Document GK73X5B4Y07x9dy0dy935XYZx

' December 22, 2016 ilahoma Cogeneration,LLC mmer tnBTf Hit ffftuis Cmamu fChm ftoi*i*ttfsliMfl~ctffillOlUstf VIA ELECTRONIC SUBMISSION AND HAND DELIVERY Office of the Administrator (Mail Code 1101A) US Environmental Protection Agency 1200 Pennsylvania Avenue NW, Room WJCN 3000 Washington DC 20460 RE: Request for Reconsideration of ERA'S "Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS" (EPA Docket No. EPA-HQ-OAR-2015-0500) Dear Administrator: Pursuant to Section 307(d)(7)(B) of the Clean Air Act, Oklahoma Cogeneration, LLC ("OK Cogen") respectfully petitions the U.S. Environmental Protection Agency ("EPA" or "Agency") for reconsideration of the final rule entitled "Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS," 81 Fed. Reg. 74,504 (Oct. 26, 2016) ("CSAPR Update Rule" or "Final Rule"). Specifically, OK Cogen requests that EPA recalculate unitlevel allocations of seasonal nitrous oxide ("NOx") allowances for 2017 and beyond for OK Cogen's Oklahoma Cogeneration LLC Unit CC01 (Boiler ID CC01; ORIS ID 50558; CAMD Unit ID 90991) using data-substitution called for by the Final Rule. EPA's current calculations rely on a single (highly unrepresentative) year of data for Unit CC01, resulting in a significant allowance shortfall. This outcome contradicts EPA's own stated methodology and policy goals. OK Cogen is a small (two full-time employees, with 18 operational personnel) electric service company located in Oklahoma City, Oklahoma. The company is committed to environmental compliance and efficient NOx emissions controls. OK Cogen operates a single, independent 120 MW (nominal) natural gas-fired combined-cycle and topping-cycle cogeneration power plant ("Unit CC01").1 The facility consists of a natural gas-fired combustion turbine ("gas turbine"), a supplementary fired Heat Recovery Steam Generator that can receive additional energy from a natural gas-fired duct burner ("duct burner"), and a single automated extraction condensing steam turbine generator ("steam turbine"}.2 As a direct means of controlling NOx 1 Formerly known as the PowerSmith Cogeneration Project. 2 The unit's normal load (from gas and steam turbine electricity production) is 107 MW. The duct burner is used to make maximum load, and is used infrequently (only when called upon for dispatch by the Southwest Power Pool). In 2016, the duct burner was called upon twice, for a total of 15 hours of run time. 7425 SW 29th Street, Oklahoma City, OK 73179 Phone: 405.745.4442 Fax: 405.745.2499 www.OklahomaCogeneration.com 17cv1906 Sierra Club v. EPA - 6/22 Production ED 001523 00008508-00001 Oklahoma Cogeneration, LLC Facility ID 50558, Unit CC01 Page 2 emissions, this system injects steam into the gas turbine combustion chamber. The combined exhaust gases exit through a common main stack. The electricity is sold under a long term Power Purchase Agreement to a local electric utility company that serves customers in Oklahoma and Western Arkansas. Unit CC01 has been in operation since 1989. It was the first natural gas-fired combined-cycle cogeneration plant built and operated in Oklahoma. BACKGROUND CSAPR addresses the "good neighbor" provision of the Clean Air Act, which prohibits sources within each state "from emitting any air pollutant in an amount which will . . . contribute significantly" to any other state's nonattainment, or interference with maintenance of, any National Ambient Air Quality Standard ("NAAQS"). 42 U.S.C. 7410(a)(2)(D)(i)(l). EPA defines "significant contribution" by reference to (1) a state's "linkage" to downwind receptors (i.e., emissions of approximately 1 percent of compliant ambient levels) and (2) the ability of the state to achieve emission reductions at the relevant cost threshold.3 CSAPR achieves emissions reductions through annual and ozone season emissions trading programs. EPA finalized CSAPR in 2011 to address three NAAQS, including the 1997 ozone NAAQS. 76 Fed. Reg. 48,208 (Aug. 8, 2011) ("Original CSAPR Rule" or "CSAPR"). In December 2011, EPA finalized a supplemental CSAPR rule that added several states, including Oklahoma, to the ozone season NOx program. 76 Fed. Reg. 80,760 (Dec. 27, 2011) ("Supplemental CSAPR Rule"). Various groups challenged CSAPR, resulting in a stay of the rule. See EME Homer City Generation, L.P. v. EPA, No. 11-1302 (D.C. Cir. Dec. 30, 2011). CSAPR and Supplemental CSAPR Rule requirements and deadlines were effectively tolled pending resolution of the litigation. See 79 Fed. Reg. 71,663 (Dec. 3, 2014). In April 2014, the U.S. Supreme Court generally upheld the rule. See EPA v. EME Homer City Generation LP, 134 S. Ct. 1584 (2014). The stay was lifted in October 2014. See EME Homer City, No. 11-1302 (Oct. 23, 2014). Phase 1 of the CSAPR ozone season program began in May 2015. EPA published the CSAPR Update Rule in October 2016 to address good neighbor provisions with respect to the 2008 ozone NAAQS. The Agency had published a proposed rule about 10 months earlier. See 80 Fed. Reg. 75,706 (Dec. 3, 2015) ("Proposed CSAPR Update Rule" or "Proposed Rule"). In the Final Rule, EPA found that 22 eastern states, including Oklahoma, had failed to submit a state implementation plan to meet their good neighbor obligations. For these 22 states, EPA issued federal implementation plans that generally update existing CSAPR NOx ozone season emission budgets, and that implement these budgets through modifications to the existing CSAPR NOx ozone season allowance trading program. The Final Rule addresses only emission reductions from electric generating units ("EGUs"). Implementation will start in the 2017 ozone season (May - September 2017). EPA made several significant changes between the Proposed and Final CSAPR Update Rules. Most notably for OK Cogen: 3 EPA uses the Integrated Planning Model v.5.15 ("IPM") to predict how many emissions reductions are available at the relevant cost thresholds. IPM is a dynamic, linear programming model used to project power sector behavior under current and future conditions. IPM's primary objective is to provide estimates of least-cost capacity expansions, electricity dispatch, and emission control strategies while meeting energy demand and environmental, transmission, dispatch, and reliability constraints. See 17cv1906 Sierra Club v. EPA - 6/22 Production ED 001523 00008508-00002 Oklahoma Cogeneration, LLC Facility ID 50558, Unit CC01 Page 3 (1) In calculating allocations for Oklahoma units in the Final Rule, EPA did not use data-substitution. Both the Proposed and Final Rules call for EPA to use up to five years of historic heat input data and up to eight years of historic NOx emissions data.4 To accomplish this, both rules also call for EPA to use a datasubstitution method (so that if data is not available from EPA's preferred data source for a given year, EPA can pull equivalent data from an alternative source).5 EPA followed this method in the Proposed Rule.6 But in the Final Rule, EPA switched to using a single year of historic baseline data without any data-substitution for Unit CC01. See EPA, Final Rule, Unit-Level Allocations and Underlying Data for the CSAPR Update for the 2008 Ozone NAAQS ("Final Allocation Spreadsheet TSD"). Unit CCOl's allowance allocation dropped more than 70 percent from the Proposed Rule to the Final Rule, from 40 allowances to 12 allowances. (2) In calculating Oklahoma's budget In the Final Rule, EPA used a revised formula with new inputs. Both the Proposed and Final Rules call for EPA to set state budgets as the minimum of either (1) historic emissions7 or (2) IPM-predicted 2017 emissions. In the Final Rule, EPA introduced new variables to the formula for calculating IPM-predicted 2017 emissions, including (1) a NOx emission rate "delta" (equal to the difference between an IPM 2017 Base Case and IPM 2017 Policy Case emission rate); and (2) an "adjusted" historic emission rate, based on a newly-developed adjusted historic dataset. With these new variables, EPA added several steps to the calculation and increased its complexity. See 81 Fed. Reg. at 74,547-48. Due in large part to these changes, Oklahoma's budget dropped about 28 percent from the Proposed Rule to the Final Rule, from 16,215 tons to 11,641 tons, more than any other state.8 * Oklahoma's reduced state budget contributed to Unit CCOl's reduced allowance allocation. 4 To calculate allocations, EPA first "uses the average of the three highest years of heat input data out of a consecutive five-year period to establish the heat input baseline for each unit," and calculates initial heat input-based allowance allocations based on each unit's percentage share of the state's total ozone season heat input. 81 Fed. Reg. at 74,564. Next, EPA "constrains the unit-level allocations so as not to exceed the maximum historical baseline emissions, calculated as the highest year of emissions out of a consecutive eight-year period." Id. This methodology "bases a unit's allocation on the unit's historical heat input but limits any unit's allocation to its historical maximum emissions." EPA, Allowance Allocation Final Rule TSD at 6 (Aug. 2016) ("Allocation TSD"), available at h ,/, 1 - - j <:.,r, ",, .. r. -i u , - c . i. 5 The two data sources EPA says it will look to are: (1) EPA's Clean Air Markets Division ("CAMD"), for years for which it is available; and (2) the U.S. Energy Information Administration ("EIA"), for years for which CAMD data is unavailable. 6 With some caveats: EPA did not include 2014 EIA data because it was unavailable at the time the Proposed Rule was published. Thus, for units without 2014 CAMD data, EPA did not "backfill" or substitute any EIA data. Additionally, EPA did not include data for years for which a unit was not yet operating (e.g., if a unit that began operating in 2012, EPA used available 2012-2014 heat input and NOx emissions data). See EPA, Proposed Rule, Unit Level Allocations and Underlying Data for the CSAPR for the 2008 Ozone NAAQS ("Proposed Allocation Spreadsheet TSD"). Excel file available at - .-.T,.-, : , >, - ... i j> --i ,n, ,>> 1" >iu: v." -Ii'i-y. Further, as discussed below, EPA inappropriately relied on annual, not monthly, EIA data and made arbitrary downward adjustments to reported EIA data for cogeneration and combined-cycle units. EPA should use monthly, reported (i.e., unadjusted) EIA data in the revised Final Rule allocations. 7 Based on a baseline year of 2014 in the Proposed Rule and 2015 in the Final Rule. 8 Under the Proposed Rule formula, Oklahoma's IPM-predicted 2017 emissions were higher than historic emissions. Thus, Oklahoma's budget was set equal to historic (2014) emissions. Under the revised Final Rule formula, Oklahoma's IPM-predicted 2017 emissions were lower than historic (2015) emissions. Thus, Oklahoma's budget was set equal to these lower IPM-predicted emissions. This change was not driven solely by the switch from a 2014 to 2015 historic baseline. The primary driver appears to be the new IPM-derived emission rate "delta." Oklahoma's IPM 2017 Base Case emission rate is unrealistically and arbitrarily high-- 17cv1906 Sierra Club v. EPA - 6/22 Production ED 001523 00008508-00003 Oklahoma Cogeneration, LLC Facility ID 50558, Unit CC01 Page 4 REQUEST FOR RECONSIDERATION I. Requested Technical Correction A. EPA Should Correct Errors In OK Cogen's Allowance Allocations EPA's unit-level allowance allocation calculations in the Final Rule are arbitrary and capricious as applied to OK Cogen's Unit CC01. EPA's failure to perform EIA data-substitution--and use of a single historic baseline year for some units--goes against the Final Rule's own prescribed methodology. It also puts units on unequal footing: some units, like Unit CC01, received allocations based on one year of operation, while other units received allocations based on multiple years of operation. This effectively penalizes units, like Unit CC01, that were not required to report to CAMD in prior years. OK Cogen is especially disadvantaged because Unit CCOl's single year of available CAMD data (2015) is highly unrepresentative of the unit's historic operations. EPA must recalculate OK Cogen's allocations for Unit CC01 to avoid this unfair and arbitrary outcome. Specifically, EPA must use (1) five years of reported heat input data (2011-2015) and eight years of reported NOx emissions data (2008-2015); and (2) EIA data-substitution, where CAMD data is unavailable. Therefore, OK Cogen's allocations for Unit CC01 should be based on 2011-2014 EIA and 2015 CAMD heat input data and 2008-2014 EIA and 2015 CAMD NOx emissions data. EPA should use monthly (not annual), reported (not adjusted) data. Corrected calculations,9 summarized in Table 1, show that OK Cogen likely is entitled to 62 total allowances compared to 12 allowances under the current calculation: an increase of 50 allowances, or more than 500%. See Appendix A (CD-Rom Enclosure) for detailed calculations.10 * Table 1. Comparing OK Cogen's Unit CCOl's Average Heat Input, NOx Emissions Maximum Historic Baseline, and Final Allowance Allocations Under the Final Rule and a Corrected Rule. 3-Year Average Heat Input NOx Emissions Maximum Historic Baseline Final Allocation Final Rule (No EIA Data) 284,731 MMBtu (based on 2015) 43 tons (based on 2015) 12 tons Corrected Rule (Monthly Reported EIA Data) 1,478,244 MMBtu (based on 2011-2013) 163 tons (based 2011) 62 tons - _ - - Difference 1,193,513 MMBtu 120 tons 50 tons significantly higher than Oklahoma's historic actual or adjusted 2015 emission rates. As a result, Oklahoma's NOx emission rate "delta" also is arbitrarily high. This means the Final Rule formula over-estimates how many emissions reductions are available in the state. This error carries through the entire calculation, resulting in final IPM-predicted 2017 emissions that are unrealistically low. These arbitrarily low model-predicted rates became the basis for Oklahoma's final budget. Compare EPA, Proposed Rule, Appendix E- Detailed Budget Calculations, Excel file available at ;t , ....... . i . < r : ,.(* i* t ........ . 'mi .)'"' \>' T' v . ' i','; '. i with EPA, Final Rule, Appendix E: Budget Calculations, Excel file available at \,t . V, ,, V, .ic i 11 i ! Mi ` . ! M` i i .lr ` t .. 9 The corrected calculations are based on EIA heat input data from the 923 Report Form and as published on the EIA website at fn ;> .'w'v 'i, y\ In. mm i. v, im/ >i , ; 'mi1 / ' i. . vy > , =. See Appendix B (CD-Rom Enclosure). 10 At minimum, technical corrections using annual, adjusted EIA data (i.e., the EIA data EPA used in the Proposed Rule) likely still would raise OK Cogen's allocation. 17cv1906 Sierra Club v. EPA - 6/22 Production ED 001523 00008508-00004 Oklahoma Cogeneration, LLC Facility ID 50558, Unit CC01 Page 5 B. The Requested Corrections Are Supported By The Final Rule 1. Final Rule Calls for Multiple Historic Baseline Years OK Cogen's request to EPA is straightforward: simply do what you said you would do (but did not actually do). The Final Rule calls for using a five-year (2011-2015) historic baseline period for heat input data, and an eight-year (2008-2015) historic baseline period for NOx emissions data. See Allocation TSD at 6-7. EPA's rationale for using multiple historic baseline years is sound: it helps ensure that outlier data from a single unrepresentative year (e.g., where heat input or NOx emissions levels were significantly lower than usual) does not skew the calculations.11 As EPA recognizes, the power sector is susceptible to a range of variables affecting fuel use and emissions, including equipment failures, changing market forces, and weather patterns. See 81 Fed. Reg. at 74,566. One year of historic data cannot capture the inherent variability in a unit's operations from year to year, or ozone season to ozone season. Nonetheless, EPA set Unit CCOl's allocations based solely on 2015 operations. 2015 was a highly unrepresentative year for the unit because of unexpected mechanical equipment failures.12 The unit was outof-service for repairs during most of the 2015 ozone season (from May 5 to July 31, 2015). As a result, fuel usage/heat input and NOx emissions for the 2015 ozone season were uncharacteristically low.13 Indeed, the unit typically dispatches more during the ozone season than other times of the year. For the 2016 ozone season, Unit CCOl's dispatch rate was higher, much closer to historic levels. OK Cogen believes this trend of higher dispatch will continue. Market forces are likely to drive more and more dispatch of natural gas-fired units as the coal-fired units prevalent in the region phase out of service. EPA's reliance on solely 2015 CAMD data to establish the Unit CCOl's allocations is arbitrary and capricious. It results in the exact outcome EPA tried to avoid through a multi-year allocation methodology, unfairly penalizing Unit CC01. 2. The Final Rule Calls for Data Substitution Again, the requested corrections simply ask EPA to do what the Agency said it would do. EPA's prescribed methodology calls for using historic data from up to two different sources: (1) CAMD, if available for a given year; and (2) ElA, if CAMD data is unavailable for a given year. See Allocation TSD at 6-7. Indeed, for many units EPA must look to a historic data source other than CAMD to be able to use the multi-year baseline periods called for in the Final Rule. Prior to Phase I of the CSAPR program in 2015, many units, like Unit CC01, had no obligation to report data to CAMD under any EPA program. Unit CC01 has only a single year 11 See Allocation TSD at 7. EPA chose a multi-year heat input baseline because "[selecting the three highest, non-zero ozone season heat input values within the five-year baseline reduces the likelihood that an/ p, nicular sing.* yr v \> \c \ u 1 inn h might be negatively affected by outages or other unusual events) determine a unit'' .<fbn." Id. Er-i < I,, > ,< m > , /> er w missions baseline "in order to capture the unit-level emissions before and after the promulgation of the original CbAKft. id. 12 While OK Cogen has an aggressive preventative maintenance program, unexpected equipment maintenance is a part of all power plant's operations. 13 In 2014, Unit CC01 also experienced multiple ozone season outages due to mechanical equipment failures. The unit did not experience similar ozone season outages in 2011-2013. 17cv1906 Sierra Club v. EPA - 6/22 Production ED 001523 00008508-00005 Oklahoma Cogeneration, LLC Facility ID 50558, Unit CC01 Page 6 of reported CAMD data (2015), but has multiple years of EIA data (to before 2008, the earliest relevant baseline year under the Final Rule). Under such circumstances, EPA's methodology calls for the Agency to use a combination of 2015 CAMD data and 2008-2014 E1A data. It is arbitrary and capricious for EPA not to apply this methodology to Unit CC01. EPA also states it will look to publicly available, reported EIA data.14 EPA does not state, in either the Final Rule or the Allocation TSD, that it will adjust EIA data from what is reported directly on the EIA forms.15 EPA therefore should use monthly (not annual), reported (not adjusted for combined-cycle or cogeneration units) EIA data whenever EIA data is called for in allocation calculations. Monthly data is better than annual data with a crude 5/12 multiplier because monthly data more accurately reflects actual ozone season operations.16 Reported heat input data is better than downward-adjusted heat input data for cogeneration and combined-cycle units because reported data more accurately reflects these units' actual fuel use, as well as their highly efficient processes.17 Using monthly, reported EIA data also is consistent with EPA's treatment of CAMD data, which EPA did not adjust when incorporating it into the Final Rule's current allocation calculations. Treating EIA and CAMD data differently would be arbitrary and capricious. C. EPA Should Issue the Technical Corrections Throu/' rect final Rule EPA should issue the requested corrections through a direct final rule as an alternative to full noticeand-comment rulemaking.18 Direct final rules rely on the Administrative Procedure Act's "good cause" Specifically, EPA "used historical heat input and emissions data [EIA] forms, 860, 906, 920, and 923. These data are publicly available Allocation TSD at 6. 15 In the Proposed Rule, EPA appears to have altered OK Cogen's reported EIA data for Unit CC01 in two ways: (1) instead of looking at monthly data for ozone season months, EPA took annual data and multiplied it by 5/12 to estimate ozone season operations (because the ozone season comprises 5 months out of the year); and (2) instead of using total reported heat input values, EPA applied a downward "proportional nameplate capacity adjustment" to account for the fact that Unit CC01 is a combined-cyclele unit with both a gas turbine and a steam turbine that produce electricity (basically, EPA multiplied the gas turbine's share of total nameplate capacity (~59 percent) by total heat input, thereby "discounting" the total heat input by about 41 percent). Email correspondence with EPA (Nov. 7, 2016) and EPA contractors (Nov. 21, 2016). Both of these data manipulations are inappropriate. EPA did not apply either of these changes to OK Cogen's EIA ozone season data in the Original CSAPR or Supplemental CSAPR Rules. Instead, EPA historically has used reported, monthly EIA data--as it should again here. 16 The 5/12 ozone season multiplier incorrectly assumes that Unit CC01 operates more or less the same during all 12 months of the year. In fact, Unit CC01 operates significantly more during the ozone season because it is a highly-efficient natural gas-fired unit that is called on during peak periods of electricity demand, which often coincide with ozone season summer months. Further, monthly EIA data for May-September for 2008-2014 is available for Unit CC01. There is no good reason not to use it. 17 The "proportional nameplate capacity adjustment" for cogeneration and combined cycle units misunderstands how these units operate and punishes these units for being efficient. At a typical combined-cycle plant like Unit CC01, waste heat (exhaust) from the gas turbine produces steam that powers a steam turbine to generate extra electricity. All fuel consumed in combined-cycle units is therefore used in electricity generation: fuel is combusted in the gas turbine to either produce power or produce steam, which produces power. The adjustment ignores this fact and underestimates how much of the unit's heat input goes toward electricity production. Therefore, the adjustment punishes units for employing a more efficient process that reuses gas turbine exhaust to produce steam and more electricity, rather than just venting it off. 1SA direct final rule is "a rule that is issued in final form, without prior notice and comment, that becomes effective on a particular date unless adverse comment is submitted within a specified period of time." EPA Office of General Counsel, Direct Final Rulemaking Guidance for EPA Rule Writers, Attachment 1, 2 (1998). Available at 17cv1906 Sierra Club v. EPA - 6/22 Production ED 001523 00008508-00006 Oklahoma Cogeneration, LLC Facility ID 50558, Unit CC01 Page 7 exemption from notice-and-comment rulemaking,19 while giving the Agency "the benefit of any public input that may unexpectedly surface." Direct Final Rulemaking Guidance at 2 (citation omitted). EPA uses direct final rules for "noncontroversial rules where [the Agency does not] expect adverse comment," including routine or minor actions. Id. at 4, 6. EPA previously has issued direct final rules under the CSAPR program. See, e.g., Revisions to Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone, 77 Fed. Reg. 10,342 (Feb. 21, 2012). Here, the corrections to EPA's allocation calculations for Unit CC01 are a non-controversial, minor action unlikely to attract adverse comment because they (1) would affect only a subset of units within a single state; and (2) are necessary to correct clear technical errors in EPA's application of the Final Rule's allocation methodology. Further, time is of the essence. A direct final rule generally is a more efficient procedural mechanism than notice-and-comment rulemaking. The 2017 ozone season begins in just over five months. OK Cogen needs to get the correct amount of allowances on the books for Unit CC01 as soon as possible in order to plan, and carry out, its compliance strategy for the 2017 ozone season. II. Reconsideration is Required by the Clean Air Act A. Legal Standard The Clean Air Act requires that EPA grant reconsideration of a final rule when a petitioner raising an objection can show that: (1) it was impracticable to raise the relevant objections during the comment period or the grounds for such objection arose after the period for public comment; and (2) the objection is of central relevance to the outcome of the rule. 42 U.S.C. 7607(d)(7)(B). In such a situation, reconsideration is mandatory: EPA "shall convene a proceeding for reconsideration of the rule and provide the same procedural rights as would have been afforded had the information been available at the time the rule was proposed." Id. (emphasis added). The notice-and-comment requirements of the Clean Air Act and the Administrative Procedure Act further require that EPA's "proposed rule and its final rule . . . differ only insofar as the latter is a 'logical outgrowth' of the former." Envtl. Integrity Project v. EPA, 425 F.3d 992, 996 (D.C. Cir. 2005). A "final rule is a 'logical outgrowth' of a proposed rule only if interested parties should have anticipated that the change was possible, and thus reasonably should have filed their comments on the subject during the notice-andcomment period." Id. at 998. The "test is whether a new round of notice and comment would provide the first opportunity for interested parties to offer comments that could persuade the agency to modify its rule." Id. at 996. >iM j ,V . i !ii:t i |.,i i, j, ,-j_ !y > '' '.5. >,) ` , v- ' -1 c ii! (' < < ' ' >u\ . i . (. ' ' i! , ;i'; i' <,-ni >. ument ("Direct Fin?! Rulemaking Guidance"), in conjunction with a direct final rule, FPA's typical practice is to simultaneously publish a separate, parallel proposed rule. If EPA receives significant adverse comment; on the direct final rule, the Agency will withdraw the direct final rule and address the public comments in a subsequent final rule based on the parallel proposed rule. Id. at 4. 19 5 U.S.C. 553(b)(3)(l that notice and public j an 553's notice-and-comment requirement does not apply "when the agency for good cause finds ... -e thereon are impracticable, unnecessary, or contrary to the public interest."). 17cv1906 Sierra Club v. EPA - 6/22 Production ED 001523 00008508-00007 Oklahoma Cogeneration, LLC Facility ID 50558, Unit CC01 Page 8 B. Failure to Comply with Notice and Comment Requirements The grounds for OK Cogen's objection arose after the public comment period. Before the Final Rule was issued, OK Cogen could not have expected or anticipated that EPA would set Unit CCOl's allocations based on a single historic baseline year and only CAMD data. Both the Proposed and Final Rules call for EPA to set unit allocations using multiple historic baseline years20 and EIA data-substitution. EPA did this in the Proposed Rule, but not in the Final Rule. What EPA did in the Final Rule looks like a clear technical error. It would be impracticable, if not impossible, for OK Cogen to have anticipated and submitted comment on an error that EPA had not yet committed during the public comment period, but committed for the first time in the Final Rule. OK Cogen therefore had no meaningful opportunity to comment on the final allocations. EPA did not provide notice of or seek comment on the possibility of switching from multiple to single historic baseline years, or from using both CAMD and EIA data to only CAMD data. Had EPA done so, OK Cogen would have submitted comments that these changes would arbitrarily and unfairly penalize Unit CC01. As it stands, OK Cogen was caught by surprise by the new unit-level allocation data inputs. EPA may not "use the rulemaking process to pull a surprise switcheroo on regulated entities." Envtl. Integrity Project, 425 F.Bd at 998. In yet another "surprise switcheroo," OK Cogen was stunned by the cut in Oklahoma's budget from the Proposed to the Final Rule--the biggest reduction of any state. This reduction resulted largely from the significant revisions EPA made to its formula for calculating model-predicted statewide emissions. Because state budgets dictate the size of the available allowance "pool" for units within the state, the drop in Oklahoma's budget contributed to the drop in OK Cogen's allocations under the Final Rule. Had EPA provided notice of its plan to drastically reduce Oklahoma's budget, OK Cogen would have submitted comments explaining how the revised formula significantly overestimates the amount of emissions reductions achievable in the state and results in an overly stringent budget. OK Cogen's objection also is of central relevance to the outcome of the rule. EPA's data errors have left OK Cogen with a major, unexpected allowance shortfall for the 2017 ozone season. Correcting these errors is critical to OK Cogen's ability to plan for and achieve compliance with the CSAPR Update Rule, especially given the extremely near-term compliance timeframe for the 2017 ozone season. Correcting these errors also would provide a fairer and more representative distribution of allowances within Oklahoma, allowing for more efficient compliance on a state-wide level. Compliance feasibility and efficiency are central to the outcome of the CSAPR Update Rule. CONCLUSION In summary, OK Cogen requests that EPA reconsider the CSAPR Update Rule. As described above, EPA must recalculate the allowance allocations for OK Cogen's Unit CC01 using a corrected methodology that is based on multiple historic baseline years (not just one year) and data-substitution using a combination of 20 The only difference between the Proposed a Because 2015 data was not yet available, the baseline period and a 2007-2014 NOx emission: 2008-2015 NOx emissions baseline period. See t athodologies was a one-year shift in the relevant baseline periods, alculated allowance allocations based on a 2010-2014 heat input . The Final Rule uses a 2011-2015 heat input baseline period and a 6. 17cv1906 Sierra Club v. EPA - 6/22 Production ED 001523 00008508-00008 Oklahoma Cogeneration, LLC Facility ID 50558, Unit CC01 Page 9 CAMD and E1A data (not just CAMD data). EPA should use monthly, reported (unadjusted! data for these calculations. EPA should issue these technical corrections through a direct final rule because they are noncontroversial and are needed on an extremely short time frame. Sincerely, miiigs 11 Beers Ilf Managing Member Enclosures (CD-Rom): Appendix A: Revised 2017 CSAPR Update Allowance Allocation Calculations for Oklahoma Cogeneration LLC Appendix B: Published EIA Data for Oklahoma Cogeneration LLC 2008-2014 CC: David Risley Clean Air Markets Division (Mail Code 6204M) US Environmental Protection Agency 1200 Pennsylvania Avenue NW, Room WJCE 7B55G Washington, DC 20460 Associate General Counsel Air and Radiation Law Office (Mail Code 2344A) US Environmental Protection Agency 1200 Pennsylvania Avenue NW, Room WJCN 7340 Washington, DC 20460 Megan H. Berge Baker Botts LLP 1299 Pennsylvania Ave., NW Washington, DC 20004 202-639-1308 17cv1906 Sierra Club v. EPA - 6/22 Production ED 001523 00008508-00009 Oklahoma Cogeneration, LLC Facility ID 50558, Unit CC01 Page 10 Appendices Along with an electronic submission of this petition, OK Cogen is supplying EPA with a CD-Rom containing the two Appendices (Appendix A and B), The Appendices are Excel datasheets and workbooks demonstrating the calculations described in this petition. The CD-Rom contains both a "locked" fi.e., password-protected, read-only) version and an "unlocked" courtesy working copy of each file. Appendix A-l is a modification of EPA's Final Rule Allocation Spreadsheet TSD. Detailed revised calculations for the reapportionment analysis are contained in Columns AB-AI. 17cv1906 Sierra Club v. EPA 6/22 Production ED 001523 00008508-00010