PUBLIC PARTICIPATION DOCUMENTS For DCP Midstream, LP Hamilton Township, Michigan

STATE OF MICHIGAN Rick Snyder, Governor DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION CONSTITUTION HALL 525 WEST ALLEGAN STREET P.O. BOX 30260 LANSING, MICHIGAN 48909-7760 www.michigan.gov/air PUBLIC PARTICIPATION DOCUMENTS For DCP Midstream, LP Hamilton Township, Michigan PERMIT APPLICATION NUMBER 187-12 June 27, 2013

DCP Midstream, LP Page 1 Purpose and Summary FACT SHEET June 27, 2013 The Michigan Department of Environmental Quality (MDEQ), Air Quality Division (AQD), is proposing to act on Permit to Install (PTI) application No. 187-12 from DCP Midstream, LP (DCP). The permit application is for a proposed installation and operation of a new natural gas processing facility. The proposed project is subject to permitting requirements of the Department s Rules for Air Pollution Control and state and federal Prevention of Significant Deterioration (PSD) regulations. Prior to acting on this application, the AQD is holding a public comment period and a public hearing, if requested in writing, to allow all interested parties the opportunity to comment on the proposed Permit to Install (PTI). All relevant information received during the comment period and hearing if held, will be considered by the decision maker prior to taking final action on the application. Background Information The new natural gas processing facility is proposed to be located at Section 8, T19N, R3W of Hamilton Township (near the intersection of Stockwell Road and North Rodgers Avenue), near Harrison, Clare County, Michigan. The proposed facility would be built at a greenfield site and would process natural gas pulled from the existing pipeline. DCP is not proposing to install any new natural gas wells at this facility. The facility would take pipeline natural gas and separate the stream into natural gas liquids and residue natural gas while removing impurities such as water. Both the natural gas liquids and residue natural gas will be sent off-site via sales pipelines. Proposed Facility and Present Air Quality The draft air permit for the proposed natural gas processing facility consists of 2 processing trains that would process a total of 180 million standard cubic feet of natural gas per day. The natural gas feed from the pipeline will be sent through five processes to achieve the desired final products of residue natural gas and natural gas liquids: inlet separation, amine treating, dehydration, cryogenic cooling, and final compression. Inlet separation will take the raw natural gas from a high pressure natural gas pipeline and send it to a slug catcher for liquid removal. Liquids removed will be sent to a flash tank to recycle any recovered gas back to the inlet stream and liquids to water and condensate tanks. Next, amine treating will remove any minor amounts of carbon dioxide (CO 2 ) and hydrogen sulfide (H 2 S) from the natural gas stream. The natural gas will have already been treated prior to obtaining it from the pipeline so it is not expected to contain significant amounts of CO 2 and H 2 S. The amine regeneration stream will be controlled by a regenerative thermal oxidizer (RTO). Next, the natural gas stream will be dehydrated by a glycol unit and a molecular sieve to remove additional water.

DCP Midstream, LP Page 2 After dehydration, the natural gas stream will be sent to the cryogenic plant and gas sub-cooling process. This will cause the natural gas liquids to condense out of the gas stream. The natural gas liquids will be stored in pressurized bullet tanks prior to being piped off-site for sales. The residue natural gas stream will undergo compression and be sent to a pipeline for sales. The proposed permit addresses the following equipment: A total of ten natural gas-fired lean burn compressor engines. Three 2,370 brake horsepower (bhp) or smaller engines used to compress the residue natural gas prior to sending it to the sales pipeline for each processing train. Two 1,035 bhp or smaller engines used to compress propane in the cryogenic plant that condenses the natural gas liquids out of the natural gas feed stream for each processing train. Each engine will be equipped with an oxidation catalyst to control emissions. Three 46.35 million Btu per hour (MMBtu/hr) heat input natural gas-fired turbines for generating on-site electricity. One turbine is dedicated to each processing train with the third used as a back-up. Each turbine will be equipped with a waste heat recovery unit and dry low- NO x burners. A total of four natural gas-fired hot oil heaters to provide heat to various portions of the plant. One 40 MMBtu/hr heat input heater and one 10 MMBtu/hr heat input heater for each processing train. Each heater is equipped with low-no x burners. Two 0.76 MMBtu/hr emergency flares that will also control residue sweep/purge gas used in the regeneration of each processing train s molecular sieve. A total of two amine treaters with heat supplied by each processing train s hot oil heater. The waste stream vapors from each amine treater will be sent to an RTO for control. A total of two triethylene glycol dehydrators with heat supplied by each processing train s hot oil heater. Each dehydrator will be equipped with a flash tank and atmospheric condenser. Gases from each flash tank are sent to the hot oil heaters for use as a fuel. Residual vapors from the condenser are controlled by a vapor combustor and liquids are sent to the condensate tanks. A total of 12 above ground storage tanks. Four 300 barrel capacity condensate tanks for each processing train. Two 300 barrel capacity water tanks for each processing train. All tank emissions will be controlled by a vapor combustor. Clare County is currently in attainment with all of the National Ambient Air Quality Standards (NAAQS) - carbon monoxide (CO), nitrogen oxides (NOx), sulfur dioxide (SO2), ozone, particulate matter that has an aerodynamic diameter less than or equal to a nominal 10 microns (PM10), particulate matter that has an aerodynamic diameter less than or equal to a nominal 2.5 microns (PM2.5), ozone, and lead. There is no NAAQS for Greenhouse Gases (GHG). Pollutant Emissions The source, as proposed, will have the potential to emit GHGs (232,000 tpy of carbon dioxide equivalent (CO2e)) that are over the significance level of 100,000 tons per year CO2e. The proposed source will be a new major stationary source, and, therefore, subject to the PSD regulations in Part 18 of the Michigan Air Pollution Control Rules. The potential to emit of NOx, CO, volatile organic compounds (VOC), PM2.5, and PM10 are also above significance and will be subject to PSD review. The source will be a minor source of hazardous air pollutant (HAP) emissions. The facility will be located in an attainment area for all criteria pollutants; therefore, the entire project is subject to the PSD requirements.

DCP Midstream, LP Page 3 The following table provides the estimated emissions for each criteria pollutant: EMISSION SUMMARY Pollutant Estimated Emissions (tpy) Particulate Matter (PM) 2.8 PM10 16.1 PM2.5 16.1 SO 2 39.0 CO 229.3 NO x 185.5 VOCs 77.6 Lead 0.00052 Fluorides N/A Sulfuric Acid Mist N/A Hydrogen Sulfide (H 2 S) 0.3 GHGs (as CO 2 e) 232,000 Key Permit Review Issues Staff evaluated the proposed project to identify all state rules and federal regulations which are, or may be, applicable. The tables in Appendix 1 summarize these rules and regulations. Prevention of Significant Deterioration (PSD) Regulations Based on the potential emissions, the proposed source is subject to PSD review for NOx, CO, VOC, PM2.5, PM10, and GHGs. Review under the PSD regulations requires a Best Available Control Technology (BACT) analysis, a source impact analysis, an air quality impact analysis, and an additional impact analysis for each regulated air pollutant for which the project will result in significant emissions. The PSD major source threshold is 250 tpy for each of the criteria pollutants and 100,000 tpy of GHG (as CO 2 e) unless the source is one of 28 source categories listed in the PSD regulations, then the PSD major source threshold is only 100 tpy. Once a source or project is major for a single pollutant, it is also major for any other pollutants emitted above their significant level. The following table summarizes the potential emissions for the project.

DCP Midstream, LP Page 4 Pollutant Total Emission PSD Significant Increase (tpy) Emission Rate (tpy) Subject to PSD? PM 2.8 25 NO PM10 16.1 15 YES PM2.5 16.1 10 YES SO 2 39.0 40 NO CO 229.3 100 YES NO 2 185.5 40 YES VOC 77.6 40 YES Lead 0.00052 0.6 NO Fluorides N/A 3 NO Sulfuric Acid Mist N/A 7 NO H 2 S 0.3 10 NO GHGs (as CO2 e ) 232,000 100,000 YES CO: The PSD BACT determination for CO for the engines was based on data for similar engines, vendor data, review of the RACT/BACT/LAER Clearinghouse and proposed controls by the applicant. BACT for the residue gas compression engines has been determined to be an emission limitation of 0.50 grams CO per brake horsepower hour (g/bhp-hr) through the use of an oxidation catalyst. BACT for the propane compression engines has been determined to be an emission limitation of 0.45 grams CO per brake horsepower hour (g/bhp-hr) through the use of an oxidation catalyst. The engines are lean burn by design and will also have built-in timing and air-fuel ratio controls to minimize CO (and by balance - NOx). Any additional or alternative add-on controls for CO were ruled out as technically infeasible due to the lean burn design of the engine, the effectiveness of the proposed oxidation catalysts, and also to eliminate an associated increase in NOx emissions. The PSD BACT determination for CO for the turbines was based on data for similar sized and functioning turbines, vendor data, review of the RACT/BACT/LAER Clearinghouse and proposed controls by the applicant. BACT for the turbines has been determined to be an emission limitation of 0.60 grams CO per brake horsepower hour (g/bhp-hr) through the use of combustion controls and good combustion practices. Catalytic oxidation controls were considered not cost effective at over $40,000 per ton. The turbines will utilize air-fuel ratio monitoring to minimize CO (and by balance - NOx). Any additional or alternative add-on controls for CO were ruled out as technically infeasible due to the design of the turbine and no proven demonstration of effectiveness. The PSD BACT determination for CO for the hot oil heaters was based on data for similar sized heaters, vendor data, review of the RACT/BACT/LAER Clearinghouse and proposed controls by the applicant. BACT for the heaters has been determined to be an emission limitation of 0.082 pounds CO per million British thermal unit heat input (lb/mmbtu) through the use of combustion controls and good combustion practices. Catalytic oxidation controls were considered not cost effective at $14,000 per ton. The heaters will utilize air-fuel ratio monitoring to minimize CO (and by balance - NOx). Any additional or alternative add-on controls for CO were ruled out as technically infeasible due to the design of the heaters and no proven demonstration of effectiveness.

DCP Midstream, LP Page 5 Other potential sources of CO at the proposed source will be 2 dehydrators. Some minor amounts of CO may be stripped off from the previously dehydrated pipeline quality gas during this process. Emissions from the dehydrators are sent to a vapor combustor or heater for control. The remaining emission units (amine treaters, condensate tanks, and water tanks) will not produce any CO emissions by themselves but will contribute to the overall CO emission total after control devices (flares, vapor combustors, and RTOs) are utilized to reduce other pollutant emissions. The permit conditions will require that these control devices are operated and maintained properly for efficiency and good combustion. Good combustion and high control efficiencies will minimize the amount of CO emitted. No PSD BACT emission limits for CO will be included for these remaining emission units as other limits (VOC limits, control efficiency, and opacity limits) will act as surrogates. NOx: The PSD BACT determination for NO x for the engines was based on data for similar engines, vendor data, review of the RACT/BACT/LAER Clearinghouse and proposed controls by the applicant. BACT for the residue gas compression engines has been determined to be an emission limitation of 0.70 grams NO x per brake horsepower hour (g/bhp-hr) through the use of lean burn technology. BACT for the propane compression engines has been determined to be an emission limitation of 0.50 grams NO x per brake horsepower hour (g/bhp-hr) through the use of lean burn technology. The engines are lean burn by design and will also have built-in timing and air-fuel ratio controls to minimize NO x (and by balance - CO). Any additional or alternative add-on controls for NO x were ruled out as technically infeasible due to the lean burn design of the engines and also to eliminate an associated increase in CO emissions. The PSD BACT determination for NO x for the turbines was based on data for similar sized and functioning turbines, vendor data, review of the RACT/BACT/LAER Clearinghouse and proposed controls by the applicant. BACT for the turbines has been determined to be an emission limitation of 0.50 grams NO x per brake horsepower hour (g/bhp-hr) (and 42 ppm NO x at 15% oxygen to comply with NSPS KKKK) through the use of combustion controls and dry low-no x burners. Selective catalytic reduction (SCR) controls were considered not cost effective for this size of turbine at over $17,000 per ton. The turbines will utilize dry low-no x burners and air-fuel ratio monitoring to minimize NO x (and by balance - CO). Non-selective catalytic reduction (NSCR) controls for NO x were ruled out as technically infeasible due to the design of the turbine and no proven demonstration of effectiveness. The PSD BACT determination for NO x for the hot oil heaters was based on data for similar sized heaters, vendor data, review of the RACT/BACT/LAER Clearinghouse and proposed controls by the applicant. BACT for the heaters has been determined to be an emission limitation of 0.049 pounds NO x per million British thermal unit heat input (lb/mmbtu) through the use of combustion controls and low-no x burners. SCR and flue gas recirculation (FGR) controls were considered not cost effective at over $50,000 per ton for these smaller sized heaters. The heaters will utilize low-no x burners and air-fuel ratio monitoring to minimize NO x (and by balance - CO). Any additional or alternative add-on controls for NO x were ruled out as technically infeasible due to the size of the heaters and no proven demonstration of effectiveness.

DCP Midstream, LP Page 6 The remaining emission units (amine treaters, dehydrators, condensate tanks, and water tanks) will not produce any NO x emissions by themselves but will contribute to the overall NO x emission total after control devices (flares, vapor combustors, and RTOs) are utilized to reduce other pollutant emissions. The permit conditions will require that these control devices are operated and maintained properly for efficiency and good combustion. No PSD BACT emission limits for NO x will be included for these remaining emission units. VOC: The PSD BACT determination for VOC for the engines was based on data for similar engines, vendor data, review of the RACT/BACT/LAER Clearinghouse and proposed controls by the applicant. BACT for the residue gas compression engines has been determined to be an emission limitation of 0.18 grams VOC per brake horsepower hour (g/bhp-hr) through the use of an oxidation catalyst. BACT for the propane compression engines has been determined to be an emission limitation of 0.25 grams VOC per brake horsepower hour (g/bhp-hr) through the use of an oxidation catalyst. The engines are lean burn by design and will also have built-in timing and air-fuel ratio controls to minimize VOC through more complete combustion (and by balance - NOx). Any additional or alternative add-on controls for VOC were ruled out as technically infeasible due to the lean burn design of the engine, the effectiveness of the proposed oxidation catalysts, and also to eliminate an associated increase in NOx emissions. The PSD BACT determination for VOC for the turbines was based on data for similar sized and functioning turbines, vendor data, review of the RACT/BACT/LAER Clearinghouse and proposed controls by the applicant. BACT for the turbines has been determined to be an emission limitation of 0.10 grams VOC per brake horsepower hour (g/bhp-hr) through the use of combustion controls and good combustion practices. Catalytic oxidation controls were considered not cost effective at over $250,000 per ton due to the already low VOC emissions. Even using a combined control approach for CO and VOC is not cost effective at more than $35,000 per ton. The turbines will utilize air-fuel ratio monitoring to minimize VOC (and by balance - NOx). Any additional or alternative add-on controls for VOC were ruled out as technically infeasible due to the design of the turbine and no proven demonstration of effectiveness. The PSD BACT determination for VOC for the hot oil heaters was based on data for similar sized heaters, vendor data, review of the RACT/BACT/LAER Clearinghouse and proposed controls by the applicant. BACT for the heaters has been determined to be an emission limitation of 0.005 pounds VOC per million British thermal unit heat input (lb/mmbtu) through the use of combustion controls and good combustion practices. Catalytic oxidation controls were considered not cost effective at $200,000 per ton due to the already low VOC emissions. Even using a combined control approach for CO and VOC is not cost effective at $13,000 per ton. The heaters will utilize air-fuel ratio monitoring to minimize VOC (and by balance - NOx). Any additional or alternative add-on controls for VOC were ruled out as technically infeasible due to the design of the heaters and no proven demonstration of effectiveness. Other potential small sources of VOC at the proposed source will be dehydrators, amine treaters, condensate tanks, and water tanks. All of this equipment will be sent to control devices (flares, vapor combustors, and RTOs) to reduce VOC emissions. The permit conditions will require that these control devices are operated and maintained properly for efficiency and good combustion. No PSD BACT emission limit for VOC will be included for

DCP Midstream, LP Page 7 the flares but the permit conditions contain an opacity limit that will act as a surrogate for proper operation. A PSD BACT emission limit of 1.98 lb/hr VOC for each RTO will be included along with other limits (98.5% control efficiency, minimum temperature and retention time) to ensure proper operation of the control device. Proper operation of the flares will promote good combustion and high control efficiencies that will minimize the amount of VOC emitted. A PSD BACT emission limit of 1.53 lb/hr VOC for each vapor combustor will be included along with other limits (99% control efficiency, operation according to preventative maintenance/malfunction abatement plan) to ensure proper operation of the control device. PM10 and PM2.5: The PSD BACT determination for PM10 and PM2.5 for the engines was based on data for similar engines, vendor data, review of the RACT/BACT/LAER Clearinghouse and proposed controls by the applicant. BACT for the residue gas compression engines and propane compression engines has been determined to be an emission limitation of 0.00999 pounds PM10 per million British thermal unit heat input (lb/mmbtu) and 0.00999 lb PM2.5/MMBtu through the use of natural gas. The company is proposing to use pipeline quality natural gas that will contain extremely low amounts of fine particles. The main portion of fine particulates emitted from natural gas combustion operations are condensable fine particulates formed after the exhaust begins to cool in ambient air and are due to incomplete combustion. The engines are lean burn by design and will also have built-in timing and air-fuel ratio controls to minimize incomplete combustion. Any additional or alternative add-on controls for PM10 and PM2.5 were ruled out as technically infeasible due to the low concentration of emissions and the fact that they are condensable in nature. The PSD BACT determination for PM10 and PM2.5 for the turbines was based on data for similar sized and functioning turbines, vendor data, review of the RACT/BACT/LAER Clearinghouse and proposed controls by the applicant. BACT for the turbines has been determined to be an emission limitation of 0.0066 pounds PM10 per million British thermal unit heat input (lb/mmbtu) and 0.0066 lb PM2.5/MMBtu through the use of natural gas. The company is proposing to use pipeline quality natural gas that will contain extremely low amounts of fine particles. The main portion of fine particulates emitted from natural gas combustion operations are condensable fine particulates formed after the exhaust begins to cool in ambient air and are due to incomplete combustion. The turbines will utilize air-fuel ratio monitoring to minimize incomplete combustion. Any additional or alternative add-on controls for PM10 and PM2.5 were ruled out as technically infeasible due to the low concentration of emissions and the fact that they are condensable in nature. The PSD BACT determination for PM10 and PM2.5 for the hot oil heaters was based on data for similar sized heaters, vendor data, review of the RACT/BACT/LAER Clearinghouse and proposed controls by the applicant. BACT for the heaters has been determined to be an emission limitation of 0.007 pounds PM10 per million British thermal unit heat input (lb/mmbtu) and 0.007 lb PM2.5/MMBtu through the use of natural gas. The company is proposing to use pipeline quality natural gas that will contain extremely low amounts of fine particles. The main portion of fine particulates emitted from natural gas combustion operations are condensable fine particulates formed after the exhaust begins to cool in ambient air and are due to incomplete combustion. The heaters will utilize air-fuel ratio monitoring to minimize incomplete combustion. Any additional or alternative add-on controls for PM10 and PM2.5 were ruled out as technically infeasible due to the low concentration of emissions and the fact that they are condensable in nature.

DCP Midstream, LP Page 8 The remaining emission units (amine treaters, dehydrators, condensate tanks, and water tanks) will not produce any PM10 or PM2.5 emissions by themselves but will contribute to the overall PM10 and PM2.5 emission totals after control devices (flares, vapor combustors, and RTOs) are utilized to reduce other pollutant emissions. The permit conditions will require that these control devices are operated and maintained properly for efficiency and good combustion. No PSD BACT emission limits for PM10 or PM2.5 will be included for this equipment as other limits (VOC limits, control efficiency, and opacity limits) will act as surrogates. GHGs (as CO2e): The PSD BACT determination for GHGs for each residue gas compression engine has been determined to be an emission limitation of 8,300 tpy carbon dioxide equivalent (CO 2 e), use of natural gas, and the submittal, implementation, and maintenance of a preventative maintenance/malfunction abatement plan for maintaining the most efficient combustion for the engines. The PSD BACT determination for GHGs for each propane compression engine has been determined to be an emission limitation of 3,900 tpy carbon dioxide equivalent (CO 2 e), use of natural gas, and the submittal, implementation, and maintenance of a preventative maintenance/malfunction abatement plan for maintaining the most efficient combustion for the engines. The PSD BACT determination for GHGs for each turbine has been determined to be an emission limitation of 23,750 tpy carbon dioxide equivalent (CO 2 e), use of natural gas, and the submittal, implementation, and maintenance of a preventative maintenance/malfunction abatement plan for maintaining the most efficient combustion for the turbines. The PSD BACT determination for GHGs for each large hot oil heater has been determined to be an emission limitation of 20,500 tpy carbon dioxide equivalent (CO 2 e) and the use of natural gas. The PSD BACT determination for GHGs for each small hot oil heater has been determined to be an emission limitation of 5,130 tpy carbon dioxide equivalent (CO 2 e) and the use of natural gas. Other potential sources of GHGs (mostly methane) at the proposed source will be dehydrators, amine treaters, condensate tanks, and water tanks. All of this equipment will be sent to control devices (flares, vapor combustors, and RTOs) to reduce the emissions of methane (higher global warming potential). Combusting methane will result in CO 2 emissions but CO 2 has a lower global warming potential so it is an overall benefit. The permit conditions will require that these control devices are operated and maintained properly for efficiency and good combustion. No PSD BACT emission limit for GHGs will be included for the flares as the opacity limit will act as a surrogate for proper operation and the low amount of GHGs expected from each flare. A PSD BACT emission limit of 33,000 tpy carbon dioxide equivalent (CO 2 e) for each RTO will be included along with other limits (98.5% control efficiency, minimum temperature and retention time) to ensure proper operation of the control device. No PSD BACT emission limit for GHGs for the vapor combustors will be included as other limits (99% control efficiency, operation according to preventative maintenance/malfunction abatement plan) will act as a surrogate to ensure proper operation of the control devices.

DCP Midstream, LP Page 9 Carbon capture and sequestration (CCS) has not been demonstrated as technically feasible for this type and size of source. Only demonstration projects on large power plants with high concentration GHG exhaust are in existence. CCS controls for GHGs were ruled out as technically infeasible due to the design of the facility, no proven demonstration of effectiveness for multiple sources of lower concentration GHG emissions, and the technology not being commercially available. Federal NSPS Regulations New Source Performance Standards (NSPS) were established under Title 40 of the Code of Federal Regulations (40 CFR) Part 60. The hot oil heaters will be subject to the NSPS for Small Industrial-Commercial-Institutional Steam Generating Units, Subpart Dc. Because of the size of the proposed heaters and being natural gas fired, the regulatory requirements will be minimal and will not include any emission limits. DCP will be required to submit a notification of construction and operation and maintain records of the hours of operation and amount of natural gas burned in each heater. These requirements are specified in the FGHEATERS section of the permit conditions. Some of the compressor engines may be subject to the NSPS for Stationary Spark Ignition Internal Combustion Engines, Subpart JJJJ. This will be dependent on the date of manufacture of the engines and the size of the engines. DCP will be required to submit a notification of construction and operation and install engines that are certified to meet the requirements of NSPS Subpart JJJJ or will be required to meet the emission limits and testing and monitoring requirements of NSPS Subpart JJJJ. These requirements are specified in the FGNSPSENGINES section of the permit conditions. The turbines will be subject to the NSPS for Stationary Combustion Turbines, Subpart KKKK. Because of the size of the proposed turbines and being natural gas fired, the regulatory requirements will only include an emission limit for NO x of 42 ppm with associated initial and annual compliance stack testing. DCP will also be required to submit a notification of construction and operation, submit periodic reports, maintain records of the total sulfur content of the fuel used in each turbine, and operate and maintain each turbine, air pollution control equipment, and monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions at all times. These requirements are specified in the FGTURBINES section of the permit conditions. Some of the ancillary equipment at the facility may be subject to the NSPS for Crude Oil and Natural Gas Production, Transmission, and Distribution, Subpart OOOO. This will be dependent on the type of equipment utilized at the facility. NSPS OOOO regulates emissions from different types of natural gas wells, storage vessels, controllers, compressors, and can require a leak detection and repair program. DCP will be required to submit notifications and reports, maintain records, and utilize and replace certain pieces of equipment. These requirements are specified in the FGFACILITY section of the permit conditions. Federal NESHAP Regulations - National Emission Standards for Hazardous Air Pollutants (NEHAP) were established under 40 CFR Part 61 or Part 63. DCP has accepted HAPs opt-out emission limits to show that the source s potential HAP emissions are less than major source levels thus DCP is an area source of HAPs.

DCP Midstream, LP Page 10 The engines will be subject to the NESHAP for Stationary Reciprocating Internal Combustion Engines (RICE) located at area sources of HAP emissions, 40 CFR Part 63, Subpart A and Subpart ZZZZ (RICE MACT). The company has demonstrated that it can comply with MACT ZZZZ. Because the State of Michigan has not accepted delegation of this area source MACT, detailed requirements of the MACT will not be listed in the permit but rather only a requirement to comply with all applicable provisions of MACT ZZZZ. The dehydrators will be subject to the NESHAP for Oil and Natural Gas Production Facilities located at area sources of HAP emissions, 40 CFR Part 63, Subpart A and Subpart HH. The company has demonstrated that it can comply with MACT HH. Because the State of Michigan has not accepted delegation of this area source MACT, detailed requirements of the MACT will not be listed in the permit but rather only a requirement to comply with all applicable provisions of MACT HH. Rule 224 TBACT Analysis The MDEQ Rules for Air Pollution Control require that new or modified equipment that emits toxic air contaminants (TAC) must use the Best Available Control Technology for Toxics (T-BACT). Rule 224(2) lists exemptions from T-BACT for emission units subject to MACT standards (dehydrators and compressor engines) and emission units that emit only TACs that are particulates or VOCs and are in compliance with BACT or LAER requirements for particulates and VOCs (turbines, heaters, tanks). Because all of these emission units underwent a BACT review for VOCs, T-BACT does not apply. The amine treaters and any remaining emission sources will be controlled by RTOs, vapor combustors, and flares which will meet T-BACT. Rule 225 Toxics Analysis The MDEQ Rules for Air Pollution Control require the ambient air concentration of TACs not exceed health-based screening levels. AQD staff reviewed DCP s air quality modeling and evaluation of TAC impacts. The review found that all TACs show impacts less than the established health-based screening levels and will comply with the requirements of Rule 225. See Table 1 below for a listing of each individual TAC and the predicted ambient impact. TABLE 1 RULE 225 TAC MODELING RESULTS Pollutant Averaging Time Screening Level Predicted Impact (µg/m 3 ) (µg/m 3 ) Percent of SL Benzene 24-hr 30 (ITSL) 3.90 13.00% Benzene Annual 1 (SRSL) 0.394 39.42% Ethylbenzene Annual 3 (IRSL) 0.191 6.37% Xylenes (total) 24-hr 100 (ITSL) 4.47 4.47% Rule 702 VOC Emissions This rule requires an evaluation of the following four items to determine what will result in the lowest maximum allowable emission rate of VOCs: a. BACT or a limit listed by the department on its own initiative b. New Source Performance Standards (NSPS) c. VOC emission rate specified in another permit d. VOC emission rate specified in the Part 6 rules for existing sources

DCP Midstream, LP Page 11 An evaluation of these four items determined that BACT (702(a)) would dictate the lowest maximum allowable emission rate of VOC from the facility. Rule 702(a) BACT for the emission units at the proposed facility was determined to be the same as PSD BACT for VOCs emission limits and the use of oxidation catalysts on all compressor engines, emission limits and good combustion practices on the turbines and heaters, and emission limits and various controls (flares, vapor combustors, and RTOs) for all other small sources of VOC. Please see the PSD BACT for VOC section above for additional details. Criteria Pollutants Modeling Analysis - Computer dispersion modeling was performed to predict the impacts of the following air emissions: CO, NO x, PM10, PM2.5, and SO 2. Emissions from the proposed facility were evaluated against both the National Ambient Air Quality Standards (NAAQS) and the PSD increments. The NAAQS are intended to protect public health. The PSD increments are intended to allow industrial growth in an area, while ensuring that the area will continue to meet the NAAQS. The results show that the predicted impacts are lower than the allowable levels. PM2.5, PM10 (24-hr), and NO x impacts from the facility were determined to be above their respective Significant Impact Level (SIL) and full impact modeling to demonstrate compliance with applicable NAAQS and PSD Increments was required. It should be noted that there are no NAAQS or PSD Increments for VOCs or GHGs. After the modeling analysis was completed by DCP, but before the AQD acted on the permit application, the PM2.5 SILs were vacated. This did not change the modeling analysis since the impacts were above the SILs and further modeling was conducted. The results of the preliminary modeling are in Table 2. The results of the PSD Increment analysis are in Table 3. The results of the NAAQS analysis are in Table 4. TABLE 2 PRELIMINARY MODELING RESULTS Pollutant Averaging Time SIL (µg/m 3 Predicted Additional ) Impact (µg/m 3 ) Modeling? PM2.5* Annual 0.3 0.85 YES PM2.5* 24-hr 1.2 5.31 YES PM10 Annual 1 0.85 NO PM10 24-hr 5 5.31 YES CO 8-hr 500 108.83 NO CO 1-hr 2,000 195.62 NO NO 2 Annual 1 6.44 YES NO 2 1-hr 7.6 121.85 YES *After the modeling analysis was completed by DCP, but before the AQD acted on the permit application, the PM2.5 SILs were vacated. This did not change the modeling analysis since the impacts were above the SILs and further modeling was conducted.

DCP Midstream, LP Page 12 TABLE 3 PSD INCREMENT ANALYSIS MODELING RESULTS Pollutant Averaging Time PSD Increment Predicted Percent of PSD Level (µg/m 3 ) Impact (µg/m 3 ) Increment PM2.5 Annual 4 0.85 21.28% PM2.5 24-hr 9 4.94 54.91% PM10 24-hr 30 4.94 16.47% NO 2 Annual 25 6.44 25.75% NO 2 1-hr None See Table 4 See Table 4 SO 2 ** Annual 20 3.86 19.30% SO 2 ** 24-hr 91 32.15 35.33% SO 2 ** 3-hr 512 74.24 14.50% **SO 2 potential emissions are 39 tpy which is below the significance level of 40 tpy and modeling is not required under PSD regulations. However, modeling was done by AQD to ensure compliance with NAAQS and PSD Increments. TABLE 4 NAAQS ANALYSIS MODELING RESULTS Pollutant Averaging Time NAAQS (µg/m 3 Combined Percent of ) Impact (µg/m 3 ) NAAQS PM2.5 Annual 12 7.23 60.25% PM2.5 24-hr 35 21.68 61.95% PM10 24-hr 150 32.56 21.70% NO 2 Annual 100 8.34 8.34% NO 2 1-hr 188 112.95 60.08% SO 2 ** Annual 80 3.86 4.83% SO 2 ** 24-hr 365 32.15 8.81% SO 2 ** 1-hr 196 94.77 48.35% **SO 2 potential emissions are 39 tpy which is below the significance level of 40 tpy and modeling is not required under PSD regulations. However, modeling was done by AQD to ensure compliance with NAAQS and PSD Increments. Additional Impact Analysis An additional impact analysis is required for new major sources pursuant to Michigan Rule 336.2815. This analysis is necessary to evaluate the impacts from the proposed project on soils, vegetation, visibility and growth. The facility demonstrated that the project will not result in unfavorable secondary impacts. This was determined to be acceptable due to the fact that the impacts from the project, as determined through dispersion modeling, are below the applicable standards; therefore, it is assumed not to cause unfavorable secondary impacts. Secondary ozone and PM2.5 formation The potential for secondary ozone formation resulting from NO x and VOC emissions was assumed to be negligible as a result of the proposed new facility. The closest monitor to this facility, Houghton Lake, is currently in attainment for the 8-hr ozone standard and the 2013 design value for this monitor is 82 ppb. The secondary ozone impacts from the proposed DCP facility on this, and other, regional ozone monitors are anticipated to be minimal. The proposed facility should not have a significant impact on the ozone NAAQS attainment status in the region.

DCP Midstream, LP Page 13 The potential for secondary PM2.5 formation resulting from NO x and SO 2 emissions from the proposed new facility was assumed to be a negligible contributor to total PM2.5. It is possible that some of the NO x and SO 2 emissions from the proposed facility may be transformed into nitrates and sulfates and be transported downwind. The modeling analysis above shows an ample margin of safety with the PM2.5 NAAQS and PSD increments due to potential directly emitted PM2.5 from the proposed facility. Considering the very minimal expected PM2.5 impacts from secondary formation, compliance with the PM2.5 NAAQS and PSD increments should not be affected. Soils, Vegetation, and Wildlife Compliance with the secondary NAAQS will demonstrate negligible impacts from the project on soils, vegetation, and wildlife. EPA has stated that the secondary NAAQS set limits to protect against damage to animals, crops, and vegetation. Dispersion modeling results show that all impacts are below the applicable NAAQS thresholds; therefore, no adverse impacts to soils, vegetation, or wildlife are expected. TABLE 5 SECONDARY NAAQS ANALYSIS MODELING RESULTS Pollutant Averaging Time Secondary Combined Percent of NAAQS (µg/m 3 ) Impact (µg/m 3 ) NAAQS PM2.5 Annual 15 7.23 48.22% PM2.5 24-hr 35 21.68 61.95% PM10 24-hr 150 32.56 21.70% NO 2 Annual 100 8.34 8.34% SO 2 3-hr 1,300 74.24 5.71% Visibility The nearest Class I (Seney National Wildlife Refuge) area is more than 200 kilometers from the proposed DCP natural gas facility; therefore, a Class I area analysis is not required for this project. The effect on local visibility from the new facility will not create local visual impacts that are considered objectionable or adverse due to the low amount of potential NO x (less than 200 tons per year) and particulate emissions (less than 20 tons per year). Growth There are minor impacts expected because of site preparation and facility construction activities. Emissions from construction vehicles and fugitive dust are not expected to cause any adverse impacts on or beyond the plant boundary. Vehicle emissions will occur over only a portion of any given day and proper construction techniques and fugitive dust controls will be employed to keep emissions to a minimum. Temporary construction employment is expected to be filled mostly by area residents, thus minimizing population growth. Permanent jobs at the plant will be a smaller amount and should have no significant effect on area population. Some minor commercial growth may occur as a result of construction and operation but this cannot be effectively estimated. The growth analysis includes a projection of the associated industrial, commercial, and residential growth that may occur in the area as a result of the project and an estimation of emissions due to the projected growth. Minor industrial and residential growth is expected as a result of this project. No additional commercial growth is expected. The natural gas industry does not have immediate complementary business sectors that typically site new facilities as a result of construction of new natural gas facilities, as do other industries. An insignificant amount of overall growth may occur as a result of this project; therefore, no significant degradation to the existing air quality in the surrounding area is expected.

DCP Midstream, LP Page 14 Key Aspects of Draft Permit Conditions The draft permit conditions contain emission limits, material limits, process/operational restrictions, monitoring, recordkeeping, and reporting requirements necessary for an enforceable permit that meets all applicable state and federal requirements. The following is a brief discussion of the key aspects of the draft permit conditions: Emission Limits The draft permit includes the following emission limits for each compressor engine, turbine, and hot oil heater: NO x, CO, PM2.5, PM10, VOC, and GHG as CO 2 e. The flares have a no visible emissions limit that will be used as a surrogate to demonstrate proper combustion and destruction of any gas streams sent to the flares. The amine treaters that are controlled by RTOs have VOC, GHG as CO 2 e, and SO 2 emission limits. The tanks and dehydrators that are controlled by vapor combustors have a VOC emission limit. The draft permit also contains HAP opt-out limits to maintain the proposed source as an area source of HAP emissions. The draft permit will also include a facility-wide benzene emission limit as a result of using Rule 225(2) for compliance. Material/Usage Limits - The draft permit only allows the combustion of sweet natural gas in each piece of combustion equipment. Process/Operational Restrictions The draft permit requires Malfunction Abatement Plans for the compressor engines, turbines, and vapor combustors. DCP is required to develop the plans to include a preventative maintenance program and corrective procedures in the event of an equipment malfunction or failure. The plan shall incorporate procedures recommended by the equipment manufacturer as well as incorporating standard industry pratices. For the turbines, DCP has proposed an operating restriction of 18,000 total operating hours per year for the 3 turbines combined. This restricts the emissions from the turbines to less than their maximum potential to emit while allowing for a transition for each processing train from the dedicated turbine to the back-up turbine without losing electrical power. Federal Regulations The proposed hot oil heaters are subject to the New Source Performance Standard (NSPS) for Small Industrial-Commercial-Institutional Steam Generating Units, 40 CFR Part 60 Subpart Dc. The permit specifies that compliance with natural gas usage limits, notification, and recordkeeping requirements will constitute compliance with the NSPS. The proposed compressor engines may be subject to the NSPS for Stationary Spark Ignition Internal Combustion Engines, 40 CFR Part 60 Subpart JJJJ. The permit specifies that compliance with the emission limits, testing and monitoring requirements, notification, and recordkeeping requirements specified in the FGNSPSENGINES section of the draft permit will constitute compliance with the NSPS. The proposed turbines are subject to the NSPS for Stationary Combustion Turbines, 40 CFR Part 60 Subpart KKKK. The permit specifies that compliance with natural gas usage limits, NO x emission limits and testing, notification, reporting, and recordkeeping requirements will constitute compliance with the NSPS.

DCP Midstream, LP Page 15 The proposed facility will contain ancillary equipment that is subject to the NSPS for Crude Oil and Natural Gas Production, Transmission, and Distribution, 40 CFR Part 60 Subpart OOOO. The permit specifies that compliance with equipment installation and replacement requirements, a leak detection and repair program, notification, reporting, and recordkeeping requirements will constitute compliance with the NSPS. The proposed compressor engines are also subject to the NESHAP for Stationary Reciprocating Internal Combustion Engines located at Area Sources of HAP emissions, 40 CFR Part 63 Subpart ZZZZ. The permit specifies that compliance with the area source NESHAP be maintained at all times. The proposed dehydrators are subject to the NESHAP for Oil and Natural Gas Production Facilities located at Area Sources of HAP emissions, 40 CFR Part 63 Subpart HH. The permit specifies that compliance with the area source NESHAP be maintained at all times. Emission Control Device Requirements The draft permit includes emission control device requirements for certain emission units. Emissions will be controlled using both low emitting process equipment and add-on emission controls. Compressor Engines These units will be lean burn in design to control NO x emissions. The engines will also contain oxidation catalysts to control CO and VOC/HAP/TAC emissions. Dehydrators These units will send flash tank vapors to the hot oil heaters to control VOC/HAP/TAC emissions. Condenser overheads will be sent to the vapor combustors to control VOC/HAP/TAC emissions. Turbines These units will contain dry low-no x burners to control NO x emissions. Hot Oil Heaters These units will contain low-no x burners to control NO x emissions. Amine Treaters These units will send flash vapors to the hot oil heaters to control VOC/HAP/TAC emissions. Amine regenerator stream gases will be sent to the RTOs to control VOC/HAP/TAC emissions. Water and Condensate Tanks - These units will send vapors to the vapor combustors to control VOC/HAP/TAC emissions. Molecular Sieve Regeneration The residue gas used to sweep and purge the molecular sieves during regeneration will send that gas to the emergency flares to control VOC/HAP/TAC emissions.

DCP Midstream, LP Page 16 Testing & Monitoring Requirements The draft permit includes the following emissions testing, monitoring, and recordkeeping requirements: Compressor Engines Emissions testing of a representative engine of each size of the following: NO x, CO, PM2.5, PM10, and VOC, natural gas usage and hours of operation monitoring and recordkeeping, log of maintenance activities, and GHG as CO 2 e emission calculation records. Additional emissions testing and recordkeeping will be required for NSPS JJJJ subject engines. Dehydrators Any monitoring and recordkeeping required by Area Source MACT HH. Turbines Emissions testing of CO, PM2.5, PM10, and VOC, natural gas usage and hours of operation monitoring and recordkeeping, log of maintenance activities, and GHG as CO 2 e emission calculation records. Additional NO x emissions testing of each turbine and fuel total sulfur content monitoring and recordkeeping will be required per NSPS KKKK. Hot Oil Heaters Natural gas usage and hours of operation monitoring and recordkeeping and GHG as CO 2 e emission calculation records. Additional emissions and operating information monitoring and recordkeeping will be required per NSPS Dc. Amine Treaters Testing of VOC emissions and destruction efficiency from the RTOs, combustion chamber temperature monitoring and recordkeeping, and GHG as CO 2 e and SO 2 emission calculation records. Water and Condensate Tanks/Dehydrators - Testing of VOC emissions and destruction efficiency from the vapor combustors and a log of maintenance activities. Flares Monitoring and recordkeeping of residue gas burned. Facility Wide Natural gas usage monitoring and recordkeeping and GHG as CO 2 e, HAP, and benzene emission calculation records. Additional monitoring and recordkeeping will be required per MACT OOOO. Conclusion Based on the analyses conducted to date, staff concludes that the proposed project would comply with all applicable state and federal air quality requirements. Staff also concludes that this project, as proposed, would not violate the federal NAAQS or the federal PSD increments. Based on these conclusions, staff has developed draft permit terms and conditions which would ensure that the proposed facility design and operation are enforceable and that sufficient monitoring, recordkeeping, and reporting would be performed by the applicant to determine compliance with these terms and conditions. If the permit application is deemed approvable, the delegated decision maker may determine a need for additional or revised conditions to address issues raised during the public participation process. If you would like additional information about this proposal, please contact Mr. Jeremy Hoeh, AQD, at 517-241-2194.

DCP Midstream, LP Page 17 State Rule R 336.1201 R 336.1205 R 336.1224 R 336.1225 to R 336.1232 R 336.1279 to R 336.1290 R 336.1301 R 336.1331 R 336.1370 R 336.1401 and R 336.1402 R 336.1601 to R 336.1651 R 336.1702 R 336.1801 R 336.1901 R 336.1910 Appendix 1 STATE AIR REGULATIONS Description of State Air Regulations Requires an Air Use Permit for new or modified equipment that emits, or could emit, an air pollutant or contaminant. However, there are other rules that allow smaller emission sources to be installed without a permit (see Rules 336.1279 through 336.1290 below). Rule 336.1201 also states that the Department can add conditions to a permit to assure the air laws are met. Outlines the permit conditions that are required by the federal Prevention of Significant Deterioration (PSD) Regulations and/or Section 112 of the Clean Air Act. Also, the same types of conditions are added to their permit when a plant is limiting their air emissions to legally avoid these federal requirements. (See the Federal Regulations table for more details on PSD.) New or modified equipment that emits toxic air contaminants must use the Best Available Control Technology for Toxics (T-BACT). The T-BACT review determines what control technology must be applied to the equipment. A T-BACT review considers energy needs, environmental and economic impacts, and other costs. T-BACT may include a change in the raw materials used, the design of the process, or add-on air pollution control equipment. This rule also includes a list of instances where other regulations apply and T-BACT is not required. The ambient air concentration of each toxic air contaminant emitted from the project must not exceed health-based screening levels. Initial Risk Screening Levels (IRSL) apply to cancer-causing effects of air contaminants and Initial Threshold Screening Levels (ITSL) apply to non-cancer effects of air contaminants. These screening levels, designed to protect public health and the environment, are developed by Air Quality Division toxicologists following methods in the rules and U.S. EPA risk assessment guidance. These rules list equipment to processes that have very low emissions and do not need to get an Air Use permit. However, these sources must meet all requirements identified in the specific rule and other rules that apply. Limits how air emissions are allowed to look at the end of a stack. The color and intensity of the color of the emissions is called opacity. The particulate emission limits for certain sources are listed. These limits apply to both new and existing equipment. Material collected by air pollution control equipment, such as dust, must be disposed of in a manner, which does not cause more air emissions. Limit the sulfur dioxide emissions from power plants and other fuel burning equipment. Volatile organic compounds (VOCs) are a group of chemicals found in such things as paint solvents, degreasing materials, and gasoline. VOCs contribute to the formation of smog. The rules set VOC limits or work practice standards for existing equipment. The limits are based upon Reasonably Available Control Technology (RACT). RACT is required for all equipment listed in Rules 336.1601 through 336.1651. New equipment that emits VOCs is required to install the Best Available Control Technology (BACT). The technology is reviewed on a case-by-case basis. The VOC limits and/or work practice standards set for a particular piece of new equipment cannot be less restrictive than the Reasonably Available Control Technology limits for existing equipment outlined in Rules 336.1601 through 336.1651. Nitrogen oxide emission limits for larger boilers and stationary internal combustion engines are listed. Prohibits the emission of an air contaminant in quantities that cause injurious effects to human health and welfare, or prevent the comfortable enjoyment of life and property. As an example, a violation may be cited if excessive amounts of odor emissions were found to be preventing residents from enjoying outdoor activities. Air pollution control equipment must be installed, maintained, and operated properly.