George E. Hays Attorney at Law 236 West Portal Avenue #110 San Francisco, CA Office: (415) Fax: (415)

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1 George E. Hays Attorney at Law 236 West Portal Avenue #110 San Francisco, CA Office: (415) Fax: (415) Steven M. Pirner, Secretary Department of Environment and Natural Resources PMB 2020 Division of Environmental Services Air Quality Program 523 East Capitol Joe Foss Building Pierre, South Dakota RE: Sierra Club and Clean Water Action Comments on the Draft Revised Big Stone Title V Permit Dear Secretary Pirner: I am submitting comments on behalf of Sierra Club and Clean Water Action regarding a draft revision to the Big Stone Title V air quality permit made by the South Dakota Department of Environment and Natural Resources ( DENR ). DENR made the draft revision available for public comment on approximately February 9, 2009 and proposed the draft revision in an attempt to address issues raised in EPA s January 22, 2009 objection to the previously proposed Big Stone Title V permit. As the comments below detail, this draft revision fails to address adequately EPA s objection. Accordingly, the draft revised Big Stone Title V permit fails to ensure compliance with all applicable requirements and, therefore, cannot be lawfully issued by the South Dakota Board of Minerals and Environment ( BME ). This comment letter focuses on the changes to the Big Stone Title V permit currently proposed by DENR and does not discuss those other deficiencies in either the Title V permit or the Unit #13 PSD permit that we have previously identified. We still find the Big Stone Title V and PSD permits to be seriously deficient, however, for all of the reasons put forth in our 2008 petition, motions, and post-hearing briefs. Accordingly, we hereby incorporate those documents and related testimony into this comment letter. The deficiencies related to the draft revisions to the Big Stone Title V permit are as follows: I. The Draft Revision to the Big Stone Title V Permit Fails to Respond Adequately to EPA s Objection #2: Lack of Proper PSD Applicability Analysis for SO and NO. 2 x As we have repeatedly informed the State, there are only two ways for a new unit such as Unit #13 to avoid prevention of significant deterioration ( PSD ) review for sulfur dioxide ( SO ) 2

2 Page 2 and nitrogen oxides ( NO x ). The primary option allowed under the PSD regulations is to net out of PSD review by following the requirements in the definition of net emissions increase in 40 C.F.R (b)(3) and associated definitions, incorporated by reference into ARSD 75:36:09:02, for creating creditable emission increases and decreases. The other option would be for Otter Tail to obtain a plantwide applicability limit (PAL) pursuant to 40 C.F.R (aa) for SO 2 and NO x. The plantwide limits that were in the November 2008 proposed Big Stone Title V permits did not meet either of these options, and thus EPA objected to the proposed Title V permit for the lack of a proper PSD applicability analysis for SO 2 and NO x. To correct this deficiency, EPA informed the state it had three options: conduct appropriate PSD netting, establish a PAL, or conduct PSD major modification review for the SO 2 and NO x emissions from Unit #13 and revise the PSD permit. See EPA s January 22, 2009 objection letter, Enclosure at 5-8. DENR chose Option 1, to conduct appropriate PSD netting. However, the draft revised Big Stone Title V permit fails to allow Unit #13 to net out of PSD review for SO 2 or NO x properly for several reasons as follows. A. The Draft Title V Permit Cannot Be Used to Create New Requirements to Allow Unit #13 to Net Out of PSD Review. DENR is using this Title V permit to create limits on the potential to emit for SO 2 and NO x for both Unit #1 and Unit #13 in order to allow Unit #13 to net out of PSD review for those pollutants. See Section 9.0 of the draft permit ( PSD Exemption ). Title V permits, however, cannot be used for this purpose; rather, Title V permits are only meant to consolidate pre-existing requirements into a single, comprehensive document, and then assure compliance with those requirements: Each permit issued under this subchapter shall include enforceable emission limitations and standards, a schedule of compliance, a requirement that the permittee submit to the permitting authority, no less often than every 6 months, the results of any required monitoring, and such other conditions as are necessary to assure compliance with applicable requirements of this chapter, including the requirements of the applicable implementation plan. See 42 U.S.C. 7661c(a). See also 40 C.F.R. 70.6(a): (a) Standard permit requirements. Each permit issued under this part shall include the following elements: (1) Emission limitations and standards, including those operational requirements and limitations that assure compliance with all applicable requirements at the time of permit issuance.

3 Page 3 Id. (emphasis added). (i) The permit shall specify and reference the origin of and authority for each term or condition, and identify any difference in form as compared to the applicable requirement upon which the term or condition is based. See also ARSD 74:36:05:16.01: Operating permit requirements. Each permit issued for the operation of a Part 70 source must contain: * * * (8) Emission limits and standards, including operational requirements and limits for all regulated emission units, necessary to assure compliance with applicable requirements of the Clean Air Act and including the following: Id. (emphasis added). (a) The reference of authority for each term or condition. th See also Romoland Sch. Dist. v. Inland Empire Energy Ctr., LLC, 548 F.3d 738 (9 Cir. 2008)( Rather than imposing an additional set of requirements on pollution sources, this permitting scheme was intended to incorporate the requirements of the Act (including SIP requirements) that are [already] applicable to the source. ")(quoting S. Rep. No , at 350 th (1989)); Sierra Club v. Johnson, 541 F.3d 1257, 1260 (11 Cir. 2008) ( Title V does not generally impose new substantive air quality control requirements. ); Ohio Pub. Interest th Research Group, Inc. v. Whitman, 386 F.3d 792, 794 (6 Cir. 2004) ( Title V does not impose new obligations; rather, it consolidates pre-existing requirements into a single, comprehensive document for each source, which requires monitoring, record-keeping, and reporting of the th source's compliance with the Act. ); Sierra Club v. Leavitt, 368 F.3d 1300, 1302(11 Cir. 2004)( Title V imposes no new requirements on sources. Rather, it consolidates existing air pollution requirements into a single document.... ); ( Lafleur v. Whitman, 300 F.3d 256, 262 (2d Cir. 2002) ( Although these operating permit programs do not impose new substantive air quality control requirements, the permits themselves must include limitations on emissions and other conditions (such as regular monitoring, recordkeeping, and reporting) necessary to ensure compliance with the provisions of the CAA, including the PSD program (if applicable) ); United States v. E. Ky. Power Coop., Inc., 498 F. Supp. 2d 1010, 1011 (E.D. Ky. 2007) ( Title V permits were not intended to impose new substantive requirements. ) (citing 57 Fed. Reg. 32,250, 32,250 (July 21, 1992)).

4 Page 4 In 2004, EPA sent a Notice of Deficiency to the State of Wisconsin regarding its implementation of the Title V program that confirms that Title V permits cannot be used to create new requirements. See Notice of Deficiency for Clean Air Act Operating Permit Program in Wisconsin, 69 Fed. Reg , (March 4, 2004) ( Wisconsin s rules do not ensure these source specific permit terms remain in effect and exist independently of a title V permit.... Because Wisconsin s rules do not assure that construction permit conditions exist independently of title V permits and because its interpretation that its title V program provides the authority to create source specific limitations, the State s program does not meet the program approval requirements of title V and part 70. ). See also Notice of Deficiency for Clean Air Act Operating Permit Program in Indiana, 66 Fed. Reg , (Dec. 11, 2001) ( Because Indiana's rules do not assure that construction permit conditions exist independently of title V permits, the state s program does not meet the program approval requirements of title V and 40 CFR part 70. ). Because the PSD avoidance limits imposed in Section 9.0 of the permit have no Clean Air Act antecedent, they are illegal and cannot remain in the Title V permit. B. A Valid PSD Permit Must be in Place Before a Title V Permit Can Be Issued for the Entire Facility, the Current PSD Permit is Invalid Because it Fails to Address SO 2, and NO x, and the Title V Permit Cannot Be Used to Create PSD Avoidance Limits Because it Cannot Exist Without the PSD Permit Being Created First. The fact pattern in this case provides a perfect illustration for why Title V permits cannot be used to create PSD avoidance limitations. The permits at issue in this matter are mutually dependent. By itself, the PSD permit is defective because Unit #13 would be a major modification for SO 2 and NO x, but the permit does not cover those pollutants. Thus, some unit-specific limitation on the emissions Unit #1 to create creditable emission reductions for netting is necessary before the state can issue a PSD permit for Unit #13 that does not address SO and NO. 2 x In addition to the reasons stated above, the Title V permit is not the appropriate vehicle for creating the PSD avoidance limits for Unit #13 because Unit #13 cannot be covered in the Title V permit without the PSD permit (since Unit #13 cannot lawfully exist without a PSD permit). Furthermore, if a Title V permit is going to be issued that covers the entire new facility (Units 1 and 13), then that permit must contain all applicable requirements, including the requirements of the PSD permit. 2 2 Thus, to lawfully permit the construction of Unit 13 without covering SO and NO, some other legal mechanism, such as a source-specific SIP revision would first have to be adopted limiting the emissions of those pollutants from Unit 1 and from the anticipated Unit 13. Then the state can issue the PSD permit, and then the Title V permit. Following this course of proceedings

5 Page 5 would avoid the flaws created by the state s current proposal. C. The Draft Title V Permit Fails to Require that the SO 2 and NO x Emission Reductions At Unit #1 Be Enforceable as a Practical Matter At and After the Time Construction Commences on Unit #13. Even if the Title V permit could be used to create PSD avoidance limits, the limitations in the permit are flawed because they only begin to apply upon the initial startup of Unit #13. See Permit Conditions 9.2 and 9.5. To be valid, these reductions actually must be in place before construction commences on Unit 13. The definition of net emissions increase, 40 C.F.R (b)(3), requires that increases and decreases in actual emissions be taken into account to the extent they are contemporaneous and otherwise creditable. Subsection (vi) of this provision specifically covers decreases and specifically provides that a decrease in actual emissions is creditable only to the extent that... it is enforceable as a practical matter at and after the time that actual construction on the particular change begins. 40 C.F.R (b)(3)(vi)(b)(emphasis added). The conditions placed in the Title V permit fail to meet this requirement because they only take effect once Unit #13 commences operation. This distinction is important because, among other things, Otter Tail is relying on one scrubber to control SO 2 emissions from both Unit #1 and #13, but that scrubber will not be place when construction on Unit #13 begins. Consequently, if DENR comes up with a legally permissible mechanism for limiting the emissions from Unit #1, if Otter Tail insists on retaining the joint scrubber concept, Otter Tail will have to limit operation at Unit #1 to meet this requirement until the scrubber is operational. D. DENR s Netting Analysis and SO 2 and NO xemission Limitations Are Based on Improper Baseline Actual Emissions for Big Stone. Even if DENR manages to resolve the issues raised Sections I(A), (B), and (C) of this letter, DENR s netting analysis is still flawed because the proposed SO 2 and NO x emission limits fail to comply with other regulatory requirements to net Unit #13 out of PSD review. As mentioned above, the definition of net emissions increase requires that, to be creditable in netting out a particular change from PSD review, emission increases and decreases must be contemporaneous with the particular change and otherwise creditable. 40 C.F.R (b)(3)(i)(b). The contemporaneous timeframe is defined as beginning on the date five years before construction on a particular change commences and ending on the date the increase on the particular change occurs. 40 C.F.R (b)(3)(ii). The definition of net emissions increase also provides that baseline actual emissions as defined in 40 C.F.R (b)(48) shall apply for calculating

6 Page 6 emission and decreases. Baseline actual emissions are defined for existing electric utility steam generating units such as Unit #1 as: the average rate, in tons per year, at which the unit actually emitted the pollutant during any consecutive 24-month period selected by the owner or operator within the 5-year period immediately preceding when the owner or operator begins actual construction of the project C.F.R (b)(48)(i); ARSD 74:36:09:02. At this point, the absolute earliest actual construction could begin on Unit #13 would be in May or June of 2009, after the state adopts a new proposed Title V permit and EPA has concurred. Thus, DENR should not have looked back at Unit #1's SO 2 and NO x emissions any earlier than May of Yet, DENR relied on emissions at Unit #1 from calendar years 2003 and 2004 to reflect baseline actual emissions. DENR s Statement of Basis for Draft Revised Big Stone Title V Permit, at 6. Specifically, DENR relied on baseline actual emissions for Unit #I of 13,278 tons per year (tpy) of SO and 16,448 tpy of NO. Id. 2 x A review of the monthly emissions data submitted to EPA s Clean Air Markets Database (CAMD) for Unit #1 shows that these level of emissions are higher than the average rate at which the unit emitted SO 2 and NO x during any consecutive 24-month period from May through September 2008 (which is the most recent data available in EPA s CAMD ). Attachment 1 to this letter shows the rolling 24-month average emissions from May 2004 through September 2008, and the maximum consecutive 24 month average emissions during this period are 11,720 tpy for SO 2 and 14,609 tpy for NO x. Thus, only emission reductions below these levels of baseline actual emissions can be considered creditable emission reductions to net Unit #13 out of review. The proper baseline actual emissions for SO 2 are 1,508 tpy lower than the baseline emissions relied on by DENR in its SO 2 netting calculations for Unit #13. For NO x, the proper baseline is 1,839 tpy lower. Accordingly, the SO 2 and NO x emission limits for Unit #1 in the draft revised permit do not create sufficient creditable emission reductions to allow Unit #13 to net out of review because Unit #13 would have potential emissions considering DENR s proposed emission limits of 2,268 tpy for SO 2 and 1,314 tpy for NO x. Specifically, subtracting the draft Unit #1 emission limits from proper baseline actual emissions shows the following creditable emission reductions that would be created by the Unit #1 SO and NO emission limits of the draft revised Title V permit: 2 x 1 Data downloaded from

7 Page 7 Creditable SO 2 Emission Reductions at Unit #1: 11,720 tpy - 11,005 tpy = 715 tpy. (Amount needed: 2,268 tpy). Creditable NO x Emission Reductions at Unit #1: 14,609 tpy - 15,104 tpy = 0 creditable emission reductions. (Amount needed: 1,314 tpy). Clearly, the Unit #1 SO 2 and NO x emission limits of the draft Title V permit do not create sufficient creditable emission reductions to net Unit #13 out of PSD review for these pollutants. The definition of baseline actual emissions does allow for the permitting authority to select a different time period to reflect baseline actual emissions upon a determination that it is more representative of normal source operation. 40 C.F.R (b)(48)(i). However, DENR has not made any determination that the years of emissions it relied on to establish baseline actual emissions (i.e., 2003 and 2004) were more representative of normal source operation than the 5 years immediately preceding the date construction will begin on Unit #13. As EPA has stated in the NSR Workshop Manual and in several policy documents, use of an earlier time period as representative of normal source operations should only be allowed in limited circumstances such as periods of strikes, retooling, major industrial accidents and other catastrophic occurrences. October 1990 NSR Workshop Manual at A.39. Further, although EPA adopted a ten year lookback period for sources other electric utility steam generating units (EUSGUs) in its December 31, 2002 New Source Review rulemaking, EPA retained a 5 year lookback period for baseline emissions that EPA originally allowed in a July 21, 1992 rulemaking (57 Fed.Reg ) stating that: The data we collected to support the 1992 rule changes show that allowing EUSGUs to use any 2-year period out of the preceding 5 years is a sufficient period of time to capture normal business cycles at an EUSGU. 67 Fed.Reg (December 31, 2002). While EPA retained the provision that allows the permitting authority to allow the use of a different two year period of emissions for EUSGUs in its December 31, 2002 rulemaking, EPA never stated that it was changing its longstanding policy on the limitations to using a different time period reflective of baseline emissions discussed above. Neither Otter Tail nor DENR has made a demonstration to justify the use of a different time period than the 5 years immediately preceding when actual construction will begin on Unit #13 as reflective of baseline actual emissions. Further, the fact the Otter Tail and DENR based the previously proposed plantwide emission limits on emissions at Unit #1 from 2003 and 2004 is

8 Page 8 not adequate justification for DENR to now rely on those same years of emissions, as it seems to imply in its Statement of Basis for the revised Title V permit. Statement of Basis for Revised Title V Permit at 6. As DENR made clear at the August 2008 contested case hearing and in its post-hearing briefs, DENR never previously proposed to allow Unit #13 to net out of review and it was not previously relying on the definition of net emissions increase or its associated terms and definitions. Now, in response to EPA s objection that the plantwide emission limits are not a lawful way for Unit #13 to avoid PSD review, DENR is for the first time relying the requirements of the definition of net emissions increase in its attempt to allow Unit #13 to avoid PSD review. Accordingly, DENR must abide by the requirements of the definition of net emissions increase and its associated terms and definitions in order to properly allow Unit #13 to net out of PSD review even though it means that Otter Tail now cannot lawfully rely on the same years of data it did when it first requested a permit for Unit #13. Given that DENR has not previously gone through an analysis of net emissions increase and the proposal of unit-specific emission limits for SO 2 and NO x, there was no additional burden for DENR to evaluate the proper lookback period to determine baseline actual emissions of SO 2 and NO x for Unit #1 and thus it should have done so. Accordingly, the draft revised Title V permit does not properly allow Unit #13 to net out of PSD for SO 2 and NO x because it is based on an improper period of baseline actual emissions for Unit #1. The SO 2 and NO x emission limitations of the draft revised Title V permit are not sufficient to ensure that there will not be a significant net emissions increase of SO 2 and NO x emissions at the Big Stone facility as a result of the Big Stone II project. If DENR, in response to this comment, decides to do a new netting analysis and impose lower SO 2 and NO x emission limits on Unit #1 using the proper baseline actual emissions for SO 2 and NO x, DENR must provide an analysis that verifies that Unit #1 can comply with those emission limits. Given that Otter Tail has already begun its more aggressive operation of the overfire air system at Unit #1 (see DENR Exhibit 211 from 2008 contested case hearing), it is questionable whether Otter Tail could obtain the further NO x emission reductions necessary to properly net Unit #13 out of PSD review for NOx with additional changes to its overfire air system. E. DENR Failed to Take Into Account All Creditable Emission Increases and Decreases in Determining Net Emissions Increase of SO and NO. 2 x According to EPA s New Source Review Workshop Manual, one of the common errors in netting analyses is the failure to consider all other contemporaneous emission increases in determining net emissions increase. See October 1990 NSR Workshop Manual at A.44. It appears that DENR did not review any other emissions increases and decreases at the Big Stone facility over the last 5 years as part of determining the net emissions increase of SO 2 and NO x. This is a major error.

9 Page 9 We are aware of at least one change that occurred at Big Stone facility during the contemporaneous period which should have been evaluated in determining net emissions increase of SO 2 and NO x by DENR. Specifically, the ethanol plant that is co-located with and receives steam from the Big Stone facility undertook modifications and received an air quality permit to significantly increase its capacity. According to a Poet Biorefining press release, the Big Stone ethanol plant was modified to increase its ethanol production capacity from 40 million gallons to 75 million gallons in 2007, with construction completed by June See press release at A copy of that press release is included as Attachment 2 to this letter. According to a 2008 Statement of Basis for revisions to the Northern Lights Ethanol Title V permit, DENR issued a permit on September 8, 2006 that allowed Northern Lights Ethanol to increase production to up to 80 million gallons per year. See Statement of Basis, Title V Air Quality Operating Permit, Northern Lights Ethanol, (d/b/a POET Biorefining Big Stone) at 1 (Attachment 3 to this letter). Because the Big Stone facility provides steam to the ethanol plant for use in producing ethanol, an almost doubling of the capacity of the ethanol plant would require more steam production from Unit #1 which would in turn require an increase in the amount of coal burned and an increase in emissions. According to EPA s NSR Workshop Manual, an increase in operation should be evaluated to determine whether there was a creditable emission increase. October 1990 NSR Workshop Manual at A.46. In this case, the amount of steam that Otter Tail could provide to the Northern Lights Ethanol plant was limited by the ethanol production capacity of the Northern Lights facility. Once the ethanol plant was permitted and modified to increase ethanol production capacity, the amount of steam that Otter Tail could provide to the ethanol plant increased. For the purposes of determining creditable increases in actual emission for this operational change, one must first determine the baseline actual emissions for the facility. 40 C.F.R (b)(3)(i)(b); 52.21(b)(48). As discussed above, the proper baseline actual emissions for the Big Stone facility are 11,720 tpy for SO 2 and 14,609 tpy for NO x. The new level of actual emissions is the lower of the unit s potential or allowable emissions after the operational change. See NSR Workshop Manual at A.48. The difference between these two levels of actual emissions are the creditable emissions increases that must be included in determining the net emissions increase of SO 2 and NO x at the Big Stone facility. Although EPA revised the term net emissions increase in its December 31, 2002 rulemaking to be based on baseline actual emissions, EPA did not revise its longstanding requirement that, for the purposes of determining net emissions increase, actual emissions for modified emission units be based on the potential to emit of the unit. Specifically, the determination of creditable emission increases is based on changes in actual emissions, and actual emissions is defined to provide that: for any emissions unit which has not begin normal operations [as of] a particular date, actual emissions shall equal the potential to emit of the unit on that date. See 40 C.F.R (b)(3)(i)(b), (b)(3)(v); 52.21(b)(21)(iv).

10 Page 10 In accordance with the definition of net emissions increase, all of the creditable SO 2 and NOx emission increases and decreases including the creditable emissions increases due to the Unit #13 project must be tallied up to compare to the major modification significance levels. 40 C.F.R (b)(3)(i); 52.21(b)(23). DENR did not do this, and thus its SO 2 and NO x netting analysis for the Big Stone II project is seriously flawed. F. The Monthly Emissions Calculations Appear to Differ from the Acid Rain Program Equations. In equation 9-2 of Condition 9.3 of the draft revised Title V permit, DENR has included an equation to determine the SO 2 emissions in tons per month from the CEMs that will be operated at Big Stone I and II. In equation 9-4 of Condition 9.6 of the draft revised Title V permit, DENR has included an equation to determine the NO x emissions from the CEMs. The draft permit indicates that these are derived from the Acid Rain Program equations. However, in the explanation of the variables in the equations in the draft permit, there are slight wording changes from the acid rain equations. The Statement of Basis does not explain how these equations were derived from the acid rain equations or why they are somewhat different. DENR must explain how these equations will assure that all of each Unit #1 and Unit #13's SO 2 and NO x emissions will be accounted for in determining compliance with each units SO and NO emission limits. G. Netting Summary 2 x In summary, DENR s determination of the SO 2 and NO x net emissions increases for the Big Stone II project is seriously flawed. For all of the legal and technical issues raised in our comments above, the draft revisions to the Big Stone Title V permit do not result in Unit #13 legitimately netting out of PSD review for SO 2 and NO x. Accordingly, DENR cannot issue this Title V permit until a PSD permit has been issued for the SO 2 and NO x to be emitted by Unit #13. II. The State Has Failed to Address Adequately EPA s Objections Regarding the Synthetic Minor Hazardous Air Pollutant (HAP) Emission Limitations for Unit #13. EPA objected in several respects to the HAP limits in the proposed Big Stone Title V permit that were intended to allow Unit #13 to avoid a case-by-case determination of maximum achievable control technology (MACT) requirements, and DENR has failed to address EPA s points adequately. In the absence of enforceable emission limitations on all HAPs to be emitted by Unit #13 and periodic monitoring sufficient to ensure continuous compliance, this unit must be subject to a case-by-case MACT determination before DENR can authorize operation of Unit #13.

11 Page 11 A. The Draft Revisions to the Big Stone Title V Permit Fail to Respond Adequately to EPA s Objection #3: Inadequate Compliance Provisions for Unit-Wide Limits on the HF and HCl EPA s Objection #3, Inadequate Compliance Provisions, included an objection that the required monitoring in Conditions 11.3 and 11.4 of the proposed Big Stone Title V permit failed to comply with 40 C.F.R. 70.6(c)(1) because it fails to ensure compliance with the 2.17 lb/hr limits on emissions of HF and HCl due to the failure to specify a test method and test frequency. EPA s January 22, 2009 Objection Letter, Enclosure at 10. EPA also stated that the Condition 7.12 of the proposed Big Stone Title V permit, which only required a one time stack test within 180 days of startup of Unit #13, failed to comply with 40 C.F.R. 70.6(a)(3)(i)(B) because it fails to require periodic testing. Id. at 11. DENR responded to EPA s objection on these issues by specifying EPA reference method 26A (of 40 C.F.R. Part 60, Appendix A) for the HF and HCl stack testing, and by revising the requirement for stack testing for HF and HCl to once per year. Condition 7.12 of the draft revised Big Stone Title V permit. However, DENR has failed to explain or demonstrate that a once-per-year stack test is sufficient to ensure compliance with the 2.17 lb/hr HF and HCl emission limits of Conditions 11.3 and 11.4 of the permit. 40 C.F.R. 70.6(a)(3)(i)(B) requires a Title V permit to include the following with respect to monitoring (among other requirements): Where the applicable requirement does not require periodic testing or instrumental or noninstrumental monitoring (which may consist of recordkeeping designed to serve as monitoring), periodic monitoring sufficient to yield reliable data from the relevant time period that are representative of the source's compliance with the permit, as reported pursuant to paragraph (a)(3)(iii) of this section. Such monitoring requirements shall assure use of terms, test methods, units, averaging periods, and other statistical conventions consistent with the applicable requirement. Recordkeeping provisions may be sufficient to meet the requirements of this paragraph (a)(3)(i)(b) of this section. A similar requirement can be found in South Dakota rules at ARSD 74:36:05:16.01(9)(b). 40 C.F.R. 70.6(c) provides as follows: Compliance requirements. All part 70 permits shall contain the following elements with respect to compliance: (1) Consistent with paragraph (a)(3) of this section, compliance certification, testing,

12 Page 12 monitoring, reporting, and recordkeeping requirements sufficient to assure compliance with the terms and conditions of the permit. Any document (including reports) required by a part 70 permit shall contain a certification by a responsible official that meets the requirements of 70.5(d) for this part. South Dakota has a comparable requirement at ARSD 74:36:05.16:01(14)(a). DENR has not provided any documentation to verify that a once per year stack test is sufficient to show compliance with the 2.17 lb/hr HF and HCL emission limits. Thus, the state has failed to address EPA s objection which required that: [t]he state must develop periodic monitoring requirements that assure compliance with the permit conditions and explain why the proposed requirements will, in fact, assure compliance. EPA s January 22, 2009 objection, Enclosure at 10. As discussed at the August 2008 contested case hearing, the chloride and fluoride content of the coal can vary. August 2008 Contested Case Hearing Transcript at 442, , 850, Further, the HF and HCl emissions out of a coal-fired power plant can also vary on an hour-byhour basis, as well as a day-to-day basis. Id. at Given this variability of the chloride and fluoride in the coal as well as with the HF and HCl emissions, a once-per-year stack test and determination of HF and HCl removal efficiency cannot be considered as monitoring of sufficient frequency to ensure continuous compliance with the 2.18 lb/hr HF and HCl limits. This is especially important given that these are short term average emission limits. An annual stack test does not provide sufficient monitoring to ensure that these limits are being met on an hour-by-hour basis. EPA has previously objected to Title V permits for several power plants in Florida that only required once-per-year stack tests to show compliance with a three-hour average particulate standard. See December 11, 1997 letter from EPA Region IV to the Florida Department of Environmental Protection. A copy of that objection letter is included as Attachment 4 to this letter. A similar objection was issued by EPA for another Florida power plant in See November 1, 1999 letter from EPA Region IV to Florida Department of Environmental Protection, included as Attachment 5 to this letter. The permit also does not explain how Otter Tail is to determine accurately the HF and HCl emissions of the Unit #13 boiler to show compliance with the 2.17 lb/hr emission limits in light of the combined stack and merged gas stream with Unit #1. Further, the permit does not explain how Otter Tail is to determine compliance with the HF and HCl emission limits during startup and shutdown. Thus, DENR has failed to address the requirements of EPA s objection to include periodic

13 Page 13 monitoring requirements sufficient to assure that Unit #13 will continuously comply with the 2.17 lb/hr limits on HF and HCl in Conditions 11.3 and 11.4 of the draft revised Big Stone Title V permit. DENR should either require much more frequent stack testing requirements or, alternatively, DENR should require HCl and HF continuous emission monitoring systems (CEMS). CEMs are available for HCl and HF from at least two vendors. See Attachments 6 and 7. B. The Draft Revisions to the Big Stone Title V Permit Fail to Respond Adequately to EPA s Objection #3: Inadequate Compliance Provisions for Unit-Wide Limits on the 9.5 tpy Single HAP Limit for Unit #13 EPA s Objection #3, Inadequate Compliance Provisions, also included an objection over inadequate compliance provisions for the 9.5 tpy limit on the emissions of any single HAP from Unit #13 in Condition 11.5 of the draft Big Stone Title V permit. EPA s January 22, 2009 Objection Letter, Enclosure at EPA stated that the monitoring in Condition 11.5 of the November 2008 proposed Title V permit failed to indicate how the permittee must demonstrate that it is maintaining emissions less than the major source single HAP threshold and also that it was not clear whether emissions during startup, shutdown, and malfunction are to be included in demonstrating compliance. Id. at 11. To resolve EPA s objection, EPA required the state to provide such detail as is necessary to confirm the...<10 tpy status requested by the permittee and that it must explain how it established the potential to emit HAP for the Unit #13 boiler, Unit #13. Id. DENR has not provided any additional explanation for its estimate of emissions of HF and HCl, beyond what was stated at the August and September 2008 contested case hearing. At the September 2008 contested case hearing, DENR s Kyrik Rombough stated that he evaluated the USGS coal quality database for Powder River Basin coal and compared it to Otter Tail s assumed fluoride and chloride content of the coal to be burned at Unit #13. September 2008 Contested Case Hearing Transcript at This is all information that EPA had when it objected to the Big Stone Title V permit, so clearly this explanation was not sufficient to EPA. DENR has provided no analysis of Otter Tail s assumed HF and HCl control efficiency upon which the 9.5 tpy limit was based. In addition, DENR must determine whether Unit #13 has the potential to emit any other HAP in excess of 10 tpy and, if so, require adequate periodic monitoring of those HAPs to ensure compliance with the 9.5 tpy limit. EPA also required the State to revise Condition 11.5 of the Big Stone Title V permit to, among other things, include [a] requirement specifying how the permittee must demonstrate compliance with the emission limit of 9.5 tons per rolling 12-month period for the identified acid

14 Page 14 gas HAP. Also, EPA stated that the required test methods and frequency of measurement must be stated in the permit. Regarding Condition 11.7 that requires coal analyses, EPA stated that, if this data is to be used to support the enforceability of HAP limits, the permit must state how it is to be used. EPA s January 22, 2009 Objection Letter, Enclosure at To address the need for the permit to indicate how compliance with the 9.5 ton per rolling 12- month period would be determined, DENR added Condition 11.8 to the permit. Condition 11.8 includes equations for determining HF and HCl emissions. These equations are based on the fluoride and chloride concentration in the coal based on weekly coal composite samples required by Condition 11.7 of the permit, the HF and HCl control efficiencies determined from the onceper-year stack test required under Condition 7.12 of the permit, and the monthly total tonnage of coal burned. While the permit now has more detail on how Otter Tail is to show compliance with the 9.5 tpy limits on a single HAP, the permit terms still fail to include adequate monitoring and testing requirements and fail to ensure compliance with the single HAP synthetic minor emission limits for several reasons as follows: 1. The HF and HCl stack testing is not sufficient to determine the control efficiency of Unit #13 s HF and HCl emissions. The HF and HCl control efficiency is only based on a once-per-year stack test. As discussed in the above comment, HF and HCl emissions can vary hour by hour and day by day. Thus, a stack test conducted once in a year to determine HF and HCl control efficiencies is not going to be reflective of the variability in control efficiencies that occurs for various reasons throughout the year. It is also not clear that the control efficiency determined during the stack test will be reflective of acid gas control efficiency during startup and shutdown. DENR has provided no justification to show that the HF and HCl control efficiencies collected during an annual stack test will accurately reflect control efficiencies throughout the year. Stack tests are typically conducted during optimum conditions with much advance notice. So, the control efficiencies determined during the once-per-year stack tests may not be reflective the HF and HCl control efficiencies that are achieved day in and day out at Unit #13. Further, the control efficiencies during the stack test would not be reflective of the HF and HCl control efficiencies that occur during startup and shutdown. The most appropriate way to avoid this issue would be to install HF and HCl CEMs, as discussed above. Due to the combined stack and different control equipment before the combined stack, Otter Tail would need to have HF and HCl CEMs on each unit before the add-on control equipment as well as in the common stack, so that Otter Tail could apportion the HF and HCl emissions to Unit #13. This may be necessary in any case, because it is not clear how DENR will determine the HF and HCl emissions due to the Unit #13 boiler from the once-per-year stack tests, given the combined flue gas streams of Unit #1 and II as discussed above.

15 Page 15 If DENR is planning on having Unit #1 routed to the existing Unit #1 stack during HF and HCl stack testing for Unit #13, then DENR must first demonstrate that the HF and HCl control efficiency obtained from a stack test of just Unit #13 won t differ from the HF and HCl control efficiency when both the gas streams of both Unit #1 and II are merged. It is not clear that such a demonstration could even be made. If HF and HCl CEMs were required on each unit before being merged and in the common stack, this CEM data could then be relied on to ensure compliance with the 9.5 tpy limit on a single HAP as well as the 2.17 lb/hr HF and HCl limits. Indeed, acid gas CEMs seem to be the only way DENR can ensure compliance with the 9.5 tpy limit on emissions of a single HAP. 2. DENR has provided absolutely no justification for the assumed HF and HCl control efficiencies that apply in equations 11-3 and Specifically, Equation 11-3 provides that the HF control efficiency shall be assumed to be 93.1% until the initial performance test is completed. Similarly, Equation 11-4 provides that the HCl control efficiency shall be assumed to be 96.2% until the initial performance test is completed. DENR s Statement of Basis for the draft revised permit fails to provide any basis or documentation for these presumed levels of control efficiency. It is also not clear that these assumed control efficiencies are reflective of acid gas control efficiencies during startup and shutdown. 3. The coal sampling requirement in Condition 11.7 of the draft revised Title V permit fails to specify test methods and procedures to ensure valid testing and representative samples for this testing. EPA has specified such requirements in 40 C.F.R. Part 60, Subpart A, Method 19 for an as-fired fuel monitoring system to ensure proper collection of uncontrolled emission data based on coal analysis for NSPS standards. Thus, DENR must specify a similar requirement in the permit for a coal sampling tower to ensure valid testing and representative samples and must make clear in the permit the test methods that must be used to determine fluoride and chloride content of the coal burned at Unit # The equations in Condition 11.8 allow the fluoride and chloride content of the coal burned to be based on the average of four weekly coal composite samples. However, by averaging the once per week coal composite samples, this condition allows Otter Tail to discount weeks with higher uncontrolled HF and HCl emissions in determining if the 12 month sum of HF or HCl emissions is over the 9.5 tpy synthetic minor emissions threshold. The fact that the draft permit allows Otter Tail to then assume the same HF and HCl control efficiencies will be obtained on a continuous basis along with the averaging of the chloride and fluoride content in the coal just compounds this issue. Thus, this approach will not ensure that Unit #13 is truly complying with the 9.5 tpy synthetic minor limit on emissions of a single HAP. As discussed above, HCl and HF CEMs are the most reliable method to ensure compliance with

16 Page 16 the lb/hr and tpy limits. If DENR continues to instead require coal sampling and stack testing to show compliance with the 9.5 tpy limit, the coal sampling should be done more frequently, as should the stack testing. The coal sampling towers required under EPA Method 19 typically sample coal on a daily basis. If DENR continues to require coal sampling to assure compliance, it should require a determination of HF and HCl emissions on a daily basis, and it must also require evaluations of HF and HCl removal efficiencies on a much more frequent basis than once per year. Without more frequent monitoring, coal sampling requirements and test methods consistent with EPA s approved methods, and more frequent tallying of emissions, the draft revised Title V permit fails to assure that Unit #13 does not emit more than 9.5 tpy of HF or HCl. C. The Draft Revisions to the Big Stone Title V Permit Fail to Respond Adequately to EPA s Objection #3: Inadequate Compliance Provisions for Unit-Wide Limit on Total HAPs for Unit #13 EPA s Objection #3, Inadequate Compliance Provisions, included an objection over inadequate compliance provisions for the 23.8 tpy limit on the combination of HAPs from Unit #13 in Condition 11.5 of the draft Big Stone Title V permit. EPA s January 22, 2009 Objection Letter, Enclosure at EPA stated that the proposed monitoring in Condition 11.5 of the November 2008 proposed Title V permit failed to indicate how the permittee must demonstrate that it is maintaining emissions less than the major source HAP thresholds. EPA also stated that it was not clear whether emissions during startup, shutdown, and malfunction are to be included in demonstrating compliance. Id. at 11. To resolve EPA s objection, EPA required the state to provide such detail as is necessary to confirm the...<25 tpy status requested by the permittee and that it must explain how it established the potential to emit HAP for the Unit #13 boiler, Unit #13. Id. DENR has not provided any explanation for its estimate of emissions of any HAP other than HF, HCl and mercury (and DENR did not provide much support for its assumptions for HF and HCl emissions, as discussed further above). While DENR refers to all of the other HAP to be emitted by Unit #13, including HAPs such as arsenic, dioxins, benzenes, lead, and numerous other toxic air pollutants, as insignficiant hazardous air pollutants (Statement of Basis for Revised Title V permit at 19-20), DENR neither provided a basis for that claim nor attempted to respond to EPA s objection to provide its analysis to confirm that the less than 25 tpy total HAP status requested by Otter Tail. EPA also required the State to revised Condition 11.5 of the Big Stone Title V permit to, among other things, include: A requirement specifying how the permittee must demonstrate compliance with the total HAP limit of 23.8 tpy per rolling 12-month period, or, alternatively, the

17 Page 17 State must include an explanation of why monitoring and reporting of HAP emissions above what is required for acid gas and mercury HAP is not required to assure compliance with the limit. EPA s January 22, 2009 Objection Letter, Enclosure at DENR s response to this part of EPA s objection was simply to state To account for the insignificant hazardous air pollutants, DENR determined the potential hazardous air pollutant emissions for these insignificant hazardous air pollutants and placed that amount in the equation for the combined hazardous air pollutant emission limit of 23.8 tons per 12-month period. Statement of Basis for revised Title V permit at DENR also stated DENR did not exempt startup, shutdown, and malfunctions, in determining long term hazardous air pollutant emissions in permit condition Therefore, startup, shutdown and malfunctions are included in determining the 12-month totals. Id. Also apparently in response to EPA s objection, DENR added Condition 11.8 to the Big Stone Title V permit which specifies how compliance with the 23.7 tpy limit on total HAPs is to be determined. For the HAPs other than HF, HCl and mercury, emissions are determined based on an emission factor of lb/tbtu and the heat input to the boiler. Equation 11-5 of Condition 11.8 of the draft revised Big Stone Title V permit. It must be noted that this equation must be revised to make clear that the heat input in the equation must be in TBtus (rather than MMBtus as is typically reported). DENR has failed to provide any justification or explanation of the lb/tbtu emission factor in its Statement of Basis for the revised draft Big Stone Title V permit. It appears that the lb/tbtu emission factor for the HAP emissions other than HF, HCl and mercury may be based on the HAP emission calculations provided by Otter Tail in its March 18, 2008 submittal to DENR. A copy of Otter Tail s March 18, 2008 submittal is included as Attachment 17 to this letter. If this is the case, then DENR clearly has no justification for this emission factor as was made clear at the August 2008 contested case hearing on the Big Stone permits and as is discussed further below. Because DENR is not requiring Otter Tail to conduct any emissions testing for emissions of HAPs other than mercury, HCl, and HF and is instead relying solely on an emission factor and the heat input of the coal burned to determine emissions of all other HAPs emitted by Unit #13, it is imperative that the emission factor be conservative to insure that all HAP emissions are accounted for. Otherwise, no party will know for certain whether Unit #13 is truly emitting HAPs less than the major source emission thresholds. The fact that the majority of other new coal-fired electrical utility steam generating units are considered major sources of HAPs and

18 Page 18 2 subject to case-by-case MACT requirements make this issue all the more important. Coal-fired boilers the size of Unit #13 have not historically been considered as minor sources of HAPs and exempt from MACT. Assuming that DENR s lb/tbtu other HAP emission factor is based on Otter Tail s March 2008 submittal of HAP emission calculations, we have analyzed Otter Tail s March 2008 emission calculations for the HAPs to be emitted by Unit #13. We compared those emission calculations to other data sources of HAP emissions from coal-fired boilers, and we have found that Otter Tail s HAP emission factors (based on the EPRI-LARK TRIPP software) to be incomplete, unjustified, and significantly lower than other sources of HAP emission factors. Specifically, we have identified the following deficiencies in Otter Tail s HAP estimates in its March 2008 submittal to DENR: 1. Otter Tail Improperly Omitted Several HAPs in its Emission Estimates. Otter Tail left out several HAPs in its emissions estimates submitted in March That is, Otter Tail utterly failed to estimate any level of emissions for several HAPs, including the following: Table 1: HAPs that Otter Tail Failed to Project Emissions for in its March 2008 HAP Emission Estimates for Unit #13 Cyanide compounds Carbon tetrachloride o-cresol m-cresol 1,3-Dichloropropene (Trans-1,3-Dichloropropene) Hexachlorobenzene N-Nitrosodimethylamine Pentachlorophenol Phosphorus Phthalic anhydride Quinoline 1,1,2-Trichloroethane Trichloroethylene Vinylidene chloride (1,1-Dichloroethylene) Sierra Club researched the available EPA emission factors for these HAPs, looking first to EPA s 2 August 2008 Contested Case Hearing Transcript at 805.

19 Page 19 3 AP-42 emission factors. For those HAPs for which AP-42 did not identify emission factors, Sierra Club used EPA s February 1998 Study of Hazardous Air Pollutant Emissions from 4 Electric Utility Steam Generating Units-Final Report to Congress, Appendix A, Table A-4. As shown in the following table, the omission of any emission estimates for these HAPs was a significant error. Table 2: HAPs Omitted from Otter Tail s March 2008 HAP Emission Estimates for Unit #13. CAS No. HAP AP-42 Emission Factor, lb/tbtu Median Emission Factor from EPA s 1998 Report to Congress, lb/tbtu Other Source for Emission Factor, lb/tbtu Comment Cyanide compounds Carbon Tetrachloride From AP-42 Section 1.1, Table , converted from lb/ton to lb/tbtu with Otter Tail s Coal Usage Data Highest Median Emission Factor from Table A-4, Appendix A o-cresol 1.7 Id m-cresol Id. 3 A copy of EPA s AP-42 Emission Factors, Section 1.1 Bituminous and Subbituminous Coal Combustion and EPA s Emission Factor Documentation for AP-42 Section 1.1 are included as Attachments 8 and 9, respectively, to this letter. 4 Sierra Club used the highest of the three median factors listed in Table A-4 for 1990, 1994 and projected for The appendices in Volume 2 of the 1998 EPA Report to Congress are included as Attachment 11 to this letter.