Citizens Opposed to Oil Pollution, Save Union County, and the Sierra Club

Transcription

1 Citizens Opposed to Oil Pollution, Save Union County, and the Sierra Club Comments on Hyperion Energy Center s Amended Prevention of Significant Deterioration Air Quality Pre-Construction Permit Draft Permit # PSD April 1, 2011

2 TABLE OF CONTENTS I. INTRODUCTION AND INTERESTS OF ORGANIZATIONS AS COMMENTERS...1 II. PROCEDURAL BACKGROUND...2 III. LEGAL BACKGROUND...3 IV. THE AMENDED DRAFT PERMIT AND STATEMENT OF BASIS ARE DEFICIENT...4 V. GENERAL ISSUES WITH THE AMENDED DRAFT PERMIT S BACT DETERMINATIONS...10 VI. DISCUSSION OF POTENTIAL TO EMIT AND BACT DETERMINATIONS...27 VII. THE GREENHOUSE GAS BACT ANALYSIS IS DEFICIENT...74 VIII. HYPERION S AIR QUALITY MODELING IS CRITICALLY FLAWED...82 IX. CONCLUSION...97

3 I. INTRODUCTION AND INTERESTS OF ORGANIZATIONS AS COMMENTERS Save Union County, LLC ( Save Union County ), Citizens Opposed to Oil Pollution ( C.O.O.P. ) and the Club (collectively Citizens ) oppose the Amended Draft Prevention of Significant Deterioration ( PSD ) Air Quality Preconstruction Permit for the Hyperion Energy Center ( Facility or the HEC ) issued by the Department of Environment and Natural Resources ( DENR ) on February 14, 2011 ( Amended Draft Permit ) and request that DENR decline to issue a final permit and/or grant any purported request for an extension of the commence construction deadline. In 2008, Citizens provided extensive comments on the original draft PSD permit for the HEC 1 and in 2009, Citizens presented expert testimony in the contested case hearing on that permit. For their comments on the Amended Draft Permit, Citizens hereby incorporate by reference all comments made in their November 13, 2008 comment letter on the original draft PSD permit for the HEC. Citizens also incorporate by reference into their comments the testimony provided by their expert witness, William Powers, at the contested case hearing on June 25, 2009 and June 26, Save Union County is a grassroots organization of over 1,500 members throughout the tri-state area who are opposed to the HEC, which Save Union County believes will have serious and life-threatening consequences to the environment and the present quality of life of its members. Save Union County firmly supports the development of renewable sustainable energy and economic development that is appropriate for and commensurate with our present infrastructure and socio-economic systems. Save Union County has many members who own and rent land near the proposed site for the HEC, many within 2 to 3 miles of the proposed location. Many of Save Union County s members use their land for farming. Save Union County members regularly enjoy fishing, hiking, and other recreational activities at Brule Creek, which runs through the proposed location of the HEC. C.O.O.P. is a cooperative effort of people of all political affiliations, farmers, city dwellers, business leaders, conservationists, and environmentalists who question the logic of locating an oil refinery in South Dakota. As we move forward into the next century, C.O.O.P. would like to see South Dakota lead the way in renewable and alternative energy production and not cling to old polluting technologies like oil. C.O.O.P has approximately 60 members who live in close proximity to the proposed location of the HEC. Many C.O.O.P. members own or rent land within a few miles of the proposed location. The Sierra Club is a national nonprofit organization of approximately 1.4 million members and supporters dedicated to exploring, enjoying, and protecting the wild places of the earth; to practicing and promoting the responsible use of the earth s ecosystems and resources; to educating and enlisting humanity to protect and restore the quality of the natural and human environment; and to using all lawful means to carry out these objectives. The Sierra Club s concerns encompass the goal of achieving a more efficient use of current energy resources, conservation of precious natural resources, development of clean, renewable energy resources, protection of public health and the reduction of greenhouse gas emissions that may result in 1 Citizens Opposed to Oil Pollution, Save Union County, and the Sierra Club, Comments on Hyperion Energy Center s Prevention of Significant Deterioration Pre-Construction Air Quality Permit Application and Draft Permit # PSD, November 13, 2008 (hereinafter Citizens 2008 Comments ).

4 climate change and variability. The Club s particular interest in this case and the issues which the case concerns stem from the impact of the proposed the HEC on each of the concerns just mentioned. In particular, there is concern over the health impacts on individual members of the South Dakota Chapter and its Living River Group, as well as a threatened reduction in the overall quality of life of its members, including but not limited to recreation, economic, and aesthetic interests. The South Dakota Chapter of the Sierra Club has approximately 896 members, 96 of whom make up the Chapter s Living River Group. The Living River Group is based in the town of Vermillion, South Dakota, located less than 10 miles from the site of the proposed HEC. Save Union County, C.O.O.P. and the Sierra Club were granted intervention and the rights of full parties in the contested case hearing on the original PSD permit by order of the Board of Minerals and Environment ( the Board ), dated February 11, In addition, during the first contested case hearing, Hyperion and DENR did not challenge the standing of Save Union County, C.O.O.P. and the Sierra Club in these proceedings. 2 In addition, on June 23, 2010, the Sixth Judicial Circuit Court of South Dakota ( the Court ) ruled that Citizens were parties to any proceedings regarding further changes to Hyperion s original PSD permit, including the contested case hearing scheduled for July 25, II. PROCEDURAL BACKGROUND On August 20, 2009, the Board of Minerals and the Environment approved and issued a PSD permit for the HEC. In September 2009, both Hyperion Energy LLC ( Hyperion or the Applicant ) and Citizens appealed the Board s decision to the Court. On June 1, 2010, after the appeal was fully briefed to the Court, Hyperion asked the Court to send the proceedings back to the Board so that the Board could take additional evidence. Hyperion argued that it needed additional evidence because it would be seeking an extension of the commence construction date in its PSD permit. On June 23, 2010, the Court ordered that the Board should take additional evidence more broadly, specifically ruling that it: Directs the Board of Minerals and Environment to take additional evidence under SDCL , including at least the issues resulting from: Hyperion s request for extension of the construction commencement date established in the permit; the Primary National Ambient Air Quality Standards for Nitrogen Dioxide Final Rule; the Primary National Ambient Air Quality Standard for Sulfur Dioxide Final Rule; the coker quench water tank; and final greenhouse gas rules; and any additional evidence regarding Best Available Control Technology (BACT) determinations, applicable as a result of Hyperion s request for extension of the construction commencement date. 3 2 Transcript of Proceedings, Volume 6, June 24, 2009, p In re PSD Air Quality Permit Application of Hyperion Energy Center, Hyperion Refining LLC, Case No. CIV (June 23, 2010).

5 I. INTRODUCTION AND INTERESTS OF ORGANIZATIONS AS COMMENTERS Save Union County, LLC ( Save Union County ), Citizens Opposed to Oil Pollution ( C.O.O.P. ) and the Club (collectively Citizens ) oppose the Amended Draft Prevention of Significant Deterioration ( PSD ) Air Quality Preconstruction Permit for the Hyperion Energy Center ( Facility or the HEC ) issued by the Department of Environment and Natural Resources ( DENR ) on February 14, 2011 ( Amended Draft Permit ) and request that DENR decline to issue a final permit and/or grant any purported request for an extension of the commence construction deadline. In 2008, Citizens provided extensive comments on the original draft PSD permit for the HEC 1 and in 2009, Citizens presented expert testimony in the contested case hearing on that permit. For their comments on the Amended Draft Permit, Citizens hereby incorporate by reference all comments made in their November 13, 2008 comment letter on the original draft PSD permit for the HEC. Citizens also incorporate by reference into their comments the testimony provided by their expert witness, William Powers, at the contested case hearing on June 25, 2009 and June 26, Save Union County is a grassroots organization of over 1,500 members throughout the tri-state area who are opposed to the HEC, which Save Union County believes will have serious and life-threatening consequences to the environment and the present quality of life of its members. Save Union County firmly supports the development of renewable sustainable energy and economic development that is appropriate for and commensurate with our present infrastructure and socio-economic systems. Save Union County has many members who own and rent land near the proposed site for the HEC, many within 2 to 3 miles of the proposed location. Many of Save Union County s members use their land for farming. Save Union County members regularly enjoy fishing, hiking, and other recreational activities at Brule Creek, which runs through the proposed location of the HEC. C.O.O.P. is a cooperative effort of people of all political affiliations, farmers, city dwellers, business leaders, conservationists, and environmentalists who question the logic of locating an oil refinery in South Dakota. As we move forward into the next century, C.O.O.P. would like to see South Dakota lead the way in renewable and alternative energy production and not cling to old polluting technologies like oil. C.O.O.P has approximately 60 members who live in close proximity to the proposed location of the HEC. Many C.O.O.P. members own or rent land within a few miles of the proposed location. The Sierra Club is a national nonprofit organization of approximately 1.4 million members and supporters dedicated to exploring, enjoying, and protecting the wild places of the earth; to practicing and promoting the responsible use of the earth s ecosystems and resources; to educating and enlisting humanity to protect and restore the quality of the natural and human environment; and to using all lawful means to carry out these objectives. The Sierra Club s concerns encompass the goal of achieving a more efficient use of current energy resources, conservation of precious natural resources, development of clean, renewable energy resources, protection of public health and the reduction of greenhouse gas emissions that may result in 1 Citizens Opposed to Oil Pollution, Save Union County, and the Sierra Club, Comments on Hyperion Energy Center s Prevention of Significant Deterioration Pre-Construction Air Quality Permit Application and Draft Permit # PSD, November 13, 2008 (hereinafter Citizens 2008 Comments ). 1

6 climate change and variability. The Club s particular interest in this case and the issues which the case concerns stem from the impact of the proposed the HEC on each of the concerns just mentioned. In particular, there is concern over the health impacts on individual members of the South Dakota Chapter and its Living River Group, as well as a threatened reduction in the overall quality of life of its members, including but not limited to recreation, economic, and aesthetic interests. The South Dakota Chapter of the Sierra Club has approximately 896 members, 96 of whom make up the Chapter s Living River Group. The Living River Group is based in the town of Vermillion, South Dakota, located less than 10 miles from the site of the proposed HEC. Save Union County, C.O.O.P. and the Sierra Club were granted intervention and the rights of full parties in the contested case hearing on the original PSD permit by order of the Board of Minerals and Environment ( the Board ), dated February 11, In addition, during the first contested case hearing, Hyperion and DENR did not challenge the standing of Save Union County, C.O.O.P. and the Sierra Club in these proceedings. 2 In addition, on June 23, 2010, the Sixth Judicial Circuit Court of South Dakota ( the Court ) ruled that Citizens were parties to any proceedings regarding further changes to Hyperion s original PSD permit, including the contested case hearing scheduled for July 25, II. PROCEDURAL BACKGROUND On August 20, 2009, the Board of Minerals and the Environment approved and issued a PSD permit for the HEC. In September 2009, both Hyperion Energy LLC ( Hyperion or the Applicant ) and Citizens appealed the Board s decision to the Court. On June 1, 2010, after the appeal was fully briefed to the Court, Hyperion asked the Court to send the proceedings back to the Board so that the Board could take additional evidence. Hyperion argued that it needed additional evidence because it would be seeking an extension of the commence construction date in its PSD permit. On June 23, 2010, the Court ordered that the Board should take additional evidence more broadly, specifically ruling that it: Directs the Board of Minerals and Environment to take additional evidence under SDCL , including at least the issues resulting from: Hyperion s request for extension of the construction commencement date established in the permit; the Primary National Ambient Air Quality Standards for Nitrogen Dioxide Final Rule; the Primary National Ambient Air Quality Standard for Sulfur Dioxide Final Rule; the coker quench water tank; and final greenhouse gas rules; and any additional evidence regarding Best Available Control Technology (BACT) determinations, applicable as a result of Hyperion s request for extension of the construction commencement date. 3 2 Transcript of Proceedings, Volume 6, June 24, 2009, p In re PSD Air Quality Permit Application of Hyperion Energy Center, Hyperion Refining LLC, Case No. CIV (June 23, 2010). 2

7 On the same day as the Court s order, Hyperion filed with DENR an Application for Extension of Commence Construction Date, initiating the current proceedings. Between at least June 23, 2010 and February 7, 2011, Hyperion and DENR exchanged information regarding Hyperion s request for changes to its original PSD permit. On February 14, 2011, DENR posted the Amended Draft Permit and its Statement of Basis and sought public comments on these documents. On March 10, 2011, DENR extended until April 1, 2011, the deadline for submission of public comments. III. LEGAL BACKGROUND A. State And Federal Requirements The Clean Air Act ( CAA or the Act ) was written to protect and enhance the quality of the nation s air so as to promote the public health and welfare and the productive capacity of its population. 4 As directed by Section 109 of the Act, 42 U.S.C. 7409, the U.S. Environmental Protection Agency ( EPA ) has established National Ambient Air Quality Standards ( NAAQS ) to protect human health and the environment for seven criteria pollutants, including sulfur dioxide ( SO 2 ), nitrogen oxides ( NOx ), particulate matter, carbon monoxide ( CO ), and ozone. 5 Under section 107(d) of the Act, 42 U.S.C. 7407(d), each state must designate those areas in its territory where the air quality is better or worse than the NAAQS for each criteria pollutant, or where the air quality cannot be classified because of insufficient data. An area that meets the NAAQS for a particular criteria pollutant is an attainment area for that pollutant. Under section 110(a) of the Act, 42 U.S.C. 7410(a), states are responsible for implementing many of the regulatory requirements of the Act, including provisions of the PSD program, through State Implementation Plans ( SIPs ). SIP provisions must satisfy the requirements of the Act before they are approved by EPA. 6 Part C of subchapter I of the Act, 42 U.S.C (the PSD program ), sets out requirements for the prevention of significant deterioration of air quality in areas designated as attainment areas. The purpose of these requirements is to protect public health and welfare, to ensure that economic growth will occur in a manner consistent with the preservation of existing clean air resources, and to assure that any decision to permit increased air pollution is made only after careful evaluation of all the consequences of such a decision and after adequate procedural opportunities for informed public participation in the decision making process. 7 Section 165(a) of the Act, 42 U.S.C. 7475(a), prohibits the construction and operation of a major emitting facility in an attainment area unless a permit has been issued that contains emissions limitations that comply with the requirements of section 165. Section 165 includes several requirements. First, the owner or operator of the facility must show that emissions from construction or operation of such facility will not cause, or contribute to, air pollution in excess of (A) maximum allowable increase for any pollutant in 4 42 U.S.C. 7401(b)(1) (2008) C.F.R. pt. 50 (2008). 6 See 42 U.S.C. 7410(k); see also 40 C.F.R (PSD); 40 C.F.R (NNSR) U.S.C

8 any area to which this part applies more than one time per year; (B) [NAAQS] in any air quality control region; or (C) any other applicable emission standard or standard of performance under this chapter. 8 Second, the facility must install the best available control technology ( BACT ) for each pollutant subject to regulation under the Act that is emitted from the facility. 9 Third, the facility must analyze any air quality impacts projected for the area as a result of growth associated with such facility. 10 Fourth, if the owner or operator of the proposed facility is notified that emissions from the proposed facility may cause or contribute to a change in the air quality in [a Class I PSD] area, that owner or operator must demonstrate that emissions of particulate matter and sulfur dioxide will not cause or contribute to concentrations which exceed the maximum allowable increase for a class I area. 11 Finally, the owner or operator of the proposed facility must agree to conduct such monitoring as may be necessary to determine the effect which emissions from any such facility may have on air quality in any area which may be affected by emissions from such source. 12 South Dakota s federally approved SIP implements, with minimal exception, the PSD provisions of the Act in South Dakota. 13 Since Hyperion received its original PSD permit, EPA has promulgated several new air quality rules. On February 9, 2010, EPA issued a final rule establishing a new 1-hour NAAQS for NO On June 3, 2010, EPA issued a final rule addressing BACT requirements for greenhouse gases. 15 On June 22, 2010, EPA issued a final rule establishing a new 1-hour 16 NAAQS for SO 2. IV. THE AMENDED DRAFT PERMIT AND STATEMENT OF BASIS ARE DEFICIENT Due to deficiencies in the original PSD permit and Hyperion s request to extend the commence construction deadline of that permit, Hyperion is now seeking issuance of a new PSD permit. Although Hyperion and DENR characterize this new permit as an extension request, the fact remains that DENR is proposing to issue a new PSD permit with new language, based on a new, albeit inadequate review, for additional equipment and applying new federal rules, almost two years after the initial PSD permit was issued. As explained above, no major emitting facility may be constructed unless the proposed facility is subject to the best available control technology for each pollutant subject to regulation 8 42 U.S.C. 7475(a)(3) U.S.C. 7475(a)(4); see also 40 C.F.R (b)(12) U.S.C. 7475(a)(6) U.S.C. 7475(d)(2)(C)(i); see also 40 C.F.R (b)(29) U.S.C. 7475(a)(7). 13 See S.D. Admin. R. 74:36:09:02; Approval and Promulgation of Air Quality Implementation Plans; South Dakota, 72 Fed. Reg. 72,617 (Dec. 21, 2007). 14 Primary National Ambient Air Quality Standard for Nitrogen Dioxide, 75 Fed. Reg. 6,474 (February 9, 2010). 15 Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, 75 Fed. Reg. 31,514 (June 3, 2010). 16 Primary National Ambient Air Quality Standard for Sulfur Dioxide, 75 Fed. Reg. 35,520 (June 22, 2010). 4

9 under this chapter emitted from, or which results from, such facility. 17 The process used by DENR to evaluate Hyperion s new application does not ensure that BACT has been properly applied to the HEC because DENR treated the application as a construction extension and performed only a limited evaluation. In reality, the changes proposed by Hyperion go far beyond a simple construction deadline extension and instead are fundamental changes to its PSD permit. 18 Under EPA guidance, a change to a PSD permit is a fundamental change, requiring a new permit, if the proposed revisions change the fundamental nature of a portion of the source. 19 As discussed below, among other changes, Hyperion has identified an entirely new emission source a coker quench water tank to its PSD permit. The changes proposed by Hyperion are significant, requiring that Hyperion apply for a new permit that is then fully evaluated as required under South Dakota and federal law. Additionally, regardless of how the changes to Hyperion s PSD permit are classified, it cannot be disputed that the new or any revised permit must ensure that the HEC applies BACT and complies with all air quality requirements in effect at the time the new or revised permit is issued. 20 One of the central provisions of the Clean Air Act is its requirement that facilities implement the best control technology available at the time the permit is issued. DENR has acknowledged in its Statement of Basis that Hyperion s BACT analysis must be re-analyzed. However, as discussed below, Hyperion and DENR s re-analysis falls short of what is required under the law. A. The Amended Draft Permit Relies On An Ill-Defined Project Description For The Facility According to DENR, the Facility consists of a refinery that will process 400,000 barrels per day ( bbl/day ) of crude oil and 26,000 bbl/day of butane and an integrated gasification combined cycle ( IGCC ) power plant, which will provide the refinery with up to 450 million cubic feet per day ( MMcf/day ) of hydrogen, 200 megawatts ( MW) worth of electricity, and 2.4 million pounds ( MMlb ) of steam per hour. 21 The Facility will include dozens of individual emission units and control equipment and thousands of connectors, valves, compressors, process drains, etc., which will emit criteria air pollutants, greenhouse gases and hazardous air pollutants. Yet, the application materials provided by Hyperion include only cursory descriptions of the Facility s processes, emissions units and control equipment, insufficient to verify the presented BACT emission limits and emission estimates and accompanying ambient air quality modeling that are part of this PSD permit. For example, the Applicant did not provide a to-scale project design layout that identifies the location of individual emission units; the only layout information we could find in the permit U.S.C. 7475(a)(4). 18 See July 5, 1985 EPA memorandum from Daryl D. Tyler, Director Control Programs Development Division to Directors, Air Divisions Region I-X. 19 Id. at See, e.g., In re Vulcan Const. Materials, LP, PSD Appeal No , decided March 2, Statement of Basis, p. 1. 5

10 record is an aerial overview projection 22 and a diagram showing the construction boundaries. 23 Neither of these diagrams identifies the individual emissions units or control devices. Similarly, the Applicant provided 36 process flow charts for the Facility; 24 not one of them includes any information on material throughput or discharges. Materials, water or energy balances are also nowhere to be found in the permit record. Both the refinery processes and the IGCC power plant have extensive cooling needs, which, according to the Amended Draft Permit are met by one 13-cell 130,000-gallons per minute ( gpm ) wet cooling tower (Unit #41). 25 Yet, neither the application materials nor the Amended Draft Permit provide any information on how this cooling tower was sized to meet the Facility s cooling demand. The December 2007 Application states that both the refinery processes and the IGCC power plant will make extensive use of air coolers. 26 However, even with the proposed extensive use of air coolers, it appears questionable that the cooling needs of both the refinery and the IGCC power plant of the size proposed here could be met by one cooling tower with a circulating capacity of 130,000 gpm alone. Because Hyperion failed to produce heat and water balances for the HEC, it is impossible to verify whether the proposed cooling tower indeed satisfies the cooling demands of both the refinery and the IGCC power plant or whether Hyperion accidentally omitted specifying a separate cooling tower for the IGCC power plant. The Applicant must be in possession of detailed information regarding the throughput and other parameters in order to size the Facility s numerous processes and calculate and model its emissions: For example, the Applicant provides estimates for fugitive emissions from thousands of individual components. 27 Clearly, the number of individual connectors, valves, compressors, process drains, etc. can only be determined if the location of individual emission units and their throughput and discharge is known. Similarly, the Applicant sizes pollution control equipment, e.g., the acid gas removal ( AGR ) system for the power island or the thermal oxidizers for the sulfur recovery plant, based on the throughput and characteristics of materials that would be processed in these units. Any information used for estimating emissions or ambient air quality modeling that would influence their results, must be made part of the permit. 22 Hyperion Contested Case Hearing Exhibit Hyperion Contested Case Hearing Exhibit Hyperion Refining LLC, Hyperion Energy Center, Prevention of Significant Deterioration (PSD) Permit Application, December 2007 (hereinafter December 2007 Application ),, Appendix B Process Flow Diagrams. 25 Amended Draft Permit, Table 1-1, p December 2007 Application, p December 2007 Application, Appendix C Equipment Leaks. 6

11 B. The 2011 Statement Of Basis Fails To Provide A Revised Potential To Emit For The Facility It is axiomatic that an application for a pre-construction PSD permit must identify, quantify, and analyze all emissions from the proposed new facility. 28 Hyperion must identify all potential emission sources and all types of emissions coming from the Facility s emission sources. 29 Only after Hyperion identifies all potential emission sources associated with the Facility can the applicant determine the facility s potential to emit regulated pollutants, as required under the CAA. 30 The federal regulations define potential to emit as: the maximum capacity of a stationary source to emit a pollutant under its physical and operational design. Any physical or operational limitation on the capacity of the source to emit a pollutant, including the type or amount of material combusted, stored, or processed, shall be treated as part of its design only if the limitation or the effect it would have on emissions is federally enforceable. EPA guidelines clarify that PTE is a worst-case accounting of the maximum amount of emissions a facility could emit, given its physical and operational design. 31 Further, [t]he definition of potential to emit under the new source regulations is extremely important. 32 All emissions not just selected ones count towards a facility s potential to emit. For purposes of the definition [of major source ], all emissions of listed pollutants are counted from a group of sources within a plant boundary This is to assure that emissions from the facility as a whole are adequately controlled. 33 After determining the potential to emit, an applicant must identify all potential emission sources in order to know which sources require a BACT analysis. 34 Additionally, an applicant must identify all potential emission sources during construction and operation of the facility and analyze emissions from those sources in order to satisfy air quality modeling requirements under the CAA. 35 DENR s engineering evaluation for the HEC s original draft PSD permit ( 2008 Statement of Basis ) identifies the Facility s potential emissions of regulated air pollutants for purposes of New Source Review ( NSR ), i.e., its potential to emit ( PTE ), and C.F.R 52.21(n) C.F.R (a)(2)(i); 52.21(b)(1); 52.21(b)(4-6); SD Code 74:36:10: C.F.R (b)(4). 31 EPA Memorandum from Steven Riva to William O Sullivan, Accounting for Emergency Generators in the Estimate of Potential to Emit, at 2 (Feb. 14, 2006) (hereafter Riva Memo ). 32 EPA Memorandum from Terrell E. Hunt and John S. Seitz to Regional Counsels, Guidance on Limiting Potential to Emit in New Source Permitting (June 13, 1989) (hereafter Hunt Memo ) (emphasis added). 33 Nat l Mining Ass n v. EPA, 59 F.3d 1351, 1359 (D.C. Cir. 1995) (fugitive emissions must count towards a facility s emissions totals) C.F.R (j)(2) U.S.C. 7475(a)(3) (recognizing that an applicant must demonstrate that emissions from construction or operation of a facility will not cause or contribute to air pollution in excess of applicable standards); 40 C.F.R (k). 7

12 compares them to the respective significant emission rates. 36 The DENR s engineering evaluation for the Amended Draft Permit ( 2011 Statement of Basis ) 37 does not provide an updated estimate of the Facility s PTE, even though the PSD Permit purports to address emissions from the coker quench water handling system. Each permit revision must contain an updated PTE which will serve as the baseline to determine whether any future modifications of the Facility will be major. Under the Act, determining a source s PTE is necessary for the Agency to identify which sources are major sources subject to regulation under the applicable PSD requirements Hyperion Did Not Provide Any Information Regarding The Crude Oil Or Petcoke Composition; Without This Information DENR Cannot Accurately Determine The HEC s Potential To Emit. Hyperion did not provide any information regarding the composition of the crude oil that the refinery is going to process or the petcoke the integrated gasification combined cycle ( IGCC ) plant is going burn. The design of the refinery and the IGCC plant and their emissions allowed under the permit depend an accurate account of a facilities potential to emit. Without understanding the composition of the crude the refinery will process or petcoke the IGCC plant will burn, it is impossible to determine mass-balance of the pollutants entering and leaving the refinery (such as SO 2 or other sulfur compounds, as well as numerous metals) or the IGCC plant. For instance, emissions depend on the processing of the crude and its resultant crude-derived products in the refinery. The composition of the crude (including parameters such as its sulfur content, its acid content, its metal content and others) will determine the severity of the processing anticipated and therefore the potential emissions of certain pollutants. The Application simply does not provide any information regarding the crude or petcoke composition; therefore precluding an accurate projection of potential to emit. Without information regarding the crude or petcoke chemical composition, it was impossible for DENR to conduct a meaningful review under the Clean Air Act. As a simple example, if DENR cannot validate the emissions estimates provided by Hyperion, then it cannot determine if appropriate maximum emissions inputs were used in the air quality modeling analyses, risk analyses, etc. Without appropriate maximum emission inputs, DENR cannot verify that the appropriate control technologies are in place e.g. does the Hyperion permit need to required sulfur restrictions on the feedstock to ensure that emission limits are met. If the State cannot evaluate the accuracy of Hyperion s emissions estimates or air quality impact analyses, then it cannot adequately review whether the Hyperion Energy Center would lead to an exceedance of the NAAQS or PSD increments and thus lawfully issue a PSD permit. 36 South Dakota Department of Environment and Natural Resources, Statement of Basis, Prevention of Significant Deterioration Permit # PSD, Hyperion Energy Center, Near Elk Point, Union County, South Dakota, Table 7-1, p South Dakota Department of Environment and Natural Resources, Statement of Basis, Construction Deadline Extension Request for the Prevention of Significant Deterioration Permit # PSD, Hyperion Energy Center, Near Elk Point, Union County, South Dakota. 38 Id.; see also Ass n of Irritated Residents v. Fred Schakel Dairy, Case No. CIV F AWI SMS, 2005 U.S. Dist. LEXIS (E.D. Cal. Dec. 2, 2005). 8

13 2. Hyperion Did Not Include Emissions From Refinery Flares That Malfunction; Without This Information DENR Cannot Accurately Determine The HEC s Potential To Emit. The application provides no information on the emissions of regulated New Source Review ( NSR ) pollutants from the flares other than the flare pilot gas combustion. Hyperion only calculated emissions from the pilot flames of the refinery flares, not emissions from flaring events, because Hyperion claims that it will not flare at the Hyperion Energy Center refinery except in emergency situations. Consequently, there is no clearly ascertainable basis for concluding that the emissions estimate represents, the maximum capacity of the source to emit a pollutant under its physical and operational design. 39 EPA guidelines clarify that PTE is a worst-case accounting of the maximum amount of emissions a facility could emit, given its physical and operational design. 40 That is why EPA has consistently advised states over the last twenty years that an applicant must include start-up, shut-down, and malfunctions emissions in its potential to emit. 41 In fact, EPA guidance has specifically stated that malfunctions are included in potential to emit estimates: to determine PTE, a source must estimate its emissions based on the worst-case scenario taking into account startups, shutdowns and malfunctions. 42 C. Hyperion Did Not Include Emissions From Support Facilities; Without This Information, DENR Cannot Accurately Determine The Facility s Potential To Emit Hyperion did not provide any information regarding emissions from the numerous facilities that would support at the HEC. Without emission estimates for these facilities it is impossible to accurately project the HEC s potential to emit. For instance, Hyperion refused to disclose the emissions from the pipeline pumping stations. The pipeline from Alberta, Canada, which brings the heavy Canadian crude into the storage tanks at the Facility, and the refined products pipeline, which transports the liquid fuels leaving the refinery will have air emissions associated with them. 43 These pipelines will hook up to the Facility and are dedicated to supplying the Facility with feedstock and to transporting refined product to market. 44 DENR did not require Hyperion to submit information concerning the air emissions from the heavy Canadian crude pipeline, 45 and Hyperion s application did not quantify the air emissions from either the heavy Canadian crude pipeline or the refined products pipeline identified in Hyperion s Application. 46 In addition, Hyperion did not quantify the emissions from the water wells associated with 39 See 40 C.F.R (a)(1); ARSD 74:36:10: See Riva Memo. 41 See In re Tallmadge, 2003 WL at p *8-9 (collecting sources). 42 See Riva Memo at 2 (emphasis added). 43 Transcript of Proceedings, Volume 1, May 19, 2009, p Transcript of Proceedings, Volume 1, May 19, 2009, p ; Volume 3, May 21, 2009, p Transcript of Proceedings, Volume 6, June 24, 2009, p Transcript of Proceedings, Volume 1, May 19, 2009, p

14 this facility. The Facility will require 12 million gallons of water per day for operational purposes. 47 To obtain these 12 million gallons per day, Hyperion plans to access and use shallow wells located approximately 10 miles south of the Facility along the Missouri River. 48 Running pumps used to obtain the groundwater from wells will create air emissions, none of which are quantified or identified in Hyperion s Application. 49 DENR must determine the Facility s potential to emit, including its support facilities. Potential to emit means the maximum capacity of a stationary source to emit a pollutant under its physical and operational design. Any physical or operational limitation on the capacity of the source to emit a pollutant, including the type or amount of material combusted. Under EPA s support facility test, for the purpose of determining total emissions, even where there are two or more industrial groupings at a commonly owned facility, these groupings should be considered together if the output of one is more than 50 per cent devoted to support of another. 50 EPA s current interpretation under the CAA is that if one facility contributes 50% or more of its output to another facility, both facilities should be treated as a single source in a PSD analysis. Likewise, if one facility receives more than 50% of its input from another facility, both facilities should be treated as a single source. 51 Hyperion failed to establish that these emission sources were not support facilities; therefore, Hyperion failed to fulfill its burden of proving that all facility emissions are considered in the permit application. Finally, without information regarding emissions from support facilities, it is impossible for DENR to conduct a meaningful review under the Clean Air Act. Without information regarding these emissions, the State cannot evaluate the accuracy of Hyperion s emissions estimates or air quality impact analyses and thus, preventing the agency from determining whether the Facility would lead to an exceedance of the NAAQS or PSD increments and, thus, cannot lawfully issue a PSD permit. V. GENERAL ISSUES WITH THE AMENDED DRAFT PERMIT S BACT DETERMINATIONS A new major source of air pollution proposed to be constructed in an area that is in attainment with all NAAQS is subject to the Act s PSD permitting requirements. One of the principal requirements of the PSD regulations is that the major source must install and operate state-of-the-art pollution controls, known as best available control technology ( BACT ) for each pollutant subject to regulation under the Act Transcript of Proceedings, Volume 1, May 19, 2009, p Id. 49 DENR Contested Case Hearing Exhibit 23; Transcript of Proceedings, Volume 1, May 19, 2009, p See EPA Proposed Interim Approval of West Virginia Operating Permits Program, 60 Fed. Reg , (Aug. 29, 1995) (emphasis added); see also Requirements for Preparation, Adoption, and Submittal of Implementation Plans, 45 Fed. Reg , (Aug. 7, 1980). 51 See January 13, 1997 letter from Cheryl L. Newton, EPA Region V to Paul Dubenetzky, Indiana Department of Environmental Management U.S.C. 7475(a)(4). 10

15 To ensure that the BACT determination is reasonably moored to the Clean Air Act s statutory requirement that BACT represent the maximum achievable reduction, EPA has established a top-down analysis process that is described in the so-called NSR Manual. 53 This guidance is widely used by permitting engineers and agencies to make BACT determinations and by the EAB in deciding appeals of PSD cases. 54 The top-down BACT analysis methodology is standard operating procedure. For example, a PSD permit was remanded to Michigan s Department of Environmental Quality for failing to follow the NSR Manual. 55 The NSR Manual details the necessary process for determining top-down BACT, as required by 42 U.S.C This five-step process is conducted to ensure that a valid BACT determination has been made: STEP 1: Identify all control technologies. This list must be comprehensive and include all lowest achievable emission rates ( LAER ). STEP 2: Eliminate technically infeasible options. A demonstration of technical infeasibility should be clearly documented and must show, based on physical, chemical, and engineering principles, that technical difficulties would preclude the successful use of the control option on the emissions unit under review. STEP 3: Rank remaining control technologies by control effectiveness. This includes: control effectiveness (percent pollutant removed); expected emission rate (tons per year and pounds per hour); expected emission reduction (tons per year); energy impacts; environmental impacts (other media and the emissions of toxic and hazardous air emissions); and economic impacts (total cost effectiveness, incremental cost effectiveness). 53 U.S. Environmental Protection Agency, New Source Review Workshop Manual, Prevention of Significant Deterioration and Nonattainment Area Permitting, Draft, October 1990 ( NSR Manual ); see Alaska Dept. of Envt l Conservation v. Envt l Protection Agency, 540 U.S. 461, 485 (2004). 54 See, for example, In re Northern Michigan University Ripley Heating Plant, PSD Appeal No (EAB, 2/18/09); In re Columbia Gulf Transmission Co., 2 E.A.D. 824 (Adm r 1989); In re Inter-Power of New York, Inc., 5 E.A.D 130 (EAB 3/16/94); Steel Dynamics, 9 E.A.D. 165 (EAB, 6/22/10); In re Masonite Corp., 5 E.A.D. 551 (EAB, 11/1/94). EAB decisions are available at 55 In re Northern Michigan University Ripley Heating Plant, PSD Appeal No (EAB, 2/18/09) p. 1: The Board finds that in analyzing this issue [BACT for SO 2 ], MDEQ failed to follow the U.S. Environmental Protection Agency s New Source Review Manual or any other method faithful to statutory and regulatory guidelines. ; p. 16: The alignment between the NSR Manual and NMU s BACT analysis, as approved by MDEQ, is, at best, imperfect. 11

16 STEP 4: Evaluate most effective controls and document results. This must include a case-by-case consideration of energy, environmental, and economic impacts. If top option is not selected as BACT, evaluate next most effective control option. STEP 5: Select BACT. The most effective option not rejected is BACT. 56 In a typical BACT process, the Applicant prepares an initial analysis that is submitted to the permitting agency. The agency reviews the analysis, requests additional information, conducts independent analyses, and makes an independent determination. A draft permit is then prepared based on the BACT analysis that is reviewed by the Applicant and the public. The permitting agency reviews and responds to comments received on its draft determination and issues a final BACT determination, which is subject to EPA s review and oversight. The Department s analyses do not satisfy the definition of BACT and the top-down BACT process for numerous reasons including: (1) failure to adequately document BACT decisions; (2) failure to evaluate all control options; (3) failure to establish enforceable conditions; (4) failure to establish averaging times; (5) failure to document the reason proposed monitoring assures continuous compliance; and (6) omission of regulated PSD pollutants, among others. The following section discusses generic problems that are present in the BACT determinations for almost all of the Facility s sources. A. The Organization Of The Department s BACT Determinations Is Overly Complicated In its application and supplements, Hyperion followed a five-step top-down method as described in the NSR Manual to determine BACT, organized by (1) each of the Facility s identified emission units and subsequently (2) their respective pollutant emissions. 57 The Department s 2008 Statement of Basis and the Amended Draft Permit turned this approach on its head and reorganized the BACT determinations (1) by pollutant and subsequently (2) by type of equipment emitting a particular pollutant. The Department s approach is difficult to follow as it disassociates the description of an emission unit and the type of pollutants it emits with their respective BACT determinations. In order to verify that the Amended Draft Permit s BACT determinations address all pollutants emitted from a specific emission source, the reviewer has to check each BACT pollutant section to confirm that all emission units were adequately addressed. Exacerbating deficiencies in the analysis, the BACT re-analysis presented in the 2011 Statement of Basis follows the Applicant s original approach and is organized by (1) the types of equipment and (2) for each of its pollutant emissions; thereby unnecessarily complicating any comparison with the prior version of the Department s engineering evaluation or the Amended Draft Permit. 56 See NSR Manual, Table B December 2007 Application, pp

17 Further, the Department s engineering evaluations did not follow the above described five-step approach but rather an ill-defined four-step approach that leaves out most of the necessary details for a standalone BACT determination and makes it difficult to reconcile the Applicant s BACT determination with the Department s revisions. Finally, a BACT determination consists of three parts: (1) the emission limitation; (2) the control technology that the limitation is based on; and (3) the compliance provisions. Here, none of these parts is found in the same place in the Amended Draft Permit, creating significant ambiguity. For example, the emission limitations in the Amended Draft Permit are found in Chapter 4, Sections 4-1 through 4-11; the control technology that the limitation is based on is found in Chapter 1, Table 1-1; and the compliance provisions are specified in Chapters 5 and 11 through 13, and cross-referenced in Tables 4-1 through 4-8 and their footnotes. This scattered approach makes the Amended Draft Permit and its supporting engineering evaluations difficult to follow. B. The Amended Draft Permit Fails To Address PM2.5 As A Separate PSD Pollutant The Amended Draft Permit does not contain a BACT emission limit for particulate matter with an aerodynamic diameter equal to or smaller than 2.5 micrometers ( PM2.5 ), or fine particulate matter, as required by law. The Amended Draft Permit contains neither PM2.5 BACT limits nor limits on PM2.5 precursors based upon a PM2.5 BACT determination. When EPA established NAAQS for PM2.5in 1997, this triggered the duty to apply the PSD requirements to fine particulate matter. Because the HEC is a major source of PM2.5, DENR should not permit the HEC without: (1) a demonstration that its PM2.5 emissions would not cause or contribute to air pollution in excess of the PM2.5 NAAQS or increment; and (2) a BACT limit for PM2.5. Although in the past, permitting authorities used particulate matter with an aerodynamic diameter equal to or smaller than 10 micrometers ( PM10 ) as a surrogate for direct limits for PM2.5, that is no longer a valid argument. As the EAB recently explained, the technical difficulties in calculating PM2.5 emissions have now been largely resolved, which eliminated, in large part, the basis for using PM10 as a surrogate for PM The EAB also explained that, even if a surrogacy analysis were appropriate [there must be a] degree of specificity necessary to support the conclusion that PM10 serves as an appropriate surrogate for PM2.5 emissions. 59 Neither Hyperion nor DENR have made such a specific showing to justify the use of PM10 as a surrogate for PM2.5 in the Amended Draft Permit. Therefore, the PM surrogacy policy cannot be used for the HEC permit. The failure to include a BACT emission limit for PM2.5 is a serious deficiency in the Amended Draft Permit. 58 In re Vulcan Constr. Materials, LP, PSD Appeal No , at 12, (EAB, March 2, 2011). 59 Id. at 14. D.C. Circuit cases addressing particulate matter surrogacy also allow use of PM10 as a surrogate only based on a rigorous factual analysis demonstrating that it is a reasonable approach under the circumstances. Compare Am. Trucking Ass n v. EPA, 175 F.3d 1027, 1054 (D.C. Cir. 1999) (finding that PM10 was an arbitrary indicator for coarse PM), rev d on other grounds, with Am. Farm Bureau v. EPA, 559 F.3d 512, (D.C. Cir. 2009) (finding that EPA offered adequate factual and scientific justification to use PM10 as an indicator for coarse PM under the circumstances of that case). 13

18 C. The Amended Draft Permit Fails To Conduct A BACT Analysis For Total Reduced Sulfur Total Reduced Sulfur ( TRS ) is subject to PSD review if emissions exceed the significance threshold of 10 tons per year ( ton/yr ). DENR recognizes that the Facility would emit 25 ton/yr of TRS 60, triggering PSD review. Therefore, a BACT analysis is required to establish an emission limitation based on the maximum degree of reduction that is feasible and compliance procedures. Yet, the Amended Draft Permit fails to set BACT limits or require monitoring for TRS. The 2008 Statement of Basis explains that because TRS is primarily composed of hydrogen sulfide it was included with the hydrogen sulfide discussions. 61 This is not acceptable nor is it further explained or justified in the 2011 Statement of Basis. In addition to H 2 S, TRS includes a number of other reduced sulfur compounds including, e.g., methyl mercaptan, dimethyl sulfide, dimethyl disulfide, carbonyl sulfide, and other organic sulfides. Thus, emissions of total reduced sulfur can be higher than H 2 S emissions and must therefore be addressed separately. The Amended Draft Permit contains BACT limits and requires source testing for H 2 S emissions from the coke drums (Units #34 and #35), the refinery flares (Units #36 through 40), the sulfur recovery plant thermal oxidizers (Units # 42a and 42b), and the gasification flare (Unit #50) and H 2 S CEMS for the power island AGR (Unit #59). 62 The Amended Draft Permit should be revised to include a separate top-down BACT analysis for TRS emissions from these units and require adequate monitoring and reporting procedures. Because reduced sulfur compounds can leak from heat exchangers into the cooling water, a BACT analysis must also be conducted for the Facility s cooling tower and adequate compliance procedures specified. D. BACT For Sulfuric Acid Mist Sulfuric acid mist ( SAM ), is a PSD pollutant. If the significance threshold of 7 ton/yr is exceeded, it is subject to PSD review, including a BACT determination. The emission calculations indicate that 80 ton/yr will be emitted, 63 triggering PSD review for SAM. This requires a BACT analysis to establish an emission limitation based on the maximum degree of reduction that is feasible and compliance procedures. The application and supplements and the DENR s engineering evaluations fail to make a BACT determination for SAM, set emission limitations for SAM, or require any compliance monitoring for SAM. Instead, DENR concludes with no analysis or support that the BACT analysis for sulfur dioxide would be the same for sulfuric acid mist. 64 This is inconsistent with Statement of Basis, Table 7-1, p Statement of Basis, p Draft Permit, p Statement of Basis, p Statement of Basis, pp

19 the surrogacy policy set out in the EAB s ruling in the Vulcan case 65 and EPA s decision in the Louisville Gas case, 66 which conclude that to establish surrogacy between two pollutants (PM10 and PM2.5 in those cases), the source or permitting authority must establish a strong statistical relationship between the two parameters in the permit record or in the alternative, that the degree of control achieved for, say, SO 2, would be at least as effective as the degree of control for the other, SAM. Neither of these conditions has been met here. The Amended Draft Permit sets the BACT emission limits for SAM equal to the BACT emission limits for SO This is a flagrant violation of the PSD regulations, which regulate SO 2 and SAM as separate pollutants. Further, BACT for SO 2 does not satisfy BACT for SAM; SO 2 emissions do not equal SAM emissions; and SO 2 and SAM emissions are not correlated. 1. Sulfur Dioxide Is Not A Replacement For Sulfuric Acid Mist Sulfur dioxide and sulfuric acid mist are recognized as separate pollutants under the law due to their distinguishable physical and chemical characteristics, health effects, and pollution controls. The record contains no basis for asserting that BACT for SO 2 satisfies BACT for SAM. Sulfur in refinery fuel gas is present as a mixture of various reduced sulfur and organic sulfur compounds. During combustion in the heaters, flares, turbines, and thermal oxidizers virtually all of the sulfur is oxidized to gaseous species such as SO 2 and sulfur trioxide ( SO 3 ), with SO 2 being the principal oxide. The SO 3 combines with water in the exhaust gases and is converted into very small liquid droplets of sulfuric acid ( H 2 SO 4 ), called sulfuric acid mist or SAM, before it leaves the stack. 68 The total amount of sulfur in the exhaust gases is constant at any given instant, but contains different amounts of SO 2 and SO 3 depending upon many complex factors, including combustion temperature, fuel to oxygen ratio, composition of the fuel gas, surface area of heat exchangers, and materials of construction of the burners and heater internals (i.e., metals may catalyze the oxidation of SO 2 to SO 3 ). 69 This makes any prediction of one from the other with information available in the pollution control context essentially impossible. 65 In re Vulcan Constr. Materials, LP, PSD Appeal No , at 12, (EAB, March 2, 2011). 66 In re Louisville Gas and Electric Co., Petition No. IV-20083, Order Responding to Issues Raised in April 28, 2008 and March 2, 2006 Petition, and Denying in Part and Granting in Part Requests for Objection to Permit (Adm r Aug. 12, 2009). Available at: 67 Amended Draft Permit, Sec. 4.6, pp Charles E. Baukal, Jr. and Robert E. Schwartz (Eds.), The John Zink Combustion Handbook, CRC Press, 2001, p. 539; R.K. Srivastava and others, Emissions of Sulfur Trioxide from Coal-Fired Power Plants, J. Air & Waste Manage. Assoc., June 2004, v. 54, pp , p. 750 (Exhibit 1); EPRI, Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, Version 2010a, Technical Update, April 2010, p. 3-3; J.I. Gmitro and T. Vermeulen, Vapor-Liquid Equilibria for Aqueous Sulfuric Acid, Am. Inst. Ch. Eng. Journal, v. 10, no. 5, Sept. 1964, pp Arthur L. Kohl and Fred C. Riesenfeld, Gas Purification, 5 th Ed., 1997, pp ; M.U. Alzueta and others, Inhibition and Sensitization of Fuel Oxidation by SO2, Combustion Flame, 2001, v. 127, pp

20 Further, these pollutants are inversely related, in other words, as one goes up, the other goes down. As combustion temperature decreases, the amount of SO 3 increases. 70 In general, the lower the sulfur content of the fuel 71 and the higher the excess air 72, the higher the conversion to SO 3. The inverse relationship between SO 2 and SO 3 makes them unsuitable as surrogates for each other in the pollution control context. For example, compliance with an SO 2 BACT limit does not guarantee compliance with a SAM BACT limit due to the inverse relationship. When SO 2 drops, sulfur that would otherwise be SO 2 is converted into SO 3, increasing SAM. This could allow an SO 2 limit to be met while violating a SAM limit. Thus, due to the wide range of variables that affect the relative proportions of SO 2 and SO 3, there is no readily predictable relationship between the concentration of SO 2 and SAM. Further, the constant amount of sulfur linked by an inverse relationship renders them unsuitable for indicator or surrogacy monitoring. 2. Sulfuric Acid Mist Is Created By The Facility s Selective Catalytic Reduction Systems Under Hyperion s proposal, the larger heaters will all be equipped with selective catalytic reduction ( SCR ) units to satisfy BACT for NOx. The emission calculations indicate that Hyperion assumed that heaters equipped with SCR would emit seven times more SAM than the smaller heaters that will not use SCR. 73 This increase in SAM emissions should have been subjected to a BACT analysis. It is well known that the SCR catalyst converts some of the SO 2 in the flue gases to SO 3. As explained above, the SO 3 is converted into SAM before it leaves the stack. The extent of this oxidation depends on the catalyst formulation and SCR operating conditions and can range from 0.1% to 3%. In other words, from 0.1% to 3% of the SO 2 in the flue gases at the entrance to an SCR is oxidized to SO A publication by EPA and industry experts in a noted, referred journal explains: It is well known that the catalyst used in the selective catalytic reduction (SCR) technology for nitrogen oxides control oxidizes a small fraction of the sulfur 70 William Bartok and Adel F. Sarofim, Fossil Fuel Combustion. A Source Book, John Wiley & sons, Inc., New York, Arthur Levy, Earl L. Merryman, and William T. Reid, Mechanisms of Formation of Sulfur Oxides in Combustion, Environmental Science & Technology, v. 4, no. 8, August 1970, pp (Fig. 6). 72 B.W. Harris, Conversion of Sulfur Dioxide to Sulfur Trioxide in Gas Turbine Exhaust, Journal of Engineering for Gas Turbines and Power, v. 112, October 1990, pp /15/08 from Colin Campbell to Kyrik Rombough, attaching revised Appendix C (The SAM emission factor for process heaters equipped with SCR is lb/mmbtu while the SAM emission factor for the uncontrolled smaller heaters is lb/mmbtu.) 74 EPRI, April 2010, p. 3-3; Srivastava et al., June 2004, p ; Nick Irvin and Larry S. Munroe, A Review of Sulfuric Acid Formation and Behavior in Coal-Fired Power Plants, Mega,

21 dioxide in the flue gas to SO 3. The extent of this oxidation depends on the catalyst formulation and SCR operating conditions. Gas-phase SO 3 and sulfuric acid, on being quenched in plant equipment (e.g., air preheater and wet scrubber), result in fine acidic mist, which can cause increased plume opacity and undesirable emissions. 75 These reactions occur regardless of the fuel that is burned, e.g., coal, oil, natural gas, refinery fuel gas. This conversion can be minimized by catalyst selection and regeneration methods, as discussed below. 3. BACT Was Not Required For Sulfuric Acid Mist The Application and DENR s engineering evaluations do not include a BACT analysis for SAM, but rather conclude that the BACT analysis for SAM would be the same as for SO 2. As indicated above, this is incorrect. There are several methods that can be used to control SAM that would not be considered for SO 2 control and were not evaluated in the record. These include catalyst selection and regeneration. Low conversion catalysts are available that are routinely guaranteed to achieve an SO 2 to SO 3 conversion as low as 0.1% per layer of catalyst. 76 The SO 2 to SO 3 conversion rate can also be reduced by as much as 50% below the guarantee by regenerating the catalyst rather than replacing spent catalyst with new catalyst at the end of its useful life. 77 Regeneration not only reduces the cost of periodic catalyst replacement but reduces the amount of SAM that is produced for no increase in cost effectiveness. These controls are unique to SAM and therefore would not be considered in an SO 2 BACT analysis. The BACT analysis for the HEC should have evaluated the use of low SO 2 to SO 3 conversion catalyst and catalyst regeneration to control SAM, rather than assuming a seven-fold increase in SAM emissions without any BACT analysis at all. Other options also are available to lower SAM emissions that were not considered, including sorbent injection, wet electrostatic precipitators, and a lower sulfur content in the refinery fuel gas. Thus, BACT has not been required for SAM emissions from fired sources at Hyperion. The Application, Statement of Basis, and Amended Draft Permit should be revised to include a SAM BACT analysis and should be recirculated for public review and comment. 75 R.K. Srivastava and others, Emissions of Sulfur Trioxide from Coal-Fired Power Plants, J. Air & Waste Manage. Assoc., June 2004, v. 54, pp , p Isato Morita and others, Development and Operating Results of Low SO 2 to SO 3 Conversion Rate Catalyst for DeNOx Application (Exhibit 2); Haldor Topsoe, DNX Topsoe SCR DeNOx Catalysts Oxidation of SO 2 into SO 3; n.ashx, accessed January 1, 2011; Anthony C. Favale and others, Application and Operating Results of Low SO 2 to SO 3 Conversion Rate Catalyst for DeNOx Application at AEP Gavin Unit 1, Proceedings of the 2006 Environmental Controls Conference, U.S. Department of Energy, National Energy Technology Laboratory (Exhibit 3). 77 Michael Cooper, Recent Advances in Controlling SO 2 Oxidation Rates in Regenerated Catalyst, Power-Gen, 2009; Y. Inatsune and others, Rejuvenation Work of SCR Catalyst for Mehrum Power Station, See also SCR Tech, Catalyst Regeneration References 2005 and Catalyst Regeneration Experience List Europe (Exhibit 4). 17

22 4. Sulfuric Acid Mist Emission Limits Were Not Set Best available control technology is an emission limitation based on the maximum degree of reduction that is achievable. A limit must be set unless there are technological or economic limitations in the application of a measurement methodology. The Amended Draft Permit fails to set emission limitations for SAM, instead setting the SAM BACT limit equal to the SO 2 BACT limit. This is incorrect. Section 4.6 of the Amended Draft Permit, BACT limits for sulfuric acid mist, refers to Permit Condition 4.2, captioned BACT limits for sulfur dioxide. Thus, the Amended Draft Permit sets SAM equal to SO 2. A quick glance at the emission calculations clearly indicates that SAM does not equal SO 2. The SO 2 emission rate for large heaters, for example, is pounds per million British thermal units ( lb/mmbtu ), while the SAM emission rate for the same heaters is lb/mmbtu, or nearly seven times lower. A similar large discrepancy exists for every single combustion source. The Amended Draft Permit, in essence, allows substantially more SAM emissions than assumed in the emission calculations. This increased amount of SAM, if realized, would show up at the stack as condensable particulate matter, which is measured only once over the entire lifetime of the facility. 78 While the Amended Draft Permit contains limits on total PM10, these limits are not enforceable as a practical matter as PM10 is measured only once over the entire life of the facility. Thus, the Permit as drafted allows PM10 and PM2.5 emissions that are substantially higher than assumed in the dispersion modeling. These increases likely would result in exceedances of the PM10 and PM2.5 increments and NAAQS. Thus, based on the emission calculations alone, SAM is clearly not equal to SO 2. The Permit must be revised to set unit-specific SAM emission limits for every combustion source in the refinery and must be recirculated for public comment. 5. No Monitoring Is Required For Sulfuric Acid Mist The Amended Draft Permit does not contain any monitoring for sulfuric acid mist, a regulated PSD pollutant that is present in significant amounts. The compliance section of the Amended Draft Permit is silent as to SAM. 79 The Permit must be modified to include SAM BACT limits and be recirculated for public review and comment. It is possible that DENR intended to use SO 2 as an indicator or surrogate for SAM, but failed to explain this in the record. This use is not scientifically defensible for the reasons explained above, i.e., the relationship, if any, is complex and inverse. Further, the permit as drafted does not meet the requirements for indicator monitoring. The rationale for selecting the monitoring requirements must be documented in the permit record. The permit record for Hyperion does not explain how monitoring of SO 2 is 78 Amended Draft Permit, Section Amended Draft Permit, Section

23 sufficient to ensure continuous compliance with unidentified SAM BACT emission limits, arbitrarily set equal to SO 2. EPA has objected to many Title V permits based on failure to document the rational for selected monitoring and for failing to establish a correlation between a monitoring parameter and compliance with an applicable emission limit. 80 Thus, to use indicator monitoring for SAM, Hyperion must conduct a study to demonstrate a statistically significant relationship between SO 2 and SAM and explain how this relationship would be used to assure compliance with SAM. Based on the science, it is doubtful that SO 2 could serve as an indicator or surrogate for SAM in any case. E. The Emission Estimates Supporting The Amended Draft Permit s BACT Determinations Are Not Adequately Documented DENR s determination that emissions from the Facility would not result in violations of ambient air quality standards are based on emission estimates for the Facility s emission units provided by Hyperion. Many of these emission estimates are not adequately supported and cannot be verified. The CAA requires the owner or operator of a proposed source to submit a detailed description of all emission estimates. 81 In most cases, Hyperion s emission estimates fall far short of the legal requirement that they be supported by a detailed description. The following discussion addresses a few examples of this persistent lack of documentation. 1. Storage Tanks Hyperion provides a summary table with emission estimates for volatile organic compounds ( VOC ) and hazardous air pollutants ( HAP ) from organic liquid storage tanks See, e.g., EPA Region 4 Objection, Proposed Part 70 Operating Permit, Southdown, Inc Brooksville Plant, Hernando County, Florida, Permit No AV, Objections 4 and 7; In the Matter of Fort James Camas Mill, Order Denying in Part and Granting in Part Petition for Objection to Permit, December 22, 2000 ( the rationale for the selected monitoring method must be clear and documented in the permit record. ); In the Matter of Waste Management of LA LLC Woodside Sanitary Landfill & Recycling Center, Order Granting in Part and Denying in Part Petition for Objection to Permit, Petition No. VI , May 27, 2010, p. 5; In the Matter of Public Service Company of Colorado, dba cel Energy, Hayden Station, Order Granting in Part and Denying in Part Petition for Objection to Permit, Petition No. VIII , p. 6 ( we find that CDPHE has not established that either indicator is currently adequate to assure proper operation and maintenance of the PM control device in order to assure compliance with the PM limit. ), p. 8 ( the selected monitoring requirements must be clear and documented in the permit record. ); In the Matter of Wisconsin Public Service Corporation s JP Pulliam Power Plant, Order Granting Petition for Objection to Permit, Petition Number V , p. 10 ( WDNR must establish the correlation between the operating parameters being measured and the ESP performance, and must identify the parameter indicator ranges in the title V permit if they are to be used to demonstrate compliance. ); In the Matter of Alliant Energy WPL Edgewater Generating Station, Order Granting in Part and Denying in Part Petition for Objection to Permit, Petition Number V , p. 8 ( WDNR must establish the correlation between the operating parameters being measured and the ESP performance, and must identify the parameter indicator ranges in the Title V permit if they are to be used to demonstrate compliance ) C.F.R (n)(iii). 82 December 2007 Application, Appendix C, Tables Storage Tanks VOC and Storage Tanks HAP. 19

24 These emission estimates were obtained by running EPA s TANKS model. 83 Citizens previously commented that the Amended Draft Permit s emission estimates for liquid storage tanks were not adequately supported; specifically, that Hyperion did not provide the model runs for EPA s TANKS model nor any of the assumptions required to run the model. 84 DENR denied the allegation and responded that all required input data may be found in the 2007 Application as follows: Hyperion identifies the volume of each tank in Appendix A of the application, the dimensions of each tank may be found in the modeling files that identify the building 3 parameters or by estimating the dimensions by knowing that volume is the height times Pi times the radius squared. The ratio of height to diameter is generally within 1:2 or 2:1 depending on the size of the tank. The number of turnovers may be obtained from the design rate of how many barrels of crude oil processed, gasoline produced, jet fuel produced, diesel fuel produced, and the number of tanks that store each product. Hyperion identifies the rim seal systems and deck characteristics in Appendix C of the application 85 DENR s response is not acceptable for the following reasons: First, the information for storage tanks found in the various locations indicated by DENR is not sufficient to run the TANKS model. The model requires a large number of input parameters including the tank diameter; tank volume; turnovers per year; net throughput; roof support; number of columns; effective column diameter; internal and external shell condition and color; roof color and condition; type of primary and secondary seal; deck type; deck fitting category; fitting types and quantity; daily average and annual minimum and maximum average ambient temperature; average wind speed; annual average solar insolation; atmospheric pressure; chemical category and speciation of stored liquid or mixture; vapor pressure; molecular weight; and liquid density. Only few of these input parameters can be found in the application materials. Second, the application materials failed to provide information on the design rate for gasoline produced, jet fuel produced, and diesel fuel produced. Consequently, the number of turnovers cannot be obtained. Third, and most importantly, bits of information scattered here and there all over the record does not qualify as adequate documentation to support the Applicant s emission estimates. Each emission estimate must be accompanied by documentation of all assumptions. 83 December 2007 Application, p Citizens 2008 Comments XII.C.2, p South Dakota Department of Environment and Natural Resources, Hyperion Energy Center, Union County, DENR s Response to Comments Received on the Prevention of Significant Deterioration Preconstruction Air Quality Permit, (hereinafter 2009 DENR Response ), No , p

25 2. Wastewater Treatment System Citizens previously commented that Hyperion relied on EPA s WATER9 model to estimate emissions from the Facility s wastewater treatment system but failed to provide the model runs or any of the assumptions required to run the model. 86 The DENR failed to directly respond to this comment. As discussed above, all assumptions used to run a model must be adequately documented to enable review of the Applicant s emission estimates. 3. Coker Quench Water Handling The 2010 Coker Quench Water Application estimated uncontrolled VOC emissions from the coker quench water handling using EPA s WATER9 model. 87 Neither the 2010 Coker Quench Water Application nor the 2011 Statement of Basis nor the files posted on DENR s website contain any additional support for these emission calculations. The WATER9 model requires a number of input variables, including the composition of the coker quench wastewater, which is not provided in the permit record. Therefore, a meaningful review of the modeled VOC emissions from the coker quench water handling system is not possible. This information must be provided to allow public review and comment as required by law. F. The Amended Draft Permit Fails To Adequately Characterize And Limit Refinery And IGCC Power Plant Inputs The December 2007 Application specifies that the Facility is nominally designed to receive and process 400,000 bbl/day of crude oil and 26,000 bbl/day of butane and would also use natural gas and purchased gasoline blending components such as ethanol. 88 Review of the permit record shows that the Facility would also receive coke and coal. As discussed in the following, the operational throughput of these materials at both the refinery and the IGCC power plant is not or not adequately restricted by permit conditions. 1. The Amended Draft Permit Fails To Set Operational Throughput Limits The Amended Draft Permit contains only one operational throughput limit for the Facility: a limit for refining crude oil at 400,000 bbl/day based on a rolling 365-day average. 89 This is inadequate for several reasons. First, the Amended Draft Permit contains no throughput limit for butane, which is proposed to be processed at a rate of 26,000 bbl/day. 86 Citizens 2008 Comments XII.C.2, p RTP Environmental Associates, Letter to Kyrik Rombough, South Dakota DENR, Re: Hyperion Energy Center, Response to Information Request Letters of July 9 and August 23, 2010, September 8, 2010, Enclosure 1. Application Supplement for Coker Quench Water Handling System (hereinafter 2010 Coker Quench Water Application ), Section Application, p Amended Draft Permit, Condition 5.1, p

26 Second, there are no throughput limits for the IGCC power plant. The IGCC system operational limit in Section 5.2 of the Amended Draft Permit does not limit the potential to emit of the IGCC system. There is no limitation on coal/coke charged to the IGCC power plant that effectively limits the potential to emit of this process unit. The overall limit in Section 5.1 on crude oil refined per day does not necessarily limit the short-term potential to emit of individual process units within the refinery. Third, the Amended Draft Permit contains no operational throughput restrictions whatsoever for natural gas, purchased gasoline blending components, etc. The lack of specific throughput limits for all materials received at the Facility undermines compliance with the proposed BACT limits and renders the permit unenforceable. The Amended Draft Permit should be revised to include throughput limits for all materials received and include adequate monitoring provisions specifying flow metering, turnover, etc. 2. Lack Of Definition For Crude Oil Charge The Amended Draft Permit sets a limit for refining crude oil at 400,000 barrels per day based on a rolling 365-day average 90 and requires daily monitoring and quarterly reports of crude oil processed. 91 Elsewhere, the Amended Draft Permit uses the term crude charged for daily monitoring and quarterly reports of CO 2 e emissions and to set CO 2 e BACT limits. 92 None of these terms is defined, nor does the Amended Draft Permit specify how the amount of crude charged or crude processed would be monitored. The Facility would process crude oil that is mixed with diluent. (See below.) The Amended Draft Permit does not specify whether the 400,000 bbl/day would be measured before or after the diluent is separated from the crude oil. Without this information, a full and fair review of the Amended Draft Permit cannot be conducted. 3. The Facility Has Been Specifically Designed To Process Dilsynbit But Could Process Other Heavy Sour Crude Oils During the contested case hearings, Hyperion disclosed that the Facility is designed to process heavy sour 93 crude oils pipelined from Canada. 94 Yet, neither the Amended Draft Permit nor the Statement of Basis contains any reference to the specific type of crude oil that would be refined and the Amended Draft Permit does not include a limit on the type of feedstock that would be processed. 90 Amended Draft Permit, Condition 5.1, p Amended Draft Permit, Conditions and Amended Draft Permit, Conditions , , and Sour is a term of art in the refining industry indicating high concentrations of H 2 S and other sulfur compounds in the crude oil. 94 Transcript of Proceedings, Volume 1, May 19, 2009, pp

27 Citizens previously commented on the 2008 Amended Draft Permit s failure to provide information regarding the composition of the feedstock that would be refined at the Facility. 95 EPA submitted similar comments and requested that the feedstock be better characterized including, at a minimum, sulfur content, hydrogen/carbon content ( H/C ratio ), and metals in representative crude oil. 96 DENR responded that the type of crude oil was not a direct factor in determining the BACT emission limitations for each of the Facility s emission units and concluded that, since the PSD regulations do not specify that all indirect factors be analyzed to determine BACT, it is not required to limit the type of crude oil in the permit. 97 Consequently, DENR did not make any changes to the original PSD permit and the Amended Draft Permit does not contain any specifications for the feedstock. As described below, DENR s reasoning for not requiring this information was flawed in 2008 and was flawed again in Hyperion admits that the Facility has been specifically designed to refine heavy sour crude oils recovered from Canadian tar sands deposits. 98 Because the sluggish, tarry bitumen recovered in the Canadian tar sands deposits will not reliably flow through a pipeline at ambient temperatures it is often blended with lighter hydrocarbon diluents (creating dilbit 99, or synbit if synthetic crude oil ( SCO ) is used as the diluent) to reduce its viscosity, which makes it easier to pump and transport in pipelines. Hyperion stated that it designed and modeled the Facility for so-called dilsynbit, a blend of dilbit and synbit, from an undisclosed Canadian upgrader 100 and explained that dilsynbit is about the hardest material to refine into transportation fuels. 101 In other words, all components of the refinery have been designed to be able to handle the difficult Canadian tar sands blends, specifically, dilsynbit, as feedstock. Yet, the refinery could also process other crude oils if, e.g., dilsynbit is not available or if other crude oils are considered more cost-effective in the future. At present, there appears to be only one Canadian source for dilsynbit, named Albion Heavy Synthetic ( AHS ). 102 Hyperion has not documented that it can reliably source and contract dilsynbit at the proposed rate of 400,000 bbl/day. In fact, the pipeline that would deliver the respective feedstock to the refinery has not even been built Citizens 2008 Comments, Section IV.A EPA Comments, Section III DENR Response Nos and Transcript of Proceedings, Volume 1, May 19, 2009, pp Dilbit is typically a mixture of 50% bitumen with 50% naphtha; other light hydrocarbons including condensate can also be used as diluent. 100 Transcript of Proceedings, Volume 1, May 19, 2009, p Transcript of Proceedings, Volume 1, May 19, 2009, p Canadian Crude Quick Reference Guide, Version 0.54, November 25, 2009; ei=keuoty3lhylssapf-ed2ca&usg=afqjcnfgjk5liuu7nd5ikcl-fdvhevutnq&cad=rja or [www_google_com]. 103 Transcript of Proceedings, Volume 1, May 19, 2009, p

28 4. Canadian Crude Oil Characteristics Crude oils from Canada vary considerably in their chemical and physical characteristics depending on their origin and their degree of blending and pre-processing, as shown in the following table. Chemical and physical characteristics of Canadian crude oils and blends* Grade API (deg) Sulfur (wt%) TAN (mg KOH/g) MCR (wt%) Viscosity at 60 F (cst) RVP (psi) Conventional crude Dilsynbit (AHS) Dilbit Synthetic crude ** API = American Petroleum Institute gravity; TAN = total acid number; MCR = micro carbon residue; RVP = Reid vapor pressure; deg = degrees; wt% = percent by weight; mg KOH/g = milligrams potassium hydroxide per gram; cst = centistokes; psi = pounds per square inch; AHS = Albion Heavy Synthetic * Data summarized from Canadian Crude Quick Reference Guide, Version 0.54, November 25, 2009 ** Only one value reported for 8 blends 5. Emission Estimates Depend On Crude Characteristics Emissions from a refinery vary with the characteristics of the processed crude oil, or feedstock, such as its vapor pressure, sulfur content, metals content, acid content, etc. Therefore, crude oil characteristics have a direct influence on emissions estimates. Because the Amended Draft Permit does not contain any condition limiting the feedstock, Hyperion could switch the feedstock to be processed at any time as long as it does not violate its permit emission limits. As discussed below, due to the Amended Draft Permit s failure to set adequate BACT limits and provide enforceable permit conditions, the Facility could increase its emissions beyond those estimated by Hyperion and modeled in the ambient air quality analysis without ever violating permit conditions. DENR appears to assume that compliance with the Amended Draft Permit s established BACT limits would limit facility emissions. This is not correct because not all proposed BACT limits limit the amount of emissions; instead, some specify use of a control efficiency. For example, the VOC BACT limits the tank farm thermal oxidizers (Units #175 and #176) are specified as the least stringent between 98% destruction efficiency; or 20 parts per million. 104 Emissions in pounds per hour ( lb/hr ) and ton/yr therefore depend on the flow rate and VOC content of the gas flows that are incinerated by the thermal oxidizers. The VOC content of the gases routed from the tank farm to the thermal oxidizers is dependent on the vapor pressure of the liquids that are stored in the tanks. Hyperion used a maximum true vapor pressure of 6.0 psi 105 to calculate VOC emissions of 153 tons/yr from tanks. 106 As shown in the above table, the reported Reid vapor pressure Amended Draft Permit, p December 2007 Application, Appendix A, Table A Amended Draft Permit, Appendix C, Emissions Calculations, Table Storage Tanks VOC. 24

29 for dilsynbit is 6.2 psi, somewhat higher than the vapor pressure used by the Applicant. Further, the vapor pressure of dilsynbit is lower than the upper end of the range of reported Reid vapor pressure for dilbit bitumen blends of 8.0 psi or for conventional Canadian crude of 11.0 psi for conventional crude. 108 Thus, if the Facility received and processed dilbit or conventional crude instead of dilsynbit, VOCs emissions from storage tanks would be higher than estimated and modeled for the Amended Draft Permit due to the higher vapor pressure of dilbit and conventional Canadian crude. Because the Amended Draft Permit does not require any monitoring for vapor pressure of the crude oil processed at the Facility, this emission increase would go undetected. G. The Amended Draft Permit s Proposed BACT Emission Rates Are Inadequate And Not Continuously Enforceable A PSD permit must contain sufficient monitoring to assure compliance with the terms and conditions of the permit. 109 It must be a standalone document that identifies the emissions units to be regulated; establishes emissions standards or other operational limits to be met; specifies methods for determining compliance and/or excess emissions including reporting and recordkeeping requirements; and outlines the procedures to maintain continuous compliance with the emission limits. 110 The rationale for the selected monitoring requirements must be clear and documented in the permit record. 111 Here, the monitoring in the Amended Draft Permit is inadequate for most sources and pollutants. 1. Failure To Include Averaging Times BACT emission limits or conditions must be met on a continual basis at all levels of operation and must be enforceable as a practical matter, i.e., contain appropriate averaging times, compliance verification procedures and recordkeeping requirements. Thus, the Amended Draft Permit must be able to show compliance or noncompliance. 112 The Amended Draft Permit specifies BACT limits for PM10 in Section 4.1 but fails to include any averaging times. The stringency of an emission limit is a function of both the magnitude and averaging time. The NSR Manual is very clear that an averaging time must be included in an enforceable permit. 113 Thus, averaging times must be required True vapor pressure is somewhat higher than Reid vapor pressure. 108 Canadian Crude Quick Reference Guide, Version 0.54, November 25, 2009; ei=keuoty3lhylssapf-ed2ca&usg=afqjcnfgjk5liuu7nd5ikcl-fdvhevutnq&cad=rja or [www_google_com] CFR 70.6(c)(1). See also 40 CFR 70.6(a)(3)(i). 110 NSR Manual, p. H CFR 70.7(a)(5). 112 NSR Manual, p. B See the discussion of this issue in the NSR Manual at pages B.56 and c EPA s Review of Proposed Title V Permit No AV, Southdown, Inc. Brooksville Plant, Hernando County, Florida, June 19, 2000, Objections 3. 25

30 2. Inadequate Monitoring Requirements For Equipment Not Monitored By Continuous Emissions Monitoring Systems The Amended Draft Permit contains BACT emission rates for PM10, SO 2, NOx, VOCs, CO, SAM, hydrogen chloride, and carbon dioxide equivalent ( CO 2 e ) emissions 115 and the maximum hourly emission rates established in the Amended Draft Permit are the basis of the ambient air quality modeling. Yet, the Amended Draft Permit s compliance monitoring provisions are insufficient to assure continuous compliance with applicable requirements and are not enforceable. The Amended Draft Permit requires the following continuous emissions monitoring systems ( CEMS ): Process heaters (Units #1 through #30): SO 2, NOx, CO, carbon dioxide ( CO 2 ) Sulfur recovery plant thermal oxidizers (Units #42a and #42b): SO 2, NOx, CO Wastewater treatment plant catalytic oxidizer (Unit #45a): SO 2, NOx Power island acid gas removal system (Unit #59): CO, H 2 S Combined cycle gas turbines ( Units #60 through #64): SO 2, NOx, CO, CO 2 Tank farm thermal oxidizers (Units #175 and #176): SO For emissions of PM10 and VOCs, and emissions of SO 2, NOx, CO, and CO 2 from most other equipment, the Amended Draft Permit appears to require only a single initial stack performance test to demonstrate compliance. 117 A single stack test over the life of a facility is not adequate to assure continuous compliance. Further, no routine, periodic follow-up tests or continuous monitoring are required to demonstrate continuous compliance. Thus, the BACT limits are not enforceable as a practical matter. While additional monitoring can be specified in the forthcoming Title V permit, the underlying applicable requirement is BACT, which must itself be continuously enforceable. 3. The Amended Draft Permit Fails To Specify Test Methods For Performance Tests The Amended Draft Permit Section 10 requires PM10, SO 2, NOx, CO, H 2 S, and hydrogen chloride performance tests for a large number of the Facility s emission units; however, the Amended Draft Permit fails to specify the test methods for these tests. A BACT emission limit must be enforceable as a practical matter, which means it must contain averaging times, compliance verification procedures and recordkeeping requires. Thus, the test methods must be specified in the permit itself. 118 This is particularly critical for 115 Amended Draft Permit, Sections 4-1 through Amended Draft Permit Conditions 11.1 through 11-5, pp Amended Draft Permit, Conditions 10.7 through 10.11, pp See NSR Manual p. B.56 and Chapter H. 26

31 parameters that are defined by the test method itself, such as measurements for particulate matter emissions. 4. GHG Emissions From Small Combustion Sources Are Not Adequately Monitored The Amended Draft Permit sets BACT limits for CO 2 emissions from small combustion sources at 0.2 tons of CO 2 e per thousand barrels. 119 Compliance is determined based on an emission calculations specified in Condition The equation for determining emissions is based on based on the heat content of the fuel used in MMBtu per gallon or MMBtu per cubic feet and CO 2 e emission factors of lb/mmbtu for natural gas, lb/mmbtu for refinery gas and lb /MMBtu for diesel. 121 Emissions calculated based on this equation are not reliable because a) the Amended Draft Permit fails to require any monitoring of fuel heat content and b) the carbon content of the permitted fuels varies considerably. Both parameters are particularly variable for refinery fuel gas, however, even pipelinegrade natural gas can show considerable variation in carbon content and heating values over space and time. 122 The U.S. Department of Energy ( DoE ) reports CO 2 -fuel efficiency coefficients for pipeline natural gas ranging from lb/mmbtu for natural gas with a higher heating value of 1,075-1,100 Btu/scf to lb/mmbtu for natural gas with a higher heating value of 975-1,000 BTU per cubic foot ( Btu/scf ) to. 123 Thus, the Amended Draft Permit should require that GHG emission calculations for natural gas be based on fuel specifications provided by the supplier or require testing. Given this variability in fuel composition, facility-specific values for carbon content and heating value should be used to determine GHG emissions from natural gas combustion wherever possible. VI. DISCUSSION OF POTENTIAL TO EMIT AND BACT DETERMINATIONS The following sections discuss flaws in individual BACT determinations. A. Natural Gas Is A Cleaner Fuel Than Coal-Syngas And The Department Must Consider This In Its BACT Analysis For The IGCC Unit The gas turbines in the IGCC unit are permitted to burn several fuels including syngas, natural gas, pressure swing absorption ( PSA ) tail gas, distillate oil and various combinations thereof. Natural-gas would result in lower emission rates from the proposed plant. Therefore, the 119 Amended Draft Permit, Table 4-8, pp Amended Draft Permit, Footnote 2 to Table 4-8, p Amended Draft Permit, Condition 4.11, p See, e.g., Energy Information Administration, Emissions of Greenhouse Gases in the United States , Figure A U.S. Department of Energy, Voluntary Reporting of Greenhouse Gases Program, Fuel Emission Coefficients; available at 27

32 Department must consider the use of natural gas and the resulting lower emission limits in its BACT determination. Natural gas fired combustion turbines are an available option commercial power production applications and at competitive costs, and within the meaning of 42 U.S.C. 7479(3). Both the plain language of the Clean Air Act and Act s legislative history require it. The Clean Air Act requires BACT limits to be based on the maximum degree of reduction of each pollutant achievable for such facility through application of production processes and available methods, systems, and techniques, including innovative fuel combustion techniques 124 Here, natural gas not only can but is planned to be burned at the plant. If the proposed facility can burn natural gas (or a larger percentage of it) then the Department must consider it as an available clean fuel in a top-down BACT analysis and may only reject it in favor of syngas in accordance with the procedures detailed in the EPA's NSR Manual. The Department should establish the BACT emission limits that the Facility must meet no matter what fuel is burned based on the emission limit that the Facility can achieve by burning natural gas. Establishing BACT limits based on natural gas would not redefine the source. BACT is applied to the major emitting facility, rather than some different major emitting facility. 125 The Clean Air Act states that [n]o major emitting facility may be constructed unless the proposed facility is subject to the best available control technology for each pollutant subjected to regulation under this chapter emitted from, or which results from, such facility 126 As long as BACT is being applied to the major emitting facility, there are no redefining the source problems. Here, the process to generate electricity from natural gas requires same major emitting facility as the synthetic gas process. Not only do they both fall within the Standard Industrial Classification Manual s Major Group 49: Electric Services, by which a major emitting facility is defined, but both fuels can and will be used in the combustion turbines used to produce electricity at the Facility. In its Hibbing Taconite decision, EPA noted that: EPA regulations define major stationary sources by their product or purpose (e.g., steel mill, municipal incinerator, taconite ore processing plant, etc.), not by fuel choice. Here, Hibbing will continue to manufacture the same product (i.e., taconite pellets) regardless of whether it burns natural gas or petroleum coke The record here indicates that there are other taconite plants that burn natural gas, or a combination of natural gas and other fuels. Thus, it is reasonable for Hibbing to consider natural gas as an alternative in its BACT analysis. In Re: Hibbing Taconite Co., 2 E.A.D. 838 (EAB 1989). Thus, it is reasonable for Hibbing to consider natural gas as an alternative in its BACT analysis. Moreover, because Hibbing is already equipped to burn natural gas, this alternative would not require a fundamental change to the facility U.S.C. 7479(3). 125 See 42 U.S.C. 7475(a). 126 Id. 28

33 Therefore, where an applicant can produce the same end-product with a cleaner fuel (or a blend of different fuels to get to the lowest emission rates), a BACT determination must account for the emission reductions available from that cleaner fuel. The Department s BACT analysis does not appear to have addressed the lower emissions achievable with cleaner natural gas. The Department must correct this omission. B. Coker Cokers convert heavy feedstocks into solid coke and lower boiling hydrocarbon products that are suitable as feed to other refinery units. Pairs of coke drums operate in a semi-batch mode, one coking and one decoking, each with an associated heater. The HEC will operate two delayed cokers, each using two pairs of large coke drums that are alternately switched on- and off-line after filling with hot vacuum residuum and fractionator column bottoms. The coker design charge rate is 120,000 bbl/day or 15,000 bl/day to each of eight coke drums. 127 The Amended Draft Permit limits operation of each coke drum to 2,190 cycles per 12-month rolling period, 128 suggesting a single drum cycle lasts 4 hours. 129 The feed is routed to the coke drums and cooked at high temperatures and pressure to strip off hydrocarbon vapors, leaving behind drums filled with coke. After the coking reactions are complete, the full coke drums are switched off-line, steamed out and cooled. The coke drum bottom and top heads are opened and the coke is cut from the drums using a water jet. The coke and quench water drop into a concrete pit beneath the drums, where free water is separated from the coke and recycled. The wet coke is transferred from the pit to a concrete pad to drain and then to a chopper. From the chopper, the coke enters an enclosed conveyor and is sent to the coke storage building. 130 These operations can release substantial amounts of VOCs, reduced sulfur compounds, particulate matter, and greenhouse gas emissions if not properly controlled. The major sources of emissions are: (1) quench water handling; (2) steam vent, (3) coke drilling, and (4) coke handling. The December 2007 Application included only VOC emissions from the steam vent. It established a BACT work practice standard for the steam vent as a release pressure of 5 pounds per square inch gauge ( psig ). The 2010 Coker Quench Water Application included greenhouse gas emissions from the steam vent, but did not revisit the underlying 2007 BACT determination, which is outdated. The 2010 Coker Quench Water Application also added VOC emissions from quench water handling and made a BACT determination for this source, but neglected other emissions. Finally, neither the December 2007 Application nor the 2010 Coker Quench Water 127 RTP Environmental Associates, Inc., Hyperion Energy Center, Best Available Control Technology Review for Greenhouse Gas Emissions, Supplement #1, November 2010 (hereinafter GHG BACT Analysis, Supplement #1 ), p Amended Draft Permit, p (8,760 hours/year)/(2,190 drum cycles/year) = 4 hours/drum cycle. 130 December 2007 Application, pp and Appx. B, pdf pp

34 Application includes emissions from coke drilling or VOC or reduced sulfur emissions from coke handling. Further, the BACT determinations for the steam vent and quench water handling do not represent BACT. Each of these emission sources, errors, and omissions is discussed below. 1. Coker Quench Water Handling System Hot coke is quenched with water, which drains out the bottom of the coke drum into a concrete pit below the drum. The quench water is pumped out of the pit to a clarifier and then to a surge tank. 131 This source was omitted from the December 2007 Application and has been added to the 2010 Coker Quench Water Application in response to EPA comments. The 2010 Coker Quench Water Application does not contain any process flow diagram of the coke quench water handling system, verbally identifying only a pump pit, clarifier, and surge tank. This is not adequate to assess emissions and controls for this system. It is unknown, for example, whether the pump pit is the coke pit beneath the coke drum or a separate pit; whether there are components in this system, such as junction boxes, sewer vents, valves and connectors that could leak; how many pumps and control valves are used; whether the quench water is recycled for quenching or decoking; whether the clarifier is a standard open tank design; and the type of surge tank. Thus, it is not feasible to evaluate the estimated emissions. Further, it is not possible to identify BACT controls without identifying all of the emission sources that require controls. The hot quench water contains elevated concentrations of both VOCs and TRS, 132 which are released to the atmosphere from the pit, clarifier, and tank and other components unless the quench water handling operations are fully enclosed and vented to a control device. The December 2007 Application did not disclose this source of emissions nor does it include any BACT controls. The 2010 Coker Quench Water Application estimates VOC emissions and includes a top-down BACT analysis for a subset of the components in the coke quench water handling system. This approach is inadequate. a) VOC Emissions Are Unsupported In its June 11, 2010 letter, EPA commented that this source would have potential uncontrolled VOC emissions in excess of 1,700 ton/yr, 133 based on a study at an Amoco 131 December 2007 Application, Section , pp ; Letter from Colin Campbell, RTP Environmental, to Kyrik Rombough, South Dakota DENR, September 8, 2010, Re: Hyperion Energy Center Response to Information Request Letters of July 9 and August 23, 2010, Enclosure 1. Application Supplement for Coker Quench Water Handling System ( Coker Quench Water Application ), Section Patrick Foley, U.S. Environmental Protection Agency, USEPA Petroleum Refinery Initiative, Slides, February 17, 2001, p. 37. See also discussion at Coking.com, Coking, Cat Cracking & Sulfur Discussion Forum at e.g., Blowdown settling drum water is typical sour water. the distinction of putting the roof up or not general [sic] are associated with the potential emissions of H 2 S, because of their sour water condition. 133 Letter from Callie A. Videtich, Director Air Program, EPA Region 8, to Preston Phillips, VP of Refining, Hyperion Energy Center, Re: Hyperion PSD Permit, Attachment: Questions and Requests for Hyperion in 30

35 Refinery. 134 In response, the 2010 Coker Quench Water Application estimated uncontrolled VOC emissions from coker quench water handling as only 8 ton/yr and 0.16 ton/yr assuming 98% control using the tank farm thermal oxidizers. These low emissions are used to justify eliminating the top tank control option (a roof and internal floating roof) as not cost-effective on a dollar-per-ton basis. 135 As discussed above, these VOC emissions are unsupported. They were reportedly estimated using EPA s WATER9 model. 136 This model requires a number of input variables, including the composition of the subject coker quench wastewater. The Coker Quench Water Application, Statement of Basis, and files posted on DENR s website contain no additional support for Hyperion s emission calculations. The assumed composition of the coker quench water, for example, is not reported, preventing any meaningful review of the resulting VOC emissions. b) Emission Estimates Are Incomplete The emission calculations include three sources: (1) pump pit; (2) clarifier; and (3) surge tank. The VOC emissions from these sources were estimated using EPA s wastewater treatment model. These calculations do not include emissions from other sources, including the coke pit beneath the coke drum, a major source of both VOC and reduced sulfur compounds, or drains, junction boxes, sumps, or pumps in the quench water handling system. EPA wrote: EPA has noted that cokers generally have uncontrolled waste water systems. Sumps, drains, junction boxes and sewer lines are uncovered and uncontrolled. 137 EPA specifically asked if Hyperion considered covering and controlling these emission sources as BACT, but the 2010 Coker Quench Water Application does not address them. 138 c) Sulfur Emissions Are Not Estimated The coker quench water contains both VOCs and TRS compounds such as H 2 S and mercaptans. 139 The 2010 Coker Quench Water Application does not include any emission calculations or BACT analysis for H 2 S and TRS emissions from coker quench water handling. Preparation for the February 1, 2010 Meeting, January 28, 2010 (hereinafter 6/11/10 EPA Letter, 1/28/10 Attachment ), p U.S. Environmental Protection Agency and Amoco, Amoco EPA Pollution Prevention Project, Yorktown, Virginia, Volume II, Air Quality Data, Table 4-3 (Exhibit 5) Coker Quench Water Application, Sections 4.19 and Coker Quench Water Application, Section /11/10 EPA Letter, 1/28/10 Attachment, p /11/10 EPA Letter, 1/28/10 Attachment, p Patrick Foley, U.S. Environmental Protection Agency, USEPA Petroleum Refinery Initiative, Slides, February 17, 2001, p

36 d) Top-Down BACT Analysis for Quench Water Handling Is Flawed The 2010 Coker Quench Water Application includes a BACT analysis for VOC emissions from coker quench water handling. 140 This analysis is fundamentally flawed as it fails to include all emission sources in the quench water handling system, fails to identify all potential controls, and fails to identify BACT. (1) The BACT Analysis For The Quench Water Handling System Does Not Include All Emission Sources The quench water handling system includes a large open concrete pit under the coker, the water pump pit(s), pump(s), valves, connectors, drains, junction boxes, tank(s), and clarifier(s), all of which emit VOCs and reduced sulfur compounds. The BACT analysis addresses only the surge tank, clarifier, and surge tank. All emission sources must be accounted for in the emission calculations and BACT analysis. (2) The BACT Analysis For The Quench Water Handling System Omits H 2 S and TRS As discussed below, BACT for VOCs from the coker quench water handling system is apparently covering tanks and routing the vapors to thermal oxidizers. This is not necessarily BACT for the sulfur compounds from all sources. A BACT analysis for sulfur compounds should additionally consider routing this quench stream to the sour water stripping unit to remove the sulfur compounds and routing the resulting acid gases to the sulfur recovery unit for conversion into sulfur product. Further, when a control option controls multiple pollutants, such as VOCs and sulfur compounds, as would be the case for tank covering and thermal oxidation, costs are proportioned to each pollutant before the dollar-per-ton cost is figured. 141 Thus, the cost of adding an internal floating roof to the surge tank, eliminated as not cost-effective for VOCs alone, 142 may be costeffective when evaluated considering the sum of the controlled pollutants. (3) Step 1 Of The Top-Down BACT Analysis For The Quench Water Handling System Is Incomplete Step 1 of the top-down BACT analysis process must identify all feasible control options. 143 Instead, the analysis fails to identify any control options specific to quench water Coker Quench Water Application, Section Letter from Brian L. Beals, Chief Preconstruction/HAP Section, U.S. Environmental Protection Agency, Air and Radiation Technology Branch, to Edward Cutrer, Jr., Program Manager, Georgia Department of Natural Resources, March 24, 1997 (Responding to a question by Georgia permitting authorities of how to account for a control device that reduces both VOC and CO, EPA agreed with the Georgia agency s interpretation that the cost-effectiveness should be calculated by dividing the annualized cost of the control device by the total of the CO and VOC emissions reduced by said device. ) Coker Quench Water Application, Section NSR Manual, pp. B.5 B.7. 32

37 handling, but rather refers to Sections 4.7 (Storage Tanks) and 4.9 (Wastewater Treatment Plant) of the December 2007 Application for related sources. The subsequent steps of the top-down BACT analysis focus on controls for tanks. This fails to identify controls that are unique to coker quench water handling. These include the following: The use of only fresh water as coker quench water or quench makeup water or water that has been stripped in a sour water stripper and contains no VOCs, TRS, or H 2 S; and A closed-vent system that routes vapors from all components and equipment within the coker quench water system to a control device, from the point of coke discharge from the coke drum pit to the quench water tank, including all drains, junction boxes, sewer lines, sumps, pits, clarifiers to the coker quench water tank. 144 Both of these controls are feasible and should be required as BACT for the Facility s coker quench water handling system. (4) BACT Is Not Required For The Quench Water Handling System The 2010 Coker Quench Water Application concluded that BACT for VOC emissions from the coker quench water handling operations at the HEC refinery is a requirement to route all emissions through the closed vent system serving the Tank Farm Oxidizers to achieve a VOC emission rate of 0.16 ton/yr. 145 This does not satisfy BACT. EPA and Murphy Oil, for example, concluded in a 2010 Consent Decree that the controls listed in the first two items above establish the floor, i.e., or the starting point, for BACT for any new coking unit at existing Murphy refineries. 146 The Hyperion BACT analysis did not consider anything beyond this floor, and, in fact, did not even include the entire floor. The Hyperion quench water handling BACT analysis did not consider quench water quality as a control option even though EPA alerted Hyperion to this issue in its June 11, 2010 letter and it has been required in Consent Decrees. 147 The December 2007 Application states: The coke is cut from the drum with a water jet and dropped into a pit where the free water is separated from the coke and recycled. 148 This indicates that recycled quench water will be used to cool the coke. This increases VOC and TRS emissions compared to the use of freshwater as it 144 See, e.g., Consent Decree, U.S. et al. v. Murphy Oil USA, Civil Action No. 3:10-cv bbc (hereinafter U.S. et al. v. Murphy Oil Consent Decree ), pp ; available at: See also 6/11/10 EPA Letter, 1/28/10 Attachment, p Coker Quench Water Application, Section See, e.g., U.S. et al. v. Murphy Oil Consent Decree, pp Available at: See, e.g., Murphy Consent Decree, p December 2007 Application, p

38 allows contaminants to build up and be recycle through the coker. This use does not satisfy the minimum requirements for BACT for the quench water system. Further, there is no description of the enclosed vent system required to satisfy BACT and designated as Unit # It is unclear, for example, whether the BACT vent system includes just covers on the surge tank, pump pit, and clarifier, which is all that is discussed in the 2010 Coker Quench Water Application, or whether the entire system is enclosed. Finally, there is no discussion anywhere in the record of emissions from or control of emissions from the pit beneath the coke drum and other components in the quench water system, such as the pumps, junction boxes, connectors, etc. Thus, BACT has not been established for the entire quench water handling system. (5) The Permit Fails To Require BACT For The Quench Water Handling System The results of Hyperion s BACT analysis are transferred into the Amended Draft Permit as a closed vent system on the water pump pit and clarifier and Unit #175 and # Units #175 and #176 are tank farm thermal oxidizers. Thus, the Amended Draft Permit only requires control of VOC emissions from two of the three identified sources, omitting the surge tank. The Amended Draft Permit also does not clarify whether the subject vent system involves only covering the pump pit and clarifier with a fixed roof, or requires enclosing the entire quench water system, which would capture emissions from sources such as the pump(s), junction boxes, drains, connectors, etc. The BACT analysis, which cited to Section of the December 2007 Application to describe the subject vent system, suggests that only a fixed roof is intended, as this section is captioned: Fixed roof with vapor collection by a closed vent system routed to a control device. This is not BACT as it does not control the entire system, but rather only the tank. Further, the Amended Draft Permit does not include the VOC emission limit of 0.16 ton/yr identified as the BACT emission limit. This limit is based on an assumed 98% VOC destruction efficiency for the tank farm thermal oxidizers (#175, #176). The Amended Draft Permit also does not require 98% VOC control, but rather the least stringent between 98% destruction efficiency; or 20 parts per million by volume. 151 Thus, for all the reasons set out above, the Amended Draft Permit fails to enforce the BACT analysis and fails to require BACT for the quench water handling system Statement of Basis, pp ; Amended Draft Permit, p. 18; 2010 Coker Quench Water Application, Section Amended Draft Permit, p Amended Draft Permit, p

39 2. Coker Steam Vent At the end of each coking cycle, the drum is steam stripped, cooled, and depressurized. The gases from these processes are depressurized to the scrubber system to recover the steam for reuse until the pressure drops below the operating pressure of the gas recovery compressor. At this point, the blowdown system is vented to atmosphere through steam vents (Units #34a 35d). These emissions are variously called coker steam vent emissions or depressurization emissions. The gases exiting the vent contain PM, PM10, CO, VOCs, H 2 S, and TRS. The lower the pressure at which the steam vent is opened to atmosphere, the lower the emissions. Emissions are controlled by limiting the pressure at which the vent is opened to the atmosphere and assuring the coke is properly cooled. The original PSD permit established a BACT work practice standard requiring each coke drum to be depressurized to 5 psig before the exhaust gases are vented to atmosphere. The Amended Draft Permit lowers this standard to 2 psig, sets specific emission limits in pounds per drum cycle ( lb/ cycle ) on VOCs (127.8 lb/ cycle), H 2 S (70.9 lb/ cycle), CO (5.12 lb/ cycle), and PM10 (30.3 lb/ cycle), 152 and limits the number of cycles to no more than 2,190 per coke drum 153 to limit greenhouse gas emissions. 154 a. The 2 psig Work Practice Standard Is Not BACT For The Coker Steam Vents The 2009 Final PSD Permit set a venting pressure of 5 psig. The 2010 Coker Quench Water Application lowered this BACT work practice standard to 2 psig, based on a permit issued to Chevron in July This is a step in the right direction. However, this decision is not supported by a BACT analysis but rather is based on an undocumented survey of the RBLC and other issued permits. 155 Step 1 of the top down BACT analysis process requires that all available control technologies be evaluated including inherently lower emitting processes and practices. 156 There are at least two additional practices that should have been considered to lower steam vent emissions: (1) a lower vent pressure and (2) limits on coker operation to assure the coke is adequately cooled prior to venting to atmosphere, e.g., a limit on the temperature of the vapor phase above the coke or the volume of water per unit of coke in the drum. 157 The record contains no evidence that work practice standards to assure adequate coke cooling were considered Statement of Basis, p. 17; Amended Draft Permit, pp. 27, 43, 47, and Amended Draft Permit, p GHG Supplement, p Statement of Basis, p NSR Manual, pp. B.10 B /11/10 EPA Letter, 1/28/10 Attachment, p. 2 35

40 Stack testing at two cokers has demonstrated less than 1 psig and lower venting pressures. 158 A lower venting pressure would reduce emissions but was not evaluated as BACT for Hyperion. Analysis of the Hovensa stack test used by Hyperion to estimate GHG emissions indicates that lowering the vent pressure from 2 psig to 1 psig would reduce VOC emissions by about 42 lb/cycle; PM emissions by 10 lb/cycle; PM10/PM2.5 by 9 lb/cycle; H 2 S emissions by 30 lb/cycle; 159 and GHG emissions by 9,230 lb/cycle. 160 Assuming the permit limit of 2,190 drum cycles per year, this amounts to 46 ton/yr of VOCs; 11 ton/yr of PM; 10 ton/yr of PM10/PM2.5; 33 ton/yr of H 2 S; and 10,100 ton/yr of CO 2 e. Thus, BACT for the steam vent should include a vent pressure of no less than 1 psig unless a demonstration is made on the record that this pressure is infeasible or would result in adverse energy, environmental, or economic impacts. Any cost-effectiveness analysis should be based on the sum of the controlled pollutants or 90 ton/yr of criteria pollutants and 10,100 ton/yr of GHG emissions. 161 Further, EPA specifically commented to Hyperion that [t]he pressure based venting standard, by itself, may not be sufficient to minimize VOC, TRS, and H 2 S emissions from a coker steam vent. In its investigation of this issue, EPA has identified an additional control option: ensuring that the coke temperature is sufficiently quenched before opening the steam vent to limit and control VOC, TRS, and H 2 S emissions. 162 The record contains no evidence that Hyperion considered any additional operational limits to ensure adequate cooling of the coke. EPA specifically requested that Hyperion include detailed supporting documentation of costs and emissions for each considered option with total and incremental cost analyses. 163 The record contains no evidence that any control option for the steam vent other than the lowered vent pressure was considered. Thus, the BACT analysis is flawed and has failed to make a proper BACT determination. BACT for the coker steam vents should be a vent pressure of 1 psig and operating limits to ensure the coke is adequately cooled. 158 SCAQMD, Source Test Report , Conducted at BP/ARCO Refinery, Particulate Matter (PM), Volatile Organic Compound (VOC), Speciated Hydrocarbons, Aromatic Hydrocarbons, and Sulfur Compound Emissions from a Coke Drum Steam Vent, February 20, 2008, p. 11 and Attachment A. (0.21 to 0.89 psig) (Exhibits 6, 7); SCAQMD, Source Test Report Conducted at Chevron/Texaco Refinery, El Segundo, California, Volatile Organic Compound (VOCs), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions from a Coke Drum Steam Vent, May 14, 2004, p. 7 (0.04 psig) (Exhibit 8). 159 URS Corporation, Source Test Report of the Coker Steam Vent, Prepared for Hovensa, LLC, September 8, 2008 (Exhibit 9) and EPA, HOVENSA, Coker Steam Vent Emissions, March 19, 2010, Slides (Exhibit 10). 160 GHG BACT Analysis, Supplement #1. Assuming 1 psig in the equation on page 2 results in negative emissions. Thus, it is assumed that GHG emissions at 1 psig would be equal to zero Coker Quench Water Application, Section /11/10 EPA Letter, 1/28/10 Attachment, p /11/10 EPA Letter, 1/28/10 Attachment, p. 2 36

41 a) The Coker Steam Vent Emission Limits Are Incomplete And Unsupported The 2011 Statement of Basis identifies BACT limits for the steam vents of lb/cycle for VOCs, 70.9 lb/cycle for H 2 S, and 30.3 lb/cycle for PM10, 164 which are included in the Amended Draft Permit as BACT limits. However, the steam vents also emit substantial amounts of TRS, PM2.5, and CO. The Amended Draft Permit should be revised to include limits on these additional pollutants. Further, the limits that are set are simply stated with no citation to the record and no supporting calculations. BACT is an emission limit based on the maximum degree of reduction that is achievable. The absence of any support prevents reviewers from confirming that these limits represent the maximum degree of reduction that is achievable. Supporting calculations should be provided and the Amended Draft Permit and Statement of Basis recirculated for public review. b) The Coker Steam Vent BACT Emission Limits Are Not Practically Enforceable As discussed above, BACT emission limits or conditions must be met on a continual basis at all levels of operation and be enforceable as a practical matter, i.e., contain appropriate averaging times, compliance verification procedures and recordkeeping requirements. 165 The Amended Draft Permit requires a single initial compliance test for total PM10 (filterable plus condensable) and VOCs. 166 No monitoring at all is required for H 2 S, TRS, or CO which are also emitted in significant amounts from the steam vents. Further, no routine, periodic follow-up tests or continuous indicator monitoring are require to demonstrate continuous compliance. A single stack test over the life of a facility is not adequate to assure continuous compliance. Thus, the BACT limits are not enforceable as a practical matter. 3. Coke Drilling Emissions are released during the entire decoking process, from opening of the drums through shipping of the coke. The emission calculations and BACT analyses excluded most of these emission sources and hence BACT controls. Coke drilling is a major source of VOCs, H 2 S, TRS, PM10, and CO. The purpose of coking is to recover lighter products gasoline, diesel, gas oil from the heavy coker feed. This process leaves behind a bed of coke impregnated with residual product, vapors which are subsequently released. 167 After the blowdown period, the drum heads are Statement of Basis, p NSR Manual, p. B Amended Draft Permit, pp. 64, Serge Raseev, Thermal and Catalytic Processes in Petroleum Refining, Marcel Dikker AG, 2003, p

42 removed to allow further cooling. Coke is then drilled out of the drum using high pressure (2,000 to 5,000 psig) water jets. 168 Vapors trapped in the fissures and pores are released during decoking, generating billowing odiferous black clouds. 169 A photograph of the bottom of a coker during decoking is shown below. Release of clouds from bottom of coker during decoking VOC emissions have been measured during coke drilling at a delayed coker. 170 This study used a real-time laser measurement method called DIAL 171, which was developed by BP to 168 SCAQMD 2/20/08, p. 16. See also SCAQMD, Source Test Report Conducted at Chevron/Texaco Refinery, El Segundo, California, Volatile Organic Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions from a Coke Drum Steam Vent, May 14, 2004, pp ; SCAQMD, Source Test Report Conducted at Valero (Ultramar) Refinery, Wilmington, California, Particulate Matter (PM), Volatile Organic Compounds (VOC), Speciated Hydrocarbons, Aromatic Hydrocarbons, and Sulfur Compound Emissions from a Coke Drum During the Steaming and Venting to Atmosphere Phases, July 22, 2008, pp (Exhibit 11). 169 See, e.g., ( We would like to cool coker cutting/quench water below the current degf to reduce deheading vapor cloud and hot spot eruptions. 90 degf is the target ). 170 Allan K. Chambers and others, Direct Measurement of Fugitive Hydrocarbons from a Refinery, Journal of the Air & Waste Management Association, v. 58, 2008, pp (hereinafter Chambers et al ) (Exhibit 12); Allan Chambers and Mel Strosher, Refinery Demonstration of Optical Technologies for Measurement of Fugitive Emissions and for Leak Detection, Prepared for Environment Canada, Ontario Ministry of the Environment, and Alberta Environment, March 31, 2006 (hereinafter Chambers and Strosher 2006 ) (Exhibit 13). 38

43 measure fugitive emissions from oil and gas processing facilities. DIAL has been used for the past two decades in Europe to measure refinery fugitive emissions by Spectrasyne and BP Research (pre-1992) 172 and more recently in Canada. 173 DIAL is particularly attractive where physical access is difficult or hazardous, such as around a coker. Coke drilling VOC emissions were measured using DIAL at a 140,000-bbl/day Canadian refinery, 174 whose overall emissions were about average for a group of refineries that had been tested using the same method. 175 At the time of the study, this refinery was processing a blend of 60 percent conventional sweet Alberta crude and 40 percent synthetic crude from upgrading of Canadian tar sands 176 and was operating within 3 percent of its capacity of 140,000 bbl/day. 177 There were no plant upsets or any unusual events during the DIAL study. 178 The refinery was considered to be very well run. 179 This study demonstrated that fugitive VOC emissions from coke drilling, which were omitted from the Hyperion application, is a major source of VOC emissions in a refinery. 180 The Canadian coker consisted of two drums operated on a 12-hour cycle. The study separately measured VOC emissions from the entire coker complex, first while one drum was being drilled and then while the same drum was being steam-purged. 181 The measurements were made in the plume, downwind from the coker. Thus, each measurement included emissions from the coking drum and fugitive components. During coke drilling for the Canadian study, VOC emissions (measured as C2+ hydrocarbons) ranged from 134 lb/hr to 507 lb/hr and averaged 295 lb/hr. During steaming, 171 DIAL or Differential Absorption LIDAR (Leak Identification and Repair) is an open-path optical sensing technique used for remote measurement of trace gases in the atmosphere. 172 Chambers et al. 2008, p See, e.g., County Administration of Vastra Gotaland, Fugitive VOC-Emissions Measured at Oil Refineries. Development and Results , 2003 (Exhibit 14). 173 Clearstone Engineering Ltd., A Review of Experiences Using DIAL Technology to Quantify Atmospheric Emissions at Petroleum Refineries, Final Report, September 6, 2006 (Exhibit 15). 174 The refinery is apparently the Petro-Canada Products Lts. Edmonton refinery, based on the reported fact that it is in Alberta and this is the only refinery in Alberta that has a coker. (Exhibit 16) Worldwide Refining Survey, Oil & Gas Journal, v. 103, issue 47, December 19, 2005 (Exhibit 17). 175 Chambers et al. 2008, Fig. 5; Chambers and Strosher, March 31, 2006, Sec A major modification is currently being built to allow the Petro-Canada refinery to process 100% tar sands derivatives. This modification will include a new coker. However, at the time of the measurements, the old coker was in use. 177 Chambers and Strosher 2006, p from Allan Chambers, Alberta Research Council, Inc, December 5, 2008; Chambers and Strosher 2006, p. 16 ( There were no significant upsets in the plant operation or hydrocarbon spills during the survey. ) 179 U.S. Environmental Protection Agency, VOC Fugitive Losses: New Monitors, Emissions Losses, and Potential Policy Gaps, 2006 International Workshop, October 25-27, 2006 (hereinafter EPA October 2006 ), p. 26 (Exhibit 18). 180 Chambers et al. 2008, p and Table 3 (17.1%). 181 Chambers et al. 2008, p and Table 5; Chambers and Strosher 2006, p

44 VOC emissions ranged from 82 to 247 lb/hr and averaged 141 lb/hr. Thus, the increase in emissions due to drilling alone would be 154 lb/hr, 182 using steaming to back out non-target emissions from the second coke drum and fugitive sources. These averages represent annual averages 183 and are background corrected. These DIAL measurements are also more likely to underestimate than overestimate VOCs because DIAL does not capture 100 percent of the plume 184 and the VOC measurements exclude a number of VOC species, such as alkenes and cyclic hydrocarbons. Thus, the reported VOC include only about 55 percent to 85 percent by weight of the total VOC present. 185 This study also detected VOCs emanating from piles of coke, but these data were not published as the coke pile was outside of the boundary of the refinery. 186 These emissions can be extrapolated to Hyperion by assuming the emissions are proportional to the coker throughput. The design capacity of the Canadian tested coker is 7,500 BPD, based on data reported in Worldwide Refining Surveys. 187 Thus, the DIAL study indicates that for every 1,000 barrels of coker feed, about 20 pounds of VOCs are emitted during each hour of drilling. As the throughput of the Hyperion coker will be 120,000 barrels per day, coke drilling could emit about 2,400 lb/hr of VOCs. Drilling emissions are similar to steam vent emissions. Thus, drilling emissions would be expected to have elevated concentrations of PM10, H 2 S, TRS, and CO. The high emissions that occur during decoking are so well known that the U.S. Chemical Emergency Preparedness and Prevention Office and the U.S. Occupational Safety & Health Administration ( OSHA ) jointly issued a bulletin warning of their hazards. They report, for example, that [f]ugitive mists and vapors from the cutting and the quench water can contain contaminants that pose a health hazard Increase in VOC emissions due to drilling alone: = 154 lb/hr. The steam purging emissions (141 lb/hr) are VOCs from fugitive component leaks in the coker complex plus VOCs from coke handling as steam purging takes place in a sealed drum while the second drum is still coking. This same background, fugitive component leaks and coke handling, is present in the drilling emissions (295 lb/hr). Thus, the difference is the VOCs from drilling alone. 183 Chambers et al., 2008, p ( The average of coker emissions during DIAL measurements while drilling and not drilling represent average annual coker area emissions. ); EPA October 2006, p. 27 ( There should be no fear of annualizing emission figures. The DIAL provides a very conservative estimate because it does not capture the whole plume. ) 184 See, e.g., EPA October 2006, p. 12 ( DIAL is more likely to underestimate emissions than overestimate them ). 185 Chambers and Strosher 2006, p Personal communication with Allan Chambers, Alberta Research Council, Inc., December 5, Worldwide Refining Survey, Oil & Gas Journal, December 24, 2001, p. 87; 2002 Worldwide Refining Survey, Oil & Gas Journal, December 23, 2002, p U.S. Chemical Emergency Preparedness and Prevention Office and U.S. Occupational Safety & Health Administration, Hazards of Delayed Coker Unit (DCU) Operations, August 2003, SHIB ; accessed March 27,

45 The emissions from this process are also reported in textbooks. These textbooks state, e.g., that coking air emission sources include decoking emissions (hydrocarbons and particulates) ; and, Particulate emissions from decoking can also be considerable. Coke-laden water from decoking operations in delayed cokers (hydrogen sulfide, ammonia, suspended solids) and coke dust (carbon particles and hydrocarbons) occur. 189 Additionally, the Texas Commission on Environmental Quality ( TCEQ ) requires that miscellaneous VOC sources, including cokers, be included in state emission inventories. In connection with this requirement, the TCEQ notes: Petroleum coke is removed from the wall of a coke drum by decoking or coke cutting. During the decoking or coke cutting process, VOC gases trapped in the coke will be released, creating hot spots and steam eruptions. Hydrocarbons may also be emitted during the associated cooling and venting of the coke drum prior to decoking. 190 Neither the 2007 nor the 2010 Hyperion Applications recognizes this source of emissions and does not include BACT analyses for coke drilling. These emissions can be and should be controlled. The owner of the Canadian refinery in the DIAL study installed an enclosed system for their coke drilling operations to capture the VOC emissions. 191 Another company, Conoco, has recently designed totally enclosed coke cutting systems for refineries in California and Germany. 192 The HOVENSA Consent Decree required enclosed drop zones and coke pit Coke Handling The wet coke is transferred from the pit beneath the cokers by clam shell or front end loader to a temporary storage pad to dewater. From the pad, it is moved to a coke chopper and then to the enclosed conveyor system for transport to the coke storage building. The December 2007 Application included PM and PM10 drop emissions from these various material handling operations, but failed to acknowledge that these operations are sources of VOC, TRS, and H 2 S emissions. 194 The wet coke is saturated with quench water, discussed above, which is known to contain elevated concentrations of VOCs, H 2 S, and TRS. These substances are released to atmosphere during open handling and storage. The Applications did not estimate VOC, H 2 S or TRS emissions from these open drop and storage operations nor include a BACT analysis to determine controls for these emissions. 189 James G. Speight, Environmental Analysis and Technology for the Refining Industry, Wiley-Interscience, 2005 (hereinafter Speight 2005 ), Table 4.1 and p Texas Commission on Environmental Quality, 2008 Emissions Inventory Guidelines, January 2009, Appendix A, Technical Supplements, p. A-2 (emphasis in original) (Exhibit 19) FR (5/14/07). 192 Franz B. Ehrhardt, Delayed Coking; From Bottoms Upgrading to Power Plant, An Attractive Alternative, available at U.S. and U.S. Virgin Islands v. HOVENSA LLC, ( HOVENSA Consent Decree ), Appendix H, Available at: December 2007 Application, pdf pp

46 Controls are feasible. For example, the coke chopper and storage pad could be enclosed and clam shells required. 195 C. Startup And Shutdown Emissions The periods when a stationary source starts up, shuts down, or malfunctions are among the most dangerous, because a facility at these times may release high levels of pollution. As a result, the Clean Air Act imposes strict emissions limitations on start-up, shut-down, and malfunction ( SSM ) periods. However, under the Amended Draft Permit, the HEC s pollution spikes during startup and shutdown periods are allowed to evade control because, while pollutants emitted during the startup and shutdown periods count against annual emissions limits, they are excluded from short-term emission limits, thereby allowing day-to-day exceedances as long as emissions even out by year s end. These short-term emission limits do not represent BACT. Indeed, in its 2008 Comments, EPA informed DENR that the short-term BACT limits which exclude emissions during SSM periods are the least stringent EPA has seen and are unacceptable. The BACT requirement, expressed as an emission limitation is designed to limit[ ] the quantity, rate, or concentration of emissions of air pollutants on a continuous basis. 196 As a result, although emission limits may vary to reflect special conditions during malfunction and atypical performance periods, DENR may not waive them. 197 Because the Amended Draft Permit does not include SSM periods in short-term compliance average periods and only includes SSM periods in 365-day average compliance periods, the Amended Draft Permit does not comply with PSD BACT requirements. D. Flares A flare is a vertical hollow pipe, topped off with a flare tip designed to optimize the mixing of air, fuel, and steam. Upstream of the flare stack, a system of relief ducts collects vent gases and routes them through knockout drums to remove liquids. The purpose of a flare is to dispose of large volumes of gases that are released during emergencies, such as power outages, process upsets, or acts of nature. Emissions from flares arise from burning three sources of gas: (1) pilot gases; (2) purge gases; and (3) emergency releases. 195 See, e.g., HOVENSA Consent Decree, Appendix H U.S.C. 7602(k), App. F (emphasis added). 197 See In re Indeck, PSD Appeal No , slip op. at 66, 2006 WL ( It is well established that BACT requirements cannot be waived or otherwise ignored during periods of startup and shutdown. ); see also In re Rockgen Energy Center, 8 E.A.D. 536, 553 (EAB 1999) (citations excluded) ( Startup and shutdown of process equipment are part of the normal operation of a source.... Accordingly, it is reasonable to expect that careful and prudent planning and design will eliminate violations of emission limitations during such periods ); In re Tallmadge Generating Station, PSD Appeal No , 2003 WL at *10; 65 Fed, Reg. 70,792, 70,793 (Nov. 28, 2000) (EPA rulemaking reiterat[ing] that, under the Act, all excess emissions during starts up, shuts down, or malfunctions episodes are violations of applicable emission limitations. ). 42

47 The Facility will operate four flares at the refinery (Units #36 through #40) and one flare at the IGCC power plant (Unit #50). The refinery flares are only permitted to combust releases from malfunction of equipment at the refinery that vent to the flares. The IGCC flare is permitted to combust releases during startups and shutdowns as well as malfunctions of the gasifiers. 1. The Flare BACT Analysis Is Incomplete The first step in a top down BACT analysis is to identify all available control options. Available control options are those with a practical potential for application to the emission unit and pollutions under evaluation. 198 The BACT analyses for the flares are found in the 2008 Statement of Basis. These analyses evaluated the following options for each pollutant: good combustion and flare minimization plan (for PM10). In addition, the BACT analysis evaluated flue gas cleanup for SO 2 ; post-combustion controls for NOx and CO; and design specifications for VOCs. 199 For each pollutant, DENR concluded that BACT for the flares is (a) good combustion practices and (b) a flare minimization plan. There are several problems with this determination, as discussed below. a. All Available Control Options Were Not Required There are a number of flaring control options that are available, feasible, and costeffective within the meaning of BACT that were not considered in the DENR flare BACT analyses. These include: First, flare gas recovery compressors are widely used to capture gases sent to refinery flares and recycle them into the fuel gas system. Citizens understand that compressors will be used. However, the level of compression is unknown, and the Amended Draft Permit does not require any recycle compression capacity. A proper BACT analysis should determine the level of compression to satisfy the requirement that BACT be based on the maximum degree of reduction that is achievable. EPA specifically requested that Hyperion provide justification on how the level of compression to be installed at the refinery will be sufficient to ensure that only malfunction emission will be combustion in the refinery flares? 200 DENR did not respond to this inquiry, instead stating that Hyperion has appropriate data that may be used to design a compression system to capture fuel gas during normal operation 201 This defers making a BACT determination to the future. BACT is a pre-construction requirement, and the BACT determination must be made before the construction permit is issued. Second, a common method used to minimize flaring is to spare critical equipment in a process, such as compressors. This prevents a release before it occurs. The record contains no evidence that sparing was considered specifically to reduce releases to the flares. 198 NSR Manual, p. B Statement of Basis, pp. 66, 84, 97, 105, 128, /11/10 Letter, 1/28/10 Attachment, p Statement of Basis, p

48 Third, the IGCC flare is used during planned startups and shutdowns of the gasifiers as there is no place to send the gases until the entire system is operational. The Application, for example, estimated that 186 hours of planned flaring would occur, emitting substantial amounts of criteria pollutants: 20.6 ton/yr of PM10; 68.8 ton/yr of SO 2 ; and ton/yr of NOx. These emissions can be substantially reduced by using a low ash, low sulfur coal during planned startups. This method is commonly used to limit planned startups and shutdown emissions at IGCC facilities. 202 This method was not evaluated in the BACT analyses and is both available and feasible for the Hyperion IGCC facility. The BACT analysis for the IGCC flare should be revised to require this option to satisfy BACT. Fourth, the design of the flare ultimately determines the combustion or destruction efficiency of the flare. The BACT analysis should have evaluated design destruction efficiencies for pollutants of concern, sulfur, VOCs, and CO, specified a level that corresponds to the maximum degree of reduction that is achievable, established it as a permit limitation, requested a supporting vendor guarantee, and required monitoring in the permit to demonstrate compliance. The BACT analysis also should have considered ground level flares, which are designated as BACT for flares by the Bay Area Air Quality Management District and have been required as BACT by the EPA. 203 The Amended Draft Permit should be modified to incorporate a limit on flare destruction efficient and monitoring to demonstrate that it is being achieved. Finally, the flare BACT analyses failed to consider monitoring to allow real time adjustment to flare operation, based on actual observation. Video cameras are commonly used to monitor the progress of flaring by operators in the control room. This helps identify smoking flares, oversteaming, detached plumes, and other similar operational problems that can cause elevated emissions and only be detected and thus corrected by actual observation. b. Good Combustion Practices Is Not Required By The Permit And Is Not Defined The BACT analyses concluded that good combustion practices is BACT. However, the Amended Draft Permit itself does not require good combustion practices, explain how it is to be achieved, nor define what the term means. Good combustion practices can reduce CO and VOCs, but may simultaneously increase NOx. Thus, the Amended Draft Permit should define the term and establish operating ranges on controlling variables, such as steam to hydrocarbon ratio, temperature, and velocity to assure good combustion is achieved. The NSPS standards do not satisfy BACT, but rather establish only a floor, or a starting place, for a BACT analysis. c. The Flare Minimization Plan Must Be Included In The Permit The BACT permit limit section of the Permit for all criteria pollutants refer to Section 12.0 for the refinery flares and Section 13.0 for the IGCC flare. These sections require flare minimization plans. These plans, coupled with good combustion practices, are the BACT 202 Potesta & Associates, Inc., Regulation 13 Permit Application for the Construction of a Coal to Gasoline Plant in Mingo County, West Virginia, Prepared for TransGas Development, LLC, December 2008 (Exhibit 20). 203 EPA, Statement of Basis and Ambient Air Quality Impact Report for a Clean Air Act Prevention of Significant Deterioration Permit, Big West of California, November 2, 2007, Sec. 7.5, p. 28 (Exhibit 21). 44

49 controls selected in the top down BACT analyses. 204 The flare minimization conditions, Sections 12.3 (refinery flare) and 13.3 (IGCC flare) do not contain the flare minimization plans. Rather, they contain a requirement to develop, maintain, and implement a flare minimization plan within 60 days prior to initial startup. BACT is a preconstruction requirement that must be in place before construction starts. Thus, the flare minimization plan must be developed and subject to public review, along with the draft permit and statement of basis. The flare minimization plans should be developed and circulated for public review before the final permit in this matter is considered by the Board in a contested case hearing. 2. The Flare BACT Analyses Excluded Malfunctions, Which Must Be Included In Potential To Emit The potential to emit must include startups, shutdown, and malfunction and the BACT analyses must evaluate controls for these emissions to satisfy the statutory and regulatory definition of BACT. The DENR did not include malfunction emissions in the potential to emit and did not prepare a BACT analysis for these emissions. The Amended Draft Permit defines a malfunction as any sudden and unavoidable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner. A failure caused entirely or in part by poor maintenance, careless operation, preventable equipment breakdown, or any other cause within the control of the owner or operator of the source is not a malfunction. 205 The DENR variously excluded emissions that occur during malfunctions from the potential to emit, emission limits, and the air quality analysis. 206 These exclusions are fatal flaws, as discussed below. In its June 11, 2010 comments in Issue #6, the EPA explained that startup, shutdown, and malfunction ( SSM ) emissions must be strictly prohibited or included in the potential to emit, citing its Title V Order in the BP case. 207 The Amended Draft Permit does neither, but rather allows malfunctions without penalty. The DENR disagreed with the EPA in the 2011 Statement of Basis, citing Alabama Power Company v. EPA as authority that potential to emit must be based on the design of a facility and U.S. vs. Louisiana-Pacific Corp. as authority that potential to emit is not the worst conceivable operation but rather maximum emissions that can be generated while operating the source as it is intended to be operated and as it is normally operated. 208 However, DENR s interpretation of potential to emit does not apply to flares. A malfunction is part of the normal operation of a flare and must be included in the flare s potential to emit, BACT analysis, and air quality analysis. A flare is designed to handle Statement of Basis, pp. 66 (PM10), 84 (SO 2 ), 97 (NOx), 105 (VOCs), 129 (CO). 205 Amended Draft Permit, Section 12.0, p Statement of Basis, pp , 60-61, /11/10 EPA Letter, 1/28/10 Attachment, Issue 6, pp Statement of Basis, pp

50 emergency releases from malfunctions at the equipment that it serves. Thus, a flare is turned on or used in its normal design capacity only when there is an emergency at an upstream unit. In all other circumstances, the flare is turned off. The flare itself is not malfunctioning and thus, even assuming DENR s argument had merit, there would be no basis under its argument that the flare emissions are malfunction emissions. Thus, malfunction emissions from upstream units that are served by a flare are normal emissions from flares. The flares are designed to handle the maximum expected release from upstream units that discharge to the flare, typically those that occur during a power outage. Moreover, it has long been EPA s position that malfunction emissions should be included in a facility s potential to emit calculation. In 2006, EPA wrote the New Jersey Department of Environmental Protection regarding the inclusion of emergency emissions in the potential to emit, based on consultation with their Office of Air Quality Planning ( OAQPS ) and Standard and Office of Enforcement and Compliance Assurance ( OECA ): The consensus is that for the purposes of determining PTE in the New Source Review (NSR) and the Title V programs, EPA has no policy that specifically requires exclusion of emergency (or malfunction) emissions. Rather, to determine PTE, a source must estimate its emissions based on the worst-case scenario taking into account startups, shutdowns and malfunctions. 209 This policy postdates the two federal cases that DENR cites as its authority. 3. The Amended Draft Permit Must Set Emission Limits For The Refinery Flares The Amended Draft Permit does not set any BACT limits on emissions from the four Refinery flares. Rather, it cites Chapter 12.0 of the Amended Draft Permit in the BACT limit sections, 210 which prohibits flaring at all times except during malfunction. A work practice standard is set for malfunctions. 211 BACT is an emission limitation based on the maximum degree of reduction that is achievable. A work practice standard may only be substituted if it is not feasible to measure emissions. The Amended Draft Permit does not contain any emission limits for criteria pollutants PM10, SO 2, NOx, VOC, or CO for the refinery flares when they are turned on, i.e., when malfunctions at upstream units are routed to the flares. EPA specifically requested an explanation for the absence of such emission limits. 212 The 2011 Statement of Basis argues that 209 Letter from Steven C. Riva, Chief, Permitting Section Air Programs Branch, EPA Region 2, to William O Sullivan, Director, Division of Air Quality, New Jersey Department of Environmental Projection, February 14, Amended Draft Permit, Sections Amended Draft Permit, Section /11/10 EPA Letter, 1/28/10 Attachment, Issue 6, p

51 work practice standards are imposed because it is not feasible to measure emissions from flares. 213 Three methods are available to determine emissions from flares. First, emissions from flares can be directly monitored using various optical remote sensing methods. Open-path Fourier Transform Infrared ( OP-FTIR ) has been used to measure emissions from two very large flares that burned waste gas consisting of over 99% CO saturated with water vapor at a low temperature and low concentrations of other hydrocarbon and sulfur gases. 214 FTIR has also been used to monitor emissions and combustion efficiency from natural gas flares. 215 Other tests by John Zink Co. have demonstrated that Passive Fourier Transform Infrared ( P-FTIR ) can be used to determine species concentrations and combustion efficiencies in the flare gases, remotely and continuously. 216 This method has been successfully used to measure the emissions from Marathon s main flare at its Texas City refinery 217 and at other refinery flares whose test reports have not yet been finalized. Further, EPA recommends the use of this method to determine the combustion efficiency of flares, 218 a key parameter required to estimate emissions. Second, emissions can be determined indirectly by measuring three variables: (1) the volume of gas sent to the flare, (2) the amount, or concentration, of pollutants in the gases, and (3) the flare s combustion efficiency. The flow rate and chemical composition of gases sent to a flare can be monitored in the flare header and used to calculate CO, VOC, and SO 2 emissions, pollutants typically released in the largest amounts during flaring. This method is required and routinely implemented at refineries in the Bay Area Air Quality Management District under Regulation 12, Rules 11 and 12 and South Coast Air Quality Management District under Rule EPA specifically advised DENR that there are methods that may be used by Hyperion to determine compliance with flare limits and listed the BAAQMD and SCAQMD rules noted above. EPA questioned why Hyperion rules out these methods. 219 The DENR did not respond to EPA s query as to measuring flow rate and concentration, but rather states there is no direct method to measure flare emissions. 220 This is not responsive. A direct method of monitoring is Statement of Basis, p. 67 ( The reason the above requirements were identified is because there is no direct method such as a performance test to demonstrate compliance with a numerical limit for a flare. ) 214 Thomas R. Blackwood, An Evaluation of Flare Combustion Efficiency Using Open-Path Fourier Transform Infrared Technology, v. 50 J. Air & Waste Mgmt Ass n, 1714, October 2000 (Exhibit 22). 215 Rainer Haus et. al., Remote Sensing of Gas Emissions on Natural Gas Flares, v. 7, Pure Appl. Opt. 853, 1998 (Exhibit 23). 216 See, e.g., David Castiñeira, A Computational Fluid Dynamics Simulation Model for Flare Analysis and Control, Ph.D. Thesis, University of Texas, Austin, May 2006), pp (Exhibit 24). 217 Clean Air Engineering, Performance Test of a Steam-Assisted Elevated Flare with Passive FTIR, Final Report, May 2010 (Exhibit 25). 218 Patrick Foley, U.S. Environmental Protection Agency, USEPA Petroleum Refinery Initiative, Slides, February 17, 2011, pp See also 6/11/10 EPA Letter, 1/28/10 Attachment, Issue 6, p Statement of Basis, Section 6.6, Issue #6, pp

52 not required to determine compliance with an emission limitation. Compliance can be determined using indirect monitoring, as used elsewhere in the Draft Amended Permit, e.g., for the IGCC flare and cooling tower. Third, the heat content of gases routed to a flare can be continuously monitored and used with emission factors to estimate emissions. This approach is used in the Amended Draft Permit to estimate emissions from the IGCC flare 221 and could also be used for the refinery flares. Emission factors can be developed specifically for a given flare(s) by periodic performance testing, e.g., the Marathon stack test, or in the absence of site specific factors, by using emission factors from EPA s Compilation of Air Pollutant Emission Factors ( AP-42 ). In fact, many permits, issued across the U.S., include emergency flaring emissions in potential to emit calculations and establish BACT limits for the flares. 222 Further, EPA consent decrees 223 have specifically required permit limits for refinery flares. Thus, DENR should modify Hyperion s Amended Draft Permit to include BACT emission limits for the refinery flares that apply to malfunctions and testing to assure continuous compliance. 221 Amended Draft Permit, p Iowa Department of Natural Resources, Air Quality Construction Permit, Homeland Energy Solutions, Application, Technical Support Document (see, e.g., at pdf 8, All emissions listed in Table 4 above are stated at the BACT emission limits. A BACT limit is specified for the flares.) (Exhibit 26), and Permits (Exhibit 27); Bay Area Air Quality Management District, Permit Evaluation and Statement of Basis for the Major Facility Review for Air Liquide Large Industries, April 2009 and issued Permit; Mississippi Department of Environmental Protection, Information Relative to the Draft Title V Operating Permit, Permit Issuance, October 2008 for Denbury Onshore LLC, Little Creek Facility (See: After the addition of the emergency flare, the facility s potential to emit of tons per year (tpy) of VOC s exceeds the Title V threshold of 100 tpy. (p. 1) and Based upon the potential to emit of this flare (i.e., year-round operation at maximum design flowrate), the construction of the flare for this new source of emissions would be a de minimis modification per APC-S-2, not requiring a construction permit. ) (Exhibit 28); IDEM, Technical Support Document for an Exemption for Koch Pipeline Company (at pdf 3: The assumption that the emissions could occur for 8,760 hours per year at multiple points along the pipeline would render the pipeline useless for its economic purpose (i.e., transport of ammonia). Instead, the potential to emit was calculated based on the maximum number of flaring episodes anticipated along the pipeline. ) (Exhibit 29); IDEM, Technical Support Document for an Exemption, Koch Fertilizer Storage and Terminal Company, January 6, 2003 (pdf 12 calculation of emissions from 240 hr/yr of emergency flaring); IDEM, Notice of Decision, Koch Fertilizer Storage & Terminal Company, December 6, 2002 (pdf 10 calculation of emissions from 300 hr/yr of emergency flaring); Illinois Environmental Protection Agency, Construction Permit, NESHAP Source, NSPS Source, PSD Approval, for ConocoPhillips Wood River Refinery, May 15, 2006, see, e.g., at pdf 11-12, emission limits on debottlenecked flares (Exhibit 30); Montana Department of Environmental Quality, Guidance Statement, Oil & Gas Well Facilities and Calculating Potential to Emit, June 1, 2007; Montana Department of Environmental Quality, Air Quality Permit, Bear Paw Energy, Inc., Permit # , April 17, 2008, see, e.g., pdf 2 (PBE shall limit the hours of operation of the emergency flare to 1,800 hours during any rolling 12-month period. This will result in emissions from the emergency flare of less than 41.4 tons of sulfur oxides (SOx) and 45.8 tons of CO during any rolling 12- month time period. ) and pdf 6 ( In order to maintain potential emissions below major source threshold, use of the emergency flare is limited to 1,800 hours per year. ) (Exhibit 31); Montana Department of Environmental Quality, Air Quality Permit, Encore Energy Partners Operating, LLC, Permit , Administrative Amendment, September 9, 2007, see, e.g., pdf 1 ( Encore shall limit the volume of gas routed to the emergency flare pit (5-EF) to 4.42 million standard cubic feet (MMScf) of gas flaring during any rolling 12-month time period (ARM ). ) and calculations at pdf 18 (Exhibit 32); Montana Department of Environmental Quality, Air Quality Permit, Permit , May 27, 2004, see, e.g., pdf 13 ( SO 2 emission increases, due to upset conditions or discontinuance of the SRU, shall be offset by an equivalent rate from any other sources covered by this permit (Exhibit 33). 223 Murphy Consent Decree, U.S. et al v. Murphy Oil, Civil Action No. 3:10-cv bbc, August 16, 2010, p

53 4. The Amended Draft Permit Must Limit Emissions To Those Included In The Ambient Air Quality Modeling An applicant for a PSD permit is required to conduct an analysis of the air quality impacts due to construction and operation of the new source or modification. This analysis must demonstrate that the new emissions in conjunction with other applicable emission increases and decreases from existing sources will not cause or contribute to a violation of any applicable NAAQS or PSD increment. A PSD permit cannot issue if the new emissions will cause or contribute to a violation of a NAAQS or increment. 224 The appropriate demonstration has not been made for the HEC as worst-case emissions were not modeled. This is critical here as modeled emissions are very close to applicable standards, within 98% of the 1-hour SO 2 standard, 94% of the 1-hour NO 2, 225 and 98% of the 24-PM2.5 standard 226, based on the Applicant s modeling. As discussed elsewhere, the Applicant s modeling underestimates these impacts. The modeling must be based on a source s maximum allowable emission limit or federally enforceable permit limit. 227 The record contains no support for the emissions that were modeled. These emissions should have been based on the design basis of the flares, calculated as the design flare flow rate times the maximum potential concentration for each criteria pollutant based on the same averaging time of standard. Instead, as discussed above, DENR and Hyperion assert that malfunction emissions do not have to be included in the potential to emit. Flares are designed to handle the largest potential malfunction, typically due to a power outage. a) Refinery Flares The table below compares the emissions that were modeled with the emissions calculated in the December 2007 Application. 228 Refinery Flare Emission Comparison (lb/hr/ton/yr) PM10 SO 2 NOx Modeled 0.01/ / /0.3 Emission Estimate 0/0 0/0 0.1/0.3 Permit Limit See CAA 165(a)(3), 42 U.S.C. 7475(a)(3); 40 CFR (k)-(m). 225 Letter from Colin Campbell, RTP, to Kyrik Rombough, DENR, Re: Hyperion Energy Center Response to Information Request Letters of July 9 and August 23, 2010, Addendum 2,Table S, Table 7-127, p Fed. Reg. 68,218, 68,240 (Nov. 9, 2005) codified at 40 CFR 51, Appendix W; Sec a and NSR Manual, pp. C December 2007 Application, pdf

54 The emission calculations are based only on the refinery flare pilots. Thus, the comparison shows that the only emissions included in the air quality modeling for the refinery flares is pilot emissions. In other words, the modeling did not include emissions from malfunctions. These flares are designed to handle malfunctions of the units they serve. The maximum emissions occur during these malfunctions. Thus, the modeling has underestimated air quality impacts, perhaps fatally so. This was not corrected in the 2010 Application. The Amended Draft Permit should be modified to include enforceable permit limitations that restrict emissions of PM10, SO 2, and NOx to no more than those that were modeled, as summarized in the above table, or the modeling should be revised to use the maximum potential emissions under the flares design capacity and that capacity appropriately limited in the Amended Draft Permit. b) IGCC Flare The following inset table compares the emissions that were modeled with the emissions estimates presented in the December 2007 Application. 229 IGCC Flare Emission Comparison (lb/hr/ton/yr) PM10 SO 2 NOx Modeled: Pilot 0.02/ / /0.3 Modeled: Flare 4.76/ / /234.3 Emission Estimate: Pilot 0.02/ / /0.3 Emission Estimate: Flare 4.8/ / /5.1 Permit Limit (12-mo roll) -/0.6 -/1.5 -/5.4 This table shows that the modeling is based on the same emission rates for the flare pilot and gasification events as calculated in the December 2007 Application. However, the emissions in the December 2007 Application are based on only 189 hours of planned startup events. 230 They do not include emissions from malfunctions or shutdowns, but rather only the initial start, hot restarts, warm restarts, and cold restarts. 231 This error was not corrected in the Amended Draft Permit. These types of failures (unplanned releases due to emergency conditions in the IGCC power plant) have been widely documented in the gasification industry and are not rare occurrences. They occur as a result of harsh processing conditions unique to coal/coke gasification due to high concentrations of substances that corrode, erode and foul processing equipment such as ash, slag, sulfur compounds, and various organic acids. These components cause overheating, plugging, corrosion, erosion, and fouling of common processing equipment such as heat exchangers, coolers, slag handling equipment, and pump, compressor rotors, 229 December 2007 Application, pdf Ibid. 231 December 2007 Application, p. 133, Table

55 impellers and blades; fouling and associated corrosion of heat exchangers and coolers. 232 For example, the gasifiers at the Puertollano, Spain, IGCC plant experienced unplanned outages 12.8% of the time they would otherwise be available, compared to 8.6% planned outages. 233 In other words, the modeling did not include emissions from the maximum potential emissions from the IGCC flare as it excluded malfunctions. This flare is designed to handle malfunctions of the units it serves. The maximum emissions occur during these malfunctions. Thus, the modeling has underestimated air quality impacts. This issue was not corrected in the Amended Draft Permit. Malfunction emissions must be included in air quality modeling. The West Virginia Air Quality Board, for example, recently remanded a permit that included an IGCC flare for failure to demonstrate on the record that the potential to emit included emissions from startups, shutdowns, and malfunctions. 234 The emission limits in Section 13.0 of the Amended Draft Permit for the IGCC flare do not address this concern for two reasons. 5. IGCC Flare Permit Limits Not Based On Worst-Case Emissions First, the IGCC flare emission limits do not represent worst-case emission rates because they are based on very long averaging times, 12-month rolling averages. The relevant NAAQS and PSD increments have averaging times as short as 1 hour (for CO, NO 2, SO2), 3 hours (for SO 2 ), 8 hours (for CO), and 24 hours (for PM10, SO 2, NOx). 235 The longer averaging times in the Amended Draft Permit mask shorter-term emission spikes by averaging them with longer runs of relatively low emissions. The very high short-term spikes are often the cause of violations of NAAQS and increments. Spikes may occur, for example, due to malfunctions. However, under the Amended Draft Permit s averaging regime, these spikes would be averaged with planned startup and shutdown events which would likely have lower emissions due to their planned nature. A 12-month rolling average essentially hides violations that would occur during malfunctions or any other spikes. The shorter term emission spikes represent the facility s maximum or worst-case emissions, which must be modeled to demonstrate that the new emissions do not 232 Neville A.H. Holt, Operating Experience and Improvement Opportunities for Coal-Based IGCC Plants, Materials at High Temperatures, v. 20, no. 1, pp. 1-6, 2003 (Exhibit 34); W. Schellberg and others, World s Largest IGCC Celebrates 10th Anniversary, 25th Annual International Pittsburgh Coal Conference, September 29 - October 2, 2008 (Exhibit 35); EPRI, Evaluation of Alternative IGCC Plant Designs for High Availability and Near Zero Emissions, December2006; Neville A.H. Holt, IGCC Technical Status, Trends and Future Improvements, ACS Meeting, San Francisco, March K. Radtke & M. Heinritz-Adrian, Uhde PRENFLO: PSG and PDQ, Latest Developments based on 10 Years Operating Experience at Elcogas IGCC, Puertollano, Spain (Exhibit 36); M. Hooper & B. Richards, Uhde Corporation of America, Presentation at Gasification Technologies Conference, Washington, D.C., October 5-8, 2008, p Final Order in Sierra Club et al. v. Div. Of Air Quality, West Virginia Dept of Environmental Protection and Transgas Development LLC, Appeal No AQB, March 28, Compare, e.g., Amended Draft Permit, Section 13.0, Table 13-1 with 40 CFR , 50.11, (NAAQS for SO 2, PM10, PM2.5, CO, NO 2 ) and 40 CFR 52.21(c) (increments for PM10, SO 2, NO 2 ). 51

56 cause or contribute to violations of NAAQS. 236 These maximum emissions should be based on the design capacity of the flare. The Amended Draft Permit should be modified to include the 1-hour average emission rates that were included in the modeling and are summarized in the table above. 6. IGCC Flare Permit Limits Are Not Enforceable Second, the IGCC flare emission limits are not practically enforceable as the Amended Draft Permit does not require sufficient monitoring to determine compliance. Compliance will be determined using engineering calculations, as set out in Condition The referenced condition requires only measuring the flow rate and visible emissions. Otherwise, the Amended Draft Permit requires determining the higher heating value and total sulfur content of the gas flow and calculating monthly PM10, SO 2, NO 2, VOCs, and CO. However, the Amended Draft Permit is silent on how to determine and calculate these values. No test methods are specified. No emission factors are cited. No equations are presented. No information is provided as to how one will determine and calculate 12-month rolling average emissions. It is not possible to calculate emissions from the measured quantities flow rate and visible emissions. Thus, presumably, various estimating procedures involving unidentified emission factors, such as AP-42 and engineering calculations will be used. The Amended Draft Permit must be revised to specify test methods, testing frequency, and calculation procedures that will be used to determine compliance with the 12-monthly rolling average emission limits in Condition E. Cooling Tower The Facility will include a 13-cell 130,000-gpm process cooling tower (Unit #41) equipped with high efficiency drift eliminators. 238 The Amended Draft Permit fails to provide adequate monitoring provisions to demonstrate compliance with BACT limits for PM10 and H 2 S and reduced sulfur compounds. 1. Particulate Matter Emissions DENR determined a drift fraction of % as BACT for particulate matter emissions from the cooling tower. 239 Accordingly, the Amended Draft Permit specifies the design efficiency for the cooling tower drift eliminators at percent 240 and sets a BACT permit limit for PM10 of 1.2 lb/hour 241, which was calculated based on three parameters: a TSD content 236 See discussion of this issue in In re Northern Michigan University Ripley Heating Plant, EAB, PSD Appeal No , February 18, 2009, pp and NSR Manual, p. B Amended Draft Permit, Section 13.1, Table 13-1, note 1, p Amended Draft Permit, Table 1-1, p Statement of Basis, Table 3-9, p Amended Draft Permit, Condition 5.3, p Amended Draft Permit, Table 4-1, p

57 of the circulating water of 3,750 parts per million ( ppm ), the design cooling tower circulating rate of 130,000 gpm, and the design efficiency of the drift eliminators. 242 Compliance with the pounds-per-hour limit for PM10 emissions is based on Condition , which requires analysis of the TDS content in a 24-hour composite sample of the cooling tower water and calculation of the emission rate based on a mass balance calculation. The mass balance calculation for PM10 emissions (in lb/hr) is based on the TDS content measured in cooling water, the maximum water circulation for the sampling period, and the design efficiency of the drift eliminators: E = W (60 minutes/hour) (TDS/1,000,000) (8.34 lb/gal) (Eff/100) where TDS = total dissolved solids in parts per million by volume by weight; W = maximum water circulation for the sampling period for the system in gallons per minute; and Eff = design efficiency for the drift eliminators 244 Condition 10.15, as written, is not effective to ensure that the Facility complies with the BACT determination for the cooling tower for several reasons: First, the BACT emission limit of 1.2 lb/hour for particulate matter emissions was determined based on three parameters. Only two of these parameters, TDS content and water circulation rate, are measured during the test required in Condition The Amended Draft Permit fails to require monitoring of the drift fraction and instead uses the design efficiency for the drift eliminators to calculate emissions. Compliance based on calculations using design parameters is a self-fulfilling prophecy. It is not possible to determine if the emission rate (in lb/hr) is met unless it is determined that the drift eliminators operate at their design drift rate. Vendor certification for new equipment is not adequate to assure design performance over the life of the cooling tower. Drift eliminators degrade with age and composition of the circulating water. At a minimum, the permit must require periodic inspection of the drift eliminators to assure that they are clean and in good working order and associated recordkeeping. A recently proposed emission control plan for a cooling tower by the Massachusetts Department of Environmental Protection ( MassDEP ), for example, requires quarterly inspection of the cooling towers from internal walkways and an annual complete inspection of the cooling tower by an inspector with recognized expertise in the field of natural draft cooling tower drift eliminators Application, Appendix C Emissions Calculations, Table Cooling Tower. 243 Amended Draft Permit, Footnote 3 to Table 4-1, p Amended Draft Permit, Condition 10.15, pp Massachusetts Department of Environmental Protection, Proposed Conditional Approval, Brayton Point Station, Somerset, Massachusetts, February 11, 2009, Section VIII.F.3, p. 26; 53

58 Second, Condition fails to explicitly specify that the TDS content be determined in the cooling tower recirculating water. Instead, it ambiguously requires measuring TDS content in cooling tower water. As written, the Condition could be interpreted as TDS content measured in the cooling tower makeup water. As the TDS content in makeup water is lower by a factor corresponding to the number times a given volume of water recirculates through the cooling tower before being discharged (cycles of concentration), this would result in a continual underestimate of actual particulate matter emissions by a factor equivalent to the number of cycles of concentration. Likewise, the Amended Draft Permit fails to explicitly define that the measured flow rate is that of the circulating water rather than the makeup water or blowdown. Third, in order to calculate the BACT emission rate of 1.2 lb/hour of particulate matter, Hyperion assumed the cooling tower design circulating rate of 130,000 gpm and a maximum TDS content of 3,750 ppm in the circulating water. Yet, the Amended Draft Permit sets no limits for the TDS content in circulating water. However, based on the Amended Draft Permit s monitoring requirements, the 1.2 lb/hr BACT limit would be equally satisfied if, for example, the cooling tower would operate at a circulation rate of 100,000 gpm and a TDS content of 4,950 ppm. 246 Fourth, the Amended Draft Permit fails to require any compliance monitoring reporting of cooling tower emissions. The Amended Draft Permit should be revised to require drift rate tests for the cooling tower drift eliminators (at least once every five years), clarify the ambiguous terminology to require measuring TDS content in cooling tower recirculating water, set limits for the cooling tower recirculating rate and the TDS content in recirculating water, and establish compliance monitoring reporting requirements. F. Reduced Sulfur Compounds Emissions of reduced sulfur compounds including hydrogen sulfide emissions from the cooling towers are likely due to leaks into cooling water used to cool process units or gas streams containing reduced sulfur compounds. The Amended Draft Permit does not contain a BACT emission limit for emissions of H 2 S or other reduced sulfur compounds from the cooling tower nor does it require any monitoring. The Amended Draft Permit must definitively rule out the possibility of such emissions or quantifiably account for them, perform a BACT analysis, and include an enforceable permit limit for cooling tower H 2 S and TRS emissions. G. Fugitive Particulate Matter Emissions From Facility Roads DENR previously received comments from both EPA and Citizens that fugitive particulate matter emissions from Facility roads were not properly identified, quantified, modeled and permitted. 247 DENR responded that the permit and accompanying documents 246 (100,000 gpm)(60 min/hour)(4,950/1,000,000)(8.34 lb/gal)(0.0005/100) = 1.24 lb/hr. 247 Citizens 2008 Comments, Sections V.B, p. 13, VI.F.7 and VI.F.8, p. 28, and 2008 EPA Comments, Section XIII, p

59 include sufficient detail and that fugitive particulate matter emissions were properly permitted and that it therefore did not recommend any changes to the permit. 248 Citizens disagree and reiterate and further discuss these issues below. 1. Failure To Provide Adequate Information On Facility Road Network Citizens previously commented that the permit record does not contain a sufficiently detailed map of the site road network necessary to verify Hyperion s fugitive particulate matter emissions calculations and modeling analysis. 249 In response, DENR stated that Hyperion s modeling files contain the parameters for the roads that were modeled, which includes the coordinates of each section of the road modeled, the base elevation, release height, horizontal and vertical dimensions, and the particulate emission rates. 250 This response is not sufficient. In order to verify that the particulate matter emissions from Facility roads were correctly modeled, i.e., that the correct modeling parameters were used, a reviewer needs a to-scale map of the Facility s road network that shows the location, length and width of the modeled roads. This was not provided and therefore the modeling parameters cannot be verified. 2. Failure To Quantify And Model Particulate Matter Emissions From All Roads Review of the emission calculations shows that Hyperion quantified particulate matter emissions only for gasoline and propane loading roads assuming a total length of 0.28 miles (0.56 miles roundtrip). 251 Clearly, the Facility will have more than 0.28 miles (about 1,400 feet) of roads on site. The inset aerial view below, which was provided by Hyperion, shows that the Facility will indeed have numerous on-site roads including a perimeter road, roads to all tanks, roads throughout the refinery and IGCC power plant, wastewater treatment plant, and other facilities at the HEC DENR Response, No. 5, pp. 6-7, No. 20, p. 20, No. 129, pp , No. 130, pp Citizens 2008 Comments, Section V.B., p DENR Response, No. 5, pp December 2007 Application, Appendix C, Emissions Calculations, Table Paved Roads. 55

60 Aerial view of the Facility (Hyperion Contested Case Hearing Exhibit 1021) Fugitive entrained road dust emissions from vehicle traffic on these roads, including maintenance, loading, and employee vehicle movement, must be included in the Facility s PTE emission calculations and the ambient air quality modeling. Review of the modeling files confirms that Hyperion modeled particulate matter emissions not for the entire road network but only for the gasoline and propane customer road with a total length of 0.28 miles, as shown in the figure below AERMOD input file named pmtn04.adi: File: C:\Lakes\ISC-AERMODView\Our\1newHyp\PM10\August 2008runs\2004\pmtn04.ADI, dated August 8,