From: Vasu, Amy

Sent: Wednesday, July 29, 2015 10:42 AM

To: nfrey@omb.eop.gov

Cc: Szabo, Aaron; Tsirigotis, Peter; Culligan, Kevin; Harvey, Reid
Subject: For interagency review -- revised legal memo for the Clean Power Plan final rule

Nathan,

Attached, for interagency review, is an expanded and updated version of the legal memo for the
CPP final rule.

Thank you.

Amy

~~~~~~~~~~~~~~~~~~~~~~~ Amy B. Vasu
U.S. EPA / OAQPS Sector Policies and Programs Division email: vasu.amy@epa.gov phone: 919.541.0107

<< Legal Memo v3_07-29-15_clean (2).docx >>1 Legal Memo v3_07-29-15_clean Legal Memorandum Accompanying Clea n Power Plan for Certain Issues

This document includes additional information c oncerning certain legal issues relevant to

the Clean Power Plan. This document is intended to be read in conjunction with the preamble and the Response to Comments document. In c onnection with the proposed Clean Power Plan, we included in the docket a legal memorandum that provided our proposed position on a variety of legal issues. The discussion of legal issues contained in the preamble for the final rule, this Memorandum, and the Response to Comments Document supersede some of the preliminary interpretations taken in that document, as in dicated in the preamble or this Memorandum.

I. Relationship between the Building Bl ocks and the BSER for New EGUs.

In this section, in response to comments, we describe why we have not included building blocks 1, 2, and 3 as part of the BSER for new sources in the section 111(b) rule. This section largely reproduces section XI of section 111(b) preamble.

In the CAA section 111(b) rule for new, m odified, and reconstructed steam units and combustion turbines that the EPA is promulgati ng at the same time as this CAA section 111(d) rule, the EPA is not identifying as part of the BS ER for those sources building block 1 (for steam units, efficient operation), building block 2 (for steam units, dispatch shift to existing NGCC units), and building block 3 (for steam units and combustion turbines, substitution of generation with new renewable energy). In this section, we explain why the EPA is not identifying building blocks 1, 2, or 3 as part of th e BSER for new, modified, or re constructed steam generators or

combustion turbines in th e section 111(b) rule.

A. Newly constructed steam generating units.

1. Preference for technological controls.

As discussed in the preambles for the secti on 111(b) and 111(d) rules, the phrase “system of emission reduction” is undefined and provides the EPA with discretion in setting a standard of performance under CAA section 111(b) or em ission guidelines under CAA section 111(d). Because the phrase by its plain language does not lim it our review of potentia l systems in either context, the same systems could be considered for application in new and existing sources. That said, many other factors and considerations di rect us to focus on different systems when establishing a standard of performance under CAA section 111(b) and an emission guideline under CAA section 111(d). Thus, it is useful to describe part of the underlying basis for the BSER – partial CCS - that the EPA has determin ed for new steam units before discussing the building blocks that form th e BSER for existing units.

For new steam generating units, the EPA is identifying, as the BSER, systems of

emission reduction that assure that these sour ces are inherently low-emitting at the time of

construction. There are several reason s for this approach to the BSER.

While CAA section 111(b)(1)(B) and (a)(1) by its terms does not mandate that the BSER assure that new sources are inherently low emitting, that approach to the BSER is consistent with2 congressional intent for new sources, as expressed in the legislative history. 1 For instance, the 1970 Senate Committee Report explains that “[ t]he overriding purpose of this section [concerning new source performance standards] would be to preven t new air pollution problems, and toward that end, maximum feasible control of new sources at the time of their construction is seen by the committee as the most effective and, in the long run, the leas t expensive approach.” 2
Existing sources, on the other hand, would be regul ated through emission standards, which were broadly understood at the time to reflect availabl e technology, alternativ e methods of prevention and control, alternative fuels, processes, and operating methods. 3

In 1977, Congress reinforced the distinction be tween new and existing source standards. Specifically, Congress amended the definition for a standard of performance to clarify that new source standards would reflect the “best technolog ical system of continuous emission reduction.” This new formulation was intended to compel new sources to install techno logical controls rather than implement lower-cost compliance measures . In shifting new sources towards technological controls, Congress explained, lower-cost measures would be available to existing sources where “higher capital costs could be avoided”. 4 As an example, Congress believed section 111 (following the 1977 CAA Amendments) would compel new coal-fired power plants to install scrubbers and take advantage of coal wash ing in order to free lower-sulfur coal ( i.e. , fuel switching) for use by existing units.

The 1990 CAA Amendments repealed the pr ovisions in section 111(a)(1) that distinguished between new and existing sour ces, but nothing in the 1990 CAA Amendments precludes the EPA from continuing to prefer technologica l controls for new sources in order to

ensure lower-cost measures would be available for existing sources. Indeed, this approach is sensible because new sources are expected to ha ve long operating lives over which initial capital costs can be amortized. Thus, new construction is the pr eferred time to drive capital investment

in emission controls.

In this case, the BSER for new steam genera tors, partial CCS, requires substantial capital expenditures, which new sources are best able to accommodate.

2. Practical implications of including the building blocks.

1 Although Congress expressed a clear preference th at new sources would be “designed, built, equipped, operated, and maintained so as to reduce emissions to a minimum,” the Senate Committee Report also makes clear th at the term standard of perf ormance “refers to the degree

of emission control which can be achieved through process change s, operation changes, direct emission control, or other methods .” Sen. Rep. No. 91-1196 at 15-17, 1970 CAA Legis. Hist. at 415-17 (emphasis added).

2 Sen. Rep. No. 91-1196 at 15-16, 1970 CAA Legi s. Hist. at 416 (emphasis added).

3 See 1970 CAA Amendments, Pub. L. 91-604, § 4, 84 Stat. 1676, 1679 (Dec. 31, 1970) (describing information that the EPA must issu e to the States and a ppropriate air pollution control agencies along with the i ssuance of ambient air quality cr iteria under Section 4 of the 1970 CAA titled “Ambient Air Quality and Emission Standards”).

4 H.R. Rep. No. 95-294 at 186, 1977 CAA Legis. Hist. at 2653.3 Aside from whether the EPA can prefer tec hnological controls wh en setting new source standards, several practical c onsiderations make the building blocks inappropriate for new sources. Thus, for the following reasons, the EPA doe s not consider it appropr iate to include the building blocks as part of the BSER for new sources:

a. Additional cost. Partial CCS will impose substantial costs on new steam-generating EGUs, and, as a result, the EPA does not believe that including additional meas ures as part of the BSER would be appropriate. One disadvantage in adding additional costs is that doing so would make it more difficult for new steam-generati ng EGUs to compete with new nuclear units.

Because the BSER is selected after considering cost (among ot her factors), the EPA is not required to, 5 and in this case believes it would not be appropriate to, select the most stringent adequately demonstrated system of emission re duction (through the combin ation of partial CCS and the building blocks) for purposes of setting a standard of performance under CAA section 111(b).

Building block 1 measures are not appropr iate because the BSER for new steam generating units is based on highly efficient su percritical technology, i. e., state-of-the-art, efficient equipment. Accordingly, th ere is little improvement in efficiency that can be justified as part of the BSER.

Building block 2 and 3 measures are not a ppropriate for the BSER because new steam units would have a significantly limited range of options to implement building blocks 2 and 3. The new source performance standard was proposed and is being finalized as a rate-based standard. Thus, if building blocks 2 and 3 were included in the BSER, a more stringent ratebased standard would be applicable to all new sources. However, it is conceivable that EPA could propose a hybrid standard that would include both an em ission-rate limit that reflects partial CCS and a requirement for allowances that reflects building blocks 2 and 3. Accordingly, the following discussion assumes either a rate-bas ed or mass-based standard, or part of a hybrid

standard.

In both a rate-based program and a mass- based program, building blocks 2 and 3 measures can be implemented through a range of methods, including trading with other EGUs. While it is not necessarily the case that every ex isting source will be able to implement each of the methods, in general, existing sources will have a range of measures to choose from.

5 For example, as early as a 1979 NSPS rulemaki ng for affected EGUs, the EPA recognized that it was not required to establish as the BSER the most stringent adequately demonstrated system of emission reduction available, and instead could weigh the amount of additional emission reductions against the costs. See 44 F.R. 52792, 52798 (Sept. 10, 1979) (“Although there may be emission control technology availa ble that can reduce emissions be low those levels required to comply with standards of perfor mance, this technology might not be selected as the basis of standards of performance due to costs associat ed with its use. Acco rdingly, standards of performance should not be viewed as the ultimate in achievable emission cont rol. In fact, the Act requires (or has potential for requi ring) the imposition of a more stringent emission standard in several situations.”).4 However, at least some of those methods may not be available to new sources, which would render compliance with their emission limits mo re challenging and potentially more costly.

One example is emission trading with ot her affected EGUs. For existing sources, emission trading is an important option for im plementing the building blocks. There are large numbers of existing sources, and they will become subject to the section 111(d) standards of performance at the same time. It may be more cost-effective for some existing sources to implement the building blocks than others, and, as a result, some may over-comply and some may under-comply, and the two groups may trade with each other. Because of the large numbers of existing sources, the trading market can be expected to be robust. Trading optimizes efficiency. As a result, existi ng sources have more flexibility in the overall amount of their investment in building blocks 2 and 3, and can adjust investment obligations among themselves through emissions trading.

In contrast, new sources construct one at a time, and it is unknown how many new

sources there will be. Without a sizeable number of new sources, there will not be a robust trading market. Thus, a new source cannot count on being able to find a new source trading

partner.

In addition, it is not possible to count on new sources being able to trade with existing sources, for several reasons. First, there is legal uncertainty as to whether new sources could trade with existing sources under section 111. 6 Second, new sources must meet their standards of performance as soon as they begin operations. If they do so before the year 2022, when existing sources become subject to sec tion 111(d) state plan standard s of performance, no existing

sources will be available as trading partners.

In addition, for section 111(d) sources, we are granting a 7-year period of lead-time for the implementation of the building blocks. This is due, in part, to the benefits of allowing the ERC and allowance markets to develop. Howeve r, the new source standards take effect immediately, so that new sources would not have the advantage of this lead time were they subject to more stringent standard s reflected in th e building blocks. 7

In addition, if there are an unexpectedly large number of new sources, then they would be obliged to invest in greater amounts of buildi ng blocks 2 and 3, and th at could reduce the

6 Part of the uncertainty lies in the distinc tions between CAA section 111(b) and CAA section 111(d). While the EPA establishes nationally appl icable performance standards for new sources,

each state has considerable discretion in esta blishing standards of performance for existing sources. Accordingly, it is not clear that a new source rule could tap into existing source programs, particularly if that action woul d disrupt the operation of the state’s plan.

7 At least in theory, we could consider promulga ting a standard of performance for new affected EGUs that becomes more stringent beginning in 7 years, based on a more stringent BSER. We are not inclined to adopt that approach because section 111(b)(1)(B) requires that we review and, if necessary, revise the secti on 111(b) standards of performan ce no later than every 8 years

anyway.5 amounts of building blocks 2 and 3 available for existing sources, and ther eby raise the costs of building blocks 2 and 3 for existing sources. This could compromise the BSER under section 111(d) and undermine the ability of existing s ources to comply with their section 111(d) obligations. 8

B. New combustion turbines.

For new combustion turbines, the building blocks are not appropriate as part of the BSER for the following reasons: Building block 1 is limited to steam ge nerating units, and therefore has no applicability to new combustion turbines. Measures comparable to those in building block 1 would not be appropriate because the highly e fficient NGCC construction already entails high efficiency equipment and operation.

Building block 2 is also limited to steam genera ting units and is not appropriate as part of

the BSER for new NGCC units because it w ould not result in any emission reductions.

The reasons why building block 3 are not approp riate are the same as discussed above for why building blocks 2 and 3 are not appropriate for new steam generating units (limited range of options for implementation (including lack of av ailability of trading), lack of lead-time for implementation, and the possibility of reducing th e availability of renewable energy for existing sources).

C. Modified and reconstructed steam and NGCC units

For modified and reconstructed steam gene rators, the EPA identified the BSER as maintenance of high efficiency or implementa tion of a highly efficient unit. The resulting emission limit must be met over the specified time period and cannot be deviated from or averaged. As a result, a modified or reconstruc ted steam generator gene rally will require ongoing maintenance, and may find it prudent to operate below its limit as a safety margin. This represents a substantial commitment of res ources. For these units, the additional costs of implementing the building blocks would not be appropriate.

In addition, building block 1 is not appropriate for modifi ed or reconstructed steam generating units because the BSER for these units is already base d on highly efficient performance. For the same reasons, it does not make sense to attempt to develop the analogue to building block 1 for modified or reconstructed NGCC units – the BSER for them, too, is already based on highly efficient performance.

Building block 2 is not appropriate for modi fied or reconstructed NGCC units because it would not yield any reductions.

8 The EPA is authorized to consider the BSER for new and existing sources in conjunction with each other. In the 1977 CAA Amendments, Congr ess revised section 111(a)(1) to require technological controls for new combustion source s at least in part be cause this requirement would preclude new sources from relying on low- sulfur coal to achieve their emission limits, which, in turn, would free up low-su lfur coal for existing sources.6 Building blocks 2 and 3 are not appropriate for modified or reconstructed steam generators, and building block 3 is not appropria te for modified or reconstructed NGCC units, for the same reasons that they are not appropr iate for new EGUs, as described above (limited range of options for implementation (including lack of availability of trad ing), lack of lead-time for implementation, and the possibility of reducin g the availability of renewable energy for existing sources).

II. Uniqueness of CO 2 and of the Electric Power Sector

In section V.A.2.b. of the preambl e, we note the reasons why CO 2 is a unique air pollutant and why the electric power sector is a unique source category, and the critical importance of those characteristics in shaping th is rule. Here we note that the U.S. Supreme Court has recognized both the uniqueness of CO 2 and the electric power sector. In Utility Air Regulatory Group v. EPA , 134 S. Ct. 2427 (2014), the Court recognized that greenhouse gases like carbon dioxide are “atypical pollutants” that are emitted in “vast quantities.” Id. at 2442; see also AEP v. Connecticut , 131 S. Ct. 2527, 2538 (2011) (“Congress could hardly preemptively prohibit every discharge of carbon di oxide unless covered by a permit.”). 9 Moreover, the Supreme Court has repeatedly affirmed the auth ority and responsibility of the agency, charged with implementing the Clean Air Ac t, to deploy its expertise and th e exercise of its discretion to fashion workable regulatory frameworks for greenhouse gases. UARG , 134 S. Ct. at 2441, 2442 (directing the agency to use its discretion and look to “statutory context” in applying the CAA to greenhouse gases); AEP , 131 S. Ct. at 2539 (“Congress delega ted to EPA the decision whether and how to regulate carbon dioxide emi ssions from power plants . . . .”); id. at 2539 (“It is altogether fitting that Congress desi gnated an expert agency, here, EPA, as best suited to serve as primary regulator of greenhouse gas emissions.”). See also AEP , 131 S. Ct. at 2539 (“The appropriate amount of regulation in any partic ular greenhouse gas-produc ing sector cannot be prescribed in a vacuum ..., informed assessm ent of competing interests is required.”).

The Court has also recognized the uniqueness of the electric power sector. This sector is the single largest contributor to national CO 2 emissions (in addition to other air pollutants); as the preamble notes, it operates as a large machin e, i.e., as an interconnected entity; and it is economically critical to the c ountry. This uniqueness is recogn ized by Congress throughout the Clean Air Act, including in va rious provisions of section 111. 10 The Supreme Court recently directed the agency to fully exercise its discre tion by considering costs in determining whether it is “appropriate and necessary” to regulate hazar dous air pollutants from the power sector under section 112(n). See Michigan v. EPA , No. 14-46, at 6 (June 29, 2015) (Slip Op.) (“The Clean Air Act treats power plants differently from ot her sources for purposes of the hazardous-airpollutants program.”). As required under section 111, in the Clean Power Plan, the agency has, of course, considered costs among the other factor s relevant to the power sector in determining the “appropriate amount of regulat ion” for carbon dioxide. As we discuss elsewhere, Congress

9 Notably, the Court in UARG recognized, and did not disturb, the agency’s conclusion that greenhouse gases are a pollutant under the CAA b ecause they endanger public health and welfare by fostering global climate change. See UARG , 134 S. Ct. at 2436-37.

10 See sections 111(a)(7)(B), 111( a)(8), and 111(b)(6).7 added section 112(n) in the 1990 CAA Amendments, at the same time that it added Title IV to regulate acid rain precursors from the electric power sector and revised section 111 with respect to the electric power sector, and linked the Ti tle IV revisions to th e section 111 revisions.

Numerous commenters objected that the EPA has never applied measures like the building blocks in section 111 rules, and asserted that the EPA was depa rting from long-standing precedent without explaining why. We disagree with these comments. As we explain in section V.A.2.b. of the preamble, to determine the BSER, we began by considering the characteristics of

CO 2 pollution and the utility power sector. We have not previously regulated CO 2 pollution from the utility power sector, and the combination of the unique character istics of that air pollutant with the unique characteri stics of that sector have led us to include building blocks 2 and 3 in the BSER. As we note in the preamble, not surprisi ngly, whenever the EPA begins the regulatory process under section 111, we initially undertak e these same inquiries and then proceed to

fashion the rule to fit the industr y. In that sense, our approach to this rulemaking is consistent with our approach to previous section 111 rules.

III. NSPS Rulemakings and the Integrated Grid

This section provides a more detailed desc ription of two EPA NSPS rulemakings that relied on the integrated grid, which supports the discussion in the preamble in section V.B.3.c.(6)(c).

On June 11, 1979, EPA finalized new standards of performance to limit emissions of sulfur dioxide, particulate matter, and nitrogen oxides from ne w, modified, and reconstructed electric utility steam generating units. 11 The revised standards limited sulfur dioxide emissions to 1.20 ppm BTU heat input for solid derived fuel and 0.80 ppm heat input for liquid or gaseous fuels. In both instances, a 90 pe rcent reduction was also required. 12 A 70 percent reduction was required for solid derived fuels when emissions are less than 0.60 ppm BTU heat input, and a zero percent reduction was required for liquid or ga seous fuels when emissions are less than 0.20 ppm BTU heat input. 13 In selecting these standards, th e Administrator investigated “coal cleaning and the relative economics of FGD [flu e gas desulfurization] and coal cleaning” together as the “best demonstrated system for SO 2 emission reduction.” 14 Compliance with the standards could be met through credits “for any cl eaning of the fuel, or reduction in pollutant characteristics of the fuel, after mining and prior to combustion.” 15

11 See New Stationary Sources Performance Standard s; Electric Utility Steam Generating Units, 44 F.R. 33580 (June 11, 1979).

12 44 F.R. 33580, 33614.

13 44 F.R. 33580, 33614.

14 44 F.R. 33580, 33593. The amount of sulfur that c ould be removed from co al was investigated by the U.S. Department of the Interior and consid ered sulfur reduction pote ntial of coal cleaning

for the Eastern Midwest and the No rthern Appalachian Coal regions. Id. at 33593.

15 44 F.R. 33580, 33581. In order to re ceive credit for fuel pretreat ment, owners or operators of an affected facility must list th e “quantity, heat content, and date each pretreated fuel shipment was received during the previous qu arter; the name and location of the fuel pretreatment facility;8 Notably, in assessing the best demonstrated system against concerns of electric service reliability, the Administrator took into account “t he generating capacity of the affected utility company..., and the amount of power that could be purchased from neighboring interconnected utility companies.” 16 Part of this analysis noted that “[a] lmost all electric utility generating units in the United States are electrically inte rconnected through power transmission lines and switching stations.” 17 The Administrator determined that a broad exemption from the standards was not necessary “because load can usually be shifted to other electric generating units.” 18
Moreover, “reducing the level of electric generation” could be implemented in the case of a

failed FGD module and would not affect the rema inder of the FGD system, thus “permit[ting] the utility to maintain compliance with the standards without having to take the generating unit entirely out of operation.” 19 In other words, “a properly designed FGD system has no routine need for an exemption from the SO 2 percentage reduction requireme nt when the unit is operated

at reduced load.” 20 Accordingly, an exemption from the standards was “not necessary to protect electric service reliability or to maintain compliance with the[] SO 2 standards.” 21 These standards were upheld by the D.C. Circuit in Sierra Club v. Costle , 657 F.2d 298 (D.C. Cir. 1981).

Similarly, in a 1982 rulemaking promul gating an NSPS, the EPA stated:

The EPA position is that un like utility turbines, indus trial turbines in some instances may represent the sole prim ary energy source for a major industrial process. Such a turbine could not be shut down more frequently without an unacceptable economic consequence. The unacceptable economic consequence could be that an entire plant or proc ess depends on the continuously running gas turbine. This is not the case for utility turbines, however, since other electric generators on the grid can restore lo st capacity caused by turbine down time. Inspection and maintenance can be sche duled for a low load period when full

and the total quantity and total heat content of all fuels received at the affected facility during the previous quarter. Id. at 33619.

16 44 F.R. 33580, 33597.

17 44 F.R. 33580, 33599.

18 44 F.R. 33580, 33600. A limited exemption that “a llow[ed] an owner or operator to bypass uncontrolled flue gases around a malfunctioning FGD system” was permitted so long as three conditions were met: “(1) the FGD system has b een constructed with a spare FGD module, (2)

FGD modules are not available in sufficient numbers to treat the entire quantity of flue gas generated, and (3) all available el ectric generating capacity is be ing utilized in a power pool or network consisting of the generating capacity of the affected utility company (except for the capacity of the largest single ge nerating unit in the company), and the amount of power that could be purchased from neighboring interconnected utility companies.” Id. at 33597.

19 44 F.R. 33580, 33600. In other words, because FGD systems could be designed to have backup modules, a malfunctioning module coul d be bypassed and, combined with reduced generation, total flue gas generated could be ro uted through the backup module and the standard

could still be met.

20 44 F.R. 33580, 33600.

21 44 F.R. 33580, 33600.9 generating capacity is not needed. Since inspection and maintenance of continuously running utility turbines is not economically unreasonable, the NOx

emission limit for these turbines has not been rescinded.

47 F.R. 3767, 3768 (Jan. 27, 1982).

IV. Types of Measures that May Be Included in the BSER

A. Measures undertaken by third parties

Some commenters state that ev en if the BSER may be ba sed on measures within the control of a source’s owner or opera tor, the BSER cannot be based on any measures undertaken by a third party. This argument is conclusory and has no basis in the provisions of Sections 111(a)(1) or (d).

Section 111 standards have long embraced the no tion that source owners or operators can rely on measures undertaken by a third party. Sp ecifically, physical co al cleaning—sometimes referred to as coal washing—is a recognized tech nique for reducing sulfur emissions from coalfired power plants. However, co al cleaning technologies are ofte n employed off-site and may be owned and operated by entities other than the owners or operator of the coal-fired EGU. 22
Nevertheless, when EPA first promulgate d performance standards to control SO 2 emissions from certain fossil fuel fired power plants, EPA relied in part on fuel cleaning as a control technique. 23

In the 1977 CAA Amendments, Congress was cl ear that section 111 standards may be based on measures that may be ta ken off-site or may involve a th ird-party entity. For example, Congress added the words “precombustion clean ing or treatment of fuels” to section 111(a)(7)(B) to “insure that in upgrading the stan dards and in defining the ‘best technological system of continuous emission reduction’, th e Administrator would not be limited to consideration of stack gas cleani ng or clean combustion processes.” 24 This addition was

intended to indicate that an asse ssment of the “best technological system of continuous emission reduction” for fossil fuel-fired power plants woul d include off-site or th ird-party pre-combustion techniques for reducing emissions at the source (“ e.g. , various coal-cleaning technologies such as solvent refining, oil desulfurization at the refinery ”)—techniques that had been authorized under

the 1970 CAA Amendments. 25 Congress also added a perc ent reduction requirement and authorized EPA to give “credit for minemouth and other precombustion fuel treatment processes

22 See, e.g. , U.S. EPA, Summary of Regulatory Analysis for New Source Performance Standards:

Industrial-Commercial-Institutional Steam Genera ting Units of Greater than 100 Million Btu/hr Heat Input , EPA-450/3-86-005, p. 4-4 (June 1986).

23 See U.S. EPA, Office of Air Programs, Background Information for Proposed New-Source Performance Standards: Steam Generators, Incinera tors, Portland Cement Plants, Nitric Acid Plants, Sulfuric Acid Plants , p. 7 (Aug. 1971).

24 Sen. Conf. R. No. 94-1742, at 88 (Sept. 30, 1976).

25 H.R. Rep. No. 95-294, at 188 (May 12, 1977) (emphasis added).10 whether or not undertaken by the source itself .” 26 Thus, even under the more prescriptive regime of the 1977 CAA Amendments (which adopted the term “best technological system of

continuous emission reduction” as the basis for standards of pe rformance, instead of “best system of emission reduction”), a standard of performance reflecting the best technological system implementable by an affected source coul d be based, in part, on off-site technologies operated by third-parties.

Nothing in the 1990 CAA Amendments suggests that Congress intended to narrow the scope of measures that may be considered when identifying the BSER. In fact, the 1990 CAA Amendments restored the broader scope of section 111(a)(1) by rem oving the conditions on EPA’s evaluation of the best “system” under Section 111 ( i.e. , the terms “technological” and “continuous”). Thus, we believe it is reasonable to consider measures th at an owner or operator of an affected source may rely on, including those undertaken by a third-party entity, as within the scope of the BSER for purposes of sections 111(a)(1) and (d). 27

B. Section 111(h)

Some commenters rely on Secti on 111(h) to argue for a cont extual constraint on defining a standard of performance for purposes of s ection 111(d). We respond to these comments in section V.B.3. of the preamble, and add additional information here.

Section 111(h)(1) states that –

if in the judgment of the Administrator, it is not feasible to prescribe or enforce a standard of performance, [she] may inst ead promulgate a design, equipment, work practice, or operational standa rd, or combination thereof, which reflects the best technological system of continuous emission reduction which (taking into consideration the cost of achieving such emission reduction, and any non-air quality health and environmental im pact and energy requirements) the

Administrator determines has b een adequately demonstrated.

Section 111(h)(2) provides that it is “not feasib le to prescribe or en force a standard of performance” when the Administrator determines that (A) a pollutant or pollutants cannot be emitted through a conveyance designed and constructe d to emit or capture such pollutant, or that

26 Sen. Muskie, Sen. Consideration of H.R. Conf. Rep. No. 95-564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353 (emphasis added). EPA has in terpreted this to mean that “[a]n owner or operator of an affected facility who elects to use fuel pretreat ment credits is responsible for insuring that the EPA Method 19 proce dures are followed in determining SO 2 removal credit for pretreatment equipment.” New Stationary Sources Performan ce Standards; Electric Utility Steam Generating Units , 44 Fed. Reg. 33580, 33611 (June 11, 1979).

27 Our interpretation is limited to only those third-party measures that are within the control of an affected source’s owner or operator. This includes measures that an affected source’s owner or operator can arrange for ( e.g. , contractually) but does not include state implemented measures, such as building codes. As is demonstrated be low, each of the building blocks is within an

owner or operat or’s control.11 any requirement for, or use of, such a conveyance would be inconsistent with any Federal, State, or local law, or (B) th e application of measurement methodology to a particular class of sources is not practicable due to tec hnological or economic limitations.

Commenters infer that these provisions limit EP A’s interpretation of the BSER to the use of a pollution control conveyan ce at the source. This inference is unfounded and conveys a misunderstanding of Section 111(h).

As discussed in section V.B. of the preamble, section 111(h) concerns the relatively rare situation in which an emissions standard, which entails a numerical limit on emissions, is not appropriate because emissions cannot be measured, due either to the nature of the pollutant ( i.e.

, the pollutant is not emitted through a conveyanc e) or the nature of the source category ( i.e. , the source category is not able to conduct measurem ents). In such cases, the Administrator is authorized to require sources to implement speci fic actions to control pollution, in the form of design, equipment, work practice, or operationa l standards. When an emissions standard is appropriate, including in the presen t rule, section 111(h) is silent as to what types of measures— whether or not limited to a source’s own design or operations—may considered as a system of

emission reduction.

Moreover, it is far from clear that even s ection 111(h) draws a lin e between on-site and off-site measures. In particular, section 111(h) authorizes the Administrator to adopt a “work practice ... standard” (section 111(h)(1)) or “alte rnative means of emission limitation” (section 111(h)(3)), which, by their terms, could include on-site or off-s ite activities. In fact, the

distinction between on-site and off-site measures is nowhere to be found in section 111. Section 111(h) merely provides that, under circumstances in which a source’s air pollutant cannot be measured, in light of the fact that it is impossible to set a numerical limit on the source’s emissions, the Administrator may promulgate other t ypes of controls. Nevert heless, to the extent that section 111(h) standards are limited to on-site actions this is further evidence that Congress

knew how to draw a line between on-site and o ff-site measures under section 111(a)(1), which indicates that by not .

This interpretation of section 111(h) is c onfirmed by its legislative history. Section 111(h) was added in the Conference Committee to re flect similar changes to section 112(e) as part of the 1977 CAA Amendments . As with section 111(h), C ongress added section 112(e) to allow the promulgation of “a design, equipment, work practice, or operational standard, or combination thereof, which in [the Administrato r’s] judgment is adequate to protect the public health from such pollutant or polluta nts with an ample margin of safety.” 28 Congress endorsed this addition because “[]ection 112 of the existing law [had] been interpreted by some courts as only allowing the use of nu merical emission standards.” 29 As a result, Congress intended to “fully authorize . . . EPA regulations governing asbestos,” which had been “demonstrated as requiring other than a direct numerical emission limitation.” 30 In fact, Congress observed that

28 1977 CAA Amendments, at § 110, 91 Stat. at 703.

29 Sen. Rep. No. 95-127, at 44 (May 10, 1977).

30 Sen. Rep. No. 95-127, at 44 (May 10, 1977).12 “[w]ork practice and other design ch aracteristics” appeared to be “the only means available for controlling such pollutants.” 31 Accordingly, sections 111(h) and 112(e) draw a distinction between quantitative levels of c ontrol (as reflected by, for example, a standard of performance) and qualitative levels associated with work practice or design standards. 32 Nothing in the legislative history suggests that Congress in tended for section 111( h) to constrain our interpretation of section 111(a)(1).

For these reasons, we find nothing in the pl ain language of section 111(h) or in its legislative history to support the inference commenters seek to draw . In any case, as we note in the preamble, section 111(h) only relates to standards of performance imposed by the Administrator ( i.e. , under section 111(b)) a nd should have no bearing on our interpretation for purposes of section 111(d).

V. AEP v. Connecticut

This section provides additional information based on the Supreme Court’s 2011 decision

in American Electric Power v. Connecticut , 131 S. Ct. 2527 (2011) (“ AEP ”) that is relevant to the EPA’s interpretation of sec tion 111(d)(1) and (a)(1) in se ction V.B.3. of the preamble.

A. The AEP decision

In interpreting the scope of the Agency’s section 111(d) authority, the EPA was also guided by case law, including the Supreme Court’s 2011 decision in American Electric Power v.

Connecticut , 131 S. Ct. 2527 (2011) (“ AEP ”). EPA has relied on and cited AEP , along with

Massachusetts v. EPA

, for the proposition that it has the au thority, and the re sponsibility, to regulate GHGs from the power sector under CAA section 111. See CPP Proposal Preamble, 79 Fed. Reg. at 34853. Moreover, the Court in AEP clearly understood, and expected, that EPA possessed sufficient authority under section 111 to achieve meani ngful and significant reductions

of GHG emissions.

In AEP , plaintiffs brought a federal common law claim of nuisance ag ainst five of the largest GHG emitters in the power sector. The Court held that the CAA displaced federal

common law in this area. The Court articulated the test as being whether a federal statute “speaks directly to the que stion at issue.” Id. at 2537 (quoting Mobil Oil Corp. v. Higginbotham , 436 U.S. 618, 625 (1978)). Applying this test, the Court stated, “we th ink it ... plain that the [CAA] ‘speaks directly’ to emissions of carbon dioxide from the defendants’ plants.” Id. After walking through the framework of section 111, the Court concluded, “The [CAA] itself thus provides a

means to seek limits on emissions of carbon dioxide from domestic power plants—the same relief the plaintiffs seek by invoki ng federal common law. We see no room for a parallel track.”

Id. at 2538 (emphasis added).

31 Sen. Rep. No. 95-127, at 44 (May 10, 1977).

32 See, e.g.

, Adamo Wrecking Co. v. U.S. , 434 U.S. 275, 286 (1978) (rec ognizing this distinction

under section 112 “now endor sed by Congress”).13 The “relief” plaintiffs sought were caps on existing power plant emissions that would “abate their contribution to global warming.” See Complaint, Conn. et al. v. AEP et al. , No. 04- civ-5669, at para. 1 (S.D.N.Y. filed July 21, 2004); id. para. 156 (“Defendants could generate the same amount of electricity while emitting sign ificantly less carbon dioxide by employing readily available processes and technologies.”); cf. S. Ct. Oral Arg. Tr., at 23, 40.

In rejecting the plaintiffs’ argument that displacement cannot occur until EPA has actually regulated GHGs, the Court went on to analy ze in greater detail th e regulatory scheme for GHG reduction that Congress, in its “consid ered judgment,” 131 S.Ct. at 2538, adopted in the CAA. “The critical point is that Congr ess delegated to EPA the decision whether and how to regulate carbon-dioxide emissions from power plants ... .” Id. (emphasis added). While noting that EPA’s judgment would ultimately be subjec t to judicial review, the Court found a host of ways in which the delegation of power from Cong ress, and the expertise of the EPA, make it the primary, and the most appropriate, decision ma ker for reductions of GHGs, noting that the Administrator must exercise her judgment in de termining which sources “cause, or contribute significantly to, air pollution.” Id. at 2539. The Court stated:

The appropriate amount of regulation in any particular greenhouse gas-producing sector cannot be prescribed in a vacuum; as with other questions of national or international policy, informed assessmen t of competing interests is required. Along with the environmental benefit poten tially achievable, our Nation’s energy needs and the possibility of economic disruption must weigh in the balance. The

CAA entrusts such complex balancing to EPA in the first instance, in combination with state regulators.

Id. (emphases added).

The Court characterized EPA as the expert ad ministrative agency uniquely suited to the complex task of regulating GHGs. Id. at 2539 (“It is altogether f itting that Congress designated an expert agency, here, EPA, as best suited to serve as primary regulator of [GHG] emissions.”). Such regulation would depend on “extensive cooper ation between federal and state authorities,”

id. , and further, the Agency would be in a positi on (unlike a court), to “commission scientific studies or convene groups of expe rts for advice,” “seek the counsel of regulators in the States where defendants[’ power plants] are located, as well as consider and incorporate public input via the rulemaking process. Id. at 2540.

Further, EPA could be expected to, in the words of the Court, “apportion[] responsibility for emissions reductions” among sources, id . at 2539 (citing 111(b)(2 ) and (d)). And the Court reasoned that it was EPA, rather than the courts, who would be in the best position to “determine, in the first instance, what amount of carbon-di oxide emissions is unreasonable ... and then decide what level of reduction is prac tical, feasible and economically viable.” Id. at 2540.

These statements from AEP suggest, first, that as an e ssential component of its federal common law displacement analysis, the Court as sumed that Congress had delegated sufficient authority to EPA, and that EPA possessed the nece ssary scientific, policy a nd regulatory tools, to address the global problem of carbon pollution in a robust and comprehensive manner; and,14 second, that it is appropriate for the EPA to c onsider the magnitude of the climate change problem, and the U.S. power sector’s unique contri bution to that problem, in determining BSER. Moreover, when EPA decides what level of reduction is reasonable, the Court accords wide discretion and speaks only of pr acticality, feasibility, and economi c viability. Although the Court

in AEP was not presented with direct review of the EPA’s action, it is noteworthy that there is no

mention from the Court of “insid e-the-fenceline” or similar cons traints on how the BSER can be

defined that have been insist ed upon in some public comments.

B. Industry Representations regarding Section 111 in AEP

This understanding of AEP is supported by the electric pow er industry’s own views, as expressed in that case. These were provi ded in briefs to the Supreme Court in AEP The EPA recognizes that the electric util ity sector is large and comple x, and does not necessarily speak with one voice. Even so, although many of thes e key representatives of the sector have questioned the scope of the agency’s legal aut hority under section 111(d), the information they provided to the U.S. Supreme Court regarding their views that the CAA gives the EPA broad authority to regulate carbon pollution from pow er plant and their views on their capacity to reduce emissions, and the measures they identified as available to do so – such as increasing renewable energy -- are all relevant to, and overall supportive of, the reasonableness of the agency’s decisions in defining the BSER, and other aspects of Emission Guidelines.

The electric utility industry its elf appeared to adopt a relati vely expansive view of the EPA’s authority under section 111(d) to addr ess carbon pollution from power plants. In particular, in AEP , the power company Petitioners 33 and supporting electric power sector Amici 34
argued, inter alia , that EPA’s authority under the Clean Ai r Act, and in particular section 111, was sufficiently broad to displace any federal co mmon law action against the power sector based

on GHG emissions.

Industry Petitioners stated to the Court, fo r example, that “Congress has addressed the issue of greenhouse gas emissions,” Pet’rs’ Br. 41; “the Clean Air Act delegates regulatory authority over carbon dioxi de emissions to EPA,” id. at 46. Amici from the power sector further emphasized that, “Congress has ‘spoken directly to the question’ of GHG regulation,” “and has

33 American Electric Power Co., American Electr ic Power Service Corp., Cinergy Corp (merged with Duke Energy), Southern Company, and Xcel Energy Inc.. The federal government filed a separate brief on behalf of th e Tennessee Valley Authority.

34 Edison Electric Institute (EEI), American Public Power Association (APPA), and National Rural Electric Cooperative Asso ciation (NRECA). According to the Statement of Interest, Amicus Br. at 1-2, EEI is the national association of U.S. shareholder-owne d electric utilities and affiliates and industry associates, whose members represent three-quarters of all electricity produced by U.S. energy companies and serve 70 percent of all retain customers in the U.S. APPA represents the over-2000 non-profit, publicl y owned electric utilitie s, serving 45 million Americans. NRECA represents the 930 non-profit customer-owned rural electric cooperatives, serving 42 million end users. Together, their memb er companies serve 94 percent of the electric

customers in the U.S.15 already ‘addressed the problem’ pl aintiffs now attempt to bri ng before the federal courts.” 35
Amicus Br. 26 (quoting Milwaukee v. Illinois , 451 U.S. 304, 315 (1972)).

The Petitioners adopted a broad view of fede ral authority under the Clean Air Act. “‘To say this regulatory and permitting regime is comprehensive would be an understatement.’” Pet’rs’ Br. 42 (quoting North Carolina ex rel. Cooper v. TVA , 615 F.3d 291, 298 (4th Cir. 2010)). “The Clean Air Act, like the Clean Water Ac t, is a ‘comprehensive’ regulatory scheme to address environmental pollution. Id. at 41. “Nothing in the [CAA] or legislative history suggests that Congress intended to leave ‘room for courts to attempt to improve on that program with federal common law.’” Pet’rs’ Br. 41, 42 (quoting Milwaukee II , 451 U.S. at 319). Indeed, “Throughout the debates and reports of Congress, [t he CAA’s] sponsors repeatedly characterized the Act as ‘comprehensive,’ and commented on its expansive reach.” Id. at 42. “[T]he Clean Air Act vests EPA with broad authority not only to pr omulgate national standa rds for pollutants, but also to enforce those standards directly ....” Id. at 43. “The Act is ‘sweeping’ and ‘capacious.’”

Id. at 41 (quoting Massachusetts v. EPA , 549 U.S. 497, 528, 532 (2007)). 36

These parties recognized, furthe r, that “Congress has given EP A substantial authority to regulate within the context of a comprehensive legisl ative scheme and has left it to the Agency to oversee matters of implementation and enforcement.” Amicus Br. 27; cf. id. at 26 (“Through the Clean Air Act, Congress chose to regulate GHGs and to delegate the details to EPA .”) (emphasis added). See also Amicus Br. 7; id. at 28-29 (“It is clear that EPA has the power to regulate GHGs, and it is doing so.”).

The Amicus Brief on behalf of EEI and othe rs, in particular, gives examples of the complexity of the climate problem, and also explains why the “ existing regulatory scheme ,” is sufficient and should not be “undermined,” Amic us Br. 14 (emphasis added). This Brief also notes, “EPA’s forthcoming NSPS regulations cali brate GHG performance sta ndards to ‘the best demonstrated emissions control technology’ for the particular industry segment in order to avoid ‘unreasonable economic disruption.” Id. at 17-18. This initiative “is designed to produce hard emissions standards for the very power plants plai ntiffs want the federal courts to regulate.” Id.

at 9.

35 Although this memo focuses on th e Petitioners’ brief and the main amicus brief of the power sector, other amici on behalf of i ndustry also put forward this position. See, e.g., Amicus Brief of Consumer Energy Alliance et al. (Laurence H. Tribe, Counsel of Record), at 3 (“[J]udicial action is foreclosed by the fact that Congress has al ready authorized the Environmental Protection Agency (EPA) to regulate those emissions.”), at 20 (“EPA possesses ‘significant latitude as to the manner, timing, content, and coordi nation of its regula tions ...’” (quoting Mass. v. EPA, 549 U.S. at 533)), and at 35 (“By textually committing [treaty negotiation] power to the President, Article II [of the U.S. Constitution] precludes judicial authority to establish de facto regulatory standards that might disrupt a treaty-based or ot her internationally nego tiated response to the inescapably global issue of climate change.”).

36 Justice Scalia noted in UARG that, as used in Massachusetts

, those terms refer to the CAA’s definition of air pollutant rather than its “co mmand to regulate.” Slip Op. at 14. However,

Petitioners make no such distinction to the Court in AEP

.16 The Amicus Brief of the power sector amic i endorses the view that different, cleaner sources of generation are necessary to solve the GHG problem:

[R]ational GHG-emissions cuts—especially the sorts of sharp reductions that some contemplate in an effort to mitigate global climate change—cannot be instituted overnight. They will require the adoption of an array of advanced noor low-carbon technologies, including incr eased use of wind, solar, incremental hydroelectric, and nuclear power.

Id. at 16 (emphasis added). The Amicus Brief goes on to endorse the conclusion of an industry study that a scenario in which “the United States comprehensiv ely encourages new technologies as part of its regulatory scheme” is necessary to avoid a spike in electricity prices, radical demand curtailment, or a “dash to [natural] gas” th at would lead to “too high an emissions rate to satisfy ambitious long-term GHG reduction goals.” Id. at 19-20. This discussion takes place within an argument to the Supr eme Court that such a national, comprehensive regulatory scheme already exists and should not be “undermined.” Id. at 14.

VI. Industry Statements made to the EPA Pr ior to Proposal of the Clean Power Plan

Representatives of the electric power industry also provided comments related to section 111(d) in the course of prior Agency rulema kings, such as the Endangerment Finding and the 2008 GHG ANPR, as well as the pre-proposal outreach sessions for the Clean Power Plan. While we recognize that there is a diversity of viewpoints in thes e comments, and many questioned either the appropriateness or lawfulness of regulation under sec tion 111(d), two categories of comments are particularly relevant here: : 1) several of these st atements appear to endorse the view that the BSER could encompass the measur es in building block 2 (dispatch shifts from coal-fired EGUs to NGCC units) and building bloc k 3 (renewable energy) , and (2) virtually all industry commenters urged the ag ency to allow for these meas ures as effective compliance options. This second category of comments is rele vant given the breadth of its support across the sector. It indicates that because the industry considers these measures to be economical and effective at achieving emission reduc tions for compliance, these measures merit consideration as part of the “best system of emission reduction ... adequately demonstrated” itself. 37

The electric utility industry’s views on the role of the EPA under section 111, and how it should approach regulation of GHGs from the power sector, were presented during the Agency’s early stakeholder engagement efforts on the sect ion 111(d) proposal. In a “Summary of Listening Session 1: Electric Power Industry Representative s,” dated February 4, 2011, we noted industry representatives’ “general advice” to the agency:

37 See, e.g., Basin Electric, Draft 111(d) Design Commen ts (working draft), at 27 (Dec. 4, 2013)(“[E]ven the many commenters who say the Administrator’s authority is limited solely to withinthe-fenceline CO2 emission reductions ... are also often saying that States should also be

allowed to consider outside-the-fenceline reductions to meet inside-the-fenceline emission reduction requirements.”).17  “Think of the industry as an interconnected grid and not plant by plant .” Id. at 1 (emphasis in original).

 “Rate-based approach is pref erred (i.e., lbs CO2/ MWh).” Id.

 “Allow for technological and fuel flexibility .” Id. (emphasis in original).

 “Allow for flexibility for states when demonstrating equivalency.” Id.

 For existing sources, “determine best pract ices nationwide using existing technologies and set the standard based on those technologi es,” “give states flexibility,” “allow for a fleet-wide approach to meet performance standards; allow for emissions averaging and the use of offsets across companies.”

 “Approaches to avoid: limitations on the technol ogies that can be used to comply with the standard”; “plant by plant a pproach to existing units.” Id.

Finally, the industry’s representa tives noted that the timeline fo r action should balance two core

considerations: “must allow for utilities to main tain reliability (slower timeline); must move quickly to address global warming effects.” Id. at 2.

The American Public Power Association (APPA), in comments on the Endangerment Finding, while questioning the appropriateness of NSPS regulation of GHGs, recognized the efficacy of measures not taken on site, for in stance, stating, “APPA st rongly believes that sequencing or other practical a pproaches might allow the use of energy efficiency measures involving the ultimate utility customer to be cons idered as a viable emissions reductions options for fossil generation electric utilities ...” APA Comments on Endangerment Finding, at 23-24.

The Edison Electric Institute (EEI), in its comments on the Endangerment Finding, also questioned the use of section 111, but urged, “if EPA were to decide, ne vertheless, to move forward with its existing CAA title I authorities to regulate GHG, we encourage the Agency to utilize market-based programs (i.e., cap-and-trade) instead of traditional command-and-control approaches.” EEI, Comments on Endangerment Finding, at 7 n.1; see also Appendix I to EEI

ANPR comments.

The Utility Air Regulatory Group (UARG), in its comments on the Endangerment Finding, encouraged the agency to use flexible approaches under secti on 111(d) that would go beyond a particular unit. “Facility-wide, plant-wi de, and company-wide standards would provide valuable flexibility but also complexity in tr ying to integrate such standards into potential economy-wide programs like trading. UARG, Comments on Endangerment Finding, at 108-09 (emphases added). In its comments on the Adva nced Notice of Proposed Rulemaking (ANPR) for the Endangerment Finding, UARG stated, “The development of new technologies will be key to the ability to reduce GHG emissions from all sectors of the economy. ... [T]here may be existing technologies that can be employed in the short term as identified in the ANPR, such as improved plant efficiencies, fuel switching, nuc lear power, and renewable power ....” UARG, ANPR Comments, at 6 (emphasis added).

In December 2013, in pre-proposal comments, the APPA identified, as one of the principles to guide the agency’s decision ma king under section 111, “Rec ognizes the substantial emission reductions from the power sector that ha ve already occurred and will continue to occur as a result of unit retirements, fuel switching, en ergy efficiency programs, and increasing use of18 renewable and other non-emitting or lower emitting energy sources, both voluntarily and pursuant to state mandates, among other factors.” 38

Some utility commenters explicitly urged the agency to use a system-wide approach to standard setting. For example, cons ensus principles the Municipal El ectric Utilities of Wisconsin (MEUW) shared with the agency included:

Systemwide Compliance Basis – Standards should not apply to individual plants because GHG reduction projects at individual pl ants are extremely limited. Allow entities to average their emissions over their entire fl eet or provide for an even broader base for compliance. Allow for Total System Emission Reducing Actions – Affected entities should be able to comply with the standards of performance utiliz ing any activities that reduce emissions. These activities include supply- a nd demand-side energy efficiency measures, and shifting generation from fossil resources to renewables and other emission-free or lower emitting resources.

Letter from MEUW to Gina McCarthy and George Czerniak, at 2 (Dec. 20, 2013).

Individual companies and utilities amplified these points in their pre-proposal comments, frequently highlighting the role of fuel-switching to natural gas, plant retirements, and their growing RE and EE programs, which they beli eved should be credited for compliance in achieving emission reductions, even while disputi ng the agency’s legal authority. For example,

“ Early action ‘credit’ should specifically include prior compliance actions, including retirement of
coal units, system or end-user efficiency improvem ents, additions of renewable generation, development of carbon offset projects , etc., as well as any compliance activities that can be taken inside the unit’s boundaries.” Am. Muni. Power & Ohio Muni. Elec. Ass’n, Ltr. to Gina McCarthy, at 7 (Dec. 2013) (emphasis added). In a joint letter, utilities in the state of Missouri made clear their opposition to the EPA’s legal authority to directly impose or enforce the BSER, but went on to request that the agency recognize a broad swath of measures as compliance options, including: averaging/bubbling that could include new, lower-emitting units (i.e., across a fleet, across units in a particular state or region, among sources in the same source category or in different subcategories, among existing and closed facilities, etc.); trading; purchasing energy efficiency credits generated by the increased deployment of end-use efficiency programs; shifting dispatch to lower-emitting generation; and adding new lower-emissions fossil fuels and renewable energy. Letter from Missouri Utilities to Mark Smith, Branch Chief, Air Permitting and Compliance Branch, U.S. EPA, Region 7, at 4 (Nov. 27, 2013).

These comments are similar in nature to many others received from various members of the

power sector. See, e.g., Salt River Project (SRP), State of Arizona, Responses to EPA Stakeholder Questions , at 11 (Dec. 17, 2013) (“Under [SRP’s recommended phased-implementation] approach [to section 111(d)], stat es could establish a series of ‘increments’ at a rate- or massbased level based on measures that are more likely to be achievable in the shorter term and in the longer term. For example: Short-term reductions are based on cost-effectiv e “low-hanging-fruit”

38 APPA, Principles on EPA Rulemakings to Esta blish Standards of Performance for Existing Electric Generating Units under Section 111(d) of the Clean Air Act (December 2013).19 (i.e., basic plant efficiency upgrades, incorporation of existing renewables and demand-side efficiency programs )....”) (emphasis added). At the same time these “beyond-the-fenceline” measures were touted as cost-effective complia nce options for achieving substantial emission reductions, utility commenters also emphasized the relatively small emissions reductions plant efficiency upgrade could achieve on their own. See, e.g., See Letter from Kansas Utilities to Administrator Gina McCarthy, at 5 (May 20, 2014) (“Because EGUs inherently operate very close to their design efficiencies, we believe unit specific efficiency improvements will have limited impact on overall CO2 emission reductions. ”). Rather, individual utilities highlighted fuel-switching, plant retirements, RE, and demand-s ide energy efficiency measures as actions they were taking to substantia lly reduce their carbon emissions. See, e.g., id. at 4-5 (“Kansas is uniquely positioned to take advantage of a signi ficant amount of renewable energy, especially wind electricity generation.”); Letter from Iowa Utilities Board to Gina McCarthy and Rebecca Weber, at 3 (Dec. 6, 2013) (“Iowa has significa ntly increased the amount of wind generation

installed in the state and has reduced the CO2 intensity of it s electric generation between 2000 and 2012.”); Letter from CPS Energy to EPA, at 1 (Oct . 23, 2013) (“As part of a decarbonization strategy, CPS Energy has announced it will indefinite ly suspend operation of two baseload coal units ... at the end of 2018. [Combined with] sola r, wind, IGCC, coal gasification with carbon capture and energy efficiency will reduce overa ll CO2 emissions by about 45% in 2020 from baseline year 2011.”); Letter from First En ergy to Joseph Goffman, at 1 (Jan. 21, 2014) (“Substantial CO2 reductions have already been realized over the past decade due to ... increasing renewable generation, low natural gas prices, energy efficiency programs, and retirements of older, less-efficient plants ...”)

Taken collectively, the body of information pr ovided by the power sector to the agency strongly supports the technical and policy choices the EPA made in defining the BSER. The industry urged the agency to consider the sector as inter-connected rather than comprised of discrete power plants. It highlighted the efficacy of fuel-switching to natural gas, and increasing RE, among other things, to reduce emissions. Thes e measures were sufficiently measurable and enforceable that the industry sought recogniti on for them as compliance options. The industry recognized the limited potential of at-the-plant efficiency upgrades to reduce emissions. And it requested maximum flexibility for states and companies through the use of trading, a broad scope of creditable compliance actions, and ex tended compliance periods. While the agency must reject the legal theory th at it can only define the BSER ba sed solely on measures that are integrated into the design a nd operations of the facility, a ll of these tec hnical and policy suggestions from the industry are found reflected in the agency’s fina l rule, and support the

reasonableness of the EPA’s choices.

VII. Division of Resp onsibilities under 111(d)

This section briefly summarizes the key dete rminations in this rulemaking under section 111(d), including the EPA’s determination of the be st system of emission reduction (BSER), the

identification of the source subc ategory-specific emission performance rates, and the state-level

rate-based and mass-based CO 2 goals; the states’ establishment of the standards of performance and submission of state plans; and the EPA’s promulgation of standards of performance in a federal plan, under certain circumstances. In su mmarizing these determinations, this section highlights the respective roles of the EPA and the States.20 A. The Determination of the BSER

For present purposes, the initia l regulatory determination unde r CAA section 111(d)(1) is the BSER. As we explain in section V.B.1 of th e preamble, the statute clearly gives the EPA the authority to determine the BSER. Section 111(a )(1) defines “standard of performance” as a

standard for emissions that “r eflects the degree of emission limitation achievable through the application of the best syst em of emission reduction ... the Administrator determines has been adequately demonstrated” (emphasis added). Th us, we disagree with commenters who contend that the states, and not EPA, have that author ity. The Administrator, under both 111(b) and (d), determines the BSER and the degree of emissi on limitation achievable th rough the application of the BSER, pursuant to section 111(a)(1). 39 As discussed below, stat es establish standards of performance under section 111(d)(1), which is in contrast to th e Administrator’s authority to establish standards of performance under se ction 111(b). But secti on 111(d) does not alter section 111(a)(1)’s delegation of th e determination of the BSER to the Administrator of the EPA.

The language of section 111(a)(1) is also clear that after determining the BSER, the EPA is authorized under the CAA and the implementi ng regulations as an integral component to setting emission guidelines, to determine the re sulting emission limitation from the BSER. Thus, in general, under section 111(a )(1), following the dete rmination of the BSER, the EPA has the authority to identify the amount of emission limit ation that reflects the ap plication of the BSER

to the affected sources.

Under the CAA, an “emission limitation” is amen able to expression as a quantity, rate, or concentration of emissions of air pollutants. In the Clean Power Plan, the emission limitation is expressed as the source subcategory-specific em ission performance rates for the affected EGUs. Source subcategories in this context refers to fossil steam units and stationary combustion

39 The legislative history confirms that the Administrator determines the BSER. Congress revised section 111(d)(1) in th e 1977 CAA Amendments to provi de that state plans must establish “standards of performance” (in lieu of emission standards, under the 1970 CAA Amendments). According to the House Committee Report:

This section is also intended to clarif y the basis for standard-setting for existing sources under section 111(d) of the Act. Under the committee bill, the standards in the section 111(d) State pl an would be based on the best available means (not necessarily technological) for categories of existing sources to reduce emissions. The Administrator would establish guidelines as to what the best system for each such category of existing sources is. However, the State would be responsible for determining the applicability of such guidelines to any part icular source or sources.

H. Rep. 95-294 at 195, reprinted in 1977 CAAA Legislative History (“1977 LH”) at 2662 (emphasis added). The referen ce to “guidelines” should be ta ken to be a reference to the emission guidelines that the EPA described in the 1975 framework regulations under section 111(d).21 turbines. Thus the emission limitation is expre ssed as two rates in pounds of CO2 per megawatthour of electrical generation output, one rate for st eam electric units and on e rate for stationary combustion turbines. (The CO 2 emission performance rates may also be referred to in the emission guidelines as the emission performance le vel or levels. As discussed in the following section, the emission performance rates are to be distinguished both from the state goals and from standards of performance. 40 ) As discussed below, the agency is providing flexibility to

allow states to demonstrate an equivalent level of emission performance through several design options for state plans.

These emission performance rates reflect the required emission performance level for all

the affected sources. Because the EPA has determined these rates to be achievable, the States in submitting approvable plans must demonstrate that th ey will be met. This is consistent with the agency’s longstanding view of its role in dete rmining the BSER. Some “substantive criterion” must be available to govern the Administrator’s review of state plans. 40 FR 53340, 53342 (Nov. 17, 1975). While the BSER as determined in the emission guidelines “will not have the purpose

or effect of national emission st andards” directly applicable to sources, the agency has long believed that “it is desirable (if not legally requi red) that the criteria [for approvability of state plans] be made known in advance to the Stat es, to industry, and to the general public.” Id. at
53343. See also 40 CFR 60.22(b)(3) (emissions guideline s will contain “information on the degree of emission reduction which is achievable with each system”); id. 60.25(a) (requiring states to submit “correlated” data “presented in such a manner as to show the relationship

between measured or estimated emissions and the amounts of such emissions allowable under applicable emission standards”).

In this rulemaking, after the EPA determined the BSER as the building blocks, the EPA then applied the building blocks to the source su bcategories on a region-by-region basis. This allows us to identify the two source subcateg ory-specific emission performance rates in the region where application of the building blocks produced the least stringent rates. The EPA selected those least stringent rates as the na tionally uniform two source subcategory-specific emission performance rates in order to ensure achievability and enhance flexibility nationwide.

We discuss in more detail the legal authority to take this a pproach (applying the BSER on a regionwide basis, and determining nationally un iform emission levels) in section V.A.3.e-f. 41
These source subcategory-specific emission perfor mance rates are, in essence, the arithmetic expression of the BSER as appl ied to the two source subcategor ies on the basis of the least stringent region, which are then applied to the ot her regions. While they constitute the “degree of emission limitation achievable,” and inform the ag ency’s review of stat e plans for approvability, they are not binding in -and-of-themselves.

40 “Emission standard” is the term found in the implementing regulations for section 111(d), and for our purposes, is synonymous with “standards of performance.”

41 We note that this regionalized approach diffe rs from the proposal, where we applied building block 2 on a state-by-state basis. This had the unintended consequence of creating an unacceptable degree of inequity between sources in different states. In response to the many adverse comments we received on these state-by-stat e inequities, we modified our approach from the proposal and agree that a regionwi de approach is more appropriate.22 B. The Calculation of the State Goals

Once the EPA determined the BSER and the degree of emission limitation achievable, the agency translated the source subcategory- specific emission performance rates into the equivalent state-by-state, state- level rate-based and mass-based CO 2 goals. As we explain in Section VII of the preamble, thes e state goals inform the agency ’s review of state plans for approvability. However, these state goals are not binding or enforceable in and of themselves. Rather, they are the application of the source sub category-specific emission performance rates to the mix of affected EGUs on a state-by-state basis. Thus, they are another form of the arithmetic expression of the BSER, in this case as applied to the mix of affected EGUs in each state.

Just because the goals are not binding in the sense of being enforceable against the states or sources, does not mean a state is free to ignore them. To do so w ould be to invite the EPA’s disapproval of that state’s plan. The goa ls are a type of acc ounting device, that is, they are part of the methodology for assuri ng that if states adopt standards of performance that differ from the source subcat egory specific emission performance rates,

the states will be able to a ssure that they are obtaining the same emission performance level as the application of the BSER to th eir sources would require. The ability to use accounting metrics to determine equivalent leve ls of stringency is provided for, and wholly consistent with, the framework regula tions of subpart B, which provide that an emission guideline is to contain information th at “reflects the app lication of the best system of emission reduction (considering the cost of such reduction) that has been adequately demonstrated for designated facili ties, and the time within which compliance

with emission standards of equivalent stringency can be achieved.” 40 CFR 60.22(b)(5) (emphasis added).

The state goals represent an equivalenc y to the subcategory-specific emission performance rates. They do not impose an oblig ation directly on states. The EPA agrees with commenters who say that the states, as states, ar e not the obligated parties for compliance with emission reduction requirements under section 111. The ultimate enforceable regulatory obligation under the Clean Power Plan, as under a ll section 111(d) emissi on guidelines, must fall on the affected sources themselves, here, the affected EGUs.

We disagree with commenters who consider the state goals to be binding in and of

themselves and who then assert that the EPA doe s not have the authority to set binding state goals. This is a misunderstanding of the nature of the state goals as an accounting device that aids in the review of submitted state plans for approvability. Although the goals are not binding, they will inform the agency’s substantive review of state plans for satisfact oriness. Given that the EPA has determined the degree of emission limitat ion achievable, state plans that fail to meet

these levels of emission reduction would be proposed for disapprova l through a disapproval process that would include notice and opportunity for public comment. Nonetheless, failure to submit an approvable state plan is not a sanctiona ble violation of the Clean Air Act. It simply means the agency will have the re sponsibility to develop a federal plan for the affected EGUs in

that state.23 The agency recognizes that the goals for each st ate may vary to some degree, but this is a natural and unsurprising consequence of the appl ication of the emission performance rates to each state’s unique mix of affected EGUs. The va riation in state goals has been substantially reduced in the final rule as compared to the proposal, in part to respond to the many adverse comments that this variation produced an unacc eptable degree of inequity among sources in

different states. The level of variat ion is minimized in the final rule.

We note that in the final rule, the agency is allowing the states important flexibilities with respect to meeting their goals: St ates utilizing early action progra ms to achieve reductions prior to the start of the interim period may qualify fo r matching credits or allowances from the EPA that increase the overall size of a mass budget or th e overall pool of emissi on rate credits. States may set their own “steps” in the interim period to allow for relatively greater emissions earlier and relatively lower emissions later (in effect, allowing a form of emissions borrowing), so long as the interim performance level is achieve d. Beyond limited circumstances expressly provided in the guidelines, the EPA is not authorizing states to set less st ringent standards of performance for their sources in such a way th at the overall state goal goes unmet.

Some commenters stated that this exceeds the proper scope of the EPA's authority because it sets binding, inflexible emission rate lim its in the aggregate for a ll of a state's affected EGUs. Commenters said that under the proposal, once these “goals” are finalized, states will have no authority to change th em, despite section 111(d)’s expr ess grant of authority to the states, not EPA, to establish st andards of performance and to consider factors such as the remaining useful life of sources in es tablishing standards of performance.

These comments are premised on a legal view that the statute unambiguously requires that EPA must allow states to reduce the stringe ncy of standards of performance below emissions performance levels EPA determined were achievable. The agency disagrees with these

commenters. The state must establish the standard s of performance for their sources in a manner consistent with the emission guidelines, and the st andards are ultimately subject to the agency’s substantive review of a state plan for satisfact oriness under section 111(d )(2)(A). States plans

that do not meet the level of stri ngency the agency believes is achievable for the sources in that state can be disapproved. This comports with th e agency’s longstanding view that its review of state plans under section 111(d) is substantive. The agency agrees with commenters to the extent

that the statute affords EPA the discretion to deci de in certain rules that a downward variation in emissions performance for some affected sour ces in a state under se ction 111(d) could be authorized. The implementing regulations provi de this authority at 40 CFR 60.24(f). But this does not mean that for a particular emissions guide line for a particular pollu tant from a particular category of sources, the agency cannot reasonably decide that such downward variations are

unwarranted. That is the case here , as we explain in th e section of the preamble and this Legal Memorandum concerning the remaining usef ul life provision of section 111(d)(1). 42

42 The implementing regulations make clear that the agency is not bound to permit states to set less stringent standards in all cases, particularly where the pollutants pose a risk to public health. 40 CFR 60.24(c), (f) Paragraph (f) expressly provides that speci fic emission guidelines may not

allow for its use. See id. (“Unless otherwise specified in the applicable subpart on a case-by-case basis for particular designated facilities or classes of facilities...”).24 The alternative suggested by commenters would leave the agency powerless to prevent an unbounded loosening of stringency of national ai r pollution control under section 111(d) by the states. As we describe in the preamble in se ction V., Congress intend ed that the CAA be a comprehensive vehicle for regulatin g air pollution, and enacted this provision to ensure there was no gap in the statute through which serious air pollution problems might go unaddressed. Allowing the states to have the degree of unrev iewable discretion that the commenters urge means that the states could functionally ignore na tional air pollution cont rol objectives and leave the federal government wit hout any recourse to respond. See 40 FR at 53343.

C. The Establishment of Standards of Performance and Design of State Plans

Following the promulgation of the emission guide lines, the scene shifts to the States. The States are required to submit stat e plans that take the emissions standards approach or the state measures approach, and that meet the requireme nts of the guidelines. The emission guidelines give states a wide ra nge of choices in the design of their plans. 43 They may impose the subcategorized emission performance levels on their s ources as rate-based emission standards, or they may take one of several options to achieve an equivalent result, any of which may be preferable for a particular state given its uniqu e circumstances. They could impose the single,

combined state rate on all affected EGUs in th eir state. They could use a mass-based program using the mass budget that the agency determined in the final rule represents an equivalence in performance to the sub-categorized emission rates.

The above-described set of requirements and calculations in the emission guidelines does not mean that the EPA is requiring that sources or states implement the BSER. The agency’s requirement is that state plans meet emissi on guidelines requirements for approvability, including most importantly, the achievement of the emission performance levels. The EPA is not requiring the implementation of the building blocks or any other type of specific controls. In fact, under section 111(b)(5), where the EPA imposes st andards of performance on new sources, the EPA is explicitly precluded from requiring any part icular type of emission control, including the BSER. Rather, the “degree of emission limitation” determined by the BSER sets the standard of performance, but sources remain free to determine how they will meet the standard. There is no comparable provision to 111(b)(5) for existing so urces under section 111(d) , but the notion that the BSER is not specifically required is consis tent with this statutor y construct. When we promulgate a 111(d) rule determining an add-on technology like a scrubber to be the BSER, we do not require that the sources or states implement that add-on technology; rather, we require only that the states submit plans that achieve the emission performance level of the BSER that we have determined. In some past rules, as a pr actical matter, it may be that for a given type of pollutant or source category, a pa rticular technology the EPA identifi ed as the BSER is the only available means of achieving the performance standa rd. But this is not the case for this rule.

43 The agency recognizes states’ reserved aut hority under section 116 of the CAA to implement more stringent standards on their sources. The ag ency also recognizes that states may find it advantageous to enact complementary programs, enti rely outside of the CAA, that help make the state goals even more cost-effective to achieve.25 Thus, we disagree with commenters who stated that we are improperl y requiring states to implement the building blocks, such as by orderi ng re-dispatch to natural gas-fired units, or ordering the construction of re newable energy projects. The premise of these comments is incorrect. Nowhere in the final emission guidelines ar e such actions directed or ordered to occur. Furthermore, under this rule, the EPA would not exert enforcement authority over entities other

than the affected EGUs and their owners and operators, in order to enforce the emission standards applicable to the affected EGUs set in a state plan (or federal plan if necessary). This

rule does not mandate or authorize that state renewable energy or energy efficiency programs become federally enforceable under the CAA.

As a practical matter, the states do not have to implement the BSER or require that sources implement the BSER, and sources do not have to implement the BSER to achieve the emission performance levels; even so, we recognize that some sources will, in fact, take actions that reflect or resemble the implementation of the building blocks. But as we explain in V.B, states and sources have many choices other than the building blocks. They can choose to get emissions reductions by implementing demand-side -energy efficiency (DS-EE) projects and programs; co-fire with natural gas, re-power with natural gas, or take other measures that we describe in the preamble and th at others have described.

We expect that some sources will implement measures that reflect or resemble the building blocks. These measures met the requireme nts of being the “best” system of emission reduction that is adequately demons trated, taking into ac count costs and other factors. Thus it is entirely reasonable to anticipate that they will be used in practice. But commenters are incorrect in asserting that the EPA is re quiring states and so urces to implement the building blocks or reduce generation, or that states and sources have no choice but to implement the BBs or reduce generation. As discussed above, st ates and sources have choices as to the amount or degree to which they implement the BBs and a high degr ee of flexibility as to other methods.

All of this is consistent with how EPA ha s promulgated section 111 rules in the past. Sources do not have to implement BSER, although in many cases they can be expected to do so. For this rule, we expect greater us e of alternatives to the BSER measures than in other rules, in part because DS-EE is a relatively inexpensive means of obtaining emission reductions from the

affected EGUs.

D. The Establishment of Standards of Performance in a Federal Plan

If a state does not submit a state plan or the EPA disapproves a state plan submittal, the EPA will promulgate a federal plan that will impose the standards of performance (in implementing regulations referred to as “emission standards”) on affected EGUs, and provide for their implementation and enforcement. The EPA is proposing a federal plan to demonstrate how this can be done. The federal plan will also serve as a model rule for states to adopt or tailor for use in their own state plans. Even where the EPA is directly implementing the standards of performance in a federal plan, however, the ag ency will not, and need not, attempt to order sources to implement the measures that comp rise the BSER. Rather, the agency would set

emission standards for each of the affected EGUs in the federal-plan state, provide mechanisms for their implementation and enforcement, and ot herwise leave to the owners and operators of26 the affected EGUs the decisions about what meas ures they want to take to comply with the emission standard. Though the emission standards will be federally enforceable, as under a state plan, sources may achieve them through implementation of measures in the BSER, or any other

method. The state and its officials do not necessarily need to play any role in the implementation of a federal plan. However, the agency may delega te administration of aspects of the program or may approve partial state plans for portions of the otherwise-federal program. These mechanisms and other facets of implementation will be set ou t in greater detail in the preamble and other supporting documentation to th e proposed federal plan.

In the context of a federal plan, it become s easier to see why th e question whether the EPA would have the authority to directly order the implementation of the measures in the building blocks is not only not relevant but re presents a categorical misunderstanding of the nature of the BSER in relation to the imposition of standards of performance. Commenters on the proposal asserted that the BSER cannot include building blocks 2, 3, or 4 because the EPA may include in the BSER only controls that the EPA has the authority to implement or enforce, and, the commenters continue, the EPA does not have the authority to implement or enforce these building blocks. We disagree with these comments because the authority or practical ability of the EPA to implement or enforce the BSER itself is irrelevant and based on a false premise. To illustrate this, by the same token the EPA could not enforce many logistical aspects of a control requirement such as a scrubber – for instance, th e EPA does not have the authority to order the creation of companies that manuf acture scrubbers, or order thei r construction or delivery on a

certain schedule. The EPA need not have before it at the stage of determining the BSER all of the information regarding manufactur ing, transportation of parts, orother logistical requirements to ensure that each scrubber gets constructed a nd delivered to a source. Nonetheless, the agency can determine the BSER premised on a reasonab le assumption that all of those things can actually happen.

What is relevant is that the control requirements that the EPA identifies meet the statutory considerations to qualify as the BSER, which include that the owners or operators of the affected sources be able to implement the control meas ures and achieve their emission limits through those control measures. As we discuss elsewhere, th at is the case for all of the building blocks in the final rule. Thus, the EPA can reasonably dete rmine that the federally enforceable emission

standards that would be set in a fe deral plan, just as in a state pl an, are achievable by the affected EGUs and will be met either through the measures in the building blocks or, if the affected EGUs so choose, through other measures that contribute to its compliance. The agency will provide for the implementation of the standards of performan ce via the same types of regulatory mechanisms being made available to stat es in the emission guidelines.

E. Summary of the determinations under sect ion 111(d) and respective EPA and State roles

Through the process of section 111(d), the EPA regulates air pollutants from source categories of existing sources, in this case, CO 2 from certain fossil fuel-fired EGUs. This regulation necessarily has impacts on the source category, which in th is case is a key part of the broader electric utility power s ector. But this does not mean th at the EPA is overstepping its authority. The fact that the EPA has the authorit y to determine the BSER means that the EPA has the authority to determine the degree of emi ssion limitation achievable, which in the Clean27 Power Plan is expressed as the CO 2 emission performance rates. The agency has translated these into a set of state goals that each reflect an emission performance le vel that is equivalent to the emission performance rates. The agency’s emi ssion guidelines set forth these performance levels, along with other requirements, as the mini mum requirements for states to meet in order to have an approvable state plan. If a state fa ils to submit an approvable plan, the EPA will implement a federal plan imposing emission standa rds for the affected EGUs in that state.

Contrary to the views of some commenters , the Clean Power Plan does not usurp state authority over the electric utility sector or other traditional area s of state regulation. As in many other areas of environmental law, the EPA has se t minimum federal requir ements for a class of polluting facilities, and states have the oppor tunity to design a program to meet those requirements, or go beyond them if they so choo se. In this way, the Clean Power Plan is fully consistent with the principles of cooperative fe deralism that underlie th e Clean Air Act and that are incorporated into section 111 and maintains a proper balance of roles between the federal government and the States.

VIII. Authority of the Administrator to de termine State Plans to be “Satisfactory”

Section 111(d)(2)(A) authorizes EPA to prom ulgate a federal plan for any State that “fails to submit a satisfactory plan” estab lishing standards of pe rformance under Section 111(d)(1). This also provides the standard by which EPA review s state plan submittals: such submittals must be “satisfactory.” The reas on is structural: Any other standard than “satisfactory” for EPA’s action on a plan submitt al would leave a grey area between submittals that are disapproved under the ot her standard and EPA’s federal plan authority, which is based on whether a plan is “satisfactory.” In other words, the standard triggering EPA’s federal plan authority must be identical with the standard for action on state plans.

The relevant dictionary meaning of “satis factory” is “fulfilling all demands or requirements.” The American College Dic tionary (“ACD”) 1078 (C.L. Barnhart, ed. 1970); see also Oxford English Dictionary (“OED”) (2d and 3d ed.; online version) (“To answer the requirements of (a state of th ings, a hypothesis, etc.); to ac cord with (conditions). †Also rarely of a person: To fulfil the requirements of.”). The related word “satisfy” (both originate from the Latin “satisfacere”) can mean “to fulfill the requirements or conditions of.” ACD at 1078. Thus, the natural interpretation of “satisfactory plan” is a section 111(d) plan that meets the conditions or requirements of the emission guidelines.

Furthermore, section 111(d)(2) states that EPA shall have the “same authority to prescribe a plan for a State in cases where the St ate fails to submit a satisfactory plan as [EPA] would have under section 7410(c) of this title in the case of failure to submit an implementation plan.” Since 111(d)(2) gives EPA the “same” authority as EPA would have under section 110(c), the meaning of “s atisfactory” should be informed by the structure of 110(c). In other words, EPA should have the same authorit y, structurally, as EPA does under 110(c).

When section 111 was added to the CAA, section 110(c) read:28 The Administrator shall, after considerati on of any State hearing record, promptly prepare and publish proposed regulations set ting forth an implementation plan, or portion thereof, for a State if—

(1) the State fails to submit an implementation plan for any national ambient air quality primary or secondary stan dard within the time prescribed, (2) the plan, or any portion thereof, submitted for such State is determined by the

Administrator not to be in accordance with the requirements of this section, or (3) the State fails, within 60 days after notification by the Administrator or such longer period as he may prescribe, to revise an implementation plan as required pursuant to a provision of its plan refe rred to in subsection (a)(2)(H).

Clean Air Amendments of 1970, Pub. L. 91- 604, § 4, 84 Stat. 1682 (1970). Subsections 110(c)(1) and (c)(3) correspond to failure to subm it a plan or revised plan, respectively, and do not set a standard for a submitted plan. On the other hand, subsection 110(c)(2) does set a standard: under subsection 110(c )(2), State submissions must “be in accordance with the requirements” of Section 110. 44 Thus, the natural interpretati on of “satisfactory” described

above is consistent with this: if EPA can issue a FIP after determining a SIP is not in accordance with the requirements of sect ion 110, then under section 111(d)(2 ) EPA can issue a federal plan if the state plan is not in accord ance with the requirements of sect ion 111(d)(1). In both cases, it is understood that regulations EPA issues spec ifying requirements under the relevant sections (e.g. subpart B and these emission guidelines under section 111(d)(1)) ar e to be considered “requirements of” the relevant section. Any other outcome would eviscerate EPA’s authority under sections 301(a) an d 111(d)(1) to issue binding regulations.

In its current form, as amended by the 1990 Clean Air Act Amendments, the corresponding portion of section 11 0(c)(1) (i.e. the portion that gives EPA FIP authority when the state submits a SIP but it is deficient) does no t set a standard for submitted SIPs. Instead, the corresponding portion, section 110(c)(1)(B), is conditioned on EPA’s disapproval of a SIP submittal in whole or part. The substantive stan dard for EPA’s action on a SIP submittal is set in section 110(k)(3): it must “meet[] the app licable requirements of [the Act].” ( See also section 110(l): SIP revisions cannot “interfere with ... any other applicab le requirement of [the Act].”)

It should be noted that in this context “meet” is synonymous with the connotation of “satisfy” mentioned above: “to satisfy the requirements of (a particular case, a dead line, etc.).” OED. Thus, the current form of section 110(c) confirms the above interpretation of “satisfactory”: for a section 111(d)(1) state plan to be “satisfactory,” it must meet the applicable requirements of the Act, including and in particular the applicable requirements of s ection 111(d)(1), subpart B, and this guideline. And the language “applicable re quirements of the Act” in section 110(k)(3) confirms that the plan must meet the requireme nts of section 111(d)(1) an d any other applicable section of the Act, and any regulations EPA prom ulgates (i.e. subpart B and this guideline) under section 111(d)(1) or se ction 301 that apply.

44 In addition, the 1970 version of section 110(a)(3) provided a positive (i.e. not in the context of a disapproval and FIP) standard. See Train v. NRDC, 421 U.S. 60 (1975).29 Thus, based on the dictionary meaning of “s atisfactory” and the structure of the Act, Congress has spoken directly to the issue. “Satisfactory” means “meet all applicable requirements of the Act.” But even if a court f ound “satisfactory” ambiguous with respect to this issue, EPA’s interpretation of “satisfactory” w ould be reasonable. Th ere is nothing in the legislative history to suggest that section 111( d)(1) state plans should be reviewed by EPA by any other standard, and as described above it is reasonable that EPA’s authority to issue regulations under sections 111(d)(1 ) and 301 should have actual e ffect in EPA’s action on state plans.

Finally, courts have routinely referred to “satisfactory” plan s or SIPs as a shorthand way of summarizing the approval/disappr oval process under section 110(k). See, e.g., Vigil v. Leavitt

, 381 F.3d 826, 830-831 (9th Cir. 2004) (“In the even t that a state does not submit a SIP or does not submit a satisfactory plan within the specified time, the EPA Administrator shall promulgate a federal implementation plan”); NRDC v. EPA , 22 F.3d 1125, 1134-35 (D.C. Cir. 1994) (discussing conditional approvals as “an alternativ e to disapproving substantive, but not entirely satisfactory, SIPs submitted by the statutory deadlines”); Illinois EPA v. U.S. EPA , 947 F.2d 283, 285 (7th Cir. 1991) (describing SIP negotiations th at “failed to produce a satisfactory SIP” and the consequential SIP disapproval); New Mexico Environmental Improv. Div. v. Thomas , 789 F.2d 825, 833 (10th Cir. 1986) (explaining that “EPA reasonably concluded that a satisfactory SIP in terms of section 7502 requireme nts had never been submitted”); and Air Pollution Control

Dist. v. U.S. EPA , 739 F.2d 1071, 1075 (6th Cir. 1984) (explai ning EPA’s authority to devise a FIP “[i]f a state fails to submit a satisfactory plan”).

Accordingly, in light of EPA’s authority und er section 110(c), it is mandated, or at the least reasonable, that the term “satisfactory plan” should be interpreted to m ean a plan that meets all applicable requirements of the Act, including but not limited to section 111(d), subpart B, and these emissions guidelines. For structur al reasons, it is also the case that EPA not only has the authority to, but in fact must approve a plan that meet s all applicable requirements of the

Act. 45 Although there is no case law specifically on the standard of review of a section 111(d)(1) state plan or EPA’s duty to appr ove satisfactory plans, as expl ained above structurally EPA’s action on a 111(d)(1) state plan is identical to EPA’s acti on on a state implementation plan (“SIP”). Under section 110(k)(3 ), EPA must approve a SIP that meets all requirements of the

Act. See Train v. NRDC , 421 U.S. 60 (1975) (discussing the 1970 version of the Act); Virginia

v. EPA , 108 F.3d 1397, 1408-10 (D.C. Cir. 1995) (discussing the 1970, 1977, and 1990 versions). Therefore EPA must also approve section 111(d)(1) state plans that meet all applicable requirements of the Act (i.e. are “sat isfactory”) – any other result would leave a void where EPA did not approve a satisfactory plan but could not promulgate a federal plan.

Based on the reasoning of Train v. NRDC and the language of sections 110 and 116 of the Act, the U.S. Supreme Court in Union Elec. Co. v. EPA , 427 U.S. 246 (1976), held that EPA could not disapprove a SIP on the basis that the plan required technologically infeasible controls that might force facilities to shut down. The Court noted that the most natural reading of section

45 Of course, this does not mean that EPA lacks authority to determine what requirements should apply to those plans, as EPA is doing in thes e emission guidelines. See the discussion in the previous section.30 110 did not preclude the state fr om imposing requirements that might reduce emissions more than necessary to attain the national ambient air quality standards (“NAAQS”). Id. at 262-63.

The Court also noted that sect ion 116 specifically provided that States could adopt emission standards that are more string ent than national standards. Id. In response to the argument that such more stringent emission standards could not be part of the SIP, th e Court reasoned that it

would be difficult for the Administrator to dete rmine what emission standards would precisely bring an area into attainment but no more, and pointless for States to maintain two sets of emission standards (one federally enforceable and one not). Id. at 264. Thus, the Court held that “States may submit implementation plans more stringent than federal law requires and that the Administrator must approve such plans if they meet the minimum requirements” of the Act.

Id. at 265.

Both Train and Union Electric set out a general principle th at EPA cannot “question the

wisdom of a State's choices of emission limitations if they are part of a plan which satisfies” the requirements of the Act. 46 Train , 421 U.S. at 79. “[S]o long as the ultimate effect of a State's choice of emission limitations is compliance with the national standards for ambient air, the State is at liberty to adopt whatever mix of emission limitations it deem s best suited to its particular

situation.” Id. ; accord Union Elec. , 427 U.S. at 266 (“So long as the national standards are met, the State may select whatever mix of control devi ces it desires, and industries with particular economic or technological problems may seek sp ecial treatment in the plan itself.”) (citing Train

, 421 U.S. at 79). This State discretion include s the discretion to “submit implementation plans more stringent than federal law requires.” Id. at 265.

No Court has had occasion to consider whether the general principles of Train and Union

Electric should apply to emission guidelines for secti on 111(d) state plans, but to the extent those principles do apply here, these guidelines sa tisfy them. The EPA has given States maximum flexibility to achieve the rate-based or mass-based goals, or (s hould a State adopt the performance rates) to provide ERCs from various types of measures. Numerous measures that

reduce CO 2 emissions from affected EGUs and th at are otherwise c onsistent with the requirements of these guidelines (such as enforc eability) and the purposes of section 111(d)(1) may be credited. Furthermore, a state is free to reallocate the burdens of these guidelines among affected EGUs by imposing emission standards th at vary from EGU to EGU. Finally, the possibility of interstate trad ing using fungible allowances or ERCs does not impermissibly constrain a state’s authority under section 116 to impose more stringent emission standards, as a state is free to require affected EGUs to hol d more allowances or ERCs, or to emit less CO 2 than is required under these guidelines.

IX. “Remaining Useful Life” Pr ovision of Section 111(d)(1)

This section discusses our in terpretation of the “remaining useful life” provision of section 111(d)(1) and our applicat ion of that interpretation to these emission guidelines.

The second and last sentence of section 111( d)(1) provides: “Regulations of the Administrator under this paragra ph shall permit the State in appl ying a standard of performance31 to any particular source under a plan submitted unde r this paragraph to take into consideration, among other factors, the remaini ng useful life of the existing s ource to which such standard applies.” This portion of the legal memorandu m examines: A) remaining useful life in the context of the implementing regulations in 40 CFR part 60 subpart B; B) the legislative history of the remaining useful life provision; C) the m eaning of certain terms in the provision; and D) EPA’s interpretation of similar provisions in the Act’s visibility pr ogram (including some relevant case law). Finally, we conclude that (and as supported by the preceding four discussions) these emission guideli nes reasonably interpret the remaining useful life provision,

and we conclude that on the record before us these emission guidelines reasonably permit states

to take into consideration remaini ng useful life and ot her factors.

A. Implementing Regulations in Subpart B

Some commenters argued that, due to the remaining useful li fe provision, these guidelines impermissibly require state plan s to achieve the rate-based or mass-based goals. In these commenters’ views, if a State relaxes an emi ssion limitation for one affected EGU in order to take into consideration remaining useful life, the State should not be requir ed to increase the stringency of other emission limitations to mainta in the goal. The implementing regulations in subpart B contemplate that states , in certain limited circumstances subject to EPA approval, may impose emission standards on particul ar facilities that ar e less stringent than generally required by emission guidelines. See 40 C.F.R. § 60.24(f). We therefore start with a discussion of those regulations.

The EPA first promulgated the subpart B regulations in 1975. 40 Fed. Reg. 53,340 (Nov. 17, 1975). At that time, section 111(d)(1) st ood as enacted by the 1970 Clean Air Act:

The Administrator shall prescrib e regulations which shall establish a procedure similar to that provided by section 110 under which each St ate shall submit to the Administrator a plan which (A) establishes emission sta ndards for any existin g source for any air pollutant (i) for which air quality criteria have not been issued or which is not included on a list published under section 108( a) or 112(b)(1)(A) but (ii) to which a standard of performance under subsection (b) would apply if such existing source were a new source, and (B) provides for the implementation and enforcement of such emission standards.

Pub. L. 91-604 § 4(a), 84 Stat. 1676, 1684. Thus, when EPA first promulgated the subpart B regulations, there was no remain ing useful life provision, and s ubsection 111(d)(1)(A) required states to establish “emission standards, ” not “standards of performance.”

In proposing the subpart B regulations, EPA st ated: “It is the Admi nistrator's judgment that section 111(d) permits him to approve St ate emission standards only if they reflect application of the best systems of emission re duction (considering the cost of such reduction) that are available.” 39 Fed. Reg. 36,102, 36,102/1,2 (O ct. 7, 1974). Of particular relevance to remaining useful life, EPA went on to state:

It is recognized, however, th at application of such sta ndards may be unreasonable in some situations. For example, to require th at existing controls be upgraded by a small32 margin at a high relative cost may be unreasonable in some cases. The proposed regulations, therefore, provide that States may establish less stringent emission standards on a case-by-case basis provided that sufficient justification is demonstrated in each case.

Id. at 36,102/2. EPA therefore proposed that the s ubpart B regulations should contain a variance provision. See id. at 36,104/2. In response to an adve rse comment, EPA in finalizing the regulations stated:

Although section 111(d) does not explicitly provide for variances, it does require

consideration of the cost of applying standards to existing f acilities. Such a consideration is inherently different than for new sources , because controls cannot be included in the design of an existing facility and because physical limitations may make installation of particular control systems impossible or unreas onably expensive in some cases. For these reasons, EPA believes the provision [§ 60.24(f)] a llowing States to grant relief in cases of economic hardship (where health-related pol lutants are involved) is permissible under section 111(d).

40 Fed. Reg. 53,340, 53,344/2 (Nov. 17, 1975). EPA did not state that section 111(d) compelled EPA to provide for variances, just that it was permissible. As promulgated in 1975, subsection 60.24(f) provided:

On a case-by-case basis for partic ular designated facilities, or classes of facilities, States may provide for the application of less stri ngent emission standards or longer compliance schedules than those otherwise required by pa ragraph (c) of this section, provided that the State demonstrates with respect to each such facility (or cl ass of facilities) : (1) Unreasonable cost of control resu lting from plant age, location, or basic process design; (2) Physical impossibility of instal ling necessary control equipment; or (3) Other factors specific to the facil ity (or class of facilities) that make application of a less stringe nt standard or final complia nce time significantly more

reasonable.

Id. at 53,347/3. Thus, under the 1975 regulations, Stat es had to demonstrate that a less stringent emission standard was warranted, and that dem onstration and the resulting emission standard were subject to EPA review and approval. Id. at 53,348/2, 3. Despite the adverse comment, the promulgation of 60.24(f) was not challenged.

As discussed in detail in the ne xt section, Congress added the rema ining useful life provision in the 1977 Amendments. The legislative history indicates that Congress was aware of the 1975 implementing regulations and, in the remaining useful life provision, addressed the concerns (particularly regarding unreas onably expensive retrofit contro ls) that EPA expressed when promulgating 60.24(f). EPA did not revise the implementing regulations after the 1977 Amendments, but EPA did issue emission gui delines for certain source categories. E.g. , 45 Fed. Reg. 26,294 (Apr. 17, 1980) (primary aluminum plants ). In responding to an adverse comment on the primary aluminum plant emission guideline s, EPA stated: “The States may take into consideration the remaining useful life of a pl ant. Where a facility contains both old and new33 [reduction] cells, it may be reason able to apply somewhat less st ringent standards to the old.” Id. at 26,295. Thus, EPA thought that that subpart B ad equately addressed the remaining useful life provision for the purposes of that guideline, and was not challenged on that position. 47

Some commenters argued that the 1975 regulations, having b een promulgated prior to the 1977 Amendments, necessarily do not implement the remaining useful life provision. Based on the history of the 1975 implementing regulations presented here and the 1977 Amendments presented below, we think those comments are overs tated; however, that disagreement is not necessary to our promulgation of these emi ssion guidelines as we next explain.

In 1995, EPA added the prefatory phrase “Unless sp ecified otherwise in the applicable subpart” to 60.24(f). EPA was not challe nged on that revision to subpart B, which now applies to emission guidelines issued under both sections 11 1(d)(1) and 129(b). On its face, the language thus now allows for other approaches to satisf ying the remaining useful life provision. Thus, subpart B does not mandate the outcome that the commenters suggest, that States must be permitted to relax emission standards on particul ar affected EGUs on the basis of remaining useful life (or other factors) without requiring of fsetting reductions from other affected EGUs. In fact, EPA promulgated section 111(d)(1) em ission guidelines, as part of the Clean Air Mercury Rule (CAMR), 48 that set mass-based statewide caps on mercury emissions from coalfired electric utility steam-generating units. St ates either had to adopt an allowance-based trading program, or had to impose individual emi ssion standards; in both cases, the statewide cap had to be met and could not be adjusted. T hus, under CAMR, the sort of adjustment that commenters argue is necessarily re quired in order to take into account remaining useful life was not allowed. In any case, these emission guidelines avail themselves of the possibility added in the 1995 revision to make the source-specific varian ce factors inapplicable. Instead, they satisfy the remaining useful life provisi on in other ways, as discussed in this section of the legal

memorandum.

B. Legislative History

As mentioned above, the 1970 version of s ection 111(d)(1) did not contain a remaining useful life provision. The provision in subsection 111(d)(1) for state plans and the similar but not identical provision for federal plans in subsectio n 111(d)(2) were added to section 111(d) in the

1977 Clean Air Act Amendments. Pub. L. 95-95 § 109(b)(1), 91 Stat. 685, 699. The provisions first appeared in a House bill introduced in the 94th Congress. See H.R. 10498, § 111 (May 15, 1976), reprinted in A Legislative History of the Clean Air Act Amendments of 1977 (“1977 LH”), Environmental Policy Divisi on, Congressional Research Servic e, Library of Congress, at 5961 (Aug. 1978, Serial No. 95-16). Th ey were “intended to clar ify the basis for standard-

47 In that action, EPA determined that designa ted pollutant, fluoride, was welfare-related, id. at 26,296, which provided certain other flexibilities, see 40 C.F.R. § 60.24(d). Nonetheless, the use of the word “reasonable,” which does not occu r in 60.24(d), indicates that 60.24(f) might have applied.

48 CAMR was vacated by the D.C. Circuit on ac count of the EPA’s flawed CAA section 112 delisting rule, although the court dec lined to reach the merits of the EPA’s interpretation of CAA section 111(d). New Jersey v. EPA , 517 F.3d 574 (D.C. Cir. 2008).34 setting for existing sources under section 111(d) of the Act.” H. Rep. to accompany H.R. 10498;

1977 LH at 6717.

In the 95th Congress, the House proposed a nearly identical bill to H.R. 10498, which included the same language on “remaining useful life.” The House report accompanying H.R. 6161 even repeated the explana tions stated in the House re port accompanying H.R. 10498, see H. Rep. 95-264 at 195; 1977 LH at 2662. Also, H. R. 6161 added a new section on visibility protection, which required the cons ideration of the remaining usef ul life of any existing source subject to “best available retr ofit technology” (BART) or “max imum feasible progress” (as enacted, “reasonable progress”) requiremen ts. See H.R. 6161, § 116 (May 12, 1977); 1977 LH

at 2329.

According to the House report accompanying H.R. 6161, 49 the revisions to section 111

were also intended to clarify section 111(d):

This section is also intended to clarif y the basis for standard-setting for existing sources under section 111(d) of the Act. Under the committee bill, the standards in the section 111(d) State plan would be based on the best available means (not necessarily technological) for categories of existing sources to reduce emissions. The Administrator would establish guidelines as to what the best system for each such category of existing sources is. Howe ver, the State would be responsible for determining the applicability of such guidelines to any particular source or sources. The Administrator's guidelines mu st take into account the remaining useful life of existing sources. Unless the State decides to adopt and enforce more stringent standards, the State plan would be expected to take into account the remaining useful life of the source (or sources).

H. Rep. 95-294 at 195; 1977 LH at 2662.

From the perspective of remaining useful lif e, three things are wo rth noting about this passage. First, it adopts the term “guidelines” cons istently with EPA’s usage of the term in the 1975 framework regulations. This indicates th at the remaining useful life provision was informed by those framework regulations, in cluding EPA’s intention in using the word “guideline” to indicate a rule that was not directly enforceable against affected sources, but that was binding on states in developi ng and submitting their plans. See 40 Fed. Reg. 53,340, 53,341/2 (Nov. 17, 1975). The sentence in the legisl ative history about states determining applicability is consistent with this: the guideli nes are not directly appl icable to a particular source, but the state plan does appl y to particular sources within the guideline source category.

Second, since Congress recognized EPA’s inte rpretation in the fr amework regulations and therefore expected EPA’s emission guideline s in general to set binding requirements for states, Congress in particular expected EPA to set binding requirements for consideration of

49 The Senate bill had no corresponding provisions, and the Senate concurred with minor amendments. H. Rep. 95-564 (conference report ); 1977 L.H. at 510. Thus, the House report should be taken as the primary source of legislative history.35 remaining useful life. This is clear from the sentence stating “The Admi nistrator’s guidelines

must take into account the remaini ng useful life of existing sources.” It should also be noted that this sentence uses “life,” not “lives”; thus it was not expected that EP A in promulgating emission guidelines would examine the remaining useful life of each particular source individually. Instead, EPA should determine how remaining usef ul life should generally be taken into account for a particular source category.

Third, the House report states: “Unless the State decides to adopt and enforce more stringent standards, the State plan would be expe cted to take into acc ount the remaining useful life of the source (or sources).” Thus, consistent with the statut ory text “in applying a standard of performance to any particular source,” Congre ss intended that taking into account remaining

useful life was not an avenue to avoid application of a standard of performance to a particular source, but instead a way to tailor to some extent (based on remain ing useful life) the application

of the standard to th at particular source. 50 In other words, the remaining useful life provision does not provide an unmitigated ability for States to exempt their sources from standards of performance, particularly if such exemptions w ould lead to a failure to achieve the degree of

emission limitation the EPA determined to be achi evable when there is on the record no warrant for doing so.

This is consistent with the 1975 framewor k regulations, which do not provide for an exemption but instead provide for application of a less stringent sta ndard based on certain factors. 40 Fed. Reg. 53,340, 53,347/3 (Nov. 17, 1975) (promulgation of 40 C.F.R. 60.24(f)). Thus, the interpretation of the provision here as no t allowing for an exemption is consistent with those regulations.

The points above are general but consistent with the overall framewo rk of section 111(d); a concrete concern of Congress ad dressed in the remaining useful life provision was the cost of retrofit technology at exis ting sources and the potential for ot her, more cost-effective means of compliance. 51 This can be seen in the legislativ e history in the broa der context of the corresponding changes in the House bill to the pr ovisions for new source performance standards. In the 1977 Amendments, Congress required that new sources install controls to reduce emissions, in lieu of reliance on cleaner fuels. A reason for this was to reduce demand by new sources for cleaner fuels, freeing up those fuels (whi ch were perceived at th e time to be relatively scarce) to be used by existing sources. H. Rep. 95-294 at 185; 1977 LH at 2652. For older and smaller existing sources, it might not be physically or economically feasible to install retrofit

50 As discussed below, there could be factual circumstances for a particular source category under which it might be reasonable for EPA to in terpret the remaining us eful life provision as allowing states to impose no obligations for particul ar sources because of remaining useful life or other factors. However, those circ umstances are not present here.

51 As mentioned before, concern with the cost of retrofit controls was expressed by EPA as a basis for the variance provision in the 1975 fr amework regulations: “[ C]ontrols cannot be included in the design of an exis ting facility and [] physical limita tions may make installation of particular control systems impossible or unreason ably expensive in some cases.” 40 Fed. Reg. 53,340, 53,344/2 (Nov. 17, 1975).36 technology. By allowing those latter sources to comply through use of cleaner fuels, sources with “relatively short remaining useful lives” could stay in oper ation rather than shut down, and sources with small marginal reve nues could avoid large up-front capital costs associated with retrofit controls. H. Rep. 95-294 at 186; 1977 LH at 2653.

This provides necessary context for the stat ement in the legislative history that “the standards in the section 111(d) State plan would be based on the best available means (not necessarily technological) for categ ories of existing sources to reduce emissions.” H. Rep. 95- 294 at 195; 1977 LH at 2662. Thus, in explicitly retaining BSER as the standard for existing

sources, 52 Congress made clear that the EPA was not obligated to base BSER on control technology but could nonetheless, for some sour ce categories and some po llutants, reasonably do so after considering costs.

One other parallel context in the 1977 Am endments should be discussed. Congress added a new section to the Clean Air Act, sect ion 169A, regarding protection of visibility in

certain National Parks and Wilderness Areas. The de finition of best avai lable retrofit technology (BART) required states (or EPA in a FIP) to c onsider five specific factors, in cluding the remaining useful life of the sour ce and the costs of compliance. 53 While the legislative history does not discuss the remaining useful life factor in detail, Congress made clear that best available retrofit technology (BART) should notbe required at all on sources older than fifteen years. H. Rep. to accompany H.R. 6161, 1977 LH at 2480; see also H.R. 6161, § 116, 1977 LH at 3237. Thus, Congress explicitly prohibited EPA from requiring a retrofit technology on those sources likely to have shorter remaining useful lives. This is consistent with the legislative history for the section 111(d)(1) re maining useful life provision, which expresses a concern that older sources with “relatively short remaining useful lives” might prematurely shut down.

In summary, we draw the following conclusi ons from the legislative history. First, Congress intended EPA to issue binding requirement s for remaining useful life and to take into

account characteristics of a source category in determining how re maining useful life should be addressed. Second, Congress intended remaining usef ul life to be used by states to tailor the application of a standard of performance to a par ticular source, and not to exempt sources from a standard of performance altogeth er. Third, Congress intended the provision to primarily address the problem of existing sources with relatively sh ort remaining useful lives for which installation of retrofit technology – for t hose standards for which tec hnology was the BSER and the compliance method of choice -- might be unreasonably expensive.

C. Meaning of Terms in the Rema ining Useful Life Provision

The term “shall” of course creates a mandatory requirement for this guideline; in other words, this guideline must “permit the State in applying a standard of performance to any

52 The 1977 Amendments made the application of BS ER in section 111(d)(1) to existing sources explicit by “by striking out ‘emissions standards’ in each place it appears and inserting in lieu thereof ‘standards of performance’.” Pub. L. 95-95 § 109(b)(1), 91 Stat. 685, 699.

53 EPA’s interpretation of remaini ng useful life under the visibility program is discussed in detail

below. Here we discuss only the legislative history.37 particular source ... to take into consideration, among other factors, the re maining useful life of

the source.”

However, contrary to some commenters’ assertions, this mandatory requirement does not create unbounded authority for States to consider remaining useful life (or, for that matter, any other factor the state may wish to consider) in an y way a State sees fit. Because this provision is part of the CAA, the EPA has the authority to interpret it in the first instance. In addition, ultimately, the EPA has the authority to review and determine whether state plans are satisfactory, including whether they achieve a requisite level of em ission performance. Thus, the provision is best read to focus on the Administrator’s obligation to promulgate guidelines that permit States to consider remaining useful life, and not on any “right” of the States Compare the provision with, for example, section 116 of the Act, which specifically reserv es “the right of any State or political subdivision” to adopt more stringent requiremen ts. 42 U.S.C. § 7416 (emphasis added). Thus, when Congress wanted to prohibit EPA from imposing constr aints or parameters on State discretion, Congress knew how to say that.

The language of the remaining useful life provisi on is consistent with this. To “permit” is “to let (something) be done or o ccur,” as in “the law permits the sale of such drugs.” ACD at 902 to 903; see also OED (“To allow or give cons ent to (a person or thing) to do or undergo something.”). In the dictionary’s example usage, “the law permits the sale of such drugs,” it is well understood that the law may (and likely does) se t conditions on the sale. Thus, the natural interpretation of the remaining useful life provision is that th e Administrator may set reasonable conditions on how, or reasonable terms under which, states are allowed or “permitted” to take into consideration remaining useful life.

In addition, the terms “consideration” and “am ong other factors” must be discussed.

“Consideration” in this context is “regard or account: somethi ng taken, or to be taken, into account.” ACD at 258; see also OED (“The taking into account of anything as a motive or reason; a fact or circumstance take n, or to be taken, into account; a reason c onsidered.”). Thus, “consideration” of “remaining us eful life” means taking it into acc ount “in applying a standard of performance to any particular source.”

However, taking remaining useful life into a ccount is not the same as making remaining useful life dispositive. This interpretation is bolstered by the language “among other factors.” This indicates that “remaining usef ul life” is itself a “f actor.” A “factor” is “one of the elements that contribute to bring about any given result .” ACD at 431 (emphasis added); see also OED (“a circumstance, fact, or influence which contributes to a result.”). Thus remaining useful life is one element of the application of a State’s standard of performance to a particular source, but it is not dispositive.

Finally, to “apply” is “to bri ng to bear; put into practical operation, as a principle, law, rule, etc.” ACD at 61; see also OED (“To bring (a rule, a test, a principle, etc.) into contact with facts; to bring to bear practically; to put into practical operation”). Thus , “applying a standard of performance” to a “particular source” means putti ng the standard of performance into practical

effect for that source. It does not mean exem pting a particular source from a standard of38 performance, and as discussed in the legislative history, Congre ss knew how to allow sources to be exempted from requirements when Congress so desired.

This analysis of the language of the remaini ng useful life provision confirms much of the legislative intent discussed above . First, even after addition of the remaining useful life provision, in submitting approvable state plans, stat es would remain subject to minimum criteria in the emission guidelines promulgated by the Admi nistrator; the remaining useful life provision is not an unrestricted grant of a right to a st ate. Second, the Administrator can set conditions under which states are “permitted” to consider remaining useful life. Third, a state’s consideration of remaining useful life should tailor the standard of performance to the source, not exempt it. Finally, the Administrator may review the state’s applicati on of the standard of performance to its sources, as part of the state pla n, to assure that the stat e plan is “satisfactory,” that is, meets the requirements of the CAA and EPA’s emission guidelines.

D. Remaining Useful Life in the Visibility Program

A closer look at the “remaining useful life” provision in the visibility program sheds additional light on the meaning of the provision under se ction 111(d)(1).

Under section 169A of the Act, SIPs are required to contai n “a long-term [] strategy for making reasonable progress toward meeting th e national goal,” 42 U.S.C. 7491(b)(2)(B), of “prevention of any future, and th e remedying of any existi ng, impairment of visibility” in certain National Parks and Wilderness Areas, id. (a)(1). A component of re asonable progress is the imposition of best available retrofit technology (BART) at certain existing sources. Id. (b)(2)(A).

Remaining useful life plays a part in the visi bility program in two ways. In determining BART for a particular source, States (or EPA in th e case of a FIP) “shall take into consideration” five enumerated factors, including “the remaining useful life of the source.” Id. (g)(2). Similarly, the remaining useful life of existing so urces (along with three ot her factors) must be taken into consideration in determining reas onable progress for the long-term strategy. Id. (g)(1).

Section 169A also requires EPA to issue “guide lines” for states to use in determining

BART. Id. (b)(1). These guidelines must be followed for certain fossil-fuel fired power plants.

Id. (b). In the “BART Guidelines,” EPA has inte rpreted the “remaining us eful life” BART factor and set very specific requirements (that is, re quirements when it comes to the mandatory BART sources) for how States should consider it:

The “remaining useful life” of a source, if it represents a relatively short time period, may affect the annualized costs of retrofit controls. ... If the remaining useful life will clearly exceed th[e] time period [for amortization based on the type of control], the remaining useful lif e has essentially no effect on control costs and on the BART determination process. Wh ere the remaining useful life is less than the time period for amortizing costs, you should use this shorter time period in your cost calculation.39 40 CFR Part 51, App. Y, section IV.D.4.k (emphasis added). 54 Thus, EPA interpreted the BART remaining useful life factor, consistent with Congressional intent, to address a possible

unreasonable cost of retrofit cont rols at a particular source, and EPA promulga ted a specific methodology for taking the factor into considerat ion through computing the annualized cost of retrofit controls. The effect of this is, wher e a source may have a shorter remaining useful life than the amortization period for th e retrofit control, the annual cost of the control will be correspondingly higher, and that may weigh (w hen considering the five factors) against determining that the particular control is BART. In promulga ting this interpretation of the remaining useful life factor and corresponding re quirement, EPA rejected a comment that the remaining useful life factor should be inte rpreted to allow for postponement of BART requirements. 70 Fed. Reg. 39,104, 39,127/3 (July 6, 2005).

As explained in section VIII of the preamble, these emission guidelines permit states to take into consideration remaining useful life in a manner consistent with the statute, legislative history, and prior agency interpretation in the BART Guidelines. The agency has determined the

BSER in this case to be a set of measures th at produce an emission perf ormance level that is reasonable rather than maximal and that already accounts for an average le vel of performance at a regionalized level. In the emission guidelines, the EPA is giving the states the tools to take advantage of this flexibility, such as relativ ely long periods for sources to come into full compliance, multiple-year compliance periods, the ability to credit early action, the use of emissions trading, and the ability to link to other state plans to create la rger emissions markets. Among other things, these mechanisms creat e economic incentives that reward overperformance of some sources, allow others to si mply acquire credits or allowances to comply with their emission standard, and avoid the need for in stallation of costly pollution controls at

sources on a short time horizon.

The availability of trading is particularly important to how remaining useful life is permitted to be considered in these emission guidelines. Essentially, trading amortizes the costs of compliance over compliance periods. Affected EGUs with relatively short remaining useful lives need only comply for a proportionately smaller number of periods as compared with affected EGUs with relatively long remaining usef ul lives. Thus, the cost of complying with these emission guidelines is distributed in a way that is consistent with how the BART Guidelines compute the cost of compliance for sources with relatively short remaining useful

lives.

It is true that the same term may be interpre ted in different ways in different contexts of

the Clean Air Act. Envt’l Def. et al. v. Duke Energy Corp. et al. , 549 U.S. 561, 574 (2007). However, general consistency w ith the BART Guidelines is ev idence that EPA’s interpretation of the remaining useful life provisi on here is reasonable. This is particularly true in light of the addition by Congress of both provisions in the 1977 Amendments and the Congressional concern in both provisions with the cost of retrofit controls. Our interpretation that remaining useful life

54 In guidance, EPA has recommended that the re asonable progress remainin g useful life factor be evaluated in a similar way. “Guidance fo r Setting Reasonable Progress Goals Under the Regional Haze Program,” U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, at 5-3 (June 1, 2007).40 does not create an exemption is also consistent with EPA’s rejection of the comment that remaining useful life should allow for postponement of BART requirements.

The 2005 promulgation of the BART Guidelines in part responded to a decision of the U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”), Am. Corn Growers

v. EPA , 291 F.3d 1 (D.C. Cir. 2002) (“ Corn Growers ”). In Corn Growers , various parties challenged EPA’s initial promulgation of the Re gional Haze Regulations, which created various requirements for SIPs to address visibility im pairment. A particular requirement that was challenged was a “no degradation” provision that “require[d] impl ementation plans to ‘provide for an improvement in visibility for the most impaired days over the period of the implementation plan and ensure no degradation in visibility for the least impaired days over the same period.’” Id. at 11. The petitioners argued that this impermissibly conflicted with States’

discretion to consider the four reasonable progress factors, in cluding the remaining useful life factor. The court rejected this argument, firs t stating that the “no de gradation” provision was consistent with the statutory purpose of progress toward the national goal. Id. at 12. Second, the court noted that degradation was not even one of th e four factors and “[t]he refore, the states will be able to comply with the no degradation requirement while appl ying” the four factors. In essence, EPA could permissibly constrain application of the four factors to be consistent with the

statutory purpose.

This decision rebuts comments that EPA must gi ve states discretion to revise the goals in order to consider remaining useful life. First, in response to such comments, we note here (as elsewhere) that states can ade quately consider remaining useful life, through the use of trading, even when they do not adopt a rate or mass-base d goal but instead adopt th e performance rates. No adjustment of a goal is necessary. However, if a state decides to re allocate burdens among its affected EGUs in order to address remaining useful life or other factors, it is permissible for EPA

to constrain the state’s discretion so that application of those fact ors is consistent with the overall purpose of section 111(d): the se t of affected EGUs as a whol e achieves BSER-level emission reductions. To be sure, the agency agrees with co mmenters to the extent that the statute affords

EPA the discretion to decide in certain cas es that a downward variation in emissions performance for some affected sources in a state under section 111(d) could be authorized. Indeed, the agency’s implementing regulations ha ve provided that ability for many years. But this does not mean that for a particular emissi ons guideline for a particular pollutant from a particular category of sources , the agency cannot reasonably decide that such downward

variations are unwarranted and unne cessary. That is the case here.

Finally, we note two recent decisions regarding EPA’s ac tion on visibility SIPs. Okla. et

al. v. U.S. EPA , 723 F.3d 1201 (10th Cir. 2013); N. Dakota et al. v. U.S. EPA et al. , 730 F.3d 750 (8th Cir. 2013). Both the Eighth and Tenth Circ uit Courts of Appeals rejected (among other arguments) generic arguments that States had primacy in determining BART and that EPA merely had the ministerial task of approving the State’s determination. Okla. , 723 F.3d at 1207- 10.; N. Dakota , 730 F.3d at 760-61. In both cases, the c ourts upheld EPA’s re jection of BART

determinations that relied on cost estimates that either were inconsistent with the BART Guidelines, Okla. 723 F.3d at 1211-14, or otherwise flawed, N. Dakota , 730 F.3d at 760-61. These decisions are consistent with our interpreta tion that we have the au thority to prescribe the41 conditions under which remaining useful life can be considered and to reject as unsatisfactory plans that do not follow those conditions.

E. These Emission Guidelines and Remaining Useful Life

There are two general reasons that these emi ssion guidelines satisfy the requirement that they “permit the State in applying a standard of performance to any particular source ... to take into consideration, among other factors, the remain ing useful life of the source.” First, the emission guidelines are based on a reasonable in terpretation of the provision, and second, on the record before us the consequences of this interpretation are reasonable.

In general, EPA may reasonably interpret am biguous terms in the remaining useful life provision. The first (potentially) ambiguous term is “permit.” In its natural reading, discussed above, the term “permit” is well understood in it s legal usage to authorize the entity permitting an action to set binding conditions on the action that is permitted. If in fact the term is ambiguous, then the question that is left unanswered by the statut e is whether EPA may, as urged by commenters, decline to set bi nding conditions on the manner in which states can consider remaining useful life. Our interpretation that EPA may do so, if not compelled, is certainly

reasonable: to hold otherwise woul d be contrary to the typical supervisory role of EPA in this cooperative federalism scheme (as discussed in N. Dakota and Okla. ) and, as it would allow states to relax requirements at a ffected EGUs virtually at will, contrary to the statutory purpose of achieving emissions performance levels equi valent to the BSER at affected EGUs.

The term “permit” does not specify the pa rticular manner in wh ich EPA should permit States to consider remaining us eful life (and other factors). It is therefore ambiguous with respect to this issue. We also note that the other terms discussed above, “applying,” “consideration,” and “factors” are not specific as to the manner of consideration. In sum, it is perhaps most straightforward to say that the entire phrase “permit the State in applying a standard of performance to any particular so urce under a plan submitted under this paragraph to take into consideration, among othe r factors, the remaining useful life of the existing source to which such standard applies” is ambiguous with respect to the issue of how EPA may permit the State to do so. Thus, EPA may reasonably spec ify the conditions under which States may take into consideration remaining useful life.

The specifications in these emission guidelines are reasonable. First, as discussed in detail above they are consistent with the langua ge of the provision, with the legislative intent, and with our interpretation of the similar (but no t identical) provision in the visibility program. As with the BART Guidelines, EPA may reas onably be quite specific about the manner of

consideration of this factor that is allowe d. The additional flexibilities provided by these guidelines – adoption of the uniform performan ce rates, adoption of th e rate-based goal but imposition of non-uniform rates, adoption of em ission trading programs, adoption of the massbased goal with flexibility to distribute allowances , or adoption of the state measures plan type – reasonably permit States to consider remaining usef ul life and other factors in various ways. For example, a state may adopt mass limits, and allocate a relatively grea ter number of allowances to a source with limited remaining useful life, on the unde rstanding that the source will retire before 2030 and free up allowances for other sources. Si milarly, under rate-based limits, a state could42 direct ERCs generated by a stat e-run or state-subsidized renewa ble energy or energy efficiency project to be transferred to an affected EGU with limited remaining useful life, or the state could simply impose a less stringent rate-based limit on the affected EGU. Give n this, it is permissible (as seen in Corn Growers ) for these emission guidelines to ensu re that affected EGUs as a group

in a state achieve BSER-determine d levels of emission reductions.

Several commenters said that that the statut e does not authorize the EPA to require other facilities to achieve greater reductions to compen sate for a facility that the state determines warrants relief based on remaining useful life. One said that cons ideration of remaining useful

life and other relevant factors is a one-way ratchet that provides relief to sources that cannot achieve an emission performance rate determin ed by the BSER, and that the EPA turns that approach on its head by prohibiting a state from providing such relief to a specific facility unless it can identify another facility to “punish” by re quiring additional emission s reductions to offset

that relief.

The EPA disagrees with these comments, for se veral reasons. First, as noted above, the availability of trading substant ially accounts for remaining useful life. Second, the EPA is not establishing the BSER emission level for individu al facilities, and then requiring better-thanBSER from some facilities to ma ke up for worse-than-BSER perfor mance that a state authorizes

for other facilities because of a short remaining useful life. Ra ther, as previously noted, the guidelines set EGU performance rates and state goa ls that represent the average or aggregate emission level achievable by affected EGUs based on regional average estimates of the impact of applying the BSER to collective groupings of affected EGUs. 55 In estimating the amount of improvement achievable through each building bloc k (e.g., improvement in heat rate or amount of generation shift to lower-emitting EGUs), the EPA relies on estimating the average level achievable by EGUs in a region rather than atte mpting to estimate a level achievable by each and every affected EGU in the absence of trading. Thus , the fact that an individual facility may be unable, for example, to achieve the average le vel of heat rate improvement assumed in goalsetting is consistent with the EPA’s analysis, and does not undermine the EPA’s determination of state goals.

Third, for states that adopt a mass goal, the reti rement of an EGU at the end of its useful remaining life actually eases compliance by other EGUs post retirement. 56 For states that adopt a

55 The EPA expects that states that choose to a dopt the national EGU perfor mance rates for all of their EGUs would permit ERC trading, rather than requiring each facility to meet the applicable rate without trading. In effect, the presence of trading means that the EGU performance rates will be achieved on average by the EGUs involved in trad ing, rather than be achieved by each facility in the absence of trading.

56 As discussed in the sections on the legislativ e history and the visibility program, EPA believes that Congress in adding the remaining useful lif e provision was primarily concerned with sources with relatively short remaining useful lives. However, in thes e emission guidelines EPA is not assuming any particular length of life for affected EGUs, and history has shown that some fossil

fuel-fired EGUs have continued to operate beyond what was assumed to be their lifetime.43 rate goal, a similar effect would happen when higher-emitting EGUs retire. Depending on the timing of the retirement, the retirement may he lp the state’s affected EGUs to achieve the required level in the state plan (i.e., the nationa l EGU performance rate, or the rate-based or mass-based state goal), even if the state were to place lesser requirements on an EGU during its limited remaining useful life. In such cases, the retirement would not create any deficit of emission reductions to be made up by other EGUs.

The EPA has considered a scenario in which an EGU might not be scheduled to retire until just before the end of th e interim period, or until soon after the final goal must be met, 57 and the state would prefer to requi re no emission reduction from the retiring EGU in the meantime. Under this hypothetical scenario, the lack of emission reduction re quirements for the EGU that is planning retirement on these timelines could creat e an emission reduction deficit. However, for this limited scenario and in light of the other fl exibilities provided in these guidelines, the EPA believes that it continues to be reasonable to require the state plan as a whole to meet the state goal. The EPA would therefore be justified in disapproving a plan that did not achieve compensating emissions reductions to m eet the state goal in this instance.

Finally, contrary to the views of commente rs, the EPA believes that the agency has discretion under section 111(d) over whether or not the remaining us eful life criterion should be grounds for diminishing the overall emission reducti on required by the guidelines for a particular source category. Stated anothe r way, commenters believe the st atute unambiguously requires the agency to approve state plans that achieve le ss emission reductions than the agency knows are achievable. The agency has long recognized th at there may be grounds for this for some pollutants from some categories of sources, under section 111(d) and the agency’s implementing regulations. However, for a par ticular emissions guideline for a particular pollutant from a particular category of sources, the agency can reasonably decide that such adjustments are unwarranted and unnecessary. As discu ssed above, that is the case here.

To summarize, the agency has determined the BSER in this case to be a set of measures that produce an emission performance level that is reasonable rather than maximal and that represents an average level of performance achievable by EGUs in each of the three interconnect regions. In the emission guidelines, the EPA is gi ving states flexibility on the design of the state

The benefit to other EGUs mentioned above ev entually applies regardless of how long an affected EGU operates before retirement, albeit with reduced benefits for other EGUs as the retirement happens fart her in the future.

57 Under this scenario, the aff ected EGU would continue to op erate and generate revenue for roughly 15 years from promulgation of these guidelines . This is significant for two reasons. First, it seems appropriate that an EGU that is operating until roughly 2030 should bear substantial responsibility for obtaining emission reductions desp ite its plans to retire eventually. Under the agency’s interpretation of “remaining useful life, ” a plant that plans to operate for 15 years or more would justify lesser relief from standards of performance on the basis of remaining useful life. Second, the typical debt life for coal-fired EGU is 20 years, so the number of affected EGU that have not repaid their debt dwindles si gnificantly by 2030. The number of facilities that are not fully depreciated based on book life also diminishes over time.44 programs to achieve the EGU performance rates or state goals. The guidelines also give the states tools to take advantage of this flexibilit y, such as relatively long periods for sources to come into compliance, the ability to credit ea rly action, the ability to use emissions trading, multi-year compliance periods, and the ability to link to other state plans to create larger

emissions markets. These tools can be used to create economic incentives that reward overperformance of some sources, and allow others to simply acquire credits or allowances to comply with their emission standard. While ther e are technologies that could require expensive

retrofits available for EGUs to reduce their em issions, including co-fir ing with natural gas 58 , repowering with natural gas, or CCS, we do not expect that any affected EGUs will need to rely on them and, in fact, we did not include them in the BSER. Thus, there is no need for affected EGUs with limited remaining useful life to inst all costly pollution cont rols. Because of these features of the guidelines, EPA believes that a ny unit-specific considerations that a state may find warrant the application of a less stringent standard of perform ance are fully capable of being addressed without reducing the overall emission pe rformance level. Given this determination, these guidelines require that state plans achieve an aggregate emission level from the affected EGUs, and may be disapproved if they do not.

EPA’s interpretation of the remaining usef ul life provision is al so reasonable on the

record before us. As discussed in detail in Section V of the preamble and supporting documents, there is substantial evidence that BSER, as expre ssed in the performance ra tes, rate-based goals, and mass-based goals, is achievable considering co sts. In other words, affected EGUs with relatively short remaining useful lives will have cost-effective ways to comply and will not be required to make expensive initial capital expenditu res that would be hard to justify in light of that short remaining useful life. Indeed, such EGUs need not inst all retrofit controls at all, but may purchase ERCs or allowances in order to co mply, or may negotiate directly with qualified generators of credits.

With respect to stranded assets, the legisl ative history indicates that Congress was primarily concerned with the marginal costs of compliance with the emission guidelines going forward and not with past, sunk costs. Notw ithstanding our interpretation of the remaining useful life provision, the agency recognizes it to be possible that there could be circumstances under which an emission guideline should explicitl y address a severe pos sibility of stranded assets. However, our analysis s hows that stranded assets are not likely to be an issue under these emission guidelines (unless of course a State at its discretion decides to shut down certain affected EGUs). 59 Thus, although nothing in the remain ing useful life provision explicitly compels us to take into account the possibility of stranded assets , and nothing in the legislative history indicates the provision shou ld be interpreted to do so, this emission guideline nonetheless reasonably addresses the potential problem.

X. Response to Claims that the CPP Raises Constitutional Concerns

A. Tenth Amendment

58 In many instances, co-firing could be accomplished without significant retrofits; in other cases, it might require retrofits.

59 See Memorandum to Docket, “Analysis of Potential for Stranded Assets.”45 Commenters have claimed that the emission guidelines and requirements for 111(d) state plans violate principles of federalism embodied in the U.S. Constitution. These commenters claim that states will be unconstitutionally “coe rced” or “commandeered” into taking certain actions in order to avoid the pros pect of either a federal 111(d) plan applying to sources in the state, or of losing federal funds.

We disagree with these commenters’ conclusions, which rest on fundamental misunderstandings or inaccurate descriptions of th e Clean Air Act, this rule, and the applicable case law. As an initial matter, we agree that it is black-letter constitutional law that the federal government cannot coerce or commandeer state governments into enacting a federal regulatory

program. 60 But the emission guidelines and requirement s for 111(d) state plans provided in this rule do no such thing. Far from violating principl es of federalism, this rule and CAA section 111(d) fully respects such principles. In part icular, they provide states with the initial opportunity to submit a satisfactory state plan, with no consequences to states in their sovereign capacity should they decline to participate. Rather , if a state declines to take advantage of that opportunity, affected EGUs in that state will inst ead be subject to a fede ral plan that satisfies statutory requirements. 61 No state is legally required to submit a 111(d) plan, and the lone consequence for failing to submit a satisfactory 111(d) plan—imposition of a federal plan for

affected EGUs in the state—does not violate the Tenth Amendment.

1. Federal Plan

The prospect of a federal plan applying to affected EGUs in a state does not “coerce” or “commandeer” that state into submitting its ow n satisfactory 111(d) plan. In CAA section 111(d)(2), Congress required the EPA to prescrib e and implement a federal plan where states do not submit or enforce a satisfactory state plan. Aff ected EGUs in that state would thus be subject to a federal plan that sati sfies statutory requirements. 62

60 See, e.g., New York v. United States , 505 U.S. 144, 161 (1992) (citing Hodel v. Va. Surface Mining & Reclamation Assn., Inc. , 452 U.S. 264, 288 (1981)) (“Congress may not simply ‘commandeer the legislative processes of the St ates by directly compelling them to enact and enforce a federal regulatory program.’”); Printz v. United States , 521 U.S. 898 (1997) (holding the same with respec t to state officers).

61 Among other things, a federal plan will impl ement standards of performance subject to specific statutory requirements. See 42 U.S.C. § 7411(a)(1). The APA and CAA would prohibit the imposition of any federal plan that is “arb itrary, capricious, an a buse of discretion, or

otherwise not in accordance w ith law.” 5 U.S.C. § 706(2)(a). Particularly given these independent constraints on the EP A’s authority with respect to any potential federal plan, the prospect of any such plan would not commandeer states or coerce them into submitting their own state plans.

62 Among other things, a federal plan will impl ement standards of performance subject to specific statutory requirements. See 42 U.S.C. § 7411(a)(1). The APA and CAA would prohibit the imposition of any federal plan that is “arb itrary, capricious, an a buse of discretion, or

otherwise not in accordance w ith law.” 5 U.S.C. § 706(2)(a). Particularly given these independent constraints on the EP A’s authority with respect to any potential federal plan, the46 This approach is consistent with ordinary cooperative federalism regimes that federal courts have routinely upheld ag ainst Tenth Amendment challenges. 63 Among other things, this is because a federal plan would re gulate private entities, not “the St ates as States,” and there is “no Tenth Amendment impediment” when, as he re, a federal plan would regulate “private persons and businesses . . . .” 64 As the U.S. Supreme Court e xplained in upholding the federalplan aspect of another cooperative federa lism regime, the Surface Mining Control and Reclamation Act (SMCRA):

[T]the steep-slope provisions of the Su rface Mining Act govern only the activities of coal mine operators who are private individuals and businesses. Moreover, the States are not compelled to enforce the st eep-slope standards, to expend any state funds, or to participate in the fede ral regulatory program in any manner

whatsoever. If a State does not wish to submit a proposed permanent program that complies with the Act and implementing regulations, the full regulatory burden will be borne by the Federal Government. Thus, there can be no suggestion that the Act commandeers the legislative pro cesses of the States by directly compelling them to enact and enforce a fe deral regulatory program. The most that can be said is that the Surface Mining Act establishes a program of cooperative federalism that allows the States, with in limits established by federal minimum standards, to enact and admi nister their own regulatory programs, structured to meet their own particular needs. 65

The Court noted that SMCRA thus “resembles a number of other federal statutes that have survived Tenth Amendment challenges in the lowe r federal courts,” citing a case in which the Second Circuit upheld the constitutionality of the Clean Air Act against a similar challenge. 66

One constitutional scholar has noted that the “straightforward” unanimous opinion in Hodel was “nothing more than a preemption case” because the provision at issue “governed only the activities of coal mine operators who are private individuals a nd businesses”—not the states in

prospect of any such plan would not commandeer states or coerce them into submitting their own state plans.

63 See, e.g.

, Hodel v. Va. Surface Mining & Reclamation Ass’n, Inc. , 452 U.S. 264, 283–93 (1981); Texas v. EPA , 726 F.3d 180, 196–97 (D.C. Cir. 2013) (noting that “Supreme Court precedent repeatedly affirm[s] the constitutionality of federal statutes that allow States to administer federal programs but provide for direct federal administration if a State chooses not to administer it”).

64 Hodel , 452 U.S. at 287 (citing Nat’l League of Cities v. Usery

, 426 U.S. 833, 845 (1975)); cf.

Printz v. United States , 521 U.S. 898, 920 (1997) (quoting New York v. United States , 505 U.S. 144, 166 (“The Framers explicitly chose a Cons titution that confers upon Congress the power to regulate individua ls, not States.”).

65 Hodel , 452 U.S. at 288–89 (interna l citations omitted).

66 See Hodel , 452 U.S. at 289 & 30 (citing, inter alia

, Friends of the Earth, Inc . v. Carey , 552 F.2d 25, 36–39 (2d. Cir. 1977)).47 their sovereign capacity—and “the states were still free to promulgate whatever regulations they wished so long as they were not incons istent with minimum federal guidelines.” 67

A decade later, in New York v. United States , the Court reaffirmed the principle that merely offering states an opportunity to regulate , with the understanding the federal government will otherwise step in, does not “compel” the st ates to regulate—once again citing as examples pollution-control statutes administered by EPA:

[W]here Congress has the authority to regulate private activity under the Commerce Clause, we have recognized Congress’ power to offer States the choice of regulating that activity accordi ng to federal standards or having state law pre-empted by federal regulation. This arrangement, which has been termed “a program of cooperative federalism,” is replicated in numerous federal statutory schemes. These include the Clean Water Act ... [and]... the Resource Conservation and Recovery Act of 1976 . . . .

[Under these cooperative federalism regime s], as by any other permissible method of encouraging a State to conform to fe deral policy choices, th e residents of the State retain the ultimate decision as to whether or not the State will comply. [...] If state residents would pr efer their government to devote its attention and resources to problems other than those deemed important by Congress, they may

choose to have the Federal Government rath er than the State b ear the expense of a federally mandated regulatory program, and they may continue to supplement that program to the extent stat e law is not pre-empted. 68

The Clean Air Act and this rule recognize the importance of preserving the division of power between state and federal governments. 69 Congress, in enacting CAA section 111(d)(2), required the EPA to develop a reasonable federal plan to regulate affected sources where the state does not. Federal statutes and regula tions governing commerci al facilities that emit pollutants with

substantial effects on interstate commerce are we ll within the bounds of th e federal government’s Commerce Clause authority. 70 The fact that section 111(d) st ays EPA’s reasonable exercise of that constitutional power while states consider whether or not to devel op their own satisfactory plan to regulate those private entitie s does not offend the Tenth Amendment. 71

67 Laurence H. Tribe, American Constitutional Law 389–90 (2d ed. 1988).

68 New York v. United States , 505 U.S. 144, 167–168 (quoting Hodel , 456 U.S. at 289) (internal citations omitted).

69 See Printz v. United States , 521 U.S. 898, 921–22 (1997) (citing The Federalist No. 51, at 323).

70 See, e.g.

, Hodel , 452 U.S. at 282 (“[W]e agree with the lower federal courts that have uniformly found the power conferred by the Commerce Clause broad enough to permit congressional regulation of ac tivities causing air or water poll ution, or other environmental hazards that may have effects in more than one State.”).

71 Cf. NFIB v. Sebelius , 132 S. Ct. 2566, 2603 (2012) (plurality ) (“The states are separate and independent sovereigns. Sometimes they have to act like it.”).48 2. Sanctions

States that decline to take certain actions under this rule will not face the prospect of sanctions, such as withdrawn federal highway f unds. Here again, we acknowledge the general legal principle that conditions on a state’s continued receipt of federal funds can cross the constitutional line between permissible “en couragement” and impermissible “coercion.” 72 But that principle simply has no applicability here because there are no federa l funds at issue. CAA

section 111 does not contain sancti ons provisions, and we are finaliz ing revisions to the emission guidelines making explicit that the EPA will not withhold federal funds from a state on account

of that state’s failure to submit or im plement an approvable 111(d) state plan. 73

Some commenters pointed to section 110(m) as a possible source of the EPA’s sanction authority. 74 Section 110(m) grants the EPA discretiona ry authority to withhold some federal highway funds under certain cond itions. However, section 110(m) requires the EPA to adopt regulations to “establish criteria for exercising” this discretiona ry authority, and the only EPA regulations implementing section 110(m) apply to SIPs submitted under section 110. 75

The EPA never intended to even imply that we would contemplate using this authority to encourage state participation in this rule unde r section 111. To the contrary, we believe that imposition of a federal plan rather than sanctions is the appropriate path in the context of this program. Accordingly, regardless of whether th e EPA could theoretically apply discretionary sanctions against states in the section 111(d) c ontext, the rule today fo rbids the agency from exercising any such authority. We ha ve included in this rule a pr ovision that prohibits the agency from imposing sanctions in the event that a state fails to submit or implement a satisfactory plan

under this rule. As states consid er whether to take advantage of the opportunity to develop state plans, they can be assured that the EPA will not withdraw federal funding should they decline to participate. There are no “sanctions” against the States available under this rule.

3. Direct Regulation of States

72 See NFIB v. Sebelius , 132 S. Ct. 2566, 2603–04 (citing New York v. United States , 505 U.S. 144, 175 (1992); South Dakota v. Dole , 483 U.S. 203, 208, 211) (1987).

73 Some commenters alternatively claimed that emission offset requirements could constitute

sanctions that coerce states in violation Tenth Amendment. Ev en if those sanctions were somehow available pursuant to this rule—which they are not, for the reasons discussed below— those offsets would not implicate the Tenth Amendment because they are directed at the “States

as States.” See Hodel , 452 U.S. at 287 (citing Nat’l League of Cities v. Usery

, 426 U.S. 833, 845 (1975)).

74 Other commenters point to CAA section 179 as a possible direct source of this sanctions authority. However, the mandatory sanctions outlin ed in section 179 clearly apply only in the contexts of nonattainment SIPs and responses to SIP Calls made under CAA section 110(k)(5).

See 42 U.S.C. § 7509(a).

75 40 CFR 52.30 (defining “plan or plan item”).49 This rule does not promulgate a federal pla n. Even if some sources regulated by a future federal plan are owned or operated by states, such a federal plan would still not violate the Tenth Amendment because it “would not require the States in their sovereign capacity to regulate their

own citizens.” 76 In Reno v. Condon , the Supreme Court upheld a ge nerally applicable federal law that regulated states and private individuals that sold or disclosed certain personal information. Although state governments were among the entities that sold or disclosed this information, and were thus regulated by the federa l law, the Court explained that this raised no Tenth Amendment impediment because the law regul ated the states “as owners of databases,”

not in their sove reign capacity. 77 The federal law did not require st ate legislatures to enact laws or regulations, and did not require state officials to assist in th e enforcement of the federal law against private individuals. 78 Any federal plan regulating stat e-owned or state-operated EGUs would similarly not be regulating stat es in these sovereign capacities.

B. Contract Clause

Commenters raised concerns that the portf olio approach could violate the Contract Clause because “a state-driven portfolio approa ch that adopts EPA’s suggestion to use the renewable energy and RECs [renewab le energy credits] located in th e state to satisfy a state goal will take that RE [renewable energy] and RECs out of the hands of the purchaser . . . and into the

hands of the state to meet its ob jectives.” Others asserted that any regulations interfering with contractual rights would viol ate the Contract Clause.

As an initial matter, insofar as commenters are uniquely concerne d about the Contract Clause implications of the portfolio approach, those concerns are moot because the EPA is not finalizing the portfolio approach.

The Contract Clause provides that, “No Stat e shall . . . pass any . . . Law impairing the Obligation of Contracts . . . .” 79 By its terms, the Contract Cl ause does not apply to the federal government. Accordingly, commenters’ concerns a bout the Contract Clause implications of the provisions of hypothetical state pl ans are best reserved until st ate plans have actually been

submitted.

Furthermore, we note that commenters have tended to ignore the full Contract Clause analysis in their comments. The Supreme Court explained that there are two primary questions in a Contract Clause analysis. The first is whether there is a change in a state law 80 that operates

76 Reno v. Condon , 528 U.S. 141, 151 (2000).

77 Id.

78 Id. (citing New York v. United States , 505 U.S. 144 (1992); Printz v. United States , 521 U.S. 898 (1997)).

79 U.S. Const. art. I, § 10, cl. 1.

80 Again, we note that there have not yet been ch anges in state law in re sponse to this rule.50 as a “substantial impairment” of a contractual relationship. 81 “This inquiry has three components: [1] whether there is a contractual relationshi p, [2] whether a change in law impairs that contractual relationship, and [3] whethe r the impairment is substantial.” 82 Commenters have largely stopped their analysis at whether a hypotheti cal state law would “i mpair” a contract, ignoring the fact that a “ substantial impairment” typically (although not necessarily) involves a

total “destruction of c ontractual expectations.” 83 Highly regulated industries like utilities have a difficult time showing that a contract impairment is “substantial”—contractual agreements in the industry are typically formed with the expectation of additional, future government regulation. But even assuming arguendo that a hypothetical state plan pr ovision did substantially impair a contract, there is still no constitutional violati on if the law has a “legitimate public purpose,” like remedying a “broad and general social or economic problem.” 84 This requirement is to ensure that the state law is regulating in the public interest, rather than merely trying to benefit a special interest by excusing it from contr act obligations. It is likely that any generally applicable state plan would satisfy this requirement.

C. Compact Clause

Some commenters and individuals have asse rted that multi-state plans would require congressional consent pursua nt to the Compact Clause 85 or Section 102(c) of the Clean Air

Act. 86 Some commenters’ concerns flow from the fa ulty assumption that enforceable multi-state will allow states to directly enforce the terms of a binding multi-state agreement against each other, as is often the case with interstate agreements covered by the Compact Clause. These commenters and individuals are incorrect, first and foremost because they

misunderstand the nature of multi-st ate plans under this rule. As a conceptual and legal matter, the “multi-state plans” envisioned under this rule are sets of independently adopted and enforced state laws that mirror (or allow for interaction with ) other state laws. In this sense, the state laws comprising multi-state plans are nothing more than r eciprocal legislation of the sort that states have routinely enacted in consultation with each ot her, including in the context of the Clean Air Act. States are allowed to cooperate in this way without obtaining c ongressional approval under either the Compact Clause or S ection 102 of the Clean Air Act.

1. The Compact Clause does not apply

The Compact Clause provides that, “No State sh all, without the Consent of Congress . . . enter into any Agreement or Compact with another State . . . .” 87

81 General Motors Corp. v. Romein , 503 U.S. 181, 186 (citing Allied Structural Steel Co. v. Spannaus , 438 U.S. 234, 244 (1978); Energy Reserves Group, Inc. v. Kansas Power & Light Co.

, 459 U.S. 400, 411 (1983)).

82 Id.

83 Energy Reserves Group, Inc. , 459 U.S. at 411–12.

84 Energy Reserves Group, Inc. , 459 U.S. at 412

85 U.S. Const. art. I, § 10, cl. 3.

86 42 U.S.C. § 7402(c).

87 U.S. Const. art. I, § 10, cl. 3.51 Despite the provision’s superficial breadth, “not all agreements between States are subject to the strictures of the Compact Clause.” 88 Rather, the Compact Clause requires congressional consent only for a narrow subset of interstate agreements th at tend to increase “the political power in the States” in a way that encroaches upon or interferes with federal

government. 89 Thus, for example, Compact Clause concerns may arise when agreements authorize states to exercise powers they could not otherwise, or that actually delegate state sovereign power to an interstate entity or process. 90 By contrast, no congressional consent is necessary when, as here, states merely coopera te to achieve a common goal by independently adopting and enforcing state laws that mirror (or allow for interaction with) other state laws. Perhaps given the modest scope of the Compact Cl ause’s prohibition, no in terstate agreement has ever been invalidated for lacking congressional consent. 91

As noted in section VIII.C.5, the multi-state plans envisioned under this rule are, as a legal matter, coordinated sets of single-state plan s that do not enhance or diminish the sovereign authority of any state, and that do not enhan ce state power vis-à-vis the federal government. 92
Rather, the state laws comprising a multi-stat e plan are “nothing more than reciprocal legislation” 93 of the sort that states have routinely enacted in consultati on with each other, including within the context of the Clean Air Act. They do not implicate the Compact Clause.

For example, states coordinating to meet a joint CO 2 emission goal under this rule is similar to the relationship between states coordinating SIP submissions to attain the NAAQS in

an interstate nonattainment area. 94 In both cases, the states coordina te their actions in a way that,

88 See U.S. Steel Corp. v. Multistate Tax Comm’n , 434 U.S. 452, 469 & n.21 (1978); Ne. Bancorp, Inc. v. Bd. of Governors of Fed. Reserve Sys. , 472 U.S. 159, 175 (1985) (citing Virginia v. Tennessee , 148 U.S. 503, 518–19 (1893)).

89 See, e.g.

, U.S. Steel Corp. , 434 U.S. at 468, 471 (1978) (describing this rule as, “stat[ing] the proper balance between federal and state power with respect to compacts and agreements among States”); New Hampshire , 426 U.S. at 369 (quoting Virginia v. Tennessee , 148 U.S. 503, 519 (1893) (“application of the Compact Clause is limited to agreements that are ‘directed to the formation of any co mbination tending to the increase of political power in the states, which may encroach upon or interfere with the just supr emacy of the United States.’”).

90 See, e.g.

, U.S. Steel Corp. , 434 U.S. at 472–73.

91 David E. Enghdahl, Characterization of Interstate Arrangements: When is a Compact Not a Compact? , 64 M ICH

. L. R EV . 63, 69 (1965) (“[I]ndeed, in every case since Virginia v. Tennessee in which an interstate arrangement has been challenged for lack of congressional consent, it has be en held exempt from the consent requirement.”); William Funk, Constitutional Implications of Regi onal CO2 Cap-and-Trade Programs: Th e Northeast Regional Greenhouse

Gas Initiative as a Case in Point , 27 UCLA L. J. E NVTL

. L. & P OL ’ Y 353, 361 (2009) (“[O]f the hundreds of interstate agreements and compacts that have been adopted in our nation’s history not one has ever been found to have been required to have congressional consent despite numerous challenges to agreements and compacts brought in both state and federal court.”).

92 See U.S. Steel Corp. , 434 U.S. at 469 & n.21 (quoting Laurence H. Tribe, Intergovernmental Immunities in Litigation, Taxation, and Regulation: Separation of Powers Issues in Controversies about Federalism , 89 Harv. L. Rev. 682, 712 (1976)) (reciprocal stat e tax statutes do not implicate the Compact Clause because “they neither project a new presence onto the federal system nor alter any state’s basic sphere of authority”).

93 See U.S. Steel Corp., 434 U.S. at 476–77.

94 Indeed, in the 1990 Clean Air Act Amendments, Congress added section 174(c) to cl arify that, for multi-state nonattainment areas, states can jointly undertake the Act’s nonattainment planning procedures—even without an interstate compact. See 42 U.S.C. § 7504(c) (“In the case of a nonattain ment area that is included in more than one State, the affected States may jo intly, through interstate compact or otherwise , undertake and implement all or part of the planning procedures” under section 174) (emphasis added); H.R. Rep. 101-490, pt. 1, at 226 (1990) (section52 cumulatively, the measures applicable in each state will lead to achievement of a common interstate goal (with the EPA evaluating the suffi ciency and success of the plans on a holistic, interstate basis). Despite the shared goal, in both cases, the mere fact of coordination has no

effect on each state’s so vereign legal authority. 95 For example, the legally applicable rules in a given state are adopted by that state individua lly, not by a joint entity or other interstate mechanism. Similarly, the mere fact that the states coordinate their rules does not grant them the authority to directly enforce each other’s rules, or to take direct legal action against a state that is failing to implement its own rules.

Another example is provided by SIP provision s adopted to comply with the CAA’s Good Neighbor Provision 96 that allow sources in one state to e ngage in emissions trading with out-ofstate sources. 97 Although the trading provisions allow for interstate exchanges between sources, the states have direct legal authority onl y over the sources within their own borders. Furthermore, while participation in an emissions trading program may be premised on the state’s adoption of a model or uniform law, the st ate develops and submits the SIP on its own initiative—pursuant to its independent, sovere ign authority. Interstate emissions trading programs that states may which to develop under this rule similarly w ould not implicate the

Commerce Clause.

Finally, as noted above with respect to the Tenth Amendment, states cannot be legally required to implement a federal regulatory program. Should states with satisfactory state plans decide to stop implementing the plan as a ma tter of state law, the Tenth Amendment provides that they may do so, and section 111(d)(2) provides fo r federal regulation of s ources in that state. There is thus no merit to commenters’ contention that all multi-state plans would necessarily require congressional consen t under the Compact Clause.

2. Section 102(c)’s prohibition does not apply

Commenters are also off-base in their clai m that CAA section 102( c) prohibits states from forming multi-state plans. The text and st atutory context of CAA section 102(c) indicates that Congress did not intend to preempt a broade r range of state action than would otherwise require congressional consen t under the Compact Clause.

Section 102(c) is situat ed in a larger secti on entitled, “Cooperative act ivities.” The thrust

of that section—as with the Act as a whole 98 —is that where appropriate, Congress wanted to

174(c) “clarifies” that in such instances “states may jointly undertake planning procedures). Section 174(c) does not itself provide congressional consent for interstate comp acts to implement section 174’s planning requirements.

95 Cf. New York v. United States , 505 U.S. 144, 183 (1992) (“The fact that the Act, like much federal legislation, embodies a compromise among the States does not elevate the Act (or the an tecedent discussions among representatives of the States) to the status of an interstate agreement requiring Congress' approval under the Compact Clause.”).

96 42 U.S.C. § 7410(a)(2)(D)(i)(I).

97 See, e.g. , 66 FR 43795 (Aug. 21, 2001) (final action approving Pennsylvania SIP revision to allow certain Pennsylvania sources to participate in the interstate NO

x Budget Trading Program).

98 See, e.g. , CAA section 101(b)(4), 42 U.S.C. § 7401(b)(4) (declaring that purpose of the CAA is “to encourage and assist the development and operation of regional air pollution prevention and control efforts”).53 encourage interstate efforts at addressing polluti on control. For example, section 102(a) of the Act expressly directs the EPA to encourage all ma nners of cooperative ac tivities between states:

The Administrator shall enc ourage cooperative activities by the States and local governments for the prevention and cont rol of air pollutio n; encourage the enactment of improved and, so far as pract icable in the light of varying needs, uniform State and local laws relating to the prevention and control of air pollution; and encourage the making of ag reements and compacts between States for the prevention and control of air pollution. 99

It is within this context of encouraging interstate cooperation that Congress included section 102(c), which speaks only to the interstate compacts and says in relevant part:

The consent of the Congress is hereby given to two or mo re States t negotiate and enter into agreements or compacts, not in conflict with any la w or treaty of the United States, for (1) cooperative effort and mutual assistance for the prevention and control of air po llution and the enforcement of their respective laws relating thereto, and (2) the establishment of such agencies, joint or otherwise, as they may deem desirable for making effective su ch agreements or compacts. No such agreement or compact shall be binding or obligatory upon any State a party thereto unless it has been approved by Congress. 100

To the extent section 102(c) is ambiguous, EPA r easonably interprets this provision as clarifying that Congress’s encouragement of interstate cooperation in se ctions 102(a) and 102(c) does not equate to congressional cons ent to compacts where necessary under the Compact Clause. Because the multi-state plans envisioned under th is rule do not require congressional consent under the Compact Clause, they accordingly do not require special congressional action under section 102(c). EPA’s reasonabl e interpretation is based on th e context of section 102(c)— within section 102 and the Act as a whole, as described above—as well as for the additional

reasons below.

Adverse commenters tended to ignore the fi rst sentence of section 102(c), which gives express consent for states to “negotiate and en ter into” non-preempted compacts “for cooperative effort and mutual assistance for the prevention and control of air pollution and the enforcement of their respective laws relating thereto,” as we ll as to create of comp act entities that help effectuate such arrangements. 101 Members of Congress have accu rately noted that the provision

99 Id. § 7402(a).

100 42 U.S.C. § 7402(c). Section 102(c) includes a third and final sentence: “It is the intent of Congress that no

agreement or compact entere d into between States after November 21 , 1967, which relates to the control and abatement of air pollution in any air quality control region, shall provide for participation by a State which is not include (in whole or in part) in such air quality control region.” The reference to “ai r quality control region[s]” makes clear that congressional intent regardi ng this sentence concerns NAAQS pollutants. See id. § 7407(b)(1) (defining air quality control region). Because air quality co ntrol regions concern the attainment and maintenance of the NAAQS, and there are no air quality control regions under CAA section 111(d), EPA reasonably interprets this sentence as having no bearing on multi-state plans developed pursuant to this rule.

101 Id. § 7402(c).54 purports to grant consent in some inst ances where consent is not required. 102 This may be because the provision was initia lly adopted in 1955, and has not been revisited since two landmark Supreme Court opinions clarifying when the Compact Clause requires congressional

consent. 103 As discussed above, and in those case, the Compact Clause cases make clear, the Compact Clause simply does not apply to all agre ements between states, almost all of which are for cooperative effort and mutual assistance in addressing a shared concern. Accordingly, it is perhaps unsurprising that member s of Congress have suggested th at section 102(c) is “merely a restatement of the general constitutional provision a pplicable to all compacts (art. I, sec. 10) . . .

.” 104

Additionally, the second senten ce of section 102(c) does not prohibit states from engaging in any “cooperative efforts and mutual assist ance” regarding air pollution. Rather, it only withholds consent from agreements or compacts to effectuate those purposes if “such agreements or compacts” are “binding or obligatory” upon a compacting state. Whether an agreement has a power to bind a state—and thus the limit the state’s sovereign authority—is one indicia of a constitutional compact. 105

Section 102(c) is not, as some individuals have suggested, intended to preempt a broader range of interstate agreements than would be prohibited under the Compact Clause. Courts apply a presumption against preemption in this context, and Congress has spoken clearly in other parts of the Act where it intended to pr eempt otherwise lawful state action. 106 Furthermore, Congress’s titling of section 102(c) (“Consen t of Congress to compacts”) mi rrors the phraseology of the Compact Clause itself (“Consent of Congress” ). Additionally, if Congress had intended to expressly preempt certain “binding or obligatory” interstate agreements and compacts, it likely

would have said so in the firs t sentence of section 102(c), which uses preempting language to preclude states from entering into arrangements “i n conflict with any law or treaty of the United

States . . . .” 107

Alternatively, even if sec tion 102(c) unambiguously preempt s a further range of conduct than is covered by the Compact Clause—which it does not—it is inapplicable to multi-state plans

under this rule for another r eason: Section 102(c) only withholds congressional consent from “agreements or compacts” that are “binding or obligatory” upon party states, and multi-state plans are not binding or obligatory agreements or compacts between states. As explained above, multi-state plans that adopt a joint goal or allow for interstate emission trading under this rule are merely coordinated sets of coordi nated single-state plans. The fact that states may reach informal agreements prior to simultaneously submitting their plans does not render “binding or

102 H.R. Rep. No. 728, at 23–24, 30 (1967) (recommending the deletion of section 102(c) because, inter alia , “States do not require the consent of the Federal Government to enter into negotiations”).

103 See U.S. Steel Corp. v. Multistate Tax Comm’n , 434 U.S. 452 (1978); New Hampshire v. Maine , 426 U.S. 363 (1976).

104 H.R. Rep. No. 728, at 23–24, 30 (1967) (recommending the deletion of section 102(c) because, inter alia , “States do not require the consent of the Federal Government to enter into negotiations”).

105 See U.S. Steel Corp. , 434 U.S. at 468; cf. West Virginia ex rel. Dyer v. Sims , 341 U.S. 22 (1951) (applying contract law estoppel principles under an interstate compact).

106 See, e.g.

, Engine Mfrs. Ass’n v. S. C oast Air Quality Mgmt. Dist. , 541 U.S. 246 (2004) (interpreting 42 U.S.C. § 209(a)).

107 Compare 42 U.S.C. § 7402(c), with U.S. Const. art. VI, cl. 2.55 obligatory” the informal agreement itself. The onl y direct legal consequence for the state is in the act of submitting the plans for approval by EPA which, depending on whether the applicable state plan is satisfactory, can obvi ate federal regulation of sources in the state under 111(d)(2).

D. Fifth Amendment Takings Clause

Several commenters claim that this rule unconstitutionally takes private property in violation of the Takings Clause of the Fifth Amendment.

EPA has considered commenters’ hypothetical takings claims but, for the reasons set for below, has not altered this rule as a result. EPA disagrees that this rule itself constitutes a taking within the meaning of the Fifth Amendment, or that it is likely this rule will lead to widespread regulatory takings that require compensation.

The Takings Clause of the Fifth Amendmen t prohibits the federal government from taking “private property . . . for publ ic use, without just compensation.” 108 Federal courts have explained that, broadly speaking, “The purpose of the Takings Clause is to prevent ‘Government from forcing some people alone to bear public bur dens which, in all fairness and justice, should be borne by the public as a whole.’” 109 The Federal Circuit has deve loped a two-part test for determining whether this “fairness and justice” require compensation for the burdens imposed by a particular government action:

First, as a threshold matter, the court must determine whether the claimant has established a property interest for purposes of the Fifth Amendment . This is because only persons with a valid property interest at the time of the taking are entitled to compensation. [...]

Second, after having identified a valid property interest, the court must determine whether the government action at issue am ounted to a compensable taking of that property interest

. 110

Before addressing the substance of commenters ’ claims, however, it is worth noting that the remedy for an uncompensated taking is to provide the “just compensation” required by the Takings Clause—not invalidate or withhold implementation of the government action. Thus, even assuming arguendo that private entities can (1) identify a compensable property interest, and (2) demonstrate that a regulatory taking has occurred, some commenters still miss the mark by claiming that this rule must accordingly be invalidated as “ unconstitutional.” As the Supreme Court has explained, “Equitable reli ef is not available to enjoin an alleged taking of private property for a public use, duly authorized by la w, when a suit for comp ensation can be brought

108 U.S. Const. amend. V.

109 See, e.g.

, Huntleigh U.S.A. Corp. v. United States , 525 F.3d 1370, 1377 (Fed. Cir. 2008) (quoting Penn. Cent. Transp. Co. v. City of N.Y. , 438 U.S. 104, 123 (1978)).

110 Huntleigh U.S.A. Corp. v. United States , 525 F.3d 1370, 1378 (Fed. Cir. 2008) (emphasis added) (internal citations and quotations omitted).56 against the sovereign subs equent to the taking.” 111 The Tucker Act provides the exclusive avenue for aggrieved parties to seek compensation under federal statues like the Clean Air Act. 112
Furthermore, because the takings claims hypothesized by commenters would likely exceed $10,000 in amount, exclusive jurisdiction over such cl aims (should they materialize) would be in the United States Court of Claims, 113 with initial appellate review in the Federal Circuit. 114 Nor would the pendency of takings claims in those courts justify delaying implementation of this rule, given that the “Fifth Amendment does not require that compensation precede the taking.” 115

Turning to the Federal Circuit’s two-step test for determining when compensation is required by the Takings Clause of the Fifth Amen dment, the first step is for commenters to identify a compensable property interest. We agr ee with commenters that private entities may have property interests in real property, and both tangible and in tangible personal property. We note, however, that courts have held that, “Where a citizen voluntarily en ters into an area which from the start is subject to pe rvasive Government control, a pr operty interest is likely lacking.” 116
Furthermore, many of the purported property inte rests identified by commenters have been rejected by courts. To take just one example, fr ustration of business interests does not form the basis of a takings claim, particularly when th e alleged taking comes as a result of regulations directed at a third party. 117 Here too, many commenters appear to acknowledge that this rule does not itself regulate affected EGUs, but is merely establishes the framework for state plans to do

so. The fact that federal law di rected at Party A may “drastic ally reduce[] the demand” for a Party B’s services—and thus “res ult[] in adverse economic cons equences” for Party B—does not mean that the federal government has eff ectuated a “taking” of Party B’s property. 118 Nor have commenters cited any precedent for the proposition th at affected EGUs or coal companies have a property interest in the being able to emit CO 2 without regulation. 119

Assuming arguendo that legitimate property interests do exist, the second step of the Federal Circuit’s framework requires consid eration of whether th e government action ( i.e. , this rule) amounts to a compensable ta king of that property interest. A takings claim can be based on the theory of physical taking, a “total regulatory taking,” a Penn Central regulatory taking, or certain types of land exactions. 120 Commenters do not claim that this rule—or applicable 111(d)

111 Ruckelshaus v. Monsanto Co. , 467 U.S. 986, 1016 (1984) (citing Larson v. Domestic Foreign Commerce Corp.

, 337 U.S. 682, 697 n.18 (1949)).

112 See Ruckelshaus , 467 U.S. at 1016 (holding that the Tucker Act applies to private property taken pursuant to a federal statute, unless the statute withdraws Tucker Act applicability).

113 See 28 U.S.C. § 1346(a)(2); Transcapital Fin. Corp. v. Director, Office of Thrift Supervision , 44 F.3d 1023, 1025 (D.C. Cir. 1995) (noting that federal district courts do not have such jurisdiction).

114 See 28 U.S.C. § 1295(a)(3).

115 Ruckelshaus , 467 U.S. at 1016 (citing Hurley v. Kincaid , 285 U.S. 95, 104 (1932)).

116 Heart Bluff Game Ranch, Inc. v. United States , 669 F.3d 1326, 1330 (Fed. Cir. 2012).

117 See, e.g.

, Huntleigh USA Corp. v. United States , 525 F.3d 1370, 1379–81 (Fed. Cir. 2008) (discussing cases);

Omnia v. United States , 261 U.S. 502 (1923).

118 See Huntleigh USA Corp. , 525 F.3d at 1380.

119 Cf. Ruckelshaus , 467 U.S. at 1008–09 (holding that, given the highly-regulated nature of the pesticide industry, pesticide manufacturers had “no basis for a reasonable investment-backed expectation” that data submitted to EPA

would remain confidential under the Tr ade Secrets Act, even when EPA had not previously taken a position on disclosure of certain pesticide-related data).

120 Lingle v. Chevron U.S.A. Inc. , 125 S. Ct. 2074, 2087 (2005) (describing the theories of takings claims).57 plan developed under this rule—w ould result in a physical taking. 121 Rather, they claim that this rule will lead to widespread, uncompensated re gulatory takings in vi olation of the Takings

Clause of the Fifth Amendment.

There are two types of regulator y takings relevant here. Under Lucas v. South Carolina

Coastal Council , just compensation is required for regul ations that “complete ly deprive[s] an

owner of ‘ all economically beneficial us[e]’” of propert y, “except to the extent that ‘background principles of nuisance and propert y law’ independently restrict the owner’s intended use of the property.” 122 Lucas applies to a “relatively narrow” category of government regulation. 123 By contrast, regulatory challenges are ordinar ily governed by the standards set forth in Penn Central Transportation Co. v. New York City

. 124 That approach requires a ba lancing of factors including:

. . . “the economic impact of the regulation on the claimant and, particularly, the extent to which the regulation has interf ered with distinct investment-backed expectations.” In addition, the “characte r of the governmental action” -- for instance whether it amounts to a physical invasion or instead merely affects property interests through "some public program adjusting the benefits and burdens of economic life to promote the common good" -- may be relevant in discerning whether a taking has occurred. 125

Assessments of regulatory takings claims are not ordinarily done in the abstract: “[A] takings claim must be ripe,” 126 and commenters’ hypothetical ta kings claims are not.

Contrary to many commenters’ assertions, this rule does no t establish emission standards for any affected EGU. This rule does not require EGUs to retire, to reduce utilization, or impose any regulatory requirements on EGUs at all. Rath er, emission standards applicable to affected EGUs will be found in as-yet undeveloped state or federal plans. 127 This rule—the only regulatory action present at this state—merely establishes (1) state-specific CO 2 goals reflecting

CO 2 performance rates based on the BSER, and (2) guidelines for the development, submittal and implementation of states plan s that will implement those CO 2 performance rates.

As noted throughout the preamble, both states an d utilities have substa ntial flexibility and latitude in the manner of achieving the emissi on reductions resulting from implementation of these guidelines. Accordingly, it is simply too early in the process to claim that any takings will necessarily materialize. For exam ple, it is not yet know what em ission standards will apply to

121 A physical taking involves the government physically taking possession of an interest in property, and always requires compensation. Tahoe-Sierra Pres. Council v. Tahoe Reg’l Planning Agency , 535 U.S. 302, 323 (2002); Loretto v. Teleprompter Manhattan CATV Corp. , 458 U.S. 419 (1982).

122 Lingle v. Chevron U.S.A. Inc. , 125 S. Ct. 2074, 2081 (quoting Lucas v. South Carolina Coastal Council , 505 U.S. 1003, 1019, 1026–32 (1992)) (emphasis and second alteration in original).

123 Id.

124 438 U.S. 104 (1978).

125 Lingle , 125 S. Ct. at 2081–82 (quoting Penn Central , 438 U.S. at 124).

126 Palazzolo v. Rhode Island , 533 U.S. 606, 618 (2001) (citing Williamson Cnty. Reg'l Planning Comm’n v. Hamilton Bank of Johnson City , 473 U.S. 172 (1985)).

127 See 42 U.S.C. § 111(d)(1), (2).58 any specific EGUs; or whether such standards wi ll apply by virtue of a state or federal plan; 128 or how individual EGUs will otherwise comply with the emission standards (including whether the future applicable plan will allow EGUs to acquire credits or allowances). In the takings context, it is important to wait for the final decision a ffecting a regulated entity, as the U.S. Supreme Court has explained in the c ontext of land-use regulations:

[A] takings claim challenging the app lication of land-use regulations is not ripe unless the government entity charged w ith implementing the regulations has reached a final decision regarding the app lication of the regulations to the property at issue . A final decision by the responsi ble state agency informs the

constitutional determination whether a re gulation has deprived a landowner of all economically beneficial us e of the property [under Lucas ], or defeated the reasonable investment backed expectations of the landowner to the extent that a taking has occurred [under Penn Central ]. 129

This importance of waiting for f acts to develop is partially becau se determining the existence of a taking is, “essentially an ‘ad hoc, factual’ inquiry.” 130 It is thus “particularly important” that courts not decide constitutional takings claims “except in an actual factual setting that makes such a decision necessary.” 131 The weight of the Penn Central factors—and thus the outcome of the balancing test—turns on cri tical facts that can differ betw een EGUs, or depending on the emission standards applicable to an EGU thr ough (currently non-existent) state or federal plans. 132 (For the same reasons, it is too early for commenters to claim that they have been partially or fully deprived of a property interest in coal-reserves, or of the real property where

affected EGUs are located. 133 )

The prematurity of these takings argument s are further evidenced by the separate requirement in Takings Clause cases that part ies must typically avail themselves of any opportunities to “obtain administrative relief,” which might result in “a mutually acceptable

128 This is an important distinction given that commenters’ assert takings under the Fi fth Amendment, which applies only to the federal government, whereas the Clause applies to state governments through the Fourteenth

Amendment. See Chicago, B. & Q. R. Co. v. Chicago , 166 U.S. 226 (1897).

129 Palazzolo v. Rhode Island , 533 U.S. 606, 618 (2001) (emphasis added) (internal quotations and citations omitted).

130 See Ruckelshaus , 467 U.S. at 1005 (quoting Kaiser Aetna v. United States , 444 U.S. 164, 175 (1979)).

131 Hodel v. Va. Surface Mining & Reclamation Assn., Inc. , 452 U.S. 264, 294–95 (1981).

132 For example, the “economic impact” factor could differ dramatically depending on whether a hypothetical

emission standard results in 1% reduced utilization vers us 99% reduced utilization. Similarly, the utility power sector—“an industry that has long been the focus of great public concern and significant government regulation”— should have expected the substantial probability that the Clean Air Act would be used to regulate CO 2

. Cf.

Ruckelshaus , 467 U.S. at 1008–09 (holding that, given the highly-regulated nature of the pesticide industry, pesticide manufacturers had “no basis for a reasonable investment-backed expectation” that data submitted to EPA

would remain confidential under the Tr ade Secrets Act, even when EPA had not previously taken a position on disclosure of certain pesticide-related data)

. Nevertheless, the possibility exists that some EGUs within this highly regulated industry can, because of unique factual circ umstances, demonstrate the existence of reasonable investment-backed expectations. At this stage of the process, howev er, all that exists are hypothetical state plans applying hypothetical emission standards against hypothetical EGUs with hypothetical backgrounds.

133 Cf. Hodel , 452 U.S. at 296–97 & nn.37–38 (rejecting a facial challenge to a federal statute that “does not categorically prohibit coal mining” or “p urport to regulate alternative uses to which coal-bearing lands may be put”).59 solution” that would “obviat[e] the need to address the constitutional questions.” 134 EGUs cannot pursue administrative relief from emission sta ndards that do not exist. All that exists are hypothetical state plans applyi ng hypothetical emission stan dards against EGUs with hypothetical investment-backed expectations. Co mmenters’ taking arguments are simply not ripe.

XI. Example of Reduced Utilization: Permit Limits

This section supports section V.B.5. of the preamble by providing additional examples of CAA regulations that incorpor ate reduced production as a method for achieving emissions limitation and permits in which fossil fuel-fired EGUs accepted limits on generation to achieve

emissions limitations.

A. Limits on Potential to Emit

Stationary sources that emit or have the poten tial to emit a pollutant equal to or above specified major source thresholds are subjec t to major source requirements under the CAA. See,

e.g., CAA §§ 302(j) (defining “major stationary source” and “major emitting facility”), 112(a)(1) (defining “major source” with respect to hazar dous air pollutants), 169(1) (defining “major emitting facility” for purposes of prevention significant deterioration [PSD] permitting). For this reason, the determination of a source’s potential to emit, or PTE, often play s a critical role in determining what CAA requirements apply to a source. PTE is a si gnificant factor in determining applicability of major source requirements for th e program to control hazardous air pollutants (HAPs) under CAA § 112, the operating permits program under title V of the CAA, the PSD permitting program under part C of title I, and Nonattainment New Source Review (NNSR) permitting program under part D of title I. See CAA §§ 112(a)(1), 112(d)(1), 165(a), 169(1), 172(c)(5), 173(a) & (c), 501(2), 502(a), 302(j).

EPA regulations similarly make clear that P TE is a significant factor in determining applicability for certain CAA programs. For exampl e, the applicability provisions for the federal PSD permitting program state that PSD requireme nts apply to construction of “any new major stationary source” in an area designated as attain ment or unclassifiable, 40 CFR 52.21(a)(2), and define “major stationary source” as a stationary source that “emits or has the potential to emit” at least 100 tons per year for any source in a listed source category or 250 tons per year for any source, 40 CFR 52.21(b)(1)(i)(a-b). See also 40 CFR 70.3(a)(1) and 71.3(a)(1) (major source applicability under the regulat ions for the title V permitting programs); 40 CFR 70.2 and 71.2 (definition of “major source” for title V, which in cludes PTE thresholds that qualify a source as a major source if exceeded).

Not surprisingly, given its role in these CAA programs, PTE is defined several places in the EPA’s regulations, and these regulations expressly recognize th at certain sources may take

enforceable restrictions on util ization, specifically including limitations on hours of operation.

134 Hodel , 452 U.S. at 297.60 The regulations for the PSD program for permits issued under federal authority, for instance, define “potential to emit” as:

the maximum capacity of a stationary sour ce to emit a pollutant under its physical and operational design. Any physical or operational limitation on the capacity of the source to emit a pollutant, including air pollution control equipment and restrictions on hours of operation ... shall be treated as part of its design if the limitation or the effect it would have on emissions is federally [135] enforceable. ...

40 CFR 52.21(b)(4) (regulations for federal PSD permitting program) (emphasis added). Several other CAA programs have materially similar PTE definitions. See 40 CFR 51.166(b)(4) (addressing SIP-approved PSD programs), 51.165(a)(1)(iii) (addressing SIP-approved NNSR programs), 70.2 (addressing title V operating permit programs), and 63.2 (hazardous air pollutants). As the EPA’s Environmental A ppeals Board, or EAB, has summarized, “PTE reflects a source’s maximum emissions capacity considering the application of any emission control equipment, or other capac ity-limiting restrictions, that effectively and enforceably limit emissions capacity.” 136

For decades, EPA has recognized that source s that would otherwise exceed the major source threshold for a pollutant may accept limits to reduce the capacity to emit that pollutant and to consider those limits in calculating PTE fo r that pollutant, so long as those limits satisfy enforceability criteria. 137 In this way, if the source accepts an enforceable limit that restricts its capacity to emit a pollutant below the relevant threshold, the source avoids triggering major

135 Although the federal definition of PTE for PSD includes the term "federally enforceable," EPA has clarified that the term "federally enforc eable" as used in rela tion to the definition of PTE for the federal PSD program in 40 C.F.R. 5 2.21(b)(4) should be read to mean "federally enforceable or legally and practicably enfor ceable by a state or local air pollution control agency." Memorandum from John Seitz, Director, Of fice of Air Quality Planning and Standards, and Robert Van Heuvelen, Director, Office of Re gulatory Enforcement, Release of Interim Policy on Federal Enforceability of Limitations on Potential to Emit at 3 (Jan. 22, 1996), available at http://www.epa.gov/ region07/air/nsr/nsrmemos/potto emi.pdf. The term "federal enforceability" has also been interpreted to require practical enforceability. See, e.g., In re Shell Offshore, Inc., Kulluk Drilling Unit and Frontier Discoverer Drilling Unit , 13 E.A.D. 357 at 394, n.54 (EAB 2007).

136 In re Shell Offshore, Inc. , 15 E.A.D. __ , Slip. Op. at 17 (EAB 2012) (citations omitted).

137 See, generally, Memorandum from Terrell Hunt, Assoc. Enforcement Counsel, U.S. EPA, & John Seitz, Director, Stationary Source Compliance Div., U.S. EPA, Guidance on Limiting Potential to Emit in New Source Permitting, at 1-2, 6 (June 13, 1989), (“ 1989 PTE Guidance ”), available at http://www.epa.gov/region07/air/ nsr/nsrmemos/lmitpotl.pdf; Memorandum from John Seitz, Dir., Office of Air Quality Planni ng & Standards, U.S. EPA, & Robert Van Heuvelen, Dir., Office of Re gulatory Compliance, to EPA Reg’l Air Div. Dirs., Options for Limiting the Potential to Emit (P TE) of a Stationary Source Unde r Section 112 and Title V of the Clean Air Act (Act) ( “Options for Limiting PTE” ) (Jan. 25, 1995), available at http://www.epa.gov/region7/air/titl e5/t5memos/ptememo.pdf.61 source obligations for that pollutant and obviates the associated requirements. This type of PTE limit is frequently called a synt hetic minor limit, and it has become a well-es tablished tool under several major source CAA programs. 138 The use of such PTE limits for sources has been recognized by the EPA in guidance documents, 139 rulemaking notices, 140 and orders signed by EPA Administrators responding to petiti ons for objection to title V permits, 141 by the EAB in considering permit challenges, 142 and by federal courts. 143

138 See, e.g., In re Shell Offshore, Inc. , 15 E.A.D. __ , Slip. Op. at 18 n.15 (EAB 2012) (quoting a definition of “synthetic minor” in EP A guidance and prior EAB decisions). See also 40 CFR 49.152 (defining “synthetic minor source” for purposes of EPA’s minor new source review permitting program for sources on Indian Country).

139 See, e.g., 1989 PTE Guidance at 1-2; Options for Limiting PTE at 1-2; U.S. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases , at 8 (Mar. 2011), EPA-457/B-11-001, available at http://www.epa.gov/ nsr/ghgdocs/ghgpermittingguidance.pdf.

140 See, e.g., 45 FR 52689 (Aug. 7, 1980) (NSR rulemaking noting that availability of PTE limits in permit conditions addressed concerns raised concerning peak load units, among others); 67 FR 80188 (Dec. 31, 2002) (NSR rulemaking); 61 FR 34,211-12 (July 1, 1996) (Title V Part 71 rulemaking).

141 See, e.g., In re Orange Recycling and Ethanol Producti on Facility, Pencor Masada Oxynol,

LLC , Petition No. II-2001-05, at 4-10 (April 8, 2002), available at: http://www.epa.gov/Region7/air/title5/pe titiondb/petitions/m asada-2_decision2001.pdf (denying petition’s request to object to title V permit based on alle ged flaws with PTE limits); In re Columbia University , Petition No.: II-2000-08, at 33- 35 (Dec. 16, 2002), available at: http://www.epa.gov/Region7/air/title5/petiti ondb/petitions/columbia_university_decision2000.pd

f (recognizing availability of PTE limits, but granti ng petition’s request to object to title V permit where PTE limits were not adequately enforceable); In re Hu Honua Bioenergy LLC , Petition No.: IX-2011-1, at 9-14, 16- 19 (Feb. 7, 2014), available at http://www.epa.gov/Region7/air/title5/pe titiondb/petitions /hu_honua_decision2011.pdf (recognizing availability of PTE limits and granti ng petition’s request to ob ject to title V permit for proposed bioenergy electricity generating facility where PTE limits for criteria pollutants and HAPs were not adequately enforceable); In the Matter Of Cash Creek Generation, LLC, Petition No. IV-2010-4 at 14-15 (June 22, 2012), available at http://www.epa.gov/Region7/air/title5/pet itiondb/petitions/cas hcreek_response2010.pdf (granting in part and denying in part requests for objections base d on alleged flaws in PTE limits for a new coal gasification facility and co-located natural gas combined cycle plant). In granting objections in some of these title V orders, the EP A did not in any way diminish the viability of a PTE limit as a means of restricting utilization to ensure compliance. Rather, these objections were based on specific flaws that arose in these particular permitting actions.

142 See, e.g., In re Shell Offshore, Inc. , 15 E.A.D. __ , Slip. Op. at 18 n.15 (EAB 2012) (citing In re Shell Offshore, Inc., Kulluk Drilling Unit and Frontier Discoverer Drilling Unit , 13 E.A.D. 357, 366 (EAB 2007) and In re Peabody Western Coal Co. , 12 E.A.D. 22, 26 & n.11, 31. (EAB 2005)).

143 See, e.g., United States v. Louisiana-Pacific Corp ., 682 F. Supp. 1122, 1132-33 (D. Colo. 1987); Weiler v. Chatham , 392 F.3d 532 (2d Cir. 2004) (“In short, then, a proposed facility that is physically capable of emitting major levels of the relevant pollutants is to be considered a62 Thus, the EPA and state and local air permitting authorities generally have broad authority to establish such capaci ty-limiting restrictions for sources that request them, as long as the restrictions are adequately enforceable. Th ese restrictions may, generally speaking, be established through a variety of mechanisms, including rules, general permits, and sourcespecific permits. 144 Accordingly, the use of PTE limits or synthetic minor limits for stationary sources is widely available and well accepted by both air agencies and sources.

One well-established means of establishing a PTE limit or synthetic minor limit is by taking an enforceable restricti on that limits utilization, such as a limit on the hours of operation

of an emissions unit. Such PTE limits that restri ct hours of operation are pa rticularly relevant for the § 112 program and the title V, PSD, and NNSR permitting programs. The implementing regulations for those programs specifically provide for such limits, and treat them as equivalent

to other enforceable restrictions on emissions , such as requirements for pollution control equipment. As noted above, in relevant part, EPA regulations provide that “[a]ny physical or operational limitation on the capacity of the sour ce to emit a pollutant, including air pollution control equipment and restrictions on hours of operation ” is considered in determining PTE “if

the limitation or the effect it would have on em issions” is enforceable as a legal and practical matter. 40 CFR 52.21(b)(4) (regulations for federa l PSD permitting program) (emphasis added). The other CAA programs mentioned above have materially similar provisions in the corresponding PTE definitions. 145 Under these regulatory prov isions, a source can take an enforceable limitation on hours of operation that ha s the effect of restri cting actual emissions below the relevant threshold, and by complying with that limit, the source also complies with the CAA by avoiding triggering the corresponding HAP, PSD, NNSR, or Title V requirements. Such a limit on the hours of operation would also restrict utilization. By acknowledging that

PTE limitations include both “air pollution control equipment” a nd “restrictions on hours of operation,” these regulations treat reduced ut ilization and emission controls as equally cognizable means of restric ting potential emissions and avoiding CAA obligations.

major emitting facility under the Act unless there are legally and practicably enforceable mechanisms in place to make certain that the emissions remain below th e relevant levels.”).

144 Memorandum from Kathie A. Stein, Dir ector, Air Enforcement Division, Office of Enforcement and Compliance Assurance, to Regional Air Directors, Guidance and Enforceability Requirements for Limiting Po tential to Emit through SIP and § 112 Rules and

General Permits , at 2-5 (Jan. 25, 1995), available at http://www.epa.gov/region07/air/title5/t5memos/potoem.pdf ; Options for Limiting PTE at 3-5.

145 See 40 CFR 51.166(b)(4) (addressing SIP appr oved PSD programs), 51.165(a)(1)(iii) (addressing SIP approved NNSR programs), 70.2 (a ddressing title V opera ting permit programs), and 63.2 (hazardous air pollutants). The EPA, or a tribal agency operatin g under delegation, also has authority to issue synthetic minor permits to sources in Indian Country under 40 CFR 49.158, including synthetic minor HAP permits, a nd those permit may contain enforceable limitations on the hours of operation or other operational restrictions. See 40 CFR 49.152(d) (definitions of PTE a nd reviewing authority).63 Furthermore, the EPA has also specifically recognized reduced utilization, particularly limits on the hours of operation, as a mechanism to limit PTE in various documents. In a memorandum setting forth types of restrictions that may limit PTE, for example, the EPA stated “[r]estrictions on production or operation that will limit potential to emit include limitations on quantities of raw materials consumed, fuel combusted, hours of operation, or conditions which specify that the source must install and maintain controls that reduce emissions to a specified emission rate or to a specified efficiency level.” 146 As with the regulatory provisions discussed above, this statement treats restrictions on hours of operation and re quirements to install pollution controls as comparable means of reducing capacity and limiting potential emissions. The EAB has likewise acknowledged EPA’s authority to impose limits on hours of operation to

serve as a PTE limit. 147 Federal courts have also determin ed that limits on the hours of operation are properly considered in the calculation of a source’s PTE. United States v. Louisiana-Pacific Corp ., 682 F. Supp. 1122, 1133 (D. Colo. 1987).

Synthetic minor limits, includi ng limits on utilization, are ava ilable for EGUs in the same way as they are for any other stationary source. EPA is aware of numer ous instances in which EGUs have taken limits on utilization, and in pa rticular limits on hours of operation, as a means of avoiding triggering particular CAA requirements. Sources may also take such limits to comply with requirements under the CAA. Such lim its have been used by EPA when it has acted as the permitting authority for sources 148 , as well as by state or local agencies acting in their capacity as permitting authorities. 149 Several examples of such pe rmits are highlighted in this Memorandum. A more extensive list of examples of permits containing such limits is included in supporting tables contained in Section XI.C of this Memorandum. These examples illustrate that taking enforceable limits on utilization is a viable means of complying with, or obviating CAA, obligations for EGUs.

146 1989 PTE Guidance , at 6 (emphasis added).

147 In re Shell Offshore, Inc. , 15 E.A.D. __ , Slip. Op. at 25-27 (EAB 2012) (quoting 1989 PTE Memorandum and denying a challenge to an em issions-based PTE limit where, among other things, Petitioners had not addressed the opera tional limits in the permit issued by EPA, including hourly operational li mits on certain activities)

. 148 See, e.g., GHG PSD permit for Shady Hills Genera ting Station, Permit No. PSD-EPA-R4013 (EPA Region 4, 1/13/2014), Condition IX.B.2 at p. 6 of 14 (“If both EU 005 and 006 [combustion turbines] are constructed, they sha ll not operate an aver age of more than 3,390 hours per year per combustion turb ine on a 12-month rol ling total basis. No single unit shall operate more than 5,000 hours per year on a 12 -month rolling total ba sis. If only one combustion turbine is installed, it shall operate no more than 3,390 hours per year on a 12 month rolling total basis. Permittee shall monitor and record the number of hours each combustion turbine operates monthly and totaled ever y month for the previous 12 months.”).

149 See, e.g., PSD Permit for Tampa Electric Company, Polk Power Station, Permit No. PSD-FL263 (Fl. Dept. Env. Prot., 10/8/1999), Gene ral Operating Condition 13 at p.15 of 219, (“Maximum allowable hours of operation for e ach unit are 4,380 hours per year on natural gas and 750 hours per year on fuel oil.”)64 If a source does not take an enforceable limit on hours of operation, its PTE is calculated based on its maximum capacity, which is ge nerally 8760 hours per year (i.e., 24 hours a day multiplied by 365 days a year). Sources may take limits below this level to avoid PSD permitting requirements. For example, Sunbury Generation LP in Pennsylvania obtained a minor new source preconstruction permit, called a plan approval, for a repowering project from the Pennsylvania Department of Environmental Protection in 2013 that limited the hours of operation of three combined cycle combustion turb ines that were planned for construction below 8760 hours in any 12 month consecutive period in order to remain below the significance

threshold for GHGs. 150 Similarly, Manitowoc Public Utiliti es in Wisconsin obtained a title V renewal permit that limited the operating hours of the single simple-cycle combustion turbine to not more than 194 hours per month, averaged over any consecutive 12 month period, as part of limiting its potential to emit for volatile organi c compounds below the title V threshold of 100 tpy, and carbon monoxide, nitrogen oxides and sulf ur dioxide below the PSD threshold of 250

tpy. 151

Similarly, to avoid triggering NNSR requi rements for NOx and VOC. NTE Ohio, LLC

obtained a Final Permit-to-Install for the Middletown Energy Center that included utilization limits on the auxiliary boiler (as an annual lim it on fuel consumption and emission limits for NOx and VOC) 152 and on the emergency generator (as an annual limit of 500 hours of operation

150 See Plan Approval No. 55-00001E for Sunbury Ge neration LP (Pa. Dept. Env. Protection, 4/1/2013), Conditions #016 on pp. 24, 32 and 40 of 48 (limiting turbine units to operating no more than 7955, 6920, or 8275 hours in any 12 consecu tive month period de pending on which of three turbine options was selected); Me morandum from J. Piktel to M. Zaman, Addendum to Application Review Memo for the Repowering Project (Pa. Dept. Env. Protec tion, 4/1/2013) at p. 2 of 10 (noting that source ha d “calculated a maximum hours pe r year (12 consecutive month period) of operation for the sour ces proposed for each of the turbin e options in order to remain below the significance threshold for GHGs.”).

151 See Final Operation Permit No. 436123380-P10 for Ma nitowoc Public Utilitie s - Custer Street (Wis. Dept. Nat. Res., 8/19/2013), Condition ZZZ.1.a (1) at p. 9 of 14 (limiting potential to emit) and n. 11 (“These conditions are established so th at the potential emissi ons for volatile organic compounds will not exceed 99 tons per year and potential emissions for carbon monoxide, nitrogen oxides and sulfur dioxide emissions from the facility will not exceed 249 tons per year.”). See also Analysis and Preliminary Determination for the Renewal of Operation Permit 436123380-P10 (Wis. Dept. Nat. Res., 5/21/2013) at p. 5 of 6 (noting that the “existing facility is a major source under Part 70 because potential em issions of sulfur dioxi de, nitrogen oxides and carbon monoxide exceed 100 tons per year. The existing facility is a minor source under PSD

and an area source of federal HAP” and further noting that after renewal, “the facility will continue to be a major source under Part 70 be cause potential emissions of sulfur dioxide, nitrogen oxides and carbon monoxide exceed 100 tons per year. The facility will also continue to

be a minor source under PSD and an ar ea source of federal HAP.”).

152 See Final Permit to Install No. P0116610 for NTE Ohio, LLC (OhioEPA, 11/5/2014), Condition 1.b)(1)d. at p.22 of 87 (imposing s ynthetic minor to avoid NNSR for NOx and VOC by providing that NOx emissions for the emissi on unit shall not exceed 3.30 TPY and that VOC emissions shall not exceed 1.50 TPY, both base d on a rolling 12-mont h summation); Condition65 and emission limits for NOx and VOC), 153 as well as emission limits on the combustion turbine and heat recovery steam ge nerator with duct burners. 154 This permit also contains conditions explaining that the limits on the amount of NOx and VOC that may be emitted by the auxiliary boiler and the emergency generator are derived from and reflect the limits on utilization of those

units. 155 This demonstrates that emission limits ma y also restrict utiliz ation, depending on how

the emission limit was calculated.

Synthetic minor limits may also be taken to avoid requirements of the title V operating permit program. For example, City Center West in Wisconsin obtained a state operating permit when it proposed to modify its emergency generato rs so that they could provide electric power to the grid, thus making them peak shaving generators. 156 In that permit, it accepted a limit that restricted each generator to operating no more than 16.66 hours per month, averaged over any 12 consecutive months, in order to keep its PTE for NOx below the 100 tpy major source threshold for purposes of the title V operating permit program. 157

For construction that triggers PSD permitting requirements, the CAA requires, among other things, that the proposed new source or major modification be subject to best available control technology (BACT) for each pollutant subj ect to regulation under the Act that it will emit. CAA § 165(a)(4). Permitting authorities ha ve used limits on util ization as part of establishing BACT limits for EGUs. For exampl e, in the PSD permit for Antelope Elk Energy

1.b)(2)k. at p. 25 of 87 (“The maximum annual fuel consumption for this em issions unit shall not exceed 600,000 MMBtu per rolling, 12-month peri od. ....”); and Condition 1.f)(1)b & e at p. 27- 29 of 87 (explaining relationship between th e emission limitations and the annual fuel consumption limit correlate).

153 Id. , Condition 3.b)(1)c. at p. 63 of 87 (imposing synthetic minor to avoid NNSR for NOx and VOC by providing that NOx emissions for the emission unit shall not exceed 7.25 TPY and the VOC emissions shall not exceed 0.26 TPY, both based on a rolling 12-month summation); Condition 3.b(2)e. at p. 65 of 87 (“The maximu m annual operating hours for this emissions unit shall not exceed 500 hours, based upon a rol ling, 12-month summation of the operating hours. ...”); and Condition 3.f)(1)b & e at p. 69-70 of 87 (explaining relationship between the tpy

emission limitations and the a nnual fuel consumption limit).

154 Id. , Condition 2.b)(1)b at p. 33 of 87 (imposing synthetic minor to avoid NNSR for NOx and VOC by providing that NOx emissions for the emission unit shall not exceed 88.4 TPY and the VOC emissions shall not exceed 92.3 TPY, both based on a rolling 12-month summation).

155 Id. , Condition 1.f)(1)b & e at p. 27-29 of 87, Condition 3.f)(1)b & e at p. 69-70 of 87.

156 See Analysis and Preliminary Determination fo r the Construction and Operation Permits for the Proposed Modification of Two Diesel Electric Generators for City Center West (Wis. Dept. Nat. Res., 3/12/2007) at p. 3 of 13.

157 FESOP (Synthetic Minor, Non-Part 70) – Final Permit, Permit No. 113225200-F01 for City Center West (Wis. Dept. Nat. Res., 4/19/2007), C ondition I.A.2(2) at p. 4 of 15 (“Each generator may not be operated for more than 16.66 hour s per month, averaged over any 12 consecutive months. This limit is proposed by the permittee to be minor for Part 70.”). See also id . at n.2 (“This limit will keep the facility NO x potential to emit (PTE) less than 100 tons per year, the Part 70 major source threshold leve l in ch. 407, Wis. Adm. Code.”).66 Center, EPA Region 6 limited the turbine to 4,572 operational hours on a 12 month rolling

basis. 158 Likewise, in order to ensure that the Rockgen Energy Center could meet its BACT emission limits for several pollutants, the state permitting authority limited each of the combustion turbine processes to operating less than 3800 hours in any 12 consecutive months,

with an additional limit on the hour s fired with distillate fuel. 159

In addition, permitting authorities have impos ed limits on the utilization of EGUs to protect the NAAQS. For example, a title V rene wal permit for Madison Gas & Electric Co.’s Blount Street Generating Station took limits on the operating hours fo r a boiler in order to protect the NAAQS for nitrogen oxides. 160

B. Title V permit limits

Among other things, title V of the CAA requi res all major stationary sources of air pollution and certain other sources to apply for a title V operating permit that includes emission limitations and other conditions as necessary to as sure compliance with applicable requirements of the CAA. CAA §§ 502(a), 503(a) , 503(c), 504(a). The title V operating permit program is a vehicle for ensuring that air quali ty control requirements are appr opriately applied to facility emission units and for assuring compliance with such requirements, but does not generally impose new substantive air quality control requirements. The tit le V program is implemented through regulations promulgated under 40 CFR pa rt 70 for programs implemented by state and local agencies and tribes, and 40 CFR part 71 for programs generally implemented by the EPA. The title V program expressly authorizes permitting authorities to impose operational requirements on sources to ensure compliance with applicable requi rements under the CAA, including any requirement under section 111. Sec tion 504(a) of the CAA requires in pertinent part that each permit issued under title V “sha ll include enforceable emission limitations and

standards ... and such other conditions as are ne cessary to assure compliance with applicable

158 PSD Permit for Antelope Elk Energy Center, Permit No. PSD-TX-1358-GHG, (EPA Region 6, 6/2/2014), Condition III.A.2.d at p. 7 of 14 (“The turbine is limited to 4,572 operational hours on a 12-month rolling total basi s.”); Condition III.A.2.a at p. 7 of 14 (“The BACT limit of 1,304 lbs of CO2/MW-hr gross output is based on a 4,572 rolling operational hour average basis ....”).

159 Title V Renewal Permit for Rockgen Energy Center, LLC, Permit No. 113308030-P10 (Wis. Dept. Nat. Res., 2/4/2010), Condition I.C.1(1) at p. 29 of 55, (“Each of the three combustion turbine processes (P01, P02, and P03) may not be operated more than 3800 hours in any 12

consecutive months of which not more than 800 hours in any consecutive 12-month period shall

be on distillate fuel oil with less than 0.05% sulf ur by weight. This condition is necessary to meet the BACT emission limits for sulfur dioxide, carbon monoxide, nitrogen oxides, particulate matter, volatile organic compounds and sulfuric acid (mist).”)

160 Title V Renewal Permit for Madison Gas & Elec tric Co. - Blount Stre et Generating Station, Permit No. 113004430-P20 (Wis. Dept. Nat. Res., 6/30/2015), Condition I.A.3.1 at p. 6 of 75 (“The operating hours for boiler B22 may not exceed 5,100 hours during each 12 consecutive month period.[FN 1].” FN 1 st ates: “The operating hour limitations are necessary to ensure that the national ambient air quality standard for ni trogen oxide is attained and maintained.” )67 requirements” under the CAA. “Emission limitation” is defined in CAA § 302(j), in relevant part, as “a requirement established by the State or Administrator which li mits the quantity, rate,

or concentration of emissi ons of air pollutants on a continuous basis, including any requirement relating to the operation ... of a source to assure c ontinuous emission reduction, and any ... operational standard promulgated under this chapter.” (Emphasis added.) The implementing regulations specifically state that title V perm its may include “operational requirements and limitations,” and makes clear that those operational requirements can “assure compliance with ... applicable requirements....” 161 The regulations define “applicab le requirements” to include any new source performance standards or other requirement under CAA § 111. 162

As the EAB has observed, title V permits may function as vehicles for permitting

authorities to establish enforceable limits that re strict PTE, thus allowing sources to qualify as synthetic minor sources for major source requireme nts that would otherwise apply without such

a limit. 163 Indeed, the section of this Memorandum above discussing utilization limits in EGU permits and the supporting tables contained in S ection XI.C of this Memorandum that contain additional examples of permits with such limits both include several ex amples of utilization limits that were taken in title V permits. The authority to impose this type of limit provides permitting authorities with a tool to ensure compliance with requirements under the CAA by establishing enforceable requirements that prev ent an applicable requirement from being triggered in the first instance. Thus, these t ypes of limits increase flexibility for permitting authorities and for sources that can keep actual emissions below the relevant thresholds, as well as providing an incentive to do so. Some sources , rather than taking such limits in a title V permit, take synthetic minor limits to avoid be ing subject to requirements under title V, which include permitting requirements and title V fees. Whether the limit is taken in a title V permit or

to avoid title V obligations, however, I illustrate that taking enforceable limits on operations is a

viable means for sources such as EGUs to use reduced utilization to co mply with, or obviate, CAA obligations.

161 40 CFR 70.6(a) (“ Standard permit requirements . Each permit issued under this part shall include the following elements: (1) Emissions limitations and standa rds, including those operational requirements and limitations that assure compliance with all applicable requirements at the time of permit issuan ce....” (emphasis added)). See also 40 CFR 71.6(a) (same).

162 40 CFR 70.2 (defining applicable requirement to include “(3) Any standard or other requirement under section 111 of the Ac t, including sect ion 111(d); ....”). See also 40 CFR 71.2 (same).

163 In re Shell Offshore, Inc. , 15 E.A.D. __ , Slip. Op. at 18 (EAB 2012) (citing In re Peabody

Western Coal Co. , 12 E.A.D. at 31 & n.21 (EAB 2005)).68C. Examples of Permits Requiring Reduced Utilization at EGUs164Facility name Location offacilityType of EGU Type ofpermitPermitnumberPermit authorityissuing permitDate permitsigned orissuedText of permit condition containingutilization limitWeb address wherepermit can be found, ifavailable, and pagecitation for limitShady HillsGenerating StationPasco County,FloridaPeaking plant;permit authorizedconstruction oftwo simple cyclecombustionturbines (naturalgas with backupfuel of ULSDfuel oil)GHG-onlyPSD permitPSD-EPAR4013EPARegion 41/13/2014 Condition IX.B.2: If both EU 005 and 006[combustion turbines] are constructed, theyshall not operate an average of more than 3,390hours per year per combustion turbine on a 12-month rolling total basis. No single unit shalloperate more than 5,000 hours per year on a 12-month rolling total basis. If only onecombustion turbine is installed, it shall operateno more than 3,390 hours per year on a 12month rolling total basis. Permittee shallmonitor and record the number of hours eachcombustion turbine operates monthly andtotaled every month for the previous 12 months.http://www.epa.gov/region4/air/permits/ghgpermits/shadyhills_ghg.htmlPage 6 of 14Tampa ElectricCompany, PolkPowerStationPolk County,Florida260 MWintegrated coalgasification andcombined cycleturbine unit;permit added twodual fuel simplecycle combustionturbinesPSD PSD-FL-263 Florida DEP 10/8/1999General Operation Requirements13. Maximum allowable hours of operation foreach unit are 4,380 hours per year on natural gasand 750 hours per year on fuel oil. [Rule 62-210.200, FAC, (Definitions – PotentialEmissions), 62.212.400, FAC, (BACTDetermination)]http://armpermit2k.dep.state.fl.us/psd/1050233/000109D2.pdfPage 15 of 219Antelope ElkEnergy CenterAbernathy,Texas168 MW,peaking andintermediate loadplant; permitadded onenatural gas firedsimple cyclecombustionturbineGHG-onlyPSDPSD-TX-1358-GHGEPARegion 66/2/2014 Special Permit Conditions – Turbine BACTRequirementsIII.A.2.d – The turbine is limited to 4,572operational hours on a 12-month rolling totalbasis.III.A.2.a – The BACT limit of 1,304 lbs ofCO2/MW-hr gross output is based on a 4,572rolling operational hour average basis,calculated daily using equations for CO2provided in 40 CFR Part 75, Appendix G,Procedure 2.3 or the CO2 emissions CEMS data40 CFR Part 75, Appendix F. The Permitteehttp://www.epa.gov/earth1r6/6pd/air/pdr/ghg/goldenspreadantelope-finalpermit060314.pdfPage 7 of 14.164These examples of permits containing terms that require reducedutilization at EGUs were identified with the assistance of EPAregional staff.Copies of the cited permits are available in the docketfor this action.69Facility name Location offacilityType of EGU Type ofpermitPermitnumberPermit authorityissuing permitDate permitsigned orissuedText of permit condition containingutilization limitWeb address wherepermit can be found, ifavailable, and pagecitation for limitshall calculate each day a combustion turbineoperates, CO2 emissions over the rolling 4,572hours of operation basis divided by grosselectrical output over the same period forcomparison to the limit for the combustionturbine.SunburyGeneration LPSnyder County,PARepowering offacility byreplacing coalfired generationwith natural-gasfired combinedcycle turbinesMinor newsourcereviewpreconstructionpermitPlan ApprovalNo. 55-00001EPennsylvania DEP 4/1/2013Condition #016: Pursuant to the best availabletechnology requirements of 25 Pa. CodeSections 127.1 and 127.12, Source ID P181[turbine] shallnot be operated in excess of the following rates:(a) 7,955 hours in any 12 consecutive monthperiod (CMP) if the Siemen[s] F4 option isselected,(b) 6,920 hours in any 12 CMP if the SiemensF5 option is selected,(c) 8,275 hours in any 12 CMP if the GE7FA.05 option is selected.N/APage 24 of 48; see also pp.32 and 40 of 48 (same forother turbines)Madison Gas &Electric Co.,Blount StreetGenerating StationMadison, DaneCounty,WisconsinNaturalGas/DistillateFuel Oil BoilersTitle VRenewal113004430-P20 Wisconsin DNR 6/30/2015 Condition I.A.3.1(1) The operating hours for boiler B22 may notexceed 5,100 hours during each 12 consecutivemonth period.[FN 1]. [ss. 285.63(1)(b) and285.65(7), Wis. Stats, s. NR 407.09(2)(d), Wis.Adm. Code]FN 1 states: “The operating hour limitations arenecessary to ensure thatthe national ambient airquality standard for nitrogen oxide is attainedand maintained.”http://dnr.wi.gov/cias/am/amexternal/AM_PermitTrackingSearch.aspx(search by permit number)Page 6 of 75City Center West Madison, DaneCounty,WisconsinPeak shavinggeneratorsFESOP(SyntheticMinor, NonPart 70)113225200-F01 Wisconsin DNR 4/19/2007 Condition I.A.2(2) [Part of NOx limit](2) Each generator may not be operated formore than 16.66 hours per month, averagedover any 12 consecutive months. This limit isproposed by the permittee to be minor for Part70. [s. 285.65(7), Wis. Stats.]http://dnr.wi.gov/cias/am/amexternal/AM_PermitTrackingSearch.aspx(search by permit number)Page 4 of 15Rockgen EnergyCenter, LLCChristiana, DaneCounty,WisconsinNominal 525MW Peak PowerElectricGenerationFacilityTitle VRenewal113308030-P10 Wisconsin DNR 2/04/2010 Condition I.C.1(1)(1) Each of the three combustion turbineprocesses (P01, P02, and P03) may not beoperated more than 3800 hours in any 12consecutive monthsof which not more than 800 hours in anyconsecutive 12-month period shall be ondistillate fuel oil with less than 0.05% sulfur byweight. Thiscondition is necessary to meet the BACTemission limits for sulfur dioxide, carbonmonoxide, nitrogen oxides, particulate matter,volatilehttp://dnr.wi.gov/cias/am/amexternal/AM_PermitTrackingSearch.aspx(search by permit number)Page 29 of 5570Facility name Location offacilityType of EGU Type ofpermitPermitnumberPermit authorityissuing permitDate permitsigned orissuedText of permit condition containingutilization limitWeb address wherepermit can be found, ifavailable, and pagecitation for limitorganic compounds and sulfuric acid (mist). [s.285.65(7), Wis. Stats.]We Energies –ConcordGenerating StationWatertown,JeffersonCounty,WisconsinCombustionturbinesTitle VRenewal128065080-P30 Wisconsin DNR 01/15/2013 ConditionI.A.7(3) The operation of turbinesP01, P02, P03 and P04 combined at less than 75MW output may not exceed 540 hours/monthaveraged over any 12-month period, excludingstartup/shutdown periods. [s. 285.65(7), Wis.Stats., 05-SDD-320 for P01 and P02, and 08-SDD-104 for P03 and P04]http://dnr.wi.gov/cias/am/amexternal/AM_PermitTrackingSearch.aspx(search by permit number)Page 18 of 21Washington IslandElectricCooperativeWashingtonIsland,WisconsinBackupelectricitygeneratingfacility fromdiesel generatorsFESOP(SyntheticMinor, NonPart 70) -Renewal415186750-F20 Wisconsin DNR 02/09/2010 Condition I.Z.1.a.(1):The permittee may notburn more than 300,000 gallons of Numbers 1and 2 distillate fuelin generators P08 and P09, combined, duringeach 12consecutive month period.3 [s. 285.65(7), Wis.Stats.]Condition I.Z.2.a.(1): The permittee may notoperate generators P03 and P04 for more than500 hours, each, during each 12 consecutivemonth period. [s.285.65(7), Wis. Stats.]http://dnr.wi.gov/cias/am/amexternal/AM_PermitTrackingSearch.aspx(search by permit number)Page 6 of 8Manitowoc PublicUtilities - CusterStreetManitowoc,ManitowocCounty,WisconsinSimple cyclecombustionturbineTitle VRenewal436123380-P10 Wisconsin DNR 08/19/2013 Condition I.ZZZ.1.a(1): The operating hours forthe single simple-cycle combustion turbine(P01) may not exceed 194 hours per monthaveraged over any 12 consecutive month period.[s.285.65(3), Wis. Stats., s. 285.65(7), Wis.Stats.; 98-RV-153]http://dnr.wi.gov/cias/am/amexternal/AM_PermitTrackingSearch.aspx(search by permit number)Page 9 of 14Madison Gas &Electric - WestMarinette FacilityMarinetteCounty,WisconsinSimple cyclecombustionturbineTitle VRenewal438022420-P10 Wisconsin DNR 08/31/2010 Condition I.A.9.a(1)(a) The total hours ofoperation of Process B04 [combustion turbine]may not exceed 4,000 hoursin any year. Of thetotal 4,000 hours, the hours fired on distillatefuel oil may not exceed 2,000 hours in any year;and (b) The total hours of operation in the peakpower mode may not exceed 100 hours in anyyear.[s. 285.65(7), Wis. Stats.; Permit #99-RV-136-OP-R1]http://dnr.wi.gov/cias/am/amexternal/AM_PermitTrackingSearch.aspx(search by permit number)Page 14 of 32Wisconsin DOAUW-Stout PowerPlantMenomonie,Dunn County,Wisconsin23 Emergencygenerator (9powered by CIdiesel enginesand 14 poweredby SI natural gasengines)Title V 617013320-P30 Wisconsin DNR 1/21/2014 (1) Each emergency electric generator inProcess P01 shall only be used to provideelectricity to the facility if normal electricalservice is interrupted and shall be operated nomore than 200 hours in any consecutive 12-month period. [s. NR 400.02(56), Wis. Adm.Code, and s. 285.65(3), Wis. Stats.]http://dnr.wi.gov/cias/am/amexternal/AM_PermitTrackingSearch.aspx(search by permit number)Page 50NTE Ohio, LLC –MiddletownEnergy CenterMiddletown,OhioCombined cycleturbinePermit toInstallP0116610 Ohio EPA 11/5/2014 Auxiliary Boilerhttp://wwwapp.epa.ohio.gov/dapc/permits_issued/1224365.pdf71Facility name Location offacilityType of EGU Type ofpermitPermitnumberPermit authorityissuing permitDate permitsigned orissuedText of permit condition containingutilization limitWeb address wherepermit can be found, ifavailable, and pagecitation for limitCondition 1.b)(1)d. Synthetic Minor to avoidNonattainment Area New Source Review(NAA-NSR) for NOx and VOC. The NOxemissions shall not exceed 3.30 TPY based on arolling 12-monthsummation. The VOC emissions shall notexceed 1.50 TPY based on a rolling 12-monthsummation. See b)(2)k.Condition 1.b)(2)k. The maximum annual fuelconsumption for this emissions unit shall notexceed 600,000 MMBtu per rolling, 12-monthperiod. ...Condition 1.f)(1)b.Emission Limitation:NOx emissions shall not exceed 0.011Lb/MMBtu of heat input, 1.65 pounds per hour,and 3.30 tons per rolling, 12-month period....The annual emission limitation was developedby multiplying the hourly emission limitation(1.65 pounds per hour) by the maximum annualoperating hours (4,000 hours per year) anddividing by 2,000 pounds per ton. The 4000hours per year value is equivalent to the600,000 MMBtu, per rolling, 12-month periodvalue....See also Condition 1.f)(1)a (similar provisionfor CO); Condition 1.f)(1)c (similar provisionfor PE, PM10, and PM2.5); Condition 1.f)(1)e.(similar provision for VOC); Condition 1.f)(1)f(similar provision for sulfuric acid mist)Emergency GeneratorCondition 3.b)(1)c. Synthetic Minor to avoidNonattainment Area New Source Review(NAA-NSR) for NOx and VOC.The NOx emissions shall not exceed 7.25 TPYbased on a rolling 12-month summation. TheVOC emissions shall not exceed 0.26 TPYbased on a rolling 12-month summation. seeb)(2)e.Condition 3.b(2)e. The maximum annualoperating hours for this emissions unit shall notexceed 500 hours, based upon a rolling, 12-month summation of the operating hours. ...Pages 22, 25, 27-29, 63,65, 69-70 of 87; see also33 for an emissions-basedsynthetic minor limit onthe turbine with heatrecovery steam generator,natural gas-fired, includingduct burners72Facility name Location offacilityType of EGU Type ofpermitPermitnumberPermit authorityissuing permitDate permitsigned orissuedText of permit condition containingutilization limitWeb address wherepermit can be found, ifavailable, and pagecitation for limitCondition 3.f(1)b.Emission limitationNOx emissions shall not exceed 8.92 g/hp-hr,9.01 Lbs/hr, and 7.25 tons per rolling, 12-monthperiod.... The hourly emission limitation wasdeveloped by multiplying the maximumoperating load (1475 HP) by the NOx emissionfactor supplied by the manufacturer (8.92 g/hphr) divided by (453.59 g/Lb) to determine thehourly emissions....The annual emission limitation was developedby multiplying the hourly emission limitation(29.01 Lbs/hr) by the maximum annualoperating hours (500 hrs/yr) and dividing by2,000 pounds per ton. Compliance with therolling, 12-month emission limitation shall bedemonstrated by the recordkeeping in d)(1).Condition 3.f(1)e. Emission Limitation:VOC emissions shall not exceed 0.26 tons perrolling, 12-month period....The annual emission limitation was developedby multiplying the maximum hourly emissions(1.04 Lbs/hr) by the maximum annual operatinghours (500 hrs/yr) and dividing by 2,000 poundsper ton. Compliance with the rolling, 12-monthemission limitation shall be demonstrated by therecordkeeping in d)(1).PREPA San Juan San Juan, PuertoRico2 Turbines and 4BoilersPSD permitwith PSDnonapplicabilityconditionsfor somepollutants.Not applicable EPA Region 2 4/01/2004Condition XII.3: Both Westinghouse 501distillate oil fired combustion turbines shall onlybe allowed to operate for up to 15,000 hours peryear. Daily compliance shall be determined byadding the total amount of hours operated byboth turbines during each calendar day to thetotal hours operated by both turbines in thepreceding 364 calendar days.Condition XII.3.c: The maximum total fuel usein these four boiler unitsshall be limited to173.1 million gallons per year.http://www.epa.gov/region2/air/permit/PREPA04012004.pdfPage 17 of 30El Paso ElectricCompany,Montana PowerStationEl Paso, Texas 400 MW peakand intermediateload ElectricPowerGHG onlyPSDPSD-TX-1209-GHGEPA Region 6 3/25/2014 BACT Limit:III.A.2.a. The limit of 1,100 lbs of CO2/MWhrgross output is based on ...calculate each day acombustion turbine operates, CO2 emissionshttp://yosemite.epa.gov/r6/Apermit.nsf/AirPPage 7 of 1473Facility name Location offacilityType of EGU Type ofpermitPermitnumberPermit authorityissuing permitDate permitsigned orissuedText of permit condition containingutilization limitWeb address wherepermit can be found, ifavailable, and pagecitation for limitGenerationFacilityover the rolling 5,000 hours of operation basisdivided by gross electrical output over the sameperiod for comparison to the limit for eachcombustion turbine.III.A.2.d. Each turbine ...is limited to 5,000operational hours on a 12-month rolling basiswhich shall include periods of startup andshutdown.Burney MountainPowerBurney,CaliforniaBiomass Boiler PSD SAC 08-01 EPA Region 9 10/21/2010 Condition X.D.1.b: Operation of the boiler shallnot exceed 8,400 hours on a 12-month rollingbasis.http://www.regulations.gov/#!documentDetail;D=EPA-R09-OAR-2009-0966-0026Page 6 of 13Fort Pierre Powerand Light PlantStanley County,SDPeaking, DieselGeneratorsTitle V 28.0801-58South DakotaDept. of Environ. &Nat. Res.04/13/2015 10.3 Hourly limit for diesel enginesIn accordance with ARSD74:36:05:16.01, theowner or operator shall not operate Unit #1, #2,and #3 for more than a total of 8,112 hoursduring any 12-month rolling period. The 12-month rollingtotal shall be calculated every month using thatmonth’s value and the previous 11 months’values.http://denr.sd.gov/pdfaq1/28.0801-58_permit_20150413.pdfPage 37 of 37MadisonGeneration PlantLake County, SD Peaking, DieselGeneratorsTitle V 28.0801-43South DakotaDept. of Environ. &Nat. Res.04/07/2015 7.4 Hourly limit for diesel enginesIn accordance with ARSD 74:36:05:16.01(8),the owner or operator shall not operate Engines#1, #2, #3, #4 and #5 for more than a combined7,834 hours during any 12-month rolling period.The 12-month rolling total shall be calculatedevery month using that month’s value and theprevious11 months’ values. The initial startup of thefacility shall be the first month of the 12-monthrollingperiod.http://denr.sd.gov/pdfaq1/28.0801-43_permit_20150407.pdfPage 17 of 38NorthwesternPublic ServiceCompany,YanktonYankton, SD Peaking, DieselGeneratorsTitle V 28.0801-07South DakotaDept. of Environ. &Nat. Res.03/06/2015 7.3 Hourly limit for Unit #4In accordance with ARSD 74:36:05:16.01(8),the owner or operator shall not operate Unit #4for more than 1,120 hours each during any 12-month rolling period. The 12-month rolling totalshall be calculated every month using thatmonth’s value and the previous 11 months’values.http://denr.sd.gov/pdfaq1/28.0801-07_permit_20150306.pdfPage 17 of 37Basin CreekEquity Partners,Basin CreekSilver BowCounty, MTPeaking, Naturalgas reciprocatinginternalcombustionenginesTitle V OP3211-02 MontanaDept. of Env.Quality09/04/2011 B.5. Combined RICE operation (9 engines total)shall be limited to a maximum of 34,200 hoursduring any rolling 12-month time period (ARM17.8.749).http://www.deq.mt.gov/airquality/ARMpermits/awm_final_permit.mcpxPage 11 of 4074Facility name Location offacilityType of EGU Type ofpermitPermitnumberPermit authorityissuing permitDate permitsigned orissuedText of permit condition containingutilization limitWeb address wherepermit can be found, ifavailable, and pagecitation for limitBasin ElectricPowerCooperative,CulbertsonRooseveltCounty, MTPeaking,combustionturbineTitle V OP4256-00 MontanaDept. of Env.Quality12/14/2010 B.6. Operation of the turbine generator,including startup and shutdown, shall notexceed 3,400 hours per rolling 12-month timeperiod (ARM 17.8.749).http://www.deq.mt.gov/airquality/ARMpermits/awm_final_permit.mcpxPage 10 of 39Payson CityCorporation –Payson CityPowerUtah County,UtahPeaking; fourdual-fuel(NG/oil) internalcombustionengines, twoserving 2.65-MW electricalgenerators, oneserving a 2.093-MW electricalgenerator, andone serving a1.80-MWelectricalgeneratorTitle V 4900080004 UtahDept. of Env.Quality1/16/2015 Permit condition II.B.6.e (pertaining to the dualfuel engines):Total hours of operation shall not exceed 12,600hours per rolling 12-month period for allengines combined.[Origin: DAQE-AN108230006-14, SIPIX.H.3.c]. [R307-110-17(SIP IX.H.3.c), R307-403-8(1)(a)(BACT)]http://168.178.3.241:8080/DAQ_NOI/DocViewer?IntDocID=79251Page 23 of 34Provo City Power- Power PlantUtah County,UtahPeaking; fourdual-fuel(NG/oil) internalcombustionengines, eachserving a 2.585-MW electricalgenerator; twoNG-fired boilers,each serving a9.20-MWelectricalgeneratorTitle V 4900018003 UtahDept. of Env.Quality10/28/2009 Permit condition II.B.2.c (pertaining to the dualfuel engines):Combined hours of operation shall be no greaterthan 48 hours per day for the four engines.[Authority granted under R307-401-8(1)(a)[BACT]; condition originated in DAQEAN0795006-04].http://168.178.3.241:8080/DAQ_NOI/DocViewer?IntDocID=50100Page 16 of 2275Capacity LimitsFacility name Location offacilityType of EGU Type ofpermitPermitnumberPermitauthorityissuingpermitDate permitsigned or issuedText of permit condition containing utilizationlimitWeb address wherepermit can be found, ifavailable, and pagecitation for limitPREPA CostaSurGuayanillaPuerto RicoTwo boilers 4 & 5.Each boiler is rated at3,950.7 MMBTU/hrand can produce 410MW (820 MW intotal).Revised stateconstruct-ionpermitPFE-31-0810-0455-II-C(in Spanish)Puerto RicoEnvt’l QualityBoard09/20/2010 Condition B.2 provides 5 different operatingscenarios for the two boilers: 1) 100% natural gas;2) 25% natural gas & 75% fuel oil; 3) 50% NG &50% fuel oil; 4) 75% NG & 25% fuel oil, and5)100% fuel oil. Each operating scenario has amaximum fuel oil and natural gas restriction limit.The capacity factor for each of the operatingscenario is 71%, 65%, 65%, 65%, and 65%,respectively.Page 3 of 14.AES-Puerto RicoCo-generationProjectGuayama,Puerto Rico454 MW CirculatingFluidized Bed BoilerCoal fired.PSD - RevisedPermitNot applicable EPA Region 2 08/10/2004 See Condition XVI.6:Maximum Annual Capacity Factora.AES-PRCP shall not exceed a maximumannual capacity factor of 95% during anyperiod of 12 consecutive months.Compliance will be demonstrated bylimiting facility fuel use to a maximumof 40,966,709 MMBtu during any periodof 12 consecutive months. AES-PRCPshall maintain fuel use records todemonstrate compliance with thiscondition.b.“Annual capacity factor” means the ratiobetween the actual heat input to thesteam generating units from fuel useduring a period of 12 consecutivecalendar months and the potential heatinput to the steam generating units fromfuels had the steam generating units beenoperated for 8,760 hours during that 12-month period at the maximum designheat input capacity of 4922.7 MMBtu/hr.Therefore, a maximum annual capacityfactor of 95% means fuel use will notexceed 40,966,709 MMBtu during aperiod of 12 consecutive calendarmonths.http://www.epa.gov/region2/air/permit/AES08102004.pdfPage 28 of 31Great RiverEnergy - CoalCreek StationMcLeanCounty, NorthDakotaBase-loaded; twolignite-fired boilers,one rated at 6,015MMBtu/hr, one ratedat 6,022 MMBtu/hr;two liquid fuel firedauxiliary boilers,each rated at 172MMBtu/hrTitle V T5-F82006 North DakotaDept. ofHealth, Dept.of Air Quality1/30/2015 Permit condition 3.C:Auxiliary Boilers Annual Capacity Factor:Beginning on the compliance date of NDAC 33-15-22 (40 CFR 63) Subpart DDDDD for existingboilers (January 31, 2016 or as amended), EU3 andEU4 auxiliary boilers shallbe limited to an averageannual capacity factor of no more than 10 percent tomaintain status as limited use boilers as defined in40 CFR 63.7575. ...http://www.ndhealth.gov/EHS/FOIA/AQPermits/AQPermitOperating.aspxPage 6 of 6176Facility name Location offacilityType of EGU Type ofpermitPermitnumberPermitauthorityissuingpermitDate permitsigned or issuedText of permit condition containing utilizationlimitWeb address wherepermit can be found, ifavailable, and pagecitation for limitOtter Tail PowerCompany -Coyote StationMercerCounty, NorthDakotaBase-loaded; onelignite-fired cycloneboiler rated at 5,800MMBtu/hr; one oilfired auxiliary boilerrated at 202MMBtu/hrTitle V T5-F84011 North DakotaDept. ofHealth, Dept.of Air Quality10/2/2013 Permit condition 4.F:In order to maintain limiteduse boiler classificationas defined by 40 CFR 63Subpart DDDDD, EU2 shall combust no more than1,263,943 gallons of No. 2 fuel oil per calendaryear, which corresponds to an average annualcapacity factor of 10 percent. Periodic tune-upsshall be completed as specified in 40 CFR 63.7540.These requirements shall become effective at thetime EU2 must comply with 40 CFR 63 SubpartDDDDD.Applicable Requirement: PTC 13032 and NDAC33-15-22-03, Subpart DDDDDhttp://www.ndhealth.gov/EHS/FOIA/AQPermits/AQPermitOperating.aspxPage 5 of 35Fuel or Heat Input LimitsFacility name Location offacilityType of EGU Type ofpermitPermitnumberPermit authorityissuing permitDate permitsigned orissuedText of permit condition containing utilization limit Web address wherepermit can be found, ifavailable, and pagecitation for limitWisconsin DOAUW – Green BayGreen Bay,Wisconsin6 IndustrialWatertube boilerswhich burn naturalgas and distillateoilSyntheticminor, nonPart 70405043540-F20WisconsinDepartment ofNatural Resources2/16/2010 D. Conditions applicable to the entire facility.1. Synthetic Minor Restrictions [fn 7](1) The total quantity of natural gas fired by the facilitymay not exceed 109.6 million Cubic Feet (cf6) permonth, averaged over any 12 consecutive monthperiod. [s. 285.65(7), Wis. Stats.](2) The total quantity of distillate fuel oil fired by thefacility may not exceed 109,600 gallons per month,averaged over any 12 consecutive month period. [s.285.65(7), Wis. Stats.]FN 7 states: These restrictions on fuel use, and thelimitations on Nitrogen Oxides emissions when firingnatural gas (0.10 lbs/MMBTU) and distillate oil (0.143lbs/MMBTU) are both necessaryfor the facility to beconsidered a synthetic minor source under PSD andTitle V.A. [Boiler Limitations]3. Nitrogen Oxides(1) 0.10 pounds of Nitrogen Oxides per million BTUof heat input when firing natural gas and 0.143 poundsof Nitrogen Oxides per million BTU of heat inputwhen firing distillate fueloil. [FN2] [s. 285.65(3), ands. 285.65(7), Wis. Stats., 04-DCF-301]http://dnr.wi.gov/cias/am/amexternal/AM_PermitTrackingSearch.aspx(search by permitnumber)Page 12 of 15 forrestriction on fuel use;Page 6 of 15 for NitrogenOxide Emissions Limits77FN2 states: This condition, along with the facilityrestrictions on the quantities of natural gas anddistillate fuel oil that may be fired, are necessary toassure that the facility constitutes a synthetic minorsource under the Title V and PSD permit programs.These emission rates are based on the AP-42 emissionfactors of 100 lbs/cf6 for natural gas and 20 lbs/gal3for distillate oil combustion, in boilers with heat inputsless than 100 MMBTU/hr.Anita MunicipalUtilitiesAnita, IA IC Diesel Engines Minor newsource reviewpreconstruction permit02-A-375 Iowa Departmentof NaturalResources8/22/2002 14. Operating Limits...The total amount of fuel used by this unit (EU-11) shallnot exceed 189,225 gallonsper twelve (12) monthrolling period.165Page 6 of 11165While Caterpillar makes several versions of this generatorset, the low fuel consumptionversion uses 123.2 gal/hr at 100% load (specificationsavailable at http://s7d2.scene7.com/is/content/Caterpillar/17791289. Under that assumption, the 189,225 fuel limit would restrict operations to 1,536hours (189,225 gal/123.2 gal/hr = 1,536 hrs), which is less than 8760 hours.78 XII. Combining Categories

This section provides more information rele vant for section IV.E., “Combined Categories

and Codification in the Code of Federal Regulations.”

Combining the two steam generator category and the combustion turbine category is reasonable because the sources in both categorie s provide the same product: electricity services. Moreover, combining them in this rule is consis tent with our decision to combine them in the CAA section 111(b) rule for new sources that acc ompanies this rule. In addition, many of the monitoring, reporting, and verifica tion requirements are the same for both source categories, and, as discussed next, we are codifying all requiremen ts in a single new subpart of the regulations; as a result, combining the two categories into a single category will reduce confusion. Moreover, combining the categories facilitates emission tr ading between steam generators and combustion turbines by obviating any legal qu estions as to whether section 111 authorizes emission trading between sources in different source categories.



### [All of the following sections are new]

XIII. Timetable for source compliance

This section provides more information in support of preamble section V., which explains that affected EGUs are able to implement the bu ilding blocks on a timetable that allows them to meet their emission performance requirement s by 2022 and later without having to incur significant expenditures for the firs t several years after promulgation of this rule. This same information supports preamble section VIII, whic h explains that implementation of the building blocks is not expected to cause reliability concerns.

There are a number of instances (cited below) in which the owners or operators of fossil fuel-fired EGUs have retired their plants on shor t notice, sometimes retiri ng their plants within a few months of announcing their intention to do s o. In some instances, transmission upgrades or reconfigurations were needed to facilitate the retirements. The ability of owners or operators to retire their plants on short notice depends at least in part on the extent to which the plants are being utilized, along with the ava ilability of other generation resources needed to meet load requirements. Even so, these instances illustra te that significant reductions in generation resources can occur over very short periods.

As a result, these instances illustrate that one method of implementing building blocks 2 and 3 -- reduced generation, which is less intrusiv e than retirement -- should be available to

affected EGUs on a timetable that allows them to meet their emission performance requirements by 2022 and later without having to in cur significant expenditures fo r the first seve ral years after promulgation of this rule.

In addition, these instances also demonstr ate circumstances in which the electricity system has sufficient resiliency, including the ability to make some types of transmission79 upgrades and reconfigurations on short notice, to accommodate retirements without raising reliability concerns.

Retirement of Hatfield Ferry 1,2,3 (1590 MW) and Mitchell 2,3 (359 MW) 166
All of these units were owned by First En ergy, which notified PJM on July 9, 2013 that the plants would be retired on October 9, 2013. The retirements entailed 30 transmission upgrades, some of which were prev iously identified and needed to be accelerated, and some of which were new. Most involved small, lower vol tage transmission lines, and some were larger, costing tens of millions of dollars. In a few places, lines needed to be reconfigured to address thermal issues. Most transmission upgrades were completed by the time of plant retirements, and the rest were managed with operating pr ocedures. The plants closed on time.

Will County Unit 3 (251 MW) 167

This unit notified PJM in the fall of 2 014 that it would close on April 15, 2015. PJM found no reliability issues with the cl osure, and the unit closed on schedule.

Walter C. Beckford 5 & 6 (652 units) 168
The units notified PJM in Septem ber of 2014 that it wanted to cl ose as soon as possible. PJM found no issues and the units closed later in September.

XIV. Explanation for Certain Aspects of the EPA’s Interpretation of the BSER

This section provides additional support for certain aspects of the EPA’s interpretation and application of the BSER, as describe d in section V. of the preamble.

In this rulemaking, the EPA is determining th e BSER on the basis of the relevant source subcategory. For example, the BSER for the fossil fuel-fired steam generator subcategory includes, along with building block 1, substituting lower- and zero- emitting generation for higher-emitting generation, through building blocks 2 and 3. For convenience, the remainder of this discussion will refer only to the steam gene rator subcategory, and will refer only to building

blocks 2 and 3.

Based on its determination of the BSER, the EP A determines the emission performance rate that reflects the degree of emi ssion limitation achievable through the application of the BSER. For the fossil fuel-fired steam generator subc ategory, the EPA is determining the emission performance rate to be 1305 lbs CO 2 /MWh.

Individual affected EGUs in the source subcat egory would be able to achieve the emission standard performance rate, if their state were to impose it as the standard of performance, by undertaking any of a set of measures or actions that apply or implement 169 the BSER. These

166 https://www.firstenergycorp.com/c ontent/fecorp/newsroom /news_releases/firstenergy -to-deactivate-two-coalfired-power-plants-in-pennsyl.html

167 http://www.powermag.com/nrg-to-shutter-repowe r-illinois-coal-units-in-modernization-bid/

168 http://www.cincinnati. com/story/money/2014/0 8/29/beckjord-plant-s hutting-monday/14839437/

169 In this context, the terms “implement” and “apply” are used interchangeably.80 include purchasing emission reduction credits (ERCs ), engaging in bilateral transactions with lower- or zero-emitting units, reducing gene ration, emissions trading, or undertaking a

combination of those measures or actions.

It should be noted that while it would be t echnically feasible for each affected EGU to substitute part of its generation for lower- or zero-emitting generation in its share of the amounts contemplated for the source category, by reduc ing a portion of its generation and purchasing ERCs or undertaking other actions , that would not maximize the e fficiencies available to each

source. The EPA’s determination of the BSER fo r the source category -- in this case, substitution of lower- or zero-emitting generation for higher emitting generation -- does not depend on each

individual affected source bei ng able to implement the BSER in precisely the manner that the

EPA defined it for the sour ce category as a whole.

Rather, it is sufficient th at each affected EGU is capable of achieving its emission limit (which, again, EPA calculated on the basis of th e degree of emission limitation achievable by the application of the BSER to the source categor y) by applying or implem enting the BSER (which, again, each affected EGU can do by undertaking any of a set of meas ures or actions).

As just described, our approach complies fully with CAA section 111(d)(1) and (a)(1). These provisions require that the EPA determine the BSER and the related emission performance standard, and that the affected sources be ab le to achieve the emission performance standard through the application of the BSER. These provisions do not specify how the EPA is to determine the BSER, and as a result, the EPA may determine the BSER on the basis of the source category, as it has done here. The ability of all of the affected EGUs to achieve the emission performance standard by implementing or applying the BSER through the abovedescribed set of measures assures that the EPA’s approach is consistent with section 111(d)(1) and (a)(1).

It is useful to present anothe r set of circumstances that, although different from the ones in this rulemaking, illustrate another application of the EPA’s approach. Assume that for a source category, the EPA identifies as the BSER an add- on control that, when inst alled and operated at full capacity, reduces emissions by 90%, but that the EPA determin es is of reasonable cost only if applied to half the production. A ssume further that it is reasonabl e to expect that the sources in the source category will engage in emissions tr ading. In this case, the EPA, in its emission guidelines, would identify the add-on contro l technology as the BSER, and determine the

emission rate for the sources that reflects the degree of emission limitation achievable by reducing emissions by 45% (half of 90%). Each source would be able to achieve its emission rate – which means lowering its emissions by 45 % -- by implementing the BSER, which it could do either by (i) installing an add-on control (and reducing its em issions by 90%, and being able to sell emission reduction credits to defray the costs of the add-on contro l), or (ii) purchasing emission reduction credits or conducting a bilateral transaction with another source to, in effect, jointly implement the add-on control on one of the sources.

XV. Coal-cleaning as a “Beyond-the-unit” measure81 This section provides additional explanation for section V.B.3. of the preamble by explaining in more detail how the history of EPA’s and Congress’s relia nce on coal-cleaning as

the basis for emission limits under section 111 make s clear that, contrary to the views of some commenters, section 111(a )(1) incorporates “beyond-the-unit” measures.

Some commenters argue that under section 111, Congress never intended to authorize “beyond-the-unit” or “beyond-the-fenceline” meas ures, and that such measures cannot be considered components of a system of emission reduction. We disagree with these comments, for reasons discussed in section V.B.3 of the pr eamble, including the point that at least one “beyond-the-unit” measure has been part of the BSER for EGUs for some standards of performance for decades, and, in fact, for a period of time, was expressly authorized under section 111, namely, pretreatment of fuels. Here we provide a more detailed discussion of this point.

Shortly after the 1970 CAA Amendments, EPA pr oposed standards of performance for an “initial list of five stationary source categorie s which contribute significantly to air pollution

which causes or contributes to the endangerment of pub lic health or welfare.” 170 The first category identified in the proposed rule addresse d fossil fuel-fired steam generators, for which EPA proposed standards for particulate matter, SO 2 , and NO x
. 171

With respect to SO 2 emissions, EPA proposed to restrict emissions in excess of 0.8 ppm BTU heat input when liquid fuel ( i.e. , oil) is burned and 1.2 ppm BTU heat input when solid fuel ( i.e.

, coal) is burned. 172 The stringency of this standard was based upon consideration of “the availability and cost of fuels and control techniques and to e ffects on the economics of producing electric power.” 173 In particular, one of EPA’s major cons iderations was “[t]he desirability of setting [SO 2 ] standards that would allow the us e of low-sulfur fuels as well as fuel cleaning

, stack-gas cleaning, and equipment modifications.” 174 As noted in the preamble, fuel cleaning activities are frequently undertaken off-site, by parties not related to the affected EGU. EPA

even considered oil desulfuriza tion facilities that would come on-line outside th e country after

the rule went into effect. 175 Thus, the availability of fuel cleaning technologies, whether or not implemented on site or even directly by the aff ected source, were part of the basis for the standards of performance. 176

170 Standards of Performance for New Stationary Sources: Proposed Standards for Five Categories , 36 Fed. Reg. 15704 (Aug. 17, 1971).

171 36 Fed. Reg. 15704, 15704-706.

172 36 Fed. Reg. 15704, 15706.

173 U.S. EPA, Office of Air Programs, Background Information for Proposed New-Source Performance Standards: Steam Generators, Incinerators, Portland Cement Plants, Nitric Acid Plants, Sulfuric Acid Plants , p. 7 (Aug. 1971).

174 Background Information for Proposed New-Source Performance Standards: Steam Generators, Incinerators, Portland Cement Plants, Nitric Acid Plants, Sulfuric Acid Plants , p. 7 (emphasis added). As noted above, fuel cleaning activities are frequently undertaken by partie s not related to the affected EGU, off-site.

175 Background Information for Proposed New-Source Performance Standards: Steam Generators, Incinerators, Portland Cement Plants, Nitric Acid Plants, Sulfuric Acid Plants , p. 8.

176 See Standards of Performance for New Stationary Sources , 36 Fed. Reg. 24876, 24879 (Dec. 23, 1971).82 By 1977, Congress observed that many fossil fuel-f ired stationary sources were complying with new source performance standards exclusively by fuel shifting to untreated low-sulfur coal. This made it more expensive for existing sources to use naturally low-sulfur coal (due to supply limitations) and potentially resulted in higher overall SO 2 emissions. To address this, Congress inserted the term “technological” into the defini tion of standard of performance and required new fossil fuel-fired stationary sources to achieve a percentage reduction in emissions that would result from burning untreated fuels. 177 Together, this narrowed the underlying considerations

used to calculate a standard of performance and would essen tially “force new sources to burn high-sulfur fuel thus freeing low-sulfur fuel for use in existing sources where it is harder to

control emissions and where low-sulfur fuel is needed for compliance.” 178

Although Congress strongly discouraged fuel-s witching under the 1977 CAA Amendments, Congress made clear that EPA could not require the installation or operation of any particular technological system of conti nuous reduction under Section 111. 179 Congress nevertheless

ensured that EPA could still consider fuel cl eaning as part of a “t echnological system of continuous emission reduction,” ju st as EPA had prior to the 1977 CAA Amendments. To that end, Congress added to the defini tion of standard of performa nce for certain new sources in section 111(a)(1) the word s “precombustion cleaning or treatmen t of fuels” to “insure that in upgrading the standards and in de fining the ‘best technological system of continuous emission reduction’, the Administrator would not be limited to consideration of stack gas cleaning or clean combustion processes.” 180 Congress also understood that th ese techniques would not necessarily be accomplished at the individual source. For example, a House committee report indicates that an assessment of the best technological systemof continuous emission reduction for fossil fuelfired power plants would include “various coal-clean ing technologies such as solvent refining,

oil desulfurization at the refinery”. 181 Coal-cleaning, Senator Musk ie observed, can occur at the “minemouth” (rather than at the source), and, similarly, other precombustion fuel treatment processes may or may not even be “undertaken by the source itself.” 182 EPA has also recognized in a regulatory analysis of new source performance standards for industrial-commercialinstitutional steam generating units that coal-c leaning technology “requires too much space and is too expensive to be employed at indivi dual industrial-commercial-institutional steam

177 See 1977 CAA Amendments, § 109, 91 Stat. at 700; see also, New Stationary Sources Performance Standards; Electric Utility Steam Generating Units , 44 Fed. Reg. 33580, 33582 (June 11, 1979).

178 44 Fed. Reg. 33580, 33581-33582. In particular, the percentage reduction requirement made burning high-sulfur

coals more economical because it would be easier to achieve the reductions than with low-sulfur coals. Achieving a percentage reduction in emissions at the individual plant level could be accomplished in several ways. An individual source could install pollution control technology, such as the application of flue gas desulfurization systems, or receive credit for fuel clea ning or other fuel pre-treatment measures taken “after extraction and prior to combustion”. 1977 CAA Amendments, § 109, 91 Stat. at 700. In fact, Congress authorized EPA to give “credit for minemouth and other precombustion fuel treatment processes whether or not undertaken by the source itself .” Sen. Muskie, Sen. Consideration of H.R. Conf. Rep. No. 95-564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353 (emphasis added).

179 1977 CAA Amendments, § 109, 91 Stat. at 700-01.

180 Sen. Conf. R. No. 94-1742, at 88 (Sept. 30, 1976).

181 H.R. Rep. No. 95-294, at 188 (May 12, 1977). If th ere is any doubt whether coal-cleaning activities must be conducted at a fossil fuel-fired power pl ant for purposes of identifying the BSER, the committee report also names oil refineries, which are clearly separate facilities.

182 Sen. Muskie, Sen. Consideration of H.R. Conf. Rep. No . 95-564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353.83 generating units.” 183 Thus, Congress assured that ev en between 1977 and 1990, standards of performance reflecting the best technological system implementable by an affected source could be based, in part, on technologies operated by third-parties outs ide the affected source.

In 1990, Congress largely reinstated the 1970 de finition of “standard of performance” and thus eliminated many of the restrictions added in the 1977 CAA Amendments, including the specific reference in section 111(a) (1) to fuel cleaning. Neverthele ss, there is no indication that reinstating the 1970 definition of standard of pe rformance was designed to limit its scope. Thus, just as fuel cleaning was factored into the firs t set of regulations for new source performance standards, fuel cleaning is still considered by the EPA in establishing post-1990 CAA

Amendment standards. For instance, in 2007, the EPA, in amending its standards of performance for industrial-commercial-instituti onal steam generating uni ts, required the owner or operator of such units to include “a signed st atement from the owner or operator of the fuel pretreatment facility certifying that the percent removal efficiency achieved by fuel pretreatment was determined in accordance with the provisions of Method 19 of appendix A”. 184

All told, the example of fuel cleaning sheds light on the scope of section 111. Since the 1970 CAA Amendments, and up to the present time, the EPA has (with congressional acquiescence) interpreted section 111 to author ize basing standards of performa nce on off-site fuel cleaning. Even during the period when Congress imposed the most narrow limits on section 111(a)(1) – 1977 to 1990 – Congress expressly authorized standard s of performance to be based on off-site fuel cleaning, whether or not undertaken by the source itself.

XVI. CAA Title IV

This section supports section V of the preambl e by providing additional information that in Title IV of the Clean Air Act, Congress recognized the integrated nature of the electricity system and the usefulness of dispatch shifts and renewa ble energy in reducing emi ssions from coal-fired

EGUs.

On June 30, 1980, Congress enacted the Acid Precipitation Act of 1980, as part of the broader Energy Security Act, to authorize a ten-year comprehensive study “(1) to identify the causes and effects of acid precipita tion and (2) to identify actions to limit or ameliorate the harmful effects of acid precipitation.” 185 The study, titled the National Acid Precipitation

183 U.S. EPA, Summary of Regulatory Analysis for New Source Performance Standards: Industrial-CommercialInstitutional Steam Generating Units of Greater than 100 Million Btu/hr Heat Input , EPA-450/3-86-005, p. 4-4 (June 1986).

184 40 C.F.R. § 60.49b(n)(4); see also Amendments to New Source Performance Standards (NSPS) for Electric Utility Steam Generating Units and Industrial-Commercial-Institutional Steam Generating Units; Final Rule , 72 Fed. Reg. 32742 (June 13, 2007).

185 Acid Precipitation Act of 1980, Pub. L. 96-294, § 704, 94 Stat. 611, at 770 (June 30, 1980). Under Subtitle B of the Acid Precipitation Act of 1980, Congress instructed th e Director of the Office of Science and Technology Policy and the National Academy of Sc iences to study the “proj ected impact on the level of carbon dioxide in the atmosphere, of fossil fuel combustion, coal-conversion and related synthetic fuels activities authorized in the [Energy Security Act]”. Id. at § 711, 94 Stat. at 774. Congress made clear that the study “should also include an assessment of the economic, physical, climatic , and social effects of such impacts.” Id.84 Assessment Program (NAPAP), produced two main reports to Congress: the Interim Assessment, released in September 1987, and the 1990 Integrated Assessment Report, released in November 1991. These reports, including their many drafts, along with many other scientific studies helped shape one of the most signifi cant additions to the CAA in 1990: Title IV. 186

Leading up to the 1990 CAA Amendments, the NAPAP had established that fossil fuel-fired power plants were the greatest source of acid rain precursors, i.e. , sulfur dioxide (SO 2 ) and nitrogen oxide (NO x ), in the United States and that older plants in particular were responsible for “[m]ore than 90 percent” of to tal U.S. power plant emissions. 187 However, the existing CAA proved inadequate to address concer ns with acid rain because olde r plants could not be regulated on a national scale for these criteria pollutants due to the pollution exclusions in Section 111(d). 188 Thus, in 1990, Congress added Title IV to address these “principal sources of . . . sulfur and nitrogen oxides” 189 and designed it to encourag e “energy conservation, use of

renewable and clean alte rnative technologies, and pollution pr evention as a long-range strategy . . . for reducing air pollution”. 190 In doing so, Congress fashioned an SO 2 cap-and-trade program

for fossil fuel-fired utilities—the most notable feature of Title IV—a nd required a technology

based NO x emission rate for certain utility boilers.

Title IV and its legislative history show that Congress was well aware of the unique opportunities for reducing emissions from the utility industry and from existing power plants in particular. 191 In fact, Congress found that many “strat egies and technologies for the control of precursors to acid deposition exist now that are economically feasible, and improved methods are expected to become increasingly available over the next decade”. 192 But by establishing an “allowance system” 193 in lieu of a particular control strategy or technology, Congress intended that the system would encourage such “technolo gies and strategies” as “energy efficiency;

enhanced emissions reduction or control techno logies—like sorbent in jection, cofiring with natural gas, integrated gasification combined cycles; fuel-switching and least-emissions dispatching in order to ma ximize emissions reductions.” 194 Indeed, the allowance system would

186 See, e.g. , Sen. Rep. No. 101-228, at 261-346 (Dec. 20, 1989) (discussing Title IV, including NAPAP and other scientific reports).

187 See Sen. Rep. No. 101-228, at 282-83 (Dec. 20, 1989). According to the NAPAP, 23.1 million tons of SO 2 and

20.5 million tons of NO

x were emitted from anthropogenic sources in 1985 . Id. at 828. Electric utilities accounted

for 16.1 million tons of SO 2 and 6.7 million tons of NO

x , and industrial sources (including industrial combustion and industrial processes) accounted for 5.6 million tons of SO 2 and 4.1 million tons of NO

x . Id.

188 Existing plants could be indirectly regulated through the NAAQS program ( e.g. , by tightening ambient air quality standards) and directly regulated on a case-by-case basis through the EPA’s new source review program ( e.g. , as a result of a plant modification).

189 42 U.S.C. § 7651(a)(2); CAA § 401(a)(2).

190 42 U.S.C. § 7651(b); CAA § 401(b).

191 “[B]y their business nature,” Congress explained, “utilitie s appear to be well-suited to create, and to take advantage of, an active market in emissions allowances.” Sen. Rep. No. 101-228, at 319 (Dec. 20, 1989). In fact, “utilities already engage in power-pooling arrangements to ensure maximum flexibility and efficiency in supplying power.” Id. Moreover, the allowance system enabled parties to “transfer between them and among themselves pursuant to a wide variety of commercial agreements such as under leases, sales agreements and exchanges between

emissions and electric power or capacity.” Id. at 320.

192 42 U.S.C. § 7651(a)(4); CAA § 401(a)(4).

193 See Sen. Rep. No. 101-228, at 320 (Dec. 20, 1989).

194 See Sen. Rep. No. 101-228, at 316 (Dec. 20, 1989).85 “maximize the economic efficiency of the pr ogram both to minimize costs and to create incentives for aggressive and innova tive efforts to control pollution.” 195

The following briefly addresses the relevant c ontrol “strategies and technologies” that are reflected in building blocks 2 and 3.

1. Congressional Support for the Building Blocks

a. Re-dispatch (Building Block 2) For Title IV purposes, Congress was aware that “utilities already engage in power-pooling arrangements to ensure maximum flexib ility and efficiency in supplying power.” 196 Some of these arrangements incorporated least-emissions dispatch for pollution control. 197 Leastemissions dispatch is a “relatively inexpensive approach to air pollution control” and has been considered a pollution control strategy since at least 1970. 198 It has been studied and used specifically to meet SO 2 and NO x emission limitations and also to meet heat discharge limits. 199
It was therefore logical to de sign an allowance system that took these arrangements into

account. 200 In fact, the Senate Report explained that “the Administra tor should be mindful that to exploit the efficiencies afforded by the allo wance system,” recognizi ng that parties would transfer allowances “between them and among themselves pursuant to a wide variety of commercial arrangements such as under leases, sales agreements and exchanges between emissions and electric power or capacity.” 201

b. Renewables (Building Block 3) To encourage the “use of renewable and cl ean alternative technol ogies,” Congress added Section 404(g) to establish “a renewable energy technology reserve within the allowance

195 Sen. Rep. No. 101-228, at 320 (Dec. 20, 1989).

196 Sen. Rep. No. 101-228, at 319 (Dec. 20, 1989).

197 See Sen. Rep. No. 101-228, 316 (Dec. 20, 1989) (recognizi ng “least-emissions dispatch ing” as an exploitable technology and strategy used to reduce emissions) and id. at 320 (discussing various commercial arrangements including emissions exchanges).

198 Shepard, Donald S., A Load Shifting Model for Air Pollution Control in the Electric Power Industry , Journal of the Air Pollution Control Association, Vol. 20:11, pp. 756-761 (November 1970).

199 See, e.g.

, Delson, Jerome K., Controlled Emission Dispatch , IEEE Trans. PAS, Vol. PAS-93, No. 5, pp. 1359- 1366 (1974); see also Tyle, Navin et al.

, Emission Constrained Dispatching of Electric Power , Paper ICTTE-92- 046, Presented at the International Congress on Technology and Technology Exchange (1982), Cadogan, J.B. and L. Eisenberg, Sulfur Oxide Emission Management for Electric Power Systems , IEEE Trans. PAS, Vo l. PAS-96, No. 2, pp. 393-400 (1977); and Friedmann, Paul G., Power Dispatch Strategies for Emission and Environmental Control

, Proc. ISA Power Institute Symp., Vol. 16 (1973).

200 See McDermott, K.A. and D.W. South, Argonne Nationa l Laboratory, Alternative Emission Cost Control Strategies for Electric Utilities: A Review, pp. 18-22 (Dec. 1990) (work sponsored by U.S. Department of Energy) (reproducing section 7 ( Electric Utilities: Alternative Emission Cost Control Strategies ) of South, D.W., et al.

, Technologies and Other Measures for Controlling Emissions: Performance, Cost and Applicability , which is NAPAP Rep. SOS/T 25, in Vol. IV of Acidic Deposition: State of Science/Technology (Dec. 1990)) (finding that “a least emission dispatch program can be used in conjunction w ith . . . trading programs.” The report also stated that “[e]nvironmental dispatching appears to be a viable strategy when used selectively and in tandem with other emission reductions strategies, such as fuel switching, conservation (demand-side management) or scrubber installations.”).

201 Sen. Rep. No. 101-228, at 320 (Dec. 20, 1989).86 system.” 202 The addition would encourage utilities to adopt renewable energy technologies, which, “along with increased energy efficienc y, can greatly reduce emissions of acid rain precursors and global warming gases.” 203 “That makes them a potent weapon against catastrophic climate change, widespread respirat ory disease, crop and forest damage, and the poisoning of our lakes and streams.” 204 “With a little foresight,” Senator Fowler explained, “we can also see that renewable syst ems can easily and cost-effectively be integrated into the existing utility sector, increasing power s upplies without increasing pollution.” 205
Allowances for emissions avoided through ener gy conservation and renewable energy would

be allocated on a first-come-first-served basis from the reserve pursuant to Section 404(f). Such

allowances would be issued to an electric utili ty for qualified energy c onservation measures or qualified renewable energy paid for “directly or through purchase from another person,” 206 such as “a third-party provider.” 207 By adding Section 404(f), Congress recognized that [c]onservation and renewables not only signifi cantly curtail sulfur dioxide emissions, but they emit little or no nitr ogen oxides and carbon dioxide, an d decrease the envionmental
[ sic ] degradation of land and water associat ed with oil imports and energy production. 208
Moreover, “[t]hese important e nvironmental attributes should make conserva tion and renewables a central part of the nation’s clean air policies immediately.” 209

2. Title IV Does Not Preclude Consideration of the Building Blocks as the BSER

These Title IV provisions and the accompanying statements in the legislative history make clear that Congress considered the tools proposed under buildings blocks 2 and 3 as appropriate and cost-effective methods to reducing emissions of SO 2 and NO x from fossil fuel-fired power plants. Congress was also clear that these tool s could be used “in combination” and in many

cases could be used to reduce emissions of CO 2 . Accordingly, these meas ures are appropriately within the scope of Sect ion 111(a)(1) and may be considered as the BSER.

Some commenters claim th at Title IV precludes regulation of the “electricity system as a whole” and that Sections 401(b) a nd 404(f) in particular prohib it EPA from considering building

blocks 2 and 3 as the BSER. As an initial matte r, this rule does not regulate the “electricity system as a whole.” All this rule provides is an emission guideline to assist States in establishing standards of performance for existing fossil fuel-fir ed power plants. The fact that power plants may serve an interstate electricity system doe s not mean that these same plants cannot be regulated under Section 111. Nor does regulating these same plants under Section 111 mean that EPA is regulating the electric ity system as a whole.

Second, neither the purpose statements in Sec tion 401(b) nor the credit ing instructions in Section 404(f) preclude consider ation of building blocks 2 and 3 under Section 111. These

202 Sen. Fowler, Sen. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA Legis. Hist. at 7103.

203 Sen. Fowler, Sen. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA Legis. Hist. at 7106.

204 Sen. Fowler, Sen. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA Legis. Hist. at 7106.

205 Sen. Fowler, Sen. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA Legis. Hist. at 7106.

206 42 U.S.C. § 7651c(f)(2)(B); CAA § 404(f)(2)(B).

207 Additional Views of Rep. Markey and Rep. Moorhead , H.R. Rep. No. 101-490, at 675 (May 17, 1990).

208 Additional Views of Rep. Markey and Rep. Moorhead , H.R. Rep. No. 101-490, at 674 (May 17, 1990).

209 Additional Views of Rep. Markey and Rep. Moorhead , H.R. Rep. No. 101-490, at 674 (May 17, 1990).87 provisions simply confirm that Congress designe d Title IV to “encourage” renewable energy technologies. Section 404(f) in particular prov ides additional incentives to credit sources for compliance with Title IV. Nothing in the text of Title IV nor in its le gislative history suggests that these provisions were intended to preclud e the consideration of certain “strategies and technologies” elsewhere under the CAA. Ind eed, these provisions highlight Congress’ preferences for cleaner and cost-e ffective measures to “reduce em issions of acid rain precursors and global warming gases.” 210 In fact, there is strong legi slative history indicating that

“conservation and renewables” were intended to become “a central part of the nation’s clean air policies immediately.” 211

XVII. Renewable Energy in SIPs

This section supports the determination in section V that building block 3 is an adequately demonstrated component of the BSER , by identifying additional examples in which

the States and the EPA have relied or are deve loping plans to rely, in CAA section 110 state implementation plans (SIPs), on renewable energy (RE) for emission reductions. It should be

noted that not all of these SIP measures have be en or may be limited to actions taken by fossil fuel-fired power plants themselves; some of these actions have been, or may be, government actions such as the governmental purchase of renewable energy certificates (RECs). These examples of governmental action are useful beca use they illustrate some of the types of nonBSER actions that are available fo r a state to meet its section 111( d) requirements. It should also be noted that while this section focuses on RE, it also makes occasional reference to demand-side energy efficiency (EE) projects in SIPs as well.

As the EPA noted in the proposal, SIPs alrea dy include RE measures to reduce the need for generation from the more polluting forms of energy generation, such as fossil fuel-fired

EGUs. See 79 FR at 34887-88. As the EPA noted, severa l states have already adopted RE measures in their SIPs for attaining and mainta ining the national ambien t air quality standards (NAAQS), and the EPA has provided init ial guidance for states to do so. 212 For example, in 2005, EPA approved inclusion of county government commitments to purchase 5 percent of their annual electricity consumption from wind power in Maryland’s SIP. 213 In 2007, Virginia, Maryland, and the District of Co lumbia submitted SIP revisions for the 1997 8-hr ozone in the Washington non-attainment area that included commitments by municipalities to purchase renewable energy certificates representing 123 million kWh of wind energy each year from 2004

to 2009. 214 Similarly, Connecticut’s 1997 8-hour ozone NAAQS SIP submittal Connecticut included solar photovolt aic installations. 215

210 Sen. Fowler, Sen. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA Legis. Hist. at 7106.

211 Additional Views of Rep. Markey and Rep. Moorhead, H.R. Rep. No. 101-490, at 674 (May 17, 1990).

212 See, e.g., Guidance on SIP Credits for Emission Reductions from Electric-Sector En ergy Efficiency and Renewable Energy Measures (Aug. 2004), http://www.epa.gov/ttn/oar pg/t1/memoranda/ereseerem

_ gd.pdf; Incorporating Emerging and Voluntary Measures in a State Implementation Plan (SIP) (Sept. 2004), http://www.epa.gov/ttn/oarpg/t1/memoranda/evm

_ ievm

_ g.pdf

213 70 Fed. Reg. 24,988 (May 12, 2005).

214 Id. at K-9.

215 CT 1997 8-hour ozone SIP Web site, http://www.ct.gov/deep/cwp/view.asp?a=2684&q=385886&depNav

_ GID=1619 (see Attainment88 Since those SIPs were submitted, many states have adopted legislative mandates for renewable energy, and the EPA has provided add itional guidance for including EE/RE projects in SIPs, which we refer to as the EE/RE Roadmap. 216 The EPA has also partnered with the

Northeast States for Coordinated Air Use Mana gement (NESCAUM) and th ree states (Maryland, Massachusetts, and New York) to identify opport unities for including EE/RE in a NAAQS SIP and to provide real-world examples and less ons learned through thos e states’ case studies. 217

In the EE/RE Roadmap, EPA recognized four “pathways” for incorporating EE and RE into SIPs: the baseline emissions projecti on pathway, the control strategy pathway, the emerging/voluntary measures pathway, and the we ight of evidence pathway. Of these four options, only the “control strategy” pathway resu lts in federally enforceable obligations with respect to EE and RE. A collection of fifteen States provided additiona l information to EPA noting some states may choose the federally-enf orceable control strategy pathway within their State Plans, and “EPA and the stat e would share enforcement authority.” 218 However, these States anticipated that most st ates would choose the “baseline em issions projection pathway” in which states would project the em issions reduction attributable to those programs over the course of the compliance period, to demonstrate that such programs “substantially limit section 111(d)

source emissions.” 219 These states went on to provide de tailed appendices for twelve states explaining the success of their various invest ments in EE and RE strategies for pollution

control. 220

Multiple commenters on the CPP responded to EPA’s request for comment on these issues and many, including states, strongly affirmed that the use of RE and EE in SIPs is now an accepted and growing practice. These commenters also provided greater detail on the various options states have for treating RE and EE in th eir SIPs, and urged EPA to encourage states to use its existing guidance on RE and EE, pa rticularly EPA’s 2012 EE/RE Roadmap, in developing plans under the CPP. 221

Demonstration TSD, Chapter 8 at 31, http://www.ct.gov/deep/lib/deep/air/regulations/proposed

_ and

_ reports/section

_ 8.pdf ).

216 U.S. EPA, Roadmap for Incorporating EE/RE Po licies and Programs into SIPs/TIPs (July 2012), http://epa.gov/airquality/eere/manual.html (hereinafter “EE/RE Roadmap”)

217 States’ Perspectives on EPA’s Roadmap to Inco rporate Energy Efficiency/Renewable Energy in NAAQS State Implementation Plans: Three Case Studies, Final Report to the U.S. Environmental Protection Agency (Dec. 2013), http://www.nescaum.org/documents/n escaum-final-reptto-epa-ee-innaaqs-sip-roadmap-case-studies-20140522.pdf

. 218 States’ Roadmap, at 32.

219 Id.

220 Id. at 34-57.

221 See Alliance to Save Energy, Comments on the Clean Power Plan, at 10 (Nov. 24, 2014) (hereinafter “Alliance Comments”) (“We urge EPA to emphasize the applicability of [the RE/EE Roadmap and other resources] and to provide pertinent training and technical assistance to fac ilitate inclusion of EE in state CPP compliance.”); States’ Roadmap on Reducing Carbon Pollution, Attach. at 20 (D ec. 16, 2014) (hereinafter “States’ Roadmap”) (“The [2012] Roadmap discusses all three of our strategies, including energy efficiency programs, emissions trading systems, and renewable portfolio standards which can help reduce grid-level emissions. Those same strategies work to reduce greenhouse gas pollution as well.”).89 EPA has continued to work closely with stat es engaged in pioneer ing efforts to reduce power plant pollution through RE measures. Fo r example, EPA has collaborated with the Connecticut Department of Environmental Protec tion (CTDEP) to develop pathways for the state to use its renewable portfolio standard (RPS) requirements and extensive energy efficiency programs for CAA planning and compliance under section 110. 222 Having assessed the effect of its EE and RE projects on NO X emissions during high demand days as part of the weight of evidence analysis in its 2007 8- hr ozone attainment demons tration, CTDEP contacted EPA Region 1 for guidance on additional opportunities for incorporating RE and EE programs into its CAA planning. 223 Region 1 responded by providing CTDEP with a guidance letter outlining key issues and questions for CTDEP to consider in incorporating RE/EE meas ures into its SIP as federally enforceable control measures, in particul ar, discussing the four key criteria: permanent, enforceable, quantifiable, and surplus. 224

Commenters on the proposal have also noted that recently developed tools – particularly, EPA’s AVERT system 225 -- facilitate the calculation of the amount of emission reductions available from RE, as well as EE. AVERT relie s on publicly available and auditable data maintained by EPA to estimate the emission benefits of RE and EE policies and programs, including reductions in carbon di oxide. States, PUCs, analysts, and environmental agencies are currently using AVERT to lower th e costs of their analytical wor k, ensure and improve electric supply reliability, and diversify their energy supply portfolios. 226 Commenters have noted that AVERT, along with EPA’s new guidance materials, will significantly ease the quantification and documentation issues with RE, as well as EE. 227

XVIII. EPA Transport Rulemakings and the Building Blocks

This section supports the preamble section V di scussion concerning the in tegrated nature of the electricity sector and the determinations that building blocks 2 and 3 are adequately demonstrated by pointing out similar statements and conclusions that the EPA made in the transport rulemakings, the NOx SIP Call, Clean Ai r Interstate Rule (CAIR), and Cross-State Air Pollution Rule (CSAPR).

The EPA’s regulatory initiatives under th e CAA’s “good neighbor” provision in section 110(a)(2)(D)(i)(I) have recognized the unique opportunities availabl e for reducing emission from

fossil fuel-fired EGUs. The EPA’s NO x SIP Call, CAIR, and CSAP R have recognized that emissions from EGUs can be reduced through many of the building-block mechanisms identified

222 EE/RE Roadmap, Appendix K, at K-9-K-10, K-12-14.

223 Id.

224 Id. at K-14-K-15, K-32-K-38.

225 See “Avoided Emissions and geneRation Tool (AVERT),” http://epa.gov/avert/ (last updated May 21, 2015).

226 AVERT, Fact Sheet for Deci sion Makers, available at http://www.epa.gov/statelocalclimate/documents/pdf /AVERT%20Decision%20Makers%20Fact%20Sheet%202-13- 14%20Final_508.pdf

227 See Alliance Comments, at 10 (“AVERT, though it has some li mitations, is an easy-to-use tool that can provide adequate calculations of avoided emissions.”).90 as part of the BSER in this rule, as well as from demand-side energy efficiency. Commenters noted these salient precedents as well. 228

A. Building Block 2 – Generation Shifts Among Affected EGUs

1. NO
x SIP Call

In the NO x SIP Call, the EPA calculated the stat e emission budgets in part based on the degree of emission reductions that could be achieved from EGUs by applying feasible and highly

cost-effective controls. 229 The EPA determined that one set of highly cost-effective controls for EGUs was an intrastate program that allowed EGUs to meet an average emission rate of 0.15

lbs/mmBtu. 230 The EPA explained that it had determined that these controls were highly-cost effective because, “ considering changes in dispatch and other aspects of the future of the nation’s power system,” the projecte d average costs were $1,499 per ton. 231 This mirrored EPA’s approach at the proposal stage, during which the EPA also clearly considered generation shifting to be a legitimate way to reduce NO x emissions from EGUs:

System NO x emissions can be reduced in several ways . One way is through dispatch decisions, by increasing gene ration from lower-emitting units, while decreasing the use of higher-NO
x units . For States covered by the Ozone Transport Rulemaking, the model results di d indicate lower leve ls of generation from fossil-fueled units under the proposed regulatory approach. 232

2. CAIR

In CAIR, the EPA noted the importance of regulating EGUs in a holistic manner that takes into account the generation shifting faci litated by the interconnected nature of the electricity grid, and the fact that all EGUs pr oduce an identical product— electricity. Several of EPA’s decisions regarding CAIR were influenced by the practical reality of generation shifting in the utility power sector.

In some instances, the EPA recognized that because shifting gene ration also shifts emissions in way that could interfere with CAIR ’s air quality goals, it was important that any regulation of EGUs under CAIR apply to all E GUs. For example, the prospect of generation shifting led the EPA to reject commenters’ sugge stion to exclude all cogeneration units from CAIR’s model cap-and-trade program. 233 Instead, the EPA found it “important to include in the CAIR Program all units, includi ng cogeneration units, s ubstantially in the business of selling electricity,” because:

228 See, e.g. , EDF 111(d) Comment at 21–23.

229 63 FR at 57362.

230 63 FR at 57401.

231 63 FR at 57401 (emphasis added).

232 NO

x SIP Call Proposal RIA at 2-16 (emphasis added).

233 70 FR 25162, 25277.91 Inclusion of all units substa ntially in the electricity sales business minimizes the potential for shifting utilization, and em issions, from regulated to unregulated

units in that business and th ereby freeing up allowances, w ith the result that total emissions from generation of electricity for sale exceed the CA IR emissions caps. The fact that units in the electricity sales business are gene rally interconnected through their access to the grid significan tly increases the potential for utilization shifting. 234

The EPA’s requirements for state transport SIPs submitted under CAIR were similarly influenced by the prospect that generation shifting among EGUs coul d undermine CAIR’s air quality goals. The EPA explained that if a stat e wished to meet is good neighbor obligation under CAIR by limiting emissions from EGUs , it would have to impose limits on all EGUs:

The requirement to cap all EGUs is impor tant because it prevents shifting of utilization (and resulting em issions) to uncapped EGUs. The EGUs are part of a highly interconnected electricity grid t hat makes utilizati on shifting likely and

even common . The units are large and offer the same market product ( i.e.

, electricity), and therefore the units that ar e least expensive to operate are likely to be operated as much as possible. If ca pped and uncapped units are interconnected, the uncapped units’ costs w ould tend to decrease rela tive to the capped units,

which must either reduce emissions or use or buy allowances, and the uncapped units' utilization would likely increas e. The cap ensures that emissions

reductions from these interconnected sources ar e actually achieved rather than emissions simply shifting among sources. The caps constitute the State EGU Budgets for SO 2 and NO x
. 235

The potentially negative consequence of genera tion shifting between regu lated and unregulated

EGUs drove the EPA’s decisions to include ce rtain cogeneration units in the CAIR model trading program, and to require that any state regulation of EGUs under CAIR apply to all EGUs. Similarly, the decision whether EGUs built on Tribal lands would have to be included in an EGU cap-and-trade program turned on the potential fo r generation shifting across an interconnected electricity grid:

. . . in the event of any future planne d construction of EGUs on Tribal lands within the CAIR region, EPA intends to work with the relevant Tribal government to regulate the EGU through either a Tribal implementation plan (TIP) or a Federal implementation plan (FIP ). We anticipate that at a minimum, a proposed EGU on a reservation within a St ate participating in the CAIR cap and trade program would need to be made subj ect to the cap and trade program. In the

case of a new EGU on a reservation in a CAIR-affected State which chose not to participate in the cap and trade progra m, the new EGU might also be required, through a TIP or FIP, to pa rticipate in the program. This would depend on the potential for emissions shifting and other specific circumstan ces (e.g., whether the

234 70 FR 25162, 25277 (emphasis added);

235 70 FR at 25256–57 (emphasis added).92 EGU would service the elect ric grid of States invo lved in the cap and trade program.) 236

The EPA was not only motivated in CAIR to de velop a rule that would avoid the negative consequences of generation shifting between regu lated and unregulated EGUs. The Agency was also influenced by the opportuni ties that generation shifting presented as a compliance option. For example, the EPA considered whether cer tain EGUs smaller than 250 MW should be included in the CAIR budgets and model rule, give n commenters’ claims that inclusion in CAIR

would cause these smaller EGUs to shut down. 237 The EPA declined to set a cut-off at 250 MW, noting its projections that “some [EGUs] below 250 MW” would im plement highly costeffective controls, and that smaller EGUs “also have the option to . . . alter dispatch, and/or purchase power ” as a means of compliance. 238

3. CSAPR

In evaluating the costs for CSAPR, the EPA pr ojected that fossil-fu el-fired EGUs would achieve emission reductions through, inter alia , “increased dispatch of more efficient units and lower-emitting generation technologies (e.g., some reduction of coal-fired generation with an increase of generation from natural gas).” 239

The EPA established the stringency of CSAP R’s deadlines based on the fact that EGUs were expected to engage in generation shifting. For example, in quantifying the state budgets for CSAPR, the EPA assessed the emission reductions that EGUs could achieve at various cost thresholds. The ability of EGUs to engage in generation shifting directly influenced the stringency of state budgets. For example, the EPA based 2012 requirements for “Group 1” states

on the emission reductions emissions that EGUs were expected to achieve by implementing controls that cost up to $500/ton. The EPA decide d that a certain quantity of emission reductions

was “feasible” at that cost threshold because a ffected EGUs could cheaply and efficiently reduce emissions by generation shifting to lower-emitting sources:

EPA applied escalating SO 2 cost per ton thresholds for Group 1 states to create the cost curves for 2014 and beyond. For 2012 SO 2 , the cost per ton was held constant at $500/ton as the cost thres holds in 2014 and beyond were varied. The advanced pollution controls incentivized by these higher cost-per-ton levels can reasonably be installed by 2014. EPA also considered whether any of these emission reductions could be achieved prio r to 2014. For the reasons that follow, EPA concluded that significant reducti ons could be achieved by 2012 and that it is important to require all such reduc tions by 2012 to ensure that they are achieved as expeditiously as practicable. SO 2 and NO
x reductions come from operating existing controls, installing com bustion controls, fuel switching, and

236 70 FR at 25168 (emphasis added).

237 70 FR at 25276.

238 70 FR at 25276; U.S. EPA, Corrected Response to Significant Public Comments on the Proposed Clean Air

Interstate Rule , Docket No. OAR-2003-0053-2172 at 158–59 (April 2005) (emphasis added).

239 Regulatory Impact Analysis (RIA) for the Final Transport Rule, Docket ID No. EPA-HQ-OAR-2009-0491 at 255–56 (June 2011), available at http://www.epa.gov/airtran sport/pdfs/FinalRIA.pdf.93 increased dispatch of lower-emitting ge neration which can be achieved by 2012. In general, compliance mechanisms that do not involve post-combustion control installation are feasible before 2014. For this reason, EPA believes it is appropriate to require these em issions to be removed in 2012 , consistent with the Act's requirement that downwind states attain the NAAQS as expeditiously as practicable.

Therefore, all of the cost curves pr esented below include all feasible 2012 reductions up to a threshold of $ 500/ton for SO 2 and $ 500/ton for annual NO

x in states linked to receptors for PM 2.5 , as well as $ 500/ton for ozone-season NO

x in states linked to receptors for ozone. These cost per ton levels do not precipitate advanced post-combustion c ontrol installation in 2012 (as EPA acknowledges that such installations are not feasible by 2012), but they do promote the compliance options outlined above

. 240

EPA’s selection of a $500 threshol d “reflect[ed] an amount of . . . generation shifting that can be achieved for $500/ton.” 241 Had EPA ignored the reality of ge neration shifting when determining the CSAPR requirements, the 2012 budgets EPA set based on feasibility would have been less stringent than they ended up being.

It made sense for EPA to take generation shifting into account when setting the CSAPR budgets because, at all compliance stages, EP A projected that gene ration shifting was a technique that EGUs would actua lly engage in as a means of reducing emissions: The electric utility sector would meet 2012 NO x requirements by, inter alia , “dispatching lower emitting units

more often . . . .” 242 For the 2012 SO 2 requirements, EPA projected th at, “the fleet will increase dispatch from lower-sulfur-emitting units as we ll as from natural gas-fired generators.” 243 For the 2014 phase 2 compliance deadline, EPA pr ojected that sector would reduce SO 2 by “dispatch[ing] lower emitting generation units.” 244

B. Building Block 3 – Renewable Energy

The following describes the role that RE played in the transport rules, and also mentions the roles that energy efficiency, both supply side (building block 1) and demand-side (building block 4) played in those rules. While the EP A relied on other measures as the basis for the control requirements, it recognized that RE could be used for compliance and encouraged that

use.

1. NO
x SIP Call

240 76 FR at 48252 (emphasis added).

241 76 FR at 48280.

242 76 FR at 48279.

243 76 FR at 48279; see also id. at 48280 (describing EPA’s modeling showing that for SO 2 , EGUs would use “changes in dispatch and generation shifting from higher emitting units to lower emitting units” as a means of meeting requirements).

244 76 FR at 48281.94 In the NO x SIP Call, the EPA noted that NO X emissions from EGUs could be reduced through efficiency projects that improve EGU heat ra te (referred to in the instant rule as building block 1), and by replacing generation at existin g EGUs with generation from renewable energy projects (building block 3). 245 The EPA also noted that demand-side EE programs can reduce

emissions from EGUs. The NO x SIP Call’s emission budgets were ultimately based on “highly

cost-effective measures” that did not include these methods of reducing EGU emissions. 246
However, the EPA recognized that heat rate improvement, renewable energy, and demand-side EE programs could be part of a “cost-effective NO X reduction strategy” for EGUs, including as part of an emission trading program:

The EPA believes that, with respect to E GUs, there is a large potential for energy efficiency and renewables in the NO x SIP call region that reduce demand and provide for more environmen tally-friendly energy resour ces. For example, if a company replaces a turbine with a more efficient one, the unit supplying the

turbine would reduce the amount of fuel (heat input) the unit combusts and would

reduce NO x emissions proportionately, while the associated generator would produce the same amount of electricit y. Renewable energy source generation includes hydroelectric, solar, wind, and geothermal generation. EPA recognizes that promotion of energy efficiency a nd renewables can contribute to a costeffective NO x reduction strategy. As such, EP A encourages States in the NO x SIP call region to consider incl uding energy efficiency and re newables as a strategy in meeting their NO x budgets. One way to achieve this goal is by including a provision within a State’s NO x Budget Trading Rule that allocates a portion of a State’s trading program budget to impl ementers of energy efficiency and renewables projects that reduce energy-related NO x emissions during the ozone

season. Another is to include energy efficiency and renewabl es projects as part of a State’s implementation plan. 247

The EPA’s treatment in the NO x SIP Call of heat rate improveme nts, renewable energy projects, and demand-side energy efficiency as “additiona l control measures” for reducing emissions from

EGUs further illustrates how the EPA has enc ouraged sources and states to leverage the integration of the utility power sector to reduce emissions. 248 Indeed, when some commenters expressed concern that the NO x SIP Call provided insufficient time for the construction, procurement, and installation of add-on polluti on controls at EGUs, the EPA allayed those concerns in part by pointing to the “NO x -reducing benefits that energy efficiency and renewables projects provide, many of which could be devel oped in less than three years and incorporated

into a SIP.” 249 With respect to cost, the EPA noted that for many states, “energy efficiency and renewable energy actions may be the least cost method of compliance with the requirements of

245 63 FR 57356, 57359, 57438 (Oct. 27, 1998).

246 See, e.g.

, 63 FR at 57405.

247 63 FR at 57438.

248 See 63 FR at 57438 (discussing these measures as distinct from control measures for reducing emissions from non-EGU stationary sources, or from mobile sources).

249 63 FR at 57449.95 the SIP Call,” and opened the door for states to award emission trading allowances for energy efficiency and renewable energy projects. 250

In that vein, the EPA established a NO x Budget Trading Program to facilitate states’ implementation of an interstate trading program, and included an option for states to set-aside allowances for renewable energy and energy efficiency projects. 251 The EPA explained that “the

Clean Air Act Amendments of 1990 and the Po llution Prevention Act (PPA) of 1990 recognize the significant role that energy efficiency and renewable energy resource s can play in reducing pollution and achieving the na tion’s environmental goals.” 252 These set-aside pools of allowances are for “energy efficiency and rene wable energy projects th at reduce electricity generation,” and thereby “reduce em issions of pollutants, including NO x .” 253 The EPA’s Climate Protection Division explained in gu idance for the set-asides that this voluntary option for states “focuses primarily on end-use electricity effici ency and renewable energy actions, since the amount and source of electricity consumed by end-users affects the quantity of NO x emitted at an electricity generating unit (EGU).” 254 By 2005, seven states had incorporated such energy efficiency and/or renewable energy programs into their NO x Trading Program budgets, 255
reflecting the reality that “[e]nergy efficiency and renewable energy resources can result in reductions of fossil-fuel energy use, which are a primary cause of pollution emissions.” 256

2. CAIR

As some commenters noted, CAIR con tinued in the tradition of the NO x SIP Call by allowing the use of allowance set-asides for renewables and energy efficiency. 257 The EPA explained that in allocating allowances, “States are welcome to use set-asides” to “promot[e] energy efficiency or renewables.” 258 The EPA also promulgated an example method for allocating allowances based in part on electri cal output, and noted that “states may choose to include non-emitting generation (such as renewa bles)” within that type of approach. 259

250 U.S. EPA, Responses to Significant Comments on the Proposed Finding of Significant Contribution & Rulemaking for Certain States in the Ozone Transport Assessment Group (OTAG) Region for Purposes of Reducing Regional Transport of Ozone , Docket No. A-96-56 VI-C-1 at 332–33 (Sept. 24, 1998).

251 See U.S. EPA, Guidance on Establishing an Energy Efficiency and Renewable Energy (EE/RE) Set-Aside in the

NO

x Budget Trading Program , vol. 1 (March 1999); id. vol. 2 (April 2000); id. vol. 3 (July 2007).

252 U.S. EPA Climate Prot. Div., Guidance on Establishing an Energy Efficiency and Renewable Energy (EE/RE)

Set-Aside in the NO

x Budget Trading Program , vol. 3 at ii (July 2007) (citing as an example the Clean Air Act’s “encouragement of energy conservation and renewabl e energy resources in the Acid Rain Program”).

253 U.S. EPA Climate Prot. Div., Guidance on Establishing an Energy Efficiency and Renewable Energy (EE/RE)

Set-Aside in the NO

x Budget Trading Program , vol. 3 at ii (July 2007).

254 U.S. EPA Climate Prot. Div., Guidance on Establishing an Energy Efficiency and Renewable Energy (EE/RE)

Set-Aside in the NO

x Budget Trading Program , vol. 3 at ii (July 2007).

255 U.S. EPA U.S. EPA Climate Prot. Div., Guidance on Establishing an Energy Efficiency and Renewable Energy (EE/RE) Set-Aside in the NO

x Budget Trading Program , vol. 3 at 1-5 (July 2007).

256 U.S. EPA U.S. EPA Climate Prot. Div., Guidance on Establishing an Energy Efficiency and Renewable Energy (EE/RE) Set-Aside in the NO

x Budget Trading Program , vol. 3 at i (July 2007).

257 See, e.g. , 70 FR 25162, 25279 (May 12, 2005).

258 U.S. Envtl. Prot. Agency, Corrected Response to Significant Public Comments on the Proposed Clean Air

Interstate Rule , Docket No. OAR-2003-0053-2172 at 797 (April 2005).

259 U.S. Envtl. Prot. Agency, Corrected Response to Significant Public Comments on the Proposed Clean Air

Interstate Rule , Docket No. OAR-2003-0053-2172 at 114 (April 2005); 70 FR at 25280.96 3. CSAPR

When EPA promulgated CSAPR as a replacemen t for CAIR, much of the prior rule’s treatment of renewables and energy efficiency carried over. For example, EPA took comment on

two mechanisms for states to submit SIPs that would satisfy CSAPR, both of which allowed the state to allocate allowances to “renewable energy facilities.” 260

XIV. Stack Height Emissions Balancing Polic y, BB-2, and the Integrated Electricity Sector

This section supports section V of the pream ble by describing how the 1988 Stack Height Emissions Balancing Policy recognized the integr ated electricity sector and the usefulness of shifting dispatch to lower emitting sources as a means of emissions reduction.

In 1988, the EPA issued the Stack Height Emissions Balancing Policy, 261 which implemented the revised stack height regula tion, issued under CAA section 123, on July 8, 1985. This 1988 policy addresses the special case of “l ower emissions dispatch,” which explicitly couples the curtailment of operations at high -emitting EGUs with increased use of wellcontrolled EGUs to assure overall emission reduc tions, and authorizes its use where specified

criteria are met. 262

In 1977, Congress added CAA section 123 in order to address the use of “dispersion techniques,” such as unnecessa rily tall smokestacks, as a me thod of obtaining less stringent

emission limitations. 263 Dispersion techniques are techni ques that lower the predicted groundlevel concentrations of a pollutant, 264 for example by using excessi vely tall stacks that exceed “good engineering practice” (GEP), or vary ing emissions based on weather conditions. 265
Congress saw these attempts to obtain less string ent emission limitations by diluting emissions as antithetical to the polluti on-reducing goals of the CAA. 266 In order to eliminate the incentive to use dispersion techniques, secti on 123 provides that the “degree of emission limitation required” from a source may “not be affected in a ny manner” by that source’s use of dispersion

260 76 FR 48208, 48326–28 (Aug. 8, 2011) (“the state may allocate allowances to . . . renewable energy facilities”).

261 53 FR 480 (Jan. 7, 1988).

262 53 FR at 480, “Detailed Response to Public Comme nts on the December 23, 19 85 Proposal,” pp. 2-3.

263 For example, if a source built a tall enough smokestack in a nonattainment area, the pollutants would be diluted in the atmosphere and not contribute as much (if at all) to monitors in the area. Section 123 was intended to eliminate this incentive to use unnecessarily tall stacks, which Congress saw as an improper “attempt to use dispersion rather than clean up.” S. Rep. No-94-1742 ( accompanying S. 3219), as found in 5 Legislative History of

Clean Air Act Amendments of 1977 at 4435.

264 50 Fed. Reg. 52418, 52418 (Dec. 23, 1985).

265 See 40 C.F.R. § 51.100(hh)(1).

266 See, e.g. , S. Rep. No-94-1742 ( accompanying S. 3219), as found in 5 Legislative History of Clean Air Act Amendments of 1977 at 4435 (calling these techniques improper “attempt to use dispersion rather than clean up”).97 techniques. 267 Thus, for example, sources with unnecessa rily tall stacks that dispersed pollutants

would be treated for standard-set ting purposes as if those stacks “were note excessively ‘tall.’” 268

Congress understood that the costs of comply ing with these more stringent limits could be high, and accordingly grandfathered-in some older sources with tall stacks. 269 For the other sources with unnecessarily tall stacks, or that ha d been using other disper sion techniques, section 123 and EPA’s implementing regulations meant that they would have to comply with more stringent (and costly) emission limitations. 270

In order to ameliorate cost concerns for tall-stacked sources, EPA in 1988 promulgated a “Stack Heights Emission Balancing Policy.” 271 That policy allowed these sources “to meet more stringent emission limitations re quired by the revised stack height regulation by securing

emission limitations from anot her source or sources . . . .” 272

In evaluating how to apply the Emission Balancing Policy, EPA recognized that the integrated nature of the electricity system provided unique opportunities for EGUs affected by stack height rules to reduce their emissi ons through “lower emission dispatch”:

“Lower emissions dispatch” is the term used in this policy to describe a utility company, holding company, or powerpool management strategy to control emissions by decreasing electricity pr oduction at higher emitting (e.g., higher

lbs/10 6 Btu) power plants , and increasing electricity production at lower emitting (cleaner) power plants , rather than distributing (dispatching) electricity production solely on the basis of least cost. 273

Provided that sources could show “enforceable , easily monitored procedures for assuring equivalent emission reductions,” EPA committed itself to reviewing proposals to reduce EGU emissions through lower emission di spatch on a case-by-case basis. 274 EPA further recognized, however, that the integrated natu re of the electricity grid required a system-wide approach to ensuring that emission reductions achieved from some EGUs we re not obviated by increased

emissions from others:

267 42 U.S.C. § 7423(a)(1).

268 53 Fed. Reg. at 481; 50 Fed. Reg. 27,892. For example, if a so urce’s 100-meter stack ex ceed good engineering practices by 35 meters, that source would be treated for emission modeling and standard-setting purposes as if its stack was only 65-meters tall. Under the legal fiction of that shorter stack, the source’s emissions would have a more significant effect on the ambien t air, and the source would likely be subject to more stringent emission

limitations.

269 See 42 U.S.C. § 7423(a) (grandfathering in “stack heights in existence befo re December 31, 1970”).

270 See 50 Fed. Reg. 52418, 52418 (Dec. 23, 1985).

271 53 Fed. Reg. 480 (Jan. 7, 1988).

272 53 Fed. Reg. 480, 481 (Jan. 7, 1988) . The crediting sources are required to be in the same state or air quality control region as the affected source, and offsetting reductions must be in a 1:1.2 ratio in order to ensure

environmental benefits are achieved. Id.

273 53 Fed. Reg. 480, 482 (Jan. 7, 1988) (emphasis added).

274 53 Fed. Reg. 480, 482 (Jan. 7, 1988).98 EPA believes that the potential for sh ifting production demand (e.g., increased dispatching) to less well-c ontrolled sources as a result of an emissions balance could generally be offset by use of such practices as an enforceable system of production constraints (i.e ., caps and floors) and emission limits selected. However, in the case of lower emissi on dispatch (LED), methods by which

emission reductions are calculated and enforced may have to be expanded to include consideration of changes in capaci ty factors for all sources in a system affected by the proposed LED approach. 275

XV. Emissions Trading

This section supports section V of the pream ble by describing EPA rules, primarily for the electric power sector, that rely on emissions trading.

As discussed in section V., EPA has promulga ted numerous rules, under the authority of several CAA provisions, that base emission reduc tion obligations on the ab ility of sources to engage in emissions trading and purchase emissi on reduction credits from other sources. In purchasing emission reduction credits to achieve an emission limit – which, in the present rule, is one of the measures to implement building blocks 2 and 3 – the source must engage with other

entities to achieve its emission limit. In the cas e of emissions trading, th e source typically does not itself implement measures with in its facility to control its emissions, but instead depends on

other entities to sell it allowan ces or emission reduction credits, which the other entities typically are able to sell because they have controlled their own emissions.

A. Clean Air Mercury Rule

The EPA’s 2005 Clean Air Mercury Rule 276 was “a nationwide inte rstate cap-and-trade program for mercury, with mercury allowances fu lly allocated at the le vel authorized by the

Administrator and with full and unr estricted participation by affect ed sources in all 50 states.” 277
By establishing a cap-and-trade program for me rcury, EPA projected that mercury reductions would “result from units that are most cost effective to control, which enables those units that are not cost effective to use other approaches fo r compliance including buyi ng allowances, switching fuels, or making dispatch changes.” 278 This program enabled EPA to set the cap’s stringency at a level commensurate with widespread compliance (whereas if the cap were based solely on the installation of control technologi es, the cap would not be cost-effective for the source category).

In CAMR, the EPA determined the BSER to be the cap-and-trade program:

275 “Detailed Response to Public Co mments on the December 23, 1985 Pro posal,” Docket No. A-85-05 at 2–3 (accompanying 53 Fed. Re g. 480 (Jan. 7, 1988)).

276 70 Fed. Reg. 28606 (May 18, 2005). CAMR was vacated by the D.C. Circuit on account of the EPA’s flawed CAA section 112 delisting rule, although the court dec lined to reach the merits of th e EPA’s interpretation of CAA section 111(d). New Jersey v. EPA , 517 F.3d 574 (D.C. Cir. 2008).

277 Comments of the Utility Air Resources Group on the Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units and Su pplemental Notice, 133 (June 29, 2004).

278 70 Fed. Reg. 28606, 28619 (May 18, 2005).99 EPA must next ‘‘determine’’ that such a sy stem is ‘‘the best system of emissions reductions which (taking into account th e cost of achieving such reduction and any nonair quality health and environmenta l impact and energy requirements) * * * has been adequately demonstrated.’ ’ (See CAA section 111(a)(1).) EPA has determined that a cap-and-trade progra m based on control technology available in the relevant timeframe is the best system for reducing Hg emissions from existing coal-fired Utility Units. 279

The EPA justified this determination by reviewin g the successful cap-and -trade programs for EGUs in Title IV and the 1998 NOx SIP Call, and concluded:

The success of the Acid Rain cap-and tr ade program for utility SO2 emissions, which EPA duplicated in large measur e with the NOX SIP Call cap-and-trade program for, primarily, utility NO x emission[ns] from utilities qualifies as the “best system of emission reductions” that “has been adequately demonstrated.” 280

That interpretation was recognized by industry commenters as “reasonable,” 281 indeed, “compelling.” 282 Industry commenters argued that a “cap-and-trade program . . . is the best way to produce the largest mercury reducti ons in the most efficient manner.” 283 Their views aligned with EPA’s recognition that “[a] uthorizing the allowances to be traded maximizes the costeffectiveness of the emissions reducti ons in accordance with market forces.” 284 These commenters supported the EPA in defending the nationwide intersta te cap-and-trade program in

the D.C. Circuit. 285

B. NOx SIP Call

In the NO x SIP Call, the EPA set emission budgets based in part on the emissions reductions that EGUs could achieve by implemen ting highly cost-effect ive controls. The EPA “assumed an emissions trading system” when asse ssing the costs—and thus the appropriate level

of control—for EGUs to reduce emissions of NO x
. 286 Ultimately, the Agency “decided to base

279 70 FR at 28617.

280 70 FR at 28617.

281 Comments of the Utility Air Resources Group on the Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units and Su pplemental Notice, 133 (June 29, 2004).

282 Joint Brief of State and Industry Respondent-Intervenors, at 25, New Jersey v. EPA (May 18, 2007) (“EPA has offered compelling legal justifications for a mercury cap-and-trade program”).

283 Comments of the Utility Air Regulatory Group on the Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units and Supplemental Notice, 5 (June 29, 2004).

284 70 Fed. Reg. 28606, 28616 (May 18, 2005).

285 Commenters went even further by arguing that state plans could not deviate from the trading program set up by

EPA. See, e.g.

, Brief of Petitioner Utility Air Regulatory Group, State of New Jersey, et al. v. EPA , No. 05-1097 (D.C. Circuit) (Jan. 12, 2007). The argu ment reasoned that by allowing states to deviate, individual states could “unilaterally establish a new cap that is contrary to EPA’s ‘best system.’” Brief of Petitioner, at 8.

286 63 FR at 57400.100 the emissions budgets for EGUs on a 0.15 lb/mmBtu trading level of control.” 287 To facilitate compliance, the EPA established a NO x Budget Trading Program— “a compliance mechanism that capitalizes on a proven means of cost eff ectively meeting a specific emissions budget” that

EPA could assist states with administering. 288

The EPA’s identification of EGUs’ ability to comply with emission limits by purchasing

allowances affected the NO x SIP Call’s emission reductions re quirements in several ways. For example, the availability of trading affected EPA’s assessment of the cost-effectiveness for the chosen level of controls. At the proposal stage, the EPA explained that its “approach to the NO x budget component for the electric power industry re lies on consideration of the States using [an interstate] cap-and-trade program to redu ce emissions from this source category.” 289 An interstate trading approach, the EPA explained, “is 25 percent more cost effective (lower in cost per ton reduced) than the use of a comparable traditional command-and-control approach, such as setting rate-based NO x emission limitations . . . at every source.” 290

As a second example, the availability of trad ing greatly influenced the EPA’s decision to base budgets on a uniform rate applicable to all fossil fuel-fired EGUs. On e of the decisions the

EPA made was to base emissions reductions on a uniform 0.15 lb/mmBtu control level applicable to all EGUs, regardless of the fact that the costs of meeting that standard differ based on EGU fuel type. 291 The EPA explained that these cost differences did not undermine the feasibility of a 0.15 lb/mmBtu approach because EGUs could trade with each other: “Because

the EPA envisions a market for NO x allowances, transfers of allowa nces from low-cost to highcost units will tend to equalize the marginal costs of control across all affected units.” 292
Because of the availability of trading, it was thus appropriate to consider average costeffectiveness for all EGUs:

In this rulemaking, EPA has chosen to focus on an average cost-effectiveness measure in identifying highly cost-effectiv e control options for several reasons. Since EPA's determination for the core group of sources is based on the adoption of a broad-based trading program , average cost-effectiveness serves as an adequate measure across sources because sources with high marginal costs will be able to take advantage of this program to lower their costs. 293

287 63 FR at 57401–02.

288 63 FR at 57458.

289 62 FR 60318, 60349.

290 62 FR at 60349; see U.S. EPA, Responses to Significant Comments on the Proposed Finding of Significant Contribution & Rulemaking for Certain States in the Ozone Transport Assessment Group (OTAG) Region for Purposes of Reducing Regional Transport of Ozone , Docket No. A-96-56 VI-C-1 at 217–18 (Sept. 24, 1998) (stating that in calculating the emissions reductions required from sources in each state, “a cap and trade approach is better than an [alternative] rate-based appro ach because it is more cost-effective”).

291 U.S. EPA Responses to Significant Comments on the Proposed Finding of Significant Contribution & Rulemaking for Certain States in the Ozone Transport Assessment Group (OTAG) Region for Purposes of Reducing Regional Transport of Ozone , Docket No. A-96-56 VI-C-1 at 217 (Sept. 24, 1998).

292 U.S. EPA Responses to Significant Comments on the Proposed Finding of Significant Contribution & Rulemaking for Certain States in the Ozone Transport Assessment Group (OTAG) Region for Purposes of Reducing Regional Transport of Ozone , Docket No. A-96-56 VI-C-1 at 217 (Sept. 24, 1998).

293 63 FR at 57399 (emphasis added).101 Accordingly, although the EPA concluded that, wh ile it might be less cost-effective for some

individual EGUs to meet an emission rate thr ough installing on-site cont rols, overall those EGUs could purchase allowances through a trading program, so that ove rall the emission rate remained highly cost-effective. 294 This was despite the differences in feasibility for gas and oil-fired EGUs compared to coal-fired EGUs:

In terms of the proposed level of contro l on which the trading program budget is based, EPA believes that trading at 0. 15 lb/mmBtu is feasible because the proposed limit can readily be achieved by ga s and oil-fired boilers. In fact, more than 50 percent of gas and oil-fi red boilers already operate at NO x levels below 0.15 lb/mmBtu and should readily be able to generate emission credits if affected States join a trading program.

The EPA recognizes that for coal-fired boilers to operate at or below a 0.15 lb/mmBtu emission limit, SCR would gene rally be necessary. Under a trading scenario, however, if one coal-fired boiler is able to emit below 0.15 lb/mmBtu by installing SCR, it can provide emission cr edits to another co al-fired boiler and

obviate the need for that sec ond boiler to install SCR.

* * * In summary, EPA believes that an emi ssion rate of 0.15 lb/mmBtu reflects the greatest emissions reduction that EPA can confidently conclude is feasible and that is highly cost-effective . . . . 295

The EPA projected that EGUs with the most cost -effective control possibilities would be “tightly controlled, at significant cost” becau se of the incentive to sell allowances to EGU owners who

“elect to under-control their plants’ emission.” 296 Accordingly, although the cost to reduce emissions would vary across EGUs, the existing of an emission trading market would level compliance costs. For purposes of modeling th e emissions, cost, and economic impact of the

NO x SIP Call:

Firms are assumed to either buy or sell allowances depending on their costs of control in comparison to the market price of allowances. As the price reacts to changes in demands and supplies of allowances, the market will help ensure that

the costs of incremental reductions of NO x are the same for all participants. 297

C. CAIR

In 2005, the EPA promulgated an expanded and more stringent transport rule, the CAIR, which regulated SO 2 as well as NO x emissions from fossil fuel-f ired EGUs through a tradable allowance system. Similar to the NO x SIP Call, the state budgets set by CAIR were based on

294 See e.g.

, 63 FR 57356, 57399, 57413, 57457 (Oct. 27, 1998); RTC at 217.

295 63 FR at 7413 (emphasis added).

296 NO

x SIP Call RIA at 4-10.

297 NO

x SIP Call RIA at 4-10102 cost-effective controls on EGUs. The EPA’s eval uation of the cost impacts of CAIR assumed that EGUs would be participating in an interstate trading program. 298 The EPA explained that –

In modeling the CAIR with the IPM, EP A assumes interstate emissions trading. While EPA is not requiring states to part icipate in an interstate trading program for EGUs, we believe it is reasonable to evaluate control costs assuming states choose to participate in such a program since that will result in less expensive

reductions. 299

D. CSAPR

In 2011, the EPA promulgated the CSAPR, whic h regulated intersta te transport of SO 2 , NO x , and particulate matter emissions from fossil fuel-fired EGUs through a tradable allowance

system. 300 Here, again, the EPA concluded that --

the preferred trading reme dy will allow source owners to choose among several compliance options to achieve required emission reductions in the most cost effective manner, such as installing contro ls, changing fuels, re ducing utilization, buying allowances , or any combination of these actions. 301

As with the previous two inte rstate transport programs, the EPA in CSAPR recognized that interstate trading was a particularly well-suite d mechanism for addressing emissions from EGUs because of “the power sector’s ability to operate as an integrated, interstate system and to promote reliability.” 302 As described below, this recognition makes CSAPR merely the most

recent in a line of EPA intersta te transport rules that took into account trading as a method for

EGUs to reduce emissions. 303

E. Regional Haze SIPs

Under Section 169A of the Clean Air Act, Congress required EPA to promulgate regulations to assure reasonable progress toward meeting the nationa l visibility goal. 42 U.S.C. § 7491(a)(4). Congress further directed EPA to include in its regulations a re quirement that States revise their SIPs to include “emission limitations, schedules of compliance and other measures as may be necessary to make reasonable pr ogress toward meeting the national goal.” Id. § 7491(b)(2). One such measure that Congress deemed necessary to make reasonable progress was

298 70 FR 25162, 25196 (May 12, 2005).

299 70 FR at 25196.

300 76 FR 48208 (Aug. 8, 2011).

301 76 FR at 48272.

302 76 FR at 48272.

303 See, e.g.

, NO x SIP Call, 63 FR 57356, 57399 (Oct. 27, 1998) (noting that the EPA set state budgets using a uniform emission standard for E GUs in part because those standards were “based on the adoption of a broad-based trading program” that would allow sources with higher marginal costs to more cost-effectively comply); CAIR, 70 FR 25162, 25196 (May 12, 2005) (noting that the EPA set state budgets based on cost-effective controls on EGUs and, in evaluating the cost impacts, “assume[d] interstate emissions trading” because of the reasonable

likelihood that states and EGUs would use trading as the way to meet emission requirements).103 a requirement that certain older stationary s ources that cause or contribute to visibility impairment “procure, install, and operate, as expe ditiously as practicable . . . the best available retrofit technology,” more co mmonly referred to as BART. Id. § 7491(b)(2)(A). As the statutory language makes clear, Congress envisioned BART as a technology-based standard that would apply at a specific set of sources. Neithe r Section 169A nor the related Section 169B, see 42 U.S.C. § 7492, contain any explic it statutory authorization for EP A to permit States to adopt trading programs or other alternatives to comply with the BART requirement.

In 1999, EPA promulgated the Regional Haze Rule to satisfy Congress’s mandate to promulgate regulations that would assure reas onable progress toward th e national goal. 64 Fed. Reg. 35,714 (July 1, 1999) (codified at 40 C. F.R. §§ 51.308-309). The Regional Haze Rule allows States to adopt trading pr ograms or other alternatives in li eu of requiring retrofit controls at sources subject to BART. Specifica lly, the Regional Haze Rule provides:

A State may opt to implement or require participation in an emissions trading program or other alternative measure rath er than to require sources subject to BART to install, operate, and mainta in BART. Such an emissions trading program or other alternative measure mu st achieve greater reasonable progress than would be achieved through the in stallation and operation of BART.

40 C.F.R. § 51.308(e)(2). EPA provided the follo wing explanation why the Agency had the authority to allow States to adopt trading programs in li eu of BART despite Section 169A(b)(2)(A)’s clear statement that BART was a technology-based standard:

In recognition of the contro l and cost efficiencies th at can be achieved through trading programs and other alternative m easures, EPA is providing States with the opportunity to adopt alternative measures in lieu of BART where such measures would achieve even greater reasonable pr ogress toward the national visibility goal. The overarching requirement of th e visibility protec tion provisions of

section 169A is to make reasonable progress toward th e national goal of eliminating visibility impairment. If greater reasonable progress can be made through an approach that does not require source specific application of BART, EPA believes that approach would compor t with this statutory goal. The EPA reached this conclusion in determining the appropriate measures to address visibility impairment in the Grand Canyon National Park resulting from the Navajo Generating Station. In that case, 304 EPA ultimately chose not to adopt the emission control limits indicated by its BA RT analysis. Instead, as explained by the Ninth Circuit in upholding EPA’s final decision, EPA acted within its discretion in adopting an alternative emission contro l standard ‘‘that would produce greater visibility improvement at a lower cost. Congress’ s use of the term ‘including’ in [section 169A(b)(2)] prio r to its listing BART as a method of attaining ‘reasonable progress’ supports EP A’s position that it has the discretion to allow States to adopt implementation pl an provisions other than those provided by source specific BART analyses in situ ations where the agency reasonably concludes that more ‘reasonable progre ss’ will thereby be attained.’’ Under

304 Cent. Ariz. Water Conservation Dist. v. EPA, 990 F.2d 1531 (9th Cir. 1993).104 today’s final rule, States may elect to a dopt an emissions trading program or other

alternative measures in lie u of BART so long as great er reasonable progress is

made.

64 Fed. Reg. at 35,739 (citation omitted). EPA also explained that a State’s trading program could include sources not subject to BART:

[T]he regional trading program may in clude sources not subject to BART. Inclusion of such sources provides for a more economically efficient and robust trading program. The EPA believes the program can include diverse sources, including mobile and area sources, so l ong as the reductions from these sources can be accurately calculated and tracked.

In other words, any sources subject to BART that a State chose to include in a trading program could comply with their obligations through actions taken to reduce emissions by non-BART sources.

In addition to the general provisions at 40 C.F.R. § 51.308(e)(2) discussed above, the Regional Haze Rule also provided a specific option for States on the Colorado Plateau to adopt

an SO 2 backstop trading program in lieu of BART. Id. § 51.309. Before these States could take advantage of this option, however, the Regiona l Haze Rule required the Grand Canyon Visibility Transport Commission or another regional plan ning body to submit a report to EPA that would fill in the details for two aspects of the program: (1) specific emission reduction milestones and (2) documentation for implementing a market trading program in the event that voluntary

measures were not sufficient to meet the required milestones. See 64 Fed. Reg. at 35,751-52. The Western Regional Air Partners hip (WRAP) submitted this report to EPA in 2000, and EPA amended the Regional Haze Rule in 2003 to incorporate the WRAP’s recommendations regarding the milestones and trading program. 68 Fed. Reg. 33,764 (June 5, 2003). In a challenge to the 2003 revisions to the Regional Haze Rule, th e D.C. Circuit held that EPA had reasonably interpreted Section 169A(b)(2) as permitting alte rnatives to BART, including trading programs, so long as they achieve greater reasonable pr ogress than would the in stallation of retrofit

controls. Ctr. for Econ. Dev. v. EPA , 398 F.3d 653, 660 (D.C. Cir. 2005).

Since 2003, EPA has twice amended the Regional Ha ze Rule to allow States to rely on other trading programs as altern atives to BART. In 2005, EPA am ended the Regional Haze Rule to allow States to rely on the Clean Air Inters tate Rule (CAIR) in lieu of BART, 70 Fed. Reg. 39,104 (July 6, 2005), while in 2012, EPA again amende d the Rule to allow States to rely on CAIR’s predecessor, the Cross State Air Po llution Rule (CSAPR), 77 Fed Reg. 33,642 (June 7, 2012) (codified at 40 C.F.R. § 51.308( e)(4)). In addition to the many eastern States that chose to rely on the CAIR and CSPAR trading programs to satisfy BART requirements, three States and one municipality ultimately submitted SIPs implementing the SO 2 backstop trading program pursuant to 40 C.F.R. § 51.309, see 77 Fed. Reg. 70,693 (Nov. 27, 2012) (New Mexico), 77 Fed. Reg. 71,119 (Nov. 29, 2012) (Albuquerque-Bernalillo County, New Mexico), 77 Fed. Reg. 73,926 (Dec. 12, 2012) (Wyoming), 77 Fed. Reg. 74,355 (Dec. 14, 2012) (Utah), while one State relied on a state-developed trading program pur suant to the general provisions of 40 C.F.R.105 51.308(e)(2). See 79 Fed. Reg. 39,322 (July 10, 2014) (Connec ticut). Each of these trading programs included coal-fired power plan ts that were subject to BART.

F. Title IV

Title IV expressly reflects C ongress’ view that an “emission allocation and transfer system”

is a suitable alternative co mpliance method for meeting “prescribed emission limitations.” 305 In fact, Congress explained that “through a system of marketable allo wances, the reduction programs established by the title maximize the range of choices sources have for complying with their emissions limitation requirements.” 306 “On a regional basis,” Congress continued,

this may allow areas with substantial reduction obligations and total costs to lower their net costs by producing and sell ing ‘extra’ reductions ( i.e. , reductions beyond those they are required to achieve) to sources seeking to emit more than is permitted. At the same time, areas facing growth in the [sic] energy demand or units with high emissions control cost on a perton [ sic ] basis find that purchasing ex cess emissions reductions from plants in other areas, rather than making on-site reductions, enab les them to comply with their emissions limitations at a significantly lower cost. 307

Moreover, by “[a]llowing sources to market ‘e xtra’ emissions reductions” a trading system “should also yield important environmental benef its as sources will have strong incentives to make greater-than-required reductions earlier th an required. Since sour ces will enjoy maximum flexibility in responding to those incentives, this approach shou ld also stimulate innovation in pollution-control tec hnology and practices.” 308

Taken together, the flexibility inherent in an allowance based system “minimizes costs and maximizes flexibility and efficiency.” 309

In fact, many sources did comply with their obligations by purchasing allowances. According to a 2001 report by the Energy In formation Agency (EIA):

On January 1, 2000, the electric industry came under Phase II regulations of the

Clean Air Act Amendments of 1990. This Act was primarily designed to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxides. Phase I, which began on January 1, 1995, affected 435 generating units and allowed the release of 2.5 pounds of sulfur dioxide pe r each million Btu of fuel consumed. Under Phase II, coverage increased to mo re than 2,000 units, while restrictions on emissions were set at 1.2 pounds of sulfur dioxide per million Btu of fuel consumed. Since 1995, some generators have over complied with Phase I in order

to create excess allowances. This has a llowed them to delay enacting additional

305 42 U.S.C. § 7651(b).

306 S. Rep. No. 101-228, p. 303 (Dec. 20, 1989).

307 S. Rep. No. 101-228, p. 303 (Dec. 20, 1989).

308 S. Rep. No. 101-228, p. 303 (Dec. 20, 1989).

309 S. Rep. No. 101-228, p. 303 (Dec. 20, 1989).106 strategies that would be necessary for compliance with Phase II. [citing Energy Information Administration, The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update , DOE/EIA-0582(97) (Washington, DC, March 1997), pg. vii, 45.] Strategies that are being used for compliance include fuel switching/ bl ending, co-firing with natural gas, allowance acquisitions, scrubbers, repowering, and plant retirements. 310

G. Reasonably available control technology

The EPA has long interpreted the reasona bly available contro l technology (RACT) requirements under CAA 172(c)(1) so that the EPA may establish a RACT-level emission reduction obligation on all sour ces in a category based on a technology that the sources could, on average, implement cost-effectively, an d that sources could be expected to meet their emission limits through emissions trading. 311

310 EIA, “Electric Power Annual 2000,” vol. 1 (August 2001) 13 http://www.eia.gov/electric ity/annual/archive/vol1/0348001.pdf (emph. added).

311 See, e.g., NOx Supplement to the Title I Ge neral Preamble, 57 FR 55620 (Nov. 25, 1992); EIP Final Rule, 59 FR 16690, 16704 (April 7, 1994).