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Home My WebLink About20102307.tiff STATE OF COLORADO Bill Ritter,Jr.,Governor Martha E. Rudolph,Executive Director /04•cozQ\ Dedicated to protecting and improving the health and environment of the people of Colorado t3 of 4300 Cherry Creek Dr.S. Laboratory Services Division * */ Denver,Colorado 80246-1530 8100 Lowry Blvd. "1 Phone(303)692-2000 Denver,Colorado 80230-6928 tags; TDD Line(303)691-7700 (303)692-3090 Colorado Department Located in Glendale,Colorado P of Public Health http://www.cdphe.state.co.us and Environment September 23, 2010 Mr. Steve Moreno Weld County Clerk 1402 N. 17th Ave. Greeley, CO 80631 Dear Mr. Moreno: The Air Pollution Control Division will publish a public notice for the DCP Midstream, LP. This public notice will be published in The Greeley Tribune on September 29, 2010. Thank you for assisting the Division by making the enclosed package (includes public notice, preliminary analysis, Air Pollutant Emission Notice(s) and draft permit(s)) available for public review and comment. It must be available for public inspection for a period of thirty (30) days from the date the public notice is published. Please forward any comment regarding this public notice to the address below. Colorado Department of Public Health and Environment APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Attention: Jacquie Barela Regards, Ii)(4.(!!t 1 t 5ie.., Jacqueline N. Barela Public Notice Coordinator Stationary Sources Program Air Pollution Control Division °) 'W l 6{ 2010-2307 NOTICE OF REQUEST FOR MAJOR SOURCE PERMIT FOR NATURAL GAS PROCESSING PLANT BY DCP Midstream, LP CONTENTS 1 . PUBLIC NOTICE 2. PRELIMINARY ANALYSIS 3. AIR POLLUTANT EMISSION NOTICES 4. DRAFT PERMIT PREPARED BY: STEPHANIE CHAOUSY COLORADO DEPARTMENT OF PUBLIC HEALTH & ENVIRONMENT 4300 CHERRY CREEK DRIVE SOUTH, APCD-SS-B1 DENVER, CO 80246-1530 STATE OF COLORADO Bill Ritter,Jr.,Governor ov.c��o Martha E. Rudolph,Executive Director 4� ;- Dedicated to protecting and improving the health and environment of the people of Colorado 4300 Cherry Creek Dr.S. Laboratory Services Division etnavIvi Denver,Colorado 80246-1530 8100 Lowry Blvd. *1876 Phone(303)692-2000 Denver,Colorado 80230-6928 TDD Line(303)691-7700 (303)692-3090 Colorado Department Located in Glendale,Colorado of Public Health http://www.cdphe.state.co.us and Environment Released to: The Greeley Tribune on September 23, 2010; published September 29, 2010 PUBLIC NOTICE OF A PROPOSED PROJECT OR ACTIVITY WARRANTING PUBLIC COMMENT The Colorado Air Pollution Control Division declares the following proposed construction activity warrants public comment. Therefore, the Air Pollution Control Division of the Colorado Department of Public Health and Environment hereby gives NOTICE, pursuant to Section 25-7-114.5(5), C.R.S. of the Colorado Air Quality Control Act that the Division received an application for an air pollution emission permit on the following proposed project and activity: DCP Midstream, LP proposes to operate and modify an oil and natural gas processing plant known as the Roggen Natural Gas Processing Plant. This source will be designed to process 168.5 MMSCF per day of natural gas and will be located in Section 24 of Township 2 North, Range 63 West in Weld County. This modification includes the addition of a TriEthylene Glycol (TEG) glycol dehydrator, amine unit, and two (2) 4-stroke, lean burn reciprocating internal combustion engines. The source would be considered a major modification at a major source of air pollutants subject to New Source Review (NSR) requirements if the operator did not install emissions controls and accept Federally enforceable emissions limits in the proposed permit. The increase of NOx at the facility was less than the 40 tons per year threshold for NSR review, and therefore, the modification will be considered a synthetic minor modification and not subject to NSR review. The source will have permitted emissions greater than 100 tons per year for criteria pollutants and will be considered a major source subject to Title V Operating Permit requirements and an existing major source for non-attainment NSR. As such, this permit is subject to public comment per Regulation 3, Part B, Section III.C.I.d. Copies of the draft permit and preliminary analysis are available for review in the public comment package. The Division hereby solicits and requests submission of public comment concerning the aforesaid proposed project and activities for a period of thirty (30) days from the date of this publication. Any such comment must be submitted in writing to the following addressee: Stephanie Chaousy, P.E. Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South, APCD-SS-B 1 Denver, Colorado 80246-1530 Within thirty(30)days following the said thirty(30)-day period for public comment,the Division shall consider comments and, pursuant to Section 25-7-114.5(7)(a), either grant, deny, or grant with conditions, the emission permits. Said public comment is solicited to enable consideration of approval of and objections to the proposed construction of the subject project and activity by affected persons. A copy of the applications for the emission permits,the preliminary analysis of said applications, and accompanying data concerning the proposed project and activity are available for inspection at the office of the Clerk and Recorder of Weld County during regular business hours and at the office of the Air Pollution Control Division, Colorado Department of Public Health and Environment, 4300 Cherry Creek Drive South, Denver, Colorado. Construction Permit Application Preliminary Analysis Summary Section 1 —Applicant Information Company Name: DCP Midstream, L.P. Permit Number: 10WE1659 Source Location: S24, T2N, R63W,Weld County (non-attainment) Point 122: Fugitive Emission Leaks Point 135: Caterpillar G3608TALE at 1000 RPM Point 136: 85.0 MMSCF/day TEG dehydrator Equipment Description: Point 137: Amine Sweetening Unit Point 138: Hot oil heater Point 139: Caterpillar G3608TALE at 1000 RPM AIRS ID: 123-0049 Date: September 23, 2010 Review Engineer: Stephanie Chaousy, P.E. Control Engineer: Chris Laplante Section 2—Action Completed Grandfathered Modification APEN Required/Permit Exempt X CP1 Transfer of Ownership APEN Exempt/Permit Exempt Section 3—Applicant Completeness Review Was the correct APEN submitted for this source type? X Yes No Is the APEN signed with an original signature? X Yes No Was the APEN filled out completely? Yes X No Did the applicant submit all required paperwork? X Yes No Did the applicant provide ample information to determine emission rates? X Yes No Page 1 If you answered -Point 122: Calculations were showing more components than what was on APEN. "no"to any of the Emailed 7/13/10. Phone call from Wes Hill on 7/13/10 confirmed discrepancy and I above, when did redlined the APEN accordingly. you mail an Information -Point 122: n-pentane was wrong in the spreadsheet calculating VOC wt%. Not Request letter to sure if it will make a drastic change. Emailed 7/13/10. Email on 7/15/10 confirmed the source? that n-pentane was wrong, but it was incorporating the value of cyclopentane so that all pentane emissions were accounted for. Question: wanted to ask about C181 (if it was Point 134). Uncontrolled emissions on operator facility inventory were incorrect. Emailed 7/13/10. Phone call from Wes Hill on 7/13/10 confirmed discrepancy and will send over a revised inventory form. Received revised inventory on 7/15/10. -Question: if I could receive a copy of the most recent APEN submitted for the condensate loadout. PTS does not show an APEN that matches their inventory. Most current APEN in PTS is for a flare, not for condensate loadout. Received a copy of the loadout APEN via email on 7/15/10. -Believed that Point 135 (which consists of 2 engines) would be sharing the yearly hours between engines (not overlapping time). Emailed 7/13/10 on what I thought the new emission limit would be for the combining of engines (8760 total hours). Wes Hill called and said that they were hoping to run each engine at 75% of 13140 hours (so that there could be some overlapping of both engines running at the same time), and would minimize their process limits to 13140 hours for total engines. Wanted to confirm this with Chris (for I didn't think we agreed at the meeting that the engines would ever overlap in running time). Had a meeting with Chris on 7/26/10 regarding the 2 engines sharing 1 emission and process point. We reviewed the DRAFT APENS submitted by DCP on 7/15/10 and we didn't have a problem with them sharing as long as each point had separate APENs and were able to be accounted for separately in inventory. Emailed Wes on 7/26/10 that we were accepting the DRAFT APENs and to send us final APENs with additional check. On 7/29/10, CDPHE received new package (check, revised APENs and supporting calculations). -Did not see Points 105, 106, and 116 on operator facility inventory form. Did not see anything in PTS that indicated cancellation. Emailed on 7/14/10 regarding status on these points. Received a cancellation letter via email 7/15/10. On what date was this application December 11, 2009 complete? Section 4—Source Description AIRS Point Equipment Description 122 Equipment leaks (fugitive VOCs) from a natural gas processing facility. One (1) Caterpillar, Model G3608TALE, Serial Number BEN00537, natural gas-fired, 135 turbo-charged, 4SLB reciprocating internal combustion engine, site rated at 2370 horsepower at 1000 RPM. This engine shall be equipped with an oxidation catalyst and air- fuel ratio control. This emission unit is used for natural gas compression. One (1) Triethylene glycol (TEG) natural gas dehydration unit(make, model, serial number: not submitted)with a design capacity of 85 MMscf per day. This emissions unit is 136 equipped with one (1) gas-glycol pump (make, model: not submitted) with a design capacity of 20 gpm. This unit is equipped with a flash tank, reboiler and still vent. Emissions from the flash tank and still vent are routed to a regenerative thermal oxidizer (RTO) with a minimum control efficiency of 99%. Page 2 One (1) Diethanolamine (DEA) and Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 85 MMSCF per day (make, model, serial number: TBD). This emissions unit is equipped with one (1) electric OR gas-injection 137 amine recirculation pump. This system includes a natural gas/amine contactor and still vent and reboiler. Flash gases are routed to fuel line of the hot oil heater(Point 138). Still vent emissions shall be routed to a regenerative thermal oxidizer(RTO)with a minimum control efficiency of 99%. 138 36.7 MMBTU/hr hot oil heater equipped wth low NOx burners that provides the heat for the amine sweetening unit reboiler. One (1) Caterpillar, Model G3608TALE, Serial Number BEN00539, natural gas-fired, turbo- 139 charged, 4SLB reciprocating internal combustion engine, site rated at 2370 horsepower at 1000 RPM. This engine shall be equipped with an oxidation catalyst and air-fuel ratio control. This emission unit is used for natural gas compression Is this a portable source? Yes X No Is this location in a non-attainment area for any criteria X Yes No pollutant? If"yes", for what pollutant? PM,o CO X Ozone Is this location in an attainment maintenance area for Yes X No any criteria pollutant? If"yes", for what pollutant? (Note: These pollutants are subject to minor source PM,o CO Ozone RACT per Regulation 3, Part B, Section III.D.2) Is this source located in the 8-hour ozone non- attainment region? (Note: If"yes" the provisions X Yes No of Regulation 7, Sections XII and XVII.C may apply) Section 5—Emission Estimate Information AIRS Point Emission Factor Source 122 EPA 453/R-95-017 Emission factors from manufacturer specifications 135 NOx = 0.5 g/hphr; VOC = 0.63 g/hphr; CO = 2.76 g/hphr; Formaldehyde = 0.40 g/hphr Other HAPS are AP-42 Emission factors from Promax model and AP-42 NOx= 0.068 Ib/mmbtu fuel (AP-42) Uncontrolled VOC = (1299 TPY*2000 lb/ton)/ 29967 mmscf/yr= 86.7 lb/mmscf(promax model) Controlled VOC = (13 TPY*2000 lb/ton) /29967 mmscf/yr= 0.87 lb/mmscf(promax model) CO = 0.37 lb/mmbtu fuel (AP-42) Uncontrolled HAP E.F. Benzene = (81.5 TPY*2000 lb/ton)/29967= 5.44 lb/mmscf(promax model) 136 Toluene = (112.1 TPY*2000 lb/ton)/29967= 7.48 lb/mmscf(promax model) Ethylbenzene = (5.24 TPY*2000 lb/ton)/29967= 0.35 lb/mmscf(promax model) Xylenes = (42.5 TPY*2000 lb/ton)/29967= 2.84 lb/mmscf(promax model) n-hexane = (180.2 TPY*2000 lb/ton)/29967= 12.03 lb/mmscf(promax model) Controlled HAP E.F. Benzene = (0.82 TPY*2000 lb/ton)/29967= 0.05 lb/mmscf(promax model) Toluene = (1.12 TPY*2000 lb/ton)/29967= 0.07 lb/mmscf(promax model) Ethylbenzene = (0.05 TPY*2000 lb/ton)/29967= 0.003 lb/mmscf(promax model) Xylenes = (0.43 TPY*2000 lb/ton)/29967= 0.03 lb/mmscf(promax model) n-hexane = (1.80 TPY*2000 lb/ton)/29967= 0.12 lb/mmscf(promax model) 137 Emission factors from Promax model and AP-42 NOx= 0.068 lb/mmbtu fuel (AP-42) Page 3 Uncontrolled VOC = (321.47 TPY*2000 lb/ton) /31025 mmscf/yr= 20.72 lb/mmscf (promax model) Controlled VOC = (11.8 TPY*2000 lb/ton) / 31025 mmscf/yr= 0.76 lb/mmscf(promax model) CO = 0.37 lb/mmbtu fuel (AP-42) SO2 = 1.88 ton SO2/H2S Uncontrolled HAP E.F. Benzene = (37.71 TPY*2000 lb/ton)/31025= 2.43 lb/mmscf(promax model) Toluene = (40.15 TPY*2000 lb/ton)/31025= 2.59 lb/mmscf(promax model) Xylenes = (7.44 TPY*2000 lb/ton)/31025= 0.48 lb/mmscf(promax model) n-hexane = (6.78 TPY*2000 lb/ton)/31025= 0.44 lb/mmscf(promax model) Controlled HAP E.F. Benzene = (0.5 TPY*2000 lb/ton)/31025= 0.03 lb/mmscf(promax model) Toluene = (0.5 TPY*2000 lb/ton)/31025= 0.03 lb/mmscf(promax model) Xylenes = (0.1 TPY*2000 lb/ton)/31025= 0.01 lb/mmscf(promax model) n-hexane = (0.3 TPY*2000 lb/ton)/31025= 0.02 lb/mmscf(promax model) 138 AP-42 Emission factors from manufacturer specifications 139 NOx = 0.5 g/hphr; VOC = 0.63 g/hphr; CO = 2.76 g/hphr; Formaldehyde = 0.40 g/hphr Other HAPS are AP-42 Did the applicant provide actual process data for the emission inventory? X Yes No Basis for Potential to Emit(PTE) AIRS Point Process Consumption/Throughput/Production Equipment Type Gas Heavy Oil (or Light Oil (or Water/Oil Heavy Liquid) Light Liquid) Connectors 2637 0 5162 0 122 Flanges 1929 0 1460 0 Open-Ended Lines 0 0 0 0 Pump Seals 0 0 40 0 Valves 1649 0 2388 0 Other 105 0 49 0 135 122.4 mmscf/yr(Permit will show a combination of Points 135 and 139 for a process limit of 244.8 mmscf/yr). 136 29,967 mmscf/yr 137 31,025 mmscf/yr 138 280.72 MMSCF/year 139 122.4 mmscf/yr(Permit will show a combination of Points 135 and 139 for a process limit of 244.8 mmscf/yr). Basis for Actual Emissions Reported During this APEN Filing (Reported to Inventory) AIRS Point Process Consumption/Throughput/Production Data Year Equipment Type Gas Heavy Oil Light Oil Water/Oil (or Heavy (or Light Liquid) Liquid) Connectors 2637 0 5162 0 122 Flanges 1929 0 1460 0 Open-Ended 0 0 0 0 Lines Pump Seals 0 0 40 0 Valves 1649 0 2388 0 Other 105 0 49 0 Page 4 135 122.4 mmscf/yr(Permit will show a combination of Points 135 and 139 for a process limit of 244.8 mmscf/yr). 136 29,967 mmscf/yr 137 31,025 mmscf/yr 138 280.72 MMSCF/year 139 122.4 mmscf/yr(Permit will show a combination of Points 135 and 139 for a process limit of 244.8 mmscf/yr). Basis for Permitted Emissions (Permit Limits) AIRS Point Process Consumption/Throughput/Production Equipment Type Gas Heavy Oil (or Light Oil (or Water/Oil Heavy Liquid) Light Liquid) Connectors 2637 0 5162 0 122 Flanges 1929 0 1460 0 Open-Ended Lines 0 0 0 0 Pump Seals 0 0 40 0 Valves 1649 0 2388 0 Other 105 0 49 0 135 122.4 mmscf/yr(Permit will show a combination of Points 135 and 139 for a process limit of 244.8 mmscf/yr). 136 29,967 mmscf/yr 137 31,025 mmscf/yr 138 280.72 MMSCF/year 139 122.4 mmscf/yr(Permit will show a combination of Points 135 and 139 for a process limit of 244.8 mmscf/yr). Does this source use a control device? X Yes No AIRS Point Process Control Device Description % Reduction Granted Valves, Other, Pump Seals, Open-ended lines: 75% 122 01 Controlled Connectors, Flanges: 30% VOC135 01 Oxidation catalyst and air-fuel ratio controller Form:: 50%; CO: 93%; 90%; HAPS: 50% 136 01 RTO (regenerative thermal oxidizer) 99 137 01 RTO (regenerative thermal oxidizer) 99 138 01 Low NOx burner 50 VOC: 50%; CO: 93%; 139 01 Oxidation catalyst and air-fuel ratio controller Form: 90%; HAPS: 50% Page 5 Section 6— Emission Summary (tonsper year) Point NO,, VOC CO SO2 Single HAP Total HAP 122 --- 99.1 --- --- 0.5 (n-hexane) 0.7 135 8.6 10.8 47.4 --- 6.9 (formaldehyde) 7.7 136 3.9 1299 21.2 --- 180 (n-hexane) 421.5 PTE: 137 0.2 321.5 1.2 32.3 40.2 (toluene) 93.1 138 14.0 0.7 11.8 --- --- --- 139 8.6 10.8 47.4 --- 6.9 (formaldehyde) 7.7 122 --- 99.1 --- --- 0.5 (n-hexane) 0.7 135 8.6 10.8 47.4 --- 6.9 (formaldehyde) 7.7 Uncontrolled point 136 3.9 1299 21.2 --- 180 (n-hexane) 421.5 source emission rate: 137 0.2 321.5 1.2 32.3 40.2 (toluene) 93.1 138 14.0 0.7 11.8 --- --- 139 8.6 10.8 47.4 --- 6.9 (formaldehyde) 7.7 122 --- 31.4 --- --- 0.2 (n-hexane) 0.3 135 8.6 5.3 3.3 --- 0.7 (formaldehyde) 1.2 Controlled point 136 3.9 13.0 21.2 --- 1.8 (n-hexane) 4.2 source emission rate: 137 0.2 11.8 1.2 32.3 0.5 (toluene) 1.4 138 7.0 0.7 11.8 --- --- --- 139 8.6 5.3 3.3 --- 0.7 (formaldehyde) 1.2 Total of Other Point 236.5 171.1 238.3 7.7 Sources at Facility Total of nsignificants (1.2) (1.3) (1.0) 0 0 Total APEN Reported 266.0 239.9 280.0 16.4 emissions: Section 7—Non-Criteria/Hazardous Air Pollutants Uncontrolled Amnia Controlled Emission Pollutant CAS # BIN Emission Rate emissions (Ib/yr) reportable? Rate(Ib/yr) Point 122 Benzene 71432 A 171 Yes 56 Toulene 108883 C 180 No 60 Ethylbenzene 100414 C 0 No 0 Xylenes 1330207 C 120 No 40 n-Hexane 110543 C 1027 Yes 339 Points 135 Formaldehyde 50000 A 13731 Yes 1373 Acetaldehyde 75070 A 980 Yes 490 Acrolein 107028 A 603 Yes 301 Page 6 Toulene 108883 C 48 No 48 n-Hexane 110543 C 130 No 130 Point 136 Benzene 71432 A 163,000 Yes 1630 Toulene 108883 C 224,145 Yes 2241 Ethylbenzene 100414 C 10,484 Yes 105 Xylenes 1330207 C 85,023 Yes 860 n-Hexane 110543 C 360,366 Yes 3604 Point 137 Benzene 71432 A 75424 Yes 980 Toulene 108883 C 80300 Yes 989 Ethylbenzene 100414 C 2180 Yes 26 Xylenes 1330207 C 14886 Yes 186 n-Hexane 110543 C 13567 Yes 640 Point 138 Formaldehyde 50000 A 21 No 21 n-Hexane 110543 C 600 No 600 Point 139 Formaldehyde 50000 A 13731 Yes 1373 Acetaldehyde 75070 A 980 Yes 490 Acrolein 107028 A 603 Yes 301 Toulene 108883 C 48 No 48 n-Hexane 110543 C 130 No 130 Note: Regulation 3, Part A, Section II.B.3.b APEN emission reporting requirements for non-criteria air pollutants are based on potential emissions without credit for reductions achieved by control devices used by the operator. Section 8—Testing Requirements Will testing be required to show compliance with any emission rate or regulatory X Yes No standard? If"yes", complete the information listed below AIRS Point Process Pollutant Regulatory Basis Test Method 135 01 VOC Regulation No. 3, Part B., Section III.G.3 Stack testing 136 01 VOC and SO2 Regulation No. 3, Part B., Section III.G.3 Inlet& outlet testing 137 01 VOC and SO2 Regulation No. 3, Part B., Section III.G.3 Inlet& outlet testing 139 01 VOC Regulation No. 3, Part B., Section III.G.3 Stack testing Section 9—Source Classification Is this a new previously un-permitted source? Page 7 Originally individ. Permit Point 122: Fugitive Emission Leaks Yes X No 97WE0340, but was incorporated into 95OPWE055 Point 135: Caterpillar G3608TALE at 1000 RPM X Yes No Within 1 yr, will be rolled into OP Permit Point 136: 85.0 MMSCF/day TEG dehydrator X Yes No Within 1 yr, will be rolled into OP Permit Point 137: Amine Sweetening Unit X Yes No Within 1 yr, will be rolled into OP Permit Point 138: Hot Oil Heater X Yes No Within 1 yr, will be rolled into OP Permit Point 139: Caterpillar G3608TALE at 1000 RPM X Yes No Within 1 yr, will be rolled into OP Permit What is this point classification? Point 122: Fugitive Emission Leaks X True Synthetic Major Minor Minor Point 135: Caterpillar G3608TALE at 1000 RPM X True Synthetic Major Minor Minor Point 136: 85.0 MMSCF/day TEG dehydrator True X Synthetic Major Minor Minor Point 137: Amine Sweetening Unit True X Synthetic Major Minor Minor Point 138: Hot Oil Heater X True Synthetic Major Minor Minor Point 139: Caterpillar G3608TALE at 1000 RPM X True Synthetic Major Minor Minor What is this facility classification? True Synthetic X Major Minor Minor Classification relates to what programs? X Title V PSD X NA NSR X MACT Is this a modification to an existing permit? Point 122: Fugitive Emission Leaks X Yes No Emission limits T New permit, but facility Point 135: Caterpillar G3608TALE at 1000 RPM Yes X No has an OP Permit (95OPWE0255) New permit, but facility Point 136: 85.0 MMSCF/day TEG dehydrator Yes X No has an OP Permit (95OPWE0255) New permit, but facility Point 137: Amine Sweetening Unit Yes X No has an OP Permit (95OPWE0255) New permit, but facility Point 138: Hot Oil Heater Yes X No has an OP Permit (95OPWE0255) New permit, but facility Point 139: Caterpillar G3608TALE at 1000 RPM Yes X No has an OP Permit (95OPWE0255) If"yes" what kind of modification? X Minor Synthetic Major Minor Section 10— Public Comment Does this permit require public comment per CAQCC Regulation 3? X Yes No NOx, VOC and CO (A> 25 TPY for non-attainment areas). If"yes", for which pollutants?Why? Public Comment is also required to establish Federal enforceable limits to avoid major NANSR modification. Page 8 Section 11 —Modeling Is modeling required to demonstrate compliance with National Ambient Yes X No Air Quality Standards (NAAQS)? If"yes", for which pollutants?Why? AIRS Point Section 12—Regulatory Review Regulation 1 - Particulate, SmokQ Carbon Monoxide and Sulfur Dioxide Section II.A.1 - Except as provided in paragraphs 2 through 6 below, no owner or operator of a source shall allow or cause the emission into the atmosphere of any air pollutant which is in excess of 20% opacity. This standard is based on 24 consecutive opacity readings taken at 15-second intervals for six minutes. The approved reference 122, 135- test method for visible emissions measurement is EPA Method 9 (40 CFR, Part 60, 139 Appendix A(July, 1992)) in all subsections of Section II. A and B of this regulation. Section II.A.5 -Smokeless Flare or Flares for the Combustion of Waste Gases No owner or operator of a smokeless flare or other flare for the combustion of waste gases shall allow or cause emissions into the atmosphere of any air pollutant which is in excess of 30% opacity for a period or periods aggregating more than six minutes in any sixty consecutive minutes. Regulation 2 —Odor Section I.A- No person, wherever located, shall cause or allow the emission of odorous 122, 135- air contaminants from any single source such as to result in detectable odors which are 139 measured in excess of the following limits: For areas used predominantly for residential or commercial purposes it is a violation if odors are detected after the odorous air has been diluted with seven (7) or more volumes of odor free air. Re•ulation 3 -APENs, Construction Permits, Operatin• Permits, PSD Part A-APEN Requirements Criteria Pollutants: For criteria pollutants, Air Pollutant Emission Notices are required for: 122, 135- each individual emission point in an attainment area with uncontrolled actual emissions of 139 two tons per year or more of any individual criteria pollutant (pollutants are not summed) for which the area is attainment. (Applicant is required to file an APEN since emissions from TEG dehydrator exceed 2 tons per year VOC) 122, 135- Part B—Construction Permit Exemptions 139 Applicant is required to file a permit since uncontrolled VOC emissions are greater than the 5.0 TPY threshold(Reg. 3, Part B, Section 11.D.3.a) Regulation 6 - New Source Performance Standards 122 NSPS KKK 136 MACT HH 137 NSPS LLL 138 NSPS Subpart Dc 135 and 139 NSPS JJJJ Re•ulation 7—Volatile Organic Compounds Section XVII.D (State only enforceable). Beginning May 1, 2008, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas- condensate-glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by an average of at least 90 percent through the use of air pollution control 136 equipment when uncontrolled actual VOC emissions from a single dehy or group of dehys at same site are at least 15 tpy or greater. Applicant is required to have controls on their TEG dehydrator since total uncontrolled VOC emissions from all dehydrators onsite are greater than the 15.0 TPY threshold(this single TEG dehydrator is 1299 TPY uncontrolled by itself). Subject to NSPS JJJJ, therefore, will not be subject to Reg. 7 (NSPS JJJJ is much 135 and 139 more stringent than Reg. 7 (state-only)) Regulation 8— Hazardous Air Pollutants 136 MACT HH (area source) 135 and 139 MACT ZZZZ (area source) Page 9 I Section 13—Aerometric Information Retrieval System Coding Information Uncontrolled Emission Controlled Point Process Process Pollutant/ Fugitive Control Description Emission CAS# (Y/N) Factor Emission (ego) Factor Source Factor 122 01 Fugitive VOC Leak Emissions VOC Yes EPA-453/R-95-017, NA Table 2-4 SCC 31000220: All Equip. Leak Fugitives (Valves, flanges, connections, seals, drains) 0.5 NOx No Manfacturer NA 0 g/hp-hr 0.63 p 0.VOC No Manfacturer /h3 hr 50 g/ hp-hr hr q/hp-hr 4SLB 2.76 CO No Manfacturer 0.19 93 Reciprocating g/hp-hr g/hp-hr 01 Internal 40 Formaldehyde No Manfacturer 0.04 90 135 Combustion 9h phr g/hp-hr Engine 0.0086 Acetaldehyde No AP-42 0.004 50 lbs/MMBtu lbs/mmBtu 0.0051 Acrolein No AP-42 0.0026 50 lbs/MMBtu lbs/mmbtu 0.0004 Benzene No AP-42 0.0002 50 lbs/MMBtu lbs/mmbtu SCC 20200254—4-cycle lean burn 0.068 NOx No AP-42 NA 0 lb/mmbtu 86.7 lb/mmscf .7 VOC No Promax lb/mmscf 6 99 0.37 CO No AP-42 NA 0 lb/mmbtu 5.44 0.05 TEG Glycol lb/mmscf Benzene No Promax lb/mmscf 99 136 01 Dehydrator 7.48 0.07 lb/mmscf Toluene No Promax lb/mmscf 99 0.35 0.003 bs MMscf Ethylbenzene No Promax lbs/MMscf 99 2.84 0.03 lbs/MMscf Xylenes No Promax lbs/MMscf 99 12.03 0.12 lbs/MMscf n-hexane No Promax lbs/MMscf 99 SCC 31000301 —Glycol dehydrators: reboiler still vent: Triethylene glycol 0.068 NOx No AP-42 NA 0 lb/mmbtu 20.72 VOC No Promax 0.76 99 lb/mmscf lb/mmscf 0.37 CO No AP-42 NA 0 Amine lb/mmbtu 01 Sweetening 2'43 Benzene No Promax 0.03 99 137 Unit lb/mmscf lb/mmscf 2.59 Toluene No Promax 0.03 99 lb/mmscf lb/mmscf 0.48 Xylenes No Promax 0.01 99 lbs/MMscf lbs/MMscf 0.44 n-hexane No Promax 0.02 99 lbs/MMscf lbs/MMscf SCC 31000201 —Gas Sweetening: Amine process 100 NOx No AP-42 50 50 lbs/mmscf lb/mmscf 5.5 01 Hot Oil Heater Ibs mmscf VOC No AP-42 NA 0 138 84 CO No AP-42 NA 0 Ibs/mmscf SCC 31000404-Natural Gas Process heaters Page 10 0.5 NOx No Manfacturer NA 0 g/hp-hr 0.63 hr g VOC No Manfacturer 0.32 50 r g/ 4SRB g hp hr CO No Manfacturer q/hp-hr 2.76 h1 93 Reciprocating 01 Internal g/hp hr Formaldehyde No Manfacturer g�'Phr 90 139 Combustion 0.0086 0.004 Engine lbs/MMBtu Acetaldehyde No AP-42 lbs/mmBtu 50 0.0051 Acrolein No AP-42 0.0026 50 lbs/MMBtu Ibs/mmbtu 0.0004 Benzene No AP-42 0.0002 50 lbs/MMBtu Ibs/mmbtu SCC 20200253-4-cycle rich burn Section 14—Miscellaneous Application Notes AIRS Point 122 Fugitive Emission Leaks Point originally was issued permit 97WE0340, but was incorporated into 95OPWE0255. A modification was received by the Division on 12/11/09. Will incorporate this point on this new permit(10WE1659) and it will be incorporated into the OP permit. Emission factors using EPA453/R-95-017 Component count reflected in this analysis is: Equipment Type Gas Heavy Oil (or Light Oil (or Water/Oil Heavy Liquid) Light Liquid) Connectors 2637 0 5162 0 Flanges 1929 0 1460 0 Open-Ended Lines 0 0 0 0 Pump Seals 0 0 40 0 Valves 1649 0 2388 0 Other 105 0 49 0 This source is located in the 8-hour ozone non-attainment area (Parts of Weld County is in non- attainment). This facility has been issued an operating permit (95OPWE055). I emailed Geof Drissel from the Title V team and asked him what the fugitive limit is for Roggen. He said "The fugitive emission numbers that I see in the last issued OP are 16.8 tpy for the Russell, Randall and Petrofac Plants." The revised APEN requests a controlled emission limit of 31.44 TPY. This is an increase of 14.64 TPY from the original operating permit emission limit. This point source is considered fugitive emissions, and therefore, fugitive emissions are not included in the facility inventory for determining if the project is considered a significant modification. Reg. 3, Part D, Section II.A.22.f states that fugitives should not be considered in determining a major modification if the source was not regulated under Section 111 or 112 prior to August 7, 1980. Roggen Natural Gas Plant was not a listed source or was regulated under Section 111 or 112 prior to August 7, 1980, and therefore, the fugitives from this facility shall not be considered in determining major modification. Page 11 AIRS Point 135 4SLB RICE New point source at a major facility of NOx, CO and VOC. Synthetic minor for HAPS (which makes it an area source for MACT and NSPS review). Source will require a permit> 2 TPY (permit threshold). Site-Specific emission factors using manufacturer spec sheet for a Caterpillar G3608 TALE. NOx= 0.5 g/hp-hr VOC = 0.63 g/hp-hr CO = 2.76 g/hp-hr Formaldehyde = 0.40 g/hp-hr Acetaldehyde, Acrolein and Benzene = AP-42 Believed that Point 135 (which consists of 2 engines) would be sharing the yearly hours between engines (not overlapping time). Emailed 7/13/10 on what I thought the new emission limit would be for the combining of engines (8760 total hours). Wes Hill called and said that they were hoping to run each engine at 75% of 13140 hours (so that there could be some overlapping of both engines running at the same time), and would minimize their process limits to 13140 hours for total engines. Wanted to confirm this with Chris (for I didn't think we agreed at the meeting that the engines would ever overlap in running time). Had a meeting with Chris on 7/26/10 regarding the 2 engines sharing 1 emission and process point. We reviewed the DRAFT APENS submitted by DCP on 7/15/10 and we didn't have a problem with them sharing as long as each point had separate APENs and were able to be accounted for separately in inventory. Emailed Wes on 7/26/10 that we were accepting the DRAFT APENs and to send us final APENs with additional check. This source is located in the 8-hour ozone non-attainment area (Parts of Weld County is in non- attainment). Engine will be subject to NSPS JJJJ and MACT ZZZZ (in "Notes to Permit Holder.") Will not be subject to Req. 7. AIRS Point 136 TEG Dehydrator New point source at a major facility of NOx, CO and VOC. Synthetic minor for HAPS (which makes it an area source for MACT and NSPS review). Source is a synthetic minor source. Source will require a permit > 2 TPY (permit threshold). Emission factors from Promax model and AP-42 NOx= 0.068 lb/mmbtu fuel (AP-42) Uncontrolled VOC = (1299 TPY*2000 lb/ton)/29967 mmscf/yr= 86.7 lb/mmscf(promax model) Controlled VOC = (13 TPY*2000 lb/ton) /29967 mmscf/yr= 0.87 lb/mmscf(promax model) CO = 0.37 lb/mmbtu fuel (AP-42) Uncontrolled HAP E.F. Benzene = (81.5 TPY*2000 Ib/ton)/29967= 5.44 lb/mmscf(promax model) Toluene = (112.1 TPY*2000 lb/ton)/29967= 7.48 lb/mmscf(promax model) Ethylbenzene = (5.24 TPY*2000 lb/ton)/29967= 0.35 lb/mmscf(promax model) Xylenes = (42.5 TPY*2000 lb/ton)/29967= 2.84 lb/mmscf(promax model) n-hexane = (180.2 TPY*2000 lb/ton)/29967= 12.03 lb/mmscf(promax model) Controlled HAP E.F. Benzene = (0.82 TPY*2000 lb/ton)/29967= 0.05 lb/mmscf(promax model) Toluene = (1.12 TPY*2000 lb/ton)/29967= 0.07 lb/mmscf(promax model) Ethylbenzene = (0.05 TPY*2000 Ib/ton)/29967= 0.003 lb/mmscf(promax model) Xylenes= (0.43 TPY*2000 lb/ton)/29967= 0.03 lb/mmscf(promax model) n-hexane= (1.80 TPY*2000 lb/ton)/29967= 0.12 lb/mmscf(promax model) This source is located in the 8-hour ozone non-attainment area (Parts of Weld County is in non- attainment). Subject to MACT HH (total uncontrolled VOC > 15 TPY for all TEG dehydrators onsite) Page 12 AIRS Point 137 Amine Sweetening Unit New point source at a major facility of NOx, CO and VOC. Synthetic minor for HAPS (which makes it an area source for MACT and NSPS review). Source is a synthetic minor source. Source will require a permit > 2 TPY (permit threshold). Emission factors from Promax model and AP-42 NOx= 0.068 lb/mmbtu fuel (AP-42) Uncontrolled VOC = (321.47 TPY*2000 lb/ton)/ 31025 mmscf/yr= 20.72 lb/mmscf(promax model) Controlled VOC = (11.8 TPY*2000 lb/ton) / 31025 mmscf/yr = 0.76 lb/mmscf(promax model) CO = 0.37 lb/mmbtu fuel (AP-42) SO2 = 1.88 ton SO2/H2S Uncontrolled HAP E.F. Benzene = (37.71 TPY*2000 lb/ton)/31025= 2.43 lb/mmscf(promax model) Toluene = (40.15 TPY*2000 lb/ton)/31025= 2.59 lb/mmscf(promax model) Xylenes = (7.44 TPY*2000 lb/ton)/31025= 0.48 lb/mmscf(promax model) n-hexane = (6.78 TPY*2000 lb/ton)/31025= 0.44 lb/mmscf(promax model) Controlled HAP E.F. Benzene = (0.5 TPY*2000 lb/ton)/31025= 0.03 lb/mmscf(promax model) Toluene = (0.5 TPY*2000 lb/ton)/31025= 0.03 lb/mmscf(promax model) Xylenes = (0.1 TPY*2000 lb/ton)/31025= 0.01 lb/mmscf(promax model) n-hexane= (0.3 TPY*2000 lb/ton)/31025= 0.02 lb/mmscf(promax model) This source is located in the 8-hour ozone non-attainment area (Parts of Weld County is in non- attainment). Subject to NSPS LLL. AIRS Point 138 Hot Oil Heater New point source at a major facility of NOx, CO and VOC. Synthetic minor for HAPS (which makes it an area source for MACT and NSPS review). Source will require a permit> 2 TPY (permit threshold). Site-Specific emission factors using AP-42 Emission factors from previous permit. NOx = 100 lb/mmscf VOC = 5.5 lb/mmscf CO = 84 lb/mmscf This source is located in the 8-hour ozone non-attainment area (Parts of Weld County is in non- attainment). The purpose of the hot oil heater is to provide the heat for both the amine and dehydration unit reboilers. The reboilers of each of these units are basically heat exchangers, so the reboilers will use the heated oil from the hot oil heater to regenerate the amine and TEG in the respective reboiler units. This point source is subject to NSPS Subpart Dc Page 13 AIRS Point 139 4SLB RICE New point source at a major facility of NOx, CO and VOC. Synthetic minor for HAPS (which makes it an area source for MACT and NSPS review). Source will require a permit > 2 TPY(permit threshold). EMISSION AND PROCESS LIMITS ARE COMBINED WITH POINT 135. THE TWO ENGINES COMBINED SHALL NOT EXCEED THE ONE EMISSION AND PROCESS LIMIT ASSIGNED TO THEM (AS ONE POINT SOURCE). Site-Specific emission factors using manufacturer spec sheet for a Caterpillar G3608 TALE. NOx = 0.5 g/hp-hr VOC = 0.63 g/hp-hr CO = 2.76 g/hp-hr Formaldehyde = 0.40 g/hp-hr Acetaldehyde, Acrolein and Benzene =AP-42 -Believed that Point 135 (which consists of 2 engines) would be sharing the yearly hours between engines (not overlapping time). Emailed 7/13/10 on what I thought the new emission limit would be for the combining of engines (8760 total hours). Wes Hill called and said that they were hoping to run each engine at 75% of 13140 hours (so that there could be some overlapping of both engines running at the same time), and would minimize their process limits to 13140 hours for total engines. Wanted to confirm this with Chris (for I didn't think we agreed at the meeting that the engines would ever overlap in running time). Had a meeting with Chris on 7/26/10 regarding the 2 engines sharing 1 emission and process point. We reviewed the DRAFT APENS submitted by DCP on 7/15/10 and we didn't have a problem with them sharing as long as each point had separate APENs and were able to be accounted for separately in inventory. Emailed Wes on 7/26/10 that we were accepting the DRAFT APENs and to send us final APENs with additional check. This source is located in the 8-hour ozone non-attainment area (Parts of Weld County is in non- attainment). Engine will be subject to NSPS JJJJ and MACT ZZZZ (in "Notes to Permit Holder.") Will not be subject to Reg. 7. Page 14 Regulatory Considerations for the facility-Roggen Compressor Station DCP Midstream, LP proposes to modify Roggen Natural Gas Processing Plant by adding a TriEthylene Glycol (TEG) glycol dehydrator, amine unit, and two (2)4-stroke, lean burn reciprocating internal combustion engines. The total controlled emission limit changes for this facility from this modification include: NOx: 28.31 TPY Increase (which is < 40 TPY NOx delta change for significant modification threshold) CO: 40.79 TPY Increase (which is < 100 TPY CO delta change for significant modification threshold) VOC: 36.10 TPY Increase (of which 14.64 TPY is from fugitive emissions; which is < 40 TPY significant modification threshold) HAPs: 8.52 TPY Increase The federal NSR program applies to attainment and non-attainment areas that result in emission increases in excess of specified thresholds for NOx and VOC. This facility is located in Weld County (non- attainment)which means that this modification might potentially be subject to NANSR review if the modifications were greater than the specified thresholds. This facility is considered major for NOx and VOC for the purposes of NANSR review. However, the proposed modifications are less than the specified federal threshold of 40 TPY for NOx and VOC each, and 100 TPY for CO. Therefore, this project is considered a minor modification for NANSR review. However, DCP Midstream is accepting hours of operation limits (process limits) for the 2 new engines in this modification (points 135 and 139) in order to avoid a major modification. Therefore, these process limits may not be relaxed in the future without evaluating if NANSR is triggered and must be applied. (Reg. 3, Part D, Section V.A.7.b) Under PSD, specific listed facilities are subject to PSD review if their PTE (Potential to emit) exceeds 100 TPY of any criteria pollutant. However, oil and gas production facilities are not one of these listed source types. All other source types are subject to PSD review if their PTE exceeds 250 TPY. This facility will exceed 250 TPY CO with this modification; however, the modification by itself is not major. Therefore, PSD review may be considered in future projects at this facility if the major thresholds are exceeded. Roggen Natural Gas Plant has existing sources permitted under operating permit 95OPWE055. Operating permits are required for stationary sources that are a major source of emissions. A major source of emissions is a source that emits or has a PTE of 100 TPY or greater of any criteria pollutant, 10 TPY or greater of a single HAP source, or 25 TPY or greater of combined HAPs. Aggregation Issues Prior to public comment, I emailed the operator a question regarding potential aggregation of production wells with the natural gas plant. The question asked was: "Does DCP own or operate any production wells that feed into Roggen Natural Gas Plant?" Wes Hill from DCP, replied on 9/16/10: "No, DCP does not own any production wells." 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O c 4_ V U O c▪ 0 E 00 c a, _ O 0 U E no c a o C N - a 0 0 W v) z s1 U v c x o- 0 8 0 3 0 ,2.a .2 G co o. u o c - >, " ' 0 rn a® U v. O G. > 0 -U u w a. on • z cr.) en .. STATE OF COLORADO of•coz0 e COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT * AIR POLLUTION CONTROL DIVISION *+,876•+ TELEPHONE: (303) 692-3150 CONSTRUCTION PERMIT PERMIT NO: 10WE1659 Issuance 1 DATE ISSUED: ISSUED TO: DCP Midstream, LP THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS: Natural gas processing facility, known as the Roggen Natural Gas Processing Plant, located in Section 24, Township 2N, Range 63W, in Weld County, Colorado. THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING: Facility AIRS Description Equipment ID Point P025 122 Equipment leaks (fugitive VOCs) from a natural gas processing facility. One (1) Caterpillar, Model G3608TALE, Serial Number BEN00537, natural gas-fired, turbo-charged, 4SLB TBD1 135 reciprocating internal combustion engine, site rated at 2370 horsepower at 1000 RPM. This engine shall be equipped with an oxidation catalyst and air-fuel ratio control. This emission unit is used for natural gas compression. One (1) Triethylene glycol (TEG) natural gas dehydration unit (make, model, serial number: not submitted) with a design capacity of 85 MMscf per day. This emissions unit is equipped with one (1) gas-glycol pump (make, model: not submitted) with TBD3 136 a design capacity of 20 gpm. A second glycol pump is used as a backup and won't operate unless the first pump goes down. This unit is equipped with a flash tank, reboiler and still vent. Emissions from the flash tank and still vent are routed to a regenerative thermal oxidizer (RTO) with a minimum control efficiency of 99%. AIRS ID: 123/0049/122, 135-139 Page 1 of 26 NGEngine Version 2009-1 DCP Midstream, LP Cola do a p. e $ o Public Health and Environment Permit No. 10WE1659 Air Pollution Control Division Issuance 1 Facility AIRS Equipment ID Point Description One (1) Methyldiethanolamine (MDEA)-based natural gas sweetening system for acid gas removal with a design capacity of 85 MMSCF per day (make, model, serial number: TBD). This emissions unit is equipped with one (1) electric OR gas- injection amine recirculation pump. A second amine TBD4 137 recirculation pump is used as a backup and won't operate unless the first pump goes down. This system includes a natural gas/amine contactor and still vent and reboiler. Flash gases are routed to fuel line of the hot oil heater (Point 138). Still vent emissions shall be routed to a regenerative thermal oxidizer (RTO) with a minimum control efficiency of 99%. Hot Oil Heater 138 36.7 MMBTU/hr hot oil heater equipped wth low NOx burners that provides the heat for the amine sweetening unit reboiler. One (1) Caterpillar, Model G3608TALE, Serial Number BEN00539, natural gas-fired, turbo-charged, 4SLB TBD2 139 reciprocating internal combustion engine, site rated at 2370 horsepower at 1000 RPM. This engine shall be equipped with an oxidation catalyst and air-fuel ratio control. This emission unit is used for natural gas compression Points 135 and 139 may be replaced with another engine in accordance with the temporary engine replacement provision or with another Caterpillar G3608LE engine in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment A. THIS PERMIT IS GRANTED SUBJECT TO ALL RULES AND REGULATIONS OF THE COLORADO AIR QUALITY CONTROL COMMISSION AND THE COLORADO AIR POLLUTION PREVENTION AND CONTROL ACT C.R.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. YOU MUST notify the APCD no later than thirty days after commencement of the permitted operation or activity by submitting a Notice of Startup (NOS) form to the APCD. The Notice of Startup (NOS) form may be downloaded online at www.cdphe.state.co.us/ap/downloadforms.html. Failure to notify the APCD of startup of the permitted source is a violation of AQCC Regulation No. 3, Part B, Section III.G.1 and can result in the revocation of the permit. 2. Within one hundred and eighty days (180) after commencement of operation, compliance with the conditions contained on this permit shall be demonstrated to the Division. It is the permittee's responsibility to self-certify compliance with the conditions. Failure to demonstrate compliance within 180 days may result in revocation of the permit. (Reference: Regulation No. 3, Part B, II.G.2). 3. This permit shall expire if the owner or operator of the source for which this permit was issued: (i) does not commence construction/modification or operation of this source AIRS ID: 123/0049/122, 135-139 Page 2 of 26 DCP Midstream, LP Col do p e ' o Public Health and Environment Permit No. 10WE1659 Air Pollution Control Division Issuance 1 within 18 months after either, the date of issuance of this construction permit or the date on which such construction or activity was scheduled to commence as set forth in the permit application associated with this permit; (ii) discontinues construction for a period of eighteen months or more; (iii) does not complete construction within a reasonable time of the estimated completion date. The Division may grant extensions of the deadline per Regulation No. 3, Part B, III.F.4.b. (Reference: Regulation No. 3, Part B, III.F.4.) 4. The operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self-certification process. (Reference: Regulation No. 3, Part B, Section III.E.) 5. The manufacturer, model number, and serial number of Points 136, 137 and 138 shall be provided to the Division within thirty days (30) after commencement of operation. This information shall be included on the Notice of Startup (NOS) submitted for the equipment. (Reference: Regulation No. 3, Part B, III.E.) 6. The operator shall retain the permit final authorization letter issued by the Division after completion of self-certification, with the most current construction permit. This construction permit alone does not provide final authority for the operation of this source. EMISSION LIMITATIONS AND RECORDS 7. Emissions of air pollutants shall not exceed the following limitations (as calculated in the Division's preliminary analysis). (Reference: Regulation No. 3, Part B, Section II.A.4) Monthly Limits: Facility AIRS Pounds per Month Emission Equipment ID Point NO. VOC CO SO2 Type P025 122 --- 5341 --- Fugitives TBD1 135 Combined 3900 1807 2420 --- Point TBD2 139 TBD3 136 663 2208 3601 Point TBD4 137 39 2004 210 5487 Point Hot Oil Heater 138 1189 119 2004 --- Point Monthly limits are based on a 31-day month. Facility-wide emissions of each individual hazardous air pollutant shall be less than 1,358.9 lb/month. Facility-wide emissions of total hazardous air pollutants shall be less than 3,397.3 lb/month. AIRS ID: 123/0049/122, 135-139 Page 3 of 26 DCP Midstream, LP Col do B e. o Public Health and Environment Permit No. 10WE1659 Air Pollution Control Division Issuance 1 Annual Limits: Facility AIRS Tons per Year Emission Equipment ID Point NO„ VOC CO SO, Type P025 122 --- 31.4 --- --- Fugitives TBD1 135 Combined 17.2 10.6 6.5 TBD2 139 Point TBD3 136 3.9 13.0 21.2 --- Point TBD4 137 0.2 11.8 1.2 32.3 Point Hot Oil Heater 138 7.0 0.7 11.8 --- Point See "Notes to Permit Holder #4 for information on emission factors and methods used to calculate limits. Facility-wide emissions of each individual hazardous air pollutant shall be less than 8.0 tpy. Facility-wide emissions of total hazardous air pollutants shall be less than 20.0 tpy. During the first twelve (12) months of operation, compliance with both the monthly and yearly emission limitations shall be required. After the first twelve (12) months of operation, compliance with only the yearly limitation shall be required. Compliance with the synthetic minor status of this facility shall be determined by recording the facility's annual pollutant emissions, including all HAPs above the de- minimis reporting level, from each emission unit, on a rolling (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate monthly emissions and keep a compliance record on site or at a local field office with site responsibility, for Division review. This rolling twelve-month total shall apply to all emission units, requiring an APEN, at this facility. Point 122: Fugitive Leak Emissions 8. The operator shall calculate actual emissions from this emissions point based on representative actual component counts for the facility along with the most recent gas analysis, as required in the Compliance Testing and Sampling section of this permit. Points 135 and 139: Reciprocating Internal Combustion Engines 9. These engines shall be equipped with an oxidation catalyst and air-fuel ratio control. The oxidation catalyst shall reduce uncontrolled emissions of VOC and CO 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.) Point 136: TEG Dehydrator 10. Compliance with the emission limits in this permit shall be demonstrated by running the Promax process simulation software or Division-approved equivalent software on a monthly basis using the most recent plant inlet gas analysis and recorded operational AIRS ID: 123/0049/122, 135-139 Page 4 of 26 DCP Midstream, LP Col do P 4 r e o Public Health and Environment Permit No. 10WE1659 Air Pollution Control Division Issuance 1 values (including gas throughput, lean glycol recirculation rate, and other operational values specified in the O&M Plan). Recorded operational values, except for gas throughput, shall be averaged on a monthly basis for input into Promax process simulation software or Division-approved equivalent software. 11. This unit shall be configured such that the flash tank and still vent vapors are routed to the regenerative thermal oxidizer (RTO). The RTO shall reduce uncontrolled emissions of VOC from the TEG dehydration unit to the emission levels listed in this section, above. The RTO shall achieve a minimum destruction efficiency of 99% for VOC. Operating parameters of the control equipment are identified in the operation and maintenance plan. (Reference: Regulation No.3, Part B, Section III.E.) Point 137: Amine Sweetening Unit 12. Compliance with the emission limits in this permit shall be demonstrated by running the Promax process simulation software or Division-approved equivalent software on a monthly basis using the most recent amine unit inlet extended gas analysis. 13. Emissions from the still vent shall be collected and controlled by a regenerative thermal oxidizer (RTO) in order to reduce the emissions of volatile organic compounds to the level listed in this section, above. The RTO shall achieve a minimum destruction efficiency of 99% for VOC. Operating parameters of the thermal oxidizer are identified in the operation and maintenance plan for this unit. (Reference: Regulation No.3, Part B, Section III.E.) PROCESS LIMITATIONS AND RECORDS 14. 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 AIRS Annual Monthly Limit Equipment Point Process Parameter Limit (31 days) ID TBD1 135 244.8 20.8 Consumption of natural gas as a fuel TBD2 139 MMscf/yr MMscf/month 31,025 TBD3 136 Natural gas plant throughput MMscf/yr 2,635 MMscf/month 31025 2,635 TBD4 137 Natural gas plant throughput MMscf/yr MMscf/month Hot Oil 280.7 23.8 138 Natural gas throughput Heater MMscf/yr MMscf/month 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. 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 AIRS ID: 123/0049/122, 135-139 Page 5 of 26 DCP Midstream, LP Coll do e p ice o Public Health and Environment Permit No. 10WE1659 , Air Pollution Control Division Issuance 1 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. Point 136: TEG Dehydrator 15. This unit shall be limited to the maximum lean glycol circulation rate 20 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) Point 137: Amine Sweetening Unit 16. This unit shall be limited to the maximum lean amine recirculation pump rate of 350 gallons per minute. The lean amine recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. A pump stroke correlation may be used to demonstrate compliance with this condition. (Reference: Regulation No. 3, Part B, II.A.4) STATE AND FEDERAL REGULATORY REQUIREMENTS 17. 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). 18. 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. &4.) 19. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) Point 122: Fugitive Leak Emissions 20. This source is subject to Regulation No. 7, Section XII.G.1 (State only enforceable). For fugitive VOC emissions from leaking equipment, the leak detection and repair (LDAR) program as provided at 40 C.F.R. Part 60, Subpart KKK (see Regulation Number 6, Part A, Subpart KKK) shall apply, regardless of the date of construction of the affected facility. The operator shall comply with all applicable requirements of Section XII. 21. This facility is subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart KKK, Standards of Performance for Onshore Natural Gas Processing Plants including, but not limited to, the following: • 40 CFR, Part 60, Subpart A—General Provisions • §60.632 Standards o (a) - Each owner or operator subject to the provisions of this subpart shall comply with the requirements of § 60.482-1 (a), (b), and (d) and 60.482-2 through 60.482-10, except as provided in § 60.633, as soon as practicable, but no later than 180 days after initial startup. o (b) - An owner or operator may elect to comply with the requirements of §60.483-1 and §60.483-2. AIRS ID: 123/0049/122, 135-139 Page 6 of 26 DCP Midstream, LP Col do ,p a o Public Health and Environment Permit No. 10WE1659 ,, Air Pollution Control Division Issuance 1 x,:_. o (d) Each owner or operator subject to the provisions of this subpart shall comply with the provisions of§60.485 except as provided in §60.633(f) of this subpart. o (e) Each owner or operator subject to the provisions of this subpart shall comply with the provisions of §§60.486 and 60.487 except as provided in §§60.633, 60.635, and 60.636 of this subpart. • §60.633 Exceptions o (a) Each owner or operator subject to the provisions of this subpart may comply with the following exceptions to the provisions of subpart VV. o (b)(1) Each pressure relief device in gas/vapor service may be monitored quarterly and within 5 days after each pressure release to detect leaks by the methods specified in §60.485(b) except as provided in §60.632(c), paragraph (b)(4) of this section, and §60.482-4 (a) through (c) of subpart VV. • (2) If an instrument reading of 10,000 ppm or greater is measured, a leak is detected. • (3W) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 calendar days after it is detected, except as provided in §60.482-9. • (ii) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected. o (c) Sampling connection systems are exempt from the requirements of §60.482-5. • §60.635 Recordkeeping o (a) Each owner or operator subject to the provisions of this subpart shall comply with the requirements of paragraphs (b) and (c) of this section in addition to the requirements of§60.486. o (b) The following recordkeeping requirements shall apply to pressure relief devices subject to the requirements of§60.633(b)(1) of this subpart. • (1) When each leak is detected as specified in §60.633(b)(2), a weatherproof and readily visible identification, marked with the equipment identification number, shall be attached to the leaking equipment. The identification on the pressure relief device may be removed after it has been repaired. • (2) When each leak is detected as specified in §60.633(b)(2), the following information shall be recorded in a log and shall be kept for 2 years in a readily accessible location: • (i) The instrument and operator identification numbers and the equipment identification number. • (ii) The date the leak was detected and the dates of each attempt to repair the leak. • (iii) Repair methods applied in each attempt to repair the leak. • (iv) "Above 10,000 ppm" if the maximum instrument reading measured by the methods specified in paragraph (a) of this section after each repair attempt is 10,000 ppm or greater. AIRS ID: 123/0049/122, 135-139 Page 7 of 26 DCP Midstream, LP > Coldo 'hip e n o` Public Health and Environment Permit No. 10WE1659 Air Pollution Control Division Issuance 1 • (v) "Repair delayed" and the reason for the delay if a leak is not repaired within 15 calendar days after discovery of the leak. • (vi) The signature of the owner or operator (or designate) whose decision it was that repair could not be effected without a process shutdown. • (vii) The expected date of successful repair of the leak if a leak is not repaired within 15 days. • (viii) Dates of process unit shutdowns that occur while the equipment is unrepaired. • (ix) The date of successful repair of the leak. • (x) A list of identification numbers for equipment that are designated for no detectable emissions under the provisions of §60.482-4(a). The designation of equipment subject to the provisions of §60.482-4(a) shall be signed by the owner or operator. • §60.636 Reporting Requirements o (a) Each owner or operator subject to the provisions of this subpart shall comply with the requirements of paragraphs (b) and (c) of this section in addition to the requirements of§60.487. o (b) An owner or operator shall include the following information in the initial semiannual report in addition to the information required in §60.487(b) (1)— (4): Number of pressure relief devices subject to the requirements of §60.633(b) except for those pressure relief devices designated for no detectable emissions under the provisions of §60.482-4(a) and those pressure relief devices complying with §60.482-4(c). o (c) An owner or operator shall include the following information in all semiannual reports in addition to the information required in §60.487(c)(2) (i) through (vi): • (1) Number of pressure relief devices for which leaks were detected as required in §60.633(b)(2) and • (2) Number of pressure relief devices for which leaks were not repaired as required in §60.633(b)(3). Points 135 and 139: Reciprocating Internal Combustion Engines 22. This equipment is subject to the control requirements for stationary and portable engines in the 8-hour ozone control area under Regulation No. 7, Section XVI.B.2. For lean burn reciprocating internal combustion engines, an oxidation catalyst shall be required. Point 136: TEG Dehydrator 23. The regenerative thermal oxidizer (RTO) covered by this permit is subject to Regulation No. 7, Section XVII.B General Provisions (State only enforceable). If a flare or other combustion device is used to control emissions of volatile organic compounds to comply with Section XVII, it shall be enclosed, have no visible emissions during normal operations, and be designed so that an observer can, by means of visual observation AIRS ID: 123/0049/122, 135-139 Page 8 of 26 DCP Midstream LP z w Cola;do p r. e. o Public Health and Environment sy Permit No. 10WE1659 Air Pollution Control Division Issuance 1 from the outside of the enclosed flare or combustion device, or by other convenient means approved by the Division, determine whether it is operating properly. The operator shall comply with all applicable requirements of Section XVII. 24. This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XII.H. Beginning May 1, 2005, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas- condensate-glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by at least 90 percent through the use of air pollution control equipment. This source shall comply with all applicable general provisions of Regulation 7, Section XII. 25. This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XVII.D (State only enforceable). Beginning May 1, 2008, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas-condensate-glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by an average of at least 90 percent through the use of air pollution control equipment. This source shall comply with all applicable general provisions of Regulation 7, Section XVII. 26. 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)(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)(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. AIRS ID: 123/0049/122, 135-139 Page 9 of 26 DCP Midstream, LP ill Coll do • p e » o Public Health and Environment Permit No. 10WE1659 Air Pollution Control Division Issuance 1 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-GLYCaIc 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 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)(ii) - The actual average benzene emissions (in terms of benzene emissions per year) as determined in accordance with §63.772(b)(2). Point 137: Amine Sweetening Unit 27. This amine unit is subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart LLL, Standards of Performance for Onshore Natural Gas Processing: SO2 Emissions, including, but not limited to, the following: • 40 CFR, Part 60, Subpart A—General Provisions • §60.640 —Applicability and Designation of Affected Facilities o §60.640(b) - 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 §60.647(c) but are not required to comply with §§60.642 through 60.646. • §60.647 — Record keeping and reporting Requirements o §60.647(c) - To certify that a facility is exempt from the control requirements of these standards, each owner or operator of a facility with a design capacity less that 2 LT/D of H2S in the acid gas (expressed as sulfur) shall keep, for AIRS ID: 123/0049/122, 135-139 Page 10 of 26 DCP Midstream, LP Col do p met o Public Health and Environment Permit No. 10WE1659 :n Air Pollution Control Division Issuance 1 the life of the facility, an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H2S expressed as sulfur. Point 138: Hot Oil Heater 28. 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)). 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. (§ 60.12) e. Written notification of construction and initial startup dates shall be submitted to the Division as required under § 60.7. f. Records of startups, shutdowns, and malfunctions shall be maintained, as required under § 60.7. OPERATING & MAINTENANCE REQUIREMENTS 29. Upon startup of this point, the applicant shall follow the operating and maintenance (O&M) plan and record keeping format approved by the Division, in order to demonstrate compliance on an ongoing basis with the requirements of this permit. Revisions to your O&M plan are subject to Division approval prior to implementation. (Reference: Regulation No, 3, Part B, Section III.G.7.) 30. Points 136 and 137: The combustion chamber temperature shall be recorded as per the frequency required in the O&M Plan. This information shall be maintained in a log on site and made available to the Division for inspection upon request. The combustion chamber temperature shall not go below 1400 °F on a monthly average basis. AIRS ID: 123/0049/122, 135-139 Page 11 of 26 DCP Midstream, LP • Col do op e o Public Health and Environment Permit No. 10WE1659 F' Air Pollution Control Division Issuance 1 F' w 31. Point 137: The inlet gas temperature and inlet gas pressure shall be measured and recorded weekly. COMPLIANCE TESTING AND SAMPLING Initial Testing Requirements for Point 122: Fugitive Leak Emissions 32. Within one hundred and eighty days (180) after commencement of operation, the permittee shall complete the initial extended gas analysis of gas samples that are representative of volatile organic compound (VOC) that may be released as fugitive emissions. This extended gas analysis shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. The operator shall submit the results of the gas analysis and emission calculations to the Division as part of the self-certification process to ensure compliance with emissions limits. 33. Within one hundred and eighty days (180) after commencement of operation, the operator shall complete a hard count of components at the source and establish the number of components that are operated in "heavy liquid service", "light liquid service", "water/oil service" and "gas service". The operator shall submit the results to the Division as part of the self-certification process to ensure compliance with emissions limits. Initial Testing Requirements for Points 135 and 139: Reciprocating Internal Combustion Engines 34. A source initial compliance test shall be conducted on emissions point 135 and 139 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 Carbon Monoxide Formaldehyde Initial Testing Requirements for Point 136: TEG Dehydrator 35. The owner or operator shall complete the initial annual extended wet gas analysis testing required by this permit and submit the results to the Division as part of the self- certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) Initial Testing Requirements for Point 137: Amine Sweetening Unit 36. The owner or operator shall complete the initial annual sour gas analysis testing required by this permit and submit the results to the Division as part of the self-certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) AIRS ID: 123/0049/122, 135-139 • Page 12 of 26 • DCP Midstream, LP Col do i p, e o Public Health and Environment Permit No. 10WE1659 Air Pollution Control Division Issuance 1 E x Initial Testing Requirements for the Regenerative Thermal Oxidizer(RTO) 37. A source initial compliance test shall be conducted on the combined emission stream from points 136 and 137 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 shall include inlet and outlet testing for VOC in order to demonstrate compliance with the minimum destruction efficiency of 99% for the RTO in addition to outlet testing for sulfur dioxide. 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) Volatile Organic Compounds and sulfur dioxide using EPA approved methods. Periodic Testing Requirements for Point 122: Fugitive Leak Emissions 38. 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. 39. This facility is subject to the leak detection and repair (LDAR) requirements of 40 C.F.R Part 60, Subpart KKK. Periodic Testing Requirements for Points 135 and 139: Reciprocating Internal Combustion Engines 40. 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. Periodic Testing Requirements for Point 136: TEG Dehydrator 41. 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 Condition no. 7. Periodic Testing Requirements for Point 137: Amine Sweetening Unit 42. The operator shall sample the inlet gas to the plant on an annual basis to determine the concentration of hydrogen sulfide (H2S) in the gas stream. 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 38 may be used for this demonstration AIRS ID: 123/0049/122, 135-139 Page 13 of 26 DCP Midstream, LP Cola do ' p e o Public Health and Environment Permit No. 10WE1659 • 7:. Air Pollution Control Division Issuance 1 43. 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 per Condition No. 7. ADDITIONAL REQUIREMENTS 44. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, II.C) a. Annually whenever a significant increase in emissions occurs as follows: For any criteria 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. f. Points 135 and 139: Within 14 calendar days of commencing operation of a permanent replacement engine under the alternative operating scenario outlined in this permit as Attachment A. The APEN shall include the specific manufacturer, model and serial number and horsepower of the permanent replacement engine, the appropriate APEN filing fee and a cover letter explaining that the permittee is exercising an alternative-operating scenario and is installing a permanent replacement engine. 45. This source is subject to the provisions of Regulation Number 3, Part C, Operating Permits (Title V of the 1990 Federal Clean Air Act Amendments). The provisions of this construction permit must be incorporated into the operating permit. The application for the modification to the Operating Permit is due within one year of commencement of operation of the equipment or modification covered by this permit. 46. Non-attainment New Source Review requirements 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 applicable NSR threshold will require a full NSR review of the source as though construction had not yet commenced on the source. The source shall not exceed the NSR threshold until a NSR permit is granted. (Regulation No. 3 Part D, V.A.7) 47. 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 AIRS ID: 123/0049/122, 135-139 Page 14 of 26 DCP Midstream, LP Col + do p one o Public Health and Environment Permit No. 10WE1659 Air Pollution Control Division Issuance 1 relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of Subpart HH. (Reference: Regulation No. 8, Part E) 48. MACT Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines 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 that Subpart on the date as stated in the rule as published in the Federal Register. (Reference: Regulation No. 8, Part E) GENERAL TERMS AND CONDITIONS: 49. 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. 50. 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. 51. 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 applicant's agents. It is valid only for the equipment and operations or activity specifically identified on the permit. 52. Unless specifically stated otherwise, the general and specific conditions contained in this permit have been determined by the APCD to be necessary to assure compliance with the provisions of Section 25-7-114.5(7)(a), C.R.S. 53. 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. 54. 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 AIRS ID: 123/0049/122, 135-139 Page 15 of 26 DCP Midstream, LP Op Coll do It p ev o Public Health and Environment Permit No. 10WE1659 . ` i Air Pollution Control Division Issuance 1 :x Division in writing requesting a cancellation of the permit. Upon notification, annual fee billing will terminate. 55. Violation of the terms of a permit or of the provisions of the Colorado Air Pollution Prevention and Control Act or the regulations of the AQCC may result in administrative, civil or criminal enforcement actions under Sections 25-7-115 (enforcement), -121 (injunctions), -122 (civil penalties), -122.1 (criminal penalties), C.R.S. By: Stephanie Chaousy, PE Permit Engineer Permit History Issuance Date Description Issuance 1 This Issuance Modification of emission limits for fugitive emission leaks. Addition of 2 engines, TEG dehydrator, amine sweetening unit, and a hot oil heater. Major facility for NOx, CO and VOC. Synthetic minor facility for HAPs. This facility is considered major for NOx and VOC for the purposes of NANSR review. However, the proposed modifications are less than the specified federal threshold of 40 TPY for NOx and VOC each, and 100 TPY for CO. Therefore, this project is considered a minor modification for NANSR review. AIRS ID: 123/0049/122, 135-139 Page 16 of 26 DCP Midstream, LP 1 ' Col do e p e o Public Health and Environment Permit No. 10WE1659 u r - r Air Pollution Control Division Issuance 1 �.. Notes to Permit Holder: 1) 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. 2) 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/airreqs/100102aacccommonprovisionsreo.pdf. 3) The following emissions of non-criteria reportable air pollutants are estimated based upon the process limits as indicated in this permit. This information is listed to inform the operator of the Division's analysis of the specific compounds emitted if the source(s) operate at the permitted limitations. Uncontrolled Emission Are the Controlled AIRS Rate emissions Emission Point Pollutant CAS# BIN (lb/yr) reportable? Rate(lb/yr) Benzene 71432 A 171 Yes 56 Toulene 108883 C 180 No 60 122 Ethylbenzene 100414 C 0 No 0 Xylenes 1330207 C 120 No 40 n-Hexane 110543 C 1027 Yes 339 Formaldehyde 50000 A 13731 Yes 1373 Acetaldehyde 75070 A 980 Yes 490 135 Acrolein 107028 A 603 Yes 301 and Methanol 67561 C 293 No 293 139 each n-Hexane 110543 C 130 No 130 Toluene 108883 C 48 No 48 1,3-Butadiene 106990 A 31 No 31 Benzene 71432 A 163,000 Yes 1630 Toulene 108883 C 224,145 Yes 2241 136 Ethylbenzene 100414 C 10,484 Yes 105 Xylenes 1330207 C 85,023 Yes 860 n-Hexane 110543 C 360,366 Yes 3604 Benzene 71432 A 75424 Yes 980 137 Toulene 108883 C 80300 Yes 989 AIRS ID: 123/0049/122, 135-139 Page 17 of 26 DCP Midstream, LP CoI . do e p ety o Public Health and Environment Permit No. 10WE1659 * Air Pollution Control Division Issuance 1 Ethylbenzene 100414 C 2180 Yes 26 Xylenes 1330207 C 14886 Yes 186 n-Hexane 110543 C 13567 Yes 640 Formaldehyde 50000 A 21 No 21 138 n-Hexane 110543 C 600 No 600 4) The emission levels contained in this permit are based on the following emission factors: Point 122: Component Gas Service Heavy Oil Light Oil ervi S Water/Oil Service Connectors 2637 0 5162 0 Flanges 1929 0 1460 0 Open-ended Lines ' 0 0 0 0 Pump Seals 0 0 40 0 Valves 1649 0 2388 0 Other* 105 0 49 0 VOC Content(wt%) 2251% 100% 100% 100% *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. Point 135 and 139: Emission Factors - Emission Factors— Uncontrolled Controlled CAS Pollutant Ib/MMBtu g/bhp-hr lb/MMBtu g/bhp-hr NOx 0.1464 0.5 0.1464 0.5 CO 0.8081 2.76 0.0566 0.1932 VOC 0.1845 0.63 0.0922 0.315 50000 Formaldehyde 0.1171 0.4 0.0117 0.04 75070 Acetaldehyde 0.0084 0.0286 0.0042 0.0143 AIRS ID: 123/0049/122, 135-139 Page 18 of 26 • DCP Midstream, LP Col do ;,,up. 'rne o`Public Health and Environment Permit No. 10WE1659 Air Pollution Control Division Issuance 1 Emission Factors - Emission Factors- Uncontrolled Controlled CAS Pollutant lb/MMBtu g/bhp-hr lb/MMBtu g/bhp-hr 107028 Acrolein 0.0051 0.0176 0.0026 0.0088 67561 Methanol 0.0025 0.0085 0.0025 0.0085 110543 n-Hexane 0.0011 0.0038 0.0011 0.0038 108883 Toluene 0.0004 0.0014 0.0004 0.0014 106990 1,3-Butadiene 0.0003 0.0009 0.0003 0.0009 Emission factors are based on a Brake-Specific Fuel Consumption Factor of 7530 Btu/hp-hr, a site-rated horsepower value of 2370, and a fuel heat value of 958 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); 50% Natural Gas 107028 Acrolein AP-42; Table 3.2-2 (7/2000); 50% Natural Gas Point 136: The emission levels contained in this permit are based on information provided in the application and the Promax process simulation software or Division-approved equivalent software. Point 137: The emission levels contained in this permit are based on the Promax process simulation software or Division-approved equivalent software using the extended sour gas analysis representative of the natural gas processed by this unit submitted with the permit application. Point 138: The emission levels contained in this permit are based on information provided in the application and AP-42, Section 1.4, Table 1.4-1. 5) In accordance with C.R.S. 25-7-114.1, the Air Pollutant Emission Notice (APEN) associated with this permit is valid for a term of five years. The five-year term for this APEN expires on 12/10/2014. A revised APEN shall be submitted no later than 30 days before the five-year term expires. 6) Points 135 and 139 are 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.gov/ttn/atw/area/fr18ia08.pdf 7) Points 135 and 139 are 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/fr18ia08.pdf Additional information regarding area source standards can be found on the EPA website at: http://www e pa.qov/ttn/atw/area/arearu les.html 8) This facility is classified as follows: Applicable Status Requirement AIRS ID: 123/0049/122, 135-139 Page 19 of 26 DCP Midstream, LP Cols rdo a p e o Public Health and Environment Permit No. 10WE1659 ' Air Pollution Control Division Issuance 1 •m Operating Permit Major Source: NOx, CO, VOC Synthetic Minor Source: HAPs Major Source: NOx, CO, VOC NANSR MINOR MODIFICATION TO A MAJOR SOURCE: NANSR REVIEW NOT APPLICABLE AT THIS TIME MACT HH Area Source Requirements: Applicable MACT ZZZZ Area Source Requirements: Applicable 9) Full text of the Title 40, Protection of Environment Electronic Code of Federal Regulations can be found at the website listed below: http://ecfr.gpoaccess.gov/ Part 60: Standards of Performance for New Stationary Sources NSPS 60.1-End Subpart A— Subpart KKKK NSPS Part 60, Appendixes Appendix A—Appendix I Part 63: National Emission Standards for Hazardous Air Pollutants for Source Categories MACT 63.1-63.599 Subpart A—Subpart Z MACT 63.600-63.1199 Subpart AA—Subpart DDD MACT 63.1200-63.1439 Subpart EEE—Subpart PPP MACT 63.1440-63.6175 Subpart QQQ—Subpart YYYY MACT 63.6580-63.8830 Subpart 777Z— Subpart MMMMM MACT 63.8980-End Subpart NNNNN —Subpart XXXXXX 10) An Oil and Gas Industry Construction Permit Self-Certification Form is included with this permit packet. Please use this form to complete the self-certification requirements as specified in the permit conditions. Further guidance on self-certification can be found on our website at: http://www.cdphe.state co.us/ap/oilgaspermitting.html AIRS ID: 123/0049/122, 135-139 Page 20 of 26 • DCP Midstream, LP Col ' do 'p. me ° o Public Health and Environment Permit No. 10WE1659 '• st. _ I Air Pollution Control Division Issuance 1 .x ATTACHMENT A: ALTERNATIVE OPERATING SCENARIOS RECIPROCATING INTERNAL COMBUSTION ENGINES December 10, 2008 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 permittee shall be allowed to perform such engine replacement without applying for a revision to this permit or obtaining a new Construction Permit. A.1 Engine Replacement The following AOS is incorporated into this permit in order to deal with a compressor 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 permittee shall maintain a log on-site and contemporaneously record the start and stop date of any engine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the engine(s)that are replaced during the term of this permit, and the manufacturer, model number, horsepower, and serial number of the replacement engine. In addition to the log, the permittee shall maintain a copy of all Applicability Reports required under section A.1.2 and make them available to the Division upon request. A.1.1 The permittee may temporarily replace an existing compressor 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 emissions from the temporary replacement engine comply with the emission limitations for the existing permitted engine as determined in section A.2. Measurement of emissions from the temporary replacement engine shall be made as set forth in section A.2. A.1.2 The permittee may permanently replace the existing compressor engine with an engine that is of the same manufacturer, model and horsepower without modifying this permit so long as the emissions from the permanent replacement engine comply with 1) the permitted annual emission limitations for the AIRS ID: 123/0049/122, 135-139 Page 21 of 26 DCP Midstream, LP j Coll do I p er1 o Public Health and Environment Permit No. 10WE1659 Air Pollution Control Division Issuance 1 existing engine, 2) any permitted short-term emission limitations for the existing permitted engine, and 3) the applicable emission limitations as set forth in the Applicability Report submitted to the Division with the Air Pollutant Emissions Notice (APEN) for the replacement engine (see http://www.cdphe.state.co.us/ap/oilgaspermittinq.html for example applicability report formats). Measurement of emissions from the permanent replacement engine and compliance with the applicable emission limitations shall be made as set forth in section A.2. The AOS cannot be used for the permanent replacement of an entire engine at any source that is currently a major stationary source for purposes of Prevention of Significant Deterioration or Non- Attainment Area New Source Review ("PSD/NANSR") unless the existing engine has emission limits that are below the significance levels in Reg 3, Part D, II.A.42. 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 permittee 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 http://www.cdphe.state.co.us/ap/oilgaspermittinq.html. This submittal shall be accompanied by a certification from a person legally authorized to act on behalf of the source 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 permittee shall agree to pay fees based on the normal permit processing rate for review of information submitted to the Division in regard to any permanent engine replacement. Nothing in this AOS shall preclude the Division from taking an action, based on any permanent engine replacement(s), for circumvention of any state or federal PSD/NANSR requirement. Additionally, in the event that any permanent engine replacement(s) constitute(s) a circumvention of applicable PSD/NANSR requirements, nothing in this AOS shall excuse the permittee from complying with PSD/NANSR and applicable permitting requirements. A.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 permittee 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 permittee 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. AIRS ID: 123/0049/122, 135-139 Page 22 of 26 , DCP Midstream, LP Col do p et o" Public Health and Environment Permit No. 10WE1659 i Air Pollution Control Division Issuance 1 . _ y 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 website at: http://www.cdphe.state.co.us/ap/clown/portanalyzeproto.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. 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. A.3 Applicable Regulations for Permanent Engine Replacements A.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. AIRS ID: 123/0049/122, 135-139 Page 23 of 26 DCP Midstream, LP t Col do • p1 ` a otPublic Health and Environment Permit No. 10WE1659 Air Pollution Control Division Issuance 1 � =� A.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 A.1.2. Emission Standards: Section XVII.E— State-only requirements 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: Construction or Emission Standards in G/hp-hr Max Engine HP Relocation Date 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 2.0 4.0 1.0 July 1, 2010 1.0 2.0 0.7 The source shall submit copies of the relevant Applicability Reports required under Condition A.1.2 A.3.3 NSPS for spark ignition internal combustion engines: 40 CFR 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 40 CFR 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 A.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 A.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition A.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 AIRS ID: 123/0049/122, 135-139 Page 24 of 26 DCP Midstream LP Co do p me oPublic Health and Environment Permit No. 10WE1659 Air Pollution Control Division Issuance 1 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 November 1, 2008 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, § 1.8 (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. A.3.4 Reciprocating internal combustion engine (RICE) MACT: 40 CFR Part 63, Subpart ZZZZ A.3.4.1 Area Source for HAPs A permanent replacement engine located at an area source that commenced construction or reconstruction after June 12, 2006 as defined in § 63.2, will meet the requirements of 40 CFR Part 63, Subpart ZZZZ by meeting the requirements of 40 CFR Part 60, Subpart JJJJ. 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 A.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 A.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition A.2. A.3.4.2 Major source for HAPs A permanent replacement engine that is located at major source is subject to the requirements in 40 CFR Part 63 Subpart ZZZZ as follows: Existing, new or reconstructed spark ignition 4 stroke rich burn engines with a site rating of more than 500 hp are subject to the requirements in 40 CFR Part 63 Subpart ZZZZ. New or reconstructed (construction or reconstruction commenced after 12/19/02) 2 stroke and 4 stroke lean burn engines with a site rating of more than 500 hp are subject to the requirements in 40 CFR Part 63 Subpart ZZZZ. New or reconstructed (construction or reconstruction commenced after 6/12/06) 4 stroke lean burn engines with a site rating of greater than or equal to 250 but less or equal to 500 hp and were manufactured on or after 1/1/08 are subject to the requirements in 40 CFR Part 63 Subpart ZZZZ. New or reconstructed (construction or reconstruction commenced after 6/12/06) 2 stroke lean burn or 4 stroke rich burn engines with a site rating of 500 hp or less will meet the requirements of 40 CFR 63, Subpart ZZZZ by meeting the requirements of 40 CFR 60, Subpart JJJJ. New or reconstructed (construction or reconstruction commenced after 6/12/06) 4 stroke lean burn engines with a site rating of less than 250 hp will meet the requirements of 40 CFR 63, Subpart ZZZZ by meeting the requirements of 40 CFR 60, Subpart JJJJ. 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 A.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 AIRS ID: 123/0049/122, 135-139 Page 25 of 26 DCP Midstream, LP s Cali ado p e , o Public Health and Environment Permit No. 10WE1659 �'. f+ Air Pollution Control Division Issuance 1 under Condition A.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition A.2. A3.5 Additional Sources The replacement of an existing engine with a new engine is viewed by the Division as the installation of a new emissions unit, not"routine 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. AIRS ID: 123/0049/122, 135-139 Page 26 of 26 Hello