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Home My WebLink About20191544.tiffCOLORADO? Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Weld County - Clerk to the Board 1150O St PO Box 758 Greeley, CO 80632 April 15, 2019 Dear Sir or Madam: On April 18, 2019, the Air Pollution Control Division will begin a 30 -day public notice period for DCP Operating Company, LP - Eaton Compressor Station. 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 beginning of the public notice period. Please send any comment regarding this public notice to the address below. Colorado Dept. of Public Health Et 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 4300 Cherry Creek Drive S., Denver, CO 80246-1530 P 303-692-2000 www.colorado.gov/cdphe John W. Hickenlooper, Governor LI /ZZ/ 9 I Larry Wolk, MD, MPH, Executive Director and Chief Medical Officer (�. PLC Pr1LSM/F LICkICYA 2019-1544 Air Pollution Control Division Notice of a Proposed Project or Activity Warranting Public Comment Website Title: DCP Operating Company, LP - Eaton Compressor Station - Weld County Notice Period Begins: April 18, 2019 Notice is hereby given that an application for a proposed project or activity has been submitted to the Colorado Air Pollution Control Division for the following source of air pollution: Applicant: DCP Operating Company, LP Facility: Eaton Compressor Station Natural gas compressor station SEC 34 T7N R66W, Weld County The proposed project or activity is as follows: This facility is currently named Eaton Natural Gas Processing Plant, and is being converted to Eaton Compressor Station. All existing equipment at this facility will be decommissioned before the installation and startup of the new equipment. New permitted emission sources include 3 compression turbines, 2 glycol dehydrators, pressurized condensate loadout, pigging emissions, fugitives, and compressor blowdowns. The Division has determined that this permitting action is subject to public comment per Colorado Regulation No. 3, Part B, Section III.C due to the following reason(s): • permitted emissions exceed public notice threshold values in Regulation No. 3, Part B, Section III.C.1.a (25 tpy in a non -attainment area and/or 50 tpy in an attainment area) • the source is requesting a federally enforceable limit on the potential to emit in order to avoid other requirements The Division has made a preliminary determination of approval of the application. A copy of the application, the Division's analysis, and a draft of Construction Permit 97WE0349 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 https://www.colorado.gov/pacific/cdphe/air-permit-public-notices The Division hereby solicits submission of public comment from any interested person concerning the ability of the proposed project or activity to comply with the applicable standards and regulations of the Commission. The Division will receive and consider written public comments for thirty calendar days after the date of this Notice. Comments may be submitted using the following options: • Use the web form at https://www.colorado.gov/pacific/cdphe/air-permit-public-notices. This page also includes guidance for public participation • Send an email to cdphe.commentsapcd@state.co.us • Send comments to our mailing address: Betsy Gillard Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South, APCD-SS-B1 Denver, Colorado 80246-1530 COLORADO Colorado Air Permitting Project PRELIMINARY ANALYSIS - PROJECT SUMMARY Project Details Review Engineer: Package 6: Received Date: Review Start Date: Betsy GillaOd' 387647!IIF Section 01- Facility Information Company Name: County AIRS ID: Plant AIRS ID: Facility Name: Physical Address/Location: County: Type of Facility: ;Natural Gas Compressor Station"" What industry segment?Natural GaeTransmission`& Storage Is this facility located in a NAAQS non attainment area? ; - yes If yes, for what pollutant? ❑ Carbon Monoxide (CO) DCP 123? Section 34, Township 7N, Range 66W Weld County Section 02 - Emissions Units In Permit Application Particulate Matter (PM) Quadrant Ozone (NOx & VOC) Section Township Range AIRS Point 4 Emissions Source Type Equipment Name Emissions Control? Permit 8 Issuance 8 Self Cert Required? Action Engineering Remarks `012 : Turbine _ - ; TURB-1 no 97W60349 3'" `,yes -' Permit. New point 013 Turbine TURB-2 - no 97WE0349 3 yes Permit New point 014 Turbine TURB-3 .": no .-. 97WE0349 3 "" yes Permit : New point 015 Dehydrator D-1 yes 97WE0349 3 Yes .. Permit New point 016 Dehydrator D-2 yes 97W60349 3 yes Permit. New point .. 017 Liquid Loading L-1 Yes 97WE0349 3 yes Permit New point 018 MaintenanceBlowdowns PIG yes 97WE0349 3 yes _ Permit i . Modification New point - pigging blowdowns 019 Fugitive Component Leaks FUG -1 no 97WE0349 3 - yes Permit New Point 021 MaintenanceBlowdown s = =TURB TURB-BD no 97WE0349 3 yes ermit Modification New point - turbine blowdowns Section 03 - Description of Project This facility is currently named Eaton Natural Gas. Processing Plant, and is being converted to Eaton Compressor Station. Ail existing equipment at this facili ty will be decommissioned before the installation and startup of the equipment included in this permit application package. All existing points on permit 97WE0349 have been removed, with a permit condition stating that those points will be cancelled upon issuance of the permit. The facility will remain a synthetic minor source, Section 04 - Public Comment Requirements Is Public Comment Required? Yes If yes, why? ilitequeiting,Synthetie,-Minor Permit Section 05 - Ambient Air Impact Analysis Requirerr Was a quantitative modeling analysis required? :No If yes, for what pollutants? If yes, attach a copy of Technical Services Unit modeling results summary. Section 06 - Facility -Wide Stationary Source Classification Is this stationary source a true minor? Is this stationary source a synthetic minor? If yes, indicate programs and which pollutants: Prevention of Significant Deterioration (PSD) Title V Operating Permits (OP) Non -Attainment New Source Review (NANSR) Is this stationary source a major source? SO2 NOx CO VOC PM2.5 PM10 TSP HAPs 1 ❑ E Turbine Emissions Inventory Section 01- Administrative Information Facility AIRS ID: County Plant 012,70,4,40-10 Point Section 02 - Equipment Description Details Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: 5oLoNOx is considered an integral control device. Section 03 - Processing Rate Information for Emissions Estimates Heat Input Rate = Heat content of waste gas= Actual Hours of Operation = Requested Hours of Operation = Actual heat input rate = Requested heat input rate = Potential to Emit (PTE) heat input rate = Actual Fuel Consumption = Requested Fuel Consumption = Potential to Emit (PTE) Fuel Consmption = Section 04- Emissions Factors & Methodologies MMBtu/hr Btu/sct hrs/year hrs/year 0-00 MMBTU per year 672,855.60 MMBTU per year 672,85560 MMBTU per year 0.00 MMscf/year 873.53 MMscf/year 573.53 MMscf/year Pollutant Uncontrolled Uncontrolled (lb/MMBtu) (lb/MMscf) (Fuel Input) 111711 r r 5,450E-02 Formaldehyde MgEMMMI KW1400411B2 1"4.305-07 3.20E-05 (Fuel Consumption) 54.446 7.09E-01 4.00E-02 NEEMM 4.30E-04 7. Hdx ?1.30E-04. 2.20E-06 ,6.40505 MICEMEMI MET= WIZ= 6.39E-02 Emission Factor Source Section 05- Emissions Inventory Startup emissions Startup 48 events/yr 480 minutes/yr Noy CO VOC Emissions per start (Ib) 1 88 18 Total start/shutdown (tpy) 0.024 2.112 0.432 Shutdown 48 events/yr 480 minutes/yr Nox CO VOC Emissions per shutdown (Ib) Total start/shutdown (tpy) 1 62 8 0.0240 1.4880 0.1920 Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled , Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested permit limits include startup and shutdown emissions 238 391 391 194 3125 3771 VOC PM10 PM2.5 S0x NOx CO 0.71 0.00 0.00 1.41 1.40 2.22 0.00 0.00 2.30 2.30 2.22 0.00 0.00 2.30 2.30 1.14 0.00 0.00 1.14 1.14 18.34 0.00 0.00 18.40 18.40 18.60 0.00 0.00 22.20 22.20 Hazardous Air Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled llbs/year) (Ibs/year) Formaldehyde 2.389E-01 0.000E+00 0.000E+00 2.389E-01 2.389E-01 478 478 Acetaldehyde 1.346E-02 0.000E+00 0,000E+00 1.346€-02 1.346E-02 27 27 Acrolein 2.153E-03 0.000E+00 0.000E+00 2.153E-03 2.153E-03 4 4 Benzene 4.037E-03 0.000E+00 0.000E+00 4.037E-03 4.037E-03 0 8 1,3 -Butadiene 1.447E-04 0.000E+00 0.000E+00 1.447E-04 1.447E-04 0 0 Ethylbenzene 1.077E-02 0.000E+00 0.000E+00 1.077E-02 1.077E-02 22 22 Toluene 4.374E-02 0.000E+00 0.000E+00 4.374€-02 4,374E-02 87 87 PAH 7.401E-04 0.000E+00 0.000E+00 7.401E-04 7.401E-04 1 1 Xylene 2.153E-02 0.000E+00 0.000E+00 2.153E-02 2.153E-02 43 43 2 of 16 K:\PA\97\97 W E0349.CP3.xlsm Turbine Emissions Inventory Section 06 - Regulatory Summary Analysis Rebulation 1 Section M.A. No owner or operator shall cause or permit to be emitted into the atmosphere from any fuel -burning equipment, particulate matter in the flue gases which exceeds the following: III.A.1.b. For fuel burning equipment with designed heat inputs greater than 1x105 BTU per hour, but less than or equal to 5004.05 BTU per hour, the following equation will he used to determine the allowable particulate emission limitation. PE=0.5(FI)-o'' PE= Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. The turbines have a design heat input rate of 76.81 MMBtu/hr andare therefore subject. limitations (Heat input rates shall be the manufacturer's guaranteed maximum heat input rates.) V1.B.4.c.(i). Combustion Turbines with a heat input of less than 250 million BTU per hour: 0.8 pounds of sulfur dioxide per million BTU of heat input. The turbines have a design heat input rate of 76.81 MMBtu/hr and are therefore subject. Regulation 3 Source is APEN- and Permit -required. Regulation 6 Part B Section II: Standards of Performance for New Fuel Burning Equipment: II.C. Standard for Particulate Matter: On and after the date on which the required performance test is completed, no owner or operator subject tothe provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: II.C.2. For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation: PE=0.5(FI)-0.26 PE is the allowable particulate emission in pounds per million Btu heat input. Fl is thefuel input in million Btu per hour. If two or more units connect to any opening, the maximum allowable emission rate shall be the sum of the individual emission rates. II.C.3. Greater than 20 percent opacity. 11.0 Standard for Sulfur Dioxide: On and after the date on which the required performance testis completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere sulfur dioxide in excess of: II.D.3.a. Sources with a heat input of less than 250 million Btu per hour: 0.8 lbs. SO2/million Btu The turbines have a design heat input rate of 61.58 MMBtu/hr and were constructed after 01/30/79 and are therefore subject. NSPS GG: The provisions of this subpart are applicable to the following affected facilities: All stationary gas turbines with a heat input at peak load equal to or greater than 10.7 gigajoules (10 million Btu) per hour, based on the lower heating value of the fuel fired. According to NSPS KKKK §60.4305(b) Stationary combustion turbines regulated under this subpart are exempt from the requirements of subpart GG of this part. NSPS GG does not apply. gigajoules (10 MMBtu) per hour, based on the higher heating value of the fuel, which commenced construction, modification, or reconstruction after February 18, 2005, your turbine is subject to this subpart. Each of these turbines has a heat input at peak load > 10MMBta/hr and commenced construction after February 18, 2005. NSPS KKKK applies. ' Regulation 7 Section XVI.D. Combustion Process Adjustment XVI.D.1. As of January 1, 2017, this Section XVI.D. applies to the following combustion equipment with uncontrolled actual emissions of NOx equal to or greater than five (5) tons per year, and that are located at existing major sources of NOx, as listed in Section XIX.A. XVI.O.1.d. Stationary combustion turbine The turbines are not located at a major source of NOx and are therefore not subject. MACE MACF YYYY: You are subject to this subpart if you own or operate a stationary combustion turbine located at a major source of HAP emissions. These turbines are not subject to MACF YYYY because they are located at an area source of HAP emissions. Section 07 -Technical Anal sis Notes To at eminslon"sore #fie sum efthe normal operating cur Section 08 - Inventory SCC Coding and Emissions Factors AIRS Point # Process # SCC Code 012, 013, 014 01 Uncontrolled Emissions Pollutant Factor Control % Units PM10 6.60E-03 0 - lb/MMBtu Input PM2.5 6.60E-03 0 lb/MMBtu Input NOx 5.45E-02 0 lb/MMBtu Input VOC 2.10E-03 N/A lb/MMBtu Input CO 5.53E-02 0 lb/MMBtu Input SOx 3.40E-03 0 lb/MMBtu Input Formaldehyde 7.10E-04 N/A lb/MMBtu Input Acetaldehyde 4.00E-05 - N/A lb/MMBtu Input Acrolein 6.40E-06 N/A lb/MMBtu Input Benzene 1.20E-05 N/A lb/MMBtu Input 1,3 -Butadiene 4.30E-07 N/A lb/MMBtu Input Ethylbenzene 3.20E-05 N/A lb/MMBtu Input Toluene 1.30E-04 N/A lb/MMBtu Input PAH 2.20E-06 N/A lb/MMBtu Input Xylene 6.40E-05 N/A lb/MMBtu Input 3 of 16 K:\PA\97\97 W E0349.CP3.xlsm Glycol Dehydrator Emissions Inventory section 01-AdmInIstrative Information 'FadIlhans lo: Plan Dehydrator Information oehydratoriype YrIal Number. Design Camlty: Recirculation Pump Information Number of Pumps Pumprype Make Model: Rate: Dehydrator Equipment Flash Tank Rehoeer Burner Dehydrator Equlpmentoeaeription :flash lank, and reboer burner ne(1)enet,yleneslycullrev(natural gas dmymatIon unfit(Maga:r3D,Mdal:ree,serlelnumbocrsolwnhoaasigo peehya s3 MMfe' hi(Make, TBD. Modal, reDi ale ctldvenghml equlppaaaw pump a vpa=1Nof atdmvanspxminsrta, rntsaehydranon unteeaqukpeaeMtnanpaseo+., flash tank, and muonar enlissians m;hen and than. ra tank ale:mead (Ike., the p Recovery n&f�u� Asesocondaryconvol devce,flaacmnk emissions are mutedta Emonon Control Deel[e Description: :Ile Enclosed Pare. Section 03 -Prooassina Rate Inbrmatlon for Emissions Est:mates Primary emissions -oehydratorsillya n nd flash ranklupresenry timltrhrMbeuteQB1MarArkewscr per year PotentlelmE (PPEIThroughpote gs,Ges MIlsof per year Secondary EmIsslons- Combustion owlce(s(fo qe PoUntIon Con. Vent Control Condenser ornission Primary control aevi reduction claimed: e. Plimarycontrol device operation: secondary...0i device: secondastill Vale mntrol operator,: ...fog Valua Primary Primary control ry control device operation: naaryrvmmideaRe: ndarymnwlde4. operation: Rase TenlMes eating Value Fleahllank Waste Gas Vent Rata: Pilot fuel rale: AssIstgas rate: Heat Conlent e/h Pollutant m mlb Controlled MA, 1647 36.75.000 Tol lbenzene enez 0.5297 0 01 150. 05063 01 OOeTA IC Pollutant VOC Benzene Toluene Ethylbenaene Itylenes tom. Rena. Prrrnary 0(00 to (mmr Controlled ubmr 0.00.2975 0.000045 :607 Pn00usr 0r,-tO`a00wer: r. Wffi eiax.?Eti!E 0.03071 Wat Gas Processed: MMscf/yr EtnlVentseco ry Control, 458.25 MI:40/0 WastStIll.Vent Perna, Control: e 09.8160 MIllzer/yr sml Ven[Seean ry awl. 0.0 Wilsef/yr Wet Gaspramsed, Flash reek Secondary control: Mscf/yr Wasta Gas Co2,40125stet Flash Tank PrImargentrol: 0.0 MSR/yr Ms.-al...n ry contr. os MMscrryr Pllot reel/nss..Gaa combustor, WNW/Year AssIstf Ilealr Total: 35.03 / MMsnryear 38.75 193,5 .amens avu. 2.08 RDwmrr�a 02, Mare rleS remelene 0.73, L.:Quer:tam 351.1 0.073.1 4000, 375,6 nentatee LiellmMolmone 001.1, MIS 0,5 r_G Lower Heating Val.& 4,-os mgaer Neetno valaa,rGa5 1.3.7.451 Rrwar, 1481..;91_ R1Mcl 52017 63,1 Glycol Dehydrator Emissions Inventory leaden. -Frnissions Inventor, Did operator Requested Buffer VaP buffer, Cage. Pollutants Potentlel to Emit (tons/pearl 33,g E Item/r�r1a (..N.4a/070003/ Peter .. ncontrolled Controlled Imn:Ha0/ PM10 PM35 PlOa CO VOC 0.12 0.12 0.32 012 0.12 012. 042 0.12 1.11 Liu 141 L11 506 5.00 5.05 5.06 69016 $5. Hazardous airPollutan6 Potendel m Emit Voea/Vaa,/ Actual EmissionsRogues. dlieo ear) Im0Nalan Pe rnft Urn. Uncontrolledtr.. (r�neerl Benzene Toluene Etha Xylem 115969 .5963 lia339 115950 107133 - 31860 31860 1892 31360 1652 section 06- P uloto Somme Anal is gegulalion 3. Parl3 A.0 Sourceit Regulation 3.:eanen 0071.0,0 l.re au1.eu0/0000 Regulation -7,5,0n Regulation 7, Section 3,133., The canon, �„r020104hedahyaaterl.not ±eiectta liegulatagnp,001en alVII.0.2.0 Regulation 7.5ectlo Regulation Pegulodon 8. Port Ca Hx Wee) Mrs 00/00waet eir44. warm ropulra000a insvw^layil Regulation B. Pert E. MACT SubpHPIMerrl rc Mdlor gout. at NI Regulation 8, Pert E, MACT :rtalHx `Pao have indicated that m.radlay isnot eublert toMACrNatal. p.m rugulmory 0ppnumlrywoaabax 200 0070 004 enalnlal 7-loan.,and Perlcdicsamolpre and Testing neoulrements iwet, sa Wes the extended mple red in the airCelr modelroapes,model sim,yearn and collected wamn a year of aoollcaton Unto, the perm.. contain en CompuancemtNe reqDuementto demonstrate complmncewith vnkslon lima¢ 1886091262 118592.0059 4550726159 goes the company rapes. control deal. ef er glen 5594 for flare oreornbustlon deakea Hyes.the pem,nwllcont. anam,aal p ce140300dmunto demonstrate thedesnumun enc ncyorehecombusaemaeme dead ou mletand outlaw,' troconse 015 14802003 10.692 Uncontrolled Pollutant Emleslons Factor Control% Units lagno 0,000/000:12 W15 000b/MMscf NOx 0.0319 0.00M1NM, 000 .603 3622b/MM,r /MM Benzene 2.502 04.10/Mtvlsof Toluene 2308b/MM.( Ethylbenzene 0.00 94.07b/MM.xr gylene 0.6. 54../3031007 n-alexene 0,67 95.41 b/M31007 224 TMP 0.001 0537 b/MMscf Porapogant aVaar .. 101712-1 Pi, Para/gag oga 00137 metbage 0.31 1010 3 PIP, 2.313.2 3352 13.3,333.33 3.9 croanaana 3332 333 3763, 373, agrgageg .0.737 5,03.3 3533.3 agmagge '_01.000030 sga 577,3 3251.6 63 1-1313 33,752 Louyerafeatino Value. of Gay Higher H.aano Value of Gas .03/.07 ss_a_0,m_ 020/02/ 0.u,e, 0030 3,013603034 7000. 73e^%a 01bu,egg-P Dehydrator Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and B - APEN and Permit Requirements You have indicated that source is in the Non -Attainment Area NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual sourcegreater than 1TPY (Regulation3, Part A, Section lI.D.1.a)? 2. Are total facility uncontrolled VOC emissions from the greater than 2TPY, NOx greaterthan 5 TPY or CO emissions greater than 5 TPY (Regulation 3, Part B, Section 11.0.2)? [Source requires a permit Colorado Regulation 7, Section XII.H 1. Is this glycol natural gas dehydrator located in the 8 -hr ozone control area or any mane non -attainment area or attainment/maintenance area (Reg 7, Section XII.H.1 and 2)? 2. Is this glycol natural gas dehydrator located at en oil and gas exploration and production operation', natural gas compressor station, natural gas drip station or gas -processing plant (Reg 7 Section 3. Is the sum of actual uncontrolled emissions of VOC from any single dehydrator or group of dehydrators at a single stationary source equal to or greater than 15 tpy (Reg 7, Section 111.14.3.6)? 4. Are actual uncontrolled emissions of VOC from the individual glycol natural gas debydator equal to or greater than 1 tpy (Reg 7, Section Xll.H.3.a)? 'Dehydrator is suhjectto Regulation 7, Section XI I.H Section XII.H— Emission Reductions from glycol natural gas dehydrators MACT Analysis 1. Is the dehydrator located at an oil and natural gas production facility that meets either of the following criteria: a. A facility that processes, upgrades or stores hydrocarbon liquids' (63.760(e)(2)); OR A facility that processes, upgrades or stores natural gas prior to the point at which natural gas enters the natural gas transmission and storage source category or is delivered to a final end b. user' (63.760(a)(3))? 2. Is the dehydrator located at a facility that is a major source for HAPs? I On to MACT HH Area Source Requirement section to determine MACE HH applicability 40 CFR, Part 63, Subpart MACT HH, Oil and Gas Production Facilities Area Source Requirements 1. Is the dehydrator a triethylene glycol (TEG) dehydration unit (63.760(b)(2))? Exemptions 2a. Is the actual annual average flowrate of naturalgas to the glycol dehydration unit less than 3.001747 MMscf per day (63.764(e)(1)(i)? 2b. Are actual annual average emissions of'benzene from the glycol dehydration unit process vent to the atmosphere less than 1,984.2 lb/yr (63.764(e)(1)(ii)? 3. Is the unit located inside of a UA plus offset and UC boundary area? Deity is subject to area source MACE HH, per the requirements in 63.764)d)(2) Subpart A, General provisions per 563.764 (a) Table 2 §63.765 - Emissions Control Standards Do Not Apply §63.773 - Monitoring Standards Do Not Apply 463.774- Recordkeeping 463.775 - Reporting 40 CFR, Part 63, Subpart MACT HHH, Natural Gas Transmission and Storage Facilities 1 Is the facility wide actual annual average natural gas throughput less than 0.9994051 MMscf/day and glycol dehydrators the only HAP emission source (63.1270(0)7 Small or Large Dehy Determination 2a. Is the actual annual average flowrate of natural gas to the glycol dehydration unit less than 9.994051 MMscf per day (63.127o(b)(2))? 2b. Are actual annual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere less than 1,984.2 lb/yr (63.1270(b)(2))? Small Dehy Requirements 3. Did construction of the small glycol dehydration unit commence on or before August 23, 2011 (63.1270(b)(2) and (3) )? 4. For this small dehy, is a control device required to meet the BTEX emission imit (standard?) given by the applicable equation? Yes Yes 4409. You have indicated that this facility is not subject to MACT HHH. Subpart A, General provisions per §63.1274 (a) Table 2 §63.1275 - Emissions Control Standards §63.1281 -Control Equipment Standards §63.1283 - Inspection and Monitoring §63.1284- Recordkeeping §63.1285 - Reporting Colorado Regulation 7, Section XVII.D 1. Is the dehydrator subject to an emissions control requirement under MACT HH or HHH (Regulation 7, Section XVII.B.5)? 2. Is this dehydrator located ate transmission/storage facility? 3. Is this dehydrator located et an oil and gas exploration and production operation, natural gas compressor station or gas processing plant (Reg 7, Section XVII.D.3)? 4. Was this glycol natural gas dehydrator constructed before May 1, 2015 (Reg 7 Section XVII.D.4.b)? If constructed prior to May 1, 2015, are uncontrolled actual emissions from a single glycol natural gas dehydrator equal to or greater than 6 tons per year VOC or 2 tpy VOC if the 4a. dehydrator is located within 1,320 feet of a building unit or designated outside activity area (Reg 7, Section XVILD.4.6)7 5. If constructed on or after May 1, 2015, are uncontrolled actual emissions from a single glycol natural gas dehydrator equal to or greater than 2 tpy VOC (Regulation 7, Section XVII.D.4.a)? I Dehydrator is subject to Regulation 7, Section XVII, B, 0.3 Section XVII.B — General Provisions for Air Pollution Control Equipment and Prevention of Emissions Section XVII.D.3- Emissions Reduction Provisions Alternative Emissions Control (Optional Section) 6. Is this glycol natural gas dehydrator controlled by a back-up or alternate combustion device (i.e., not the primary control device) that is not enclosed? IThe control device for this dehydrator is not subject to Regulation 7, Section XVII.8.2.e Section XVII.B.2.e—Alternative emissions control equipment Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations, and Air Quality Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances, This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act, its implementing regulations, and Air Quality Control Commission regulations, the language of the statute or regulation will control. The use of non -mandatory language such as "recommend," "may," "should," and tan," is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and "required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself. No No Yes Source Requires en Source Requires a p Continue -You have Continue -You have Go to the next ques Dehydrator is sable Continue - Source is Go to MACE HH Are Continue - You have go to the next ques) goto the next goes( The dehy is subject Continue - You have Continue -You have Continue -You have Go to question 5 Source is subject Glycol Dehydrator Emissions Inventory sectiono3-AdmimnrnFrolwonnwlnn IFanunanID, PI Section ox- .04401 SossHwlon Dwells Dehydrator lnformotion Model: Serlal Number, Design Capacity: Redrculatlon Pump Inform.. mteroor Pumps ce gn/Maxgcirculadonnate, DehydrweFquipment PlasicTank Relmitar Butner Dehydrator EquipmentDesaipllan F... Control DeNce 0m<dptlon: Ions/minute am rebo1er burner nenlldafnaneeV. lTFG) nttural a0dehwntion qdtWake, ThD,Ma4I:TOD..seaal:I,umbe:TaDl with admOn capackyolni Msodpecday. Thaemtsswsankh equipped who 2(MakeTOO, M.et TOD)w4ancdmlmglyo.1 pump capacity ofaogaSam per mbwe.T11. dehydration unit is equipped with st3lvent, Rash tank, andreboder bum Ern.sions rom Need, vent are rout.to an eir-cool. condemn, and then to the Erect...are. minions from !kn.. tanker. .Eed d: Vey hYepornecov ry citl 2uh As n somndemmntrw device, lashankemi®wns aremwedm Section 03. Processing Pate lnlSlmatlanforEntaebne Enlmatro Maury Emletiov., Dehydrator StIll Vent end Fl h k Np a nt Requested PelmtUrnitTroughput= it"nryO ` , 4 , ,515 eescf per year Cots. b Emlt(P(EITM1mugM1put= 0,315 MM . -foe, year Semndary Emiad05..Combuctlonomic.la)farAlt Pollution Control till Vent Control Condenser.msalon reduniandnmad: Mme, Control devkv. Primary controltlevlae operation: Semnderymntrol day,.. Secondary control devkeaperatlon: SOP Vann Gas Heating Wee: WO Vent Waste Gas Veit Pate: FlnM1tenkcantrol Mmwycanroldwkx e operation: Nary mat.MI= Secondary control device operation: aaM1TenicGamHeating Value v FlasicTankW te Gee Vent Pnwaelra:: Enclosed HeroAs* gas palm 0e¢lon09-FmHabm F31te AMelhoddodey 0,1 ONC215,1 p ( Psdlkyv Inlo{on11155/7A13 Inlet Gas Temper...Pa Requested Glycol neclreuiaa Rate STILL VENT Pollulant V0C Benzene Toluene Fdnlbm ene xNanes Central Scenario Uncontrolled /ctrl 103.71 16.0663 7161 Flash a�Tank Pressure,rT 0,6as Water Content Primary ContmlkE MAO Secondary Controlled MAO 10,39671 152668 411,56 25162 0.016 0.02075 02.83 9.2166 24102 8.016 otkcoa Control Scene. RPM TANK ummnoaad dbmq VOC UrIEP Toluene Ethylicenzene Coneoib103/55) Convened 01.1 0.00701 04.1 0.00.05 rpHexace Gue Processed, stllNent Primary Control, 03.451.2S Ms Nr snirvmtsemndary control: 841.10 PilMscr/yr Waste Gas Combust.: sdirventPrknarvcont , 14.2044 IPIMscl/yr RIO Vet SecondaryControl: m IVIMscfArr Wet Gas Processed: PlashTanicPcfmary Control: Ms hr Hash Tank Secondary...4 1.10 0401055* Waste Ga.m FlashIank PANIscf./yr Flash ankYmrkaryCan5ot ii MMscf/yr el/Assist Gm Combust. Pilot Mot fuel/Assist Mscf/year AssIst Fuel: 1,232 Msd/year Total: ss.aF.a Mhacf/year mot ,.,ryyPm, HVMmn.n 'New 0 G .z me 1813, 170.7 - _ - 16.2 M+,stow nlT Ceplocantar 370 1763.0 OPPIchexace .31 »Inns hews: Melhyicacb.Msrb _ edge 4.. 17413 9273.1 3.0S .1,79.5 5772.0 0.00173 6031.5 H5 0 0 en Lower Hes.. Value of Gas PlInfler Valca of Gas 1416.721,016 me/ad Waccpc txy.ov,mak.% 100.11.,h,e) 017.2 PtHane 1150:9 161 p01..8 32214 0.72, 4000.4 andesentcne 0.074: 41.79, ILLS1.5 Macs oe 9 .244 S.135.0 57.55 ,P00617 .624. 6413.2 7.3 00297 TolLece 0.0.626 6031.45 Lower Heating ...aces Moller linen. va. ofGa� 1,13.57.4189 .an.T5ss33 Pup, Yuroe GP.. Fnelrcarin,.,Daes•ct.:ae}E3tiplgue 2s7 0,1 Glycol Dehydrator Emissions Inventory Section 05 -Emissions DUI operator coque.. rteru re pecudsted Buffer (94 cnlada Pollutant ne Ponoel to EmitUncontrolled (mn3Ns/ Controlled Emissions (m5cAre0 ltons/year) Limit ennh Controlled ud ftons/yeerl(tom/s/ PHI10 PM. NOx VaC ills 0.35 0,5 015 0.15 123 1.35 1.35 1.35 ntPotentialm q 33,36. Hazardous. PalludnnControlled Emit Uncontroencontrolle Actlal Emission,Bd V�Ibs/yearld (Ibs/year) Cecile:OW Pernik limits tlpbs/yealrld IIbshelarl Ramona Toluene Ethplommne 153197 9035 153.7,3 9034. 14.60 14.50 5353 141159.91 - 3 203 0090.07 242.79 4156l3 44556 0575 4056557 Reguladon 3, Parts A, source inquires a permit Oahu.... is subject to Pequlationq.aeatfon xvg,a. 0.3 Regulation Section liegulatIon 5,6540 Mh[r 0ubpar1/H pvea/ Peculation B. Part E. / /Melon Regulation 9, Part 5, MAR SubpartHNH (sae regulatory applIcability worlob. or detailed enalels) Dehydrator is dub,. to Population]. S4Rfen CNA .754/.1/01 You I...Ile...that th,raci011 is not bleat to Maleyspume requirements 5100 section 07- Initlatood,r1odicSampltngandrectInsPequIrernent5 eWas Ihe stended wetgassamploused In the wlKpk model/Process model sl2spedgcand collected within a year of application submittal, Ifni, the penultWIIICOntaln an 'Initial Compllance.teCtIng requlrementtodemonstram wmpllance with mission Mac 1042903711 3701.534293 Does the company recluesta ntrol devlce y p itwllltontain anl dlnitlal compllace tesfklency ereeter than 9556.1or Clamor cornbustron device? co Gluon to demonstrate Mee destruction ney of me combusaon device based oninlet and outlet Concentra. sampling Section 09 -Inventory 5[e[uding end ...cos Factors MPS Perot', 036 C Code 29436.33 Pollutant Emisd afaetar P5410 0.004b f PNI2.3 0.50 MMuf 003 /INAMCcf VOC 56.33 b/MMxt 00 0.146 0.07 /NINIUr Benzene 3.517 04.101NIA4505 b/MM Ethy Toluene 54.01 /MMacf 441ene 0505 34.0 ICCINsof ',Hexane 0397 95.44s/MIN, aaTNIP 0.003 65.43 bimmeaf Dehydrator Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and B - APEN and Permit Requirements You have indicated that source is in the Non -Attainment Area NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1TPY (Regulation 3, Part A, Section ll.D.1.a)? 2. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOxgreater than 5 TRY or CO emissions greater than 5 TPY (Regulation 3, Part B, Section 11.0.2)? Source requires a permit Colorado Regulation 7, Section XII.H 1. Is this glycol natural gas dehydrator located in the 8 -hr ozone control area or any ozone non -attainment area or attainment/maintenance area (Reg 7, Section 11114.1 and 2)? 2. Is this glycol natural gas dehydrator located at an oil and gas exploration and production operation', natural gas compressor station, natural gas drip station or gas -processing plant (Reg 7 Section 3. Is the sum of actual uncontrolled emissions of VOC from any single dehydratoror group of dehydrators at a single stationary source equal to or greater than 15 tpy (Reg 7, Section XII.H.3.b)? 4. Are actual uncontrolled emissions of VOC from the individual glycol natural gas dehydrator equal to or greater than 1 tpy (Reg 7, Section XII.H.3.a)? Dehydrator is subject to Regulation 7, Section XII.H Section XII.H —Emission Reductions from glycol natural gas dehydrators MACT Analysis 1. Is the dehydrator located at an oil and natural gas production facility that meets either of the following criteria: a. A facility that processes, upgrades or stores hydrocarbon liquids' (63.760(0)(2)); OR A facility that processes, upgrades or stores natural gas prior to theipoint at which natural gas enters the natural gas transmission and storage source category or is delivered to a final end b. user' )63.760(a)(3))? 2. Is the dehydrator located at a facility that is a major source for HAPs? IGo to MACE HH Area Source Requirement section to determine MACT HH applicability 40 CFR, Part 63, Subpart MAC! HH, Oil and Gas Production Facilities Area Source Requirements 1. Is the dehydrator a triethylene glycol (TEG) dehydration unit (63.760(b)(2))? Exemptions 2a. Is the actual annual average flowrate of natural gas to the glycol dehydration unit less than 3.001747 MMscf per day (63.764(e)(1)(i)? 26. Are actual annual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere less than 1,984.2 lb/yr (63.764(e)(1)(ii)? 3. Is the unit located inside of a UA plus offset and UC boundary area? 'Deily is subject to area source MACT HH, per the requirements in 63.764)d)(2) Subpart A, General provisions per §63.764 (a) Table 2 §63.765 - Emissions Control Standards Do Not Apply §63.773 - Monitoring Standards Do Not Apply §63.774 - Recordkeeping §63.775 - Reporting Major Source Requirements 1. Does the facility have a facility -wide actual annual average natural gas throughput less than 0.65 MMscf/day AND a facility -wide actual annual average hydrocarbon liquid throughput less than 249.7 Small or Large Dehy Determination 2a. Is the actual annual average flowrate of natural gas to the glycol dehydration unit less than 3.001747 MMscf per day (63.761)? 2b. Are actual annual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere less than 1,984.2 lb/yr (63.761)? Small Dehy Requirements 3. Did construction of the small glycol dehydration unit commence on or before August 23, 2011 (63.760(b)(1)(i)(B) and (C )? 4. For this small dehy, is a control device required to meet the BTEX emission limit given by the applicable equation? You have indicated that this facility is not subject to Major Sourcerequirements of MACT HH. 40 CFR, Part 63, Subpart MACT HHH, Natural Gas Transmissnon and Storage Facilities 1 Is the facility wide actual annual average natural gas throughput less than 0.9994051 MMscf/day and glycol dehydrators the only HAP emission source (63.1270(f))? Small or Large Deity Determination 2a. Is the actual annual average flowrate of natural gas to the glycol dehydration unit less than 9.994051 MMscf per day (63.1270(b)(2))? 26. Are actual annual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere less than 1,984.2 lb/yr (63.1270(6)(2))? Small Dehy Requirements 3. Did construction of the small glycol dehydration unit commence on or before August 23, 2011 (63.1270(6)(2) and (3) )? 4. For this small dehy, is a controjdevice required to meet the BTEX emission limit (standard?) given by the applicable equation? Yes Yes Yes Yes You have indicated that this facility is not subject to MACT HHH. Colorado Regulation 7, Section XVII.D 1. Is the dehydrator subject to an emissions control requirement under MACT H H or HHH (Regulation 7, Section XVI I.B.5)? 2. Is this dehydrator located at a transmission/storage facility? 3. Is this dehydrator located at an ail and gas exploration and production operation , natural gas compressor station or gas processing plant (Reg 7, Section XVI I.D.3)? 4. Was this glycol natural gas dehydrator constructed before May 1, 2015 (Reg 7 Section XVII.D.4.b)? If constructed prior to May 1, 2015, are uncontrolled actual emissions from a single glycol natural gas dehydrator equal to or greater than 6 tons per year VOC or 2 tpy VOC if the 4a. dehydrator is located within 1,320 feet of a building unit or designated outside activity area (Reg 7, Section XVII.D.4.b)? 5. If constructed on or after May 1, 2015, are uncontrolled actual emissions from a single glycol natural gas dehydrator equal to or greater than 2 tpy VOC (Regulation 7, Section )(VII.0,4.a)? 'Dehydrator is subject to Regulation 7, Section XVII, B, D.3 Section XVII.B— General Provisionsfor Air Pollution Control Equipment and Prevention of Emissions Section XVII.D.3 - Emissions Reduction Provisions Alternative Emissions Control (Optional Section) 6, Is this glycol natural gas dehydrator controlled by a back-up or alternate combustion device (i.e., not the primary control device) that is not enclosed? 'The control device for this dehydrator is not subject to Regulation, 7, Section XVII.B.2.e Section XVII.B.2.e—Alternative emissions control equipment Disclaimer Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute forany law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Ad„ its implementing regulations, and Air Quality Control Commission regulations, the language of the statute or regulation will control. The use of non -mandatory language such as `recommend,""may," "should,°and tan," is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and "required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself. Source Re Source Re Continue • Continue Go to the Dehydratr Continue Go to MA Continue • No Continue. No Continue. Yes Continue Go to que Source isr Hydrocarbon Loadout Emissions Inventory Section 01- Administrative Information Facility AlRs ID: 23E County 0035 Plant 017 Point Section 02- Equipment Description Details Detailed Emissions Unit Description: from a pressurized bullet tank to pressurized tank troll Emission Control Device Emissions from this source . are : not controlled. Description: Is this loadout controlled? Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Hydrocarbon Loadout Truck Loadout Capacity �� t ztJ� ' sir kqq. gallons/load Loadouts/month Loadouts/year �txw5'/000 b00 gallons/month 1,428,571.43 bbl/year 714.29 loadout/month 8,571.43 load out/year Section 04- Emissions Factors & Methodologies Loadout Hose Parameters Liquid Hose Diameter `s'i'°f " iii I 011660 ll47 feet Vapor Hose Diameter mu a9 141r)'if,i1 ntl o 16by66l feet Liquid Hose Length* v7,N�jEjiijE);hT,s`,p rn$.h„$B} feet Vapor Hose Lenth* <43§ it d$r+r- r'' -, r2. feet Liquid Hose Volume 0.021816616 cubic feet Vapor Hose Volume 0.021816616 cubic feet Tank and Truck Pressure Tank and truck pressure psig psia 109.2 Notes: *Length accountsfor length of isolation valve on pressurized hose. There are two hoses connected to each truck during loadout. PV=nRT Where: P = pressure in hose at time of disconnect =storage tank pressure (psia) ,, V= volume of hoses (cubic feet) n = number of lb -moles of product in hoses R = Universal gas constant =10.73 ft^3 * psi / Ibmele / degR T =average loadout temperature =601=519.67R Vapor Density n 0.000427251 Ibmol n/V 0.019583724 Ibmol/ft^3 MW r= 116.49 lb/Ibmol Vapor Density 2.281307958 Ib/ft^3 Liquid Density SG qilltatfjii.J46 Density of Water r ;r 8.33 lb/gallon Liquid Density 6.160868 lb/gallon 46.08329264 lb/ft^3 Notes: 11. All liquid lines contain liquid products at individual specific gravity. 12. All vapor return lines contain products that behave as ideal gases at 60'F and storage tank pressure. VOC Emissions: Vapor Emissions 426.60 lb/year 0.21 tpy Liquid Emissions 8,617.56 lb/year 4.31 tpy Total Emissions 4.52208 tpy Component Mass Fraction Source Benzene (SAS 54E'03 11 Toluene 111233E-02)„ Ethylbenzene i -P ,lb I 'h 11 pF554ntative Sample e �ttcL+ XVlene dEk�i 1t7i' O'21p1LLi 1n (-',":: s . '1)8 for notes)' n -Hexane -�� 66 5.,02VugEr fi 224 TMP 'At °u.00ST68 t' ill._ 10 of 16 K:\PA\97\97 W E034&CP3.xlsm Hydrocarbon Loadout Emissions Inventory Emission Factors Hydrocarbon Loadout Emission Factor Source Pollutant Uncontrolled Controlled (lb/loadout (lb/loadout event) event) (Volume Loaded) (Volume Loaded) VOC 1.0552E+00 1.06E+00 Other (Docu tentation in Technical A -• Other (Dec -strati n to Technical Aria Other (Decion in Technical An y .- Benzene 9.01E-03 9.01E-03 Toluene 2.46E-02 2.46E-02 Ethylbenzene 2.92E-03 2.92E-03 Other (Doeumentationin Technical Ana •%- Xylene 1.84E-02 1.84E-02 Other (Documentation in Technical Ana. n -Hexane 6.96E-02 5.96E-02 Other DatUrrientatian in l ethnical Ana 224TMP 6.09E-03 6.09E-03 «L Technical An Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) ITequested Permit Limits Uncontrolled Controlled (tors/year) (tons/year) PM10 PM2.5 Sox NOx VOC CO 0.00 0.00 0.00 .0.00 0.00 - 0.00 0.00 0.00 20.00 0.00 0.00 0.00 0.00 40.00 0.00 0.00 0.00 0.00 70.00 0.00 4.52 4.52 4.52 -4.52 4.52 0.00 0.00 0.00 70.00 0.00 Hazardous Air Pollutants Potential to Emit Uncontrolled (Ibs/year) Actual Emissions Uncontrolled Controlled (Ibs/year) (Ibs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (Ibs/year) Benzene Toluene Ethylbenzene Xylene n -Hexane 224 TMP 77.20 77.20 77.20 97.20 77.20 210.46 210.46 210.46 210.46 210.46 25.03 25.03 25.03' 25.03 25.03 157.37 157.37 157.37 157.37 1157.37 596.47 596.47 596.47 t96.47 596.47 52.17 52,17 52.17 52.17 52.17 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit RACT- Regulation 3, Part B, Section III.D.2.e (See regulatory applicability worksheet for detailed analysis) The loadout operation must satisfy RACT. Section 07 - Initial and Periodic Sampling and Testing Requirements Section 08 -Technical Analysis Notes 1. Based on the information provided in the application, emss ons only ocaar from a pressurized loacnut operation when the hoses used to transfer fluids are disconnected and exposed to the atmt calculate emissions, the operator has assumed both the liquid hose and vapor return hose are completely filled with emissions at the time of disconnection and the entirety of these emissions are atmosphere. As such, the volume of each hose was calculated and used in the emission estimate. 2. The emissions estimates are considered convstrvative for the following reasons: The calculation assumes all the liquid in the liquid hose is converted to a gas and vented tc the atmosphere. - the liquid and vapor are assumed 100% VOC. Inmost cases oil will have a specific gravity less than that of water: A conservative estimate of spec gravity for oil is l and was used for the calculations for loadout emissions. 3. 1tie molecular weight of the gas, density of the liquid and mass fractions of FIAPs used toestlmate the HAP emissions were obtained from a representative sample taken from the SLW Compressor Station on 09/24/2014. The sample is not site specific and more than one year old, however the emissions estimates are considered comer vat ve for the reasons stated above. 4. This source is subject to IL1CT. Based on information provided, the loadout operation transfers fluid from pressurized storagevessels to pressurized tank trucks. As the loadout operation is conducted, the vapors displaced from the pressurized trucks is routed back to the pressurized storage vessels. Asa result, emissions only occur when the liquid and vapor hoses are disconnected after completion: of the loadout operation. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point 017 Process If 01 SCC Code Uncontrolled Emissions Pollutant Factor Control % Units _. PM10 0.00E+00 0 Ib/1,000gallons transferred PM2.5 0.00E+00 0 Ib/1,000gallonstranferred SOx 0.00E+00 0 lb/1,000gallons transferred NOx 0.00E+00 0 lb/1,00ogallons transferred VOC 1.51E-01 0 lb/1,000gallons transferred CO 0.00E+00 0 lb/1,000 gallons transferred Benzene 1.29E-03 0 lb/1,000 gallons transferred Toluene 3.51E-03 0 Ib/1,000gallons transferred Ethylbenzene 4.17E-04 0 lb/1,000 gallons transferred Xylene 2.62E-03 0 lb/1,000 gallons transferred n -Hexane 9.94E-03 0 lb/1,000 gallons transferred 224 TMP 8.69E-04 0 Ib/1,000gellons transferred 11 of 16 K:\PA\97\97 W E0349L P3. xlsm Hydrocarbon Loadout Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and B - APEN and Permit Re. uirements Source is in the Non -Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.0.1.a)? 2. Is the loadout located at an exploration and production site (e.g., well pad) (Regulation 3, Part B, Section 11.0.1.1)? 3. Is the loadout operation loading less than 10,000 gallons (238 BBLs) of crude oil per day on an annual average basis? 4. Is the loadout operation loading less than 6,750 bhls per year of condensate via splash fill? 5. Is the leadout operation loading less than 16,308 bbls per year of condensate via submerged fill procedure? 6. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part 6, Section II.O.3(? Not enough information NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section Il.0.1.a)? 2. Is the loadout located at an exploration and production site (e.g., well pad) (Regulation 3, Part B, Section 11.0.1.1)7 3. Is the loadout operation loading less than 10,000 gallons (238 BBIs) of crude oil per day on an annual average basis? 4. Is the loadout operation loading less than 6,750 bbls per year of condensate via splash fill? 5. Is the loadout operation loading less than 16,308 bbls per year of condensate via submerged fill procedure? 6. Are total facility uncontrolled VOC emissions greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 5 TPY (Regulation 3, Part B, Section II.D.2)? 'Source requires a permit 7. RACT- Are uncontrolled VOC emissions from the loadout operation greater than 20 tpy (Regulation 3, Part B, Section III.D.2.a)? 'The loadout operation musts tlsfy RAC?. Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations, and Air Quality Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act„ its implementing regulations, and Air Quality Control Commission regulations, the language of the statute or regulation will control. The use of non -mandatory language such as "recommend," "may," "should," and "can," is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and "required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself. NA: NA' Yet Go to next question. Go to question 6 The loadout requires a permit Nni The loadout operation must satisfy RACT. Separator Venting Emissions Inventory 018 Separator Venting 'Facility AlRs ID: County 0035 Plant 018 Point Section 02 - Equipment Description Details Emission Control Device Description: '-v Requested Overall VOC & HAP Control Efficiency %: Section 03- Processing Rate Information for Emissions Estimates Description Receiver 12" Receiver 8" Launcher 16" Emissions per event Receiver 12" Receiver 8" Launcher 16" Diameter (in.) Length (ft) 12 8 16 Volume (scf) 8.217169712 5.436653279 6.353922899 Gas moles vented Total gas vented (lb) wt% VOC 1.8039 41.4897 0.5304 12.1992 6.691 153.893 Section 04- Emissions Factors & Methodologies Description Emission factors 25.815 7.591 35.487 VOC vented (lb/event) 28.71 11.91169287 28.71 3.50239032 28.68 44.1365124 Emissions are divided into 3 distinct processes: Receiver 12", Receiver 8', and Launcher 16 Receiver 12" Receiver 8" Launcher 16" Events/yr Blowdown events/yr 365 365 230 960 Pollutant (lb/event) (lb/event) (lb/event) Total (lb/yr) Total (tpy) VOC 11.896 3.4979 44.0918 '-.: 15759.9 7.88 Benzene 0.0201 0.00592 0.0706 25.7 1.29E-02 Toluene 0.0153 0.0045 0.0531 '.19.4 9.72E-03 Ethylbenzene 0.000383 0.000113 0.00132 0.5 2.42E-04 Xylenes 0.00862 0.00253 0.000143 4.1 2.05E-03 n -Hexane 0.155 0.0457 0.576 „r»+,• (hr? rrr 205.7 1.03E-01 Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (eons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) VOC 7.88 0.00 I 0.00 7.88 ( 7.88 Potential to Emit Actual Emissions Requested Permit Limits Hazardous Air Pollutants Uncontrolled Uncontrolled Controlled Uncontrolled Controlled (lbs/year) (Ibs/year) (Ibs/year) (Ibs/year) (Ibs/year) Benzene 26 0 0 26 26 Toluene 20 0 0 20 20 Ethylbenzene 1 0 0 1 1 Xylene - 5 - 0 0 5 5 e -Hexane 206 0 0 206 206 224 TMP 0 0 0 0 0 Section 06 - Regulatory Summary Analysis I Regulation 3, Parts A, B 'Source requries a permit (See regulatory applicability worksheet for detailed analysis) Section 07 - Initial and Periodic Sampling and Testing Requirements Using Gas Throughput to Monitor Compliance Doesthe company use site specific emission factors based on agas sample to estimate emissions? If no, the permit will contain en "Initial Testing Requirement" to collect a site -specific gas sample from the equipment being permitted and conduct an emission factor analysis to demonstrate that the emission factors are less than or equal to the emissions factors established with this application. Are facility -wide permitted emissions of VOC greater than or equal to 90 tons per year? Section 08 -Technical Analysis Notes )' Operator used the ideal gas law to estimate the total moles of gas vented during each event for each piece of equipment. Assumed a temperature of 90 deg F. The receivers have pressure bf 400psi, and the launcher has a pressure of 1100 psig VOC and HAP content are from representative inlet gas sample. collected 11704/2019.A site-spevfic inlet gas sample will be required for emission calculations. ''. Althoughannualgas sampling is not required based do permitted emissions for this facility, there is an annual sampling requirement nt of inlet as for the se p g q p y, p � � . g separator, which is the same gas emitted during pigging events. As a result, the annual sampling requirement will also apply to this point and tthe source can recalculate emission factors annually: 7hiv permit will not comtain monthly emission or eventlimits. 13 of 16 K:\PA\97\97 W E0349.CP3.xls m Fugitive Emissions Inventory Regulation 7 Section 01-AdminstretNe Information Facility AIRS ID: Eyy; 123 -r 0035"„«d 500 Section 02 -Equipment,. on Details Detailed Emissions Unit Description: Emission Control Device Description: Section 03 - Emissions Factors & Methodologies Regulation 7 Information Operating Hours Emission Factorsoume Control Efficiency Source: Calculations Service Component ppnen Type Count EmissionFactor(kg/hr. ) Table24 Table 28 Centr0l % ( ) Pollutant Mass Fraction Uncontrolled Emissions Boy) Controlled Emissionsltpv) Gas Connectors Flanges Open -Ended Lines Pump Seals Valves Other Relief Valves — 3° 5 'S 2.00E-04 3.90E-04 2.00E-03 2.40E-03 4.50E-03 8.80E-03 8.80E-03 — 1.00E-05 5.70E-05 1.50E-05 3.50E-04 2.50E-05 120E-04 1.20E -0q — 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% — VOC (�kk6,2e [ BenzeneN>R 501 Toluene 00,009 EthWbermenesp0hd4 Xylem. 04 7 tetp,: n-Hexane(i40."Wsoo?' y 204 -TOP 04004 £ Methanolb 0.030740428 5.46068E-05 4.17582E-05 1.07072E-06 2.35559E-05 2.35559E-05 0.0000.19723 4.28289E-06 0 0.030740428 5.450600-00 4.17582E-05 1.07072E-06 2.36559E-05 0.000414723 4.28283E-06 0 Light Oil Connectors Flanges Open -Ended Lines Pump Seals Valves Oter Relief Valves C 08•' 9$i4 wL+§ „9 15 {d 210E-04 110E-04 140E-03 130E-02 250E-03 7.50E-03 7.50E-03 9.70E-06 240E-06 1.40E-05 5.10E-04 1.90E-05 1.10E-04 110E-04 0.0% 0.0% 0.0% 00% 0.0% 0.0% 0.0% VOC Benzene gq1 v^� Tclaene ii, 1 j Ethylbe ` S l Xyleng 000z6 n -Hexane ti 2,04 -TOP oii++�,.�:. Methanol ' `6 eF'�1::t7 1.677568366 0.002966298 0.002247942 5.03271E-05 0.001214952 0.000210084 0 1.677588306 0.002969296 0.082247942 5.03271E-05 0.0220t09s2 504 0.000216084 0 t pyF,'gP}~j„�e;. LiI74b houislyear Section 9S -Emissions Inventory Did operator request a buffer? Requested Suffer (%): Pollutant Uncontrolled Emissions Controlled Emissions Source VOC 2.39 tpy 2.39 tpy Screening EFs -EPA453/R-95-017 Table 2-8 Benzene 1627 lb/yr 16.97 lb/yr Screening EFs—EPA453/R-95-017 Table 2-8 Toluene 1228 lb/yr 12.82 lb/yr Screening EFs— EPA453/R-95.017 Table 2.8 Ethylbeneene: 0:32 lb/yr 0.32 lbnyr Screening EFs— EPA -053/R-95-017 Table2-8 Xylenes 7.26 lb/yr 7.26 I6/yr Screening EFs— EPA453/5-95-017 Table 2-8 n -Hexane 130.91 IS/yr 130.90 lb/yr Screening EFs- EPA -053/R-95.017 Table 28 22.4-TMP 1.2216/yr 1.22 Iblw Screening EFs- EPA -453/0-95-017 Table2-8 Methanol 0.00 lb/yr 0.00 lb/yr Screening EFs-EPA-053/R-95.017 Table 2-8 Summa An Review Regulation 3, Pad B, Section 111.02 to determine is RACT is required? Renew 40 CFR, Part 60, Subpart KKK to determine if applicable to this source? Review 40 CFR, Part 60, Subpart 0000 t0 determine if 60.5380 and/or 605385 is applicable? Review Section XVII.F to determine is LEAR is applicable? 61.48 0.11 0.08 000 0.05 084 0.01 0.00 3355.14 5.04 4.50 0.10 2.55 45.83 544 0.00 13.10483473 406.2498767 TPY 0.008485 0.008485 0.00644 0.00644 0.00016 0.00016 0.00363 0.00363 0.055455 0.065455 0.0006075 0.0006-075 0 0 Is this source at anonshore"naturat gasproceaawg plant" as defined In 40CFR-Part60.631? 'N .. Facility is classified as a natural gas processrg plant Therefore, this source is subject to Regulation 7 Section XII.G. Is the facility classified as a well production (wilily or natural gas compressorstation? Since this facility is classified as a natural gas compressor station, it is subject. Regulation 7 Section XII.L. and XVII.F. Did this source commence cons. Lion, reconsWdion, or modification after September 18, 2015? Is this source at a well site, compressor station or onshore'natural gas processing plant' as defined in 40 CFR Part 60.543055 NSPS 0000a This facility meets the definition of compressor station as defined by 40 CFR, Part 60.5430a. Therefore, the fuai5ve emissions at this facility are subject to NSPS 0000a. Section 07-Tedmical Analysis Notes Section 06 -Inventory SCC Coding and Emissions Factors AIRS Point*, 019 Process *, 01 SCC Code Uncontrolled Pollutant Emissions Factor Control% Source Varies by Varies by VOC component type component type Screening EFs-EPA-453/R-95-017 Table 28 Varies by Varies by Benzene compone. type component type Screening EFs-EPA-053/R-95-017 Table 2A Varies by Varies by Toluene component type component type Screening EFs- EPA -433/R-95-01717 Table 2-8 Varies by Varies by Ethylbensene componenttype component type Screening EFs- EPA -453/6.95-017 Table 2'0 Varies by Varies by Xylene component type component type Screening EFs-EPA-453/R-95-017 Table2-8 Varies by Varves by n -Hexane component type component type Screening EFs -EPA-453/R-95-01?Table 2-8 Varies by Varies by 224TMP component type component type Screening EFs -EPA-453/R-95-017 Table 2-8 Separator Venting Emissions Inventory Section 01 -Administrative Information 'Facility AIRs ID: County � � z 0035......95k4,'Mr%inflearraF4ASIW Plant Point Section 02 - Equipment Description Details e[ Detailed Emissions Unit Description: 4 ne la .¢Yet Emission Control Device Description: *T1O1$ r`„Kq Requested Overall VOC & HAP Control Efficiency %: Limited Process Parameter Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions -Separator Compressor Blowdown Volume= Requested Compressor Slowdown Events= Actual Compressor Blowdown Events= Actual Throughput = MMscf events/year events/year 0.0 MMscf per year Requested Permit Limit Throughput = Potential to Emit (PTE) Throughput = 1.17 MMscf per year 1.17 MMscf per year Requested Monthly Throughput= 0.0995 MMscf per month Process Control (Recycling) Equipped with a VRU: Section 04- Emissions Factors & Methodologies MW 22.92833624 Ib/Ib-mol Displacement Equation Ex=D,"MW5Do/C Mole % Molecular Weight Ib/Ib-mie Mass % Corrected Mass % Helium 001 II 4 0.0004 0.001744566 - 0O2 - 1.99 F 43:99 0.875401 3.817987449 - N2 0.42 28.02 0.117684 0.513268816 - methane 71.42 18.01 11.43443806 49.87033486 52.1290887 ethane 14.01 30.02 4.20493142 18.33945288 19.17009317 propane - 7.36 44.03 3.242193]8 14.140551 14.78101239 isobutane 0.90 58.04 0.51969016 2.266584695 236924406 n -butane 2.40 58.04 1.39069594 6.065404945 6.340122505 isopentane 0.49 72.05 0.353045 1.539775919 1.609516272 n -pentane 0.55 72.05 0.39980545 1.743717668 L82269506 cyclopentane 0.03 70.1 0.0205393 0.08958042 0.093637745 n -Hexane 0.10 86.16 0.08616 0.375779555 0.392799564 cyclohexane 0.02 84.16 0.01859936 0.081119536 0.084793645 Otherhexanee 0.17.. 86.16 0.14836752 0.647092395 0.676400849 heptanes 0.06 100.2 0.0570138 0.248660868 0.259923349 methylcyclohexane 0.02 98.19 0.01659411 0.072373808 0.075651801 224 -IMP 0.00 114.23 0.00079%1 0.003487431 0.003645386 Benzene 0.01 78.1 0.0111683 0.048709596 0.050915777 Toluene 0.01 92.14 0.00847688 0.036971199 0.038645715 Ethylbenzene 0.00 92.1 0.0001842 0.000803373 0.00083976 Xylenes 0.00 106.17 0.00159255 0.006945772 0.007260364 C8+ Heavies 0.02 114.2 0.020556 0.089653256 0.093713879 Total 99.99 VOC Mole% 12.19 TOC % 95.67 VOC WOO 28.70081812 Emission Factors Compressor Slowdowns Pollutant Uncontrolled Controlled (lb/MMscf) (lb/MMscf) (Gas Throughput) (Gas Throughput) Emission Factor Source VOC 17363.1137 17363.1137 Benzene Toluene 30.8025 23.3795 0.5080 4,3923 237.6317 30.8025 23.3795 0.5080 4.3923 Ethylbenzene X71ene n -Hexane 224 IMP 237.6317 2.205.3 2.2053 ended gas analysis. ended gas analysis ended gas analysis! Emission Factors - Compressor slowdowns Pollutant Uncontrolled Controlled _ _ lb/event lb/event (Compressor Blowdown) (Compressor Blowdown) VOC 282.4631 282.4631 Benzene 0.5011 0.5011 Toluene 0.3803 0.3803 Ethylbenzene 0.0083 0,0083 xvlene 0,0715 0.0715 n -Hexane 3.8658 3.8658 224TMP 0.0359 0.0359 155916 K:\PA\97\97WE034R.CP3xlsm Separator Venting Emissions Inventory Section OS - Emissions inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year[ (tons/year) Requested Permit Limits Uncontrolled Controlled (tans/year) (tons/year) Requested Monthly Limits Controlled Ohs/month) VOC 10.17 0.00 I 0.00 10.17. I 10,17 1727 HazardousAir Pollutants Potential to Emit Uncontrolled (Ibs/year) Actual Emissions Uncontrolld Controlled (ibs/year) (Ibs/yea) Requested Permit Limits Uncontrolled Controlled (lbs/year) (Ibs/year) Benzene Toluene Ethylbenzene Xylene n -Hexane 224 TMP 36.08 0.00 0.00 36.08 36.08 27.38 0.00 0,00 27.38' 27.38 0.60 0.60 0.00 - 0.60 0.60 5.14 0.00 0,00 5,14 5.14 278.34 0.00 0.00 278.34 278.34 2.58 0.00 0.00 2.58 2.58 Section 06- Regulatory Summary Analyst Reg. 3 Reg. 6 Reg. 7 Review Regulation 3, Part B, Section III.D.2 to determine is RAGT is required? Review 40 CFR, Part 60, Subpart KKK to determine if applicable to the source? Review 40 CFR, Part 60, Subpart 0000 to determine -060.5380 andlor 60.5385 is applicable? Review Section XVII.F to determine is LDAR is applicable? Regulation 7 Is this source at en onshore "natural gas processing plant as defined in 40 CFR, Pert 60.631? Facility is classified as a natural gas processing plant Therefore, this source is subject to Regulation 7 Section XII.G. Is the facilityclassified as a well production facility or natural gas compressor station? Since this facility is classified as a natural gas compressor station, it Is subject to Regulation 7 Section XII,L, and XVII.F. Did Otis source commence construction, reconstruction, or modification. after September 18, 2015? This facility meets the definition of compressor station as defined by40 CFR, Part 60.04300. Therefore, the fugitive emissions at this facility are subject to NSPS' NSPS 0000a Section 07 - Initial and Periodic Sampling and Testing Requirements Using Gas Throughput to Monitor Compliance Goes the company use site specific emission factors based on a yas sample to estimate emissions? f$ t This sample should represent the gas outlet of the equipment covered under this AIRsil, and should have been.collected within one year of the application received date. However, if the facility has not been modified (e.g., no new wells brought on-line), then it may be appropriate touse an older site -specific sample. If no, the permit will contain an "Initial Testing Requirement" to collect a site -specific gas sample from the equipment being permitted and conduct an emission factor analysis to demonstrate that the emission factors are less than or equal to the emissions factors established with this application. Are facility -wide permitted emissions of VOC greater than or equal to 90 tons per year? Section OS -Technical Ansysis Sates jr�a s� N r 1�Em o xacFt5(S` to due de corn al is Section 09.- Inventory SCC Coding and. Emissions Factors AIRS Point tt Process p SCC Code 021 01 Pollutant PM10 PM2.5 500 600 VOC CO Benzene Toluene Ethylbenzene xylene n -Hexane 224 TMP Uncontrolled Emissions Factor Control % PREF! 0 cREF! #REF! PREF] 17363.11 PREF! 30,80 23.38 0.51 4.39 237,63 2.21 0 0 0 0 0 0 0 0 0 0 0 Units b/MMSCF- b/MMSCF b/MMSCF b/MMSCF b/MMSCF b/PA MSCF b/MMSCF b/MMSCF b/MMSCF b/MMSCF b/MMSCF b/MMSCF 16 of16 K:\PA\97\97 W E0349.CP3.0Ism LORADO Pollution Control Division meat of Public Health & Environment CONSTRUCTION PERMIT Permit number: 97WE0349 Issuance: 3 Date issued: Issued to: DCP Operating Company, LP Facility Name: Eaton Compressor Station Plant AIRS ID: 123/0035 Physical Location: SEC 34 T7N R66W County: Weld County. General Description: Natural Gas Compressor Station Equipment or activity subject to this permit: Facility Equipment ID AIRS Point Equipment Description Emissions Control Description TURB-1 012 One (1) Solar Taurus 70 (Serial Number TBD) natural-gas fired combustion turbine site rated at 76.81 MMBtu/hr heat input and 9,439 horsepower at 11,763 RPM. This turbine is used for natural gas compression. This turbine is equipped with SoLoNO, technology. None TURB-2 013 One (1) Solar Taurus 70 (Serial Number TBD) natural-gas fired combustion turbine site rated at 76.81 MMBtu/hr heat input and 9,439 horsepower at 11,763 RPM. This turbine is used for natural gas compression. This turbine is equipped with SoLoNO,t technology. None TURB-3 014 One (1) Solar Taurus 70 (Serial Number TBD) natural-gas fired combustion turbine site rated at 76.81 MMBtu/hr heat input and 9,439 horsepower at 11,763 RPM. This turbine is used for natural gas compression. This turbine is equipped with SoLoNO,t technology. None D-1 015 One (1) Triethylene glycol (TEG) natural gas dehydration unit (make, model, and serial number TBD) with a design capacity of 125 MMscf per day. This emissions unit is equipped Emissions from the still vent are routed to an air-cooled condenser and then to an enclosed combustor. COLORADO Air Pollution Control Division Department of Pubbc Health b Environment Page 1 of 37 wi � (2) a - and odel TBD glycol pumps wl � a a } lgn apacity 30 gallons per te. , a e pu : I`ll operate at a time. This unit is equipped with a flash tank, reboiler and still vent. Emissions from the flash tank are routed to a vapor recovery unit (VRU). During VRU downtime (maximum 5% annually), emissions are routed to an enclosed combustor D-2 016 One (1) Triethylene glycol (TEG) natural gas dehydration unit (make, model, and serial number TBD) with a design capacity of 231 MMscf per day. This emissions unit is equipped with two (2) make and model TBD glycol pumps with a design capacity of 40 gallons per minute. Only one pump will operate at a time. This unit is equipped with a flash tank, reboiler and still vent. Emissions from the still vent are routed to an air-cooled condenser and then to an enclosed combustor. Emissions from the flash tank are routed to a vapor recovery unit (VRU). During VRU downtime (maximum 5% annually), emissions are routed to an enclosed combustor L-1 017 Loadout of condensate from a pressurized storage vessel to pressurized tank trucks. Vapor balance PIG 018 Pig launching and receiving emissions. None FUG -1 019 Fugitive component leaks from a natural gas compressor station. None TURB-BD 021 Compressor blowdown emissions from turbines. None Points 012, 013, £t 014: This turbine may be replaced with another Solar Taurus 70 turbine in accordance with the temporary turbine replacement provision, or with another Solar Taurus 70 in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment A. Points 015 Ft 016: The glycol pump may be replaced with another pump of the same design capacity in accordance with the provisions of the Alternate Operating Scenario (AOS) included in this permit. This permit is granted subject to all rules and regulations of the Colorado Air Quality Control Commission and the Colorado Air Pollution Prevention and Control Act (C.R.S. 25-7-101 et seq), to the specific 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 Air Pollution Control Division (the Division) no later than fifteen days of the latter of commencement of operation or issuance of this permit, y submitting a Notice of Startup form to the Division. The Notice of Startup form may be downloaded online at www.colorado.gov/cdphe/air/manage-permit. Failure to notify the Division of startup of the permitted source is a violation of Air Quality Control Commission (AQCC) Regulation No. 3, Part B, Section III.G.1 and can result in the revocation of the permit. COLORADO Air Pollution Control Division Dtpanmelt of Publ. Ffealttib E 4xonment Page 2 of 37 2. • d d a ei ty da 180) of the latter of commencement of operation or issuance o t is permit, compliance with the conditions contained in this permit shall be demonstrated to the Division. It is the owner or operator'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 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 deadline per Regulation No. 3, Part B, III.F.4.b. (Reference: Regulation No. 3, Part B, III.F.4.) 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. Points 012, 013, £t 014: The following information shall be provided to the Division within fifteen (15) days of the latter of commencement of operation or issuance of this permit. • Points 012, 013, £t 014: serial number. • Points 015 a 016: TEG dehydrator manufacturer name, model, and serial number. • Points 015 a 016: glycol circulation pump manufacturer name and model. This information shall be included with the Notice of Startup 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 Equipment ID AIRS Point Pounds per Month Emission Type NO. VOC CO SO2 PM2.5 PM10 TURB-1 012 3,115 120 3,161 195 378 378 Point COLORADO Air Pollution Control Division rtment of Public Health & Environment Page 3 of 37 UR•r- 113 115 120 3,161 195 378 378 Point •B-3 ` ; " 120 3,161 195 378 378 Point D-1 015 189 4,359 862 -- Point D-2 016 229 5,702 1,043 -- -- -- Point L-1 017 -- 782 -- -- -- "" Point FUG -1 019 -- 406 -- -- -- -- Fugitive Notes: Monthly limits are based on a 31 -day month. Points 012, 013, & 014 emissions are based on steady-state turbine emissions. The owner or operator shall calculate monthly emissions based on the calendar month. Annual Limits: Facility Equipment ID AIRS Point Process Tons per Year Emission Type NO. VOC CO 5O2 PM2.5 PM10 TURB-1 012 01 18.4 0.8 18.6 1.2 2.3 2.3 Point 02 0.1 0.5 2.2 -- -- -- 03 0.1 0.2 1.5 -- -- -- TURB-2 013 01 18.4 0.8 18.6 1.2 2.3 2.3 Point 02 0.1 0.5 2.2 -- -- -- 03 0.1 0.2 1.5 -- -- -- TURB-3 014 01 18.4 0.8 18.6 1.2 2.3 2.3 Point 02 0.1 0.5 2.2 -- -- "" 03 0.1 0.2 1.5 -- -- - D-1 015 -- 1.2 25.7 5.1 -- -- "- Point D-2 016 -- 1.4 33.6 6.2 -- -- -- Point L-1 017 -- -- 4.6 -- -- -- "" Point PIG 018 -- -- 7.9 -- -- -- -- Point FUG -1 019 -- -- 2.4 -- -- -- -- Fugitive TURB-BD 021 -- 10.1 -- -- -- Point See "Notes to Permit Holder" for information on emission factors and methods used to calculate limits. For Points 012, 013, & 014, the following process designations apply: (01) Steady-state Turbine Emissions; (02) Start-up Turbine Emissions COLORADO Air Pollution Control Division s`Yeprtment of Pub tc t-€eakh t Environment Page 4 of 37 Facility -wide emissions of benzene shall be less than 8.3 tpy. Facility -wide emissions of all other individual hazardous air pollutants shall be less than 8.0 tpy. Facility -wide emissions of total hazardous air pollutants shall be less than 21.8 tpy. During the first twelve (12) months of operation, compliance with both the monthly and annual emission limitations is required. After the first twelve (12) months of operation, compliance with only the annual limitation is required. Compliance with the annual limits, for criteria and hazardous air pollutants, 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 actual emissions each month and keep a compliance record on site or at a local field office with site responsibility for Division review. 8. Points 015 &t 016: Compliance with the emission limits in this permit shall be demonstrated by running the GRI GlyCalc model version 4.0 or higher on a monthly basis using the most recent extended wet gas analysis and recorded operational values, including: dry gas throughput, lean glycol recirculation rate, enclosed combustion device (ECD) downtime, vapor recovery unit (VRU) downtime, condenser outlet temperature, flash tank temperature and pressure, wet gas inlet temperature, and wet gas inlet pressure. Recorded operational values, except for gas throughput, shall be averaged on a monthly basis for input into the model and be provided to the Division upon request. 9. The owner or operator shall track emissions from all insignificant activities at the facility on an annual basis to demonstrate compliance with the facility potential emission limitations as seen below. An inventory of each insignificant activity and associated emission calculations shall be made available to the Division for inspection upon request. For the purposes of this condition, insignificant activities are defined as any activity or equipment, which emits any amount but does not require an Air Pollution Emission Notice (APEN) or is permit exempt. Total potential emissions from the facility, including all permitted emissions and potential to emit from all insignificant activities, shall be less than: • 10 tons per year of n -hexane; and • 25 tons per year of total hazardous air pollutants (HAP). 10. The owner or operator shall operate and maintain the emission points in the table below as a closed loop system and shall recycle 100% of emissions as described in the table below. (Regulation Number 3, Part B, Section III.E.) Facility Equipment AIRS Point Emissions Recycling Description Pollutants Recovered ID COLORADO Air Pollution Control Division Public Haak's Fi Enexonmeni Page 5 of 37 r '+ Flash Tank: Recycled to Plant Inlet with ,. 01 VRU (except during VRU downtime - up to VOC and HAP ®`5% downtime annually) Flash Tank: Recycled to Plant Inlet with D-2 016 VRU (except during VRU downtime - up to VOC and HAP 5% downtime annually) 11. The emission points in the table below shall be operated and maintained with the emissions control equipment as listed in order to reduce emissions to less than or equal to the limits established in this permit. (Regulation Number 3, Part B, Section III.E.) Facility Equipment ID AIRS Point Control Device Pollutants Controlled D-1 015 Flash Tank: Enclosed combustor during VRU downtime (up to 5% downtime annually) VOC and HAP Still Vent: Enclosed combustor except during enclosed combustor downtime (up to 1% downtime annually) D-2 016 Flash Tank: Enclosed combustor during VRU downtime (up to 5% downtime annually) VOC and HAP Still Vent: Enclosed combustor except during enclosed combustor downtime (up to 1% downtime annually) 12. Points 018 Et 021: The owner or operator shall calculate actual emissions from this emissions point based on the most recent gas analysis, as required in the Compliance Testing and Sampling section of this permit. 13. Point 019: The owner or operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent extended gas analysis, 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. PROCESS LIMITATIONS AND RECORDS 14. 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 owner or operator and made available to the Division for inspection upon request. (Reference: Regulation 3, Part B, II.A.4) Process/Consumption Limits Facility Equipment ID AIRS Point Process Process Parameter Annual Limit Monthly Limit (31 days) TURB-1 012 01 Consumption of natural gas as a fuel 673.6 MMscf 57.21 MMscf COLORADO Air Pollution Control Division Department of Publ,c Health b Environment Page 6 of 37 Sta -up events 48 events -- 0 Sh . n events 48 events -- TURB-2 013 01 Consumption of natural gas as a fuel 673.6 MMscf 57.21 MMscf 02 Start-up events 48 events -- 03 Shutdown events 48 events -- TURB-3 014 01 Consumption of natural gas as a fuel 673.6 MMscf 57.21 MMscf 02 Start-up events 48 events -- 03 Shutdown events 48 events -- D-1 015 01 Total dry gas throughput 45,625 MMscf 3,875 MMscf 02 Dry gas throughput while still vent emissions are vented to atmosphere 456.3 MMscf -- 03 Dry gas throughput while flash tank emissions are routed to enclosed combustor 2,281.3 MMscf -- 04 Assist gas and pilot fuel to enclosed combustor 15.33 MMscf 1.31 MMscf D-2 016 01 Total dry gas throughput 84,315 MMscf 7,161 MMscf 02 Dry gas throughput while still vent emissions are vented to atmosphere 843.2 MMscf -- 03 Dry gas throughput while flash tank emissions are routed to enclosed combustor 4,215.8 MMscf __ 04 Assist gas and pilot fuel to enclosed combustor 15.46 MMscf 1.32 MMscf L-1 017 -- Pressurized loadout events728 8,572 loadouts loadouts PIG 018 01 Receiver 12" pigging events 365 events - 02 Receiver 8" pigging events 365 events -- 03 Launcher 16" pigging events 230 events -- TURB-BD 021 -- Turbine compressor blowdown events 72 events The owner or operator shall calculate monthly process rates based on the calendar month. COLORADO Air Pollution Control Division Department of Patric Neal"a fr Environment Page 7 of 37 nths operation, compliance with both the monthly and ns is •uired. After the first twelve (12) months of operation, comp lance wit only t e annual limitation is required. Compliance with the annual 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 throughput each month and keep a compliance record on site or at a local field office with site responsibility, for Division review. 15. Points 012, 013, Et 014: The owner or operator shall continuously monitor and record the volumetric flow rate of natural gas combusted as fuel for each turbine using an operational continuous flow meter at the inlet of each turbine. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. During flow meter downtime, the natural gas consumed by the turbine as fuel shall be assumed to be 1.85 MMscf/day until the flow meter is repaired and/or operational. 16. Points 012, 013, £t 014: On a monthly basis, the owner or operator shall monitor and record the total number of turbine startup and shutdown events. By the end of each month, the total number of startup and shutdown events 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. The owner or operator shall use monthly records to demonstrate compliance with the process limits and to calculate emissions as described in this permit. 17. Point 015: The owner or operator shall continuously monitor and record the volume of dry gas throughput using an operational continuous flow meter at the outlet of the dehydrator. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. During flow meter downtime, a dry gas throughput of 125.0 MMscf/day shall be assumed until the flow meter is repaired and/or operational. 18. Point 015: This unit shall be limited to the maximum lean glycol circulation rate of 30 gallons per minute. The lean glycol recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. Glycol recirculation rate shall be monitored by one of the following methods: assuming maximum design pump rate, using glycol flow meter(s), or recording strokes per minute and converting to circulation rate. This maximum glycol circulation rate does not preclude compliance with the optimal glycol circulation rate (Loft) provisions under MACT HH. (Reference: Regulation Number 3, Part B, II.A.4) 19. Point 016: The owner or operator shall continuously monitor and record the volume of dry gas throughput using an operational continuous flow meter at the outlet of the dehydrator. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. During flow meter downtime, a dry gas throughput of 231.0 MMscf/day shall be assumed until the flow meter is repaired and/or operational. 20. Points 016: This unit shall be limited to the maximum lean glycol circulation rate of 40 gallons per minute. The lean glycol recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. Glycol recirculation rate shall be monitored by one of the following methods: assuming COLORADO Air Pollution Control Division melt of Public 1 feaitn 6 Envsonment Page 8 of 37 ing col flow meter(s), or recording strokes per minute ci la on rat This maximum glycol circulation rate does not preclu•e comp lance wit t e optimal glycol circulation rate (Loot) provisions under MACT HH. (Reference: Regulation Number 3, Part B, II.A.4) 21. Points 015 a 016: On a weekly basis, the owner or operator shall monitor and record operational values including: vapor recovery unit (VRU) downtime, flash tank temperature and pressure, condenser outlet temperature, wet gas inlet temperature and pressure. These records shall be maintained for a period of five years. 22. Points 015 £t 016: The owner or operator shall monitor and record enclosed combustor (ECD) downtime on a daily basis. ECD downtime shall be defined as times when the waste gas vented from the dehydrator still vent is routed to the atmosphere rather than the ECD. The total hours of ECD downtime and the dry gas throughput during ECD downtime shall be recorded on a monthly basis. The operator shall demonstrate ECD downtime does not exceed one percent (1%) of the total dry gas throughput on a rolling twelve (12) month total basis. 23. Points 015 Et 016: The owner or operator shall monitor and record vapor recovery unit (VRU) downtime on a daily basis. VRU downtime shall be defined as times when the waste gas vented from the dehydrator flash tank is routed to the enclosed combustor instead of the VRU. The total hours of VRU downtime and the dry gas throughput during VRU downtime shall be recorded on a monthly basis. The operator shall demonstrate VRU downtime does not exceed five percent (5%) of the total dry gas throughput on a rolling twelve (12) month total basis. STATE AND FEDERAL REGULATORY REQUIREMENTS 24. The permit number and AIRS ID point number (e.g. 123/4567/890) shall be marked on the subject equipment for ease of identification. (Reference: Regulation Number 3, Part B, III.E.) I. E.) (State only enforceable) 25. Visible emissions shall not exceed twenty percent (20%) opacity during normal operation of the source. During periods of startup, process modification, or adjustment of control equipment visible emissions shall not exceed 30% opacity for more than six minutes in any sixty consecutive minutes. Emission control devices subject to Regulation 7, Sections XII.C.1.d or XVII.B.2.b shall have no visible emissions. (Reference: Regulation No. 1, Section II.A.1. .A.1. it 4.) 26. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) 27. These sources are in a designated ozone nonattainment area and shall apply Reasonably Available Control Technology (RACT) (Reference: Regulation No. 3, Part B, III.D.2.a). The following requirements are determined to be RACT for these sources: Facility Equipment ID AIRS Point RACT Pollutants TURB-1 012 Natural gas as fuel, low NOx burners, good combustion practices NOx, VOC TURB-2 013 Natural gas as fuel, low NOx burners, good combustion practices NOx, VOC COLORADO Air Pollution Control Division of Public 14eatth 6 Environment Page 9 of 37 R 3 - 01 N tural as as fuel, low NOx burners , • . • combustion practices NOx, VOC D-1 015 Still vent: enclosed combustor VOC Flash tank: recycled to plant inlet via VRU. Routed to enclosed combustor during 5% VRU downtime. D-2 016 Still vent: enclosed combustor VOC Flash tank: recycled to plant inlet via VRU. Routed to enclosed combustor during 5% VRU downtime. L-1 017 Loading from a pressurized tank to a pressurized tank truck using a vapor balance system. VOC PIG 018 Good maintenance practices. VOC FUG -1 019 LDAR in accordance with Regulation No. 7 Sections XII.L a XVII.F, and 40 CRF Part 60 Subpart 0000a VOC TURB-BD 021 Good maintenance practices. VOC 28. Points 012, 013, £t 014: This source is subject to the Particulate Matter and Sulfur Dioxide Emission Regulations of Regulation 1 including, but not limited to, the following(Regulation 1, Section III.A.1):: a. No owner or operator shall cause or permit to be emitted into the atmosphere from any fuel -burning equipment, particulate matter in the flue gases which exceeds the following (Regulation 1, Section III.A.1):: (i) For fuel burning equipment with designed heat inputs greater than 1x106 BTU per hour, but less than or equal to 500x106 BTU per hour, the following equation will be used to determine the allowable particulate emission limitation. PE=0.5(FIyo.26 Where: PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. b. Emissions of sulfur dioxide shall not emit sulfur dioxide in excess of the following combustion turbine limitations. (Heat input rates shall be the manufacturer's guaranteed maximum heat input rates). (i) Combustion Turbines with a heat input of less than 250 Million BTU per hour: 0.8 pounds of sulfur dioxide per million BTU of heat input. 29. Points 012, 013, £t 014: This source is subject to the New Source Performance Standards requirements of Regulation 6, Part B including, but not limited to, the following (Regulation 6, Part B, Section II): DPHE 'COLORADO Air Pollution Control Division partment of Public Wealth & Environment Page 10 of 37 ate Mai er - On and after the date on which the required per ormance test is complete •, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: (i) For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation: PE=0.5 (FI )-o.26 Where: PE is the allowable particulate emission in pounds per million Btu heat input. Fl is the fuel input in million Btu per hour. (ii) Greater than 20 percent opacity. b. Standard for Sulfur Dioxide - On and after the date on which the required performance test is competed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere sulfur dioxide in excess of: (i) Sources with a heat input of less than 250 million Btu per hour: 0.8 lbs. SO2/million Btu. 30. Points 012, 013, Et 014: The combustion turbines are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart KKKK, Standards of Performance for Stationary Combustion Turbines including, but not limited to, the following: 40 CFR, Part 60, Subpart A - General Provisions • §60.4320 - Nitrogen Oxide Emissions Limits o §60.4320 (a) - NOx emissions shall not exceed 25 ppm at 15% O2 or 1.2 lb/MW- hr; • §60.4330 - Sulfur Dioxide Emissions Limits o §60.4330 (a)(1) - SO2 emissions shall not exceed 0.9 lb/MW-hr gross output; or o §60.4330 (a)(2) Operator shall not burn any fuel that contains total potential sulfur emissions in excess of 0.060 lb SO2/MMBtu heat input. • §60.4333 - General Requirements o §60.4333 (a) - Operator must operate and maintain your stationary combustion turbine, air pollution control equipment, and monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions at all times including during startup, shutdown and malfunction. • §60.4340 - NOx Monitoring o §60.4340 (a) - Operator shall perform annual performance tests in accordance with §60.4400 to demonstrate continuous compliance with NOx emissions limits. If the NOx emission result from the performance test is less COLORADO Air Pollution Control Division Compartment of Public Efeaith b Environment Page 11 of 37 per nt of the NOx emission limit for the turbine, the equent erformance testing may be reduced to once every two years no more t an 26 calendar months following the previous performance test). If the results of any subsequent performance test exceed 75 percent of the NOx emission limit for the turbine, you must resume annual performance tests. • §60.4365 (or §S60.4360 and 60.4370) - SO2 Monitoring o The operator shall comply with §60.4365 or with both §§60.4360 and 60.4370 to demonstrate compliance with 502 emissions limits. • 560.4375 - Reporting o §60.4375 (b) - For each affected unit that performs annual performance tests in accordance with 560.4340(a), you must submit a written report of the results of each performance test before the close of business on the 60th day following the completion of the performance test. • §S60.4400 and 60.4415 - Performance Tests o Annual tests must be conducted in accordance with 560.4400(a) and (b). o Unless operator chooses to comply with §60.4365 for exemption of monitoring the total sulfur content of the fuel, then initial and subsequent performance tests for sulfur shall be conducted according to §60.4415. 31. Points 015 Et 016: This source is subject to Regulation Number 7, Section XII.H. The operator shall comply with all applicable requirements of Section XII and, specifically, shall: • Comply with the recordkeeping, monitoring, reporting and emission control requirements for glycol natural gas dehydrators; and • Ensure uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas -condensate -glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by at least 90 percent on a rolling twelve-month basis through the use of a condenser or air pollution control equipment. (Regulation Number 7, Section XII.H.1.) 32. Points 015 a 016: The combustion device covered by this permit is subject to Regulation Number 7, Section XVII.B.2 General Provisions (State only enforceable). If a flare or other combustion device is used to control emissions of volatile organic compounds to comply with Section XVII, it shall be enclosed; have no visible emissions during normal operations, as defined under Regulation Number 7, XVII.A.17; and be designed so that an observer can, by means of visual observation from the outside of the enclosed flare or combustion device, or by other convenient means approved by the Division, determine whether it is operating properly. This flare must be equipped with an operational auto -igniter according to the following schedule: • All combustion devices installed on or after May 1, 2014, must be equipped with an operational auto -igniter upon installation of the combustion device; • All combustion devices installed before May 1, 2014, must be equipped with an operational auto -igniter by or before May 1, 2016, or after the next combustion device planned shutdown, whichever comes first. COLORADO Air Pollution Control Division Department of Public Health 5 Environment Page 12 of 37 33.E & O1 -$ gl • '•ehyr ation unit covered by this permit is subject to the equi m gists in R lation Number 7, Section XVII.D.3. Beginning May 201 still vents anvents from any flash separator or flash tank on a glycol natural gas dehydrator located at an oil and gas exploration and production operation, natural gas compressor station, or gas -processing plant subject to control requirements pursuant to Section XVII.D.4., shall reduce uncontrolled actual emissions of hydrocarbons by at least 95% on a rolling twelve-month basis through the use of a condenser or air pollution control equipment. 34. Points O15 Et O16: The glycol dehydration unit at this facility is subject to National Emissions Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities, Subpart HH. This facility shall be subject to applicable area source provisions of this regulation, as stated in 40 C.F.R Part 63, Subpart A and HH. (Regulation Number 8, Part E, Subpart A and HH) COLORADO Air Pollution Control Division 6lic } Sea42n & Envaon;nen Page 13 of 37 C H Area Source bl = . rem rem utside UA/UC boundary §63.760 - Applicability and designation of affected source §63.760 (f) - The owner or operator of an affected major source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(1) and (f)(2) of this section. The owner or operator of an affected area source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(3) through (f)(6) of this section. • $63.764 - General Standards §63.764 (d)(2) -Each owner or operator of an area source not located in a UA plus offset and UC boundary (as defined in §63.761) shall comply with the provisions specified in paragraphs (d)(2(i) through (iii) of this section. §63.764 (d)(2)(i) - Determine the optimum glycol circulation rate using the following equation: LOP, 3.0 gal TEG * F * (I — O) =1.15* lb H2O 24hr/day Where: LOPT = Optimal circulation rate, gal/hr. F = Gas flowrate (MMSCF/D) I = Inlet water content (lb/MMSCF) 0 = Outlet water content (lb/MMSCF) 3.0 = The industry accepted rule of thumb for a TEG-to water ratio (gal TEG/lbH2O) 1.15 = Adjustment factor included for a margin of safety. §63.764 (d)(2)(ii) - Operate the TEG dehydration unit such that the actual glycol circulation rate does not exceed the optimum glycol circulation rate determined in accordance with paragraph (d)(2)(i) of this section. If the TEG dehydration unit is unable to meet the sales gas specification for moisture content using the glycol circulation rate determined in accordance with paragraph (d)(2)(i), the owner or operator must calculate an alternate circulation rate using GRI-GLYCalcTM, Version 3.0 or higher. The owner or operator must document why the TEG dehydration unit must be operated using the alternate circulation rate and submit this documentation with the initial notification in accordance with §63.775(c)(7). §63.764 (d)(2)(iii) - Maintain a record of the determination specified in paragraph (d)(2)(ii) in accordance with the requirements in §63.774(f) and submit the Initial Notification in accordance with the requirements in §63.775(c)(7). If operating conditions change and a modification to the optimum glycol circulation rate is required, the owner or operator shall prepare a new determination in accordance with paragraph (d)(2)(i) or (ii) of this section and submit the information specified under §63.775(c)(7)(ii) through (v). COLORADO Air Pollution Control Division 62partment d Public Health & Enrlaarmeni Page 14 of 37 C H Area Source :remutside UA/UC boundary §63.774 (b) - Except as specified in paragraphs (c), (d), and (f) of this section, each owner or operator of a facility subject to this subpart shall maintain the records specified in paragraphs (b)(1) through (11) of this section §63.774 (b)(1) §63.774 (b)(1) - The owner or operator of an affected source subject to the provisions of this subpart shall maintain files of all information (including all reports and notifications) required by this subpart. The files shall be retained for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report or period. §63.774 (b)(1)(i) - All applicable records shall be maintained in such a manner that they can be readily accessed. §63.774 - Recordkeeping 563.774 (b)(1)(ii) - The most recent 12 months of records shall be retained Requirements on site or shall be accessible from a central location by computer or other means that provides access within 2 hours after a request. §63.774 (b)(1)(iii) - The remaining 4 years of records may be retained offsite. §63.774 (b)(1)(iv) - Records may be maintained in hard copy or computer - readable form including, but not limited to, on paper, microfilm, computer, floppy disk, magnetic tape, or microfiche. §63.774 (f) - The owner or operator of an area source not located within a UA plus offset and UC boundary must keep a record of the calculation used to determine the optimum glycol circulation rate in accordance with §63.764(d)(2)(i) or §63.764(d)(2)(ii), as applicable. COLORADO Air Pollution Control Division tmpamment of Pubk He hh b Fn dranment Page 15 of 37 §63.775 - Reporting Requirements dept a •rovided in paragraph (c)(8), each owner or operator ce subjt to this subpart shall submit the information listed (1) o `.04°" section. If the source is located within a UA plus offset and UC boundary, the owner or operator shall also submit the information listed in paragraphs (c)(2) through (6) of this section. If the source is not located within any UA plus offset and UC boundaries, the owner or operator shall also submit the information listed within paragraph (c)(7). 863.775 (c)(1) - The initial notifications required under §63.9(b)(2) not later than January 3, 2008. In addition to submitting your initial notification to the addressees specified under §63.9(a), you must also submit a copy of the initial notification to EPA's Office of Air Quality Planning and Standards. Send your notification via e-mail to CCG-ONG@EPA.GOV or via U.S. mail or other mail delivery service to U.S. EPA, Sector Policies and Programs Division/Coatings and Chemicals Group (E143-01), Attn: Oil and Gas Project Leader, Research Triangle Park, NC 27711. 563.775 (c)(7) - The information listed in paragraphs (c)(1)(i) through (v) of this section. This information shall be submitted with the initial notification. §63.775 (c)(7)(i) - Documentation of the source's location relative to the nearest UA plus offset and UC boundaries. This information shall include the latitude and longitude of the affected source; whether the source is located in an urban cluster with 10,000 people or more; the distance in miles to the nearest urbanized area boundary if the source is not located in an urban duster with 10,000 people or more; and the names of the nearest urban duster with 10,000 people or more and nearest urbanized area. §63.775 (c)(7)(ii) - Calculation of the optimum glycol circulation rate determined in accordance with §63.764(d)(2)(i). §63.775 (c)(7)(iii) - If applicable, documentation of the alternate glycol circulation rate calculated using GRI-GLYCalcTM, Version 3.0 or higher and documentation stating why the TEG dehydration unit must operate using the alternate glycol circulation rate. §63.775 (c)(7)(iv) - The name of the manufacturer and the model number of the glycol circulation pump(s) in operation. 563.775 (c)(7)(v) - Statement by a responsible official, with that official's name, title, and signature, certifying that the facility will always operate the glycol dehydration unit using the optimum circulation rate determined in accordance with §63.764(d)(2)(i) or §63.764(d)(2)(ii), as applicable. §63.775 (f) - Notification of process change. Whenever a process change is made, or a change in any of the information submitted in the Notification of Compliance Status Report, the owner or operator shall submit a report within 180 days after the process change is made or as a part of the next Periodic Report as required under paragraph (e) of this section, whichever is sooner. The report shall include: §63.775 (f)(1) - A brief description of the process change; COLORADO Air Pollution Control Division invrnnmax ............ Page 16 of 37 [h; bl_ rem Area Source utside UA/UC boundary 863.775 (f)(2) - A description of any modification to standard procedures or quality assurance procedures §63.775 (f)(3) - Revisions to any of the information reported in the original Notification of Compliance Status Report under paragraph (d) of this section; and 863.775 (f)(4) - Information required by the Notification of Compliance Status Report under paragraph (d) of this section for changes involving the addition of processes or equipment. 35. Point 017: All hydrocarbon liquid loading operations, regardless of size, shall be designed, operated and maintained so as to minimize leakage of volatile organic compounds to the atmosphere to the maximum extent practicable. (Regulation Number 3, Part B, Section III.E.) 36. Point 017: The owner or operator shall follow loading procedures that minimize the leakage of VOCs to the atmosphere including, but not limited to (Regulation Number 3, Part B, Section III.E.): a. The owner or operator shall inspect onsite loading equipment to ensure that hoses, couplings, and valves are maintained to prevent dripping, leaking, or other liquid or vapor loss during loading and unloading. The inspections shall occur at least monthly. Each inspection shall be documented in a log available to the Division on request. b. Inspect pressure relief devices (PRD) annually for proper operation and replace as necessary. PRDs shall be set to release at a pressure that will ensure flashing, working and breathing losses are not vented through the PRD under normal operating conditions. c. Document annual inspections of the PRD with an indication of status, a description of any problems found, and their resolution. d. Install and operate the vapor collection and return equipment to collect vapors during loading of tank compartments of outbound transport trucks. e. Include devices to prevent the release of vapor from vapor recovery hoses not in use. f. Use operating procedures to ensure that hydrocarbon liquid cannot be transferred unless the vapor collection equipment is in use. g. Operate all recovery and disposal equipment at a back -pressure less than the pressure relief valve setting of transport vehicles. 37. Points 018: On a monthly basis, the owner or operator shall monitor and record the total number of pig blowdown events. By the end of each month, the total number of COLORADO Air Pollution Control Division Department of Puhho. Wean b Environment Page 17 of 37 prey anus months' data shall be calculated, and a new calcu ted and recorded based on the previous twelve months •ata. he owner or operator shall use monthly records to demonstrate compliance with the process limits and to calculate emissions as described in this permit. 38. Point 018: The owner or operator shall calculate VOC emissions from each event using the volume of gas estimated in accordance with the conditions of this permit and the most recent representative gas analysis. 39. Point 019: Fugitive component leaks at this natural gas compressor station are subject to the Leak Detection and Repair (LDAR) program requirements, including but not limited to: monitoring, repair, re -monitoring, recordkeeping and reporting contained in Regulation Number 7, Section XII.L. In addition, the operator shall comply with the General Provisions contained in Regulation Number 7, Section XII.C. 40. Point 019: Fugitive component leaks at this natural gas compressor station are subject to the Leak Detection and Repair (LDAR) program requirements, including but not limited to: monitoring, repair, re -monitoring, recordkeeping and reporting contained in Regulation Number 7, Section XVII.F. In addition, the operator shall comply with the General Provisions contained in Regulation Number 7, Section XVII.B.1. 41. Point 021: On a monthly basis, the owner or operator shall monitor and record the total number of turbine compressor blowdown events. By the end of each month, the total number of turbine compressor blowdown events 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. The owner or operator shall use monthly records to demonstrate compliance with the process limits and to calculate emissions as described in this permit.. 42. Point 021: The owner or operator shall calculate VOC emissions from each event using the volume of gas estimated in accordance with the conditions of this permit and the most recent representative gas analysis. OPERATING R MAINTENANCE REQUIREMENTS 43. Points 012, 013, a 014: At all times during normal operation, the owner or operator shall operate the turbine in SoLoNOx mode. On a daily basis, the owner or operator shall monitor and record the status of the SoLoNOx mode, including records of when the unit is not operating in SoLoNOx mode. These records shall be made available to the Division upon request. Normal operation shall be defined as all periods of operation except for startup, shutdown, or malfunction events. 44. Points 015 Ft 016: Upon startup of these points, the owner or operator shall follow the most recent operating and maintenance (OEM) 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.) COMPLIANCE TESTING AND SAMPLING Initial Testing Requirements 45. Points 012, 013, £t 014: These turbines are subject to the initial testing requirements of 40 C.F.R. Part 60, Subpart KKKK as referenced in this permit. COLORADO Air Pollution Control Division Department of Public Health b Environment Page 18 of 37 46. • • 01 • - o e 4 or o t �: rator shall complete the initial extended wet gas and ei ty days (180) of the latter of commencement of operation or issuance o t is permit. The owner or operator shall use this analysis to calculate actual emissions, as prescribed in the Emission Limitation and Records section of this permit, to verify initial compliance with the emission limits. The owner or operator shall submit the analysis and the emission calculation results to the Division as part of the self -certification process. (Reference: Regulation Number 3, Part B, Section III.E.) 47. Point 019: Within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit, the owner or operator shall complete the initial extended gas analysis of gas samples that are representative of volatile organic compound (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas analysis 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 analysis and emission calculations to the Division as part of the self -certification process to ensure compliance with emissions limits. 48. Point 019: Within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit, 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. 49. Points 018 &t 021: The owner/operator shall complete an initial site specific extended gas analysis ("Analysis") within one hundred and eighty days (180) after commencement of operation or issuance of this permit, whichever comes later, of the natural gas vented during the blowdown events covered by this permit in order to verify the VOC content (weight fraction) of this emission stream. Results of the Analysis shall be used to calculate site -specific emission factors for the pollutants referenced in this permit (in units of lb/blowdown event) using Division approved methods. Results of the Analysis shall be submitted to the Division as part of the self -certification and must demonstrate the emissions factors established through the Analysis are less than or equal to, the emissions factors submitted with the permit application and established herein in the "Notes to Permit Holder" for this emissions point. If any site specific emissions factor developed through this Analysis is greater than the emissions factors submitted with the permit application and established in the "Notes to Permit Holder" the operator shall submit to the Division within 60 days, or in a timeframe as agreed to by the Division, a request for permit modification to address this/these inaccuracy(ies). Periodic Testing Requirements 50. Points 012, 013, a 014: The combustion turbines are subject to the periodic testing requirements of 40 C.F.R. Part 60, Subpart KKKK, as referenced in this permit. 51. Points 012, 013, Et 014: The operator shall conduct, at a minimum, semi-annual portable analyzer monitoring of the turbine exhaust outlet emissions of nitrogen oxides (NO.) and carbon monoxide (CO) to monitor compliance with the emissions limits. After two (2) consecutive compliant semi-annual tests, the frequency may be reduced to annually. If any of the annual tests fails, the testing frequency shall return to semi- annual until two (2) consecutive compliant semi-annual tests are achieved. Results of all tests conducted shall be kept on site and made available to the Division upon request. COLORADO Air Pollution Control Division Dapattment of Public fear b Enviroronent Page 19 of 37 52. a 01- o e or o rator shall complete an extended wet gas analysis to e ale of - d dratiunit on an annual basis. Results of the wet gas analysis s all •e use to ca culate emissions of criteria pollutants and hazardous air pollutants per this permit and be provided to the Division upon request. 53. Points 018 £t 021: The owner or operator shall complete an extended gas analysis of the natural gas vented during the blowdown events covered by this permit on an annual basis. Results of the gas analysis shall be used to determine VOC content (weight fraction) of the emissions stream calculate to emissions of VOC per this permit and be provided to the Division upon request. 54. Point 019: On an annual basis, the owner or operator shall complete an extended gas analysis of gas samples that are representative of volatile organic compounds (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas analysis shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. POINTS 015 Et 016: ALTERNATE OPERATING SCENARIOS 55. The electric glycol pumps may be replaced with another electric glycol pump in accordance with the requirements of Regulation 3, Part A, Section IV.A and without applying for a revision to this permit or obtaining a new construction permit. The maximum glycol recirculation rate of a replacement pump shall not exceed the glycol recirculation rate as authorized in this permit. 56. The owner or operator shall maintain a log on -site or at a local field office to contemporaneously record the start and stop dates of any pump replacement, the manufacturer, model number, serial number and capacity of the replacement pump. 57. All pump replacements installed and operated per the alternate operating scenarios authorized by this permit must comply with all terms and conditions of this construction permit. ADDITIONAL REQUIREMENTS 58. All previous versions of this permit are cancelled upon issuance of this permit. 59. This permit replaces the following points, which are cancelled upon issuance of this permit. The owner or operator shall submit a cancellation notice for the following equipment with the Notice of Startup for the new equipment in this permit. Existing Permit No. Existing Emission Point Facility Equipment ID Description 97WE0349 123/0035/001 C-102 Waukesha L70425I, S/N: 368176, 4SRB internal combustion reciprocating engine 123/0035/002 C-103 Waukesha L70425I, S/N: 383730, 4SRB internal combustion reciprocating engine COLORADO Mr Pollution Control Division rtment of Public Heath b Environment Page 20 of 37 a 12 4 '03 C104 Waukesha L7042SI, S/N: 230355, 4SRB internal combustion reciprocating engine 123/0035/004 C-142 Waukesha L3521GSI, S/N: 278153, 4SRB internal combustion reciprocating engine 123/0035/006 TEG DENY Triethylene glycol (TEG) natural gas dehydration unit. 123/0035/008 FUG Fugitive emissions from equipment leaks 60. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, II.C) a. Annually by April 30th whenever a significant increase in emissions occurs as follows: For any criteria pollutant: For sources emitting less than 100 tons per year, a change in actual emissions of five (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 e. No later than 30 days before the existing APEN expires. f. Points 012, 013, a 014: Within 14 calendar days of commencing operation of a permanent replacement turbine 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 turbine, the appropriate APEN filing fee and a cover letter COLORADO Air Pollution Control Division Department of Pubtx Heath & CmPonment Page 21 of 37 ner operator is exercising an alternative -operating lling a permanent replacement turbine. Submittal of an up ate PEis a so required for replacement of components if such replacement results in a change of serial number. 61. Points 012, 013, £t 014: MACT Subpart YYYY - National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines requirements shall apply to this source at any such time that this source becomes a major source of hazardous air pollutants (HAP) solely by virtue of a relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of that Subpart on the date as stated in the rule as published in the Federal Register. (Regulation Number 8, Part E) 62. Points 015 Ft 016: MACT Subpart HH - National Emission Standards for Hazardous Air Pollutants for TEG Dehydrators requirements shall apply to this source at any such time that this source becomes a major source of hazardous air pollutants (HAP) solely by virtue of a relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of that Subpart on the date as stated in the rule as published in the Federal Register. (Regulation Number 8, Part E) 63. The requirements of Colorado Regulation Number 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 (Regulation Number 3, Part D, Section V.A.7.B). GENERAL TERMS AND CONDITIONS 64. 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 Number 3, Part B, Section II.B. upon a request for transfer of ownership and the submittal of a revised APEN and the required fee. 65. 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 Number 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. 66. This permit is issued in reliance upon the accuracy and completeness of information supplied by the owner or operator 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 owner or operator or owner or operator's agents. It is valid only for the equipment and operations or activity specifically identified on the permit. COLORADO Air Pollution Control Division 9eoartment of Public Health b Environment Page 22 of 37 67. rwis the general and specific conditions contained in mined the APCD to be necessary to assure compliance with the provisions o ection 25- 4.5(7)(a), C.R.S. 68. 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 owner or operator, or the Division revokes a permit, the owner or operator of a source may request a hearing before the AQCC for review of the Division's action. 69. 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. 70. 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: Betsy Gillard, PE Permit Engineer Permit History Issuance Date Description Initial Approval February 23,1998 Issued to Duke Energy Field Services, LP Final Approval December 05, 2002 Cancel operating permit. Issuance 1 August 26, 2010 APEN-exempt/permit-exempt source is now APEN- required/permit-required at a synthetic minor source. Modification to facility -wide permit. Issuance 2 November 16, 2017 Issued to DCP Operating Company, LP Modification to increase component counts and emission limit for Point 008. Updated engine serial numbers for Points 001, 002, and 004 to reflect permanent AOS replacements. Issued as Final Approval Issuance 3 This Issuance Issued as initial approval. Removed points 001, 002, 003, 004, 006, 008. CDPHE COLORADO Air Pollution Control Division Department of Public ii€eattth b Environment Page 23 of 37 In '•° Description Added new turbines under points 012, 013, a 014. Added new glycol dehydration units under points 015 lit 016. Added new pressurized loadout emissions under point 017. Added blowdown emissions for pigging events (point 018) and turbine blowdowns (point 021). Added new fugitive emissions under point 019. COLORADO Air Pollution Control Division S}enartment of Public Ffeaha 6 Environment Page 24 of 37 Notesmit issuance: 1) T = -q �� -� �.ay 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 owner or operator providing there is no exceedance of any specific emission control regulation or any ambient air quality standard. A revised air pollution emission notice (APEN) and complete 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, Affirmative Defense Provision for Excess Emissions During Malfunctions. The owner or operator 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: https://www.colorado.gov/pacific/cdphe/aocc-regs 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. Facility Equipment ID AIRS Point Pollutant CAS # Uncontrolled Emissions (lb/yr) Controlled Emissions (lb/yr) TURB-1 012 Acetaldehyde 75070 27 27 Acrolein 107028 5 5 Benzene 71432 9 9 Toluene 108883 87 87 Formaldehyde 5000 478 478 TURB-2 013 Acetaldehyde 75070 27 27 Acrolein 107028 5 5 Benzene 71432 9 9 Toluene 108883 87 87 Formaldehyde 5000 478 478 TURB-3 014 Acetaldehyde 75070 27 27 Acrolein 107028 5 5 Benzene 71432 9 9 DPHE LI COLORADO Air Pollution Control Division rtment of Pu@8c Mean & Environment Page 25 of 37 o: ene 108883 87 87 - :lde 5000 478 478 D-1 015 Benzene 71432 115,964 6,839 Toluene 108883 107,133 6,340 Ethylbenzene 100414 3,111 185 Xylenes 1330207 31,860 1,892 n -Hexane 110543 25,862 1,186 2,2,4- Trimethylpentane 540841 165 8 D-2 016 Benzene 71432 153,198 9,035 Toluene 108883 141,160 8,353 Ethylbenzene 100414 4,093 243 Xylenes 1330207 42,567 2,528 n -Hexane 110543 33,503 1,529 2,2,4- Trimethylpentane 540841 212 10 L-1 017 Benzene 71432 78 78 Toluene 108883 211 211 Ethylbenzene 100414 25 25 Xylenes 1330207 158 158 n -Hexane 110543 597 597 2,2,4- Trimethylpentane 540841 53 53 PIG 018 Benzene 71432 26 26 Toluene 108883 20 20 Ethylbenzene 100414 1 1 Xylenes 1330207 5 5 n -Hexane 110543 206 206 FUG -1 019 Benzene 71432 17 17 Toluene 108883 13 13 Ethylbenzene 100414 1 1 Xylenes 1330207 8 8 COLORADO Air Pollution Control Division CMaartment cf Public t€eat£n b Envuonrnem Page 26 of 37 ,2,4 Trimethylpentane 110543 131 131 540841 2 2 TURB-BD 021 Benzene 71432 37 37 Toluene 108883 28 28 Ethylbenzene 100414 1 1 Xylenes 1330207 6 6 n -Hexane 110543 279 279 2,2,4- Trimethylpentane 540841 3 3 Note: All non -criteria reportable pollutants in the table above with uncontrolled emission rates above 250 pounds per year (lb/yr) are reportable and may result in annual emission fees based on the most recent Air Pollution Emission Notice. 5) The emission levels contained in this permit are based on the following emission factors: Points 012, 013, 8 014: Process 01: Turbine emissions during steady state operations CAS Pollutant Emission Factors - Uncontrolled Source lb/MMBtu PM2.5 6.60E-03 AP -42 Chapter 3 Table 3.1-2a PM10 6.60E-03 AP -42 Chapter 3 Table 3.1-2a NOx 5.45E-02 Manufacturer CO 5.53E-02 Manufacturer VOC 2.10E-03 AP -42 Chapter 3 Table 3.1-2a 50000 Formaldehyde 7.10E-04 AP -42 Chapter 3 Table 3.1-3 Note: Emission factors are based on a heat input rate of 76.81 MMBtu/hr, a fuel heat value of 999 Btu/scf and 8,760 hours of operation a year. Actual emissions are calculated by multiplying the emission factors in the table above by the gas combusted as fuel by the turbine as measured by flow meter. Process 02: Turbine start-up emissions CAS Pollutant Emission Factors - Uncontrolled Source lb/event NOx 1.0 Manufacturer CO 88.0 Manufacturer VOC 18.0 Manufacturer COLORADO Air Pollution Control Division artmcnt of Public}lea„ n b Envronnrent Page 27 of 37 ec' emisfactors for turbine start-ups are based on 10 minute ns are c culated by multiplying the emission factor in the table f tur. - ` tart -up events. Process 03: Turbine shutdown emissions CAS Pollutant Emission Factors - Uncontrolled Source lb/event NOx 1.0 Manufacturer CO 62.0 Manufacturer VOC 8.0 Manufacturer Note: The manufacturer provided emission factors for turbine shutdowns are based on 10 minute shutdown events. Actual emissions are calculated by multiplying the emission factor in the table above by the recorded number of turbine shutdown events. Points 015 £t 016: The emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. Controlled flash tank emissions are based on 100% control efficiency when emissions are routed to the VRU and 95% control when emissions are routed to the ECD during VRU downtime. The VRU has a maximum of 5% annual downtime. Controlled still vent emissions are based on 95% control efficiency when emissions are routed to the ECD and 0% control when emissions are routed to the atmosphere during ECD downtime. The ECD has a maximum of 1% annual downtime. The following table summarizes the control efficiency for each scenario: Control Scenario VOC Control Efficiency Still vent emissions routed to the ECD. 95% Still vent emissions routed to atmosphere during ECD downtime. 0% Flash tank emissions routed to the VRU and recycled to the plant inlet. 100% Flash tank emissions routed to the ECD during VRU downtime. 95% Total actual combustion emissions are based on the sum of the emissions for the still vent and flash tank controlled by the ECD and the combustion of ECD pilot and assist fuel. Total combustion emissions are based on the following emission factors: Still Vent Controlled by the ECD: CAS # Pollutant Uncontrolled Emission Factors lb/MMBtu Source NOx 0.068 AP -42 Chapter 13.5 Industrial Flares CO 0.31 Note: Actual emissions are calculated based on the heat content and waste gas flow rate from the condenser vent stream in the monthly GlyCalc report and the hours per month the still vent waste gas COLORADO Air Pollution Control Division bti11 Page 28 of 37 Point 015: The permitted 1,525 Btu/scf. Point 016: The permitted 1,521 Btu/scf. Flash Tank Controlled e t is c ulated on a monthly basis using the composition of the hly Gly c report and the higher heating value of each component. combustion emissions are based on a still vent waste gas heating value of combustion emissions are based on a still vent waste gas heating value of by the ECD: CAS # Pollutant Uncontrolled Emission Factors lb/MMBtu Source NOx 0.068 AP -42 Chapter 13.5 Industrial Flares CO 0.31 Note: Actual emissions are calculated based on the heat content and waste gas flow rate from the flash tank off gas stream in the monthly GlyCalc report and the hours per month the flash tank waste gas is routed to the ECD. The heat content is calculated on a monthly basis using the composition of the flash tank off gas stream in the monthly GlyCalc report and the higher heating value of each component. Point 015: The permitted combustion emissions are based on a flash tank waste gas heating value of 1,483 Btu/scf. Point 016: The permitted combustion emissions are based on a flash tank waste gas heating value of 1,487 Btu/scf. Combustion of ECD Pilot/Assist Fuel: AIRS Point Pollutant Uncontrolled Emission Factors lb/MMscf Source 015 NOx 67.93 AP -42 Chapter 13.5 Industrial Flares CO 309.70 016 NOx 67.93 CO 309.70 Note: The permitted combustion emissions are based on a heating value of 999 Btu/scf. The pilot fuel and assist gas flow rates are constant. Actual emissions are calculated by multiplying the emissions factors in the table above by the total fuel flow of the pilot gas and assist gas routed to the ECD. Point 015: Permitted emissions are based on a constant pilot fuel flow rate of 50 scf/hr and a constant assist fuel flow rate of 1,700 scf/hr. Point 016: Permitted emissions are based on a constant pilot fuel flow rate of 65 scf/hr and a constant assist fuel flow rate of 1,700 scf/hr. Point 017: CAS # Pollutant Uncontrolled Emission Factors lb/loadout Source VOC 1.0552 Engineering calculation 110543 n -Hexane 6.96E-02 COLORADO Air Pollution Control Division parallel of Public Heahh b Environment Page 29 of 37 Point 018: n iquid n d vapor line volumes of 0.0218 ft3/loadout venting ssions a calculated by multiplying the number of loadout events by to ve. Process VOC content (%wt.) Uncontrolled Emission Factors (lb/event) Source Receiver 12" 28.7 11.90 Engineering calculation Receiver 8" 28.7 3.50 Launcher 16" 28.7 44.09 Point 019: Component Gas Service Heavy Oil Light Oil Water/Oil Service Connectors 213 --- 9,208 --- Flanges 105 --- 1,320 --- Open-ended Lines 0 --- 0 --- Pump Seals 0 --- 18 --- Valves 248 --- 3,185 --- Other` 18 --- 105 --- `Other equipment type inc udes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms, hatches, instrument meters, polish rods and vents Weight % Gas Service Heavy Oil Light Oil SWater/Oil ervi Service VOC 28.71 --- 100 --- Benzene 0.051 --- 0.177 --- Toluene 0.039 --- 0.134 --- Ethylbenzene 0.001 --- 0.003 --- Xylenes 0.022 --- 0.076 --- n-hexane 0.392 --- 1.366 --- 2,2,4-Trimethylpentane 0.004 --- 0.013 --- TOC Emission Factors (kg/hr-component): Component Gas Service Heavy Oil Light Oil Water/Oil Connectors 1.0E-05 7.5E-06 9.7E-06 1.0E-05 Flanges 5.7E-06 3.9E-07 2.4E-06 2.9E-06 Open-ended Lines 1.5E-05 7.2E-06 1.4E-05 3.5E-06 Pump Seals 3.5E-04 NA 5.1E-04 2.4E-05 Valves 2.5E-05 8.4E-06 1.9E-05 9.7E-06 COLORADO Air Pollution Control Division Department of Pear.' Health & Environment Page 30 of 37 they 1..^R. - 4 3.2E-05 1.1E-04 5.9E-05 S u e: EP e Emission limits are derived by multiplying the equipment counts in the table above by a safety factor of 1.4. Compliance with emissions limits in this permit will be demonstrated by using the TOC emission factors listed in the table above with representative component counts, multiplied by the VOC content from the most recent extended gas analysis. Point 021: CAS Weight% of Gas Pollutant Emission Factors - Uncontrolled Source lb/blowdown event 28.7 VOC 282.46 Mass Balance 110543 0.393 n -Hexane 3.87 Note: The emission factors for turbine compressor blowdown events are based on a compressor volume of 0.016268 MMscf, a representative inlet gas analysis obtained from the Troudt facility inlet on 11/04/16 and the EPA Emission Inventory Improvement Program Publication: Volume II, Chapter 10 - Displacement Equation (10.4-3). Actual emissions are calculated by multiplying the emission factor in the table above by the recorded number of turbine compressor blowdown events. 6) In accordance with C.R.S. 25-7-114.1, each Air Pollutant Emission Notice (APEN) associated with this permit is valid for a term 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. 7) Point 019: This source is subject to 40 CFR, Part 60, Subpart OOOOa—Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification or Reconstruction Commenced After September 18, 2015 (See June 3, 2016 Federal Register posting - effective August 02, 2016). 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: https://www.gpo.gov/fdsys/pkg/FR-2016-06- 03/pdf/2016-11971.pdf 8) This facility is classified as follows: Applicable Requirement Status Operating Permit Synthetic Minor Source of: VOC, benzene, toluene, xylenes, n -hexane, and total HAPs NANSR Synthetic Minor Source of: VOC MACT HH Area Source: Applicable COLORADO Air Pollution Control Division Apartment of Public Health b Environment Page 31 of 37 NSPS 0000a Applicable MACT YYYY Area Source: Not 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://ecfr.gpoaccess.gov/ Part 60: Standards of Performance for New Stationary Sources NSPS 60.1 -End Subpart A - Subpart KKKK NSPS Part 60, Appendixes Appendix A - Appendix I 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 YYYY MACT 63.6580-63.8830 Subpart ZZZZ - Subpart MMMMM MACT 63.8980 -End Subpart NNNNN - Subpart XXXXXX COLORADO Air Pollution Control Division of Public Health b Environment Page 32 of 37 ATT { _ HMENT A: AL TIVERATING SCENARIOS TURBINES WITHOUT CONTINUOUS EMISSIONS MONITORING August 16, 2011 1. Routine Turbine Component Replacements The following physical or operational changes to the turbines in this permit are not considered a modification for purposes of NSPS GG, major stationary source NSR/PSD, or Regulation No. 3, Part B. Note that the component replacement provisions apply ONLY to those turbines subject to NSPS GG. Neither pre-GG turbines nor post GG turbines (i.e. KKKK turbines) can use those provisions. 1) Replacement of stator blades, turbine nozzles, turbine buckets, fuel nozzles, combustion chambers, seals, and shaft packings, provided that they are of the same design as the original. 2) Changes in the type or grade of fuel used, if the original gas turbine installation, fuel nozzles, etc. were designed for its use. 3) An increase in the hours of operation (unless limited by a permit condition) 4) Variations in operating loads within the engine design specification. 5) Any physical change constituting routine maintenance, repair, or replacement. Turbines undergoing any of the above changes are subject to all federally applicable and state only requirements set forth in this permit (including monitoring and record keeping). If replacement of any of the components listed in (1) or (5) above results in a change in serial number for the turbine, a letter explaining the action as well as a revised APEN and appropriate filing fee shall be submitted to the Division within 30 days of the replacement. Note that the repair or replacement of components must be of genuinely the same design. Except in accordance with the Alternate Operating Scenario set forth below, the Division does not consider that this allows for the entire replacement (or reconstruction) of an existing turbine with an identical new one or one similar in design or function. Rather, the Division considers the repair or replacements to encompass the repair or replacement of components at a turbine with the same (or functionally similar) components. 2. Alternative Operating Scenarios The following Alternative Operating Scenario (AOS) for the temporary and permanent replacement of combustion turbines and turbine components 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 COLORADO Air Pollution Control Division meat of Public Health b Environment Page 33 of 37 pr orporates and shall be considered a Construction nent replacement performed in accordance with t is LOS, an' the owner or operator s a l be allowed to perform such turbine or turbine component replacement without applying for a revision to this permit or obtaining a new Construction Permit. 2.1 Turbine Replacement The following AOS is incorporated into this permit in order to deal with a turbine breakdown or periodic routine maintenance and repair of an existing onsite turbine that requires the use of a temporary replacement turbine. "Temporary" is defined as in the same service for 90 operating days or less in any 12 month period. "Permanent" 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 turbine is in operation. If the turbine 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. Any permanent turbine replacement under this AOS shall result in the replacement turbine being considered a new affected facility for purposes of NSPS and shall be subject to all applicable requirements of that Subpart including, but not limited to, any required Performance Testing. All replacement turbines are subject to all federally applicable and state -only requirements set forth in this permit (including monitoring and record keeping). The results of all tests and the associated calculations required by this AOS shall be submitted to the Division within 30 calendar days of the test or within 60 days of the test if such testing is required to demonstrate compliance with the NSPS requirements. Results of all tests shall be kept on site for five (5) years and made available to the Division upon request. The owner or operator shall maintain a log on -site and contemporaneously record the start and stop date of any turbine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the turbine (s) that are replaced during the term of this permit, and the manufacturer, model number, horsepower, and serial number of the replacement turbine. 2.1.1 The owner or operator may temporarily replace an existing turbine that is covered by this permit with a turbine that is the exact same make and model as the existing turbine without modifying this permit, so long as the temporary replacement turbine complies with the emission limitations for the existing permitted turbine and other requirements applicable to the original turbine. Measurement of emissions from the temporary replacement turbine shall be made as set forth in section 2.2. 2.1.2 The owner or operator may permanently replace the existing turbine that is covered by this permit with a turbine that is the exact same make and model as COLORADO Air Pollution Control Division party nt of Public Heeita fi Environment Page 34 of 37 hout r odifying this permit so long as the permanent t .m corn s with the emission limitations and other requirements app ica• e to t e original turbine as well as any new applicable requirements for the replacement turbine. Measurement of emissions from the temporary replacement turbine shall be made as set forth in section 2.2. 2.1.3 An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and serial number and horsepower of the permanent replacement turbine shall be filed with the Division for the permanent replacement turbine within 14 calendar days of commencing operation of the replacement turbine. The APEN shall be accompanied by the appropriate APEN filing fee, a cover letter explaining that the owner or operator is exercising an alternative operating scenario and is installing a permanent replacement turbine. This AOS cannot be used for permanent turbine replacement of a grandfathered or permit exempt turbine or a turbine that is not subject to emission limits. The owner or operator 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 turbine replacement. 2.2 Portable Analyzer Testing Note: In some cases there may be conflicting and/or duplicative testing requirements due to overlapping Applicable Requirements. In those instances, please contact the Division Field Services Unit to discuss streamlining the testing requirements. Note that the testing required by this Condition may be used to satisfy the periodic testing requirements specified by the permit for the relevant time period (i.e. if the permit requires quarterly portable analyzer testing, this test conducted under the AOS will serve as the quarterly test and an additional portable analyzer test is not required for another three months). The owner or operator may conduct a reference method test, in lieu of the portable analyzer test required by this Condition, if approved in advance by the Division. The owner or operator shall measure nitrogen oxide (NOX) and carbon monoxide (CO) emissions in the exhaust from the replacement turbine using a portable flue gas analyzer within seven (7) calendar days of commencing operation of the replacement turbine. All portable analyzer testing required by this permit shall be conducted using the most current version of the Division's Portable Analyzer Monitoring Protocol as found on the Division's website. Results of the portable analyzer tests shall be used to monitor the compliance status of this unit. For comparison with an annual (tons/year) or short term (lbs/unit of time) emission limit, the results of the tests shall be converted to a lb/hr basis and multiplied by the allowable operating hours in the month or year (whichever applies) in order to monitor compliance. If a source is not limited in its hours of operation the test results will be multiplied by the maximum number of hours in the month or year (8760), whichever applies. COLORADO Air Pollution Control Division rtment of Public Health & Environment Page 35 of 37 imit at is either input based (lb/mmBtu), output based (� sL ok coeatib -d (pp d @ 15% O2) that the existing unit is currently subject to or the rep acement turbine will be subject to, the results of the test shall be converted to the appropriate units as described in the above -mentioned Portable Analyzer Monitoring Protocol document. If the portable analyzer results indicate compliance with both the NOX and CO emission limitations, in the absence of credible evidence to the contrary, the source may certify that the turbine is in compliance with both the NOX and CO emission limitations for the relevant time period. Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if the portable analyzer results fail to demonstrate compliance with either the NOX or CO emission limitations, the turbine will be considered to be out of compliance from the date of the portable analyzer test until a portable analyzer test indicates compliance with both the NOX and CO emission limitations or until the turbine is taken offline. 2.3 Applicable Regulations for Permanent Turbine Replacements 2.3.1 NSPS for Stationary Gas Turbines: 40 CFR 60, Subpart GG §60.330 Applicability and designation of affected facility. (a) The provisions of this subpart are applicable to the following affected facilities: All stationary gas turbines with a heat input at peak load equal to or greater than 10.7 gigajoules (10 million Btu) per hour, based on the lower heating value of the fuel fired. (b) Any facility under paragraph (a) of this section which commences construction, modification, or reconstruction after October 3, 1977, is subject to the requirements of this part except as provided in paragraphs (e) and (j) of §60.332. A Subpart GG applicability determination as well as an analysis of applicable Subpart GG monitoring, recordkeeping, and reporting requirements for the permanent turbine replacement shall be included in any request for a permanent turbine 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 commence construction date for purposes of determining the applicability of NSPS GG requirements). 2.3.2 NSPS for Stationary Combustion Turbines: 40 CFR 60, Subpart KKKK §60.4305 Does this subpart apply to my stationary combustion turbine? (a) If you are the owner or operator of a stationary combustion turbine with a heat input at peak load equal to or greater than 10.7 gigajoules (10 MMBtu) per hour, based COLORADO Air Pollution Control Division torrent of Public Hearth b 6nvaarnnent Page 36 of 37 f the j el, which commenced construction, modification, ruary 1 2005, your turbine is subject to this subpart. Only eat input to t e combustion turbine should be included when determining whether or not this subpart is applicable to your turbine. Any additional heat input to associated heat recovery steam generators (HRSG) or duct burners should not be included when determining your peak heat input. However, this subpart does apply to emissions from any associated HRSG and duct burners. (b) Stationary combustion turbines regulated under this subpart are exempt from the requirements of subpart GG of this part. Heat recovery steam generators and duct burners regulated under this subpart are exempted from the requirements of subparts Da, Db, and Dc of this part. A Subpart KKKK applicability determination as well as an analysis of applicable Subpart KKKK monitoring, recordkeeping, and reporting requirements for the permanent turbine replacement shall be included in any request for a permanent turbine 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 commence construction date for purposes of determining the applicability of NSPS KKKK requirements). 2.4 Additional Sources The replacement of an existing turbine with a new turbine is viewed by the Division as the installation of a new emissions unit, not "routine replacement" 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; a turbine that is being installed as an entirely new emission point and not as part of an AOS-approved replacement of an existing onsite turbine has to go through the appropriate Construction/Operating permitting process prior to installation COLORADO Air Pollution Control Division Deparment cf Public Health b Cmi>onment Page 37 of 37 General APEN - Form APCD-200 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. There may be a more specific APEN for your source (e.g. boiler, mining operations, engines, etc.). A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 97WE0349 AIRS ID Number: 123 /0035' 012 - [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name1: Site Name: DCP Operating Company, LP Eaton Compressor Station Sire Location: Section 34, T7N, R66W Mailing Address: 370 17th Street, Suite 2500 (Include Zip Code) Portable Source Home Base: Denver, CO 80202 Site Location WeIA ld County: NAICS or SIC Code: 1311 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com 1 Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. 387637 COLOR ADO Form APCD-2O0 - General APEN - Revision 7/2018 Permit Number: 97WE0349 AIRS ID Number: 123 /0035/ TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑✓ NEW permit OR newly -reported emission source (check one below) ❑✓ STATIONARY source O PORTABLE source -OR - ❑ MODIFICATION to existing permt (check each box below that applies) ❑ Change fuel or equipment 0 Change company name3 O Add point to existing permit o Change permit limit 0 Transfer of ownership4 0 Other (describe below) -OR - ❑ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) ❑ APEN submittal for permit exempt/grandfathered source Additional Info £t Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 For transfer of ownership, a completed Trarefer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Information General description of equipment and purpose: Natural Gas Compression Turbine Manufacturer: Solar Model No.: Taurus 70 Serial No.: TBD Company equipment Identification No. (optional): For existing sources, operation began on: TURB-1 For new or reconstructed sources, the projected start-up date is: TBD ▪ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day days/week weeks/year Seasonal use percentage: Dec -Feb: Mar -May: Form APCD-200 - General APEN - Revision 7/2018 Jun -Aug: Sep -Nov: 2 1 A,COLORS DO ry`v, e r Permit Number: 97WE0349 AIRS ID Number: 123 / 0035/ TBD [Leave blank unless APCD has already assigned a permit # and MRS ID] Section 4 - Processing/Manufacturing Information a Material Use 0 Check box if this information is not applicable to source or process From what year is the actual annual amount? 5 u Description '<, t SY ' ' , :ice t.. ;. Design Process ` Rate ` (Specify Units) .-_ Actual Annual a Amount �' .: E +� x §# (Specify Units) ' r a Requested Anne I rl 3r asPermit Lim t , dr r r'k a-. #,WxGiY'5,s (Specify Units),° Material t Consumption: It� s Finished Product(s) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information 40.5308 / -104.7575 ❑ Check box if the following information is not applicable to the source because emissions will not be emitted from a stack. If this is the case, the rest of this section may remain blank. " era o k i ® Dischar 3 ' tt•,:. Heig .., P5 .. emB -� _. w: "� e� �IIi Fro to P�c i+ �`Y� ,. r.. � .. ., �. .... ti ec ,. ...... i�r F�end Le. 2 TURB-1 50.0 919 Indicate the direction of the stack outlet: (check one) ❑✓ Upward ❑ Horizontal ❑ Downward ID Other (describe): Indicate the stack opening and size: (check one) ❑ Upward with obstructing raincap ❑✓ Circular Interior stack diameter (inches): 45,0 O Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Form APCD-200 - General APEN - Revision 7/2018 3 1 e L'akA DO c r.atP W Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Combustion Equipment &t Fuel Consumption Information ❑ Check box if this information is not applicable to the source (e.g. there is no fuel -burning equipment associated with this emission source) Design Input Rate (Mti19TU/hrj:_ ;', Actual Annual Fuel Use f5pecify Unitsj Requested Annual Permit Limits (Specify Umts) 76.81 057.75 MMscf/yr From what year is the actual annua fuel use data? Indicate the type of fuel used6: ❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑ Field Natural Gas Heating value: BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) ❑ Propane (assumed fuel heating value of 2,300 BTU/SCF) ❑ Coat Heating value: BTU/lb Ash content: ❑✓ Other (describe): Pipeline Natural Gas Heating value (give units): G93, 53 -See. ad% hr) env-' $6 3/2A/) l Sulfur content: 499 -1-;023 Btu/scf 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 If fuel heating value is different than the listed assumed value, provide this information in the "Other" field. gee. 24 -2 QrAoi� - (5G 3/Zo// Section 7 - Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? ❑ Yes ❑✓ No escribe the control equipment AND state the overall control efficiency (% reduction): Pollutant . .. -. ControlEquipment_ uipment Description : ` overall Collection Efficiency_ '_ Overall Control Efficienry. ,(Yreduction in emissions) TSP (PM) PM -to PM2.5 SOX NO), CO VOC Other: Form APCD-200 - General APEN - Revision 7/2018 4I A :COLORADO w—,..n„z a of we,-tc t.: EV:VVAn:+MN 50-00-0 Formaldehyde Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 / TB D [Leave blank unless APCD has already assigned a permit # and AIRS ID] From what year is the following reported actual annual emissions data? Use the following table to report the criteria pollutant emissions from source: (Use the data reported in Sections 4 and 6 to calculate these emissions.) Pollutant --,- Uncontrolled Emission Factor (Specify Units). .. .. Emission` Factor Source.....: ( 42 Mfg etc) y, :�`i �-� ual An uat Emis.mns -cam r � .wrxF�a4'�arP�ib`'�''` a nested nnua� Permit �� isslon tmit � � Uncontrolled (t60#year) Conroll ted7. .., (tons/year) ` Uncontrolled -.:(tonslyear)?;. .Controlled (tonslyear)': TSP (PM) 6.6E-03 lb/MMBtu AP -42 2.22 2.22 PM10 6.6E-03Ib/MMBtu AP -42 2.22 2.22 PM2.5 6.6E-03 lb/MMBtu AP -42 2.22 2.22 SOx 3.4E-03 lb/MMBtu AP -42 1.14 1.14 NOx 5.45E-021b/MMBtu Mfg. �a 'sue l�•3 1.8--32 CO 5.53E-02 I b/M M Btu Mfg. c2 -18.59 11 1 *859- VOC 2.1E-031b/MMBtu AP -42 1$x -O7"1 1.33 O.71 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Section 8 - Non -Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non -criteria pollutants (e.g. HAP - hazardous air pollutant) equal to or greater than 250 lbs/year? ❑✓ Yes ❑ No If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source: Overall Control Efficiency Uncontrolled Emission Factor (Specify Units)' AP -42 Uncontrolled. Actual Emissions ontrolled ctua mis5lons�' (lbs/year) 0.0% 7.1E-04 477.75 477.75 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-200 - General APEN - Revision 7/2018 00 5I COLORADO D.5.fl enT Fut. Permit Number: 97WE0349 AIRS ID Number: 123 /0035/ TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 9 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran Dat' zolg Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: E✓ Draft permit prior to issuance �✓ Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B 1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: //www.colorado.gov/cdphe/apcd Form APCD-200 - General APEN - Revision 7/2018 COLORADO 6I i7::=11 3/21/2019 State.co.us Executive Branch Mail - Permit application for Eaton Compressor Station, 97WE0349 STATE OF COLORADO Gillard - CDPHE, Betsy <betsy.gillard@state.co.us> Permit application for Eaton Compressor Station, 97WE0349 Shankaran, Roshini <RShankaran@dcpmidstream.com> To: Betsy Gillard - CDPHE <betsy.gillard@state.co.us> AIRS 123-0035 -GIZ Hi Betsy, Fri, Jan 4, 2019 at 10:52 AM Sorry for the delay. After we spoke, we were going to change a couple things and it made sense to update everything at once rather than provide partial responses. Please see below in this email for additions as well as responses further down embedded in your email. If you have any further questions or want to discuss these, please let me know! As discussed, we are providing a couple updates based on other applications we have recently worked on with the Division: • DCP would like to take this opportunity to add Startup and Shutdown (SUSD) emissions from the turbines, as requested by the Division in recent DCP permit applications with Turbines. Can you please red -line the Turbine APENs for NOX, VOC and CO to reflect these updated emission calculations. The tons per year emissions are given below (inclusive of SUSD emissions): N0x CO V0C S02 PM Per Turbine Emissions 1,2 18.33 22.1& 1:33 Lid 2:22. DCP also requests that the heating value (Btu/scf ) value be updated to 999 Btu/scf on the APENs (see response in your email below). • DCP would also like to add Turbine Compressor Blowdowns as a separately permitted source. Note that these blowdown emissions were previously accounted under the insignificant activity list. The number of compressor blowdowns were increased to provide greater flexibility, which resulted in this source being classified now as a "permit required" source. • The following attachments have been provided with this response: > Revised Emission Calculations with Supporting Documentation and Revised APCD-102 — Attachment A > Revised Project Summary Table — Attachment B > APEN for TURB-BD (Turbine Blowdown APEN) — Attachment C Please let me know if you'd like a hard copy of any of the attachments and we will mail that over to you! Thanks, https://mail.google.com/mail/u/0?ik=2e1 a84e57d&view=pt&search=all&permmsgid=msg-f%3A1621753211724474251 &simpl=msg-f%3A16217532117... 1/4 General APEN - Form APCD-200 Air Pollutant Emission Notice (APEN) and Application for Construction Permit 4;0/, crff,t, X46 All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and maybe returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. There may be a more specific APEN for your source (e.g. boiler, mining operations, engines, etc.). A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 97WE0349 AIRS ID Number: 123 /0035/ 6 13 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name1: Site Name: DCP Operating Company, LP Eaton Compressor Station Site Location: Section 34, T7N, R66W Mailing Address: (Include Zip Code) 370 17th Street, Suite 2500 Portable Source Home Base: Denver, CO 80202 Site Location WeIA ld County: NAICS or SIC Code: 1311 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com I Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-200 - General APEN - Revision 7/2018 387638 COLORADO ii n,at Paiic Permit Number: 97WE0349 AIRS ID Number: 123 /0035/ TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action El NEW permit OR newly -reported emission source (check one below) ❑✓ STATIONARY source O PORTABLE source -OR - ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment O Change company name3 O Add point to existing permit ❑ Change permit limit O Transfer of ownership4 ❑ Other (describe below) - OR • APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) ❑ APEN submittal for permit exempt/grandfathered source Additional Info Et Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Information General description of equipment and purpose: Natural Gas Compression Turbine Manufacturer: Solar Model No.: Taurus 70 Serial No.: TBD Company equipment Identification No. (optional): For existing sources, operation began on: TURB-2 For new or reconstructed sources, the projected start-up date is: TBD ❑✓ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day days/week weeks/year Seasonal use percentage: Dec -Feb: Mar -May: Form APCD-200 - General APEN - Revision 7/2018 Jun -Aug: Sep -Nov: 2 LTV' Env= COLORADO Permit Number: 97WE0349 AIRS ID Number: 123 / 0035/ TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Processing/Manufacturing Information a Material Use E✓ Check box if this information is not applicable to source or process From what year is the actual annual arno®nt? Description Design Process Rate (Specify Units) Actual Annual Amount (Specify Units) Requested Annual Permit Limits ` (Specify Units) t --- a eria n" Consuimpttoce arlr rr 7n3"S�a x i, finished Products) u?t',"'M ''3tj jr k, { L 5 Requested values will. become permit limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information eographical Coor-41.41417 dina. Latitudellongitude or'Ul 40.5308 / -104.7575 Check box if the following information is not applicable to the source because emissions will not be emitted from a stack. If this is the case, the rest of this section may remain blank. � Aiz se ,ge Heigh e -round Lew e s �, z ; - t�� m + l. �� u loH+ Ra eb ..... T✓ t Y6 itY £ ....�,aat u��C��,.7+ne, ,;� Ope Stactclp o TU RB-2 50.0 919 Indicate the direction of the stack outlet: (check one) E✓ Upward El Horizontal El Downward Other (describe): Indicate the stack opening and size: (check one) ❑ Upward with obstructing raincap 0 Circular Interior stack diameter (inches): 45.0 Square/rectangle Interior stack width (inches): Interior stack depth (inches): Other (describe): Form APCD-2O0 - General APEN - Revision 7/2018 3 1 A. COLORAtlo F:ea:fl�e En IrGitt YRE Permit Number: 97WE0349 AIRS ID Number: 123 /0035/1 -BD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Combustion Equipment Et Fuel Consumption Information ❑ Check box if this information is not applicable to the source (e.g. there is no fuel -burning equipment associated with this emission source) Design Input Rate (MM8TU/hr,l ;, Actual Annual Fuel Use (specify Units Requested Annual Permit Limits (specify Units) 76.81 6&7 MMscf/yr From what year is the actual annual fuel use data? Indicate the type of fuel used6: ❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑ Field Natural Gas Heating value: BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) ❑ Propane (assumed fuel heating value of 2,300 BTU/SCF) o Coal Heating value: BTU/lb Ash content: Sulfur content: 0 Other (describe): Pipeline Natural Gas Heating value (give units):1-7923 Btu/scf col 3. s3 S ez AzdA4) eh A gG 3/zl /l`l qqq s Requested values will become permit Limitations. Requested limit(s) should consider future process growth. Sd°- aka 6 If fuel heating value is different than the listed assumed value, provide this information in the "Other" field. - Q (, 3 /21 /1 q Section 7 - Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? ❑ Yes 0 No If yes, describe the control equipment AND state the overall control efficiency (% reduction): TSP (PM) PMto PM2.5 SOX NO„ CO VOC Other: Form APCD-200 - General APEN - Revision 7/2018 41 COLORADO :o�Ftd Permit Number: 97VVE0349 AIRS ID Number: 123 / 0035 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] From what year is the following reported actual annual emissions data? Use the following table to report the criteria pollutant emissions from source: Use the data reported in Sections 4 and 6 to calculate these emissions.) Pollutant } 9 wr ; r`4 ^ Uncontrolled l;rrissn i r Fac ors spe''tifyr 1 riff fi Emission , n, r -Factor $ r..�._:., Source 4P 4z�M r 'efc � 4 J.ti_, ` ct a a E i• s �, � �S � 'tee ested, _ rnua En sio r its mi S P Uncontrolled ¢ = tonsl ear ` f=.,.Y Y,. r, controlled _': o ' r�`'' .(# gf.1M. - I rr . F Uncontrolled =r ons/7 ear = ,, 1 Y r {, ' Controlled tonsIy (__; . fgr, --: TSP (PM) 6.6E-03 lb/MMBtu AP -42 2.22 2.22 PMto 6.6E-031b/MMBtu AP -42 2.22 2.22 PM2.5 6.6E-03 lb/MMBtu AP -42 2.22 2.22 SOx 3.4E-03 Ib/MMBtu AP -42 1.14 1.14 NOx 5.45E-©2Ib/MMBtu Mfg. 11.332 tg.131-8f32 CO 5.53E-02 Ib/MMBtu Mfg. 22.' 61 9 22•i X59 VOC 2.1E-031b/MMBtu AP -42 033 -8771 t.53 e-71' Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Section 8 - Non -Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non -criteria pollutants (e.g. HAP - hazardous air pollutant) equal to or greater than 250 lbs/year? ❑✓ Yes ® No if yes, use the following table to report the non -criteria pollutant (HAP) emissions from source: - � ; CAS k Number. ; ss,:_ Chemicals },•.r .≥ Nainew J o , . r 1 : ; ff ienc Uncontrolled x Emission Factor 7S Emission Pac£oc" r a s3 i 4 oh fg etc ff rllncantrollec]`"' % ,rh , r� ti Actual ?}! , Em• issions ((hs(year) controlled Actua! Emissions' ..... (bslyear) 50-00-0 Formaldehyde 0.0% 7.1E-04 AP -42 477.75 477.75 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. 2Yt1 a•t -$G S/zl /19 Form APCD-200 - General APEN - Revision 7/2018 5IA. COLORADO .-e m wrac i F•sIN�Ei.VltetenMW Permit Number: 97WE0349 AIRS ID Number: 123 / 0035/ TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 9 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. tOog Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: ❑✓ Draft permit prior to issuance 0✓ Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B 1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: / /www.colorado. goy /cdphe / apcd Form APCD-200 - General APEN - Revision 7/2018 6I grCOLORADO �,"n°, 3/21/2019 State.co.us Executive Branch Mail - Permit application for Eaton Compressor Station, 97WE0349 STATE OF COLORADO Gillard - CDPHE, Betsy <betsy.gillard@state.co.us> Permit application for Eaton Compressor Station, 97WE0349 Shankaran, Roshini <RShankaran@dcpmidstream.com> Fri, Jan 4, 2019 at 10:52 AM To: Betsy Gillard - CDPHE <betsy.gillard@state.co.us> 5-$ 12 3-0035 - O 13 Hi Betsy, Sorry for the delay. After we spoke, we were going to change a couple things and it made sense to update everything at once rather than provide partial responses. Please see below in this email for additions as well as responses further down embedded in your email. If you have any further questions or want to discuss these, please let me know!' As discussed, we are providing a couple updates based on other applications we have recently worked on with the Division: • DCP would like to take this opportunity to add Startup and Shutdown (SUSD) emissions from the turbines, as requested by the Division in recent DCP permit applications with Turbines. Can you please red -line the Turbine APENs for NOX, VOC and CO to reflect these updated emission calculations. The tons per year emissions are given below (inclusive of SUSD emissions): NDx CO VOC SO2 PM Per Turbine Emissions 18.33 22.16 1.33 1.14 2.22 DCP also requests that the heating value (Btu/scf ) value be updated to 999 Btu/scf on the APENs (see response in your email below). • DCP would also like to add Turbine Compressor Blowdowns as a separately permitted source. Note that these blowdown emissions were previously accounted under the insignificant activity list. The number of compressor blowdowns were increased to provide greater flexibility, which resulted in this source being classified now as a "permit required" source. • The following attachments have been provided with this response: • Revised Emission Calculations with Supporting Documentation and Revised APCD-102 — Attachment A > Revised Project Summary Table — Attachment B > APEN for TURB-BD (Turbine Blowdown APEN) — Attachment C Please let me know if you'd like a hard copy of any of the attachments and we will mail that over to you! Thanks, httos://mail.aooale.com/mail/u/0?ik=2e1 a84e57d&view=at&search=all&permmsgid=msn-f%3A1621753211724474251 &simpl=msg-f%3A16217532117... 1/4 General APEN - Form APCD-200 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. There may be a more specific APEN for your source (e.g. boiler, mining operations, engines, etc.). A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. CENED SE' 1 T 2018 APCD Stationary Sources This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 i orL [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Namei: Site Name: Site Location: DCP Operating Company, LP Eaton Compressor Station Section 34, T7N, R66W Mailing Address: 370 17th Street, Suite 2500 (include Zip Code) Portable Source Home Base: Denver, CO 80202 Site Location WeIA ld County: NAICS or SIC Code: 1311 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com i Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-200 - General APEN - Revision 7/2018 387639 COLORADO 1 I -y I °r.�,„, R��„vE Permit Number: 97WE0349 AIRS ID Number: 123 /0035/ TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑✓ NEW permit OR newly -reported emission source (check one below) ❑✓ STATIONARY source ❑ PORTABLE source -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment O Change company name3 ❑ Add point to existing permit ❑ Change permit limit 0 Transfer of ownership' ❑ Other (describe below) -OR- ❑ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) ❑ APEN submittal for permit exempt/grandfathered source Additional Info Et Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Information General description of equipment and purpose: Natural Gas Compression Turbine Manufacturer: Solar Model No.: Taurus 70 Serial No.: TBD Company equipment Identification No. (optional): For existing sources, operation began on: TURB-3 For new or reconstructed sources, the projected start-up date is: TBD 0 Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day days/week weeks/year Seasonal use percentage: Dec -Feb: Mar -May: Form APCD-200 - General APEN - Revision 7/2018 Jun -Aug: Sep -Nov: ......... ... ...... .. COLORADO 2 I n.,� °'l„ Hm Permit Number: 97WE0349 AIRS ID Number: 123 / 0035/ TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Processing/Manufacturing Information a Material Use Check box if this information is not applicable to source or process From what year is the actual annual amount? Design Process,, Rate, (Specify Units) Actual Annual, Amount (Specify Units) Requested Annual Permit Limit. Specify Units)` 5 Requested values will become permit Limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information eographical Coordinates_ (Latitude/Longitude orUTM); 40.5308 / -104.7575 ❑ Check box if the following information is not applicable to the source because emissions will not be emitted from a stack. If this is the case, the rest of this section may remain blank. r a 'HS`Y�`yku71�G-,r r e • ra ac ® Di char a l�eig , o Ground Lee - _ �x • a F f t _ e • u� �. t � TURB-3 50.0 919 Indicate the direction of the stack outlet: (check one) ❑✓ Upward ❑ Horizontal ❑ Downward O Other (describe): Indicate the stack opening and size: (check one) O Upward with obstructing raincap ❑✓ Circular Interior stack diameter (inches): 45.0 ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Form APCD-200 - General APEN - Revision 7/2018 3 1 hi COLORADO : F:•:a3h c [nvlMnn.ni TSP (PM) Permit Number: 97WE0349 AIRS ID Number: 123 /0035/1 -BD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Combustion Equipment Et Fuel Consumption Information 0 Check box if this information is not applicable to the source (e.g. there is no fuel -burning equipment associated with this emission source) Design Input Rate (MMBTU/hr)' Actual Annual Fuel Use (Specify Units) Requested Annual Permit Limits (Specify Units) 76.81 X75 MMscf/yr From what year is the actual annual fuel use data? Indicate the type of fuel used6: ❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑ Field Natural Gas Heating value: BTU/SCF 0 Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) ❑ Propane (assumed fuel heating value of 2,300 BTU/SCF) ❑ Coal Heating value: BTU/lb Ash content: Sulfur content: 0 Other (describe): Pipeline Natural Gas Heating value (give units): 1,023 Btu/scf G33. S3 • s ?,14-4A,.) ev+tal (36 3 /2..k 7/1 qG 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Ste- akk"'l") 6 If fuel heating value is different than the listed assumed value, provide this information in the "Other" field. Em2.1 -(3G 3 /et //Li Section 7 - Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? ❑ Yes 0 No If yes, describe the control equipment AND state the overall control efficiency (% reduction): verall, Control Efficient' reduction rn emissions; PM10 PM2.5 SOX NO„ CO VOC Other: Form APCD-200 - General APEN - Revision 7/2018 4( rivvImnniimt COLO S. A DO 50-00-0 Formaldehyde TSP (PM) Permit Number: 97WE0349 AIRS ID Number: 123 i 0035 i TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] From what year is the following reported actual annual emissions data? Use the following table to report the criteria pollutant emissions from source: (Use the data reported in Sections 4 and 6 to calculate these emissions.) Uncontrolled Emission'_ factor`.: (Specify Units) AP -42 2.22 2.22 Uncontrol led (tops/year) Controlled' (tons/year);! ncontrolied tons/year),,-` ontralled tons/year) 6.6E-03 Ib/MMBtu PMto 6.6E-03 Ib/MMBtu AP -42 2.22 2.22 PM2.s 6.6E-03 lb/MMBtu AP -42 2.22 2.22 505 3.4E-03 Ib/MMBtu AP -42 1.14 1.14 N05 5.45E-02 Ib/MMBtu Mfg. tB•33a-8732 CO 5.53E-02 lb/MMBtu Mfg. 22t6 18.32 `$ Zz\ 18.59 V0C 2,1E-03 Ib/M M Btu AP -42 t.33 -1 Other:' 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. / Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Section 8 - Non -Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non -criteria pollutants (e.g. HAP - hazardous air pollutant) equal to or greater than 250 lbs/year? D Yes ❑ No If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source: Overall Control Efficiency_,, Uncontrolled ? Emission Factor (Specify Units) ,'? Emission Factor Source (4P-47. Mfg , etc.; Incontrolle�d, Actual - Emissions . (lbs/year);. Controlled; Actual Emissions (ibs/year) 0.0% 7.1E-04 AP -42 477.75 477.75 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Ste 4 ) eM5.\ Form APCD-200 - General ADEN - Revision 7/2018 5IA - COLORADO n� ePe E „ Permit Number: 97WE0349 AIRS ID Number: 123 / 0035/ TBD [Leave blank unless APCD has already assigned a permit €! and AIRS ID] Section 9 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran Gj(cq- /2o/g Date Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: ❑� Draft permit prior to issuance 0✓ Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B 1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: //www.colorado.gov/cdphe/apcd Form APCD-200 - General APEN - Revision 7/2018 OLORADO 6 �!n,et 3/21/2019 State.co.us Executive Branch Mail - Permit application for Eaton Compressor Station, 97WE0349 STATE OF COLORADO Gillard - CDPHE, Betsy <betsy.gillard@state.co.us> Permit application for Eaton Compressor Station, 97WE0349 Shankaran, Roshini <RShankaran@dcpmidstream.com> Fri, Jan 4, 2019 at 10:52 AM To: Betsy Gillard - CDPHE <betsy.gillard@state.co.us> Hi Betsy, A1rtS I23- 0035 -6I`1 Sorry for the delay. After we spoke, we were going to change a couple things and it made sense to update everything at once rather than provide partial responses. Please see below in this email for additions as well as responses further down embedded in your email. If you have any further questions or want to discuss these, please let me know! As discussed, we are providing a couple updates based on other applications we have recently worked on with the Division: • DCP would like to take this opportunity to add Startup and Shutdown (SUSD) emissions from the turbines, as requested by the Division in recent DCP permit applications with Turbines. Can you please red -line the Turbine APENs for NON, VOC and CO to reflect these updated emission calculations. The tons per year emissions are given below (inclusive of SUSD emissions): NO): Co S02 PM Per Turbine Emissions. 18.33 22.16 1.33 1.14 2:.22 DCP also requests that the heating value (Btu/scf ) value be updated to 999 Btu/scf on the APENs (see response in your email below). • DCP would also like to add Turbine Compressor Blowdowns as a separately permitted source. Note that these blowdown emissions were previously accounted under the insignificant activity list. The number of compressor blowdowns were increased to provide greater flexibility, which resulted in this source being classified now as a "permit required" source. • The following attachments have been provided with this response: > Revised Emission Calculations with Supporting Documentation and Revised APCD-102 — Attachment A > Revised Project Summary Table — Attachment B > APEN for TURB-BD (Turbine Blowdown APEN) — Attachment C Please let me know if you'd like a hard copy of any of the attachments and we will mail that over to you! Thanks, https://mail.google.com/mail/u/0?ik=2e1 a84e57d&view=pt&search=all&permmsgid=msg-f%3A1621753211724474251 &simpl=msg-f%3A16217532117... 1/4 Glycol Dehydration Unit APEN Form APCD-202 Air Pollutant Emission Notice (APEN) and Application for Construction Permit RECEIVED SEP 1 7 2U18 APCD Stationary +3earce. All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for glycol dehydration (dehy) units only. If your emission unit does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, hydrocarbon liquid loading, condensate storage tanks, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.Rov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 % b r5 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': DCP Operating Company, LP Site Name: Eaton Compressor Station Site Location: Section 34, T7N, R66W 370 17th Street, Suite 2500 Mailing Address: (Include Zip Code) Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1311 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address': RShankaran@DCPMidstream.com ' Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-202 - Glycot Dehydration Unit APEN - Revision 7/2018 387640 COLORADO 1 IZif nw,n Permit Number: 97WEO349 AIRS ID Number: 123 /0035/TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑✓ NEW permit OR newly -reported emission source -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment O Change company name3 O Add point to existing permit ❑ Change permit limit O Transfer of ownership4 ❑ Other (describe below) OR ❑ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ▪ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Et Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Information General description of equipment and purpose: TEG dehydration unit for water removal Company equipment Identification No. (optional): D-1 - TEG Dehydration Unit For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TB D ❑✓ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day days/week weeks/year Will this equipment be operated in any NAAQS Yes ❑ No nonattainment area? Is this unit located at a stationary source that is considered O Yes ❑✓ No a Major Source of (HAP) Emissions? Form APCD-2O2 - Glycol Dehydration Unit APEN - Revision 7/2018 COLORADO 2 I lair mw Permit Number: 97WE0349 AIRS ID Number: 123/0035/TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Dehydration Unit Equipment Information Manufacturer: TBD Dehydrator Serial Number: TBD Glycol Used: Model Number: TBD Reboiler Rating: 4 MMBTU/hr ❑ Ethylene Glycol (EG) ❑ DiEthylene Glycol (DEG) ❑r TriEthylene Glycol (TEG) Glycol Pump Drive: ❑✓ Electric O Gas If Gas, injection pump ratio: Pump Make and Model: TBD - 1 primary, 1 backup 1 Glycol Recirculation rate (gal/min): Lean Glycol Water Content: Max: 30 1.0 Wt.% Requested: 30 Acfm/gpm # of pumps: 2 Dehydrator Gas Throughput: Design Capacity: 125 MMSCF/day Requested5: 45,625 MMSCF/year Actual: MMSCF/year Inlet Gas: Pressure: 1,000 psig Water Content: Wet Gas: lb/MMSCF Flash Tank: Pressure: 60 psig Cold Separator: Pressure: psig ❑✓ None ❑ Flash Gas ❑ Dry Gas O Nitrogen scfm Stripping Gas: (check one) Flow Rate: Temperature: ❑✓ Saturated Temperature: Temperature: 130 Dry gas: 100 °F 5.0 lb/MMSCF °F ❑ NA °F ❑✓ NA Additional Required Information: ❑✓ Attach a Process Flow Diagram ❑✓ Attach GRI-GLYCalc 4.0 Input Report Et Aggregate Report (or equivalent simulation report/test results) O Attach the extended gas analysis (including BTEX 6 n -Hexane, temperature, and pressure) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Form APCD-202 - Glycol Dehydration Unit APEN - Revision 7/2018 3 1 J^� ,COLORADO Permit Number: 97WE0349 AIRS ID Number: 123/0O5/TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information eographicalCoordinates Latitude/Longitude or UTM) 40.5308 / -104.7575 ;le atar taC Q _ O �� was � Discharge eigi �� ,�� ove t round ever � � �r � � -_ Tetr�p .. �1 � �" t ' FiowRate� � u 4CFht. cit �� a or�t fJsec gri D-1 24 TBD TBD TBD Indicate the direction of the stack outlet: (check one) ❑ Downward ❑ Other (describe): ❑✓ Upward ❑ Horizontal Indicate the stack opening and size: (check one) ❑✓ Circular 0 Square/rectangle ❑ Other (describe): 0 Upward with obstructing raincap Interior stack diameter (inches): 24 Interior stack width (inches): Interior stack depth (inches): Section 6 - Control Device Information ❑ Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. O Condenser: Used for control of: Type: Make/Model: Maximum Temp: °F Average Temp: Requested Control Efficiency: ✓❑ VRU: Used for control of: Flash Tank Vapors Size: Make/Model: Requested Control Efficiency: 100.0 VRU Downtime or Bypassed: 5.0 * ❑ Combustion Device: ** Used for control of: Still Vent Stream Rating: Type: Enclosed Combustor MMBtu/hr Make/Model: TBD Requested Control Efficiency: 95.0 Manufacturer Guaranteed Control Efficiency: 98.0 Minimum Temperature: °F Waste Gas Heat Content: Btu/scf Constant Pilot Light: 0 Yes 0 No Pilot Burner Rating: 0.051 MMBtu/hr Closed ❑ Loop System: Used for control of: Description: System Downtime: O Other: Used for control of: Flash tank vapors during VRU downtime (5%) Description: ECD Combustion Device Requested Control Efficiency: 95.0 COLORADO Form APCD-202 - Glycol Dehydration Unit APEN - Revision 7/2018 4 iisk. (*, **) see note on last page PM Permit Number: 97WE0349 AIRS ID Number: 1 23 /0035/TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emission calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): escriptionof Control Method ;:Overa[I Requested, Control Efficiency ".: (%reduction in emissions)..: SOX NOx CO VOC Vapor Recovery Unit/Enclosed Combustor 95% HAPs Vapor Recovery Unit/Enclosed Combustor 95% Other: From what year is the following reported actual annual emissions data? Criteria Pollutant Emissions Inventory: PM SOUrCe (AP -42; Mfg., etc.) ctuat Annual.Ermissions.. Requesteo �A inuat Permit • Emission Lmt(sj5;:::' ncontr"oiled, Emissions:' (tonsfyear) �i�,Controlled • Emissions6--` (tohsl year)' UnconY oiled ,': Emissions • (torlslyeat)-: Confrolled :Einiss oiis": .(torisfyear). SOX NOx 0.068 lb/MM Btu AP -42 111 1-4S' I : IL 3--1-3 CO 0.31 Ib/MMBtu AP -42 0.4 ,643 So} 5-93' VOC 30.60 Ib/MMscf GLYCalc 698.16 25.66 ..= = ••, .=:.":„ Non. -Criteria Reportable. Pollutant Emissions Inventory..:.; .::. . .≤_...:: :.r. Ch..- iical Name:; .. :: • ..:..... ... :.....,: ,� ...::. • �-..,..:.:::.. ....... .. Chemical ;: = .... .: •.:.Abstracf::,.:...::,,:..•.: •.. •''. : Service•CAS) ......r„...� -, ...:... .. ... -46 : ,_: `; Emission' Factor. ":::k " " ` `. ; ''Actual`Annual. Em ss ons"` '.:-:-.• -: , ., -1J ncoritrolled- . '• :• ..::.sis . 'Unitsr : . Source • �(AP=42;,i� : Mf`c� etc:'. g:,. ) � - Uncontrolled.:` r.- ::—.':-..'..• ounds%'edr `. (p y.. ) • ' - `=ontrol''-6'.` .' '.�Emissonsfi�.• (p"oundsfyear) Benzene 71432 2.54 Ib/MMscf GLYCalc 115,964 6,839 Toluene 108883 2.35 Ib/MMscf GLYCalc 107,132 6,340 Ethylbenzene 100414 0.07 Ib/MMscf GLYCaIc 3,112 185 Xylene 1330207 0.70 Ib/MMscf GLYCalc 31,860 1,892 n -Hexane 110543 0.57 Ib/MMscf GLYCaIc 25,862 1,186 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limftations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Note: Emissions shown are potential to emit emissions since this is a new source. Please include the emissions in the Notes to Permit Holder section of the permit. COLORADO Form APCD-2O2 - Glycol Dehydration Unit APEN - Revision 7/2018 5 i k¢ f;'4'n'm.;, Permit Number: 97WE0349 AIRS ID Number: 123 /0°35 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: ❑✓ Draft permit prior to issuance �✓ Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. * 5% annual VRU downtime is equal to a D-1 natural gas throughput of 2,282 MMSCF/yr that is processed while the flash tank is routed to the ECD (ECD-1). ** ECD combustion device use for still vent control has a 1'.0% annual downtime for maintenance and repairs. Still vent emissions will vent to atmosphere during periods of ECD-1 downtime. 1% annual ECD downtime equates to a D-1 natural gas throughput of 457 MMSCF/yr that is processed while the still vent is vented to atmosphere. Send this form along with $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: //www.colorado.gov/cdphe/apcd Form APCD-202 - Glycol Dehydration Unit APEN - Revision 7/2018 6Awr co LORADO 3/21/2019 State.co.us Executive Branch Mail - Permit application for Eaton Compressor Station, 97WE0349 You are right, the value of 69.83 MMBtu/hr (in LHV) was taken from the spec sheet for fuel flow. If fuel flow is measured in LHV units, it must be converted to HHV before calculating emissions when using AP -42 emission factors (for VOC, PM, SO2, and HAPs). Note that 7399 Btu/HP-hr does equate to 69.83 MMBtu/hr, which is the fuel flow on a LHV basis. Therefore, 69.83 MMBtu/hr was multiplied by a factor of 1.1 to convert the MMBtu/hr from LHV to HHV, which is a typical rule of thumb for natural gas (this factor varies between 1.108 to 1.11). By correcting the HHV to match the spec sheet, the heat rate reflects 76.81 MMBtu/hr as used in the calculations. See below links for some references: https://wvvw.clarke-energy.com/heating-value/ https://www.fortisbc.com/NaturalGas/Business/PriceAndMarket!nformation/Pages/Heat-content-values.aspx Additionally, To avoid confusion and to ensure consistency with the turbine spec sheet heating value, DCP is revising the fuel heat value from 1023 Btu/scf to 999 (HHV) Btu/scf throughout the emission calculations. Note that 999 (HHV) Btu/scf is 908.2 (LHV) Btu/scf. DCP also requests that the Dehydrator APENs (D-1 and D-2) APENs be marked up/red- lined appropriately for NOX and CO emissions to reflect the latest NOX and CO numbers (for the control device) with the change in Btu/scf. There are no changes to the VOC or HAP emissions represented on the APENs. The second question I have relates to the emission factors for NOx and CO. The APEN has emission factors for NOx and CO as 0.0545 and 0.0553 lb/MMbtu, respectively. However the spec sheet indicates the NOx and CO emissions are 0.060 and 0.061 lb/MMBtu. Can you help me understand why there is a difference between the two? This emission factor was also converted from LHV to HHV basis for the APEN. The methodology used to convert the emissions was: NOx (lb/MMBtu) => 4.18 lb/hr (from the spec sheet) / 76.81 MMBtu/hr (HHV Basis) = 0.0545 lb/MMBtu CO (lb/MMBtu) => 4.24 lb/hr (from the spec sheet) / 76.81 MMBtu/hr (HHV Basis) = 0.0553 lb/MMBtu Thank you for your help, Bets' Betsy Gillard, P.E. Oil Et Gas Permitting Engineer Stationary Sources Program P (direct) 303.692.6330 I F 303.782.5493 4300 Cherry Creek Drive South, Denver, CO 80246-1530 betsy.gillard@state.co.us I www.colorado.gov/cdphe/apcd A IRS (Z3 -003's -615 Are you concerned about ground -level ozone in Colorado? Visit our ozone webpage to learn more. COLORADO Air Pollution Control Division Department of Public Health Er Environment https://mail.google.com/mail/u/0?ik=2e1 a84e57d&view=pt&search=all&permmsgid=msg-f%3A1621753211724474251 &simpl=msg-f%3A16217532117... 3/4 Glycol Dehydration Unit APEN Form APCD-202 Air Pollutant Emission Notice (APEN) and Application for Construction Permit RECEIVED SEP172018 APCD Stationary $ouro€ c All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for glycol dehydration (dehy) units only. If your emission unit does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, hydrocarbon liquid loading, condensate storage tanks, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 / 9/ 6' [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': DCP Operating Company, LP Site Name: Eaton Compressor Station Site Location: Section 34, T7N, R66W Mailing Address: (Include Zip Code) 370 17th Street, Suite 2500 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1311 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address': RShankaran@DCPMidstream.com ' Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-202 - Glycol Dehydration Unit APEN - Revision 7/2018 387641 i COLORA DO 1 Air! De,..na<ec et wri< K.vlk iinr lrortewmt Permit Number: 97WE0349 AIRS ID Number: 123/0O5/TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑r NEW permit OR newly -reported emission source -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment O Change company name3 O Add point to existing permit ❑ Change permit limit O Transfer of ownership4 O Other (describe below) OR - ▪ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - El Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info ft'Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Information General description of equipment and purpose: TEG dehydration unit for water removal Company equipment Identification No. (optional): D-2 - TEG Dehydration Unit For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TBD ❑r Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: Will this equipment be operated in any NAAQS nonattainment area? hours/day Is this unit located at a stationary source that is considered a Major Source of (HAP) Emissions? Form APCD-202 - Glycol Dehydration Unit APEN - Revision 7/2018 days/week Yes Yes O weeks/year No No coLORADo 2I n,o« '. HeQa.fin 6EnvlranmwN Permit Number: 97WE0349 AIRS ID Number: 123/0O5/TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Dehydration Unit Equipment Information Manufacturer: TBD Dehydrator Serial Number: TBD Model Number: TBD Reboiler Rating: 4.5 MMBTU/hr Glycol Used: O Ethylene Glycol (EG) O DiEthylene Glycol (DEG) ❑/ TriEthylene Glycol (TEG) Glycol Pump Drive: ✓❑ Electric O Gas If Gas, injection pump ratio: Pump Make and Model: TBD - 1 primary, 1 backup Glycol Recirculation rate (gal/min): Max: 40 Lean Glycol Water Content: 1.0 Wt.% Requested: 40 Acfm/gpm # of pumps: 2 Dehydrator Gas Throughput: Design Capacity: 231 MMSCF/day Requested5: 84,315 MMSCF/year Actual: MMSCF/year Inlet Gas: Pressure: 1,000 psig Temperature: 130 °F Water Content: Wet Gas: lb/MMSCF ✓❑ Saturated Dry gas: 5.0 lb/MMSCF Flash Tank: Pressure: 60 psig Temperature: 100 °F O NA Cold Separator: Pressure: psig Temperature: °F El NA Stripping Gas: (check one) ❑✓ None O Flash Gas ❑ Dry Gas O Nitrogen Flow Rate: scfm Additional Required Information: ❑✓ Attach a Process Flow Diagram ❑ Attach GRI-GLYCalc 4.0 Input Report Et Aggregate Report (or equivalent simulation report/test results) O Attach the extended gas analysis (including BTEX it n -Hexane, temperature, and pressure) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Form APCD-202 - Gtycot Dehydration Unit APEN - Revision 7/2018 COLORADO 3 1AIDepartment m IV.< Permit Number: 97WE0349 AIRS ID Number: 123/0035/TBD [Leave blank unless APCD has already assigned a permit #t and AIRS ID] Section 5 - Stack Information Geographical Coordinates'. Latitude%Longitude or.UTM) 40.5308 / -104.7575 0 erato Sta ID _ Discharge Hei ht � �� ove G au d Le e I fei� _ Temp s � FlowtRateVelocity jstcF sea' D-2 40 TBD TBD TBD Indicate the direction of the stack outlet: (check one) ✓❑ Upward El Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) O Upward with obstructing raincap 0 Circular Interior stack diameter (inches): 84 ❑ Square/rectangle Interior stack width (inches): ❑ Other (describe): Interior stack depth (inches): Section 6 - Control Device Information O Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. Condenser: Used for control of: Type: Maximum Temp: °F Requested Control Efficiency: Make/Model: Average Temp: 0 VRU: Used for control of: Flash Tank Vapors Size: Make/Model: Requested Control Efficiency: 100 VRU Downtime or Bypassed: 5.0 * % Combustion Q Device:** Used for control of: stiti Vent Stream Rating: Type: Requested Manufacturer Guaranteed Minimum Temperature: Constant Pilot Light: MMBtu/hr Enclosed Combustor Make/Model: TBD Control Efficiency: 95.0 Control Efficiency: 98.0 °F Waste Gas Heat Content: Btu/scf O Yes O No Pilot Burner Rating: 0.066 MMBtu/hr Closed ❑ Loop System: Used for control of: • Description: _ System Downtime: ❑✓ Other: Used for control of: Flash tank vapors during VRU downtime (5%) Description: ECD Combustion Device Requested Control Efficiency: 95.0 Form APCD-202 - Glycol Dehydration Unit APEN Revision 7/2018 4 I A` (*, **) see note on last page COLORADO R oa, Permit Number: 97WE0349 AIRS ID Number: 123/0035/ T B D [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emission calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction ): :..' Pollutant :. Description of Control Methods) . :. Overall Requested ...:. :. Control: Efficiency • . . (% reduction in emissions) . PM SOX NOx CO VOC Vapor Recovery Unit/Enclosed Combustor 95% HAPs Vapor Recovery Unit/Enclosed Combustor 95% Other: From what year is the following reported actual annual emissions data? Criteria Pollutant Emissions Inventory Pollutant: . .:•• •:. .. Emission Factor. •• . ":. ... .. .. .. :.... Actual Annual Emissions .. :: ... Requested Annual Permit .:::Emission Limit(• a}s:�. :. Uncontrolled . .. Basis .: . • - Units . : Source (AP -.42 _Mfg..; .":c..) Uncontrolled Emissions :. (tons/year) • Controlled ; ` 6: Emissions . (tdns/year) Uncontrolled :- • Emissions (tonsfyear).:-. Controlled . Emissions : (tons/year) PM SOx NOx 0.068 lb/MMBtu AP -42 4,, I. 3 s 4736 1.3 S CO 0.31 Ib/MMBtu AP -42 G. l M 620 6, i4 6,2.0 VOC 21.68 lb/MMscf GLYCaIc 913.89 33.56 Non -Criteria Reportable Pollutant •Emissions Inventory. . :. Chemical Name ... • Chemical Abstract : Service (CAS) . Number ' ` .. - Emission Factor :-' Actual Annual Emissions'" •- - o • Uncontrolled. . .Basis. :.-.: � � - Units.: � � � r • Source . . AP=42;, ::' (g ) Mf . etc. . Uncontrolled ::; Emissions : • oundsl `ear '(pY ) : Controlled :, : Emissions 6 . : (p Y ) ounds! 'ear Benzene 71432 1.82 lb/MMscf GLYCaIc 153,198 9,035 Toluene 108883 1.67 lb/MMscf GLYCaIc 141,160 8,353 Ethylbenzene 100414 0.05 lb/MMscf GLYCaIc 4,093 243 Xylene 1330207 0.50 lb/MMscf GLYCaIc 42,567 2,528 n -Hexane 110543 0.40 lb/MMscf GLYCaIc 33,503 1,529 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Note: Emissions shown are potential to emit emissions since this is a new source. Please include the I-orm AK_U-LLOL eulycotsDehydl ation unit Ai I N - Re Revision t COLORADO 5 .co." s az 241-2)4` 0)12,1 4'or 121. -a6 i/u /la Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran Date Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: 0 Draft permit prior to issuance Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. * 5% annual VRU downtime is equal to a D-2 natural gas throughput of 4,216 MMSCF/yr that is processed while the flash tank is routed to the ECD (ECD-2). ** ECD combustion device use for still vent control has a 1.0% annual downtime for maintenance and repairs. Still vent emissions will vent to atmosphere during periods of ECD downtime. 1% annual ECD downtime equates to a D-2 natural gas throughput of 844 MMSCF/yr that is processed while the still vent is vented to atmosphere. Send this form along with $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B 1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: //www.colorado.gov/cdphe/apcd Form APCD-202 - Glycol Dehydration Unit APEN - Revision 7/2018 Avr COLORADO 6 ( Department of Fa Cd wnnrortm.M 3/21/2019 State.co.us Executive Branch Mail - Permit application for Eaton Compressor Station, 97WE0349 You are right, the value of 69.83 MMBtu/hr (in LHV) was taken from the spec sheet for fuel flow. If fuel flow is measured in LHV units, it must be converted to HHV before calculating emissions when using AP -42 emission factors (for VOC, PM, S02, and HAPs). Note that 7399 Btu/HP-hr does equate to 69.83 MMBtu/hr, which is the fuel flow on a LHV basis. Therefore, 69.83 MMBtu/hr was multiplied by a factor of 1.1 to convert the MMBtu/hr from LHV to HHV, which is a typical rule of thumb for natural gas (this factor varies between 1.108 to 1.11). By correcting the HHV to match the spec sheet, the heat rate reflects 76.81 MMBtu/hr as used in the calculations. See below links for some references: https://www.clarke-energy.com/heating-vaiue/ https://www.fortisbc.com/NaturalGas/Business/PriceAndMarketinformation/Pages/Heat-content-values.aspx Additionally, To avoid confusion and to ensure consistency with the turbine spec sheet heating value, DCP is revising the fuel heat value from 1023 Btu/scf to 999 (HHV) Btu/scf throughout the emission calculations. Note that 999 (HHV) Btu/scf is 908.2 (LHV) Btu/scf. DCP also requests that the Dehydrator APENs (D-1 and D-2) APENs be marked up/red- lined appropriately for NOX and CO emissions to reflect the latest NOX and CO numbers (for the control device) with the change in Btu/scf. There are no changes to the VOC or HAP emissions represented on the APENs. The second question I have relates to the emission factors for NOx and CO. The APEN has emission factors for NOx and CO as 0.0545 and 0.0553 lb/MMbtu, respectively. However the spec sheet indicates the NOx and CO emissions are 0.060 and 0.061 lb/MMBtu. Can you help me understand why there is a difference between the two? This emission factor was also converted from LHV to HHV basis for the APEN. The methodology used to convert the emissions was: NOx (Ib/MMBtu) => 4.18 lb/hr (from the spec sheet) / 76.81 MMBtu/hr (HHV Basis) = 0.0545 lb/MMBtu CO (lb/MMBtu) => 4.24 lb/hr (from the spec sheet) / 76.81 MMBtu/hr (HHV Basis) = 0.0553 lb/MMBtu Ams 123- 0035- o l C Thank you for your help, Betsy Betsy Gillard, P.E. Oil £t Gas Permitting Engineer Stationary Sources Program P (direct) 303.692.6330 I F 303.782.5493 4300 Cherry Creek Drive South, Denver, CO 80246-1530 betsy.gillard@state.co.us I www.colorado.gov/cdphe/apcd Are you concerned about ground -level ozone in Colorado? Visit our ozone webpage to learn more. COLORADO Air Pollution Control Division Department of Public Health Environment hltnc•//mail nnnnla rnm/mail/I I/(l9ik=7A1 aR4ar,7riRviaw=nt&saarrh=allRnermmsnid=msa-f%3A1621753211724474251 &simol=msa-f%3A16217532117... 3/4 JAN 1 8 2019 Gas Venting APEN - Form APCD-211 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for gas venting only. Gas venting includes emissions from gas/liquid separators, well head casing, pneumatic pumps, blowdown events, among other events. If your emission unit does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, hydrocarbon liquid loading, condensate storage tanks, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 97WE0349 AIRS ID Number: 123 /0035 / .62J [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name: Site Name: Site Location: Mailing Address: DCP Operating Company, LP Eaton Compressor Station Section 34, T7N, R66W (Include Zip Code) 370 17th Street, Suite 2500 Denver, CO 80202 Site Location Weld County: NAICS or SIC Code: 1311 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: rshankaran@dcpmidstream.com I Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. 39227S Form APCD-211 - Gas Venting APEN - Revision 7/2018 W ICOLORADO Permit Number: 97WE0349 AIRS ID Number: 123 /0035 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information ❑ Gas/Liquid Separator ❑ Well Head Casing ❑ Pneumatic Pump Make: Model: ❑ Compressor Rod Packing Make: ❑✓ Blowdown Events # of Events/year: ❑ Other Description: Serial #: Capacity: gal/min Model: # of Pistons: Leak Rate: Scf/hr/pist 72 Volume per event: 0.016 MMscf/event If you are requesting uncontrolled VOC emissions greater than 100 tpy for a gas/liquid separator, you must use Gas Venting as a process parameter. Are requested uncontrolled VOC emissions greater than 100 tpy? O Yes Gas Venting Process Parameters5: Liquid Throughput Process Parameters5: Vented Gas Properties: ❑✓ No Vent Gas Heating Value: 1332.5 BTU/SCF Requested: 1.17 MMSCF/year Actual: MMSCF/year -OR- Requested: bbl/year Actual: bbl/year Molecular Weight: 22.9 VOC (Weight %) 28.57 Benzene (Weight %) 0.05 Toluene (Weight %) 0.04 Ethylbenzene (Weight %) 0.001 Xylene (Weight %) 0.01 n -Hexane (Weight %) 0.39 2,2,4-Trimethylpentane (Weight %) 0.004 Additional Required Information: ❑ Attach a representative gas analysis (including BTEX Et n -Hexane, temperature, and pressure) Attach a representative pressurized extended liquids analysis (including BTEX Et n -Hexane, temperature, and pressure) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Form APCD-211 - Gas Venting APEN - Revision 7/2018 !COLORADO 3 PulgIc x.mn 6 Enwlmnmml PM Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) SOX NO. CO VOC HAPs Other: From what year is the following reported actual annual emissions data? N/A Criteria Pollutant Emissions Inventory PoUutant' PM Emission Factor_. Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled.. Emissions` (tons/year)`, ontrolled Emissions6 (tons/year) Uncontrolled Emissions (tons/year) Controlled Emissions (tons/year) SOX NO. CO VOC 280.58 lb/event Eng. Est. 10.10 10.10 Chemical Name Non -Criteria Reportable Pollutant Emissions Inventory Chemical Abstract Service (CAS), Number Emission Factor Actual Annual Emissions Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (pounds/year) Controlled Emissions6 (pounds/year) Benzene 71432 Toluene 108883 Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 3.86 lb/event Eng. Est. 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-211 - Gas Venting APEN - Revision 7/2018 COLORADO ' DeparcerEnu�rtp.me�t SEP 17 ?oi8 Hydrocarbon Liquid Loading APE IIAc S Form APCD-208 oubbD Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for hydrocarbon liquid loading only. If your emission unit does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, glycol dehydration unit, condensate storage tanks, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 / 017 [Leave blank unless APCD has already assigned a permit ft and AIRS ID] Section 1 - Administrative Information Company Name': DCP Operating Company, LP Site Name: Eaton Compressor Station Site Location: Section 34, T7N, R66W Mailing Address: (Include Zip Code) 370 17th Street, Suite 2500 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1311 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com i Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 387642 COLORADO 1 I R`°"'"'"'` Env.,eT ., Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑✓ NEW permit OR newly -reported emission source ✓❑ Request coverage under construction permit ❑ Request coverage under General Permit GP07 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment ❑ Change company name3 ❑ Change permit limit ❑ Transfer of ownership4 O Other (describe below) OR - • APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - El Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info £t Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Information General description of equipment and purpose: Pressurized truck load out of condensate Company equipment Identification No. (optional): L-1 For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TBD Will this equipment be operated in any NAAQS nonattainment area? Yes No p ■ Is this equipment located at a stationary source that is considered a Major Source of (HAP) emissions? Yes No • p Does this source load gasoline into transport vehicles? Yes No ■ SI Is this source located at an oil and gas exploration and production site? Yes No ■ p If yes: Does this source load less than 10,000 gallons of crude oil per day on an annual average? Yes No • ■ Does this source splash fill less than 6750 bbl of condensate per year? Yes No ■ ■ Does this source submerge fill less than 16308 bbl of condensate per year? Yes No • • Form APCD-208 - Hydrocarbon Liquid Loading APEN -- Revision 7/2018 2 1AlCOLORADO rPam Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 /TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information Product Loaded: ❑✓ Condensate O Crude Oil ❑ Other: If this APEN is being filed for vapors displaced from cargo carrier, complete the following: Requested Volume Loaded5: bbl/year This product is loaded from tanks at this facility into: (e.g. "rail tank cars" or "tank trucks") Actual Volume Loaded: bbl/year If site specific emission factor is used to calculate emissions, complete the following: Saturation Factor: Average temperature of bulk liquid loading: ,F True Vapor Pressure: Psia @ 60 °F Molecular weight of displaced vapors: lb/lb-mol If this APEN is being filed for vapors displaced from pressurized loading lines, complete the following: Requested Volume Loaded5: 1,428,571.4" bbl/year Actual Volume Loaded: bbl/year Product Density: 46.08 lb/ft3 Load Line Volume: 0.0218 ft3/truckload Vapor Recovery Line Volume: 0.0218 ft3/truckload 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. *8,572 loads/yr Form APCD-208 Hydrocarbon Liquid Loading APEN - Revision 7/2018 ''COLORADO 3 1 • - Department. �„ F��.;I11 Er Permit Number: 971/VE0349 AIRS ID Number: 123 / 0035 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.5308 / -104.7575 ?+d F N�ya Y3 Operator = Stac 1 No are s r° Discharge egAbove" -Group �' beve eet - ' s«r '" * T ,fit 1� o Rate C a ocit '� 1sec c, F L-1 Indicate the direction of the stack outlet: (check one) ❑ Upward ❑ Horizontal ❑ Downward Other (describe): Indicate the stack opening and size: (check one) ❑ Circular ❑ Other (describe): Interior stack diameter (inches): ❑ Upward with obstructing raincap Section 6 - Control Device Information Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. ❑✓ Loading occurs using a vapor balance system: Requested Control Efficiency: 1 00 yo ❑ Combustion Device: Used for control of: Rating: Type: MMBtu/hr Make/Model: Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency: Minimum Temperature: °F Waste Gas Heat Content: Constant Pilot Light: 0 Yes 0 No Pilot Burner Rating: Btu/scf MMBtu/hr ❑ Other: Pollutants Controlled: Description: Requested Control Efficiency: COLORADO Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 4 Benzene 71432 PM Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 /113D [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Overall Requested Control Efficiency % reduction in emissions) sox NOx • CO VOC HAPs Other: ❑ Using State Emission Factors (Required for GP07) ❑ Condensate ❑ Crude VOC. 0.236 Lbs/BBL 0.104 Lbs/BBL Benzene 0.00041 Lbs/BBL 0.00018 Lbs/BBL n -Hexane 0.0036 Lbs/BBL 0.0016 Lbs/BBL From what year is the following reported actual annual emissions data? riteria.Pollutant.Emtss ons Inventory _; ctual Annual Emissions PM nested Annual Permit mission Limit(s)5 SOx NO. CO VOC 1.06 lb/load Eng. Est. 4.52 4.52 Nero Criteria Reportable .Pollutant Emissions Inventory.::: mson,Factor etual Annual Emissions uncontrolled s.. Basis lb/load Eng. Est. ncontrolled; Emissions s ontrolled missions6 pounds/year) Toluene 108883 Ethylbenzene •Xylene n -Hexane 100414 1330207 110543 .07 596.47 596.47 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started o erating, leave blank. Note: Emissions shown are potential to emit emissions since this is a new source. Please include the s in the N tes to Pe mit Hol r section .of th mil. COLORADO Form A k yorocarbon LtquXo rLcad rig PLN - Rev1s8on 772B 5 I COLORADO Permit Number: 97WE0349 AIRS ID Number: 123 I 0035f TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. If this is a registration for coverage under General Permit GP07, I further certify that this source is and will be operated in full compliance with each condition of General Permit GP07. Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: Draft permit prior to issuance ❑✓ Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with $191.13 and the General Permit registration fee of $312.50, if applicable, to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: / /www.colorado.>;ov/cdphe/apcd Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 �V COLORADO REcF D SEP 1 7 2018 s 4`FnD Gas Venting APEN - Form APCD-211 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for gas venting only. Gas venting includes emissions from gas/liquid separators, well head casing, pneumatic pumps, blowdown events, among other events. If your emission unit does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, hydrocarbon liquid loading, condensate storage tanks, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 97WE0349 AIRS ID Number: 123 /0035 / O(" [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Hamel: Site Name: Site Location: DCP Operating Company, LP Eaton Compressor Station Section 34, T7N, R66W Mailing Address: 370 17th Street, Suite 2500 (Include Zip Code) Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1311 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPIVIidstream.com 1 Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. 387643 iSAW COLORADO Form APCD-211 - Gas Venting APEN - Revision 7/2018 Permit Number: 97WE0349 AIRS ID Number: 123 /0035 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑✓ NEW permit OR newly -reported emission source -OR - ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment ❑ Change company name3 ❑ Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership4 ❑ Other (describe below) - OR ❑ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ▪ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Ft Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Information General description of equipment and purpose: Pigging - 2 receivers, 1 launcher 12" Receiver; 8" Receiver; 16" Launcher Company equipment Identification No. (optional): P I G For existing sources, operation began on: For new, modified, or reconstructed sources, the projected start-up date is: TBD 0 Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: Wilt this equipment be operated in any NAAQS nonattainment area? hours/day Is this equipment located at a stationary source that is considered a Major Source of (HAP) Emissions? Is this equipment subject to Colorado Regulation No. 7, Section XVII.G? Form APCD-211 - Gas Venting APEN - Revision 7/2018 days/week weeks/year Yes Yes Yes ❑ No ❑✓ No ❑✓ No 2j •VCOLORADO ��"b, Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information ❑ Gas/Liquid Separator ❑ Well Head Casing ❑ Pneumatic Pump Make: Model: Compressor Rod Packing Make: Model: ❑✓ Blowdown Events # of Events/year: ❑ Other Description: 960 Serial #: Capacity: gal/min # of Pistons: Leak Rate: Scf/hr/pist Volume per event: 25.8 scf; 7.6 scf; 35.5 scf MMscf/event If you are requesting uncontrolled VOC emissions greater than 100 tpy for a gas/liquid separator, you must use Gas Venting as a process parameter. Are requested uncontrolled VOC emissions greater than 100 tpy? ❑ Yes Gas Venting Process Parameters5: Liquid Throughput Process Parameters5: Vented Gas Properties: ❑✓ No Vent Gas Heating Value: BTU/SCF Requested: 0.0204* MMSCF/year Actual: MMSCF/year -OR- Requested: bbl/year Actual: bbl/year Molecular Weight: 23.0 VOC (Weight %) 28.71; 28.71; 28.68 Benzene (Weight %) 0.051; 0.051; 0.048 Toluene (Weight %) 0.039; 0.039; 0.036 Ethylbenzene (Weight %) 0.001; 0.001; 0.001 Xylene (Weight %) 0.022; 0.022; 0.019 n -Hexane (Weight %) 0.392; 0.392; 0.392 2,2,4-Trimethylpentane (Weight %) 0.004; 0.004; 0.004 * Requested limit is 960 total pigging events per year Additional Required Information: ❑✓ Attach a representative gas analysis (including BTEX Et n -Hexane, temperature, and pressure) Attach a representative pressurized extended liquids analysis (including BTEX It n -Hexane, temperature, and pressure) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Form APCD-211 Gas Venting APEN - Revision 7/2018 COLORADO 3 I •.,F.. n rt,b , Permit Number: 97WE0349 AIRS ID Number: 123 /0035 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or!UTM) 40.5308 / -104.7575 era or E $t ac1C ID NOS Dischar a Hel htf E a �* Above Ground Level � � { Temp. (. F}� 1 ' � Flow Rate n {ACFM Velocityk ft/. .,a .. ,.�?;, �. _� ', _ 7 () a .. . .- Feet e F.. __...,. ,�jd.,._ - - �=.. PIG N/A N/A N/A N/A Indicate the direction of the stack outlet: (check one) ❑ Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑ Circular ❑ Other (describe): Interior stack diameter (inches): ❑ Upward with obstructing raincap Section 6 - Control Device Information ❑✓ Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. ❑ VRU: Pollutants Controlled: Size: Make/Model: Requested Control Efficiency: VRU Downtime or Bypassed: ❑ Combustion Device: Pollutants Controlled: Rating: Type: Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency: Minimum Temperature: MMBtu/hr Make/Model: Waste Gas Heat Content: Btu/scf Constant Pilot Light: ❑ Yes ❑ No Pilot burner Rating: MMBtu/hr Other: Pollutants Controlled: Description: Requested Control Efficiency: Form APCD-211 - Gas Venting APEN - Revision 7/2018 4I� COLORADO F. En.,roR 'm, Permit Number: 97WE0349 AIRS ID Number: 123 /0035 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (s' reduction): Pollutant • Description of Control Method(s). :.. . Overall. Requested :.Control.Efficiency (% reduction in emissions) PM SOX NO. CO VOC HAPs Other: From what year is the following reported actual annual emissions data? .-- Criteria Pollutant Emissions Inventery Pollutant Emission Factor Actual.Annual Emissions ,. :. -..•. .:. •Requested Annual Permit • Emission Limit(s)5 :.'.. • Uncontrolled Basis Units • : - . Source (AP -42, Mfg.: etc.. Uncontrolled • Emissions (tons/year) Controlled : Emissions6' • (tonslyear) - Uncontrolled - Em . issions (tanslyear):,;.: Controlled' 'Emissions (tons/year) . PM SOX NOx CO VOC 11.9; 3.5; 44.1 ib/blowdown Eng. Est. 7.88 7.88 ... Non -Criteria Reportable Pollutant Emissions Inventory ... `: Chemical Name Chemical Abstract Service CAS. .) Number "' Emission Factor • Actual Annual Emissions' Uncontrolled Basis . Units . . Source � .(AP=42, . Mfg.; etc.) tJ d ncontrolle .. : Emissions: ::(poundslyear) Controlled e : � emissions, i::-(pounds/year) : Benzene 71432 Toluene 108883 Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-211 Gas Venting APEN - Revision 7/2018 eun 5I hi, COLORADO Czw.macniowe Permit Number: 97WE0349 AIRS ID Number: 123 / 0035/ TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran 6V/4-'2Og/ Date Environmental Engineer Name (please print) Title Check the appropriate boa to request a copy of the: ❑✓ Draft permit prior to issuance ID Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: / /www.colorado. gov/cdphe/apcd Form APCD-211 - Gas Venting APEN - Revision 7/2018 COLORADO 6 1 •V I F7,ct=mt, Fugitive Component Leak Emissions APEN Form APCD-203 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for fugitive component leak emissions only. If your emission source does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, hydrocarbon liquid loading, condensate storage tanks, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 97WE0349 AIRS ID Number: RECE D SEP 1 7 7918 StarJCD Sou 123 /0035/ 0/9 [Leave blank unless APCD has already assigned a permit it and AIRS ID] Section 1 - Administrative Information Company Name: Site Name: DCP Operating Company, LP Eaton Compressor Station Site Location: Section 34, T7N, R66W Mailing Address: 370 17th Street, Suite 2500 (Include Zip Code) Denver, CO 80202 Site Location Weld County: NAICS or SIC Code: 1311 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com 1 Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-203 Fugitive Component Leak Emissions APEN - Revision 7/2018 387644 COLORADO 1 e, e« Permit Number: 97WE0349 AIRS ID Number: 123 /0035/TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action El NEW permit OR newly -reported emission source (check one below) -OR - ❑ MODIFICATION to existing permit (check each box below that applies) D Change process or equipment ❑ Change company name3 O Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership's ❑ Other (describe below) -OR- ❑ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - • APEN submittal for permit exempt/grandfathered source ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Et Notes: 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Information Company equipment Identification No. (optional): For existing sources, operation began on: FUG -1 TBD For new or reconstructed sources, the projected start-up date is: Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: Facility Type: ❑ Well Production Facility5 ❑✓ Natural Gas Compressor Stations ❑ Natural Gas Processing Plants ❑ Other (describe): hours/day days/week weeks/year 5 When selecting the facility type, refer to definitions in Colorado Regulation No. 7, Section XVII. Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision 7/2018 COLORADO 2rtrtrrnt Gas 28.71 Permit Number: 97WE0349 AIRS ID Number: 123 /0035 /TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Regulatory Information What is the date that the equipment commenced construction? Will this equipment be operated in any NAAQS nonattainment area? 0 Yes ❑ No Will this equipment be located at a stationary source that is considered a ❑ Yes 0 No Major Source of Hazardous Air Pollutant (HAP) emissions? Are there wet seal centrifugal compressors or reciprocating compressors ❑ Yes ❑✓ No located at this facility? Is this equipment subject to 40 CFR Part 60, Subpart KKK? ❑ Yes ❑✓ No Is this equipment subject to 40 CFR Part 60, Subpart OOOO? ❑ Yes 0 No Is this equipment subject to 40 CFR Part 60, Subpart OOOOa? ❑✓ Yes ❑ No Is this equipment subject to 40 CFR Part 63, Subpart HH? ❑ Yes 0 No Is this equipment subject to Colorado Regulation No. 7, Section XII.G? ❑ Yes 0 No Is this equipment subject to Colorado Regulation No. 7, Section XVII.F? ❑✓ Yes ❑ No Is this equipment subject to Colorado Regulation No. 7, Section XVII.B.3? El Yes ❑ No Section 5 - Stream Constituents ❑✓ The required representative gas and liquid extended analysis (including BTEX) to support the data below has been attached to this APEN form. Use the following table to report the VOC and HAP weight % content of each applicable stream. enzene.: wt%) 0.039 Ethylbenzene Xylene, (-t%) 0.392 0.004 0.051 0.001 0.022 Heavy Oil (or Heavy Liquid) Light Oil (or Light Liquid) 100 0.177 0.134 0.003 0.076 1.366 0.013 Water/Oil Section 6 - Geographical Information eographical Coordinate Latitude/Lo`n`gitude or_;UTM' 40.5308 / -104.7575 Attach a topographic site map showing location Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision 7/2018 COLORADO 3 1 Al. °`'.na; m.`, Permit Number: 97WE0349 AIRS ID Number: 123 / 0035 / TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Leak Detection and Repair (LDAR) and Control Information Check the appropriate boxes to identify the LDAR program conducted at this site: ❑ LDAR per 40 CFR Part 60, Subpart KKK ❑ Monthly Monitoring - Control: 88% gas valve, 76% light liquid valve, 68% light liquid pump O Quarterly Monitoring - Control: 70% gas valve, 61% light liquid valve, 45% light liquid pump ❑✓ LDAR per 40 CFR Part 60, Subpart 0000/0000a O Monthly Monitoring - Control: 96% gas valve, 95% light liquid valve, 88% tight liquid pump, 81% connectors ✓❑ LDAR per Colorado Regulation No. 7, Section XVII.F ❑ Other6: ❑ No LDAR Program 6 Attach other supplemental plan to APEN form if needed. Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision 7/2018 COLORADO 4 I Ava. :am.om, Gas' Permit Number: 97WE0349 AIRS ID Number: 123 /0035/TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Emission Factor Information Select which emission factors were used to estimate emissions below. If none apply, use the table below to identify the emission factors used to estimate emissions. Include the units related to the emission factor. Table 2-4 was used to estimate emissions7. ❑✓ Table 2-8 (< 10,000ppmv) was used to estimate emissions7. Use the following table to report the component count used to calculate emissions. The component counts listed in the following table are representative of: ❑✓ Estimated Component Count Actual Component Count conducted on the following date: Equipment Type: • Connectors. 105 Open -Ended., Lines;:,.:.: Pump Seals, 248 18 Count8 213 Emission Factor 2.21 E-05 1.26E-05 5.51 E-05 2.65E-04 Units lb/hr/source lb/hr/source lb/hr/source lb/hr/source Heavy Oil. (or Heavy Liquid Count8 Emission Factor Units Light Oil (or Light`Li_quid) • Count8 9208 1320 18 3185 105 Emission Factor 2.14E-05 5.29E-06 1.12E-03 4.19E-05 2.43E-04 Units lb/hr/source lb/hr/source lb/hr/source lb/hr/source lb/hr/source Water/Oil Count8 Emission Factor Units 7 Table 2-4 and Table 2-8 are found in U.S. EPA's 1995 Protocol for Equipment Leak Emission Estimates (Document EPA -453/R- 95-017). 8 The count shall be the actual or estimated number of components in each type of service that is used to calculate the "Actual Calendar Year Emissions" below. 9 The "Other" equipment type should be applied for any equipment other than connectors, flanges, open-ended lines, pump seals, or valves. Form APCD-203 Fugitive Component Leak Emissions APEN - Revision 7/2018 5 I A. COLORADO Cc -yammer,' of we -,c Permit Number: 97W E0349 AIRS ID Number: 123 /0035/TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 9 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. From what year is the following reported actual annual emissions data? Use the following table to report the criteria pollutant emissions and non -criteria pollutant (HAP) emissions from source: Use the data reported in Section 8 to calculate these emissions. Chemical Name. --- CAS Number; : Actual Annual Emissions `; Requested A i m t Permit Emission"- i )ii :.• :.•a Uncontrolled' (tons/year) : Controlled10 ; (tons/year) ::.a :. Uncontrolled . .: .:', (tons/year): .. Controlled (tons/year) VOC 2.39 2.39 Does the emissions source have any actual emissions of non -criteria pollutants (e.g. HAP - hazardous air pollutant) equal to or greater than 250 lbs/year? Yes No If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source: Chemical Name. - 71432 ctual.Annual Emissions equested Annual: Permit Emission ; Ltmtt(s):i 'Uncontrolled (ttis/year) Controlled?.°. (lbsIyear) ._ Uncontrolled;. • (lbs/year); Controlled, fibs/year).... Benzene Toluene 108883 Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 2,2,4 Trimethylpentane 540841 Other: 10 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Requested values will become permit limitations. Requested limit(s) should consider future process growth, component count variability, and gas composition variability. Form APCD-203 Fugitive Component Leak Emissions APEN - Revision 7/2018 6 I A COLOR DO oru iica31, En'l12Nn%v Permit Number: 97WE0349 AIRS ID Number: 123 /0035 /TBD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 10 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran Date Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: Draft permit prior to issuance 0 Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B 1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: / /www.colorado. goy /cdphe/apcd Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision 7/2018 COLORADO 7 AV: Dert:nem Pubds W..≤mnmRmnu Hello