New proposal addresses certain criticisms of initial proposed rule, but retains partial carbon capture and sequestration requirement for coal-fired power plants.
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Latham & Watkins Environment, Land & Resources Practice
Number 1590 | September 27, 2013
EPA Proposes New Greenhouse Gas Performance Standards for New Power Plants
New proposal addresses certain criticisms of initial proposed rule, but retains partial carbon capture and sequestration requirement for coal-fired power plants.
On September 20, 2013, EPA released new proposed new source performance standards (NSPS) for greenhouse gas emissions (GHGs) from new fossil fuel-fired electric generating units (EGUs).1 EPA’s proposed NSPS replaces an earlier proposed rule from April 2012, which solicited a record 2.5 million public comments. While the new proposal shares much in common with the previous proposal, there are also a number of differences, including the universe of sources covered by the rule, the emissions standards for subcategories of sources, a determination of the best system of emission reduction (BSER) for coal-fired EGUs, and a new alternative compliance option, among others. Importantly, for new fossil fuel-fired power plants other than natural gas-fired facilities, partial carbon capture and sequestration (CCS) is required to meet the emission standards for carbon dioxide (CO2), the only GHG subject to regulation under EPA’s proposal. For new natural gas-fired units, EPA has concluded that compliance should be achievable without additional controls.
Overview of EPA’s New Proposed Standards
EPA’s new proposal would establish standards of performance for three subcategories of fossil fuel-fired EGUs: utility boilers and Integrated Gasification Combined Cycle (IGCC) units (coal-fired units); natural gas-fired combustion turbine EGUs with heat input rating greater than 850 MMBtu/hr; and natural gas fired combustion turbine EGUs with heat input rating less than or equal to 850 MMBtu/hr.2
Emission Limit (Gross Basis)
Proposed Best System of Emission Reduction (BSER)
New fossil fuel-fired boilers and IGCC units
1,100 lb CO2/MWh
New stationary natural gas-fired combustion turbine EGUs with heat input rating greater than 850 MMBtu/hr
1,000 lb CO2/MWh
Modern Natural Gas Combined Cycle (NGCC) Technology
New stationary natural gas-fired combustion turbine EGUs with heat input rating less than or equal to 850 MMBtu/hr
1,100 lb CO2/MWh
Modern NGCC Technology
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EPA states that its proposed standards would not apply to: existing EGUs, modifications to or reconstructions of existing EGUs, combustion turbines that sell one-third or less of their potential output to the grid, new non-natural gas-fired stationary combustion turbines (i.e. oil-fired),3 and EGUs for which 10 percent or less of the heat input over a three-year period is derived from a fossil fuel (i.e. an EGU that primarily fires biomass would not be subject to the standards).4 A source is considered a “new source” under the Clean Air Act for the purposes of this rule (and, thus, subject to these standards) if it commences construction after the proposal is published in the Federal Register.5
EPA proposes that compliance will be determined on a 12-month rolling average, with an alternative compliance demonstration possible for utility boilers and IGCC units of an 84-month (seven-year) rolling average with a more stringent standard (1,000 to 1,050 lb/MWh).6 EPA is seeking comment to determine an appropriate standard within that range, and to determine an appropriate 12-month average standard under the alternative compliance option.
To track geologic sequestration of CO2, the proposed rule relies on EPA’s existing GHG Reporting Program, codified at 40 C.F.R. Part 98, for sources that supply CO2 to the economy and/or inject CO2 underground for geologic sequestration. Specifically, any new EGU that injects CO2 onsite and any offsite facility that receives the CO2 from a new EGU for injection (e.g. for enhanced oil recovery) must meet the reporting requirements of 40 C.F.R. Part 98 subpart RR if the EGU desires to demonstrate NSPS compliance via geologic sequestration. These subpart RR requirements include securing EPA’s approval of a monitoring, reporting, and verification plan designed to ensure the long-term sequestration of CO2. Regardless of where CO2 is injected, any new facility capturing CO2 would be subject to subpart PP of the GHG Reporting Program, which establishes certain applicability requirements to report the mass of CO2 captured for commercial applications or sequestration.
Background on EPA’s Development of Performance Standards for GHGs
Section 111 of the Clean Air Act (CAA) grants EPA the authority to establish standards governing the emission of air pollutants from stationary sources. Specifically, Section 111(b) requires EPA to develop performance standards for any source which the EPA Administrator finds “causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.”7 Section 111 requires that these performance standards adopt “the [BSER] which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.”8
EPA listed fossil fuel-fired EGUs as a source category under CAA Section 111(b)(1)(A) in 1971.9 EPA subsequently established standards of performance for new sources in that category, as required by 111(b)(1)(B), and these standards are codified at 40 C.F.R. Part 60. EPA amended the standards of performance in a 2006 final rule,10 and a number of groups challenged the final rule in the D.C. Circuit Court of Appeals for, among other reasons, EPA’s failure to establish standards of performance for GHG emissions.11 In 2007, following the Supreme Court’s decision in Massachusetts v. EPA12 — in which the Court found that GHGs fit the definition of an air pollutant under the CAA — EPA sought remand of the 2006 rulemaking in order to re-examine the issue of whether the NSPS for EGUs should include performance standards for GHGs. In 2009, EPA issued an “Endangerment Finding,”13 providing the legal justification for subsequent rulemakings relating to GHG emissions.14 In 2010, EPA and the petitioners reached a settlement that included deadlines for EPA to propose and finalize: (1) standards of performance for GHGs for new and modified EGUs under CAA Section 111(b), and (2) emission guidelines for GHG emissions from existing EGUs under CAA Section 111(d).15
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In April 2012, EPA first proposed GHG standards for new fossil fuel-fired EGUs.16 In contrast to the new proposed rule, the 2012 proposal relied on a single emissions standard and a single BSER determination for all covered fossil fuel-fired EGUs, regardless of fuel or technology.17 EPA received over 2.5 million comments on the 2012 proposed rule and failed to finalize the rule within a year of proposal, as required by statute. On June 25, 2013, in conjunction with President Obama’s Climate Action Plan announcement, the President directed EPA to, among other actions, re-propose its GHG standards for new fossil fuel-fired EGUs by September 20, 2013.18 EPA met this deadline with its release of the new proposal and contemporaneously withdrew the April 2012 proposal.
Differences Between the New Proposal and the April 2012 Proposal
The table below highlights some of the key differences between the EPA’s new proposal and the April 2012 proposal.
APRIL 2012 PROPOSAL
EPA initially proposed a single standard for all covered fossil-fuel generating units, regardless of fuel or technology used.19
EPA has now proposed standards for three subcategories of sources: utility boilers and IGCC units (generally coal-fired), large natural gas-fired combustion turbine EGUs and small natural gas-fired combustion turbine EGUs.20
EPA did not make a BSER determination for new coal-fired power plants.
EPA has determined that partial CCS is BSER for new coal-fired power plants.21
EPA initially proposed a 30-year emissions averaging provision, that would have made it possible for coal-fired EGUs to be constructed without CCS and to operate for up to 10 years before having to implement CCS, so long as the EGUs met stringent near-term performance standards and incorporated emissions reductions technologies in a timeframe that allowed them to comply with the emissions limits over a 30-year period.22
EPA has now proposed a shortened alternative compliance standard for utility boilers and IGCC units that would allow compliance to be demonstrated on an 84-month (seven-year) rolling average, requiring a standard in the 1,000 to 1,050 lb/MWh range.23
EPA’s initial proposal excluded certain “transitional” sources (certain coal-fired power plants that had received approval of their Prevention of Significant Deterioration (PSD) preconstruction permits as of the prior proposal and that commenced construction within one year of the date of that proposal).24
EPA is no longer excluding a category of sources defined as “transitional sources,” but is currently proposing to exclude one to three coal-fired projects currently under development and is considering a potential subcategory for those sources.25 EPA explains that any former potential “transitional” source that commenced construction prior to publication of this proposal is an existing source and not subject to these standards.
EPA defined EGUs as units that were constructed for the purpose of supplying more than one third of its electrical capacity for sale to a utility, and more than 25 MW of net electrical output.26
EPA revised the applicability criteria with the intention of exempting most simple cycle turbines and peaking units.27 The revised rule applies only to units, coal or gas-fired, that are actually used to generate and sell more than one third of the
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potential output capacity to the grid, and more than 219,000 MWh, on a three year rolling-average basis.28 As a result, facilities that, due to external factors such as transmission outages, are temporarily supplying more than one third of their potential capacity, or are temporarily producing over 219,000 MWh annually, would continue to be exempt. EPA based the 219,000 MWh figure on continuous production of 25MW, on an annual basis.29
EPA proposed to exempt biomass-fired boilers that burned less than 250 MMBtu/h of any fossil fuel.30
EPA proposes to exempt boilers that use less than 10 percent fossil fuel on a heat input basis.31
EPA previously explicitly exempted simple cycle turbines.32
EPA relies on the limited application of the rule, described above, to exempt most simple cycle turbines.33
The April 2012 proposal did not address Title V fee issues related to GHG emissions.
EPA’s proposal addresses Title V fee issues and includes options for calculating reasonable costs associated with GHG permitting.34
Areas of Likely Comment and Debate on EPA’s New Proposal
EPA’s new proposal includes a number of aspects likely to generate significant comment and debate from various stakeholder groups.
EPA’s determination that a separate endangerment finding is not required
One anticipated source of comment is EPA’s determination that a separate endangerment finding for the proposed rule is not necessary. EPA received numerous comments on this issue in response to its April 2012 proposal. In that proposal, EPA similarly stated that the agency was not required to make findings that GHGs from fossil-fuel fired plants “cause, or contribute significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare” under Section 111(b)(1)(A) of the CAA.35 In its new proposal, EPA states that under Section 111 of the CAA, the agency is required to have a rational basis for promulgating NSPS for GHGs from new fossil-fuel fired EGUs. EPA explains that its rational basis relies on the agency’s prior determination that GHG emissions may reasonably be anticipated to endanger public health and welfare and EPA’s finding that electricity generating plants are the largest GHG emitters.36 EPA issued its prior endangerment finding in 2009, when it determined that elevated concentrations of GHGs may reasonably be anticipated to endanger public health and welfare.37 EPA further concludes in its new proposal that its rational basis determination would qualify as an endangerment finding, if Section 111 does in fact require such a finding.38
EPA addresses prior comments suggesting that EPA must make a pollutant-specific endangerment finding for CO2 and cannot rely on the 2009 endangerment finding, which applied to a mix of six GHGs. First, EPA concludes that under Section 111(b)(1)(B) of the Clean Air Act, EPA is not required to make an endangerment finding for a particular pollutant in order to promulgate NSPS for that pollutant. Second, EPA claims that it can rely on its 2009 endangerment finding even when regulating only CO2 because air
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pollution based on the six GHGs has caused the public health and welfare impacts that are the basis for the rule and because CO2 emissions from EGUs are a major component of that air pollution.39
EPA’s interpretation of its statutory authority with respect to BSER
Another area of EPA’s new proposal likely to generate a significant debate is EPA’s interpretation of its statutory authority and the legal support for its BSER determinations. Observers will likely comment on EPA’s interpretation, not only in the context of this proposal, but also anticipating EPA’s forthcoming rulemaking to establish GHG emission guidelines under Section 111(d) for existing power plants.
EPA states that case law permits the agency to consider the costs and other factors for determining the BSER on a regional or national level over time and that EPA is not limited to considering the factors on a plant-specific level at the time of rulemaking.40 EPA also claims that the D.C. Circuit has permitted EPA “a great deal of discretion in weighing the various factors to determine the ‘best system.’”41 EPA explains that the D.C. Circuit has outlined a number of key considerations EPA makes in determining BSER, including:
• Technical Feasibility: EPA states that a standard of performance is achievable “if the technology can reasonably be projected to be available to new sources at the time they are constructed that will allow them to meet the standard.”42 EPA further states that a standard may meet the requirements of Section 111 “even if it cannot be met by every new source in the source category that would have constructed in the absence of that standard.”43
• Amount of Emissions Reductions: EPA states that the D.C. Circuit requires EPA to take into account the amount of emissions from the source and the amount of reductions achieved in determining BSER.44
• Costs: EPA states that D.C. Circuit cases have used a number of different ways to describe the cost standard, including whether the costs are “exorbitant,” “excessive” or “unreasonable.”45 EPA adopts a reasonableness standard for this rulemaking and states that in determining the costs of a system, it is reasonable for EPA to take into account revenue enhancements from the sale of CO2 for enhanced oil recovery, for example.46
• Development of Technology: EPA also states that case law suggests that EPA should consider promoting the development and implementation of technology in determining BSER.47
EPA’s determination that few, if any, solid fossil fuel-fired EGUs will be built over the foreseeable future
EPA found that no new unplanned coal-fired power plants would be built without CCS before 2020.48 As a result, EPA projects that the proposed rule would not have significant cost or benefits, as no plants are expected to react to the requirements in the proposal in the analysis timeframe, but rather “will likely choose technologies that meet these standards even in the absence of this proposal.”49 To reach this conclusion, EPA conducted its own modeling, and also reviewed the modeling of the Energy Information Administration (EIA).50 Both EIA’s and EPA’s models projected that the only unplanned coal facilities that would be built by 2020 would use CCS.51 In large part, this projection is due to EPA’s cost of energy calculations that found in all modeled scenarios of coal and natural gas prices, natural gas plants would be less expensive than coal plants, with or without CCS.52 According to EPA’s calculations, a natural gas price of $10 per MMBtu would be required to make new coal construction competitive (while including carbon risk) without a market for the captured CO2.53 EPA states that the average delivered natural gas price to the power sector in 2012 was $3.44 per MMBtu,54 and EPA notes that to achieve $10 per MMBtu
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would require prices 30 percent higher than any of the modeling runs analyzed.55As a result, the models EPA cites predict that new unplanned coal capacity will only be built when there is a market for the captured CO2, and thus only plants with integrated carbon capture are considered economically viable in the 2020 time horizon.
EPA’s evaluation of partial CCS as BSER
Significance of BSER Selection
Despite EPA’s position that selection of a CO2 control standard for power plants is likely to have a minimal impact on the type of power plants designed and built in the near-term, the agency’s rulemaking is significant nonetheless because it reflects the agency’s view that under Section 111(b) it may, to some extent, force technology if it can project the necessary technological feasibility, cost and other determinations associated with applying a technology prospectively to new sources. In recent days agency officials have been careful to distinguish this view from EPA’s authority to regulate existing sources under Section 111(d), for which EPA does not anticipate making the determination that CCS has been adequately demonstrated.56 It will be important for EPA to approach the regulation of modified units as part of its overall existing source program if it is to avoid practical and potential legal challenges that a technology-forcing approach would pose for such units.
EPA evaluated three alternatives in deciding which control strategy satisfies the BSER standard:
(1) Highly efficient new generation technology that does not include CCS
(2) Highly efficient new generation technology with “full capture” CCS (capture of CO2 above 90 percent)
(3) Highly efficient new generation technology with “partial capture” CCS
EPA ultimately selected “partial capture” CCS as the strategy that best satisfies the technical, environmental, economic, energy, and innovation considerations of BSER. EPA believes partial CCS is consistent with the needs of the current and future power sector, will have virtually no impact on the price of electricity, and is the best system of emission reduction on a national and regional level over time.
EPA dismissed all potential CO2 control technologies that did not include CCS because it determined these alternatives, including supercritical pulverized coal (SCPC), a circulating fluidized bed (CFB) boiler, and a modern IGCC unit, did not significantly reduce CO2 emissions. These alternatives reduce emissions to between 1,800 lb CO2/MWh and 1,450 lb CO2/MWh, well above the emission levels that can be achieved by CCS. EPA concluded that an option excluding CCS also did not advance the development and implementation of controls that reduce CO2 emissions.
Partial Versus Full CCS
EPA examined the partial versus full CCS alternatives in depth, but ultimately opted for partial capture because of the enhanced “operational flexibilities” and lower cost partial capture offers. EPA found that partial CCS allows operators to adjust carbon capture rates during peak versus non-peak electricity demand periods to “optimize the operation and minimize the cost of CCS in new fossil fuel-fired projects.”57 EPA also concluded that partial CCS provides added design flexibility in new coal-fired power plants. And, as opposed to full carbon capture, EPA found that partial CCS will allow project developers to continue to use conventional syngas combustion turbines rather than advanced hydrogen turbines and will minimize the need for multi-stage water-gas shift reactors. All told, EPA estimates that the difference in cost per MWh is $92/$97 (SCPC/IGCC) for partial CCS versus $147/$136 (SCPC/IGCC) for full CCS.58 According to a Department of Energy/National Energy Technology Laboratory study of partial CCS, the
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technology can reduce CO2 emissions by 25-75 percent, which corresponds to emissions of approximately 1,060 to 380 lb CO2/MWh-gross. EPA’s proposed standard of performance of 1,100 lb CO2/MWh-gross, is at the high end of this range.59
Technical Feasibility and Availability of Partial CCS
The already brewing battle over EPA’s selection of emissions limits based on partial CCS is likely to focus, in large part, on the technical feasibility and availability of partial CCS. In finding that partial CCS is technically feasible and available, EPA relies on literature, fossil fuel-fired industrial plants and pilot-scale plants in operation, and the progress of EGUs that are implementing CCS on a commercial scale. Critics of partial CCS are likely to attack this record and argue that the technical feasibility of partial CCS has not been “adequately demonstrated,” as required under Section 111(a)(1) of the CAA. In the proposed rule, EPA vigorously defends its determination that CCS is technically feasible, laying out a lengthy legal defense and also citing numerous studies and examples of upcoming projects incorporating partial CCS, including: Southern Company’s Kemper County Energy Facility, Summit Power’s Texas Clean Energy Project, Hydrogen Energy California Project, and SaskPower’s Boundary Dam Project.60 The fate of these projects appears likely to shape the ongoing debate regarding the feasibility and availability of partial CCS.
Sequestration and Enhanced Oil Recovery
EPA indicates that capture and compression represents the most significant cost related to CCS, accounting for 70-90 percent of CCS costs.61 In the proposed rule, EPA briefly evaluates the capture and compression technologies available as well as CO2 transportation (which EPA considers to be both feasible and a relatively insignificant cost). Potentially more problematic, EPA believes CO2 storage is technically feasible and available, but concedes sequestration will require further study including an increased understanding of “site selection and characterization, CO2 plume tracking, and monitoring.”62 In support of the current viability of geologic sequestration, EPA points to multiple studies as well as four existing commercial CCS projects in Sleipnir (North Sea, off Norway), Snøhvit (Barents Sea, off Norway), Salah, Algeria, and Weyburn, Canada.63
In addition to these projects, EPA places particular emphasis on the potential for use of CO2 in enhanced oil and gas recovery. Carbon dioxide has been used for over 40 years to enhance oil and natural gas recovery from oil zones. EPA draws on industry experience and studies of potential CO2 leakage from these fields to enhance its argument that geologic sequestration is not only feasible, but is already successful in practice. EPA anticipates that active or depleted oil and gas reservoirs, with some 226 billion tons of potential CO2 storage space, may be the most common early sites for geologic sequestration.64 EPA states that enhanced oil recovery, particularly if a suitable site is located near a coal-fired plant, can help defray the costs of CCS. Although EPA believes current CCS costs are reasonable even without enhanced oil recovery, it anticipates that the costs of CCS will also decrease over time as new CCS projects complete construction and begin operation.65 According to EPA, the adoption of partial CCS as the BSER also will result in a positive feedback loop, increasing utilization of the technology and further driving down costs.
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EPA’s proposed standards of performance for CO2 emissions from new EGUs raise important issues for multiple segments of the US power and oil and gas industries. EPA is accepting comments on the proposed rule for 60 days after publication of the proposed performance standards in the Federal Register. EPA advises that comments submitted on the withdrawn April 2012 proposal will need to be resubmitted, where applicable, in order for EPA to consider the comments in this current rulemaking proposal. While this September 2013 proposal does not include performance standards for existing EGUs, EPA has announced that in the coming months, it will be engaging with states, the power sector, environmental groups, the public and other entities regarding GHG emissions from existing power plants.
If you have questions about this Client Alert, please contact one of the authors listed below or the Latham lawyer with whom you normally consult:
Robert A. Wyman, Jr.
Claudia M. O'Brien
Karl A. Karg
Joshua T. Bledsoe
Andrea M. Hogan
Matthew D. Thurlow
Stacey L. VanBelleghem
Eli W.L. Hopson
Laura J. Glickman*
* This Alert was prepared with the assistance of Laura J. Glickman, an associate in the Washington, D.C. office of Latham & Watkins not admitted to the DC Bar.
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1 EPA, “Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units” (Sept. 20, 2013) (prepublication version) [EPA-HQ-OAR-2013-0495] available at http://www2.epa.gov/sites/production/files/2013-09/documents/20130920proposal.pdf (hereinafter “Proposed Rule”).
2 Proposed Rule at 15-16, 88.
3 Id. at 86-87.
4 Id. at 85.
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5 42 U.S.C. § 7411(a)(2).
6 Proposed Rule at 89, 96.
7 42 U.S.C. § 7411(b)(1).
8 Id. § 7411(a)(1).
9 EPA, “List of Categories of Stationary Sources,” 36 Fed. Reg. 5931 (Mar. 31, 1971).
10 EPA, “Standards of Performance for Electric Utility Steam Generating Units, Industrial-Commercial-Institutional Steam Generating Units, and Small Industrial-Commercial-Institutional Steam Generating Units.” 71 Fed. Reg. 9866 (Feb. 27, 2006).
11 State of New York, et al. v. EPA, No. 06–1322.
12 Massachusetts v. EPA, 549 U.S. 497 (2007).
13 EPA, “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 66496 (Dec. 15, 2009).
14 In Coalition for Responsible Regulation, Inc. v. EPA, the D.C. Circuit upheld EPA’s endangerment finding and its stationary source-related statutory interpretations based upon it. 684 F.3d 102 (D.C. Cir. 2012). Numerous petitions for certiorari have been filed seeking US Supreme Court review of this decision.
15 “Proposed Settlement Agreement,” 75 Fed. Reg. 82392 (Dec. 30, 2010).
16 “Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units.” 77 Fed. Reg. 22392 (proposed April 13, 2012).
17 Id. at 22394.
18 Memorandum from President Obama to Administrator of the Environmental Protection Agency, Power Sector Carbon Pollution Standards (June 25, 2013).
19 77 Fed. Reg. at 22394.
20 Proposed Rule at 88.
21 Id. at 15-16.
22 77 Fed. Reg. at 22394.
23 Proposed Rule at 96-97.
24 77 Fed. Reg. at 22395.
25 Proposed Rule at 87, 163-65.
26 77 Fed. Reg. at 22439.
27 Proposed Rule at 82.
28 Id. at 82-83.
29 Id. at 83.
30 77 Fed. Reg. at 22398.
31 Proposed Rule at 379.
32 77 Fed. Reg. at 22437.
33 Proposed Rule at 82-83.
34 Id. at 313-343.
35 Id. at 120.
37 Id.at 122; EPA, “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 66,496 (Dec. 15, 2009).
38 Proposed Rule at 136-137.
39 Id. at 134.
40 Id. at 172-73 (citing Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981)).
41 Id. at 173 (citing Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999)).
42 Id. at 174.
43 Id. at 190-91.
44 Id. at 175-76 (citing Sierra Club, 657 F.2d at 326).
45 Id. at 177-78 (citing Sierra Club, 657 F.2d at 343; Lignite Energy Council, 198 F.3d at 933).
46 Id. at 180-81.
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47 Id. at 181-82 (citing Sierra Club, 657 F.2d at 347).
48 EPA, “Regulatory Impact Analysis for the Proposed Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units,” 5-1 (Sept. 2013) available at http://www2.epa.gov/sites/production/files/2013-09/documents/20130920proposalria.pdf (hereinafter “Proposal RIA”).
49 Proposed Rule at 16.
51 Proposal RIA at 5-8.
52 Id. at 5-23 – 5-24.
53 Id. at 5-24 – 5-25.
54 Id. at 5-13.
55 Proposal RIA at 5-25 – 5-26.
56 Andrew Childers, “EPA Won't Require Carbon Capture for Existing Power Plants, McCarthy Says,” BLOOMBERG BNA, Sept. 24, 2013, http://www.bna.com/epa-wont-require-n17179877247/.
57 Proposed Rule at 210.
58 Id. at 248
59 Id. at 211.
60 Id. at 236-37; 258.
61 Id. at 218.
62 Id. at 221.
63 Id. at 222, n. 201.
64 Id. at 230.
65 Id. at 256.