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Home My WebLink About20181778.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 May 30, 2018 Dear Sir or Madam: RECEIVED JUN 042018 WELD COUNTY COMMISSIONERS On May 31, 2018, the Air Pollution Control Division will begin a 30 -day public notice period for Summit Midstream Niobrara, LLC - Hereford Ranch Processing Plant. 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 Denser, Colorado 80246-1530 Attention: Clara Gonzales Regards, Clara Gonzales Public Notice Coordinator Stationary Sources Program Air Pollution Control Division Enclosure ?,tiol►c, ke,t/LIA.4) 06-13 -IS ec ?L. (null Ire), 14LC1Tl, 17KER/CHI AJGK) 06-fly-l�r 4300 Cherry Creek Drive S., Clenver, CO 80246-1530 P 303-692-2000 www.colorado.gov/cdphe John W. Hickentooper, Governor I Larry Wolk, MD, MPH, Executive Director and Chief Medical Officer 2018-1778 Air Pollution Control Division Notice of a Proposed Project or Activity Warranting Public Comment Website Title: Summit Midstream Niobrara, LLC - Hereford Ranch Processing Plant - Weld County Notice Period Begins: May 31, 2018 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: Summit Midstream Niobrara, LLC Facility: Hereford Ranch Processing Plant Natural Gas Processing Plant Section 26, T12N, R63W, Weld County, CO Weld County The proposed project or activity is as follows: Modification to existing plant process flare, consolidation of two previously permitted but unconstructed amine units into one larger unit, addition of hot oil heaters for amine regeneration and addition of natural gas fired engine. Increase in permitted plant emissions. 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 10WE2188 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. Any such comment must be submitted in writing to the following addressee: Christian Lesniak Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South, APCD-SS-B1 Denver, Colorado 80246-1530 cdphe.commentsapcd@state.co.us 1 QRADO Ski:s3omm�m). Summary of Preliminary Analysis - NG RICE Company Name Summit Midstream Niobrara, LLC Facility Name Hereford Ranch Processing Plant Facility Location Section 26, Township 12N, Range 63W Facility Equipment ID ENG-1 Permit No. AIRS Review Date Permit Engineer 10WE2188 123/8761/040 01/01/1900 Christian Lesniak Requested Action New permit/newly reported emission Issuance No. 6 Emission Point Description One (1) Caterpillar, Model G3608 TALE, Serial Number To Be Determined, natural gas -fired, turbo -charged, 4SLB reciprocating internal combustion engine, site rated at 2317 horsepower. This engine shall be equipped with an oxidation catalyst and air -fuel ratio control/non-selective catalytic reduction (NSCR) system and air -fuel ratio control/This engine is not equipped with emission controls. This emission unit is used for natural gas compression. Natural Gas Consumption Nours of Operation Requested (mmscf/yr) 151.37 Requested (mmscf/m) 12.86 Fuel Heat Value (btu/scf) 1020 BSCF (Btu/hp-hr) 7607 Emission Factor Sources PTE Calculated at (hpy) Permit limits calculated at (hpy) 8760 8760 Uncontrolled Controlled NOx Manufacturer 0 VOC Manufacturer 0 CO Manufacturer 0 Formaldehyde Manufacturer 0 SOX AP -42; Table 3.2-2 (7/2000); Natural Gas No Control TSP AP -42; Table 3.2-2 (7/2000); Natural Gas No Control PM10 AP -42; Table 3.2-2 (7/2000); Natural Gas No Control PM2.5 AP -42; Table 3.2-2 (7/2000); Natural Gas No Control Other Pollutants Describe EF sources - HAPs etc. Describe EF sources - HAPs, etc. Point Summary of Criteria Emissions (t Uncontrolled Requested Controlled Requested PTE Proposed Control Efficiency NOx 11.2 11.2 11.2 0.0% VOC 19.9 15.7 19.9 21.4% CO 61.5 4.3 61.5 93.0% SOx 0.0 0.0 0.0 0.0% TSP 0.8 0.8 0.8 0.0% PM10 0.8 0.8 0.8 0.0% PM2.5 0.8 0.8 0.8 0.0% Total HAPs* 0.0 0.0 7.3 0.0% *Uncontrolled requested and controlled, requested totals include HAPs only if the uncontrolled actual values are above de minimus thresholds. PTE includes all HAPs calculated, even those below de minimus. Point Summary of Hazardous Air Pollutants (lb/yr HAP Name Uncontrolled Requested Controlled Requested PTE Proposed Control Efficiency Formaldehyde 11634 11634 11634 0.0% Acetaldehyde 1291 1291 1291 0.0% Acrolein 794 - 794 794 0.0% Methanol 386 386 386 0.0% n -Hexane * * 171 0.0% Benzene * * 68 0.0% Toluene * * 63 0.0% *Uncontrolled requested and controlled requested values are shown only for pollutants where REQUESTED UNCONTROLLED is greater than de minimus Permitting Requirements Ambient Air Impacts Source is not required to model based on Division Guidelines/No NAAQS violations expected (see details of modeling analysis) Public Comment Public Comment Required MACT Z777 New/Recon 4SLB over 500 HP located at a(n) Area Source Reg 7 XVII.E Standards (g/hp-hr) NOx: 1.0 CO: 2.0 VOC: 0.7 Reg 7 XVI.B (Ozone NAA requirements) applies? No MACT ZZZZ (area source) Is this engine subject to MACT ZZZZ area source requirements? Yes NSPS JJJJ Is this engine subject to NSPS JJJJ? Yes Note: JJJJ requriements are not currently included as permit conditions because the reg has not been adopted into Reg 6. Comments/Notes 0 Preliminary Analysis: RICE Emission Calculations - NG RICE Company Name Summit Midstream Niobrara, LLC Permit No. 10WE2188 AIRS 123/8761/040 Engine Type 4SLB Throughputs MMBtu/yr MMscf/yr Requested Fuel Consumption (MMBtu/yr) 154398.7 151.3712 Max Potential Fuel Consumption (MMBtu/yr) 154398.7 151.3712 Actual Fuel Consumption (MMBtu/yr) Emissions (tpy) - Criteria PM10 PM2.5 TSP SO2 NOx VOC CO Uncontrolled Requested Emissions 0.8 0.8 0.8 0.0 11.2 19.9 61.5 Controlled Requested Emissions 0.8 0.8 0.8 0.0 11.2 15.7 4.3 PTE 0.8 0.8 0.8 0.0 11.2 19.9 61,6 Uncontrolled Actual Emissions Controlled Actual Emissions Emission Factors - Criteria PM10 PM2.5 TSP SO2 NOx VOC CO lb/MMBtu - Uncontrolled 0.010 0.010 0.010 0.001 0.145 0.258 0.797 lb/MMBtu - Controlled 0.010 0.010 0.010 0.001 0.145 0.203 0.056 % Control 0.0 0.0 0.0 0.0 0.0% 21.4% 93.0% Emission Factor Sources/Notes: Controlled Uncontrolled PM10 No Control AP -42; Table 3.2-2 (7/2000); Natur SO2 No Control AP -42; Table 3.2-2 (7/2000); Natur NOx 0 Manufacturer VOC 0 Manufacturer CO 0 Manufacturer PM2.5 No Control AP -42; Table 3.2-2 (7/2000); Natur TSP No Control AP -42; Table 3.2-2 (7/2000); Natur Printed 5/29/2018 Colorado Department of Public Health Envrionment Air Pollution Control Division Page 3 of 5 Preliminary Analysis: RICE Emission Calculations Company Name Permit No. AIRS Emissions - NCRPs Summit Midstream Niobrara, LLC 10WE2188 123/8761/040 Colorado Department of Public Health Envrionment Air Pollution Control Division Pollutant Formaldehyde 50000 A 11634.2 11634.2 11634.2 Acetaldehyde 75070 A 1290.8 1290.8 1290.8 Acrolein 107028 A 793.6 793.6 793.6 Methanol 67561 C 386.0 386.0 386.0 n -Hexane 110543 C 171.4 171.4 171.4 Benzene 71432 A 67.9 67.9 67.9 Toluene 108883 C 63.0 63.0 63.0 1,3 -Butadiene 106990 A 41.2 41.2 41.2 2,2,4-Trimethylpentane 540841 C 38.6 38.6 38.6 Biphenyl 92524 C 32.7 32.7 32.7 Xylene 1330207 C 28.4 28.4 28.4 Naphthalene 91203 B 11.5 11.5 11.5 Ethylene Dibromide 106934 A 6.8 6.8 6.8 1,1,2,2-Tetrachloroethane 79345 A 6.2 6.2 6.2 Ethylbenzene 100414 C 6.1 6.1 6.1 Carbon Tetrachloride 56235 A 5.7 5.7 5.7 2-Methylnaphthalene 91576 0 5.1 5.1 5.1 1,1,2-Trichloroethane 79005 A 4.9 4.9 4.9 Chlorobenzene 108907 A 4.7 4.7 4.7 CAS BIN Re uested Controlled Uncontrolled lb/yr Ib/yr PTE lb/yr Chloroform 67663 A 4.4 4.4 4.4 PAH 0 0 4.2 4.2 4.2 1,3-Dichloropropene 542756 A 4.1 4.1 4.1 Phenol 108952 C 3.7 3.7 3.7 Styrene 100425 C 3.6 3.6 3.6 Methylene Chloride 75092 A 3.1 3.1 3.1 Vinyl Chloride 75014 A 2.3 2.3 2.3 Phenanthrene 0 0 1.6 1.6 1.6 Fluorene 7782414 C 0.9 0.9 0.9 Acenaphthylene 0 0 0.9 0.9 0.9 Tetrachloroethane 79345 A 0.4 0.4 0.4 Pyrene 0 0 0.2 0.2 0.2 Acenaphthene 0 0 0.2 0.2 0.2 Fluoranthene 0 0 0.2 0.2 0.2 Chrysene 0 0 0.1 0.1 0.1 Benzo(e)pyrene 0 0 0.1 0.1 0.1 Benzo(g,h,i)perylene 0 0 0.1 0.1 0,1 Benzo(b)fluoranthene 0 0 0.0 0.0 0:0 0 0 0 0.0 0.0 0.0 0 0 0 0.0 0.0 0.0 Actual Controlled lb/yr Uncontrolled lb/yr Cont. Req. actual>Rep lb/yr 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 PTE >Reportable lb/yr 11634.2 1290.8 793.6 386.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Unc. Requested actual>Rep lb/yr 0.0 0.0 0.0( 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Printed 5/29/2018 Page 4 of 5 Preliminary Analysis: RICE Emission Calculations Company Name Permit No. AIRS Summit Midstream Niobrara, LLC 10WE2188 123/8761/040 Emission Factors - NCRPs Colorado Department of Public Health Envrionment Air Pollution Control Division Pollutant CAS Controlled Uncontrolled Emission Factor lb/MMBtu Ig/bhp-hr % Control Notes Emission Factor Ib/MMBtu Ig/bhp-hr Notes Formaldehyde Acetaldehyde Acrolein Methanol n -Hexane 0 0.00111 0.003830035 0.0% No Control Benzene 0 0.00044 0.001518212 Toluene 0 _ 0.000408 0.001407797 1,3 -Butadiene 0 0.000267 0.000921279 2, 2, 4-Tri methy l penta ne Biphenyl Xylene Naphthalene Ethylene Dibromide 1,1,2,2-Tetrachloroethane Ethylbenzene Carbon Tetrachloride 2-Methylnaphthalene 1,1,2-Trichloroethane Chlorobenzene 50000 0 0 0 0.075351793 0.26 0.00836 0.028846029 0.00514 0.017735477 0.0025 0.008626205 0.0% 0.0% No Control 0.0% No Control 0.0% No Control Chloroform PAH 1,3-Dichloropropene Phenol Styrene Methylene Chloride Vinyl Chloride Phenanthrene Fluorene Acenaphthylene Tetrachloroethane Pyrene Acenaphthene Fluoranthene Chrysene Benzo(e)pyrene Benzo(g,h,i)perylene Benzo(b)fluoranthene 0 0.0% No Control 0.0% No Control OM No Control 0 0.08 0.26 Manufacturer 0.00836 0.02885 AP -42; Table 3.2-2 (7/2000); Natural Gas 0.00514 0.01774 AP -42; Table 3.2-2 (7/2000); Natural Gas 0.0025 0.00863 AP -42; Table 3.2-2 (7/2000); Natural Gas 0.00111 0.00383 AP -42; Table 3.2-2 (7/2000); Natural Gas 0.00044 0.00152 AP -42; Table 3.2-2 (7/2000); Natural Gas 0.000408 0.00141 AP -42; Table 3.2-2 (7/2000); Natural,Gas 0.000287 0.00092 AP -42; Table 3.2-2 (7/2000); Natural Gas 0 0.00025 0.00086262 0.0% No Control 0.00025 0.00086 AP -42; Table 3.2-2 (7/2000); Natural Gas 0 0.000212 0.000731502 0.0% No Control 0.000212 0.00073 AP -42; Table 3.2-2 (7/2000); Natural Gas 0 0.000184 0.000634889 0.0% No Control 0.000184 0.00063 AP -42; Table 3.2-2 (7/2000); Natural Gas 0 0.0000744 0.000256716 0.0% No Control 7.44E-05 0.00026 AP -42; Table 3.2-2 (7/2000); Natural Gas 0 0.0000443 0.000152856 0.0% No Control 4.43E-05 0.00015 AP -42; Table 3.2-2 (7/2000); Natural Gas 0 0.00004 0.000138019 0.0% No Control 0 0.0000397 0.000136984 0.0% No Control 0 0.0000367 0.000126633 0.0% No Control 0 0.0000332 0.000114556 0.0% No Control 0 0.0000318 0.000109725 0.0% No Control 0 0.0000304 0.000104895 0.0% No Control 0 0.0000285 9.83387E-05 0.0% No Control 0 0.0000269 9.2818E-05 0.0% No Control 0 0.0000264 9.10927E-05 0.0% No Control 0 0.000024 8.28116E-05 0.0% No Control 0 0.0000236 8.14314E-05 0.0% No Control 0 0.00002 6.90096E-05 0.0% No Control 0 0.0000149 5.14122E-05 0.0% No Control 0 0.0000104 3.5885E-05 0.0% No Control 0 0.00000567 1.95642E-05 0.0% No Control 0 0.00000553 1.90812E-05 0.0% No Control 0 0.00000248 8.5572E-06 0.0% No Control 0 0.00000136 4.69266E-06 0.0% No Control 0 0.00000125 4.3131E-06 0.0% No Control 0 0.00000111 3.83003E-06 0.0% No Control 0 0.000000693 2.39118E-06 0.0% No Control 0 0.000000415 1.43195E-06 0.0% No Control 0 0.000000414 1.4285E-06 0.0% No Control 0 0.000000166 5.7278E-07 0.0% No Control 0 0 0 #DIV/0! 0 0 0 #DIV/0! 0.00004 0.00014 AP -42; Table 3.2-2 (7/2000); Natural Gas 3.97E-05 0.00014 AP -42; Table 3.2-2 (7/2000); Natural Gas 3.67E-05 0.00013 AP -42; Table 3.2-2 (7/2000); Natural Gas 3.32E-05 0.00011 AP -42; Table 3.2-2 (7/2000); Natural Gas 3.18E-05 0.00011 AP -42; Table 3.2-2 (7/2000); Natural Gas 3.04E-05 0.0001 AP -42; Table 3.2-2 (7/2000); Natural Gas 2.85E-05 9.8E-05 AP -42; Table 3.2-2 (7/2000); Natural Gas 2.69E-05 9.3E-05 AP -42; Table 3.2-2 (7/2000); Natural Gas 2.64E-05 9.1E-05 AP -42; Table 3.2-2 (7/2000); Natural Gas 0.000024 8.3E-05 AP -42; Table 3.2-2 (7/2000); Natural Gas 2.36E-05 8.1E-05 AP -42; Table 3.2-2 (7/2000); Natural Gas 0.00002 6.9E-05 AP -42; Table 3.2-2 (7/2000); Natural Gas 1.49E-05 5.1E-05 AP -42; Table 3.2-2 (7/2000); Natural Gas 1.04E-05 3.6E-05 AP -42; Table 3.2-2 (7/2000); Natural Gas 5.67E-06 2E-05 AP -42; Table 3.2-2 (7/2000); Natural Gas 5.53E-06 1.9E-05 AP -42; Table 3.2-2 (7/2000); Natural Gas 2.48E-06 8.6E-06 AP -42; Table 3.2-2 (7/2000); Natural Gas 1.36E-06 4.7E-06 AP -42; Table 3.2-2 (7/2000); Natural Gas 1.25E-06 4.3E-06 AP -42; Table 3.2-2 (7/2000); Natural Gas 1.11E-06 3.8E-06 AP -42; Table 3.2-2 (7/2000); Natural Gas 6.93E-07 2.4E-06 AP -42; Table 3.2-2 (7/2000); Natural Gas 4.15E-07 1.4E-06 AP -42; Table 3.2-2 (7/2000); Natural Gas 4.14E-07 1.4E-06 AP -42; Table 3.2-2 (7/2000); Natural Gas 1.66E-07 5.7E-07 AP -42; Table 3.2-2 (7/2000); Natural Gas 0 0 0 0 0 0 0 0 Printed 5/29/2018 Page 5 of 5 Colorado Air Permitting Project PRELIMINARY ANALYSIS - PROJECT SUMMARY Project Details Review Engineer: Package it Received Date: Review Start Date: 4/12/2018' C 2/9/2018' Section 01- Facility Information Company Name: County AIRS ID: Plant AIRS ID: Facility Name: Physical Address/Location: Section 26, Township 12N, Range 63W County: 'Weld County Type of Facility: t What industry segment? Is this facility located in a NAAQS non -attainment area? If yes, for what pollutant? D Carbon Monoxide (CO) Section 02 - Emissions Units In Permit Application .Sd snhit.MidtreemNiohrarS, LL'C 876E Iflerefdrd Raft Quadrant Section Township Range 26 Particulate Matter (PM) ❑ Ozone (NOx & VOC) AIRs Point # Emissions Source Type Equipment Name Emissions Control? Permit # Issuance # Self Cert Required? Action Engineering Remarks 023 Prose s l lbre �L02 Yes 10WE2188 ' 6 l3 f e'oermit � imit" '3 / E �� 4 p duetocorrected EFsand S �a throughput3 034 E� €E y !" „€ E� € _� A 03 ;E €E t £ tiY 1OWE2188:, 6 Combuwtion of two $mli1e't'IOP,;rvir}i Q� gE #f36) intositg ₹ biMscfctttttd Point03593: will be cancel ed pn �r startup) 037 Boilel orProcess flea FITSS02 ' o 1OWE2188 6 3 v 038 bore t€103 _-'4WE2388' / ' 039 � - � � � 'i �"s ' t " , zfeat � d. 3 ._�� ... 6704 E 18WE0449-:' .... M1� 3�i � E� `€'/1Sn Ej33 ,r, •� Point insets Categorical s pe�m�3n„xempGoii � r <• heater 1tMMMBtu hr 04fl £NG 1 P w 30WE238Y 6 Q6�� f,..A Sheet in file:`: iS j1�WE$1$B.�PCtL140j . `s r--- Section 03 - Description of Project Modification'4nd additidn'of points:'Pdint d2Glycol behy `era3 Meadowlark Midstream, but submitted addendum to application Section 04 - Public Comment Requirements Is Public Comment Required? If yes, why? elled Wit tinder new C ever panyoriginallysubmitted part of this modifitationflri 1f /20i8, under: McnikMitietreentililobrarkilC g�E Section 05 - Ambient Air Impact Analysis Requirement Was a quantitative modeling analysis required? If yes, for what pollutants? If yes, attach a copy of Technical Services Unit modeling results summary. Colorado Air Permitting Project 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? If yes, explain what programs and which pollutants hers 5O2 Prevention of Significant Deterioration (PSD) Title V Operating Permits (OP) Non -Attainment New Source Review (NANSR) SO2 NOx CO VOC PM2.5 PM10 TSP HAPs NOx CO VOC PM2.5 PM10 TSP HAPs ❑ ❑ Produced Natural Gas Venting/Flaring Preliminary Analyse Sectionol- Administrative Infontmtion (FaciMy AIRS ID: County Section 02 -Equipment Descdo0on Deeds Plant Poi Emergency flare for plant emergency shutdowns. presume relief wives, compressor bbwdoo s, and other miscellaneous sources. Flare has a minimum destruction efficiency of 95% and 8 is not enclosed. Control Efficiency 95% 5ectlon 03-Procealne Rate Information for Emissions Estimates Fiore Pilot Rating 0.21098112 MMBWrhr Fuel Gas Heat Value 1098.86 Btu/sof G. streams Residue Piles Gas Residue Waste Gas Inlet Wate Gas ford 2.03090713 MMsd/fr Per Source Hours of operati 8760 lr/yr 18.25 MMsef/yr 1050 BhJacf as Natural Gas 82125 MMsd/yr 960 Shied 82125 MMscf/yr 1269 Btu/sd Leon MMscf/yr. 1108.05 Weighted Avg BOilsd Total He. lnouf 202219.1250 MMBtu/yr 21875 MMBturhr 9.00 MMBOLhr 11.896875 MMBMIhr 1.7 MMscf/yr 0.14 seeehm Saepan 04- Emission Factors & Methodoloeies Residue Gas= Pt050 Waste Emission Calculation Method EPA Emission Inventory Improvement Program Publication: Volume II. Chapter 10 - Displacement Equation (10.4-3) Ex = 0' MW'XxIC Ex = emissions of pollutant x G = Volumetric flow rate/volume of gas processed MW = Molemuar veigM of gas = SG of gas' MW of air Xx = mass fraction of x in gas C = molar volume of ideal gas (379 scf/Ib-moo at 60F end 1 atm Maximum Vent Rate I 0 stifle Requeefed7Magfqut (0) 82.13 MMael/yr 9375.0 aclRv I 0.225 MMect/d I 6.98 MMscf/no %Vented I 100% MW 17.5891bilbmd Component mole% MW Ibx/bmol mass fraction E Ib/hr lb/yr tpy Mellon 0 4.0028 0.000 0.000 Helium 00 0 000 CO2 0.377 4401 0.166 0.009 CO2 4.1 3694 17.98 N2 1.3708 28.013 0.384 0.022 N2 9.5 83209 41.60 methane 88.8254 16041 14.409 0.819 methane 358.4 3122244 1561.12 ethane 7.6833 30.083 2.313 0.131 ethane - 57.2 50118 250.58 propane 0.6959 44.092 0.3068 0.017 propane 7.6 66488 3324 iagm4ane 0.0071 58.118 0.0341 0.000 uobudane 0.1 694 045 nbutane 00099 58.118 0.0058 0.000 n -butane 0.1 1247 0.62 le0padaie 0.0002 72.114 0.0001 0.000 ieopedane 0.0 31 0.02 n -pentane 0.0002 72.114 0.0001 0.000 n-prdare 0.0 31 0.02 cyclopentane 0 70.13 0.0=00 0.000 cycbpmaene 0.0 0 0.00 n -Hexane 0.0001 86.18 0.0001 0.000 n -Hexane 0.0 19 0.01 Mishears 0.0000 84.16 0.0000 0.000 c/cldnvre 0.0 0 0AO Other hexates 0.0001 88.18 0,0001 0.000 Other hvaes 00 19 0.01 heptanes 0.0001 100.21 0.0001 0.000 he9fares 00 22 0.01 melfr/lc)cbhnane 0 98.19 0.0000 0.000 melhybycbtglae 0.0 0 0,30 224-TMP 0 114.23 00000 0.000 224 -IMP 0.0 0 0.00 Benzene 0 78.12 0ocoo 0.000 Benzene 0.0 0 000 Toluene 0.0001 92.15 00001 0800 Tame 0.0 20 0.01 EBMbenzene 0 106.17 0.0000 0000 EOrylbereene 00 0 000 Xylcrtes 0 106.17 0.0000 0.000 )(Wanes 0.0 0 OW CB+ Heavies 0.0001 121216 00001 0.000 08+ Heavies 0.0 26 0.01 99.8803 VOC Souse requested Nf6ne mass fraction: 0.0181 Tall VOC Emissions (Uncontrolled) mess fraction: 0.22 Requested Total VOC Emissions (Uncontrolled) 34.4 4182 Mole %. MW. and mass fractions are based on 2015 anemia of Residue Gas at Hereford Ranch Natural Gas Processing Plant Enessias are based an 8760 hove of operation per year. MW 0008+ is assumed to be 121.2155 Inlet Waste GAS Emission Calculation Method EPA Emission Inventory Improvement Program Publication: Vohme II, Chapter 10 - Displacement Equation (10.4-3) Ex=O'MW'Xx/C Ex = emissions of pollutant x 0 = Volumetric flow rate/where of gas processed MW = Molecular weight of gas = SG of gas MW of air Xx = mass fraction of x in gas C = molar vohme of ideal gas (379 sof/b-mat) at GOP and 1 amt Maxmum Vent Rate I 9376 sof/hr Remested houghpM (01 82.1 MMecf/y7 9375.0 scf/1r I 0225 MMscf/d I 6.98 MMecemo % Vented I 100% MW 24.765 lb/mot Component mole% MW lbwlluml mass fraction E IWhr Iblyr MY Helium 0 40026 0000 0000 Helium 0.0 0 000 CO2 2.8702 44.01 1.263 0051 CO2 312 273716 136.86 N2 1.0433 28,013 0,292 0012 N2 72 63329 31.8 methane 66.5635 16.041 10677 0431 methane 264.1 2313882 1156.84 ethane 12.0611 30.063 3.628 0.146 ethane 69.7 785698 382.85 propane 10.6781 44.092 4.7082 0190 propane 116.5 1020211 510.11 Ieobodane 1.042 58,118 0.686 0024 ieabtsane 150 131124 65.61 nbulare 3.5836 58,118 20710 0.84 n -butane 51.2 448/70 224.38 ieapadate 0.0672 72,114 0.4811 0.019 lecoadane 11.9 104253 - 52.13 n -pentane 0.8333 72.114 0.608 0024 n -pentane 14.9 130214 8.11 c900openiare 0.0785 70.13 0851 082 cwlopentans 1.4 11929 5.96 n -Hexane 0.1487 8.18 0.1281 008 n-Hesas 3.2 27769 13.88 cycloheoaie 0.0508 84.16 00428 0002 cycloteQe 1,1 9264 4.63 Other tisanes 0.2465 86.18 02124 0809 Other hmaea 5.3 4682 23.02 hipbones 0.0234 100.21 0.0234 0801 hsptams 0.6 5081 2.54 nldhylcycldtatane 00217 98.19 00213 0.001 nethylcwldexae 05 4817 2.31 224-TMP 0.0137 11423 00158 0801 224-TMP 0.4 3391 1.70 Benzene 0.0215 78.12 00168 0001 Benzene 04 3669 1.82 Toluene 0.0098 92.15 0080 0000 Toluene 02 1957 098 Ethrtbermerte 00013 18.17 08014 0.000 Ethylbeeene 00 269 015 Xylenes 0.002 18.17 0.0021 0800 Xylenea 0.1 460 023 080 Heavies 0.0038 121.218 00046 0800 080 Heavies 01 998 050 999433 VOC H2S 08009 34.081 Me men fraction 0.3634 Total VOC Emissions (Uncontrolled) 975.1 0800034 0800814 0001 7.38 0.00 Mole A. MW, and mass (rasters am based on 2015 analyse of Residue Gas at Hereford Ranch Natural Gas Processing Plate Emissions are based on 8760 hours of operation per year. MW of C8+ is assumed to be 121,2155 Colorado Department of Public Health and Environment Air Pollution Control Diesbn Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment Air Pollution Control Division Uncontrolled toy Ib/y7 r VOC 1009.5 Benzene 1.8197 3639 Toluene 0.9884 1977 Ethylbenzene 0.1495 299 Xylene 0.2301 460 n -Hexane 13.9 27787 0 Section 05 -Emissions Inventory 201338.9 1008.894395 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) lb/31 day lb/ quarter 0 3 1 3 1168 3466 5324 15801 8573 25444 PM10 PM2.5 Nos CO VOC 0.0 0.0 _ 0.0 _ _ 0.0 0.0 0.0 0.0 0.0 0.0 0.0 6.9 6.9 6.9 6.9 6.9 31.3 31.3 31.3 313 31.3 1009.5 1009.5 50.5 1009.5 50.5 Hazardous Air Pollutants Potential to Emit Uncontrolled pons/yearl Actual Emissions Uncontrolled Icons/yeaq Controlled pons/yeaq Requested Permit Limits Uncontrolled Controlled (tons/yearl a (tons/yearl Requested Permit Limits Uncontrolled Controlled lie/yrl llo/yr) Benzene Toluene Etttlbenzerle Xylene n-Hanzne 224 IMP 1.82 1.82 0.09 1.82 0.09 3639 182 0.99 0.99 0.05 0.99 0.05 1977 99 0.15 0.15 0.01 0.15 0.01 299 15 0.23 0.23 0.01 0.23 0.01 460 23 13.89 13.89 0.69 13.89 0.69 27787 1389 0.00 0.00 0.Oo 0.00 0.00 0 0 1708 Section 06 -Regulatory Summery Analysis Regulation 3, Parts A, B Regulation 7, Section 10.41.0 Regulation 7. Section XV11.0.2.0 Unit is required to have an ADEN end a permit unit is not used to comply with Reg> Unit is not used as en ahernadve control device for Reg 7 Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Heakh and Environment Air Pollution Control Division ;motion 02 - INtld end Periodic Semolina and Tesdnggeganments Was a see -specific gas sample collected within a year of application submittal used to estimate emissions? If no, the permit will contain an °Initial Compliance' testing requirement to demonstrate compliance with emission Bmks Does the company request a control device efflclenrygeater than 95% for a flare or combustion device? Destruction effidency cannot be tested on an open flare. 5ectton 09 -Inventory SCC Coding and Emissions factors AIRS Pant It 005 I.M0I seat blawdwvaamiwntingbpel000te. asw isscon tagtets have also boonupdated..TT ca.„18.25 MMsof/yreomffi&drwm papogas 15482.1 salfip rB aperiodicsompila Process SCC Code 01 swamies Th modlrrcallaolaarod brfoi.. onthe weighted aoenage of infaean ---- UncontrolledEmissions Pollutant Factor Control% PM10 7.600 0.0% PM2.5 7.600 0.0% NOa 75.347 0.0% VOC 11062.6 95A% CO 343.496 0.0% Benzene 199422 95.0% Toluene 108319 95.0% Ethyibensen 1.6388 95.0% Xylene 2.5212 95.0% n-Heaane 152.2589 95.0% 224TMP 0.000 iDIV/01 Glycol Dehydrator Emissions Inventory Section 01 -Administrative Information (Facility AIRS ID: Section 02 -Equipment Description Details Amine Sweetening Unit Information Amine Type: • Make: Model: Serial Number. Design Capacity. Recirculation Puna Information Number of Pumps Pu my Type Make: Model: Design/Max Recirculation Rate: Amine Unit Equipment Flash Tank Reboiler Burner Stripping Gas Dehydrator Equipment Description I,-.. County OD4 Paled P MMscf/day gallons/minute , flash tank, and reboiler burner Methyldiethanolamine (M0EA) natural gee swretening system with a design capacity of 62.7 MMsd/day (Make: TBD; Model: TBD) SN: TE M). This emissions unit is egmpped with Two (2) amine recirculation pumps with a total limited capacity of 300 galbrs per minute of lean amine. This system includes one (1) natural gas/amine contactor, a flash tank, still vent, and hot oil rebollers (AIRS Points 036, 037, 038). The acid gas stream from the still overheads and from the flash tank is routed toe thermal oxidizer (Make: TBD; Model: Tee; Emission Control Devke Description: SN: TBD) with a minimum destruction efficiency of 98% for VOC. Destruction efficiency for H25 U 96.45%. Section 03 -Processing Rate Information for Emissions Estimates Primary Emisiore: - Amine Acid Gas and Flash Tandy Requested Permit Limit Throughput Potential to EmR (PTE) Throughput = 2,2,89&: MMsd per year 22,886 MMsd per year, Secondary Emissions -Combustion Device(s)for Air Pollution Control Still Vent Control Primary control device: Primary control device operation: Secondary control device: Secondary control device operation: Still Vent Gas Heating Value: Still Vent Warn Gas Went Rate: Flash tack Control Primary control device: Primary control device operation: Secondarycontrd device: Secondary control device operation: Flash Tank Gas Heating Value Flash Tank Warn Gm Vent Rate: 1944 MMscf per month 96.45% HIS Control 9820. Control Effidenq% ':95%'. Control Efflcienry % Still Vent Primary Control: Still Vent Secondary Control: Still Vent Primary Control: Still Vent Secondary Control: (Unbuffered) Wet Gas Processed: 22,885.5 MMsd/yr 0.0 MMscf/yr Waste Gas Combusted: 1,468.4 MMsd/yr 0.0 MMsd/yr 124.71579 MMsd/Mo Still. Flash 1,495.1 MMsd/yr 7.69E-01 MMmu/hr 126.9845777 MMtcf/Mo Wet Gas processed: Control Efficiency% Flash Tank Primary Control: 22,8855 MMscf/yr Flash Tank Secondary Control: 0.0 MMsd/yr Waste Gas Combusted: Flash Tank Primary Control: 26.7 MMscf/yr Flash Tank Secondary Control: 0.0 MMscf/yr 2.2687877 MIVIscf/Mo Glycol Dehydrator Emissions Inventory Section 04 - rm4sbr a Factors & Methodolodes Amine Unit The*** aeAMnt4#A#0estlrr etAe*DegAt Je4tgea by ARP.Thetredrd 4bpeedonUtetdHRwing)glamooerai Input Parameters Inlet Gas Prostate Inlet Gas Temperature Requested Glycol Recirculate Rate 'Total TO Burner Rating Supplemental Fuel Heat content Water Carbon 21004e Hydrogen Sulfide Nitrogen Methane Ethane Propane n -Butane Iso-Bubne n -Pentane Ho -Pentane CycloPatbne n -Haase CykbHaane n-Heptane 2 -Methyl Hexane Toluene n -Octane Ethyl Benzene tylene Ibmol/hr Oecane Ibmol/tr 'TOTAL 0000' 39.62 MMBtu/hr Benzene 3.26E+00 1075.41 btu/sd Stil Vent Idh tom/yr lb/hr 2.81E+02 1232.58 3.2675 9.28E+03 40661.34 20.14% 9.50E-01 4.16 0.0021938 3.00E-02 0.13 0324525 9.96E+00 43.62 862759 2.68E+00 33.64 34.1755 5.56E+00 24.35 29.0104 1.25E+00 7.67 2.49966 3.40E-01 1.49 2.18478 1.30E-01 0.57 0.250884 8.00E-02 0.35 0.56361 0.00E+00 0.00 0 2.00E-02 0.09 0.11 0.1 0.48 1428 0.0 0.04 284.7 MMscf/yr 242 MMsd/month 0.33 0.16 0.06 "Based on Total rating Flesh Tank toot/tt 14.31 88.26 041 3.83 377.89 149.69 122.01 3295 9.57 3.29 2.47 0.00 048 1.45 0.61 0.26 0.0o a.ao 0 0.m 0.88 3.T2 300E-02 0.13 000 000 0.000000 0.00 0.02 0.09 0.00EM0 0.00 0.07 0.31 000E.00 0.09 0.00 0.01 0 0.00 12.21 53.49 40.68 12818 c After subtracting still vent gas Glycol Dehydrator Emissions Inventory STILL VENT Polhbr4 VOC H2S Benzene Toluene Ethylberaerc Xyknes n -Haan 224-TMP Uncatdkd IbAr) Cats Scenario Primary Controlled (840) 0.2442 0.033725 0.065347 0.0172158 0.000407004 0.001351444 0.000338194 Secondary Controlled (Ibhr) 0.6105 0.0075 '; 3,2974._......'. 0.1633675 0.0430395 0.00101751 0.00337861 0.000845485 0 A.0188097 102 (Reduced iron H2S by combustion) FLASH TANK Pollutant VOC H2S Benzene Toluene Eth)lbereene Xyleres n -Hexane 224-TMP 1.785877347 Uncontrolled (Ibh) 1.721478702 1.69658348 Control Scenario Prknry Controlled (Ebr) Secondary Catdled (840) 0.8138 2.0345 0 0.00283806 0.000610386 1.45333E-05 3.30923E-05 0.00210734 0.00709515 0.001525965 3.63332E-05 8.27302E-05 0.00526835 40305193......;.; '1:'0.001654614 102 (Reduced from H2S by combustion) Emission Factors 0 Amine Unit Pollutant VOC H25 Benzene Toluene Ethylbenzene mNesane 224 TM)) Pollutant PM10 P842.5 502 NO4 Co Uncontrolled Controlled )Ib/MMxd) (lb/MMscf) (Wet Gin Throughput) (Wet Gas Throughput) 20.249 0.364 0.405 0.013 1.250660287 0.329488995 0.00778955 0.025861957 0.006472612 0.026099544 0.00682342 0.000161354 0.000529966 0.00093609 Sill Vent Primary Control Devke Emission Fedor Source Uncontrolled Uncontrolled (Ib/MMBtu) (lb/MMscf) (Waste Hen COmbusted) ..:. vtnoMir,,T7 7 ,r. ... 0.Mrcti (Waste Gas Combusted) 0.0342 0.0342 0.3121 x:c am.) 0 H2510 SO2 H2e 502 1 and to 1 and MdecUar weight (g/mol) 100% conversion 34.06 64.066 Emission Factor Source mission Faded Based on total gas combusted Uncontrolled Nos CO VOC H25 602 Benzene Toluene Ethylberoene Xylene n -Hexane Controlled 1326008@8 lb/mood 1326008428 Ib/mmsd 60.4503842 Ib/mmsd 60.4503842 lb/mmscf 260.3625836 lb/mmscf 5.207251672 lb/mmscf 4.675698571 Ib/mmsd 0.165987299 lb/mmsd 8.789709644 lb/mmsd 8.78970964 Ib/mmsd 16.08120382 lb/mmscf 0.335592408 lb/mrnscf 4.236625867 lb/mmsd 0.087736708 Ib/mmsd 0.10015937 lb/mrnscf 0.002074717 Ib/mmsd 0.332576041 lb/mmscf 0.006814394 Ib/mmsd 0.083225958 lb/mmscf 0.0120364 lb/mmsd 0,0000 0.0000 Pollutant Flash Tank Primary Control Devke Uncontrolled (Ib/MMBW) (Waste Hest Conbnted) Emission Fedor Source Uncontrolled (Ib/MMsd) (Waste Gas Combusted) PM10 PM25 502 NO3 CO 8.2661 82661 74.9455 341.6634 Glycol Dehydrator Emissions Inventory Section OS- Emissions inwmtoel Old wwamr request a butler? Requested Butter t%): 'See analysis notes Criteria Pollutants Potential to Emit Uncontrolled (toas/yearl ActualEmbsinns Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Controlled (Ib/month) PM10 PM2.5 Non Co VOC H2$ SO2 0.0 0.0 0.0 0.0 0.0 4 0.0 0.0 0.0 0.0 0.0 4 11.8 11.8 119 11.8 11.80 3004 53.8 53.8 53.8 53.8 53.80 9138 231.7 231.7 4.6 231.7 4.6 787 4.2 4.2 0.1 4.2 0.1 25 7.8 7.8 7.8 7.8 7.8 1329 Hazardous Air Pollutants Potential to Emit Uncontrolled (tons/year) Actual Embsiom Uncontrolled Controlled (tons/year) (tons/year) Requested Pe mit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (lb/Y8 (lb/yr) Bero.ne Toluene Ethylbemerre Rylene n-Hezana 14.31 14,31 0.30 14.31 0.30 28622 597 3.77 3.77 0.04 3.77 0.08 7541 156 0.09 0.09 0.00 0.09 0.00 178 4 0.30 0.30 0.01 0.30 0.01 592 12 0.07 0.07 0.01 007 0.01 148 21 Section 06 -Regulatory Summary Arvin', Please see PA associated with Issuance 5. No regulatory applicability has changed. Section 01 -Initial aim Perfodlc Sampling and Yodel Reoaeasems Was the extended wet gas sample used in the Process model site -specific and collected within a year of application submittal? lf no, the permit will contain an "Initial Compliance" testing requirement to demonstrate compliance with emission limits Does the company request a control device efficiency greater than 95%for a flare or combustion device? if yes, the permit will contain and Initial compliance test condition to demonstrate the destruction effideny of the combustion devke based on inlet and outlet concentration samping Section 08 Techm (Analysis Not ,, -: 5ourcehaskldgf 98.%son.' fi-v0gagd MAPs,aM95.+75%forM25 anionto502.Fora <onserYativeefttmate sfi50x,t aim mUtgitM%ialvan�onaE41 theagercetpatould tlipyiialnaarlhat wait ar sll, proms model hi:Iii frsNazEtrditateathata eempdeaA, IPPgatliNed onWInes .ep.ct .fremas afSeal raptvmin[initlalt mpitn�topt₹reamme-enk_9oeh rtB(ven[nndflash tanitambsMrean routed /aarefaxratNathazmaloeidloer ). „ Oadondarym ssrons''' iw okoku4batadAn"firaidmumkN8fm51'wdtllXerratSrtgof39,6xMrylbty/h tamteq itmgmetedni ofwastegas {et l)¢ymrto faslkt nR)m Raplywrhprage.mNbl Nq tgpMeNhotderwl8lncladeyyastegaeami ionpior«a.} Proposal matB76tta tkmorotrate compda ss.Tf"fe'500rahasijteedYo ltYeterintofthecumbbiedsareamand,rMryertedthattheaomposkbntwdtemeettomptianorwf WI);t#edOmnbinedstreamsftheetttt eCt ndthettash tankas ptedieted by Proenak.Th 4oarnebatf ,esthatth ongoinjttad nt olsataesaooag�ed by Premae nut rroslam coon eanamadthatthewascegas hem, Iamd"andarcs dlawingtheus. otrmena twpmdkethewabtega500 per e)oo inletgassamste 8r prasemat,vgsftlre area. Sources ill haves antawi inlettesSP;mgm omarlas-well as In attaslto sonflmq $t thacetateticendeCafmr:tha:eggfpmem:..,„,..a.,lepe mberlO,2415.themndl ,snot nol gFi5P15 bpart0000waorbeendhogthepeaneI t Ehea citing ryol be In85055 boo''000Oa,SM exiteAO.CChunot adapted deiegatbno0Iaprn4teolkOepulaf,an64 a us dl knwllLtie cOlodedintha 'n tegtaremenneedtdeonea)hbalaaudadtetest82smnoentrxjeatoKtebibhe?nn errant mmetcofthersde,.bptsrnce edit Pastsotb«nadeoeedbyepiond trio ded. Inthe mem of edopton sRN5P900004, h 0 reaommendedthatItbe Inn),ledfk's tcl)ar ondhrortmaN beteand Irs l2 dEr1A62„enfenadhgr.rtlogrel eheughtee rrrgdmmemsaeeitdtemiall, AIRS Point If 004 Process R SCC Code 01 tssm 1„1:ondoloo 032s,Thaap II Re tstopetmttholdei Adrieionatlyia tesking :at eynymtynot be dil) requlremenfaof NSPS 0000)nsteedof0000., Pollutant PM10 PM2.5 502 NOx VOC CO Benzene Toluene Ethylbenzene Ilylnne n -Hexane H25 a Cnnntn190tnwilt t:eam,Thenkre.I Uncontrolled Emislonsracmr Control% 0.002 00% 0.002 0.0% 0.684 1031 20.2 4.701 1.251 0.329 0.008 0.026 0.006 04 0.0% 0.0% 900% 0.0% 97.9% 979% 979% 98.0% 855% 965% 1314 Units b/MMscf b/MMscf b/MMscf b/MMuf imMscf b/MMuf b/MMsd b/MMsd b/MMsd b/MMsd b/MMscf b/MMsd 0.65? Hot Oil Heater Emissions Inventory Section 01- Administrative Information Facility AIRS ID: County Plant Point Section 02 - Equipment Description Details Heater Information Fuel Type Number of Heaters Purpose Make: Model: Serial Number Design Heat Input Rate: Equipped with Low-NOx burners: Equipped with Add -On Control Equipment: One (1) natural gas heater (Make: TED, Model: 25 MMEtu/hr, Serial Number TED) each with a design heat input rate of 25 MMEtu/hr. Each unit is a hot oil heater. Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Section 03 - Processing Rate Information for Emissions Estimates Design Heat Input Rate = Heat content of waste gas= Actual Hours of Operation = Requested Hours of Operation = Requested heat input rate = Actual Fuel Consumption = No add-on control equipment 25 MMBtu/hr 1020"'. Btu/scf hrs/year hrs/year 219,000.00 MMBTU per year 0.00 MMscf/year Requested Fuel Consumption = 214.71 MMscf/year Requested Monthly Throughput= 18.2 MMscf per month Potential to Emit (PTE( Fuel Consumption = Section 04- Emissions Factors & Methodologies 214.71 MMscf/year Emission Factors Pollutant PM10 PM2.5 SOx NOx CO VOC Formaldeh de Benzene Toluene n -Hexane Uncontrolled Ib/MMBtu (Fuel Heat Combusted) Uncontrolled Ib/MMscf (Fuel Consumption) Emission Factor Source Section 05 - Emissions Inventory 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 Monthly Limits Controlled (lbs/year) PM10 PM2.5 SOx NOx CO VOC 0.82 0.00 0.00 0.82 0.82 139 0.82 0.00 0.00 0.82 0.82 139 0.06 0.00 0.00 0.06 0.06 11 10.74 0.00 0.00 10.80 10.80 1835 9,02 0.00 0.00 9.10 9.10 1546 0.59 0.00 0.00 0.59 0.59 100 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (Ibs/yearl Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Formaldehyde 16 0 0 16 16 Benzene 0 0 0 0 0 Toluene 1 0 0 1 1 n -Hexane 386 0 0 306 306 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires apermit Regulation 1, Section VI New source not subject to Regulation 1 Section VI. Regulation 1, Section III & Regulation 6, Part B, Section II Based on the design heat input rate, the source is subject to Regulation 1 Section III.A.1.b. and Regulation 6, Part 0, Section II.C.2. and 3. Regulation 6, Part A, Subpart Db, SO2 Standards Source is exempt from the 502 emission standard in 60.42b)k))1) per §60.42b)k)(2). Regulation 6, Part A, Subpart Db, NOx Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Dc Source is subject to NSPS Dc. Regulation 7, Section XVI.D Source is not subject to Regulation 7, Section XVI.D. Regulation 8, Part E, MAR Subpart DDDDD Source is not subject to MAR 00000. . 10 of 21 K:\PA\2010\10 W E2188.CP6.xlsm Hot Oil Heater Emissions Inventory (See regulatory applicability worksheet for detailed analysis) Section 07 - Initial and Periodic Sampling and Testing Requi•ements Is the project dose to the 40 tpy modeling / NANSR threshold for NOx? If yes, stack -testing should be required for NOx, as well as for CO. Is the operator limiting their heat input rate below the design rate? If yes, stack -testing should be required for NOx, as well as for CO. Is the project dose to the 5 tpy modeling threshold for PM 25? If yes, stack -testing should be required for PM 2.5 Does the company use AP -42 emission factors (or more conservative factors)? If no and testing hasn't already been required due to proximity to modeling thresholds, testing should be required for any pollutants for which alternative emission factors have been used. If testing is being done for only NOx or only CO, the other should be included as well. Section 08 - Technical Analysis Notes YCe reguesteitroeiptling up 0{per ,., rttreAPEH;,hgl requ AIRS Point # 0 Section 09 - Inventory 5CC Coding and Emissions Factors iteL.I_havf mended up.to the tenths niece end used the coffesp tdktg value eemssibislie, based onpipelinegasat102tiStu/sc"B5 have theta bttiti limits. EhaverequirecE an initial compliance test. Sbuma initiallyp Dealt 617,Ptihtt017 waspermltted at 25MtYlbtti/hr.tiUt ieslad,a 10 A9MBtu/hrireaterwasinstalled, which knot coveredundertha previous issuance of this permit Essentielly,tbis, installed under Pant Brr, and a notice ofcanckliatmrt4bnthst'paOt will be re4ufred:whan this point starts. Process # SCC Code Uncontrolled Emissions Pollutant Factor Control % links 01 I3-10-004-04: Industrial Process; Oil & Gas Production; Process Heaters; Natural Gas (MMscf) PM10 7.60 0 lb/MMscf Burned PM2.5 7.60 0 lb/MMscf Burned SOx 060 0 lb/MMscf Bumed NOx 100.00 0 lb/MMscf Burned CO 84.00 0 Ih/MMscf Burned VOC 5.50 0 lb/MMscf Burned Formaldehyde 7.50E-02 0 lb/MMscf Burned Benzene 2.10E-03 0 lb/MMscf Burned Toluene 3.40E-03 0 lb/MMscf Burned n -Hexane 1.8 0 lb/MMscf Burned 11 of 21 K;\PA\2010\10 W E2188.CP6.xlsm Heater Regulatory Analysis Worksheet Based on the heater purpose selection in the inventory, this unit qualifies as fuel burning equipment per Colorado Regulations 1 & 6, a steam generating unit per NSPS Db & Dc and a industrial, commercial or institutional boiler or process heater per MACT DDDDD This unit fires natural gas as defined by NSPS Db & Dc and/or is designed to burn gas 1 fuels as defined by MACT 00000 Colorado Regulation 3 Parts A and B - APEN and Permit Requirements I Source is in the 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.D.1.a)? 2. Does the heater have a design heat input rate less than or equal to 5 MMBtu/hr? (Regulation 3, Part A, Section 11.0.1.k.) 3. Does the heater have a design heat input rate less than or equal to 10 MMBtu/hr? (Regulation 3, Part B, Section II.D.1.e.) 4. 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 B, Section 11.0.3)? Source requires a permit NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Does the heater have a design heat input rate less than or equal to 5 MMBtu/hr? (Regulation 3, Part A, Section 11.0.1.k.) 3. Does the heater have a design heat input rate less than or equal to 10 MMBtu/hr? (Regulation 3, Part B, Section II.D.1.e.) 4. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 5 TPY (Regulation 3, Part B, Section II.D.2)? NA NA INot enough information Colorado Regulation 1, Section VI 1. Was the natural gas fired heater constructed, reconstructed or modified after August 11, 1977? (Regulation 1, Section VI.A.) 2. Are sulfur dioxide emissions from the heater greater than 2 tpy? (Regulation 1, Section VI.B.1) INew source not subject to Regulation 1 Section VI. Section VI.B.5 - Emission Limits Section VI.B.6 and 7- Recordkeeping, Reporting, Data Retention Colorado Regulation 1, Section III and Colorado Regulation 6, Part B. Section II, Standards of Performance for New Fuel -Burning Equipment 1. Was the natural gas fired heater constructed, reconstructed or modified after January 30, 1979? (Regulation 6, Part B, Section II.A.) 2. What is the design heat input rate of the heater? (Regulation 1, Section III.A. and Regulation 6, Part B, Section II.C.) 'Based on the design heat input rate, the source is subject to Regulation 1 Section III.A.1.b. and Regulation 6, Part B, Section lI.C.2. and 3. Colorado Regulation 7, Section XVI.D. 1. Is the natural gas fired heater located at an existing facility that is classified as a major source of NOx as listed in Regulation 7 Section XIX.A.? (Regulation 7 Section XVI.D.1.) 2. Does the natural gas fired heater have uncontrolled actual emissions of NOx equal to or greater than 5 tpy? (Regulation 7 Section XVI.D.1.) No 25 'Source is not subject to Regulation 7, Section XVI.D. Section XVI.D.2.a, e and f. —Combustion Process Adjustment Section XVI.D.3. — Recordkeeping Section XVI.D.4.—Alternative to requirements described in Sections XIV.D.2.a. through XVI.D.2.e. and XVI.D.3.a. NSPS Analysis 1. Does the natural gas fired heater have a maximum design heat input capacity of 29 megawatts (MW) (100 MMBtu/hr) or less, but greater than or equal to 2.9 MW (10MMBtu/hr)? (§60.40c(a)) 2. Does the natural gas fired heater have a maximum design heat input capacity greater than 29 megawatts (MW) (100 MMBtu/hr)? (§60.406ja)) Evaluate questions in NSPS Dc section below. 40 CFR, Part 60, Subpart Dc. Standards of Performance for Small Industrial -Commercial -Institutional Steam Generating Units 1. Did construction, modification, or reconstruction of the steam generating unit commence afterJune 9, 1989? (§60.40c(a)) Yes No 'Source is subject to NSPS Dc. Subpart A, General Provisions §60.48c - Reporting and Recordkeeping Requirements 40 CFR, Part W, Subpart Db, Standards of Performance for Industrial -Commercial -Institutional Steam Generating Units 1. Did construction, modification, or reconstruction of the steam generating unit commence after June 19,1984? (§60.40b(a)) 502 Standards 2. Does the natural gas fired heater have a potential 5O2 emission rate of 140 ng/J (0.32 lb/MMBtu) heat input or less? (§60.42b(k)(2)) 3. Did the affected facility commence construction, reconstruction or modification after February 28, 2005? (§60.42b(k)(1)) 'Source is exempt from the 502 emission standard in 60.42b(k)(1) per §60.42b(k)(2). NOx Standards 4. Does the natural gas fired heater have a heat input capacity of 73 MW (250 MMBtu/hr) or less? (§60.44b(k)) 5. Does the heater meet all of the following criteria? (§60.44b(k)) 5a. Combust, alone or in combination, only natural gas, distillate dl, or residual oil with a nitrogen content of 0.3 weight percent or less (§60A4b(j)(1)); 5b. Have a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and residual oil with a nitrogen content of 0.30 weight percent or less (460.44b(j)(2% and Are subject to a federally enforceable requirement limiting operation of the affected facility to the firing of natural gas, distillate oil, and/or residual oil with a nitrogen content of 0.30 weight percent or less and limiting operation of the affected facility to a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and residual oil with a nitrogen 5c. content of 0.30 weight percent or less. (§60.44b(j)(3)) 6. Did the affected facility commence construction, reconstruction or modification after July 09, 19977 (§60.44b(I)) Is the natural gas fired heater subject to and in compliance with a federally enforceable requirement that limits operation of the facility to an annual capacity factor of 10 percent (0.10) or less for, 7. coal, oil, and natural gas (or any combination of the three)? (§60.44b(I)(1)) Does the natural gas fired heater have low heat release rate and combust natural gas or distillate oil in excess of 30 percent of the heat input on a 30 -day rolling average from the combustion of all 8. fuels? (§60.446(1)(2)) 'Source is not subject to NSPS Db. 460.426(tc)(1) - Standard for sulfur dioxide (502) §60.440$a) or (k) or (I) -Standard for nitrogen oxides (NOx) should section (h) & (i)/(j) also be referenced here? §60.45b - Compliance and performance test methods and procedures for sulfur dioxide §60.46b- Compliance and performance test methods and procedures for particulate matter and nitrogen oxides §60.47b- Emission monitoring for sulfur dioxide §60.46b- Emission monitoring for particulate matter and nitrogen oxides §60.46b- Reporting and recordkeeping requirements MACT Analysis 40 CFR, Part 63, Subpart MACT DDDOD, NESHAP for Major sources: Industrial, Commercial, and Institutional Boilers and Process Heaters 1. Is the heater located at a facility that is a major source for HAPs? (§63.7485) 2. Did construction (563.7490(b)) or reconstruction (563.7490(c)) of heater commence afterlune 4, 2010? 3. Is the heat input capacity less than or equal to 5 MMBtu/hr? (563.7500(e)) 4. Is the heat input capacity greater than 5 MMBtu/hr but less than or equal to 10 MMBtu/hr? (§63.7500(e)) 'Source is not subject to MACT 00000. §63.7500 (e) and Table 3 - Work practice standards §63.7505 (a) - General requirements §63.7510 (e) - Initial requirements for existing sources OR 63.7510 (g) for new sources §63.7515(d)- Subsequent tests, fuel analyses or tune-ups §63.7530 (e) and (f) - Demonstrating initial compliance §63.7540 (a)(10) and (a)(13) - Demonstrating continuous compliance 463.7545 (a), (b - for existing or c - for new), (e), (e)(1), e(6), e(7), e(8) - Notifications 463.7550 (a), (b), (c), (c)(1), h(3) - Reporting §63.7555 (a), (a)(1) and (2) and 63.7560 (a), (b) and (c) -Recordkeeping 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 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 "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 yes Hot Oil Heater Emissions Inventory Section 01- Administrative Information Facility AIRs ID: 123 . ,,,8781 County Plant Point Section 02 - Equipment Description Details Heater Information Fuel Type Number of Heaters Purpose Make: Model: Serial Number: Design Heat Input Rate: Equipped with Low-NOx burners: Equipped with Add -On Control Equipment: One (1) MMBtu/hr One (1) natural gas -fired hot oil heater (Make: TBD, Model: 25 MMBtu/hr, Serial Number: TBD) each with a design heat input rate of 25 MMBtu/hr. Each unit is a hot oil heater. Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Section 03- Processing Rate Information for Emissions Estimates Design Heat Input Rate = Heat content of waste gas= Actual Hours of Operation = Requested Hours of Operation = Requested heat input rate = Actual Fuel Consumption = No add-on control equipment 25 MMBtu/hr Btu/scf hrs/year hrs/year 219,000.00 MMBTU per year 0.00 MMscf/year Requested Fuel Consumption = 214.71 MMscf/year Requested Monthly Throughput = 18.2 MMscf per month Potential to Emit (PTE) Fuel Consumption = Section 04- Emissions Factors & Methodologies 214.71 MMscf/year Emission Factors Pollutant PM10 PM2.5 SOn NOx CO VOC Formaldehyde Benzene Toluene n -Hexane Uncontrolled Ih/MMBtu (Fuel Heat Combusted) 007458 8M8745090 0,000588235 -. 0;098039218 eRi!:4k 9.4Lt x...0.005392157....:: 2.,05882E-06 Uncontrolled lb/MM (Fuel Consumption) Emission Factor Source Section 05 - Emissions Inventory 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 Monthly Limits Controlled (lbs/year) PM10 PM2.5 5Ox NOx CO VOC 0,82 0.00 0.00 0.82 0.82 139 0.82 0.00 0.00 0,82 0.82 139 0.06 0.00 0.00 0.06 0.06 11 10.74 0.00 0.00 10.80 10.80 1835 9.02 0.00 0.00 9.10 9.10 1546 0.59 0.00 0.00 0.59 0.59 100 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) Os/year) Formaldehyde 16 0 0 16 16 Benzene 0 0 0 0 0 Toluene 1 0 0 1 1 n -Hexane 386 0 0 306 306 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 1, Section VI New source not subject to Regulation 1Section VI. Regulation 1, Section III & Regulation 6, Part B, Section II Based on the design heat input rate, the source is subject to Regulation 1 Section III.A.1.b. and Regulation 6, Part B, Section II.C.2. and 3. Regulation 6, Part A, Subpart Db, 502 Standards Source is exempt from the 502 emission standard in 60.42b(k)(1) per §60.42b(k)(2). Regulation 6, Part A, Subpart Db, NOx Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Dc Source is subject to NSPS De. Regulation 7, Section XVI.D Source is not subject to Regulation 7, Section KVI.D. Regulation 8, Part E, MALT Subpart DDDDD Source is not subject to MAR 00000. 14 of 21 K:\PA\2010\10 W E2188.CP6.xlsm Hot Oil Heater Emissions Inventory (See regulatory applicability worksheet for detailed analysis) Section 07 - Initial and Periodic Sampling and Testing Requirements Is the project dose to the 40 tpy modeling / NANSR threshold for NON? If yes, stack -testing should be required for NOx, as well as for CO. Is the operator limiting their heat input rate below the design rate? If yes, stack -testing should be required for NOx, as well as for CO. Is the project dose to the 5 tpy modeling threshold for PM 2.5? If yes, stack -testing should be required for PM 2.5 Does the company use AP -42 emission factors (or more conservative factors)? If no and testing hasn't already been required due to proxindty to modeling thresholds, testing should be required for any pollutants for which alternative emission factors have been used. If testing is being done for only NOx or only CO, the other should be included as well. Section 08 - Technical Analysis Notes pipe inl;natbralgas •td.heingdsedastilel required an initial compliance test. AIRS Point g 038 Section 09 - Inventory 5CC Coding and Emissions Factors unding,up of permit emission limits. I boot roondfdiap he correspdhding yah1eS Uncontrolled Emissions Process 0 5CC Code Pollutant Factor ControlUnits 01 13-10-004-04: Industrial Process; Oil & Gas Production; Process Heaters; Natural Gas (MMscf) PM10 7.60 0 Ib/MMxf Burned PM2.5 7.60 0 Ib/MMscf Burned SOx 0.60 0 Ib/MMxf Burned NOx 100.00 0 Ib/MMxf Bumed CO 84.00 0 lb/MMscf Bumed VOC 5.50 0 lb/MMscf Burned Formaldehyde 7.50E-02 0 lb/MMscf Burned Benzene 2.10E-03 0 Ib/MMscf Bumed Toluene 3.40E-03 0 Ib/MMxf Burned n -Hexane 1.8 0 lb/MMscf Burned 15 of 21 K:\PA\2010\ 10WE2188.CP6.xlsm Heater Regulatory Analysis Worksheet Based on the heater purpose selection in the inventory, this unit qualifies as fuel burning equipment per Colorado Regulations 1 & 6, a steam generating unit per NSPS Db & DC and a industrial, commercial or institutional boiler or process heater per MACT D0DDD This unit fires natural gas as defined by NSPS Db & Dc and/or is designed to burn gas 1 fuels as defined by MAR DDDDD Colorado Regulation 3 Parts A and B - APEN and Permit Requirements I Source is in the 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.D.1.a)? 2. Does the heater have a design heat input rate less than or equal to 5 MMBtu/hr? (Regulation 3, Part A, Section 11.0.1.k.) 3. Does the heater have a design heat input rate less than or equal to 10 MMBtu/hr? (Regulation 3, Part B, Section II.D.1.e.) 4. 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 B, Section II.D.3)? 'Source requires a permit NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Does the heater have a design heat input rate less than or equal to 5 IVIMBtu/hr? (Regulation 3, Part A, Section II.D.1.k.) 3. Does the heater have a design heat input rate less than or equal to 10 MMBtu/hr? (Regulation 3, Part B, Section II.D.1.e.) 4. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 5 TPY (Regulation 3, Part B, Section II.0.2)? Not enough information Colorado Regulation 1, Section VI 1. Was the natural gas fired heater constructed, reconstructed or modified after August 11, 1977? (Regulation 1, Section VIA.) 2. Are sulfur dioxide emissions from the heater greater than 2 tpy? (Regulation 1, Section V1.B.1) New source not subject to Regulation 1 Section VI. Section VI.B.5 - Emission Limits Section VI.B.6 and 7 - Recordkeeping, Reporting, Data Retention Colorado Regulation 1. Section III and Colorado Regulation 6. Part B, Section II, Standards of Performance for New Fuel -Burning Equipment 1. Was the natural gas fired heater constructed, reconstructed or modified after January 30, 1979? (Regulation 6, Part B, Section II.A.) 2. What is the design heat input rate of the heater? (Regulation 1, Section III.A. and Regulation 6, Part B, Section II.C.) 'Based on the design heat input rate, the source is subject to Regulation 1 Section III.A.1.b. and Regulation 6, Part B, Section II.C.2. and 3. Colorado Regulation 7, Section XVI.D. NA NA 1. Is the natural gas fired heater located at an existing facility that is classified as a major source of NOx as listed in Regulation 7 Section XIX.A.? (Regulation 7 Section XVI.D.1.) 2. Does the natural gas fired heater have uncontrolled actual emissions of NOx equal to or greater than 5 tpy? (Regulation 7 Section XVI.D.1.) (Source is not subject to Regulation 7, Section XVI.D. Section XVI.D.2.a, e and f. —Combustion Process Adjustment Section XVI.D.3. — Recordkeeping Section XVI.D.4.—Alternative to requirements described in Sections XIV.D.2.a. through XVI.D.2.e. and XVI.D.3.a. NSPS Analysis 1. Does the natural gas fired heater have a maximum design heat input capacity of 29 megawatts (MW) (100 MMBtu/hr) or less, but greater than or equal to 2.9 MW (10MMBtu/hr)? (§60.40c(a)) 2. Does the natural gas fired heater have a maximum design heat input capacity greater than 29 megawatts (MW) (100 MMBtu/hr)? (§60.40b(a)) Evaluate questions in NSPS Dc section below. 40 CFR, Part 60. Subpart Dc, Standards of Performance for Small Industrial -Commercial -Institutional Steam Generating Units 1. Did construction, modification, or reconstruction of the steam generating unit commence afteriune 9, 1989? (§60.40c(a)) 'Source is subject to NSPS Dc. Subpart A, General Provisions §60.48c - Reporting and Recordkeeping Requirements No 25 Yes No 40 CFR, Part 60, Subpart Db, Standards of Performance for Industrial -Commercial -Institutional Steam Generating Units 1. Did construction, modification, or reconstruction of the steam generating unit commence after June 19,1984? (§60.40b(a)) SO2 Standards 2. Does the natural gas fired heater have a potential 502 emission rate of 140 ng/J (0.32 lb/MMBtu) heat input or less? (§60.42b(k)(2)) 3. Did the affected facility commence construction, reconstruction or modification after February 28, 2005? (§60.42b(k)(1)) • 'Source is exempt from the 502 emission standard in 60.42b(k)(1) per §60.42b(k)(2). NOx Standards 4. Does the natural gas fired heater have a heat input capacity of 73 MW (250 MMBtu/hr) or less? (460.44b(k)) 5. Does the heater meet all of the following criteria? (§60.44b(k)) 5a. Combust, alone or in combination, only natural gas, distillate oil, or residual oil with a nitrogen content of 0.3 weight percent or less (§60.44b(j)(1)); 56. Have a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and residual oil with a nitrogen content of 0.30 weight percent or less (§60.44b(j)(2)); and Are subject to a federally enforceable requirement limiting operation of the affected facility to the firing of natural gas, distillate oil, and/or residual oil with a nitrogen content of 0.30 weight percent or less and limiting operation of the affected facility to a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and residual oil with a nitrogen 5c. content of 0.30 weight percent or less. (§60.44b(j)(3)) 6. Did the affected facility commence construction, reconstruction or modification after July 09, 1997? (§60.44b(I)) Is the natural gas fired heater subject to and in compliance with a federally enforceable requirement that limits operation of the facility to an annual capacity factor of 10 percent (0.10) or less for 7. coal, oil, and natural gas (or any combination of the three)? (§60.446(')(1)) Does the natural gas fired heater have low heat release rate and combust natural gas or distillate oil in excess of 30 percent of the heat input on a 30 -day rolling average from the combustion of all 8. fuels? (§60.44b(I)(2)) 'Source is not subject to.NSPS Db. §60.42b(k)(1) - Standard for sulfur dioxide (502) §60.44b$a) or (k) or (I) -Standard for nitrogen oxides (NOx) should section (h) & (i)/(j) also be referenced here? §60.45b - Compliance and performance test methods and procedures for sulfur dioxide §60.46b - Compliance and performance test methods and procedures for particulate matter and nitrogen oxides §60.47b- Emission monitoring for sulfur dioxide §60.46b- Emission monitoring for particulate matter and nitrogen oxides §60.46b- Reporting and recordkeeping requirements MACT Analysis 40 CFR, Part 63, Subpart MACT DDDDD. NESHAP for Maior sources: Industrial, Commercial. and Institutional Boilers and Process Heaters 1. Is the heater located at a facility that is a major source for HAPs? (463.7485) 2. Did construction (§63.7490(b)) or reconstruction (463.7490(c)) of heater commence afterJune 4, 2010? 3. Is the heat input capacity less than or equal to 5 MMBtu/hr? (§63.7500(e)) 4. Is the heat input capacity greater than 5 MMBtu/hr but less than or equal to 10 MMBtu/hr? (§63.7500(e)) 'Source is not subject to MACT D0000. §63.7500 (e) and Table 3 - Work practice standards 463.7505 (a) - General requirements §63.753:1(e) - Initial requirements 'or existing sources OR 63.7510 (g) for new sources §63.7525(d)- Subsequent tests, fuel analyses or tune-ups 463.7530 (e) and (f) - Demonstrating initial compliance 463.7540 (a)(10) and (a)(13) - Demonstrating continuous compliance §63.7545 (a), (b - for existing or c -for new), (e), (e)(1), e(6), e(7), e(S) - Notifications §63.7550 (a), (b), (c), (c)(1), h(3) - Reporting §63.7555 (a), (a)(1) and (2) and 63.7560 (a), (b) and (c) -Recordkeeping 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 terns of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself Yes Hot Oil Heater Emissions Inventory Section 01- Administrative Information 'Facility AIRs ID: County Plant Point Section 02 - Equipment Description Details Heater Information Fuel Type Number of Heaters Purpose Make: Model: Serial Number: Design Heat Input Rate: Equipped with Law-NOx burners: Equipped with Add -On Control Equipment: 1 .{ 'i'. One (1) MMBtu/hr One (1) natural gas heater (Make: TBD, Model: 7.1 MMBtu/hr, Serial Number: TOD) each with a design heat input rate of 7.1 MMBtu/hr. Each unit is a molecular sieve regeneration heater. Detailed Emissions Unit Description: - Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Section 03- Processing Rate Information for Emissions Estimates Design Heat Input Rate = Heat content of waste gas= Actual Hours of Operation = Requested Hours of Operation = Requested heat input rate = Actual Fuel Consumption = No add-on control equipment 7.1 MMBtu/hr 1020:: Btu/scf hrs/year hrs/year 62,196.00 MMBTU per year 0.00 MMscf/year Requested Fuel Consumption = 60.98 MMscf/year Requested Monthly Throughput = 5 MMscf per month Potential to Emit (PTE) Fuel Consumption = Section 04- Emissions Factors & Methodologies 60.98 MMscf/year Emission Factors Pollutant PM10 PM2,5 SOx NOx CO VOC Formaldehyde Benzene Toluene n -Hexane Uncontrolled lb/MMBtu (Fuel Heat Combusted) 0.0079599$_.:;: 0;000588285. ©:08}352941 735294E -OS Uncontrolled Ib/MMsd (Fuel Consumption) 0.0021 0.0034 0.001784706`, Emission Factor Source Section 05 - Emissions Inventory 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 Monthly Limits Controlled (lbs/year) PM10 PM2.5 5Ox NOx CO VOC 0.23 0.00 0.00 0.23 0.23 39 0.23 0.00 0.00 0.23 0.23 39 0.02 0.00 0.00 0.02 0.02 3 3.05 0.00 0.00 3.05 3.05 518 2.56 0.00 0.00 2.56 2.56 435 0.17 0.00 0.00 0.17 0.17 28 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (Ibs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Formaldehyde 5 0 0 5 5 Benzene 0 0 0 0 0 Toluene 0 0 0 0 0 n -Hexane 110 0 0 110 110 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source is permit exempt per Regulation 3, Part B, Section II.D.1.e. Regulation 1, Section VI New source not subject to Regulation 1 Section VI. Regulation 1, Section III & Regulation 6, Part B, Section II Based on the design heat input rate, the source is subject to Regulation 1 Section III.A.1.b. and Regulation 6, Part 8, Section II.C.2. and 3. Regulation 6, Part A, Subpart Db, 502 Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Db, NOx Standards Source is not subject to NSPS Db. Regulation 6, Part A, Subpart Dc Source is not subject to NSPS Dc. Regulation 7, Section OVI.D Source is not subject to Regulation 7, Section XVI.D. - Regulation 8, Part E, MACT Subpart DDDDD Source is not subject to MACE DDDDD. 18 of 21 K:\PA\2010\10 W E2188.CP6.xlsm Hot Oil Heater Emissions Inventory (See regulatory applicability worksheet for detailed analysis) Section 07- Initial and Periodic Sampling and Testing Requirements Is the project close to the 40 tpy modeling / NANSR threshold for NO07 If yes, stack -testing should be required for NOx, as well as for CO. Is the operator limiting their heat input rate below the design rate? If yes, stack -testing should be required for NOx, as well as for CO. Is the project close to the 5 tpy modeling threshold for PM 2.57 If yes, stack -testing should be required for PM 2.5 Does the company use AP -42 emission factors (or more conservative factors)? If no and testing hasn't already been required due to proximity to modeling thresholds, testing should be required for any pollutants for which alternative emission factors . have been used. If testing is being done for only NOx or only CO, the other should be included as well. Section 08 - Technical Analysis Notes SflLFtxe'idC3#lf gars AIRS Point # 0 (g.n4t on thispertnig but.is pa Process # SCC Code this project.The pe Section 09 - Inventory 5CC Coding and Emissions Factors Uncontrolled Emissions Pollutant Factor Control % Units 01 I3-10-004-04: Industrial Proces& Oil & Gas Production; Process Heaters; Natural Gas (MMscf) PM10 7.60 0 lb/MMscf Burned PM2.5 7.60 0 lb/MMscf Burned 5Ox 0.60 0 Ib/MMscf Burned NOx 100.00 0 lb/MMscf Burned CO 84.00 0 lb/MMscf Burned VOC 5.50 0 lb/MMscf Bumed Formaldehyde 7.50E-02 0 lb/MMscf Bumed Benzene 2.10E-03 0 lb/MMscf Burned Toluene 3.40E-03 0 lb/MMscf Burned n -Hexane 1.8 0 lb/MMscf Burned 19 of 21 K:\PA\2010\30W E2188.CP6.xlsm Heater Regulatory Analysis Worksheet Based on the heater purpose selection in the inventory, this unit qualifies as fuel burning equipment per Colorado Regulations 1 & 6, a steam generating unit per NSPS Db & Dc and a industrial, cmnmercial or institutional boiler or process heater per MACT DDDDD This unit fires natural gas as defined by NSPS Oh & Dc and/or is designed to burn gas 1 fuels as defined by MACT OODDO Colorado Regulation 3 Parts A and B - APEN and Permit Requirements Source is in the 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.D.1.a)? 2. Does the heater have a design heat input rate less than or equal to 5 MMBtu/hr? (Regulation 3, Part A, Section II.D.1.k.) 3. Does the heater have a design heat input rate less than or equal to 10 MMBtu/hr? (Regulation 3, Part B, Section II.D.1.e.) 4. 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 B, Section II.D.3)? 'Source is permit exempt per Regulation 3, Part B, Section II.D.1.e. NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Does the heater have a design heat input rate less than or equal to 5 MMBtu/hr? (Regulation 3, Part A, Section II.D.1.k.) 3. Does the heater have a design heat input rate less than or equal to 10 MMBtu/hr? (Regulation 3, Part B, Section II.D.1.e.) 4. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 5 TPY (Regulation 3, Part B, Section II.D.2)? Not enough information NA NA Colorado Regulation 1, Section VI 1. Was the natural gas fired heater constructed, reconstructed or modified after August 11, 1977? (Regulation 1, Section VIA.) 2. Are sulfur dioxide emissions from the heater greater than 2 tpy? (Regulation 1, Section Vl.B.1) I New source not subject to Regulation 1 Section VI. Section VI.B.5 - Emission Limits Section VI.B.6 and 7 - Recordkeeping, Reporting, Data Retention Colorado Regulation 1, Section III and Colorado Regulation 6, Part B, Section II, Standards of Performance for New Fuel -Burning Equipment 1. Was the natural gas fired heater constructed, reconstructed or modified afterJanuary 30, 1979? (Regulation 6, Part B, Section II.A.) 2. What is the design heat input rate of the heater? (Regulation 1, Section III.A. and Regulation 6, Part B, Section II.C.) 'Based on the design heat input rate, the source is subject to Regulation 1 Section III.A.1.b. and Regulation 6, Part B, Section II.C.2. and 3. Colorado Regulation 7, Section XVI.D. 1. Is the natural gas fired heater located at an existing facility that is classified as a major source of NOx as listed in Regulation 7 Section XIX.A.? (Regulation 7 Section XVI.D.1.) 2. Does the natural gas fired heater have uncontrolled actual emissions of NOx equal to or greater than 5 tpy? (Regulation 7 Section XVI.D.1.) No 7.1. 'Source is not subject to Regulation 7, Section XVI.D. Section XVI.D.2.a, e and f. —Combustion Process Adjustment Section XVI.D.3. — Recordkeeping Section XVI.D.4.—Alternative to requirements described in Sections XIV.D.2.a. through XVI.D.2.e. and XVI.D.3.a. NSPS Analysis 1. Does the natural gas fired heater have a maximum design heat input capacity of 29 megawatts (MW) (100 MMBtu/hr) or less, but greater than or equal to 2.9 MW (10MMBtu/hr)? (§60.40c(a)) 2. Does the natural gas fired heater have a maximum design heat input capacity greater than 29 megawatts (MW) (100 MMBtu/hr)? (§60.40b$a)) 'Source is not subject to NSPS Db or NSPS Dc. 40 CFR. Part 60. Subpart DC. Standards of Performance for Small Industrial -Commercial -Institutional Steam Generating Units 1. Did construction, modification, or reconstruction of the steam generating unit commence after June 9, 1989? (560.40c(a)) 'Source is not subject to NSPS Dc. Subpart A, General Provisions §60.48c - Reporting and Recordkeeping Requirements No No 40 CFR. Part 60, Subpart Db, Standards of Performance for Industrial -Commercial -Institutional Steam Generating Units 1. Did construction, modification, or reconstruction of the steam generating unit commence afterJune 19, 1984? (§60.40b(a)) 502 Standards 2. Does the natural gas fired heater have a potential 502 emission rate of 140 ng/J (0.32 lb/MMBtu) heat input or less? (§60.42b(k)(2)) 3. Did the affected facility commence construction, reconstruction or modification after February 28, 2005? (§60.42b(k)(1)) 'Source is not subject to NSPS Db. NOn Standards 4. Does the natural gas fired heater hate a heat input capacity of 73 MW (250 MMBtu/hr) or less? (§60.44b(k)) 5. Does the heater meet all of the following criteria? (§60.44b(k)) 5a. Combust, alone or in combination, only natural gas, distillate oil, or residual oil with a nitrogen content of 0.3 weight percent or less (460.44b(j)(1)); 56. Have a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and residual oil with a nitrogen content of 0.30 weight percent or less (§60.44b(j)(2)); and Are subject to a federally enforceable requirement limiting operation of the affected facility to the firing of natural gas, distillate oil, and/or residual oil with a nitrogen content of 0.30 weight percent or less and limiting operation of the affected facility to a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and residual oil with a nitrogen 5c. content of 0.30 weight percent or less. (§60.44b(j)(3)) 6. Did the affected facility commence :onstruction, reconstruction or modification after July 09, 1997? (§60.44b(I)) Is the natural gas fired heater subject to and in compliance with a federally enforceable requirement that limits operation of the facility to an annual capacity factor of 10 percent (0.10) or less for 7. coal, oil, and natural gas (or any combination of the three)? (460.44b(I)(1)) Does the natural gas fired heater have low heat release rate and combust natural gas or distillate oil in excess of 30 percent of the heat input on a 30 -day rolling average from the combustion of all 8. fuels? (460.44b(l)(2)) 'Source is not subject to NSPS Db. §60.42b(k)(1)Standard for sulfurdioxide ($02) §60.44b(a) or (k) or (I) - Standard for nitrogen oxides (NOx) should section (h) & (i)/(j) also be referenced here? §60.45b - Compliance and performance test methods and procedures for sulfur dioxide §60.46b - Compliance and performance test methods and procedures for particulate matter and nitrogen oxides 460.471- Emission monitoring for sulfur dioxide §60.466 - Emission monitoring for particulate matter and nitrogen oxides §60.461 - Reporting and recordkeeping requirements MACT Analysis 40 CFR, Part 63, Subpart MAR DDDDD, NESHAP for Maior sources: Industrial, Commercial, and Institutional Boilers and Process Heaters 1. Is the heater located at a facility that is a major source for HAPs? (§63.7485) 2. Did construction (§63.7490(b)) or ,econstruction (§63.7490(c)) of heater commence afterJune 4, 20107 3. Is the heat input capacity less than or equal to 5 MMBtu/hr? (§63.7500(e)) 4. Is the heat input capacity greater than 5 MMBtu/hr but less than or equal to 10 MMBtu/hr? (§63.7500(e)) 'Source is not subject to MACT DD000. §63.7500 (e) and Table 3 - Work p-actice standards §63.7505 (a) - General requirements §63.7510 (e) - Initial requirements for existing sources OR 63.7510 (g) for new sources §63.7515(d)- Subsequent tests, fuel analyses or tune-ups §63.7530 (e) and (f) - Demonstrating initial compliance §63.7540 (a)(10) and (a)(13) - Demonstrating continuous compliance §63.7545 (a), (b - for existing or c- for new), (e), (e)(1), e(6), e(7), e(8) - Notifications §63.7550 (a), (b), (c), (c)(1), h(3) - Reporting 463.7555 (a), (a)(1) and (2) and 63.7560 (a), (b) and (c) -Recordkeeping Disclaimer " This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations, and Air Quality Control Commission regulatons. 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 Pie Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself. Yes 10WE2188 Issuance: 6 Permit number: Date issued: Issued to: Facility Name: Plant AIRS ID: Physical Location: County: General Description: Summit Midstream Niobrara, LLC Hereford Ranch Processing Plant 123/8761 Section 26, Township 12N, Range 63W Weld County, Colorado Natural Gas Processing Plant THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING: Facility Equipment ID AIRS Point Description FL 011 One (1) Emergency open flame flare (make, model, and s/n to be provided with a normal operating rate of 12.6 MMBtu per hour, for control of emissions from plant emergency shutdowns, pressure relief valves, and compressor blowdowns. FUG 012 Equipment leaks (fugitive VOCs) from equipment/components in natural gas, natural gas liquid, and heavy oil streams. FUG Propane 013 Equipment leaks (fugitive VOCs) from equipment/components in gaseous and liquid propane service. TEG 016 One (1) Triethylene glycol (TEG) natural gas dehydration unit (Make: ITS Engineered System, Inc., Model: 4.0 MMscfd, Serial Number: 2576-3) with a design capacity of 4 MMscf per day. This emissions unit is equipped with 2 (Make: Rotor -Tech, Model: GA2EP) electric driven glycol pumps with a design capacity of 4 gallons per minute. This dehydration unit is equipped with a still vent, flash tank, and reboiler. Flash tank vapors are vented to the atmosphere. Emissions from this unit are not controlled. HT5802 017 One (1) natural gas fired hot oil heater (Make, Model, and s/n to be provided) for process heating, maximum design rated at 25 MMBtu/hour. Page 1 of 32 Facility Equipment ID AIRS Point Description AMInc 018 One (1) Diethanolamine (DEA) gas and liquids sweetening system with one liquid -liquid contactor with a design capacity of 75 gpm and one gas -liquid contactor with a design capacity of 10 MMscf/day (Tryer Process Equipment T-6502, SN: 12-011-300). This emissions unit is equipped with one (1) DXP electric amine recirculation pump with a total design capacity of 35 gallons per minute. This system includes a natural gas liquids/amine contactor, one natural gas/amine contactor, a flash tank, and an amine regeneration reboiler heated by hot oil. All emissions from the flash tank and amine regenerator are routed to a combustor. FL02 028 Emergency flare for plant emergency shutdowns, pressure relief valves, compressor blowdowns, and other miscellaneous sources. Flare has a minimum destruction efficiency of 95% and it is not enclosed. AMIN03 034 Methyldiethanolamine (MDEA) natural gas sweetening system with a design capacity of 62.7 MMscf/day (Make: TBD; Model: TBD; SN: TBD). This emissions unit is equipped with Two (2) amine recirculation pumps with a total limited capacity of 300 gallons per minute of lean amine. This system includes one (1) natural gas/amine contactor, a flash tank, still vent, and hot oil reboilers (AIRs Points 036, 037, 038). The acid gas stream from the still overheads and from the flash tank is routed to a thermal oxidizer (Make: TBD; Model: TBD; SN: TBD) with a minimum destruction efficiency of 98% for VOC. Destruction efficiency for H2S is 96.45%. HT02 036 Hot oil heater for process heating. HT5802 037 One (1) natural gas -fired hot oil heater (Make, Model, and s/n to be provided) for process heating, maximum design rated at 25 MMBtu/hour. HT03 038 One (1) natural gas -fired hot oil heater (Make: TBD, Model: 25 MMBtu/hr, Serial Number: TBD) each with a design heat input rate of 25 MMBtu/hr. This unit is a hot oil heater. ENG-1 040 One (1) Caterpillar, Model G3608 TALE, Serial Number To Be Determined, natural gas -fired, turbo -charged, 4SLB reciprocating internal combustion engine, site rated at 2317 horsepower. This engine shall be equipped with an oxidation catalyst and air -fuel ratio control/non-selective catalytic reduction (NSCR) system and air -fuel ratio control. This emission unit is used for natural gas compression. Page 2 of 32 THIS PERMIT IS GRANTED SUBJECT TO ALL RULES AND REGULATIONS OF THE COLORADO AIR QUALITY CONTROL COMMISSION AND THE COLORADO AIR POLLUTION PREVENTION AND CONTROL ACT C.R.S. (25-7-101 et seq), TO THOSE GENERAL TERMS AND CONDITIONS INCLUDED IN THIS DOCUMENT AND THE FOLLOWING SPECIFIC TERMS AND CONDITIONS: REQUIREMENTS TO SELF -CERTIFY FOR FINAL AUTHORIZATION 1. Points 028, 034, 036, 037 and 038: YOU MUST notify the Air Pollution Control Division (the Division) no later than fifteen days after commencement of operation, by submitting a Notice of Startup form to the Division. The Notice of Startup form may be downloaded online at https://www.colorado.gov/pacific/cdphe/other-air- permitting-notices. 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. 2. Points 028, 034, 036, 037 and 038: Within one hundred and eighty days (180) after commencement of operation, compliance with the conditions contained on this permit shall be demonstrated to the Division. It is the permittee's responsibility to self -certify compliance with the conditions. Failure to demonstrate compliance within 180 days may result in revocation of the permit. (Reference: Regulation No. 3, Part B, II.G.2). 3. Points 028, 034, 036, 037 and 038: This permit shall expire if the owner or operator of the source for which this permit was issued: (i) does not commence construction/modification of this source within 18 months after either, the date of issuance of this construction permit; (ii) discontinues construction for a period of eighteen months or more; (iii) does not complete construction within a reasonable time of the estimated completion date. The Division may grant extensions of the deadline per Regulation No. 3, Part B, III.F.4.b. (Reference: Regulation No. 3, Part B, III.F.4.) 4. The operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self -certification process. (Reference: Regulation No. 3, Part B, Section III.E.) 5. Points 037, 038: The manufacturer, model number and serial number of the subject equipment shall be provided to the Division within fifteen days (15) after commencement of operation. This information shall be included on the Notice of Startup (NOS) submitted for the equipment. (Reference: Regulation No. 3, Part B, III.E.) 6. Point 040: 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. • manufacture date • construction date • order date • date of relocation into Colorado • manufacturer • model number • serial number This information shall be included with the Notice of Startup submitted for the equipment. (Reference: Regulation No. 3, Part B, III.E.) Page 3 of 32 7. 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 8. Emissions of air pollutants shall not exceed the following limitations (as calculated in the Division's preliminary analysis). (Reference: Regulation No. 3, Part B, Sect Point ion II.A.4) Monthly Limits: Facility Equipment ID AIRS Pont Pounds per Month Emission Type H2S SO2 N0,V0C CO AMlnc 018 -- 1088 1835 Point AMlnc 018 AMIN03 034 25 1,329 2,004 787 9,138 Point HT02 036 1,444 85 1,206 Point HT5802 037 -- 1,835 1,546 Point HT03 038 -- 1,835 1,546 Point ENG-1 040 --- --- 1,900 2,660 732 Point Monthly limits are based on a 31 -day month. Quarterly Limits1'2: Facility Equipment ID AIRS Point Pounds per Quarter Emission Type NO, V0C CO FL02 028 3,466 25,444 15,801 Point 1: Quarterly limits will be establ'shed beginning with the calendar month of permit issuance. 2: Quarterly limits are based on a 92 -day quarter. Page 4 of 32 Annual Limits: Facility Equipment ID AIRS Point Tons per Year Emission Type H2S SO2 N0 V0C CO FL 011 3.8 1.7 20.5 Point FUG 012 --- --- --- 85.8 --- Fugitive FUG Propane 013 --- --- --- 33.8 --- Fugitive TEG 016 --- --- 5.9 --- Point HT5802 017 --- --- 10.8 0.6 9.1 Point AMlnc 018 6.4 10.8 Point FL02 028 -- 6.9 50.5 31.4 Point AMIN03 034 0.15 7.8 11.8 4.6 53.8 Point HT02 036 --- 8.5 --- 7.1 Point HT5802 037 --- --- 10.8 --- 9.1 Point HT03 038 --- --- 10.8 --- 9.1 Point ENG-1 040 --- --- 11.2 15.7 4.3 Point See "Notes to Permit Holder #4 for information on emission factors and methods used to calculate limits. During the first twelve (12) months of operation after issuance of this permit, compliance with both the monthly and yearly emission limitations shall be required. After the first twelve (12) months of operation, compliance with only the yearly limitation shall be required. Compliance with the synthetic minor status of this facility shall be determined by recording the facility's annual criteria pollutant emissions, from each emission unit, on a rolling (12) month total. By the .end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate monthly emissions and keep a compliance record on site or at a local field office with site responsibility, for Division review. This rolling twelve-month total shall apply to all emission units, requiring an APEN, at this facility. 9. Points 012 and 013: The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent gas and liquids analyses, as required in the Compliance Testing and Sampling section of this permit. The operator shall maintain records of the results of component counts and sampling events used to calculate actual emissions and the dates that these counts and events were completed. These records shall be provided to the Division upon request. Page 5 of 32 10. Point 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 wet gas analysis and recorded operational values (including gas throughput, lean glycol recirculation rate, and other operational values specified in the OEtM Plan). Recorded operational values, except for gas throughput, shall be averaged on a monthly basis for input into GRI GlyCalc. 11. Points 018: Compliance with the emission limits in this permit shall be demonstrated by running the Promax model on a monthly basis using the most recent amine unit inlet extended gas and liquid analyses and recorded operational values (including gas throughput, NGL throughput, and lean amine recirculation rates). Recorded operational values, except for gas and liquid throughput, shall be averaged on a monthly basis for input into Promax. 12. Point 018: Emissions from the flash tank and amine regenerator shall be routed to a combustor. The combustor shall reduce uncontrolled emissions of VOC from the unit to the emission levels listed in this section, above. Operating parameters of the control equipment are identified in the operation and maintenance plan. (Reference: Regulation No.3, Part B, Section III.E.) 13. Points 034: The owner or operator shall calculate uncontrolled VOC, HAP, and H2S emissions on a monthly basis by running the Promax simulation model or Division - approved software using the most recent amine unit inlet extended gas analysis and recorded operational values including: inlet gas throughput, lean amine recirculation rate, flash tank temperature and pressure, gas inlet temperature and gas inlet pressure. Recorded operational values, except for gas throughput, shall be averaged on a monthly basis for input into Promax simulation model. The model shall be used to produce a gas composition, representing the weighted composition of the still vent and flash tank streams. The modeled gas composition shall be combined with the monthly measured waste gas flow volume for both the still vent and flash tank gas, as specified in the Process Limitations and Records section of this permit. A control efficiency of 98%, based on maintaining the minimum temperature requirements specified in the Operating and Maintenance Requirements section of this permit, shall be applied to the uncontrolled VOC, HAP emissions. A control efficiency of 96.45%, based on maintaining the minimum temperature requirements specified in the Operating and Maintenance Requirements section of this permit, shall be applied to the uncontrolled H2S emissions. 14. The emission points in the table below shall be operated and maintained with the control equipment as listed in order to reduce emissions to less than or equal to the limits established in this permit (Reference: Regulation No.3, Part B, Section III.E.) Facility Equipment ID AIRS Point Control Device Pollutants Controlled FUG 012 LDAR VOC, HAPs FUG Propane 013 LDAR VOC, HAPs Page 6 of 32 AMInc 018 Combustor VOC FLO2 028 Flare VOC, HAPs AMINO3 034 Still Vent: Thermal Oxidizer Flash tank: Thermal Oxidizer VOC, HAPs, H2S ENG-01 040 Oxidation catalyst and air/fuel ratio controller VOC and CO PROCESS LIMITATIONS AND RECORDS 15. This source shall be limited to the following maximum consumption, processing and/or operational rates as listed below. Monthly records of the actual consumption rate shall be maintained by the applicant and made available to the Division for inspection upon request. (Reference: Regulation 3, Part B, II.A.4) Process/Consumption Limits Facility Equipment ID AIRS Point Process Parameter Annual Limit Monthly Limit (31 days) Quarterly Limit (92 days) FL 011 Consumption of natural gas as a fuel 109.5 MMSCF N/A N/A TEG 016 Processing of natural gas MMSCF N/A N/A HT5802 017 Consumption of natural gas as a fuel MMSCF N/A N/A AMInc 018 Processing of natural gas liquids 39,420,000 Gallons 3,348,000 Gallons N/A Processing of natural gas 3,650 MMSCF 310 MMSCF N/A FLO2 028 Consumption of natural gas as a fuel MMSCF N/A 46.0 MMSCF AMINO3 034 Natural Gas Throughput 22,886 S MMSCF N/A Combustion of waste gas1 495 MMSCF 127 MMSCF284.7 N/A Combustion of Supplemental Fuel MMSCF 24.2 MMSCF N/A HT02 036 Consumption of natural gas as a fuel MMSCF MMSCF14.4 N/A HT5802 037 Consumption of natural gas as a fuel 4.7 MMSCF 18.2 MMSCF N/A HT03 038 Consumption of natural gas as a fuel 4.7 MMSCF 18.2 MMSCF N/A ENG-1 040 Consumption of natural gas as a fuel 151.37 MMscf 12.86 MMscf N/A During the first twelve (12) months of operation, compliance with both the monthly and yearly consumption limitations shall be required. After the first twelve (12) months of operation, compliance with only the yearly limitation shall be required. Page 7 of 32 Compliance with the yearly consumption limits shall be determined on a rolling twelve (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate monthly consumption of natural gas and keep a compliance record on site or at a local field office with site responsibility, for Division review. 16. Points 011: The operator shall continuously monitor total gas volume routed to the flare on a monthly basis using a flow meter. By the end of each month, the total flow for the previous months' data shall be calculated, and a new twelve-month total shall be calculated and recorded based on the previous twelve months' data. 17. Point 016: This unit shall be limited to the maximum lean glycol circulation rate of 2.2 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. (Reference: Regulation No. 3, Part B, II.A.4) 18. Point 018: This unit shall be limited to the maximum lean amine recirculation rate of 35 gallons per minute. A maximum of 27 gallons per minute shall be pumped to the gas - liquid contactor. The amine recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. (Reference: Regulation No. 3, Part B, II.A.4) 19. Point 028: The operator shall continuously monitor total gas volume routed to the flare on a monthly basis using a flow meter. By the end of each month, the total flow for the previous months' data shall be calculated, and a new twelve-month total shall be calculated and recorded based on the previous twelve months' data. 20. Point 034: This unit shall be limited to the maximum lean amine recirculation rate of 300 gallons per minute. The amine recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. (Reference: Regulation No. 3, Part B, II.A.4) 21. Point 034: The volumetric flow rate of the waste gas combusted shall be measured and recorded using an operational non-resettable elapsed flow meter at the thermal oxidizer. A system that collects, sums, and stores electronic data from a continuous fuel flow meter is considered to be an operational non-resettable elapsed flow meter. 22. Points 037, 038: The owner or operator must install and maintain an operational non- resettable elapsed flow meter to record the flow rate of the fuel gas combusted. A system that collects, sums, and stores electronic data from a continuous fuel flow meter is considered to be an operational non-resettable elapsed flow meter. The flow rate of the fuel combusted in these natural gas -fired combustion emission units shall be measured and recorded at each inlet. Total monthly fuel use shall be recorded once per month. 23. Point 040: Fuel consumption shall be measured by one of the following methods: individual engine fuel meter; facilty-wide fuel meter attributed to fuel consumption rating and hours of operation; or manufacturer -provided fuel consumption rate. Page 8 of 32 STATE AND FEDERAL REGULATORY REQUIREMENTS 24. The permit number and AIRS ID number shall be marked on the subject equipment for ease of identification. (Reference: Regulation Number 3, Part B, III.E.) (State only enforceable). 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. (Reference: Regulation No. 1, Section II.A.1. Et 4.) 26. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) 27. Points 012 and 013: The fugitive emissions addressed by AIRS ID 012-013 are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: • §60.5365 Applicability - The group of all equipment, except compressors, within a process unit for which you commence construction, modification or reconstruction after August 23, 2011 is an affected facility per §60.5365(f). • §60.5400 Standards - The group of all equipment, except compressors, within a process unit must comply with the requirements of §60.5400 and §60.5401. • §60.5410 - Owner or operator must demonstrate initial compliance with the standards using the requirements in §60.5410(f). • § 60.5415 - Owner or operator must demonstrate continuous compliance with the standards using the requirements in §60.5415(f). • § 60.5421 - Owner or operator must comply with the recordkeeping requirements of $60.5421(b). • § 60.5422 - Owner or operator must comply with the reporting requirements of paragraphs (b) and (c) of this section in addition to the requirements of § 60.487a(a), (b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii). 28. Point 016: This source is subject to the TEG dehydrator area source requirements of 40 CFR, Part 63, Subpart HH - National Emission Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities including, but not limited to, the following: • §63.764 - General Standards o §63.764 (e)(1} -The owner or operator is exempt from the requirements of paragraph (c)(1) and (d) of this section if the criteria listed in paragraph (e)(1)(i) or (ii) of this section are met, except that the records of the determination of these criteria must be maintained as required in §63.774(d)(1). ■ §63.764 (e)(1)(i) - The actual annual average flowrate of natural gas to the glycol dehydration unit is less than 85 thousand standard cubic meters per day (3.0 MMSCF/day), as determined by the procedures specified in §63.772(b)(1) of this subpart; or Page 9 of 32 ■ §63.764 (e)(1)(ii) - The actual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere are less than 0.90 megagram per year, as determined by the procedures specified in §63.772(b)(2) of this subpart. • §63.772 - Test Methods, Compliance Procedures and Compliance Demonstration o §63.772(b) - Determination of glycol dehydration unit flowrate or benzene emissions. The procedures of this paragraph shall be used by an owner or operator to determine glycol dehydration unit natural gas flowrate or benzene emissions to meet the criteria for an exemption from control requirements under §63.764(e)(1). ■ §63.772(b)(1) - The determination of actual flowrate of natural gas to a glycol dehydration unit shall be made using the procedures of either paragraph (b)(1)(i) or (b)(1)(ii) of this section. • §63.772(b)(1)(i) - The owner or operator shall install and operate a monitoring instrument that directly measures natural gas flowrate to the glycol dehydration unit with an accuracy of plus or minus 2 percent or better. The owner or operator shall convert annual natural gas flowrate to a daily average by dividing the annual flowrate by the number of days per year the glycol dehydration unit processed natural gas. • §63.772(b)(1)(ii) - The owner or operator shall document, to the Administrator's satisfaction, that the actual annual average natural gas flowrate to the glycol dehydration unit is less than 85 thousand standard cubic meters per day. ■ §63.772(b)(2) - The determination of actual average benzene emissions from a glycol dehydration unit shall be made using the procedures of either paragraph (b)(2)(i) or (b)(2)(ii) of this section. Emissions shall be determined either uncontrolled, or with federally enforceable controls in place. • §63.772(b)(2)(i) - The owner or operator shall determine actual average benzene emissions using the model GRI- GLYCaIc TM , Version 3.0 or higher, and the procedures presented in the associated GRI-GLYCalc TM Technical Reference Manual. Inputs to the model shall be representative of actual operating conditions of the glycol dehydration unit and may be determined using the procedures documented in the Gas Research Institute (GRI) report entitled "Atmospheric Rich/Lean Method for Determining Glycol Dehydrator Emissions" (GRI-95/0368.1); or • $63.772(b)(2)(ii) - The owner or operator shall determine an average mass rate of benzene emissions in kilograms per hour through direct measurement using the methods in §63.772(a)(1)(i) or (ii), or an alternative method according to §63.7(f). Annual emissions in kilograms per year shall be determined by multiplying the mass rate by the number of Page 10 of 32 hours the unit is operated per year. This result shall be converted to megagrams per year. • §63.774 - Recordkeeping Requirements o §63.774 (d)(1) - An owner or operator of a glycol dehydration unit that meets the exemption criteria in §63.764(e)(1)(i) or §63.764(e)(1)(ii) shall maintain the records specified in paragraph (d)(1)(i) or paragraph (d)(1)(ii) of this section, as appropriate, for that glycol dehydration unit. • §63.774 (d)(1)(i) - The actual annual average natural gas throughput (in terms of natural gas flowrate to the glycol dehydration unit per day) as determined in accordance with §63.772(b)(1), or • §63.774 (d)(1)(ii) - The actual average benzene emissions (in terms of benzene emissions per year) as determined in accordance with §63.772(b)(2). 29. Point 017: Particulate emissions shall be limited as per: Regulation 6, Part B, II.C.2. 30. Point 018: The amine units addressed by AIRS ID 018 are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart 0000, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: • §60.5365 - Applicability and Designation of Affected Facilities o §60.5365(g)(3) - Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in §60.5423(c) but are not required to comply with §§60.5405 through 60.5407 and §§60.5410(g) and 60.5415(g). • §60.5423 - Record keeping and reporting Requirements o §60.5423(c) - To certify that a facility is exempt from the control requirements of these standards, for each facility with a design capacity less that 2 LT/D of H2 S in the acid gas (expressed as sulfur) you must keep, for the life of the facility, an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H2 S expressed as sulfur. 31. Point 034: The inlet gas stream to the amine unit shall have a total sulfurs concentration, including H2S, of less than or equal to 4.0 ppm 32. Points 036, 037 and 038: This source is subject to the New Source Performance Standards requirements of Regulation No. 6, Part A Subpart Dc, Standards of Performance for Small Industrial -Commercial -Institutional Steam Generating Units including, but not limited to, the following: a. The owner or operator of the facility shall record and maintain records of the amount of fuel combusted during each month (40 CFR Part 60.48c(g)). b. Monthly records of fuel combusted required under the previous condition shall be maintained by the owner or operator of the facility for a period of two years following the date of such record (40 CFR Part 60.48c(i)). Page 11 of 32 In addition, the following requirements of Regulation No. 6, Part A, Subpart A, General Provisions, apply. c. At all times, including periods of start-up, shutdown, and malfunction, the facility and control equipment shall, to the extent practicable, be maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. Determination of whether or not acceptable operating and maintenance procedures are being used will be based on information available to the Division, which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. (Reference: Regulation No.. 6, Part A. General Provisions from 40 CFR 60.11 d. No article, machine, equipment or process shall be used to conceal an emission which would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere. (S 60.12) e. Written notification of construction and initial startup dates shall- be submitted to the Division as required under S 60.7. f. Records of startups, shutdowns, and malfunctions shall be maintained, as required under 5 60.7 33. Points 036, 037 and 038: Each heater is subject to the Particulate Matter Emission Regulations of Regulation 1 and Regulation 6,including, but not limited to, the following: 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(FI)-0.26 Where: PE = Particulate Emission in Pounds per million BTU heat. input. Fl = Fuel Input in Million BTU per hour (Regulation 1, Section III.A.1.b and (Regulation 6, Part B, Section II.C.2). (ii) Greater than 20 percent opacity (Regulation 6, Part B, Section II.C.3). OPERATING £t MAINTENANCE REQUIREMENTS 34. Upon startup, the applicant shall follow the operating and maintenance (O&tM) 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 Page 12 of 32 subject to Division approval prior to implementation. (Reference: Regulation No. 3, Part B, Section III.G.7.) 35. Point 034: The combustion temperature of the thermal oxidizer used to control emissions from the amine unit shall be greater than 1400 ' F, representative of normal historical operation, and shall be the temperature established during the most recent stack test of the equipment that was approved by the Division, on a daily average basis. The approved minimum combustion temperature shall be achieved at all times that any amine unit emissions are routed to the thermal oxidizer. The combustion chamber temperature shall be measured and recorded at least once every hour. If the combustion chamber temperature value is measured more frequently than once per hour, the source shall record either each measured data value or each block average value for each 1 -hour period calculated from all measured data values during each period. 36. Points 011 and 017: This source is not required to follow a Division -approved operating and maintenance plan. 37. Points 012, 013, 016, 036, 037 and 038: This source is not required to follow a Division -approved operating and maintenance plan. COMPLIANCE TESTING AND SAMPLING Initial Testing Requirements 38. Point 028: The operator shall complete an initial site -specific extended gas analysis of the natural gas that is routed to the flare in order to verify the VOC content of the stream as well as the heat content of the gas routed to the flare. The sampled stream shall represent the combined streams of all gas being routed to the flare at the time of sampling. The extended gas analysis shall be conducted using ASTM methods or equivalent, if approved in advance by the Division. The extended gas analysis shall be used to ensure compliance with the emissions limits in this permit. 39. Points 034: The owner or operator shall complete the initial annual extended sour gas analysis testing required by this permit. The owner or operator shall use this sour gas analysis to calculate actual emissions, as prescribed in the Emission Limitations 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. 40. Point 034: A source initial compliance test shall be conducted on this emissions point to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits specified in this permit. The natural gas throughput, lean amine circulation rate and MDEA concentration entering the amine unit shall be monitored and recorded during this test. The operator shall also measure and record combustion zone temperature during the initial compliance test to establish the minimum combustion temperature as described in the Operating and Maintenance section of this permit. The operator shall demonstrate the thermal oxidizer achieves a minimum destruction efficiency of 98.0% for VOC and 96.45% for H2S. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for Page 13 of 32 review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Common Provisions Section II.C and Regulation No. 3, Part B., Section III.G.3) Hydrogen Sulfide using EPA approved methods. Oxides of Nitrogen using EPA approved methods. Volatile Organic Compounds using EPA approved methods. Carbon Monoxide using EPA approved methods. 41. Points 037, 038: A source initial compliance test shall be conducted on each heater to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits contained in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods Carbon Monoxide using EPA approved methods 42. Point 040: A source initial compliance test shall be conducted on emissions point 040 to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emission limits in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods. Carbon Monoxide using EPA approved methods. Periodic Testing Requirements 43. Point 012: On an annual basis, the permittee 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. Page 14 of 32 44. Point 016: The owner or operator shall complete an extended wet gas analysis of the plant inlet on an annual basis. Results of the wet gas analysis shall be used to calculate emissions of criteria pollutants and hazardous air pollutants per this permit. 45. Points 018: The operator shall sample the inlet liquid and gas to the plant on an annual basis to determine the concentration of hydrogen sulfide (H2S) in the inlet streams. The sample results shall be monitored to demonstrate that this amine unit qualifies for the exemption from the Standards of Performance for Onshore Natural Gas Processing: SO2 Emissions (§60.640(b)). The testing required by Condition 37 may be used for this demonstration 46. Points 018: The owner or operator shall complete extended sour liquid and sour gas analyses prior to the inlet of the amine unit on an semi-annual basis. Results of these analyses shall be used to calculate emissions of criteria pollutants. 47. Point 028: The operator shall complete a site specific extended gas analysis of the natural gas that is routed to the flare in order to verify the VOC content of the stream as well as the heat content of the gas routed to the flare on a recurring basis. The sampled stream shall represent the combined streams of all gas being routed to the flare at the time of sampling. The extended gas analysis shall be conducted using ASTM methods or equivalent, if approved in advance by the Division. The extended gas analysis shall be used to ensure compliance with the emissions limits in this permit. On the basis of the VOC weight percentage, comparing the two most recent site -specific samples of natural gas routed to the flare, the sampling frequency shall be determined as follows: • If the percent difference of the VOC weight percentage of the two most recent site -specific analyses natural gas is 5% or greater, the testing frequency for the next test shall be quarterly • If the percent difference of the VOC weight percentage of the two most recent site -specific analyses natural gas is less than 5%, the testing frequency for the next test shall be semi-annual Where percent difference is defined as: I VOCwt%1 — VOCwt%2 Percent Difference = rVOCwt%1 + VOCwt%2 * 100 L 2 J 48. Points 034: The owner or operator shall complete an extended sour gas analysis prior to the inlet of the amine unit on an annual basis. Results of the sour gas analysis shall be used to calculate emissions of criteria pollutants and hazardous air pollutants as prescribed in the Emission Limitation and Records section of this permit. 49. Point 040: This engine is subject to the periodic testing requirements as specified in the operating and maintenance (O&M) plan as approved by the Division. Revisions to your O&M plan are subject to Division approval. Replacements of this unit completed as Alternative Operating Scenarios may be subject to additional testing requirements as specified in Attachment A. Page 15 of 32 ADDITIONAL REQUIREMENTS 50. All previous versions of this permit are cancelled upon issuance of this permit. 51. This permit replaces the following permits and/or points, which are cancelled upon startup of the points in this permit. The owner or operator shall submit a cancellation notice for the following equipment with the Notice of Startup for the corresponding new equipment in this permit: Existing Permit No. Existing Emission Point New Emission Point 10WE2188 123/8761/011 123/8761/028 10WE2188 123/8761/016 123/8761/030 (14WE1301) 10WE2188 123/8761/018, 123/8761/035 123/8761/034 10WE2188 123/8761/017 123/8761/037 52. Revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, II.C) a. Annually whenever a significant increase in emissions occurs as follows: For any criteria 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 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. 53. This source is subject to the provisions of Regulation No. 3, Part C, Operating Permits (Title V of the 1990 Federal Clean Air Act Amendments). The application for the Operating Permit is due within one year of the earliest commencement of operation of any piece of equipment covered by this permit. 54. Federal regulatory program requirements (i.e. PSD, NANSR) shall apply to this source at any such time that this source becomes major solely by virtue of a relaxation in any permit condition. Any relaxation that increases the potential to emit above the Page 16 of 32 applicable Federal program threshold will require a full review of the source as though construction had not yet commenced on the source. The source shall not exceed the Federal program threshold until a permit is granted. (Regulation No. 3 Part D). 55. MACT Subpart HH - National Emission Standards for Hazardous Air Pollutants From Oil and Natural Gas Production Facilities major stationary source requirements shall apply to this source at any such time that this source becomes major solely by virtue of a relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of Subpart HH. (Reference: Regulation No. 8, Part E) GENERAL TERMS AND CONDITIONS: 56. This permit and any attachments must be retained and made available for inspection upon request. The permit may be reissued to a new owner by the APCD as provided in AQCC Regulation No. 3, Part B, Section II.B upon a request for transfer of ownership and the submittal of a revised APEN and the required fee. 57. If this permit specifically states that final authorization has been granted, then the remainder of this condition is not applicable. Otherwise, the issuance of this construction permit does not provide "final" authority for this activity or operation of this source. Final authorization of the permit must be secured from the APCD in writing in accordance with the provisions of 25-7-114.5(12)(a) C.R.S. and AQCC Regulation. No. 3, Part B, Section III.G. Final authorization cannot be granted until the operation or activity commences and has been verified by the APCD as conforming in all respects with the conditions of the permit. Once self -certification of all points has been reviewed and approved by the Division, it will provide written documentation of such final authorization. Details for obtaining final authorization to operate are located in the Requirements to Self -Certify for Final Authorization section of this permit. 58. This permit is issued in reliance upon the accuracy and completeness of information supplied by the applicant and is conditioned upon conduct of the activity, or construction, installation and operation of the source, in accordance with this information and with representations made by the applicant or applicants agents. It is valid only for the equipment and operations or activity specifically identified on the permit. 59. Unless specifically stated otherwise, the general and specific conditions contained in this permit have been determined by the APCD to be necessary to assure compliance with the provisions of Section 25-7-114.5(7)(a), C.R.5. 60. Each and every condition of this permit is a material part hereof and is not severable. Any challenge to or appeal of a condition hereof shall constitute a rejection of the entire permit and upon such occurrence, this permit shall be deemed denied ab initio. This permit may be revoked at any time prior to self -certification and final authorization by the Air Pollution Control Division (APCD) on grounds set forth in the Colorado Air Quality Control Act and regulations of the Air Quality Control Commission (AQCC), including failure to meet any express term or condition of the permit. If the Division denies a permit, conditions imposed upon a permit are contested by the applicant, or the Division revokes a permit, the applicant or owner or operator of a source may request a hearing before the AQCC for review of the Division's action. 61. 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 Page 17 of 32 Division in writing requesting a cancellation of the permit. Upon notification, annual fee billing will terminate. 62. 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. Page 18 of 32 By: Christian Lesniak Permit Engineer Permit History Issuance Date Description Issuance 1 August 3, 2012 Issued to Bear Tracker Energy, LLC Issuance 2 May 24, 2013 Change in permit limits for point 011 and addition of point 025. Facility is synthetic minor. Issuance 3 March 18, 2014 Reissued to Meadowlark Midstream Company, LLC. Modified point 018 to include a gas contactor. Changed emissions for points 012 and 013. Addition of point 027. Removed points 019-025 from permit. Issuance 4 October 2, 2014 Modification to Points 012 and 013. Addition of Points 028, 029, 031, 032, 033, 034, 035 and 036. Facility is now major for CO. Issuance 5 March 14, 2017 Removal of Points 027, 031, 032, 033 per cancellation notices received 10/01/2015. Removed Self -Certification Requirements for Point 018. Removed monthly limits for points 011,012,013,016,017. Modification - raised emission limit of point 016 and changed requested glycol recirculation rate. This permit modification also represents an 18 -month extension to construct previously unconstructed points, which will supersede one that had been granted outside of a permit service. Amended incomplete equipment descriptions for points 034 Et 035 from previous permit issuance. Issuance 6 This Issuance Issued to Summit Midstream Niobrara, LLC (Company Name Change). Combining Point 035 (Amine unit) with Point 034 - Remains as single larger amine unit (Point 034). Removal of Point 029 (EG Dehydrator). Point 017 (Natural Gas Heater) will be replaced with Point 037 (A heater other than the permitted heater was installed originally). Source has requested permit modification. Addition of heater and natural gas -fired engine. Modification of process flare (Point 028) - Increase in throughput and permitted emissions. Increase in throughput and emissions from amine unit (Point 034) - Control by thermal oxidizer. Addition of hot oil heater (Point 038). Addition of engine (Point 040) Page 19 of 32 Notes to Permit Holder: 1) The permit holder is required to pay fees for the processing time for this permit. An invoice for these fees will be issued after the permit is issued. The permit holder shall pay the invoice within 30 days of receipt of the invoice. Failure to pay the invoice will result in revocation of this permit (Reference: Regulation No. 3, Part A, Section VI.B.) 2) The production or raw material processing limits and emission limits contained in this permit are based on the consumption rates requested in the permit application. These limits may be revised upon request of the permittee providing there is no exceedance of any specific emission control regulation or any ambient air quality standard. A revised air pollution emission notice (APEN) and application form must be submitted with a request for a permit revision. 3) This source is subject to the Common Provisions Regulation Part II, Subpart E, Affirmative Defense Provision for Excess Emissions During Malfunctions. The permittee shall notify the Division of any malfunction condition which causes a violation of any emission limit or limits stated in this permit as soon as possible, but no later than noon of the next working day, followed by written notice to the Division addressing all of the criteria set forth in Part II.E.1. of the Common Provisions Regulation. See: http://www.cdphe.state.co.us/regulations/airregs/100102aocccommonprovisionsreg.pdf. 4) The following emissions of reportable 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. AIRS Point Pollutant CAS # Uncontrolled Emission Rate (Ib/yr) Are the emissions reportable? Controlled Emission Rate (lbfyr) 012 Benzene 71432 913 Yes 516 Toluene 108883 674 Yes 381 Ethybenzene 100414 90 No 51 Xylene 1330207 183 No 96 n -Hexane 110543 5872 Yes 3320 016 Toluene 108883 178 No 178 Xylene 1330207 279 Yes .279 018 Benzene 71432 1824 Yes 91 Toluene 108883 488 No 24 Ethybenzene 100414 21 No 1 Xylene 1330207 59 No 3 028 Benzene 71432 3639 Yes 182 Toluene 108883 1977 Yes 99 Ethybenzene 100414 299 Yes 15 Xylene 1330207 460 Yes 23 n -Hexane 110543 27787 Yes 1389 034 Benzene 71432 28622 Yes 572 Toluene 108883 7541 Yes 151 Ethylbenzene 100414 178 No 4 Page 20 of 32 Xylenes 1330207 592 Yes 12 n -Hexane 110543 148 No 3 037 Formaldehyde 50000 16 No 16 Toluene 108883 1 No 1 n -Hexane 110543 386 Yes 386 038 Formaldehyde 50000 16 No 16 Toluene 108883 1 No 1 n -Hexane 110543 386 Yes 386 040 Formaldehyde 50000 11,634 Yes 11,634 Acetaldehyde 75070 1,291 Yes 1,291 Acrolein 107028 794 Yes 794 Methanol 67561 386 Yes 386 n -Hexane 110543 171 No 171 Benzene 71432 68 No 68 Toluene 108883 63 No 63 5) The emission levels contained in this permit are based on the following emission factors: Point 011: Pollutant Emission Factor Source/Comments Control (%) NOx 0.068 lb/mmbtu AP-42,Tabte 13.5-1 0.0% CO 0.370 lb/mmbtu AP-42,Table 13.5-1 0.0% VOC 621.0 lb/mmscf Engineering Calculation 95.0% Point 012: Component Gas Service Heavy Oil Light Oil SWater/Oil ervi Service Connectors 1440 2067 2451 0 Flanges 403 166 375 0 Open-ended Lines 751 233 564 0 Pump Seals 1 11 19 0 Valves 481 272 756 0 Other* 45 5 18 0 VOC Content (wt. fraction) 0.4788 1.0 0.8267 N/A Benzene Content (wt. fraction) 0.00306 N/A O.00306 N/A Toluene Content (wt. fraction) 0.00226 N/A 0.00226 N/A Page 21 of 32 Ethylbenzene (wt. fraction) 0.0003 N/A 0.0003 N/A Xylenes Content (wt. fraction) 0.00067 N/A 0.00067 N/A n -hexane Content (wt. fraction) 0.01968 N/A 0.01968 N/A *Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms, hatches, instrument meters, polish rods and vents TOC Emission Factors (kg/hr-component): Component Gas Service Heavy Oil Light Oil Water/Oil Service Connectors 2.0E-04 7.5E-06 2.1E-04 1.1E-04 Flanges 3.9E-04 3.9E-07 1.1E-04 2.9E-06 Open-ended Lines 2.0E-03 1.4E-04 1.4E-03 2.5E-04 Pump Seals 2.4E-03 NA 1.3E-02 2.4E-05 Valves 4.5E-03 8.4E-06 2.5E-03 9.8E-05 Other 8.8E-03 3.2E-05 7.5E-03 1.4E-02 Source: EPA -453/R95-017 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 gas analysis. Control for quarterly monitoring is: 88% gas valve, 76% light liquids valve, and 68% light liquids pump. Point 013: Component Gas Service Heavy Oil Light Oil Water/Oil Service Connectors 297 0 0 0 Flanges 75 0 0 0 Open-ended Lines 583 0 0 0 Pump Seals 1 0 0 0 Valves 132 0 0 0 Other* 8 0 0 0 VOC Content (wt. fraction) 1.0 N/A N/A N/A *Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms, hatches, instrument meters, polish rods and vents TOC Emission Factors (kg/hr-component): Component Gas Service Heavy Oil Light Oil Water/Oil Service Connectors 2.0E-04 7.5E-06 2.1E-04 1.1E-04 Flanges 3.9E-04 3.9E-07 1.1E-04 2.9E-06 Open-ended Lines 2.0E-03 1.4E-04 1.4E-03 2.5E-04 Pump Seals 2.4E-03 NA 1.3E-02 2.4E-05 Page 22 of 32 Valves 4.5E-03 8.4E-06 2.5E-03 9.8E-05 Other 8.8E-03 3.2E-05 7.5E-03 1.4E-02 Source: EPA -453/R95-017 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 gas analysis. Control for quarterly monitoring is: 88% gas valve, 76% light liquids valve, and 68% light liquids pump. Point 016: The emission levels for this point are based on information provided in the application and the GRI GlyCalc 4.0 model. Point 018: The emission levels for this point are based on the ProMax 3.2 model using extended sour gas and liquids analyses representative of the gas and liquid processed by this unit submitted with the permit application. Point 028: Pollutant Emission Factor Source/Comments Control (%) NOx 0.068 lb/mmbtu AP-42,Table 13.5-1 0.0% CO 0.370 lb/mmbtu AP-42,Table 13.5-1 0.0% VOC 11062.6 lb/mmscf Engineering Calculation 95.0% Points 034: The amine unit is subject to the New Source Performance Standards requirements of 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 including, but not limited to, the following: • §60.5365a — Applicability and Designation of Affected Facilities o §60.5365a(g)(3) - Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in §60.5423(c) but are not required to comply with §§60.5405 through 60.5407 and §§60.5410(g) and 60.5415(g). • §60.5423a - Record keeping and reporting Requirements o §60.5423a(c) - To certify that a facility is exempt from the control requirements of these standards, for each facility with a design capacity less that 2 LT/D of H2 S in the acid gas (expressed as sulfur) you must keep, for the life of the facility, an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H2 S expressed as sulfur. This rule has not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 6. Emissions from the amine unit result from venting of acid gas (still vent overhead) and flash tank emissions to the thermal oxidizer. Additionally, emissions result from combustion of supplemental fuel Page 23 of 32 required to combust the acid gas (still vent overhead) and flash tank emissions at the thermal oxidizer. Actual VOC, HAP and H2S emissions from venting of still vent acid gas and flash tank emissions shall be calculated based on the most recent monthly weighted still vent and flash tank stream composition from running Promax 4.0, and the most recent metered monthly waste gas flow volume. Controlled emissions are based on a thermal oxidizer control efficiency of 98% for VOC and HAPs other than H2S. Controlled emissions of H2S are based on a thermal oxidizer control efficiency of 96.45%. SO2 emissions resulting from the controVcombustion of H2S emissions in the waste gas are based on mass balance and assuming 96.45% of the H2S is converted to SO2. Additional combustion emissions (from both supplemental fuel and waste gas) are calculated using the following emission factors and volume of total gas combusted. Total gas combusted is the sum of most recent waste gas flow volume plus most recent supplemental fuel volume plus burner volume. Total actual emissions for each point are then based on the sum of emissions calculated for controlled waste gas plus combustion (including supplemental fuel, burner fuel and waste gas). Pollutant Emission Factors Uncontrolled lb/MMscf total gas combusted1 Emission Factors Controlled lb/MMscf total gas combusted1 Source NOx 13.26 13.26 AP -42, Chapter 13.5 CO 60.45 60.45 AP -42, Chapter 13.5 1: Total gas combusted equals still vent waste gas volume plus flash tank waste gas plus supplemental fuel volume to burner. Equation for Actual NOx and CO Emissions Calculations: Actual emissions ( lb ) — Emission Factor ib ) x [Still Vent Waste Gas (MMscf) + month MMscf month Flash Tank Waste Gas (month) + Supplemental Fuel (mmscr)] *Still Vent Waste Gas and Supplemental Fuel are based on actual measured monthly flow volumes. *Supplemental Fuel is based on actual measured monthly flow volume. Equation for Actual VOC Emissions Calculations: lb \I VOCTotal (month) = VOCwaste Gas +VOCCombvstion MMsc f VOCwaste Gas = VOC concentration (wt %) _ 100 x Combined Waste Gas ( month lb scf x Gas Molecular Weight (lbmol) : 379 (lbmol) x (1 — 98% control) *VOC concentration and Gas Molecular Weight are based on the weighted combined waste gas streams of the amine unit still vent and flash tank, as predicted by Promax 4.0, based on the most recent inlet gas sample. *Combined Waste Gas is the actual measured monthly flow volume of the amine unit still vent and flash tank. Equation for Actual HAP Emissions Calculations: HAP (month) = HAP concentration (wt %) : 100 x Combined Waste Gas (month) lb x Gas Molecular Weight (lbmol) : 379 (lbmol) x (1 — 98% control) Page 24 of 32 *HAP concentration and Gas Molecular Weight are based on the weighted combined waste gas streams of the amine unit still vent and flash tank, as predicted by Promax 4.0, based on the most recent inlet gas sample. *Combined Waste Gas is the actual measured monthly flow volume of the amine unit still vent and flash tank. Equation for Actual H2S Emissions Calculations: lb l H2STotal (month) = H2S Waste Gas SC HZSwasteGas = H2S concentration (mol %) = 100 x Combined Waste Gas (month/ scf x 34.08 (lbmoi H2S)/ : 379 (lb al) x (1— 96.45% control) *H2S concentration is based on the weighted combined waste gas streams of the amine unit still vent and flash tank, as predicted by Promax 4.0, based on the most recent inlet gas sample. *Combined Waste Gas is the actual measured monthly flow volume of the amine unit still vent and flash tank. Equation for Actual SOx Emissions Calculations: SOXTotal (moThnth/ SOXwaste Gas + SOXCombustion SOXwaste Gas = [H2Swasate Gas ± 0.0355 x 64.05 lb SO2 - 34.08 lb H2S] Points 036, 037, 038: Pollutant lb/MMSCF Source/Comments Control (%) NOx 100 AP -42 0.0% VOC 5.5 AP -42 0.0% CO 84 AP -42 0.0% Point 040: CAS Pollutant Emission Uncontrolled Ib/MMBtu Factors - g/bhp-hr Emission Controlled lb/MMBtu Factors — g/bhp-hr NOx 0.1449 0.50 - - CO 0.7970 2.75 0.0558 0.19 VOC 0.2579 0.89 0.2029 0.70 50000 Form eldehy de 0.0754 0.26 0.0754 0.26 75O70 Acetaedehyd 0.0084 0.03 0.0084 0.03 107028 Acrolein 0.0051 0.02 _ 0.0051 0.02 67561 Methanol 0.0025 0.01 0.0025 0.01 110543 n -Hexane 0.0011 0.00 0.0011 0.00 71432 Benzene 0.0004 0.00 0.0004 0.00 108883 Toluene 0.0004 0.00 0.0004 0.00 Page 25 of 32 Emission factors are based on a Brake -Specific Fuel Consumption Factor of 7607 Btu/hp-hr, a site - rated horsepower value of 2317, and a fuel heat value of 1020 Btu/scf. Emission Factor Sources: CAS Pollutant Uncontrolled EFSource Controlled EF Source NOx Manufacturer Manufacturer CO Manufacturer Manufacturer VOC Manufacturer Manufacturer 50000 Formaldehyde Manufacturer Manufacturer 75070 Acetaldehyde AP -42; Table 3.2-2 (7/2000); Natural Gas No Control 107028 Acrolein AP -42; Table 3.2-2 (7/2000); Natural Gas No Control 67561 Methanol AP -42; Table 3.2-2 (7/2000); Natural Gas No Control 110543 n -Hexane AP -42; Table 3.2-2 (7/2000); Natural Gas No Control 71432 Benzene AP -42; Table 3.2-2 (7/2000); Natural Gas No Control 108883 Toluene AP -42; Table 3.2-2 (7/2000); Natural Gas No Control Page 26 of 32 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 040: This engine is subject to 40 CFR, Part 60, Subpart JJJJ—Standards of Performance for Stationary Spark Ignition Internal Combustion Engines (See January 18, 2008 Federal Register posting — effective March 18, 2008). This rule has not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 6. A copy of the complete subpart is available on the EPA website at: http://www.epa.qov/ttn/atw/area/fr18ja08.pdf 8) Point 040: This engine is subject to 40 CFR, Part 63, Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines. (See January 18, 2008 Federal Register posting - effective March 18, 2008). The January 18, 2008 amendments to include requirements for area sources and engines < 500 hp located at major sources have not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 8. A copy of the complete subpart is available on the EPA website at: http://www.epa.gov/ttn/atw/area/fr181a08.pdf Additional information regarding area source standards can be found on the EPA website at: http://vvww.epa.qov/ttn/atw/area/arearules.html 9) This facility is classified as follows: Applicable Requirement Status Operating Permit Major Source: CO Synthetic Minor Source: n -Hexane PSD Synthetic Minor Source: VOC MACT HH Area Source Requirements: Applicable MACT ZZZZ Area Source Requirements: Applicable 10) 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 Page 27 of 32 ATTACHMENT A: ALTERNATIVE OPERATING SCENARIOS RECIPROCATING INTERNAL COMBUSTION ENGINES October 12, 2012 2. Alternative Operating Scenarios The following Alternative Operating Scenario (AOS) for the temporary and permanent replacement of natural gas fired reciprocating internal combustion engines has been reviewed in accordance with the requirements of Regulation No. 3., Part A, Section IV.A, Operational Flexibility -Alternative Operating Scenarios, Regulation No. 3, Part B, Construction Permits, and Regulation No. 3, Part D, Major Stationary Source New Source Review and Prevention of Significant Deterioration, and it has been found to meet all applicable substantive and procedural requirements. This permit incorporates and shall be considered a Construction Permit for any engine replacement performed in accordance with this AOS, and the owner or operator shall be allowed to perform such engine replacement without applying for a revision to this permit or obtaining a new Construction Permit. 2.1 Engine Replacement The following AOS is incorporated into this permit in order to deal with an engine breakdown or periodic routine maintenance and repair of an existing onsite engine that requires the use of either a temporary or permanent replacement engine. "Temporary" is defined as in the same service for 90 operating days or less in any 12 month period. "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 engine is in operation. If the engine operates only part of a day, that day shall count as a single day towards the 90 day total. The compliance demonstrations and any periodic monitoring required by this AOS are in addition to any compliance demonstrations or periodic monitoring required by this permit. All replacement engines are subject to all 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 NSPS or MACT 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 engine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the engine(s) that are replaced during the term of this permit, and the manufacturer, model number, horsepower, and serial number of the replacement engine. In addition to the log,' the owner or operator shall maintain a copy of all Applicability Reports required under section 2.1.2 and make them available to the Division upon request. 2.1.1 The owner or operator may temporarily replace an existing engine that is subject to the emission limits set forth in this permit with an engine that is of the same manufacturer, model, and horsepower or a different manufacturer, model, or horsepower as the existing engine without modifying this permit, so long as the temporary replacement engine complies with all permit limitations and other requirements applicable to the existing engine. Measurement of emissions from the temporary replacement engine shall be made as set forth in section 2.2. 2.1.2 The owner or operator may permanently replace the existing engine with another engine with the same manufacturer, model, and horsepower engines without modifying this permit so long as the permanent replacement engine complies with all permit limitations and other requirements applicable to the Page 28 of 32 existing engine as well as any new applicable requirements for the replacement engine. Measurement of emissions from the permanent replacement engine and compliance with the applicable emission limitations shall be made as set forth in section 2.2. An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and serial number and horsepower of the permanent replacement engine shall be filed with the Division for the permanent replacement engine within 14 calendar days of commencing operation of the replacement engine. The APEN shall be accompanied by the appropriate APEN filing fee, a cover letter explaining that the owner or operator is exercising an alternative operating scenario and is installing a permanent replacement engine, and a copy of the relevant Applicability Reports for the replacement engine. Example Applicability Reports can be found at https://www.colorado.gov/pacific/cdphe/alternate-operating-scenario-aos- reporting-forms. This submittal shall be accompanied by a certification from the Responsible Official indicating that "based on the information and belief formed after reasonable inquiry, the statements and information included in the submittal are true, accurate and complete". This AOS cannot be used for permanent engine replacement of a grandfathered or permit exempt engine or an engine 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 engine 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 engine using a portable flue gas analyzer within seven (7) calendar days of commencing operation of the replacement engine. All portable analyzer testing required by this permit shall be conducted using the Division's Portable Analyzer Monitoring Protocol (ver March 2006 or newer) as found on the Division's web site at: https://www.colorado.gov/pacific/sites/default/files/AP Portable-Analyzer-Monitoring-Protocol.pdf 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. For comparison with a short-term limit that is either input based (lb/mmBtu), output based (g/hp-hr) or concentration based (ppmvd @ 15% O2) that the existing unit is currently subject to or the replacement engine 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. Page 29 of 32 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 engine 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 engine 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 engine is taken offline. 2.3 Applicable Regulations for Permanent Engine Replacements 2.3.1 Reasonably Available Control Technology (RACT): Reg 3, Part B § II.D.2 All permanent replacement engines that are located in an area that is classified as attainment/maintenance or nonattainment must apply Reasonably Available Control Technology (RACT) for the pollutants for which the area is attainment/maintenance or nonattainment. Note that both VOC and NOX are precursors for ozone. RACT shall be applied for any level of emissions of the pollutant for which the area is in attainment/maintenance or nonattainment, except as follows: In the Denver Metropolitan PM10 attainment/maintenance area, RACT applies to PM10 at any level of emissions and to NOX and SO2, as precursors to PM10, if the potential to emit of NOX or SO2 exceeds 40 tons/yr. For purposes of this AOS, the following shall be considered RACT for natural gas fired reciprocating internal combustion engines: VOC: The emission limitations in NSPS JJJJ CO: The emission limitations in NSPS JJJJ NOX: The emission limitations in NSPS JJJJ SO2: Use of natural gas as fuel PM10: Use of natural gas as fuel As defined in 40 CFR Part 60 Subparts GG (§ 60.331) and 40 CFR Part 72 (§ 72.2), natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. 2.3.2 Control Requirements and Emission Standards: Regulation No. 7, Sections XVI. and XVII.E (State - Only conditions). Control Requirements: Section XVI Any permanent replacement engine located within the boundaries of an ozone nonattainment area is subject to the applicable control requirements specified in Regulation No. 7, section XVI, as specified below: Rich burn engines with a manufacturer's design rate greater than 500 hp shall use a non -selective catalyst and air fuel controller to reduce emission. Lean burn engines with a manufacturer's design rate greater than 500 hp shall use an oxidation catalyst to reduce emissions. The above emission control equipment shall be appropriately sized for the engine and shall be operated and maintained according to manufacturer specifications. The source shall submit copies of the relevant Applicability Reports required under Condition 2.1.2. Emission Standards: Section XVII.E — State -only requirements Page 30 of 32 Any permanent engine that is either constructed or relocated to the state of Colorado from another state, after the date listed in the table below shall operate and maintain each engine according to the manufacturer's written instructions or procedures to the extent practicable and consistent with technological limitations and good engineering and maintenance practices over the entire life of the engine so that it achieves the emission standards required in the table below: Max Engine HP Construction or Relocation Date Emission Standards in G/hp-hr NOx CO VOC January 1, 2008 2.0 4.0 1.0 100<Hp<500 January 1, 2011 1.0 2.0 0.7 500<Hp July 1, 2007 July 1, 2010 2.0 1.0 4.0 2.0 1.0 0.7 The source shall submit copies of the relevant Applicability Reports required under Condition 2.1.2. 2.3.3 NSPS for stationary spark ignition internal combustion engines: 40 CFR Part 60, Subpart JJJJ A permanent replacement engine that is manufactured on or after 7/1/09 for emergency engines greater than 25 hp, 7/1/2008 for engines less than 500 hp, 7/1/2007 for engines greater than or equal to 500 hp except for lean burn engines greater than or equal to 500 hp and less than 1,350 hp, and 1/1/2008 for lean burn engines greater than or equal to 500 hp and less than 1,350 hp are subject to the requirements of 40 CFR Part 60, Subpart JJJJ. An analysis of applicable monitoring, recordkeeping, and reporting requirements for the permanent engine replacement shall be included in the Applicability Reports required under Condition 2.1.2. Any testing required by the NSPS is in addition to that required by this AOS. Note that the initial test required by NSPS Subpart JJJJ can serve as the testing required by this AOS under Condition 2.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition 2.2. 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 manufacture date for purposes of determining the applicability of NSPS JJJJ requirements). However, as of October 1, 2011 the Division has not yet adopted NSPS JJJJ. Until such time as it does, any engine subject to NSPS will be subject only under Federal law. Once the Division adopts NSPS JJJJ, there will be an additional step added to the determination of the NSPS. Under the provisions of Regulation No. 6, Part B, § l.B (which is referenced in Part A), any engine relocated from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of NSPS JJJJ. 2.3.4 Reciprocating internal combustion engine (RICE) MACT: 40 CFR Part 63, Subpart ZZZZ A permanent replacement engine located at either an area or major source is subject to the requirements in 40 CFR Part 63, Subpart ZZZZ. An analysis of the applicable monitoring, recordkeeping, and reporting requirements for the permanent engine replacement shall be included in the Applicability Reports required under Condition 2.1.2. Any testing required by the MACT is in addition to that required by this AOS. Note that the initial test required by the MACT can serve as the testing required by this AOS under Condition 2.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition 2.2. 2.4 Additional Sources Page 31 of 32 The replacement of an existing engine with a new engine is viewed by the Division as the installation of a new emissions unit, not "routine 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; an engine that is being installed as an entirely new emission point and not as part of an AOS-approved replacement of an existing onsite engine has to go through the appropriate Construction/Operating permitting process prior to installation. Page 32 of 32 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. paint booths, mining operations, engines, etc.). A list of specialty APENs is available on the Air Pollution Control Division (APCD) website at www.colorado.gov/pacific/cdphe/air-permits. 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: 10WE2188 AIRS ID Number: 123 /8761/028 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information I �1 Company Name: �k 1 GAS ��2G N I Ov raiq Li C. Site Name: Hereford Ranch Processing Plant Site Location: Section 26, Township 12N, Range 63W Mailing Address: (Include Zip Code) 999 18th Street, Suite 3400 South Portable Source Home Base: Denver, Colorado Site Location County: Weld NAICS or SIC Code: 1311 Permit Contact: Zak N. Covar Phone Number: (832) 608 - 6175 E -Mail Address: zcovar@summitmidstream.com 'Please 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. Form APCD-200 - General APEN - Revision 7/2015 373198 ,COLORADO 1 I NNK1IA.6E . *, .tm.nt Permit Number: 10WE2188 AIRS ID Number: 123 /8761/ 028 [Leave blank unless APCD has already assigned a permit ft 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 ❑ Change permit limit ❑ Change company name ❑ Add point to existing permit ❑ Transfer of ownership2 ❑ Other (describe below) -OR - ❑ APEN submittal for update only (Please 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 ft Notes: Updated using corrected emission factors and throughput 2 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: Emergency Flare for plant emergency shutdowns, pressure relief valves, and compressor blowdowns Manufacturer: TBD Model No.: TBD Serial No.: TBD Company equipment Identification No. (optional): FL02 For existing sources, operation began on: For new, modified, or reconstructed sources the projected start-up date is: 5/1/2016 ❑✓ 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: 25 D/0 Mar -May: 25 % June -Aug: 25 % Sept -Nov: 25 Form APCD-200 - General APEN - Revision 7/2015 COLORADO 2 I .® agwm,mm nvi� ik 1@16 FJ19.R0[IM�N Permit Number: 10WE2188 AIRS ID Number: 123 /8761/ 028 [Leave blank unless APCD has already assigned a permit ft and AIRS ID] Section 4 - Processing/Manufacturing Information a Material Use r❑ 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) ctual'Annual Amount (Specify Units` Requested Annual Permit Limit3 (Specify Units) Material Consumption: 3Requested values will become permit limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information eographical Coordinates Latitude/Longitude-or UTM) UTM Zone 13, 551,139 E, 4,536,300 N ❑ 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 Operator, S aek l� PlO , r �,�, ., ,.., i ' _ Dischar Het ht x , h ove Grou�dl Level N,,° ,e x w .,..' - ._... �.__-ee�",� � "�a r Temp F) �r �r tY f�r�t 't Flow Rate w F sl r .4�FM) ` __ ...� e _.. . • 1/elocity x - � ; . FLO2 100 1832 15115 3 Indicate the direction of the stack outlet (check one) O Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) 0 Upward with obstructing raincap ❑✓ Circular Interior stack diameter (inches): 18 inches 0 Square/rectangle Interior stack width (inches): Interior stack depth (inches): 0 Other (describe): Form APCD-200 - General APEN - Revision 7/2015 3 I ,COLORADO aap-tim erd Pu lc FAIN 6 F. ViAIRIM N TSP (PM) Permit Number: 10WE2188 AIRS ID Number: 123 /8761/ 028 [Leave blank unless APCD has already assigned a permit ft and AIRS ID] Section 6 - Combustion Equipment &t Fuel Consumption Information ❑Q 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 Limit (Specify Units) <= 15 182,500,000 scf/y From what year is the actual annual fuel use data? Indicate the type of fuel used4: ❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑� Field Natural Gas Heating value: ,098.86 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) ❑ Coal Heating value: BTU/lb Ash Content: Sulfur Content: ❑ Other (describe): Heating value (give units): 3 Requested values will become permit limitatio-is. Requested limit(s) should consider future process growth. 4 If fuel heating value is different than the listed assumed value, please provide this information in the "Other" field. 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 If yes, please describe the control equipment AND state the overall control efficiency (% reduction): Control EquipmentDescription Overall Control Efficiency (% reduction in emissions) PM10 PM2.5 SOX NOx CO VOC Flare 95% Other: Form APCD-200 - General APEN - Revision 7/2015 coioRmio 4 I AV -". Nsal,h Er :ens TSP (PM) Permit Number: 10WE2188 Section 7 (continued) AIRS ID Number: 123 /8761/ 028 [Leave blank unless APCD has already assigned a permit # and AIRS ID] From what year is the following reported actual annual emissions data? TBD 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) Emission Factor Source 4P-42, Mfg. etc) ctual Annual Emissio nested Annual Permi mission Limtt(s Uncontrolled (Tons/year) Controlled5 (Tonslyear) ;, ncontrolled (Tons'year) Controlled (Tons/year) PM10 PM2.s SOX NOx CO 0.068 lb/mmbtu 0.31 Ib/mmbtu AP -42 AP -42 G.q G 7 VOC 10940 Ib/mmscf Eng. Calc 998 50 .5 Other: 3 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 5Annual emission 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 f yes, use the following table to report the non -criteria pollutant (HAP) emissions from source: umber Chemical Name Overall Control Efficiency; Uncontrolled. Emission Factor (specify units) Emission Factor' Source Jncontrolled =Actual Emissions;.,,; (lbs/year) 1)6Y1 let1 Controlled Actual Emissions5 (ibs/year) 71-43-2 108-88-3 Benzene 95% 55 Ib/mmscf Eng. Calc. 100-41-4 Toluene Ethylbenzene 95% 95% 11 Ib/mmscf 2 Ib/mmscf Eng. Calc Eng. Calc 99 15 1330-20-7 Xylenes 95% 3 Ib/mmscf Eng. Calc. 110-54-3 n -Hexane 95% 152/mmscf Eng. Calc. AAnnual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-200 - General APEN - Revision 7/2015 AVID= V ICOLORADO 5 n�Na� Nwtu f4m+Nhk EnWMnm�N Permit Number: 10 OWE21 AIRS ID Number: 123 /8761 / 028 [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. 09/25/2015 Signature of Legally Authorized Person (not a vendor or consultant) Date Zak N. Cover Vice President of HSE&R Name (please print) Title Check the appropriate box to request a copy of the: ❑✓ Engineer's Preliminary Analysis conducted 2 Draft permit prior to issuance 2 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 $152.90 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Telephone: (303) 692-3150 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: www.colorado.gov/pacific/cdphe/air-permits Form APCD-200 - General APEN - Revision 7/2015 6 COLORADO N H ,*avulse.. 1.- aISw6E,,auss. Amine Sweetening Unit - Form APCD-206 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 Amine Sweetening Units only. If your emission unit does not fall into this category, there may be a more specific APEN for your source. 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/aped. 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: 10WE2188 AIRS ID Number: 123 / 8761 / 034 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Company equipment Identification: AMIN03 [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] Section 1 - Administrative Information Company Name': Summit Midstream Niobrara, LLC. Site Name: Hereford Ranch Processing Plant Site Location: Section 26, Township 12N, Range 63W Mailing Address: p Cod999 18th Street, Suite 3400S (Include Zip Code) Denver, CO 80202 E -Mail Address2: aparisi@summitmidstream.com Site Location County: Weld NAICS or SIC Code: 211130 Permit Contact: Andrew Parisi Phone Number: 303-626-8269 'Please 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 APCD via e-mail to the address provided. 374729 Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 1 I COLORADO NeahnlEnavanmtn< Permit Number: 10WE2188 AIRS ID Number: 123 / 8a/ 034 [Leave blank unless APCD has already assigned a permit # and MRS 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 name ❑ Add point to existing permit ❑✓ Change permit limit ❑ Transfer of ownership' ❑ Other (describe below) OR ❑ APEN submittal for update only (Please 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 Et Notes: Combine two (2) existing 30 MMscfd amine treaters (AIRS Points -034/-035) into single 62.7 MMscfd treater (AIRS Point -034) 3 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 sweetening Facility equipment Identification: For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: AMIN03 / / 08 /01 / 2018 IZI 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 nonattainment ❑ Yes I=I No area l Does this facility have a design capacity less than 2 longlil Yes ❑ No tons/day of H2S in the acid gas? Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 2 I COLORADO Ikguemvn dlwtUc I /:.1th b Emunnanent Permit Number: 10WE2188 AIRS ID Number: 123 / V 034 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Dehydration Unit Equipment Information Manufacturer: TBD Model : 62.7 MMscfd Reboiler Rating: N/A (hot oil system) MMBtu/hr Amine Type: ❑ MEA Serial Number: Absorber Column Stages: ❑ DEA ❑ TEA Pump Make and Model: Electric, Make/Model TBD 21 actual TBD stages ❑✓ MDEA ❑ DGA # of pumps: 2 Sweet Gas Throughput4: Design Capacity: 62.7 MMSCF/day Requested: 22,885.5 MMSCF/year Actual: MMSCF/year 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth Inlet Gas: Pressure: 835 psig Temperature: 80 °F Rich Amine Feed: Pressure: 847,12 Asia Flowrate: 300 Gal/min Temperature: 127 °F Lean Amine Stream: Pressure: Flowrate: 962.12 psia 300 Mole loading H2S 0.288 mol/mol Temperature: 117 Gal/min Wt. % amine: 50% Mole Loading 2 0.288 mol/mol °F Sour Gas Input: Pressure: 847.12 Asia Temperature: 80 ° F Flowrate: 62.7 MMSCF/Day NGL Input: Pressure: Flowrate: psia Gal/min Temperature: No NGL Treating °F Flash Tank: ❑ No Flash Tank Pressure: 82 psia Temperature: 129 ° F Additional Required Information: i ❑✓ Attach a Process Flow Diagram ❑✓ Attach the simulation model inputs It emission report ❑� Attach composition reports for the rich amine feed, sour gas feed, NGL feed, ft outlet stream (emissions) ✓❑ Attach the extended gas analysis (including BTEX ft n -Hexane, H2S, CO2, temperature, and pressure) Form APCD-2O6 - Amine Sweetening Unit APEN - Revision 04/2017 31 COLORADO I{lMhB EnuYomatk Permit Number: 10WE2188 AIRS ID Number: 123 / 86/ 034 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information eographical Coordinates gtitude%Longitude or UT; UTM Zone 13, Easting 551151.27, Northing 4536860.80 ws, Opera tor 4 eF"P rte' -h 'f�•, u�q. Sac k ID No x� rFrPs, 5 ,Dischar eHei h Y fay gar Above GroundLeve[ ' $rFee-.`.,<s«;,,Xs h s Temp ( ) 5, a��fi ;; ,t Floe Rate - � .. r (ACFt� 1 Veloci �r ; (�Eisecl S034 30' 2,557 102,455,422 TBD Indicate the direction of the stack outlet: (check one) Q Upward ❑ Horizontal ❑ Downward O Other (describe): Indicate the stack opening and size: (check one) ❑ Upward with obstructing raincap ❑ Circular Interior stack diameter (inches): TBD ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Form APCD-2O6 - Amine Sweetening Unit APEN - Revision 04/2017 4 COLORADO ucwun.nl a Public 1WE06 Envinmmaiu Permit Number: 10WE2188 AIRS ID Number: 123 I 87/ 034 [Leave blank unless APCD has atready assigned a permit # and AIRS ID] Section 6 - Control Device Information ❑ VRU: Used for control of: Size: Make/Model: Requested Control Efficiency VRU Downtime or Bypassed % ❑ Combustion Device: Used for control of: Rating: MMBtu/hr Type: Make/Model: Requested Control Efficiency: % Manufacturer Guaranteed Control Efficiency % Minimum Temperature: Waste Gas Heat Content Btu/scf Constant Pilot Light: ❑ Yes 9 No Pilot burner Rating MMBtu/hr 9 Other: Used for control of: Thermal Oxidizer (TO) Description: Flash gas and still vent vapors are sent to the TO Control Efficiency Requested 98.0 98.0% for VOC; 96.45% for H2S Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 5 1 ViCOLORADO °.n.c 1.'011,& Envintrantwi Permit Number: 1 OWE2188 AIRS ID Number: 123 / 8;/ 034 [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. Is any emission control equipment or practice used to reduce emissions? ❑✓ Yes D No If yes, please describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description --' "fir Requested Control Efficiency %l .. . e )..,. . retluction m emus'ons PM SOX H2S 'TO 96.45% NOX VOC "TO 98% CO HAPs `RIO 98% Other: C,F'' 9.1-.csk \4e 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.) f � Cntena pollutant Emissions Inventory Pollutant 3 Uncontrolled --1:1-i16-6.Factor Factor Emission Units Emission Factor Source (aP 3,; Mfg:- etc) Actual Annual Emissions Requested Annual Permit Emission Ltmit(s)4 Uncontrolled (Tons/year);_ , Controlletl3 (Tons/year) Uncontrolled (Ton's/year)(Tons/.year) Controlled ' PM Sox 0. 6cl'Lt iqu'ArkScA OnG54 c:“.6tt - � .3. C6 HZS 0.3639 lb/MMscf ProMax 4.2 0.2 NOx 0.068 Ib/mmbtu AP -42 11.8 VOC 20.2490 lb/MMscf ProMax 231.7 41 1.\.(0 CO 0.31 Ib/mmbtu AP -42 53.8 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 5Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. c, Form APCD-2O6 - Amine Sweetening Unit APEN - Revision 04/2017 6 liailihtravrtnatvnon 'COLORADO Permit Number: 10WE2188 AIRS ID Number: 123 /8i/ 034 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 (continued) on.Critena Reportable Pollutant Emissions lnvento ack)(0aa ncontroll (Ibsfyear. Benzene 71432 1.3022 lb/MMscf ProMax Toluene 108883 0.3406 lb/MMscf ProMax l5\ Ethylbenzene 100414 Xylenes 1330207 0.0264 Ib/MMscf ProMax \`- n -Hexane 110543 0.0468 lb/MMscf ProMax NC6 3 2,2,4- Trimethylpentane Other: 540841 5Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. 02/07/2018 Signature of Legally Authorized Person (not a vendor or consultant) Date Zak N. Covar Vice -President, HSE&R Name (please 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) Send this form along with $152.90 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 Telephone: (303) 692-3150 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 COLORADO �,«mot Boiler APEN - Form APCD-220 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 maybe 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 boilers, hot oil heaters, process heaters, and similar equipment. If your emission unit does not fall into one of these categories, there may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, 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. Do not complete this form for the fotlowingsource categories: - Heaters or boilers with a design capacity less than or equal to 5 MMBtu/hour that are fueled solely by natural gas or liquid petroleum gas (LPG). Heaters or boilers with a design capacity less than or equal to 10 MMBtu/hour used solely for heating buildings for personal comfort that is fueled solely by natural gas or liquid petroleum gas (LPG). More information can be found in the APEN exempt/permit exempt checklist: https: / /www.colorado. Rov/ pacific/cdphe/apen-or-air-permit-exemptions. 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 (significantemissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 10WE2188.CP6 AIRS ID Number: 03- 123 / 8761 /-01-7- [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Meadowlark Midstream Company, LLC Site Name: Hereford Ranch Processing Plant Site Location: Section 26, Township 12N, Range 63W Mailing Address: (Include Zip Code) 999 18th Street, Suite 3400S Denver, CO 80202 E -Mail Address2: aparisi@summitmidstream.com Site Location County: Weld NAICS or SIC Code: 1321 Permit Contact: Andrew Parisi Phone Number: 303-626-8269 1 Please 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 cEanges will require additional paperwork. 2 Permits, exemption let_ers, and any processing invoices will be issued by APCD via e-mail to the address provided. Form APCD-220 - Boiler APEN - Revision 11 /2047 373200- 1, COLORADO o'Vrajec jetty R»+DtRbf vinnsMn! .Y Permit Number: 1 0WE21 88. C P6 AIRS ID Number: 123 / 8761 / 017 [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 name ❑ Change permit limit ❑ Transfer of ownership3 ❑ Add point to existing permit ❑ Other (describe below) OR - ▪ APEN submittal for update only (Please note blank APEN5 will not be accepted) - ADDITIONAL PERMIT ACTIONS - El 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: Update existing hot oil system rating to 25 MMBtu/hr. No change to permitted emission or process limits. 3 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Boiler Information General description of equipment and purpose: Hot oil heater for process heating. Manufacturer: TBD Model No.: 25 MMBtu/hr Serial No.: TBD Company equipment Identification No. (optional): For existing sources, operation began on: HT5802 8/28/2013 For new, modified, or reconstructed sources, the projected start-up date is: March 2018 ❑✓ 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 Seasonal use percentage: Dec -Feb: 25 Mar -May: 25 days/week weeks/year June -Aug: 25 Sept -Nov: 25 Are you reporting multiple identical boilers on this APEN? ❑ Yes ❑✓ No If yes, please describe how the fuel usage will be measured for each boiler (i.e., one meter for all boilers or separate meters for each unit): 'COLORADO Form APCD-22O - Boiler APEN - Revision 1112017 2 I Permit Number: 10WE2188.CP6 AIRS ID Number: 123 / 8761 / 017 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Stack Information Geographical; Coordinates' (Latitude/Longitude or UTM) UTM Zone 13, Easting 551139, Northing 4536300 , Operator � Stack 1D NO Discharge Height Above Ground Level_ Temp ( F) flow Rate jdCFM) q * Velocity, (ft/sec's HT5802 25 800 13,145 93 Indicate the direction of the stack outlet: (check one) ❑✓ Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) E Circular Interior stack diameter (inches): ❑ Square/rectangle Interior stack width (inches): ❑ Other (describe): ❑ Upward with obstructing raincap 10" Interior stack depth (inches): Section 5 - Fuel Consumption Information Design Input Rate (MMBTU/hr) Actual Annual Fuel Use (Specify Units) Requested Annual Permit Limifi (Specify Units) 25.0 214,8- MMscf/yr From what year is the actual annual fuel use data? Fuel consumption values entered above are for: ✓❑ Each Boiler ❑ All Boilers ❑ N/A Indicate the type(s) of fuel used': LPL 5P -(►g Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) )z1eld Natural Gas Heating valuer -7(31-2- 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) ❑ Coal Heating value: BTU/lb Ash content: Sulfur Content: ❑ Other (describe): Heating value (give units): 4 If you are reporting multiple identical boilers on one APEN, be sure to clarify if the values in this section are on an individual boiler basis, or if the values represent total fuel usage for multiple boilers. 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, please provide this information in the "Other" field. Form APCD-220 - Boiler APEN - Revision 11/2017 COLORADO 3I gr TSP (PM) Permit Number: 10WE2188.CP6 AIRS ID Number: 123 / 8761 / 017 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6- 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 If yes, please describe the control equipment AND state the overall control efficiency (% reduction): TSP (PM) Overall Control Efficiency %reduction in emissions), PM10 PM2_5 SOX NO. CO VOC Other: From what year is the following reported actual annual emissions data? Use the following tables to report the criteria pollutant emissions from source: (Use the data reported in Section 5 to calculate these emissions.) ncontrolled,; Emission Factor Specify Units) Emission Factor Source;. - (AP 42, Mfs etc) Uncontrolled (Tons/year) mission. re e �?? uesteci Annual mission Limits Gontrolled7 (Tons/year) ncontrolled.; Tons/year)',; ontrolted ns/year) Natural Gas 7.6 lb/MMscf AP -42, Table 1.4-2 0.9 PM10 7.6 Ib/MMscf AP -42, Table 1.4-2 0.9 PM2.5 7.6 Ib/MMscf AP -42, Table 1.4-2 0.9 SOX 0.6 Ib/MMscf AP -42, Table 1.4-2 0.1 NOX 100 lb/MMscf AP -42, Table 1.4-1 to.� CO 84 Ib/MMscf AP -42, Table 1.4-1 9.1 VOC 5.5 lb/MMscf AP -42, Table 1.4-2 0.6 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 7 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. a Form APCD-220 - Boiler APEN - Revision 11/2017 4 DepartzramtalPualk COLORADO H YEmOvnmmt TSP (PM) Permit Number: 10WE2188.CP6 AIRS ID Number: 123 / 8761 / 017 [Leave blank unless APCD has already assigned a permit # and AIRS ID] ✓❑ Check this box if the boiler did not combust a secondary fuel during this reporting period and skip to Section 7. If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total criteria emissions table below: Secondary Fuel Type (#2 diesel, Waste oil, j etc.) TSP (PM) Uncontrolled Emission Factor (Specify Units) Emission Factor Source ." (AP -42, Mfg. nnual Emissio uested Annual Permit rmission Limit(s)5 Uncontrolled (Tons%year) Controlled' '(Tons/Year)-: Uncontrolled (Toas/year) Controlled " (Tons/year) PMio PM2.s SOX NO. CO VOC Other: If multiple fuels were fired during this reporting period, use the following table to report the TOTAL criteria pollutant emissions from the source. Values listed below should be the sum of the reported emissions from the primary and secondary fuels' emissions tables in this Section 6: ctual Annual Emissio nested Annual Perini msslon Uncontrolled (Tons/year) Controlled? (Tons%year):_ ncontrolled (Tons/year) ; Controlled (Tons/year)" PMio PM2.5 SOX NO. CO VOC Other: 5 Requested values wit: become permit limitations. Requested limit(s) should consider future process growth. 7 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 11/2017 COLORADO 5 wmknau.wemnan+ 110-54-3 Hexane Permit Number: 10WE2188.CP6 AIRS ID Number: 123 / 8761 / 017 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - 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: verall Control Efficiency. Uncontrolled Emission Factor (specify units) AP -42, Table 1.4-3 Uncontrolled Actual s missions (!bs/year);; Controlled actual mission1 !bs/year) 0.0% 1.8 lb/MMscf 390 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 11/2017 6 COLORADO Departmme Ihadic t3„lthi, aanm,w Permit Number: 10WE2188.CP6 AIRS ID Number: 123 / 8761 / 017 [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. 12/28/2017 Signature of Legally Authorized Person (not a vendor or consultant) Date Zak N. Covar Vice -President Health, Safety, Environmental and Regulatory Name (please print) Title Check the appropriate box if you want: 0 Draft permit prior to public notice 0 Draft of the permit prior to issuance (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 $152.90 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 Telephone: (303) 692-3150 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692- 3148 Or visit the APCD website at: https: / /www.colorado.Rov/cdphe/apcd Form APCD-220 - Boiler APEN - Revision 11/2017 7I COLORADO 74emID GEnNwnmenf Boiler APEN - Form APCD-220 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 boilers, hot oil heaters, process heaters, and similar equipment. If your emission unit does not fall into one of these categories, there may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, 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.00v/cdphe/apcd. Do not complete this form for the following source categories: - Heaters or boilers with a design capacity less than or equal to 5 MMBtu/hour that are fueled solely by natural gas or liquid petroleum gas (LPG). Heaters or boilers with a design capacity less than or equal to 10 MMBtu/hour used solely for heating buildings for personal comfort that is fueled solely by natural gas or liquid petroleum gas (LPG). More information can be found in the APEN exempt/permit exempt checklist: https: //www.colorado.00v/pacific/cdphe/apen-or-air-permit-exemptions. 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: i 0WE2188.CP6 AIRS ID Number: 123 / 8761 / d 38 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Summit Midstream Niobrara, LLC Site Name: Hereford Ranch Processing Plant Site Location: Section 26, Township 12N, Range 63W Mailing Address: (Include Zip Code) 999 18th Street, Suite 4400S Denver, CO 80202 E -Mail Address2: aparisi@summitmidstream.com Site Location County: Weld NAICS or SIC Code: 211130 Permit Contact: Andrew Parisi Phone Number: 303-626-8269 ' Please 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 APCD via e-mail to the address provided. Form APCD-220 - Boiler APEN - Revision 11/2017 374730 COLORADO in�..�.mdamu: AIRS ID Number: 123 / 8761 / Permit Number: 1OWE2188.CP6 [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 name 0 Add point to existing permit ❑ Change permit limit 0 Transfer of ownership3 ❑ Oth?r (describe below) OR ❑ APEN submittal for update only (Please 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 It Notes: New 25 MMBtu/hr natural gas fired hot oil heater. 3 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Boiler Information General description of equipment and purpose: Hot oil heater for process heating. Manufacturer: TBD Model No.: 25 MMBtu/hr Serial No.: TBD Company equipment Identification No. (optional): HT03 For existing sources, operation began on: For new, modified, or reconstructed sources, the projected start-up date is: -August 2018 ❑✓ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: 24 + Seasonal use percentage: Dec -Feb: 25 hours/day 7 days/week Mar -May: 25 June -Aug: 25 52 Sept -Nov: weeks/year 25 Are you reporting multiple identical boilers on this APEN? ❑ Yes ❑✓ No If yes, please describe how the fuel usage will be measured for each boiler (i.e., one meter for all boilers or separate meters for each unit): Form APCD-220 - Boiler APEN - Revision 11/2017 2 I I COLORADO o=nm.ocdn.�.-_. {FM:Qt6kl�vi[�mmprti Permit Number: 10WE2188.CP6 AIRS ID Number: 123 / 8761 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Stack Information eographical Coordinates; titude/Longitude or MTM, UTM Zone 13, Easting 551151.27, Northing 4536860.80 UUIP5 DischargeHeight - el 1MU__ i , 4 mPFlow , �� i ate a � 4E y ocr € a u HT03 25 800 16,430 93 Indicate the direction of the stack outlet: (check one) Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑✓ Circular ❑ Square/rectangle Interior stack width (inches): ❑ Other (describe): Interior stack diameter (inches): ❑ Upward with obstructing raincap 12" Interior stack depth (inches): Section 5 - Fuel Consumption Information Design InPt Rate BTU/hr) Actual Annual Fuel Use4 ' (Specify Units) ' = Requested Annual Permit � Limrt5 (specify Units) 25.0 214.7 MMscf/yr From what year is the actual annual fuel use data? Fuel consumption values entered above are for: LI Each Boiler ❑ All Boilers ❑ N/A Indicate the type(s) of fuel used': 0 Pipeline Natural Gas El Field Natural Gas ❑ Ultra Low Sulfur Diesel El Propane ❑ Coal ❑ Other (describe): (assumed fuel heating value of 1,020 BTU/SCF) Heating value: BTU/SCF (assumed fuel heating value of 138,000 BTU/gallon) (assumed fuel heating value of 2,300 BTU/SCF) Heating value: BTU/lb Ash content: Sulfur Content: Heating value (give units): 4 4 If you are reporting multiple identical boilers on one APEN, be sure to clarify if the values in this section are on an individual boiler basis, or if the values represent total fuel usage for multiple boilers. 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, please provide this information in the "Other" field. Form APCD-220 - Boiler APEN - Revision 11/2017 VKosatettir environment rICOLORADO Permit Number: 10WE2188. 88.CP6 AIRS ID Number: 123 / 8761 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6- 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, please describe the control equipment AND state the overall control efficiency (% reduction): TSP (PM) verall Control Efficiency %reduction iinemissions). PM10 PM2.5 SOX NO, CO VOC Other: From what year is the following reported actual annual emissions data? Use the following tables to report the criteria pollutant emissions from source: (Use the data reported in Section 5 to calculate these emissions.) TSP (PM) 7.6 Ib/MMscf 0.8 0.8 uested Annual -Permit mission Ljmiis ncontrolled onslyear) Natural Gas AP -42, Table 1.4-2 PM10 7.6 lb/MMscf AP -42, Table 1.4-2 0.8 0.8 PM2.5 7.6 Ib/MMscf AP -42, Table 1.4-2 0.8 0.8 SOX 0.6 lb/MMscf AP -42, Table 1.4-2 0.1 0.1 NO, 100 lb/MMscf AP -42, Table 1.4-1 10.8 10.8 CO 84 lb/MMscf AP -42, Table 1.4-1 9.1 9.1 VOC 5.5 Ib/MMscf AP -42, Table 1.4-2 0.6 0.6 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 7 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. 1f * Form APCD-220 - Boiler APEN - Revision 11/2017 4 I COLORADO ixp.,mmdr.:au. ISM1R1 b ETwvanmau Permit Number: 10WE2188.CP6 AIRS ID Number: 123 / 8761 / TSP (PM) [Leave blank unless APCD has already assigned a permit # and AIRS ID] ✓❑ Check this box if the boiler did not combust a secondary fuel during this reporting period and skip to Section 7. If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total criteria emissions table below: ncontrolled mission actor 5 ControlIe (Tons/yea guested Annual Perini m1ss1on Limits ncontrolle ons/year. PM10 PM2.5 SO. NOx CO VOC Other: If multiple fuels were fired during this reporting period, use the following table to report the TOTAL criteria pollutant emissions from the source. Values listed below should be the sum of the reported emissions from the primary and secondary fuels' emissions tables in this Section 6: Pollutant � ° Actual Annual•Emissions � � _ (Requested Annual 4 � .Emissio e... Permit ��` g ; (s Uncontrolled (Tonslyear) , . Controlled : "(Tonsryear), . -Uncontrolled : , (Tons year) •` Controlled (Tons/year) j. TSP (PM) PMio PM2.s SOx NOx CO VOC Other: 5 Requested values will become permit limitatiors. Requested limit(s) should consider future process growth. 7 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 11/2017 5 COLORADO Deparbrourt at Public r=. Permit Number: 10WE2188.CP6 AIRS ID Number: 123 / 8761 / 110-54-3 Hexane 0.0% [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - 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: ncontrolled mission actor pecify urtin AP -42, Table 1.4-3 Incontrolled ctual;, mission (lbs/year) .; 1.8 Ib/MMscf 387 7Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. 4 Form APCD-220 - Boiler APEN - Revision 11/2017 6I i COLORADO apcuaoemnasc iSal:Rbfl+rhvnmeni r 1=r a Permit Number: 10WE2188.CP6 AIRS ID Number: 123 / 8761 / [Leave blank unless APCD has already assigned a permit # and MRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. 02/07/2018 Signature of Legally Authorized Person (not a vendor or consultant) Date Name (please print) Title Zak N. Cover Vice President - HSE&R Check the appropriate box if you want: I✓ Draft permit prior to public notice ❑� Draft of the permit prior to issuance (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 $152.90 to: 4 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 Telephone: (303) 692-3150 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692- 3148 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-220 - Boiler APEN - Revision 11/2017 7I COLORADO m«,ain, toviewarma ;0!0 ,a,n Reciprocating Internal Combustion Engine APEN - Form APCD-201 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 reciprocating internal combustion engines (RICE). If your engine is a diesel compression ignition engine or your emission unit does not fall into the RICE category, there may be a more specific APEN for your source (e.g. diesel compression ignition engine, mining operations, asphalt plant, crusher, screen, 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: 10WE2188 AIRS ID Number: 123 /8761 / DAD [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Summit Midstream Niobrara, LLC Site Name: Hereford Ranch Processing Plant Site Location: Section 26, T12N, R63W Mailing Address: (Include Zip Code) 999 18th Street, Suite 2500S Portable Source Home Base: Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 211130 Permit Contact: Andrew Parisi Phone Number: 303-626-8269 E -Mail Address2: aparisi@summitmidstream.com {� f 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 qy the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided. 374732 Form APCD-201 - Reciprocating Internal. Combustion Engine APEN - Revision 1/2017 COLORADO S. t MAMA MAMAw�s mutant FTulafu Permit Number: 1 0WE2188 AIRS ID Number: 123 /8761 / [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 Request coverage under a Construction Permit ❑ Request coverage under General Permit GP023 (Natural Gas Only) If General Permit coverage is requested, the General Permit registration fee of $1,500.00 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 name LI Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership4 ❑ Other (describe below) - OR • APEN submittal for update only (Blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - • APEN submittal for permit-exempt/grandfathered source Ei Notification of Alternate Operating Scenario (AOS) permanent replacements Additional Info a Notes: add source to 10WE2188 3 Only one engine may be reported per APEN for GP02 coverage. Coverage under GP02 is voluntary. 4 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. 5 This does not apply to General Permit GP02, as it does not contain a provision for AOS permanent replacements. Section 3 - General Information Does this engine have a Company Equipment Identification No. (e.g. ENG-1, Engine 3, etc)? Yes If yes, provide the Company Equipment Identification No. ENG-1 General description of equipment and purpose: natural gas compression. Natural gas fired four-stroke lean burn engine used for For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: Will this equipment be operated in any NAAQS nonattainment area? (http: / /www.colorado.gov / cd phe /attainment) Normal Hours of Source Operation: 24 Seasonal use percentage: Dec -Feb: 25 ;t -08/01/2018 ❑ Yes No hours/day 7 days/week 52 weeks/year Mar -May: 25 June -Aug: 25 Sept -Nov: 25 Form APCD-201 - Reciprocating Internal Combustion Engine APEN - Revision 1/2017 2 l COLORADO Department m P�Nlc Naxltn 6 Envsamment Permit Number: 10WE2188 AIRS ID Number: 123 /8761 / [Leave blank unless APCD has already assigned a permit #, and AIRS ID] Section 4 - Engine Information Engine Function: El Primary and/or Peaking ❑ - Pump ❑ Water Pump ❑ Emergency Back-up El - Other: ❑r Compression What is the maximum number of hours this engine will be used for emergency back-up power? N/A Engine Make: Caterpillar Engine Model: G3608 TALE Serial Number': TBD hours/year What is the maximum designed horsepower rating? 2370 hp What is the engine displacement? 21.2 l/cyl What is the maximum manufacturer's site -rating? 2317 hp kW What is the engine Brake Specific Fuel Consumption at 100% Load? 7607 BTU/hp-hr Engine Features: Cycle Type: El 2 -Stroke ✓❑ 4 -Stroke Combustion: ❑✓ Lean Burn ❑ Rich Burn Ignition Source: E Spark ❑ Compression Aspiration: ❑ Natural ❑✓ Turbocharged Is this engine equipped with an Air/Fuel ratio controller (AFRC)? (] Yes ❑ No If yes, what type of AFRC is in use? ❑ O2 Sensor (mV) ❑✓ NOx Sensor (ppm) Is this engine equipped with a Low-NOx design? ❑Q Yes O No Engine Dates: What is the manufactured date of this engine? TBD ❑ Other: What date was this engine ordered? not yet ordered What is the date this engine was first located to Colorado? TBD What is the date this engine was first placed in service/operation? TBD What is the date this engine commenced construction? TBD What is the date this engine was last reconstructed or modified? TBD Is this APEN reporting an AOS replacement engine? ❑ Yes ❑✓ No If yes, provide the make, model, and serial number of the old engine below: Engine Make: Engine Model: Serial Number: 6 The serial number must be submitted if coverage under GP02 is requested. 4 Form APCD-201 - Reciprocating Internal Combustion Engine APEN - Revision 1/2017 COLORADO 0eparm.on1 Public Ne0111 Prvleanmcnt 144 f= Permit Number: 1 CWE2188 AIRS ID Number: 123 /8761 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information eographical Coordinat atitude/Longitude or UT Lat. 40.98211 , Long. -104.39298 'SP 'b.'.' t...�c;s -:- • 0 erato tac ID o x- `'"'Es�s',Tf`""«''a�: Discharg eigh bore rou lever eef �rn �f a u� ,Y�� .grya a e = il f c �# �Ielncityq c s ENG-1 -25 ft. 862 15,939 150 Indicate the direction of the Stack outlet: (check one) O Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check cne) ❑✓ Circular ❑ Square/Rectangle ❑ Other (describe): Interior stack diameter (inches): O Upward with obstructing raincap 18 in. Interior stack diameter (inches): Interior stack depth (inches): Section 6 - Fuel Data and Throughput Information Fue1,Use ai' X00% Load S YF hd�; lct ial Annual Fuel Us (rNti1CF ar € Re 6este AnnUa1 ' mi P. A. , ,,� 17,280 scf/hr 151.4 MMScf/yr. From what year is the actual annual amount? Indicate the type of fuel used': E Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/scf) ❑ Field Natural Gas Heating value: BTU/scf ❑ Propane (assumed fuel heating value of 2,300 BTU/scf) ❑ Landfill Gas Heating Value: BTU/scf ❑ Other (describe;: Heating Value (give units): 7 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 8 If fuel heating value 's different than the listed assumed value, provide this information in the "Other" field. Form APCD-201 - Reciprocating Internal Combustion Engine APEN - Revision 1/2017 COLORADO 4 I ,� et� IkutiT b ESrvin+nmaN Permit Number: 1 0WE2188 AIRS ID Number: 123 /8761 / TSP (PM) [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. The APCD website has a Natural Gas Fired Engines Calculator available to assist with emission calculations. Is any emission control equipment or practice used to reduce emissions? Yes ❑ No If yes, describe the control equipment AND state the overall control efficiency (% reduction): ve_ rall Requested Contro' Efficiency': ctron nemissi!ons; PM10 PM2.5 SOx NOx VOC SCO (oxidation catalyst) 21% CO SCO (oxidation catalyst) 93% Other: Use the following tables to report criteria and non -criteria pollutant emissions from source: (Use the data reported in Section 6 to calculate these emissions.) From what year is the following reported actual annual emissions data? itena Pollutant Emissions Inventory mission Fact' 0.01010 lb/mmbtu ctual Annual Emissions9 ed Annual Perini mission Lim'.it(s)7.: TSP (PM) AP -42 0.78 0.78 PM10 PM2.5 0.0000771 lb/mmbtu AP -42 0.006 0.006 0.0000771 lb/mmbtu AP -42 0.006 0.006 SOX NOx VOC 0.000588 lb/mmbtu AP -42 0.05 0.05 0.5 g/hp-hr Manufacturer 11.2 11.2 0.89 g/hp-hr Manufacturer 19.91 15.7 CO 2.75 g/hp-hr Manufacturer 61.53 4.31 Does the emissions source have any uncontrolled actual emissions of non -criteria ❑✓ Yes ❑ No pollutants (e.g. HAP - hazardous air pollutant) equal to or greater than 250 lbs/year? If yes, please use the following table to report the non -criteria pollutant (HAP) emissions from source: Non COtera,Reportable_PollutantEmssions.Inventory , Chemical Name . mica Emus on Factor , Actual Annual > miss ons 5 '* r f Abstract Service Number _ Uncontrolled ,. Basis _ tJmts y - Source ' (A d2 k Mfg. etch;: c x Uncontrolled Emisslon5 > lPounds/year) s P 2 .a Controlled frnlssionsz. z p afinds year ( Formaldehyde 50000 0.26 g/hp-hr Manufacturer 2,792 Acetaldehyde 75070 0.00836 lb/mmbtu AP -42 645 Acrolein 107028 0.00514 lb/mmbtu AP -42 397 Benzene 71432 0.00044 lb/mmbtu AP -42 Other: Methanol 0.00250 lb/mmbtu AP -42 386 7 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 9 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-201 - Reciprocating Internal Combustion Engine APEN - Revision 1/2017 COLORADO neynm�w» we Ndxttb b Fm9mnmant Permit Number: 10WE2188 AIRS ID Number: 123 /8761 / [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 GP02, I further certify that this source is and will be operated in full compliance with each condition of general permit GP02. 02/07/2018 Signature of Legally Authorized Person (not a vendor or consultant) Date Zak N. Covar Vice President, HSE&R Name (please 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. Send this form along with $152.90 and the General Permit registration fee of $1,500, 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 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: Make check payable to: https://www.colorado.gov/cdphe/apcd Colorado Department of Public Health and Environment Telephone: (303) 692-3150 Form APCD-201 - Reciprocating Internal Combustion Engine APEN - Revision 1/2017 t COLORADO aE ar,tuk ;Dian, t„6pnGqImxq 4 Hello