10/1 6 /2013 

### Discussion Background Paper: Best System of Emission Reduction (BSER)

Relevant Statutory and Regulatory Text

CAA S ection 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 o f 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 be st 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 ha s 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 fi nal 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 d egree 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 demonstra ted for designated facilities. ” 4 0 C

. F

. R

. § 60.2 1 (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 S ection 111(d) contained in the Clean Air Act Amendments of 1990. The House version would bar regulation of any source category already regulated under S ection 112, while the Senate version focuses instead on whether EPA has already listed a pollutant under S ection 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. Th is issue is expected be resolved by the courts, but not likely until after EPA finalizes its Section 111(d) guidelines

.2 10/1 6 /2013 Options for BSER in EPA Guidelines

The q uestion 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 S tates 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 appro ach 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 e xample s of potential supply

- side actions within a source

- based BSER

, heat rate improvements or energy efficiency upgrades at the source , fuel switching to a lower

emitting fuel at the source, or co

- firing with a l ower

- emitting fuel at the source

.

T he source

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

- based BSER is consist ent 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 lower

emitting 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 act ions into account in determining BSER would e ssentially redefine the source

. While this issue has not been addressed in the Section 111 context, i n the context of an analogous EPA CAA regulatory
program , EPA has expressly recognized that the statute proba bly 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) per mitting 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. 201 1) (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 rede fine 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

- bas ed BSER approach that relies upon heat rate improvements alone provides greater legal certainty, it would likely reflect a modest reduction in CO 2 emissions. Some have suggested , for example, that t he u pper bound of the se average on

- site efficiency improvements3 10/1 6 /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 ef ficiency at all . Thus, total potential emissions reductions through

a source

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

. Sy s tem

- 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 reducti ons derived from reducing the overall end use of electricity in homes and businesses that receive power from the interconnected power grid.

E xample s 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 th e 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 CO 2 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 authorize s 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 se tting (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, Dal las 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 opportuniti es 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 efficie ncy 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 re quiring a car manufacturer or refiner to reduce vehicle miles traveled.4 10/1 6 /2013 A lthough the scope of EPA’s reach into the energy system is relatively untested, many believe that EPA lacks the authority 4 to mandate State or source action beyond the source . Many S tates 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 C O 2 emission reduction s that S tates
, third parties and regulated sources a chieve 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 unit s , there is still a strong basis for EPA to credit the reductions because they would occur at one or more units with in 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 rathe r than authorizing independent EPA regulatory action.10/1 6 /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 o f 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 a ir 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 polluti on emissions.” 40 C

. F

. R

. § 60.2 1 ( 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 cl early impracticable.” 40 C

. F

. R

. § 60.2 4(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 r ate

- 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

m ass

- based standard that caps the total tons of CO 2 emitted in the sector o ver some selected period of time; or (3) a r eduction

- based standard that requires a certain degree of CO 2 emissions

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

.

Rate

- Based Carbon Intensity Approach

A rate

- based ap proach 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 CO 2 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 Ad ministrator 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, S tate, 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 10/1 6 /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 a bove, the regulations provide for an emissions standard “setting forth an allowable rate of emissions into the atmosphere.” 40 C

. F

. R

. § 60.2 1 ( 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 L ead 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. 3 0, 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 CO 2 New Source Per formance 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) (prepub lication 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 c ontroversial task of allocating allowances among the S tates. However, a rate

- based approach does not guarantee an exact quantity of CO 2 reductions

, since it does not limit the total CO 2 emitted from the regulated sector.

Averaging

If EPA adopted a rate

- based standard in its guidelines, performance c ould 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,
g iven source diversity in this sector . Some electric generating units , including many newer, very efficient ones, would have few, if any, opport unities to reduce CO 2 emissions. Thus, t hese

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 regul ated 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 Fue l 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 Vehi cle 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 the3 10/1 6 /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).

Ma ss - Based Approach

A mass

- based approach would express minimum performance expectations in the form of a total
cap on tons of CO 2 emitted in the sector over some period of time . EPA initially adopted a mass

based standard with allowance trading under Secti on 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 app roach is designed to provide certainty regarding the amount of CO 2 that is emitted by the regulated sector within each s tate. C urrent 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 S tate CO 2 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 attain ment

- 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 c onsiderations. 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 al lowance

- 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 performan ce expectations in the form of a specified minimum degree of CO 2 emission reduction s by a State or

source relative to a chosen baseline period. Such an approach would be designed to ensure a total degree of CO 2 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 contro l reg ions under the Act. Sections 171 and 172 of the Act pr ovide , for example, that S tate 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 Jer sey v. EPA , 517 F.3d 574 (D.C. Cir. 2008).4 10/1 6 /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 S tates have undertaken CO 2 emission reduction activities in recent years, and these S tates would want the selected baseline to provide credit for these reductions in measuring performance. Selecting the appropriate degree of reduction would also be challeng ing, as there would seem to be no necessary environmental or economic benchmark to guide that selection

. F inally, 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 m andates in its Section 111(d) guidelines. Under such circumstances, as outline d 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 costl y analysis.10/1 6 /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 ra tes of emissions except when it is clearly impracticable.” 40 C

. F

. R

. §§ 60.2 4(a), (b)(1). State plans must specify “[t]est methods and procedures for determining compliance with the emission standards

, ” i d. § 60.2 4(b)(2) , and the “[e]mission standards shall apply to all designa ted facilities within the State, ” id. § 60.2 4(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. § 60.2 5(a). “C orrelated” means “presented in such a manner as to show the relationship between measured or estimated amounts of emissions and the amounts of such emission s 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. §§ 60.2 5(b), (c). Finally, State plans must demonstrate that the State has legal authority to carry out and enforce the plan. Id. § 60.2 6.

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. § 60.2 4( 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 re asonable.” Id. § 60.2 4(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. § 60.2 4(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 rul e would be deemed compliant. C ommenters 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 jurisdict ion meet the prescribed emissions performance in the manner designated by EPA (e.g., rate

- based), (2) that the State program achieves comparable2 10/1 6 /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. Th ese methods are described below.

• Rate

- Based Carbon Intensity Equivalency : A rate

- based equiv alency 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 equival ency would demonstrate that the State program achieves a n equal or greater total CO 2 emission s or emission reduction s 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 a n equal or greater degree of CO 2 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 approa ch, that is comparable to or above the cost

effectiveness 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 p rogram is equivalent or more stringent than EPA’s guidelines is untested as a legal matter. T here are a number of questions regarding the measurement of State performance and implementation of equivalency demonstrations that would be releva nt to any of th ese approaches:

H

ow would the measurement of State equivalency take into account the S tate’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 par ticular facility or class of facilities if certain factors are demonstrated. This will be an important consideration when crafting State equivalency methodolog ies

.3 10/1 6 /2013 If EPA’s emissions guidelines adopt a particular form of performance standard (i.e. rate

- b ased,

mass

- based, percent reduction

- base d ) 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 und er each of these metrics. However, t here 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 offse ts ou tside of the regulated sector? I t 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 electricit y sector. EPA has suggested that, f or the purposes of Section 111(d), the statute may constrain EPA to de termin e that emissions r eductions are happening at the covered source category. However, E PA has indicated a strong interest in understanding the views of California and other S tates on this point.

Do es 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 inco rporates both rates of emission and allowance systems, suggesting considerable discre tion 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).

Do es each of these potential methods of measuring State p erformance or equivalency facilitate compliance with State plan requirements, such as the designated facility inventory that could require correlation between emission rates for designated facilit ies and the emissions standards? EPA may choose to change i ts 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 th e 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 cer tain conditions and benchmarks are met. For example, if a State program reduce s energy sector CO 2 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 d etermine that a State program must in fact have achieved the purpose of the guidelines. This approach essentially would recognize that, if a State were4 10/1 6 /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 present s some legal risk because it is untested and deviate s from EPA’s
pa st evaluation of State plans under Sections 110 or 111(d) , it is well within the President’s

announc ed 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 easil y 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 e mission guidelines under Section 111(d)).10/1 6 /2013 

### Discussion Background Paper: Harmonizing Section 111(d) Requirements with Secti on 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 Modif ied Sources

After EPA determines that a category of stationary sources “cause s or contribute s 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 Sect ion 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 routi ne for a source category. . . . (2) An increase in production rate of an existing facility, if that increase can be accomplished without a capit al expenditure on that facility. (3) An inc rease 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 l ess environmentally beneficial. (6) The relocation or change in own ership of an existing facility.

Id. § 60.14(e).2 10/1 6 /2013 The regulations further clarify tha t “[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 emission s 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, u pon 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) f or 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 ver sion) (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 t here 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 s ources 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 th e 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 w ithin 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 expectation s f or existing unit s , EPA may also consider potential perfor mance expectations for modifications. EPA may likely find that existing and modified sources are limited to the same universe of potential reduction s . This is because EPA is likely to find that existing and modified sources are similarly situated with no add

- on control opportunity to reduce CO 2 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, see3 10/1 6 /2013 Proposed Rule at 15

- 16, EPA has indicated that it does not anticipate determining that CCS has been adequ ately 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 fo r 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 d etermines that the only reasonably available measures to achieve CO 2 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 Sec tion 111(d), this would further secure such a harmonizing determination because the market price would reward CO 2 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 sou rces. 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, the n instal lation of Best Available Control Technology (BACT) is required. The nonattainment NSR requirements apply to major sources making major modifications in non attainment areas. See generally , 42 U.S.C. §§ 7502(c)(5), 7503. If the nonattainment NSR requiremen ts 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 progr am 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 emissi ons 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 1 11(d) program is designed to encourage.

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

As noted above, s ince the Section 111(d) program may be designed to encourage existing units to reduce their emissions by making on

- site e ffic iency improvements, there is a risk that regulated units will be considered to trigger NSR as they make such modifications

. This is4 10/1 6 /2013 because a more efficient unit will likely be dispatched more and this additional activity could result in a net increas e 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, th ere 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 approa ch, EPA could establish screening tools to confirm that already well

controlled sources and sources whose “net emissions increases” of criteria pollutants remain below attainment

- related significance thresholds are deemed to comply with NSR.

EPA could a lso 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).10/1 6 /2013 

### Discussion Background Paper: Crediting State End

- Use Energy Efficiency Measures

A number of stakeholders have argued that relatively inexpensive, near

- term CO 2 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 decrease d utilization of electric generation acro ss the interconnected power grid. Therefore, s ome stakeholders have raised the potential for State end

use energy efficiency (EEE) measures to be compliance options for Section 111(d) emission standards, although t here 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) perfo rmance 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 cl aiming 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

T here are no existing statutory or regulatory provisions n or EPA policy guidance that address crediting CO 2 reductions from S tate EEE policies or programs for complian ce with EPA stationary source regulations . However, EPA has prepared extensive guidance o n providing SIP credit for criteria pollutant reductions from S tate EEE measures

. While that guidance addresses different pollutants under a separate regulatory framework, there are aspects of the g uidance that
may help inform the discussion in the CO 2 em issions 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 strateg ies 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 the ir 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 ap proach 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 10/1 6 /2013 Quantifiable: EPA guidance directs States to use reliable and replicable emissions quantification approach es

. See Roadmap at 36. The guidance notes that the measu res 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 Ener gy 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 reasonabl e 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 Measu res 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 “pre s umptive 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

.
Enforceab le: 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 ach ieve 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 eliminate s the need for the credit. See Roadmap at 36.3 10/1 6 /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 collab orate, 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 Mea sures 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 mandat ory 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 ap plication

. Quantifiable: The quantification of CO 2 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 en gineering 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 EE E 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 CO 2 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 progra ms for which they want to quantif y and credit CO 2 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 result ing 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 u se of electricity due to4 10/1 6 /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.

Enforceab le: Enforceability of EEE m easures 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 th e marketplace), then the use of an alternative c ompliance 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 CO 2 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, t he challenges of perman en cy and verification for a program in which home owners replace incandescent light bulbs with compact fluorescent bulbs. Would a crediting program take into account th e possibility that a home owner could later reinstall the incand escent 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.10/1 6 /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 S tate

- directed energy

- efficiency and low

- carbon energy (i.e., cleantech) investment s and serve as a safety valve if compliance costs are higher than anticipated

. As outlined below, this policy instrument was first recogniz ed by the Clinton Administration as a compliance option for implement ing 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 introdu ced 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 Jul y 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 recomme nded an ACP option for sources facing control costs above a
cost

- effective ness 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 sour ces. 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 effi cient 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 an d 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

am ended its Rule 1121 (“ Control of Nitrogen Oxides from Residential Type, Natural Gas

- Fired Water Heaters ”) to inclu de a mitigation fee alternative. This mitigation fee alternative was2 10/1 6 /2013 defined as an “emission reduction option, in which monies collected by t he 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 NO x 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 Revisi on; 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 mitiga tion 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 limit s

. . . . ” 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 A n ACP Program Co uld 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 investment s are designed to achieve CO 2 emission reduction s. 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 CO 2 emission reduction opportunities. Such a program could accelerate investment in energy efficiency, renewable energy, energy storage and carbon capture and sequestration.

EPA would establish t he 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 u po n the empirical analysis it conducts when developing or adjusting the standard

.