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 Clean Power Plan for Certain Issues 

This document includes additional information concerning 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 connection 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 indicated in the preamble or this Memorandum. 

I. Relationship between the Building Blocks 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, modified, and reconstructed steam units and 

combustion turbines that the EPA is promulgating at the same time as this CAA section 111(d) 

rule, the EPA is not identifying as part of the BSER 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 the BSER for new, modified, or reconstructed steam generators or 

combustion turbines in the section 111(b) rule. 

A. Newly constructed steam generating units. 

1. Preference for technological controls. 

As discussed in the preambles for the section 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 emission guidelines under CAA section 111(d). 

Because the phrase by its plain language does not limit our review of potential systems in either 

context, the same systems could be considered for application in new and existing sources. That 

said, many other factors and considerations direct 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 determined for new steam units before discussing the 

building blocks that form the BSER for existing units. 

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

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

construction. There are several reasons 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 with 
2 

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 prevent 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 least expensive approach.”2

Existing sources, on the other hand, would be regulated through emission standards, which were 

broadly understood at the time to reflect available technology, alternative methods of prevention 

and control, alternative fuels, processes, and operating methods.3

In 1977, Congress reinforced the distinction between 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 technological system of continuous emission reduction.” 

This new formulation was intended to compel new sources to install technological 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 washing in order to free lower-sulfur coal (i.e., fuel 

switching) for use by existing units. 

The 1990 CAA Amendments repealed the provisions in section 111(a)(1) that 

distinguished between new and existing sources, but nothing in the 1990 CAA Amendments 

precludes the EPA from continuing to prefer technological 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 have long operating lives over which initial capital 

costs can be amortized. Thus, new construction is the preferred time to drive capital investment 

in emission controls. 

In this case, the BSER for new steam generators, 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 that 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 that the term standard of performance “refers to the degree 

of emission control which can be achieved through process changes, 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 Legis. 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 issue to the States and appropriate air pollution 

control agencies along with the issuance of ambient air quality criteria 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 technological controls when setting new source 

standards, several practical considerations make the building blocks inappropriate for new 

sources. Thus, for the following reasons, the EPA does not consider it appropriate 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 measures 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-generating EGUs to compete with new nuclear units. 

Because the BSER is selected after considering cost (among other 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 reduction (through the combination 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 appropriate because the BSER for new steam 

generating units is based on highly efficient supercritical technology, i.e., state-of-the-art, 

efficient equipment. Accordingly, there is little improvement in efficiency that can be justified as 

part of the BSER. 

Building block 2 and 3 measures are not appropriate 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 emission-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-based 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 existing 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 rulemaking 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 available that can reduce emissions below those levels required to 

comply with standards of performance, this technology might not be selected as the basis of 

standards of performance due to costs associated with its use. Accordingly, standards of 

performance should not be viewed as the ultimate in achievable emission control. In fact, the Act 

requires (or has potential for requiring) 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 more challenging and potentially more costly. 

One example is emission trading with other affected EGUs. For existing sources, 

emission trading is an important option for implementing 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, existing 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 section 111(d) state plan standards 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. However, 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 standards reflected in the 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 building blocks 2 and 3, and that could reduce the 

 

6

 Part of the uncertainty lies in the distinctions between CAA section 111(b) and CAA section 

111(d). While the EPA establishes nationally applicable performance standards for new sources, 

each state has considerable discretion in establishing 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 would disrupt the operation of the state’s plan. 

7

 At least in theory, we could consider promulgating 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 section 111(b) standards of performance no later than every 8 years 

anyway. 
5 

amounts of building blocks 2 and 3 available for existing sources, and thereby 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 sources 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 generating 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 efficient NGCC construction already entails high 

efficiency equipment and operation. 

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

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

The reasons why building block 3 are not appropriate 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 availability of trading), lack of lead-time for 

implementation, and the possibility of reducing the availability of renewable energy for existing 

sources). 

C. Modified and reconstructed steam and NGCC units 

For modified and reconstructed steam generators, the EPA identified the BSER as 

maintenance of high efficiency or implementation 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 reconstructed steam generator generally will require ongoing 

maintenance, and may find it prudent to operate below its limit as a safety margin. This 

represents a substantial commitment of resources. For these units, the additional costs of 

implementing the building blocks would not be appropriate. 

In addition, building block 1 is not appropriate for modified or reconstructed steam 

generating units because the BSER for these units is already based 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 modified 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, Congress revised section 111(a)(1) to require 

technological controls for new combustion sources at least in part because this requirement 

would preclude new sources from relying on low-sulfur coal to achieve their emission limits, 

which, in turn, would free up low-sulfur 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 appropriate for modified or reconstructed NGCC units, 

for the same reasons that they are not appropriate for new EGUs, as described above (limited 

range of options for implementation (including lack of availability of trading), lack of lead-time 

for implementation, and the possibility of reducing the availability of renewable energy for 

existing sources).

II. Uniqueness of CO2 and of the Electric Power Sector 

In section V.A.2.b. of the preamble, we note the reasons why CO2 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 this rule. Here we note that the U.S. Supreme 

Court has recognized both the uniqueness of CO2 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 dioxide unless covered by a permit.”).9

 Moreover, the 

Supreme Court has repeatedly affirmed the authority and responsibility of the agency, charged 

with implementing the Clean Air Act, to deploy its expertise and the 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 delegated to EPA the decision whether 

and how to regulate carbon dioxide emissions from power plants . . . .”); id. at 2539 (“It is 

altogether fitting that Congress designated 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 particular greenhouse gas-producing sector cannot be 

prescribed in a vacuum ..., informed assessment 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 CO2 emissions (in addition to other air pollutants); as 

the preamble notes, it operates as a large machine, i.e., as an interconnected entity; and it is 

economically critical to the country. This uniqueness is recognized by Congress throughout the 

Clean Air Act, including in various provisions of section 111.10 The Supreme Court recently 

directed the agency to fully exercise its discretion by considering costs in determining whether it 

is “appropriate and necessary” to regulate hazardous 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 other 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 factors relevant to the power sector in determining 

the “appropriate amount of regulation” 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 because 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 Title IV revisions to the 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 departing 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 

CO2 pollution and the utility power sector. We have not previously regulated CO2 pollution from 

the utility power sector, and the combination of the unique characteristics of that air pollutant 

with the unique characteristics of that sector have led us to include building blocks 2 and 3 in the 

BSER. As we note in the preamble, not surprisingly, whenever the EPA begins the regulatory 

process under section 111, we initially undertake these same inquiries and then proceed to 

fashion the rule to fit the industry. 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 description 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 new, 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 percent 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 gaseous fuels when emissions are less than 0.20 

ppm BTU heat input.13 In selecting these standards, the Administrator investigated “coal 

cleaning and the relative economics of FGD [flue gas desulfurization] and coal cleaning” 

together as the “best demonstrated system for SO2 emission reduction.”14 Compliance with the 

standards could be met through credits “for any cleaning of the fuel, or reduction in pollutant 

characteristics of the fuel, after mining and prior to combustion.”15 

 

11 See New Stationary Sources Performance Standards; 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 could be removed from coal was investigated 

by the U.S. Department of the Interior and considered sulfur reduction potential of coal cleaning 

for the Eastern Midwest and the Northern Appalachian Coal regions. Id. at 33593. 

15 44 F.R. 33580, 33581. In order to receive credit for fuel pretreatment, owners or operators of 

an affected facility must list the “quantity, heat content, and date each pretreated fuel shipment 

was received during the previous quarter; 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 “the 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 interconnected 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 remainder 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 SO2 percentage reduction requirement 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[] SO2 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 promulgating an NSPS, the EPA stated: 

The EPA position is that unlike utility turbines, industrial turbines in some 

instances may represent the sole primary 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 process 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 lost capacity caused by turbine down time. 

Inspection and maintenance can be scheduled 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 “allow[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 been 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 electric generating capacity is being 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 generating 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 could be bypassed and, combined with reduced 

generation, total flue gas generated could be routed 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 even if the BSER may be based on measures within the 

control of a source’s owner or operator, 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 notion that source owners or operators can 

rely on measures undertaken by a third party. Specifically, physical coal cleaning—sometimes 

referred to as coal washing—is a recognized technique for reducing sulfur emissions from coalfired power plants. However, coal cleaning technologies are often 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 promulgated performance standards to control SO2 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 clear that section 111 standards may be 

based on measures that may be taken off-site or may involve a third-party entity. For example, 

Congress added the words “precombustion cleaning or treatment of fuels” to section 

111(a)(7)(B) to “insure that in upgrading the standards and in defining the ‘best technological 

system of continuous emission reduction’, the Administrator would not be limited to 

consideration of stack gas cleaning or clean combustion processes.”24 This addition was 

intended to indicate that an assessment of the “best technological system of continuous emission 

reduction” for fossil fuel-fired power plants would include off-site or third-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 percent 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 Generating 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, Incinerators, 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 performance, instead of “best 

system of emission reduction”), a standard of performance reflecting the best technological 

system implementable by an affected source could 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 removing 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 that 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 Section 111(h) to argue for a contextual constraint on defining 

a standard of performance for purposes of section 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 instead promulgate a design, equipment, work 

practice, or operational standard, 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 impact and energy requirements) the 

Administrator determines has been adequately demonstrated. 

Section 111(h)(2) provides that it is “not feasible to prescribe or enforce a standard of 

performance” when the Administrator determines that (A) a pollutant or pollutants cannot be 

emitted through a conveyance designed and constructed 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 interpreted this to mean that “[a]n owner or 

operator of an affected facility who elects to use fuel pretreatment credits is responsible for 

insuring that the EPA Method 19 procedures are followed in determining SO2 removal credit for 

pretreatment equipment.” New Stationary Sources Performance 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 below, each of the building blocks is within an 

owner or operator’s control. 
11 

any requirement for, or use of, such a conveyance would be inconsistent with any Federal, State, 

or local law, or (B) the application of measurement methodology to a particular class of sources 

is not practicable due to technological or economic limitations. 

Commenters infer that these provisions limit EPA’s interpretation of the BSER to the use 

of a pollution control conveyance 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 conveyance) or the nature of the source category (i.e., the 

source category is not able to conduct measurements). In such cases, the Administrator is 

authorized to require sources to implement specific actions to control pollution, in the form of 

design, equipment, work practice, or operational standards. When an emissions standard is

appropriate, including in the present 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 section 111(h) draws a line 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 “alternative means of emission limitation” (section 

111(h)(3)), which, by their terms, could include on-site or off-site 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 types of controls. Nevertheless, 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 off-site measures under section 111(a)(1), which 

indicates that by not . 

This interpretation of section 111(h) is confirmed by its legislative history. Section 

111(h) was added in the Conference Committee to reflect similar changes to section 112(e) as 

part of the 1977 CAA Amendments. As with section 111(h), Congress added section 112(e) to 

allow the promulgation of “a design, equipment, work practice, or operational standard, or 

combination thereof, which in [the Administrator’s] judgment is adequate to protect the public 

health from such pollutant or pollutants 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 numerical 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 characteristics” 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 control (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 intended for section 111(h) to constrain our 

interpretation of section 111(a)(1). 

For these reasons, we find nothing in the plain 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)) and 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 section 111(d)(1) and (a)(1) in section 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 authority, and the responsibility, 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 meaningful and significant reductions 

of GHG emissions. 

In AEP, plaintiffs brought a federal common law claim of nuisance against 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 question at issue.” Id. at 2537 (quoting Mobil Oil Corp. v. Higginbotham, 436 

U.S. 618, 625 (1978)). Applying this test, the Court stated, “we think 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 invoking 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) (recognizing this distinction 

under section 112 “now endorsed 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 significantly 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 analyze in greater detail the regulatory scheme 

for GHG reduction that Congress, in its “considered judgment,” 131 S.Ct. at 2538, adopted in the 

CAA. “The critical point is that Congress 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 subject to judicial review, the Court found a host of 

ways in which the delegation of power from Congress, and the expertise of the EPA, make it the 

primary, and the most appropriate, decision maker for reductions of GHGs, noting that the 

Administrator must exercise her judgment in determining 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 assessment of competing interests is required. 

Along with the environmental benefit potentially 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 administrative agency uniquely suited to the 

complex task of regulating GHGs. Id. at 2539 (“It is altogether fitting 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 cooperation between federal and state authorities,” 

id., and further, the Agency would be in a position (unlike a court), to “commission scientific 

studies or convene groups of experts 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-dioxide emissions is unreasonable ... and then 

decide what level of reduction is practical, feasible and economically viable.” Id. at 2540. 

These statements from AEP suggest, first, that as an essential component of its federal 

common law displacement analysis, the Court assumed that Congress had delegated sufficient 

authority to EPA, and that EPA possessed the necessary scientific, policy and 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 consider the magnitude of the climate change 

problem, and the U.S. power sector’s unique contribution 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 practicality, feasibility, and economic 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 “inside-the-fenceline” or similar constraints on how the BSER can be 

defined that have been insisted upon in some public comments. 

B. Industry Representations regarding Section 111 in AEP 

This understanding of AEP is supported by the electric power industry’s own views, as 

expressed in that case. These were provided in briefs to the Supreme Court in AEP The EPA 

recognizes that the electric utility sector is large and complex, and does not necessarily speak 

with one voice. Even so, although many of these key representatives of the sector have 

questioned the scope of the agency’s legal authority 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 power 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 itself appeared to adopt a relatively expansive view of the 

EPA’s authority under section 111(d) to address carbon pollution from power plants. In 

particular, in AEP, the power company Petitioners33 and supporting electric power sector Amici34

argued, inter alia, that EPA’s authority under the Clean Air Act, and in particular section 111, 

was sufficiently broad to displace any federal common law action against the power sector based 

on GHG emissions. 

Industry Petitioners stated to the Court, for example, that “Congress has addressed the 

issue of greenhouse gas emissions,” Pet’rs’ Br. 41; “the Clean Air Act delegates regulatory 

authority over carbon dioxide 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 Electric 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 the Tennessee Valley Authority. 

34 Edison Electric Institute (EEI), American Public Power Association (APPA), and National 

Rural Electric Cooperative Association (NRECA). According to the Statement of Interest, 

Amicus Br. at 1-2, EEI is the national association of U.S. shareholder-owned 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, publicly owned electric utilities, serving 45 million 

Americans. NRECA represents the 930 non-profit customer-owned rural electric cooperatives, 

serving 42 million end users. Together, their member companies serve 94 percent of the electric 

customers in the U.S. 
15 

already ‘addressed the problem’ plaintiffs now attempt to bring 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 federal 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 Act, 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, [the 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 promulgate national standards 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, further, that “Congress has given EPA substantial authority to 

regulate within the context of a comprehensive legislative 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 others, 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,” Amicus Br. 14 (emphasis added). This Brief also 

notes, “EPA’s forthcoming NSPS regulations calibrate GHG performance standards 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 plaintiffs want the federal courts to regulate.” Id.

at 9. 

 

35 Although this memo focuses on the Petitioners’ brief and the main amicus brief of the power 

sector, other amici on behalf of industry 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 already authorized the Environmental Protection 

Agency (EPA) to regulate those emissions.”), at 20 (“EPA possesses ‘significant latitude as to 

the manner, timing, content, and coordination of its regulations ...’” (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 other internationally negotiated 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 “command 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 amici 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 increased 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 comprehensively 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” that 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 Supreme 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 Prior 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 rulemakings, 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 these comments, and many questioned 

either the appropriateness or lawfulness of regulation under section 111(d), two categories of 

comments are particularly relevant here: : 1) several of these statements appear to endorse the 

view that the BSER could encompass the measures in building block 2 (dispatch shifts from 

coal-fired EGUs to NGCC units) and building block 3 (renewable energy) , and (2) virtually all 

industry commenters urged the agency to allow for these measures as effective compliance 

options. This second category of comments is relevant 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 reductions 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 section 111(d) proposal. In a “Summary of Listening 

Session 1: Electric Power Industry Representatives,” dated February 4, 2011, we noted industry 

representatives’ “general advice” to the agency: 

 

37 See, e.g., Basin Electric, Draft 111(d) Design Comments (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 preferred (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 practices nationwide using existing technologies 

and set the standard based on those technologies,” “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 technologies that can be used to comply with the 

standard”; “plant by plant approach to existing units.” Id. 

Finally, the industry’s representatives noted that the timeline for action should balance two core 

considerations: “must allow for utilities to maintain 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 instance, stating, “APPA strongly believes that 

sequencing or other practical approaches might allow the use of energy efficiency measures 

involving the ultimate utility customer to be considered 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, nevertheless, 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 section 111(d) that would go 

beyond a particular unit. “Facility-wide, plant-wide, and company-wide standards would provide 

valuable flexibility but also complexity in trying 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 Advanced 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, nuclear 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 making under section 111, “Recognizes the substantial 

emission reductions from the power sector that have already occurred and will continue to occur 

as a result of unit retirements, fuel switching, energy efficiency programs, and increasing use of 
18 

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, consensus principles the Municipal Electric 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 plants are extremely limited. Allow entities 

to average their emissions over their entire fleet 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 utilizing any activities that reduce 

emissions. These activities include supply- and 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 believed should be credited for compliance in 

achieving emission reductions, even while disputing 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 improvements, 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)], states 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-effective “low-hanging-fruit” 

 

38 APPA, Principles on EPA Rulemakings to Establish 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 compliance 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-side energy efficiency measures as actions 

they were taking to substantially reduce their carbon emissions. See, e.g., id. at 4-5 (“Kansas is 

uniquely positioned to take advantage of a significant 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 significantly increased the amount of wind generation 

installed in the state and has reduced the CO2 intensity of its 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 indefinitely suspend operation of two baseload coal 

units ... at the end of 2018. [Combined with] solar, wind, IGCC, coal gasification with carbon 

capture and energy efficiency will reduce overall CO2 emissions by about 45% in 2020 from 

baseline year 2011.”); Letter from First Energy 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 provided 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. These measures were sufficiently measurable and 

enforceable that the industry sought recognition 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 extended compliance periods. While the agency 

must reject the legal theory that it can only define the BSER based solely on measures that are 

integrated into the design and operations of the facility, all of these technical and policy 

suggestions from the industry are found reflected in the agency’s final rule, and support the 

reasonableness of the EPA’s choices. 

VII. Division of Responsibilities under 111(d) 

This section briefly summarizes the key determinations in this rulemaking under section 

111(d), including the EPA’s determination of the best system of emission reduction (BSER), the 

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

rate-based and mass-based CO2 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 summarizing 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 initial regulatory determination under CAA section 111(d)(1) is 

the BSER. As we explain in section V.B.1 of the 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 “reflects the degree of emission limitation achievable through the 

application of the best system of emission reduction ... the Administrator determines has been 

adequately demonstrated” (emphasis added). Thus, we disagree with commenters who contend 

that the states, and not EPA, have that authority. The Administrator, under both 111(b) and (d), 

determines the BSER and the degree of emission limitation achievable through the application of 

the BSER, pursuant to section 111(a)(1).39 As discussed below, states establish standards of 

performance under section 111(d)(1), which is in contrast to the Administrator’s authority to 

establish standards of performance under section 111(b). But section 111(d) does not alter 

section 111(a)(1)’s delegation of the 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 implementing regulations as an integral component to 

setting emission guidelines, to determine the resulting emission limitation from the BSER. Thus, 

in general, under section 111(a)(1), following the determination of the BSER, the EPA has the 

authority to identify the amount of emission limitation that reflects the application of the BSER 

to the affected sources. 

Under the CAA, an “emission limitation” is amenable 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 emission 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 the 1977 CAA Amendments to provide 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 clarify 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. However, the State would be responsible for 

determining the applicability of such guidelines to any particular source or sources. 

H. Rep. 95-294 at 195, reprinted in 1977 CAAA Legislative History (“1977 LH”) at 2662 

(emphasis added). The reference to “guidelines” should be taken 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 expressed as two rates in pounds of CO2 per megawatthour of electrical generation output, one rate for steam electric units and one rate for stationary 

combustion turbines. (The CO2 emission performance rates may also be referred to in the 

emission guidelines as the emission performance level 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 they will be met. This is consistent with the 

agency’s longstanding view of its role in determining 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 standards” directly applicable to sources, the agency has long 

believed that “it is desirable (if not legally required) that the criteria [for approvability of state 

plans] be made known in advance to the States, to industry, and to the general public.” Id. at 

53343. See also 40 CFR 60.22(b)(3) (emissions guidelines 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 subcategories on a region-by-region basis. This 

allows us to identify the two source subcategory-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 nationally 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 approach (applying the BSER on a 

regionwide basis, and determining nationally uniform emission levels) in section V.A.3.e-f.41 

These source subcategory-specific emission performance rates are, in essence, the arithmetic 

expression of the BSER as applied to the two source subcategories on the basis of the least 

stringent region, which are then applied to the other regions. While they constitute the “degree of 

emission limitation achievable,” and inform the agency’s review of state 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 differs 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-state inequities, we modified our approach from 

the proposal and agree that a regionwide 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 CO2 goals. As we explain in 

Section VII of the preamble, these 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 subcategory-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 would be to invite the 

EPA’s disapproval of that state’s plan. The goals are a type of accounting device, that is, 

they are part of the methodology for assuring that if states adopt standards of 

performance that differ from the source subcategory specific emission performance rates, 

the states will be able to assure that they are obtaining the same emission performance 

level as the application of the BSER to their sources would require. The ability to use 

accounting metrics to determine equivalent levels of stringency is provided for, and 

wholly consistent with, the framework regulations of subpart B, which provide that an 

emission guideline is to contain information that “reflects the application of the best 

system of emission reduction (considering the cost of such reduction) that has been 

adequately demonstrated for designated facilities, 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 equivalency to the subcategory-specific emission 

performance rates. They do not impose an obligation directly on states. The EPA agrees with 

commenters who say that the states, as states, are 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 all section 111(d) emission 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 does 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 satisfactoriness. Given that the 

EPA has determined the degree of emission limitation achievable, state plans that fail to meet 

these levels of emission reduction would be proposed for disapproval through a disapproval 

process that would include notice and opportunity for public comment. Nonetheless, failure to 

submit an approvable state plan is not a sanctionable violation of the Clean Air Act. It simply 

means the agency will have the responsibility to develop a federal plan for the affected EGUs in 

that state. 
23 

The agency recognizes that the goals for each state may vary to some degree, but this is a 

natural and unsurprising consequence of the application of the emission performance rates to 

each state’s unique mix of affected EGUs. The variation 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 unacceptable degree of inequity among sources in 

different states. The level of variation 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: States utilizing early action programs to achieve reductions prior 

to the start of the interim period may qualify for matching credits or allowances from the EPA 

that increase the overall size of a mass budget or the overall pool of emission 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 achieved. Beyond limited circumstances expressly provided 

in the guidelines, the EPA is not authorizing states to set less stringent standards of performance 

for their sources in such a way that 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 limits in the aggregate for all of a state's affected 

EGUs. Commenters said that under the proposal, once these “goals” are finalized, states will 

have no authority to change them, despite section 111(d)’s express grant of authority to the 

states, not EPA, to establish standards of performance and to consider factors such as the 

remaining useful life of sources in establishing standards of performance. 

These comments are premised on a legal view that the statute unambiguously requires 

that EPA must allow states to reduce the stringency of standards of performance below emissions 

performance levels EPA determined were achievable. The agency disagrees with these 

commenters. The state must establish the standards of performance for their sources in a manner 

consistent with the emission guidelines, and the standards are ultimately subject to the agency’s 

substantive review of a state plan for satisfactoriness under section 111(d)(2)(A). States plans 

that do not meet the level of stringency the agency believes is achievable for the sources in that 

state can be disapproved. This comports with the 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 decide in certain rules that a downward variation in 

emissions performance for some affected sources in a state under section 111(d) could be 

authorized. The implementing regulations provide this authority at 40 CFR 60.24(f). But this 

does not mean that for a particular emissions guideline for a particular pollutant 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 the section of the preamble and this Legal 

Memorandum concerning the remaining useful 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 specific 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 air pollution control under section 111(d) by the 

states. As we describe in the preamble in section V., Congress intended that the CAA be a 

comprehensive vehicle for regulating 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 unreviewable discretion that the commenters urge 

means that the states could functionally ignore national air pollution control objectives and leave 

the federal government without 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 guidelines, the scene shifts to the States. The 

States are required to submit state plans that take the emissions standards approach or the state 

measures approach, and that meet the requirements of the guidelines. The emission guidelines 

give states a wide range of choices in the design of their plans.43 They may impose the subcategorized emission performance levels on their sources 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 unique circumstances. They could impose the single, 

combined state rate on all affected EGUs in their 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 emission 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 standards of performance on new sources, the 

EPA is explicitly precluded from requiring any particular 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 sources under section 111(d), but the notion that 

the BSER is not specifically required is consistent with this statutory 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 practical matter, it may be that for a given type of 

pollutant or source category, a particular technology the EPA identified as the BSER is the only 

available means of achieving the performance standard. But this is not the case for this rule. 

 

43 The agency recognizes states’ reserved authority under section 116 of the CAA to implement 

more stringent standards on their sources. The agency also recognizes that states may find it 

advantageous to enact complementary programs, entirely 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 improperly requiring states to 

implement the building blocks, such as by ordering re-dispatch to natural gas-fired units, or 

ordering the construction of renewable energy projects. The premise of these comments is 

incorrect. Nowhere in the final emission guidelines are 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 that others have described. 

We expect that some sources will implement measures that reflect or resemble the 

building blocks. These measures met the requirements of being the “best” system of emission 

reduction that is adequately demonstrated, taking into account 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 requiring states and sources 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, states and sources have choices as to the amount or degree to 

which they implement the BBs and a high degree of flexibility as to other methods. 

All of this is consistent with how EPA has 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 use 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 agency will not, and need not, attempt to order 

sources to implement the measures that comprise 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 otherwise leave to the owners and operators of 
26 

the affected EGUs the decisions about what measures 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 delegate 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 out in greater detail in the preamble and other 

supporting documentation to the proposed federal plan. 

In the context of a federal plan, it becomes easier to see why the 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 represents 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, the EPA does not have the authority to order the 

creation of companies that manufacture scrubbers, or order their 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 manufacturing, transportation of parts, or other logistical requirements 

to ensure that each scrubber gets constructed and delivered to a source. Nonetheless, the agency 

can determine the BSER premised on a reasonable 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 measures and achieve their emission limits through 

those control measures. As we discuss elsewhere, that is the case for all of the building blocks in 

the final rule. Thus, the EPA can reasonably determine that the federally enforceable emission 

standards that would be set in a federal plan, just as in a state plan, 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 performance via the same types of regulatory mechanisms 

being made available to states in the emission guidelines. 

E. Summary of the determinations under section 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, CO2 from certain fossil fuel-fired EGUs. This 

regulation necessarily has impacts on the source category, which in this case is a key part of the 

broader electric utility power sector. But this does not mean that the EPA is overstepping its 

authority. The fact that the EPA has the authority to determine the BSER means that the EPA has 

the authority to determine the degree of emission limitation achievable, which in the Clean 
27 

Power Plan is expressed as the CO2 emission performance rates. The agency has translated these 

into a set of state goals that each reflect an emission performance level that is equivalent to the 

emission performance rates. The agency’s emission guidelines set forth these performance 

levels, along with other requirements, as the minimum requirements for states to meet in order to 

have an approvable state plan. If a state fails to submit an approvable plan, the EPA will 

implement a federal plan imposing emission standards 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 areas of state regulation. As in many 

other areas of environmental law, the EPA has set minimum federal requirements for a class of 

polluting facilities, and states have the opportunity to design a program to meet those 

requirements, or go beyond them if they so choose. In this way, the Clean Power Plan is fully 

consistent with the principles of cooperative federalism that underlie the 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 determine State Plans to be “Satisfactory” 

 Section 111(d)(2)(A) authorizes EPA to promulgate a federal plan for any State that 

“fails to submit a satisfactory plan” establishing standards of performance under Section 

111(d)(1). This also provides the standard by which EPA reviews state plan submittals: such 

submittals must be “satisfactory.” The reason is structural: Any other standard than 

“satisfactory” for EPA’s action on a plan submittal would leave a grey area between submittals 

that are disapproved under the other 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 “satisfactory” is “fulfilling all demands or 

requirements.” The American College Dictionary (“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 things, a hypothesis, etc.); to accord 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 State 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 “satisfactory” should be informed by the structure of 110(c). In other 

words, EPA should have the same authority, structurally, as EPA does under 110(c). 

 When section 111 was added to the CAA, section 110(c) read: 
28 

The Administrator shall, after consideration of any State hearing record, promptly 

prepare and publish proposed regulations setting 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 standard 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 referred 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 submit 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 interpretation 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 section 110, then under section 111(d)(2) EPA can issue a federal plan 

if the state plan is not in accordance with the requirements of section 111(d)(1). In both cases, it 

is understood that regulations EPA issues specifying requirements under the relevant sections 

(e.g. subpart B and these emission guidelines under section 111(d)(1)) are to be considered 

“requirements of” the relevant section. Any other outcome would eviscerate EPA’s authority 

under sections 301(a) and 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 110(c)(1) (i.e. the portion that gives EPA FIP authority when 

the state submits a SIP but it is deficient) does not 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 standard for EPA’s action on a SIP submittal is set in 

section 110(k)(3): it must “meet[] the applicable requirements of [the Act].” (See also section 

110(l): SIP revisions cannot “interfere with ... any other applicable 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 deadline, 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 section 111(d)(1), subpart B, and 

this guideline. And the language “applicable requirements of the Act” in section 110(k)(3) 

confirms that the plan must meet the requirements of section 111(d)(1) and any other applicable 

section of the Act, and any regulations EPA promulgates (i.e. subpart B and this guideline) under 

section 111(d)(1) or section 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 “satisfactory” 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 found “satisfactory” ambiguous with respect to this 

issue, EPA’s interpretation of “satisfactory” would be reasonable. There 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 effect in EPA’s action on state 

plans. 

 Finally, courts have routinely referred to “satisfactory” plans or SIPs as a shorthand way 

of summarizing the approval/disapproval process under section 110(k). See, e.g., Vigil v. Leavitt, 

381 F.3d 826, 830-831 (9th Cir. 2004) (“In the event 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 alternative 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 that “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 requirements had never been submitted”); and Air Pollution Control 

Dist. v. U.S. EPA, 739 F.2d 1071, 1075 (6th Cir. 1984) (explaining EPA’s authority to devise a 

FIP “[i]f a state fails to submit a satisfactory plan”). 

 Accordingly, in light of EPA’s authority under section 110(c), it is mandated, or at the 

least reasonable, that the term “satisfactory plan” should be interpreted to mean 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 structural reasons, it is also the case that EPA not only 

has the authority to, but in fact must approve a plan that meets 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 approve satisfactory plans, as explained above structurally EPA’s 

action on a 111(d)(1) state plan is identical to EPA’s action 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 “satisfactory”) – 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 these emission guidelines. See the discussion in the 

previous section. 
30 

110 did not preclude the state from 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 section 116 specifically provided that States could adopt emission 

standards that are more stringent than national standards. Id. In response to the argument that 

such more stringent emission standards could not be part of the SIP, the Court reasoned that it 

would be difficult for the Administrator to determine 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 that 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 deems 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 devices it desires, and industries with particular 

economic or technological problems may seek special treatment in the plan itself.”) (citing Train, 

421 U.S. at 79). This State discretion includes 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 section 111(d) state plans, but to the extent those 

principles do apply here, these guidelines satisfy them. The EPA has given States maximum 

flexibility to achieve the rate-based or mass-based goals, or (should a State adopt the 

performance rates) to provide ERCs from various types of measures. Numerous measures that 

reduce CO2 emissions from affected EGUs and that are otherwise consistent with the 

requirements of these guidelines (such as enforceability) 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 that vary from EGU to EGU. Finally, the 

possibility of interstate trading 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 hold more allowances or ERCs, or to emit less CO2 than 

is required under these guidelines. 

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

This section discusses our interpretation of the “remaining useful life” provision of 

section 111(d)(1) and our application of that interpretation to these emission guidelines. 

The second and last sentence of section 111(d)(1) provides: “Regulations of the 

Administrator under this paragraph shall permit the State in applying a standard of performance 

 
31 

to any particular source under a plan submitted under this paragraph to take into consideration, 

among other factors, the remaining useful life of the existing source to which such standard 

applies.” This portion of the legal memorandum 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 meaning of certain terms in the provision; and D) 

EPA’s interpretation of similar provisions in the Act’s visibility program (including some 

relevant case law). Finally, we conclude that (and as supported by the preceding four 

discussions) these emission guidelines 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 remaining useful life and other factors. 

A. Implementing Regulations in Subpart B 

Some commenters argued that, due to the remaining useful life provision, these guidelines 

impermissibly require state plans to achieve the rate-based or mass-based goals. In these 

commenters’ views, if a State relaxes an emission limitation for one affected EGU in order to 

take into consideration remaining useful life, the State should not be required to increase the 

stringency of other emission limitations to maintain the goal. The implementing regulations in 

subpart B contemplate that states, in certain limited circumstances subject to EPA approval, may 

impose emission standards on particular facilities that are 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) stood as enacted by the 1970 Clean Air Act: 

The Administrator shall prescribe regulations which shall establish a procedure similar to 

that provided by section 110 under which each State shall submit to the Administrator a 

plan which (A) establishes emission standards for any existing 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 remaining useful life provision, and subsection 111(d)(1)(A) required 

states to establish “emission standards,” not “standards of performance.” 

 In proposing the subpart B regulations, EPA stated: “It is the Administrator's judgment 

that section 111(d) permits him to approve State emission standards only if they reflect 

application of the best systems of emission reduction (considering the cost of such reduction) 

that are available.” 39 Fed. Reg. 36,102, 36,102/1,2 (Oct. 7, 1974). Of particular relevance to 

remaining useful life, EPA went on to state: 

It is recognized, however, that application of such standards may be unreasonable in 

some situations. For example, to require that existing controls be upgraded by a small 
32 

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 subpart B regulations should contain a variance 

provision. See id. at 36,104/2. In response to an adverse 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 facilities. 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 unreasonably expensive in some cases. For these 

reasons, EPA believes the provision [§ 60.24(f)] allowing States to grant relief in cases of 

economic hardship (where health-related pollutants 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 particular designated facilities, or classes of facilities, States 

may provide for the application of less stringent emission standards or longer compliance 

schedules than those otherwise required by paragraph (c) of this section, provided that 

the State demonstrates with respect to each such facility (or class of facilities) : 

 (1) Unreasonable cost of control resulting from plant age, location, or basic 

 process design; 

 (2) Physical impossibility of installing necessary control equipment; or 

 (3) Other factors specific to the facility (or class of facilities) that make 

 application of a less stringent standard or final compliance time significantly more 

 reasonable. 

Id. at 53,347/3. Thus, under the 1975 regulations, States had to demonstrate that a less stringent 

emission standard was warranted, and that demonstration 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 next section, Congress added the remaining 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 unreasonably expensive retrofit controls) that EPA expressed when 

promulgating 60.24(f). EPA did not revise the implementing regulations after the 1977 

Amendments, but EPA did issue emission guidelines 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 guidelines, EPA stated: “The States may take into 

consideration the remaining useful life of a plant. Where a facility contains both old and new 
33 

[reduction] cells, it may be reasonable to apply somewhat less stringent standards to the old.” Id. 

at 26,295. Thus, EPA thought that that subpart B adequately 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 been 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 overstated; however, that disagreement is not 

necessary to our promulgation of these emission guidelines as we next explain. 

In 1995, EPA added the prefatory phrase “Unless specified otherwise in the applicable subpart” 

to 60.24(f). EPA was not challenged on that revision to subpart B, which now applies to 

emission guidelines issued under both sections 111(d)(1) and 129(b). On its face, the language 

thus now allows for other approaches to satisfying 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 particular affected EGUs on the basis of remaining 

useful life (or other factors) without requiring offsetting reductions from other affected EGUs. 

In fact, EPA promulgated section 111(d)(1) emission 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. States either had to adopt an allowance-based 

trading program, or had to impose individual emission standards; in both cases, the statewide cap 

had to be met and could not be adjusted. Thus, under CAMR, the sort of adjustment that 

commenters argue is necessarily required 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 variance factors inapplicable. Instead, they satisfy 

the remaining useful life provision in other ways, as discussed in this section of the legal 

memorandum. 

B. Legislative History 

 As mentioned above, the 1970 version of section 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 subsection 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 Division, Congressional Research Service, Library of Congress, at 

5961 (Aug. 1978, Serial No. 95-16). They were “intended to clarify the basis for standard-

 

47 In that action, EPA determined that designated 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 occur in 60.24(d), indicates that 60.24(f) might have 

applied. 

48 CAMR was vacated by the D.C. Circuit on account of the EPA’s flawed CAA section 112 

delisting rule, although the court declined 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 explanations stated in the House report 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 consideration of the remaining useful life of any existing source 

subject to “best available retrofit technology” (BART) or “maximum feasible progress” (as 

enacted, “reasonable progress”) requirements. 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 clarify 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. However, the State would be responsible for 

determining the applicability of such guidelines to any particular source or 

sources. The Administrator's guidelines must 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 life, three things are worth noting about this 

passage. First, it adopts the term “guidelines” consistently with EPA’s usage of the term in the 

1975 framework regulations. This indicates that the remaining useful life provision was 

informed by those framework regulations, including 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 developing and submitting their plans. See 40 Fed. Reg. 53,340, 

53,341/2 (Nov. 17, 1975). The sentence in the legislative history about states determining 

applicability is consistent with this: the guidelines are not directly applicable to a particular 

source, but the state plan does apply to particular sources within the guideline source category. 

Second, since Congress recognized EPA’s interpretation in the framework regulations 

and therefore expected EPA’s emission guidelines 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 Administrator’s guidelines 

must take into account the remaining useful life of existing sources.” It should also be noted that 

this sentence uses “life,” not “lives”; thus it was not expected that EPA in promulgating emission 

guidelines would examine the remaining useful life of each particular source individually. 

Instead, EPA should determine how remaining useful 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 expected to take into account the remaining useful 

life of the source (or sources).” Thus, consistent with the statutory text “in applying a standard 

of performance to any particular source,” Congress 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 remaining useful life) the application 

of the standard to that 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 would lead to a failure to achieve the degree of 

emission limitation the EPA determined to be achievable when there is on the record no warrant 

for doing so. 

This is consistent with the 1975 framework regulations, which do not provide for an 

exemption but instead provide for application of a less stringent standard 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 not allowing for an exemption is consistent with 

those regulations. 

The points above are general but consistent with the overall framework of section 111(d); 

a concrete concern of Congress addressed in the remaining useful life provision was the cost of 

retrofit technology at existing sources and the potential for other, more cost-effective means of 

compliance.51 This can be seen in the legislative history in the broader context of the 

corresponding changes in the House bill to the provisions 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 (which were perceived at the 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 interpret the remaining useful life provision as 

allowing states to impose no obligations for particular sources because of remaining useful life or 

other factors. However, those circumstances 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 framework regulations: “[C]ontrols cannot be 

included in the design of an existing facility and [] physical limitations may make installation of 

particular control systems impossible or unreasonably 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 operation rather than shut down, and 

sources with small marginal revenues 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 statement 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 categories 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 source categories and some pollutants, reasonably do 

so after considering costs. 

One other parallel context in the 1977 Amendments should be discussed. Congress 

added a new section to the Clean Air Act, section 169A, regarding protection of visibility in 

certain National Parks and Wilderness Areas. The definition of best available retrofit technology 

(BART) required states (or EPA in a FIP) to consider five specific factors, including the 

remaining useful life of the source 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 not be 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) remaining 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 conclusions from the legislative history. First, 

Congress intended EPA to issue binding requirements for remaining useful life and to take into 

account characteristics of a source category in determining how remaining useful life should be 

addressed. Second, Congress intended remaining useful life to be used by states to tailor the 

application of a standard of performance to a particular source, and not to exempt sources from a 

standard of performance altogether. Third, Congress intended the provision to primarily address 

the problem of existing sources with relatively short remaining useful lives for which installation 

of retrofit technology – for those standards for which technology was the BSER and the 

compliance method of choice -- might be unreasonably expensive. 

C. Meaning of Terms in the Remaining 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 BSER 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 remaining 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 remaining 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 any 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 emission 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 reserves “the right of any 

State or political subdivision” to adopt more stringent requirements. 42 U.S.C. § 7416 (emphasis 

added). Thus, when Congress wanted to prohibit EPA from imposing constraints or parameters 

on State discretion, Congress knew how to say that. 

 

The language of the remaining useful life provision is consistent with this. To “permit” is 

“to let (something) be done or occur,” as in “the law permits the sale of such drugs.” ACD at 

902 to 903; see also OED (“To allow or give consent 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) set conditions on the sale. Thus, the natural 

interpretation of the remaining useful life provision is that the 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 “among other factors” must be discussed. 

“Consideration” in this context is “regard or account: something 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 taken, or to be taken, into account; a reason considered.”). Thus, 

“consideration” of “remaining useful life” means taking it into account “in applying a standard of 

performance to any particular source.” 

However, taking remaining useful life into account is not the same as making remaining 

useful life dispositive. This interpretation is bolstered by the language “among other factors.” 

This indicates that “remaining useful life” is itself a “factor.” 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 bring 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 putting the standard of performance into practical 

effect for that source. It does not mean exempting a particular source from a standard of 
38 

performance, and as discussed in the legislative history, Congress knew how to allow sources to 

be exempted from requirements when Congress so desired. 

This analysis of the language of the remaining 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, states would remain subject to minimum criteria 

in the emission guidelines promulgated by the Administrator; the remaining useful life provision 

is not an unrestricted grant of a right to a state. 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 application of the standard of 

performance to its sources, as part of the state plan, to assure that the state 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 section 111(d)(1). 

Under section 169A of the Act, SIPs are required to contain “a long-term [] strategy for 

making reasonable progress toward meeting the national goal,” 42 U.S.C. 7491(b)(2)(B), of 

“prevention of any future, and the remedying of any existing, impairment of visibility” in certain 

National Parks and Wilderness Areas, id. (a)(1). A component of reasonable 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 visibility program in two ways. In determining 

BART for a particular source, States (or EPA in the 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 sources (along with three other factors) must be 

taken into consideration in determining reasonable progress for the long-term strategy. Id.

(g)(1). 

Section 169A also requires EPA to issue “guidelines” 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 interpreted the “remaining useful life” BART factor 

and set very specific requirements (that is, requirements 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 life has essentially no effect on control costs 

and on the BART determination process. Where 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 controls at a particular source, and EPA promulgated a specific 

methodology for taking the factor into consideration through computing the annualized cost of 

retrofit controls. The effect of this is, where a source may have a shorter remaining useful life 

than the amortization period for the retrofit control, the annual cost of the control will be 

correspondingly higher, and that may weigh (when considering the five factors) against 

determining that the particular control is BART. In promulgating this interpretation of the 

remaining useful life factor and corresponding requirement, EPA rejected a comment that the 

remaining useful life factor should be interpreted 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 that produce an emission performance level that is 

reasonable rather than maximal and that already accounts for an average level 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 relatively 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 larger emissions markets. 

Among other things, these mechanisms create economic incentives that reward overperformance of some sources, allow others to simply acquire credits or allowances to comply 

with their emission standard, and avoid the need for installation 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 useful 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 interpreted 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 with the BART Guidelines is evidence that EPA’s interpretation 

of the remaining useful life provision 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 reasonable progress remaining useful life factor 

be evaluated in a similar way. “Guidance for 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 Regional Haze Regulations, which created various 

requirements for SIPs to address visibility impairment. A particular requirement that was 

challenged was a “no degradation” provision that “require[d] implementation 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, including the remaining useful life 

factor. The court rejected this argument, first stating that the “no degradation” 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 the four factors and “[t]herefore, the states will 

be able to comply with the no degradation requirement while applying” 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 give 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 adequately consider remaining useful life, through the use of trading, 

even when they do not adopt a rate or mass-based goal but instead adopt the performance rates. 

No adjustment of a goal is necessary. However, if a state decides to reallocate 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 factors is consistent with the overall 

purpose of section 111(d): the set of affected EGUs as a whole achieves BSER-level emission 

reductions. To be sure, the agency agrees with commenters to the extent that the statute affords 

EPA the discretion to decide in certain cases 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 have provided that ability for many years. But 

this does not mean that for a particular emissions guideline for a particular pollutant from a 

particular category of sources, the agency cannot reasonably decide that such downward 

variations are unwarranted and unnecessary. That is the case here. 

Finally, we note two recent decisions regarding EPA’s action 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 Circuit 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 courts upheld EPA’s rejection 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 interpretation that we have the authority to prescribe the 
41 

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 emission 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 remaining useful life of the source.” First, the 

emission guidelines are based on a reasonable interpretation of the provision, and second, on the 

record before us the consequences of this interpretation are reasonable. 

In general, EPA may reasonably interpret ambiguous 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 its 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 statute is whether EPA may, as urged 

by commenters, decline to set binding 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 would 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 affected EGUs virtually at will, contrary to the statutory purpose 

of achieving emissions performance levels equivalent to the BSER at affected EGUs. 

The term “permit” does not specify the particular manner in which EPA should permit 

States to consider remaining useful 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 source under a plan submitted under this paragraph to 

take into consideration, among other 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 specify 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 language of the provision, with the legislative intent, 

and with our interpretation of the similar (but not identical) provision in the visibility program. 

As with the BART Guidelines, EPA may reasonably be quite specific about the manner of 

consideration of this factor that is allowed. The additional flexibilities provided by these 

guidelines – adoption of the uniform performance rates, adoption of the rate-based goal but 

imposition of non-uniform rates, adoption of emission 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 useful life and other factors in various ways. For 

example, a state may adopt mass limits, and allocate a relatively greater number of allowances to 

a source with limited remaining useful life, on the understanding that the source will retire before 

2030 and free up allowances for other sources. Similarly, under rate-based limits, a state could 
42 

direct ERCs generated by a state-run or state-subsidized renewable 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. Given this, it is permissible 

(as seen in Corn Growers) for these emission guidelines to ensure that affected EGUs as a group 

in a state achieve BSER-determined levels of emission reductions. 

Several commenters said that that the statute does not authorize the EPA to require other 

facilities to achieve greater reductions to compensate for a facility that the state determines 

warrants relief based on remaining useful life. One said that consideration 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 determined 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 requiring additional emissions reductions to offset 

that relief. 

The EPA disagrees with these comments, for several reasons. First, as noted above, the 

availability of trading substantially accounts for remaining useful life. Second, the EPA is not 

establishing the BSER emission level for individual facilities, and then requiring better-thanBSER from some facilities to make up for worse-than-BSER performance that a state authorizes 

for other facilities because of a short remaining useful life. Rather, as previously noted, the 

guidelines set EGU performance rates and state goals 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 block (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 attempting 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 level 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 retirement 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 adopt the national EGU performance 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 trading, rather than be achieved by each facility 

in the absence of trading. 

56 As discussed in the sections on the legislative history and the visibility program, EPA believes 

that Congress in adding the remaining useful life provision was primarily concerned with sources 

with relatively short remaining useful lives. However, in these 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 help the state’s affected EGUs to achieve the 

required level in the state plan (i.e., the national 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 the interim period, or until soon after the final goal must be met,57 and 

the state would prefer to require no emission reduction from the retiring EGU in the meantime. 

Under this hypothetical scenario, the lack of emission reduction requirements for the EGU that is 

planning retirement on these timelines could create an emission reduction deficit. However, for 

this limited scenario and in light of the other flexibilities 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 meet the state goal in this instance. 

Finally, contrary to the views of commenters, the EPA believes that the agency has 

discretion under section 111(d) over whether or not the remaining useful life criterion should be 

grounds for diminishing the overall emission reduction required by the guidelines for a particular 

source category. Stated another way, commenters believe the statute unambiguously requires the 

agency to approve state plans that achieve less emission reductions than the agency knows are 

achievable. The agency has long recognized that 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 particular 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 discussed 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 giving states flexibility on the design of the state 

 

The benefit to other EGUs mentioned above eventually applies regardless of how long an 

affected EGU operates before retirement, albeit with reduced benefits for other EGUs as the 

retirement happens farther in the future. 

57 Under this scenario, the affected EGU would continue to operate 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 despite 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 significantly 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 flexibility, such as relatively long periods for sources to 

come into compliance, the ability to credit early 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 there are technologies that could require expensive 

retrofits available for EGUs to reduce their emissions, including co-firing with natural gas58, 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 install costly pollution controls. Because of these 

features of the guidelines, EPA believes that any unit-specific considerations that a state may 

find warrant the application of a less stringent standard of performance are fully capable of being 

addressed without reducing the overall emission performance 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 useful life provision is also 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 expressed in the performance rates, rate-based goals, 

and mass-based goals, is achievable considering costs. 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 expenditures that would be hard to justify in light of 

that short remaining useful life. Indeed, such EGUs need not install retrofit controls at all, but 

may purchase ERCs or allowances in order to comply, or may negotiate directly with qualified 

generators of credits. 

With respect to stranded assets, the legislative 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. Notwithstanding 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 explicitly address a severe possibility of stranded 

assets. However, our analysis shows 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 remaining useful life provision explicitly 

compels us to take into account the possibility of stranded assets, and nothing in the legislative 

history indicates the provision should 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 “coerced” or “commandeered” into taking certain 

actions in order to avoid the prospect 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 the 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 requirements for 111(d) state plans provided in this 

rule do no such thing. Far from violating principles of federalism, this rule and CAA section 

111(d) fully respects such principles. In particular, 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 instead be subject to a federal 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 own satisfactory 111(d) plan. In CAA section 

111(d)(2), Congress required the EPA to prescribe and implement a federal plan where states do 

not submit or enforce a satisfactory state plan. Affected EGUs in that state would thus be subject 

to a federal plan that satisfies 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 States 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 respect to state officers). 

61 Among other things, a federal plan will implement 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 “arbitrary, capricious, an abuse of discretion, or 

otherwise not in accordance with law.” 5 U.S.C. § 706(2)(a). Particularly given these 

independent constraints on the EPA’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 implement 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 “arbitrary, capricious, an abuse of discretion, or 

otherwise not in accordance with law.” 5 U.S.C. § 706(2)(a). Particularly given these 

independent constraints on the EPA’s authority with respect to any potential federal plan, the 
46 

This approach is consistent with ordinary cooperative federalism regimes that federal 

courts have routinely upheld against Tenth Amendment challenges.63 Among other things, this 

is because a federal plan would regulate private entities, not “the States as States,” and there is 

“no Tenth Amendment impediment” when, as here, a federal plan would regulate “private 

persons and businesses . . . .”64 As the U.S. Supreme Court explained in upholding the federalplan aspect of another cooperative federalism regime, the Surface Mining Control and 

Reclamation Act (SMCRA): 

[T]the steep-slope provisions of the Surface 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 steep-slope standards, to expend any state 

funds, or to participate in the federal 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 processes of the States by directly 

compelling them to enact and enforce a federal regulatory program. The most that 

can be said is that the Surface Mining Act establishes a program of cooperative 

federalism that allows the States, within limits established by federal minimum 

standards, to enact and administer 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 lower 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 and 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 Constitution that confers upon Congress the power 

to regulate individuals, not States.”). 

65 Hodel, 452 U.S. at 288–89 (internal 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 inconsistent 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 states 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 according 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 regimes], as by any other permissible method 

of encouraging a State to conform to federal policy choices, the residents of the 

State retain the ultimate decision as to whether or not the State will comply. [...] 

If state residents would prefer 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 rather than the State bear the expense of a 

federally mandated regulatory program, and they may continue to supplement that 

program to the extent state 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 regulations governing commercial facilities that emit pollutants with 

substantial effects on interstate commerce are well within the bounds of the federal government’s 

Commerce Clause authority.70 The fact that section 111(d) stays EPA’s reasonable exercise of 

that constitutional power while states consider whether or not to develop their own satisfactory 

plan to regulate those private entities 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 activities causing air or water pollution, 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 funds. 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 “encouragement” and impermissible “coercion.”72 But 

that principle simply has no applicability here because there are no federal funds at issue. CAA 

section 111 does not contain sanctions provisions, and we are finalizing 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 implement 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 discretionary authority to withhold some federal 

highway funds under certain conditions. However, section 110(m) requires the EPA to adopt 

regulations to “establish criteria for exercising” this discretionary 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 under 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 the EPA could theoretically apply discretionary 

sanctions against states in the section 111(d) context, the rule today forbids the agency from 

exercising any such authority. We have included in this rule a provision 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 consider 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. Even 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 outlined 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 plan. 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 generally 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 federal law, the Court explained that this raised no 

Tenth Amendment impediment because the law regulated the states “as owners of databases,” 

not in their sovereign capacity.77 The federal law did not require state legislatures to enact laws 

or regulations, and did not require state officials to assist in the enforcement of the federal law 

against private individuals.78 Any federal plan regulating state-owned or state-operated EGUs 

would similarly not be regulating states in these sovereign capacities. 

B. Contract Clause 

 Commenters raised concerns that the portfolio approach could violate the Contract 

Clause because “a state-driven portfolio approach that adopts EPA’s suggestion to use the 

renewable energy and RECs [renewable energy credits] located in the 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 objectives.” Others asserted that any regulations interfering with 

contractual rights would violate the Contract Clause. 

As an initial matter, insofar as commenters are uniquely concerned 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 State shall . . . pass any . . . Law impairing the 

Obligation of Contracts . . . .”79 By its terms, the Contract Clause does not apply to the federal 

government. Accordingly, commenters’ concerns about the Contract Clause implications of the 

provisions of hypothetical state plans are best reserved until state 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 law80 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 changes in state law in response to this rule. 
50 

as a “substantial impairment” of a contractual relationship.81 “This inquiry has three components: 

[1] whether there is a contractual relationship, [2] whether a change in law impairs that 

contractual relationship, and [3] whether the impairment is substantial.”82 Commenters have 

largely stopped their analysis at whether a hypothetical state law would “impair” a contract, 

ignoring the fact that a “substantial impairment” typically (although not necessarily) involves a 

total “destruction of contractual 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 provision did substantially impair a 

contract, there is still no constitutional violation 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 contract obligations. It is likely that any generally applicable state 

plan would satisfy this requirement. 

C. Compact Clause 

Some commenters and individuals have asserted that multi-state plans would require 

congressional consent pursuant to the Compact Clause85 or Section 102(c) of the Clean Air 

Act.86 Some commenters’ concerns flow from the faulty 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-state 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 reciprocal legislation of the sort that states 

have routinely enacted in consultation with each other, including in the context of the Clean Air 

Act. States are allowed to cooperate in this way without obtaining congressional approval under 

either the Compact Clause or Section 102 of the Clean Air Act. 

1. The Compact Clause does not apply 

The Compact Clause provides that, “No State shall, 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 that 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 cooperate 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 Clause’s prohibition, no interstate 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 plans that do not enhance or diminish the sovereign 

authority of any state, and that do not enhance state power vis-à-vis the federal government.92

Rather, the state laws comprising a multi-state plan are “nothing more than reciprocal 

legislation”93 of the sort that states have routinely enacted in consultation 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 CO2 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 coordinate 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 combination tending to the increase of political power in the 

states, which may encroach upon or interfere with the just supremacy 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 MICH.

L. REV. 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 been held exempt from the consent requirement.”); William 

Funk, Constitutional Implications of Regional CO2 Cap-and-Trade Programs: The Northeast Regional Greenhouse 

Gas Initiative as a Case in Point, 27 UCLA L. J. ENVTL. L. & POL’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 state 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 clarify 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 nonattainment area that is included in more than one 

State, the affected States may jointly, 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) (section 
52 

cumulatively, the measures applicable in each state will lead to achievement of a common 

interstate goal (with the EPA evaluating the sufficiency 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 sovereign legal authority.95 For example, the legally applicable rules in a 

given state are adopted by that state individually, 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 provisions adopted to comply with the CAA’s Good 

Neighbor Provision96 that allow sources in one state to engage in emissions trading with out-ofstate sources.97 Although the trading provisions allow for interstate exchanges between sources, 

the states have direct legal authority only 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 state develops and submits the SIP on its own 

initiative—pursuant to its independent, sovereign authority. Interstate emissions trading 

programs that states may which to develop under this rule similarly would 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 matter of state law, the Tenth Amendment provides 

that they may do so, and section 111(d)(2) provides for federal regulation of sources in that state. 

There is thus no merit to commenters’ contention that all multi-state plans would necessarily 

require congressional consent under the Compact Clause. 

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

Commenters are also off-base in their claim that CAA section 102(c) prohibits states 

from forming multi-state plans. The text and statutory context of CAA section 102(c) indicates 

that Congress did not intend to preempt a broader range of state action than would otherwise 

require congressional consent under the Compact Clause. 

 Section 102(c) is situated in a larger section entitled, “Cooperative activities.” The thrust 

of that section—as with the Act as a whole98—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 compacts 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 antecedent 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 NOx 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 pollution control. For example, section 102(a) of the 

Act expressly directs the EPA to encourage all manners of cooperative activities between states: 

The Administrator shall encourage cooperative activities by the States and local 

governments for the prevention and control of air pollution; encourage the 

enactment of improved and, so far as practicable 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 agreements 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 more States t negotiate and 

enter into agreements or compacts, not in conflict with any law or treaty of the 

United States, for (1) cooperative effort and mutual assistance for the prevention 

and control of air pollution 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 such 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 reasonably interprets this provision as clarifying 

that Congress’s encouragement of interstate cooperation in sections 102(a) and 102(c) does not 

equate to congressional consent to compacts where necessary under the Compact Clause. 

Because the multi-state plans envisioned under this rule do not require congressional consent 

under the Compact Clause, they accordingly do not require special congressional action under 

section 102(c). EPA’s reasonable interpretation is based on the 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 first sentence of section 102(c), which gives 

express consent for states to “negotiate and enter 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 well as to create of compact entities that help 

effectuate such arrangements.101 Members of Congress have accurately 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 entered 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 “air quality control region[s]” 

makes clear that congressional intent regarding this sentence concerns NAAQS pollutants. See id. § 7407(b)(1) 

(defining air quality control region). Because air quality control 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 instances where consent is not required.102 This may be 

because the provision was initially 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 agreements between states, almost all of which are 

for cooperative effort and mutual assistance in addressing a shared concern. Accordingly, it is 

perhaps unsurprising that members of Congress have suggested that section 102(c) is “merely a 

restatement of the general constitutional provision applicable to all compacts (art. I, sec. 10) . . . 

.”104

Additionally, the second sentence of section 102(c) does not prohibit states from 

engaging in any “cooperative efforts and mutual assistance” 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 preempt otherwise lawful state action.106 Furthermore, Congress’s 

titling of section 102(c) (“Consent of Congress to compacts”) mirrors 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 first sentence of section 102(c), which uses preempting language to 

preclude states from entering into arrangements “in conflict with any law or treaty of the United 

States . . . .”107

 Alternatively, even if section 102(c) unambiguously preempts 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 reason: 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 coordinated 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. Coast 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 only 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 obviate 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 Amendment prohibits the federal government from 

taking “private property . . . for public 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 burdens which, in all fairness and justice, should 

be borne by the public as a whole.’”109 The Federal Circuit has developed 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 amounted 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 relief is not available to enjoin an alleged taking of private 

property for a public use, duly authorized by law, when a suit for compensation 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 subsequent 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 claims (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 Amendment, the first step is for commenters to 

identify a compensable property interest. We agree with commenters that private entities may 

have property interests in real property, and both tangible and intangible personal property. We 

note, however, that courts have held that, “Where a citizen voluntarily enters into an area which 

from the start is subject to pervasive Government control, a property interest is likely lacking.”116

Furthermore, many of the purported property interests identified by commenters have been 

rejected by courts. To take just one example, frustration of business interests does not form the 

basis of a takings claim, particularly when the 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 directed at Party A may “drastically reduce[] the demand” for a 

Party B’s services—and thus “result[] in adverse economic consequences” for Party B—does not 

mean that the federal government has effectuated a “taking” of Party B’s property.118 Nor have 

commenters cited any precedent for the proposition that affected EGUs or coal companies have a 

property interest in the being able to emit CO2 without regulation.119

Assuming arguendo that legitimate property interests do exist, the second step of the 

Federal Circuit’s framework requires consideration of whether the government action (i.e., this 

rule) amounts to a compensable taking 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 Trade 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—would result in a physical taking.121 Rather, they claim that this 

rule will lead to widespread, uncompensated regulatory takings in violation of the Takings 

Clause of the Fifth Amendment. 

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

Coastal Council, just compensation is required for regulations that “completely deprive[s] an 

owner of ‘all economically beneficial us[e]’” of property, “except to the extent that ‘background 

principles of nuisance and property 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 ordinarily governed by the standards set forth in Penn Central 

Transportation Co. v. New York City.

124 That approach requires a balancing of factors including: 

. . . “the economic impact of the regulation on the claimant and, particularly, the 

extent to which the regulation has interfered with distinct investment-backed 

expectations.” In addition, the “character 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 takings claims are not. 

Contrary to many commenters’ assertions, this rule does not 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. Rather, 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 CO2 goals reflecting 

CO2 performance rates based on the BSER, and (2) guidelines for the development, submittal 

and implementation of states plans that will implement those CO2 performance rates. 

As noted throughout the preamble, both states and utilities have substantial flexibility and 

latitude in the manner of achieving the emission 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 example, it is not yet know what emission 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 will 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 affecting a regulated entity, as the U.S. Supreme 

Court has explained in the context of land-use regulations: 

[A] takings claim challenging the application of land-use regulations is not ripe 

unless the government entity charged with implementing the regulations has 

reached a final decision regarding the application of the regulations to the 

property at issue. A final decision by the responsible state agency informs the 

constitutional determination whether a regulation has deprived a landowner of all 

economically beneficial use 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 facts to develop is partially because 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 critical facts that can differ between EGUs, or depending on the 

emission standards applicable to an EGU through (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 arguments are further evidenced by the separate 

requirement in Takings Clause cases that parties 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 Fifth 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 versus 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 CO2. 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 Trade 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 circumstances, demonstrate the existence of reasonable 

investment-backed expectations. At this stage of the process, however, 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 “purport 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 standards that do not exist. All that exists are 

hypothetical state plans applying hypothetical emission standards against EGUs with 

hypothetical investment-backed expectations. Commenters’ 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 incorporate 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 potential to emit a pollutant equal to or above 

specified major source thresholds are subject 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 hazardous 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 plays a critical role in 

determining what CAA requirements apply to a source. PTE is a significant factor in 

determining applicability of major source requirements for the 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 PTE is a significant factor in determining 

applicability for certain CAA programs. For example, the applicability provisions for the federal 

PSD permitting program state that PSD requirements apply to construction of “any new major 

stationary source” in an area designated as attainment 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 regulations for the title V permitting programs); 40 CFR 70.2 and 71.2 

(definition of “major source” for title V, which includes 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 that certain sources may take 

enforceable restrictions on utilization, 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 source to emit a pollutant under its physical and 

operational design. Any physical or operational limitation on the capacity of the source to 

emit a pollutant, including 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 Appeals Board, or EAB, has summarized, “PTE 

reflects a source’s maximum emissions capacity considering the application of any emission 

control equipment, or other capacity-limiting restrictions, that effectively and enforceably limit 

emissions capacity.”136 

For decades, EPA has recognized that sources 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 for 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 enforceable" as used in relation to the definition of 

PTE for the federal PSD program in 40 C.F.R. 52.21(b)(4) should be read to mean "federally 

enforceable or legally and practicably enforceable by a state or local air pollution control 

agency." Memorandum from John Seitz, Director, Office of Air Quality Planning and Standards, 

and Robert Van Heuvelen, Director, Office of Regulatory 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/pottoemi.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 Planning & Standards, U.S. EPA, & Robert Van 

Heuvelen, Dir., Office of Regulatory Compliance, to EPA Reg’l Air Div. Dirs., Options for 

Limiting the Potential to Emit (PTE) of a Stationary Source Under 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/title5/t5memos/ptememo.pdf. 
61 

source obligations for that pollutant and obviates the associated requirements. This type of PTE 

limit is frequently called a synthetic minor limit, and it has become a well-established 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 petitions 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 EPA 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 Production 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/petitiondb/petitions/masada-2_decision2001.pdf (denying 

petition’s request to object to title V permit based on alleged 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/petitiondb/petitions/columbia_university_decision2000.pd

f (recognizing availability of PTE limits, but granting 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/petitiondb/petitions/hu_honua_decision2011.pdf

(recognizing availability of PTE limits and granting petition’s request to object 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/petitiondb/petitions/cashcreek_response2010.pdf

 (granting in part and denying in part requests for objections based 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 EPA 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 a 
62 

Thus, the EPA and state and local air permitting authorities generally have broad 

authority to establish such capacity-limiting restrictions for sources that request them, as long as 

the restrictions are adequately enforceable. These 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 restriction that limits utilization, such as a limit on the hours of operation 

of an emissions unit. Such PTE limits that restrict hours of operation are particularly 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 source 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 emissions” is enforceable as a legal and practical 

matter. 40 CFR 52.21(b)(4) (regulations for federal PSD permitting program) (emphasis added). 

The other CAA programs mentioned above have materially similar provisions in the 

corresponding PTE definitions.145 Under these regulatory provisions, a source can take an 

enforceable limitation on hours of operation that has the effect of restricting 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” and “restrictions on hours of 

operation,” these regulations treat reduced utilization and emission controls as equally 

cognizable means of restricting 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 the relevant levels.”). 

144 Memorandum from Kathie A. Stein, Director, Air Enforcement Division, Office of 

Enforcement and Compliance Assurance, to Regional Air Directors, Guidance and 

Enforceability Requirements for Limiting Potential 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 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). The EPA, or a tribal agency operating 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, and those permit may contain enforceable 

limitations on the hours of operation or other operational restrictions. See 40 CFR 49.152(d) 

(definitions of PTE and 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 requirements 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 determined 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, including limits on utilization, are available for EGUs in the same 

way as they are for any other stationary source. EPA is aware of numerous instances in which 

EGUs have taken limits on utilization, and in particular 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 limits have been used by EPA when it has acted 

as the permitting authority for sources148, as well as by state or local agencies acting in their 

capacity as permitting authorities.149 Several examples of such permits 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 emissions-based PTE limit where, among other 

things, Petitioners had not addressed the operational limits in the permit issued by EPA, 

including hourly operational limits on certain activities). 148 See, e.g., GHG PSD permit for Shady Hills Generating 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 shall not operate an average of more than 3,390 

hours per year per combustion turbine on a 12-month rolling total basis. No single unit shall 

operate more than 5,000 hours per year on a 12-month rolling total basis. 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 every 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), General Operating Condition 13 at p.15 of 219, 

(“Maximum allowable hours of operation for each 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 generally 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 turbines 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 Utilities 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 organic compounds below the title V threshold of 100 

tpy, and carbon monoxide, nitrogen oxides and sulfur dioxide below the PSD threshold of 250 

tpy.151

Similarly, to avoid triggering NNSR requirements 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 limit 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 Generation 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 consecutive month period depending on which of 

three turbine options was selected); Memorandum from J. Piktel to M. Zaman, Addendum to 

Application Review Memo for the Repowering Project (Pa. Dept. Env. Protection, 4/1/2013) at p. 

2 of 10 (noting that source had “calculated a maximum hours per year (12 consecutive month 

period) of operation for the sources proposed for each of the turbine options in order to remain 

below the significance threshold for GHGs.”). 

151 See Final Operation Permit No. 436123380-P10 for Manitowoc Public Utilities - 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 that the potential emissions 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 emissions of sulfur dioxide, 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 because 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 area 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 synthetic minor to avoid NNSR for NOx and VOC 

by providing that NOx emissions for the emission unit shall not exceed 3.30 TPY and that VOC 

emissions shall not exceed 1.50 TPY, both based on a rolling 12-month summation); Condition 
65 

and emission limits for NOx and VOC),153 as well as emission limits on the combustion turbine 

and heat recovery steam generator 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 may also restrict utilization, 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 generators 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 subject to regulation under the Act that it will 

emit. CAA § 165(a)(4). Permitting authorities have used limits on utilization as part of 

establishing BACT limits for EGUs. For example, in the PSD permit for Antelope Elk Energy 

 

1.b)(2)k. at p. 25 of 87 (“The maximum annual fuel consumption for this emissions unit shall not 

exceed 600,000 MMBtu per rolling, 12-month period. ....”); and Condition 1.f)(1)b & e at p. 27-

29 of 87 (explaining relationship between the 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 maximum annual operating hours for this emissions unit 

shall not exceed 500 hours, based upon a rolling, 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 annual 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 for 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), Condition I.A.2(2) at p. 4 of 15 (“Each generator 

may not be operated for more than 16.66 hours 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 NOx potential to emit (PTE) less than 100 tons per year, the 

Part 70 major source threshold level 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 hours fired with distillate fuel.159 

In addition, permitting authorities have imposed limits on the utilization of EGUs to 

protect the NAAQS. For example, a title V renewal permit for Madison Gas & Electric Co.’s 

Blount Street Generating Station took limits on the operating hours for 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 requires 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 assure 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 quality control requirements are appropriately applied to facility 

emission units and for assuring compliance with such requirements, but does not generally 

impose new substantive air quality control requirements. The title V program is implemented 

through regulations promulgated under 40 CFR part 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 requirements under the CAA, 

including any requirement under section 111. Section 504(a) of the CAA requires in pertinent 

part that each permit issued under title V “shall include enforceable emission limitations and 

standards ... and such other conditions as are necessary 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 basis.”); 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% sulfur 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 & Electric Co. - Blount Street 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 states: “The operating hour limitations are necessary to ensure that 

the national ambient air quality standard for nitrogen 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 limits the quantity, rate, 

or concentration of emissions of air pollutants on a continuous basis, including any requirement 

relating to the operation ... of a source to assure continuous emission reduction, and any ... 

operational standard promulgated under this chapter.” (Emphasis added.) The implementing 

regulations specifically state that title V permits may include “operational requirements and 

limitations,” and makes clear that those operational requirements can “assure compliance with ... 

applicable requirements....”161 The regulations define “applicable 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 restrict PTE, thus allowing sources to qualify as 

synthetic minor sources for major source requirements 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 Section XI.C of this Memorandum that contain 

additional examples of permits with such limits both include several examples 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 prevent an applicable requirement from being 

triggered in the first instance. Thus, these types 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 being 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 comply 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 standards, including those 

operational requirements and limitations that assure compliance with all applicable requirements 

at the time of permit issuance....” (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 Act, including section 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)). 
68 

C. Examples of Permits Requiring Reduced Utilization at EGUs164

Facility name Location of 

facility 

Type of EGU Type of 

permit 

Permit number 

Permit authority issuing permit 

Date permit signed or issued 

Text of permit condition containiutilization limit 

Shady Hills Generating Station 

Pasco County, Florida 

Peaking plant; permit authorized construction of two simple cycle combustion turbines (natural gas with backup fuel of ULSD fuel oil) 

GHG-only PSD permit 

PSD-EPAR4013 EPA Region 4 1/13/2014 Condition IX.B.2: If both EU 005 a

[combustion turbines] are constructshall not operate an average of morhours per year per combustion turbmonth rolling total basis. No single operate more than 5,000 hours per month rolling total basis. If only ocombustion turbine is installed, it sno more than 3,390 hours per year month rolling total basis. Permittee monitor and record the number of hcombustion turbine operates monthtotaled every month for the previou

Tampa Electric Company, Polk Power Station 

Polk County, Florida 

260 MW integrated coal gasification and combined cycle turbine unit; permit added two dual fuel simple cycle combustion turbines 

PSD PSD-FL-263 Florida DEP 10/8/1999 General Operation Requirements 

13. Maximum allowable hours of o

each unit are 4,380 hours per year oand 750 hours per year on fuel oil. 210.200, FAC, (Definitions – PotenEmissions), 62.212.400, FAC, (BADetermination)] 

Antelope Elk Energy Center 

Abernathy, Texas 

168 MW, peaking and intermediate load plant; permit added one natural gas fired simple cycle combustion turbine 

GHG-only PSD 

PSD-TX-1358-GHG 

EPA Region 6 

6/2/2014 Special Permit Conditions – Turbin

Requirements III.A.2.d – The turbine is limited to operational hours on a 12-month robasis. III.A.2.a – The BACT limit of 1,30CO2/MW-hr gross output is based rolling operational hour average bacalculated daily using equations for provided in 40 CFR Part 75, AppenProcedure 2.3 or the CO2 emission40 CFR Part 75, Appendix F. The P

164 These examples of permits containing terms that require reduced utilization at EGUs were identified with the assistan

Copies of the cited permits are available in the docket for this action. 
69 

Facility name Location of 

facility 

Type of EGU Type of 

permit 

Permit number 

Permit authority issuing permit 

Date permit signed or issued 

Text of permit condition containiutilization limit 

shall calculate each day a combustioperates, CO2 emissions over the rhours of operation basis divided by electrical output over the same pericomparison to the limit for the comturbine. 

Sunbury Generation LP 

Snyder County, PA 

Repowering of facility by replacing coal fired generation with natural-gas fired combined cycle turbines 

Minor new source review preconstruction permit 

Plan Approval No. 55-00001E 

Pennsylvania DEP 4/1/2013 Condition #016: Pursuant to the be

technology requirements of 25 Pa. Sections 127.1 and 127.12, Source [turbine] shall not be operated in excess of the fol(a) 7,955 hours in any 12 consecutiperiod (CMP) if the Siemen[s] F4 oselected, (b) 6,920 hours in any 12 CMP if thF5 option is selected, (c) 8,275 hours in any 12 CMP if th7FA.05 option is selected. 

Madison Gas & Electric Co., Blount Street Generating Station 

Madison, Dane County, Wisconsin 

Natural Gas/Distillate Fuel Oil Boilers 

Title V Renewal 

113004430-P20 Wisconsin DNR 6/30/2015 Condition I.A.3.1 

(1) The operating hours for boiler Bexceed 5,100 hours during each 12 month period.[FN 1]. [ss. 285.63(1285.65(7), Wis. Stats, s. NR 407.09Adm. Code] FN 1 states: “The operating hour linecessary to ensure that the nationa

quality standard for nitrogen oxide and maintained.” 

City Center West Madison, Dane 

County, Wisconsin 

Peak shaving generators 

FESOP (Synthetic Minor, NonPart 70) 

113225200-F01 Wisconsin DNR 4/19/2007 Condition I.A.2(2) [Part of NOx lim

(2) Each generator may not be opermore than 16.66 hours per month, aover any 12 consecutive months. Tproposed by the permittee to be min70. [s. 285.65(7), Wis. Stats.] 

Rockgen Energy Center, LLC 

Christiana, Dane County, Wisconsin 

Nominal 525 MW Peak Power Electric Generation Facility 

Title V Renewal 

113308030-P10 Wisconsin DNR 2/04/2010 Condition I.C.1(1) 

(1) Each of the three combustion tuprocesses (P01, P02, and P03) may operated more than 3800 hours in aconsecutive months of which not more than 800 hours iconsecutive 12-month period shall distillate fuel oil with less than 0.05

weight. This condition is necessary to meet the Bemission limits for sulfur dioxide, cmonoxide, nitrogen oxides, particuvolatile 
70 

Facility name Location of 

facility 

Type of EGU Type of 

permit 

Permit number 

Permit authority issuing permit 

Date permit signed or issued 

Text of permit condition containiutilization limit 

organic compounds and sulfuric ac285.65(7), Wis. Stats.] 

We Energies – Concord Generating Station 

Watertown, Jefferson County, Wisconsin 

Combustion turbines 

Title V Renewal 

128065080-P30 Wisconsin DNR 01/15/2013 Condition I.A.7(3) The operation o

P01, P02, P03 and P04 combined aMW output may not exceed 540 hoaveraged over any 12-month periodstartup/shutdown periods. [s. 285.6Stats., 05-SDD-320 for P01 and P0SDD-104 for P03 and P04] 

Washington Island Electric Cooperative 

Washington Island, Wisconsin 

Backup electricity generating facility from diesel generators 

FESOP (Synthetic Minor, NonPart 70) - Renewal 

415186750-F20 Wisconsin DNR 02/09/2010 Condition I.Z.1.a.(1): The permitte

burn more than 300,000 gallons of and 2 distillate fuel in generators P08 and P09, combineach 12 consecutive month period.3 [s. 285Stats.] Condition I.Z.2.a.(1): The permitteoperate generators P03 and P04 for 500 hours, each, during each 12 comonth period. [s.285.65(7), Wis. St

Manitowoc Public Utilities - Custer Street 

Manitowoc, Manitowoc County, Wisconsin 

Simple cycle combustion turbine 

Title V Renewal 

436123380-P10 Wisconsin DNR 08/19/2013 Condition I.ZZZ.1.a(1): The operat

the single simple-cycle combustion (P01) may not exceed 194 hours peaveraged over any 12 consecutive m[s.285.65(3), Wis. Stats., s. 285.65(Stats.; 98-RV-153] 

Madison Gas & Electric - West Marinette Facility 

Marinette County, Wisconsin 

Simple cycle combustion turbine 

Title V Renewal 

438022420-P10 Wisconsin DNR 08/31/2010 Condition I.A.9.a(1)(a) The total ho

operation of Process B04 [combustmay not exceed 4,000 hours in any 

total 4,000 hours, the hours fired on 

fuel oil may not exceed 2,000 hourand (b) The total hours of operation power mode may not exceed 100 hyear. [s. 285.65(7), Wis. Stats.; Permit #9OP-R1] 

Wisconsin DOAUW-Stout Power Plant 

Menomonie, Dunn County, Wisconsin 

23 Emergency generator (9 powered by CI diesel engines and 14 powered by SI natural gas engines) 

Title V 617013320-P30 Wisconsin DNR 1/21/2014 (1) Each emergency electric genera

Process P01 shall only be used to pelectricity to the facility if normal eservice is interrupted and shall be omore than 200 hours in any consecumonth period. [s. NR 400.02(56), WCode, and s. 285.65(3), Wis. Stats.] 

NTE Ohio, LLC – Middletown Energy Center 

Middletown, Ohio 

Combined cycle turbine 

Permit to Install 

P0116610 Ohio EPA 11/5/2014 Auxiliary Boiler 
71 

Facility name Location of 

facility 

Type of EGU Type of 

permit 

Permit number 

Permit authority issuing permit 

Date permit signed or issued 

Text of permit condition containiutilization limit 

Condition 1.b)(1)d. Synthetic MinoNonattainment Area New Source R(NAA-NSR) for NOx and VOC. Themissions shall not exceed 3.30 TProlling 12-month summation. The VOC emissions shexceed 1.50 TPY based on a rolling summation. See b)(2)k. Condition 1.b)(2)k. The maximum consumption for this emissions uniexceed 600,000 MMBtu per rollingperiod. ... Condition 1.f)(1)b.Emission LimitaNOx emissions shall not exceed 0.0Lb/MMBtu of heat input, 1.65 pounand 3.30 tons per rolling, 12-month ... The annual emission limitation was by multiplying the hourly emission (1.65 pounds per hour) by the maxioperating hours (4,000 hours per yedividing by 2,000 pounds per ton. Thours per year value is equivalent t600,000 MMBtu, per rolling, 12-mvalue. ... See also Condition 1.f)(1)a (similar for CO); Condition 1.f)(1)c (similafor PE, PM10, and PM2.5); Condit(similar provision for VOC); Cond(similar provision for sulfuric acid Emergency Generator Condition 3.b)(1)c. Synthetic MinoNonattainment Area New Source R(NAA-NSR) for NOx and VOC. The NOx emissions shall not exceebased on a rolling 12-month summVOC emissions shall not exceed 0.based on a rolling 12-month summb)(2)e. Condition 3.b(2)e. The maximum aoperating hours for this emissions uexceed 500 hours, based upon a rolmonth summation of the operating 
72 

Facility name Location of 

facility 

Type of EGU Type of 

permit 

Permit number 

Permit authority issuing permit 

Date permit signed or issued 

Text of permit condition containiutilization limit 

Condition 3.f(1)b. Emission limitatNOx emissions shall not exceed 8.99.01 Lbs/hr, and 7.25 tons per rollinperiod. ... The hourly emission limitation wdeveloped by multiplying the maxioperating load (1475 HP) by the NOfactor supplied by the manufacturehr) divided by (453.59 g/Lb) to dethourly emissions. ... The annual emission limitation was by multiplying the hourly emission (29.01 Lbs/hr) by the maximum anoperating hours (500 hrs/yr) and di2,000 pounds per ton. Compliance rolling, 12-month emission limitatidemonstrated by the recordkeeping Condition 3.f(1)e. Emission LimitaVOC emissions shall not exceed 0.rolling, 12-month period. ... The annual emission limitation was by multiplying the maximum hourl(1.04 Lbs/hr) by the maximum annhours (500 hrs/yr) and dividing by per ton. Compliance with the rollinemission limitation shall be demonrecordkeeping in d)(1). 

PREPA San Juan San Juan, Puerto 

Rico 

2 Turbines and 4 Boilers 

PSD permit with PSD nonapplicability conditions for some pollutants. 

Not applicable EPA Region 2 4/01/2004 Condition XII.3: Both Westinghou

distillate oil fired combustion turbibe allowed to operate for up to 15,0year. Daily compliance shall be deadding the total amount of hours opboth turbines during each calendar total hours operated by both turbinepreceding 364 calendar days. Condition XII.3.c: The maximum tin these four boiler units shall be lim173.1 million gallons per year. 

El Paso Electric Company, Montana Power Station 

El Paso, Texas 400 MW peak 

and intermediate load Electric Power 

GHG only PSD 

PSD-TX-1209-GHG 

EPA Region 6 3/25/2014 BACT Limit: 

III.A.2.a. The limit of 1,100 lbs of gross output is based on ...calculatcombustion turbine operates, CO2 
73 

Facility name Location of 

facility 

Type of EGU Type of 

permit 

Permit number 

Permit authority issuing permit 

Date permit signed or issued 

Text of permit condition containiutilization limit 

Generation Facility 

over the rolling 5,000 hours of operdivided by gross electrical output operiod for comparison to the limit fcombustion turbine. III.A.2.d. Each turbine ...is limited operational hours on a 12-month rowhich shall include periods of startshutdown. 

Burney Mountain Power 

Burney, California 

Biomass Boiler PSD SAC 08-01 EPA Region 9 10/21/2010 Condition X.D.1.b: Operation of th

not exceed 8,400 hours on a 12-mobasis. 

Fort Pierre Power and Light Plant 

Stanley County, SD 

Peaking, Diesel Generators 

Title V 28.0801-58 South Dakota 

Dept. of Environ. & Nat. Res. 

04/13/2015 10.3 Hourly limit for diesel engines 

In accordance with ARSD 74:36:05owner or operator shall not operate and #3 for more than a total of 8,11during any 12-month rolling periodmonth rolling total shall be calculated every montmonth’s value and the previous 11 values. 

Madison Generation Plant 

Lake County, SD Peaking, Diesel 

Generators 

Title V 28.0801-43 South Dakota 

Dept. of Environ. & Nat. Res. 

04/07/2015 7.4 Hourly limit for diesel engines 

In accordance with ARSD 74:36:05the owner or operator shall not ope#1, #2, #3, #4 and #5 for more than 7,834 hours during any 12-month rThe 12-month rolling total shall be every month using that month’s valprevious 11 months’ values. The initial startufacility shall be the first month of throlling period. 

Northwestern Public Service Company, Yankton 

Yankton, SD Peaking, Diesel 

Generators 

Title V 28.0801-07 South Dakota 

Dept. of Environ. & Nat. Res. 

03/06/2015 7.3 Hourly limit for Unit #4 

In accordance with ARSD 74:36:05the owner or operator shall not opefor more than 1,120 hours each durmonth rolling period. The 12-montshall be calculated every month usimonth’s value and the previous 11 values. 

Basin Creek Equity Partners, Basin Creek 

Silver Bow County, MT 

Peaking, Natural gas reciprocating internal combustion engines 

Title V OP3211-02 Montana 

Dept. of Env. Quality 

09/04/2011 B.5. Combined RICE operation (9 

shall be limited to a maximum of 3during any rolling 12-month time p17.8.749). 
74 

Facility name Location of 

facility 

Type of EGU Type of 

permit 

Permit number 

Permit authority issuing permit 

Date permit signed or issued 

Text of permit condition containiutilization limit 

Basin Electric Power Cooperative, Culbertson 

Roosevelt County, MT 

Peaking, combustion turbine 

Title V OP4256-00 Montana 

Dept. of Env. Quality 

12/14/2010 B.6. Operation of the turbine gene

including startup and shutdown, shexceed 3,400 hours per rolling 12-mperiod (ARM 17.8.749). 

Payson City Corporation – Payson City Power 

Utah County, Utah 

Peaking; four dual-fuel (NG/oil) internal combustion engines, two serving 2.65-MW electrical generators, one serving a 2.093-MW electrical generator, and one serving a 1.80-MW electrical generator 

Title V 4900080004 Utah 

Dept. of Env. Quality 

1/16/2015 Permit condition II.B.6.e (pertainin

fuel engines): Total hours of operation shall not ehours per rolling 12-month period fengines combined. [Origin: DAQE-AN108230006-14, IX.H.3.c]. [R307-110-17(SIP IX.H403-8(1)(a)(BACT)] 

Provo City Power - Power Plant 

Utah County, Utah 

Peaking; four dual-fuel (NG/oil) internal combustion engines, each serving a 2.585-MW electrical generator; two NG-fired boilers, each serving a 9.20-MW electrical generator 

Title V 4900018003 Utah 

Dept. of Env. Quality 

10/28/2009 Permit condition II.B.2.c (pertainin

fuel engines): Combined hours of operation shall than 48 hours per day for the four e[Authority granted under R307-4018(1)(a)[BACT]; condition originateAN0795006-04]. 
75 

Capacity Limits 

Facility name Location of 

facility 

Type of EGU Type of 

permit 

Permit number 

Permit authority issuing permit 

Date permit signed or issued 

Text of permit condition containing ulimit 

PREPA Costa Sur 

Guayanilla Puerto Rico 

Two boilers 4 & 5. Each boiler is rated at 3,950.7 MMBTU/hr and can produce 410 MW (820 MW in total). 

Revised state construct-ion permit 

PFE-31-0810-0455-II-C (in Spanish) 

Puerto Rico Envt’l Quality Board 

09/20/2010 Condition B.2 provides 5 different oper

scenarios for the two boilers: 1) 100% n2) 25% natural gas & 75% fuel oil; 3) 550% fuel oil; 4) 75% NG & 25% fuel o5)100% fuel oil. Each operating scenarmaximum fuel oil and natural gas restriThe capacity factor for each of the operscenario is 71%, 65%, 65%, 65%, and 6respectively. 

AES-Puerto Rico Co-generation Project 

Guayama, Puerto Rico 

454 MW Circulating Fluidized Bed BoilerCoal fired. 

PSD - Revised Permit 

Not applicable EPA Region 2 08/10/2004 See Condition XVI.6: 

Maximum Annual Capacity Factor 

a. AES-PRCP shall not exceed 

annual capacity factor of 95period of 12 consecutive moCompliance will be demonslimiting facility fuel use to a of 40,966,709 MMBtu durinof 12 consecutive months. Ashall maintain fuel use recordemonstrate compliance witcondition. 

b. “Annual capacity factor” me

between the actual heat inpusteam generating units from during a period of 12 conseccalendar months and the potinput to the steam generatinfuels had the steam generatioperated for 8,760 hours durmonth period at the maximuheat input capacity of 4922.Therefore, a maximum annufactor of 95% means fuel usexceed 40,966,709 MMBtu period of 12 consecutive calmonths. 

Great River Energy - Coal Creek Station 

McLean County, North Dakota 

Base-loaded; two lignite-fired boilers, one rated at 6,015 MMBtu/hr, one rated at 6,022 MMBtu/hr; two liquid fuel fired auxiliary boilers, each rated at 172 MMBtu/hr 

Title V T5-F82006 North Dakota 

Dept. of Health, Dept. of Air Quality 

1/30/2015 Permit condition 3.C: 

Auxiliary Boilers Annual Capacity FacBeginning on the compliance date of N22 (40 CFR 63) Subpart DDDDD for eboilers (January 31, 2016 or as amendeEU4 auxiliary boilers shall be limited to 

annual capacity factor of no more than maintain status as limited use boilers as 40 CFR 63.7575. ... 
76 

Facility name Location of 

facility 

Type of EGU Type of 

permit 

Permit number 

Permit authority issuing permit 

Date permit signed or issued 

Text of permit condition containing ulimit 

Otter Tail Power Company - Coyote Station 

Mercer County, North Dakota 

Base-loaded; one lignite-fired cyclone boiler rated at 5,800 MMBtu/hr; one oilfired auxiliary boiler rated at 202 MMBtu/hr 

Title V T5-F84011 North Dakota 

Dept. of Health, Dept. of Air Quality 

10/2/2013 Permit condition 4.F: In order to maint

use boiler classification as defined by 4

Subpart DDDDD, EU2 shall combust n1,263,943 gallons of No. 2 fuel oil per cyear, which corresponds to an average acapacity factor of 10 percent. Periodic shall be completed as specified in 40 CThese requirements shall become effecttime EU2 must comply with 40 CFR 63 DDDDD. Applicable Requirement: PTC 13032 an33-15-22-03, Subpart DDDDD 

Fuel or Heat Input Limits 

Facility name Location of 

facility 

Type of EGU Type of 

permit 

Permit number 

Permit authority issuing permit 

Date permit signed or issued 

Text of permit condition containing util

Wisconsin DOAUW – Green Bay Green Bay, Wisconsin 6 Industrial Watertube boilers 

which burn natural gas and distillate oil 

Synthetic minor, nonPart 70 

405043540-F20 

Wisconsin Department of Natural Resources 

2/16/2010 D. Conditions applicable to the entire facil

1. Synthetic Minor Restrictions [fn 7] (1) The total quantity of natural gas fired bmay not exceed 109.6 million Cubic Feet month, averaged over any 12 consecutive period. [s. 285.65(7), Wis. Stats.] (2) The total quantity of distillate fuel oil f

facility may not exceed 109,600 gallons peaveraged over any 12 consecutive month p285.65(7), Wis. Stats.] FN 7 states: These restrictions on fuel uselimitations on Nitrogen Oxides emissions natural gas (0.10 lbs/MMBTU) and distilllbs/MMBTU) are both necessary for the fa

considered a synthetic minor source under Title V. A. [Boiler Limitations] 3. Nitrogen Oxides (1) 0.10 pounds of Nitrogen Oxides per mof heat input when firing natural gas and 0of Nitrogen Oxides per million BTU of hewhen firing distillate fuel oil. [FN2] [s. 28s. 285.65(7), Wis. Stats., 04-DCF-301] 
77 

FN2 states: This condition, along with the restrictions on the quantities of natural gas distillate fuel oil that may be fired, are necassure that the facility constitutes a synthesource under the Title V and PSD permit pThese emission rates are based on the AP-factors of 100 lbs/cf6 for natural gas and 2for distillate oil combustion, in boilers witless than 100 MMBTU/hr. 

Anita Municipal Utilities 

Anita, IA IC Diesel Engines Minor new 

source review preconstruction permit 

02-A-375 Iowa Department 

of Natural Resources 

8/22/2002 14. Operating Limits 

... The total amount of fuel used by this unit not exceed 189,225 gallons per twelve (12rolling period.165

165 While Caterpillar makes several versions of this generator set, the low fuel consumption version uses 123.2 gal/hr at 

available at http://s7d2.scene7.com/is/content/Caterpillar/17791289. Under that assumption, the 189,225 fuel limit woul

hours (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 relevant 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 categories provide the same product: electricity services. 

Moreover, combining them in this rule is consistent with our decision to combine them in the 

CAA section 111(b) rule for new sources that accompanies this rule. In addition, many of the 

monitoring, reporting, and verification requirements are the same for both source categories, and, 

as discussed next, we are codifying all requirements 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 trading between steam generators and combustion 

turbines by obviating any legal questions 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 building blocks on a timetable that allows them to 

meet their emission performance requirements by 2022 and later without having to incur 

significant expenditures for the first several years after promulgation of this rule. This same 

information supports preamble section VIII, which 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 short notice, sometimes retiring their plants within a 

few months of announcing their intention to do so. 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 availability of other generation resources needed to meet load 

requirements. Even so, these instances illustrate 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 intrusive 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 incur significant expenditures for the first several years after 

promulgation of this rule. 

 In addition, these instances also demonstrate circumstances in which the electricity 

system has sufficient resiliency, including the ability to make some types of transmission 
79 

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 Energy, 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 previously identified and needed to be accelerated, and some of 

which were new. Most involved small, lower voltage 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 procedures. The plants closed on time. 

Will County Unit 3 (251 MW) 167

This unit notified PJM in the fall of 2014 that it would close on April 15, 2015. 

PJM found no reliability issues with the closure, and the unit closed on schedule. 

Walter C. Beckford 5 & 6 (652 units) 168

The units notified PJM in September of 2014 that it wanted to close 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 described in section V. of the preamble. 

In this rulemaking, the EPA is determining the 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 generator subcategory, and will refer only to building 

blocks 2 and 3. 

Based on its determination of the BSER, the EPA determines the emission performance rate 

that reflects the degree of emission limitation achievable through the application of the BSER. 

For the fossil fuel-fired steam generator subcategory, the EPA is determining the emission 

performance rate to be 1305 lbs CO2/MWh. 

Individual affected EGUs in the source subcategory 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 implement169 the BSER. These 

 

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

167 http://www.powermag.com/nrg-to-shutter-repower-illinois-coal-units-in-modernization-bid/ 168 http://www.cincinnati.com/story/money/2014/08/29/beckjord-plant-shutting-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 generation, emissions trading, or undertaking a 

combination of those measures or actions. 

It should be noted that while it would be technically 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 reducing a portion of its generation and purchasing 

ERCs or undertaking other actions, that would not maximize the efficiencies available to each 

source. The EPA’s determination of the BSER for 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 being able to implement the BSER in precisely the manner that the 

EPA defined it for the source category as a whole. 

Rather, it is sufficient that each affected EGU is capable of achieving its emission limit 

(which, again, EPA calculated on the basis of the degree of emission limitation achievable by the 

application of the BSER to the source category) by applying or implementing the BSER (which, 

again, each affected EGU can do by undertaking any of a set of measures 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 able 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 another 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 installed and operated at 

full capacity, reduces emissions by 90%, but that the EPA determines is of reasonable cost only 

if applied to half the production. Assume further that it is reasonable to expect that the sources in 

the source category will engage in emissions trading. In this case, the EPA, in its emission 

guidelines, would identify the add-on control 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 emissions by 90%, and being able 

to sell emission reduction credits to defray the costs of the add-on control), 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” measure 
81 

 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 reliance on coal-cleaning as 

the basis for emission limits under section 111 makes 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” measures, 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 preamble, 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 proposed standards of performance for an 

“initial list of five stationary source categories which contribute significantly to air pollution 

which causes or contributes to the endangerment of public health or welfare.”170 The first 

category identified in the proposed rule addressed fossil fuel-fired steam generators, for which 

EPA proposed standards for particulate matter, SO2, and NOx.

171 

With respect to SO2 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 effects on the economics of producing 

electric power.”173 In particular, one of EPA’s major considerations was “[t]he desirability of 

setting [SO2] standards that would allow the use 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 desulfurization facilities that would come on-line outside the 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 affected 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 parties 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-fired 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 SO2 emissions. To address this, Congress 

inserted the term “technological” into the definition 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 essentially “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-switching under the 1977 CAA Amendments, 

Congress made clear that EPA could not require the installation or operation of any particular 

technological system of continuous reduction under Section 111.179 Congress nevertheless 

ensured that EPA could still consider fuel cleaning as part of a “technological system of 

continuous emission reduction,” just as EPA had prior to the 1977 CAA Amendments. To that 

end, Congress added to the definition of standard of performance for certain new sources in 

section 111(a)(1) the words “precombustion cleaning or treatment of fuels” to “insure that in 

upgrading the standards and in defining 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 these techniques would not necessarily 

be accomplished at the individual source. For example, a House committee report indicates that 

an assessment of the best technological system of continuous emission reduction for fossil fuelfired power plants would include “various coal-cleaning technologies such as solvent refining, 

oil desulfurization at the refinery”.181 Coal-cleaning, Senator Muskie 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-cleaning technology “requires too much space and 

is too expensive to be employed at individual 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 cleaning 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 there is any doubt whether coal-cleaning activities must be 

conducted at a fossil fuel-fired power plant 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 even 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 outside the affected source. 

In 1990, Congress largely reinstated the 1970 definition 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. Nevertheless, there is no indication that 

reinstating the 1970 definition of standard of performance was designed to limit its scope. Thus, 

just as fuel cleaning was factored into the first 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-institutional steam generating units, required the owner 

or operator of such units to include “a signed statement 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 authorize basing standards of performance 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 standards 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 preamble 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 renewable energy in reducing emissions 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 precipitation 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 the Director of the Office of Science and Technology Policy 

and the National Academy of Sciences to study the “projected 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 significant 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 (SO2) and 

nitrogen oxide (NOx), in the United States and that older plants in particular were responsible for 

“[m]ore than 90 percent” of total U.S. power plant emissions.187 However, the existing CAA 

proved inadequate to address concerns with acid rain because older 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 encourage “energy conservation, use of 

renewable and clean alternative technologies, and pollution prevention as a long-range strategy . 

. . for reducing air pollution”.190 In doing so, Congress fashioned an SO2 cap-and-trade program 

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

based NOx 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 “strategies 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 “technologies and strategies” as “energy efficiency; 

enhanced emissions reduction or control technologies—like sorbent injection, cofiring with 

natural gas, integrated gasification combined cycles; fuel-switching and least-emissions 

dispatching in order to maximize 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 SO2 and 

20.5 million tons of NOx were emitted from anthropogenic sources in 1985. Id. at 828. Electric utilities accounted 

for 16.1 million tons of SO2 and 6.7 million tons of NOx, and industrial sources (including industrial combustion and 

industrial processes) accounted for 5.6 million tons of SO2 and 4.1 million tons of NOx. 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, “utilities 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 program both to minimize costs and to create 

incentives for aggressive and innovative efforts to control pollution.”195 

The following briefly addresses the relevant control “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 flexibility 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 SO2 and NOx emission limitations and also to meet heat discharge limits.199 

It was therefore logical to design an allowance system that took these arrangements into 

account.200 In fact, the Senate Report explained that “the Administrator should be mindful that 

to exploit the efficiencies afforded by the allowance system,” recognizing 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 clean alternative technologies,” 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) (recognizing “least-emissions dispatching” 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, Vol. 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 National 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 with . . . 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 efficiency, can greatly reduce emissions of acid rain 

precursors and global warming gases.”203 “That makes them a potent weapon against 

catastrophic climate change, widespread respiratory 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 systems can easily and cost-effectively be integrated into the existing 

utility sector, increasing power supplies without increasing pollution.”205 

Allowances for emissions avoided through energy 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 utility for qualified energy conservation 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 significantly curtail sulfur dioxide emissions, but 

they emit little or no nitrogen oxides and carbon dioxide, and decrease the envionmental 

[sic] degradation of land and water associated with oil imports and energy production.208

Moreover, “[t]hese important environmental attributes should make conservation 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 SO2 and NOx from fossil fuel-fired power 

plants. Congress was also clear that these tools could be used “in combination” and in many 

cases could be used to reduce emissions of CO2. Accordingly, these measures are appropriately 

within the scope of Section 111(a)(1) and may be considered as the BSER. 

Some commenters claim that Title IV precludes regulation of the “electricity system as a 

whole” and that Sections 401(b) and 404(f) in particular prohibit EPA from considering building 

blocks 2 and 3 as the BSER. As an initial matter, 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-fired power plants. The fact that power plants 

may serve an interstate electricity system does 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 electricity system as a whole. 

Second, neither the purpose statements in Section 401(b) nor the crediting instructions in 

Section 404(f) preclude consideration 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 designed Title IV to “encourage” renewable energy 

technologies. Section 404(f) in particular provides additional incentives to credit sources for 

compliance with Title IV. Nothing in the text of Title IV nor in its legislative history suggests 

that these provisions were intended to preclude the consideration of certain “strategies and 

technologies” elsewhere under the CAA. Indeed, these provisions highlight Congress’ 

preferences for cleaner and cost-effective measures to “reduce emissions of acid rain precursors 

and global warming gases.”210 In fact, there is strong legislative 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 developing 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 been 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 because they illustrate some of the types of nonBSER actions that are available for 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 already 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, several states have already adopted RE 

measures in their SIPs for attaining and maintaining the national ambient air quality standards 

(NAAQS), and the EPA has provided initial 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 Columbia 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 photovoltaic 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 Energy Efficiency and 

Renewable Energy Measures (Aug. 2004), http://www.epa.gov/ttn/oarpg/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 Attainment 
88 

Since those SIPs were submitted, many states have adopted legislative mandates for 

renewable energy, and the EPA has provided additional 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 Management (NESCAUM) and three states (Maryland, 

Massachusetts, and New York) to identify opportunities for including EE/RE in a NAAQS SIP 

and to provide real-world examples and lessons learned through those states’ case studies.217 

In the EE/RE Roadmap, EPA recognized four “pathways” for incorporating EE and RE 

into SIPs: the baseline emissions projection pathway, the control strategy pathway, the 

emerging/voluntary measures pathway, and the weight of evidence pathway. Of these four 

options, only the “control strategy” pathway results in federally enforceable obligations with 

respect to EE and RE. A collection of fifteen States provided additional information to EPA 

noting some states may choose the federally-enforceable control strategy pathway within their 

State Plans, and “EPA and the state would share enforcement authority.”218 However, these 

States anticipated that most states would choose the “baseline emissions projection pathway” in 

which states would project the emissions 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 detailed appendices for twelve states 

explaining the success of their various investments 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 their SIPs, and urged EPA to encourage states to 

use its existing guidance on RE and EE, particularly 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 Policies 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 Incorporate 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/nescaum-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 facilitate inclusion of EE in state CPP compliance.”); States’ 

Roadmap on Reducing Carbon Pollution, Attach. at 20 (Dec. 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 states engaged in pioneering efforts to reduce 

power plant pollution through RE measures. For example, EPA has collaborated with the 

Connecticut Department of Environmental Protection (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 NOX emissions during high demand days as part of the weight of 

evidence analysis in its 2007 8-hr ozone attainment demonstration, 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 measures into its SIP as 

federally enforceable control measures, in particular, 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 system225 -- facilitate the calculation of the amount of emission reductions 

available from RE, as well as EE. AVERT relies 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 dioxide. States, PUCs, analysts, and environmental agencies are 

currently using AVERT to lower the costs of their analytical work, 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 discussion concerning the integrated 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 Air Interstate Rule (CAIR), and Cross-State Air 

Pollution Rule (CSAPR).

The EPA’s regulatory initiatives under the CAA’s “good neighbor” provision in section 

110(a)(2)(D)(i)(I) have recognized the unique opportunities available for reducing emission from 

fossil fuel-fired EGUs. The EPA’s NOx SIP Call, CAIR, and CSAPR 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 Decision 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 limitations, 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. NOx SIP Call 

In the NOx SIP Call, the EPA calculated the state 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 projected 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 NOx emissions from EGUs: 

System NOx emissions can be reduced in several ways. One way is through 

dispatch decisions, by increasing generation from lower-emitting units, while 

decreasing the use of higher-NOx units. For States covered by the Ozone 

Transport Rulemaking, the model results did indicate lower levels 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 facilitated by the interconnected nature of the 

electricity grid, and the fact that all EGUs produce 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 generation 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 EGUs. For example, the prospect of generation 

shifting led the EPA to reject commenters’ suggestion 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, including cogeneration units, substantially 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 NOx SIP Call Proposal RIA at 2-16 (emphasis added). 233 70 FR 25162, 25277. 
91 

Inclusion of all units substantially in the electricity sales business minimizes the 

potential for shifting utilization, and emissions, from regulated to unregulated 

units in that business and thereby freeing up allowances, with the result that total 

emissions from generation of electricity for sale exceed the CAIR emissions caps. 

The fact that units in the electricity sales business are generally interconnected 

through their access to the grid significantly 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 could undermine CAIR’s air 

quality goals. The EPA explained that if a state 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 important because it prevents shifting of 

utilization (and resulting emissions) to uncapped EGUs. The EGUs are part of a 

highly interconnected electricity grid that makes utilization shifting likely and 

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

electricity), and therefore the units that are least expensive to operate are likely to 

be operated as much as possible. If capped and uncapped units are interconnected, 

the uncapped units’ costs would tend to decrease relative to the capped units, 

which must either reduce emissions or use or buy allowances, and the uncapped 

units' utilization would likely increase. The cap ensures that emissions 

reductions from these interconnected sources are actually achieved rather than 

emissions simply shifting among sources. The caps constitute the State EGU 

Budgets for SO2 and NOx.

235 

The potentially negative consequence of generation shifting between regulated and unregulated 

EGUs drove the EPA’s decisions to include certain 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 for generation shifting across an interconnected 

electricity grid: 

. . . in the event of any future planned 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 State participating in the CAIR cap and 

trade program would need to be made subject 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 program, the new EGU might also be required, 

through a TIP or FIP, to participate in the program. This would depend on the 

potential for emissions shifting and other specific circumstances (e.g., whether the 

 

234 70 FR 25162, 25277 (emphasis added); 235 70 FR at 25256–57 (emphasis added). 
92 

EGU would service the electric grid of States involved in the cap and trade 

program.)236

The EPA was not only motivated in CAIR to develop a rule that would avoid the negative 

consequences of generation shifting between regulated and unregulated EGUs. The Agency was 

also influenced by the opportunities that generation shifting presented as a compliance option. 

For example, the EPA considered whether certain EGUs smaller than 250 MW should be 

included in the CAIR budgets and model rule, given 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 implement 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 projected that fossil-fuel-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 CSAPR’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 decided that a certain quantity of emission reductions 

was “feasible” at that cost threshold because affected EGUs could cheaply and efficiently reduce 

emissions by generation shifting to lower-emitting sources: 

EPA applied escalating SO2 cost per ton thresholds for Group 1 states to create 

the cost curves for 2014 and beyond. For 2012 SO2, the cost per ton was held 

constant at $500/ton as the cost thresholds 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 prior to 2014. For the reasons that follow, 

EPA concluded that significant reductions could be achieved by 2012 and that it 

is important to require all such reductions by 2012 to ensure that they are 

achieved as expeditiously as practicable. SO2 and NOx reductions come from

operating existing controls, installing combustion 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/airtransport/pdfs/FinalRIA.pdf. 
93 

increased dispatch of lower-emitting generation 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 emissions 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 presented below include all feasible 2012 

reductions up to a threshold of $ 500/ton for SO2 and $ 500/ton for annual NOx in 

states linked to receptors for PM2.5, as well as $ 500/ton for ozone-season NOx in 

states linked to receptors for ozone. These cost per ton levels do not precipitate 

advanced post-combustion control 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 threshold “reflect[ed] an amount of . . . generation shifting that can be 

achieved for $500/ton.”241 Had EPA ignored the reality of generation 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, EPA projected that generation shifting was a 

technique that EGUs would actually engage in as a means of reducing emissions: The electric 

utility sector would meet 2012 NOx requirements by, inter alia, “dispatching lower emitting units 

more often . . . .”242 For the 2012 SO2 requirements, EPA projected that, “the fleet will increase 

dispatch from lower-sulfur-emitting units as well as from natural gas-fired generators.”243 For the 

2014 phase 2 compliance deadline, EPA projected that sector would reduce SO2 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 EPA 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. NOx 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 SO2, 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 NOx SIP Call, the EPA noted that NOX emissions from EGUs could be reduced 

through efficiency projects that improve EGU heat rate (referred to in the instant rule as building 

block 1), and by replacing generation at existing 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 NOx 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 NOX reduction strategy” for EGUs, including as 

part of an emission trading program: 

The EPA believes that, with respect to EGUs, there is a large potential for energy 

efficiency and renewables in the NOx SIP call region that reduce demand and 

provide for more environmentally-friendly energy resources. 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 NOx emissions proportionately, while the associated generator would 

produce the same amount of electricity. Renewable energy source generation 

includes hydroelectric, solar, wind, and geothermal generation. EPA recognizes 

that promotion of energy efficiency and renewables can contribute to a costeffective NOx reduction strategy. As such, EPA encourages States in the NOx SIP 

call region to consider including energy efficiency and renewables as a strategy in 

meeting their NOx budgets. One way to achieve this goal is by including a 

provision within a State’s NOx Budget Trading Rule that allocates a portion of a 

State’s trading program budget to implementers of energy efficiency and 

renewables projects that reduce energy-related NOx emissions during the ozone 

season. Another is to include energy efficiency and renewables projects as part of 

a State’s implementation plan.247

The EPA’s treatment in the NOx SIP Call of heat rate improvements, renewable energy projects, 

and demand-side energy efficiency as “additional control measures” for reducing emissions from 

EGUs further illustrates how the EPA has encouraged sources and states to leverage the 

integration of the utility power sector to reduce emissions.248 Indeed, when some commenters 

expressed concern that the NOx SIP Call provided insufficient time for the construction, 

procurement, and installation of add-on pollution controls at EGUs, the EPA allayed those 

concerns in part by pointing to the “NOx-reducing benefits that energy efficiency and renewables 

projects provide, many of which could be developed 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 NOx 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 Pollution Prevention Act (PPA) of 1990 recognize 

the significant role that energy efficiency and renewable energy resources can play in reducing 

pollution and achieving the nation’s environmental goals.”252 These set-aside pools of 

allowances are for “energy efficiency and renewable energy projects that reduce electricity 

generation,” and thereby “reduce emissions of pollutants, including NOx.”253 The EPA’s Climate 

Protection Division explained in guidance for the set-asides that this voluntary option for states 

“focuses primarily on end-use electricity efficiency and renewable energy actions, since the 

amount and source of electricity consumed by end-users affects the quantity of NOx emitted at an 

electricity generating unit (EGU).”254 By 2005, seven states had incorporated such energy 

efficiency and/or renewable energy programs into their NOx 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 continued in the tradition of the NOx 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 electrical output, and noted that “states may choose to 

include non-emitting generation (such as renewables)” 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 

NOx 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 NOx Budget Trading Program, vol. 3 at ii (July 2007) (citing as an example the Clean Air Act’s 

“encouragement of energy conservation and renewable 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 NOx 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 NOx 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 NOx 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 NOx 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 replacement 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 Policy, BB-2, and the Integrated Electricity Sector

This section supports section V of the preamble by describing how the 1988 Stack Height 

Emissions Balancing Policy recognized the integrated 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 regulation, issued under CAA section 123, on July 8, 1985. 

This 1988 policy addresses the special case of “lower emissions dispatch,” which explicitly 

couples the curtailment of operations at high-emitting EGUs with increased use of wellcontrolled EGUs to assure overall emission reductions, 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 unnecessarily tall smokestacks, as a method of obtaining less stringent 

emission limitations.263 Dispersion techniques are techniques that lower the predicted groundlevel concentrations of a pollutant,264 for example by using excessively tall stacks that exceed 

“good engineering practice” (GEP), or varying emissions based on weather conditions.265 

Congress saw these attempts to obtain less stringent emission limitations by diluting emissions as 

antithetical to the pollution-reducing goals of the CAA.266 In order to eliminate the incentive to 

use dispersion techniques, section 123 provides that the “degree of emission limitation required” 

from a source may “not be affected in any 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 Comments on the December 23, 1985 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 unnecessarily tall stacks that dispersed pollutants 

would be treated for standard-setting purposes as if those stacks “were note excessively ‘tall.’”268 

Congress understood that the costs of complying 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 had been using other dispersion 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 required by the revised stack height regulation by securing 

emission limitations from another 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 emissions 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 production at higher emitting (e.g., higher 

lbs/106

 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 dispatch on a case-by-case basis.274 EPA further recognized, 

however, that the integrated nature of the electricity grid required a system-wide approach to 

ensuring that emission reductions achieved from some EGUs were 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 source’s 100-meter stack exceed 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 ambient 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 before 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 shifting production demand (e.g., increased 

dispatching) to less well-controlled 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 emission dispatch (LED), methods by which 

emission reductions are calculated and enforced may have to be expanded to 

include consideration of changes in capacity factors for all sources in a system 

affected by the proposed LED approach.275

XV. Emissions Trading 

This section supports section V of the preamble by describing EPA rules, primarily for 

the electric power sector, that rely on emissions trading. 

As discussed in section V., EPA has promulgated numerous rules, under the authority of 

several CAA provisions, that base emission reduction obligations on the ability of sources to 

engage in emissions trading and purchase emission 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 case of emissions trading, the source typically does 

not itself implement measures within its facility to control its emissions, but instead depends on 

other entities to sell it allowances 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 Rule276 was “a nationwide interstate cap-and-trade 

program for mercury, with mercury allowances fully allocated at the level authorized by the 

Administrator and with full and unrestricted participation by affected sources in all 50 states.”277 

By establishing a cap-and-trade program for mercury, 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 for compliance including buying 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 technologies, 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 Comments on the December 23, 1985 Proposal,” Docket No. A-85-05 at 2–3 

(accompanying 53 Fed. Reg. 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 declined 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). 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 Supplemental Notice, 133 (June 29, 2004). 278 70 Fed. Reg. 28606, 28619 (May 18, 2005). 
99 

EPA must next ‘‘determine’’ that such a system is ‘‘the best system of emissions 

reductions which (taking into account the cost of achieving such reduction and 

any nonair quality health and environmental impact and energy requirements) * * 

* has been adequately demonstrated.’’ (See CAA section 111(a)(1).) EPA has 

determined that a cap-and-trade program 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 reviewing 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 trade program for utility SO2 emissions, 

which EPA duplicated in large measure with the NOX SIP Call cap-and-trade 

program for, primarily, utility NOx 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 reductions 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 reductions in accordance with market forces.”284 These 

commenters supported the EPA in defending the nationwide interstate cap-and-trade program in 

the D.C. Circuit.285 

B. NOx SIP Call 

In the NOx SIP Call, the EPA set emission budgets based in part on the emissions 

reductions that EGUs could achieve by implementing highly cost-effective controls. The EPA 

“assumed an emissions trading system” when assessing the costs—and thus the appropriate level 

of control—for EGUs to reduce emissions of NOx.

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 Supplemental 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 argument 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 NOx Budget Trading Program— “a compliance mechanism 

that capitalizes on a proven means of cost effectively 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 NOx SIP Call’s emission reductions requirements 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 NOx

budget component for the electric power industry relies on consideration of the States using [an 

interstate] cap-and-trade program to reduce 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 NOx emission limitations . . . at every source.”290

As a second example, the availability of trading greatly influenced the EPA’s decision to 

base budgets on a uniform rate applicable to all fossil fuel-fired EGUs. One 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 NOx allowances, transfers of allowances 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-effective 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 approach 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, while it might be less cost-effective for some 

individual EGUs to meet an emission rate through installing on-site controls, overall those EGUs 

could purchase allowances through a trading program, so that overall 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 control 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 gas and oil-fired boilers. In fact, more 

than 50 percent of gas and oil-fired boilers already operate at NOx 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 generally 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 credits to another coal-fired boiler and 

obviate the need for that second boiler to install SCR. 

* * * 

In summary, EPA believes that an emission 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” because 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 the emissions, cost, and economic impact of the 

NOx 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 NOx 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 SO2 as well as NOx emissions from fossil fuel-fired EGUs through a tradable 

allowance system. Similar to the NOx 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 NOx SIP Call RIA at 4-10. 

297 NOx SIP Call RIA at 4-10 
102 

cost-effective controls on EGUs. The EPA’s evaluation 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, EPA assumes interstate emissions trading. 

While EPA is not requiring states to participate 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, which regulated interstate transport of SO2, 

NOx, and particulate matter emissions from fossil fuel-fired EGUs through a tradable allowance 

system.300 Here, again, the EPA concluded that -- 

the preferred trading remedy will allow source owners to choose among several 

compliance options to achieve required emission reductions in the most cost 

effective manner, such as installing controls, changing fuels, reducing utilization, 

buying allowances, or any combination of these actions.301

As with the previous two interstate transport programs, the EPA in CSAPR recognized that 

interstate trading was a particularly well-suited 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 interstate 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 national visibility goal. 42 U.S.C. § 

7491(a)(4). Congress further directed EPA to include in its regulations a requirement that States 

revise their SIPs to include “emission limitations, schedules of compliance and other measures as 

may be necessary to make reasonable progress 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., NOx SIP Call, 63 FR 57356, 57399 (Oct. 27, 1998) (noting that the EPA set state 

budgets using a uniform emission standard for EGUs 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 sources that cause or contribute to visibility 

impairment “procure, install, and operate, as expeditiously as practicable . . . the best available 

retrofit technology,” more commonly 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. Neither Section 169A nor the related Section 169B, see 42 

U.S.C. § 7492, contain any explicit statutory authorization for EPA 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 reasonable progress toward the 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 programs or other alternatives in lieu of requiring retrofit controls 

at sources subject to BART. Specifically, the Regional Haze Rule provides: 

A State may opt to implement or require participation in an emissions trading 

program or other alternative measure rather than to require sources subject to 

BART to install, operate, and maintain BART. Such an emissions trading 

program or other alternative measure must achieve greater reasonable progress 

than would be achieved through the installation and operation of BART. 

40 C.F.R. § 51.308(e)(2). EPA provided the following explanation why the Agency had the 

authority to allow States to adopt trading programs in lieu of BART despite Section 

169A(b)(2)(A)’s clear statement that BART was a technology-based standard: 

In recognition of the control and cost efficiencies that can be achieved through 

trading programs and other alternative measures, EPA is providing States with the 

opportunity to adopt alternative measures in lieu of BART where such measures 

would achieve even greater reasonable progress toward the national visibility 

goal. The overarching requirement of the visibility protection provisions of 

section 169A is to make reasonable progress toward the 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 comport 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 BART analysis. Instead, as explained by 

the Ninth Circuit in upholding EPA’s final decision, EPA acted within its 

discretion in adopting an alternative emission control standard ‘‘that would 

produce greater visibility improvement at a lower cost. Congress’s use of the term 

‘including’ in [section 169A(b)(2)] prior to its listing BART as a method of 

attaining ‘reasonable progress’ supports EPA’s position that it has the discretion 

to allow States to adopt implementation plan provisions other than those provided 

by source specific BART analyses in situations where the agency reasonably 

concludes that more ‘reasonable progress’ 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 adopt an emissions trading program or other 

alternative measures in lieu of BART so long as greater 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 include 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 long 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 SO2 backstop trading program in lieu of BART. Id. § 51.309. Before these States could take 

advantage of this option, however, the Regional Haze Rule required the Grand Canyon Visibility 

Transport Commission or another regional planning 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 Partnership (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, the D.C. Circuit held that EPA had reasonably 

interpreted Section 169A(b)(2) as permitting alternatives to BART, including trading programs, 

so long as they achieve greater reasonable progress than would the installation 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 Haze Rule to allow States to rely on 

other trading programs as alternatives to BART. In 2005, EPA amended the Regional Haze Rule 

to allow States to rely on the Clean Air Interstate Rule (CAIR) in lieu of BART, 70 Fed. Reg. 

39,104 (July 6, 2005), while in 2012, EPA again amended the Rule to allow States to rely on 

CAIR’s predecessor, the Cross State Air Pollution 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 SO2 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 pursuant to the general provisions of 40 C.F.R. 
105 

51.308(e)(2). See 79 Fed. Reg. 39,322 (July 10, 2014) (Connecticut). Each of these trading 

programs included coal-fired power plants that were subject to BART. 

F. Title IV 

Title IV expressly reflects Congress’ view that an “emission allocation and transfer system” 

is a suitable alternative compliance method for meeting “prescribed emission limitations.”305 In 

fact, Congress explained that “through a system of marketable allowances, 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 selling ‘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 excess emissions reductions from plants in other areas, 

rather than making on-site reductions, enables them to comply with their emissions 

limitations at a significantly lower cost.307 

Moreover, by “[a]llowing sources to market ‘extra’ emissions reductions” a trading system 

“should also yield important environmental benefits as sources will have strong incentives to 

make greater-than-required reductions earlier than required. Since sources will enjoy maximum 

flexibility in responding to those incentives, this approach should also stimulate innovation in 

pollution-control technology 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 Information 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 per each million Btu of fuel consumed. 

Under Phase II, coverage increased to more 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 allowed 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/ blending, co-firing with natural gas, 

allowance acquisitions, scrubbers, repowering, and plant retirements.310

G. Reasonably available control technology 

The EPA has long interpreted the reasonably available control technology (RACT) 

requirements under CAA 172(c)(1) so that the EPA may establish a RACT-level emission 

reduction obligation on all sources in a category based on a technology that the sources 

could, on average, implement cost-effectively, and 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/electricity/annual/archive/vol1/0348001.pdf (emph. added). 

311 See, e.g., NOx Supplement to the Title I General Preamble, 57 FR 55620 (Nov. 25, 1992); 

EIP Final Rule, 59 FR 16690, 16704 (April 7, 1994).