....................................................14.5:1 -Failure�to start(overcrank) � � Aspiration..............�.........................,.Air-to-Air Aftercooled . - Low coolant temperature � � Fuel System...................................................................MEUI - Low coolant leve� � � ,. . Governor Type................ Caterpillar ADEM control system Programmable protective relaying functions � '�� . . -Generator phase sequence � . . . . -OvedUnder voltage (27/59) . � � -Over/Under Frequency(81 o/u) ' � � - Reverse Power (kW) (32) (4.2 only) . '�� -Reve�se reactive.power(kVAr) (32RV) � -Overcurrent (50/51) Communications: � . � � � . - Four digital inputs (4.1) �� -Six digital inputs(43 only) ! � - Four relay outputs (Form A) � ��. -Two relay outputs (Form C) . ' . . -Two digital outputs � . ,' . � � � -Customer data link(Modbus RTU) (4.2 only) , �� -Accessory.module data link (4.2 only) �� . - Serial annunciator module data link(4.2 only) � � . -Emergency stop pushbutton � � Compatible with the fol�owing: � -Digital I/O module . � � . - Local Annunciator � � . � � . � � - Remote CAN annunciator . , - Remote seriai annunciator 3 January 15 2013 10:11 AM Sl'P�ND�Y 550 ekV1l 688 kifA � . 60 Hz 7800 rpm 480 Volts � � TEC�ENICA.L DATA Open Generator Set- -1800 rpm/60 Hzl480 Volis � DM8517 EPA CeKified for Stationary Emergency Application (EPA Tier 2 emissions levels) GeneratorSetPackage:Performance� � � � . 687.5kVP. � �� Genset Power rating @ 0.8 pf : �. � �� 550.ekW � � � � � ' GensetPower retinc�.with fan � . � Fuei Consumption 151.1 L/hr 39.9 Gallhr 100% load with fan 118.2 Uhr 31.2 Gal/hr 75% load with fan 86.0 L/hr 22.7 Gal/hr 50%load with fan � . . . � - � - . . � . - �. � �CoolingSystem'� � .. � � �� 0�.12�kPa . . .�. -O.48in.�water � �. � Airflow7estrictionlsystem) .�. �� : .. � � �� 804:m3/min �. 28393�cfm � .Air flow..(max @ rated�speed for rediator arrangementl . � � . � $� 8� - � 21.6 gal � . , � � Engine Coolant capacity with�radiator/exp.tanlc � . 20.8 L �.� 5:5 gal : � Engine coolant capacity � � � � � � � � . � 67.0 L � 76.7 gal � � � � � . Radiator coolant�capacity� � . Inlet Air 46.3 m'/min 1635.1 cfm Combustion air inlet flow rate � . . �� ExhaustSystem. . . . � � . . . � 520:6°C� � � . �� 969.1 °F . . . Exhauststackc�astemperature � � � . . . � �pg,gm'/min . . . 4552.1�cfm � � �. Exhaustgas flow rate� �� . 203 mm � � � � 8 in ��.: � �� Exhaust flange siie(intemal�diameier) �� . �� 70.0 kPa 40.2 in.water � �� fxhaustsystem6ackpressure�imaximum.allowable) Heat Rejection 180 kW 10237 Btu/min . Heat rejection to coolant(total) 595 kW � 33838 Btu/min � al 79 Btu min , Heat rejection to exhaus[(mt 1 141 I<W $� � � Heat rejection to aftercooler ��kW 4379 Btu/min � I Heat re ection�to atmosphere from engine 32.6 kW 1854.0 Biu/min 1 I Heat rejection to atmosphere from generator .. Alternator' �' �� . � � �`1445 skVA . . � � � . ' Motor starting capabilitY @ 30%voltage dip �� . � LC6114G � � � .. � Frame�, � . . � � � . 130°C � . 234°F �. � �Temperature Rise � � . Lube System � 34.0 L 9.0 gal Sump refill with fiiter . � � � � EmissionslNominalP" . � �. � �� .. . . � . � . 5.569/hP':hr �. � � . . . � . i ��NOz 9IhP-hr . . .. � � �� . . � . . . .35 g/hp_h� .. .. .. . . . � . . ' .:CO9/hp-hr .. . . . � . � . . . . .. . ' � A19/hp'hr . . . �' HC 9/hP-hr �. � . . � .033 0/hp-hr �. � . . . '� PM 9/hp-hr � . �. . . . �. . . �� .. . . . . .. . . , . . ' 'Foc ambient and altitude capabllities consult your Cat dealer.Air flow resiriciion (system!is added to existinq restriction from factory. 'Generator temperature rise is based on a 40�C(104°F) ambient per NEMA MG732 Some packages may have oversized generators Iwith a different temperature rise and motor starting characteristics. �� 'Emissions data measurement procedures are consistent with those described�in EPA CFR 40 Part 89,Subpart D&E and ISO8178-1 for I � measuring HG CO,PM,NOx. Data shown is based on steady state operating conditions of 77°F,28.42 in HG and num6er 2 diesel fuel with 35°API and LHV of 18,390 btu/Ib.The nominal emissions data shown is subject to instrumentation, measurement,facility and engine ' to engine variations.Emissions data is based on 100%load and thus cannot be used to compare ro EPA reguiations whlch use values . 6ased on a weighted cycle. � � � � . . . Iq January 15 2013 10:11 AM ' ----. . — __-- STAIVD�I' 550 elcl/V 688 k\/A � 60 Hz 7800 rpm 480 Volts � �ATIIV(3 DE�ifVITIORES ,4P�1D CON�[TIONS . Meets or Exceeds International Specifications:AS1359, � � Ratings are based on�SAE J1349 standard conditions. CSA;IEC60034-1, ISO3046, ISOS528, NEMA MG 1-22, These ratings also apply at ISO3046 standard conditions. NEMA MG 7-33, UL508A,72/23/EEC,98/37/EC, Fuel rate5are based on fuel oil of 35°API [76°C (60°F)1 2004/108/EC gravity having an LHV of 42 780 kJ/kg (18,390 Btu/16) Standby- Output available with varying load for the when used at 29°C (85°F)�and weighing 838.9 g/�iter duration of the interruption of the normal source�power. � (7.001 16s/U.S. gal.).Additional ratings may be available Average power output is 70% of the standby power for specific customer requirements, contact your Cat rating. Typical operation is 200 hours per year,with representative for details. For information regarding Low maximum expected usage of 500 hours per year. Sulfur fuei and Biodiesel capa6ility, please consult your Standby power�in accordance with ISO852S. Fuel stop . Cat dealer. power in accordance with�ISO3046. Standby ambients � shown indicate ambient temperature at 100% �oad which resuits in a coolant top tank temperature just below ihe � � shutdown temperature. - � . � January 15 2013 10:11 AM I STAND�Y 550 elc�/i! 6�� c0/A � ' 60 Hz 7800 rpm 480 Volts - DIMENSIONS . � PaCk7gg�ifllC�SIOfIS � NOTE:For reference only-do not use for � Length 4237�.4mm 166.83�in(� � . installationdesign. Pleasecontact � 1536.0 mm 60.47 in your locafdealer for exact weight Width and dlmensions. (General . Height 2165.8�Im 8527�in� Dimension Drawing#3728295). I � � www.Cat-ElectricPower.com , I r Performance No.: DM8517 2013 Caterpi la . All rights reserved. �� Feature Code:C18DE96 MaTerials and specifications are subject to change without notice. � � � � The InYemational System of Units ISI)is used in this publication. �� Gen.Arr.Number.2476127 � � CAT,CATERPILLAR,their respeciive logos,"Caterpillar Yellow;'the � "Power Edge"trade dress,as well as corporate and product identity.used � Source:U.S.Sourced . herein,are trademarl<s of Caterpillar and may not be uspermisslon. January 75 2013 21372656 � , 6 , o b 9 v � o � e � _ � � . � Q E � o F � �. �� p = � E" � �o. w Z o w �n ... � 'o p, �.. y P' d " . W � � .r. = 5� ti ❑ ¢ . �a � „ z � � z . p . � � . v . E w n°�n.�`�. � �n M �n E .: r�- .c� . � O T � � � °� ma rnw � �a CW7 p � ? « 7 S .v � ai `u� y � io � � �c .. a .. W � �� cLl m �. p" E m m�n c � 8 � � . o � N � ❑ o a. m � �0 0.Ui �� a� a L o 0 o c �" .C 'C 0 o ti r. o � v'�, o a � o m m a �'" `� � 'S �k � a a � G O � � N I� � O c � [,w� a � � v d � � ',�7, � '��c�u i o W z " �a o -.�.� . 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'� C .�� . � 7 �' m v tn. `� O N �C r1 cw d m "'w en `'��' s, c Gl a r:, �' o . � � O k�:o" O .�i O �� (.y �, �O � �' u c� .n rJ M .�. . �+ 'a'+ '`�.Ti C7 Y � '�`., K' U M G S 1.�+ s" 6 E N r � � � " $ o e q �,, � ,��, ? � � w � � v a> C �,-P . 3 v o .k� ❑ � w � y�p . a � .�"�. � `" d � a .c U w o. y o U w " � 'm' '� �''�. � o � �S��.. o rn � a , � '� � o .o � I w rn W � � O o' � W U �., . � V] � �. '� W p� � W N ' o N � i"' -� . ��,. I `"� o. I : '„P'. d c I . N a � Gc � �0 0. O O . M C � O � � C O E � . .c s .G G C G p � I � o p �.. p.i k X U a� y ,� y ' O . �N C � m z -. W 'U y C � a : Q y ❑ '^1 � . vi �-�' �� O O o � � 'c o � c �y � � r o�n g . C7 � `" r .. w ;c o a^o, E- a a � z > � � G � o b . i � n w � � � w c ¢ � � � � I� $ �� e� � Kerr-MoGec Gathociug LLC P.O.Box 173779,Deuvey Colorado 802173779 720-929-W U0 Fax 720-929-0000 December 19,2012 Mr. Christopher Laplante ��w, Air Pollurion Control Division—Oil &Gas Tevn �' \� Colorado Department of Public Health and Environment RFC�'/� `� 4300 Cherry Creek Drive South F�"2 f FU 1 Denver,CO 80246-1530 � � � �� T�,�� } `�, , ��.°'31�..� RE: Permit 12WE1A92 APplication Update ^��—'`�✓%r Lancaster Plant �""�`f Weld County, Colorado Deaz Mr. Laplante: On December 6, 2012, Kerr-McGee Gathering LLC (KMG) received an email from the Division containing qttestions regarding the PSD significant net emission analysis submitted to the Division on November 29, 2011 and then updated on April 17, 2012. KMG has addressed all the Division's concerns which are identified below. l. "it appears Kerr McGee followed a process af ne#ing emissions solely within the ppoject. This is not allowed under the PSD netting provisions. If the project emissions increase from the new, modified and other affected saurces (i.e. de-bottlenecked units or units with increased utilizafion) exceeds the signifacant dncrease in emissions thresholds, as dt will in this case, then you have the opportunity to use netting." a. KMG did complete the two step process to determine if a significant net emission increase occurred in the April 17, 2012 application. We based our detennination that there were no contemporaneous emissions increases and decreases because Regulation 3, Part D, Section II.A.26.c.(ii) states that an increase or decrease in actual emissions is credible only if"The Division has not Yelied on if in issuing a permit for the source under Regulation Number 3, or the US EPA has not relied on it in issuing a permit under Title I, Part C of the Federal Act, which permit is in effect when the increase in actual emissions frorve the particular chcange occurs". b. Since Regulation 3 includes APENs, construction permits uid major source pennits, KMG determined that there were no emissions increases or decreases Yo include in the contemporaneous period. KMG responded to the Division's December 6,2012 email with our Regulation 3 interpretation and the Division responded with the intended meaning of the Regulation and included a September 18, 1989 EPA Memo to support this claim. As a result of tliat response, KMG has modified the PSD applicability analysis to include contemporaneous emissions, even though the language in Regulation 3, Part D, Section II.A.26.c.(ii) does not support this interpretation. c. Included with this submittal is an updated PSD applicability analysis including a significanY net emission increase calculation with both Step 1 and Step 2. __ _ __ 2. "Therefore, any physical change or change in ehe method of operation for any eguipment at your facility dha# occurred during the contemporaneous period would have to be reviewed in a netting analysis...Kerr McGee should evaluate these increases and decreases to determine if they are both contemporaneous and erediCable. This evaluation must be conducted as parP of your netting ' analysis." a. The enclosed document detaiLs the determination of the contemporaneous period and explains the evaluation Yo determine the credibility of each emissions increase and decrease within that period. 3. "In addition to the revised netting analysis, the Division would like to better understand the operational interaction of the existing Ft. Lupton, Platte Palley and proposed Lancaster plants. Please provide informaZion 8o the Division with regard to how these three operations interact with one another from an operational standpoint. Specifically, the Ddvision needs to understand if there will be avry debottlenecking or increased utilization of other existing sozmces as a Yesult of the Lancaster project." a. Secrion I of the enclosed document details the process description of the Lancaster Plant vid � the interacfion with the existing Platte Valley aud Fort Lupton plants. It also explains why Yhe start-up of the Lancaster Plant will not debottleneck or increase utilization of any existing sources. 4. `As Kerr-McGee works"to revise the netling analysls,please note you may use the 2002 NSR Refot�n provisions that have now been approved into Regulation 3, Part D. Given the relative complezzty of the contemporcaneous emissions analysis, the Division requests Kerr-McGee to be very thorough in documenting all emissions calculations used to support the actucal emissions presented in the revised � netting analysis as well as their basis (i.e. actual process rates and emissions factars). It will also be helpful to obtain the functional spreadsheet used to support this work, so the Division does not have to manucally recreate the calculatians for verification purposes." a. The enclosed document should provide the Division a thorough analysis documentiug the methodology for the emissions calculations. I{MG will email a copy of the PSD significant emission increase aud net emission increase calctilaYions to help speed the Division's review process along. b. KMG did use the 2002 NSR Reform provisions in the attached analysis which were � incorporated into Regulation 3,Part D. � As part of this updated PSD siguificaut net emission increase analysis, KMG modified the three compressor engines it will be shutting down as part of the project. KMG proposes to permanently shut down EU-36 (123/0057/005) and EU37 Q23/0057/006) with the start-up of Lancaster Train 1 which is expected on January 1, 2014. KMG also proposes to shutdown EU-35 (123/0057/007) with the start-up of Lancaster Train 2 which is expected on January 1,2015. One other change, not mentioned in the previous application was the addition of five (5) 3,750-hp electric motors to drive reciprocating compressors. These compressors will take inlet gas, compress it and send the gas to the existiug high pressure pipeline. Therefore,we will not see an incxease in capacity at the facility and there will not be an inerease in emissions from existing equipment. An updaYed GHG BACT analysis reflecting any of the previously mentioned changes is also enclosed far your review along with an updated APCD-102 form. Page 2 If you have any questions, or requue additional information, please contact me at (920) 929-6028 or ' Jennifer.Shea@Anadarko.com Sincerely, � ERR-MCGEE GATHERING LLC z � Jennifer L.Shea Staff EHS Representative Enclosures ec: IC.King,M.McMillan,M.Burgett, C.Laplante,C.Money, S. Chaousy,K.Bracken,A.VJilliams, M.Ross,M.Forsyth, J.Aliin Page 3 The Lancaster Plant PSD Net Emission Increase Calculation December 19,2012 I. Introduction As pertaining to Regulation 3, Part D, Section II.A.2, a project is a major modification for a regulated NSR polluTant if it causes a signi&cant emission ulcrease(Step 1)and a significant net emissions increase (Step 2). This document explains the logic and detenninations utilized to develop the Lancaster Plant (Lancaster) project PSD applicability analysis. Kerr McGee Gathering LLC (KMG) updated this analysis to incorporate the NSR Reform provisions(2002 rules)which were approved into Regulation 3, Part R Proress Descriptinn The Fort Lupton Gas Plant (Fort Lupton) and Platte Valley Gas Plant (Platte Valley) are currently operating at maximum capacity and no increased throughput or processing capabilities are expected at either plant with the start-up of Lancaster. Fort Lupton is currently bottlenecked by the refrigeration plant which is also operating at maximum capacity. Any gas sent to the refrigeration plant is dehydrated in the nortl� and south dehydration units and there is no improvemeut scheduled for Fort Lupton's existing refrigeration plant. Platte Va11ey is currently bottlenecked by the residue compression used to send gas to Yhe discharge pipeline. There are no plans to increase compression capacity at the plant. A new 24" inlet pipeline will be constructed concurrent with the commencemenT of Yhe ls`train of Lancaster to deliver gas to the proposed plant along with gas off the existing high pressure(HP)pipeline. Fort Lupton units 36 and 37 are scheduled to be shutdown with the start-up of Lancaster Train 1 and Unit 35 will be shutdowu with the sYart-up of Train 2. Units 36 and 37 boost inlet gas from 100 psi to about 200 psi and discharge directly into the intermediate pressure (IP) pipeline. As developmenY of the basin continues and new formations are produced, the function of these units is no longer required. Unit 35 currently boosts inlet gas from about 100 psi Yo I100 psi and discharges inYo tl�e HP pipeline. Five addiYional inlet 3,750-hp electric motors driving reciprocating compressor will be installed as part of Yhis project to feed the HP pipeline. This additional compression eliminates the need for Unit 35. IL Step 1 —Significant Emission Increase Calculation KMG utilized the actual to potential test as defined in Regulation 3, Part D, Section II.B.2 to determine if a siguificant emission increase of a regulated NSR pollutam is projected to occur. All new equipment proposed for Lancaster was included in tl�e calculation as sltown in Table 1 below. As pertaining to Regulation 3, Part D, Section II.A.24.e, fugitive emissions were not included in Step 1 since Lancaster is not a source caYegory listed in Section II.A.24.a.(i). Page 1 ��e�a`�';�' � ' �'n Table caeter . '�1�S� n ' �uiss�on Inc�°.�`�exCalcu _�on�` ��';' UnitID NOx CO VOC COze SOz z x r � �x � �.��aa��rr�oaeac � � t 3.��-„ „ > , , . , „ ,. . ,,,, . ,.� , - , r. � E-2015 Mole Sieve Regenerafion Gas Heater with Ultra Low NOx Burnexs 5.2 52 2.5� 15,252 0.1 E-2016 Mole Sieve Regenerafion Gas Heater with Ultra Low NOx Bumers 52 5.2 2.5 15,252 01 H-6051 Heat Medium Heater with Low NOx Bumers li.5 13.5 1.8 39,421 02 H-6052 Heat Medium I-Ieater with Low NOx Burners 13.5 13S 1.8 39,421 02 H-6053 Heat Medium Heater with Low NOx Burners 13.5 13.5 1.8 39,421 02 H-6054 I-Ieat Medium Heater wiih Low NOx Burners 13.5 13.5 1.8 39,421 02 A-I 150 MMSCFD Amine Treater(Controlled with ATO-1) 7.9 6.6 . 3.6 94,121 11 � A-2 150 MMSCFD Amine Treater(Controlled with ATO-2) 7.9 6.6 3.6 94,121 1.1 A-3 150 MMSCFD Amine Treater(Conteolled with AT03) 7.9 6.6 3.6 94,121 11 A-4 150 MMSCFD Amine Treater(Controlled with ATO-4) 7.9 6.6 3.6 94,121 . 11 . P-2 F-2 Lancaster Plant Process Flaze 1 '7.3 14.6 1.6 6,220 0.03 F-3 F3 Lancaster Plant Process Flare 2 9.3 14.6 1.6 6,220 0.03 � GEN3 Caterpillar 670-hp Diesel Emergency Generator Z,1 0.1 0.0 139 12 � � Lancaster Project�missian Increase 112.6 120.2 29.9 577,254 G.5 PSD Signi£cance Threshold 40.0 100.0 40.0 75,000 40.0 Step 2,Net Emission�Increase Detcrmivatian Required? Yes Yes No Yes Na The new emission units proposed for Lancaster will cause a significant emission increase of NOX, CO and COZe emissions. Therefore, as required by Regulation 3, Part D, Section LA.2,KMG will deterrnine if the proposed project will result in a significanY net emission increase for NOX, CO and COZe in Step 2 below. III.Step 2—Significant Net Emission Increase Calculation To determine if Lancaster will cause a significant net emission increase, one must sum any increase in actual emissions from the proposed project and any other increases and decreases contemporaneous with the proposed project as pertaining to Regulation 3,Part D, Section II.A.26. These increases and decreases are known as Step 2 in the PSD applicability determination. Contemporaneous Periad The contemporaneous period for this project was defined as required by Regulation 3, Part D, Section II.A.26.b. The LancasYer Plant projecY consists of two Yrains with a phased construction period. Train 1 is expected to start operation on January 1, 2014 and Train 2 is expected to start operation on January 1, 2015. Therefore,KMG defined the contemparaneous period as January 1,2009 to January 1,2015. Page 2 __ ; _ __ Contemporaneous Emissions As shown in the net emission increase calculation of Table 2 below, there were uineteen (19) increases and decreases that occurred in the defuied contemporaneous period. Five (5) of the identified emissions decreases listed below were deemed not credible as defined in Regulation 3, Part D, Section II.A.26.f.(ii) due to the fact Yhat the old level of actual emissions did not exceed the new emission level (PTE). An updated Title V permit was never issued far the modification requested below. The facility is operativg under the pennit shield of the July 3, 2002 95OPWE013 Title V permit. 1. ENG 33, 123/0057/004,6/30/2009 submitted Title V modification to decrease horsepower. 2. ENG 36, 123/0057/005, 6/30/2009 submitted Title V modification to decrease horsepower. 3. ENG 37, 123/0057/006, 6/30/2009 submitted Title V modification to decrease horsepower. 4. ENG 35, 123/0057/007, 6/30/2009 submitted Title V modification to decrease horsepower. 5. North Dehy, 123/0057/021, 12/21/2011 construction permit issued to decrease thermal oxidizer combustion temperature. Eight (8) of the identified emissions increases listed below, calculated the projected actual emissions utilizing the source's potential to emit (PTE) emissions as required by Regulation 3, Part D, Section II.A36.a. These eight(8)new sources started up during the contemporaneous period. I. ENG 103, 123/0057/026— Began operation on 2/15/2009. New permit issued on 10/4/2011 to increase fuel use. 2. Soutl�Dehy; 123/0057/027—Began operation on 3/12/2009. 3. GEN2, 123/0057/029-Began operation on 9/28/201 I. 4. ENG 104, 123/0057/028—Began operation on 10/1/20ll. 5. PLVGEN, 123/0057—APEN submitted on 1/30/2012. 6. H-ST2, 123/0057—APEN exempt heater(Regulation 3,Part A, Section II.D.Lk)began operation on 11/5/2012. 7. H-ST3, 123/0057—APEN exempt heater(Regulation 3,Part A, Section II.D1.k)not yet built. 8. H-ST4, 123/0057—APEN exempt heater(Regulation 3,Part A, Section II.D1.k)not yet built. One (1) of the identified emissions decrease listed below, calculated baseline actual emissions as defined in Regulation 3, Part D, SecTion II.A.4.b by selecting the highest annual average based on a consecutive 24 month period, except Section II.A.4.b.(iv)does not apply for contemporaneous increases and decreases as stated in Regulatiou 3, Part D, Section II.A.26.a.(ii). The baseline acTual emissions were calculated for the removal of Unit 102 based on I/1/2005 to 12/31/2006 actual emissions. 1. ENG 102, 123/0057/024—Engine shutdown on 4/30/2009. One (1) of the identified emissions decrease listed below, was not iucluded in the contemporaneous emissions because fugitive emissions as defined in Regulation 3, Part D, Section II.A.24.e, sha11 not be included in deterxnining for any of the purpose of Pazt D, whether it is a major source. Lancaster is a gas processing facility and is therefore, not one of the named categories in Regulation 3, Part D, Section II.A.24.a.(i)or a source category as of 8/7/1980 regulated under Sectiou 111 or 112 of the Federal Act. Page 3 1. FUG, 123/0057/018—Decreased fiigitive emissions in Pennit 00WE0583 from actual component count. One (1) of the identified emissions increase lisTed below, calculated projected actual emissions utilizing the source's potential to emit(PTE)emissions as defined in Regulation 3, Part D, Section II.A36.a.. The baseline actual emissions were calculated as defined by Regulation 3, Part D, Section II.A.4.b by selectiug the highest anmial average based on a consecutive 24 monTh period, except Section II.A.4.b.(iv) does not apply for contemporaneous increases and decreases as stated in Regulation 3, Part D, Section II.A.26.a.(ii). The baseline actual emissions were calculated based on the sources 12/1/2010 to 11/31/2012 actual emissions. The neT emission increase = projected actual emissions (PTE) - baseline actual emissions. 1. 5021, 123/0057/053 — On 7/20/2012 reyuested to increase gas to flare vohunes and modify emissions. Permit has not been issued. Three (3) of the idenYified emissions decreases listed below calculated baseline actual emissions as defined by Regalation 3, Part D, SecYion II.A.4.b by selecting the highest annual average based on a consecutive 24 month period. One consecutive 24 month period was selected for each regulated NSR polhrtant. The period selected for NOX was 4/1/2008 to 3/31/2010 and the period selected for CO aud CO2e was 1/1/2003 to 12/31/2004. 1. ENG 35, 123/0057/007—Engine will be removed upon start-up of Lancaster Train 2 estimated as 1/1/2015. 2: ENG 36, 123/0057/005—Engine will be removed upon start-up of Lancaster Train 1 estimated as 1/1/2014. 3. ENG 37, 123/0057/006—Engine will be removed upon start-up of Lancaster Train 1 estimated as 1/1/2074. � One (1) contemporaneous emissions decrease not included in the analysis was the control of the Platte Valley amine unit with a thermal oxidizer (123/0057/043). The emissions off the still vent of the amine unit were questioned during a 12/23/2010 CDPHE inspection. The unit was installed in 1997 and was never found to be out of compliance during the fourteen (14)years it had operated. The previous owner was asked to perform an emissions test which was completed on 4/21/2011 after the ownership transfer Yo KMG. Results were submitted to KMG on 7/18/2011 and a permit application to control the amine unit was submitted on 2/5/2012 after engineering design was completed. The amine unit was controlled on 11/8/2012 and to date, not final construction permit has been issued far the source. Therefore, KMG did not include this emissions decrease as a contemporaneous source. Net Emission Increase Calculation The net emission increase was calculated as required by Regulation 3, Part D, Section II.A.26 by summing the increase in actual emissions of NOX, CO and CO2e from the proposed Lancaster project (Step 1) and the emissions increases and decreases within the defined contemporaneous period (Step 2). As shown in Table 2 below, the proposed Lancaster project will not cause a significant net emission increase in NOX and CO emissions but will cause a significant net emission increase iu CO2e emissions. Page 4 Therefore, since the proposed project results in a major modification for CO2e, a BACT analysis for Crreenhouse gases is required. Page 5 �Table 2 Lau�.ys}er Pln .,�,S[„e�p"..1;+Step 2)Nei Lmissio�Inc`�e ,�, .lc'�Yaiiun � ' � ' ""'�" � " ��,,n,�as`�, ��'#�::��:"��a�:��.`�.., z+iz x ;. UmtID AI25ID PermitF � ContemporaneoosChanne Date NOx CO COie CunRenSpo n�aoi s o`v{Fis�w�s 5 er nses.rtn`�AdW r4m6eslt�oirv�`dabNtn'7I201$f$�eP2} . F° + x,,,`: rvlrt . . .YY ,t�.• r �'.� . ,r , ,, a, ,.'., :^.,; 2NG 103� 123/0059/02G 0]V✓EO"198 � � Added U 't 103�I rease F ei U on 10/4/ll � 2/18/2009 30.4 '1.6 18,519 SwthDeAy 123/0059/029 09WE0999 3tartedup3/122009 3/1?/2009 3.19 63 2,029 ENG102'' 123/0059/0?4 03VJE1152 EvgineShutdown 4/30Y2009 -139 -9.9 -5,988 L+NG33' 123/OOi9/004 I1WE]30-I De-ratedfrom2166-hpto2046-hp 6/30/2009 � ��R��'�� ENG 36' 123/OOi9/005 I 1 WE930-2 Do-�ated fcom 2166-h0�o�46-hp 6/30/2009 � q��,� ENO 39' 123/OOi]/006 11 WE930.3 Deaated from 2I66-hp m 2046-hp 6N0@009 �' ��' ENG35' 123/OOi9/009 IIWE132 Do-�ated@om1859-hpta1956-hp 6/302009 ' FUG' 123/OOi]/018 00WE0583 Emissiansdecreueduetocompanentcomt 8/4@010 �� ' QEN2� 123/0059/029 lOWE1589 3tertednp9/28/II 9Y282011 06 0.0 N/A EU104� 123/005]/028 lOWE10]1 Stertedvpl0/1/11 10/1/2011 32.0 80 20,595 Nov�hDehy 123/OOfl/021 O1WPA964 Decceasecombustiontempecemve 12/21Y2011 #` � � ^`_.':.._�.' PLVQEN� 123/0059 ApENOuly AddedPLVPLCdeosat 1/30/2012 � 0.0 12 N/A HST2� 123/0059 Exempt Added5MMBto/ArCoudo�sateStabilizer Il/52012 1.8 42 3,661 H�T3� 123/005] Exempt Add5MMHtWhrCondwsateStabilizer TBD 18 42 3,661 A-ST4� @3/W59 AYampt Add5MMBiWh�Coudeosate9tabilizu TBD 18 42 3661 S021° 123/0059/053 02WE092] IncreasePlatteValleyGastoFlae TBD Z8 1>J 5,019 ENG35° 123/0059/009 ❑W2132 RemweevgivevponTain2stert-np 1/1/2015 -51.4 -30.1 -S,Oll ENG366 123/0059/005 11W➢930-2 Remweevgioe�ponT�eivletan-up 1/1/2014 -693 -33] -5,928 ENG3]� 123/005]/006 11WE9303 Removeengi�euponTrainlstan-up 1/1/2014 -81.5 -324 -5,]95 P�pos@A.R1oAGe§tfu�B��ect��mseiooeLSCgR]) ,. , ''�` e s n i4x , t +,o � ' �2015 NA 12WE1492 � MoleBieveRenenecaHovGasE3eaterwilLUlvaWwNOxB�mers � 1/IYLp14 5.2 5.2 15,252 � �2016 NA 12WE1492 MoleSieveRegenerationGasHeaterwithUltreLowNOxBumers I/1/2015 52 52 15,252 HS051 NA 12WE1492 HaatMediumHea[erwiFliLowNOx6umeca I/1/2014 13.5 13.5 39,421 H-6052 NA 12WL1492 HeatMediumHcaterwithLowNOxBumers 1/1/2014 13.5 135 39,421 H-6053 NA 12WE1492 HeatMediumHeaterwithLowNOxBomers 1/1/2015 13.5 13.5 39,421 H-6054 NA 12WE1492 HeatMediumHeaterwiNLowNOxBumers ld/2015 13.5 13.5 39,421 A-I NA 12WE1492 150MM3CPDAmineTceatev(CovtrolledwithATO-1) I/1/2014 9.9 66 94,121 A-2 NA 12WHi492 i50MMSCPDAmiveTreatu(Covvolledwi[hAT62) 1/I/2014 �9 6b � 94,121 A3 NA 12WE149? ISOMMSCFDAmi�eTreetu(CootrolledwilhAT03) 1A2015 ].9 6.6 94,121 A-4 NA 12WE1492 150MMSCFDAmineT�earor(CoutmlledwithATO-4) 1/1/?AIS Z9 6.6 94,121 F-2 NA 12WEt492 F-2Lanceste�PlentPmceasPlarel 1/1/2014 93 . 146 y220 P-3 NA 12WE1492 P3l,enoastuPlentPmcessFla�e2 1/1/2015 �3 14b 6,220 QEN33 NA 12WE1492 Cate�piller690-ApDieselEmergeucyOaue�atov 1/I/2014 2.1 0] 139 Stepl+Step2 d2.2 65.5 612,553 PSDSignificance'Ihreshold 40.0 ]00.0 ]5,000 � Shp2,Doesprqectcausensignificxntnetemissiouincrease. No No Yes �Emission increase vefleGing Potevtial to amit emiesions as dafined iv Regulation 3,Part D,Secfioo ILA,36.a °Lmissions ioo�ease calevlated using hiohest aemusl avarage based ou 24 covsecutiva months es pu RA.4b,axcept ICA.5.6.(iv)doas vot apply as pu IIA26_a.(ii).(lanuary 2005 m Decembev200� 'Emiesioos decrease is mt credlbla sivice the old Ievel of acmel emissions does not axceed ihe new level of emissions ae pu Regulatiov 3,Pan D ICA26f�i). °Fugi[ive emissious vot included',gas plant is mt a oemed so�mes ea per Rag 3,Part D,Swtiou ILA24 'Net emission increase=pmjected acWal emissions as de£ned in Regulation 3,Part D,Section ILA36a(PTE)-baseline acWal emissions as defined in Regulation 3,Part D,Section]I.A.4.6, except ILA4.6.(iv)doee no[apply as pe�0 A,2fla(ii). Uaed 12/12010 to L/302012 ro calculata buselive acW al emfssloos. sBaselineaotualemisaionecelculatedasd�nedinRe�ulatiov3,PartD,SecfiouR.A.46_Conseoutive24movthpe�ioddefinedsaNOx s/20083@O1P,C0&CA2a=1@003m12/2004. Kerr-McGee Gathering LLC Lancaster Plant Cryogenic Plant Project Greenhouse Gases Best Available Control Technologies (SACT) Analyses Tabfle of Contents FacilityInformation......................................................................................................................1 ProcessDescription......................................................................................................................1 EmissionSources.........................................................................................................................2 BACTAnalysis Methodology.........................................................................................................3 BACT Evaluation for Sources.........................................................................................................5 Appendix A—Economic Analysis for CCS.......................................................................................A Appendix B—RBLC Information Summary.....................................................................................B Facilitv Information: The Lancaster Plant will be adjacent to the Fort Lupton Gas Plant which is in Weld County, CO at Northwest '/a, Section 14, Township 2 North,Range 66 West. The coordinates are: Latitude: 40°, 1614'N Longitude: 104°, 45.08'W The street address is: 16116 WCR 22 Ft. Lupton, CO 80621 The existing facilities currently operate under a number of construction pennits as well as Title V operating permits. A recent acquisition of assets formerly owned by EnCana also brought the Platte Valley Station into the single facility complex. Process Description: The new 600 million standard cubic feet per day (NIMscfd) cryogenic plant will be located adjacent to the existing Fort Lupton Facility which includes gathering compression and existing refrigeration plant. The plants will receive third party gas from the Kerr McGee Gathering pipeline system in the Wattenberg Field, remove COz via amine treating, dehydrate the gas through the use of inolecular sieve beds, extract natural gas liquids (NGL) through the use of the gas sub-cooled process (GSP) and SCORE cryogenic cooling processes and then re-compress the residue gas stream for sales. Inlet gas will be compressed with five (5) 3,750-hp electric motor driven reciprocating compressors that will discharge to a high pressure pipeline that feeds the Lancaster Plant. The COZ is removed from the inlet gas stream utilizing four(4) 600 gpm amine treaters. The amine treaters incorporate a thennal oxidizer per unit to control emissions. The gas stream is then dehydrated using a molecular sieve. The molecular sieve beds are regenerated using dry gas that has been heated by the regeneration gas heater. The dry gas is then run through the cryogenic unit to super-cool it and remove natural gas liquids (NGL). The cryogenic units are supplemented by six (6) 3,000 hp electric motor driven propane refrigeration compressors. The residue gas from the cryogenic units is then compressed utilizing four (4) 12,000 hp electric motor driven compressors to deliver the gas to the transportation pipeline. The produced NGLs are also transported from the facility via a pipeline. The primary reason for treating the inlet gas with ainine is to ensure that the NGLs meet pipeline specifications. The inlet gas has about 2.7 mole % CO2. Treating the feed gas avoids issues with liquid treating, such as amine carry over and meeting the pipeline water specification. Because the amine units are designed to remove COz from the natural gas, the generation of COZ (GHG) is inherent to the process, and a reduction of COZ emissions by process changes would only be achieved by a reduction in the process efficiency, which would result in natural gas that would not meet pipeline quality specifications and leave COZ in the natural gas for emission to the atmosphere at downstream sources. The amine units do also emit methane (GHG) at the point of amine regeneration, due to a small amount of natural gas becoining entrained in the rich ainine. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 1 Emission Sources: The proposed project triggers Prevention of Significant Deterioration (PSD) permitting thresholds for greenhouse gases, but does not trigger PSD for any criteria pollutants. The primary sources of GHGs proposed at the 600 MMscfd plant will be: C-4100 Solar 12,000-hp Electric Drive Motor, Residue C-4200 Solar 12,000-hp Electric Drive Motor,Residue C-4300 Solar 12,000-hp Electric Drive Motor, Residue C-4400 Solar 12,000-hp Electric Drive Motor,Residue G5110 3000-hp Electric Motor, Refrigeration Compression G5210 3000-hp Electric Motor, Refrigeration Compression G5310 3000-hp Electric Motor, Refrigeration Compression G5410 3000-hp Electric Motor, Refrigeration Compression G5510 3000-hp Electric Motor, Refrigeration Compression C-5610 3000-hp Electric Motor, Refrigeration Compression ENG 105 3750-hp Electric Motor, Inlet Compression ENG 106 3750-hp Electric Motor, Inlet Compression ENG 107 3750-hp Electric Motor, Inlet Compression ENG 108 3750-hp Electric Motor, Inlet Compression ENG 109 3750-hp Electric Motor, Inlet Compression E-2015 Mole Sieve Regeneration Gas Heater with Ultra-Low NOx Burners E-2016 Mole Sieve Regeneration Gas Heater with Ultra-Low NOx Burners H-6051 Amine Regeneration Heat Medium Heater-Low NOx Burners H-6052 Amine Regeneration Heat Medium Heater-Low NOx Burners H-6053 Amine Regeneration Heat Medium Heater-Low NOx Burners H-6054 Amine Regeneration Heat Medium Heater-Low NOx Burners A-1 150 MMSCFD Amine Treater(Controlled with ATO-1) A-2 150 MMSCFD Amine Treater (Controlled with ATO-2) A-3 150 MMSCFD Amine Treater(Controlled with ATO-3) A-4 I50 NIMSCFD Amine Treater (Controlled with ATO-4) F-2 Vertical Process Flare F-3 Vertical Process Flare GEN3 Caterpillar 670-hp Diesel Einergency Generator FUG 3 Plant Fugitives Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 2 The proposed project triggers PSD for the estimated GHG emissions as it is estimated to emit 578,203 tons per year (tpy) COZ equivalent (COZe) including fugitive emissions. The net COZ emissions will be 561,468 tpy however, as three existing engines will be removed as part of this project. The COZe emissions are estimated by applying the global warming potential (GWP) of each GHG pollutant. The GWP for each pollutant is: CO2: 1 CH4: 21 NzO: 310 For example this means one ton of inethane would equate to 21 tons of COZe. Detailed calculations can be found in the calculations section of Yhe permit application. UNIT COae tpy C-4100 - C-4200 - C-4300 - C-4400 - G5110 - C-5210 - G5310 - G5410 - C-5510 - G5610 - ENG 105 - ENG 106 - ENG 107 - ENG 108 - ENG 109 - E-2015 15,252 E-2016 15,252 H-6051 39,421 H-6052 39,421 H-6053 39,421 H-6054 39,421 A-1 94,121 A-2 94,121 A-3 94,121 A-4 94,121 F-2 6,220 F-3 6,220 GEN3 139 FUG 3 949 TOTAL 578,203 Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 3 BACT Analvses Methodolo¢v: As of January 2, 2011, GHG is a regulated criteria pollutant under the PSD major source permitting pmgram codified in Title 40 Code of Federal Regulations (CFR) Part 52 when they are emitted by new sources or modifcations in amounts that meet the Tailoring Rule's set of applicability thresholds. For PSD purposes, GHGs are a single air pollutant defined as the aggregate group of the following gases: carbon dioxide (CO2), nitrous oxide (N2O), methane (CH4), and hydrofluorocarbons (HFCs). The PSD regulations do not prescribe a procedure for conducting BACT analyses. Instead, EPA has consistently interpreted the BACT requirement as containing two core criteria: L The BACT analysis must include consideration of the most stringent available technologies, i.e., those that provide the"maximum degree of emissions reduction." 2. Any decision to require as BACT a control alternative that is less effective than the most stringent available must be justified by an analysis of objective indicators showing that energy, environmental, and economic impacYs render the most stringenY alternative unreasonable or otherwise not achievable. EPA has developed what it terms the "top-down" approach for conducting BACT analyses and has indicated that this approach will generally yield a BACT determination satisfying the two core criteria. Under the "top-down" approach, progressively less stringent control technologies are analyzed until a level of control considered BACT is reached, based on the environmental, energy, and economic impacts. The top-down approach shall be utilized in this BACT analysis. The five basic steps of a top-down BACT analysis are listed below: 1. Identify all available control technologies with practical potential for application to the specific emission unit for the regulated pollutant under evaluation; 2. Eliminate all technically infeasible control technologies; 3. Rank remaining control tecl�nologies by effectiveness and tabulate a control hierarchy; 4. Evaluate most effective controls and document results; and 5. Select BACT, which will be the most effecYive practical option not rejected, based on economic, environmental, and/or energy impacts. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 4 BACT Evaluation for Sources: Step 1:Identify Control Options The following are potentially applicable control technologies for controlling GHG emissions associated with the Eneines: 1., All the new compressor engines at this facility will be run on electric power resulting in no GHG emissions from these sources. Therefore, no further analysis is necessary for the engines. 2. The 670-hp diesel emergency generator will operate a maximum 500 hrs/yr limited to emergency situations only. The generator will meet all emissions, operating and compliance requirements of NSPS Subpart IIII for stationary compression ignitions ICEs. All manufacturer recommended maintenance will be performed as required. The following are potentially applicable control technologies for controlling GHG emissions associated with the Amine Vents: 1. Proper Design and Operation: The amine units are designed to include a flash tank, in which gases (i.e., including CO2 and methane) are removed from the rich amine prior to regeneration, thereby reducing the amount of waste gas created. The amine units at this facility shall be constructed and operated for optimal performance; 2. Amine Unit Flash Tank Off-gas Recovery System: The amine unit flash tank off- � gases shall be routed to the proposed thermal oxidizer. 3. Routing Amine Unit Regenerator Vent to a Thermal Oxidizer: This control device will reduce the methane emissions by 99% and will convert those emissions to CO2, which has a lower GWP; 4. Routing Amine Unit Regenerator Vent to a Flare: This control device will reduce the methane emissions by 98% and will convert those emissions to CO2, which has a lower GWP; 5. Carbon Capture and Storage (CCS): This involves capturing CO2, transporting it as necessary, and permanently storing it instead of releasing it into the atmosphere. The process involves three main steps: • Capturing CO2 at its source by separating it from other gases; • Transporting the captured CO2 to a suitable storage location (typically in compressed form); and • Storing the CO2 away from the atmosphere for a long period of time, for instance in underground geological formations, or within certain mineral formations. � In the project two CCS approaches were looked at: acid gas injection well and enhanced oil recovery(EOR) The following are potentially applicable control Yechnologies for controlling GHG emissions associated with the Heaters: 1. Fuel Selection: The heaters at the site shall be fired on pipeline quality natural gas. This results in 28% less CO2 production than fuel oils (see 40 CFR Part 98, Subpart C, Table C-1, which is included in Appendix E, for a comparison of the GHG emitting potential of various fixel types); Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 5 .__ _ .. .. . ._ . _ _ . . _ _. _. ._ .__ -. ___ 2. Efficient Heater Design: New burner design iinproves the inixing of fuel, creating a more efficient heat transfer. At the new facility, new burners shall be utilized. Burner management systems shall be utilized on the heaters, such that intelligent flame ignition, flame intensity controls, and flue gas recirculation optimize the efficiency of the devices. 3. Periodic tune-ups and maintenance for optimal thennal effciency: Maintenance shall be performed routinely per vendor recommendations or the facility's maintenance plan. The components shall be serviced or replaced as needed. The heaters shall be tuned once a year for optimal thermal efficiency; 4. Oxygen trim control: Combustion devices operate with a certain amount of excess air to reduce emissions and for safety consideration. An inappropriate mixture may lead to inefficient combustion. Regular mainYenance of the draft air intake systems of the heaters can reduce energy usage. Draft control is applicable to new or existing process heaters and is cost effective for process heaters rated at 20 to 30 MMBtu/hr or greater. The heaters will have air and fuel valves mechanically linked to maintain the proper air to fuel ratio. The following are potentially applicable control technologies for controlling GHG emissions associated with the Process Flares: 1. The process flares will be designed according to best engineering practices and API Standards 521 and 537. Both flares will utilize a burner management system, a pilot monitoring system and a combustion air blower to optimize combustion. The following are potentially applicable control technologies for controlling GHG emissions associated with the Overall Facilitv: 1. Overall efficiency of facility; 2. Existing Fort Lupton equipment permanent shutdowns; 3. Compliance with NSPS Subpart KKK for fugitive equipment. Step 2:Eliminate Technically Infeasible Control Options At the current time acid gas injection wells for Yhis location appear to be technically infeasible. There are no known acid gas injection wells operating in the Denver-Julesberg (D-J) Basin. The current consensus is that acid gas injection wells would not sequester the CO2, but rather the CO2 would migrate to other producing wells creating a recycle of CO2. Step 3: Characterize Control Effectiveness of Technieally Feasible ContPol Options The efficiency improvement/GHG reduction technologies are ranked* below: • Use of electric-driven engines (100%); • Install amine unit flash tank off-gas recovery systems (100%); • Routing the amine unit vents to a thennal oxidizer (99% for methane, and generates CO2); • Routing the amine unit vents to a flare (98%for methane, and generates CO2); Kerr McGee Gathermg-Lancaster Cryogenic Project GHG BACT Analysis Page 6 • Efficiencies within the plant(variable); • Hours of operation limitation emergency generator(943%) • Fuel selection (28%when comparing natural gas and No. 2 Fuel Oil); • Burner management systems on the heaters, with intelligent flame ignition, flame intensity controls, and flue gas recirculation (10-25%); • Burner management systems on process flares, with a pilot inonitaring system and combustion air blowers (10-25%); • Efficient heater design(10%); • Annual tune-ups and maintenance (1-10%); • Oxygen trim control; • CCS (not a feasible option for the Project due to technical, environmental, and economic reasons, as discussed in Step 4). *The following documents were used Yo identify any available control efficiencies including some vendor specifications: i) Available and Einerging Technology for Reducing Greenhouse Gas Emission from the Petroleuin Indushy dated October 2010 and ii) Energy Efficiency Improvement and Cost Saving Opportunities for the Petrochemical Industry: An ENERGY STAR Guide for Energy Plant Manager, Document Number LBNL-964E, dated June 2008, Step 4:Evaluate Most Effective Control Options As part of this project the following options that were listed in Step 1, shall not be proposed for implementation as BACT: 1. The routing of amine unit regenerator vent to a flare (98% control), because a more efficient technology(thermal oxidizer,with 99%efficiency) will be addressed. 2. Amine flash tank off-gas recovery. The amine flash tank off-gas will be routed to the thermal oxidizer to aid in combustion of the regenerator vent gas. 3. CCS is not considered to be feasible, based upon its lack of readily available technologies and negative environmental and economic impacts. However, per EPA guidance, EPA has identi£ied CCS as an add-on control technology that must be evaluated as if it were technically feasible. The amine flash tank off-gas will be routed to the thermal oxidizer for combustion rather than recycled to the plant inlet. Due to Yhe low Btu and the cooling effect of the CO2 in the amine regenerator vent gas stream, additional Btu content(assist gas) will need to be added to aid in combustion in the thermal oxidizer. If the flash gas were to be routed back to the plant inlet, additional compression would be needed and the energy required would negate ihe potential savings on the flash gas. The design will utilize the high Btu flash gas to help supply some of ' the additional Btu need to offset a portion of the pipeline gas utilized for the remaining assist gas. The emerging CCS technology is an "end of pipe" add-on control method comprised of three stages (capture/compression, transport, and storage). CCS involves separation and capture of CO2 from the exhaust gas, pressurization of the captured CO2, transmission of CO2 via Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 7 pipeline, and injection and long term geologic storage of the captured CO2. CCS can also consist of use of CO2 in Enhance Oil Recovery(EOR) opportunities. The goal of CO2 capture is to concentrate the CO2 stream from an emitting source for ' transport and injection at a storage site or location utilizing EOR. CCS requires a highly concentrated, pure CO2 stream for practical and economic reasons. Extracting CO2 from exhaust gases requires equipment to capture tbe flue gas exbaust and to separate and pressurize the CO2 for transportation. Extracting CO2 from the exhaust gases of the heaters and thermal oxidizers would require equipment to capture the flue gas exhaust and to separate and pressurize the CO2 for transportation. The exhaust stack streams will be low pressure, basically atmospheric pressure. The streams would also be emitted at high temperatures. The CO2 separation would require the removal of all other pollutants from the streams. The process would require compression to increase the pressure from ahnospheric to pipeline pressures. The process would also require the reduction of the temperature of the streams by several hundreds of degrees prior to separation, compression, and transmission. Basically an entire plant similar to what is being proposed in this project (smaller in size) would bave to be constructed to remove the CO2. This process would add even more GHG emissions and large costs to the project. This option is not environmentally, nor economically feasible. Even if we assumed there was a feasible way to separate the CO2 from the combustion streams, there would be several logistical issues that need to be resolved including obtaining right of way (ROW) and National Environmental Policy Act (NEPA) efforts for a pipeline to transport the CO2 to a location that would be available to receive and handle a continuous long term stream of CO2. The geological formations available near this proposed site are not technically feasible to stare the CO2 as mentioned previously. In addition EOR is not feasible at any large scale level in the D-J Basin due to its geology and multiple owner/operators in the area. There may be some single well CO2 EOR projects forthcoming in this area, but nothing of the magnitude that would be able to handle the continuous supply of CO2 that would be produced from this project. Since different owner/operators are located in close proximity, large scale EOR is not feasible. The e�aust streams from the heaters and thermal oxidizers would have to be cooled, compressed, and treated priar to being able to enter a pipeline. A conservative estimate on the cost of equipment that could possibly be installed for these putposes was assumed to be $50,000,000. The nearest identified area utilizing EOR with CO2 is approximately 300 miles from the � Plant. At a cost of $80,000 per inch mile to install a 12" pipe line, the total cost for the pipeline alone would be approximately$288 million ($80,000 x 12 x 300). Detailed engineering was not done on harsepower requirements to boost the gas along the approximately 300 miles of pipeline because a definitive route was not chosen. However, we could estimate it take 80,000 horsepower (including horsepower required at the site to get the gas up to a pipeline pressure, intennediate pipeline booster compression, and end point injection compression). The cost of that additional horsepower would be approximately $200,000,000. There would also need to be additional surface equipment (i.e. separators, dehydrators, storage tanks, etc.) at the booster sites and all equipment would have to be able to handle the acid gas (CO2). The cost of the additional surface equipment was not estimated Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 8 in this exercise. Even excluding a portion of the cost, the engine cost and pipeline cost would equate to a $156/ton cost of control. There is a high likelihood thaY the remote booster stations would not be able to utilize electric compression, therefore it will have negative impact on the environment. Hence the use of CCS to reduce GHG emissions is not I economically or environmentally feasible for this project, and the timing required for ROW issues and NEPA analyses would ea�tend the project start date out by years. In addition there is no assurance that any available CO2 pipeline or EOR area would even have the capacity to handle the CO2 from this project. Step 5:Establish BACT After discussion in the previous sections,the proposed BACT for this project would include: En¢ines- ➢ Electric motors on compressor engines O 84,750 hp of electric driven compression ➢ Emergency generator o Limit hours of operation to 500 hrs/yr o Follow NSPS Subpart IIII requirements o Follow manufacturer recommended maintenance Amine Vents- ➢ Routing off-gases to thermal oxidizer for combustion o Thermal Oxidizers utilize combustion air preheaters and acid gas heat exchangers Heaters and Process Flares- ➢ Design, operation, and management criteria as specified in Steps 1 &3 Overall Facilitv- ➢ Efficiencies o Engine shutdowns ➢ Compliance with NSPS Subpart KI{K as applicable o LDAR to reduce fugitive leaks The thermal oxidizers proposed to control emissions from the amine vents will utilize combustion air preheaters as well as an acid gas heat exchanger to miniinize additional fuel requirements. The engineering design finn has estimated that the preheaters and heat exchangers will reduce assist gas requirements by approximately ll MMBtu/hr. That ef�iciency relates to an avoided amount of 5,637 tpy of CO2e for each Yhermal oxidizer. Kerr-McGee Gathering is committing to 84,750 horsepower of electric compression as part of this project. The choice of electric compression will eliminate GHG emissions from the compression needs of the plant. Based on Caterpillar data on recent 3600 series engines, CO2 einissions from natural gas fired engines are approximately 450 grams per horsepower- hour. That would equate to 368,267 tpy of CO2e from 84,750 horsepower of natural gas Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 9 _ _._ _._ fired engines. NoY to mention Yhere would be overall energy e�ciencies by utilizing electric compression in this projecY. As part of the overall project, three natural gas fired engine at the existing Fort Lupton plant will be pennanently shut down (EU-35, EU-36 and EU-37). The runtime restrictions on the engines will reduce up to 16,734 tpy of CO2e. Total quantifiable CO2e reductions of 385,001 tpy are proposed as part of the BACT as well as munerous reductions that are not as easily quantifiable, such as maintenance and operation conditions on the heaters. Overall the proposed project will treat 600 MMscfd of gas with only modest increases in criteria emissions at the facility. While there is a proposed 561,468 tpy net increase in GHG emissions in the project, it is effectively removing the CO2 from the gas stream that would ultimately have been emitted at some point downstream of this facility. The overall avoided and reduced GHG emissions for the project are greater than 50%of the proposed total net GHG emissions. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 10 APPENDIX A Economic Analysis for CSS Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B a � N £ � � °' o O O rs � y » ui e> � u Cl W w � N G1 u U N v O1 L �n .t°. Z,(j � N � y R ≥ U u�i m � io � �' U � — m .y: N O r -; � � i» �» � v� o '� v o N m E c' c�i - `o � U �� m � N N f�O O O "L" d Y L L � L N C Gl (C � .�-- C N O W O l� O� rn O (D � e �� Q ≤ U � � `� `p v u�.. u L Q w o � ffl Efl' fR p U � � ' N m 'o -. � � o 0 O a `m ''� v d w � o V � o o �, > � � o aLi o 0 0 0 � m o a p C O � a+ £ O O � �` O N � N N O C o m .+ - S m d a ? o o E m °'• o d '� � Y I�- w N O � " ,� � U 0 Q' W M IA O � D U = e> in � 3 G w �n o in °' ° ` U V � N U O � U O � U T - N o . (> N U � a � V m o N K � Z' F O B _ m a`i = �n � �v, p > � `�' � a ,:4 �- �^y N m n E � � � � w � O m t o rs a�i U � � � � �- � Q c � � p Q w m � " o 0 0 � S c '� - E � V N c V i U o m v v m o R o .rs.. 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UU j a9i ,.,, 5 3 U " �+ � = `° v m c d N �O �E a�9 >, a rn m � � � � v Y �� d d m � m C E E m m d »� Q U E o F- � o � y o 9 a�i .°'cinU F C C � W C C N W y m c V O II m O - (n � N O - N � `mz °' � a `vz �m � a o .a �� a U o `m 'a v 'a E � � "a� a 1° � a' o a�i � � a�i c� o � m V � � � CC V CL w � v � V . m .c v .c n Q ,ro O O �? y �? � U m N U U � _ a ¢ U I�- U APPENDIX B RBLC Information Summary Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B PreviousPage��'� ' Report Date: 04/12/2012 INDEX OF CONTROL TECHNOLOGIES DETERMINATIONS '�� NOTE:Draft determinations are marked with a"*"beside thc RBLC ID. -_.�-....._..,.r............ �.�....,.,_ ,..,.....�_t.... r .... ...��... .�,...._.�.� � -__...�.-..._._..., ..._._.� -. _..- ._.- RBLC Permit Process p Y ID Y Date(EstlAct) Type ._. .�� Com an Name � Counh� ProcessDescr� t�o�—i'_ — � � OTTUMWA GENP,RATING USA Ol/12/2012ACT 1L110 Boiler#1 STATION "IA-0101 � , COGENERATION USA 12/06/2011 ACT 15210 COGENERATION TRAINS I-3(1-1Q 2-10,3-10) PLANT '�`LA-0256 17.130 EML,RGENCY GENERATOR . SABINE PASS LNG USA 12/06/20ll ACT 15200 Combined Cycle Refrigeration Compressor Tivbines(8) � TS�RMINAL � '�`LA-0257 19.390 WeY/Diy Gas PLares(4) , 19.390 Marine Flue 50.999 Aoid Gas VenYs(4) 15.100 Simple Cycle Generation'Iltrbi�2es(2) 17.130 Generator Engines(2) � 15100 Svnple Cyole Refi�igecation Compressor Tucbines(1� 50.999 Fugitive L.missions � PORT DOLPHIN USA 12/01/2011 ACT 99.999 Fugitive GHG emissions � ENERGY LLC "FL-0330 . 11310 Boilers(4-278 mmbYu/hr each) I 1.310 Power Ge�erator Engines(3) ; H1VI-HOLY CROSS USA 10/27/2011 ACT 13220 Boiler � DRILLING PROS *FL-0328 ��. .110 Emer enc Fire Pum En ine 17 Y P g S � 17.110 Emergency Engine �� 17110 Crane Engines(anits 3 and 4) 17110 Crane Engines(units 1 and 2) �, 17.110 Main Propulsion Engines '�. 42.000 Storage Tauks hiINHNIILE POINT LA-0254 USA a8�16/2011 ACT 17.110 EMP.RGENCY DIESEL GENERATOR �LECTRIC GENERA 172I0 EMERGSNCY FIRE PUMP 99.009 LINIT 6 COOLING TOWER � 99.009 CHILLER COOLING TOWER(CHILL CT) . 11310 AUHILIARY BOILER(AiJX-1) '� 15210 COMBINED CYCLE TURBINE GENERATORS([JNITS 6A &6B) DIRP.CT REDUCTION �_0248 USA Ol/27/2011 ACT 81.900 DRI-101 DRI Unit#1 Iron Oxide Day Bins Dast Collection IRONPLANT 81.290 DRI-111-DRT Unit#1 Acid Gas Absorption Vent � 81.900 DRI-102 DRI Unit#1 Iron Oxide Screen Dust Co1lecYion I 81.900 DRI-202 DRI Unit#2Iron Oxide Screen Dust Collection � 81.900 DRI-105 DRI Unit#1 Fnrnace Feed Conveyor Baghouse 81.900 DRI-205 DRI Unit#2 Purnace Peed Conveyor Baghonse ' 81.900 DRI-103 DRI Unit#1 Coating Bin Filter � 81.900 DRI-203 DRI Unit#2 Coating Bin Filter 81.900 DRI-104 DRI Unit#1 H�on Oxide Fines Handling 81.900 DRI-204 DRI Unit#1 Iron Oxide Fines Handling _---_ . .._.. :. . 99.009 DRI-113-DRI Unit#1 Process Water Cooling Tower 99.009 DRI-213-DRI Unit#2 Process Water Cooling Tower 99.009 Dffi-114-DRI Unit#1 Clean WaYer Cooling Tower 99.009 DRI-214-DRI Unit#1 Clean Water Cooling Tower � 81.290 DRI-117-Briquetting Mill ' � 99.190 DRI-118-DRI Ba��ge Loading Dock 81290 DRI-115-Product Screen Dust Collection � 81.290 DRI-116-Screeued Product Trausfer Dust Collection 81.290 DRI-107-DRI UnitNo. 1 Furnace Dust Collection 81290 DRI-207-DRI UnitNo.2 Fnrilace Dust CollecYion . 11310 DRI-109-DRI Unit#1 Package Boiler Plue Stack I 1310 DRI-209-DRI Unit#2 Package Boiler Flue Stack � 81290 DRI-112-DRI Unit No. 1 Product storage silo Dust Collection 81290 DRI-212-DRI UniY No.2 Produot storage silo Dnst Collection 19.390 DRI-210-DRI Unit No. I Hot Plare 19390 DRI-I10-DRI Unit No. 1 Hot Flu�e ' 81.200 DRi-208-DRI Unit#2 Reformer Main FWe Stack 81.200 DRI-108-DRI U�iit#1 Reformer Main Flne Stack � 81.290 DRI-206-DRT Unit No.2 Upper Seal Gas Vent 81290 DRI-106-DRI Unit No_1 U�per Seal Gas Venf . 1.290 DRI-211-DRI Unit#1 Acid Gas Absmption Vent 8 . 81.900 DRI-201 DRI Unit#2Iron Oxide Day Bins Dust Colleetion BASF FINA NAFTA �_0550 USA 02/10/2010 ACT 50.003 N-11,REACTOR RL.GENERATION L,FFLUENT REGION OL�FINS 50.003 N-10,CATALYST REGENERATION EFPLUENT . 50.003 N-18,DECOKING DRUM .PRYORPLANT pK-0135 USA a2�z3/2009ACT 61.999 COOLINGTOWER#2 . CHEMICAL � ��, 61.012 PRIMARY REFORMCR � 62.014 NITRIC ACID PLANT#1 � 62A 14 ATITRIC ACID PLANT#3 . 61.999 CONDENSATE STEAM FLASH DRUM-AMMONIA PLT 4 '�� 61.999 COOLINGTOWER#1 '��. 13.310 NITRIC ACID PREHEATERS#1,#3,AND#4 61.999 CARBON DIOXIDE VENT 61Al2 AMMONIUM NITRATE PLANTS#1 AND#2 61.999 GRANULATOR SCRUBBERS#l,#2,AND#3 13310 BOILERS#1 AND#2 , 62.014 NITRIC ACID PLANT#4 RUMPICE SA�TARY OH-0330 USA 12/23/2008 ACT 29.900 ENCLOSED COMBUSTORS(4) ', LANDFILL �'�.. 29.900 MUNICIPAL WASTE LANDFILL . '��, 29.900 OPEN PLARE 99.150 PAVED ROADWAYS AND PARKING ARCAS , 29.900 CANDLESTICK FLARE(5) �� CPV ST CHARLES MD-0040 USA ll/12/2008 ACT 99.999 COOLING TOWER ��21a � INTL.RNAL COMBUSTION ENGINE-EMERGENCY GENERATOR �� 17210 ��'COMBUSTION ENGINE-EMERGENCY FIRL. WATERPUMP �. 13.310 BOILER 15.110 COMBUSTION TURBINES(2) 13310 F�,ATER � ACTIVATED CARBON LA-0148 USA OS/28/2008 ACT I1.110 NNLTIPLE HEARTH FURNACES/AFT�RBURN�RS FACILITY ' 99.009 COOLING TOWERS � � TWO(2)ELECTRIC ARC FURNACES AND THREE(3) NUCOR DECATUR LLC AL-0231 USA 06/12/2007 ACT 81.210 LADLP�METALLURGY FURNACES WITH TWO(2) � MELTSHOP BAGHOUSES � � 13310 VACWMDEGASSERBOILHR � 13310 GALVANIZINGLINEFURNACE 81.290 VACWM DEGASSER ' AIRPRODUCTS TX-0481 USA 11/02@004ACT 99.999 PARTS WASI-IER BAYTOWN I I � 50.007 FUGITIVHS(4) � 64.003 MSS PROCESS STEAM V�NT 64.003 PROCESS STEAM VENT 19.800 EMERGENCY GENERATOR TANK - ' 64.003 MSS-NONCONDENSIBLES(PROPYLENE VENTING) 19310 FLARE(NORMAL OPERATION) 64.003 RECTISOL V�NT I9.800 L�MERG�NCY G�NERATOR 42.005 DIESEL FUEL TANK 13.390 BOIL�R STACK(START UP) . 11390 BOILER STACI{(T-IIGH BTU FLiEL) 50.005 COOLING TOWER � 50.005 SUPPLEMENTARY COOLING TOWER 11.390 SOILER STACK � RUMPKE SANITARY �H-0281 USA O6/10/2004 ACT 29.900 PORTABLE TUB GRINDER �� LANDPILL,INC �� 29.900 LANFILLROADWAYS �� 29.900 LEACHATE STORAGE BASIN ��.. 29.900 LEACI-IATE AERATION BASIN � 29.900 FUGITIVL.EMISSIONS FROM LANDFILL AND GAS ��. COLLECTIONSYSTEM � 17210 PORTABLE ENGINE 4.68 MMBTU/H 29.900 NEW SOLID WASTE DISPOSAL WITI-I LANDFILL GAS . GENERATION ''� 17210 PORTABLE ENGIIVE 0.58 MMBTU/H � � � 29.900 LOAD-1N,LOAD-OUT,TURNING,AND WIND EROSION 29.900 PORTABLE SCREENER �. 29.900 EXISTINGSOLIDWASTSDISPOSALWITHLANDFILL ��, GAS GENERATION ; Previous Page', ,.. o." Em � �R �� x �RR�ry�, 4 m ,. . ��. . • ,. , nn ..-.. , �__`___._ _«��,.� �� e , � l.. '. . ......, , __�_ . _.. . . . -. . -. ... ,,, . .-.- _ . ry 6 g I. g "5�' _C_'�-____ B S 4`. "o : E l o EE� ieq d � � ' , . . ._� . , . . . � . . , . . . . . ..� . .. ._. , =E zE 3 pE 'n � .._ ...� . . �. .._ � .. . . ...� . . ...�� .. � . . . . . . . . . E O . .... .. . ..... t . e . . �. . . . . r.... . . - .�t� -... . i .. . � i i ! nmrorl n � O I {� � E . . ... � .-.-..m�'�,. .- S.- n�:...°'5 ._ ..�r�^�io.nna�ena-'.winn.-�nva�n��o�mnmrmwm� m�omami n��$dn�: 3 I QEq O v �: . :.... � ... .. . . ... �. . _. .. _ �E _ o rm rvm.. . , �, Eo � w�� i�E ry .._ ._ . . 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RE: Laracaster Netting Analysis - Carbon Monoxide Emissions Shea, Jennifer<JennifecShea@anadarko.com> ` V .Fri, Jan 25, 2013 at 4:12 PM To: "Laplante-CDPHE, Christopher" <christopher.laplante@state.co.us>, "Bracken, Korby" aKorby.Bracken@anadarko.com>, "Carter, � Micah" aMicah.Carter@anadarko.com> � ; � Cc: Carissa Money-CDPHE <carissa.money@state.co.us>, "mark.mcmillan@state.co.us" �mark.mcmillan@state.co.us>, . � "matt.burgett@state.co.us" <matt.burgett@state.co.us>, Jackie Joyce-CDPHE <jackie.joyce@state.co.us>, "Chaousy, Stephanie '�� (stephanie.chaousy@state.co.us)" <stephanie.chaousy@state.co.us> � . Chris, � � . . Thanks for your patience with us on this issue. KMG has reviewed the regulation and guidance you have provided and updated '��. the attached PSD Netting analysis accordingly for Lancaster. I have included the excel spreadsheet with the netting calculations, along with an updated Netting Discussion and BACTanalysis since�in addition to Units 35, 36 and 37, KMG will also�be removing � Unit 31. There will be a staged shutdown,with Units 36 and 37shutting down with the start of Train 1 and Units 31 and 35 shutting down with the start of Train 2. �. Please let me know if you have any questions. � . � � �. � Jennifer Shea � Staff EHS Representative � � � �� ANADARKO PETROLEUM CQRPORATION � � � � �. � , '��. Dired: (720) 929-60Z8 � CeIL (303) 979-0040� . . � From: Laplante- CDPHE, Christopher [mailto:christopher.laplante@stateco.us] . . Sent: Wednesday, January 16, 2013 4:32 PM � To: Shea, Jennifer; Bracken, Korby � � � - Cc: Carissa Money-CDPHE; mark.mcmillan@state.co.us; matt.burgett@state.co.us; Jackie Joyce- CDPHE; Christopher taplante- CDPHE Subject: Lancaster Netting Analysis- Carbon Monoxide Emissions . � ��.. Jennifer, � � � � � We continue to re�iew the netting analysis performed for the Lancaster PSD application. I ha�additional comments to provde on the �I�� carbon monoxide (CO)netting. � � � � �'�.. Kerr McGee has chosen the 2003-2004 24-month time period to reflect baseline actual emissions (BAE)for CO for units 35, 36 anii 37. �� Subsequently, you are intending to take creditable contemporaneous CO emissions reductions by shutting each of these sources down as part of this project. Your analysis indicates BAE for each unit of 30.1, 337 and 32.4 tons per-year of CO respecti�ly. � Regulation 3, Part D Section II.A.4.b.(iiij states that for BAE, "The a�rage rate shall be adjusted downward to�exclude any emissions that would have exceeded an emission limitation with which the major stationary source must cumently comply, had the major stationary . � source been required to comply with such limitations during the consecutive twenty-four month period. Howe�r, if an emission limitation is � part of a maximum achievable control technology standard contained in Part E of Regulation Number 8, the baseline actual emissions https://mail.google.comlmail/u/0I?ui=2&ik=da5742cbb2$tiev�pt&cat=Cabinet%2FKerrMcGeeHambert&search=cat&th=13c73fbb3cafd821 1/3 '�, __._. .. ._ . . _.__ ...�. . . . � .. . .. . ._._. . __.. . . .... . .. .__ ....... ._ . _. . . 4/4/13 � State.co.us Ea�cuti�e Branch Mail-�RE:Lancaster Netting Analysis-Car6on Monobde Emissions , ' need only be adjusted if the State has taken credit for sucFi emissions reductions in an attainment demonstration or maintenance plan." e I belie�that Kerr MCGee had Federally enforceable requirements to install catalyst emissions controls on each of these three engines through an EPA�.Consent Decree(CD). The consent decree specifically required the installation of cataiysts on the engines and for a 58% reduction in CO emissions to bemet. �Since your current analysis chose a BAE time period before these controls were installed and there . are now CO emissions limits with which Kerr McGee must currentiy compiy, the BAE must be adjusted. Therefore, I believe Kerr McGee has two options to appropriately adjust the netting analysis for CO. 1. If you continue to choose a 24-month time period for carbon monoxide BAE that predates the 2008 requirements, you would need to adjust the BAE downward to reflect 58% reduction in actual CO emissions that occured during that time period. or; 2..�You may choose a 24-month time period for carbon monoxide BAE that is after the date of the instailation of the 2008 emissions � controls for all of the affected engines. � � � In an effort to ensure your understanding of this pro�ision, you may look to Section II.C.5 in the Federal register notice at this link: � https://www.federalregister.gov/articles/2002/12/31l02-31899/prevention-of-significant-deterioration-psd-and-nonattainment-new-source- � . re�new-nsr-baseline#h-32 � . . . Please let me know if you ha�z any specific questions on this guidance. � � Chris � � � � Christopher Laplante . � � � Oil and Gas PermittingSupervisor . AirPollution Control Division � � Colorado Department of Public Health and Environment . � 4300 Cherry Creek Drive South � Denver, CO S0246-1530 . office:303.692.3216 � � . � � email:christopherJaplante@state.co.us Anadarko Confidentiality Notice: This electronic transmission and aay � attached documents or other writings are intended only for che person � � or entity to which it is addressed and may.contain information that is pxivileged, confidential ox ot^erwise protected from disclosure. If you � have received this communication in error, please immediately notify sender by return e-mail and destroy the communication. Any disclosure, copying, distribution or the taking of ang action concerning the contents � � - of this communication or any attachments by anyone other than the � named recipient is strictly prohibited. , � I ..a...�._.__._.._,_____..__...,.._�.....__�.___._...._.._.___.__.,,.__.._..___..._..___._._.._. 4 attachments . � �_� 2013-01-25 LAN PSD Nettingxls�c � � 24SK � � 2013-01-25 Netting Discussion.pdf � B1K �� 2013-01-25 LAN BACT anaNsis.qdf . � � �. https://mail.google.coMmail/W0/?ui=2&ik=da5742cbb2&�ev�r-pt&cat=Cabinet%2FKerrMcGeeHambert&search=cat&th=13c73fib3cafd821 � 2/3 The Lancaster Plant PSD Net Emission Increase Calculation - DCCembOC 19� 2012 (updated January 25,2013) . L Introducrion As pertaining to Regulation 3, Part D, Section II.A.2, a project is a major modification for a regulated NSR pollutant if it causes a significant emission increase (Step 1) and a significant net emissions increase (Step 2). This document explains the logic and determinations utilized to develop the Lancaster Plant (Lancaster) project PSD applicability analysis. Kerr McGee Gathering LLC (KMG) updated this analysis , to incorporate the NSR Reform provisions (2002 rules)which were approved into Regulation 3,Part D. P�rocess Description The Fort Lupton Gas Plant (Fort Lupton) and Platte Valley Gas Plant (Platte Valley) are currently operating at maximum capacity and no increased throughput or processing capabilities are expected at either plant with the start-up of Lancaster. Fort Lupton is cun�ently bottlenecked by the refrigeration plant which is also operating at maxiinum capacity. Any gas sent to the refrigeration plant is dehydrated in the north and south dehydration units and there is no improvement scheduled for Fort Lupton's existing refrigeration plant. Platte Valley is currently bottlenecked by the residue compression used to send gas m the discharge pipeline. There are no plans to increase compression capacity at the plant. A new 24" inlet pipeline will be consiructed concwrent with the commencement of the 1 s`trani of Lancaster to deliver gas to the proposed plant along with gas off the existing high pressure(HP)pipeline. Fort Lupton units 36 and 37 are scheduled to be shutdown with the start-up of Lancaster Train i and Unit ' 35 will be shutdown with the start-up of Train 2. Units 36 and 37 boost inlet gas from 100 psi to about ' 200 psi and discharge directly into the intermediate pressure (IP) pipeline. As development of the basin , continues and new formations are produced, the function of these units is no longer required. Unit 31 and ', 35 currently boosts inlet gas from about 100 psi to 1100 psi and discharges into the HP pipeline. Five additional inlet 3,750-hp electric motors driving reciprocating compressor wil] be installed as part of this project to feed the HP pipeline. This additional compression eliminates the need for Units 31 and 35. II. Step 1 —SigniFcant Emission Increase Calculation ', KMG utilized the acYual_to potential test as defined in Regulation 3, Part D, Section II.B.2 to determine if a significant emission increase of a regulated NSR pollutant is projected to occur. All new equipment I proposed for Lancaster was included in the calculation as shown in Table 1 below. As pertaining to �, Regulation 3, Part D, Section II.A.24.e, fugitive emissions were not included in Step 1 since Lancaster is not a source category listed in Section II.A2q.a.(i). ' � � . . Page 1 III, Tatrle 1:Lancaster Plant Step 9 PS6 Applicablity aetsrmrnati6n , � Unit I� NOs CO VGC � COze SOz PM 2.5 Lancaster Project ; � � C-4100 � Solar C4�612,00�-hp Electric Orive Motor,Residue - - - - - - . C-4200 � SolarC40612,000-hpElectricOriveMotor,Residue - - - - - - C-4300 Solar C40612,000-hp Electric Drive Moror,Residue - - - - - - C-4400 Solar C4D612,000-hp Electric Drive Moror,Residue - - - - - - � G5110 3,D00-hp Moror,Refrig � - - - - - - - G5210 3,000-hp Moror,Reirig - � - - - - - G5314 3,OG0-hp Motar,ReFri� - - - - - - C-5410 3,OOD-hp Mator,Refrig - - - - - - G5510 3,000-hpMotor,Refrig - .- -. � - - - �G5610 3,000-hp Motar,Refrig - - -� - - - I� � ENG 105 3,750-hp Moror,Inlet Compression . - - - - - - � � ENG 106 3,750-hp Moror,Inlet Compressian - - - - - �- ENG 107 � 3,750-hp Momr,Inlet Compression - - - - - - � ENG108 3,750-hpMoror,InletCompression - - - � - - - ENG 1�9 3,75�-hp Moror,Inlet Compression - - - - - - E-2015 Mole Sieve Regeneration Gas Heater with Uhra Low NOa Bumers 52 52 2.5 15,252 0.7- 7.� E-2�16 Mole Sieve Regeneration Gas Heater with Ultra Low NOs Burne�s 52 52 2.5 15,252 0.1 1.0 � H-6051 Heat Medium Heater with Low N�s Bumers 13.5 13.5 1.8 39,421 0.2 1.7 H-6052 Heat Medium Heater with Low N�s Bumers 13S � 13.5 1.8 39,421 02 1.7 H-6053 Heat Medium Heater with Low NOs Bumers 13.5 13.5 1.8 39,421 02 1.7 � H-6�54 � Heat Medium Heater with Low N�n Bumers 13.5 13.5 1.8 39,42i 02 � 1.7 k-1 150 MMSCFO Amine Trearer(Controlled with AT�-11 7,9 6.6 3.6 94,121 1.7 0.5 I A-2 � 150 MMSCFO Amine Treater[Controlled with ATO-2) 7.9 6.6 3.6 sa,7z7 1.1 0.6 A-3 150 MMSCFO Amine Treater(Contwlled with ATO-3) 7.9 6.6 � 3.6 94,121 1.1 0.5 A-4 150 MMSCFO Amine Treater(Controlled with ATO-41 7.9 6.6 3.6 94,121 1.1 0.6 p-Z F-2 Lancaster Plant Pmcess Flare 1 7.3 14.6 1.6 6,220 0.03 - F-3 F-3 Lancaster Plant Pmcess Flare 2 7,3 14.6 1.6 � 6,220 0.03 - GEN3 Cat=rpillar 839-hp�iesel Emergency Generator 2.6 02 0.0 172 1.5 �.1 � Lancaster Pmject Emissiun Increase 113.1 720.2 29.9 577,286 6.7 7t1 P50 Significance Threshold 40_0 1�Q.0 40_0 75.000 40 10_0 � Scep 2.Ne[Emission Increase�etermination Required? Yes Yes No� Yes No Yes � The new emission units pxoposed for Lancaster will cause a significant emission increase of NOX, CO, PMZ,5 and COze emissions. Therefore, as required by Regulation 3, Part D, Section I.A.2, KMG will determine if the proposed project will result in a significant net emission increase for NOX,CO,PM2,5 and COZe in Step 2 below. i i III.Step 2—Significant Net Emission Increase Calculation i To determine if Lancaster will cause a significant net emission increase, one must sum any increase in � actual emissions fram the proposed project and any other increases and decreases contemporaneous with ithe proposed project as pertaining to Regulation 3,Part D, Section II.A.26. These increases aud decreases � are known as Step 2 in the PSD applicability determination. i i � � � � Page 2 � Contempovaneous Period The contemporaneous period far this project was defined as required by Regulation 3, Part D, Section II.A.26.b. The Lancaster Plant project consists of two trains with a phased construcrion period. Train 1 is expecYed to start operation on January 1, 2014 and Train 2 is expected to start operation on January 1, 2015. Therefore,KMG defined the contemporaneous period as January l,2009 to January 1, 2015. Contemporaneous Emissions As shown in the net emission increase calculation of Table 2 below, there were nineteen (19) increases and decreases that occurred in the defined contemporaneous period. Five (5) of the identified emissions decreases listed below were deemed not credible as defined in Regulation 3, Part�D, Section II.A.26.£(ii) due to the fact that the old level of acYual emissions did not exceed the new emission level (PTE). An updated Title V permit was never issued for the modification requested below. The facility is operating under the permit shield of the July 3, 2002 95OPWE013 Title V pennit. I. ENG 33, 123/0057/004, 6/30/2009 submitted Title V modification to decrease horsepower. 2. ENG 36, 123/0057/005, 6/30/2009 submitted Title V modification to decrease horsepower. 3. ENG 37, 123/0057/006, 6/30/2009 submitted TiUe V modification to decrease horsepower. 4. ENG 35, 123/0057/007, 6/30/2009 submitted Title V modification to decrease horsepower. 5. North Dehy, 123/0057/021, 12/21/2011 construction pennit issued to decrease thennal oxidizer combustion te�nperature. Eight (8) of the identified emissions increases listed below, calculated the projected actual emissions utilizing the source's potential to emit (PTE) emissions as required by Regulation 3, Part D, Section II.A36.a. These eight(8)new sources started up during the contemporaneous period. 1. ENG 103, 123/0057/026 — Began operation on 2/IS/2009. New permit issued on 10/4/2011 to increase fuel use. 2. Soutl� Dehy, 123/0057/027—Began operation on 3/12/2009. � 3. GEN2, 123/0057/,029—Began operation on 9/28/2011. 4. ENG 104, 123/0057/028—Began operation on 10/1/2011. 5. PLVGEN, 123/0057—APEN submitted on 1/30/2012. 6. H-ST2, 123/0057—APEN exempt heater(Regulation 3, Part A, Section II.D.I.k) began operation on 11/5/2012. 7. H-ST3, 123/0057—APEN exempt heater(Regulation 3, Part A, Section II.D.11c)not yet built. 8. H-ST4, 123'/0057—APEN exeinpt heater(Regulation 3, Part A, Section II.D.l.k) not yet built. One (1) of the identified emissions decrease listed below, calculated baseline actual emissions as defined in Regulation 3, Part D, Section II.A.4.b by selecting the highest annual average based on a consecutive ', 24 month period, except Section II.A.4.b.(iv) does not apply for contemporaneous increases and decreases ' as stated in Regulation 3, Part D, Section II.A26.a.(ii). The baseline actual emissions were calculated for ' the removal of Unit 102 based on 1/1/2005 to 12/31/2006 actual emissions. I 1. ENG 102, 123/0057/024—Engine shutdown on 4/30/2009. ! Page 3 I �ii One (1) of the identi£ied emissions decrease listed below, was not included in the contemporaneous emissions because fugitive emissions as defined in Regulation 3, Part D, Section II.A.24.e, shall not be included in deterxnining for any of the purpose of Part D,whether it is a major source. Lancaster is a gas processing facility and is therefore, not one of the named categories in Regulation 3, Part D, Section II.A.24.a.(i) or a source category as of 8/7/1980 regulated under Section I 11 or 112 of the Federal Act. 1. FUG, 123/Q057/018 —Decreased fugitive emissions in Pernut 00WE0583 from actual component count. One (1) of the iden#ified emissions increase listed below, calculated projected actual emissions utilizing the source's potential to etnit(PTE) emissions as defined in Regulation 3, Part D, Section II.A.36.a.. The baseline actual emissions were calculated as defined by Regulation 3; Part D, Section II:A.4.b by selecting the highest annual average based on a consecutive 24 month period, except Section I1.A.4.b.(iv) does not apply for contemporaneous increases and decreases as stated in Regulation 3, Part D, Section ILA.26.a.(ii). The baseline actual emissions were calculated based on the sources 12/1/2010 to 11/31/2012 actual emissions. The net emission increase = projected actual emissioiis (PTE) -baseline actual emissions. 1. 5021, 123/0057/053 — On 7/20/2012 requested to increase gas to flare voluines and modify , einissions. Permit has not been issued. Four(4) of the identified emissions decreases listed below calculated baseline actual emissions (BAE) as defined by Regulation 3, Part D, Section II.A.4.b by selecting the highest annual average based on a consecutive 24 month period. One consecutive 24 month period was selected for each regulated NSR pollutant. The period selected for NOx was 4/1/2008 to 3/31/2010 and the period selected £or CO, PMZ.5 and CO2e was 1/1/2003 to 12/31/2004. The CO BAE for ENG 35, ENG 36 and ENG37 were adjusted as per Regulation 3, Part D, Section II.A.4.b.(iii) due to contxols installed in 2007 as requixed by the May 17, 2007 KMG Consent Decree. I 1. ENG 31, 123/0057/013 — Engine will be removed upon start-up oF Lancaster Train 2, estimated as 1/1/2015.� � . � � 2. ENG 35, 123/0057/007—Engine will be removed upon start-up of Lancaster Train 2 estimated as 1/1/2015. 3. ENG 36, 123/0057/005—Engine witl be removed upon start-up of Lancaster Train 1 estimated as � 1/1/2014. � 4. ENG 37, 123/0057/006—Engine will be removed upon start-up of Lancaster Train 1 estimated as 1/1/2014. i One (I) contemporaneous emissions decrease not included in the analysis was the control of the Platte Valley amine unit with a thermal oxidizer (123/0057/043). The emissions off the still vent of the aznine unit were questioned during a 12/23/2010 CDPHE inspection. The unit was installed in 1997 and was never found to be out of compliance during the fourteen (14) years it had operated. The previous owner was asked to perform an emissions test which was completed on 4/21/2011 after the ownership transfer to KMG. Results were subinitted to KMG on 7/18/2011 and a pernut application to control the amine unit , was submitted on 2/5/2012 after engineering design was completed. The amine unit was controlled on . . . . . � Page 4 11/8/2012 and to date, not final construction permit has been issued for the source. Therefore, KMG did not include this emissions decrease as a contemporaneous source. NetEmission Zncrease Calculation The net emission increase was calculated as required by Regulation 3, Part D, Section II.A.26 by summing the increase in actuat emissions of NOX, CO, PM2,5 and CO2e from the proposed Lancaster project (Step 1) and the emissions increases and decreases within the defined contemporaneous period (Step 2). As shown in Table 2 below, the proposed Lancaster project will not cause a significant net emission increase in NOX, PMZ,5 and CO emissions but will cause a significant net emission increase in CO2e emissions. Therefore, since the proposed project results in a major modification for CO2e, a BACT analysis for Greenhouse gases is required � . . � . � Page 5 � � � � � • .._---. . ._.. _.__ _. . . ... _ _ ��Ti161e 2f�Luncnster:Pland(Ste�1��+Ste 2)Ne[Cmieaian Incrcase CalculnHon . UvitlD ABSID PermicN ComempuaveousChange � Datt . � NOx CO�� CO,e PM25 .� CamenipaFv ennaslons inereuse>ai�d darroses tram]/xUu9�a lIEQ15(Slep 2j�� . ENG103� 123/005]/026 0]VfEO]98 AddedUmt103;IvcreaseFuelUseonl�/4/II 2IIgI2009 � 304 ]6 I85194 I4 � SouNDehy �23/005)/02] OTNEOl99 � Swmdup3l1212009 � 3/122009 }_�3 63 2928b � Q�J � ENG102' P3/0059/024 a3WE115Z � EngineShutdown 4/30I2009 -13.9 -99 -5]88.4 -QS ENG33' ��3I0�5]/004 IIWE]]0-1 Oe-reredfram2166-hpm2a46-hp 6/302009 ENG 3G @3/009/005 I I WE]30.2 De-rated fmm 216Ghp m 2046-Gp 6/302�09 ENG 3]' @3/0�5]/006 11 WE'/303 � D�vared from 2166-hp�0 2046-hp 6/3�/2009 ENG35' 123/005]/00] IIWEI32 De-ratedfrom1859-hpml]56-hp 6/3�/30�9 FUG° 123/OOSJ/0�8 O�WE0583 Emissio�sdecreaseduetocompoventrowe 8/42010 GEN2� I23IOOSU029 � IOWEI58] Sianedup9/29/ti 9/28/2011 0.6 0.0 � N/A � 0.0] EUI04� I23I0059/028 IOWEIO"/l Smrtedupl0/Uil 14/12011 32.0 8.0 205]50 1.4 NorihDelry' 123/OOSpI021 OIWEO]G4 Decreesecombustion�empe"rawre I�R�Rpll : � PLVGCN� 123/005] APENOnfy AddcdPLVPLCGensei �/3p2p12 00 12 � N/A 04 N-Si2� 123Po�5] Exempt Added5MMBtWhrConden,vateSmbilizer 11/S12012 1.8 42 }610.5 023 . H-ST3� 123/005] Exemp� Add5MMDnJhrCovdcvmeSmbilizer TBD 1.8 42 ]66�.5 p.23 H-ST4� 123/U05] Exempi Add 5 MMBmlhr Condensa�e Smbilizcr TBD 1.8 42 3G60.5 p21 S021' ID/OOAI09 02WE�929 I�crcasePlaueValleyGs�oFlare TBD >.8 15J i0111 0.0 ENG31" 123I005"II01] 9"IWE0180 RemoveengiveupunTrain2start-up 1/12015 -IS] -023 3345.8 -OS ENG35` 123/Of15]IUO] IIWEI32 AcmovicengimuponTnin2nart-up � I/12015 -51.4 -I?6 -51060 ¢.I . ENG36° t23/005]/005 tIWG)30-2 Rcmovcc�gi�euponTrainlsiart-up - VI2014 � -G9J -IJ.2 -G231.8 -25 � ENG39" 12JIOOSJ/U06 IIWE"130-3 Removeen6ineupunTrainlaurt-vp VI2014 -BLS -13.G -59619 d Prapaeid�MoJifieutlunPrujee�Cmissinns(Stepl). � � � � � � � �E-2015 � NA 12WEI492 MoleSieveR6 �'+�ionGsHerorwi�hUlo-aLowNOnBurncrx 1/12014 51 � 51 I52523 LU � E-2016 � NA 12WCI492 MoleSieveRegenem�ionGasHea�erwiihUlvaLuwNOx9urners tA2015 52 52 152RJ IA � H-6051 � NA ¢WEI492 HeotMedimnHearei�wiehLowNOx6umers I/i/2014 13.5 Iy5 I94212 IJ . � �H-fi052 NA 12WEt492 HeatMcdiumHea�erwitl�LowNOxBumus 1/12014 135 13.5 39421? 19 � � HL053 NA 12WGI492 Hea�McdimnHemeewiihLowNOxBomers IIV2015 ❑.5 U.5 J9421? IJ � H-6054 NA 12WEI492 Heu�MediumHearerwirhLowNOxRumers 1/II2015 13.5 ❑.5 1942L2 U � A-I NA � 12WEI492 ISOMMSCFDAmincTrcehr(Ca�voticdwithAT0.q I/12014 ].9 fi6 941213 0.6 A-2 NA 12WE1492 . ISOMMSCFDAmincTrce�a(Ca�molledwiihATO-2) t/1/2014 99 66 941213 O.fi � . Ad NA 12WEI492 ISOMMSCFDAmineTreorer(ConvolledwithATO-I) IIIR015 ].9 6.6 � 94121.3 06 A-4 NA 12WEI492 ISOMMSCPDAmineTrcater(ControllcdwithATO-0J I/12015 ].9 6.fi 94121.3 06 � � F-2 NA 12Wc1492 � F-2LancaxterPlantProccssFlarel 1/V2014 ]3 14.G 6220.� � F-3 NA 12WEI492 F-3La�emlerPlanlPmcessFlare2 IIV2015 ZI 14.G G220.0 GEN3 NA ¢WEI492 Caterpi11ar839-hpDieselEmergenryGeneraror 1/1/2014 2.6 02 191.5 O.t � Step1+S[ep2 d].5 08.9 608,654 - 6.] PSDSig�ifiaa�ceThresholJ 40.0 100.0 95,000 ]p Srcp2,Uoupmjectcauseasigoifcanenetemissionincrrsse? 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Appendix B—RBLC Information Summary...................................................................................... B � . il I � Facilitv Information: The Lancaster Plant will be adjacent to the Fort Lupton Gas Plant which is in Weld County, CO at Northwest Ya, Section 14, Township 2 North, Range 66 West. The coordinates are: Latitude: 40°, 16.14'N Longitude: 104°, 45.08'W The street address is: I 16116 WCR 22 Ft. Lupton, CO 80621 ', The existing facilities currently operate under a number of construction permits as well as � Title V operating permits. A recent acquisition of assets formerly owned by EnCana also brought the Platte Valley Station Jnto the single facility complex. Process Descriation: The new 600 million standard cubic feet per day (MMscfd) cryogenic p1anY'will be tocated adjacent to the existing Fort Lupton Facility which includes gathering compression and existing cefrigeration plant. The plants will receive third par[y gas from the Kerr McGee Gathering pipeline system in the Wattenberg Field, remove COZ via amine treating, dehydrate the gas through the use of molecular sieve beds, extract natural gas liquids (NGL)through the use of the gas sub-cooled process (GSP) and SCORE cryogenic cooling processes and then � re-compress the residue gas stream for sales. Inlet gas will be compressed with five (5) 3,750-hp electric motor driven reciprocating compressors that will discharge to a high pressure pipeline that feeds the Lancaster Plant. The COZ is removed from the inlet gas stream utilizing four(4) 600 gpm amine treaters. The amine treaters incorporate a Yhermal oxidizer per unit to control emissions. The gas stream is I then dehydrated using a molecular sieve. The molecular sieve beds are regenerated using dry gas that has been heated by the regeneration gas heater. The dry gas is then run through the cryogenic unit to super-cool it and remove natural gas liquids (NGL). The cryogenic units are supplemented by six (6) 3,000 hp electric motor driven propane refrigeration compressors. The residue gas from the cryogenic units is then compressed utilizing four (4) 12,000 hp electric motor driven compressors to deliver the gas to the transportation pipeline. The produced NGLs are also transported from the facility via a pipeline. The primary reason for treating the inlet gas with amine is to ensure that the NGLs meet pipeline specifications. The inlet gas has about 2.7 mole % COz. Treating the feed gas avoids issues with liquid treating, such as amine carry over and meeting the pipeline water specification. Because the amine units are designed to remove COZ from the natural gas, the generation of COz (GHG) is inherent to the process, and a reduction of COz emissions by process changes would only be achieved by a reduction in the process efficiency, which would result in � natural gas that would not meet pipeline quality specifications and leave COZ in the natural I� gas for emission to the atmosphere at downstream sources. The amine units do also emit _ __ methane (GHG) at the point of amine regeneration, due to a small amount of natural gas becoming entrained in the rich amine. Emission Sources: The proposed project triggers Prevention of Significant Deteriaration (PSD) permitting I thresholds far greenhouse gases, but does not trigger PSD for any criteria pollutants. The primary sources of GHGs proposed at the 600 MMscfd plant wiil be: C-4100 Solar 12,000-hp Electric Drive Motor, Residue C-4200 Solar 12,000-hp Electric Drive Motor, Residue G4300 Solar 12,000-hp Electric Drive Motor, Residue C-4400 Solar 12,000-hp�lectric Drive Motor, Residue G5110 3000-hp Electric Motor,Refrigeration Compression G5210 3000-hp Electric Motor, Refrigeration Compression G5310 3000-hp Electric Motor, Refrigeration Compression G5410 3000-hp Electric Motor, Refrigeration Compression G5510 3000-hp Electric Motor, Refrigeration Compression G5610 3000-hp Electric Motor,Refrigeration Compression ENG 105 3750-hp Electric Motor, lnlet Compression ENG 106 3750-hp Electric Motar, Inlet Compression ENG 107 3750-hp Electric Motor, Inlet Compression ENG 108 3750-hp Electric Motor, Inlet Compression ENG 109 3750-hp Electric Motor, Inlet Compression E-2015 Mole Sieve Regeneration Gas Heater with Ultra-Low NOx Burners E-2016 Mole Sieve Regeneration Gas Heater with Ulh•a-Low NOx Burners H-6051 Amine Regeneration Heat Medium Heater-Low NOx Burners H-6052 Amine Regeneration Heat Medium Heater-Low NOx Bumers H-6053 Amine Regeneration Heat Medium Heater-Low NOx Burners H-6054 Amine Regeneration Heat Medium Heater-Low NOx Burners A-1 150 MMSCFD Amine Treater(Controlled with ATO-1) A-2 150 MMSCFD Amine Treater(Controlled with ATO-2) A-3 150 MMSCFD Amine Tteater(Controlled with ATO-3) A-4 150 MMSCFD Amine Treater(Controlled with ATO-4) F-2 Vertical Process Flare F-3 Vertical Process Flare GEN3 Caterpillar 839-hp Diesel Emergency Generator FUG 3 Plant Fugitives Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 2 The proposed project triggers PSD for the estimated GHG emissions as it is estimated to emit 578,235 tons per year (tpy) COZ equivalent (COZe) including fugitive emissions. The net COz emissions will be 557,569 tpy however, as four existing engines will be removed as part of this project. The COZe emissions are estimated by applying the global warming potential (GWP)of each GHG pollutant. The GWP for each pollutant is CO2: 1 CH4: 21 N2O: 310 For example this means one ton of inethane would equate to 21 tons of COZe. Detailed calculations can be found in the calculations section of the permit application: UNIT COZe tpy I C-4100 - � C-4200 - C-4300 - C-4400 - C-5110 - G5210 - I G5310 - ' G5410 - G5510 - G5610 - ' ENG 105 - � I ENG 106 - I ENG 107 - ENG 108 - ENG 109 - �2015 15,252 ' E-2016 15,252 H-6051 39,421 H-6052 39,421 � H-6053 39,421 I H-6054 39,42] I A-I 94,121 A-2 94,121 A-3 94,121 A-4 94,121 ! F-2 6,220 F-3 6,220 ' GEN3 172 FUG 3 949 TOTAL 578,235 ' Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 3 � BACT Analvses Methodolo�v: As of January 2, 2011, GHG is a regulated criteria pollutant under the PSD major source permitting program codified in Title 40 Code of Federat Regulations (CFR) Part 52 when they are emitted by new sources or modifications in amounts that meet the Tailoring Rule's set of applicability thresholds. For PSD purposes, GHGs are a single air pol(utant defined as the aggregate group of the following gases: carbon dioxide (CO2), nitrous oxide (N2O), methane (CH4), and hydrofluorocarbons (HFCs). I The PSD re ulations do not rescribe a rocedure for conductin BACT anal ses. Instead g P P g Y , EPA has consistently interpreted the BACT requirement as containing two core criteria: L The BACT analysis must include consideration of the most stringent available technologies, i.e., those that provide the"maximum degree of emissions reduction." 2. Any decision to require as BACT a contro] alternative that is less effective than the most stringent available must be justified by an analysis of objective indicators showing that energy, environmental, and economic impacts render the most stringent alternative unreasonable or otherwise not achievable. EPA has developed what it terms the "top-down" approach for conducting BACT analyses � and has indicated that this approach will generally yield a BACT determination satisfying the two core criteria. Under the "top-down" approach, progressively less stringent control technologies are analyzed until a level of conrirol considered BACT is reached, based on the environmental, energy, and economic impacts. The top-down approach shall be utilized in this BACT analysis: , The Hve basic steps of a top-down BACT analysis are listed below: 1. Identify all available control technologies with practical potential for application to the specific emission unit for the regulated pollutant under evaluation; 2. Eliminate all technically infeasible control technologier, 3. Rank remaining control technologies by effectiveness and tabulate a contro] hierarchy; 4. Evaluate most effective controls and document results; and 5. Select BACT; which will be Yhe most effective practical option not rejected, based on economic, environmental, and/or energy impacts. � Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 4 BACT Evaluation for Sources: Step 1:Ident� Control Options I The following are potentially applicab]e control technologies for controlling GHG emissions associated with the En ines: 1. All the new compressor engines at this facility will be run on zlectric power resulting in no GHG emissions from these sources. Therefore, no further analysis is necessary for the engines. 2. The 839-hp diesel emergency generator will operate a maximum 500 hrs/yr limited to emergency situations only. The generator will meet all emissions, operating and compliance requirements of NSPS Subpart IIII for staYionary oompression ignitions ICEs. All manufacturers recommended maintenance will be performed as required. The following are poYentia]ly applicable contro] technologies for conTrolling GHG emissions associated with the Amine Vents 1. Proper Design and Operation: The amine units are designed to include a flash tank, in which gases (i.e., including CO2 and methane)are removed from the rich amine priar � to regeneration, thereby reducing the amount of waste gas created. The amine units at this faciliTy shal(be constructed and operated for optimal performance; 2. Amine Unit Flash Tan]< Off-gas Recovery System: The amine unit flash tank off- gases shall be routed to the proposed thermal oxidizer. 3. Routing Amine Unit Regenerator Vent to a Thermal Oxidizer: This control device wil( reduce the methane emissions by 99% and wilt convert those emissions to CO2, which has a lower GWP; 4. Routing Amine Unit Regenerator Vent to a Flare: This control device will reduce The methane emissions by 98% and will convert those emissions to CO2, which has a � lower GWP; 5. Carbon Capture and Storage (CCS): This involves capturing CO2, transporting it as necessary, and permanently storing it instead of releasing it into the atmosphere. The process involves three main steps • Capturing CO2 at its source by separating it from other gases; • Transporting the captured CO2 to a suitable storage location (typically in compressed form); and • Storing the CO2 away from the atmosphere for a]ong period of time, for instance in underground geological formations, or within certain mineral formations. � In the project two CCS approaches were looked at: acid gas injection well and enhanced oil recovery (EOR) The following are potentially applicable contro] technologies for controlling GHG emissions associated with the Heaters: � � � 1. Fuel Selection: The heaters at the site shall be fired on pipeline quality natural gas. This results in 28% less CO2 production than fuel oils (see 40 CFR Part 98, Subpart C, Table C-1, which is included in Appendix E, for a comparison of the GHG emitt4ng potential of various fuel types); Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page S _ 2. Efficient Heater Design: New burner design improves the mixing of fuel, creating a more efficient heat transfer. At the new facility,new bumers shall be utilized. Burner management systems shal( be utilized on the heaters, such that intelligent flame ignition, flame intensity controls, and flue gas recirculation optimize the efficiency of the devices. 3. Periodic tune-ups and maintenance for optimal therma] efficiency: Nfaintenance shall � be performed routinely per vendor recommendations or the facility's maintenance plan. The components shall be serviced or replaced as needed. The heaters shall be tuned once a year for optimal thermal efficiency; 4. Oxygen trim control: Combustion devices operate with a certain amount of excess air to reduce emissions and for safeTy consideration. An inappropriate mixture may ]ead to inefficient combustion. Regular maintenance of the draft air intake systems of the heaters can reduce energy usage. Draft control is applicable to new or existing . process heaters and is cost effective for process heaters rated at 20 to 30 MMBtu/hr or greater. The heaters wil] have air and fuel valves mechanically linked to maintain the proper air to fuel ratio. i The following are potentially applicable control technologies for controlling GHG emissions i associated with the Process Flares: 1. The process flares will be designed according to best engineering practices and API Standards 521 and 537. Both flares will utilize a bumer management system, a pilot monitoring system and a combustion air blower to optimize combustion. I The following are potentially applicable control technologies for controlling GHG emissions associated with the Overall Facilitv: 1. Overall efficiency of facility; 2. Existing Fort Luptan equipment permanent shutdowns, 3. Compliance with NSPS Subpart KKK for fugitive equipment. � Step 2:Eliminate Technically Infeasfble Control Options I At the current time acid gas injection wetls for this location appear to be technically infeasible. There are no known acid gas injection wells operating in the Denver-Julesberg (D-J) Basin. The current consensus is that acid gas injection wells would not sequester the CO2, but rather the CO2 would migrate to other producing wells creating a recycle of CO2. Step 3: Cl:aracterize Control Effectiveness of TechnicaQy Feasible Control Options The efficiency improvement/GHG reduction technologies are ranked* below: • Use of electric-driven engines (100%); • Install amine unit flash tank off-gas recovery systems (100%); • Routing the amine unit vents to a thermal oxidizer (99% for methane, and generates CO2); • Routing the amine unit vents to a flare (98%for methane, and generates CO2); Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 6 • E�ciencies within the plant(variable); � s Hours of operation limitation emergency generator(943%) • Fuel selection(28% when comparing natural gas and No. 2 Fuel Oil); • Burner management systems on the heaters, with intelligent flame ignition, flame intensity controls, and flue gas recirculation(10-25%); • Bumer management systems on process flares, with a pilot monitoring system and combustion air blowers (10-25%); • Efficient heater design (10°/o); • Annual tune-ups and maintenance(1-10%); • Oxygen trim control; • CCS (not a feasible option for the Project due to technical, environmental, and economic reasons, as discussed in Step 4). *The fo]lowing documents were used to identify any available control efficiencies including some vendor specifications: i) Available and Emerging Technology for Reducing Greenhouse Gas Emission from the Petroleum Industry dated October 2010 and ii) �nergy EY'ficiency ImprovemenY and Cost Saving Opporiunities for the Petrochemical Industry: An ENERGY STAR Guide for Energy Plant Manager, Document Number LBNL-964E, dated June 2008, Step 4: Evaluate Most Effecttve CoKtro[Options As part of this project the following options that were listed in Step 1, shall not be proposed for implementaTion as BACT: I 1. The routing of amine unit regenerator vent to a flare (98% control), because a more efficient technology (thermal oxidizer, with 99% efficiency)will be addressed. 2. Amine flash tank off-gas recovery. The amine flash tank off-gas will be routed to the therma] oxidizer to aid in combustion of the regenerator vent gas. 3. CCS is not considered to be feasibla, based upon its lack of readily available technologies and negative environmenta] and economic impacts. However, per EPA guidance, EPA has identified CCS as an add-on control technology that must be evaluated as if it were technically feasible. The amine flash tank off-gas will be routed to the thermal oxidizer for combustion rather than recycled to the plant inlet. Due to the low Btu and the cooling effect of the CO2 in the amine regenerator vent gas stream, additional Btu contenT (assist gas) will need to be added to aid in l combustion in the therma] oxidizer. If the flash gas were to be routed back to the plant inlet, additional compression would be needed and the energy required would negate the potential 'i savin s on the flash as. The desi n will utilize the hi h Btu flash as to he] su 1 some of B g g g g P P P Y the additional Btu need to offset a portion of the pipeline gas utilized for the remaining assist gas. The emerging CCS technology is an "end of pipe" add-on control method comprised of three stages (capture/compression, transport, and storage). CCS involves separation and capture of CO2 from the exhaust gas, pressurization of the captured CO2, transmission of CO2 via Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 7 _ - ------ _ -_ _ __ _— _ pipeline, and injection and ]ong term geologic storage of the captured CO2. CCS can also consist of use of CO2 in Enhance Oil Recovery (EOR) opportunities. The goal of CO2 capture is to concentrate the CO2 stream from an emitting source for � transport and injection at a storage site or ]ocation uti(izing EOR. CCS requires a highly concentrated, pure CO2 stream for practical and economic reasons. Extracting CO2 from � exhaust gases requires equipment to capture the flue gas exhaust and to separate and pressurize the CO2 for transportation. Extracting CO2 from the exhaust gases of the heaters and thermal oxidizers would require equipment to capture the flue gas exhaust and to separate and pressurize the CO2 for transportation. The exhaust stack streams will be low pressure, basically atmospheric pressure. The streams would also be emitted at high temperatures. The CO2 separation would require the remova] of all other pollutants from the streams. The process would require compression to increase the pressure from atmospheric to pipeline pressures. The process would also require the reduction of the temperature of the streams by severa] hundreds of degrees priar to separation, compression, and transmission. Basically an entire plant similar to what is being proposed in this project (smaller in size) would have to be constructed to remove the CO2. This process would add even more GHG emissions and large costs to the project. This option is not environmentally, nor economically feasible. Even if we assumed there was a feasible way to separate the CO2 from the combustion streams, there would be several logistical issues that need to be resolved including obtaining right of way (ROW) and NationaJ Environmental Policy Act (NEPA) efforts for a pipeline to I transport the CO2 to a location that would be available to receive and handle a continuous long term stream of CO2. The geological formations available near this proposed site are not technically feasible to store the CO2 as mentioned previously. In addition EOR is not, feasible at any large scale level in the D-J Basin due to its geology and multiple owner/operators in the area. There may be some single well CO2 EOR projects forthcoming in this area, but nothing of the magnitude that would be able to handle The continuous supply of CO2 that would be produced from this project. Since different owner/operators are located in close proximiTy, large scale EOR is not feasible. The exhaust streams from the heaters and thermal oxidizers would have to be cooled, compressed, and h�eated priar to being able to enter a pipeline. A conservative estimate on the cost of equipment that could possibly be installed for.these purposes was assumed 4o be $50,000,000. The nearest identified area utilizing EOR with CO2 is approximately 300 miles from the Plant. At a cost of $80,000 per inch mile to install a 12" pipe line, the total cost for the pipeline alone would be approximately $288 million($80,000 x 12 x 300). Detailed engineering was not done on horsepower requirements to boost the gas along the approximately 300 miles of pipeline because a definitive route was not chosen. However, we could estimate it take 80,000 horsepower (including horsepower required at the site to get the gas up to a pipeline pressure, intermediate pipeline booster compression, and end point injection compression). The cost of that additional horsepower would be approximately $200,p00,000. There would also need to be additional surface equipment (i.e. separators, dehydrators, storage tanks, etc:) at the booster sites and all equipment would have to be able to handle the acid gas (CO2). The cost of the additional surface equipment was not estimated Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 8 in this exercise. Even excluding a portion of the cost, the engine cost and pipeline cost would equate to a $156/ton cost of control. There is a high likelihood that the remote booster stations would not be able to uYilize electric compression, therefore it will have negative impact on the environment Hence the use of CCS to reduce GHG emissions is not economically or environmentally feasible for this project, and the timing required for ROW issues and NEPA analyses would extend the project start date out by years. In addition there is no assurance that any available CO2 pipeline or EOR area would even have the capacity to handle the CO2 from this project. Step S:Establish BACT After discussion in the previous sections,the proposed BACT for this project would include: EnEines- ➢ Electric motors on compressor engines O 84,750 hp of electric driven compression ➢ Emergency generator o Limit hours of operation to 500 hrs/yr o Follow NSPS Subpart IIII requirements o Follow manufacturer recommended maintenance Amine Vents- ➢ Routing off-gases to therma] oxidizer for combustion o Therma] Oxidizers utilize combustion air preheaters and acid gas heat exchangers i Heaters and Process Flares- ➢ Design, operation, and management criteria as specified in Steps 1 & 3 Overall Facilitv- ➢ Efficiencies � o Engine shutdowns � ➢ Compliance with NSPS Subpart KKK as applicable o LDAR to reduce fugitive leaks The therma] oxidizers proposed to control emissiorls from the amine vents will utilize combustion air preheaters as well as an acid gas heat exchanger to minimize additional fuel requirements. The engineering design firm has estimated that the preheaters and heat exchangers will reduce assist gas requirements by approximately 11 MMBtu/hr. That efficiency relates to an avoided amount of 5,637 tpy of CO2e for each thermal oxidizer. Kerr-McGee Gathering is committing to 84,750 horsepower of electric compression as part of this project. The choice of electric compression wil] eliminate GHG emissions from the compression needs of the plant. Based on Cateipillar data on recent 3600 series engines, CO2 emissions from natural gas fired engines are approximately 450 grams per horsepower- hour. That would equate to 368,267 tpy of CO2e from 84,750 horsepower of natural gas Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 9 fired engines. Not to mention there would be overall energy efficiencies by utilizing electric compression in this project. As part of the overall project, four natura] gas fired engine at the existing Fort Lupton plant will be permanently shut down (EU-31, EU-35, EU-36 and EU-37). The runtime resh•ictions on the engines will reduce up to 20,666 tpy of CO2e. Total quantifiable CO2e reductions of 394,570 tpy are proposed as part of the BACT as well as numerous reductions that are not as easily quantifiable, such as maintenance and operation conditions on the heaters. Overall the proposed project will treat 600 MMscfd of gas with only modest increases in criteria emissions at the facility. While there is a proposed 557,569 tpy net increase in GHG emissions in the project, it is effectively removing the CO2 from the gas stream that would uitimately have been emitted at some point downstream of this facility. The overall avoided and reduced GHG emissions far the project are greater than 50% of the proposed total net GHG emissions. Kerr McGee Gathering- Lancaster Cryogenic Project GHG BACT Analysis Page 10 APPENDIX A Economic Analysis for CSS Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B I 9 V N E « o d o 0 0 m o d F» » » � W m w � GJ `o � N v °J . t � y � m V co m � . .. Z,U � N o Y. R > U � m � . . i.: = U p .� ci . . . O � u °' ^ N ' ^ � � cn F» `R � � -^o � - v o N - . � v E c' c�i � w o � . U d � T m � � N f0 O O " C +L-� � d � (6 � ,�-� L Gl O � � � O rn � N . . � a �O� Q C V � O N o � � V C . Q w � - � �» � fa o O N O E ,y O U s C J � y m a. w. � o 0 p �� m . a o v `m ° > U "' � o " - ' W � ° � � j o� c o 0 0 o v rn o a j � d O O � V C O . _ N O C . O $ ' � . . E a a o m° � ' m U o � ,� - ' c . � � �' o 0 o E m p ami E . o � � . � _ � � U �. <.i o � '= m om u o a' w vs � � � O � c 5 °' o � '° � '� o ' 'c� '^ v .. () „ -o "3 � 3 � - a�°i w o o y V T U �p _ y U . � N� OJ � c O � N � N d' " �L' f . O " " °�' `° " � " p � � � � a ,m, LLLL N m n E 9 c 3 � w o p m C � _ U L �¢ 'a Z`a' o a ••-- � a � � � � c� � c Q v+ � O N � U O O O � � U ¢ E � F� ` N C � w U � v W � E � ~ � � J C ��" U [O N y T N p. N O U C O L1 � t�fl � ~ O � �� U N � C U N O Q � � ry a p. O LL c �� Q (yj (J L ' �p O O C N � Z` N Q a� o ' o a+ � E Sn n + � � w y 9 � . � ` N V � > N ^'_ C N d N � N C. C a J r . U O N O O > O Fa ? .f. ` } . ° J o ' H ._ m ` � + V E c `m � m o � 'y . � d . o � E � o o u� d o c ¢ _ _ � 3 ` .o .� vJ E . � N �i O I- Q N .i N �- m O G �@ � �O '�0 II � j N j O. N � . � S . a �E �'V U y ._°� m�m E 'm'm"m K � co � Z a o O t6 y, y �N s O D U U V L 'N 0] U � 1° � ≤ m m 11 II II � . . .� a � o p T � � y m w ro °- `m c o � � d � W 0 0 0 � E ' Q ¢ � � O � u�i « � `� o 0 o ai x ° ?� U V � � � y � ?i U "" . N C .0 � � � C � . tl) o �E a�g >. Q m m � c ° � °1 � ° � " E E m � m � � l . � Q U m y O � y � J � .�c N U . � F . .C G � W C G N W y N c � O II `m z °' � i � ° °' � m o `w m c a U o w Z ` ' ° � n � � c � . � . a o � K a � '� ° o c� � V � ° � m � U K m v w � Y . N N x5 ' .'�. � II . - Q O O �? „ �? � U rs y _ c U U =� '_- a Q U H U APPENDIX B RBLC Information Summary Kerr McGee Gathering—Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B � � - � .^Previous Page �t Report Date: 04/12/2012 INDEX OF CONTROL TECHNOLOGIES DETERMINATIONS NOTE:Draft determinations are marked with a" *"beside the RBLC ID. _ ._______ �_.____.___ .. __.. .�... ...__ ______. _�...._ _ __.___. . ._.... __._._ _._._..._ . —_._—. Company Name �LC Country Permit Process process Description ID Date(Est/Act) Type OTTUMWA -_.__ ._ -____ _.._._. _ . ___.. GENERATING � USA 07/12/2012ACT 11.110 Boiler#1 STATION � *IA-0101 . COGENERATION USA 12/06/2011 ACT I5210 COGENERATION TRAINS 1-3 Q-10,2-]0,3-10) PLANT *LA•0256 . - � 17.130 EMERGENCY GENERATOR � . . SABINE PASS LNG USA 12/06/2011 ACT 15.200 Combined Cycle Refrigeratiou Compressor Turbines(8) TERMINAL *LA-0257 � 19.390 Wet/Dry Gas Flares(4) � . . � 19390 . Marine Flare . . � . 50.999 Acid Gas VenYs(4) . � I5.100 Si�nple Cycle Genecation Turbines(2) . . 17.130 Generator Engines(2) � . I5.100 Simple Cycle Refi�igeration Compressor Turbines Q 6) . - 50.999 Fugitive Emissions . PORT DOLPHIN � ENERGY LLC * USA 12/01/2011 ACT 99.999 Fugitive GHG emissions � , FL-0330 � . � � � 11.310 Boilers(4-278 mmbtu/hr each) � 11310 Power Generator Engines(3) � ENI-HOLY CROSS � USA �0/27/20ll ACT 13.220 Boiler � DRILLMG PRO7 *FL-0328 � 17.110 Emergency Fire Pump Engine - � � � . 17.110 Emergeney Engine . 17.110 Ccane Engines(units 3 and 4)� � � �. 17.110 Crane Engines(units 1 and 2) � . . 17.170 Main Propulsion En�ines � � 42.000 Storage Tanks . NINEMILE POINT � ELECTRIC GENERA LA-0254 USA 08/16/2011 ACT 17.110 EMEAGENCY DIESEL GENERATOR . - 17.210 EMERGENCY F1RE PUMP . . � 99.009 UNIT 6 COOLING TOWER . 99.009 CHILLER COOLING TO WER(CHILL CT) - 11.910 AUXILIARY BOILER(AUX-1) � � . 15.210 COMBINED CYCLE TURBINE GENERATORS(UNITS.6A &6B) DIRECT REDUCTION 01/27/2011 ACT 81.900 DRI-101 DRI Unit#] Iron Oxide Da Bins Dust Collection IRON PLANT LA-0248� USA Y � � 81.290 Dffi-111 -Dffi Unit#1 Acid Gas Absoiption Vent � � 81.900 DRI-102 DRI Unit#1 Iron Oxide Screen Dust Cotlection � � � 81.900 DRI-202 DRI Unit#2Iron Oxide Screen Dust Collection - � � 81.900 DRI-105 DRI Unit#1 Fumace Feed Cmiveyor Baghouse � . � � 81.900 DRI-205 DRI Unit#2 Furnace Feed Conveyor Baghouse � � � � . 81.900 DRI-103 DRI Unit#1 Coating Bin Filter . 81.900 DRI-203 DRI Unit#2 Coating Bin Filter � . 81.900 DRI-104 DRI Unit#7 Iron Oxide Fines Handling . � . � � 81.900 DRI-204 DRI Unit#I Iron Oxide Fines Huidling � - 99.009 DRI-113-DRI Unit#1 Process Water Cooling Tower � � � � � � 99.009 DRI-213-DRI Unit#2 Process Water Cooling Tower . . � 99.009 DRI-114-DRI Unit#1 Clean Water Cooling Tower . � 99.009 DRI-214-DRI�Unit#1 Clean Water Cooling Tower � . . . �81290 DRI-117-Briquetting Mill . 99.190 DRI-1 l8-DRI Barge Loading Dock . . 81290 DRI-115-Product Screen Dust Collection � . . . � 81290 DRI-ll6-Screened Product Transfer Dust Collection . � � 81.290 DRI-107-DRI Unit No. 1 Furnace Dust Collection � � 81290 DRI-207-DRI Unit No.2 Furnace Dust Collection � . � 11310 DRI-109-DRI Unit#1 Package Boiler Flue Stack � 11310 DRI-209-DRI Unit#2 Package Boiler Flue Stack � 81290 . DRI-112-DRI Unit No. 1 Product storage silo Dust Collection '�, . 81190 . DRI-212-DRI Unit No.2 Product storage silo Dust Co1lecYion . � 19.390 DRI-210-DRI UnitNo.] Hot FLare � � - � 19.390 DRi-110-DRI Unit No. 1 Hot Flare . � . � . 81.200 DRI-208-DRI Unit#2 Refoemer Main Flue Stack � � � 81.200 DRI-108-DRI Unit#1 Reformer Main Flue Stack 81290 DRI-206-DRI Unit No.2 Upper Seal Gas Vent 81190 DRI-]06•DRI UnitNo. 1 Upper Seal Gas Vent � � � � 81.290 DRI-211 -DRI Unit#1 Acid Gas Absorption Vent �.. - . 81.900 DRI-201 DRI Unit#2 Iron Oxide Day Bins Dust Collection . �� . BASF FINA NAFTA � 02/10/2010 ACT 50.003 N-11,REACTOR REGENERATION EFFLUENT � � REGION OLEFINS � TX-O550 USA �. � 50.003 N-1 Q CATALYST REGENERATION EFFLUENT . 50.003 N-18,DECOKING DRUM � PRYOR PLANT 02/23/2009 AC1' 6L999 COOLING TOWER#2 ' CHEMICAL . . OK-0135 USA . � . 61.012 PR[MARY REFORMER � . 62.014 NITRIC ACID PLANT#] � 62.014 NITRIC ACID PLANT#3 � � . � � 6 L999 CONDENSATE STEAM FLASH DRUM-AMMONIA PLT 4 � 61.999 COOLINGTOWER#I � � � . 13.3�10 NITRIC ACID PREHEATERS#1,#3,AND#4 � - 61.999 CARBON DIOXIDE VENT � � . 61�.012 AMMONIUMNITRATEPLANTS#IAND#2 � . 61.999 GRANiTLATOR SCRUBBERS#1,#2,AND#3 � � 13310 BOILERS#1 AND#2 � 62A14 NITRIC ACID PLANT#4 RUMPKE SANITAAY aH-0330 USA 12�23/2008 ACT 29.900 ENCLOSED COMBUSTORS(4) � �� LANDFILL . . � 29.900 � MUNTCIPAL WASTE LANDFILL � 29.900 � OPEN FLARE � . � 99.150 � �PAVED ROADWAYS AND PAffi{ING AREAS � 29.900 CANDLESTICK FLARE(5) . CPV ST CHARLES MD-0040 USA i l/12/2008 ACT 99.999 COOLING TOWER � 17210 �TERNAL COMBUSTION ENGINE•EMERGENCY � GENERATOR . � �T 21� INTERNAL COMBUSTION ENGINE-EMERGENCY FIRE WATER PUMP � � . � � � I3310 BOILER � � . 15.110 COMBUSTION�TURBINES(2) � � � � . . li310 HEATER . � ACTIVATED CARBON LA-0148 USA OS/28/2008 ACT 11110 MULTIPLE HEARTH FURNACES/AFTERBURNEAS o FACILITY � :99.009 COOLING TOWERS � . � TWO(2)ELECTRIC ARC FURNACES AND THREE(3) � NUCOR DECATUR LLC AL-0231 USA 06/12/2007 ACT 81.210 LADLE METALLURGY FURNACES WITH TWO(2) � . . MELTSHOP BAGAOUSES li310 VACWM DEGASSER BOILER � - � . 13310 GALVANIZING LINE FURNACE � 81.296 VACWM DEGASSER � . . AIR PRODUCTS TX-0481 USA 11/02/2004 ACT 99.999 PARTS WASAER BAYTO WN I I � � � . 50.007 FUGITNES(4) � � � � 64.003 MSS PROCESS STEAM VENT � , � 64.003 PROCESS STEAM VENT � 19.800 EMERGENCY GENERATOR TANK � 64.003 MSS-NONCONDENSBLES(PROPYLENE VENTING) � � . 19.a10 FLARE(NORMAL OPERATION) . � 64.003 RECTISOL�VENT . - . � � � - � 19.800 EMERGENCY GENERATOR � 42.005 DIESEL FUEL TANK . � � _ � 13.390 BOILER STACK(START UP) � 11.390 BOILER STACI{(HIGH BTU PUEL) 50.005 COOLING TOWER � � � 50.005 SUPPLEMENTARY COOLING TOWER � � . 11.390 BOILER STACK � RUMPKE SANITARY 06/10/2004 ACT 29.900 PORTABLE TUB GRINDER I LANDFILL,INC �H-0281 USA . � � � 29.900 LANFILLROADWAYS � � � 29.900 LEACHATE STORAGE BASIN . . 29.900 LEACHATE AERATION BASIN 29.900 FUGITIVE EMISSIONS FROM LANDFILL AND GAS � COLLECTION SYSTEM � � � 17.210 PORTABLE ENGINE 4.68 MMBTU/H � 29.900 NEW SOLID WASTE D[SPOSAL WTTH LANDFILL CAS GENERATiON � � I . � � 17210 PORTABLE ENGINE 0.58 MMBTO/H � 29.900� LOAD•IN,LOAD-OUT,TURNING;AND WIND EROSION � 29.900 PORTABLE SCREENER � � � 29.900 EXiSTINC�SOLID WASTE DISPOSAL WITH LANDFILL � _ __. __ l � � GAS GENEAATION � Previous Page��f �..— _ t 4/4/13 � State.co.us E�cuti�,e Branch Mail-RE:Lancaster � � � t � ��'sp"� State �� , Colorado � r � :x R'.E: Lancaster Slhea, Jennifer<Jennifer.Shea@anadarko.com> Tue, Mar 12, 2013 at 3:00 PM �Tq: "Laplante-CDPHE, Christopher" <christopher.lapiante@state.co.us> � Ca "mark.mcmillan@state.co.us" <mark.mcmillan@state.co.us>, "Chaousy, Stephanie(stephanie.chaousy@state.co.us)" � <;>tephanie.chaousy@state.co.us>, "carissa.money@state.co.us" <carissa.money@state.co.us>, "Bracken, Korby" <I<orby.Bracken@anadarko.com> � . . , Chris, . � . . . Attached is the updated netting as requested below in#1 and#2. As for#3, we utilized AP-42factors(cond+fil)forthe 25 MMBtu/hr mole sieve regeneration heaters and al I other�sources at the facil ity except the four 60 MMBtu/hr hot oil heaters. Our manufacturer provided us guaranteed PM2.5 factors(cond+fil)forthese sources. Stephanie has all the required documentation. As requested I updated the netting analysis and also provided calculation sheets forthe sources with PM2.5 emission factors (2013-03-12 LANFacility Emissions.pdf). � Let me know if you have questions. . � lennifer Shea I Staff EHS Representative � � � � ANADARKO PETROLEUM CORPORATION . � . Direct: (720) 929-602S I CeIL (303) 919-0040 � From: Laplante- CDPHE, Christopher [mailto:christopher.laplante@state.co.us] Sent: Monday, March 11, 2013 3:44 PM � � To: Shea,]ennifer . � . � Cc: mark.mcmilian@state.m.us Subject: Fwd: Lancaster Jennifer, . � � I intended to send this e-mail to you on the 28th last month, but inad�t:rtently sent it to the wrong e-mail address. My apologies. I decided to double check since I had not heard back from you yet and determined my�error. � � Chris ------ Forwarded message---- i From: Laplante -CDPHE, Christopher<chnstopher.laplante@state.co.us> . � Date: Thu, Feb 28, 2013 at 8;56 AM . � � Subject: Lancaster . . https://mail.google.com/mail/?ui=2&i'�-7faca29a38&tiew=pt&cat=lancaster&search=cat&th=13d6067ab1b4e418 � . 1/3 . � . ._... . ._ � .. _ .. .. . _.._. . . . ... _:. . . ___.. 4/4/13 � . State.co.us F�cutiva Branch Mail-RE:Lancaster - � To: Jennifer Mattox -CDPHE.<jennifecmattox@state.co.us>, Stephanie Chaousy -CDPHE <stephanie.chaousy@state.co.us>, Carissa �Money-CDPHE <canssa.money@state.co.us>, mcmillanmaric@hotmaiLcom, ChristopherLaplante-CDPHE " _ <chnstopher.lapiante@state.co.us> . � Morning Jennifer, � � . � I ha�a few more questions related to the Lancaster netting analysis I would like to ask you. Please re�iew and respond to the questions � below. . � � . 1. I believe Kerr McGee installed emissions controis on the former Encana Ft. Lupton amine treater during the contemporaneous period. .While you indicate in your netting analysis the associated VOC reductions are not creditable (and we agree), the Di�ision belie�s there would be associated emissions increases in the form of NOX CO and PM2.5 that should be accounted for as � creditable emissions increases at that time. If you concur, I ask that you update and add these emissions to Step 2 of your nekting analysis. 2. It does not appear that PM2.5 emissions from the flares were accounted for in the 1-25-2013 version of the spreadsheet.nettin . I 9 think Stephanie may ha�run some numbers for what these emissions would represent. Please re�iew and add these PM2.5 emissions to the netting analysis Step 2 as a creditable increase. � . 3. I ha�.e not closely followed ali of the correspondence between you and Stephanie on the PM2.5 in�ntories. Therefore, I would like to�rify that ultimately Kerr McGee used.manufacturer's data for PM2.5 to estimate emissions for the newly proposed process � heaters (both the 60 MMBtu/hr and 25 MMBtulhr units)while also using AP-42 (total filterable and condesible PM2.5)for the other emissions sources in the netting analysis � � � Ultimately, I would like to recei�one final clean�rsion of the PSD Net Emissions Increase Calculation section of the permit application �� for the record. If you agree with#1 and 2 above and�rify#3 is�already reflected, those final changes should be made and a complete � clean�rsion of this section of the application sutimitted. Thank you Jen. Please let me know if you ha�2 any questions. � � Chris Christopher Laplante � � Oil and Gas Permitting5upervisor . � . AirPollution Control Division Colorado Department of Public Health and Environment 4300Cherry Creek Drive South � Denver,CO 80246-1530 office:303.692.3216 � � emaiL christopher.laplante@sYate.m.us A�adarko Confidentiality Notice: ihis electronic transmission and any attached docunents or other writings are intend=_d only fox �the person� . or entity to which it is addresaed and may contain information that is , . privileged, confidential. ot ot�erwis2 protectec from disclosure. Tr you � have received thi.s communication in error,� please immediately notify � � � sender by seturn e-mail and destroy the communication. Any disclosure,� � � copying, distribution er the taking of any action concern�ng the con�ents � � of this wmmunication or any attachments by anyone other than Cne � named recipient i.s strictly prohibited. . � . _._."__ _.....e,........�..__........,_._��__..A.._..,...G._..........._ . ..,,_...�.�....-d�-.....,...,�_ 3attachments. . � https://mail.g oog Ie.coMmai I/?ui=2&ik=7faca29a38&v�ev�r-pt&cat=Lancaster&search=cat&th=13d6067ab1 b4e418 y3 4/4/1:5' � State.co.us E�cutise Branch Mail.-RE:Lancaster � . � �o�is-v�=�� rvemng uiscussion.par � � 112K �� 2013A3-12 LAN PSD Netting.xisx .� � 257K � 2013-03-12 LAN Facility Emissions.pdf � � � . � 64K ' oo Ie.coMmail/?ui=2&ik=7faca29a38&tiev� t&cat=Lancaster&search=cat&th=13d6067ab1b4e418 - � 3/3 htt s://mail. p 9 9 P ._ ._... ...... . . . ___ _. . . ... � ; �f � � !� � � ��f�i� �`. � i' � � i � The Lancaster Plant PSD Net Emission Increase Calculation December 19, 2012 (updated March I2,20I3) I. Introduction As pertaining to Regulation 3, Part D, Section II.A.2, a project is a major modification for a regulated NSR polluta�rt if it causes a significant emission increase(Step 1) and a significant net emissions increase (Step 2). This document explains the logic and deTerminations utilized to develop the Lancaster Plant (LancasYer) project PSD applicability analysis Kerr McGee Gathering LLC (KMG) updated this analysis to incorporate the NSR Reform provisions(2002 rules)which were approved into Regulation 3, Part D. Process Description The Fort Lupton Gas Plant (Fort Lupton) and Platte Valley Gas Plant (Platte Valley) are currently operating at maximum capacity and no increased throughput or processing capabilities are expected at either plant with the start-up of Lancaster. Fort Lupton is currently bottlenecked by the refrigeration plant which is also operating at maximum capacity. Any gas sent to the refrigeration plant is dehydrated in the north and south dehydration units and there is no improvement scheduled for Fort Lupton's existing refrigeration plant. Platte Valley is currently bottlenecked by the residue compression used to send gas to the discharge pipeline. Tl�ere are no plans to increase compression capacity at the plant. A new 24"inlet pipeline will be constructed concurrent with the commeucemenY of the 1 s`train of Lancaster to detiver gas to the proposed plant along with gas off the existing high pressure(HP)pipeline. Fort Lupton units 36 and 37 are scheduled to be shutdown witl�the start-up of Lancaster Train 1 and Unit 35 will be shutdown with the start-up of Train 2. Units 36 and 37 boost inlet gas from 100 psi to about 200 psi and disoharge directly into the intermediate pressure (IP) pipeline. As development of the basin continues and new formations are produced,the fiutction of these units is no longer required. Unit 31 and 35 currently boosts inlet gas from about 100 psi to 1100 psi and discharges into the HP pipeline. Five additional inlet 3,750-hp electric motors driving reciprocating compressor will be installed as part of this project to feed the HP pipeline. This additional compression eliminates the need for Units 37 and 35. II. Step 1 —Significant Emission Increase Calculation � KMG utilized the acYual to potential test as defined in Regiilation 3, Part D, Section II.B.2 to determine if � a significant emission increase of a regulated NSR pollutant is projected to occur. A]1 new equipment proposed for Lancaster was included in the calculation as shown in Table I below. As pertaining to Regulation 3, Part D, Section ILA.24.e, fugitive emissions were not included in Step 1 since Lancaster is not a source category listed in Section II.A.24.a.(i). Page 1 _ __ __ _ _ _ ._. < ��Table2:LaticasterPlant:'iSte�I+Ste 2)iNetEmissionlucreaeeCalculation�' � Uni�10 AIR510 Pe�mit# ContemporaneousChange Oaie �NOx CO COze PM2S � ' Cantemporaneous emissions inneases and dec�eases Gom 712009 to 1l2015[Step 2J �� ENG103� 123l005�1�26 �7WE0798 AddedUnie103:IncreaseFuelUseonl0l9l11 2l18l2009 30.4 7.6 18519.4 1.4 � South�ehy 723100577027 07WE0799 Scarredup311212009 3lt212009 3.13 6.3 . 2728.6 �.03 � ENGID2` 723100571G24 03WE1152 � EngineShucdown 4130t2009 -13.9 -9.9 -5788.4 -0.5 ENG33' 1231005710�4 11WE430-1 �e-raoedfwm2166-hpro2�46-hp 6730R009 � ENG36' 123100571005 71WE730-2 Oe-�atedfrom2166-hpro2046-hp 613 012 0 0 9 � ENG3i° 12370057100fi 11WEP30-3 �e-ra�edtrom2166-hpro2046-hp 6l3012009 ENG35' 123100577007 11WE732 �e-ratedFmm1859-hpro456-hp 6i3012009 FUG° 123l00571016 00WE0563 Emissonsdecreasedue�oromponen�count glqf201� GEN2� 123f0057f029 tOWE1567 Stanedup9126111 9128l2011 0.6 0.0 � N�R 0.03� EU104� 123I�0571028 70WE'1077 � Starredupl0lV11 t0142011 320 8.0 20575D 1.4 � NorohDehy3 l23l0057t027 01WE0964 Oecreasecombus�iontemperaiuie �p�pVzp�� . PLVGEN' 123l0057 APENOnIy � AddedPLllPLCGenset 1l30l2012 �0.0 12 � NIA �� 00 H-STT 123l0057 Exempc Added5MMBcuIh�Condereace5cabilizee 111572012 1.6 42 3660.5 0.23 5009' 12310057i043 12WE1277 PlaaellalleyAmineUnitThe�malOxidirer 111812012 6.5 5.5 7076.4 0.50 H-S13� �2310057 Exempl Add5MMBmlhrCondensate5tabllizer T6� 1.6 42 3660.5 0.23 H-5T4' 12310057 Exempt Add5MMBculhrCondensaee5oab'ilirer TBo 1.6 �4.2 3660.5 023 5021' 12 310 0 5 41a53 02WE0927 IncreasePla«eVdleyGasooFiaie TB� 7.E 15.P 5017.1 0.0 � ENG3i' 123100571013 974lE0160 � RemoveengineuponLain2nao-up � ��VzO'IS 45.7 -42.3 -3345.8� -OS � EMG35` 12370057I007 11WE132 RemoveengineuponLain2starc-up '11712015 -519 -12.6 -51�6.� -2.1 � ENG36` 1231�057100517WE730-2 RemoveengineuponTrainlscan-up 1792014 -67.3 -742 -6231.8 -2.5 ENG3P` '12310057lOOfi 11WEP30-3 RemweengineuponTrainlstan-up kV2p14 -61.5 -138 3981.9 -2 P�oposed:�Modifica�ion PYofecrEmissions[Step D � � ' � E-20�5 NA 12WE1492 Mole5ieveRegeneracionGasHeareeo�ithUlttaLowNOxBumers 7�7p014 �52 5.2 152523 1.0 E-2016 NA 12WE1992 P1oleSieveReg=nerationGasHeaterwiohWrtaLowN�xB�mer: 1l112�15 52 52 15252.3 1.0 H-6051 NA 12WE1q92 Nea<MediumHeace�wi�hLowNOxBuiners 11112014 '13.5 13.5 394212 t.7 . H-6052 NA - 12WEt4ffi HeatMediomHea�erwithLowNOxBwners 111I2014 13.5 13.5 394272 t.7 H-6053 NA 72WEt4ffi HeatMediumHeatermithLowNOxBwners 1l42015 13.5 t3.5 394212 1.7 � � H-6054 NA 12WE7492 HeaeMediumHeaeermiehLowNOxBumers 71112075 13.5 73.5 394212 1.7 � A-1 NA 12WE'14ffi 750MM^aCf�AmineTrearedConaolledieiihATO-1� 11112014 7.9 6.6 9412Y.3 0.6 A-2 NA 12WE7492 t5�MM5CF�AmIneTreaierlConnolledmithATO-2). Vil2014 7.9 6.6 9412t3 O6 . A-3 NA 12WE1492 15�MMSCFORmineTrearer(ContmlledwithATO-3) 111l2015 7.9 6.6 94t213 0.6 � A-9 NN 12WE14ffi 'ISOMMSCFOAmineTreaiei�ControOedwi�hRTO-41 1!1l2075 7.9 6.6 9412t.3 OB� F2 fJF 72WE74ffi � F-2LancasreiPlantProcessFlarel 17�12014 �7.3 14.6 622Q0 0.3 F-3 NA 12WE1492 F-3LancasterPlaniProcessFlaie2 1f112015 7.3 19.6� 6220.0 0.3 � GEPl3 NA 12WE149[ Caierpillar839-hpOieselEmergencyGenerato� 11112014 2.6 02 415 � 0.1 5cept+Siep2 -3t0 84.4 675.730 7.8 � � PS�SignificanceThreshoid 40_0 100.0 75.000 t0 � � Step 2.Ooes projec[cayse a significam�t e n increase? No No Yes No The new emission units proposed for Lancaster will cause a significant emission increase of NOX, CO, PMZ.s and COZe emissions. Therefore, as required by Regulation 3, Part D, Section I.A2, KMG wil] deYermine if the proposed project will result in a significant net emission inerease for NOX, CO, PMz,s and COze in Step 2 be(ow. III.Step 2—Significant Net Emission Increase Calculation To determine if Lancaster will cause a significant net emission increase, one must sum any increase in actual emissions from the proposed project and any other increases and decreases contemparaneous with the proposed project as pertaining to Regulation 3, Part D, Section II.A.26. These increases and decreases are known as Step 2 in the PSD applicability determination. Contemporaneous Period Page 2 The contemporaueous period for this project was defined as required by Regulation 3, Part D, Section II.A.26.b. The Lancaster Plant project consists of two trains with a phased construction period. Train 1 is expected to start operation on January 1, 2014 and Train 2 is expected to start operation on Januazy 1, 2015. Therefore,KMG defined the contemporaneous period as January 1, 2009 to January 1, 2015. Contemporaneous Emissions As shown in the net emission increase calculation of Table 2 below, there were nineteen (19) increases and decreases that occurred in the defined contemporaneous period. Five (5) of the identified emissions decreases listed below were deemed not credible as defined in Regulafion 3, Part D, Section ILA26.£(ii) due to the fact that the old level of actual emissions did not exceed the new emission level (PTE). An updated TiUe V permit was never issued for the modification requested below. The facility is operating under the peTmit shield of the July 3, 2002 95OPWE013 Title V permit 1. ENG 33, 123/0057/004, 6/30/2009 submitted,Title V modification to decrease horsepower. 2. ENG 36, 123/0057/005, 6/30/2009 submitted Title V modification to decrease horsepower. 3. ENG 37, 123/0057/006, 6/30/2009 submitted Title V modification to decrease horsepower. 4. ENG 35, 123/0057/007, 6/30/2009 submitted Title V modification to decrease horsepower. 5. North Dehy, 123/0057/021, 12/21/20ll construction permit issued to decrease thermal oxidizer combustion temperature. Nine (9) of the identified emissions increases listed below, calculated the projected actual emissions utilizing the source's potential To emit (PTE) emissions as required by Regulation 3, Part D, Section II.A36.a. These new (9) new sources started up or are expected to start-up during the contemporaneous period. 1. ENG 103, 123/0057/026 — Began operation on 2/15/2009. New permit issued on 10/4/2011 to increase fuel use. 2. South Dehy, 123/0057/027—Began operation on 3/12/2009. 3. GEN2, 123/0057/029—Began operation on 9/28/2011. 4. ENG ]04, 123/0057/028—Began operation on 10/1/201 L 5. � PLVGEN, 123/0057—APEN submitted on ]/30/2012. 6. H-ST2, 123/0057—APEN exempt heater(Regulation 3, Part A, Section Il.D.Lk) began operation on I I/5/2012. � 7. S009,123/0057/056—Amine unit therma] oxidizer began operation on ll/8/2012. 8. H-ST3, 123/0057—APEN exeinpt heater(Regulation 3, Part A, Section II.D.l.k) not yet built. 9. H-ST4, 123/0057—APEN exempt heater(Regulation 3, Part A, Section II.D.Lk) not yet built One (1) of the identified emissions decrease listed below, calculated baseline actual emissions as defined in Regulation 3, Part D, Section II.A.4.b by selecting the highest annual average based on a consecutive 24 tnontl�period, except Section ILA.4.b.(iv)does not apply for contemporaneous increases and decreases as stated in Regulation 3, Part D, Section II.A.26.a.(ii). The baseline actual emissions were calculated fox the removal of Unit 102 based on 1/1/2005 to 12/31/2006 actua] emissions. 1. ENG 102, 123/0057/024—Engine shutdown on 4/30/2009. Page 3 __ _ _ __ One (1) of the identified emissions decrease listed below, was not included in the contemporaneous emissions because fugitive emissions as defined in Regulation 3, Part D, Section ILA.24.e, shall not be included in determining for any of the purpose of Part D, whether it is a major source. Lancaster is a gas processing facility and is therefore, not one of the named categories in Regulation 3, Part D, Section II.A.24.a.(i)or a source category as of 8/7/1980 regulated under Section 111 or ll 2 of the Federal Act. I 1. FUG, 123/0057/018—Decreased fu itive emissions in Permit 00WE0583 from actual com onent g P count. One (1) of the identified emissions increase listed below; calculated projected actual emissions utilizing the source's potential to emit (PTE) emissions as defined in Regulatimi 3, Part D, Section II.A.36.a.. The baseline actual emissions were calculated as defined by Regulation 3; Part D, Section II.A.4.b by selecting the highest aruival average based on a consecutive 24 month period, except Section II.A.4.b.(iv) does not apply for contemporaneous increases and decreases as stated in Regulation 3, Part D; Section II.A.26.a.(ii). The baseline actual emissions were calculated based on tl�e sources 12/1/2010 to 11/31/2012 actual emissions. The net emission increase = projected actual emissions (PTE) - baseline actual emissions. 1. 5021, 123/0057/053 — On 7/20/2012 requested 10 increase gas to flare volumes and modify emissions. Permit has not been issued. Four (4) of the idenYified emissions decreases listed below calculated baseline actual emissions (BAE) as defined by Regulation 3, Part D, Section II.A.4.b by selecting the highest annual average based on a consecutive 24 month period. One consecutive 24 month period was selected for each regulated NSR pollutant. The period selected for NOX was 4/1/2008 to 3/31/2010 and the period selected for CO, PMZ 5 and CO2� was 1/1/2003 to 12/31/2004. The CO BAE for ENG 35, ENG 36 and ENG37 were adjusted as per Regulation 3, PaM D, Section II.A.4.b.(iii) due to controls installed in 2007 as required by the May 17, 2007 KMG Consent Decree. 1. ENG 31, 123/0057/013 — Engine will be removed upon start-up of Lancaster Train 2, estimated � as 1/1/2015. � 2. ENG 35, 123/0057/007—Engine will be removed upon start-up of Lancaster Train2 estimated as � 1/1/2075. � 3. ENG 36, 123/0057/005 —Engitte will be removed upon start-up of Lancaster Train 1 estimated as 1/1/2014. 4. ENG 37, 123/0057/006—Engine will be removed upon start-up of Lancaster Train 1 estimated as 1/1/2014. One (1) contemporaneous emissions decrease not included in the analysis was the control of the Platte Valley amine unit witl� a thermal oxidizer (123/0057/043). The emissions off the still vent of the amine unit were questioned during a 12/23/2010 CDPHE inspection. The unit was installed in 1997 and was never found to be out of compliance during the fourteen (14) years it had operated. The previous owner was asked to perform an emissions test which was completed on 4/21/2011 after the ownership transfer to KMG. Results were submitted to KMG on 7/18/20ll and a permit application to conTrol the amine unit � was submitted on 2/5/2012 after engineering design was compieted. The amine unit was controlled on Page 4 , 11/8/2012 and to date, not final construction permit has been issued for the source. Therefore, KMG did not include this emissions decrease as a contemporaneous source. Net Emission Increase CaZculation The net emission increase was calculated as required by Regulation 3, Part D, Section ILA.26 by summing the increase in actual emissions of NOX, CO, PMz,5 and CO2e from the proposed Lancaster project {Step 1) and the emissions increases and decreases within the defined contemporaneous period (Step 2). As shown in Table 2 below, the proposed Lancaster project wil] not cause a significant net emission increase in NOX, PMZ 5 and CO emissions but will cause a significant net emission increase in CO2e emissions: Therefore, since the proposed project results in a major modification for CO2e, a BACT analysis for Greenhouse gases is required. Page 5 _ ___ _ _ Ta61r2:LoncosteiPlnnt:(Ste T+S[e 2)]etEmissionlnCreaseCalcdation�. Unitl� AIRSIO Permit� ContempoeaneousChange �ate NOa CO CO�e � PM2.5 � � Contemporaneous em�ssions increases and decreases f�om.712009 to 172075[Step 2) � ENG1D3� 123�0057l02fi 07WE0798 Add?dlJnic103;IncreaseFuelUseon1014711 2178120�9� 30.4 7.6 �8519.4 �A � SouthOehy� 1231�057l027 07WE0799 Startedup371212009 - 3l12120�9 3.13 6.3� 2728.6 � 0.�3 ENGl02� 723I00577024� 03WE7152 EngineShutdown 413072009 -13.9 -9.9 -5786.4 -0.5 ENG33° 723l0057l004 17WE730-t �e-raredfmm2t66-hpto2046-hp 6l30l2�09 ENG363 � 123l00577005 11WE730-2 � �e-rat?dfrom2166-hpto2046-hp 673012009 ENG373 123l��577�06 11WE730-3 De-ratedfrom2166-hpro2046-hp 613012009 � ENG353 12310�571007 11WE132 �e-raredfrom1859-hpro1756-hp 613012009 FUG° 12310057f018 00WE0583 Emissionsdecreaseduerocomponenmount 8l4120ID � � GEP12� i23700571029 10WE1587 � Starredup9l28111 972B120ri �D.6 0.0� N7A 0.03 EU104� 12310057f028 104JE1071 StarreduplDl1711 101772011 32.a 8.0 20575.0 1.4 NorthOehy' 7 2 310 0 5 710 21 O1WE�764 Oecreasecom6ustionremperature 1272V2p11 • :' , PLVGEN� 123f0057 APENOnIy � AddedPLVPLCGenset� 1130i2012 0.0 12� N!A 0.0 H-ST2� 723l0057 Enempt Added5MMBmIhrCondensate5tabilizer 1115f2072 7.8 � 42 3660.5 023 5009' 123l00577043 121JE1277 PlatreValleyAmineLlnitTheram10xidire� 111612012 6.5 55� 7076.4 0.50 H-ST3� 12310057 Enempt Add5MMBtulhrCondensareS�a6ili¢ei TBO 1.8 42 3660.5 023 H-ST4� 12310�57 Exempt Add5MMBtulhrC�ndensateStabilixer ' TBO . 7.H 42 3660.5 023 S021s� 12 310 0 5 71�53 02WE0927 IncreasePlaaeValleyGastoFlare 7g0 7.8 15.7 5017.1 0.0 ENG31" 123100571013 97WE018� � RemoveengineuponLain2start-up 1142015 -15.7 -42.3 -3345.8 -0.5 ENG35� � 123f0057l007 11WE132 RemoveengineuponTrain2start-up � 1!1l2015 -51.4 -12.6 -5106.0 -2.1 ENG36° 123100571005 11WE73�-2 RemoueengineuponTrainlstart-up 1142014 -67.3 -142 -6237.8 -2.5 � ENG37° 123100571006 11M�E730-3 RemoveengineuponTraintstart-up 1!1l2014 -81.5 -13.6 -5987.9 -2 Proposed Modification Prajec[Emissions(S1ep 1) ' � � � � � � E-2015 NA 12WE1492 MoleSieveRegeneraiionGasHeaterwithUltraLowN�xBurners y+y+2014 52 52 15252.3 1.0 E-2016 NA 12b1E1492 Mole5ieveRegenerationGasHearerwithNcraLowNOeBumers ��p015 52 52 15252.3 . 1.0 I H-6051 NA 12WE14ffi HeatMediumHearerwithLowN�xBurners 111l2014 13.5 13.5 394272 1.7 � � H-6052 NA 12WE1492 HeacMediumHeaterwithLosaN�aBurners 1lV2014 13.5 13.5 394212 1.7 H-6053 NA 72WE14ffi Heatf�7ediumHeare�withLowNOxBumers 11112015 13.5 13.5 3942t2 � 1.7 H-6054 NA i2WE1492 HeatMediumHearerwithLowPlONBurners 111l2015 13.5 13.5 394212 7.7 � � A-1 NA 12WE1492 � 150MMSCFOAmineTreater[Controlledwi�hATO-1j 111l2014 7.9 6.6 94121.3 0.6 � A-2 NA 12WE1492 150MMSCF�AmineTrearer(ConcrolledwithATO-2) 1l112014 7.9 6.6 94121.3 0.6 . A-3 NA 12WE1492 15�MMSCF�AmineTrearer(ControlledwithATO-37 1f1l2015 7.9 6.6 94121.3 0.6 � A-4 � NA 12WE14ffi � i50MM5CF0AmineTreater(ConnolledwithATO-47 17172015 7.9 6.6 94121.3 0.6 F2 NA 12WE1492 F2LancasrerPlancProcessFlarel 11V2�14 7.3 14.6 - 6220.0 0.3 F-3 NA 72WE7492 F-3Lancaste�PlantProcessFlare2 17172015 7.3 14.6 6220A 0.3 ' � GEN3 � PIA .12WE1492 Carerpillar839-hpDieselEmergencyGenerarof 11112074 2.6 0.2 171.5 0.1 � Soepl+Saep2 -31.0 84.4 615,T30 7.8 PS�Significance TFreshold 40.0 1U0.0 75.000 70 S[ep 2.�oes projec[cayse a significan[p¢5 emission inctease? No No Yes Nn �Emission increase ieflecting potential�o emi�emissions as defined in Regulation 3,Parc D,Sec�ion II.A36.a . . � �Emissionsincreasecalcularedusinghighestannualaveragebasedon24consemtivemonthsaspeell.A.4.6,excep[II.A.5.6.(ivJdoesnotspplyasper I . II.A26.a.(ii1.IJanuary 2005 m�ecember 2006] 3Emissioredecreaseisnotcrediblesincetheoldleeelofacwalemissionsdoesnoteaceedlhenemleoelofemissionsaspe�Regulation3,PartDII.R26.E[ii). � � � °Fugitiveemissionsnotinduded;gasplanlisnotanamedsourcesasperReg3,PatD,Sectionll.A24 � � . sNetemissioninneaseqpmlecredactualemissionsasdefinedinRegulation3,Part�,Section�I.A.36.a[PTEI-6aselineactualemissionsasdefinedin . Regulation3,Part0,Sectionll.A.4.b,e�cepol.A.4.b.(ieJdoesnotapplyaspeell.A26.a.Iii). Used121V2010ro1113012012rocalcula[ebaselineaclualemissions. °-BaselineactualemissionscalculaeedasdefinedinRegulation3,PartD,5eceionll.A.4.b. Consecvtiae24-monthperiodde(inedasN�a=412008-312070;CO3 PMzs and CO2e=112003 to 1272004;BAE adlusted for period p�ior to 2�07 ro reduce CO 6y 58%on ENG35,36 and 37 ro teflect controls installed per KMG consentdecree. . � Page 6 Q The Lancaster Plant PSD Net Emission Increase Calculation � December 19,2012 (updated January I6,20I3) � I. Introduction As pertaining to Regulation 3, Part D, Section II.A.2, a project is a major modification for a regu(ated NSR pollutant if it causes a significant emission increase (Step 1) and a significant net emissions inarease (Step 2). This document explains the logic and determinations utilized to develop the Lancaster Plant (Lancaster) project PSD applicability analysis. Kerr McGee Gathering LLC (KMG)updated this analysis to incorporate the NSR Reform provisions (2002 rules) which were approved into Regulation 3, Part D. Process Description The Fort Lupton Gas Plant (Fort Lupton) and Platte Valley Gas Plant (P1atte Valley) are corrently operating at maximum capacity and no increased throughput or processing capabilities are expected at either plant with the start-up of Lancaster. Fort Lupton is currently bottlenecked by the refrigeration plant which is also operating at masimum capacity. Any gas sent to the refrigeration plant is dehydrated in the north and south dehydration units and there is no improvement scheduled for Fort Lupton's existing refrigeration plant. Platte Valley is currently bottlenecked by the residue compression used to send gas to the discharge pipeline. There are no plans to increase compression capacity at the p]ant. A new 24" inlet pipeline will be constructed concurrent with the commencement of the I s`train of Lancaster to deliver gas to the proposed plant along with gas off the existing high pressure(HP)pipeline. Fort Lupton units 36 and 37 are scheduled to be shutdown with the start-up of Lancaster Train 1 and Unit 35 will be shutdown with the start-up of Train 2. Units 36 and 37 boost inlet gas from 100 psi to about 200 psi and discharge directly into the intermediate pressure (IP) pipeline. As development of the basin continues and new fonnations are produced, the function of these units is no longer required. Unit 35 currently boosts inlet gas from about 100 psi to 1100 psi and dischaa•ges into the HP pipeline. Five additional inlet 3,750-hp electric motors driving reciprocating compressor will be installed as part of this project to feed the HP pipeline. This additional compression eliminates Yhe need for Unit 35. II. Step 1 —Significant Emission Increase Calcutation � KMG utilized the actual to potentia] test as defined in Regutation 3, Part D, Section II.B.2 to determine if a significant emission increase of a regulated NSR pollutant is projected to occur. All new eGuipment proposed for Lancaster was included in the calculation as shown in Table 1 below. As pertaining to Regulation 3, Part D, Section ILA.24.e, fugitive emissions were not included in Step I since Lancaster is ' not a source category listed in Section II.A24.a.(i). Page I __ _ __ _ _ P I TabCe 1:rLancasterPlant Step 1 PSaAppficabitity;E?eterminatiao � LJnit I� � � NOH CO VOC COZe SCIz � PM 2.5 , Lancaster Project �� .G4700 Solar C4�612,000-hp Electric Orive Moror,Residue � - - - - _ � _ L'-4200 Solar C406 72,000-hp Electric�rive Motor,Residue - - - - _ _ . C-4300 � Solar C40512,000-hp Electric�rive Moror,Residue � - - - - _ _ C-4400 Solar.C40612,00�-hp Electric Oriye Motor,Residue -� - - - _ _ G5110 3,000-hp Moror,ReFrig - - - - _ _ GSZ1D 3,OD0-hp Motor,ReFrig �- - - - _ _ C-5310 3,D00-hp Motor,ReFrig - - - - _ _ G5410 3,D00-hF Motor,Refrig . - - - _ _ _ . G551� 3,000-hp Mamr,Refrig . - - - _ _ _ C-561� 3,000-hp Motor,Refrig � - - - _ _ _ ENG105 3,750-hpMotor,InletCompression �- - - _ _ _ ENG 106 3,750-hp Moror,Inlet Compression - � � - - - - _ ENG 107 3,75D-hp Mota1,Inlet Compression - - - - - _ ENG 108. 3,750-hp Maror,Inlet Compression - - - - _ _ ENG 709 � � �3,750-hp Moror,Inlet Compression - - - - _ _ E-2015 Mole Sieve Regeneration Gas Heater with Ultra Low NDa Burners� 52 5.2 2.5 15,252 0.1 1.0 E-2016 Mole Sieve Regeneration Gas Hearer with Uitra Low NOx Burners 52 5.2 2.5 15,252 � 0.1 1.0 H-6051 . Heat Medium Heater with Low NO;e Burners � 13.5 13.5 1.8 35,421 0.2 1.7 � H-6052 Heat Medium Hearer with Low NOk Bumers 13.5 13.5 1.8 39,421 0.2 1.7 . H-6053� �Heat Medium Hearer with Low NOa Bumers 13.5 13.5 1.8 39,421 02 1.7 H-6054 HeatMediumHeaterwithLowhlOkBurners 13.5 13.5 1.8 39,421 0.2 1,7 A-1 � 150 MMSCFO AminE Treater(Controlled with ATL7-1j 7.9 .6.6 3.6 94,121 1.1 0.6 A-2 150 MMSCF�Amine Treater IControlled with ATO-2) 7.9 6.6 3.6 94,121 1.1 0.6 A-3 � 150 MMSCF�Amin?Treater IControlled with ATO-3] 7,9 6.6 3.6 94,121 7.1 O.E A-4 150 MPflSCFO Amine Treater[Contmlled with RTO-41 7.9 6.6 3.6 94,121 1.1 0.6 F-2 - F-2 Lancasrer Plant Process Flare 1 7.3 14.6 1.6 6,22p O:Q3 - � F-3 F-3 Lancaster PlantProcess Flare 2 �,3 14.6 1.6 6,220� �0.03 - � .GEN3 Caterpillar833-hpLlieselEmergencyGeneraror Z_g p,Z p.p R2 1.5 0.1 � Lancaster Project Emission Inarease 113.1 120.2 29_9� 577,286 6.7 17:1 PSD SigniFicance Threshold 40_0 100.0 44.0 75.000 40 10.0 Step 2.Net Emission Inorease Oetermination Req�ired? Yes � Yes Na Yes No Yes The new emission units proposed for Lancaster will cause a significant emission increase of NOX, CO, PM2.5 and CO2e emissions. Therefore, as required by Regulation 3, Part D, Section I.A.2, KMG will determine if the proposed project will result in a significant net emissiou increase for NOX, CO, PMZ.5 and COZe in Step 2 below. IIL Step 2—Significant Net Emission Increase Calculation To determine if Lancaster will cause a significant net emission increase, one must sum any increase in actua] emissions from the proposed project vid any other increases and decreases contemporaneous with the proposed project as pertaining to Regulation 3, Part D, Section II.A.26. These increases and decreases are known as Step 2 in the PSD applicability detennination. Page 2 Contemporaneous Period The contemporaneous period for this project was defined as required by Regulation 3, Part D, Section II.A.26.b. The Lancaster Plant project consists of two trains with a phased construction period. Train 1 is expected to start operation on January l, 2014 v�d Train 2 is expected to start operation on January ], 2015. Therefore,KMG defined the contemporaneous period as January 1, 2009 to January 1, 2015. Contemporaneous Emissions As show�i in the net emission increase calculation of Table 2 below, there were nineteen Q9) increases and decreases that occurred in the defined contemporaneous period. Five (5) of the identified emissions decreases listed below were deemed not credible as defined in Regulation 3, Part D, Section II.A.26.£(ii) due to the fact that the old level of actual emissions did not exceed the new emission level (PTE). An updated Title V permit was never issued for the modification requested below. The facility is operating under the permit shield of the July 3,2002 95OPWE013 TiUe V permit. L ENG 33, 123/0057/004, 6/30/2009 submitted Title V modification to decrease horsepower. . 2. ENG 36, 123/0057/005, 6/30/2009 submitted Title V modification to decrease horsepower. 3. ENG 37, 123/0057/006, 6/30/2009 submitted Title V modification to decrease horsepower. 4. ENG 35, 123/0057/007, 6/30/2009 submitted Title V modification to decrease horsepower. 5. North Dehy, 123/0057/021, 12/21/2011 construction permit issued to decrease thermal ox'rdizer combustion temperature. Eight (8) of the identified emissions increases lisTed below, calculated the projected actual emissions utilizing the source's potenYia] to emit (PTE) emissions as required by RegulaTion 3, Part D, Section II.A36.a. These eight(8) new sources started up during the contemporaneous period. 1. ENG 103, 123/0057/026 — Began operation on 2/15/2009. New permit issued on 10/4/20ll to increase fue] use. 2. South Dehy, 123/0057/027—Began operation on 3/12/2009. 3. GEN2, 123/0057/029—Began operation on 9/28/2011. 4. ENG 1D4, 123/0057/028 —Began operation on 10/1/2011. 5. PLVGEN, 123/0057—APEN submitted on 1/30/2012. 6. H-ST2, }23/0057—APEN exempt heater(Regulation 3, Part A, Section Il.D.l.k)began operation on 11/5/2012. 7. H-ST3, 123/0057—APEN exempt heater(Regulation 3, Part A, Section II.D.I.k)not yet built. 8. H-ST4, 123/0057—APEN exempt heater(Regulation 3, Part A, Section II.D.I.k)not yet built. One Q) of the identified emissions decrease listed below, calculated baseline actual emissions as defined in Regulation 3, Part D, Section II.A.4.b by selecting the highest annual average based on a consecutive 24 month period, except Section ILA.4.b.(iv)does not apply for contemporaneous increases and decreases as stated in Regulation 3, Part D, Section II.A.26.a.(ii). The baseline actual emissions were calculated for the removal of Unit 102 based on 1/1/2005 to 12/31/2006 actual emissions. 1. ENG 102, 123/0057/024—Engine shutdown on 4/30/2009. Page 3 _ _ ____ . _ __ One (1) of the identified emissions decrease listed below, was not included in the contemporaneous emissions because fugitive emissions as defined in Regulation 3, Part D, Section II.A.24.e, shall not be included in determining for any of the purpose of Part D, whether it is a major source: Lancaster is a gas processing facility and is therefore, not one of the named categories in Regulation 3, Part D, Section II.A.24.a.(i)or a source category as of 8/7/1980 regulated under Section 111 or I 12 of the Federal Act. 1. FUG, 123/0057/018—Decreased fugitive emissions in Permit 00WE0583 from actua] component , count. One (1) of the identified emissions increase listed below, calculated projected actual emissions utilizing the source's potential to emit (PTE) emissions as defined in Regulation 3, Part D, Section ILA36.a.: The baseline actual emissions were calculated as defined by Regulation 3, Part D, Section II.A.4.b by selecting the highest annual average based on a consecutive 24 month period, except Section ILA.4.b.(iv) does not apply for contemporaneous increases and decreases as stated in Regulation 3, Part D, Section II.A.26.a.(ii). The baseline actual emissions were calculated based on the sources 12/I/2010 to 11/31/2012 actual emissions. The net emiss�on increase = projected actual emissions (PTE) - baseline actua] emissions. 1. S021; 123/0057/053 — On 7/20/2012 requested to increase gas to flare volumes and modify emissions. Permit has not been issued. Three (3) of the identified emissions decreases ]isted below calculated baseline actual emissions as defined by Regulation 3, Part D, Section II.A.4.b by selecting the highest annual average based on a consecutive 24 month period. One consecutive 24 month period was selected for each regulated NSR pollutant. The period selected for NOx was 4/1/2008 to 3/31/2010 and the period selected for CO, PM2,5 and CO2e was I/]/2003 to 12/31/2004. � 1. ENG 35, 123/0057/007—Engine will be removed upon start-up of Lancaster Train 2 estimated as l/1/2015. 2. ENG 36, 123/0057/005 —Engine will be removed upon start-up of Lancaster Train I estimated as 1/1/2014. 3. ENG 37, 123/0057/006—Engine will be removed upon start-up of Lancaster Train I estimated as 1/1/2014. One (1) contemporaneous emissions decrease not included in the analysis was the control of the Platte Valley amine unit with a thermal oxidizer (123/0057/043). The emissions off the still vent of the amine unit were quesTioned during a 12/23/2010 CDPHE inspection. The unit was installed in 1997 and was never found to be out of compliance during the fourteen (14) years it had operated. The previous owner was asked to perform an emissions test which was completed on 4/21/2011 after the ownership transfer to KMG. Results were submitted to KMG on 7/18/2011 and a permit application to control the amine unit was submitted on 2/5/2012 after engineering design was completed. The amine unit was controlled on 11/8/2012 and to date, not final construction permit has been issued for the source. Therefore, KMG did not include this emissions decrease as a contemporaneous source. Page 4 Net Emission Increase Calculation Tl�e net emission increase was calculated as required by Regulation 3, Part D, Section II.A.26 by summing the increase in actual emissions of NOx> CO, PMZ,S and CO2e from the proposed Lancaster project (Step 1) and the emissions increases and decreases within the defined contemporaneous period (Step 2). As shown in Table 2 below, the proposed Lancaster project will not cause a significant net emission increase in NOX, PMz.s and CO emissions but will cause a significant net emission increase in CO2e emissions. Therefore, since the proposed project results in a major modification for CO2e, a BACT analysis for Greenhouse gases is required. Page 5 � �TnUlc 2:Lnncastcr PInnC(S[E i�+Sle�2)Net Cmission LicrenselCnlculation �� ➢vitID AIRSID PermitN ConhmporaneousChan6e Dare NOx CD � CO�e� PiN2.5 CONefnpoennronsemisflanfintiemesunAdecrenseshoml/30091oV3015(SIep2).. � � � ENG103� 123/WSJ/026 OJN20998 AddedU�it103;IncreaseFuelUseonl0/4/Il 2I182009 304 ]6 185194 IA � SouthDehy 123/Oa59/02> 0]WE0�99 Startedup3/122009 3/12I20b9 3.13 63 . 2]28fi 0.03 ENG102° 123/005]/@4 03WE1152 EvgineShu[doxm 4/30/2009 -13.9 -9.9 -5>88.4 -OS ENG 33' 123/0059/004 I I WE]30-1 De-rated fmm 2I66-hp ta 2046-hp 6/30/2009 . � ENG 36° 123/0059/005 I I WE]30-2 De-reted fmm 2166-h0�a�046-hp b/302009 ENG3]3 123/0059I006 11V✓E93D-3 De-ratedfiom2166-hpto204Ghp b/302009 - ENG 353 123/005]/009 11 WE132 De-mted fmm 1859-hp m Ii56-hp - 6/30/2009 FOG° 123/OOSJ/O18 OOWE0583 Emissio�demeased�etacampanen[count� 8/4I201� GEN2� 123/005>/029 IOWEI589 S�artedup9/20/11 928/2011 �Ofi OD � NIA 003 EU100� 123/009/028 IOWEIOA S�artedupl0/1/11 ID/II201� 3?0 8.0 205]5.0 14 NorthDehy' 123/0059/09 OIWEO]64 OecreascwmbusfontempereWre� 12I21I201I PLVGEN� 123/OOS9 APENONy AddedPLVPLCGauset If30/2012 � 0.0 1.2 � N/A 00 �. H-ST2' 123I005"1 Exempt Added5MMBN/hrCondensareStabilizer il/5/2012 18 0? 3fi609 023 � � H-ST3� 123/005] Exempt Add5lvQv��WhrCondenseteStabilizer THD 1.6 � 42 36605 023 H-ST4� 123I005� � Exempt Add5MIv�tWhrCondense[eStabilizer TBD 1.8 42 3fi605 023 � S021° 123/OOS]/053 02WE0929 [ncreasePla¢eValleyCrzsroFlare lBD >.8 IS> SOIZI� 0.0 2NOJ5° 123/0059/009 IIWE132 RemavaengineuponToain2stevbup I/1I20I5 -514 -IOJ -51060 -2.1 ENG36° 123/005>/005 IIWE]]Od ftemoveenpineuponTrai�istan-up 1/II2014 -6ZJ J3] -623I8 2.i � � ENG39° 123/005]/006 IIV✓E]30-3 RemoveenbiveuponTrainiscan-up 1/1I2014 -81.5 -324 -5981.9 2 PrnpoeeJ Mmlifioatlon 1'rnjecl Gniiesian�.(Step I) � � � � � E-2015� NA 12WEIA92 MoleSieveRe6enerationGasHealerwi�hlllVaLowNOxBumers 1/I/2014 ' �52 52� �S252] 10 E-2016 NA 12WE1492 MoleSieveRe6enerationGasHea�erwi1hO1[reLowNOxBumers 1/1/2015 52 51 152523 � 10 H-605I NA 12WE1492 HeatMediumHPaterwithLowNOxBumers 1/12014 135 U.5 J94212 I.'1 H-6052 NA 12WE1492 HratMediumHearerwitM1l,owNOx6umers I/V2014 135 115 3942L2 I.% H-6053 NA 12WE1492 HeatMediumHcaterwithLowNOxBumers 1/V2015 13.5 13.5 394212 I] H-6054 NA 12V✓E1492 HeatMediumHeaterwitM16owNOxBumers 1/I/2G15 13.5 13.5 394212 I] A-1 NA 12WE1a92 ISON➢NSCFDAmineTreater(Convolledwi�FATO-1) 1qI2014 ].9 G.G 9412I3 Ofi A-2 NA 12WE1d92 150MMSCFDAmineireeter(CanVolledwithAT02) 1/1/2014 ?9 6,6 941213 0,6 . 4-3 NA 12WEI692 IIDMMSCFDAmineTreater(CmValledwithATO-3) 1I12015 ]9 fifi 9G@13 O6 A-4 NA 12WEi492 ISOMMSCFDAmineTrmhr(ContmlledwithATO-4J IIIY2015 J.9 6fi 941213 0.6 F-2 NA. 12WEI492 F-2LanmsterPlantPmcusFlarel 1/IY2014 ?3 14fi 6220.0 Fd NA 12WE1492 F-3WnmshrPlavtPmcusFlare2 IIIY2015 )3 19.G 62200 GEN33 NA 12WEt492 Careryillar839-FpDieselEmerSencyGe�enror 1II2014 2.6 02 1"I1.5 0.1 ' � S[ep 1+Step E� -21.8 65.5 6ll999.P 22 � PSDSignifiaanmThreshold 4�.0 ]00.0 ]SOOOA l0 � Step 2�Dors project cause a significanf ne�emission inerease? No No Yes No �Emission inerexse reFluting potenual to eait emissio�s as tlefined in Regulation 3,Patt�,Section ILA.36.e . °Emissiovsi�creaeecalcularedusin6h�6hestannualaverzyebasedon2Jwnsea[ivemon�hsesperll.A.4.b,exceptll.A.56.(ivjdoesnotapplY%tper(IA26.a(ii).(lanuary2005m Dwember 2006J � 'EmissionsdecmaseisnolerediblesincelheoldlevelofacWalemissionsdoesnotexceedehenewlevelofemissionsasperReBUlxfion3,PartDIl.A2Gf(ii). � 4 Fu6��e emissio�w nol included;gas O�flnt is roI a named soumes as per Reb 3,Part O,Section II.A20 `Net emission inerease=pmjected acwal emissions as def ved in Regulation 3,Pnrt D,Sectim II.A.l6.a(PTE)-bnseline acwal emisxians as defined in Reguletion J,Part 0,Seqion ❑.A4.b,oxcapt[I.A.4b.(iv)doesmtepplyxsOevllA26.a{if} Usetl12/1/2010m11130/20I2�ocelculatebuelineecmelemissio�_ � � °Baseli�eacmelemissionscalculeredastlefineAinRegulation3,PattD,SectionlLA.4.b. 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S`3�8��-$' � � a.^q'8vi . � . �� A I � F H 6 s�`s a..'`,".�`. � . u a�`SAu��I` Kerr-McGee Gathering LLC Lancaster Plant Cryogenic Plant Project Greenhouse Gases Best Available Control Technologies (BACT) Analyses (Updated 3/26/2013) Ta�9e �f Coaeteast� FacilityInformation......................................................................................................................l ProcessDescription......................................................................................................................1 � Emission Sources......................................................:............................................:.....................2 � . BACTAnalysis Methodology.........................................................................................................3 BACTEvaluation for Sources.................................................�........................................................5 Appendix A—Economic Analysis for CCS.......................................................................................A Appendix B—RBLC Information Summary............................................ � �............B Facilitv Information: The Lancaster Plant will be adjacent to the Fort Lupton Gas Plant which is in Weld County, CO at Northwest '/a, Section 14, Township 2 North, Range 66 West. The coordinates are: Latitude: 40°, 16.14'N Longitude: 104°,45.08'W The street address is: � 16116 WCR 22 � � Ft. Lupton, CO 80621 The existing facilities cunently operate under a number of construction permits as well as Title V operating permits. A recent acquisition of assets formerly owned by EnCana also brought the Platte Valley Station into the single facility complex. Process Description: The new 600 million standard cubic feet per day (MMscfd) cryogenic plant will be located adjacent to the existing Fort Lupton Facility which includes gathering compression and existing refrigeration plant. The plants will receive third parCy gas from the Kerr McGee Gathering pipeline system in the Wattenberg Field, remove COZ via amine treating,dehydrate the gas through the use of molecular sieve beds, extract natural gas liquids (NGL) through the use of the gas sub-cooled process (GSP) and SCORE cryogenic cooling processes and then re-compress the residue gas stream for sales. Inlet gas will be compressed with five (5) 3,750-hp electric motor driven reciprocating compressors that will discharge to a high pressure pipeline that feeds the Lancaster Plant. ' The COZ is removed from the inlet gas stream utilizing four (4) 600 gpm amine treaters. The I amine treaters incorporate a thermal oxidizer per unit to control emissions. The gas stream is then dehydrated using a molecular sieve. The molecular sieve beds are regenerated using dry gas that has been heated by the regeneration gas heater. The dry gas is then run through the cryogenic unit to super-cool it and remove natural gas liquids (NGL). The cryogenic units are supplemented by six (6) 3,000 hp electric motor driven propane refrigerarion compressors. The residue gas from the cryogenic units is then compressed utilizing four (4) 12,000 hp electric motor driven compressors to deliver the gas to the transportation pipeline. The produced NGLs are also transported from the facility via a pipeline. The primary reason for treating the inlet gas with amine is to ensure that the NGLs meet pipeline specifications. The inlet gas has about 2.7 mole % CO2. Treating the feed gas avoids issues with liquid treating, such as amine carry over and meeting the pipeline water specification. Because the amine units are designed to remove COZ from the natural gas, the generation of COZ (GHG) is inherent to the process, and a reduction of COZ emissions by process changes would only be achieved by a reduction in the process efficiency, which would result in natural gas that would not meet pipeline quality specifications and leave COZ in the natural gas for emission to the atmosphere at downstream sources. The amine units do also emit . _ _ . methane (GHG) at the point of amine regeneration, due to a small amount of natural gas becoming entrained in the rich amine. Emission Sources: The proposed project triggers Prevention of Significant Deterioration (PSD) permitting thresholds for greenhouse gases, but does not trigger PSD for any criteria pollutants. The primary sources of GHGs proposed at the 600 MMscfd plant will be: C-4100 So1ar 12,000-hp Electric Drive Motor, Residue C-4200 Solar 12,000-hp Elech'ic Drive Motor, Residue C-4300 Solar 12,000-hp Electric Drive Motor, Residue C-4400 Solar 12,000-hp Electric Drive Motor,Residue GS ll 0 3000-hp Elech-ic Motor, Refrigeration Compression C-5210 3000-hp Electric Motor, Refrigeration Compression G5310 3000-hp Electric Motor, Refrigeration Compression G5410 3000-hp Electric Motor, Refrigeration Compression G5510 3000-hp Electric Motor, Refrigeration Compression G5610 3000-hp Electric Motor, Refrigeration Compression ENG 105 3750-hp Electrio Motor, Inlet Compression ENG 106 3750-hp Electric Motor, Inlet Compression ENG 107 3750-hp Electric Motor, Inlet Compression ENG 108 3750-hp Electric Motor, Inlet Compression ENG 109 3750-hp Electric Motor, Inlet Compression E-2015 Mole Sieve Regeneration Gas Heater with Ultra-Low NOx Burners E-2016 Mole Sieve Regeneration Gas Heater with Ultra-Low NOx Bumers H-6051 Amine Regeneration Heat Medium Heater-Low NOx Burners H-6052 Amine Regeneration Heat Medium Heater-Low NOx Burners H-6053 Amine Regeneration Heat Medium Heater-Low NOx Burners H-6054 Ainine Regeneration Heat Medium Heater-Low NOx Burners A-1 150 MMSCFD Amine Treater (Controlled with ATO-1) A-2 150 MMSCFD Amine Treater(Controlled with ATO-2) A-3 I50 MMSCFD Amine Treater(Controlled with ATO-3) A-4 150 MMSCFD Amine Treater(Controlled with ATO-4) F-2 Vertical Process Flare F-3 Vertical Process Fiare GEN3 Caterpillar 839-hp Diesel Einergency Generator FUG 3 Plant Fugitives Kerr McGee Gathering- Lancaster Cryogenic Project GHG BACT Analysis Page 2 The proposed project triggers PSD for the estimated GHG emissions as it is estimated to emit 578,235 tons per year (tpy) COZ equivalent (COZe) including fugitive emissions. The net COZ emissions will be 557,569 tpy however, as four existing engines will be removed as part of this project. The COZe emissions are estimated by applying the global warxning potential (GWP)of eacL GHG pollutant The GWP for each pollutant is: CO2: 1 CH4: 21 N2O: 310 For example this means one ton of inethane would equate to 21 tons of COZe. Detailed calculations can be found in the calculations section of the permit application. UNIT COze tpy C-4100 - C-4200 - C-4300 - C-4400 - G5110 - G5210 - G5310 - G5410 - C-5510 - G5610 - ENG 105 - ENG 106 - ENG 107 - ENG 108 - ENG 109 - E-2015 15,252 E-2016 15,252 H-6051 39,421 H-6052 39,421 ' H-6053 39,421 H-6054 39,421 A-1 94,121 A-2 94,121 A-3 94,121 A-4 94,121 F-2 6,220 F-3 6,220 � GEN3 1'72 ' FUG 3 949 TOTAL 578,235 Kerr McGee Gathering- Lancaster Cryogenic Project GHG BACT Analysis Page 3 _ _ _ _ BACT Analvses Methodolo2v: As of January 2, 2011, GHG is a regulated criteria pollutant under the PSD majar source permitting prograin codified in Title 40 Code of Federal Regulations (CFR) Part 52 when they are emitted by new sources or modifications in amounts that meet the Tailoring Rule's set of applicability thresholds. For PSD purposes, GHGs are a single air pollutant defined as the aggregate group of the following gases: carbon dioxide (CO2), nitrous oxide (N2O), methane(CH4}, and hydrofluorocarbons (HFCs). The PSD regulations do not prescribe a procedure for conducting BACT analyses. Instead, EPA has consistently interpreted the BACT requirement as containing two core criteria: I. The BACT analysis must include consideration of the most stringent available technologies, i.e., those that provide the "maximum degree of emissions reduction." 2. Any decision to require as BACT a control altemative that is less effective than the most stringent available must be justified by an analysis of objective indicators showing that energy, environmental, and economic impacts render the most stringent alternative unreasonable or otheiwise not achievable. EPA has developed what it terms the "top-down" approach for conducting BACT analyses and has indicated that this approach will generally yield a BACT determination satisfying the two care criteria. Under the "top-down" approach, progressively less sh-ingent controI technologies are analyzed until a level of control considered BACT is reached, based on the environmental, energy, and economic impacts. The top-down approach shall be utilized in this BACT analysis. The five basic steps of a top-down BACT analysis are listed below: 1. Identify all available control technologies with practical potential for application to the specific emission unit for the regulated pollutant under evaluation; 2. Eliminate all technicaliy infeasible control technologies; 3. Rank remaining control technologies by effectiveness and tabulate a control hierarchy; 4. Evaluate most effective controls and document results; and S. Select BACT, which will be the most effective practical option not rejected, based on economic environmental and/ , , ar energy impacts. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 4 BACT Evaluation for Sources: Step I:Identify Contvol Options The following are potentially applicable control technologies for controlling GHG emissions associated with the En�ines: 1. All the new compressor engines at this facility will be run on electric power resulting in no GHG emissions from these sources. Therefore, no further analysis is necessary for the engines. 2. The 839-hp diesel emergency generatox will operate a maYimum 500 hrs/yr limited to emergency situations only. The generator will meet all emissions, operating and compliance requitemenYs of NSPS Subpart IIII for stationary compression ignitions ICEs. All manufacturers recommended maintenance will be performed as required. The following are potentially applicable control technologies for controlling GHG emissions . . associated with the Amine Vents: . . . � 1. Proper Design and Operation: The amine units are designed to include a flash tank, in which gases (i.e., including CO2 and methane) are removed from the rich amine prior to regeneration, thereby reducing the amount of waste gas created. The amine units at this facility shall be constructed and operated for optimal performance; 2. Amine Unit Flash Tank Off-gas Recovery System: The amine unit flash tank off- gases shall be routed to the proposed thermal oxidizer. 3. Routing Amine Unit Regenerator Vent to a Thermal Oxidizer: This control device will reduce the methane einissions by 99% and will convert those emissions to CO2, which has a lower GWP; 4. Routing Ainine Unit Regenerator Vent to a Flare: This control device will reduce the methane emissions by 98% and will convert those emissions to CO2, which has a lower GWP; 5. Carbon Capture and Storage (CCS): This involves capturing CO2, transporting it as necessary, and permanently storing it instead of releasing it into the atinosphere. The process involves three main steps: • Capturing CO2 at its source by separating it from other gases; • Transporting the captured CO2 to a suitable storage location (typically in compressed form); and • Storing the CO2 away from the ahnosphere for a long period of time, for instance in underground geological formations, ar within certain inineral formations. � In the project two CCS approaches were looked at: acid gas injection well and enhanced oil recovery(EOR) The following are potentially applicable control technologies for controlling GHG emissions associated with the Heaters: 1. Fuel Selection: The heaters at the site shall be fired on pipeline quality natural gas. This results in 28% less CO2 production than fuel oils (see 40 CFR Part 98, Subpart C, Table C-1, which is included in Appendix E, for a comparison of the GHG � emitting potential gf various fuel types); � Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 5 __ _ _ ___ _ . 2. Efficient Heater Design: New burner design improves the mixing of fuel, creating a more efficient heat ti-ansfer. At the new facility, new burners shall be utilized. Burner management systems shall be utilized on the heaters, such that intelligent flame ignition, flame intensity controls, and flue gas recirculation optimize the efficiency of the devices. 3. Periodic tune-ups and maintenance for optimal thermal efficiency: Maintenance shall be performed routinely per vendor recommendations or the facility's maintenance � plan. The components shall be serviced or replaced as needed. The heaters shall be , tuned once a year for optimal thermal efficiency; 4. Oxygen trim control: Combustion devices operate with a certain amount of excess air to reduce emissions and for safety consideration. An inappropriate mixture may lead to inefficient combustion. Regular maintenance of the draft air intake systems of the heaters can reduce energy usage. Draft control is applicable to new or existing process heaters and is cost effective for process heaters rated at 20 to 30 MMBtu/hr or greater. The heaters will have air and fuel valves inechanically linked to maintain the proper air to fuel ratio. The following are potentially applicable control technologies for controlling GHG emissions associated with the Process Flares: 1. The process flares will be designed according to best engineering practices and API Standards 521 and 537. Both flares will utilize a butner management system, a pilot monitoring system and a combustion air blower to optimize combustion. The following are potentially applicable control technologies for controlling GHG emissions associated with the Overall Facilitv: 1. Overall efficiency of facility; 2. Existing Fort Lupton equipment permanent shutdowns; 3. Compliance with NSPS Subpart KKK for fugitive equipment Step 2:Elfntinate T'echi¢ical[y Infeasible Control Options AY the current time acid gas injection wells for this location appear to be technically infeasible. There are no known acid gas injection wells operating in the Denver-Julesberg (D-J) Basin. The current consensus is that acid gas injection wells would not sequester the CO2,but rather the CO2 would migrate to other producing wells creating a recycle of CO2. Step 3: Cliaracterize Cor2tr^ol Effectiveness of Teclznically Feasible CoiTtrol Options The efficiency improvemenUGHG reduction technologies are ranked* below: • Use of electric-driven engines (100%); • Install amine unit flash tank off-gas recovery systems (100%); • Routing the amine unit vents to a thermal oxidizer (99% for methane, and generates CO2); • Routing the amine unit vents to a flare (98% for methane, and generates CO2); Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 6 . Efficiencies within the plant(variable); • Hours of operation limitation emergency generatar(943%) o Fuel selection (28%when comparing natural gas and No. 2 Fuel Oil); • Burner management systems on the heaters, with intelligent flame ignition, flame intensity controls, and flue gas recirculation(10-25%); • Burner management systems on process flares, with a pilot monitoring system and combustion air blowers (10-25%); • Efficient heater design (10%); • Annual tune-ups and maintenance (1-10%); • Oxygen trim control; • CCS (not a feasible option for the Project due to technical, environmental, and economic reasons, as discussed in Step 4). *The following documents were used to identify any available control efficiencies including some vendor specifications i) Available and Emerging Technology for Reducing Greenhouse Gas Emission from the Petroleuin Industry dated October 2010 and ii) Energy Efficiency Improvement and Cost Saving Opporhxnities for the °Petrochemical Industry: An ENERGY STAR Guide for Energy Plant Manager, Document Number LBNL-964E, dated June 2008, Step 4:Evaluate Most Effective ConCrol Options As part of this pxoject the following options that were listed in Step 1, shall not be proposed for implementation as BACT: l. The routing of amine unit regenerator vent to a flare (98% control), because a more efficient technology(thennal oxidizer, with 99% efficiency) will be addressed. 2. Amine flash tank off-gas recovery. The amine flash tank off-gas will be routed to the thermal oxidizer to aid in combustion of the regenexator vent gas. 3. CCS is not considered to be feasible, based upon its lack of readily available technologies and negative environxnental and economic impacts. However, per EPA guidance, EPA has identified CCS as an add-on control technology that must be evaluated as if it were technically feasible. The unine flash tank off-gas will be routed to the thermal oxidizer for combustion rather than recycled to the plant inlet. Due to the low Btu and the cooling effect of the CO2 in the amine regenerator vent gas stream, additional Btu content(assist gas)will need to be added to aid in combustion in the thermal oxidizer. If the flash gas were to be routed back to the plant inlet, additional compression would be needed and the energy required would negate the potential savings on the flash gas. The design will utilize the high Bhz flash gas to help supply some of the additional Btu need to offset a portion of the pipeline gas utilized for the remaining assist gas. The emerging CCS technology is an "end of pipe'' add-on control method comprised of three stages (capture/compression, transport, and storage). CCS involves separation and capture of CO2 from the exhaust gas, pressurization of the captured CO2, transmission of CO2 via Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 7 pipeline, and injection and long term geologic storage of the captured CO2. CCS can also consist of use of CO2 in Enhance Oil Recovery(EOR) opportunities. The goal of CO2 capture is to concentrate the CO2 stream from an emitting source for transport and injection at a storage site or location utilizing EOR. CCS requires a highly concentrated, pure CO2 stream for practical and economic reasons. Extracting CO2 from e�aust gases requires equipment to capture the flue gas e�aust and to separate and pressurize the CO2 for transportation. Extracting CO2 from the exhaust gases of the heaters and thermal oxidizers would require equipment to capture the flue gas exhaust and to separate and pressurize the CO2 for transportation. The exhaust stack streams will be low pressure, basically atmospheric pressure. The streams would also be emitted at high temperatures. The CO2 separation would require the remova] of all other pollutants from the streams. The process would require compression to increase the pressure froin atmospheric to pipeline pressuxes. The process would also require the reduction of the temperature of the streams by several hundreds of degrees prior to separation, compression, and transmission. Basically an entire i plant similar to what is being proposed in this project (smailer in size) would have to be constructed to re v t mo e he CO2. This roce p ss would add even more GHG emissions and luge costs to the project. This option is not environmentally, nor economically feasible. Even if we assumed there was a feasible way to separate the CO2 from the combustion streams, there would be several logistical issues that need to be resotved including obtaining right of way (ROW) and National Enviromnental Policy Act (NEPA) efforts for a pipeline to transport the CO2 to a location that would be available to receive and handle a continuous long term stream of CO2. The geological formations available near this proposed site are not technically feasible to store the CO2 as mentioned previously. In addition EOR is not feasible at any lazge scale level in the D-J Basin due to its geology and multiple owner/operators in the area. There may be some single well CO2 EOR projects forthcoming in this area, but nothing of the magnitude that would be able to handle the continuous supply of CO2 that would be produced from this project. Since different owner/operators ue located in close proximity, large scale EOR is not feasible. The exhaust streams from the heaters and thermal oxidizers would have to be cooled; compressed, and treated priar to being able to enter a pipeline. A conservative estimate on the cost of equipment that could possibly be installed for these purposes was assumed to be $50,000,00O. The nearest identified area utilizing EOR with CO2 is approximately 300 miles from Yhe Plant. At a cost of $80,000 per inch mile to install a 12" pipe line, the total cost for the pipeline alone would be approximately$288 million($80,000 x 12 x 300). Detailed engineering was not done on horsepower requirements to boost the gas along the approximately 300 miles of pipeline because a definitive route was not chosen. However, we could estimate it take 80,000 horsepower (including horsepower required at the site to get tlie gas up to a pipeline pressure, intennediate pipeline booster compression, and end point injection compression). The cost of that additional horsepower would be approximately $200,000,000. There would also need to be additional surface equipment (i.e. separators, dehydrators, storage tanks, etc.) at the booster sites and ali equipment would have to be able to handle the acid gas (CO2). The wst of the additional surface equipment was not estimated Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 8 in this exercise. Even excluding a portion of the cost, the engine cost and pipeline cost would equate to a $151/ton cost of control based on CO2e emissions from the proposed equipment except the process flares and fugitives sources. There is a high likelihood that the remote booster stations would not be able to utilize electric compression, therefore it will have negative impact on the environment. Hence the use of CCS to reduce GHG emissions is not economically or environmentally feasible for this project, and the timing required for ROW issues and NEPA analyses would extend the project start date out by years. In addition there is no assurance that any available CO2 pipeline or EOR area would even have the capacity to handle the CO2 from this project. Step 5:Establish BACT After discussion in the previous sections,the proposed BACT fox this project would include: En2ines- ➢ Electric motors on compressor engines O 84,750 hp of electric driven compression ➢ Emergency generator o Limit hours of operation to S00 lu�s/yr o Follow NSPS Subpart IIII requirements o Follow manufacturer recommended maintenance Amine Vents- ➢ Routing off-gases to thermal oxidizer for combustion o Thermal Oxidizers utilize combustion air preheaters and acid gas heat exchangers Heaters and Process Flares- ➢ Design, operation, and management critexia as specified in Steps 1 &3 Overall Facilitv- ➢ Efficiencies o Engine shutdowns ➢ Compliance with NSPS Subpart ICICIC as applicable o LDAR to reduce fugitive leaks The thermal oxidizers proposed to control emissions from the amine vents will utilize combustion air preheaters as well as an acid gas heat exchanger to minimize additional fuel requirements. The engineering design firm has estiinated that the preheaters and heat exchangers will reduce assist gas requirements by approximately 11 MMBtu/hr. That efficiency relates to an avoided amomit of 5,637 tpy of CO2e for each thermal oxidizer. Kerr-McGee Gathering is committing to 84,750 horsepower of electric compression as part of this project. 'I'he choice of electric compression will eliminate GHG emissions from the compression needs of the plant. Based on Caterpillar data on recent 3600 series engines, CO2 emissions from natural gas fired engines are approximately 450 grams per harsepower- Kerr McGee Gathering- Lancaster Cryogenic Project GHG BACT Analysis Page 9 hour. That would equate to 368,267 tpy of CO2e from 84,750 horsepower of natural gas fired engines. Not to mention there would be overall energy efficiencies by utilizing electric compression in this project. As part of the overall project, four natural gas fired engine at the existing Fort Lupton plant will be permanently shut do�ni (EU-31, EU-35, EU-36 and EU-37). The runtime restrictions on the engines will reduce up to 20,666 tpy of CO2e. Total uantifiable CO2e reductions of 394 570 are ro osed as art of the B , 9 , 1py p p p ACT as well as numerous reductions that u�e not as easily quantifiable, such as maintenance and operation conditions on the heaters. Overall the proposed project will treat 600 MMscfd of gas with only a inodest increase in CO ' and VOC emissions with a reduction in NOX emissions. While there is a proposed 557,235 tpy emission increase in GHG emissions in the project(including fugitives), it is effectively removing the CO2 from the gas stream that would uttimately have been emitted at some point downstream of this facility. The overall avoided and xeduced GHG emissions for the project are greater than 50% of the proposed total net GHG emissions. Kerr McGee Gathering—Lancaster Cryogenic Project GHG BACT Analysis Page 10 APPENDIX A Economic Analysis for CSS Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B Best Availabie Control Technology Control Cost Analysis Worksheet (Basetl on Offrce ofAv puality Planning and Standards,EPA,OAQPS Contml Cost Manual,Pourlh Edition.EPA450/3-9b006,January 1990,Section 2.32) . � Targeted Emission Reference without with � No. Control Control � � (TPY) (TPY) � Pi eline 564846 0 . . Booster Stations � � CO2 Removal E ui ment � � Reference Interest Control Capital Capital Annual Capital Realized � No. . Rate System Life Recovery Factor Investment Maintenance Recovery Cost Economic (i) (n) (CRF) (P) Cost (CRC) Benefit Pi eline 0.08 20 0.102 $288,000,000 $2,589,600 $29,333,436 $0 � Com ression 0.08 10 0.749 $200,000,000 $15,000,000 $29,805,898 $0 CO2 Removal E ui ment 0.08 15 0.117 $50,000,000 �$2,500,000 $5,841,477 $0 - "n"is the wntrol syslem economic life,fypicallythought lo be 10-20 years. � � "i"is the considered the annual prelax marginal ra[e of return on private investment(i.e.,what ii may cosi you ro borrow�he money). . "P"is[he capital invesimeM required to install the controls(i.e.,equipment purchase cost,installatioNrehoft cost,engineering,etc.). � � Annual Maintenance Cost is the yearly costs to maintain the confrol effectiveness(i.e.,cleaning,testing,etc). CRC=CRF'P� � �CRC= Capital Recovery Cost(Annualized cost of control over the life of the control) CRF= Capital recovery Factor � � � P= Capita�Investment � " � CRF=i(1+i)N(1+i)n-1 � i= Annual InterestRate � n= Economic life of the controi � Total Annual Cost(TAC)=Annual Maintenance Cost+Capi[al Recovery Cost-Realizetl Economic Benefit � Cast to Control=TAC I(Targeted Emission Volume Without Control-Targeted Emission Volumn with Control) � � Reference TAC Cost to Control Number ($) ($ITon) Pipeline $85,070,411 $157 � Booster Stations � � � CO2 Removal Equipment . . APPENDIX B RBLC Information Summary I Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B . . _ _ _ . ', Previous Page Report Date: 04/12/2012 INDEX OF CONTROL TECHNOLOGIES DETERMINATIONS NOTE:Draft determinations are marked with a"* "beside the RBLC ID. . .._....�_____. .___.__.._ . ...�_ __._. __,..._.. _._._........ .... __.._.__ _._ _...__. ______.._. .__...__ _.. __. . __. .._: CompanyName RBLC Country Permit Process processDescriptian ID Date(Est/Act) Type � _..__. _ ...._ ___. . OTTUMWA � ______ ...____._. _ . GENERATING � � Ugp 0l/12/2012ACT 11.110 Boiler#I � � STATION � 'rIA-0101 . COGENERATION USA 12/06/2011 ACT 15.210 COGENERATION TRAINS I-3(1-1Q 2-10,3-10) � PLANT �LA-0256 � 17.130 EMERGENCY GENERATOR SABINE PASS LNG USA 12/06/2011 ACT 15.200 Combined Cycle Refrigeration Compressor Tarbines(8) TERMINAL �LA-0257 � . 19.390 WeUDry Gas Flares(4) 19390 Marine Flare 50.999 Acid Gas Vents(4) . � I5.100 Simple Cycle Genecation Turbines(2) . . 17.130 Generator Engines(2) . � 15.700 Simple Cycle Reftigeration Compressor Turbines(16) � � � . 50999 Fugitive Emissions � � PORT DOLPHIN ENERGY�LLC � � USA 12/0l/2011 ACT 99.999 Fugitive GHG emissions � � II � FL-0330 11310 Boilecs(4-278 mn16m/hr each) I � 11310 Power Generator Engines(3) � � ENI-HOLY CROSS USA 10/27/2011 ACT I3.220 Boiler � � � DRILLING PROJ *FL-0328 � � . 17.110 Emergency Fire Pump Engine � ]71I0 Emergency�Engine . . 17.110 Crane Engines(units 3 and 4) � � 17.1]0 Crane Engines(units 1 and 2) 17.110 Main Propulsion Engines . . . 42.000 Storage Tanks � � NINEMILE POINT � ELECTRIC GENERA � LA-0254 USA 08/16/2011 ACT 17.110 EMERGENCY DIESEL GENERATOR � - � � 17.210 EMERGENCY FIRE PUMP � . � � 99.009 i7NIT 6 COOLING TOWER . 99.009 CAILLER COOLING TOWER(CffiLL CT) I 1310 AUXILIARY BOILER(AUX-1) . � � � - 15210 COMBINED CYCLE TUABINE GENERATORS(UNITS 6A &6B) DIRECT REDUCTION 0l/27/20ll ACT 81.900 DRI-101 DRI Unit#1 Gon Oxide Da Bins Dust Collection IRON PLANT � . LA-0248 USA y 81.290 DRI-111 -DRI Unit#I Acid Gas Absorption Vent � 81.900 DRI-102 DRI Unit#1 Iron Oxide Screen Dust Collection 81.900 DRI-202 DRI Unit#2 Iron Oxide Screen Dust Collection 81.900 DRI-105 DRI Unit#1 Furnace Feed Conveyor Baghouse - 81.9D0 DRI-205 DRI Unit#2 Fumace Feed Conveyor Baghouse � 81.900 DRI-103 DRI Unit#1 Coating Bin Filter � � 81.900 DRI-203 DRI Unit#2 Coating Bin Filter . � � 81.900 DRI-104 DRI Unit#1 Iron Oxide Fines Handling � 81.900 DRI-204 DRI Unit#1 Iron Oxide Fines Aandling � . 99.009 Dffi-113-DRI Unit#] Process Water Cooling Tower , 99.009 DRI-213-DRI Unit#2 Process Water Cooling Tower 99.009 DRI-114-DRI Unit#] Clean Water Cooling Tower � � � � � 99.009 DRI-214-DRI Unit#1 Clean Water Cooling Tower � � 8 L290 -DRI-1]7-Briquetting Mill � � � 99.190 DRI-ll 8-DRI Barge Loading Dock � � � �� 81290 DRI-1 I S-Product Screen Dust Collection - � 81290 DRI-116-Scieened Product Transfer Dust Collection � � . 81290 DRI-107-DRI Unit No. 1 Fumace Dust Collection . 81290 Dffi-207-.DRI Unit No.2 Furnace Dust Collection � . . � 11310 DRI-109-DRI Unit#I Package Boiler Flue Stack � . � 11.310 DRI-209-DRI Unit#2 Package Boiler Flue Stack � 81290 bRI-112-DRI U�it No. 1 Product storage silo Dust Collection �.. . 81290 DRI-212-DRI Unit No.2 Product storage silo Dust Coilection ,� � 19390 DRI-210-DRI Unit No. 1 Hot Flaw 19390 DRI-110-DRI Unit No. 1 Hot Flaze . . � - 81.200 DRI-208-DRI Unit#2 Reformer Main Flue Stack ' � � � 81200 DRI-108-DRI Unit#1 Refonner Main Flue Stacic . � � 81.290 DRI-206-DRI Unit No.2 Upper Seal Gas V ent � � 81290 DRI-106-�DRI Unit No. 1 Upper Seal Gas Vent � 81290 DRI-21I -DRI Unit#1 Acid Gas Absorption Veni ' R 1.900 Dffi-201 DRI Unit#2 Iron Oxide Day Bins Dust Collection ' BASF FINA NAFTA 02/10/2010 ACT 50.003 N-11,REACTOR REGENERATION EFFLUENT �� REGION OLEFINS TX-O550 USA � 50.003 N-1Q CATALYST REGENSRATION EFFLUENT � � 50.003 N-18,DECOKING DRUM � PRYOR PLANT 02/23/2009 ACT ��61.999 COOLING TOWER#2 I � CHEMICAL OK-0135 USA . � .61.012 PRiMARY REFORMER � 62.014' NITRIC ACID PLANT#1 . � �. 62.014 NITRIC ACID PLANT#3 . .. 61.999 WNDENSATE STEAM FLASH DRUM-AMMONIA PLT 4 ��. 61.999 � COOLING TOWER#1 . ' � 13.310 - NITRIC ACID PREHEATERS#I,#3,AND#4 � 61.999 CARBON DIOXIDE VENT � � I . - 61.012 �AMMONIUM NITRATE PLANTS�1 AND#2 � 61.999 GRANULATOR SCRUBBERS#1,#2,AND#3 � � 13310 HOILERS#1 AND#2 � � 62.014 NITRIC ACID PLANT#4 . . RUMPKE SANITARY OH-0330 USA 12/23/2008 ACT 29.900 ENCLOSED COMBUSTORS(4) � I LANDFILL . . . 29.900 NNNICIPAL WASTE LANDFILL � ��. � 29.900 OPEN FLARE � '� .� 99.150 � PAVED ROADWAYS AND PARffiNG AREAS . � 29.900 CANDLESTICK FLARE(5) �' CPVSTCHARLES MD-0040 USA 11/12/2008ACT. 99.999 COOLINGTOWER ,, � � INTERNAL COMBUSTION ENGINE-EMERGENCY � 17210 GENERATOR �I� . ��Z�� INTERNAL COMBUSTION ENGINE-EMERGENCY FIRE . , WATER PUMP . . � . � 13310 BOILER l, � 15.11 0 COMBUSTION TURBINES(2) � � 13.310 HEATER � � � . . � ..., � , il ACTIVATED CARBON 0S/28/2008 ACT 11110 MULTIPLE HEARTH FURNACES/AFTERBURNERS � � FACILITY LA-0148 USA � � � 99.009 COOLING TOWERS � � � TWO(2)ELECTRIC ARC FURNACES AND THREE(3) � NUCOR DECATUR LLC AL-0231 USA 06/12/2007 ACT 87210 - LADLE METALLURGY FURNACES WITH TWO(2) MELTSHOP BAGHOUSES � 13310 VACWMDEGASSERBOILSR 13310 � GALVANIZING LINE FURNACE � I . � 81.290 � VACUUM DEGASSER I � AIR PRODUCTS � 11/02/2004 ACT 99.999� PARTS WASHER BAYTOWNII TX-0481 USA . 50.007 FUGITIVES(4) - . 64.003 MSS PROCESS STEAM VENT �- 64.003 PROCESS STEAM VENT . 19.800 EMERGENCY GENERATOR TANK - 64.003 MSS-NONCONDENSIBLES(PROPYLENE VENTING) � 19310 FLARE(NORMAL OPERATTON) 64.003 RECTISOL VENT � � . 19.800 EMERGENCY GENERATOA � . . 42.005 DIESEL FUEL TANK - � . 13390 BOILER STACK(START UP) � J � �ll 390 . BOILER STACK(HIGH BTU FUEL) � 50.005 COOLING TOWER � . 50.005 SUPPLEMENTARY COOLING TOWER � . � 11390 BOILER STACK . RUMPKE�SANITARY 06/10/2004 ACT 29.900 PORTABLE TUB GRINDER LANDFILL,INC OH-028] USA . 29900 LANFILL ROADWAYS � 29.900 LEACHATE STORAGE BASIN � . 29.900 LLACHATE AERATTON BASIN � � 29.900 FUGITIVE EMISSIONS FROM LANDFILL AND GAS �. COLLECTION SYSTEM � � � � 17.210 PORTABLE ENGINE 4.68 MMBTU/H � 29.900 NEW SOLID WASTE DISPOSAL WITH LANDFILL GAS �I � . GENERATION � . 17.210 PORTABLE ENGINE 0.58 MMBTU/H . � - 29.900 LOAD-IN,LOAD-OUT,TURNING,AND WIND EROSION 29.900 PORTABLE SCREENER 29.900 EXISTING SOLID WASTE DISPOSAL WITH LANDFILL . � � � GAS GENERATION . � T _ Previous Page � . ! 4/M13 � � State.co.us E;�cutiee Branch Mail-RE;Flare GHG emissions fur Lancaster •. � ''.. State ._.. . , Colorado ` - RE: Flare GHG emissions for Lancaster ____ _----- --- — -- --- - — -- — Shea, Jennifer <,lennifecShea@anadarko.com> _ � Thu, Dec 6, 2012 at 10:36 AM To: "Money -CDPHE, Carissa" <carissa.money@state.co.us> , � �. Cc: "Chaousy, Stephanie (stephanie.chaousy@state.co.us)" <stephanie.chaousy@state.co.us>, "mark.mcmillan@state.co.us" � <mark.mcmillan@state.co.us>, "christopher.laplante@state.co.us" achristopher.laplante@state.co.us>, "Bracken, Korby" ,. <Korby.Bracken@anadarko.com> � � �Carissa, � 1 updated the BACT analysis to reflect the 139tpy of CO2e emissions from the emergency generator and induded it in the 5-step � � review. Asfarasthefacilityflares,theseequipmentarecontroldevicesforany6lowdownsandmaintenanceactivitiesthat would normally go to the atmosphere. I am confused as�to why we are required to perform a BACT analysis for a control device. � � Can you expiain whythis is required? . � Thanks, � � � � . � Jennifer Shea � Staff EHS Representative . . � � . ANADARKO Pk7ROLEUM CORPORATION � Direct: (720) 929-6028 � Cell: (303) 919-0040 � � � � ` � . . From: Money- CDPHE, Carissa [maiito:carissa.money@state.co.us] � � . I Sent: Thursday, December 06, 2012 9:36 AM � � � .. To: Shea,Jennifer Cc: Chaousy, Stephanie (stephanie.chaousy@state.co.us); mark.mcmillan@state.co:us; christopher.laplante@state.co.us 5ubject: Re: Flare GHG emissions for Lancaster � � Jennifer, - � � � �, Thank you for the retised flare calculations.and re�nsed forms. Along with ihis updated information, the BACT analysis must be re�ised to ,, indude a 5-step top-down rev�ew of controls for GHG emissions from flares. I didnY see this anlayis in the updated BACT document. I'm i assuming that good engineering practice and flare design will be BACT but this review must be included in the BACT analysis. . �i� Along ihose lines, the BACT analysis also does not address the emergency generatoc W hile the generator is listed as�zero GHG ��Ili emissions, I calculate 193 tpy CO2e from the generator. Any equipment inwl�d in the project that has GHG emissions abo�zero must .be included in the BACT revew. Similar to the flares, I expect good combustion practices will most likely suffice as BACT for the � generetor but this revew must be included in your report. � . � Please let me know if you ha�any questions regarding this emaii. Also, please let me know when I can expect a re�ised BACT analysis that includes a control technology review for flares and diesel generator. � https://mail.google.coMmail/W0/?ui=2&ik=da5742cbb2&uev�pt&cat=Cabinet°/2FKerr McGee Hambert&search=cat&th=13b714a264c098D6 . 1/3 . � _. .._.... ... . 4/4/13 State.co.us Executi�e Branch Mail�-RE:Flare GHG emissions for Lancaster . ' Thank you, Carissa - � � On Wed, Dec 5, 2012 at 8:12 AM, Shea, Jennifer<�ennifer.Shea@anadarko.com> wrote: � Carissa, � � � � � Attached are the updated BACTanalysis with the increase flare CO2 emissions. Sorry about that—I was referencing an incorrect ceil when convertingfrom metrictons to shorttons: Stephanie—Pm not sure�if this affects anythingyou have done since only the CO2 emissions were incorrect, but I attached� updated sheets anyway. let me know if you have questions. � - I Jennifer Shea � Staff EHS Representative � ANADARKO PETROLEUM CORPORATION Direct: (720) 929-6028 � Ce1L (303) 919-0040 . � . . From: Money- CDPHE, Carissa [mailto:carissa.money@state.co.us] - Sent: Tuesday, December 04, 2012 4:09 PM � � � To: Shea,Jennifer Subject: Flare GHG emissions for Lancaster . � � . Jennifer, . I ICan you please check the GHG emissions from the flares? There seems to be an error when convarting from metnc ton to tpy. The � , application shows 150 tpy CO2e per flare but I calculate 6,212 tpy CO2e. If the flares are in fact estimated to emit 6,212 tpy CO2 each, then they would hava to be addressed in the BACT analysis. Please let me know as soon as possible your thoughts�. I � Thank you, � � . �. Carissa � � � AnadarYo Confidentiality Notice: This electronic transmissio❑ and any � � attached documents or othex writings are intended only for the person � or entity to which it is addressed and may contain information that is . privileged, confidential or otherwise protected Prom disclosure. If you � � have receivcd this coirununication in error, piease immediately notify sender by return e-mail and destroy the wmmunication. Any disclosure, � copying, distribation or the taking of any action concerning the contents � of this communication or any attachment.s by anyone other than T:^e � � https://mail.google.coriJmaiVu/0/?ui=2&ik=da5742cbb2&vev�pt&cat=Cabinet°/a2FKerrMcGeeHambert&search=cat&th=13b714a264c09806 2/3 Kerr-McGee Gathering LLC Lancaster Plant Cryogenic Plant Project Greenhouse Gases Best Available Control Technologies (BACT) Analyses ��.i.L.�:��/�� ; �W� �,. f� � � 'Tai�le caf C�retent� .,.,, Pacility Information......................................................................................................................1 '� Process Description.........................................................................................................:............l EmissionSources.................................:...........................:...........................................................2 BACTAnalysis Methodology.........................................................................................................3 BACTEvaluation for Sources.........................................................................................................5 , . Appendix A—Economic Analysis for CCS.......................................................................................A � Appendix B-RBLC Information Summary.....:...............................................................................B � � � � Facilitv Information: The Lancaster Plant will be adjacent to the Fort Lupton Gas Plant which is in Weld CounTy, CO at Northwest Ya, Section 14, Township 2 North, Range 66 West. The coordinates are: Latitude: 40°, 1614'N Longitude: 104°, 45.08'W The street address is 161 I 6 W CR 22 � Ft. Lupfon, CO 80621 The existing facilities currently operate under a number of construction permits as well as Title V operating permits. A recent acquisition of assets formerly owned by EnCana also brought the Platte Valley Stationinto the single facility complex. Process Description: The new 600 million standard cubic feet per day (MMscfd) cryogenic plant will be located adjacent to the existing Forf Lupton Facility which includes gatheriug compression and existing refrigeration plant. The planYs will receive Yhird party gas from the Kerr McGee i Gathering pipeline system in the Wattenberg Field, remove CO2 via amine treating, ! dehydrate the gas through the use of molecular sieve beds, extract natural gas ]iquids (NGL) ', through the use of the gas sub-cooled process (GSP) and SCORE cryogenic cooling processes and theu re-compress the residue gas stream for sales. The CO2 is removed from the inlet gas stream utilizing four(4) 600 gpm amine treaters. The ' amine treaters incorporate a thermal oxidizer per unit to control emissions. The gas stream is then dehydrated using a molecularsieve. The molecular sieve beds are regenerated using dry , gas that has been heated by the regeneration gas heater. The dry gas is then run through the cryogenic unit to super-cool it and remove natural gas liquids (NGL). Tl�e cryogenic units , are supplemented by six (6) 2750 hp electric motor driven propane refrigeration compressors. ' The residue gas from the cryogenic units is then compressed utilizing four (4) 12,000 hp electric motor drive� compressors to deliver the gas to the transportation pipeline. The produced NGLs are also transported from the faciliTy via a pipeline. The primary reason for treating the inlet gas with amine is to ensure that the NGLs meet pipeline specifications. The inlet gas has about 2.7 mole % CO2. Treating the feed gas avoids issues with liquid treating, such as amine carry over and meeting the pipeline water � specification. �� Because the amine units are designed to remove CO2 from the natural gas, the generation of CO2 (GHG) is inherent to the process, and a reduction of CO2 emissions by process changes would only be achieved by a reduction in the process efficiency, which would result in natural gas that would not meet pipeline quality specifications and leave CO2 in the natural gas for emission to the atmosphere at downstream sources. The amine units do also emit methane (GHG) at the point of amine regeneration, due to a small amount of natural gas becoming entrained in the rich amine. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 1 I Emission Sources: The proposed project triggers Prevention of Significant Deterioration (PSD) permitting thresholds for greenhouse gases, but does not trigger PSD for any criteria pollutants. The primary sources of GHGs proposed at the 600 MMscfd plant will be: C-4100 Solar 12,000-hp Electric Drive Engines, Residue G4200 Solar 12,000-hp Electric Drive Engines, Residue G4300 Solar 12,000-hp Electric Drive Engines, Residue C-4400 Solar 12,000-hp Electric Drive Engines, Residue G51]0 2750-hp Electric Engine, Refrigeration Compression G5210 2750-hp Electric Engine, Refrigeration Compression G5310 2750-hp Electric Engine, Refrigeration Compression G5410 2750-hp Electric Engine, Refrigeration Compression G5510 2750-hp Electric Engine, Refrigeration Compression � G5610 2750-hp Electric Engine, Refrigeration Compression IE-2015 Mole Sieve Regeneration Gas Heater with Ultra-Low NOx Burners E-2016 Mole Sieve Regeneration Gas Heater with Ultra-Low NOx Burners H-6051 Amine Regeneration Heat Medium Heater-Low NOx Burners H-6052 Amine Regeneration Heat Medium Heater-Low NOx Burners H-6053 Amine Regeneration Heat Medium Heater-Low NOx Burners H-6054 Amine Regeneration Heat Medium Heater-Low NOx Burners A-1 I50 MMSCFD Amine Treater(Conirolled with ATO-1) A-2 150 MMSCFD Amine Treater(Controlled with ATO-2) A-3 150 MMSCFD Amine Treater(Controlled with ATO-3) A-4 150 MMSCFD Amine Treater(Controlled with ATO-4) F-2 Vertical Process Flare . F-3 Vertical Process Flare GEN3 Caterpiltar 670-hp Diese] Emergency Generator FUG 3 Plant Fugitives The proposed project triggers PSD for the estimated GHG emissions as it is estimated to emit 578,203 tons per year(tpy) CO2 equivalent (CO2e). The net CO2 emissions will be 562,554 tpy however, as three existing engines will be removed as part of this project. The CO2e emissions are estimated by applying the global warming potential (GWP) of each GHG pollutant. The GWP for each pollutant is: CO2: 1 CH4: 21 N2O: 310 Far example this means one ton of inethane would equate to 21 tons of CO2e. Detailed calculations can be found in the calculations section of the permit application. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 2 UNIT CO2e tpy C-4100 - C-4200 - C-4300 - C-4400 - G5110 - C-5210 - � G5310 � - � G5410 - G5510 - G5610 - E-2015 15,252 E-2016 15,252 H-6051 39,421 H-6052 39,421 H-6053 39,421 H-6054 39,421 A-1 94,121 A-2 94,121 A-3 94,121 A-4 94,121 R2 6,220 ' F-3 6,220 ' GEN3 139 FUG 3 949 TOTAL 578,203 BACT Analvses Methodoloev: As of January 2, 2011, GHG is a regulated criteria pollutant under the PSD major source permitting program codified in TiTle 40 Code of Federal Regulations (CFR) Part 52 when they are emitted by new sources or modifications in amounts that meet the Tailoring Rule's set of applicability thresholds. For PSD purposes, GHGs are a single air pollutant defined as the aggregate group of the following gases: carbon dioxide (CO2), nitrous oxide (N2O), methane (CH4), and hydrofluorocarbons (HFCs). , The PSD regulations do not prescribe a procedure for conducting BACT analyses. Instead, EPA has consistently interpreted the BACT requirement as containing two core criteria: ', 1. The BACT analysis must include consideration of the most stringent available technologies, i.e., those that provide the"maximum degree of emissions reduction." Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 3 _ _ 2. Any decision to require as BACT a control alternative that is less effective than the most stringent available must be justified by an analysis of objective indicators showing that energy, environmental, and economic impacts render the most stringent alternative unreasonable or otherwise not achievable. EPA has developed what it terms the "top-down" approach fox conducting BACT uialyses , and has indicated that this approach will generally yield a$ACT determination satisfying the two core criteria. Under the "top-down" approach, progressively less stringent control technologies are analyzed until a level of control considered BACT is reached, based on the environmental, energy, and economic impacts. The top-down approach shall lie utilized in this BACT analysis. The five basic steps of a top-down BACT analysis are listed below: I. Identify all available�contro] technologies with practical potentia] for application to the specific emission unit for the regulated pollutant under evaluation; 2. Eliminate all technically infeasible control technologies, 3. Rank remaining control technologies by effectiveness and tabulate a control hierarchy; 4. Evaluate most effective controls and document results; and 5. Select BACT, wl�ich will be the most effective practica! optioi� not rejected, based on economic, environmental, and/or energy impacts. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 4 BACT Evaluation for Sources. � Step l:Identify Control Optlons � The following are potentially applicable control technologies for controlling GHG emissions associated with the Eneines: 1. All the new compressor engines at this faciliTy will be run on electric power resulting in no GHG emissions from these sources. Therefore, no further analysis is necessary far the engines. 2. The 670-hp diesel emergency generator will operate a maximum 500 hrs/yr limited to emergency situations only. The generator will meet all emissions, operating and compliance requirements of NSPS Subpart ITII for stationary compression ignitions ' ICEs. All manufachirer recommended maintenance will be performed as required. ' The following are potentially applicable contro] technologies for controlling GHG emissions associated with the Amine Vents 1. Proper Design and Operation: The amine units aze designed to include a flash tank, in which gases (i.e., includiug CO2 and methane) aze removed from the rich amine prior to regeneration, thereby reducing tlie amount of waste gas created. The amine units at this facility shall be constructed and operated for optimal performance; 2. Amine Unit Flash Tank Off-gas Recovery System: The amine unit flash tank off- gases shall be routed to the proposed thermal oxidizer. 3. Routing Amine Unit Regenerator VenY Yo a Thermal Oxidizer: This control device will reduce Xhe meYhane emissions by 99% and will convert those emissions to CO2, which has a lower GWP; 4. Routing Amine Unit Regenerator Vent to a Flare: This control device will reduce the methane emissions by 98% and will convert those emissions to CO2, which has a i lower GWP; � 5. Carbon Capture and Storage (CCS): This involves capturing CO2, transporting it as 4 necessary, and permanently storing it instead of releasing it into the atmosphere. The process involves three main steps: I • Capturing CO2 at its source by separating it from other gases; • Transporting the captured CO2 to a suitable storage location (typically in compressed form); and • Storing the CO2 away from the atmosphere for a long period of time, for instance in underground geological formations, or within certain mineral formations. • I�i the project two CCS approaches were looked at: acid gas injection well and enl�anced oil recovery (EOR) The following are potentially applicable cmitrol technologies for controlling GHG emissions associated with the Heaters: 1. Fuel Selection: The heaters at the site shall be fired on pipeline quality natural gas. This results in 28% less CO2 production flian fuel oils (see 40 CFR Part 98, Subpart C, Table Gl, which is included in Appendix E, for a compazison of the GHG � emitting potential of various fuel types); � � � Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 5 I li _ _ �, 2. Efficient Heater Design: New burner design improves the mixing of fuel, creating a more efficient heat iransfer. At the new facility,new burners shall be utilized. Burner management systems shall be utilized on the heaters, such that intelligent flame ignition, flame intensity controls, and flue gas recirculation optimize the efficiency of the devices. 3. Periodic tune-ups and maintenance for optimal thermal efficiency: Maintenance shall be performed routinely per vendor recommendations or the faciliTy's maintenance plan. The components shall be serviced or replaced as needed. The heaters shall be tuned once a year for optimal thermal efficiency; 4. Oxygen trim control: Combustion devices operate with a certain amount of excess air to reduce emissions and for safety consideration. An inappropriate mixture may lead to inefficient combustion. Regular maintenance of the drafr air intake systems of the heaters can reduce energy usage. Draft contro] is applicable to new or existing I process heaters and is cost effective for process heaters rated at 20 to 30 MMBtu/hr or greater. The heaters will have air and fuel valves meclianically linked to maintain the proper air to fuel ratio. The following are potentially applicable control technologies far wntrolling GHG emissions associated with the Overall Facilitv: 1. Overall efficiency of facility; 2. Existing Fort Lupton equipment permanent shutdowns; 3. Compliance with NSPS Subpart KKK for fugitive equipment. Step 2:Eliminate Technically Infeasible Control Options AT the current time acid gas injection wells for this location appear to be teclmically infeasible. There are no known acid gas injection wells operating in the Denver-Julesberg (D-J) Basin. The current consensus is that acid gas injection wells would not sequester the CO2, but rather the CO2 would migrate to other producing wells creating a recycle of CO2. � Step 3: Clzaracterize Control Effectiveness of Technically Feasib[e Contro/Options The e�ciency improvement/GHG reduction technologies axe ranked* below: � • Use ofelectric-driveu engines (100%); • Install amine unit flash tank off-gas recovery systems (100°/o); • Routing the atnine unit vents to a thermal oxidizer (99% for methane, and generates CO2); • Routing the amine unit vents to a flare(98% for methane, aud geuerates CO2); • Efficiencies within the plant(variable); � ' • Hours of operation limitation emergency generator (94.3%) • Fuel selection (28% when comparing natura] gas and No. 2 Fuel Oil); • Burner management systems on the heaters, with intelligent flame ignition, flame intensity controls, and flue gas recirculation (10-25%); � • Efficient heater design (10%); • Annual tune-ups and maintenance (1-10%); Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 6 • Oxygen trim control; • CCS (not a feasible option for the Project due to technical, environmental, and economic reasons, as discussed in Step 4). *The following documents were used to identify any available contro] efficiencies including some vendor specifications i) Available and Emerging Technology for Reducing Greenhouse Gas Emission from the Petroleum Industry dated October 2010 and ii) Energy Efficiency Iinprovement and Cost Saving Opportunities for the Petrochemical Industry: An ENERGY STAR Guide for Energy Plant Manager, Docuinent Number LBNL-964E, dated June 2008, � Step 4:Evaluate Most Effective Car2trol Options As part of this project the following options that were listed in Step 1, shall not be proposed for implementation as BACT: 1. The routing of amine unit regenerator vent to a flare (98% control), because a more efficient technology (thermal oxidizer, with 99% efficiency) will be addressed. ' 2. Amine flash tank off-gas recovery. The amine flash tank off-gas wip be routed to the therma] oxidizer to aid in combustion of the regenerator vent gas. 3. CCS is not considered to be feasible, based upon its lack of readily available technologies and negative enviromnenta] and economic impacts. However, per EPA guidance, EPA has identified CCS as an add-on control technology that must be I evaluated as if it were technically feasible. � The amine flash tatilc off-gas will be routed to the thermal oxidizer for combustion rather than recycled to the plant inlet. Due to the low Btu and Yhe coolit�g effect of the CO2 in the amine regenerator vent gas stream, additional Btu content(assist gas) will need to be added to aid in combustion in the thermal oxidizer. If the flash gas were to be routed back to the plant inlet, additional compression would be needed and the energy required would negate the potential savings on the flash gas. The design will utilize the high Btu flash gas to help supply some of the additional Btu need to offset a portion of the pipeline gas utilized for the remaining assist gas. The emerging CCS technology is an "end of pipe" add-on control method comprised of three I stages (capture/compression, transport, and storage). CCS involves separation and capture of CO2 from the exhaust gas, pressurization of the captured CO2, transmission of CO2 via l pipeline, and injection and long term geologic storage of the captured CO2. CCS can also consist of use of CO2 in Enhance Oil Recovery(EOR)opportunities. Tl�e goal of CO2 capture is to concentrate the CO2 stream from an emitting source for transport and injection at a storage site or location utilizing EOR. CCS requires a highly concentrated, pure CO2 stream for practical and economic reasons. Extracting CO2 from exhaust gases requires equipment to capture the flue gas exhaust and to separate and pressurize the CO2 for transportation. Kerr McGee Gathering- Lancaster Cryogenic Project GHG BACT Analysis Page 7 ___ _ I Extracting CO2 from the exhaust gases of the heaters and thermal oxidizers would require equipment to capture the flue gas exhaust and to separate and pressurize the CO2 far transportation. The exhaust stack streams will be low pressure, basically atmospheric � pressure. The streams would also be emitted at high temperatures. The CO2 separation i would require the removal of all other pollutants from the streams. The process would jrequire compression to increase the pressure from atmospheric to pipeline pressures. The process would also require the reduction of the temperature of the streams by several hundreds of degrees prior to separation, compression, and transmission. Basically an entire plant similar to what is being proposed in this project (smaller in size) would have to be constructed to remove the CO2. This process would add even more GHG emissions and large costs to the project. This option is not enviromnentally, nor economically feasible. Even if we assumed there was a feasible way to separate the CO2 from the combustion streams, there would be several,logistica] issues that need to be resolved including obtaining right of way (ROW) and National E�rvironmental Policy Act (NEPA) efforts for a pipeline to transport the CO2 to a location that would be available to receive and handle a continuous long term stream of CO2. The geological formations available near this proposed site are not tecluiically feasible to store the CO2 as mentioned previously. In addition EOR is not feasible at any large scale level in the D-J Basin due to its geology and multiple owner/operators in the area. There may be some single well CO2 EOR projects forthcoming in this area, but nothing of the magnitude that would be able to handle the continuous supply of CO2 that would be produced from this project. Since different owner/operators are located in close proximiTy, large scale EOR is not feasible. The exhaust streams from the heaters and thennal oxidizers would have to be cooled, compressed, and treated prior to being able to enter a pipeline. A conservative estimate on the cost of equipment tltat could possibly be installed for these purposes was assumed to be $50,000,000. The nearest identified area utilizing EOR with CO2 is approximately 300 miles from the Plant. At a cost of $80,000 per inch mile to install a 12" pipe line, the tota] cost for the pipeline alone would be approximately $288 million($80,000 x 12 x 300). � Detailed engineering was not done on horsepower requirements to boost the gas along the I� approximately 300 miles of pipeline because a definitive route was not chosen. However, we � could esTimate iY take 80,000 horsepower (including horsepower required at the site to get the gas up to a pipeline pressure, intermediate pipeline booster compression, and end point ; injection compression). The cost of that additional horsepower would be approximately $200,000,000. There would also need to be additional surface equipment (i.e. separators, dehydrators, storage tanks, etc.) at the booster sites and all equipment would have to be able to handle the acid gas (CO2). The cost of the additional surface equipment was not estimated in this exercise. Even excluding a portion of the cost, the engine cost and pipeline cost would equate to a $156/ton cost of control. There is a high likelihood that the remote booster stations would not be able to utilize electric compression, therefore it will have negative impact on the environment. Hence the use of CCS to reduce GHG emissions is not economically ar environmentally feasible for this project, and the timing required for ROW issues and NEPA analyses would extend the project start date out by years. In addition there is no assurance that any available CO2 pipeline or EOR area would even have the capaciTy to handle the CO2 from this project Kerr McGee Gathering—Lancaster Cryogenic Project GHG BACT Analysis Page 8 Step S:Establish BACT After discussion in the previous sections,the proposed BACT for this project would include: En�ines- ➢ Electric motors on compressar engines O 64,500 hp of electric driven compression ➢ Emergency generatar o Limit hours of operation to 500 hrs/yr o Follow NSPS Subpart IIII requirements o Follow manufacturer recommended maintenance Amine Vents- ➢ Routing off-gases to thermal oxidizer for combustion o Thermal Oxidizers utilize combustion air preheaters and acid gas heat exchangers Heaters- ➢ Design, operation, aud management criteria as specified in Steps 1 & 3 ' Overall Facilitv- ➢ Efficiencies o Engine shutdowns ➢ Compliance with NSPS Subpart KKK as applicable o LDAR to reduce fugitive leaks The thermal oxidizers proposed to control emissions from the amine vents will utilize combustion air preheaters as well as an acid gas heat exchanger to minimize additional fuel requirements. The engineering design firm has estimated that the prel�eaters and heat excliangers will reduce assist gas requirements by approximately 11 MMBtu/hr. That efficiency relates to an avoided amount of 5,637 tpy o£CO2e for each thermal oxidizer. Kerr-McGee Gathering is committing to 64,500 horsepower of electric compression as part of this project. The choice of electric compression will eliminate GHG emissions from the compression needs of the plant. Based on Caterpillar data on recent 3600 series engines, CO2 emissions from natural gas fired engines are approximately 450 grams per horsepower- hour. That would equate to 280,272 tpy of CO2e from 64,500 horsepower of natural gas fired engines. Not to mentiou there would be overall energy efficiencies by utilizing electric , compression in this project. ' As parC of the overall project, three natural gas fired engine at the existing Fort Lupton plant � will be permanently shut down (EU-35, EU-31 and EU-32). The runtime restrictions on the I engines will reduce up to 15,649 tpy of CO2e. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 9 Total quantifiable CO2e reductions of 318,469 tpy are proposed as part of the BACT as well as numerous reductions that are not as easily quantifiable, such as maintenance and operation conditions on the heaters. Overall the proposed project will treat 600 MMscfd of gas witl� only modest increases in criteria emissions at the facility. While there is a proposed 562,414 tpy net increase in GHG emissions in the project, it is effectively removing the CO2 from the gas stream that would ' ultimately have been emitted at some point downstream of this facility. The overall avoided and reduced GHG emissions for the project are greater than 50% of the proposed total net GHG emissions. I j i � Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 10 APPENDIX A Economic Analysis for CSS Kerr McGee Gathering- Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B �I __ _ _ a � N E = � a' o 0 0 . � � p y <s » . va R' U m W ir ry � o O N � m d �� U ao m � . � . Y N m > U � m � . o N i. �' . V � " oi �r ry O z' c� � � es -;,< ,� ^ . � K m m ° Q o m c � t� � m E � � _' o . U � j� g � � m c�o 0 0 3 :� �,L�, y r . R � .��-- � :; ° ro o u�i ° � o . m 3 . ' � y. �O� a C V N O. N � N �. V C Q � _ W . . 'L d3 EA fA �p 0 � � E . �✓ O U J C J VJ � D y_ �U V � O R �� O N d �jf > � . U N G O O � O i m � � O C _ a � v o 0 0 O � .c o rdi �H o c � .. � o 0 0 � - w ,f _ . c � � a o 0 o E m �' o m E ot � = V � �i o � -- R m � o a• W ea w O � o � rn o N � h . . o � � a m. � U -� fR EA � �i G N N O N � U , � � . .o . m U O � U O � . � � O � w � N K '�'-' �' !� � . O U . U � m V N .. O > ' � � E V N � d w O O O a . « LL li N � I� �n � c c N _ U U . 9� C a . 'o, 2'a . : � �- � c = u � c Qw ro Z o rs � U o 0 o a c 'u � Q E (.j �"' ` � � V� a . V o `m �°� � m m `o �- � c •�• co d . F w � o≥ j o . . U LL t c o m o "' a N n o' ` c "Q W U L o m - c� m + s o c m �' E `. ir ii � � `� w O w "�' n � � w � o a� ^ � � m ae 4 m � _ � o o � � o ? y t m o > '+ � E � `y � � o (� N `� c a o E ` o o uo v o c . � � � : y 2 a a in E 3 o h �o m w •- m o c � m m m �n c � � � �- °'. � . d m 'E U _ U i.� 'o d u �� 'n'n'S. � ry c � Z �- p w W rA � m v � m m m � c o o O @ � � T � t Q U U U U C �� 0] U A ≤ � y II II II � � � Q a p� . : u o� ... ' LL ''� 'E . . > 'a . `m � oY c�'o � « o 0 0 ....'a' E � o � �:d Gc W Q �' `L" Oh u�i « � ` o 0 o ai x ° ?� U U m �o `o � � � ,E„ � 3 0 " w c �� m v � v y o .E a � v Q of d o m m t n F m c c a o 9 � c � m V . m � c E E m m � �n Q U � E v £ o F Q v o 3 m o � � £ U � C c N W C C w W y v > U � N II d G � fn R N O d N N v C N G. U O w Z � � O � Z � O �` � � w ` l0 N d N d � c � n LL C �. 4' O � R' � � � O `� � � � � m � U a, °1 w °� � U � � � . £ �� a O O .m y m � V . m y . . U U � _ a G U H U . APPENDIX B RBLC Information Summary Kerr McGee Gathering—Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B . . ...., Previous Page� . Report Date: 04/12/2012 INDEX OF CONTROL TECHNOLOGIES DETERMINATIONS NOTE:Drafr determinations are marked with a " *" beside the RBLC IA � � _ .. --- ' ____ _._ . -____ .__. .. _ ____. . . .. . __ ...._. ._ .._. .. Company Name �I'�" Country 1'ermit Process process Descrip[ion ID Date(Est/Act) Type . .._ __. .___.. ._..._ ... .. . . .— . — . O1'TUMWA . . _. _ ... . _ _..._. ---._..--:. GENERATINQ � � psp 01/12Y2012ACT I1.110 Boiler#1 � STATION � *IA-0101 . COGENERATION USA 12/06/2011 ACT 15210 COGENERATION TRAINS t-3 (i-10,2-]0,3-10) .. PLANT *LA-0256 � � . � . 17130 EMERGENCY GENERATOR � � SABINE PASS LNG USA 12/06/2011 ACT 15.200 Combined Cycle Retrigeration Compressor Turbines(8) TERMINAL *LA-0257 . � � 19390 WeUDry Gas Flares(4) . 19.390 Marine Flare � 50.999 Acid Gas Venis(4) . . � � 15.100 Simple Cycle Generation Turbines(2) � � � - 19.130 Generator Engi�es(2) � ' 15.700 Simple Cycle Refi�igeration Compressor Turbines(16) . 50.999 Fugitive Emissions � . � PORT DOLPHIN USA 12/0l/2017 ACT 99.999 Pugitive GHG emissions ENHRGY LLC "FL-0330 . � � � . 11310 Boilecs(4-278 mmbtu/hr eaeh) � . . 11310 Power Generator Engines(3) � ENI-HOLYCROSS . USA 10/27/20llACT 13.220 Boiler � � � DRILLING PROJ *FL-0328 � 17110 Emer enc�Fire Pum En ine � � g } p g . . 17.110 6mergencv Engine � � 17.110 Crane Engines(units 3 and 4) � I7.110 Crane Engines(units I and 2) � 17.110 Main Propulsion Engines � � 42.000 Storage Tanks � NINEMILE POINT � ELECTRIC GENERA LA-0254 USA 08/16/20ll ACT 17.110 EMERGENCY DIESEL GENERATOR � � , � � � 17210 EMERGENCY FIRE PUMP � 99.009 UNIT 6 COOLING TOWER � . 99.009 CHILLER COOLING TOWER(CHILL CT) � � ]1310 AUXILIARY BOILER(AUX-l) � �5 Z�Q COMBINED CYCLE TURBINE GENERATORS(UNITS 6A &6B) DIRECT REDUCTION 0l/27/2011 ACT 81900 DRI-101 DRI Unit#L Iron Oxide Da Bins Dust Cotleetion IRON PLANT ��LA-0248 USA Y 81290 DRI-111 -DRI Unit#1 Acid Gas Absmption Vent � � � 81.900 DRI-102 DRI Unit#I Iron Oxide Screen Dust Collection 81.900 DRI-202 DRI Unit#2 Iron Oxide Screen Dust Collection . � 81.900 � DRI-105 DRI Unit#1 Furnace Feed Conveyor Baghouse 81.900 DAI-205 DRI Unit#2 Furnace Feed Conveym�Saghouse 81.900 Dffi-]03 DRI Unit#1 Coating Bin Fitter . � S1.900 DRI-203 DRI Unit#2 Coating Bin Filiec . � 81.900 DRI-]04 DRI Unit#1 tron Oxide Fines Handling � � 81.900 DRI-204 DRI Unit#1 Iron Oxide Fines Handling . . 99.009 DRI-113-DRI Unit#I Process Water Cooling Tower � � 99.009 Dffi-213-DRI Unit#2 Process Water Cooling Tower . 99.009 DRI-7.14-DRI Unit#1 Qlean Water Cooling Tower � 99.009 DRI-214•DRI Unit#1 Clean Water Cooling Tower . 81290 DRI-ll7-B�iquetting Mill � � 99.190 DRI-ll 8-DRI Barge Loading Dock � � . � � 81290 DRI-ll 5-Product Screen Dust Collection � . � � 81.290 DRI-ll 6-Screened Product Transfer Dust Collection � � 81290 Dffi-]09-DRI Unit No. 1 Fumace D�st Collection 81290 DRI-207-DRI Unit No.2 ILrnace Dust Collection � � I1310 DRI-109-DRI Unit#1 Package Boiler Flue Stack 11310 DRI-209-DRI Unic#2 Peckage Boiler Flue Stack . . � 81290 DRI-112-DRI Unit No. 1 Product storage silo Dust Collection , � 81290 DRI-212-DRI Unit No.2 Product storage silo Dust Collection � . � �19390 DRI-210-DRI Unit No. I Hot Flare � � � 19.390 DRI-110-DRI Unit No. I.Hot Flare � � � 81200 DRI-208-DRI Uoit#2 Reformer Main Flue Stack . � � . 81.200 DRI-]0S-DRI Unit#1 Reformer Main Flue Stack . 81290 DRI-206-DRI Unit No.2 Upper Sea]Gas Vent � � � . � 81290 DRI-106-DRI UaitNo. 1 Upper Sea7 Gas Vent � � � � 81290 DRI-21 I -DRI Unit#1 Acid Gas Absorption Vent I . . 81.900 DRI-201 DRI Uoit#21co�Oxide Day Bins Dust Coflection - BASF FINA NAFTA � TX-0550 USA 02/10/2010 ACT 50.003 N-11;REACTOR REGENERATION EFPLUENT AEGION OLBFINS . � � � � 50.003 N-1Q CATALYST REGENERATION EFFLUENT . 50.003 N-18,DECOKING DRUM . . � . PRYOR PLANT pZ/Z3/2009 ACT 61�.999 COOLING TOWER#2 CHEMICAL OIG0I35 USA � � 61.012 PRIMARY REFORMER � � 62.014 NITRIC ACID PLANT#1 � � � 62.074 1VITRIC ACID PLANT#3 � 61999 CONDENSATE STEAM FLASH DRUM-AMMONIA PLT 4 � 61.999 COOLINGTOWER#1 � � � �13.310 NITffiC ACID PREHEATERS#1,#3,AND#4 � . 61.999 CARBON DIOXIDG VENT � 61.012 AMMONIUM MTRATE PLANTS#1 AND#2 � . 61.999 GRANULATOR SCRUBBERS#I,#2,AND#3 . � � 13.310 BOILERS#1 AND#2 . . . . � 62.014 NITRIC ACID PLANT#4 RUMPKE SANITARY 12/23/2008 ACT 29.900 ENCLOSED COMBUSTORS(4) � LANDFILL OH-0i30 USA . . . . � � � 29.900 � MLI]VICIPAL WASTE LANDFILL - . 29.900 OPEN FLARE � � � � � 99.150 PAVED ROADWAYS AND PARKING AREAS � � 29.900 CANDLESTICK FLARE.(5) � CPV ST CHARLES MD-0040 USA 11/12/2008 ACT 99.999 . COOLING TOWER � � � 17210 �TERNAL COMBUSTION ENGINE-EMERGENCY GENERATOR � � 17.210 ��'�AL COMBUSTION ENGINE-EMERGENCY FIRE . � � � � WATERPUMP � � � 13310 BOILER � � - 15.110 COMBUSTION�TURBINES(2) . � . . 13310 HEATER � ACTIVATED CARBON 0S/28/2008 ACT 11110 NRJLTIPLE HEARTH FURNACES/AFTERBURNERS � , FACILITY LA-0148 USA . � � . 99.009 COOLINGTOWERS ' . TWO(2)ELECTRIC ARC FURNACES�AND THREE(3) � 1ViJCOR DECATUR LLC ,q�,_0231 USA 06/12/2007 ACT 81.210 LADLE METALLURGY FURNACES WITH TWO(2) . , � MELTSHOP BAGAOUSES � � ' 133I0 VACWM DEGASSER BOILER . � 13310 GALVANIZING LINE FURNACE . � . � 81.290 VACWM DEGASSER �AIR PRODUCTS � � BAYTOWN I I TX-0481 USA 11/02/2004 ACT 99.999 PARTS WASHER . � . . � 50.007 FUGITNES(4) - . � � � � . 64.003 MSS PROCESS STEAM VENT � 64.003 PROCESS STEAM VENT . � 19.800 �EMEAGENCY GENERATOR TANK � 64.003 MSS-NONCONDENSIBLES(PROPYLENE VENTING) � � � � � 19.310 FLARE.(NORMAL OPERAI'ION) . � 64.003 RECTISOL VENT � � � -. � 19.800 EMERGENCY GENERATOR � . 42.005 DIESEL FUEL TANK � . . ' . 15.390 BOILER STACK(START UP). - � 17.390 BOILER STACK ffiGH BTUFUEL � . � ) 50.005 � COOLING TOWER . - 50.005 SUPPLEMENTARY COOLING TOWER . 11.390 BOILER STACK � � RUMPKE SANITARY � � 06/10/2004 ACT 29.900 PORTABLE TUB GRINDER LANDFILL,INC OH-0281 USA . . � � . � 29.900 LANFILLROADWAYS � . 29.900 LEACHATE STORAGE BASM . . � � 29.900 LEACHATE AERATION BASIN . � � � 29.900 FUGITIVH EMISSIONS FROM�LANDFILL AND GAS . � COLLECTIONSYSTBM � 17.210 PORTABLE CNGINE 4.68 MMBTU/H . � 29.900 NEW SOLID WASTE DISPOSAL WITH LANDFILL GAS � GENERATION � 17.210 PORTABLE ENGINE 0.58 MMBTU/H . � � � 29.900 LOAD-IN,LOAD-OUT,TURMNG,AND WIND EROSION � . 29.900 PORTABLE SCREENER 29.900 EXISTING SOLID WASTE DISPOSAL WITH LANDFILL _ � � � GAS GENERATION � � , Previous Page " � . �_.._ ........._.__.._f l �= e� � � j z, _ (<;��.�i,P s ��m x 's . . 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L Fort Lupton Gas Plant Lancaster Plant Heat Medium Fired Heater 1-4 . � Train 7 and Train 2 - � � Heater Data � � Make: Heat Medium HeaYer with Low NOx Burners l- \V�'1 Manufacturer: Sigma Thermal � � , � •� Model: HC2-50.0-H-SF ,`ti✓ r��,+ Description H-6051, H-6052, H-6053& H-6054 � . ..�:�'� ��- Heat Output 6Q.00 (MMBtu/hr) ;y Efficiency: 0.78 decimalL_ �' Heat Input: 76.9 (MMBtu/hr) �, � �•� Operation: 876O (hdyr) Fuel Heat Value: 1020 (Btu/scfl ,� � �� Emission Calculations Emission Factors Emissions Adjusted � Pollutant Source ib/MMscf Ib/MMscf" �b/MMBtu ,' Ib/hr ipy � } NOX manuf. 0,04 j 3.1 13.5 �/ �{ '� 1 CO manuf. 0.04 3.1 13.5 ✓ ,„�___.____� VOC AP-42 5.5 5.5 0.005 0.4 1.8 yr�� SOZ AP-42 0.6 0.6 0:001 0.05 0.20 r CHZO AP-a2 0.075 0.075 , 0.000 0.006 0.025 y� -�f"�. PM�o AP-42 1.9 1.9 � 0.002 0.14 0.63 ✓�,% � Benzene AP-42 0.0021 0.0021 ; 0.0000 0.0002 0:0007 v f 4 `� rGk-;�` E Toluene AP-42 0.0034 0.0034,� 0.0000 0.0003 0.0011 � !!d�: � R 'Emission factor cooversion based on footnote"a"of�qP-42 Table 1.4-1 to convert from "` � 1,020 Btu/scf to the above Fuel Heat Value in unit�of Btu/scf. / CO2e Emission Calculations / i Conversions ,� 1 Metric Ton = 2204.62 Ibs 1 kg=. . 0.001 metric t�s � � Pollutant kglmmbtu metrie ton tp . . � COZ 53.02 � �35,727 39,383 � '�� CHq 0.001 " 0.67 . 0J4 . � N2O 0.0001 ' Q07 0.07 � , COze= 39,421 � . . '''�.. � COze=COz+(CH,'21)+(NzO*310) �� i i ��-�� >> �� '@d'•�zv,�'�-��. �:�i��`��§r 1�`r w— ' _____-�"__�___ r�;�:��-,�. � `�:�� f � ��-Z� �t�� } � � � , . � ; , } t Y>�`t��+,� 1 1 ��hc.i m �� .��a�;.'��l __ ---�- � _ — —�-�— y � G��,�� y �,'e t� � ��`�( ._��ftuv�` y�; �� 64�tiV��1.�'�;./ y I \ Y . . . . ..__-_..___._. ......_._.__.__. . . W � � � ��, ti� ,. ,r\ �\� Fort Lupton Gas Plant ,> �� Lancaster Plant Mole Sieve Regeneration Gas F9eater 1 and 2 ,�� Train 1 and Train 2 ' _� Heater Data ' cY Make: Mole Sieve Pegeneration Gas Neater�ruith Ultra Low€��Ox Burners/ Manufacturer. ZEECO USA, LLC Model 35M Megafire AIRS ID: TBD Source ID E-2015 & E-2016 Heat Output 25A (MMBtu/hr) � �� Efficiency: 0.84 (decimal) Heat Input 29.8 (MMBtu/hr) Operation: 8760 (hdyr) Fuel Heat Value: 1020 (Btu/scfl �;" Emission Calculations / Emission Factors Emissions Pollutant Source Ib/MMscf Adjusted �b/MMBtu Ib/hr tpy Ib/MMscf NOx manuf. ,0.04 1.2 fi.2 ^ � { CO manuP. /0.040 1.2 5.2 � f � �e VOC manuf. i 0.019 0.6 2.5 +✓' �� PM�o manuf. 0.013 0:4 1.7 �f , SOZ AP-42 Q.6 0.6/ 0.001 0.02 0.08 v CHZO AP-42 0.075 0.0 5 0.000 0,002 0.010 .��' F Benzene AP-42 0.0021 Q<0021 0.0000 0.0001 0:0003 � Toluene AP-42 0:0034 ;�0.0034 0.0000 0.0001 O.ODO4'0�.± � � L�.Et��-- � ' Emission factor conversion based on footr�ote"a"of AP-42 Table 1.4-1 to convert from 1,020 Btu/scf to the above Fuel Heat Value in units of Btu/scf. /f;' � (�k:'—., .. CO2e Emission Calculations /� `�-� ' t" . � S � � �''s<<1�t"tv � �i��'��v�,-�-.�--�-- Conversions: � ----� t t ,� } 2t� '�1� 1 Metric Too= 2204.62 Ibs � (��r�,, � �� 1 �'1� I �� 1 kg = 0.001 (netric tons Pollutant kg/mmb4u metric tpY ' i ton! r COz 53.�2 � 13,823 15,237 �� CHq 0;001 0.26 0.29 NZO �0.0001 0.03 0.03 i / �%�ze= 15,252 COze=COZ+(CH4*21)+�NzO'310) � II j t3 } �� / { _��_�.V v__._._______--- �� 1 � ._ s�'_,.�� ---- ` �1�k'�, � ��, ! �1, it�7��R� � � ---� --� �[ `r`r y';�� !\4.. sf ��,�_1 �y �)�``y'::� il i�� _ _ _ _ ! �y � � �G•�.am�f.. C.�>> (L��'�ki�;w, t� `? ->: ':— Ir i '� . � �Fort Lupton Gas Plant . � Lancaster Ptant Amine Treater Vent Stack Emissions-Train 1 � Source ID A-1,A-2,A-3&A-4 . AIRS ID TB� � . � Source Description 150 MMSCFD Amine Treating System,Train 1 (2 each)and Train 2(2 each) Potential operation 87Go hrs/yr � . - � �� AmineSimulationResults(4/12M2) CO2e Emission Calculat(ons Acid Gas Rash Gas � Flowrate(MMscfd) 4.41� 0.t205 Conve(Sions � � Pressure(psig) 8 60 Molar Volume to Molar Mass 379.3 5cf/Ib-mole rem erature(°F) 1zo i5s � ' Camposition � � Mol% Mol% Ibllb-mole GHG Caiculation Acid Gas Flash Gas Nitrogen a.s5�E-o5 a�31 za.o� Polluf2nt SCf/yt t0ns/y! SCf/yf fons/yI CO2 91.390 1�.381 44 ' � � COz 1470992420 85319.89� 4.57E+06 265 Hytlrogen Sulfde 1.355E02 �tee0E-03 34.08 Methane i.349E-01 63.8677 16.04 . COie= 85,585 Elhane 3728E-02 11.9473 30.�7 �camwat'ionmemoaaomnPi2oo5cficcomoenaiums-�z Pmpane. 7327E-02 42115 44.1 'co,(�py)=�smyr]/�scmbmola7'�nnuv�lpesimn� n-Butane 7.359&03 1.59�3 56.12 � i-Bu[ane 2.�G0E-02 1.854 58.12 . � n-Pentane - 8.631E-04 02542 - 72.15 . VOC Emisslon Calculations i-Pentane 9.5]0E-04 02816 7215 � � n-Hexane= � 9,955E-04 02445 86.t7 ConVefSi0n5 Water 8.373E+00 5228 � Molar Volume to Molar Mass 379.3 scf/16-mole . ioiai � �oo.o mo.o VOC Calculation � Acid Gas Flash Gas � Pollutant scfl r tons/ r sct/ r tons/ r . i Pro ane 2.14E+p5 12 L85E+06 108 � � � n-Butane � 1.18E+05 9 7.03E+05 54 � � i-Butane 4.44E+05 34 8.15E+05 62 n-PenWne 1.39E+04 1 1.12E+05 11 . � i-Pentane 7.54E+04 1 124E+05 72 . n-Hexane 1.60E+a4 2 1.0BE+05 72 � ' . Uncontrolled VOC`1.1 Pactor = 350.6 �� VOC x 99%Control E�cienc 3.5 . � , . . . .._._...._..__.__. . . . ._.__.._.__.__._. . Fort Lupton Gas Plant - lancaster Plant Amine Trea[er Thermal Ozitlizer Emissians,Tmin 1 antl Train 2 . Saurce 10 A-T01,A-T02,A-T03,H-T04 AIRS ID TBD � Source Descnption Train i antl Train 2 Thermal Oxitlizer to Convol Amine Treater(A1-4) Potential operation a]6o hrs/yr . � �. '"stream will he routetl to emergency Flare when TO is tlown. � Combustion Emission Calculations Amine Simulation ResW[s(4112/12) � � Acid Gas PIasM1 Gas � Convelsions � Flowfate(MMscPo) 441� 0.1205 � ". MolarVolumetoMolarMass 37935cF/Ib-mole Pressure(psig) 8 80 �� Tempareiure(°P7 120 968 � �Aeatol qminesllllvent � ` Composl�ion Mul% f0a14'o Ibllp-mole � Cpmbustion eqtlflaehgae HeelConlent�� '� Campan¢nt �� Farmula '.'[Btullb] � [Ibili/J . [Blulhrj�� metM1ane CH4 21502 146.OB6G 3141153 Nihogen 865'IE-OS 0.13� 2801 . efiane C2Hfi 2�416 52.9853 1081]4P CO2 91.390 10.381 44 pmpane C3H6 19929 2]4193 54844� Htlmgen5Nfde t.355E-OZ 'ISBOE03 3408 �. � n-butane C4H10 19fi65 �43605 282400 Methane L349E-01 6386i1 16.04 �' . isobWane C4H10 18614 220340 4321]4 Eihane 3]28E-02 � t1.94i3 30.0] �. n-pentane CSH12 19499 2J294 53221 Pmpane 1.32�E-02 S21'IS 44.� isopenfane CSH12 18451 3D258 58855 n-Butane ].359E-03 'IS9]3 58.12 n-H�ane CfiH14 19200 32044 81525 i-6uYane 2]60E-02 1.854 58.12 �, Total(BtWhr)= 565'I51] n-Penfane 8.831&04 02542 �2.15 BW/scf= 30.0 i-Pentane 9.5]OE04 Q2818 �2d5 � n-Hexane � 9.955E04 02445 66.1J � Heatlnpuf � Water 83]3E+00 5228 TOBumerHeat fromAmineStill PvuliaryFuel TotalHeaHnput h5�y .� . Rating VentantlFlash Gas (MMBtWhr) . Total 100� 1000 M t IM1r Gas M 9Nlim B Whr ! 8.00 � 5] 3.00 16] 8]fi0 � l `Pollutaert Ib/MMsef IbIMMBtu Ib/hr �'.._., f` . � NOx �'100 0.10 1 fi3 Z9 " { � , CO . B4 �a:08 13� fi.6 ._.,t� . �I TOC '1� 0.01 _ � � � voc t.t oao ooz o.as � � PM10 1.9 1.88E-D3 0,�3 0.1 502 Ofi S.BBE-04 � O0'I OD � CH2O ��.0]5 ].35E-05 0.00 OA � � Benzene 0.0021 2.06E-06 �00 OD � � Toluene 0003 333E-06 0.00 OD � . I `AP-42 emission factors,Tables 1.4-1,1.4-2 antl'1.4-3 'Total emissions(ipyJ^1.1 factor . � �, 'HssumedVOC=10%wtofNel as � � '��. CO2eEmissionCalculations � � '�, Conversionr. � - � . '�. � 1MeVicTon= � 2204.82 Ibs � 1kg= 0.001 mehictons ' Pollutant k/mmbtu metrictonl r t . � COi 53.02 �,I3] 8,52821 � � . � cn, o.00i o.is o.�e � � � � N,o o.aooi o.m o.oz � - COz,= � 8,53] CO�,=COar(Cl42�I+N '3t0 ��. S02 Emisslan CelculeNons � , Conversions: � � � � MolallolumeroMolarMass 379.3 scf/Ib-mole � S02Aromic Wei ht 84.05 amu ' H2SAtomic Wei ht 34.08 amu . �. � Acitl Gas Coniml% � 95.00% �� Pollutant AcitlGas FlashGas � Ib/h� � t Ib/h� H25 2238E+pp � 9.801E+00 8.4B2E-a3 3715E-02 � � S02 �8.4 0.0] � , � UnconirolletlS02emissions(tpy)' 2034 � ' � CorRmlletl S02 emissions(tpyy � 1.02 � 'Total emissions`1.1 factor � ._ . . �. _ ....... . . _.._. ._. .. . . . .._. . .. .. . . __..__ ... .... ...._. ._. . . . � � � 0 0 0 � . . . � . L P r U . . LL d U N N - Q < p I m � e I LL I m P Q m 9 '� � O � m N O � � _ . C C `� ' O O Q V �. K � U � _ F � - Eo . .. � N N U LLO � � � � O G Y� y a K •� � y C W .. p v . .-. r j:r:.. �`� � O O � M CO C � E � a j � U N U . . . m. C � N . .+�'+ M O O O O O .o >° LL � « m -' % � o) v � i O � y! .V. • N � q i � a � q �,. 0 Q E _ a a II a ¢ .. o .,° � a . c a o v '�, o �N: �:.,.t_+ � � � � �i O � E 3 p v o 'y �a d o � � � C��. � �� c m E u. o s oi o rn v '""n � � a� W U c .�� rn oou�iN � m � . ° m �g � ' � m o' N � a i . > � a`�i ' - . � . � y U w U l6 L � p i+ a . � . .. N � 3 � - �. N:. , O. . ,. O C N .C , �?� � O O N O O � � II a .N 0 O y � a N O O O O O � � �+ = E ._ O 3 �, .- � ,3 o c � • °c E ! Q N �F P �O. . N � � . . �� N.'6�� . N « � y N C C � . '= N O_w O� E...C . W L a' . . � �p 7 0� �y �.N y. � M ,. � �X C G �y � ��` W � . � � � — � � �t � r O � O O > � w w m n � � N c � W U �.C�� O O m 00 � .Edrove � o - arvN � I Q � = O �.:�. _ � ` �. � L � U �.:. � p O � � N — � w � 0 � �.�� . �L' U y � 3 � � �' � � � � �{ � � t� " � wmwmwwmww w N� wo . 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Z � � � L "- � � J � — a� o o �v � O a , � � �O � .c m Q Cfl O � `� � K O � U d d W U ¢ v � � � c � � � fn '� Z ly L � ' a o 4 � M >, � c o g � Q � � c 'N N . . VJ � � `\ . � � O N p Z � � U W "O � O U N M Q-� .` io � . O N � L � � � 'V Q in �'�? � N � � � � � � .� � � � �' pp '..�pp N `-' � Q' `� T � � p p'. � c � ¢ . C � �� O O t+.�S N � � � i i � o N � 6) 6> `. U .N � � J . C 0 L � � � -a � 6) _. ....� W t6 � UI O Z � N N ��. � w � � � . � � � I� I� '--c.�� O . ¢ � d � 2 � Q y � � ..��:�'\ � U � W p � � � � C ,.p � '� `p-:.'.�,>,� ♦ � � � N ��p � � � W U,._ �1 .v vd N V 7 � � <i(n\ ,!;�:_ p � C� �"- � y Z Z iii y - . a- m � x � *°� (�p �. � c C f6 O ,� � O It � � J- t � �- d L� j N VU1 f i. `' �. c� � � V 'N 3 ~ G 1'�%';�`,'.. �/,,.% '� . � � � C N Q ,./l� � � . . � c� LLJ �- /' U c , J v ,.>.� %�''1 � 3 C ;S�� t'�Jj r+ A � � f^!� �'_" . C ai p � e ;,. ; 'Q , M � o Ydm. -O �J O o \� ��L., UJ � 6 i� �� .�_i _ fn � W j � -��\� � � ` O "6 ; � N ..,...'�.,� rl��, � � � � � Q � ,:� � � NO ..;�j�i � (p � U ..,'�ji � � � ' ...� � � C� � � � � ! >' N � � � _Y . � �3� _i� Q � .. � v � f6 � ,.�J•'`\ ..,,. / � A 'C Z � I�-% (4 � Q. � N C a�i m .�'��,�� O � �, � � /Q,�.� d' .�•...' ` 'D � L{.P i�I � C N l.l �. ��\ N � � � � � a � � . ii'�Y..\\ .O N � � � -C N ..i� .C ,N p � � �r � J v) E � �:•h. :-: � `o c�v � n N N Z X �l j\ M j� .-�-. v � — � c�i c c � o ; .� ° o ca Q � �s � � � � � '� p ., _� `, cv � >, � Y J -� -� L � /.� .\,� J � U U a= '•�' O) a> . � � � � � Qt� � N Q � Z � N f�6 y � � � ��., �'' � f6 C �. � � f6 O O N � ` V 0- L N � � � � Z :� U � �� s ln . �. Q fn � c � 3 T U O � c�i N E tCi � �� N J �' 'm � � J. C Q � �Z � C �i � "- �> � � N V ,� � 'C � � � � � � C N � (�j N � � p �� N � � � V� V C � � U Q. � I11 Q U h R�' (n � �Z ii '� /��'t° �� KemMeC¢eGatheringLLC � P.O.Bac 173779,Dprver,Colorado 802173779 . � 720�929-6000 Fax 7Z0.929-0000 April 17,2012 Ms. Stephanie Chaousy Air Pollution Control Division—Oil&Gas Team Colorado Department of Public Health and Environment �� 4300 Cherry Creek Drive South , Denver, CO 80246-1530 � �� `� _ . (.�`�'r��• ' � �: UPDATE-FacIlity 1bloditicatnon Applis�temn � ' 6`� Package#265059 Lancas4er PBant . We1d Coum4y,Cotorado Deaz Ms.Chaousy: On Nwember 29, 201 l, Ken-McGee Gathering LLC (KMG) submitted an appGcation requesting to add a 300 MMSCFD cryogenic plant to the Fort Lupton Gas Plant. KMC'i is requesting to modify that application by increasing the plant capacity to 600 MMSCFD and naming the facility the Lancaster Plant. As part of the project,KMG wil]permanently shut down e�sting compressors EU-31, EU-32 and EIJ-35 at the Fort Lupton Gas Plant. The Lancaster Plant will urilize four(4) 150 MMSCFD amine treaters to remove COZ from the inlet gas siream which will then be dehydrated with a molecular sieve. The amine will be regenerated with four (4) 60 MMSCFD heaf inedium heaters and the molecular sieve beds wi11 be regenerated with dry gas ' heated in two(2)25 MMSCFD gas heaters. The dry gas will be run through the cryogenic unit to remove natural gas liquids(NGLs)and then trnnsported offsite via a pipel'rne. Propane refrigeration compression ' will be driven by six (6) 2,750-hp electric drive motors: Residue gas will be compressed by fow (4) 12,000-hp electric drive motors and sent offsite via a pipeline. During routine plant maintenance activities and upsets, all gas will be sent to two(2)plant process ilares. ' In this updated facility modification application,KMG is requesting ta o Add four(4) 12,0D0-hp electric drive residue compressors. I • Add six(6)2,750-hp electric drive refrigeration compressors. ' • Add four(4) 150 MMSCFD each, amine h�ealment systems, two per treatment irain. Still vent and flash tank emissions from each amine wiil be controlled with a thermal oxiQizer. e Add four(4)60 MD�IBtu/hr amine regenerator heat medium heaters. • Add two(2J25 MMBtu/hr moleculaz sieve gas heater. ' • Add two(2)process flazes to handle plant maintenance actevities and upsets. • Add one (1) emergency 670-hp Caterpillaz diesel generator which will operate a maximum of 500 hrs/yr. • Add emission estimates of fugitive emissions from the cryogenic plant. Smce the plant will receive a mixture of third party gas from the Kerr-McGee gathering pipeline system, a representative sample of the streams is not currently available. A worst-case scenazio was ' utilized to estimate fugitive emissions. • Remove EU-35,a Fairbanks Morse MEP 10 1756-hp low pressure inlet compsessor. I� • Remove EU-31 and EU-32. These engines are both 5yaukesha L7042 954-hp low pressure inlet compressors. Uncontrolled potential emissions from the modification were above PSD significance thresholds for NOx, CO and VOC emissions and therefore, an actuat to potential emissions analysis was completed for fhese criteria pollutants. KMG determined NOx, CO and VOC actual emissions in ternts of an average rate in tons per year for Units 31, 32 and 35 using t]ie October 2009 to September 2011 consecufive twenty-four month period that precedes the project (Regulation 3, Part D, Section In. Potenria] emissions were assumed for the proposed equipment as per Regulation 3,Part D, Section II.A.l.a There are no contemporaneous increases or decreases included in the net emission increase catculation below because all emission decreases and increases within the last five years were retied upon by the Division in issuing permits under Regulation 3 (Regularion 3, Part D, Section II.A.26.c.) and will be in effect when this project emission change occurs. As shown in the table below, the proposed modificarion does not result in a significant net emission increase of criteria pollutants and is below all PSD significance thresholds and not considered a major modification for criteria pollutants. Leneaeter Plent Actual to Pol�Mlal PSD APpikabll�ty Celculadwy . . UNt ID Status Hr r NOu CO VOC 5O2 PM10 E-2015 � Mole Sieve Regeneration Gas Heater ADD 8760 52 5.2 2.5 0.1 1.7 E-2016 �� Mole Sieva Regeneration Gas Heater � ADD 8760 52 5.2 2.5 0.1 � 1.7 � H-6051 Heat Medium Heater with Low NOx Burners ADD 8780 13.5 13.5 1.8 02 0.6 � H-6�52 Heat Medium Heater with Low NOx Bumers ADD 8760 13.5 13.5 1.8 02 0.6 H-6053 � Heat Medium Heater with Low NOx Bumers � 'ADD 8760 13.5 13.5 1.8 0.2 D.6 '� H-6054 Heat Medium Heater with Low NOx Bumers ' ADD 8780 13.5 �13.5 1.8 02 0.6 �� a-� 150 MMSCFD Amine Treater(Controlled with ATO-1) qDD 8760 7.9 6.6 3.8 1.1 0.15 �� A-2 750 MMSCFD Amine Treater{Controlletl with ATO.2) � ADD 8760 7.g 8.6 3.6 7 9 0.15 A-3 150 MMSCFD Amine Treater(Controlled with ATO3) qDD 8760 7.9 6.6 3.6 1.1 � 0.15 � A-4 150 MMSCF�Amine Treater(Controlled with ATO-4) ADD 8760 7.9 6.6 3.6 1.1 0.15 �� . F-2 F-2 Laneaster Plant Process Plare 1 A�D 8760 � 7.3 14.6 1,6 0.03 F-3 F-3 Lancaster Plant Process Flare 2 ADD 8760 �� 7.3 14.6 1.6 0.03 - ��... GEN3 Caterpillar 670.hp Diesel Emergency Generator ADD 500 � �� FUG3 � 2.1 0.1 0.0 12 0,01 � � Plant Fugitives . AOD 8760 - EU35 Fairbanks Moree MEP/0 38D8750-15S1S 1756•h 30.5 ' - ' P REMOVE 8760 _5,y� .13.3 -12.0 -0.03 3.1 EU-31 � Waukesha L7042 954-hp REMOVE 8760 -18,2 -40.1 -72 -0.02 -0.3 � EU-32 � WaukeshaL7042954-hp REMOVE G760 -16.6 -36.6 -6.6 -0D2 -0.3 �� iotal Emissions from Motllflcation Project#3 23.7 30.2 34.5 6.4 2.7 ; � � PSD Significanee Threshold 40.0 700.0 40.0 40.0 15.0 �' An updated GHG BACT analysis reflecting the update in requested CO2e emissions can be found in Appendix J of the application. 2 _ _ __ ' Enclosed with this letter are the updated Kaizen application required forms and documentarion far the proposed modificarion. In addition, Appendix J contains the BACT analysis for the Greenhouse Gas PSD modification as required by the PSD and Title V Greenhouse Gas Tailoring Rule. If you have any quesrions, or require additional information, please contact me at (720) 929-6Q28 or Jennifer.Shea(a)�Anadazko.com 3incerely, � KERR-MCGEE GATHERING LLC . . �� '('`"l � � � . C� Jennifer L. Shea Staff EHS Representative Enclosures ec: Mike Ross,Matt Berghorn,Mike Forsyth,Jay Allin,I{evin Osif,Rob Smith,Mick Rafter and Troy Person 3 _ _ _ i �� c�-�oo� �� Colorado Department of Public Health and Environment " -r'" R`•. �y p Air Pollution Controi Division ='��.�* mfa s• C,�lora�m D�artme�ac Oal �a G�s I�c�ust� ��,��;,�� Con�traacteon Peran�t Appincatfon Co��leteness C'he��as� Ver. September22,2008 Compaay Name: Kerr-McGee Gathering LLC Soearce Na�►e: Lancaster Piant ��t�: 4/16/2012 Are you reqnesting a facility wide pernut for multiple emissions points? Z'es No In order to have a complete application,the following attachments must be provided,unless st�ated ❑ otherwise. If application is incomnlete. it will be returned to sender and filing fees will not be refunded Attaclnm�ent A ➢ic�tion Eleffient A APEN Filing Fees �PP��sant �CID � Air Pollutant Emission Notice(s) (APENs) & � � A lication s for Construction Permit(s —APCD F'oran Seraes 200 � � C' Emissions Calculations and Supporting Documentation � � BD Company Contact Information-Formn AFCI9-fl01 � � E Ambient Air Impact Analysis � � ❑ Check here if source emits only VOC(Attachment E not required) I F' Facility Emissions Inventory—�'ornt APC'gD-102 � � ❑ Check here if single emissions point source(Attachment F not requrred) � Process description, flow diagram and plot plan of emissions unit and/or '� facility � � ❑ Check here if single emissions point source(Attachwent G not required) Yi Operating&Maintenance (O&Ivn Plan—�CtD Farne Serees 300 � (� ! � Check here iftrue minor emissions source or application is for a general permit(Attachment H not required) I Regulatory Ai�alysis � ❑ � Check here to request APCD to complete regulatory analysis(Attachment I not requued) , Send Coffinlete Application to: Colorado Depart�ent mf Public Hemlth �i Emvflromenent � APCID-SS-Bl , 4300 C&�erry Creek II)rive Santh 1Denver, �odorado �0246-fl530 Check box if facility is an existing Title V soarce: � Send an additional application copy � Check box if refined modeling analysis included: ❑ Send an additionai application copy � � Page 1 Of t Form APCD-100-App CompieteCheck7ist.doc Attachmeffit 1� WGR Operating LP � � PAGE: 1 ot 1 � PO Box 193D � . Houston,TX 77251-1330 � DATE:April 10,2072 � TRACE NUMBER:742103390 � � CHECK NUMBER:742103390 � . AMOUNT PAID:$1,070.30 � � � � ACCOUNTS PAYABLE INQUIRIES:(800)370-9867 � � II��I,II��I,i�l„LIL�,,,II,LL�JJ„II,II�„iL��I�I�J �� 0DE4p IXS 6A 12301 - p442yp339p N0NNNNNNNNNN 1p151000�4W2 %392D1 ( � �� COLORADO DEPT OF PUBLIC HEALTH& - ENVIRONMENT = 4300 CHERRY CREEK DR S, APCD SS Bi �o �� DENVER CO 80246-1530 �� VENDOR NO:0003405436 . � � � � DOCUMEMtt �ENDOR INV#! � . � REMARKS �NVOIGEDATE TOTq� PRIORPtdB AMOUM &�ISCOUMS � N� 1900000150 CKRQ040512 pq/ps/qy AMOUNT FT.LUPTONCRVOGENICEPLANTPERMITqppLICATION $�'�7�'� $0.00 $�,070.30 TOTALu . � � . � . $1,076.30 $0.00 $1,070.30 PLEASE DEfAGH BEFORE OEPO.SfiING CHECK � � � �'� WGR Operating LP � � �i PO Box 7330 � � � CHECK � 74-72s2 .. Houston,TX77257•7330 � � NUMBER 742103390 �Z4 � April 10, 2092 PAY COLORADO DEPT OF PUBUC HEALTH& � TOTHE ENVIRONMENT � � '�� ORDER OF: 4300 CHERRY CREEK DR S,ppCD SS B1 �� DENVER, CO80246-1530 � � � � � . 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ZEECO USA, LLC Modei 35M Megafire AIRS ID: TBD Source ID E-2015&E-2016 Heat Output 25A (MMBtu/hr) Efficiency: 0.84 (decimal) Heat Input: 29.8 (MMBtu/hr) Operation: 876D (hrtyr) Fuel Heat Value: 1020 (Btu/sc� Emisslon Calculations Emissioo Factors Emissions Pollutant Source IblMMscf Adjusted �blMMBtu Ib/hr 4py Ib/MMscf* N�x manuf. 0.04 1.2 5.2 CO manut. 0.040 1.2 5.2 VOC manuf. 0.019 0.6 2.5 P�io manuf. 0.013 0,4 17 Saz AP-a2 0.6 -O.6 0.001 0.02 0.08 CH2O Ap.42 0.075 0.W5 0.000 0A02 0.010 Benzene AP-42 0.0021 0.0021 �.0000 0.0001 0.0q03 Toluene AP-42 0.0034 0.0034 0.0000 0:0001 0.0004 `Emission factor conversion based on footnote"a"of AR-42 Table 1.4-1 to conveR from 1,020 Btu/scf to the above Fuel Heat Value in units of Btulscf. CO2e Emission Calculations Conversions 1 Metric Ton= 2204.62 Ibs 1 kg= 0.001 metric tons Poilutant kgfmmbtu �� tpy toN r CO2 53A2 13,823 15,237 CHQ 0.001 0.26 0.29 NZO 0.00Q1 0.03 0.03 COta= 15,252 � � COia=COi+(CHe`21 } Nz0"310 Fort Lupton Cas Plant Lancaster Plant Heat AAedium Fired Heater 1-4 Treln 7 and Train 2 Heater Data Make: Heat Medium Heater with Low NOx Burners Manufacturer. Sigma Thermal Model: NC2-50.0-H-SF Description H-6051, H-8052, H-6053&H-6054 Heat Output 60.00 (MMBtulhr) E�ciency: 0.78 (decima� Heat Input: 78.9 (MMBtulhr) Operation: 8760 (hdyr) Fuel Heat Value: 1020 (Btu/sc� Emission CalculaHons Emission Factors Emissions Pollutant Source fb/MMscf Adjusted Ib/MMBfu Iblhr tpy Ib/MMscf` NOX manuf. 0.04 3.1 13.6 CO manuf. 0.04 3.1 13.5 VOC AP42 5.5 5S 0.005 0.4 9.8 SOZ AP-42 0.6 0.6 0.001 0.05 0.20 CHZO Ap-a2 0.075 0.075 0.000 0.Q06 0.025 PM�o Ap-42 1.9 1.9 0.002 0.94 0.63 Benzene AP-a2 0.0021 0.0027 0.00D0 0.00CD2 0.0007 Toluene AP-42 0.0034 0.0034 0.0000 � �U.0003 0.0011 � *Emission factor canversion based on footnote"a"of AP-42 Tabie 1.4-9 to convert from � � 1,020 Btu/scf to the above Fuel Heat Value in units of Btu/scF. CO2e Emiaaion Calculetions _ Conversions � 1 Metric Ton= 2204.62 Ibs 1 kg= 0.001 metric tons Pollutant k /mmbtu metric ton COZ 53.02 35,727 39,383 � � � CHQ 0.001 0.67� � Q.74 � . � � N2O 6.000'! 0.0? 0.07 � CO2e= 39,421 COz,=COz+(CHq*21 +(NzO`310) - Fok Lupton Gas.Plant I LaneasterPlaMAmineTreaterVentStackEmiasions-Tralnl Source ID A-1,A-2,A3&A-0 � AIRS ID � T8D � Source�escription 150 MMSCPD Amine Treating System,Train 7(2 each)antl T2in 2(2 each) � Potenlialoperedon 8780 _ hrsryr � � __ AmineSimulMion Resules(N7)112 . G02e Emiselon CnlGuletlons . . pritl Ges Flesh Gas . Flowrete MMstid � 4.47a Od205 Co Pressure( sig) 8 80 MoWNalumetoMolarMass 378.3 acNlbmole 7em arewre F /20 15B � � Com oaltlon MW46 Md% IbAb-mote �GHG Caleulation Acid Gas Flash Gas Nllrogen e.e5fE.05 0,137 26.01 . � pa��umnt eaNr tans�yr scflyr tonsryr coz e�.aso �o.ae� aa � COz 147098242� 65319.88 4.57E«OB 265 HytlrogmSulfitle 1,355E-02 7.BWE-03 34.08 Mefhane 1.309E-01 83.8671 16A4 ' COm= 88�688 Efhane 3728E-02 11.8473 30.W 'Celcuktlonmetl�otlfiomPPIZ008GHGCompeNlum&12 Pm ane �.927E-02 42115 44.1 ¢o,�py)•�e�rry�7i[scw,nwmi��uw7ipesno�l n-Butane 7.35B603 1.5973 58.72 � i-Bulene � 2JBaE-02 7.854 56d2 � � rvPenlane 8.637E-Oq 02542 7ZA5 I VOC Emledon Celculatlone � I-Peniane 9.570EA4 0.2878 72db rvHa�na 9.955E-04 0.?A45 86.77 ConvelBiOne � Water 8.373E+p0 5228 . . Moler Volume to Molar Masa .. 379.3 scF/lb-rtro�a 7otal too.o 1D0A � � V ��. Acid Gas � Flash Gas � . � PaIlWarrt . sd r ton r sd r tone!r � . Pro ene 2.74E+05 12 1.SSE+o6 708 � � rFButanE 1.18E+05 9 7.03E+05 54 i-Butene 4.44E+05 34 8.15E+05 82 - n-Penfane 1.3eE+04 1 1.12E+05 11 � � � i-Penhane 1.54E+pq 1 1,2qE+05 12 � � n-Hexarie 1.BOE+pq 2 1.08E+05 12 � Uncontrolled VOC•7.7 Fector = 960.6 � � VOC x 98°/Control EHiclen 3,6 f� � FOM1 Wq�Ges PIaM . Lanwte��dIa�RAmina lTeatx Thetmal OAtlize�Emfssione,Trsln t and Trein 2 So�aCe 10 y A-T01,hT02,A-T03,MT09 � � �AIR510 �, ' TBD � � ' � Soume Des�;ption. Trein 1 antl Traln 2 Tharmal Optlaer lo ConVol Amine Treater(A1-4) � � Poten691 ope tlOn 8790 � hrs/yr . ^siream wN routed to eme�gencyflere when TO is tlown. � � � : CanbusfbnEm�aalonGl¢ul�liom AmlrieSlmulaHonResWts M1Y112 . . Nutl Gas Flash Gas Converalons, flvwrete MMscFtl) 4AW 0.1205 MalarVolume � MWarMass � 379.3 5eFM-mola Preuure si B BO ' � Te ereWre ° 920 156 . e P�� 5� � +� c� i i. yr At �R h; x r � �� *�. . � v �'�t i a� 1� t�lan s�ry� h �.. �'' �"� �`:� Gamppallon Mol% M1bl% IbMrmoia � �I�f�� a � � � '� s _ meNerre �� CH4 21W2 148.0886 � 319'1153 � NIW en 8.851E-05 0.131 28.01 � eNane C2Hfi � 20018 52.eB53 t081)9] CO2 81.980 10.381 44 propene C3H8 �� 19828 2Za193 548440 H tlm en SulFde t.365602 7.880E-09 3a.08 � o-bWene C4Ht0 19685 14.3895 282400 Methane 1.34BE-01 03.8971 18.04 Imbufene C4N10 1Bfi14 22.0340 432tT4 ENena 3.128E02 -N.84]3 300] � � n-penNne C5H12 '19488 2]294 53221 Pro ena 1.327Et12 42115 C44 isopentane -C5H12 19451 3.d258 688fi5 mButane ].358E-03 15W3 58.12 o-HaNaria � CBHi4 � 1920� 320W 81525 4Bute� 2.]BOE-OZ 1.&54 58.12 F Tote1�BtWhp= 565/517 mPen ne 8.831E-04 02542 92d5 BhilsG= 30a I-Pentene BSlOE-09 02819 ]2]5 mHesana 8.955E-04 024d5 BBA1 Heffiinpuf Water 8.3]3E00 5228 � TOBumerHeat hamAml�Stlll AuidllaryFuel To1alHeetlnP� � hrs/yr � Retlrtp VententlFlesM1 `Ga¢ (MM6hJhr) Totel '1000 100.0 ,0p 6] 3.0 18.] BJBD PallutaM IbIMMacf IbIMM91u Iblhr N� 100 . 0.10 \ 1.83 ].9' CO B4 0.08 1.31 e.6 � . TOC N 0.01 � � 14 O.W oA2 O.OB . � PM10 ib 'Id9E-W �.�3 Od � � . � S02 0.8 S.BBE-04 0.�i OD � CH2O 0.075 ].36E-05- 0.00 OD � Bave�re 0.0021 2.OBE-0e .o0 0.0 Tduaix 0.003 333E-a8 0. 0 OA . \ . 'AP-02 emiaelon faMrs,Teblas 1.41,1.4-2 entl 1.43 'TINelemiselore(�YJ"111ector �.�Y . . �AssumetlVOC=10%wtofNel as � �� . CO7eEmiubnCtlaWWam � � , � Conwnlons: � �� 0�1 . iMeMCTon= 2204.62 Ibs ` � ikg= O.OOt. maiticbns 4� � � i+ Pa11Wirt k mmblu mebiela � t � COi 53.02 ],T3] 6,52B21 � � CHq O.Wt 0.15 048 � � Ny0 0.0001 O.Ot 0.02 co„m e,sa� � c =c ,c rz,. m . . 802 Emi{tlen GIeW�tlent � O 1!� 6' Molar Valume b MolarMew 379.3 scf/Ib-fnOk � � Shc Atamic Wei M 6l.U5 am� . \ , H25Aromic Wei ht 34.00 emu �s� � AGtl Ga¢COMioI%� 85.00% +++;;; pa�� Acid Ges . Flash Das l� . � IWhr t IWhr � H25 2238E+00 9.801EW0 8.482E-03 3.�15E-02 502 18.4 0.0'! � Unwfrtrolletlso2emise'rona(ipy)• Eo.34 . � � Coribdkd 502 emiubns(qyp 1.02 . . *Totel emissions'1.1 factor � Fort Wpton Gas Plant � � . � Len[aste�Plan[AmineTreete�The�malOzitlizerEmi5sions,Trein1antlTrain2 ' Soume ID F-T01.A-T02,A-T03,A-T04 . AIftSID TBD . SowceDescnption Train'IantlTaln2ThertnalOxi<IizermControlAmineTreater(Hi-4) � Potential operation B]60 � hrstyr � . "stream will be routetl to emergency flare when TO is tlown. � - �CombusllonEml¢sionGalculollona - � AmineSimalafionResults 4N&12� . AcitlGas RashGas � Gonve5io�5 � Flow�ate(MMscfd) 4410 0.12�5 � MolarVolumetoMola�Mass 37935Cfllb-mole � Pressure psig) 8 6� � TemperaWre(°F� 12� � 156 � . Heatof Aminestlllvent Compositlon �Mol%�� Mol%. Ibllb-mole � �� Combuation �antliloehgae .�HcotContenL�� . � ��CamPonont -�. Farmule �i . (BIWIbI ' Ilblh�7 :� � �BNIhQ, ... . . . . me�hane CH4 21502 t4fi.O8fi6 3141153 Nitmgen 8,651E-05 O.i31 2801 � e�hane C2H6 20416 529853 1081]4] CO2 91390 10.381 44 � propane C3H8 19929 2].9193 54fi440 HydmgenSWFlde 1355E-02 1.BBOE-03 34oe . . �� n-butene C4H10 19fi65 143605 2ffi400 Methane 1349E-01 63.86]i 16.04� � � isobutane C4H10 19614 220340 4321]4 E�hane 3]28E-02 11:94]3 30.01 n-pentrne C5H12 19499 ?]294 53221 Pmpane 1.32]EA2 42115 44A isopeNane C5H12 19451 30258 58855 n-Butane Z359E-�3 iS9]3 58.12 n-Hexane CfiH14 19200 52044 61525 i-Bufane 2.�60602 � 1.854 SBd2 Total(BWlhr)= 565]51]� n-Penfane 8631E-04 02542 � 92.15 � Blulscf= 30.0 i-Pen�ane 9.5I�E04 02818 ]2.15 � � n-Hexane 9.955E-0? 02445 86.P � � Heatlnput Water 8.31aE+oo 5228 � TOBumarHeat fromAmineStill AuxiliaryFuel TotalNeaflnpu[ ry5tyr Ra[in8 VentantlPlasM1 Gas (MMB1u1hQ Total 1�0.0 i000 . (MMBtWM1r) Gas(MMB[Whr) (MMBWIM1r) . 8.00 � 5] 300 ifi] 8]fi� Pollufenf IbIMMstl IbIMMBtu IbIM1r mnl r' � . NOx 100 O40 1.63 � ]9 CO 84 � 0.08 1.3] 68 TOC 11 0.01 � VOC 1d 0.0a 0.02 0.09 � PMi� 1.9 � 19fiE-03 0.03 0.1 � � S02 0.8 S.BBEA4 0.01 0.0 � CH2O �0]5 ]35E-05� 0 QO 0.0 � Benzene 0.0021 2.06E-06 0.00 0.0 � . Toluena 0.003 333E-06 0.00 OA . � `AP-02 emission facrors,Tables 14-1,1.42 and 1.0.3 � . � 'Total emissions(ipy)'14 tactor � � � � � 'AsaumetlVOC=1a°/awlofPoel a W]o Emivalon Colculation¢ � Convers 1 MefncTon= 2204.62 Ibs . � 1kg= � O.ODt metnctans - � � PolWlent k Immblu meMcton/r 1 - � COy 53A2 ],93] 8,52821 CFia 0.001 0.15 096 ' � Nz0 o.aoof O.Ot o.02 GOz,= B,5]] � � co.=oo,.�cH,rz��-�u,oam � � . � 902EmieelonColculutlon¢ Conve�sio s . � � � Molar Volume to Molar Mass 379.3 5dlib-mole 502 A�omic Wei ht 64A5 amu � H25 Atomic Wei ht 30.a8 amu � " Acitl Gas Control% 95.00% � . � Unconholletl AcitlGas FlashGas i Pollutent � Ib/M1r t Iblhr t '�� H2S 2238E+OD 9B�1E+0� BA92E-03 3.]i5EA2 . � . . 502 18.4 0.0] . . UnconimlletlH25emissionfac�orlblMMsc " � OAO ❑ncanirolled H25 emissions t 10.82 � � i Umm�tmlletl50Pemissionfadorlb/MMs ' � 0.94 ' . I. ConVOlletlS02amissiore(ipy)' 1.02 � � 'Tatel emissions'1.1 hdor � � Fort Lupton Gas Plant F-2 and F-3 Lancastee Plant Process Flare 7 and 2 Source ID Number F-2 and F-3 SCC AIRS ID Unknown Source Location Zone: Source Description Flare Horizontal: Flare Make Unknown Potential Operation 8760 hrlyr Flare Model Potential Fuei Usage 10.5 MMscf/yr Serial Number Date in Service Stack Height 40 ft Flare Conflguration Air-Assisted Stack Diameter 30 in Fuel Heating Value 1020 Btu/scf Exit Velocity 60.0 ft/s Flare Pilot Rating 0.5 MMBtu/hr Exit Temperature 1000 deg F Flare Purge Gas Rate 707 scflhr Volume Flow Rate 77,671 ft'/mi� Purge Gas Heat Rate 0721 MMBtWhr Process Gas to Flare 75.0 MMscf/yr Process Gas Heating Value 1275.0 Btu/scf Process Gas Heat Rate 10.9 MMBtu/hr °k VOC Content of Process Gas 22A Cornbuatlon Emission Calculations Heat lroput h�s�� ' AAMBtWhr ' 12.14 8760 Pollutant IbtMMBtu' Ib/hr toed r NOx 0.138 L67 7.3 CO 028 3.34 14.6 VOC �.D3 0.37 1.6 NOx antl CO emleaion fadors fram TCEq . � .�Used AP-42 THC emission Fador of o.141b/MMBtu"%VOC Coment oi gas � CO2e Emission Calculationa Conversions: 1 MetricTon = 2204.62 Ibs - � . 1 kg= 0.001 metrictons Pollutant k /mmbtu metric 4on COZ 53A2 5,637 149.44 CH4 0.001 0.11 0.00 NZO 0.0001 0.01 0.00 CO�= 150 CO a=COz'(CHa'21)+(N O*310) � � . 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Source ID Number GEN3 Source Description Lancaster Plant Diasel-Powered Standby Generator Engine Engine Usage Power Emergency Generator EPA Tier 2 Engine Make Caterpillar Potential operation 5�0 hdyr Engine Model C15 ATAAC Diesel Gen Displacement 1.27 L/cyl Serial Number TBD Potential fuel usage 18300 Gallyr Manufacture Date T8D 38.6 Gal/hr Date in Service TBD Stack ID CEN3 Maximum Rating 670 BHP Stack Height 10 ft Fuel Heating Value 18,390 BtuAb Stack Diameter 0.67 ft Heat Rate 4.77 MMBtu/hr Exit Velocity 181.8 fNs Engine Heat Rate 7t 10 Btu/hp-hr Exit Temperature 942 deg F Engine Heat Rate 0.39 Ib/hp-hr Volume Flow Rate 3,842 ft'(min PTE Emissions Emission Factor Rating Operating Estimated Emissions Source of Emission Poliutant Hrs pb/MMBtu) (g/hp-hr) (h ) (hrs/yr) (Ib/hr) (tpy) factor NOx 1 JS 574 670 500 8.48 2.12 Manuf, �ata CO 0.12 0.40 670 500 0.59 0.15 Manuf.Data VOC 0,00 0.01 670 500 0:01 0.00 Manuf.Data SOx 1.01 326 670 500 4:81 120 AP-42,Table 3.4-1 PM10 0.01 0.035 670 500 0.05 0.01 Manuf.Data PPA2.5 0.10 0.32 670 500 0.48 0.12 AP-42,Table 3.4-1 HAPs HCHO 7.89E-05 0.00025 670 500 0.00 0.00 AP-42, Table 3.4-3 Benzene 7.76E-04 0.00250 670 500 0.004 0.00 AP-42,Tabie 3.4-3 Acrolein 7.8SE-06 0.00003 670 500 0.000 0.00 AP-42,Table 3.43 Acetaldehyde 2.52E-05 0.00008 870 500 0.000 0.00 AP-42,Table 3.4-3 Propylene 2.79E-03 0.00900 670 � 500 0.013 0.00 AP-42,Table 3.4-3 . . r �{� &�8$ � DowConiidentlal Simulat6on Suenmary New Anadaeko Cryogenic Ptant Inlet Streams staeatiuo � 36ream Nema B/L Feetl Gas . InIN Block B!L P Caae . Tam 2Nre tla F 110.OOW . � . Pneeurt Pal 953.OOW � Ve IFrectlon % 'IOD.WOo FlovrtOte � IWhf 3.Bfi06E+0.5 VolumeFlow LI ul U aNnin VDIumeFloW a MMSCFO F i6�.WW . Wehr mol% 1.W52E-U2 � � � � Ueusol AP�814 tl mol% O.W W � CertonDioltltla mal% 2.88W - H ro en 5ulfltle mol Yo � NI moi'b 0.4000 MBihmB mol% 14.5817 . EMana moi°b 12.89W . Vm ene mol°6 5.5]94 � n.BWne mal% t7BBB � .. ' Iso�ButanN mol°L �.9888 n-Panlena moi% 0 0� Iw-Penteno' mol% 0.6088 n-Nezene mai% 9.A500 � � � . TOTAL mol% 100.ODOD � Outlet Streams smenM.m . e e n . � . � SbeamNnme � FI85hGe5 Abtl BS � � Oulbt Blak CO2 Flash Oea Aatl Oea Tr Gae fo Dehy Tem rature tl P 158. BO t2DA0W 120.7002 . Pi¢anure Pat . BO.OOW BA000 &14204t . Va rFrOEtlon � % 1W.OOOp 1W.OOW 1C0.0000 � FlovMte Ibi�t 315.4864 2.023]Et04 3.4589E+p5 � VolumeFleW LI Ultl U8 aVmin � VolumeFlow e o MM8CP0 OF Od2a6 4.40BB 146d444 � Wata� mot% 52280 8.3'!31 02155 . . UeanolAP-Bt4 d mol%. 5.8801E-04 'I.B263E-0S 10p2BEA4 � Cu1wn01oalaa mol% � 70.38t3 81.3800 4.�4]2E-03 . � X mqanSulflda moi9: � 7.BBIXlEAS t.9559E-02 B.teetE-OB . NHro en mai% 0.1305 B.&5NE-05 0.4100 � MeNma mol°6 83.8671 0.1348 78.4928 � Hhena mo1 Ne fl.94]3 3.]2]BE-02 12.99t4 � � Pro aire mol% 2t1 1.32 -02 57P27 � rvBWM mal% 1.5873 7.a5BeE-03 1.8355 . � Iso-Bubne' mol% 1.8640 2.7688E-02 0.8805 - � �tPmlane mml% 02542 8.8314E-04 0:4]78 IeaPenFanC ' mal% o.Zaie 9.56B9EU4 0.5231 � ' � n-Nezene mml% 02445 8,8548E-04 0.4816 � TOTAL mo194 iW.00W 100.OOW 100.OOW . The Dow Chemlwl Comparry Ges Treatlng Teehnology Group - � . � Copyrlght�2002•2070,The Dow Chemical Compafty � � ProComp Process Simulalor Verslon 6.1.1.2 12 Apr 2012,Page 3l15 . _. . . m 090 &��5 DowConfideMial Pumos.Comoressors.Turbines Exoandevs Amine Booster Pump(PUMP)Power.� 222907 HP � Amine Circ Pump(PUMP)Power: 466J440 HP � . Heat Exchanaers Lean Amine Cooler(HEATER)Duty: -17.8106 MMBiWhr � . Tr Gas Cooler(HEATER)Duty: . �4.2045 MMBtWhr - L!R Amine Exchanger(HFATX)Duty: 17.0821 MMBiWhr � � Flashd(FIASH)Dury: 0.0000 MMBtu/hr � � Inlet Fitt/Coaiescer(FLASH)Duty: . 0.0000 MMBtWhr � � � Rich Amine Flash Tank(fLASH)Duty: � 0.0000 MMB1Whr Regenerator(CONDENSER)Outy: -5.549� MMBtu/hr � � � Regeneretor(REBOILER)�uty: 30.3750 MMBtWhr � � � Absorber(COLUMNI . ��Lean Soivenf Siream ID: 4(Lean to Abs) . TempereNre: � 1277883 tleg F � Flowrate: . 3.0316E+05 IbPor SOlvent Strengih: 45.1858%-masslmass � Acid Gas Loading: 2.3041E-02 mol/mal Rich Solverrt Stream ID: . 5(Rlch Am) � � .. � � Acitl Gas Loatling: 0.3864 mol/mol � Reaenerator(COLUMM Rich SoNent Stream ID: � 8(Hot Rich ta Str) � � Tempereture: 270.0000 deg F � � � �� Flowrate: 3.22WE+0516/hr . � '� Solveni Strengih: 452760%-masslmass � � � Acid Gas Loading: 0.3853 mollmol - Lean Solvent SYream ID: � �10(Ln from SV) � Acid Gas Loading: 2.3043E-02 moVmol � Reboller Pressure: � 147570 Psi(g) � � Reflmc Flowrate: 4885.3211 Ib/hr . The Dow Chemical Company Ges TrsaNng Teehnology Gmup � Copydght O 2002�2010,.The Dow Chemieal Company � . . � ProComp Proeess Simulator Verslon 8.7.L2 - 72 Apr 2012,Page 4/15 � '��, ..___ _ .. .___—_ .. _ . . . . � ! ' SulfaTreat-A Business Unit of M-I L.L.C.-17998 ChesleAleld Airport Road-Suite 275-Chesterfleld-Missouri•63005-USA � Tel:638-532-2189-Toll Free:600-726-7887-Fax:838-532-2784-Info@sulfafreat.com � DATE:Apr03,2�12 � SULFATREAT ESTIMATED PERFORPAA1dCE^sHEET('EPS') � CUSTOMERINFORMATION Company: ANADARKO PE7ROLEUM CORP� . Lease Name: Ft.Lupton Amine Gas � . Contacl: � � Lease Cify: Unknown Phone: Lease Slata: ND Pax: Lease Country: United States � OPERATIPIG CONDITIONS Gas Flow RMe(MMSef/day): - 4R � � Gas Pressure(pslg�: 6.0 InIatH26(ppm�: � t0t� GesTemperature(F): 120.0 Max.OutletH23lPPm�; 4.0 Water3aturetion: 100% CO2(Mole hJ: 97.0 O2(Mole%): � 0.�0 � REACTOR INFORMATION AND CONFIGIIRATION � Total Number Of Vessets: 3 Inslde Diamete�Qn�: 144A � � Sysfem Deslgn: Parallel Bad Haight(H�: 16.7 � � Estimated Presaure Drop(psli: 3.93 Mln.S/5 Helgh4(fl): 20.7 � � Vessel Loading pbs): 732,000.L` PREDICTED RESULTS � PRICE ESTIAAATES Days to Nlax.Outlat H2S: 9Q7 � Product Selection: SulfaTreet CHP Sulfur Removed(ibs): �36,230 � Prodoct Price(USDI 16J: . 0.50 Sulfur Removed(Ibs/day): 39.9 Product CostNessel(USU): 66,000 . C�es Volume Produced(MMScf): 3990.92 CostlNlcf(USD): 0.0496 � Ges Velocity(fr/min): � 625 � Cost/Ib Suifur Removed(USD): 5.47 NOTES&SPECIAL CONDITIONS Application County: . Weld ContaM EmaiL• � � ASK ABOUT OUR PRODUCT WARRANTY . Any Questions?Call The SulfaTreat Campany 800-726-7687 ar 636-532-2189 �� y a m p B � p � � a � �� , � w ` � $ ��' �� e� . kk y� � 88� Q � �+� � o � a� s � `.' �`m�C�3 ��a k '��` w� m o�� a °u' .. . .� �.�. . ti,�i C �� W ��o �� pq�?UCI q Nb n � t'1 °�O4�i��bN ~cQ` x I�lOO.��S1Tlia N � q � t 0�3NO�C . 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Horizonta!lvFrea 23 k � ?�?np �p� '.. Pflof Deslgn: 2a Atomizing Meo're -•�� TyA� ••� Continuous Seif•Insnlratlna 2s Atom. Media P& T . �" Model ��- bY O.E.M, � IgnRlon --- Electr�c reauires slec iqn system 27 Componenis: � � - Neai ftelease•• �>gD,000 BTU/hr on.. Des14n RFG � zs N wt% 29 S "'� BurnerPerlormance: Modei 1 Model2 3tl '��' wt� - MlnimumHeatAelease MMBTU/hi 1.75 �or] g� N� �m Design Hea4 ftetsase MMBTU/hr 7.10 (0r 32 Va ppm -- MaximumNeatflelease MM6TUfhr 8.75 (Ot aa Na ppm ' BumerTumdown Maz:Mtn 5.00 (oij 3a Fe ppm �� UolumetriCMt. Release BTUIhrft3 f3.f40 (Ot g5 • DtalT�AfCh� � itlH2O Q70 [07 ��. 36 H2 mol% d.00 Dra/t�9umer �nN20 5.7A j01J ' 37 OZ mo1� 0.00 Combustion Air T�Bumer F 60 ss N2+Ar ma% 0.20 FlueGasT(s�8urner °F 1,49d �� (ot 39 CO mo!% 0,pp ao Cp2 mo�% 3.60 - Guaraneeed Emisalans: c-.Gbmbined—� ' a� CH4 mo1% 94.2& � gasls of Gua2ntee •-- 3.0',6 O2,dry(LHV) 42 C2N6 mof% 1,40 � NQrEmissions Lb/MMBTU 0.. 040 33pPIR jpf � 43 C2H4 mo!! 0.00 �� SOx EmiSSjpnS Lb/MMBTU n0 ouofe (Oi � . 44 C3H8 mol% 0.94 CDEm1SStO�S � Lb/MM&TU 0.Q40 500Aro (p} ' 45 C9HS ma!% 0.00 UHCEmissions !.b/MM87V p,Qp7 15ppm Ipi 48 C4HYQ � molq 0.04 � � VOCF_lp15si0R5 !6/MMBTU p.0f& . 15Dnm j0Y I� 47 C4H8 mn!% 0.00 - SPMYOEmiSsipnS Lb/MMBTU 0.013 i4Aprrt (pi 48 C5H72 mo!% 0.0a - Nolse Emissions dsa �3k 85.0 ...� qa C5N10 mo�% 0.00 ' 59 C6-r mo(k o.00 - Combust/on System Features: � � � 57 H2S moi% 0.05 - BMS Functions Yer per NFFA w/EESLP Unarades � � ez 3O2 mo1% 0.00 - Comb. Cantro/s Ye via rell I coniro/ot Cri DMPR&F TCV ' 5a NM3 mot� 0.00 Dury Contro/s Yes: vie sonventiena!atO contro�of utiet 7' 64 H2O mol% 0,07 � Main�&Piht Tra6_Yes,per931.3&NFPA w/EESLP Unarades � �' 55 spare mot% 0.00 - CocalPane! Yes, NEMA4Xvr/EESLPU qrades �� 6 � FD System Yes One Ch�caao 8lower fan or tech eourualeni 67 Cteere»CBB: � FiringTest �NafRBAu�rBd � 5e ...tcr Gas F(ringi Yenc�a! Hartzonfal 5s ...from bumer CL... per TH!Aeslan per THI DAsion F/re6ox Size i f'0"Hx i f'0"W x 24•t"1 � [Dy �� 6a ro Tu6e CL,APl ![ 5.53 3.65 Note:H& are based on tuba centeilines j0 r I 61 f0 rUbe CL, CalC. R 4.50 4.50 ESt.Flame S1ZB 2'3 Dlemetetx tT0"LOn �pf sz tp Relrac.,cale, R n/a 24.0B Met C(earance 3'4"NBT_Tube leerance M Hor c�Vert pl na tOt I 83 NetGearance 7'D NE ReiractorvGlearanceinAxialvtane (0t 64 A144ERICAN ENGINEERING SYSTEM of UNJTS F/RED HEATER ppTA SNEET � TULSA HE/4TERS INC� P>2-7934-HTRds-Rev.07 Paga 2 at 9 ! I� � � ,�B' 7' -M D . i .N IDATA Th�emN Fluid S em Dat��eeg CustomerNome MadarkaAetroleum pro'ecrNnme � � / . . LantasteYPlanf 0ote[ampleted March1,2012 V101e«Lorotion � We(dCoun[gCO � Rerlslonnumber A SolesEngineer ChadfeWadlingron HeatlnpuT 48 MMBN/1�� HCaterModelNumber . HC2-50.0-H-SF � HeaterType . H[2 HeaterConflguratlan Horizontal � SystemFlowNate 3,000 galJmin. FluitlPre55ure0rop � 25 Ib/in'�d) HeaterFlowRate 3,000 � gal/min. FlueGasGressureDrop 3.8 inW.C. SystemBypass U � ga1/min. AverageHeatFlux � 8,969 Htu/hr/ft2 Heatereypass 0 gai/min. RadianLZoneHeatFlux � 23,6H6 Btu/hr/k2 ThermaiFluid � ParathermHR MaxlmumFllmTemperature ,451 °F � Process5upplyTemperature 360 •F InnerCoilVelocity � 11 RJsec Heater0utle[Temperature 360 'F buterCoilVelacity 6 ft/sec ProcessReturnTemp¢reture 292, °F � ThermalEKciencV 88% %LHVBasis HeaterCOIIDe5ignTemperature 750 •F HeatzrCoilDesl�Pressure 250 Ib/in�(g} PoelType � Gas Selected8ufnerMake Maxon . Com6ustlonpirPreheat . No 9umerModel5elected KineCimrLE�16 EfficlencywithPreheat � N/A %LNVBasis SteadyStateFlringRate(HHVBasisj � 60,069,285 Btu)hr OxygenTrim N� 9umer�e5ignMa�gin 10% FullyMetered/CmssLimited No � DesignFiringRate(HHVBasis) 66,070,]13 8tu/ht lowNOxREqui�ed Yes GombustlonNr�esignTemperature 60 "f BMSiype � .Sxandard AvailableFuelPressureFmmCustomer ia 16/in°(g) CombustlonContralType � Stantlartl De5lgnFuelFlowRate 65,200 (std�h'/hr � [ontmlPanelLocation SkldMaunted MlnimumFiringRate 3.75 MMeTU/hr . NOu.Required�ifany) � . � 33� ppm FuelTninLocation � . Skid Mounted CORequlredQfany) 349 ppm Fuelttain/BMSCodeCompliance NFPq8Jd1 GasConsump8on@SLeady5tate 59,272 (std)ft'/hr fuelTrain5ize Z �� Ai�Bonsumption@SteadVState � 9,323 (act�k'/min FuelbainType 5igmaThermal5tandard GasConsumptfon@HighFire 65,200 (std)k'/ht WelTrainGonstruction . NPT AirConsumptio��HighFre 14,256 (attjft'/min FlueGa5Velocity � � 54 ftJse[ EuhaustGasFlowRate � 22,083 . (actNt'/min 6�haustGasTemperature 485 'F StackUlameier 36 � in SwckHeight � 40 ft EstlmatedUser&PlpingPressureDrop 30 Ib/in'(g) PumpModel RSY200330 �' PumpConfiguretion 3x100% MotorSize 200 „p . CalculatedTotalPumpFlowRequired 3000 gal/min. Llne5ize !0 � in CaiculafedTotal5ystemVre5sure0rup 65.0 Ib/In'(d) Vaive5pecification SigmaThermai5tandard � SeleceedPumpMake KSB VaNeT e . vP Bellows Seal Globe �� ThermalFluidPiping0esig�Temperature 460 °F ThermalFluidPlpingDesignPressvre 150 Ih(in°�gj '�� TutafEstlmated5ystemVolume 5,613 � gal TankType � SigfnaThermal5tandard �� CalculatadExpansionVolume 89fi gal � NltrogenelankelPressure(ifappflcabie) 5 Ib/In'(g) �' ExpansionTank5lze 5000 gal �reln7ank5ixe . - MaximumAmbieniTemperature 100 "F ControlPanelAr¢aCl3ssificatian ClasslDiv.11 �I MinimumAmbienetemperature -20 °F SkidAreaClassiflcation Classl�iv.11 ��' Elevation(abovemeansealevei� 5,055 ft Wiring5tandards PerCustomer5pecification MotorRequirements StantlardEfficiencyTEFC ElectricalCodeoftonstmctian NEC � � Instrum2ntdtion verNstomerspedficatlon Con[rolPanelCertiflcatlon � �� . Motar5farters ByOthers Pdmarv/Voltage 4GOV/3/60Hz Mlnlmumtlectricalfinclosure5Rating 4X ConttolVoltage 120V/1/60Nz � PainiColors PerCustamer5pedficatlon OverallPaint5pecifl<atlon PeKu5tomer5pecification . ��. 2 Att�ch�en� 1� '� g''orm �C�A-101 Colorado Department of Public Health and Environment �� .,,Sg Air Pollution Control I3ivision -�''` - . :-. ., ..� � . *��a��'a �fg76 p �A�flC2�C1� l af L'u6tic i�� Cornpany Contact Inffor�ation Fora� �`d�'"'�°""'�"� Ver.September 10,2008 Co�pany Namec Kerr-Iv�aGee Gathering LLC Source Na�ee Lancaster Piant Permit Com laance a Jennifer L. Shea p Contast : Contact�o Jennifer L. Shea P.O. Box 173779 P.O.Box 173779 �ddress: s�`e� Address: screet Denver � CO 80217 Denver CO 80217 Ci State Zi � Ci State Zi Phone IVm�ber: (720)929-6028 gEmm�e Piu�bere (720)929-6�28 Fas 1Vu�ber: (720)929-7028 �ax N�mbee: (720)929-7028 i E-�aiE: 3ennifer.Shea@anadazko,com E-ffiai�: Jennifer.Shea@anadazko.com , Bi61₹ng Cotttact: $illin �ontaet: ermit Fees j Same as above � 4 Same as above Annual Fees Addsess: Street A��,e9�: Street Ci State Zi Ci State Zi �. Phame Nnmber• 1'ho0e IiTumber: ' Fax Nuanber: Fax Naember: E-�tanl: �+-mail: Check how would you like to receive your permit fee invoice? Mail: ❑ E-mail: � Fax: ❑ Footnotes• ' t The permit contact should be the point of contact for technical information contained in the permit application. � This may be a company representarive or a consultant. z The compliance contact should be the point of contact for discussing inspection and compliance at the permitted facility. 3 The Uilling contact(Pernut feesl should be the point of contact that should receive the invoice for fees ' associated with processing the permit application&issuing the permit.(Reg.3,Part A, Secfion VI.B) 4 The billing contact(Annual fees)should be the point of contact that should receive the invoices issued on an ' annual basis for fees associated with actual emissions reported on APENs for the facility.(Reg. 3,Part A, Section VI.C) � � � Page.l Of 1 FotmAPCD-101-CompanyContactlnfo.doc � I Attach�eent I�" A�ach�t�nt G _ _ __ __ __ _ _ _ _ _ _ ___ _ Lancaster Plant Process Description A mixture of natural gas, oil and water is collected from individual wells thraughout the Wattenberg Field by means of a gathering system. This mixture enters the plant through two (2) - 60,000 gallon slug catchers that capiures most of the free liquids. The gas pressure is increased by ten(10) engine-driven natural gas reciprocating compressors and then dehydrated ufilizing two (2) TEG dehydrators to a water content level acceptable far ' pipeline transmission. The dehydrators incorporate a thermal o�dizer per unit to control emissions. The liquids, known as natural gas condensate, aze routed to a stabilization process and then collected in four (4) — 11,500 gallon holding tanks. The stabilized liquids aze then trucked from the facility. The facility inciudes two (2) refrigeration plants to reduce the hydrocarbon dew point to meet sales delivery requirements. One (1) propane compressor is utilized in the ' ' the refri eration roduced ui ai as li uids GL s g tion rocess. The natur (N ) P refri era g 4 g P process are collected in three (3) 60,000 gallon tanks and then transported from the facility via pipeline and/or truck. The Lancaster gas processing plant will receive third party gas from the Kerr-McGee Gathering LLC pipeline system. T'he COz is removed from the inlet gas stream utilizing four(4) 150 MMSCFD amine treaters. Each amine train will utilize thermal oxidizers to control emissions. The gas stream is then dehydrated using a molecular sieve. The moleculaz sieve beds are regenerated using dry gas that has been heated by the regeneration gas heater. The dry gas is then run through the cryogenic unit to super-cool the gas and removes natural gas liquids. The cryogenic unit is supplemented by six (6) 2,750 hp electric motor driven propane refrigerafion compressors. The residue gas from the cryogenic unit is then compressed utilizing four (A) 12,000 hp electric motor driven compressors to deliver the gas to the residue pipeline. 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O � � . m � . o o � rr�-, � `r � s ml rn � � c�x - d-— �I � . � W W � � a , �O m� CD i- W� n A ^ A O � � 3 \ / \ f � � � N I � � I � � � O I � � I I � � � m . � � � � � I � V � � V � O . . a 4 � v � � v � � � � � � F' � m„ . � � � . . . . � �.. � � �r � � - � ¢ ' U W U N = � O OX M� r•JO �Q m mz I I q� I o O� O� � 0 O w U w O � m � d' 4 N p� m � � O � J � J Q m p m m mK N � � M N r� JO �� y� , m N W F � � � � � 3 0 U _ � � 4 O Q � g og � oLL _ � � �. " � � � a i d i '� n � S $ o � � - i I E _ ¢ a $ � ` N _ OI � k3iI1S l91Y0B lBQ1t ?�ttachanent H Forem P�C'D-306 Colorado Deparhnent of Public Health and Environment e ';;_ % .r•.r. Air Pollu6on Control Division .::<(�]s; R m��o ie Cmbr,e� c of!"ru6ii�� xuedFnvienmuent �per�tfin� and 16'�ai�at�e�aaace P9an Te�gsp�te for Anaene S�veetening Systea�s Ver.September 10,2008 T'he Air Pollution Control Division (Division) developed this Operanng and Maiutenance Plan (O&M Plan) for amine sweetening systems that aze permitted at a syntheric minor facility in the State of Colorado. An O&M Plan for each type of amine sweetening systam configuration, as described in Section I, shall be submitted with the pertnit applicarioa. One OBcM Plan may be used for mulriple amine sweetening systems at one facility if each are controlled and monitored in the same manner. If the O&M Plan template is completed correctly,the Division will approve the O&M Plan and a conshvction permit will be issued with the requirement to follow the O&M Plan as submitted. If the template is not completed correctly, the Division will work with the facility to make corrections. Once a construcUon perm9t is issued, the Facility operator must comply with the requirements of the O&M Plan upon commencemenY of operation. Operators are not required to use this template. Independent case specific O&M PLws may be developed and submitted for approval with the permit application. However,the Division encourages the use of this template to e�edite the permit applicarion approval process. Submitfal Date: 4/16/2012 Section 1-Source Identificadion ' For new permits some of this information(i.e.Facility AIRS ID,Facility Equipment ID,Permit Number,and AIRS Point ID) may not be lrnown at the time of appficarion.Please�fill out those fields that aze known and leave the others blank. Company Name: Kes-McGee Gathering LLC Facility Locarion: 16166 WCR 22,Fort Lupton,CO Facility Name: Lancaster PIant Facility AIRS ID(for existing faciliries) 123/0057/ Units Covered by this O&li�i form Facili E ui ment ID A-1 A-2 A-3 A-4 Permit Number AIRS Point ID Amine T e Used° A133EA MIBEA IYIDEA MIDEA a Amine types include MEA,DEA,TEA,MDEA,and DGA i Emission Points and Coutrol Status:Check the appropriate boxes indicating whether the dehydration system(s)are equipped � with a flash tank and whether or not the jlash tank(ifpresent)and sti[I vent emissions are controlled or recycled or vented to atmarphere. � �Flash Tank �Stiil Vent �Controlled/Recycled �Conirolled/Recycled � ❑Vented to atrnosphere ❑Vented to ahnosphere Section 2-Maintenance Schedules Check one of the following: Facility shall follow manufacturer recommendations for the operation and mamtenance of equipment and control � devices.These schedules and pracHces,as weIl as any maintenance records showing compliance with these recommendarions,sha11 be made available to ffie Division upon request. Page 1 of 4 2012-04-11 A-1 to A-4 O&Mdoc I Colorado Deparlment of Public Health and Environment Air Pollution Conirol Division Facility shalI follow individually devaloped maintenance practices and schedules for the opera6on and maintenance of equipment and control devices.These schedules and practices,as well as any maintenance recards showing compliance � with these recommendations,shall be made available to the division upon request and should be consistent with good air pollutlon conhrol pracrices for minimizing emissions as defined in the New Source Performance Standazd(NSPS) genetal conditions. Seetion 3-Mon¢hlv Emission Modetine or Celculations The followiug boz must be checked for O&M plan to be consideeed complete. The source will calculate emissious based on the methods and emission factors provided'm the permit application and � approved by the division,as reflected in the conshvction permit.Please see the operation and maintenance plan guidance documentforfurther details and a:amples ofemissio»calculatrons. Section 4—General Monitorine Reauirements Table 1 below details the schedule on which the source must monitor each of the listed operating pazameters depending on the requested permitted emissions at the facility. Check the appropriate 6ox based on the facility-wide permitted VOC emissions. Table 1 Momitorin Fre uenc Parermeter �Permitted�aeility ❑Permitted Facilidy Emissiona L 80 k VOC Emissions t 80 tp VOC Lean Amine Cirsulation Rate Dail Weekl Gas Inl¢t Tem erature Weekl Monthl Gas Inlet Press�re Weekl Monthl Volume of Gas or NGi.Proceased Monthl Monthl Tables 2 and 3 outline the methods by wluch the source may monitor the lesn amine recirculation rate and the gas or NGL II processed,respectively. In Tables 2 and 3 the source must chose one primary monitoring method and,optionally,up to two ' backup monitoring rnethods. Table 2 !' Prima Sack-u Lean Amine RecirsulaHon Rate Monitorin Method Amine flow mete s -includin flow from a11 um s � � Record atrokes per minute and convert to circulation rate—pump make/model and stokes per minutel circularion rate relationslu must be made available to the division u on re uest � � Assume maximum design pump rate 6—pump make/model and cuculation rate specifications � ' must be made available to the division u on re uest 6 Note:if you are requesting to permit at a rate lower than the maximum design pump rate then tlus ogtion shoutd not be used as it will create de facto non-compliance. , Table 3 Prima Back-u Volume of Gas or NGL Processed Moaitorin iVlethod � Metered Inlet Outlet❑Com reasor Suction Q Com ressor Dischar e�Other:_ � Metered Inlet Oudet Com essor Suction Com ressor Dischaz e Other: Assume mazimum desi n rate`s ecificarions shall be made available to the division u on re uest Other(to be a roved b tHe diviaion):attach method ex lanafion and sam le calculations ` Note: if you are requesting to permit at a rate lower than the maacimum contactor design rate then this option should not be used as it will create de facto non-compliance. , Page 2 of 4 2oiz-oa-v a-i to aa o�Nt.aoo �!, Colorado Dapaztment of Public Health and Environment Air Pollution Confrol Division BecHon 5-E�ission Coatroi or Ytecvcline Eaueoment Nfonitorine Bteaenirememts Table 4 below details the monitoriag frequency for control equipment depending on the type of control equipment used and the requested permitted emissions at the facitity. Check the appropriate box for"Monitoring Frequency"based on the faci]ity- wide permitted VOC emissions. In addirion,indicate still vent and flash tauk emissions controls by checking the appropriate boxes. Table 4 N�omitorin Fre uenc Emissions Control or Still Flash �Permitted Facility ❑Permitted Eacility ibecycling Method Vent Tank $arameter �missions Emissions >80 tpy VOC <80 tpy VOC '1'LermalOzfldizer � � CombusGon aha�bex Daily Weekly Tem erature Co�abustor or Flare � � Ptiot Ligh4 Monitorimg e Daily Weekly Method 22lteadings Daily Weekly Recyeled or Closed 7.00p System(Yncludong ❑ ❑ 'To be determimed by khe source and approved by the division P Vapor Recovery Units) Re�routed to Yteboiler Burner ❑ ❑ '�a be deter�imed by the soucce and approved by the a9tvision g d NBinimum T6ermal Oxidizer Combas4ion Chember Tempes�ature If the facility uses a thermal oxidizer to control emissions then the min'vnum combustion chamber temperature shall be:Sedect one of the following options from Table 5: Table 5 � 1400°F � o F Based on manufacturer specificarions. Specifications must be submitted with the ermit a lication and made avaflable to the Division u on ra est � Based on testing performed. The test data shall be submitted and attached to the O8cM Plan `Pilot Light Monitoring Optiona If the facility uses a Combustor ar Flare then the source must indicate the method by which the presence of a gilot light will be monitored in Table 6. One primary method for Pilot Light Monitoring must be checked and,optionally,up to two backup methods can be checked. Table 6 Prima Back-u Monitorin Method ❑ � VisualIns ection ❑ O tical Sensor � ❑ Auto-I niter Si al ❑ Thermocou le r Recycled or Closed Loop System Monitoring Plan ' In the space provided below please provide a hrief description of the emission control or recycling system,including an explanation of how the system design ensures tbat emissions are being routed to the appropriate system at all times,or during all permitted runtime. � . _ Page 3 of 4 � 2o12-P4-t 1 A-1 to A-0 o&M.doc . Colorado Department of Public Health and Environment Air Pollution Control Division g bteboiler Burner Control Monitoring Plan In the space provided below please provide a brief description of the emissioseoirtrol system,including an eacplanarion of how the system design ensures that emissions are being held or rerouted when the reboiler is not firing. SecNon 6—Recoratkeeoine Reauir¢�ents The following bax mnst be checked for O&R?plan to be cousidered complete. Syntheric minor sources are required to maintsin maintenance and monitoring records for the requirements listed in � sections 2,3,4 and 5 for a period of 2 yeazs. If an applicable Federal NSPS,NESHAP or MACT requires a longer record retention period the operator must comply with the longest record retention requirement. SeeEion 7-Additional Notes and O&M Aetivities Please use this secrion to describe any additional notas or operation and maintenance acrivities. Amine still vent and flash tank emissions will be routed to the plant emergency flare when the thermal oxidizer is down. I Note: These temptates are intettded to addtess operatian and maintenance requirements of the Sdate of Co[orado for equtpmeret operated at synthe(tc�ninor facilitfes.If the facUity or equipment!s subfect ta otdrer state or federal eeguladons w&h duplicative regutrements,ihe source shall follow the most strtngent regulatory requirement Page 4 of 4 zo�z-oa-i i a-i to aa oachtaoc r�t�aehment I I,ancaster PIanB Cryogenac 1'lammt YPegu@a4on°y Analysis Sestiom i.0- S�ste Re�ula4fmns XegulreCion 3,Part A,Section PI Tha ten newly proposed electric drive motors are not subject to APEN reporting requirements. The fow 60 A�IlViBtu/hr amine regeneration heat medium hexters, two 25 MIvYBtu/hr mole sieve regeneration gas heaters,two 150 MMSCFD Train 1 amine treattnent systems each controlied with a thermal oxidizer,two 150 MMSCFD Train 2 atnine ireatment systems each controlled with a thermal o�dizer, two process flares,emergency generator,and plant fugitives are subject to APEN reporting requuements. i dfegudatlon 3,Part B,Sections I ared II ' The four 60 MA�IBtu/hr amine regenerarion heat medium heaters, two 25 MMBtu/hr moIe sieve , regeneration gas heaters, two 150 MMSCFD Train 1 amine treatment systems each controlled with a thermal oxidizer, two 150 MMSCFD Traui 2 amine treatrnent systems each controlled with a thermal oxidizer, two process flazes, emergency generator, and plant fugirives are subject to this reg�lation and required to obtain a wnstrucrion permit prior to construcfion.The operation of these units will be limited as requested on the Air Pollutant Emissions No6ce or in the permit application �egulotion 3,Part� The facility is currently operating as a major source with respect to the Title V Operating Permit Program. The facility will be required to submit a Title V Permit application modification for the proposed project within 12 months of startup. Regula2ion 3,I'arf D ' The facility is an existing major stationary source and is therefore subject to this Part. In determining the net emission increase of the proposed project, actual emissions were calculated as pertains to II.A.1 and resulted in emissions below all applicable criteria pollutant PSD significance tluesholds as pertains to II.A.42. The proposed project does not result in a significant net emission increase in criteria pollutants as pertains to II.A.26 and is not considered a major modification far criteria pollutants to an existing major stationary source. All contemporaneous changes that the Division has not relied on in issuing a permit under Regulation Number 3 as pertains to II.A.26.c.(ii) have been included in the analysis. Therefore,the proposed modifications to the facility are not subject to the permitting requirements of this Part. Regulatiote 3,Part7.TT On October 21,2010, 40 CFR Parts 51, 52,70 and 71,Prevenfion of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule was adopted into Regulation 3, Part I.TT. The second step of the tailoring rule went into effect on July 1, 2011. Under the rule all new and e�cisting sources that have the potential to amit at least 100,000 tpy COZe will be subject to the PSD and title V requirements. Also, sources that have the potential to emit at least 100,000 tpy COZe and undertake a modification that increase net emissions of GHGs by at least 75,000 tpy COZe will also be subject to PSD requirements. The existing facility has a potential fo emit at least 100,000 tpy COZe and the proposed modificarion is greater than 75,000 tpy COZe, therefore this project must submit a PSD permit application for GHGs. A BACT analysis for GHGs is included in Attachment J of the application. Regulntion 6 Regulation 6 incorporates by reference the EPA's New Source Performance Standazds (NSPS). NSPS applicability can be found in Section 2.0. Page 1 of4 Regulatiora 7,�'ection Xld The facility is located in the 8-hour Ozone Control Area;therefore tlris facility is subject to Section XII of this regulation. The proposed project does not include product storage tanks, natural gas driven engines or a glycol dehydration system. All residue gas and produced natural gas liquids will be transported off= site via a pipeline,gas will be dehydrated with a molecular sieve and natural gas will be compressed with electric drive engines. Therefore, Section XII.C, XII.H and XVI wiil not apply to the proposed modification. As pertains to Section XII.G.1, the proposed modificarions will be subject to the LDAR requirements in Subpart KiGK and therefore comply with Secflon XII.G.L Regul�Pion 8 Regulation 8 incorporates by reference the EPA's Natsonal Emission Standards for Hazardous Air Pollutants(NESHAPs). NESHAP applicability can be found in Section 3.0 and Section 4.0. Sec@ion 2.0-40 CFR 60 -IVew Source Perfornaance Sta�dards fri1SP51 Subpart,4—General Provisions The General Provisions of the federal NSPS apply to any stationary source that contains an affected facility to which an NSPS applies. The proposed modification is subject to multiple NSPS,therefore, various portions of this Subpart will apply. Subpart ]3e — Standards of Performance far Small Industrial, Commercial, Institutional Steam Generatzng Units Standards of Performance for Stnall Industrial, Commercial, and Institutional Steam Generating Units, applies to steam generating units having a maximum design heat input capacity less than or equal to 100 MMBto/hr but greater than or equal to 10 MMI�tu/hr that aze conshucted, reconshucted or modified a8er June 9, 19$9. A steam generating unit is defined in Secfion 60.41c as"a device that combusts any fuel and produces steam or heats water or heats any heat transfer medium". The proposed natural gas fired 60 NIA�IBtu/hr amine heat medium heaters and 25 MNIBtulbr mole sieve regenerator heaters aze snbject to thxs Subpart. Natural gas is the sole fuel for both heaters and therefore,the sources are subject to the reporting and record keeping requirements of 60.48a Subpart IIII—Standards of Performance for New Starionary Engines Subpart IIII applies to owners and operators of stationary compression ignition (Cn internal combustion engines. The proposed projeot includes one 670-hp emergency diesel generator that will operate a maxiruum of 500 hours per year. The proposed engine will be subject to the emission standards of 60.4205(b), the operating requirements of 60.4207(b) and the compliance requirements of 60.4211. Subpard�b-Standards of Performance for Volatile Organic Liguid Storage T'essels Subpart Kb applies to each starage vessel with a capacity greater than or equal to 7S cubic meters used to store vofatile organic liquids(VOL)for which construction,reconstruction, or modification is Page 2 of 4 commenced after July 23, 1984. There are no storage tanks proposed in this modification, therefore Subpart Kb dces not apply. SubparP LLL—Standards of Performance for Onshore Natural Gas Processing:SOZ Emissions Subpart LLL applies to onshore natural gas processing plants that have gas sweetening units, The proposed modification includas four 150 MMSCFD amine gas sweetening units which will be subject to this subpart. All units will have a design capacity of less than 2 long tons per day of HzS in the acid gas and therefore will only need to comply with the recordkeeping requirements of 60.647(c). �ubpart JdJ.�Standards of Performance for Stationmy Spark Ignition Internal Combustion Engines Standards of PerFormance for Starionary Spazk Ignition Internal Combustion Engines applies to manufacturers, ownets and operators of sta6onary spark ignition(Sn internal combustion engines (ICE). This applies to engines that were ordered from the manufacturer after June 12,2006 and aze manufactured after July 1, 2007 and aze greater than or equal to 500 hp or manufactured after July 1, 2008 and are less than 500 hp, and engines that are modified or reconslructed after June 12, 2006. The proposed modification inclUdes ten electric drive motors and one diesel fired emergency generator, therefore, Subpart JdJJ does not apply. Subpar8 dCKg Standards of Performance for Equrpment Leaks af VOC from Onshore Natura! Gas Pracessing Plants Standards of PerForntance for Equipment Leaks of VOC from Onshore NaturaI Gas Processing Plants apply to affected facilifies in onshore natural gas processing plants that commenced construction, modification or reconstrucrion after January 20, 19�4. A nahual gas processing plant is defined in the Subpart as any site "engaged in the extracrion of natural gas liquids from field gas". The proposed modification wiD extract NGL from the field gas and is therefore subject to the LDAR requirements of this Subpast and State Regulation Z Section 3.0-40 CFI2 61 -1Vatiomal Em►ission Stand�rds ffor gIazardous Air Pollretants Subpard P—National Emission Sdandards for Equipment Leaks (Fugitive Emission Sources) National Emission Standard for Equipment Leaks (Fugitive Emission Sources)applies to sources that are intendad to operate in volarile hazardous air pollutant(VHAP) service. Based on engineering judgment, historical and recent gas composition and facility process it can ba predicted that the percent VHAP content will never exceed 10 percent by weight; therefore Subpart V is not an applicable regulation for the facility. Sec4ion 4.0-40 CFR 63 -1`Tational Emasaion Standards£or liazaralous Air Pollutants Subpart H$— National Emission Standards for Hazardous Air Pollufants from Oil cmd Natural Gas Production Facilities. National Emission Standards for Hazazdous Air Pollutants from Oil and Naturat Gas Production Faciliries applies to glycol dehydration units, storage vessels with potential for flash emissions, and ancillary equipment operaring in volatile hazardous air pollutant(VHAP) service that is located at a faeility which is a major source or area source of HAPs. VFiAP service is defined in the Subpart as"a piece of ancillary equipment or compressor either contains or contacts a fluid which l�as a total VHAP concentrarion equal to or greater than 10 percent by weighY'. The proposed modificarion is located at a major source of Page 3 of 4 . HAPs, but does not include any glycol dehydration units, storage vessels with potenriai for flash emissions and equipment will not operate in VHAP service. Therefore, Subpart HH will not apply. Subpart�ZZZ—Naidonal Emission Standards for Hazardous Air Podlutants for Stationary Reciprocating Internad Combustion Engines. National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combusrion Engines(RICE)establishes narional emission limitations and operating limitations for HAPs emitted from stationary reciprocating internal combusfion engines, and requirements to demonstrate i inirial and continuous compliance with the emission limitarions and operating lunitations.The facility is a i major source of HAPs;therefore,the facility is subject to major source ZZZZ requirements.The proposed I modifications include ten electric drive motors and once diesel fired emergency generator which aze not subject to the requirements of this Subpart. Sec4iomm 5.0-40 CFYt 98—Green Iiouse Gas 1Zeuork6en¢ Subparl.� General Provisions applies to a facility that contains any source category (as dafined in subparts C through JJ of this part}that is listed in this paragraph(a)(2)in any calendar yeaz starting in 2010 and that emits 25,000 metric tons CO2e or more per yeaz in combined emissions from stationary fual combustion units, miscellaneous uses of cazbonate, and all source categories that are listed in this regulation. The faciliTy is subject to the reporting requirements of Subpart C and Subpart W. Page 4 of 4 __ __- _ Elttach�ent � ' _ ._ __ __ __ _. I�ea°r-l�Y�Gee Gathe�°iffig �.Y.C Lancaster�l��t CII°3�ogen�c Plant 1'a°oject Greenhouse Gase� �es� Avaalable Co�atroi Techffi�1�gaes (�E1C'I') r�ma�yse� ' Table off Contents FacilityInformation...........................................................................................................................l ProcessDesceiption...........................................................................................................................1 Emission Sources...............................................................................................................................2 BACTAnalysis Methodolo�y.............................................................................................................3 BACTEvaluation for Sources.............................................................................................................5 Appendix A—Economic Analysis foe CCS..........................................................................................A I �+PPendiK B—RBLC Informa¢ion Summary........................................................................................B Facilitv Imformation: The Lancaster Plant will be adjacent to the Fort Lupton Gas Plant which is in Weld County, CO at Northwest 1/a, Section l4,Township 2 North,Range 66 West. The cootdinates are: Latitude:40°, 1614'N I,ongitude: 104°, 45.08'W The street address is: 16116 WCR22 Ft.Lupton, CO 80621 The eicisting facilities currently operate under a number of construction permits as well as Title V operating permits. A recent acquisition of assets formerly owned by EnCana also brought the Platte Valley Statian into the single facility complex. ProcessH5escrip4iom: The new 600 milllon standard cubic feet per day (MAllscfd) cryogenic plant will be located adjacent to the existing Fort Lupton Facility which includes gathering compression and existing refrigerafion plant. The plants will receive third party gas from the Kerr McGee Gathering pipeline system in the Wattenberg Field, remove CO2 via amine treating, dehydrate the gas through the use of molecular sieve beds, e�tract natural gas liquids (NGL) through the use of the gas sub-cooled process (GSP} and SCOItE cryogenic cooling processes and then re-compress the residue gas stream for salea The CO2 is removed from the inlet gas stream utilizing four(4) 600 gpm amine treaters. The amine treaters incorporate a thermai oxidizer per unit to control emissions. The gas stream is then dehydrated using a molecular sieve. The molecular sieve beds are regenerated using dry gas that has been heated by the regeneration gas heater. The dry gas is then run through the cryogenic unit to super-cool it and remove natural gas liquids (NGL). The cryogenic units are supplemented by six(6)2750 hp electric miotor driven propane refrigeration compressors. The residue gas from the cryogenic units is then cornpressed utilizing four (4) 12,000 hp electric motor driven compressors to deliver the gas to the transportation pipeline. The produced NGLs are also transported from the facility via a pipeline. T7te ptimary reason for treating the inlet gas with amine is to ensure that the NGLs meet pipeline specifications. The inlet gas has about 2.7 mole % CO2. Treating the feed gas avoids issues with liquid trearing, such as amine carry over and meeting the pipeline water specification. Because the amine units are designed to remove CO2 from the natural gas, the generation of CO2 (GHG) is inherent to the process,and a reduction of CO2 emissions by process changes would only be achieved by a reducfion in the process efficiency, which would result in natural gas that would not meet pipeline quality specifications and leave CO2 in the natural as for emission to the ahnos here at downsfream sources. The amine units do also emit B P re eneration due to a small amount of natural as methane (GHG) at the point of amine g , B becoming entrained in the rich amine. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 1 Emission Sources: The proposed project triggers Prevention of Significant Deterioration (PSD) permittutg thresholds for greenhouse gases, but does not trigger PSD for any criteria pollutants. The primary sources of GHGs proposed at the 600 NIMscfd plant will be: C-4100 Solaz 12,000-hp Electric Drive Engines,Residue G4200 Solar 12,000-hp Electric Drive Engines,Residue C-4300 Solaz 12,000-hp Elechic Drive Engines,Residue C-4400 Solar 12,000-hp Electric Drive Engines,Residue G5110 2750-hp Electric Engine,Refrigeration Compression C-5210 2750-hp Electric Engine, Refrigeration Compression G5310 2750-hp Electric Engine,Refrigeradon Compression C-5410 2750-hp Electric Engine,Refrigerarion Compression G5510 2750-hp Electric Engine,Refrigeration Compression G5610 2950-hp Electric Engine,Refrigeration Compression E-2015 Mole Sieve Regeneration Gas Heater with Ultra-Low NOx Burners E-2016 Mole Sieve Regenerafion Gas Heater with Ultra-Low NOx Burners H-60S 1 Amine Regeneration Heat Medium Heater-Low NOx Burners H-6052 Amine Regeneration Heat Medium Heater-Low NOx Bumers H-6053 Amine Regenerafion Heat Iviedium Heater-Low NOx Burners H-6054 Amine Regeneration Heat Medium Heater-Low NOx Burners A-1 150 MMSCFD Amine Treater(Controlled with ATO-1) A-2 150 MMSCF`D Amine Treater(Controlled with ATO-2) A-3 I50 MMSCFD Amine Treater(Controlled with AT03) A-4 150 MMSCFD Amine Treater(Controlled with AT0-4) F-2 Vertical Process Flare F-3 Vertical Process Flare GEN3 Caterpillaz 670-hp Diesel Emergency Generator FUG 3 Plant Fugitives The proposed project triggers PSD far the estimated GHG emissions as it is estimated to emit 565,923 tons per yeaz(tpy) CO2 equivalent(CO2e). The net CO2 emissions will be SSQ273 tpy however, as three e�sting engines will be removed as part of tlus project. The CO2e emissions aze estimated by applying the global warming potential (GWP) of each GHG pollutant. The GWP for each potlutant is: CO2: 1 CH4: 21 N20: 310 For example this means one ton of inethane would equate to 21 tons of CO2e. Detailed calculations can be found in the calculations section of the permit applicarian. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACI'Analysis Page 2 __ __ i7�TIT CO2e tgay C-4100 - C-4200 - G4300 - C-4400 - C-5110 - G5210 - C-5310 - C-5410 - G5510 - C-5610 - E-2015 15,252 E-2016 15,252 H-6051 39,421 H-6052 39,421 H-6053 39,421 H-6054 39,421 A-1 94,121 A-2 94,121 A-3 94,121 A-4 94,121 F-2 150 F-3 150 GEN3 - FUG 3 949 TO'SAL 565,923 �ACT rLnalvses Methodoloev: As of January 2, 2011, GHG is a regulated criteria pollutant under the PSD major source permitting program codified in Title 40 Code of Federal Regulations (CFR) Part 52 when they are emitted by new sources or modifications in amounts that meet the Tailoring Rule's i set of applicability thresholds. For PSD purposes, GHGs are a single air pollutant defined as the aggregate group of the following gases: carbon dio�de (CO2), nitrous oxide (N2O), methane(CH4), and hydrofluorocarbons (F�Cs). The PSD regulations do not prescribe a procedure for conducting BACT analyses. Instead, EPA has consistently interpreted the BACT requirement as containing two core eriteria: 1. T`he BACT analysis must include consideration of the most stringent available technologies, z.e.,those that provide the"maximum degree of emissions reduction." Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 3 _ -._ _ _ _ __. _ 2. Any decision to require as BACT a control alternative that is less effective than the most stringent a�ailable must be justified by an analysis of objective indicators showing that energy, environmental, and economic impacts render the most stringent alternative unreasonable or otherwise not achievable. EPA has developed wt�at it terms the "top-down" approach for conducting BACT analyses and has indicated that this approach will generally yield a BACT determination satisfying the two core criteria. Under the "top-down" approach, progressively less stringent control technologies aze analyzed until a level of control considered BACT is reached, based on the environmental, energy, and economic impacts. The top-down approach shall be uulized in this BACT analysis. The ftve basic steps of a top-down BACT analysis are listed below: 1. Identify all available control technologies with practical potential for application to i the specific emission unit for the regulated pollutant under evaluation; 2. Eliminate a11 technicaliy infeasible control technologies; ' 3. Rank remaining control technologies by effectiveness and tabulate a control hierarchy; 4. Evaluate most effective controls and document resuits;and � 5. Select BACT, which will be the most effective practical option not rejected, based on economic, environmental, and/or energy impacts. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 4 �ACT Evaluation for Sources: Step l:Pdentify Control�pttons T'he following ace potenrially applicable control technologies for controlling GHG emissions associated with tbe En ines: l. Ali the new compressor engines at this facility will be run on electric power resulting in no GHG emissions from these sources. '£herefore, no fiuther analysis is necessary for the engines. The following are potenfially applicable control technologies for controlling GHG emissions associated with the A�iue Vents: 1. Proper Design and Operation: The amine units are designed to include a flash tank, in which gases (i.e., including CO2 and rnethane}are removed from the rich amine prior to regeneration, thereby reducing the amount of waste gas created.The amine units at this facility shall be constructed and operated for optimal performance; 2. Amine Unit Flash Tank Off-gas Recovery System: The amine unit flash tank off- gases shall be routed to the proposed thermal o�cidizer. 3. Routing Amine Unit Regenerator Vent to a Thermal Oxidizer: This control device will reduce the methane emissions by 99% and will convert those emissions to CO2, which has a lower GWP; 4. Routing Amine Unit Regeneratar Vent to a Flare: This control device will reduce the methane emissions by 98% and will convert those emissions to CO2, which has a lower GWP; 5. Carbon Capture and Storage (CCS): This involves capturing CO2, transporting it as necessary, and permanently storing it instead of releasing it into the atmosphere. The process involves three main steps: • Capturing CO2 at its source by separating it from other gases; o Transporting the caphued CO2 to a suitable storage location (typically in compressed form};and e Storing the CO2 away from the atmosphere for a long period of time, for instance in underground geological formations, or within certain mineral formations. a In the project two CCS approaches were looked at: acid gas injection well and enhanced oil recovery(EOR) The following aze potentially applicable control technologies for controlling GHG emissions associated with the Heaters: 1. Fuel Selection: The heaters at the site shall be fired on pipeline quality natural gas. This results in 28% less CO2 production than fuel oils (see 40 CFR Part 98, Subpart C, Table C-1, which is included in Appendix E, for a comparison of the GHG emitting potential of various fuel types); 2. Efficient Heater Design: New burner design improves the mi�cing of fixel, creating a more efficient heat transfer. At the new facility,new bumers shall be utilized. Burner management systems shall be utilized on the heaters, such that intelligent flame ignition, flame intensity controls, and flue gas recirculation optimize the e�ciency of the devices. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page S 3. Periodic tune-ups and maintenance for optimal thermal efficiency: Maintenance shall be performed routinely per vendor recommendatfions or the facility's maintenance plan. The components shali be serviced or replaced as needed. The heaters shall be tuned once a yeaz for optimal thermal efficiency; 4. Oxygen trim control: Combusfion devices operate with a certain amount of eiccess air to reduce emissions and for safety consideration. An inappropriate miYtute may lead to inefficient combustion. Regular maintenance of the draft air intake systems of the heaters can reduce energy usage. DraB control is applicable to new or existing ', process heaters and is cost effective for process heaters rated at 20 to 30 IvIMBtu/hr or ', greater. The heaters will have air and fuel valves mechanically linked to maintain the proper air to fuel ratio. The following are potentially applicable control technologies for controlling GHG emissions associated with the Overall Facititv: 1. Overall efficiency of facility; I 2. Existing Fort Lupton equipment permanent shutdowns; 3. Compliance with NSPS Subpart KKK for fizgitive equipment. Steps 2r Eldminate Tecdanicadly Infeasibde Control Options At the current time acid gas injecfion wells for this location appear to be technicaliy infeasible. There are no known acid gas injection wells operating in the Denver-Julesberg (D-.n Basin. The current consensus is that acid gas inJection wells would not sequester the CO2, but ratkter the CO2 would migrate to other producing wells creating a recycle of CO2. Step 3:CharacPerize Control Effectiveness of Technically Feaseble Control Options The efficiency improvement/GHG reduction technologies aze ranked* below: o Use of electrio-driven engines (100%); e Instali amine unit flash tank off-gas recovery systems(100%); o Routing the amine unit vents to a thermal oxidizer (99°/Q for methane, and generates CO2); B Routing the amine unit vents to a flare(98%for methane,and generates CO2); e Et£ciencies within the plant(variable); ` • Fuel selection(28%when comparing natural gas and No.2 Fuel Oil); o Bumer management systems on the heaters, with intelligent flame ignition, flame intensity controis,and flue gas recirculation(10-25%); ' s Efficient heater design(10%); • Annual tune-ups and maintenance(1-10%); o O�;ygen trim control; m CCS (not a feasible opfion for the Project due to technical, environmental, and economic reasons, as discussed in Step 4). _ 1 sis Pa e 6 Kerr McGee Gathering Lancaster Cryogenic Projece GHG BACT Ana y g *The following documents were used to identify any available control efficiencies including some vendor specifications: i} Available and Emerging Technology for Reducing Greenhouse Gas Emission from the Petroleum Industry dated October 2010 and ii) Energy Efficiency Improvement and Cost Saving Opportunities for the Petrochemical Industry: An ENERGY STAR Guide for Energy Plant Manager, Document Number LBNL-964E, dated 7une 2008, Step 4:Evaluate Most Effective Control Options I As part of this project the following opNons that were listed in Step 1, shall not be proposed Por implementation as BACT: l. The routing of amine unit regenerator vent to a flare (98% control), because a more ' efficient technology(thermal oxidizer; with 99%efficiency}will be addressed. 2. Amine flash tank off-gas recovery. The amine flash tank off-gas will be routed to the thermal oxidizer to aid in combustion of the regenerator vent gas. 3. CCS is not considered to be feasible, based upon its lack of readily available technologies and negative environmental and economic impacts. However, per EFA guidance, EFA has identified CCS as an add-on control technology that must be evaluated as if it were technically feasible. The amine flash tank off-gas will be routed to the thermal o�dizer for combustion rather than recycled to the plant inlet. Due to the low Btu and the cooling effect of the CO2 in the amine regenerator vent gas stream, additional Btu content(assist gas)will need to be added to aid in combustion in the thermal oxidizer. If the flash gas were to be routed back to the plant inlet, additional compression would be needed and the energy required would negate the potential savings on the flash gas. The design will utilize the high Btu flash gas to help supply some of the addirional Btu need to offset a portion of the pipeline gas utilized for the remaining assist gas. The emerging CCS technology is an"end of pipe"add-on control method comprised of three stages (capture/compression, transport, and storage). CCS involves separation and capture of COZ from the exhaust gas, pressurization of the captured CO2, hansmission of CO2 via pipeline, and injection and long term geologic storage of the captured CO2. CCS can also consist of use of CO2 in Enhance Oil Recovery(EOR)opportunitiea The goal of CO2 capture is to concentrate the CO2 stream from an emitting source for transport and injection at a storage site or location utilizing EOR. CCS requires a highly concentrated, pure CO2 stream for practical and economic reasons. Ea�tracting CO2 from e�aust gases requires equipment to capture the flue gas exhaust and to separate and pressurize the CO2 for tcansportarion. E�ctracting CO2 from the e�aaust gases of the heaters and thermal o�dizers would require equipment to capture the flue gas exhaust and to separate and pressurize the CO2 for transportarion. The exhaust stack streams will be low pressure, basically atmospheric pressare. The streams wouid also be emitted at high temperatures. The CO2 separation would require the removal of all other pollutants from the streams. The process would ' require compression to increase the pressure from atmospheric to pipeline pressures. The Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 7 process would also require the reduction of the temperature of the streams by several hundreds of degrees prior to sepazafion, compression, and transmission. Basically an entire plant similar to wt�at is being proposed in this project (smaller in size) would have to be constructed to remove the CO2. This process would add even more GHG emissions and lazge costs to the project. This option is not environmentally, nor economicatly feasible. Even if we assumed there was a feasible way to separate the CO2 from the combustion streams, there would be several logistical•issues that need to be resolved including obtaining right of way{ROR� and National Environmental Policy Act (NEPA) efforts for a pipeline to , transport the CO2 to a location that would be available to receive and handle a continuous I long term stream of CO2. The geological formations avaitabie near this proposed site are not technically feasible to store the CO2 as mentioned previously: In addition EOR is not feasible at any lazge scale level in the D-J Basin due to its geology and multiple ownerloperators in the area. There may be some single well CO2 EOR projects forthcoming in this area, but nothing of the magnitude that would be able to handle the continuous supply of CO2 that would be produced from this project. Since different ownerloperators are locaked in close pro�mity, lazge scale EOR is not feasible. T'he exhaust slreams from the heaters and thermal oxidizers would have to be cooled, compressed, and treated prior to being able to enter a pipeline. A conservative estimate on the cost of equipment that could possibly be installed for these purposes was assumed to be $50,000,000. The nearest identified area utilizing EOR with CO2 is approximately 300 miles from the Plant. At a cost of$80,000 per inch mile to install a 12" pipe line, the total cost far the pipeline alone would be approxirnately$288 million($80,000 x 12 x 300). Detailed engineering was not done on horsepower requirements to boost the gas along the approxlmately 300 miles of pipeline because a definitive route was not chosen. However,we could estimate it take 80,000 horsepower(including horsepower requued at the site to get the gas up to a pipeline pressure, intermediate pipeline booster compression, and end point injection compression). The cost of that additional horsepower would be approacimately $200,000,000. There would also need to be additional surface equipment (i.e. separators, dehydrators, storage tanks, etc.) at the booster sites and all equipment woutd have to be able to handle the acid gas(CO2). The cost of the additional surface equipment was not estimated in this exercise. Even excluding a portion of the cost, the engine cost and pipeline cost would equate to a $156/ton cost of control. There is a high likelihood that the xemote booster stations would not be able to utilize electric compression, therefore it will have negative impact on the environment. Hence the use of CCS to reduce GHG emissions is not economically or environmentally feasible for this project, and the timing required for ROW issues and NEPA analyses would extend the project start date out by years. In addition there is no assurance that any available CO2 pipeline or EOR area would even have the capacity to handie the CO2 from this project. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 8 S2ep Sr Establish BAC'T After discussion in the previous secrions,the proposed BACT for this project would include: �'m ig nes- ➢ Electric motors on compressor engines 0 64,500 hp of electtic driven compression Amine Ven6s- ➢ Routing off-gases to thermal oxidizer for combustion o T'hermal Oxidizers utilize combustion air preheaters and acid gas heat exchangers Heaters- ➢ Design, operation,and management criteria as specified in Steps 1 & 3 Overal9 FaciEety- B Efficiencies o Engine shutdowns ➢ Compliance with NSPS Subpart KKK as applicable o LDAR to reduce fugitive leaks The thermal o�dizers proposed to control emissions from the amine vents wi21 utilize combustion air preheaters as well as an acid gas heat exchanger to minimize additional fuel requirements. The engineering design firm has estimated that the preheaters and heat exchangers will reduce assist gas requirements by approximately ll MMBtu/hr. That efficiency relates to an avoided amount of 5,637 tpy of CO2e for each thermal oxidizer. Kerr-McGee Gathering is committing to 64,500 horsepower of electric compression as part of this project. The choice of electric compression will eliminate GHG emissions from the j compression needs of the plant. Based on Caterpillar data on recent 3600 series engines, COZ emissions from natural gas fired engines are approximately 450 grams per horsepower- hour. That would equate to 280,272 tpy of CO2e from 64,500 horsepower of natural gas fued engines. Not to mention there would be overall energy efficiencies by utilizing electric compression in this project. As part of the overall project, three natural gas fired engine at the existing Fort Lupton plant I will be permanently shut down (EU-35, EU-31 and EU-32). The runtune restrictions on the engines will reduce up to 15,649 tpy of COZe. Total quanri�able CO2e reductions of 318,469 tpy are proposed as part of the BACT as well as numerous reductions that aze not as easily quantifiable, such as maintenance and operation conditions on the heatera Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 9 Overall the proposed project will treat 600 MMscfd of gas with only modest increases in criteria emissions at the facility. While there is a proposed 550,273 tpy net increase in GHG emissions in the project, it is effecrively removing the CO2 from the gas stream that would uitimately have been emitted at some point downsiream of this facility. The overall avoided and reduced GHG emissions for the project are greater than 50%of the proposed total net GHG emissions. Kerr McGee Gathering-Lancaster Cryogenic Project GHG BACT Analysis Page 10 AFPENI)IX A Econmanac Analyses for CS3 I i I Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B Best Available Contro0 Technmlogy Control C�st Ana6ys'ss Wmrksheeg i (Beeetl on 0f9ce of AirOuaGry Plennin9 and StentleNe,EPA,OAQPS Controi Coct Menuel,FouM Etl�Uoq EPA45W3�90.008,Januery 1090,Sectlon 2.3.� Ta eletl Emieslon R9f@PBIICB . WISIIOUG WHII No. Control Control � � (TPY) TP Pi eiine 550273 0 � did not include flare or Pogitives . �'�, Booster Stations .. � �! CO2 Removal E ui ment . ' Reference Interest Control Caplpl Capkal Mnual Capital Realfzetl ' No. Rate Systam Llte Reeovery Faclor Investment Malntenanee Recovery Cost Economlc ��, i n CRF) P) Cos2 � (CRC) Banefk ' Pi eline 0.08 20 0.102. $288 000 OOD $2 589 800 $29,333 43fi $0 ' Com reuian 0.08 70 0.749 $200,000 000 $15 000 000 $29 805,898 $0 � CO2RemovalE ui ment 0.08 t5 0.117 $50A00000 $2,500,000 $5,841,477 $0 � "n"Is the wntrol system economic liFe,Lypicalry thought M be 10-20 yeers. '. "i"is 5he consitlaretl the ennual pretax marginel rete of return on private investment(i.e.,whai it may cost you to borrow Ne money). � "P"is ihe cepifel inveetmenl raquirad ta inatell the controls(i.e.,equipment purchase cost,installadon/retrofit wst,engineetlng,etc.). � Annual Maintenence Cost is tlia yearly costs M maintain ihe conVol eHectiveness(i.e.,rAeanin9,tasting,etc). . � CRC=CRF'P � CRC= Capital Recovery Cast(Mnualizetl cost of wnfroi over the life of ihe conlroi) CRF= Capihal recovery Factor . . � P= Capital InvestmeM � � � - � � . CRF=I(9+QN�1+qn-9 � . � ��. i= AnnuallnterestRate � � � � �� . .n= Economic life of the conirol � Total Annual Coat�TAC)=Annual Mahitenence Cost+Capital Recovery CosQ-Realized Eeonomic Bene04 Coat to Conlro!=TAC/(Targeted Emission Volume Without Control•Targeted Emiasion Volumn wlYh Controq Reierence TAC �� CosttoControl � � Number I 8 (BRon) � . , . - Pipeline $65,070,411 $755 � BoosterStations � . . CO2 Removai Equipment � � . �PENd)�� R�I,C Yanfor�aation Seaffiffi$�°g* Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B � PreviousPage� Report Date: 04/12/2012 YNDEX OF CONTROL TECHNOLOGIES DETERMINATIONS NQTE:Draflt detrcrminations ace marked witA a"*"beside We RBLC IID. . .._._ . . . . ._ . . . . .. . . ._ _ . .. _ .. ._.. .. _ .. ._ .. . . ... .. . . , . CompanyName ��'C Country Permit Process grocessIDeseriptiov . . IID Date(EsUAct) Type � . .. . ... . .. _ . .. . . . . . . . OTTTIMWA .. _. ...... . . . . _._ . . _ . . . � GENERATYNG USA 01/12/2012 ACT I1:110 Boiter#1 � � STATION '�IA-0101 . �,. � COGENERATION USA 12/06/2011 ACT 15210 COGENERATION TRAINS 13(1•1Q 2-10,3d0) � � ��PLANT *LA-0256 � . . � �17.130 EMERGENCY GENERATOR . . SABINE PASS LNG � � � USA 12/06@011 ACT !5.200 Combined Cycle Refrigeration Compressor Turbines(S) TERMINAL "LA-0257 � � 19.390 Wet/Dry Gas Flares(4) . � ��.. � 19.390 Mazine Ftare ' '� . 50.999 � Acid Gas Vents(4) � � '�.. � 15.100 Simple Cycle GeneraHo¢Twbines(2) �. . . � � 17.130 Generator Engines(2) � � � ��.. . 15100 Simple C�c1e Refrigeratlon Compressot Turbines(16) �� 50.999 Fugitive Emissions � � '. PORT DOLPFIIN USA 12/01/2011 ACT 99.999 FY�girive GHGemissions ' ENERGYLLC *FL-0330 � . . �'�� . � 11.310 Boiiexs(4-27S avnbtW6r each) � '�.. � . . 11310 Power Generator Engines(3) � I � EIQI-HOLYCROSS USA 10/27/2011ACT 13220 Soiler -� � DRILLING PROJ � *yq,_0328 � - . 17.110 Emergency Fire Pwnp Engine � 17.110 Emergeucy Engine - � 17.110 Ceane Bngines(units 3 and 4) � � . 19.110 Crane Engines(units 1 and 2) . 17.110 Main Propulsion�ngines I . 42.000 Stocege Tanks I NINF,MQ.E POINT LA-0254 USA 08/16/2011 ACT 19:110 EMSRGENCY DIESEL GENERATOR ELECIRIC GENERA � . � 19210 EMERGENCY FIltE PUMP � � 99.009 LJNIT 6 COOLING TOWER � � � � . . . 99.009 CHILLER COOLING TOWER(CHII.L CT) � 11.310 AUHILIARY BOILER(AUX-1} . . � i � � 15.210 COMBINED CYCLE TIJRBINE GENERATORS(CiNITS 6A &6B) bIRECT REDUCTION LA-0248 USA 0l/27(2011 ACT 8 L900 DRI-101 DRI Unit#1 uon Oxide Day Bins Dust Coilec6on � IRON PLANT . � . � 8 i.290 DRI-111-DRI Unit#I Acid Gas Absorption Vent . . . � S L900� DRI-102 DRI Unit#]Tmn Oude Screen Dust Coltection � 81.900 DRI-202 DRI Unit#2Iroa Oxide Screea Dust Coilection . � 8 L900 DRI-105 DRI Unit#1 Fumace Feed Conveyor Baghouse � 81.900 DRI-205 DRI Unif#2 Fumace Feed Gonveyor Baghouse 81.900 DRI-103 DRI Uait#1 Coating BinFilter � � � � 81.900 DRI-203 DRI Unit#2 Coating Bin Filter � . � � 81.9W . DItI-104 DRI Unit#I Iron Oside Fines Hendling . � 81.9Q0 DRI-204 DRI Unit#1 Iron O�de Fines Handling . � .._._.___.._.... . . ._.. . . � � 99.009� DRI-113-DRI Unit#I Pmcess Water Cooling Towee � � � 99.009 DRI•213-DRI Uuit#2 Process Water Coaling Tower i, 99.009 DRI-114-DRI Unit#1 Clean Water Cooling Tower '� � � � . 99.009 DRI-214-DRI Unit#1 Clean Water Cooling Tower i 81290 DRId 17-Briquetting Mil! ''�, � 99.190 DRI-118-DRI Berge Loading Dock � �'�.. S I290 DRI-115-Product Screen Dust Collecfion ''I � � . 81.290 DRI-116-Screened Pcoduct Trsasfer Dust Col(ectioa � 81.290 DRI-]07-DRI Unit No.1 Fumace Dust Collection . ! � 81�.290 DRI-207-DRI UnitNo.2 Furnace Dust Collec6on ��. � 11.310 DRI•109-DRI Unit#1 Package Boiler Flue Stack � . �� 11310 DRI-209•DRI Unit#2 Packege Boiler Flue Stack ' - � 81290 DRI-112•DRI Unit No. 1 Product smrage sito Dust Col(ecHon � 81290 DRI-212•DRI Unit No,2 Product storage silo Dust Collectian � 19.390 DRI-21D-DRI Unit No. 1 Hot Flaze II 19390 . DRI-]10-DRi Unit No.I Hot Flaze � ' . � 81.200 DRI-208-DRI Unit#2 Reformer Main Flue Stack � � � 81200 DRI-108-DRI Unit#1 ReformeYMain FWe Stack 81.290 DRI•206-DRI Unit No.2 Upper Seal Gas Vent � � 81.290 DRI-106•DRI Unit No.1 Upper Seal Gas Vent � 81.290 DRI-211-DRI Uait#1 Acid Gas Absorprioa Veat 81.900 DRI-201 DRI Unit#2 Iron Oxide Day Bins Dust Collection � � BASF FINA NAFTA �_0550 USA 02/10/2010 ACT 50.003 N-I 1,REACTOR REGENERATiON EFFLUENT REGION OLEFINS � . � � SO.OQ3 N-IQ CATALYST REGENERATION EFFI.UENT �. 50.003 N-18,DECOKIlVG➢RUM �� PRXOR PLANT OK-0135 USA 02/23/2009 ACT 61.999 COOLING TOWER#2 � CHEMICAL � � � . - 61.012 PRIMARY REFORMER 62.014 N11'RIC ACID PLANT#i 62.014 1VITRIC ACID PLANT#3 . . 61.999 � CONDENSATE STEAM FLASH DRUM-AMMOIVIA PLT 4 . � 61.999 COOLINGTOWER#1 � 13310 HITRIC ACID PREIIEATRRS#i,#3,AND#4 - '. � 61.999 CARBONDIOXIDEVENL � ' � � 61.012 AMMON[UM 1VITRAIB PLANTS#I AND#2 !, � 61.999 GItANUT,ATOR SCRUBBERS#1,#2,AND#3 � I� � 13310 BOII,ERS#i AND#2 � 62A14 NITRIC ACID PLANT#4 . � � RUMPKE St�NITARY OEi-0330 USA 12/23/2008 ACT 29.900 ENCLOSED COMBUSTORS(4) - ' LANDFILL . '. . 29.900 M[INICIPAL WASTE LANDFILL '� . 29.900 OPEN FLARE � . 99150 PAVED ROADWAYS AND PARKING AREAS � � � 29.900 CANDLESTICK FLARE(� CPV ST CHARI.ES �.p040 USA I1/12/2008 ACT � 99.999 COOLING TOR'ER 17.21U INTERNAL COMBUSTION ENGINE-EMERGENCY � GENERATOR 17.210 INTERNAL COMBUSTION ENGINE-EMEBGENCY FIRE � . WATER PUMP 13.310 BOILER � 15.110 COMBUSITON'I'URBINES(2) � � � 13.310 FIEATER ACTNATED CARBON LA•014d �USA 0Sl28/2008 ACT Y 1.110 NNLTTPLE FIEARTH FURNACES/AFTERBURNERS � PACILITY � � � 99.009 COOLING TOWERS , TWO(2)ELECTRIC ARC FLIRNACES AND TFIItL�E(3) NUCOR DECATUR LLC py.0231 USA 06/12/2007 ACT 81.210 LADLE METAI,LURGY FI7RNACES WITH TWO(2) � � � MELTSHOPBAGHOUSES . 13330 VACWMDEGASSERBOILER " � � � 13.310 GALVANIZINGLIlVEF[JANACE 81.290 �VACUUM DEGASSER - � - AIItPRODUCTS �_0481 USA 11f02l2004 ACT 99.999 PARTS WASFIER . � BAYTOWNII 50.007 F[JGITTVES(4) � � � 64.003 MSS PROCESS STEAM VENT � 64.003 PROCESS STEAM VENT . � . 19.800 EMERGENCY GENERATOR TANK � � 64.003 MSS-NO2dCONDENSIBLES(PROPYLENE VENTING) . 19.310 FLARE(NORMAL,OPERATION) . . 64.003 � RECTISOL VENT . � 19.800 EMERGENCY GENP,RATOR � . 42.005 DIESEL F[TEL T.4NK . � � 13.390 BOII.ER STACK(START UP) � . � �. 11390 BOILER STACK(HIGH BTU FUEL) � . 50.005 COOLING TOWER � � 50.005 SUPPLEMENTARY COOLING TOWER � . 11390 BOILERSTACIC � � RUNIPKE Sl�.NITARY OH-02S1 USA �6/10/2004 ACT 29.900 PORTABLE TCiB GRINllER � � . LANDFII,L,INC � . � 29.900 LANFILL ROADWAYS . 29.900 �LEACHATE�STORAGEBASIN � 29.900 LEACHATE AERATION BASIN 29.900 �GITIVE ENIISSIONS FROM LANDFILL AND GAS . � COLLECTION SYSTEM . � . 17210 PORTABLE EIdGINE 4.68 MMBTU/H 29.900 �'Ek'SOLTD WASTE DISPOSAL WITH LANBFILL GAS GENERATION � . 17.210 PORTABLE ENGIlVE 6.58 MMBTUlA . �� 29.900 LOAD-IN,LOAD•OUT,TURNING,AND W[ND EROSION . 29.900 PORTABLE SCREENER � � 29.900 EHISTING SOLID WASTE DISPOSAL WITI-I LANDFII,L GAS GENERATfON � �-- � � PreWous Page �, ,�� r�- � �.� � "' �' :i �� °� �� . Kerr-McGee Gathering LLC � � � P.O.Box 173779,Denveq Colarado 80217-3779 � , . 720-929-6000 Fas 720-929-7000 November 29,2011 ` � p � Mr. Christopher Laplante , Air Pollution Control Division—Oil& Gas Team fi ' �s��, ,��1, ' Colorado Deparhnent of Public Health and Environment , 4300 Cherry Creek Drive South Denver;CO 80246-1530 RE: Facilfity Modification Appincation Fort I.upton Gas Plant Weld County,Codorado Dear Mr. Laplante: Kerr-McGee Gathering LLC (KMG) is requesting to add a cryogenic plant at the Fort Lupton Gas Plant and shutdown existing compression with this application. The new plant will be located on the eastern fence line of the existing Fort Lupton Gas Plant as shown in the plot pian contained in Attachment G. The plant will utilize two (2) amine treaters to remove COZ from the inlet gas stream which will then be dehydrated with a molecular sieve. The amine will be regenerated with one 90 MMSCFD heat medium heater and the molecular sieve beds will be regenerated with dry gas heated in the 20 MMSCFD gas heater. The dry gas will be run through the cryogenic unit to remove natural gas liquids (NGLs) and then transported offsite via a pipeline. Propane refrigeration compression will be driven by three (3) 2,500-hp electric drive engines. Residue gas will be compressed by two (2) 11,000-hp electric drive engines and sent offsite via a ' p�peline. As part of this modificafion, KMG is also requesting to remove EU-35 and combine the hours of operation of EU-31 and EU-32. These engines perfoIIn low inlet compression afthe existing Fort Lupton Gas Plant. Due to an increase in compression and gathering efficiencies in the field, the low pressure inlet compression as mentioned above will no longer be needed at the facility. In this facility modification application,KMG is Yequesting to: • Add two(2) 11,000-hp electric drive residue compressors. • Add three(3)2,500-hp electric drive refrigeration compressors. • Add two (2) 150 MMSCFD each, amine treatment h-ains. Still vent and flash tank emissions from each train will be controlled with a thermal oxidizer. • Add one(1) 90 NIMBtu/hr amine regenerator heat medium heater. ' • Add one(1)20 MNIBtu/hr molecular sieve gas heater. • Add one (1)emergency flare to handle plant upsets. • Add one (1) emergency 670-hp Caterpillar diesel generator which will operate a maximum of 500 hrs/yr. • Add emission estimatws of fugitive emissions from the cryogenic plant. Since the plant will receive a mixture of third party gas from the Keq-McGee gathering pipeline system, a representative sample of the streams is not currently available. A worst-case scenazio was utilized to estirnate fixgitive emissions. � Remove E�J-35, a Fairbanks 1Vlorse MEP 10 1756-hp low pressure inlet compressor. � Limit the hours of operation of EU-31 and ELT-32 to a combined 8760 hrs/yr. These engines are both Waukesha L7042 954-hp low pressure anlet compressors. As previously instructed by the CDPHE, KMG submitted one AI'E1V for each engine showing maximum potential emissions but requested the limited hours in the additional notes section of the APE1V. Uncontrolled potential emissions from the modification were above PSD significance thresholds for both CO and S�OC emissions and therefore, a netting analysis was completed for these criteria pollutants. K1VIG determined CO and�1�C actual euazssions in terms of an average rate in tons per year for Units 31, 32 and 35 using the October 2009 to September 2011 consecutive twenty-four montl� period that precedes the project (Regulation 3, Part D, Section II). Fotenrial emissions were assumed for the proposed equipment as per Regulation 3,Part Y�, Section II..4.l.a As shown in the table below, the proposed modification does not result in a significant net emission increase of criteria pollutants and is not considered a major modificarion for criteria pollutants. . fort Lupton Gas Plant Wide�-Net Emission Increase from a fNodification(TPY� . Unit ID � Status HRh'R NOx CO VOC SOz PM10 - . �. . � ModificationProject#3 �� . � � � � E-2015 Mole Sieve Regeneration Gas Heater . ADD 8760 � 3.94 127 0.5 0.1 � 02 N-6050 Amine Regeneration Hea4 Medium Heater ADD 8760 17.74 572 2.5 0.3. 0.9 � A-1 150 MMSCFD Amine Treater(Controlled with ATO-1) ADD � 8760 4.60 24.3 3.5 15.3 A-2 150 MMSCFD Amiae Treater(Cortrolled with ATO-2) �ADD 8760 . 4.6D 24.3 3.5 15.3 F-2 Vertical Emergency Flare . ADD 8760 0.4 2.0 GEN3 Caterpillar 670-hp Diesel Emergency Generator ADD 500 p,1 0.1 0.0 1.2 0.01 ' � FUG3 Piant Fugitives � ADD 8760 Zp 9 - . �. EU356 Fairbanlcs Morse MEP 10 1756-hp RENIOVE 8760 _.70.0 ��13.3 -12.0 -0.03 -3.1 EU-31'�s � Waukesha V042 954-hp UPDATE 8760 -23A � 38.4 -6.9 -0.02 -D.3 � � EU32'�s � Waukesha L7042 954-hp UPDATE � � � To8�9 Emissions from Modification Project#2 -59.7 69.D �2.0 32.0 -2.3 PSD Signi£cance Threshold 40A 90U.0 40.0 40.0 25A '�.. 'KMG is requesting that EU-37 and EU32 be limited to a wmbined 8760 hours of operation �� . s Emission reductions for CO and VOC reflect the actual emissions for each pollutant during the iwo yeaf consecutive 24-month ' period of October 2009 to September 201 L � . � As reflected in the table above and in the calculations of Attachment C, the requested modifications results in a net decrease in NOX emission of 59.7 tpy and PMlo emissions of 23 tpy. Proposed emissions from all other criteria pollutants are below PSI� significance thresholds. As shown in the calcuflations of Attachment C, the proposed modification results in a net emission increase of more than 75,000 tpy of COZe and therefore, KMG is submitting a major modification application for greenhouse gases (GHG). A GFiG BACT analysis can be found in Appendix J of the application. 2 Enclosed with this letter are the Kaizen application required forms and documentation for the proposed modification. In addiflon, Appendi�c J contains the �ACT' analysis for the Greenhouse Gas PSD modification as required by the PSD and Titfle V Greenhouse Gas Tailoring Rule. If you have any questions, or require additional information, please contact me at (720) 929-6028 or Jennifer.Shea@Anadarko.com Sincerely, KERR-MCGEE GATHERING LLC . � "', � � �� .�f i i �� b A r- .-t.,� :�a__ � . . . ��i.�ti�, _. . i, Jennifer L. Shea Staff EHS Representative Enclosures ec: Mike Ross, Matt Berghorn,Mike Forsyth,Jay Allin,Kevin Osif,Rob Smith,Mick Rafter and Troy Person 3 � � �w�7 cnr�} . ��YIlIl� �� '� �' �' Colorado I)eparhnent of Public E�ealth and Environment � � �'� . ve4...�',-.-r'»�4 Air Pollution Control IDivision �;_,H,�A.� �:nEmra�cn I�e��ari�:betnc �uf S'�iFla[ec�Ical�lr �fi� �.' �a�S �ffi�9@��1 ��vdf•:ai�°irmmmn€n� �'��t�°�c�� Il� Ag��ta�� C��p�� n��fi�� Ver. September 22,2008 C�magn��y I�i�affi�e Kerr-1VIc�'see Gathering LLC S�aa�s�I�T��a�e Fort Lupton Gas Plant �A�a�e 11/29/2011 Yes No Are y�u requesting a facility wide permit for multiple emissions points? � ❑ In order to have a complete application,the following attachments must be provided, unless stated otherwise. If a�plication is incomplete it will be reriuned to sender and filing fees will not be refunded. A4tach�e�4 !� IlaC�g9��lE➢�aua¢�g e�qap&nc�ien� ��HD A APEN Filing Fees � ❑ � Air Pollutant Exnission Notice(s) (.4PEI�Ts) �i � � A plication(s for Construction I'ermit(s)—�a�iC'llD �'��unn ��a�a�� Emissions �aiculations and Supporting L)ocumentation • � ❑ &� Company�ontact Information- �'��sm l��IlD�Il�Il � ❑ � AmbienC Air Fmpact Elnalysis � ❑ ❑ Check here if source emits only VOC (Attachment E not required) � Facility Emissians Inventory—��a°�a A��II➢-Il�� ❑ ❑ Check here if single emissions point source(Attachment F not required) � I'rocess description, flow diagram and plot plan of emissions unit and/or � � facility ❑ Check here if single emissions point source(Attachment�not required) �3[ Operating�i 1Vlaintenance (��zM) Plan—�I��B9 �+�g�n ��°e�s 3�0 � ❑ � Checic here if frue minor emissions source or application is for a general permit(Attachment H not required) d Regulatory Analysis � ❑ � Check here to request APCD to complete regulatory analysis(Attachment I not rec�uired) Send ��ffinar�et�¢Application to: C�9�a°�a�m �D�ps�n°¢uun�an��Paa9rfln��¢a�gH� �a �aae�fl�°�ua�n�ffi� �]P�B➢-S�-]�Il �30� C�� c�a°��➢�E9�fi�e ��nngHn �D�aa��°, C�9o�°�aIl� ��4�-Il53� Check box if facility is an existing Title V source: � Send an addational application copy Check box if refined modeling analysis included: ❑ Send an additional application copy _ � I�agO 1 Of 1 Foim APCD-100-App CompleteChecklist.doc . ��t��c�lfir��at � WGR Operating LP PAGE: 1 of 1 . PO Box 1330 � � DATE: November 23,2011 �Houston,TX 77251-1330 � TRACE NUMBER:742102544 � � CHECK NUMBER:742102544 �� AMOUNT PAID:$305.80 � � ACCOUNTS PAYABLE INQUIRIES(800)370-9867 �Qoa�e��soeo�8u8¢On�e�lonaae��o�u�coo�o�o��oA�soe��oenOo�oo� �� 00052 CKS 6A 1132P - Di42102544 NNNNNNNNNNNN 32i5100�02504 %392D1 C � COLORADO DEPT OF PUBLIC HEALTH & � ENVIRONMENT � 4300 E CHERRY GREEK S DR � DENVER CO 80246-1530 = VENDOR IVO:0009402886 � VENDORINV#! INVOICEDATE TOTAL PRIORPMTS NE( - DOCUMENT# REMARKS AMOUNT BDISCOUNTS AMOUNT 1900002721 CKR4172111 11/21/11 $305.80 $0.00 � $305.80 � FORT LUPTON CRYOGENIC PLANT PERMIT APPLICATION-LIMITS HOURS OF � 31 AND 32 TOTALS . � $305.80 $0.00 $305.80 _, a �it6V J'� [��'�.. . . . . ..,:�`,� � . . �� . :�q,`rJ�J0110iV PLEASE OETACH BEFORE DEPOSITING CHEGK . � CHECK 741292 _ WGROpera4irngLP NUMBER 742102544 �24 PO Box 1330 . � Houston,TX 77251-1330 . �vove��e��a, ao�� PAY COLORADO DEPT OF PUBLIC HEALdH & � To THE ENVIRONMENT ORDER OF: 4300 E CHERRV CREE9(S DR � _. CHECKAMOUNT DIENVER, CO 8024fi-9530 � ��a��o� e �0.�.� � � � . � � � ��.��.. ]PMorgan Chase Bank, Dearborn . �,„��o'Eo""ruRes � �� ,., Deafborn,Mi[higan 8 sEe oe,aas oN encx AUTHORIZED REPRESENTATNE OF THE COMPANY na7� 2bD25��e a�072� � 2 � 2700 75� 66� 7� 2�i° ' WGR.Operating LP � � PAGE: 1 of 7 PO Box 1330 . _ DATE:November 23,2011 � , Houston,TX 77251-1330 � TRACE NUMBER:742102545 . � � CHECK NUMBER:742102545 . . � � AMOUNT PAID:$1,070.30 � � ACCOUNTS PAYABLE INQUIRIES:(800)370-9867 ��e��n�0000ns8n0o�aoBr�80esoieSla�a�n�eBe�ua��e�Os�o��000�0�008 � � � ❑OO53 CKS bA 1132i - 0i421�2545 NNNNNNNNNNNN 32T51��025�4 %392D1 C � - COLORADO DEPT OF PUBLIC HEALTH & = ENVIRONMENT = 4300 E CHERRY CREEK S DR = DENVER CO 80246-1530 s VENDOR NO:0009402886 � � DOCUMENT# VENDOR INV pl INVOICE DATE T�TA� PRIOR PMTS NET REMARKS . 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O N�C] O:t[l!�-iN:�-�(Le'Ni :Oli[pitn fQiWil�:OlNiC'�Oif�I,N V E �v . ��n:mv�vw;�: :ava:<,,o c�o�a:m�a�a;m:o:.- E 'E �'�`o E v � N!N:N NiN!Nir�N�N:NjNiNiN!N:N N;N!N:N;N(N:N;�:N E c a0 O L . _ "v H- o o `e° n . � . d'� w m N a rn�m�m o�o�o�o�o,o�o�o�o�o�o o .-.-.-��•-.-.- y m `o_ ¢E . 0 0 0 ��.-...-.-�..�.-��.-��•-��•-�•-•- 0 0 0 0 0 0 0 0 o c o 0 0�0 0 0 0 0 0 0 0 � a o�E�h�:_ � N N N N N N N N N N N N N N N N N N N N N N N N ym co N�E �y d m� a L ` a E � � ��p rj . � '° m � � 2'�L c ' w a y y � 2 r�i.- �a E � a`��C c g � v c `�a 3 �v� o " w a A ` � �S � v a a' c 4 n � oz°a �u.�a�»¢(nozo -�a�¢�-'�-,¢m .- . �r- ov' . . ... .. ... _._ .... _ . . .:_.. .._.. ._ .. . . . . . . ....... __.__.. _._ .. . ��U4�a��4or� ��s �Iaa�4 ��gso��o� �P�� ft�o9e�iev� R�ge�ae¢'�@Aoa� �� 2��B�e,�'P�� e�� I , F9eateP Data dUlake: Mole Sieve ��c�neration Gas N�aie�'t�iiih �a.v f�iQ^ Eur:�ers AIRS ID: TUt t SourcelD E-2Ci5 Nameplate VRating: 20 (MMBtu/hr) Efficiency: O.�G (decimal) Heat Input: 25.0 (MMBtu/hr) �peration: 8760 (hr/yr) Fuel Heat Value: 1020 (Bfu/scf) E¢niss6��a Calc¢alataoa�s Emission Factors Emissions Adjusted Pollutant Source Ib/MMsc# Ib/MMBtu Ib/hr tpy Ib/MMscf* �IOX manuf. Q04 0.9 3.9 CO manuf. 0.i i6 2.9 12J VOC manuf. 0.D650 D.1 0.5 SOZ AP-42 0.6 0.6 0.001 0.01 0.06 CH2O AP-42 0.075 0.075 0.000 0.002 0.008 PM,o AP-42 1.9 1.9 0.002 0.05 0.20 Benzene AP-42 G.0021 0.0021 0.0000 0.0001 0.0002 Toluene AP-42 0.0034 0.0034 0.0000 0.0001 0.0004 " Emission factor conversion based on footnote"a"of AP-42 Table 1.4-1 to convert from 1,020 Btu/scf to the above Fuel Heat Value in units of Btu/scf. CO2e Eonisseo�s �alculations C�aod�asaoo��; 1 Metric Ton = 2204.62 Ibs 1 kg = 0.009 metric tons ueoegmac �000�a��a ��o�� a�� trowi � COZ 53.02 11,611 12,799 CH4 0.001 0.22 0.24 N20 0.0001 0.02 0.02 C�ye� 12,812 � . CO2e=COZ+(CHy*21)+(NZO"310) � � � ��o�0@o� ��s �Van4 ��y��eeaa� ��e�k 6��a�@ �fle�0asuro �ae�d F9e��P, �o�Br� � a�� FBea#er Da&a Make: famrr,e�teg�neration P-IeaL [J�eai�,m Heater-Lo��v I�il�x Buri7ers � � � Description H-6G50 EVameplate Rating: 90 (MMBtu/hr) Efficiency: O.UO (decimal) [ieat Input: 112.5 (MMBtu/hr) Operation: 8?6C (hr/yr) Fuel Hea4 Value: i020 (Btu/sc� �an�ssiooa Calculatoons Emission Factors Emissions Pollutanf Source Ib/MMscf Adjusted Ib/MMBtu Iblhr fipy Ib/MMscf' RIOX manuf. 0.04 4.1 177 CO manuf. 0.116 13.1 57.2 VOC manuf. Q005 0.6 2.5 SOZ AP-42 O.G 0.6 0.009 0.07 0.29 CHZO AP-42 0.0%5 0.075 0.000 0.008 0.036 PM�o AP-42 '1.9 1.9 0.002 0.21 0.92 Benzene AP-42 0.0021 0.0021 0.0000 0.0002 0.0010 Toluene AP-42 OAQ31 0.0034 0.0000 0.0004 0.0016 " Emission factor co�version based on footnote"a" of AP-42 Table 1.4-1 4o convert from 1,020 Btu/scf to the above Fuel Heat Value in units of Btu/scf: �02e Emissior� CaOcaa@ations Coa�versioma�: 1 Metric Ton = 2204.62 Ibs 1 kg = 0.001 metric tons Pol0u4an4 Is�/er�eua�taa �uu�4eo��u� 4�y COZ 53.02 52,251 57,597 CHQ 0.001 0.99 1.09 N20 0.0001 0.10 0.11 ��ze= 57,654 COze=COz+(CHq*21)+(NzO*310) � --- Foet Lu�ton Gas PIan4 � � Ceyogenic Plaeeh Amine Trea4er New4 Stach Emissdons-i'saive 9 � � � . � Source ID . n-I � � AIRS ID � i�� Bource Description 150 MMSC�D Amine Treeiiny Systein.iraio 5 � Potentialoperetion �7G0 �hrs/yr � � � Amine Simulation Results(17/75/19j. � . CO2e Emission Calculations � � Acid Gas Flash Gas Flowrate(MMscidj 4.4 0.1?0� COOvel5ion5 �Pressure(psig) 8 60 Molar Volume to Molar Mass � 3798 scf/l6-mole � Temperature(°F) 12o i5� : �. Composition � PAoI% � Ib/IG-male . GHC Caiculation Acid Gas Flash Gas Nitroozn E.634E-05 or130� 28.0� � . Pollutant scf/yr . 4ons/yr scf/yr tons/yr � Co2 5t.s94 '1o.42k 44 COi � �q7�103622 85326.34 4.58E+06 266 HydmgenSulfidc 'i.017E-02 1n14E-03 3A.oe � Methane I.347E07 63.8302 1G.04 COga= 85,592 Ethane 377_OE-02 ti.939 30.07 `Calcula�ionlnethotlimmAPI2009GHGCo(npeOtliNn5-02 � � PfOp3fIB 1.324E�2 d,Q085 G4.1 �. � `COxQpyQ=lsef/yQ/�scf�b-male]•�MW�l�lbstlon] � YI-B4i2f1¢ %.343E-03 '1.5963 58.12 � � i-Butane 2753E-02 1.8528 58.�2 __ n-Peniane 8.GI0&Uh 0254 7?.IS VOC Emission Calculations � i-Pentane 9S46C-�4 02816 72.15 � � � n-Hezane � 9929E-G4 .02444 8G.17 COnVelsion5 . Wate� 8.3i3E+00 S'2371 � Molar Volume to Molar Mass 379.3 scNlb-mole Toial � 100.0 100.0 VOC Calculation Acid Gas Flash Gas . PolWtant scfNr tons/ r scf/ r tons/ r . � Pro ane 2.13E+05 12 1.85E+06 108 . . , n-Butane 1.18E+05 9 7.02E+05 54 i-6utane 4.43E+05 34 8.14E+05 62 . � n-Pentane 1.39E+04 1 1.12E+05 11 � � � i-Pentane 7.54E+04 1 124E+05 12 n-Hezane 1.60E+04 2 1.07E+05 12 Uncontrolled VOC'9.1 Factor = 350A � VOC x 99%Control Efficiency 3.5 � i I Fort Lupcon Gas Piant Cryogenic PlantAmine Treater Theemal Oxitlizer Emissions,Trzin 9 Source ID A-TG9 � AIRS ID ��D � Source Description Train 1-i hermal OxiUizer to ConYrol Hmioe Potentialoperetion ar60 hrs/yr "`stream will be mutetl to emergency flare when TO is down. . Combustion Emission Calculations Amine Simulation Results 11/15/77 Acitl Gas Flash Gas COflve�siOflS Flowrate(fvlfNsc{tl) 4.4i0 i 0.1204 � Molar Volume to Molar Mass 379.3 5CNIb-mole Pressure(psig) � 8 60 "femperaWre("F) 120 157 � . Heatof �� Amineslillvent � Composiiior. �Mol% fNol% Ib/IG-mole . ... �Combustion� andflashgas HeatContent.-. . Componant ��Formule. [Btullbj�� [Idlhr] � [6tu/hVJ�. . methane CH4 27502 i?5.G80G 3136724 Nitmoen 8.G34E-05 0.130 28.01 ethane C2H6 20416 5'_f10i0 1080028 CO2 91.394 70.426 °4 p�opane C3H8 18929 ?.Z3"r51 545559 Hytlrogen Sulfide i.017EU2 i.C74E-03 3q.0E o-bufane C4H70 � 19665 ih3362 281981 Phethane 1.a47C--01 6:.83G2 16.04 isobutane C4H70 79674 2t 9�GG 431363 Ethane � 3920E-02 1'i.'J35 30.07 n-penlane C5H12 19499 � e.7248 53730 Propane L324E02 42085 4A.1 isopentane C5H12 19457 3080� 58759 n-Butane 7.343&03 . I�963 5II.12 n-Hexane � � C6H14 �1920� 3A9'J9 67438 i-Butanc 2.753E-02 1.852II 58.12 Total(BW/hr)= 5fi48962 n-Pentane 8.610E-04 0254 72.15 � i-Pentane 9.54(iE-04 02f31G 72.15 n-Hexane J�9'L960S 0,244h UG.17 Heatlnpu[ Waier 8.373E�00 5237� � TO Burner Heat from Amine Still Auuiliary Fuel Total Heat Input hreryr Rating VentandFiash Gas (MMBtu/hr) Total 100.D 10�.0 MBtu/hr Gas MMBtu/he MMBtu/hY 5.00 5.6 3.00 13.65 � 8760 Poilutan4 Ib/MMBtu Ib/hr toNy�* � � � � � � �Npz 0.07 0.96 4.6 CO 0.37 5.05 24.3 � � � *Total emissions*11 factor � � � W2e Emission Calculations � . � � Co�versfons: '. 1 Me�dc Ton= 2204.62 Ibs . 1kg= 0.001 metnctons � POllutant k /mmbtu metric Wn/ r t COi 53D2 6,339 . 6,987.91 . CHq O.OD1 042 0.13 N�O 0.0001 0.01 0.07 COu= 6,985 ' ' co,�=co,+(cH;zi +(N,o��o) S02 Emission Calwlalions � � Conversions: Molar Volume to Molar Mass 379.3 scf/Ib-mole S02AtomicWei ht 84.05 amu � . . H25 Atomic Wai ht 34.06 amu � Acitl Gas Flash Gas � � � . Pollutant �b/hr t Ib/hr t H25 1.678E+00 - 7.351E+00 6.374E-03 2.792E-02 .. 502 13.8 � D.OS � . . Total S02 emissions(tpy)' 1525 'Total emissions'7.1 factor Foet Lupton Gas P9anY � � � Ceyogenic Plank Amine tceater 4/ent SQacPc Evteissions-Tr�ivo? . � Source ID a-<. AIRSID �� Source Description . I50 A�MSCFO Amine Tre�iinn Sysiem,Train? . � � Potentiai operation E760 hrs/yr � - � � � Rmine Simula4bn Results(99/15/17) CO2e Emission CalcWations � Acitl Gas Flash Gas � . �lowraie QJfNscfd) . 4.4 0.'1204 � Pressure(psic�) 8 60 Conversions � Molar Volume to Molar Mass 379.3 scf/lb-mole remperature(°F) 720 �5� Gamposition Mul% IU/Ih-mole GkG Caleulation Acid Gas Fiash Gas Nirrogen � e.G34E-o5 0.�30 2a.o� Polluf2nl SCflyf i00s/yf SCflyf fonS(yf CO2 9t.39? i0.424 � 44 COz 1471103622 65326.34 4.58E+06 266 Hydrogen Sulfitle t O17E-02 1.414E-as 34.Oe � Meihane �L347E-o1 63.8302 1604 COza= 85,592 � Ethane � 3720&02 11.939 � 3007 •CalculalionmetM1oafmmAPI20o9GHGCompentlium5-02 Prcpane 1.32.4E-02 42065 44.i � �coi(tpy)=[scr/yr]i[sc0ibmoie��[Mw7lpbsnon� � n-Butane %.343E-03 1.5963 58J2 i-6utane 2.753E-02 ".8528 58.12 � . n-Pentane � O.6i0E04 025�t 7Z.15 . VOGEmi5sionCalCulatio�s i-Pentane 9?ti6E-US 028'iC-' 72.15 . � . � H2zane 9.929E-04 024qn II6.17 � ConvC�5iOns � N/ater H.373E�00 523!'I Molar Volume to Molar Mass 379.3 scf/Ib-mole Total ioo.o 700.0 VOC Caiculation Acid Gas Flash Gas PolWtant scFl r . tons/yr scH r tons/ r Pro ane 2.13E+05 12 1.85E+06 108 . � n-Butane 1.18E+05 � 9 7.02E+05 54 i-Butane . 4.43E+05 34 8.14E+05 62 � � � � � � n-Pentane 1.39E+04 1 1.12E+05 11 . � i-Pentane 1.54E+04 1 1.24E+05 12 . � Hexane 1.60E+04 2. 1.07E+05 12 .. UncontrolledVOC"h.1 Factoe = 350A� � . � � VOC x 99%Cantrol Efficiency 3.5 . . .__.. ... � . .. .._. ... . . .__.. _... . ... ___._. ..___._ . ___... _._. Fort Lupton Gas Plant � CryogeNc PlantAmine TreaterYhermal Ottitlizer Emissions,Train 2 � Souroe I� � A-TO2 . � AIRSID ?BD � � � Source Description Train 2 Therm2�Gxidizer[o Cont:nl Fmine . � � � � Potentiai operation � s7so hrslyr . *"s[ream wili he routetl to emergency flare when TO is down. . Combustion Emission Calculations Amine Simuiation ResWts(11/15R9) . � Hcitl Gas Flash Gas ConVE�5ion5 � � ' Flo�vra(e(NMscfd) ?.410 0.72�4 Molar Volume to Molar Mass � 378.3 scf/Ib-mole Pressure(psiS) 8 60 � � TemperaNre('F) 120 757 � Heat oF ��Amine still vent �' � Composition ivioi% Mol% Ih/Ib-molc- . Combustlom.� andflashgas� HeatContent . � . Component ��:Formula �� [Bh/Ib]�:� pd/hr]� ��.� [etuthY� . � methane CH4 21502 1vGY80fi 3738724 Nitfogen 6.634E05 0.13D 2£,07 ethane C2H8 20416 52�010 1080026 CO2 91.39? 70.R24 4A propane C3H8 19929 773751 - 545559 � HydrogenSu!iidE i.057c-02 'I.C14E-03 34.0B n-6utane C4H10 19665 Id:i3U2 261961 Methane 1.347C--0i G3.8302 16.04 Iso6utane C4H10 19674 2t9�J2G 431363 Ethane 3720E-02 11.939 30.07 n-pentane CSH12 19499 i7246 53130 Piopane 1.324E-07_ �2085 44.'I isopenlane CSH72 19451 . 3.0209 56759 � n-Butane %.3436-U3 'i 5963 58.12 n-Hexane C6H14 19200 31999 61438 i-Bu[ane 275;Gpp 1B52n 58.12 Total(BtWhr)= 5648962 n-Peniane 8.610L(14 0254 � 72.15 . i-Penlanc 9.546604 . 0�81G 72.15 . . � n-Per.anc 9.929&0A � 02444 Z6.'17 Heatlnput water 837aE+oo 523ii � ' TO Bumer Heat fram Amine Still Auxiliary Fuel Total Heat Input hrsfyr Rating VentandFlash Gas (MMBtulhr) � "fo;al � t�0.0 100.0 (MMBtWh�) Gas(MMBtu/hr) (MMBtu/h�) � 5.00 5.6 3.00 73.fi5 876� Pollutant Ib/MMBtu Ib/hr Wn r � � � . NOx 0.07 0.96 4.6 . . . CO 0.37 5.05 24.3 � � 'Total emissions'7.7 factor � - CD2e Emission Celculations � � Conversions: . � 1 MeMcTon= 22�4.62 Ibs � . 71cg= �A�'I metncrons . � Pollutant kg/mmbtu metric ton/ r t � ' COz 53.02 6,339 6,987.91 . CHa 0.001 0.12 0.13 . Nz0 0.0001 0.01 0.D7 ' cp,�= s,sas � . co„=ca,+cH,•zi)+M o�aio � 5O2 Emisslon Calculations � Conversions: MolarVolumetoMolarMass . 379.3scf/Ib-mole . . S02AtomicWeiqht 64.05amu _� � � H2S Atomic Weiqht 34.08 amu � . � Pollutant P.citl Gas � Flash Gas . Ib/hr � t 16/hr t H25 1.678E+pp 7.351E+0� 6.374E-03 2.792E-02 . 5O2 13.8 0.05 . Total SO2 emissions(ipy)* 1525 � � "Total Emissions°L2 facfor . � � � � � _. .._ .... ... . . ... . .. . . . .____.. ._.... ._. B � � �a�� . oowConflde�rtlal �OP9�61�ffi . � � . . F➢��e Aeaadark� Cey�gero6c P9ae�g � �overpa�e � � . Conten4s � . 3 39mae9atlon Suanmaeeg 3 � Inle4 Streams � Outtet SYreams 4 Pumps,Compressors,Turbines, Expantlers � � 4 � . Heat Excha�gers � Absorbee(COLUMR�) 4 Regeneretor(COLUMf�) � Sleeaulation Gtobo9 De4a 5 Global Data � Stream Y�bie q0 hhake-up Stream(s) � � � Process Flovr Dlagaaera 9� VNa)or Equlprcaan8 Summary �2 Amine Baos4er Pump(PUMP) . � q2 Amine Circ Pump(PUAflP) 12 Heater-9 (HEATER) �Z i Lean Amine Cooler(HEATER) �Z UR Amine Exchanger(HEATX) 12 Flash-1 (FLASH) �3 Inlet Filt/Coelescer(FLASH) 73 Rich Amina Flash Tank(FLASH) 13 13 � Absorber(COLUMN) � q4 � Regenera4or(COLUMN) ' The Dou�Ghemical Co�npeny Oae.Treatln8 Technology Group - CopyMght O 2002-2070,The Dow Ghemicei Bampany 9roComp Process Slmulatmr Veesion 6.1 A.2 . � � 78 Nov 20N 1,Pege 2I75 � �� ._-_ ___ ... .._. . _... _ .. � � w �8�� . . � � �ow�ue6V�eauefa9 II �Beaaae8a�u�a��a��soaau�ry 6��w�r��rC��p��c¢�� B�a�� 8¢a@�@$BPe�ovos � $Tp 0.9.1� 9 � - �� Bb�m Nama � .. Inimt BloElt BiL FC Ges Tam areture tlo F it0.00G0 Preeoure � Pml e . 0 . W0 PGfOttlen % 9 . 000 � F aWIffia mmr 7.3092E+05 . Volumm Flaw LI Wtl U I/mN � � � . 9lolUme ImV a oP M 86P6 uuF .�� WetaP moP'h t.0862E-02 � � . c0f801AP•89�tl maB% . 000 � � � C¢e6onBloaitl¢ molK �� N m BnBUMtl� moC% 2. E-04 � ' �p 9p maB% 0. 00 MOthene ma9% �4.68 8 Etl��na m57% 92. B � , ro nM� md% 5.5]B6 . . � ro utane mol% 7. BBB � . IBo- utnna` mo1% .BBBB . � n•Pemane ma 76 o.a oo � Isp.Pentena° mo�% O.6�BB . � �� mHaxenO mml% o. o � � � . YOTd6 onol% 7W.OW0 - O0d$V��P��Pg15 . � BTflEAR9.lD 8 8 77 BM199mName � Fleeh06e AtiCGae 0NI¢t Bloc# � �mh Gea� Adtl Oea h ee o y � � Tem re9uoe EB F 9E8. 10 20.OW0 120. B ' PlBeeuM Psi BO.W00 e. 00 849.0688 � � Va e �octlon % tW. 1 . 1oa. ao . � Flowr&te IbfM 830. 838 4.09 W4 8,9108E+06 � � . VolumeFlaw LI ul0 � UB eVmin ' . � VolumaFlOW a M 9CR9 0 024aB 8818(f 28f.38H7 � 4 � 1J�a�gP �Ilol% 9 8,3]3 02165 UCePdaE&P•814 Q mmt% . 6.B]B4E�04 1.8875E-05 1.0237EA9 � � camonoio.iem rtroF% 10.4236 81.3838 4.5161 A3 � . pl tivo en 9u oa � mo1 x t.4i42EU3 1.0186E-02 B.]63B -0B � � Nttw en mol% 0.1904. 8.8341E-05 0.4104 . Metliana mo!% 83.8802 0.7347 18.4918 . ' 6 hane � mol X 71.8380 3. t -02 12.8714 . . PIa ene Oiol% 9. 1.32 �02 .�32 . . � n• WnnO mol% . t.6B63 7.3428E-03 }.6956 . �� Iea�BulOnB° mol L8528 2.7 28 -02 0.8845 n.PerMne mn�% 02546 B.BiWE-04 0.79 . IaaPenfene° moi% 0.28 6� B.5A58E�U9 Ub 'I �-Xezene molS6 0.2444 9.9285E-(14 U.4618 � � yp mml% 9W. tW.0000 100.W 0 . . . ��o�w cpemaceo cmmPa��as qr�aeiw�v�eb�oo�ev��a � Cmpyeighe B 20�2-2090a 4be��vvu Ghev�i96e9�o[wpe[�y . . � P��mroep Process Sionm9atme 4iees0oua�.8.9.8 95�9oe 2649.��3fN� i,l v . �u8 d��a�5 �oww confiidearc�a� Pavm�s Coeaaores�o�s.%ueb6nes.@x�acad�es Amine Booster Pump(PUMP)Power. . 44.3809 HP � � � � Amine Ciro Pump(PUMP)Power: 932.5520 HP � Heat Exchanaers � Heaterv9 (HEATER)Duty: � � -6.3787 MMBtWhr . � � Lean Amine Cooler(HEATER)Duty: -35.4243 MMBIWhr � � � Uk Amine�cchangar(HEATX)Duty: 34.0872 MMBfWhr . . � . Ptesh-1(FLASFq Duty: �0.0000 MMBtWhr � � Inlet Filt!Coalescer(FLASH)Duty: � O.OOOD MMBtWhr . - Rich Amine Flesh 7ank(FLASH)Duty� 0.0000 MMBtWhr � � Ragenerator(CONDENSER�Duty: •1�.9245 MMBIWhe . Regeneretar(REBOILER)Dury: 607500 MMBtWhr � A9DSOPbBe(d'i0�&DRAF99 �� Lean Solvent SVeam ID: 4(Lean to A6s) � � � � . TempereWre: � 7277883 dag F � . FlaMate: � � 6.0570E+0516lhr - � � � � SolveM St2ngPh: � 45,18a9%-mass/maes � Acid Gas Loatling; 22817E-02 moVmol � Rfch SOIveM Slream iD: �� 5{Rlch Am) � Acitl Gas Lnading: 0.3868 mol/mol . � Recaenea�akoe,,(,COLUM6ND � Rich Solvent Stream ID: 8(Hot Rich to Str) . . Tempereture: 210.0000 deg F . Flowrata: � 6.4351E+051bPor � Salvent Strength: � 452751 %-mass/mass � � Acid Gas Loading: . 0.3855 moUmol � Leen Solvent Stream�D: . 10(Ln From Str) . � . Acid Gas Loatling: � 22614E-02 molfmol � � . � Re6oller Pressure: . 14.8241 Psi(gj . �Reflux Flowrate: 9895.8321 Ibmr The Dow Cherntcal Company Gae Treeiing Technolopy Group . . . Copyrigh4 m 2002-2090,The Dow Chemlcal Company � � � .. � ProComP Proce�s Simulator Version 8.9.9.2 � � 95 Rlov 2099,Pag�4/15 . � .____.. . ...... _.____ ..._. . ___.... O m �0��$ . . 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DowCorefEdee�tiel �ajor Eqaaa@ar�a��n4��ma�oar� 9��w Aeaada�k�C�yogen6� Pl�nt �,rnlne�oostee Puarap dPIDMP► InIe2 Pressure: t4.8241 Psi(g) � � Outlet Pressure: � � � � B0A000 Psi(g) � PfOesure RI&e: 45.0759 Pai . . Flowerata: . . 8.0304E+0b Iblhr � � . Efficieney: 75�o � Power: . 44.3801 HP . � . ArnBn�G6rc Pueu��t�U�APD � Inlet Pressure: � � 52.0000 Psi(g) . . Oufiet Pressure: � 9050.0000 Psi(g) . . � Presaure Rlae: � 998.0000 Psi . F�o,��; . 6.0570E+051b1hr � � Efficlency: 76°h Power. � � � � 932.5520 HP , � 9ieaeer-9 1tl�ATERI � Inlet Temperatore: 139.0228 deg F Outlet Temperefare: � � 120.0000 deg f � � � Pressure Drop: . 3.0000 Psi � � � � Heat Dufy: -8.3787 MMBtulhr � �ave Aeniee�Coole�SHEATERD Inlet Tamperature� 989.4278 tleg P . Outlet Temperature: 125.0000 tleg P . Presaure Drop: � . 3.0000 Psi . HeaQ Duly: � � -35R243 MMBtulhr � L/�AmSn�Exchanaaee�(HEA'PX1 � Performance Stream Num6er; 8 � �� Inlef Tempereturm: . � � 156.5710 deg F � � O�llet Temparature: 210.0000 tleg F � � Pressure Drop: � � � 10.0000 Psi . . Free Sfream Num6er. � �Z � � � � � Infet Tampareture: Z51.5475 deg F Outlet Temperature: 189.4301 deg F . � Pressure Drop: 5.0000 Psi ' Heal Duly: . . 34.0@72 MMBtWiv � The Dow Chemieal Campeny 6as Treatlrog Tecfinology�roup � � � � Copyrlph4�2002�2090,Yhe Dpva Chamicei Co¢npefry . . � � . ProComp Process 3lmulator Verslon 8.1.9.3 � � 16 Nov 2011,Page 97d95 � � . ..____.. ... ... 00 �@� ��A�� . DowConfldac�21a8� . FIa3h•� (FI.ASHB Fiash Type: � � � �P - Inle4 Tamparature: . 920.0000 deg F Outlet Temperature: � 120.8969 deg F Outlet Pressure: 944.0898 Psi(g) � Heat Duiy: � . 0.0�00 MPABtWhr Vaporfrection(mola�: � � � 0.9994- . � Residence Time: 10.0000 minukes �Drum Dlamelar. � 0.8726 ft . � . � Drum Lsngth: 3.0542 ft In6e4 F6I�!Coalesc�e dPLASF99 � Flash Type: QP . Inlei Tempereture: � 7 70.0000 deg F � OuUet TemperaWre: . 108.6102 dag F Outlat Preasure: . . 950.0000 Psi(g). Heat Duty: - � � 0.0000 MMBtWhr �. Vapor ftaction(molar): 9.OD00- � Residance Tlme: 3.0000 minu4es . � Drum Dlameter.. 0.0000 H � ' Drum Lenglh: � 0.0000 ft � �fich A�aaiwm�las8�1°aeok BPLAS&@R � FlashType:� �� Inlet Temperature: 9 S5J448 deg F � Outlet Yemperafure: 158.5710 deg F ONlet Pressure: � 60.0000 Psl(g) - �� Heat DNy: D.0000 MMBtWhr . �� VaporfracNion{molar): � 12185E-03- � � Residence Time: , 5.0000 minutes � � �rum Dlameter. � 8.3332 ft ; Dmm Length: Z9.1662 fl . � �bsorb�r 6COL61ft�i19D . . . � Column � - � � � Totai Pressure Drop: 2.4102 Psi � intemaVs: Generic Valve Trays° Numher of Trays: � Zo . . . �. . Tray SpaGng:. � 2.00U0 ft � Number Of Passes: � 3 � � - Weir Heigbt: . 2.5000 inch � � Foam�Bratlng Factar: �� DiAmetee. . . 19.6671 ft . � Acfive TraY�rea . 84.4�46 fi2 � PercerH Vapor Flood: 75.0000 . � �. Percent DownComer Flood: � 65.0000 OuPlet Stream 5 Connects: At Bottom of Column � OWet Stream 3 Connects: � At Top of Column Tha Douv Chemtcal Compeng 6ee Treaf9ng Yeehnoiog7l Group . . Copyfl@h4�a002�2040,The Do�r✓Chemical Campany . � ProComp Process Slmuleior Verelon 8.1 A.2 9S Pdov 2091,Page 99l75 . . . . .. ._ .__.. . . _._ .. � � , �u0 �� o�ae�aiao Inlei Stream 2 Connec(wa: Below�eay 20 . . . . Inle@ S4reavn 4 Cunrtect�: &bove Tray 4 . � � : 64og�as�ha�a . . 9ec.SaQ Tomperuhfre �2eauro Den�lfy Viaco�fty 5RevmeiConO. H0P�IFiovv de6� F¢11�1 Ihdf13 eP Bh�Poe.WF . Ebl6er q;7 %38.Q228 EA7.SBBB 3.8882 1.9587E-02 1.8546E-0Z 0.9202Eap5 9;2 946.0752 Bd'l.70B0 3.b989 9,970BEA2 1.9885E-02 8.8944E+06 q;3 q53,$q41 847.8283 3.5238 1.t838E-02 2.0351E-02 8.83BiEa05 1:4 169.586H 947R47B 3.G507 . id977E-02 20P38E-02 8.Ba4BE+06 1:5 �69.eB1a 848.W70 3.3760 - 1214iE-02 � 2.1141EA2 6.9597E+05 1:8 t78.6140 948d863 3,3409 1.2268E-02 2.1fi47E�02 B.9"o08E�06 � �9 9872072 848.3058 32455 . 12470E-02 2d942EA2 - 6.9726E+0.�'i q;8 1@5.4WS 840.4263 3.1887 12646E-0Z 2.2308EA2 B.BB76EQ5 1:8 � 2fII.7741 848.6449 3A443 72889E-02 22815E-02 . 7.005980.5 1:90 206.H781 948.EB45 39717 72758E-02 22@98E.02 � 7A278E+05 � 9:1t 213.Ob61 B4&7800 3.W40 92BYIE-02 22978E-02 7.0528E+06 9:12 2tb.1269 848.6�44 3.OBZ8 12852EA2 3.30�0E-02 � 7.WBBE+05 1:t3 214.BBZ4 849.0245 a.tan 92842E-02 22910E-02 �dW2H05 1:14 2122683 @49.5450 3.1392 52�83EA2 229i3E-02 � 7,�904E+05 � 1:95 207.4129 849.2856 3.1W5 92704E-02 22400E-02 7.1612E+p[ 1:16 2002786 949.3BE5 32656 12675E-02 2d881E-02 7.1894E05 5:1P 180.5738 � 94B.BW8 3.3504 12348E.�2 29435E-02 7.i872E<05 � . � 9:18 977.E943 949.B2BY 3,9&59 7.2158E02 3.070�EA2 72WBE�5 � 7:79 960.3828 849.762Z 8.BB71 1.1837E-02 1.8733E�02 � 72354H05 120 . . 137.9575 949.6758 9.8865 t.1421E-02 1.8561E-02 � 9.27ZBE+05 �a��e�� 9ee:Smg Tempatetun¢ 9eenavea DanolOj N6easlflqr 'mafmaoe�am. � au��atanston 4m¢a��lour tle9 g p¢9(B) !&/Hs e9 BtWhrvSd.F . dll��em PblB�r 9:1 134."s784 9l7.7080 82.5349 3,iS72 0.2789 44.9098 B.W08E*OS 1;2 141.1988 84Y.B2B3 02.3581 2.8126 82988 43.59A2 E.0769f+05 . 1:3 148.4689 E49R476 62.7828 2.5103 027E3 43.0047 � BAB14E*05 � 9,4 qr�g,�73q. gqg,pp7p 61.9012 22314 02205 42.9872 � 8.0085E<06 1:6 96A.780B 9C8.1083 877859 7.B7B] U2213 41.]953 8.0978E+�5 � 1:B� 973.5585 898.30.58 61.5720 9A598 02221 ni.aao� 8.9�84E♦05 . � 1:Y 182.A912 B4BA263 fi1.35B1 9.6818 02228 4Q4185 8.1299E«06 .. 1:@ 1912586 998.5AW9 61.7BOB 1.4002 02286 387837 6.9927Ea05 � 1:8 t88.4S12 848.8845 8D.B851 92111 02270 382Ea8 6.9&47EM5 1:70 208.dQ46 &/8AB44 8�.B82B 1.1742 02244 38.BOB1 8.1997Ei0.5 - 7;99 291.8362 848.00@4 60.8A20 � idOBB 02245 88.5389 &21%E+OS � 1:72 216.'L743 960.0245 60,BB36 7.0734 027A8 38.q50B 6.7A3�E+05 q;�3 �2162688 @49.1450 81.0488 7.0674 02247 38.6666 82872E+06 1:14 294.8802 84B26fi8 61.3768 1A892 02241 38.8585 82881E+05 1:15 2tli.3�E3 84B.3B98 61.7170 1d3B2 0.724P 39.3�55 . 8.3tl8YEM5 1:76 205.6558 848.5079 82287A 1.P212 �.2248 38.81&5 8.3244E+05 � 277 187.9�42 .B4B.8287 83.0701 1.3454 P22AB 40.77�8 63447H06 � 9:18 9s]944] &18.9622 �.1564 i6349 02260 4'1.7273 . 8.9]22Eap$ 1:19 174.R730 949.875G 85.5888 � '1.8407 02263 43.0408 8.4094E*o5 1:20 165.�548 95�.a000 67.9023 243� 0.2260 44.7977 6.4394E+05 6�e¢OeuoeP�$oS��'�9.�D�43aR@@ . . � CQPOd@Po9BP . � � Temperature: . 120AOOOdeg� . P�ssut'�+: @.0000 Psl(g) Pressure Dmp: � 3.0000 Psl � � Heat Duty: . -90.0245 NAMB4Whr . . � � � RefluuFlawl2aPe: 961b.83291b/hr - R067�If�P � Yempera4ure: . 261.3982�eg F Pressure: � 94.92@1 Psi(9) � �� Pressure Dmp: . 12000 Psi � . . . HeaF DUFy: 6�.7500 MhABIulhr . 'LN��mwv Cheev�Bea9 Goers�eeay�+as Ye�a¢7wg��eC�no��py�soa�p . �op�elgh4�8�0��a09D��TEse�ow CBcemBe�f�meaa�Oaaog � � �eoComP PsOe�ss�@rvse�Bmt�P��sloeo�.8.�.& 9�8��2099,�age 94695 . � . ___.. .._.... . . . .__... � � �69�� w��aaPl��aa&�ao S@ripPiovg RaGo: . 0.�92� . Cm9uema¢ � . . Total Pressure Drop: 8.7�47 Psd Intem�ls: � G�nericValveTreys° . NumbarofTr�ys: 20 �� Trey SPacfng: � 2.0000� �� Number Of Passes: ti � Weir Heigh4: . 2.5Q00 Inch Foam Dera4ing F�cior: Q•B . � - Dfame4er: 9.5769ft - Acilve Yray Area: � 53.4842 flZ . . � . ' percent VaPor Flood: 75.000D � Percent DawnComer Flood: � . � 7&.0000 � Inlet Stream&Connecis: � � �bove Tray 7 � 9/apoe f�6��e� . Sec:Be� YempaeaWre Prenouro @enmY�y VlacoBMy Yhtm�e�ConB• pe�R�°� EegF Rs1181 Imm5 cP B6Whe•ffi.P !b/%e � 1:7 200A662 11.0000 OA110 9.8948E-02 1.3517E-02 � 3.8336E<04 t2 20.5.U390 919347 0.1080 t8&liE-02� L3759E-02 . 3.8438E+04 . 1:3 212.33� 912884 0.1018 1.852BE-0Z 1.4W3EA2 � 4.iB28E+pq � �;q 22p,pq,55 NppTO 92786EA2 1.6022E-02 1A387E-02 . 4.6381E+04 �;y pZg,7577 . 1t.587B 8.4891E-02 1.6480E-02 � 9.4EOBE•02 4.8803E+09 � 1:0 291.3770 11.6733 7.8159E42 1.b06�EA2 1.4767E-02 � B.��E'� �:y 234,5480 71,8093 � 7.5391E-02 1.470iE-02 ' 9A865E-02 6.8750E04 9:8 T36.B4� 91.8495 ZZ780EA2 7.4i35E-02 1.487i1E-02 ' 6.7802E+04 q;9 23@.6080 ta.0879 7.0970E-02 t.4273E-02 1.4976E-02 5.8AB5E+a4 7:90 240.0436 7$.2185 6,fl421EA2 t.6028E-02 1.5077E-02' g.9t�3E04 . q;y� b{12497 12.3551 B.B300EA2 1.38T2E�02 9.6057E-02 , S.B55BE+04 1:92 24228fi8 72.4018 &7425EA2 1.8739E.02 150T8E�02 5.8828E*04 1:78 2439886 12.8287 6.8740E-02 1.3826E�02 9.6104E-02 8.0295E+04 t:74 249.0078 � 12.7656 6,8205E-02 1.3527EA2 9.5925E02 � 8.0525E<U4 1:t5 2R47919 72.9024 6.6781E-02 1.3442E-02 1b944E-02 � 8.O180E+00 1:16 245.4942 15.0393 fi62]3E-02 � 13388E-02 1.6961E-02 6A010E*0.2 �;q7 246.OaB5 13A76? &6234E-02 1.3305E-02 9.51]HE-02 � 6.9239E04 1:18 246.6735 18.3132 6.5051E-02 7.326UE-02 7.618fiE-02 . 8.1461E+04 1:18 247.3628 73.4601 6.4085E-02 1.320BEA2 7.5220E-02 8.1862E+pd 1:20 7ABS236 13.6W1 8.4001E-02 1.9189E-02 1.6293E-02 . 8.1829Eapq � �IW�Od Pha90 � . . � � 6ec:6ng iomWerewra 9rea�ure oeneity �nasaeity ahemooa cona. smrt�ee o aensiom Yobl Fluw 0e0W P�sEag) IbRiB eP BPulhr•H.P tlyneiCm Ib1ioP 1:1 . � 198.7B90 17.1341 84.1836 1.9407 0.7273 41.0898 8.9241E+05 i � 12 202dOW 11.Z884 03.8268 � 12786 02290 407876 6.4468H�6 . j . � 1;3 208.9985 71AU2B 83.4374 9.1644 02282 402519 6.9802Et05 1:< 21Z3918 11.53i8 627811 1A434 0.2305 39.6861 8.6284E+06 1:5 22@.7a82 91.6733 82.1984 0.8484 8.2378 � 38.8133 6.5073EQ5 1:6 229.9025 99.8003 81.630P O.B87B 82324 38.4012 � � 6.5878E+05 �;7 233.fifi90 19.9458 812351 0.8474 02328 38A748 8.BO6AE+05 1:8 238.0850 12.0819 80.8359 Ob786 02333 3Z]i22 8.9959E•O6 1:8 238.a�eS 132785 8�.7059 0.7986 � Q2338 37.46Q9 6.&Z9aEa5 7:10 238.5499 12.5551 � 80.5240 �.7821 02940 3ZP660 6.6?b8E+Q5 I �;19 290.8214 12.4818 � 60.3168 OJB88 Q.2343 � 37.0781 6.8388E05 � � i:t2 241.9938 12.6287 802i70 0.75M 02397 38.914� 6.B328E*05 � 1:13 2C2.B8� 12.7@55 6b.9439 0.74f4 02360 �.��M1 8.6356E+W ]3 02369 36.8579 6.8381E+05 1:14 243.1i12 12.8024 60.0488 0. BB 1:95 1A4.R705 93.�383 58.8669 0.7318 02366 36S465 8.8906E>OS 1:18 245.1814 t3diB2 . 59.BBOP 0.7368 02369 39.4484 8.842]E+06 1:17 2457972 19.3132 58.82W 0.7785 02381 36.3%i . 6.8q4BE+P6 7:18 248.38W 13.4509 fiB.7558 0.713� 02363 . 36271� . 6.�469E«06 ttlg 246.8453 � 19.5879 58.8948 O.PWB 02968 384981 �� 6.8466E�5 . . �;Zp 2q7.4854 t9.7247 68.83CB 0.7038 . 02387 3B.'109d 8.8595E+05 YPo��ewr Chem9cei Gore+Pany�e�Teoat9sg 8�ch��iogy Oreu� � . - � � Copye➢p6�4O= 2�6S-2D9�,1'dieD�auChereeleeal�amp�ssy . . �eo�oomp�v�r.�sg 8@enw9adoa c/evs9moa�.9.4.� %��v Z09�9��e�e 9W9� �o� e�� 2 �syogeaa�� 9�ua@ ��er��a�y �0�� Source ID Number F-2 SCC AIRS ID Urk7ov�+r Source Location Zone: Source Description Fiare HorizontaL Flare Make Unknovvn Potential Operation S76C hr/yr Flare Model Potential Fuel Usage 10.5 MMscflyr Serial f�umber Date in Service Stack Height 40 ft Flare Configuration Air-Assisied S4ack Diameter 30 in Fuei !-leating Value iO2� Btu/scfi ExitVelocity 60.Q Ws Flare Pilot Rafiing 0,5 Mf�Btu/hr Exit Temperature 1000 deg F Flare Purge Gas Rate 70'7 scf/hr Volume Flow Rate 17,671 ft'/min Purge Gas Heat Rate 07;"i MMBtu/hr . �orrebustiara Emissios� Galcaala�6o¢�s ' �B��S @�o�ao� froPsl�� f��(8��usIPoP 122 8760 � V�O�BhB$�P&$ @B�/�IN�$9ll� @�6/�HP $�BH/ U RIOx 0.068 0.08 0.4 CO 0.37 0.45 2.0 � `AP-42 Table 13.5-1 � � � ��2Q �B13�SSfOl3 Qei➢BG9Af�t9099S � . . , . ��BVV�659�G9�C � � ' 1 Metric Ton = 2204.62 Ib� 1 kg = 0.001 metric tons i Po@lan8aua4 9s /ucart¢ab4aa �oe2�u�Soaa @ COZ 53.02 567 15.03 CH4 0.001 0:01 0.00 iVZO 0.0009 D.00 0.00 C�ZQ m 15 COZe=COz+(CHq*21)+(NZO'310) -- a � � U a� a � aoro .om00000wor� �n000 � C o d` m � o m o vI o N o 0 0 0 0 0 [D M o �n N o�. O ✓� w �- � N � � O � OO M O O O O O O O � O O O O b C ❑ � � O N O [`] M Ot O 61 O h ` O O O O O � cJ OJ N V O :�� . � 0. T N O (O O CJ O I� O h O O O O O (O O N V O p g N o 0 o in o n o 0 0 0 0 0 o m o 0 0 .. � � < « o �o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0< � . � u g o 0 0 0 0 0 0 0 o d o 0 0 0 0 0 0-0 0 0 0 � a d - N (o o m ro m o m o m v o 0 0 0 o.�n m m m a o .� � o a Tao n omo ro a o0 000 �o o �n voM. � a. o v o o mo �vo 00000o m o0 0 +• o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o d'� a � 6 6 d o d d 6 d d d 6 d d o d o d d d d 6 � � U d coorom m000a �n000a �oonnuo �� . =q U �,N � � N n. o v o a m o 0 0 0 0 o m m ro ro o m�. . � . O noaa orom �n00000 �vomHmoo � c ] .- am oroo �noa000000 �omovn �nory o � ocoo � o .= o � 000a000 � 0000 , U Q N . � V p � o 0 o m o 0 0 0 0 0 0 0 0 0 0 0 o N o o. `N� O O O N O O O O O O O O O O O O O N O O 0 � p,� O O O O O O O O O O O O O O O O � t0 O O a��. � N w s� � O O O O O O O O O O O O O O O O O N O O M. � F � N O O O M O O O O O O O O O O O O O � O O �. . N C U � T�- O O O N O O O O O O O O O O O O O M D O � � N d W O O O CJ O O O O O O O O O O O O O O O�. � N '� N O O O O O O O O O O O O O O O O O O O O M h W � O N O C e o� o e o 0 0 '� o � o e e e e o 0 0� . � O T� �y r p� V � O � O O 0 O O p O O O O O O O O O O O O A . pp r G V O O O O O O O O O O O O O O O O O O LL � N O � � � � V IL d �q � � � O O O O � O O O O O O O O O O O O U � E U c W a R h d m c `m o `o 0 � o � m o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0� � � �,o a m �n � � mw �o � m <om �om.ro <omaowcom �om �oao c m E � .o � � L° i_ r r n � n � r r r n r � n n r n n n � � � � . . W G c N � a a m m w w ro m m m m w m m m w w m m m m m m'y � . � r � � v w Q e a o � S o 0 o a o 0 0 o e o >o 0 0 0 o a e a o e a e e e o w . . N �i�i 1� M1 I� a Q (+1 O O C M o v n a a a m v, Q C t'J C Q Ol d' V' N fq � Z Q,C ro ro W S O O N N O O N O N N N O N N N O N (V O N N N p� � � � � j m � k .. o O N � � � N � 0 N O� � � N N 0 � N 6� � N W � � . � N � 0 � N � 0 N W � �.N N Q� � N T � N m � � Q Q @ - e x ° e � =o 0 0 �a e a a o � o �e a o �o o E (� � O O O � O O �j O O O �j N O N O O O N O O � � O p o �` o 0 0 0� o� o e e e o 0 0 0 o a o a o � , � � . V (D O O O (O O O (O O O O (O (O O t0 O O�O t0 O O O Y y � v e �ooa �n � • � m �nmm � E . . B O O � S � N� M N � N � N O O O O N � C�J N b m (D Y � , � n! V � m N C N m V � w a ? 9 m m u� rn.`� r '� '°' � � u�i � v o �n V � o m v o o. I� � Np� O N O] p 0 � O � m 0 O 0 Q l7 O O Q O O�� 0 �'-J r N V � O O O N O O O 0 O O O O Q � � IG O O O O� O 0 O O O O O p O O O O Q O O 0 p N O C j :�e � W LL � O O � � � O � � O O O p O O O O 0.0 O p o O w ? L LL L m � .q � c`� pD y 6 O� V 0 9 ]� N'� N�y� C.m pa, � a. O D 3 N > O' 0 N •� N �.J CIJ S UJ y U � d W � Q Vl C ;O� U J O C J p O 'O p � E Q � � E LL W O O O � O � 7 O' - 'J N�p L N� '..�i W W N N L N O.O'J O N O C � �Q y a'C. O. 6 6 J O Q N O)N >@ V J J J C� �S � J a � (J N E . W 1� N N @ N J `l. J f/J J S �i a � > N Z U C 0, � O U � N . � � � > �r N N tA C 'O D 9 N L N N N Z N N Q E - N L R N N L 6 C � N� � O W � d C�C�J�S C�2 J N N N Y U C C C O O O C� J S D N LL J N N E N � �° m m E � y i d m m m N W LL� 11� � �] � N N N G N } � J m U� p.� � C C _ j 6 � y v d � i � a a o.a n c C C C C C m m �N@� C C � � �9 0 � v .ffi U a oi o g Q > > > >�m m r E E E E E v m d o c c c c c m - m � O � oQo 00 0 0. OQO m Qp, � �¢� � S� ... o � o omnaao 0 oA � RpOFU . . uo �nw �n �na aa > = o bw � »» OOOoaaav� 000000LLtiLLF- . x Forti'Lupfroau:Gas PB�¢at �o�gone �e�aul �heeg Source ID Number G�h�€:� Sou�ce Description ��roc�e�a:c F�Ea€�� €�€eseE-C�r?�Fd��-�ca �Eaas�E��r C�r,era°e�r�ea�cc€e Engine Usage Fower Emergency Generator- EPA Tier 2 Engine Make Caterpillar Po4ential operation 500 hr/yr Engine Model C15 ATAAC Diesel Gen Displacement 1.27 L/cyl Seriai Rumber TSD Poten4ial fuel usage 1830� Gallyr Manufacture Date T3D 36.6 Gal/hr Date in Service TBD Stack ID G�hU3 Maximum Rating 670 BHP Stack Height 10 ft , Fuel Heating Value i II,396 Btu/Ib Stack Diameter 0.67 ft Heat Rate 477 MMBtu/hr Exit Velocity 181.8 ft/s Engine Neat Rate 7110 Btu/hp-hr Exit Temperature 942 deg F Engi�e Heat Rate 0.39 Ib/hp-hr Volume Flow Rate 3,842 ft'/min �T� �e�ufis�aoaas Poliutant Emission Factor Ra4ing opHrs��ng Estimated Emissions Source of Emission Qb/MMBtu) (g/hp-hr) (hp) (hrs/yr) (Ib/hr) (tpy) Factor MOx 1.78 5.74 670 500 8.48 2.12 Manuf. Data CO 0.12 0.40 670 500 0.59 0.15 Manuf. Data VOC 0.00 0.0 i 670 500 0.01 0.00 Manuf. Data SOx 1.L1 3.26 670 500 4.81 1.20 AP-42, Table 3.4-1 PM10 0.01 0.035 670 500 0.05 0.01 Manuf. Data PM2.5 0.10 0.32 670 500 0.48 0.12 AP-42, Table 3.4-1 8-@Re�s HCHO 7.89E-05 0.00025 670 500 0.00 0.00 AP-42, Table 3.43 Benzene ?7GE-04 0.00250 670 500 0.004 D.00 AP-42,Yable 3.4-3 Acrolein 7.88E-06 O.OOD03 670 500 0.000 0:00 AP-42, Table 3.43 Acetaldehyde 2.52E-Q5 O.OOOOS 670 500 0.000 0.00 AP-42, Table 3.4-3 Propylene 2.7�E-03 b.00900 670 500 0.013 0.00 AP-42, Tabie 3.4-3 �8�� °�� P � ,�,�,.��, , { ��9 � �� „� 3 � _`� ' '� �� 9� 6�� 9�� ,�,, ��{ � , „ ��t �� 4�� I ��y Y .� 'Y��.. .�.._. `�``� . � ` �� ' ' , �,fi ys� ��ee�oV6�� o� ��ov� f9�� vnr�� ote��a� , �, ;, .� �. pvu�rr�C�� snv°s�Ba �ov��e ��aatrfioov� eav a�u�� ..u�,�, vu 6� � � 1k� ��9aeee� aneo¢a�a4�9v��9�xu�o�o4yy, esc��eaa��,�uDa3y�p ��9��o�u�yo �sa� ��tr-�Gfr��6v��u��$, Image shown may not � � � � �. � reflect actuai package. � . � ' �� . . � � . ��.. ��/��oss��n�� sr�,�� Aac��s��uu�� EPA Certified for Stationary � Utilizes ACERTT""Techno9ogy �I Emergency Application � Reliable, rugged, durabEe design (EPA Tier 2 emissions leve4s) e Field-proven in thousands of appiications worldwide I ��ag��R' = Four-stroke diesel engine combines consiste�o8 �The generator set accepts 100% rated load in oaie performance anci excellent fueE econoreay wit6a step per NFPA 110 and meets ISO 8528-5 transde�o₹ minimum weight ' response. = Electronic engine contro9 �D@�22�� T��9�R�TI�V� � UL 2200 losted pacl:ages avaiVable. Certain a Matched to the performance and outp�st ' restrictions may app9y. Consult with youa' CatOO characteristics of Catengines ' Dealer. � Load adjustment modcale provides engiere reV¢ef ', ��e�� upon load ienpacc and improves load acceptance = Wide range of bole-on systeen expansdon and recovery time attachments,factory designed and tested � UL 1446 Recognized CEass H insu@ation = Flexible packaging options for easy and cost ��-��yg�� effective installation m Simple user friendly in2erface and navigatuon . ��_�� Scalable system to mee4 a wide range of �. � Fully prototype tested with cereified torsoonal cusaomer needs vibration ana9ysis availabVe ^ Integrated Control System ared Communications Gateway vu��nso�� a��a��mua� ^ Cat dealers provide eMensive post sale suppor8 including maintenance and repair agreements . � � � , ^ Cat dealers have over 1,800 dealer branch stores operating in 200 countries ' ^The Cat� S•0=SS"" program cost effectively detects iMernal engine component condition, even the presence of unwanted fluids and combustion by-products e� tl �fl�� Yf eA�� fi'd1�Y99 �� IWG�d .��o 6�6��s��e�e�4�a�P�o¢� � . . �� . ��5P(��n��i . �R��I��n�� Frame size.............................:...................................LC6114F EMCP 4 controls including: Excitation........................................................Self Excitation -Run/Auto/Stop Control Pitch..............................................................................0.6667 -Speed and Voltage Adjust � � IVumber of poles...................................................................4 . -Engine Cycle Crank � Number of bearings......................................Si�gle bearing -24-volf DC operation � � Number of Leads.....:........................................................012 -Environmental sealed front face � . � (nsulation.......................UL 1446 Recognized Class H wi4h -Texf alarm/event descripEions tropicalization and antiabrasian � Digital indication for. � � � -Gonsult your Caterpillar dealer for availa6le voltages -RPM � . IPRating.........................................................Drip Proof IP23 -DC volts � Alignment:.............................................................Pilot ShafiY .. Operating hours � . Overspeed capability........................................................125 -Oil pressure (psi, kPa or bar) � � Wave form Deviation (Line to Line).................................2% . _Coolanttemperature � Voltage regulator................................Three phase sensing _Volts(L-L&L-N1,¢requency(Fiz) � Voltage regulation............Less than+/- 1/2% (steady state) -Amps(per phase&average) �� Less than +/- %:% (w/3%speed change) � -ei<W,kVA,kVAR,IcW-hr,%kW,PF(4.2 only) � '��.. � Telephone in₹luence facYor...............................Less than 50 Warning/shutdown with common LED indication of: � Harmonic DisYortion.........................................Less than 5% - Low oil pressure � . ' ��g��p�gry�� -High coolant temperature -Overspeed C95 ATldAC, I-6,4-Sfrolce Wa4er-cooled Diesel -.Emergency stop . � Bore..........................................................937.20 mm (5.4 in) -Failure to start(overcrank) Stroke.....................................................177.40 mm (6J5 in) -Low coolant temperature ''. DisplacemenY...........................................15.20 L(927.56 in') -Low coolant level � ' Compression Ratio.......................................................16.1:1 Programmable protective relaying functions: Aspiration.....................................:.....Air-to-Air Aftercooled _Generator phase sequence � ��. Fuel5ystem...................................................................NVEl9V -Over/Undervol4age127/59) Governor Type................Caterpi@lar A6EM control system _OveNUnder Frequency(81 o/u) � -Reverse Power (kW) (32) (4.2 oniy) � -Reverse reactive power UcVAr) (32RV) ''i � � � -Overcurrent(50/51) . � �! � Communications: � .. -Four digital ioputs(4.1� '�� . � -Six digital inputs (42 only) . - � . � -Four relay outputs(Form A) � � �. � - -Two relay outputs(Form C) �� -Two digital outputs � �� -Customer data link(Modbus RTU) (4.2 onsy) � � -Accessory module data link(4.2 only) � � -Serial annunciator module data link(4.2�onlv) ��. � -Emergency stop pushbutton Compatible with the following: � -Digital I/O module � . �.. -Local Annunciator . . -Remote CAN annunciaYor -Remote serial annunciator � June 13 2011 13:54 PV0� �� P9a 38O�e�Oava�8�\/oV4� . �� pen Genera4or Set- -9�00 rpsan/60 8-0z/A80 VmB4s - DM8Y55 � Geeeeras�e ffiek Pac&age PeMorunawce � � � � Genset Power rating @ 0.8 pf 625 kVR � � Genset Power rating with fan 500 ekW � � Fuel Conseemgstiob � � � - . � 100%load with fan 138.5 Uhr � 36.6 GaUhr 75%load with fan 1D6.1 �/hr 28.0 Gaf/hr 50%load with fzn � 88.1 Uhr � Z3.3 GaI/hr � �ooEiag Sg�sBewi' . . Air flow restriction(system) 0.72 kPa � 0.46 in.water Air flow(max @ rated speed for radiator arrangementl 822 m3/min 29029 cfm � Engioe Coolant capaciYy wiih radiator/exp.tank 57.8 L 95.3�gal � Engine coolani capacity 20.8 L � 5.5 gaf � Radiator coolant capacity 37.0 L 9.8 gal 9nlet,4ir � � � Combustion air inlet flow rate � 39.8 m'/min � 1405.5 efm Euhaeask Sys4ern . . � . � . . Exhaust stack gas temperature � 505.6°C 942.1 °P Exhaust gas flow rate 108.8 m3/min � 3842.2 cfm Exhaus[flange size(intemal diameterl. 752.4 mm � 6.0 in '�.. Exhaust system backpressure{maximum allowable) 6.8 kPa � 27.3 in.water '�, �4-0eatRejection� � . . . ''�. �Heat rejection to coolant(total) 789 kW 10748 Btu/min �� Heat rejection to exhaust(total} � 505 kW 2S779 Btu/min . Heat rejection to atmosphere from engine . 94 kW � 5346 Btulmin Heat rejection to atmosptiere from generator �29.1 kW 9654.9 Btu/min - . ABteana8or' � � _ � � Motor starting capa6ility @ 30%voltage dip . 1428 skVA . Frame LC6174F � � � � Tempereture Rise � 7B0°C 234°F Lube System . � . � 8ump refill with�filter � 60.0 L 15.9 gaI � � �missions 1lVoseairoaBP �,. NOx g/hp-hr 5J4 g/hp-hr � . CO g/hp-hr � . .4 g/hp-hr � HC g/hp-hr .01 g/hp-hr � PM g/hp-hr � � .018 g/hp-hr �,. 'For ambient and altitude capabilities consult your Cat dealer.Air flow restriction(systeml is added to existing restriction from factory. ''�� 'Generator temperature rise is based on a 40"C(10R'F)ambient per NEMA MGt-32.Some packages may have oversized generators ' with a different temperature rise and motor starting charecteristics. � 'Emissions data measurement procedures are consistent with ihose described in EPA CFR 40 Pan 89,Subpart D@�E and ISO8978-1 For � '�. measuring HC,CO,PM,NOx.Data shown is based on steady s[aYe operating conditions of 77"F,28.42 in HG and numbef2 diesel fuel � � with 35°API and LHV of 18,390 btu/Ib.The��ominal emissions data shown is subjecito instrumentation,measurement,facility and �� engine to engine variations.Emissions data is based on 100%doad and Yhus cannot be used to compare to EPA regulations which use � values based on a weighted cycle. � 4 June 13 2011 13:54 F�f� I �0¢4 L.u�fom�as �lacat Ee�gane De�a¢9�9se�t � � Elevation: 5066 ft asl Source ID Number �€�3��a,i Source Location Zone: 13 AIRS ID 123/0057/013 UTME: 529,105 Engine Usage Compressor Engine UTMN: 4,443,833 Engine Make Wau{cesha Potential operation* 8760 hr/yr Engine Model L7042 'hrs of operation limited to 8760 hrs for EU-39 and EU-32 Serial Number 252139-4438 Date in Service 1/1/19?5 Po4ential fuel usage 73.54 MMscflyr Emission Controls Rich Bum 8395 scHhr NSCR Stack ID E6�G31 Site Rating 954 BHP S4ack Height 32.81 ft Fuel Heating Value 909 Btu/scf Stack Diameter 1.33 ft Heat Ra4e 7.63 MMBtu/hr Exit Velocity 113.6 ft/s Engine Heat Rate 8000 Btu/hp-hr Exit Temperature 800 deg F Volume Flow Rate 9,455 ft'/min 9Jncoe�4volled Eeraissioe�s Nominal Hrs of Source of Emission Factor Rating Operation Estimated Emissions Emission Polfutant (Ib/MMBtu) (g/hp-hr) (hp) (hrs/yr) Qb/hr) (tpy) Factor NOx 4.41 ?6.Ct0 954 8760 33.65 147.4 Manufacturer'sEF CO 7J2 23.00 954 8760 58.89 257.9 Manufacturer's EF VOC 028 1.00 954 8760 2.10 92 Manufacturer's EF SOx 5.&8E-04 0.00 954 8760 0.00 0.02 AP-42,Table 3.2-3 PM10 9.50L=-03 0.03 954 8760 0.07 0.3 AP-42, Table 32-3 Cg�O(�2e �.J�JF_i-Q� 480.9 954 8760 1009.8 4422.8 GHG Subpart C Calc. 0 1%�.r9 HCHO 2.39'c-02 0.087 954 8760 0.18 0.80 Permit Benzene 3.20�-03 0.012 954 8760 0.02 0.107 Permit Acrolein 263E�3 0A90 954 8760 0.02 0.088 AP-42,Table 3.23 Acetaldehyde G.i0E-O4. 0.003 954 8760 0.01 0.03 Permit 1.02 Coes4rolleol �ewissiores . .. Nominal Hrs of Source of Emission Factor Rating Operation Estimated Emissions Emission Pollutant pb/MMBtu) (g/hp-hr) (hp) (hrs/yr) (Ib/hr) (tpy) Factor j NOx 0.69 2.5 954 8760 5.26 23.0 97WE0180 . CO 1.52 5.6 . 954 �8760 11.57 50.67 97WE0180 ' � VOC 028 ?.0 954 8760 2.10 92 97WE0180 SOx 5.08E-04 0.00 954 8760 0.00 0.02 AP-42,Table 323 PM10 0.0CE50C 0.03 954 8760 0.07 0.32 AP-42, Table 3.2-3 CO2e i.3_3G+�2 480.1 954 8760 1009.8 4422.8 GHG Subpart C Calc. Bi6LPs HCHO 2.39E-02 0.087 954 8760 0.18 0.80 97WE0980 Benzene 3.7_0E-03 0.0116 954 8760 0.02 0.11 97WE0180 Acrolein 2.03E-03 0.0095 954 8760 0.02 0.09 AP-42, Table 3.2-3 Ace4aldehyde 9.1"vE-O4 0.0033 954 8760 0.01 0.03 97WE0180 ' Fow�Laptoo�C�s �lara� �wgirae Dedao9 SBaeet � Elevation: 5030 ft asl Source ID Number ��Pt�`�L Source Location Zone: 13 AIRS ID 123/0057/030 UTME: 521,105 Engine Usage Compressor Engine UTMN: 4,443,822 Engine Make Waukesha Potential operation`" 8760 hdyr Engine Model I_7042 *hrs of operation Iimi4ed to S760 hrs for EU31 and EU-32 Seriaf Number ?_86436 Date in Senrice i;ili975 Potential fuel usage 73.54 MMscf/yr Emission Controls Rich Bum 8395 scf/hr NSCR Stack ID �V�G32 Site Rating 954 BHP Stack Heigh4 20 ft Fuel Heating Value 9Q° Btu/scf Stack Diameter 9.33 ft Heat Rate 7.63 MMBtu/hr Exit Veloci4y 113.6 YUs Engine Heat Rate 8000 Btu/hp-hr Exi4 Temperature 800 deg F Volume Flow Rate 9,455 ft'/min U¢wco�rtPo90ed Ernissions Nominal Hrs of Source of Emission Factor Rating Operation Estimated Emissions Emission Pollutant Qb/MMBtu) (g/hp-hr) (hp) (hrs/yr) (Ib/hr) (tpy) Factor IVOx 4.41 16.00 954 8760 33.65 147.4 Manufacturer's EF CO 7.72 28.00 954 8760 58.89 257.9 Manufacturer's EF VOC 0.28 ?.00 954 8760 2.10 92 Manufacturer's EF SOx 5.�8E-Gi 0.00 954 8760 0.00 0.02 AP-42,Table 32-3 PM10 O.G69500 0.03 954 8760 0.07 0.3 AP-42, Table 32-3 CO2e 1.323E+07_ 480.1 954 S760 1009.8 4422.8 GHG Subpart C Cala liAPs HCHO 6.0239 0.087 954 8760 0.18 0.80 Permi4 Benzene 0.60320 0.0116 954 8760 0.024 0.11 PermiP Acrolein 0.0J2G3 0.010 954 8760 'OA20 0.09 AP-42,Table 3.2-3 Acetaldehyde 0.00091 0.003 � 954 8760 0.007 � 0.03 Permit � 1.02 Corr4ro9ied �mfissearas Nominal Hrs of Source of Emission Factor Rating Operatio� Estimated Emissions Emission Pollutant pb/MMBtu) (g/hp-hr) (hp) (hrs/yr) (Ib/hr) (tpy) FacYor Nox 0.69 2.500 954 8760 5.26 23.0 97WE0180 CO L52 . 5.500 954 8760 11.57 50.67 . 97WE0180 VOC 0.28 1.000 954 8760 2.10 9.2 97WE0180 �. SOx 5.88�-04 0.002 954 8760 � 0.00 OA2 AP-42,Table 32-3� '� PM10 0.00950� 0.0345 954 8760 0.07 0.32 AP-42,Table 3.23 CO2e 1.323E1-02 480.1 954 8760 1009.8 4422.8 GHG Subpart C Calc. F9APs �HCHO 0.023° 0.087 954 8760 0.18- 0.80 97WE0180 � Benzene O.00320 OA116 954 S760 0.024 0.11 97WE0180 � Acrolein O.OU2Fi3 0.010 954 8760 0.020 0.09 AP-42,Table 3.2-3 Acetaldehyde O.G0091 0.0033 954 8760 0.007 0.03 97WE0180 _ __ _ _------_ i __ At��ae�� ! �'�� Il�� , r `� Colorado I)epartaaient of&'ublic�Iealth a�ad Eraviranmeaat ��"�`"� ��g�;� 'n ''�[ Aig 1'�llutaoaa�onYrol l�ivisian �:��, ,!�F .,.�*. f^�.x' � ''*�ra �:v,"t ��t�ldzc;t[[a�I3e1sn,•t�9ai^ee€ of 1'ail�Cir D Cea�tls �� $ffi� ��fl�� fi��°ffi�$��Offi �`�1�'�A ac�dlaa.iccuzaaaci�E �I�r. SeptemP�er 1Q 2008 C��g��ffi�� l��nn�e ��errmI�c�'ree �ather��n� �,�,� ��e�� I�T��na�o �art �,�pt��a �'sas �lat�a� ��¢ Jennafer L. Shea ��°�°�� Je_nnifer�,. Shea ��eaH�etrgo ��rm4��ff o P.O. Box 173779 IT.O. Box 1737�9 ��,��e Street ��p�$�o Street �� g9enver CO �0217 IDenver CO ��17 City State� Zi Ci State Zi '�� 1PHn��e 1�I�nmu�n�a�: (720)929-602� ��m�rm�l�an�n9ae¢�e (720)929-602� ' ��r��o (�2o)s2s��o2� ��r��o (�20>929-7ozs lE-ean�n➢, 3ennifer.3hea@aaaadarko.com �-�nanRo Jennifer.Shea@aaaadarlco.coasn 1P�VVnang��Q��Rc �u@�dae��'�au8��4: �Permit FeesL Same as above (Annual Fees� ��e as above , . ��,��e Street ��,�$$e Sheet — � �. City � State Zi City .State . Zi ��, �Hn��n�I�Tna��: ��an�l�ianunedn�a°a �I ��l�aa�n�erce �a�t�aa�s�x�rce ! �—��0ae �—��aa, Check how would you like to receime your peruaat fee iaavoice? �I Mail: ❑ E-mail: � �'aac: ❑ II Footnotes: � The permit contact should be the point of contact ffoff te�hnical information contained in the permat appflicatfloaa. This may be a company representative or a consultz��at. 2 The coinpliance contact should be the poing of contacg fror discussing inspection and compliance at tYie perami�C�d facility. 3 The billing contact(Peruxit feesl should be the pouag o��ontact that should reeeive th�invonce for fees associated with processing the peranit applicataon a�flssaaing the permit.(Reg. 3, Part A, 9ection�/I.�) 4 The billing contact(Annual fees)should be t�ae poang o�contact that should receive the ineoices issued on aaa annual basis for fees assocnated with actuaY�rn$�si�ans geported on AFENs for the facility. (Reg. 3,Paat I�, Section VI.C) � �� fl �� . FortttAPCD-101-CompanyContactInfadoc . '�. �tt��h � ____ _ -_ A10'�F�1�T AII��ACT AlVAd.YS�S Kerr-McGee Gathering LLC (KMG) did no� perform an aiY impact analysis as the �amissioae estimates are below modeling threshold last�� s� Table 1. "Modeling Threshold of the C'odoraa'o Guideldne"and per CDPHE PS10-Ol merno g��ed September 20, 2010. 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The gas pressua�e is increased by ten(10) engine�driven natural gas recipro�ating compgessoxs arad then dehydrated utili�ixig two (2) T'�C'a dehydrators to a water content levefl acceptable fox pipeline transaraission. The dehydrators incorporate a tkceranal oxidizex per unit to coxatrol emissians. 'The liqaazds, known as natural gas condensate, are routed t� a stabilizat�on pr�cess and then collected in four (4) — 11,500 gallon holding tanks. The stabilized tiquids are then trucked from the facility. 'The facility includes tsvvo (2) refrigeration plants to reduce the hyc�ocarbon dew point t� aneet sales deliveries requiretnents. �ne (1) propane co'npressor is aatilized 'an glae re4rigeration process. The natural gas liquids (NCaL's) produced in the r�frigeration process are collected gn three (3) 60,000 gallon tanks and then transported frroan the far,ility via pipeline and/o�truck. "d'he new cryogenic gas processing plant will receive third party gas froan tl�e Kerx� D/IcCsee �'sathering LLC pipeline system. The �OZ is removed frorffi the anlet gas streaxAx �a4ilizuig two (2) 600 gadlon per minute (gpm) aatiine treaters. Each amine frain wrell utilize tflaermal oac�dizers Yo control emissions. "g'he gas stream is then dehydrated using a anolecuflar sieve. The m�lecular sieve beds are regenerated tasing dry gas that has beesa heated by the regeneration gas heater. The dry gas is then run ttixough the cryogenic azffiit to super-cool the gas and remove natural gas liquids. 'I'he cryogenic unit is supplemented by three (3) 2500 hp electcic motor driven propane refrigeratioaa�ompressors. 'I'he residue gas from the cayogenic unit is then cotnpressed utilizing two (2) 1 b,000 hp electric motor draven compressors�o deliver the gas to the transportation pipeline. The produeed loT�'aL's aee also transported from tlie facality via a pipelitxe. 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' � . 801tld 3H1 100H11M 430000Yd3tl 3B L0NNtl�9NIIdtltl0 SIH1 , ___._.. .. ..... . . ... .. _ ... _ ... ..._.. __. ... . .. . .. . . . ._.. . _._ . _.... . . . ... .. . . _ J _I_ L 1 _I_ L � _I_ L� _I_ L � � L1 _I_ L I_ L 1 _I_ L �_I_ LJ _ _ LJ_ J_ L 1 _I_ LJ �� z s g a � � o ow �� d � Y co a m o . I r � . 2 Q p 3 N �, ��.. �� o a Z U � . � Q Z � i��. O o� d I � J I � � � � . - ' .. . . � � � p E N � �y� � ln i g � �I � �pf � � O) mz I N olo � a oo � �U � o y - _______J � o o W m o � '�I� aY t' o I W $a"� � LL x� . � � �a Bw zw¢ .� I o> > a� . � � 0.' o 0 �. N � OO I I N J � �U � . �� I � O I � I � � � . - � � � ��< . . � � ��,,��I LL � a I � . � . � ��,�,��I ¢ . . � � . .. q . O I a z N � �� W . ' . .��,'�.. \ � O . . � \ / � � � . ' � . .'�. I V I °° � O O .-o rn I O �W . . . . O � - � � ��... rc 3 � o � I O m -� m m JQ . . .. � � . . �.. m � � � . . ..'.. � O U . 8 $ . � . � . ��. ≥ � d � . . � � � . . .. - -� -i- �� -i- M -i- r �-i� �--� -i- r � -i- -i- r7 -i- r �r -i- r7-i- r7 -i- r �r -i- r � 'ONI 53>Ntl3S�N1833NI�N3 NO'Jtltltld 3H1 10 1N3SN09 � " � � tlOitld 3H1 NOHLM 43JWOtld3tl 36 WNNtl0.9NN\tlY0 SIHL �. At��e�at �I IF�7CIl➢H L�P�'II�=3�� e'�,4 �bfl'�. Colorada�1ep�rtiaaent of Public Health and Environment ;�'' � `�'�, Air Pollution Control Division isx�y_; . �� ff� �� '*M;�u��_a t:csfcoca�[co-IJeuaarc3r�emc �f!'ii6fcc 9 dea.��li ai��F.�i�ir�nusneuc ��S�a��na�� ffis� l��g�n��ae��a�� a� �'��eq�� 4°�r A�e�ae ��¢a�� Sy�� I Ver. September 10,2008 The Air Pollution Control Division (Division) developed this Operating and Maintenance Plan (O&M Plan) for amine sweetening systems that are permitted at a synthetic minor facility in the State of Colorado. An O&M Plan for each type of anune sweetening system configuration, as described in 5ection 1, shall be submitted with the permit applicarion. One O&M Plan may be used for multiple amine sweetening systems at one facility if each are controlled and monitored in the same manner. If the O&M Plan template is completed correctly,the Division will approve the O&M Plan and a conshuction permit will be issued with the requirement to follow the O&M Plan as submitted. If the template is not wmpleted correctly, the Division wzll wark with the facility to make conections. Once a conshuction permit is issued, the facility operator must comply with the requirements of the O&M Plan upon commencement of operarion. Operators are not required to use this ' template. Independent case specific O&M Plans may be developed and submitted for approval with the permit application. However,the IDivision encouragesthe use of this template to expedite the permit applicaflon approval process Submittal Date: 11/29/2011 ' Secdio�Il -S¢angce II�enQeffnc�8eomm '�:� For new permits some of this information(i.e. Facility AIRS ID,Facility Equipment II➢,Permit Number,and AIRS Foint ID) � may not be laiown at the time of application.Please only fill out those fields that are lrnown and leave the others blank. i Company Name: Kerr-McGee Gathering LLC Facility Location: 16166 WCR 22,Fort Lupton CO Facility Name: Fort Lupton Gas Plant Facility AIRS ID(for existing facilities) 123/0057/ ' bJaufits�oveged 9sy Q➢aes��alb�d flor�a ' 1Face9efly E�anipment Y9D P,�-Il A-2 ' �ercauadg I@Ianieep�eg t$][A$5 IlToimmt FHD �aa�ine B' e Ns¢d° I�]E� I�IIB1Ee� a Amine types include MEA,DEA, TEA,MDEA, and DGA �e��ss¢oae�on¢eQs a��oaetvofl SRaQaaa: Check the appropriate boxes indicating whether the dehydration system(s) are equipped with a flash tknk and whether or not the flash tank(ifpresent)and still vent emissions are controlled"or recycZed or vented to ; at�nosphere. �Flash Tan2c � Still Vent � Controlled/Recycled �Conixolled/Recycled ❑Vented to ahnosphere ❑Verned to ahnosphere - Sectioca�-il'fiaia4ena�ce Se➢ae�anies . �'Haeck one o�'t➢ee ffo9➢owen�: Facility shall follow manufacturer recommendations for the operation and maintenance of equipment and control ❑ devices.These schedules and practices, as well as any maintenance records showing compliance with these recommendations, shall be made available to the Division upon request. PagC 1 of 4 A-I and A-2 APCD306-AmineUnitO&M-Ver.9-10-2008.doc �oloaado Y�eparhnent of Pubflac�-Iealth atfld Easvn�os'aaaent Air�ollaa�ion Coaa�eol�5ivaslo�t Facility shall follow individually developed maintenance practices and schedules for the operation and maintenance of equipment and control devices.These schedufles and pracfices,as well as any maintenance records showing compliance � wiEh these recommendarions,shall be made available to the division upon request and should be consistent with good air pollution control practices foa minimizing emissions as defined 'an the New Source Peaformance Standard(IdSPS) general conditions. �e�ad�¢e 3-Il�omm4@nIl��emiQ�ao�l�doeIl�96ee�oe��9ene8�i4e��¢� '9'&ce P�P&�eueng m��aas��s�ee9c�a�fl�s°O�1�pnRai�¢��e c��$��lee°¢df e��a@e4�e The source will calculaYe emissions based on the methods and emission factors provided in the permit application and ' � approved by ihe division, as reflected in the construction permit.Please see the operation and maintenance plan ' guiclance document foN fu�rther details and examples of emdssion calculations. �ee4fio��—G¢unercall�do�nR�¢��IlZ¢manda�eece�eeQs Table 1 below details the schedule on which the source muse monitor each ofthe listed operatingparameters depending on the requested perrnitted emissions at the facility. Check the appropriate box based on the facility-wide permitted VOC emissions. 7Cffi@�&�fl � IC�[o�n4o�� 1Rrce aeeets ��ga�a�4�v �I�¢a��iflf¢��+'��n➢u� ❑�ec¢ena��ea�1F�eo9's8y ' ��na�semeas��d��P�C �mna§sa�¢a$ < ��4��@P�� .ea�n.�¢onoan��avcu9��d��A�ah� Daiiy Weekly ��s F�9¢�'�'e� �p�Qaue� Weekl Monthly �a,$Fuu9e��ve�soac� �Neeldy Monthly �1�9aauaa�o&°��$�¢�1�TGII,l�e��s��¢� Monthl ItQonthly T'ables 2 and 3 ou4line the methods by dvhich the source may monitor the lean amine recirculation rate and the gas or NGI, processed,respectively. In Tables 2 and 3 the source musY chose one primary monitoring method and,optionally,up to two bacicup monitoring methods. �'��@¢3 �vu¢¢e�vy ��CBS-B➢ g.��89 AB&Il&PA�A�CC99'�WIl�gH�PA B$��L�I�O7mA$�9'PIIQ 19��Q8a�a� � �4�uan�4��ew�e�ea(�)—including flow from all um s � � 1��eov��4ro9c�s�e�eun�¢au�¢��c9 xo�v�r�to sflas�a��8flaee��a�—pump make/model and stokes per minute/circulation rate relationshi must be made available to the division u on re uest � � A�sa��aa�ae�eanaan d�sdgaa�an�gr �s,�e°—pump make/model and circulation rate specifications must be made availaUle to the division u on re uest b Note: if you are requesting to peamit at a rate lower than the maYimum design pump rate then this oprion should not be used . � �, as it will create de facto non-compliance. 'Il'�9a➢e 3 �e°e¢en�c° ]��s&�-u F�a9enffie ofl'�as oa°1�Gd.�roc�ss¢a�l�ounifl�rciee I0'�¢4➢e�a➢ � fi/�eRes�� Inlet�Outlet� Com ressor SucYion❑ Com ressor Discharge�Othex: . ❑ ❑ 1F�e8�re� Inlet❑Outlet� Com ressor Suction❑ Com ressor IJischarge DOther: ❑ � ��§oc�a¢uan��e�se¢��n a�ate`s ecifications sha11 be made available to the division u on re uest ' ❑ ❑ ��'Qgm 9�¢�� a'ovea9 by�9a��flvi�a�n): attach method e lanation and sam le calculations ` Note: if you are requesting to permiY at a rate lower than the maacimum contactor design rate then this option should not be used as it will create de facto non-compliance. ! �Pa�e 2 of 4� A-1 and A-2 APCD-306-AmineUnitO&M-Ver.9-10-2008.doc �� II �oloa°ado l�epartmern4 of Public I�ealtfi and�nvia°onmecat Air Po1luYion�ontrol d3ivisiom ��sffifo��-JEa�nfis�eoua�omrteo&��IlB�cvs9nm¢�maae��te¢et l�o�i4�ram PB�aauereee�e�Rs Table 4 below details the monitoring frequency for con9rol equipment depending on the type of control equipment used and the requested permit�ed emissions at the facility. Check the appropriaYe box for"N3onitoring Frequency"based on the facility- wide permitted VOC emissiona In addirion, indicate sfill vent and flash tank emissions confrols by checking the appropriate boxes. 'A'�@�➢�4 IVda�fltomfl� �+re [ae�sy ��u��i�a�§�offi4v�➢�a� �8nld �'➢a��n �a¢��aaae8¢a �]Perannp4¢c�II+'a�fi9udy ❑��¢sai4V¢dl 1F��fle8g� IIBee�e�fi�ng I@%[[�t6na� �/�anE 7C��e� �c�a��fious� �eene�sa�e¢s ?��dpcy�7�� <��8y�y�� . , �'9n��aaa�➢�scn��ea° � � ��¢�fleansd°e�a�C7e��aV��re I �'eean ev�daame a Daily Weelsly �ouea&eun�&�s�r 1�➢�e°� ❑ � 1�a9ot Y.uglah 1VLma�fi¢�a�daug` DaIly Weekly � 1@'de�9eaa��e�aIlfimgs Daily Weekly lt��eys9e��rr�Go§¢a➢1Lo�ga �y�rt¢�n Qgaucllan�nua� ❑ ❑ 1r�me a➢¢¢ea�eee�e�9�y 49n�saaae°e¢��d��Cg��v¢��ng�gTm��o�e�fim�f ��°IlBec�v¢xg�FJ�efl4�� E�¢-r�un4¢a��Et¢&aon➢�� , I �aupea�rr ❑ ❑ 7['�lbe¢�e�eg�ne��&ay gh¢s�a�a�e�a�n��n�rc�e�e�V�y�9e¢e@ee�fl�e�ua g , " I@/�n�eeuaune�B'&e��u¢a�fl��ae&�a�e �'�eunP�aa$4am��a9�¢e B'¢rmnqaea��d�eg¢ Yf the facility uses a thermal oxidizer to control emissions then the minimum combusrion chamber temperature shall be:Select ' one of the follawing options fromt Tabde 5: '��Vn➢�� 1400°F , � o F Based on manufacturer specificarions. Specifications must be submitted with I ihe ermit a lication and made available to the Division u on re uest ❑ Based oxi testing performed. The test data shall be submitted and a4tached to the O&M Plan ' e&°nflo8�.eg�ng t�[1�anngoe�ou��gy4ao�� If the facility uses a Combustor or Flare 8hen the source ffiust indicate the method by which the presence of a pilot light will be monitored in Table 6. One primary method for Pilot Light Monitoring must be checked and,optionally,up to two backup ' methods can be checked. 7C�b9�� i�re�eam �asfls-nu 16�m�i¢ae°ua� I�e4Cno� � � Visual dns ection ❑ ❑ O tical Sensor � ❑ Auto-Igniter Signal � ❑ Thermocou le �fl8��ys9�d�v C9o§ea�L�,o��u�y��e�l�o�agoa°aang Pd�eu , In the space provided below please pxovide a brief description of the emission control or recycling system,including an explanation of how the system design ensures that emissions aze being routed to the appropriate system at all times, or during all permitted runtime. , . Page 3 of 4 A-1 and A-2 APCD306-AmineUnitO&M-Ver.9-10-2008.doc . Colorado Department of Public IIealth and Environment Air Pollution Control Davision &i8eboiler l�a�rner Coc¢tmod 1V�oaeflfor�etg Pla� In the space provided below please provide a brief description of the emission control system,including an explanafion of how the system design ensures that emissions are being held or rerouted when the reboiler is not firing. Seetion 6—EBecordkee�ene ABeaeeirements '&'�e followiaeg boz maeast be c�ecflc�d for��c1iB p➢aea to be consiaiered coaanplete, Syntheric minor sources are required Yo mairnain maintenance and monitoring records for the requirements listed in � secrions 2, 3,4 and 5 for a period of 2 years. If an applicable Federal NSPS,NESHAP or I�ACT requires a longer record retention period the operator must comply with the longes¢record reternion requirement. Sectio�7-Additional No4es and O�z1Q�Aetivd4oes Please use this section to describe any additional notes or operation and maintenance activities. Amine still vent and flash tank emissions will be routed to the plant emergency flare when the thetmai oxidizer is down Idote: 7'hese temp[ates aae dretended to addre.ss operation and m¢ainteaeance requieements o,f the,Staee of Colosarlo foe equdpmend operated at synBAaetic mtinoe facflitfes.If the facility or equipment fs subject tm otheP sBaPe or federal eegula8ions with duplicative requirement.s, dhe sorarce sh¢ld fadlow the most sPrirzgent aegulalaay regutpement. � � PagO 4 Of 4� A-1 and A-2 APCD306-AcnineUnit0&M-Ver.9-10-2008.doc F�u°¢nn �I��AD-�� '"�r,�,. e�� g�5 Colorado 13epartment of Public I-Iealth and Environnaesat � Air Polflutaon Control I3ivision �s>�� *j� �. ��{ k.H jt' 6 i�.F C:nVcuraJ«I3euaariarurrue �mf i'uL�E¢e�Ie.�lch acre�Y E�ra 6eaeuoneilc ��°�� ffi� I��Il��ea�� Il�sn Tea�yn�� R°��° �'a��g�� '��g��n�ue� �,�a��a�g��e��n �oaa�°�� Ver. September 10,2008 The Air Pollution Conirol Division (Division) developed tlris Operating and Maintenance Plan (O&M Plan) for fugirive ' component leak emission sources that aze permitted at syntheric minor facilities in the State of Colorado and do not have any applicable NSPS or MACT requirementa If the facility has NSPS or MACT xequirements, e.g. NSPS KI{K, then the source shall follow the federal requirements and a separate O&M Plan need not be submitted. If required, the O&M Plan shall be ', submitted with the permit application. If the O&M Plan template is completed correctly, the Division will approve the O&M I Plan and a conshuction permit will be issued with the requirernent to follow the O&M Plan as submitted. If the template is not ', completed correctly, the Division will work with the facility to make coirecrions. Once a construction permit is issued, the ' facility operator anust comply with the requirements of the O&M Plan upon commencement of operation. Operators are not requued to use this template. Independent case specific O&M Plans may be developed and submitted for approval with the pemut application. However, the Division encourages the use of this template to eacpedite the permit application approval process. Submittal Date: 11/29/2011 Sestiom fl -�oan�se IIdf��tflffac�aeoun For new permits some of this information(i.e.Facility AIRS ID,Facility Equipment ID,Permit Number, and AIRS Point ID) may not be laiown at the time of application.Please onlv fill out those fields that aze lmown and leave the others blank. Company Name: KemMcGee Gathering LLC Facility Location: 16116 WCR 22,Fort Lupton, CO Facility Name: Fort Lupton C'ias Plant Facility AIRS II�(for existing facilities) 123/0057 I gJaaiRs�'�vevea➢dng�8@eus�d�zl�/I1 ff�rc¢¢e Faci&i4y�cga�ipa�eeaf II� �'87�3 �ercsaenh�TaananVr¢rc .�II1�S�oaaa�II� I S¢etdon��l�iiainke¢aaeae¢SsHne�lenle� Chee4c ou�e of 8he ffo➢E�we��: Facility shall Follow manufacturer recommendations for the operation and maintenance of equipment and control � devices. These schedules and practices,as well as any maintenance records showing compliance with these recommendations, shall be made available to the Division upon request. i Facility shall follow individually developed maintenance practices and schedules for the operarion and maintenance of equipment and control devices. These schedules and practices,as well as any mairnenance records showing compliance � with these recommendations, shall be made available to the division upon request and sbould be consistent with good ' air pollution control practices for minnuizing emissions as defined in the New Source Performance Standard(NSPS) ' general conditions. I - � PagO 1 of 2 � FUG 3 APCD303-FugitiveLeakO&M-Ver.9.10-2008.doc II . . � ._._ ..__. . . ..... _. _. . _._.___ ._.. ... .... . .. . . . . _ ._. ... .. . . . ... . .. �otarada L�eparhnent of�aablic Edealtka and Envar�nmen8 Aar Po&lu4ion Controd�3nvision �¢c4fl�ua�-IVdom4PoEw�nau��eman I��cHe➢an�me ��flsu9�8u��$ '�'6a�ffofl7�eva��&nmx�atannQ4 lla�e9aes➢��e�ff�a°��PVfi�9�m g�Ha�s�easuefl�x�m1 coeeagcIl¢kge The source will calculate emissions based on the methods and emission factors provided in the permit application and � approved by the division,as reflected in the conshuction permit.Please sze the operestiovr and maintenance plan guidance documentforfurthev details and examples ofemission ca7culations. S��Qe�co �9—��aea��&I�o�n��e-�ea�Ilt�anaeevea��eets C'aeneral Leak Detection Program-all sources must conduet a recorded walk-through by piant ar company personnel with visual, auditory and olfactory leatc detecrion accarding to the schedule in Table 1.The operator must make a reasonable attempt to£ix any leaks found during these inspections. Check which box applies based on faczlity-wide permitted VOC emissions. ��fl�Il �eneennqQ�c➢��cflln�g��7��i�ussfl�u¢§ &�s e�8aom��ea�ueesn�g� �≥$0 h�Y Monthly ❑ <80 tpY Quarterly S�x4n��-lEu�is$6�en tCom4�o�INIIarmnrt�rfi��g8�e�ann�euen�ra¢� ❑Non-I�ICIC LIDAR Frogram Using Method 21 —(If federally enforceahla emission reductions are being requested) o Attach an e�lanation af the monitoring program and recordkeeping format a The master component lis4 and monitorueg records shall be made available to the division upon request m Maintain a log of equipment and component additions and deletions �¢eQfim��—Fbee�a�aElk��n��lf��a�nnna��n��n�s 7C9a�fl�9i�avnea�9��waas$4�¢sHe¢s�s��ff�a��Ia'��m 4m lb��aasfi�ea°e�e�ea�gs➢�Qe. Syntheflc minor sources aze required to maintain uaaintenance and moniYoring records for the requirements listed i�n � sections'L,3,4 and 5 for a period of 2 yeazs. If an applicable Federal NSPS,NESHAP or 1biACT requires a longer record retention period the operator znust comply with the longest record retention requirement. S¢cffemea 9-��e�ukfloaea9l�T�Be��eadf�a�cIb�Asfdmfid¢¢� I �lease use this section to describe any addational notes or operation and maintenance activiYies. � Page 2 Of 2 . FUG 3 APCD303-FugitiveLeakO&M-Ver.9-10-2008.doc� � E'mergeaacy Deesel�eeeeea2oe Eregecee��l✓L P[are,ICeva�Rdc�ee Gaeheresa�L��-F'E EeepPott�as Pdnsat h'ovember 29,2011 � ��.��E�� E��.`�v ��S� ��eE�� . . II��ma��l��G�� t��d��uffi��,tC F�, �.ange�� ffi2 �a��a°��n�g�A�e��9��m�g�a� 1'lvs Operations and IVlaintenance (O�IVd) plan addresses �naintenance pract�ces and recordkeeping used to saxaantain compliance with tflie requisements of the applicabl� permi4. ��I]EII��J T'he Ft. Lupton C'ras Plant is a natural gas processing facility that utilizes ten natural gas compa•essor engines and one �ropane coanpressor. !� diesel engicae driven generatog Is operated to run ausiliary systeta�s in the event that commercial power is disrupted. �perational ready checics are conducted for brief per2ods on a periodic basis. �s�I�l[ ��J��ILpF�T�� Tlae diesefl geaaerator emgiaae vv�ll be operated iaa accardance witfla the manufactaarex's I recommenc4atian. Fuel c�nsumptioaa will be calculaYed usfng the hours opexated and the gnanu£acturer's provided fuel cons�nptaon rate of 36.6 gaUha. 'Phe following equation wi11 be used to calculate fuel consufaaptio�: , F'�ae1 consuinption(gal/a�onth) =I2ecorded houxs of operation(iar/manth)x 36.6 ga1/&ar I!� ��9�IElE�di�� ' a �tatnon operatoxs will maintain records according to tiae applicable permflt. I�I � �tation operators will rrcaintain recards according to this ��ilVt I'&an. ' e Records of e�agine maintenance. I� Each given month's records will be maintained at the compressor station. It�aintenacice I�, data is stored via computerized maintenance program. Applicable re�ords wi11 be anaintained in the Denver office, excluding maintenance data which are stared via ' computerized maintenance�rrogram. � �I __ i ��i�� -- _ _ F��°4 ILaa�a�en �� an� ��e� �9�� n�H�tt�u� ��flg��➢� ��eta�� fl,� m �t��e�an��a6�un� �e��e��¢e�e�3,I��a�B.�,��2d��z�'� The fave newly proposed el�ctric drive engines are not subject to AP�I�peporting requirennents. The 90 I�d1F�a�fia/hr amine regeneration heat medium heater, 20 �tu/hr mole sieve regen€ration g�s hea4er, 150 I�IVI3CFI� 'TraEn 3 amine treahnent system controlled wnth a thermal oxidizer, 150 NIlt/B Train 2 amine treatanent system controlled witla a thermal oxidizer,the emergency tlare,the emerg�ncy generatox, p1anY fugitaves and the modifica4ions requested for 4he 4wo exnst3ng S�Vaukesha compsessog �raglnes are subject to A&'E�reporting requ9rements. 14e�aadaaE��a�.�,�aaa�8�y S�eddar��d ansP�� The 9� M1i�tulhr amiaae regeneraYzon heaY snedium heater, 20 10RMShr/hr mol� sieve regeneration gas heat�r, 150 I1�IlQSCFI9 Z'rain 1 asnine treatanaent system conteolled wflth a thertnal oxidizer, 150 N�Nf Txaiaa 2 amirae treatment systean controlled with a thermal oxadizer, the emergency flare, the emergency generaEox, plant fugatives and the modifications requested for the two existing tWaukesha compressor engines are subject to this regulation and required to obtain a construction permit prior 4o construcEion. T'he operation of these units walb be lirnited as requested on tlae Aflr Polluitant Emissions 1Votice og in the permit application. ��ez�ca8��3� �aa�8� 'd'he facidit,y is curreaaYly operaYing as a nnajor souxce with respect to the'Ptgle V�perating Permig�rograaan. "d'he facility will be xequired to submit a'Title�1 Pea�anit applica4ion modiffication Por the proposed proj�ct within 12 months o£star[up. �e�ao��aoa¢3,�°ra�8� The Pacitit� is an exasting rnajor st�taoanary source and is therefoxe subject to this Paa�. In det�rmining ghe net emission encreas� of tlae proposed peoject, actual emissions were calculated as per IY.I�.l and resulted in emissions below �lfl applicable criteria pollutani PSD significance thresholds as pep dd.A.42. The propos�d project does xiot resui8 in a significant net emission increase fln criteria pofllutants as per 3F.A.2C and as a�ot considered a major �gaodnfacatiosa for criteria pollutants to an existing major stationary source. �'herefore, the proposed mod'af cations to the facility are not subject 2o th� pemni4ting requisements af ghis ' Par�. ��&E�1£�@�Db.�y�68P��B' � .. On Oc4ober 21, 2016,40 C&'pZ Parts 51, 52, 70 and 71,ITrevention of Significant➢3eterioration and T'itle�I Greenhouse �"ras Tailoring IBufle was adopted into Igegula4zon 3, ParY I.T'I'. The second step o£ the tailoring avle went into effect on Jufly 1, 201 L dJnder the rule all new and existuag sources that have eflae potential to emat at least 100,000 tpy COze will be sctbject to 4he PSD and title �1 requirements. Also, soueces that have the po4entiafl to emit at least 100,000 tp}� �OZe and undea�take a modification that i�tcrease net emissions of Cs�-IGs by at least 75,000 tpy COZe will aflso be subject to�'SD requirements. The existing facility has a pot�ntiafl to emnt at fleast 100,000 tpy COZe and the proposed modification is grea4er than 'I5,00�tpy COZe,4herefore this project musY submit a FS33 permit applicataon Por C'r�Y�'as. A BACT anaflysis for C'aI3C'rs is iaacluded in Attachment J of the applicaiion. �e�a�dtatdoaa 6 i Regulation 6 incorporates by reference the EPt�'s New Source Performance Standards (RTSPS). 1VSPS ' applicability can be foumd in Section 2.0. Page 1 of 4 88��saPcea'd�sa 9,��cta�re�d The faciliCy ns 9oca�eed an the �-�our Ozone��ntrol Apea; therefoge tkus facility is subjecY to �ectaon�II of this regulation. The proposed proj�ct does notnmclude produc4 storage tanks, naYural g�s driven engines or a glycol dehydratnon systean. All residue gas and prod��ed naturat gas liquids wntl be 4ranspor2ed off site via a pipefline, gas will be dehydaated wath a moflecuflar sieve and na9iaral gas will be compressed w��tc eiectric drive engines. Therefore, Section J{IF.C, XII.F� and X�II wiil nag appfly to the proposed I modificatioaa. f .�s per 9ec4ion XII.�'a.l, the proposed modifications will be subjec4 to the £,I�L�IB requirements an Subp�r₹ ' I�dGI�and therefare comply with 5ectian XIY.Cr.l. � �e�s¢lcadaoaa � I Regulation � incorporaYes by reference tlae E�t1's NaYional Emission 3�andards for I-dazardous r�ir j Poliutants QNE��Ps). IV��d�I'applicability can be focand °zn�ec8ioac 3.0 and Section 4.0. ' ��Ra��,� � �� 6� �1@�� nn�°��¢u°ff�suna�ffi�� Q��12a�°a&� 61VT�� ' .$e�6��staa°t!�—GeneYal Provisions I 'b'he�'aeneral Provisiams of tlse federal hTSP3 appfly to any stationary source that conYaans aaa afFectec4 I facility to which an IaTSPS app(ies. The proposed modifacatioa�is subject to mealtiple NSPS,therePore, vaaious porrtions of this Subpaa�t wnll appby. �ee��tea�4 IIAe — Stana'ar�cds of Perforrr2ance for Small Ind�astv�ial, Comrrzercial, Institutional Steam Gene�ating �Iveits Sgandaa•ds of I'erformance £or Smafll Indaastrial, Commercla9, asad Institutional Steam Caeneratiaag Units, applies to steam generating uni4s h�ving a maximum design heat is�put capacity less than or ecgual to 1001Vi1l�tu/hr but ggeater than or equai to 10 MIVi�4u/hr that are constnacYed, reconstaucted or modifi�d after June 9, 1989. A steam generaring aanit is defined 'an Sectaon 6�.�1c as"a devic�thaY combusYs any fuel and produces ' steasn or heats wa4er or heats any heat 2ransfer mediucre". ' The proposed natural gas fired 90 I0�1ly�tta/hr amine heat medium heater and 20 MMStu/hr xnole � sieve segenerator he�ter is saabject to this Subpart. Na4ura� gas is tfie sole fuel for boP3i fieaters and � therefore,the sources are subject to 4he reporting and record keeping requirements of 60.48a �usbjr�sa�¢dgdd—Starzdcrrds of Performance for^New Stationary Engines Subpart I7BI applies 40 ovrners and operators of stationary compression ignition (C� in4errnafl combus4iou engines. Tfie proposed projec4 includes one 670-hp emergency diesel generator tha4 wllfl operate a maximum oP 500 hours per year. The proposed engine will be subject to the emission standards of 60.4205(b), th� operating requirements of 60.4207(b) and the complaance eequirements , of 60.421 L �artb��s��d'rb-Standar^ds af Ferformance for Volatile Ovganic Liguid Stoa^age Vessels , Subpaz-� Y�b applies to each storage vessel with a capacity greater tlaan or equal to 75 cubic meters us€d to store volatile organic liquids (FTOL,)for whiqh construction,recotastrucCion, og mod�cation is Page 2 of 4 I' _._ . . . coaaamemced after duly 23, 19�4. There are no s2mrage taar�cs propased iae Slbas modificatioan, thereg�re SubpaYc Kb does not apply. ,�es��a��t��—Staradar^ds of Pea°foNmance for Onshore N�turad Gas I'rocessing:SOz Ernissions Subpart �,I,L applies to onsYnoYe natural gas processuag pPants that have gas sweetening aanits. '��a� propased modification inctudes two 1501!/�SCFI� amiate gas svweetening unnts which v��ill be subjecfi to this subpart. Both units wPlfl hau� a design capacity of less than 2 long tons per day of IIZS iya the acid gas and therefore will only need to comply vuith tkae recordlceeping requiremen4s of 60.647(c�. S�b�rtssP.�1/.�.�Standards ofPea^fov�mcance fo�5%ationary S�rc¢rklgnition Internad Caevabustion Engines Standards of Ferformance foa� Stationary Spaxk �gnatiota dntemal Coanbustion Engines ap�lies to maanufactiarers, owners and operators of sta4ionary spark ignition (Sn internal combustio�a enganes tgC�). This applies ta engines that wexe ordered faom the manufacturer after 5buae 12, 2006 and are manufac8urec6 after July 1, 2007 and are greaYer than or equal to 500 hp or manufactured affer 3uly 1; 200� aiad are less than 500 hp, and eangines that are modified or reconstructed after dune 12, 2006. The pxoposec� modificaaion includes £nv� elecEeic drive engines and oaxe diesel fired emergency generator, therefore, Scnbpart JJJY does not appfly. �n�bgv�rd �A� Staredards of Perfortnance for �'quipment Leaks of VOC from Oaa.shore Natuvcal Gcrs Processing Plants Standards of Y'erformance for Equipment Leaks oP VOC froan Onshore Na4ural C'aas $rocessing �IanRs apply to affectec9 facilities �n onshore natugal gas processing plants 4hat commenced constnzc4ion, modificatioaa or reconstruction after January 20, 1984. A na4ural gas processing ptant is defined an the Subpaxt a5 aaay siYe "engaged in the exlraction of naturad gas liquids from fiefld gas". The proposed mod'afacation wilfl extract 1�CaI� from the fiel� gas aand zs thexefore subject to Che Ld3.4dt sequaremeaaYs of tfl�is Subpart and Stage l�egulatioaa 7. ��g��n �e� �� '�+1� �Il �l��gn�ffi��ni��n�ea �4��¢��rra�� ff��&��°��nn��nre��Il9�a�ar�4� �sabdr�aet F�—National E�eission Standards for Equipment Lealcs (Fugitive E'mission Sour^ces) , Nataonal Emission Standazd for Equipment I,eaks (Fugitive Exnission Sources) app9iesto soenrces that are l intended to operate in votatile hazardous air poYlutant (VbIt�P) service. Based on engineexing judgment, ' historical and aecent gas comp�osition asnd facility process it can be predicted that the percent VdIAP content will never exceed 1� percent by weigh₹; therefore �ubpart V is not an appflicable regulation for the faciliry. ! �¢�@n�ffi 4.� � �� R�3 �l��n�a��nn��sn��n ��¢�s ff�a°ff��m��n�l�da-��YflanQ$u�Q� �a¢bpsaa� ��I!— National Erezissdon Standards for Hazarclorxs Ai� Pallutcmats frorn Oil and Naturesl Gas Procluction Facili2ies. National Emission Standards fbr I3azardous Air Pollutants from Oil and IVatural Gas Production�aci�ifaes appflies to glycol d�hydration units, storage vessels with potenfial for flash emissions, and ancillaay equipment opea�ating in volatile hazardous air pollutant (VIL4F) �ervice that is floca4ed at a facility which ' is a major source or area sousce of ilAPs, VFIEIP service is defined 'an the 3ubpart as "a piece af anciilarg� ' equipment or compressor either contains ar contacts a fluid which has a Yotal V�IAP conceniration equal � to or greaYer than 10 percent by weighY'. Th� proposed modification is located at a anajor source of �, Page 3 of 4 �, �Ps, bcat does saot inclu�e any glycol dehydration uraits, storage vessels rov4th potential for f�ash ernissions and e�uapment will noti operate in\/I%P� se�vice. 'Phea�efore, Subpart I�wnll saot�pply. �aabpsea^d��—Na2ioraal Emission,Stanclards for FlazcaNdous Aia^Pollutants for Stationary Reciprocating InteYnal Coroabustion Engines. National �mission Standards for E-Iazardous flir 1Tollutants for �tationary Iteciprocating Intemal Combustion Engine� (RICE)establishes natfonal emission limitations and operating limitations for�3APs emitted from stationary reciprocating internal combustion engines, and requirescnents to demonstrate initial and continuous complianpe with the emission flimitations and opera�ang limitatgons. `�he faciliYy is a major source of Ht�Ps; 4herefore, the facility is subject to rciajor source ZZZZ requirements. The proposed modifications include five electric drive engines and once d'aesel fired etaaergency generator which are not subj ect to the requirements of this Subpart. �¢��a�sn Se� - �� ]F&��—��aa d$�nn��3��a�� S�ab�aee�r¢A 1"aeneral Provisions applies to a facility th�t contains any source category (as defned an subparts C tk�a�ough JJ of this part)that as flisted iaa this paragraph(a)(2) in any calendar year starting in 2010 and 4hat emzts 25,000 metric tons CO2e or more per year in couabined emissions 4'rorn stationary fuefl combustioaa units, miscellaneaus uses of carbonate, and alb source cagegoraes that are lisYed an this regula4ion. T'he facility is subjec2 to the reportang requirements of Subpart C and Subpart''R7. Page 4 of� I �4�a�hmena � d��r�McGe� Gathergffi� L��C �'�r� L�p��ffi G�s �fl��n� C�°3�o�ena� �fla�� P�°o,�ec� �rreeffi��a�� G�se� �e�� Ava��9�� C��r�� '�'ech��m��e� (��C'�') Aa�aflg�se� � T�kS'S�� r:yi f:��1JI��E.1�,"-<z � . I�aciBi4gr 9a�foPrea�Biorca........a,.,.,......,>......................o...,,..,........,........,........,.......,...a...,...........,..e..,......,a,� Pvoc@5s Des6nip$o�¢a....,a.................................................e,...............,..............................,..,.....,......o..,� �acaisseora S�aae�e�.o..e...............e.....,,.....,..,.......,.....,..,...,oe.e.,...,,.,..............e.,...,.....,....,......,......e..........� �l6�T.9n�lysis MegB�odoO�gy.e..,...,e....:a.,.,...,.e........e,...,.e.......a....a..................................a...........:,......� �ACY Eval¢aa¢imro ffor S�a�r�es........................:.............e.......................,....,....o.,.........,.,a...,.,.,.........vo.o� 4A�p�endix A�Ecoa�oaanus 46ea�6vsas 4�a��S e.a...e...................:.....................:...............................a...,.....A Agapeu��'stt E—��2 Beoff�evv�a�ooa�Saaeva¢vaaap.............e....................e..............,......................................� A'+��nfiflflv��ff�a°�s�4a�ano The Fort Lupton C"aas Flant ls in Weld County, CO at NorYhwest '/<, Section 14, Township 2 North, Range 66 West. `I'he coordinates are: Latitude: 40°, 16.14'N Longitude: 104°, 45.08'`IJ The s�reet address is: 16116 WCI�22 ' Ft. Lupton, CO 806Z1 The existing facilities cue�rently operate under a number of construction permits as weli as ', Title V operating permits. A recent acquisition of assets formerly owned by En�ana also brought the Platte�Ialley Station into the single facility complex. l�¢��ss Il9�se�n�d��vno The new 300 million standard cubic feet per day (NdMscfd) cryogenic planY will be located adjacent to the existing Fort Lupton Facility which includes gathering compression and existing refrigeration plant. The plant will receive third party gas from the Kerr Mc('iee Gathering pipeline system in the Wattenberg Field, remove CO2 via amine treating, dehydrate the gas through the use of molecular sieve beds, extract natural gas liquids (NGb�) through the use of the gas sub-cooled process (GS�) and SCOI2E cryogenic cooting processes and then re-cornpress the residue gas stream for sales. The CO2 is removed from the inlet gas stream utilizing two (2) 600 gpm amine treaters. The , amine treaters incorporate a therrnal oxidizer per unit to control emissions. T'he gas stream is then dehydrated using a inolecular sieve. The molecular sieve beds are regenerated using dry gas that has been heated by the regeneration gas heater. The dry gas is then run through the ', cryogenic unit to super-cool it and remove natural gas liquids (NGd,). The cryogenic unit is supplemented by three (3) 2500 hp electric motor driven propane refrigeration compressors. , The P•esidue gas feom the cryogenic unit is then compressed utilizing two (2) 11,000 hp electric motor driven compressors to deliver the gas to the transportation pipeline. The , produced NGLs are also transported from the facility via a pipeline: The primary reason for treating the inlet gas with amine is to ensure that the NG'iLs meet , pipeline specifications. The inlet gas has about 2.7 mole % CO2. 'Y'reating the feed gas auoids issues with liquid treating, such as amine carry over and meeting the pipeline water specification. �ecause the amine units are designed to remove CO2 from the natural gas, the generation of CO2 (GH('a) is inherent to the process, and a reduction of CO2 emissions by process changes would only be achieved by a reduction in the process efficiency, which would result in natural gas that would not meet pipeline quality specifications and leave CO2 in the natural ', gas for emission to the atmosphere at downstream sourrces. The amine units do emit methane ' (GHG) at the point of amine regeneration, due to a small amount of natural gas becoming entrained in the rich amine. , Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Page 1 . _._ __ . F�naussn�� anm��> The proposed project Yriggers Frevention of 39gnificant Deterioration (�3D) permitting thresholds for greenhouse gases, but does not trigger PS3� for any criteria pollutants. Th� primary sources of C'a�iC'as proposed at the 300 MMscfd plant will be: G4100 �olar 11,000-hp Electric Drive Engines, Residue C-4200 Solar 11,000-bp Electric I9rive Engines,I�esidue ' C-5110 2500-hp Electric Engine,Refrigeration Compression ! C-5210 2500-hp Electric Engine,Igefrigeration Compression C-5310 2500-hp Electric Engine,Refrigeration Compression ' E-2015 Mole Sieve Regeneration Gas Heater with Low NOx�urners H-6050 Amine Regeneration Heat Medium Heater-Low NOx�umers ' A-1 150 MMSCFD Amine Treater(Controlled with ATO-1) .�-2 1501VIMSCFD Amine Treater(Controlled with ATO-2) � F-2 Vertical Emergency Flare CaEN3 Caterpillar 670-hp Diesel Emergency Generator FUG 3 Plant Fugitives ' The proposed facility triggers �SI� for the esfimated GHG emissions as it is estimated to emit 256,372 tons per year (tpy) CO2 equivalent (��2e). 'Y'he CO2e emissions are estimated by � applying the global warming potential (GWP) of each G�IG pollutant. The �'rVJP for each pollul:ant is: �O2: 1 �H4: 21 1�T2O: 310 For example this means one ton of rnethane would equate to 21 tons of C�2e. Detailed ' calculations can be found in the calculations section of the permit application. � � bT�'� ��qny ' C-4100 - C-4200 C-5110 - C-5210 - ' C-5310 - , E-2015 12,812 H-6050 57,654 A-1 92,587 A-2 92,587 F-2 15 C'aEN3 - FUC's 3 718 Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Page 2 II I�A��H��¢�IO�e4@n�a➢�@��wa As of January 2, 2011, �'iHC'a is a regulated criteria pollutant under the PSD major source permitting program codified in Title 40 Code of Federal Regulations (CFR) Part 52 when they are emitted by new sources or modifications in amounts that meet the Tailoring I�ule's set of applicability thresholds. For PSIS purposes, GIiGs are a single air pollutant defined as the aggregate group of the following gases carbon dioxide (CO2), nitrous oxide (N2�), methane (CH4), and hydrofluorocarbons(I3FCs). The PSI� regulations do not prescribe a procedure for conducting �ACT analyses. Instead, EPA has consistently interpreted the�ACT requirement as containing two core cxiteria: 1. The �ACT analysis must inclaxde consideration of the mos4 stringent available technologies, i.e.,those that provide the "maximum degree of emissions reduction." 2. Any decision ta require as Bt�CT a control alternative that is less effectzve than the most stringent available must be justified by an analysis of objective indicators showing that energy, environmental, and economic impacts render the most stringenE altemative unreasonable or otherwise not achievable. EFA has developed what it terms the "top-down" approach for conducting BACT analyses and has indicated that this approach will generally yiefld a�AC�'determination satisfying the two core criterza. Undeg the "top-dowit" approach, progressively less stringent control technologies are analyzed until a level of control considered BACT is reached, based on the ' environmental, energy, and economic impacts. The top-down approach shall be utiflized in this�AC'T analysis. "I'he five basic steps af a top-down�t�C`d'analysis are listed below: �. Identify ail available control technologies with practical potentiafl for application to , the specific emisszon unit for the regulated pollutant under evaluatiorc; 2. Elimnnate all technically infeasible control technologies; 3. Rank remaining control technologies by effectiveness and tabulate a controfl hierarchy; 4. Evaluate rnost effective controls and document resuflts; and � 5. 3elect�ACT, which will be the most effective practical option not rejected, based on � economic, environmental, and/or energy impacts. Kerr NleGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Page 3 III ��'Ea�9an�ga��e ff�r��s��-�¢�e SFels 1:dilen4a,fy �oazEp��OpPiaaa� The following are potentially applicable control technoflogies for controlling �'iHG emissions associated with the�m e�: L t�ll the new compressor engines at this facitity will be run on electric power resulting in no C'si��s emissions from these sources. T'herefore, no further analysis is necessary for the engines. "I'he following are potentially applicable cantroi technologies for controlling G�FG emissions associated with the Aa¢auffie V�un4s: 1. Proper I9esign and Operarion: The amine units are designed to inciude a flash tank, in which gases (i.e, including�O2 and methane)are removed from the rich amine prior to regeneration, thereby reducing the amount of waste gas created. T'he amine units aY this facility shall be consiructed and operated for optimal performance; 2. Amine Unnt Flash Tank Off-gas A�ecovery System: The amine unit flash tank off- gases shall be routed to the proposed thermal o�dizer. 3. l�outing Amine SJnit Regenerator i/ent to a Thermal Oxidizer: This control devic� will reduce the methane emissions by 99% and will convert those emissions to C�2, wkich has a lower G'sWP; 4. Routing Amine Unit Regenerator Vent to a F'lare: This control device will reduce"the methane emissions by 9�% and will convert those emissions to C�2, which fias � lower�WF; 5. Carbon Capture and Storage (CCS): This involves capturing C�2, transporting it as necessary, and permanently storing it instead of releasing it into the ahnosphere. The process involves three main steps � �apturing CO2 at its soazrce by separating it from other gases, � Transporting the captured CO2 to a suitable storage location (typically in compressed form); and � Storing the CO2 away from the atmosphere for a long period of time, for instance in underground geoflogical formations, or within certain mineral formafions. m In the project two C�S approaches were looked at: acid gas injection well and enhanced oil recovery(EOR) The following are potentially applicable control technologies far controlling GH6's emissions ' associated with the&�¢�t¢a�s: 1. Fuel 5election: The heaters at the site shall be fired on pipeline quality natural gas. This results in 28% less CO2 production than fuel oils (see 40 CFR Part 98, Subpart ', C, Table C-1, which is included in Appendix E, for a comparison of the GHC'a ' emitting potential of various fuel types); 2e Efficient Heater Design: New burner design improves the mi�ng of fuel, creating a ' more efficient heat transfer. At the new facility, new burners shail be utilized. Burner �, management systems shall be utilized on the heaters, such that intelligent flame ' ignition, flame intensity controls, and flue gas recirculation optimize the effaciency oP the devices: Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Page 4 3. Feriodic tune-ups and maintenance for optimal thermal ef#`iciency: IVfaintenance shall be performed routinely per vendor recommendations or the facility's maintenance plan. The components shaPl be serviced or reptaced as needed. The heaters shall be tuned once a year for optimal thermal efficiency; 4. Oxygen frim control: Combustion devices operate with a certain amount of excess air to reduce emissions and far safety consideration. .4ac mappropriate mixture may Pead to inefficient combusrion. Regular maintenance of the draft air intake systems of the heaters can reduce energy usage. d3raft control is applicable to new or existing process heaters and is cost effective for process heaters rated at 20 to 30 M1VIBtu/hr or greater. The heaters will have air and fuel valves mechanically linked to maintain the proper air to fuel ratio. The following are potentially applicable control technologies for controlling CpHG emissnons associated with the ��¢rr�69��nIlu4�: 1. Overall efficiency of facility; 2. Existing Fort Lupton equipment permanent shutdowns and restrictions; 3. Compliance w�th NSPS Subpart KI£K for fugitive equipment. �Pe� �:�dia�adnaa�e 7l'�clasa��raldy Paa,f'era$eble�'on8rod�p�a�aas At the current time acid gas injec4ion wells for this location appear to be technically ! infeasible. There are no lmown acid gas injection wells operating in the g9enver-dulesberg I (I1-J) �asin. The current consensus is that acid gas injection wells would not sequester the I CO2, but rather the CO2 would migrate to other producing wells crea4ing a recycle of CO2. I �8ep 3: �laruvt¢ct��eze ��a&ro��,�'fecd�vv�saes.s o,f�'ec�eraecrslPy�'e�.�EFrde�on�rol��ad��a� The efficiency improvement/G�I6'r reductiotn technologies are ranked* below: e Use of electric-drrven engines (100%); a Install amine unit flash tank off-gas recovery systems (100%); � Routing the amine unit vents to a thermal oxidizer (99% for methane, and generates C�2), m Itouting the amine unit vents to a flare(98% for methane, and generates CO2); � Efficiencies within the plant(variable); � Fuel selection (28%when comparing natural gas and No. 2 Fuel Oil); � Bumer management systems on the heaters, with intelligent flame ignYtion, flame intensity controls, and flue gas recarculation(10�25%); � Efficient heater design(10%); � Annual tune-ups and maintenance (1-10%); � �xygen trun control; � CCS (not a feasable option for the Project due to technical, environmental, and economic reasons, as discussed in Step 4). Kerr McGee Gathering-�'ort Lupton Cryogenic Project GI&G BACT Analysis Page 5 *T'he following documents were used to identify any available control efficiencies including some vendor specifications i) Available and Emerging Technology for Iteducing Greenhouse �'aas Emission from the PetroIeum Industry dated October 2010 and ii) Energy Efficiency Improvement and Cost Saving Opportunities for the Petrochemical Industry: An ENERGY 3TA12 Guide for Energy Plant Ivlanager, Dacument Number LBNL-964E, dated June 2008, S�ep Ae�'vaadaa��e 1✓rlo.s8�,�',fec8�e ConBa°�d�ptdo�e� As part of this project the following options that were listed in Step 1, shall ��g be proposed for implementation as BACT: 1. T'he routing of amine unit regenerator vent to a flare (98% control), because a rnore efficient technology(thermaY oxidizer, with 99%efficiency)will be addressed. 2. Amine flash tanlc off=gas recovery. The amine flash tank off-gas will be routed to the thermal oxidizet to aid in combustion of the regenerator vent gas. 3. CCS is not considered to be feasible, based upon its lack of readily available 2echnologies and negative environmental and economic impacts. However, per EPA guidance, EPA has identified CCS as an add-on control technology that rnust be evaluated as if it were technically feasible. The amine flash tank off-gas will be routed to the thermal oxidizer for combustion rather than recycled to the plant inlet. Due to the low Btu and the cooling effect of the��2 in the amine regenerator vent gas stream, additional Btu content(assist gas) will need to be added to aid in combustion in the thermal oxidizer. di the flash gas were to be routed back to the plant inlet, additional compression would be needed and the energy required would negate the potential savings on the flash gas. The design will utilize the high Btu flash gas to help suppfly some of the additional�tu need to offset a portion of the pipeline gas urilized for the remaining assast gas. The emerging CCS technology is an"end of pipe" add-on control method comprised of three II stages (capture/compressnon, transport, and storage). CCS involaes sepazation and capture of CO2 from the e�aust gas, pressurization of the captured CO2, transmission of CO2 via pipeIane, and injection and long term geologic storage of the captured CO2. CCS can also consist of use of CO2 in Enhance Oil Recovery(EO1R) opportunities. The goal of CO2 capture is to concentrate the CO2 stream from an emitting source for transport and inj�ction at a storage site or location utilizing EOR. CCS requires a highly concentrated, pure CO2 stream for practical and economic reasons. Ea-tracting �O2 from e�aust gases requires equipment to capture the flue gas e�aust and to separate and pressurize the CO2 for transportation. Extracting CO2 from Yhe e�aaust gases of the heaters and thermafl o�dizers would require equipment to capture the flue gas e�aust and to separate and pressurize the CO2 for transportation. The e�aust stack streams will be low pressure, basically ahnospheric pressure. The streams would also be emitted at high temperaturea The CO2 separation ' would require the removal of all other pollutants frorn the streams. The process would require compression to increase the pressure from atmospheric to p9peline pressures. '�he ' Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Page 6 ', process would also require the reductiion of the temperature of the streams by several hundreds of degrees prior to separation, compression, and transmission. �asically an entire plant similar to what is being proposed in this project (smaller in size) would have to be constructed to remove the CO2. This process would add even more GH�'a emissions and large costs to the prroject. Thzs option is not environmentally, nar economically feasible. Even if we assumed there was a feasible way to separate the CO2 &om the combusrion ' streams, there would be several logistical issues that need to be resolved including obtaining right of way (IgO� and National Environmental Policy Act (NEPA) efforts far a pipeline to transport the CO2 to a location that would be auailable to rreceive and handle a continuous , long term stream of CO2. The geological formations available near this proposed site are not i technically feasible to store the CO2 as mentioned previously. In addition EOR is not I feasible at any large scale level in the I3-d Basin due to its geology and multipie owner/operators in the area. There may be some single well CO2 EOR projects forthcoming in this area, but nothing of the magnitude that would be able to handle the continuous supply of CO2 that would be produced from this project. Since different owner/operatorrs are located in close proximity, large scale EOR is not feasible. The e�aust streams from the heateYs and thermal oxidizers would have to be cooled, compressed, aaad treated prior to being able to enter a pipeline. A conservative estimate on the cost of equipmetat that could possibly be installed for these purposes was assumed to be $25;000,000. The nearest identified area utilizing EOI2 with CO2 is approximately 300 miles from the Plant. At a cost of $80,000 per inch mile to instail an 8" pipe line, the total cost for the pipeline alone would be appraximately $192 miilion ($80,000 x 3 x 300). I9etailed engineering was not done on harsepower requirements to boost the gas along the ' approximately 300 miles of pipeline because a definitive route was not chosen. Ilowever, we ' could estimate it take 40,000 horsepower (including horsepower required at the site to get the gas up to a pipeline pressure, intermediate pipeline booster compression, and end point ' injection compression). The cost of that additional horsepower would be approximately I� $100,000,000. There would also need to be additionai surface equipment (i.e. separaYors, dehydrators; storage tanks, etc.) at the booster sites and all equipment would have to be able ' to handle the acid gas (C�2). The cost of the additional surface eqa�ipment was not estimated in this exercise. Even excluding a portion of the cost, the engine cost and pipeline cost would j equate to a $18Uton cost of control. There is a high likelihood that the remote booster stations would not be able to utilize el�ctric compression, therefore it will have negative impact on the environment. Hence the use of CCS to reduce GHG emissions is not ' economically or environmentally feasible far this project, and the riming required for ROW issues and NE�A analyses would extend the project start date out by years. In addition there is no assurance that any aeailable C�2 pipeline ar EOR area would even have the capacity to handle the CO2 from this project. Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Page 7 ' ��ep 5r�°.��sabl�.sla l�A��' After discussion in the previous sections, the proposed BACT for this project would include: ��n�¢s� ➢ Electric motors on compressor engines O 29,500 hp of electric driven compression ��nam��m��- ➢ Routing off-gases to thermal oxidizer for combustion o Thermal Oxidizers utilize combusfion air preheaters and acid gas heat exchangers h33[��8��s� ➢ I�esign, operation, and management criteria as specified in Steps 1 & 3 ��¢�afld��6&fi�� ➢ Effaciencies I o Engine shutdown and restrictions � Compliance with NSPS Subparc KKK as applicable o LI�AIt to reduce fugitive leaks `d'he thermal oxidizer proposed to control emissions from the amine vents will utilize combustion air preheaters as well as an acid gas heat exchanger to minianize additional fuel requirements. The engineering design firm has estimated That the preheate�s and heat � exchangers will reduce assist gas requirements by approximately 11 MMBtu/hr. That ', efficiency relates to an avoided amount of 5,637 tpy of CO2e. Kerr-McC'ree Gathering is commit8ing to 29,500 horsepower of electric compression as part of this project. T'he choice of electric compression will eliminate C',HCs emissions from the compression needs of the plant. Based on Caterpiilar data on recent 3600 series engines, CO2 emissions from natural gas fired engines are approximately 450 grams per horsepower- ', hour. That would equate to Il��,Il�7 tpy of CO2e from 29,500 horsepower of natural gas , fired engines. Plot to mention there would be overall energy efficiencies by utilizing electric compression in this project. As part of the overaIl project, one naturai gas fired engine at the existing Fort Lupton plant will be permanently shut down (EU-35). In addition two addirional existing natural gas fired engines (EU-31 and EU-32) will take federally enforceabie runtime restxictions. The ruintime ' restrictions on the engines will reduce up to �fl,22� tpy of CO2e. Total quantifiable CO2e reductions of��g,�5� tpy are proposed as part of the�ACT as well as nurnerous reductions that are not as easily quantifiable, such as maintenance and operation conditions on the heaters. Kerr McGee Gathering-Fort Lupton Gryogenic Project GHG BACT Analysis Page 8 ' Overall the proposed project will treat 300 MMscfd of gas with a N�x reductiora of aflmos4 60 tpy. There is only a modest 19 tpy increase in VOC emissions at the facility due to this projeot. While there is a proposed 245,145 tpy increase in CsHG emissions in the project it zs effectively removing the CO2 from the gas stream that would ultimately would have been emitted at some point downstream of this facility. 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Q: o � d' o � ° o �'m �' e U � I ci � U p� � a � � U c Y ',, L 1e Q � O O N �, " � U � a � ,''��. � � U � _- a ¢ U � � f.i . A��N�� a.�' �eaff�s°�an��a�an �asauflasn��g� Kerr McGee Gathering-Fort Lupton Cryogenic Project GHG BACT Analysis Appendix B ,-- ___. _____; j Previous Page � _...,._..,. . -_�_._......i Report Date: 11/28/2011 INDEX OF CONTROL TECHNOLOGIES DETERMINATIONS NOTE:DraR determinations are marked with a"*"beside the YLBLC ID. � � K _..__..,_ _...._'__._. _ _......__ _._.___..._. , _..___. ____ __..y. ___.,__� .__.._'____..�_. __.._" _ �,._.'_ _..-_._...,,.._,. Company Name �LC Country Permit � Process prosess Descriptiou . ID Date(Est/Aet). Type � I�TINENIILE POINT. USA 08/16/2011 ACT 17.110 . EMERGENCY DIESEL GENERATOR � ELECTRIC GENERA *LA-0254 - � � � 99.009 U1JIT 6 COOLING TOWER � . 99.009 CHILLER COOLING TOWER(CHII,L CT) . � � � 11.310 AUXILTARY BOII,ER(AUX-1) ��', � � 15200 COMBINED CYCLE T[JRBINE GENERATORS(UNITS 6A '��. &6B) � 17.210 EMERGENCY FIRE PUMP • DIRECT REDUCTION USA 0l/27/20ll ACT 81200 DRI-108-Dffi Ueut#1 Reformer Main Flue Stack � IRONPLANT '�LA-0248 � ��. � , � � 81200 DRI-208-DRI Unit#2 Reformer Main Flue Stack i�.. . 81.90Q DRI-101 DRI Unit#1 Iron Oxide Day Bins Dust Collec6on . � 81.900 DRI-201 DRI Unit#2Iron Oxide Day Bins Dust Collection 81.9Q0 DRI-102 Dffi Unit#1 Iron Oxide Screen Dust Collection . � . 81.900 DRI-202 DRI Unit#2 Iron Oxide Screen Dust Collection � . �, . 81.900 DRI-105 DRI Unit#1 Furnace Feed Conveyor Baghouse � 81.900 DRI-205 Dffi Unit#2 Furnace Feed Conveyor Baghouse � � 81.900 DRI-103 DRI Unit#1 Coating Bin Filter � � 81.900 DRI-203 DRI Unit#2 Coating Bin Filter - � 81.900 DRI-104 DRI Unit#1 Iron Oxide Fines Handli�g �� 81.900 DRI-204 DRI Unit#1 Iron Oxide Fines Handling 99.009 DRI-113-DRI Unit#YProcess Water Cooling Tower , � 99.009 DRI-213-DRI Unit#2 Process Water Cooling Tower � '. . . 99.009 Dffi-114-DRi Unit#1 Clean Water Cooling Tower . �� 99.009. DRI-214-DRI Unit#1 Clean Water Cooling Tower , . . 81290 DRI-ll7-Briquetting Mil( '� � 99.190 Dffi-118-DRI Bazge Loading Dock � . 81.290 DRI-115-Product Screen Dust Collecfion � � � S 1290 Dffi-116-Screened Product Transfer Dust Collection . � 81.290 DRI-107-DRI Unit No. 1 Furnace Dust Collection '� � . . 81290 DRI-207-DRI Unit No.2 Furnace Dust Collection � ' 11310 DRI-109-DRI Unit#1 Package Boiler Flue Stack ,.� 11.310 DRI-209-DRI Unit#2 Package Boiler Flue Stack � 81.290 DRI-112-DRI Unit No. 1 Product storage silo Dust Collection '. � . 81290 DRI-206-DRI Unit No.2 Upper Seal Gas Vent '��. � � � 81.290 DRI-106-DRI Unit No. i Upper Seal Ges Vent � � � 81290 DRI-21I-DRI Unit#1 Acid Gas Absorption Vent. . � .. � 81.290 . DRI-111-DRI Unit#1 Acid Gas Absorprion Vent '� , � 81.290� DRI-212-DRI Unit No.2 Product storage silo Dust Collection '. � � 19390 DRI-I 10-Dffi Unit No. 1 Hot Flaze ��.. � � 19.390 DRI-210-DRI Unit No. 1 Hot Flaze . !, BASF FINA NAFTA � 02/10/2010 ACT 50.003 N-11,REACTOR REGENERATiON EFFWENT � REGION OLEFINS '�-0550 US.4 . . ' 50.003 N-Iq CATALYST REGENERATION EFFLUENT � ' � 50.003 N-18,DECOKING DRUM � � � � � _..__ . ........ .. . . .. PRYOR PLANT pK-0135 USA 02/23/2009 ACT 61.999 COOLING TOWER#2 CHEMICAL � 61.012 PRINfARY REFORMER 62.014 IdITRIC ACID PLANT#1 � � � 62A14 NIIRIC ACID PLANT#3 . � 61.999 CONDENSATE STEAM FLASH DRUM-AMMONtA PLT 4 � 61.999 COOLINGTOWER#1 . . . 13.310 NITRIC ACID PREHEATERS#1,#3,AND#4 61.999 CARBON DIOXIDE VENT � � 61.012 AMMONNM NITRATE PLANTS#1 AND#2 . 61.999 GRANiJLATOR SCRUBBERS#1,#2,AND#3 � � 13.310 BOII,ERS#1 AND#2 62:014 DiITRIC ACID PLANT#4 � RUMPKE SANITARY OH-0330 USA 12/23/2008 ACT �29.900 M[71VICIPAL WASTE LANDFILL . . LANDFILL � . � � 29.900 OPEN FLARE . � � � 99.150 PAVED ROADPJAYS AND PARICING AREAS . . 29.900. ENCLOSED COMBUSTORS(4) 29.900 CANDLESTICK FLARE(5) CPV ST CHARLES� MD-0040 USA 11/12/2008 ACT 17.21D ��'COMBUSTION ENGINE-EMERGENCY FIRE WATERPUMP _ � � 99.999 COOLING TOVJER � � � . 15,110 COMBUSTION TURBINES(2) � 13310 BOII.ER � � � 13310 HEATER � �� 17210 ��'COMBUSTION ENGINE-EMERGENCY GENERATOR �� ACTIVATED CARBON LA-0148 USh` 0S/2S/2008 ACT 1 L I 10 Mi7LTIPLE HLARTH FURNACES/AFTERBURNERS FACILITY . � � � � � 99.009 COOLING TOWERS � . � HERCULES INC VA-0307 USA 10/0S/2007 ACT 13.210 CHEMICAL PREP � . � 13.220 CI-IEMICAL PREP . 11.310 CHEMICAL PREP . � 13.220 CHEMICAL PREP . . NUCOR DECATUR LLC �,_0231 USA 06/12/2007 ACT 81290 VACUUM DEGASSER . � � 13.310 . GALVANIZING LINE FURNACE � . 13.310 VACWMDEGASSERBOILER , TWO(2)ELECTRIC ARC FURNACES AND Tf-IREE(3) . 81210 LADLE METALLURGY FT.iRNACES WITH TWO(2) � � � � � � �MELTSHOP BAGHOUSES � AIRPRODUCTS TX-0481 USA 11/02/2004ACT 99.999 PARTSWASHER � . BAYTOWNdd . � � . . � . . . 64.003 MSS PROCESS STEAM VENT � . � 50.005 COOLING TOWER � � 50.005 SUPPLEMENTARY COOLING TOWER . � 50.007 F(7GITIVES_(4) � . - 64.003 PROCESS STEAM VENT � � . . 19.800 EMERGENCY GENERATOR TANIC � � � 64.003 MSS-NONCONDENSIBLES(PROPYLENE VENTiNG) . 19310 FLARE(NORMAI,OPERATIOI� � - 64.003 RECTISOL VENT � , 19.800 EMERGENCY GENERATOR � � 42.005 �DIESEL FUEL TANK � � � . 13390 � BOILER STACK(START UP) � � 11.390 - BOILER STACK(HIGH BTU FLiEL) ., . . ..__.___ . _._._. . _._.... .. _. .. ... ....... --_____ .. _.__. . 11.390 � BOII.ER STACK � RUMPKE SANITARY 06/10/2004 ACT Z7210 PORTABLE ENGINE 4.68 NIMBTU/H LANDFILL,INC �H-0281 USA . . , 17210 PORTABLE ENGIATE 0.58 MMBN/H � � � 29.900 LOAD-IN,LOADAUT,TURNING;AND WiND EROSION . � 29.900 PORTABLE SCREENER 29.900 PORTABLE TUB GRINDER � � � � 29.900 �W SOLID WASTE DISPOSAL WITH LANDFILL GAS _ GENERATION . . . 29.9W .LEACHATE STORAGE BASIN . � 29.900 LEACHATE AERATION BASIN 29.900 �GITiVE EMISSIONS FROM LANDFILL AND GAS . . COLLECTION SYSTEM � � � � � 29.900� EXISTING SOLID WASTE DISPOSAL WITH LANDF7LL � GAS GENERATION � � 29.900 �LANFILLROADWAYS � � � ATOFINA CHEMICALS � 12/0S/Z003 ACT 64.004 CYLINDER EVACUATTON AND FILLING � � INC. KY-0091 USA . � 64.002 FUGITIVES,PACKAGE AREA � 64.005 LOADING,RAIL AND TANK TRUCK �� 64.999 DRYER DESICCANT CHANGE-OUT � ATOFINA CHEMICALS . TX-0354 USA 12/19/2002 ACT 64.002 ACROLEIN PROCESS FUGITIVES,ACRO-FUG INCORPORATED � � 64.004 ACROLEIN STORAGE TANKS FUGITIVES, ACRO-TKSFUG . 64.006 ACROLEINWASTEWATERFUGITIVES,ACRO-WWFtJG � � . 64.002 BIB2 UNITS CHILLER SYSTEM . 64.002 TRAIN.1-ETSA OR TBM PRODUCITON FUGITIVES 64.002 TRAIN 1-MESH PRODUCTION FUGITIVES . 64.002 'PRAIN 2-MESH PRODUCTION FUGITIVES � . . � 64.003 SULFOX CHILLER SYSTEM,SULFOX-CHLR � � 99.0D9 SULFOX COOLING TOWER,SULFOX-CT 64.005 SiTI:FUR TRUCI{,S-3 . � 64.003 THERIvPAL OXIDSZER PROCESS FUGITNES . � 64.005 TANK TRUCK LOADING/UNLOADING FUGITNES . � 19.310 FLARE,SSM � � � 19.310 FLARE,TOTAL HOURLY AND ANIVIJAL � � 13310 HEAT TRANSFER FLUID HEATER,H2O2 � 19.600 (2}SULFUR/METHANE HEATERS . � � - � 13.310 HEAT TRANSFER FLUID HEATER,H2202 � . 64.999 INCINERATOR . 64.004 SULFC7R STORAGE TANK,S-1 � 64.999 SiTLFiJR PIT,S-2 � 64.006 SOUR WATER S1'RIPPERS FUGITiVES � � � 64.004 METIIANOL TANK,D307 � � . � � 62.020 SULFURIC ACID TANI{,D8600 � � 64.999 BAGFILTER,SULFOX-iNH �� b4.003 Tf�.RMAL OXIDIZER,SSM � �. 64.003 THERMAI,OXIDIZER,TOTAL AOURLY AND ANN[JAL � 64.006 WASTEWATERTREATMENTPLANT,W4VfP 19310 FLARE,S'I'EADY STATE OPERATION � 64.999 � �PRODUCT RECOVERY TOWER FUGITIVES � � � 64.005 RAILCARLOADING/UNLOADINGFUGITIVES 64.999 ACROLEIN L7NIT COLUMN/FILTER CLEANIlQG � � 42.009 DIESEL TA1VK,D-215 . 64.004 METHANOL TANI{,D-310 � � -. 42.009 GASOLINE TANK,D-398 � 42.009 DIESEL TANK,D-399 . � 64.004 METHANOL TANS,D-2307 � � 42.009 (2)DIESEL TANKS,3191A-319YB � 62.020 CAUSTIC TAN%,D8540 . 64.002 DIIVIETHYL DISULFIDE AREA PROCESS FUGITIVES . 13310 (2)STEAM BOILERS,X-426A AND X-426B � � � 64.999 RUNDOWNTANKFUGLTIVES . 64.004 STORAGE TANILS FUGITIVES � . . . 64.999 SULFOX CHILLER SYSTEM FUGITIVES � 64.002 DIIvIETAYT,SULFIDE AREA PROCESS EUGITR�ES � 64.002 HZS PLAIdT PROCESS FUGITIVES � �. 19.310 FLARE AREA FUGITIVES � � 64.999 RVCINERATORPROCESSFUGITIVES . . . 64.002 M&vIP PROCESS AREA FUGITIVES � 64.005 MIvIP RAILCAR LOADING AREA PROCESS FUGITIVES � � 64.004 MMP STORAGE AREA PROCESS FUGITIVES 64.003 THERMAL OXIDIZER,STEADY STATE SERVICE OWENS CORNING IL-00S 1 USA 12/12/2001 ACT 99A14 POLYSTYRENE FOAM BOARD EXTRUSION LINES BASF CORPORATION y�-0304 USA 10/23/2001 ACT 63.999 BULK LOADING,TDI&MDI 64.00d REACTORS,ISOCYANATES � . � � 64.005 BLENDING TAAiKS,RESIN � � . 64.004 TF.NKS � 63.999 � DRUM[��VG CHOCOLATE BAYOU TX-0347 USA 10/16/2001 ACT 64.003 LIME SILO FILTER VENT,DDZ-902 PLANT . � 64.003 LIME SILO FILTER VENT . � � � � 64.002 SEAL OIL VENTS,OFISOVENT 64.005 RAII.ROAD LOADING FUGITIVES,RAILLOAD . � � 19.600 REGENERATION FURNACE,DB-201 � � 19.600 REGENERATION HEATER,DB-601 � 19.600 REGENERATIQN HEATER,DDB-201 - � 19.600 REGENERATION HEATER,DDB-601 � � �. � 19.600 FURNACE ENIISSION CAPS FOR 30 ENIISSION POINTS . 64.004 TANK EMISSION CAPS FOR 9 EMISSION POINTS 64.004 SODIUM PIITRITE SOLUTION TAPiIC,DDF-705 � 42.009 FUEL OIL TANI{,DF-1001 - � . 64.004 ALCOI-TOL TANI{,DF-1301 � � 64.004 RERUNS BOTTOMS TANK,AFd106 �� 42.009 FL1EL OIL TANK,DDF-1001 � . � 99.009 NO.1 OLEFINS COOLiNG TOWER,AT-1210 99.009 NO.2 OLEFINS COOLIlVG TO WER,DAT-3201 . . 64.002 NO.1 OLEFINS UIVIT FUGITIVES,FUG-V10F � � � 64.002 NO.2 OLEFINS UIVIT FUGITIVES,FUG-V20F , 64.002 NO. 1&2 OLEFINS ANALYZER VENTFUGITIVES � 42.009 LUBE.OIL STORAGE,DF-502 � . . 64.004 SODIUM NITRITE SOLUTION TANIC,DF-701 � . � 64.004 SODNM 1VITRITE SOLUTiON TANI{,DF�702 . � � 64.004 SODIUM NITRITE SOLUTION TANK,DF-705 � � . � 42.009 LUBE OIL STORAGE . ' 64.003 DECOKE STACIC,DF-101 � . . ._... .__.... __.. . . .� .. . 64.003 � DECOKE STACK,DF-104 � . 64.003 DECOKE STACK,DDF-101 � � 64.003 DECOKE STACK,DDF-104 � � � . � 19310 NO.2 OLEFINS FLARE,DDM-3101 � � � 19.310 NO. 1 OLEFINS FLARE,DM-I101 - 64.003 �Z�HYDROTREATER REGENERATOR STACKS,DD-606&DDD-606 19.600 2ND STAGE HYDROTREATER FEED HEATER,J-1 � 64.004 (2)ACETONiTRILE TANKS,AF-1103&-I104 .� 64.003 (2)DECOKE STACKS,DF-105&DDF-105 . 19.310 DOCKFLARE,AM-I500 �� 64.004 SLOP TANK,AF-3701 64.004 RERUNS BOTTOMS TANK,AF-1105 � 42.009 FUEL OIL TANK,AF-1905 . � � . � 64.004 ACETOIVITRILE TANK,AF3103 � � � . 42.009 FUEL OIL TANK,AF-3905 � � 64.004 ME'IT-L4NOL TANK,DDF-1301 �. � � 64.004 METHANOL TANK,DDF-202 � '. . 64.004 SODIUM DIITRITE SOLUTION TANK,DDF-701 � - 64.002 SECOND STAGE HPDROTREATER FUGITIVES, � FUGVSSH � . . � 64.002 TANK FARM FUGITIVES,FUG-FTF � � � 64.002 � MARINE DOCK FUGITIVES,FUG-VBD : � 64.002 METERING STATION FUGITNES,FUG-VCM � ' �'�. . 64.005 RAIL LOADING FUGITIVES,FUG-RAIL � 64.005 NO.1 OLEFINS TRUCK LOADING,FUELTRKI ''�. � � � 64.005 NO.2 OLEFINS TRUCK LOADING,FUELTRK2 ��. � � 64.999 BLEACH TANK,AF-1215 . � 64.999� BLEACI3 TANK,AF-3215 WI-IIRLPOOL �_0107 USA 02/07/2001 ACT 99.014 FOAM LINE CORPORATION . � � � ...._._. __... .. .. . I, Previous Page � � � '�. _ 5TATE OF COLOlZADO John W.Hickenlooper,Govemor � � Christopher E.Urbina, MD,MPH � �w��F.•��o� Executive Director and Chief Medical Officer � NQ��o Dedicated to protecting and improving the healih and environmeni of the people of Colorado � � . o ., • ti�? 4300 Cherry Creek Dc S. Laboratory Services Division . `r 1876 r� Denver, Colorado 60246-1530 8100 Lowry Blvd. � �Phone(303)692-2000 Denver,Colorado 80230-6928 � . Coloxado Depaztlnent . � �ocated in Glendale,Coiorado (303)6923090 of PubGcHealth http://www.cdphe.state.co.us . � andEnvirontnent December 28, 2011 Jennifer Shea Kerr-McGee Gathering LLC PO Box 173779 Denver, CO 80217 Re: Permit#97WE0180 Dear Applicant: The Colorado Air Pollution Control Division has received and logged in your construction permit application to modify permit number 97WE0180. You have requested to change the hours of operation for two compressor engines, and add equipment for a cryogenic plant at the Fort Lupton Gas Plant in Weld County. Your application is now ready for initial review. If you should have any questions concerning the status of your permit application, please contact me at(303)691-4093. When calling, please reference the permit number listed above. You can also research the status of your application oNine at http:/Iwww.cdphestate.co.us/ap/ss/ssqcpt.html. The next step in processing your construction permit application is to determine if all of the information we need is contained within your application. If so,we will begin our preliminary engineering analysis. If any information is missing, , however, we will contact you in the near future to obtain the needed material. State law requires that the Division determine the completeness of an application within 60 days of receipt. If you do not ' hear from the Dlvision by 1/30/2012, you can assume that your application is complete. Sincerely, � i�`� �� f � � I Jonathan Brickey Construction Permit Unit __ _ � WGR Operating LP- PAGE: 1 of 1 j PO Box 1330 . � � ' . Hous[on,TX 77251-1330 � DATE November 23,2011 � ��.. TRACE NUMBER:742102545 , CHECK�NUMBER:742102545 . � AMOUNT PAID:$1,070.30� � � � ' � ACCOUNTS PAYABLE INQUIRIES:(800)370-9867 � — I ��n��n��i��uu��u��u��i��n��in��n� - _ I p0053 CKS bA Y1321 - O1421@545 NNNNNNNNNNNN 32i5Y00002504 %392D1 C � � � COLORADO DEPT OF PUBLIC HEALTH & = , ENVIRONMENT = ' 4300 E CHERRY CREEK S DR - DENVER CO 80246-1530 = ��., � II VENDOR NO:0009402886 � . � � � � - II� DOCUMENT# VENDORINV#/ INVOICEDATE TOTAL PRIORPMTS NET REMARKS AMOUNT B�ISCOUNTS AMOUNT 1900002722 . CKRQ172111A � 17l27M1 . $7,07030 $0.00 � $7,070.30 . FORT WPTON CRYOGENIC PL4NT PERMITAPPLICATION I TOTALS � � � � $1p70.30 �0.00 $1,070.30 � . . ...� � �� `ty'.. � .. � . . . ._:�,r� �' � . . PLEASE�ETACH BEFORE DEPOSITING CHECK � - CHECK . . 741292 N i Operating LP � � . �24 rn sox �33o NUMBER 742102545 U' ;ton,TX 77257-1330 � � November 23, 2011 ' 0 i n x COLORADO DEPT OF PUBLIC HEALTH & �' � HE ENVIRONMENT I x eR oF: 4300 E CHERRY CREEK S DR cHecK nMouNT � N � f's �"� � ��f�j� � o DENVER, CO 80246-1530 �� -' `��`�� ' **1 , 0 7 0 . 3 0** � � � 9v070 DOLLAFPS ��D 30 CEi�ipS rgan Chase Bank, Dearborn eN��pEpFE^TUREs �� . �orn, MiChigdn � �� t see oerni�s on encx AUTHORIZED REPRESENTATIVE OF THE COMPANY i�' 74 2 10 254 5�i• �:0724i2927o: 7 58664 74 2ii• II N I �. WGR Operating LP PAGE: 1 of 1� � . � PO Box 1330 � � � DATE: Novemtier 23,2011 � � Houston,TX 77251-1330 TRACE NUMBER:742102544 � � � CHEGK NUMBER:74210254�t. . . AMOUNT PAID:$305.80 . � ACCOUNTS PAYABLE INQUIRIES: (800)370-9867 ��n��un��ii��uu��n��u��n��u�i�u� — 0��52 IXS 6A 11321 - 0i42102544 NNNNNNNNNNNN 32P5Y0��2504 X392D1 C - COLORADO DEPT OF PUBLIC HEALTH & _ ENVIRONMENT = 4300 E CHERRY CREEK S DR = � DENVER CO 80246-1530 � = � VENDOR NO:0009402886 � � - � . . DOCUMENT# VEN�OR INV#/. �NVOICE DATE TOTAL PRIOR PMTS NET � . REMARKS � AMOUNT &DISCOUNTS AMOUNT 9900002721 � CKRQ112111 11/2V11 . $305.80 $0.00 $305.80 FORT LUPTON CRYOGENIC PLANT PERMIT APPLICATION-LIMITS HOURS OF � 37 AND 32 TOTALS . $305.80 $0.00 $305.80 - `�. ��k ��ti''� . . \ , PLEASE DETAGH BEFORE�EPOSITING GHECK � � CHECK 74-1292� � rn bOP330 ng LP . � 724 NUMBER 7421O2544 0 otoq TX 7725Y7330 � November 23, 2011 � n 'x COLORADO DEPT OF PUBLIC HEALTH & - � HE ENVIRONMENT . i ER OF: HERRY CREEK S DR � , , :� �� t r CHECK AMOUNT 4300 E C � � �, � .. o DENVER, CO80246-1530 F" � "� " � $**305 . 80** � � � � � ' � � 305 DOLL�1otS /�iVD �O e'Eiii'fS rgan Chase Bank, Dearborn sE"'"'T�""'uR`� � �" � eiNcwoeo: lOffl�MiChi Jd0 . t see oeraas oN encx pUTHORIZED REPRESENTATNE OF THE COMPANY ii' 742L02544��' �:0724L2927�: 7 58664 74 2ii• N . . ___ .._. . . .._ . ..__. _... .. .._.__... _._. . ... _.__ Hello