10/16/2013

Discussion Background Paper:

Best System of Emission Reduction (BSER)

Relevant Statutory and Regulatory Text

CAA Section 111(d) directs EPA to “prescribe regulations which shall establish a procedure 

similar to that provided by section 110” for the States to submit to EPA “a plan which [] 

establishes standards of performance” and “provides for the implementation and enforcement of 

such standards of performance” for existing sources of an air pollutant once EPA has established 

a standard of performance for new sources of that pollutant.1 42 U.S.C. § 7411(d). 

CAA Section 111(a)(1) defines “standard of performance” as:

a standard for emissions of air pollutants which reflects the degree 

of emission limitation achievable through the application of the 

best system of emission reduction which (taking into account the 

cost of achieving such reduction and any nonair quality health and 

environmental impact and energy requirements) the Administrator 

determines has been adequately demonstrated.

42 U.S.C. § 7411(a)(1) (emphasis added).

EPA’s CAA Section 111(d) implementing regulations call for EPA to publish draft and final 

guideline documents that provide information about the control of the designated pollutant from 

the designated sources to inform the development of State plans. These EPA regulations define 

an “emission guideline” as a guideline, “which reflects the degree of emission reduction 

achievable through the application of the best system of emission reduction which (taking into 

account the cost of such reduction) the Administrator has determined has been adequately 

demonstrated for designated facilities.” 40 C.F.R. § 60.21(e) (emphasis added). 

The regulations list, among the information that EPA will provide to the States, “[a]n emission 

guideline 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.” Id. § 60.22(b)(5) (emphasis added).

 

1 This description glosses over an important debate regarding the relationship between sections 111(d) and 

112. There is an acknowledged potential conflict in the text of the Clean Air Act as a result of competing 

House and Senate versions of Section 111(d) contained in the Clean Air Act Amendments of 1990. The 

House version would bar regulation of any source category already regulated under Section 112, while the 

Senate version focuses instead on whether EPA has already listed a pollutant under Section 112(b). EPA 

attempted to address this conflict in its 2005 Clean Air Mercury Rule by applying the bar only to pollutants 

regulated under 112, but the conflict has yet to be considered by the courts. With respect to these Section 

111(d) guidelines, EPA also appears to be proceeding as if the statutory bar only applies to pollutants 

regulated under Section 112. This issue is expected be resolved by the courts, but not likely until after EPA 

finalizes its Section 111(d) guidelines. 
2 10/16/2013

Options for BSER in EPA Guidelines

The question of what types of reductions can be considered within EPA’s BSER determination 

and in what form EPA can identify such reductions as guidelines for the States is relatively 

untested under the statute. Stakeholder dialogue up to this point has identified three primary 

options: a source-based BSER approach, a system-based BSER approach, or a hybrid approach. 

An explanation of each approach follows. 

Source-Based BSER Approach

A source-based BSER approach would only mandate reductions based upon actions that can be 

taken directly by and at the regulated source. In other words, a source-based BSER approach

would be restricted to reductions available within the source’s control and within the fence line

of the facility. 

EPA has highlighted as examples of potential supply-side actions within a source-based BSER, 

heat rate improvements or energy efficiency upgrades at the source, fuel switching to a loweremitting fuel at the source, or co-firing with a lower-emitting fuel at the source. 

The source-based BSER approach has the potential to provide some degree of legal certainty

because a source-based BSER is consistent with EPA’s previous regulation of stationary sources 

under the CAA. 

However, if EPA were to establish BSER based on fuel switching to, or co-firing of, a loweremitting fuel or the adoption of carbon capture and sequestration (CCS) at the source, this would 

introduce legal uncertainty to the source-based approach because taking these actions into 

account in determining BSER would essentially redefine the source. While this issue has not 

been addressed in the Section 111 context, in the context of an analogous EPA CAA regulatory 

program, EPA has expressly recognized that the statute probably does not allow it to redefine the 

source. In EPA’s “PSD and Title V Permitting Guidance for Greenhouse Gases,” EPA 

acknowledged that while its evaluation of Best Available Control Technology (BACT) in 

Prevention of Significant Deterioration (PSD) permitting is designed to evaluate a broad 

selection of pollution control options, it “need not necessarily include inherently lower polluting 

processes that would fundamentally redefine the nature of the source proposed by the permit 

applicant.” 26 (Mar. 2011) (citing In re Prairie State Generating Company, 13 E.A.D. 1, 23 

(EAB 2006)). EPA explained that “BACT should generally not be applied to regulate the 

applicant’s purpose or objective for the proposed facility.” Id. Having recently decided not to 

redefine the source for new and modified sources in the PSD context in its BACT guidance, it 

would be inconsistent for EPA now to decide to establish BSER for existing sources under 

Section 111 in a way that redefines the source. 

While a source-based BSER approach that relies upon heat rate improvements alone provides 

greater legal certainty, it would likely reflect a modest reduction in CO2 emissions. Some have 

suggested , for example, that the upper bound of these average on-site efficiency improvements 
3 10/16/2013

is likely around 5%.

2

 And even this level of reduction may not be achievable, since many

sources, including many newer, very efficient electric generating units, may have no actions 

available to further increase efficiency at all. Thus, total potential emissions reductions through 

a source-based BSER approach that relies upon heat rate improvements alone would likely be 

limited. 

System-Based BSER Approach

A system-based BSER approach would mandate reductions based upon actions that are taken

both at and outside the regulated source, including actions taken beyond the regulated source that 

indirectly reduce emissions at the source. In other words, a system-based BSER approach would 

include indirect emission reductions derived from reducing the overall end use of electricity in 

homes and businesses that receive power from the interconnected power grid. 

Examples of a potential system-based BSER include requiring demand-side measures, such as 

consumers installing or using more energy-efficient appliances, heating, lighting and air 

conditioning, as well as other measures outside the control of the generating unit, such as 

improvements in the transmission of electricity, dispatch changes beyond those resulting from 

market forces, and increased generation from renewable sources. 

A system-based BSER approach could achieve greater CO2 emission reductions from mandating 

offsite measures and measures beyond a source’s control. Some of those measures may be 

relatively inexpensive and some would be immediate. 

However, a system-based BSER approach that mandates reductions based on actions outside the

control of the regulated source would involve legal uncertainty.

3

 There is nothing in the CAA 

that authorizes EPA to issue guidelines that require a standard to be based on something that is 

outside the fence and outside the control of the source. It is also unprecedented—EPA, in 

stationary source regulation, has always limited its standard setting (mandatory requirements) to 

the inventory of control opportunities or work practice opportunities that reside at the source and 

over which the source has control. 

 

2 See, e.g., Burtraw, Dallas and Woerman, Matt, “Technology Flexibility and Stringency for Greenhouse Gas 

Regulations,” Resources for the Future Discussion Paper (RFF DP 13-24, July 2013)(noting at pages 6-7 

that “[t]he engineering literature suggests there are varying opportunities for efficiency improvements that 

could achieve a 4 to 5 percent improvement on average across the population of coal plants.”). It will be 

very important for EPA to do its own empirical analysis to determine the actual current opportunities for 

efficiency improvements—particularly since many of the upgrades projected in existing studies have either 

already occurred or may not be available. In doing so, EPA should be mindful of the fact that generating 

assets vary widely from state to state. 

3 Many have commented that for EPA to mandate reductions based on actions outside the control of the 

regulated source (e.g., at the customer level) would be comparable to EPA requiring a car manufacturer or 

refiner to reduce vehicle miles traveled. 
4 10/16/2013

Although the scope of EPA’s reach into the energy system is relatively untested, many believe 

that EPA lacks the authority4 to mandate State or source action beyond the source. Many States 

have implemented very successful demand-side management and renewable generation 

programs, but most of those programs have been enacted at the state level by state legislatures 

and by agencies, such as state public utility commissions, that are constitutional entities under 

state law. 

Hybrid BSER Approach

In a hybrid BSER approach, EPA would differentiate between those reductions it can mandate 

through setting minimum performance standards and those it can recognize and encourage

through one or more voluntary measures. Under a hybrid approach, EPA’s Section 111(d) 

guidelines would mandate only those reductions that are available on site at a generating unit and 

that do not redefine the source. However, EPA could also establish separate protocols to identify

and appropriately credit direct and indirect energy-sector CO2 emission reductions that States, 

third parties and regulated sources achieve by other means and that EPA can verify through 

appropriate quantification techniques. While there is an element of legal uncertainty with this 

approach, since EPA may not be able to connect offsite reductions to particular regulated units, 

there is still a strong basis for EPA to credit the reductions because they would occur at one or 

more units within the regulated source category.

 

4 See, e.g., Section 808 of the Clean Air Act, which directs EPA and the Federal Energy Regulatory 

Commission (FERC) to study the net environmental benefits of renewable energy, but directs FERC to 

transmit the study to Congress for further Congressional action rather than authorizing independent EPA 

regulatory action.
10/16/2013

Discussion Background Paper:

Form of Performance Standard

Relevant Statutory and Regulatory Text

CAA 111(d) directs EPA to “prescribe regulations which shall establish a procedure similar to 

that provided by section 110” for the States to submit to EPA “a plan which [] establishes 

standards of performance” and “provides for the implementation and enforcement of such 

standards of performance” for existing sources of an air pollutant once EPA has established a 

standard of performance for new sources of that pollutant. 42 U.S.C. § 7411(d). 

CAA Section 111(a)(1) defines “standard of performance” as “a standard for emissions of air 

pollutants. . . .” 42 U.S.C. § 7411(a)(1). EPA’s CAA Section 111(d) implementing regulations 

define “emissions standard” as “a legally enforceable regulation setting forth an allowable rate of 

emissions into the atmosphere, establishing an allowance system, or prescribing equipment 

specifications for control of air pollution emissions.” 40 C.F.R. § 60.21(f). The regulations 

further specify, with respect to the requirements for State plans, that “[e]mission standards shall 

either be based on an allowance system or prescribe allowable rates of emissions except when it 

is clearly impracticable.” 40 C.F.R. § 60.24(b)(1). The regulations provide that EPA will 

determine, in its guideline documents, the cases in which establishing emissions standards

through allowable rates of emission or allowances are impracticable. See id.1

Options for the Form of the Performance Standard in EPA Guidelines

There are several ways that EPA could frame the form of the minimum performance 

expectations in its guidelines. EPA could adopt in its guidelines: (1) a rate-based carbon 

intensity standard (e.g., pounds per megawatt-hour) and could either require the rate to be 

measured exclusively at a single source or allow it to be averaged across multiple sources; (2) a 

mass-based standard that caps the total tons of CO2 emitted in the sector over some selected 

period of time; or (3) a reduction-based standard that requires a certain degree of CO2 emissions 

reduction from a selected baseline period. An explanation of each approach follows. 

Rate-Based Carbon Intensity Approach

A rate-based approach would express minimum performance expectations in the form of an 

emissions rate or carbon intensity per unit of production for the source category averaged over 

some period of time. For example, a rate-based standard could be expressed as pounds of CO2

per megawatt hour for electric generating units. 

 

1 While the CAA allows EPA to promulgate “a design, equipment, work practice, or operational standard” 

where the Administrator finds “it is not feasible to prescribe or enforce a standard of performance,” 42 

U.S.C. § 7411(h)(1), this authority is limited to where “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 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,” id. § 7411(h)(2).
2 10/16/2013

This approach avoids legal risk as it is expressly provided for in the Section 111(d) 

implementing regulations and EPA has previously promulgated a number of rate-based emission 

standards. As noted above, the regulations provide for an emissions standard “setting forth an 

allowable rate of emissions into the atmosphere.” 40 C.F.R. § 60.21(f). EPA has considerable 

experience with rate-based programs, which it has used to remove lead from gasoline and to 

reduce emissions from various categories of mobile sources. See, e.g., EPA, Regulation of Fuel 

and Fuel Additives; Gasoline Lead Content; Final rule, 50 Fed. Reg. 9,386 (Mar. 7, 1985; 

implementing the final segment of a lead phase-out program that EPA launched in 1973); EPA, 

Final Rule for New Gasoline Spark-Ignition Marine Engines, 61 Fed. Reg. 52088 (Oct. 4, 1996); 

Final Rule, NHTSA, Average Fuel Economy Standards Passenger Cars and Light Trucks Model 

Year 2011; Final Rule, 74 Fed. Reg. 14196 (Mar. 30, 2009); EPA and NHTSA, 2017 and Later 

Model Year Light-Duty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel 

Economy Standards; Final Rule, 77 Fed. Reg. 62624 (Oct. 15, 2012). As another recent 

example, EPA’s newly proposed CO2 New Source Performance Standards for new power plants 

adopt a rate-based expression of the performance standard. See EPA, “Standards of Performance 

for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units,”

88 (Sept. 20, 2013) (prepublication version).

A rate-based standard accommodates fluctuations in the quantity of fossil energy generated over 

any given period. A rate-based standard also avoids significant practical and political risks that 

stem from the difficult and potentially controversial task of allocating allowances among the 

States. However, a rate-based approach does not guarantee an exact quantity of CO2 reductions,

since it does not limit the total CO2 emitted from the regulated sector. 

Averaging

If EPA adopted a rate-based standard in its guidelines, performance could be measured at a 

single source or could be demonstrated by averaging performance across multiple sources. 

A source-specific performance standard would raise certain practical challenges to compliance, 

given source diversity in this sector. Some electric generating units, including many newer, very 

efficient ones, would have few, if any, opportunities to reduce CO2 emissions. Thus, these 

sources may be unable to comply with a source-specific rate-based performance standard.

Allowing regulated entities to average performance across multiple sources has the practical 

benefit of providing flexibility to accommodate existing source diversity. If a regulated entity 

could average the performance of its very efficient units with other covered units in its fleet or in 

the marketplace, this would solve the problem of variation among unit performance and 

efficiency opportunities. There is also ample precedent for such an approach—EPA has 

previously allowed averaging (as well as banking and trading) in its rate-based programs. See, 

e.g., EPA, Regulation of Fuel and Fuel Additives; Final Rule, 47 Fed. Reg. 49322 (Oct. 29, 

1982); EPA, Regulation of Fuels and Fuel Additives; Banking of Lead Rights; Final rule, 50 Fed. 

Reg. 13,118 (Apr. 1, 1985); EPA, Final Rule for New Gasoline Spark-Ignition Marine Engines, 

61 Fed. Reg. 52088 (Oct. 4, 1996); EPA, Control of Air Pollution From New Motor Vehicles: 

Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements; Final 

Rule, 65 Fed. Reg. 6,698 (Feb. 10, 2000) (“Today’s action also introduces an averaging, 

banking, and trading program to provide flexibility for refiners and ease implementation of the 
3 10/16/2013

gasoline sulfur control program.”); 77 Fed. Reg. at 62,628 (compliance flexibilities for 2017 and 

Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel 

Economy Standards include credit averaging, banking and trading). 

Mass-Based Approach

A mass-based approach would express minimum performance expectations in the form of a total

cap on tons of CO2 emitted in the sector over some period of time. EPA initially adopted a massbased standard with allowance trading under Section 111(d) for its Mercury Standards of 

Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units, 

or Clean Air Mercury Rule. See 70 Fed. Reg. 28606 (May 18, 2005); although this standard was 

overturned.

2

A mass-based approach is designed to provide certainty regarding the amount of CO2 that is 

emitted by the regulated sector within each state. Current EPA Section 111(d) regulations 

appear to leave open this option for appropriate circumstances. However, some argue that EPA 

lacks any legal or other basis on which to set mandatory State CO2 budgets. Unlike ozone 

attainment and other criteria pollutant challenges, for which air quality modeling and air quality 

control region characteristics can determine a region’s attainment-based carrying capacity, there 

appear to be no environmental criteria to guide EPA in setting State greenhouse gas budgets. 

While EPA could use historical emissions, power sector greenhouse gas emissions have varied 

significantly over time due to shifts in electricity generation due to lower natural gas prices, 

regional energy strategies and other key considerations. And setting State budgets would risk 

creating winners and losers for reasons other than market conditions. Under this view, the States 

could elect to demonstrate State program equivalency with EPA’s Section 111(d) guidelines by 

using an allowance-based approach (e.g., cap and trade), but EPA could not mandate that State 

EGU emissions meet a particular mass-based limit.

Percent Reduction or Progress-Based Approach

A percent reduction or progress-based approach would express minimum performance 

expectations in the form of a specified minimum degree of CO2 emission reductions by a State or 

source relative to a chosen baseline period. Such an approach would be designed to ensure a 

total degree of CO2 emission reductions over the chosen historic level.

EPA does not appear to have previously taken a percent reduction or purely progress-based 

approach in setting source category performance standards. There is some precedent, however, 

for setting overall progress requirements for air quality control regions under the Act. Sections 

171 and 172 of the Act provide, for example, that State nonattainment plans provide for 

reasonable further progress, which requires “annual incremental reductions in emissions.”

 

2 This prior Section 111(d) mercury standard was invalidated by the D.C. Circuit on other grounds related to 

EPA’s delisting of coal- and oil-fired EGUs from the list of sources whose emissions are regulated under 

Section 112 of the CAA, which regulates hazardous air pollutants. See New Jersey v. EPA, 517 F.3d 574 

(D.C. Cir. 2008).
4 10/16/2013

If EPA selected a reductions-based standard of performance, the determination of the baseline

year and tying the degree of reduction to the BSER would present political and practical

challenges. A number of the States have undertaken CO2 emission reduction activities in recent 

years, and these States would want the selected baseline to provide credit for these reductions in 

measuring performance. Selecting the appropriate degree of reduction would also be 

challenging, as there would seem to be no necessary environmental or economic benchmark to 

guide that selection. Finally, as in the case of a mass-based emission standard, a reduction-based 

standard could arguably fail to account for regional fluctuations in fossil energy generation due 

to conditions unrelated to environmental performance.

One potential approach worth considering is the use of a progress benchmark as a proxy for State 

equivalency when EPA determines that for a state to achieve such progress it must necessarily 

have achieved the type and amount of reductions that EPA ultimately mandates in its Section 

111(d) guidelines. Under such circumstances, as outlined in a separate background paper 

regarding State equivalency, EPA may be able to use a progress demonstration to approve a State 

plan without undergoing time-consuming and costly analysis. 
10/16/2013

Discussion Background Paper:

Demonstrating State Equivalency

Relevant Statutory and Regulatory Text

EPA’s current CAA Section 111(d) implementing regulations list certain requirements that State 

plans must meet. Among the requirements of these regulations, State plans must “include 

emission standards and compliance schedules” and the emission standards “shall either be based 

on an allowance system or prescribe allowable rates of emissions except when it is clearly 

impracticable.” 40 C.F.R. §§ 60.24(a), (b)(1). State plans must specify “[t]est methods and 

procedures for determining compliance with the emission standards,” id. § 60.24(b)(2), and the 

“[e]mission standards shall apply to all designated facilities within the State,” id. § 60.24(b)(3). 

A State plan “shall include an inventory of all designated facilities, including emission data for 

the designated pollutants,” and “emission rates of designated pollutants from designated facilities 

shall be correlated with applicable emission standards.” Id. § 60.25(a). “Correlated” means

“presented in such a manner as to show the relationship between measured or estimated amounts 

of emissions and the amounts of such emissions allowable under applicable emission standards.” 

Id. A State plan must also provide for monitoring compliance, which includes recordkeeping 

and reporting requirements for owners and operators of covered sources, periodic inspection of 

covered facilities, and submission of State progress reports. Id. §§ 60.25(b), (c). Finally, State 

plans must demonstrate that the State has legal authority to carry out and enforce the plan. Id. §

60.26.

EPA’s regulations also require that where EPA has made a determination that the “designated 

pollutant may cause or contribute to endangerment of public health, [State] emission standards 

shall be no less stringent than the corresponding [EPA] emission guideline(s). . . .” Id. §

60.24(c) (emphasis added). However, the regulations authorize states to adopt a less stringent 

standard on a “case-by-case” basis for particular facilities or classes of facilities, where the state 

can demonstrate: “(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 . . . more reasonable.” Id. § 60.24(f). The regulations clarify that they should not be 

“construed to preclude any State or political subdivision thereof from adopting or enforcing [] 

emission standards more stringent than [EPA’s] emission guidelines.” Id. § 60.24(g).

Options for Measuring State Performance and Determining Equivalency

EPA’s regulations currently require States, at a minimum, to demonstrate legal authority to carry 

out and enforce a plan and to comply with the minimum monitoring, inventory, and reporting 

requirements, outlined above. States also must demonstrate that their programs meet the 

minimum required stringency as provided in EPA’s guidelines. If EPA develops a model state 

rule, then certainly timely and effective State implementation of that rule would be deemed 

compliant. Commenters have identified the following alternative methods by which a State may 

be able to demonstrate that its program is equivalent or more stringent than EPA’s guidelines:

(1) that sources within their jurisdiction meet the prescribed emissions performance in the 

manner designated by EPA (e.g., rate-based), (2) that the State program achieves comparable 
2

10/16/2013

emissions or emission reductions as anticipated by the EPA guidelines (mass-based), (3) that the 

State program achieves the progress required by EPA’s guidelines (percent reduction-based), or 

(4) that the State program reflects a degree of stringency through other indicators (e.g., market 

price in a State or regional cap and trade program) that is equivalent to or more stringent than 

required by EPA’s guidelines (e.g., price-based). EPA would be expected to promulgate 

guidance for such equivalency demonstration methods. These methods are described below.

• Rate-Based Carbon Intensity Equivalency: A rate-based equivalency would 

demonstrate that the State program achieves a carbon intensity for the regulated sector 

that is either equivalent to or better than the carbon intensity of EPA’s Section 111(d) 

emission guidelines.

• Mass-Based Equivalency: A mass-based equivalency would demonstrate that the State 

program achieves an equal or greater total CO2 emissions or emission reductions relative 

to what would be achieved by the approach outlined in EPA’s Section 111(d) emission 

guidelines.

• Percent Reduction-Based Equivalency: A percent reduction-based equivalency would 

demonstrate that the State program achieves an equal or greater degree of CO2 emission 

reductions over a selected baseline relative to the degree of emission reductions that 

would be achieved by the approach outlined in EPA’s Section 111(d) emission 

guidelines.

• Market Price-Based Equivalency: A market price-based equivalency would 

demonstrate that the State program reflects a carbon price, through a cap and trade 

program, carbon tax, or other approach, that is comparable to or above the costeffectiveness benchmark used by EPA in establishing the minimum performance 

expectations for the regulated sector in its Section 111(d) emission guidelines. 

What methods a State may use to demonstrate that its program is equivalent or more stringent 

than EPA’s guidelines is untested as a legal matter. There are a number of questions regarding 

the measurement of State performance and implementation of equivalency demonstrations that 

would be relevant to any of these approaches:

How would the measurement of State equivalency take into account the State’s ability to make 

case-by-case demonstration for a particular facility or class of facilities to support the 

application of less stringent emission standards for these facilities? Although State emission 

standards must generally be “no less stringent” than EPA’s corresponding emissions guidelines, 

EPA’s Section 111(d) implementing regulations provide the States an option to adopt less 

stringent standards for a particular facility or class of facilities if certain factors are 

demonstrated. This will be an important consideration when crafting State equivalency 

methodologies. 
3

10/16/2013

If EPA’s emissions guidelines adopt a particular form of performance standard (i.e. rate-based, 

mass-based, percent reduction-based) will EPA be able to develop effective methodology to 

evaluate State performance under all of the potential methods of equivalency? Theoretically, 

methods could be developed to compare EPA’s emission guideline under each of these metrics. 

However, there will likely be significant discourse regarding the inputs to and assumptions of 

any methodologies. 

How will the measurement of State performance and equivalency take into account a State 

program that allows offsets outside of the regulated sector? It is unclear how (or whether) the 

measurement of State performance and equivalency with EPA’s Section 111(d) guidelines would 

take into account State cap-and-trade programs that permit offsets outside of the electricity 

sector. EPA has suggested that, for the purposes of Section 111(d), the statute may constrain 

EPA to determine that emissions reductions are happening at the covered source category. 

However, EPA has indicated a strong interest in understanding the views of California and other 

States on this point.

Does each of these potential methods of measuring State performance or equivalency fall within 

the definition of “emissions standards” in EPA’s Section 111(d) implementing regulations? It is 

unclear whether each of these methods would be deemed “emission standards” under EPA’s 

definition. However, EPA’s definition incorporates both rates of emission and allowance 

systems, suggesting considerable discretion in what methods of measuring State performance 

would be encompassed within that term. There is also potential for EPA to revise the regulatory 

definition of “emission standards,” as it did in adding “allowance system” to the definition in 

conjunction with its Mercury Standards of Performance for New and Existing Stationary 

Sources: Electric Utility Steam Generating Units, or Clean Air Mercury Rule. See 70 Fed. Reg. 

28606, 28649 (May 18, 2005).

Does each of these potential methods of measuring State performance or equivalency facilitate 

compliance with State plan requirements, such as the designated facility inventory that could 

require correlation between emission rates for designated facilities and the emissions standards? 

EPA may choose to change its requirements to be more flexible for different State approaches. 

Presumptive Equivalency

Many States will be interested in whether EPA can develop an equivalency program that 

recognizes – up front (i.e., at the outset of EPA’s program) – that the State program complies 

with the EPA guidelines. If so, then a State may be able to avoid the time delay and cost 

associated with more granular equivalency demonstrations. It may be that EPA can develop 

such a “presumptive equivalency” process where certain conditions and benchmarks are met. 

For example, if a State program reduces energy sector CO2 emissions by any means (e.g., 

through generation shifts to less carbon-intensive generation sources, the implementation of 

demand-side management programs, or otherwise) beyond the minimum expected performance 

of EPA’s Section 111(d) guidelines, then more detailed analysis may not be warranted. EPA 

modeling of expected greenhouse gas reductions can provide progress or performance 

benchmarks by which it can determine that a State program must in fact have achieved the 

purpose of the guidelines. This approach essentially would recognize that, if a State were 
4

10/16/2013

ultimately required to undergo a more formal equivalency demonstration, then it would almost 

certainly be determined to have met or outperformed the guidelines.

While such an approach presents some legal risk because it is untested and deviates from EPA’s 

past evaluation of State plans under Sections 110 or 111(d), it is well within the President’s 

announced strategy for collaborating with State partners.1

 For example, if EPA were to allow 

credits generated by suitably reviewed and quantified off-system measures to be used for 

compliance by regulated electric generating units, then a state that could easily demonstrate that 

it would have sufficient credits for its on-system sources (the electric generating units) to be in 

compliance could make that demonstration to EPA rather than actually setting up a program to 

allocate the credits. EPA can insulate its overall Section 111(d) program from any legal risk 

associated with a presumptive equivalency approach if it independently promulgates that option 

or otherwise structures it as a severable component. 

 

1 Memorandum from President Obama to Administrator of the Environmental Protection Agency, Power 

Sector Carbon Pollution Standards, §1(b) (June 25, 2013) (directing EPA to “build on State efforts to move 

toward a cleaner power sector” in developing emission guidelines under Section 111(d)).
10/16/2013

Discussion Background Paper:

Harmonizing Section 111(d) Requirements with 

Section 111(b) and New Source Review for Modified Sources

A significant program design challenge of Section 111(d) guidelines will be the interaction of 

Section 111(d) with Section 111(b) requirements for modified and reconstructed sources and 

New Source Review (NSR) for modified sources. 

Relevant Statutory and Regulatory Background on Section 111(b) For Modified Sources

After EPA determines that a category of stationary sources “causes or contributes significantly 

to, air pollution which may reasonably be anticipated to endanger public health or welfare,” 

CAA Section 111(b) requires EPA to establish standards of performance for new sources within 

that category. 42 U.S.C. § 7411(b)(1). The CAA defines “new source” in this context to 

include “any stationary source, the construction or modification of which is commenced after 

the publication” of proposed new source standards under Section 111(b) that would be applicable 

to that source. Id. § 7411(a)(2) (emphasis added). The statute defines “modification” as “any 

physical change in, or change in the method of operation of, a stationary source which increases 

the amount of any air pollutant emitted by such source or which results in the emission of any air 

pollutant not previously emitted.” Id. § 7411(a)(4).

The definition of “modification” in EPA’s CAA Section 111(b) implementing regulations is 

nearly identical to the statutory definition, except that it clarifies that the reference to “any air 

pollutant” means “any air pollutant (to which a standard applies).” 40 C.F.R. § 60.2. The 

regulations separately list certain actions that are expressly excluded from consideration as 

modifications, including: 

(1) Maintenance, repair, and replacement which the Administrator 

determines to be routine for a source category. . . .

(2) An increase in production rate of an existing facility, if that 

increase can be accomplished without a capital expenditure on that 

facility.

(3) An increase in the hours of operation.

(4) Use of an alternative fuel or raw material if, prior to the date 

any standard under this part becomes applicable to that source 

type, as provided by § 60.1, the existing facility was designed to 

accommodate that alternative use. . . .

(5) The addition or use of any system or device whose primary 

function is the reduction of air pollutants, except when an emission 

control system is removed or is replaced by a system which the 

Administrator determines to be less environmentally beneficial.

(6) The relocation or change in ownership of an existing facility.

Id. § 60.14(e). 
2

10/16/2013

The regulations further clarify that “[n]o physical change, or change in the method of operation, 

at an existing electric utility steam generating unit shall be treated as a modification for the 

purposes of this section provided that such change does not increase the maximum hourly 

emissions of any pollutant regulated under this section above the maximum hourly emissions 

achievable at that unit during the 5 years prior to the change.” Id. § 60.14(h). 

EPA regulations also state that the 111(b) standard applies to “[a]n existing facility, upon 

reconstruction” and this is “irrespective of any change in emission rate.” Id. § 60.15(a). The 

regulations define “reconstruction” as “the replacement of components of an existing facility to 

such an extent that: (1) The fixed capital cost of the new components exceeds 50 percent of the 

fixed capital cost that would be required to construct a comparable entirely new facility, and (2) 

It is technologically and economically feasible to meet the applicable standards set forth in this 

part.” Id. § 60.15(b).

Considerations for Harmonizing Section 111(d) with Section 111(b) for Modified Sources

In its recently proposed “Standards of Performance for Greenhouse Gas Emissions from New 

Stationary Sources: Electric Utility Generating Units,” EPA did not propose standards of 

performance for modified or reconstructed sources. See EPA, “Standards of Performance for 

Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units,” 16 

(Sept. 20, 2013) (prepublication version) (hereinafter “Proposed Rule”). This allows an 

opportunity for EPA to harmonize any potential requirements for modified and reconstructed 

sources under Section 111(b) with its Section 111(d) guidelines for existing sources. 

Such harmonization is important because there is a significant potential for either inconsistent or 

duplicative regulation between Section 111(d) requirements and Section 111(b) requirements for 

modified sources, since they would essentially apply to the same sources—existing sources that 

are modified. Moreover, inconsistent or burdensome “modified unit” standards could truly 

interfere with Section 111(d) program objectives if they chill opportunities for improving a unit’s 

efficiency.

Given lack of detail in the statute and the fact that EPA has, up to this point, acted very 

infrequently under Section 111(d), there should be no obstacle to EPA addressing this issue. 

While EPA arguably does not have complete discretion, for instance to disregard Section 

111(b)’s application to modifications altogether, EPA has wide latitude to harmonize these 

programs within a reasonable interpretation of the statute. Such an approach would be consistent 

with Executive Order 13563, which directs agencies to “attempt to promote [] coordination, 

simplification, and harmonization” to avoid imposing regulatory requirements that are 

“redundant, inconsistent, or overlapping.” § 3 (Jan. 18, 2011). 

When EPA analyzes the performance expectations for existing units, EPA may also consider

potential performance expectations for modifications. EPA may likely find that existing and 

modified sources are limited to the same universe of potential reductions. This is because EPA 

is likely to find that existing and modified sources are similarly situated with no add-on control 

opportunity to reduce CO2 emissions for these sources. While EPA has identified partial carbon 

capture and sequestration (CCS) as the Best System of Emission Reduction for new coal-fired 

power plants in its proposed Section 111(b) standards of performance for new sources, see 
3

10/16/2013

Proposed Rule at 15-16, EPA has indicated that it does not anticipate determining that CCS has 

been adequately demonstrated for existing sources. Carbon capture technology is best designed 

when the unit is initially designed and constructed—rather than as an “add on” control. 

Furthermore, there is no geographic flexibility for existing sources to exploit for sequestration 

opportunities, while new sources at least in theory may be able to locate on or near a geologic 

formation that is suitable for sequestration. 

Thus, if EPA evaluates options for modified and reconstructed sources under Section 111(b) and 

determines that the only reasonably available measures to achieve CO2 reductions are the same 

as for existing sources evaluated in the context of Section 111(d), it would be a reasonable 

interpretation of the statute for EPA to harmonize the requirements. This could be accomplished 

through a programmatic finding that the Section 111(d) program is just as likely to address 

modified unit emissions as existing source emissions generally. If an averaging, banking and 

trading (ABT) program is adopted under Section 111(d), this would further secure such a 

harmonizing determination because the market price would reward CO2 reductions at any 

existing unit, including those that are modified. 

Of course, at any future stage, should EPA’s factual record suggest that control determinations 

(e.g., regarding cost, feasibility and energy impacts) for a modified unit differed materially from 

those for an existing source, then EPA could at that future time impose appropriate additional 

requirements on modified units. 

Relevant Statutory and Regulatory Background on NSR for Modified Sources

NSR requires existing major stationary sources that make major modifications to obtain permits 

prior to construction. There are two types of NSR permitting for major sources. The Prevention 

of Significant Deterioration (PSD) requirements apply to major sources making major 

modifications in attainment areas. See generally, 42 U.S.C. §§ 7470-7479. If the PSD 

requirements are triggered by a major modification, then installation of Best Available Control 

Technology (BACT) is required. The nonattainment NSR requirements apply to major sources 

making major modifications in nonattainment areas. See generally, 42 U.S.C. §§ 7502(c)(5), 

7503. If the nonattainment NSR requirements are triggered by a major modification, the lowest 

achievable emission rate (LAER) must be met and emissions offsets must be obtained. Although 

nonattainment NSR does not apply to significant net emission increases of greenhouse gases 

because that program applies only to criteria pollutants (i.e., and not to other “regulated” 

pollutants such as greenhouse gases), there is risk that power plant modifications pursued to 

comply with the Section 111(d) program (and thus, e.g., to reduce greenhouse gas emissions by 

improving unit’s heat rate) could be determined to trigger nonattainment NSR or PSD if that 

unit’s utilization could increase as its heat rate drops. Such a risk of triggering NSR could well 

chill the very efficiency improvements that the Section 111(d) program is designed to encourage.

Considerations for Harmonizing Section 111(d) with NSR for Modified Sources

As noted above, since the Section 111(d) program may be designed to encourage existing units 

to reduce their emissions by making on-site efficiency improvements, there is a risk that 

regulated units will be considered to trigger NSR as they make such modifications. This is 
4

10/16/2013

because a more efficient unit will likely be dispatched more and this additional activity could 

result in a net increase in emissions of one or more pollutants. 

One potential way to avoid this issue would be expressly to exempt efficiency improvements 

undertaken for Section 111(d) compliance from NSR. However, there is significant legal risk in 

such an approach. The D.C. Circuit struck down EPA’s NSR exemption for pollution control 

projects, finding that such an exemption exceeded EPA’s statutory authority. See New York v. 

EPA, 413 F.3d 3, 10-11 (D.C. Cir. 2005).

Another potential approach would be for EPA to develop appropriate alternative screening 

methods for an expedited, streamlined and less costly NSR process to assure that any criteria 

pollutant increases resulting from such efficiency improvements do not interfere with attainment. 

Under such an approach, EPA could establish screening tools to confirm that already wellcontrolled sources and sources whose “net emissions increases” of criteria pollutants remain

below attainment-related significance thresholds are deemed to comply with NSR. 

EPA could also determine that compliance with Section 111(d) standards would be deemed to 

satisfy applicable PSD or BACT requirements for GHG reductions. EPA could make this 

determination by finding that compliance with the Section 111(d) standards constitutes the 

“maximum degree of reduction . . . taking into account energy, environmental, and economic 

impacts and other costs, determine[d]” to be achievable for the permitted units. See 42 USC § 

7479(3) (definition of BACT).
10/16/2013

Discussion Background Paper:

Crediting State End-Use Energy Efficiency Measures

A number of stakeholders have argued that relatively inexpensive, near-term CO2 reductions are 

available from indirect emission reductions that result, not from controlling a unit’s emissions 

directly, but from reducing the overall end use of electricity in homes and businesses, and thus 

indirectly reducing emissions through decreased utilization of electric generation across the 

interconnected power grid. Therefore, some stakeholders have raised the potential for State enduse energy efficiency (EEE) measures to be compliance options for Section 111(d) emission 

standards, although there is disagreement on whether such EEE measures could be mandatory 

(i.e. taken into account in determining the stringency of the standard) or a voluntary alternative 

compliance option for regulated entities. 

If EPA were to base its Section 111(d) performance guidelines on the perceived availability of 

EEE measures, then there are significant questions about whether and to what extent such 

reductions can satisfy EPA guidance. As discussed below, EPA already has issued guidance to 

States interested in claiming State Implementation Plan (SIP) credit for such measures. A 

separate, but important, question is whether and to what extent such reductions also could be 

made available to regulated units for compliance purposes. 

Relevant EPA Guidance

There are no existing statutory or regulatory provisions nor EPA policy guidance that address

crediting CO2 reductions from State EEE policies or programs for compliance with EPA

stationary source regulations. However, EPA has prepared extensive guidance on providing SIP 

credit for criteria pollutant reductions from State EEE measures. While that guidance addresses 

different pollutants under a separate regulatory framework, there are aspects of the guidance that

may help inform the discussion in the CO2 emissions context.

EPA’s guidance recognizes a number of different pathways for these EEE measures to be 

credited or incorporated into SIPs. For instance, EPA provides guidance on how SIPs can 

incorporate EEE measures into SIPS as creditable control strategies or as emerging and/or 

voluntary measures. See EPA, Roadmap for Incorporating Energy Efficiency/Renewable Energy 

Policies and Programs into State and Tribal Implementation Plans, 14 (July 2012) (hereinafter 

“Roadmap”).1

EPA’s guidance explains that for States to credit EEE measures as control strategies in their

SIPs, States must document that emissions reductions from the EEE policy or program are 

quantifiable, surplus, enforceable and permanent. See Roadmap at 30. EPA acknowledges 

that these documentation and quantification efforts constitute a significant undertaking. See 

Roadmap at 35. EPA guidance allows for EEE measures to be included in SIPs as emerging 

and/or voluntary measures, and this forward-looking approach could provide some flexibility 

with respect to quantification and enforceability. 

 

1 EPA has stated that the 2012 Roadmap is a document intended to clarify existing 

guidance and does not create new guidance. See Roadmap at 16.
2

10/16/2013

Quantifiable: EPA guidance directs States to use reliable and replicable emissions 

quantification approaches. See Roadmap at 36. The guidance notes that the measures should 

include “procedures to evaluate and verify over time the level of emission reductions actually 

achieved.” EPA, Guidance on State Implementation Plan (SIP) Credits for Emission Reductions 

From Electric-Sector Energy Efficiency and Renewable Energy Measures, 5, 22-23 (Aug. 2004) 

(hereinafter “August 2004 Guidance”). EPA acknowledges that quantification may be more 

difficult with emerging and/or voluntary measures. Thus, EPA guidance allows States to include 

“provisional” reductions for reasonable further progress demonstrations and other purposes, see 

Roadmap at C-9, and those reductions can become permanent “when post-implementation 

evaluations validate the amount of emission reductions achieved.” EPA, Incorporating 

Emerging and Voluntary Measures in a State Implementation Plan, 13 (Sept. 2004) (hereinafter 

“September 2004 Guidance”). EPA recommends that the post-implementation evaluation and 

reconciliation of a measure should occur no later than 18 months after the measure is in place. 

See id. at 17. If the post-implementation evaluations show that the reductions did not occur, then 

States would be responsible for reconciling the shortfall. See id. at 13. EPA suggests that an 

assumed discount of 20 percent be used when estimating reductions from an emerging measure, 

due to uncertainty of estimates. See September 2004 Guidance at 16. For emerging and/or 

voluntary EEE measures, EPA sets the “presumptive SIP credit limit” to six percent of the total 

amount of emission reductions required for reasonable further progress, attainment or 

maintenance demonstrations. See Roadmap at 37; September 2004 Guidance at 9. Thus, in the 

absence of very substantial empirical and program development work to demonstrate actual 

emission reductions to support credit for such approaches, emerging and/or voluntary EEE 

measures can generally only be a small part of the SIP. 

Surplus: EPA guidance explains that, to count in the SIP, States must document that reductions 

from EEE measures are not double counted and demonstrate that those reductions are not being 

used for other CAA requirements. See Roadmap at 36. The guidance notes particular difficulty 

of demonstrating that emission reductions are surplus in areas that are subject to cap-and-trade 

requirements. EPA notes that one way to demonstrate that emission reductions are surplus in 

this context is through the retirement of allowances in amounts commensurate to reductions 

expected from the EEE measures. See Roadmap at Appendix C-6; August 2004 Guidance at 10. 

Enforceable: Once EEE measures are approved as control measures in the SIP, EPA notes that 

they are federally enforceable against the regulated source or the implementing party. See 

Roadmap at 30. In contrast, voluntary EEE measures that are not enforceable against a regulated 

source or implementing party require a State to make an enforceable commitment to implement 

the measures (where applicable), monitor, evaluate and report on progress, and remedy any 

shortfall if the EEE measure does not achieve the projected reductions. See Roadmap at 37. In 

other words, under the guidance, States are required to ensure that the voluntary EEE reductions 

actually occur, and the guidance states that reductions from voluntary EEE measures can only be 

credited to the State under the policy. See September 2004 Guidance at 19. 

Permanent: EPA’s guidance notes that the EEE measure must be permanent during the term in 

which the SIP credit is granted unless another measure replaces it or a SIP revision eliminates the 

need for the credit. See Roadmap at 36.
3

10/16/2013

Among the challenges that EPA has identified for incorporating EEE measures into SIPs is the 

need to establish partnerships between environmental agencies and other state agencies that may 

not typically collaborate, such as public utility commissions and state energy offices. See 

Roadmap at 15. EPA has also noted the challenge of quantifying emissions reductions from 

these measures. See id. 

Considerations for Establishing Protocols to Credit State EEE Measures for Use in a

Power Sector 111(d) Program

Aside from the important question of whether anticipated net greenhouse gas reductions from

EEE measures can be a basis for setting mandatory electric generating unit performance in a 

Section 111(d) standard or can instead be available through the trading of emission reduction 

credits as a voluntary alternative compliance option, there are important threshold 

considerations regarding whether and how reductions from these measures could be credited in a 

Section 111(d) program. These considerations generally fall within the requirement categories

that EPA has outlined for crediting criteria pollutant reductions in SIPs, each of which poses 

significant challenges for power sector application.

Quantifiable: The quantification of CO2 reductions from EEE measures for the purpose of 

crediting those reductions in a Section 111(d) program depends on a number of technically and 

economically complex issues. As an initial consideration, the research literature on energy 

efficiency indicates that there are significant challenges in estimating how much energy use is 

actually avoided by EEE measures, with significantly lower estimates flowing from empirical 

analysis than from before-the-fact engineering studies. In addition, there is a real question 

whether certain EEE measures may, by effectively making energy cheaper, trigger expanded 

energy consumption, which could offset engineering estimates of emission reductions. 

The question of how EEE measures impact dispatch will be another significant consideration. 

Where electricity generation changes in response to EEE measures affects overall emission 

reductions because each EGU has a different emission rate, based on the fuel and process used. 

In other words, whether the EEE measures displace high or low carbon intensive electricity 

generation (e.g., gas, coal or nuclear and renewable generation) is an important consideration in 

quantifying reductions. When electricity generation changes also has an important impact on the 

quantification because of the variability of generation at different times of the day or year. These 

and other considerations make it very difficult to quantify net greenhouse gas emissions, 

particularly if one must know the quantity and location of reductions in advance.

Surplus: The determination of what CO2 reductions from EEE measures are surplus rather than 

merely occurring at a spontaneous and natural rate of adoption of measures is another important 

consideration. This is particularly important if States have existing EEE policies or programs for 

which they want to quantify and credit CO2 reductions in a Section 111(d) program. 

One approach to demonstrating surplus reductions would be to allow states with high-performing 

energy efficiency programs to generate credit for decremental energy consumption and verifiable 

resulting net emission reductions attributable to the EEE measures. Surplus reductions could be 

demonstrated by crediting only efficiency achieved beyond a suitable benchmark that reflects an 

ongoing natural rate of adoption and that adjusts for any increased use of electricity due to 
4

10/16/2013

reductions in its effective cost; while real emission reductions could be verified by a suitable 

analytical approach that estimates the actual changes in dispatch due to the net improvements in 

energy efficiency, while controlling for other factors that affect generation utilization. Any such 

analysis would almost certainly have to be conducted in retrospect (i.e., after the fact) when more 

is known about actual energy consumption and the mix of generation during a specific period of 

time. Another approach that EPA has suggested in the context of its criteria pollutant guidance 

is the retirement of allocations in a cap-and-trade program. See Roadmap at Appendix C-6; 

August 2004 Guidance at 10.

Enforceable: Enforceability of EEE measures will likely raise a number of challenges in 

crediting EEE measures in a Section 111(d) program. As EPA acknowledged in its criteria 

pollutant guidance, most EEE measures would not be enforceable directly against a regulated 

stationary source. See Roadmap at Appendix C-6; August 2004 Guidance at 5. This raises 

important questions: who would be liable? how would compliance be verified? would failure to 

achieve reductions constitute a “violation”? what would the penalty be? who would be subject 

to citizen suits?

If enforcement and other challenges make it difficult to assign emission reductions credit (ERC) 

to specific generating units or to performing third parties (for trade as discrete ERCs in the 

marketplace), then the use of an alternative compliance payment (ACP) approach may be a more 

feasible method of linking EEE reductions to the Section 111(d) program. See Background 

Paper on Alternative Compliance Payment Program.

Permanent: An important consideration for crediting CO2 emission reductions from EEE 

measures is the term in which the measure must be continued and how that would be verified to 

demonstrate permanency. Depending on the EEE measure, this could raise significant practical 

challenges. Consider, for instance, the challenges of permanency and verification for a program 

in which home owners replace incandescent light bulbs with compact fluorescent bulbs. Would 

a crediting program take into account the possibility that a home owner could later reinstall the 

incandescent light bulb, or that they might delay switching to even more efficient LED lighting 

as a result of the EEE measure? There will be similar challenges for providing compliance or 

program credit for any number of demand-side EEE strategies.
10/16/2013

Discussion Background Paper:

Alternative Compliance Payment

A ceiling-price alternative compliance payment (ACP) offers multiple benefits as a potential

voluntary compliance option that EPA could consider in its Section 111(d) guidelines for State

adoption. It could fund State-directed energy-efficiency and low-carbon energy (i.e., cleantech) 

investments and serve as a safety valve if compliance costs are higher than anticipated. As 

outlined below, this policy instrument was first recognized by the Clinton Administration as a 

compliance option for implementing revised criteria pollutant standards. EPA has approved such 

a compliance alternative as part of a State Implementation Plan (SIP) revision under Section 110 

of the Act, so there is both policy and legal precedent for such an approach. 

Previous CAA Mitigation Fee Programs

Although the ceiling-price ACP concept was first introduced during Congressional staff 

discussions during the 1990 Clean Air Act Amendments as a strategy that could address 

compliance challenges when costs exceeded anticipated levels, the first formal articulation of the 

idea appeared in President Clinton’s July 1997 Memorandum to EPA when EPA revised the 

National Ambient Air Quality Standards (NAAQS) for ozone and particulate matter. 

Recognizing that the revised standards could impose an unanticipated level of cost on regulated 

sources, the Memorandum recommended an ACP option for sources facing control costs above a 

cost-effectiveness threshold to fund reductions from other sources and to stimulate new 

technologies:

There is a strong desire to drive the development of new technologies with the potential 

of greater emission reduction at less cost. It was agreed that $10,000 per ton of emission 

reduction is the high end of the range of reasonable cost to impose on sources. 

Consistent with the State’s ultimate responsibility to attain the standards, the EPA will 

encourage the States to design strategies for attaining the PM and ozone standards that 

focus on getting low cost reductions and limiting the cost of control to under $10,000 per 

ton for all sources. Market-based strategies can be used to reduce compliance costs. The 

EPA will encourage the use of concepts such as a Clean Air Investment Fund, which 

would allow sources facing control costs higher than $ 10,000 a ton for any of these 

pollutants to pay a set annual amount per ton to fund cost-effective emissions reductions 

from non-traditional and small sources. Compliance strategies like this will likely lower 

the costs of attaining the standards through more efficient allocation, minimize the 

regulatory burden for small and large pollution sources, and serve to stimulate technology 

innovation as well.

Presidential Documents, “Memorandum of July 16, 1997, Implementation of Revised Air 

Quality Standards for Ozone and Particulate Matter,” 62 Fed. Reg. 38421, 38429 (July 18, 1997).

EPA has in fact approved SIP revisions, under CAA Section 110, that incorporate just such a 

mitigation fee program. In 1999, the South Coast Air Quality Management District in California 

amended its Rule 1121 (“Control of Nitrogen Oxides from Residential Type, Natural Gas-Fired 

Water Heaters”) to include a mitigation fee alternative. This mitigation fee alternative was 
2

10/16/2013

defined as an “emission reduction option, in which monies collected by the District from water 

heater manufacturers are placed in a restricted fund and are used to fund stationary and mobile 

source emission reduction programs targeted at equivalent NOx emission reductions as to those 

that would have otherwise occurred and have been approved by the District’s Governing Board.” 

Rule 1121(b)(5). EPA approved that amendment as part of revisions to California’s SIP in 2001. 

See EPA, Revisions to the California State Implementation Plan, California State 

Implementation Plan Revision; San Joaquin Valley Unified Air Pollution Control District, and 

South Coast Air Quality Management District: Direct Final Rule, 66 Fed. Reg. 57666 (Nov. 16, 

2001). The South Coast Air Quality Management District later amended Rule 1121 in 2004, 

retaining and updating the mitigation fee alternative. EPA also approved that amended version 

of the rule as a revision to California’s SIP in 2009, noting that the “rule includes a mitigation 

fee that can be paid in lieu of meeting interim emission limits. . . .” EPA, “Revisions to the 

California State Implementation Plan, South Coast Air Quality Management District Sacramento 

Metropolitan Air Quality Management District: Direct Final Rule,” 74 Fed. Reg. 20880, 20881 

(May 6, 2009).

How An ACP Program Could Work

EPA could provide States the ACP framework as an independent model rule component that 

States could adopt in their Section 111(d) plans. EPA could identify appropriate qualifying 

criteria for fund investments to ensure that the investments are designed to achieve CO2 emission

reductions. However, the State would control the program – i.e., a State would choose whether 

to implement the fund as a compliance option, would collect the funds and would identify those 

investments that best match its energy objectives and CO2 emission reduction opportunities. 

Such a program could accelerate investment in energy efficiency, renewable energy, energy 

storage and carbon capture and sequestration.

EPA would establish the ceiling price that would enable a source to use the ACP. To enable this 

feature, it would be important for EPA to identify the upper bound of anticipated compliance 

cost(i.e., cost per ton of greenhouse gas emissions reduced) for its Section 111(d) performance 

standard, based upon the empirical analysis it conducts when developing or adjusting the 

standard.