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TABLE OF CONTENTS

CHAPTER 5 STATE PLAN CONSIDERATIONS .................................................................. 3

5.1 State Plan Approaches............................................................................................................ 4

5.1.1 Direct emission limits: rate-based ...................................................................................... 4

5.1.2 Direct emission limits: mass-based................................................................................... 13

5.1.3 Portfolio approach ............................................................................................................. 29

5.1.4 State-driven portfolio approach ....................................................................................... 36

5.1.5 Utility-driven portfolio approach..................................................................................... 64

5.1.6 Multi-state plans................................................................................................................. 76

5.1.7 Other ................................................................................................................................. 114

5.2 Incorporating demand-side energy efficiency and renewable energy programs and 

measures under a rate-based approach...................................................................... 155

5.2.1 Adjusting EGU CO2 emission rates based on the effects of end-use energy efficiency 

and renewable energy................................................................................................... 155

5.2.2 Approaches for adjusting EGU CO2 emission rates.................................................... 176

5.2.2b Adjustment of CO2 emission rate based on avoided CO2 emissions......................... 184

5.2.2c Adjustment based on the rate-based emission limit in the state plan ....................... 186

5.2.2d Other considerations ..................................................................................................... 186

5.2.3 Methods and tools for quantifying avoided CO2 emissions from end-use energy 

efficiency and renewable energy.................................................................................. 189

5.2.3a Average emission rate approach................................................................................... 195

5.2.3b Marginal emission rate approach................................................................................. 196

5.2.3c Calculation tool method................................................................................................. 198

5.2.3d Electricity sector modeling method.............................................................................. 200

5.2.3e Considerations associated with use of an avoided emissions rate.............................. 201

5.2.4 EE and RE Measures that can be incorporated............................................................ 206

5.2.5 Other ................................................................................................................................. 297

5.3 Quantification, monitoring, and verification of demand-side energy efficiency programs 

and measures................................................................................................................. 300

5.3.1 EM&V for demand-side energy efficiency programs overseen by state PUCs.......... 300

5.3.2 EM&V for Energy Efficiency Measures used in ISO Forward Capacity Markets... 308

5.3.3 EM&V for Programs and Policies Not Typically Overseen by PUCs ........................ 309

5.3.4 Considerations: Accuracy of Energy Savings Estimates.............................................. 325

5.3.5 Considerations: EM&V Technical Considerations for State Plans............................ 338

5.3.6 Options: Use of EM&V protocols and guidance........................................................... 353

5.3.7 Options: EPA review of EM&V plans as part of the state plan review process........ 394

5.3.8 Options: general quality standards for EM&V rigor and accuracy........................... 404

5.3.9 EM&V Documentation in a 111(d) state implementation plan................................... 408

5.3.10 CHP/cogeneration.......................................................................................................... 415

5.3.11 Other ............................................................................................................................... 416

5.4 Quantification, monitoring, and verification for renewable energy programs and 

measures......................................................................................................................... 421

5.4.1 Renewable portfolio standards: build renewable generating facilities....................... 421

5.4.2 Renewable portfolio standards: bilateral contract model............................................ 426

5.4.3 Renewable portfolio standards: REC model................................................................. 428

5.4.4 Renewable portfolio standards: Small distributed generators.................................... 473
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5.4.5 Feed-in tariffs................................................................................................................... 477

5.4.6 State tax incentives........................................................................................................... 478

5.4.7 Options.............................................................................................................................. 482

5.4.8 Other ................................................................................................................................. 486

5.5 Reporting and recordkeeping for demand-side energy efficiency programs and 

measures......................................................................................................................... 494

5.5.1 Reporting for EE programs and measures.................................................................... 494

5.5.2 Other ................................................................................................................................. 499

5.6 Reporting and recordkeeping for renewable energy programs and measures............. 501

5.6.1 Reporting for renewable energy programs and measures........................................... 501

5.6.2 Typical Reporting and Compliance Requirements under State RPS......................... 503

5.6.3 Typical Reporting for Renewable Energy Deployment Programs.............................. 506

5.6.4 Reporting for utility administered renewable energy incentive programs ................ 507

5.6.5 Reporting for renewable energy incentive programs administered by non-profit or 

state entities ................................................................................................................... 507

5.6.6 Considerations for reporting requirements for renewable energy measures in state 

plans ............................................................................................................................... 507

5.6.7 Other ................................................................................................................................. 507
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CHAPTER 5 STATE PLAN CONSIDERATIONS

This chapter addresses comments received on the EPA’s proposed emission guidelines for state 

plans. Comments received on the following topics are covered in this chapter: state plan 

approaches; methods of incorporating RE and demand-side EE programs/measures into a ratebased state plan; quantification, monitoring, and verification of end-use energy efficiency and 

renewable energy programs/measures; reporting and recordkeeping for end-use energy efficiency 

and renewable energy programs/measures; how interstate effects are addressed; approaches to 

projecting affected EGU CO2 emission performance; how existing state programs and measures 

should be treated in state plans; how new fossil fuel-fired EGUs not subject to Clean Air Act 

(CAA) section 111(d) are treated; how the remaining useful life of an affected EGU should be 

considered; whether state plans can include design, equipment, work practice and operational 

standards, and whether application of those types of standards should be limited by CAA section 

111(h); comments on emission averaging and trading (e.g., emission budget trading programs); 

state-specific implementation issues; and other comments related to the design and 

implementation of state plans. 

Commenters also raised issues related to a number of topics that are not covered by this chapter. 

Please refer to the following chapters for responses specific to those issues:

• Chapter 1: Legal

• Chapter 2: Applicability

• Chapter 3: GHG Mitigation Measures

• Chapter 4: State Goal Computation

• Chapter 6: State Plans

• Chapter 7: Interactions With Other EPA Programs and Rules

• Chapter 8: Impacts and Cost Analysis

• Chapter 9: Statutory and Executive Orders

• Chapter 10: Rule Language Corrections
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5.1 STATE PLAN APPROACHES

This section discusses comments on the state plan types and approaches, including rate-based

and mass-based state plans, the state-driven and utility-driven portfolio approaches, and multistate plans. Also discussed in this section are comments regarding other alternative approaches to 

state plans, including a state commitment approach, where states commit to a specific level of 

emission reductions using state programs that are not federally enforceable, carbon tax 

approaches that would levy a tax on CO2 emissions from utility boilers, dispatch fee mechanisms 

where a fee is assessed for CO2 emissions from electricity generators, and several other 

alternative approaches to implementing the CPP.

5.1.1 Direct emission limits: rate-based

This section contains comments on the rate-based emission limit plan approach for meeting the 

emission guidelines.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Numerous commenters supported rate-based emission limits.

Response 1: The final rule provides states with the ability to use a rate-based plan approach. 

Plan approaches are addressed in the preamble to the final rule in section VIII.C. The EPA 

agrees with the commenters that a rate-based approach can accommodate growth in electricity 

demand. However, the EPA disagrees with the assertion by commenters that growth in electricity 

demand cannot also be accommodated under a mass-based plan approach. The EPA notes that 

under both approaches, CO2 emissions reductions can be achieved while accommodating growth 

in electricity demand. Both rate-based and mass-based approaches apply to CO2 emissions from 

existing affected EGUs. Electricity growth can be accommodated through a mix of electricity 

generation from affected EGUs, low- and non-emitting non-affected EGUs (including new fossil 

fuel-fired EGUs subject to CAA section 111(b), and reductions in electricity demand through 

demand-side EE improvements.

The following are summaries of the specific public comments under this comment:

Several commenters stated that they support the rate-based emission limits. Many commenters

stated that they supported a rate-based approach because they believed this approach would 

better accommodate growth in electricity demand without compromising the effectiveness of the 

Clean Power Plan framework. Commenters felt that rate-based targets would be important for 

accommodating growth in states like Florida that have population growth that is higher than the 

rest of the country. Commenters stated that electricity demand in Montana, North Dakota, and 

South Dakota is expected to grow by 5 percent over the next five years and believe it is 

imperative that the EPA continue to allow states to comply with emission rate-based goals.
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Commenters noted that investments in commercial and industrial automation, growth in the 

communications and information technology, replacement of oil and natural gas-fired residential 

furnaces by electric thermal heating systems, and increased demand for electric vehicles will 

result in an increase in electricity demand over the next several years. Commenters believed that 

a rate-based system provides greater economic certainty and noted that emissions and electricity 

demand growth are highly correlated.

Commenters believed that a mass-based approach would slow or stop economic growth and 

believed that the rate-based approach was necessary to allow for reductions in GHG emission 

rates while also increasing investments in new technology, encouraging implementation of best 

practices, and adapting to changes in electricity production methods overtime. Commenters 

stated that believe the rate-based approach will provide reductions in emissions at the lowest 

compliance cost.

Commenters stated that the rate-based approach to regulation under section 111(d) is consistent 

with the statute and also best accommodates states' fluctuating needs and anticipated growth in 

electricity demand, without impacting economic growth. Commenters stated that domestic 

economic growth is likely to reduce global CO2 emissions by not "outsourcing" U.S. industrial 

activity and by shifting a greater share of industry to clean-burning, natural gas-powered 

operation in the United States. Commenters noted that the U.S. electric sector had an average 

carbon intensity of 1,109 lb CO2/MWh in 2011, while in China and India the average carbon 

intensities are 1,684 lb CO2/MWh and 1,887 lb CO2/MWh, respectively. 

Commenters recommended the EPA allow states the flexibility to structure the emission rate 

goals as the state believes appropriate.

Comment 2: Commenters believed that only rate-based standards are allowed under section 111 

of the Clean Air Act

Response 2: The EPA disagrees with the assertion that only rate-based standards are allowed 

under section 111 of the CAA. While standards of performance under CAA section 111(d) have 

typically been rate-based, the definition of "standard of performance" in the statute (in CAA 

section 111(a)(1)) and the definition of "emission standard" in the EPA’s framework regulations 

at 40 CFR 60.21(f) do not preclude the use of mass-based emission standards in a state plan. The 

term "standard of performance" in CAA section 111(a)(1) means 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..." The definition of "emission standard" at 40 CFR 

60.21(f) includes reference to an "allowance system" which involves a limit on mass emissions.

The following are summaries of the specific public comments under this comment:

Commenters believed a rate-based standard is the only defensible approach allowed by section 

111 of the Clean Air Act and noted that performance standards promulgated under 40 CFR Part 

60 are generally rate-based, concentration-based, or prescribed work practices.
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Comment 3: Some commenters believed RE and demand-side EE measures could be easily 

incorporated into rate-based state plans

Response 3: The EPA agrees with the commenter’s statement that RE and demand-side EE 

measures may be easily incorporated into a rate-based approach. Use of RE and demand-side EE

measures to adjust the reported CO2 emission rate of an affected EGU is addressed in the 

preamble to the final rule in section VIII.K.1. The EPA notes that electric generation from other 

resources such as CHP could be used to adjust the reported CO2 emission rate of an affected 

EGU, as discussed in section VIII.K.1 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters believed that RE and demand-side EE measures may be easily incorporated into a 

rate-based approach through an adjustment or tradable credit system. Commenters recommended 

that this approach should be applied to all demand-side solutions, including fuel cells and CHP.

Comment 4: Commenters believed rate-based goals can be used in market-based trading 

programs.

Response 4: The EPA agrees that rate-based goals can be used in market-based trading 

programs. Rate-based emission trading approaches are discussed in section VIII.C of the 

preamble to the final rule; specific requirements for rate-based emission trading approaches are 

discussed in section VIII.K.2.

The following are summaries of the specific public comments under this comment:

Some commenters disagree with other commenters who believed a mass-based approach is 

necessary for states implementing a market-based program. Commenters noted that a marketbased trading system can be implemented under a rate-based approach without the risk of 

limiting economic growth through a cap on emissions. Commenters cited a 2012 paper published

by "Resources for the Future" that explains how a rate-based trading program would work. 

Commenters further noted that rate-based market systems could be implemented without 

requiring policymakers to make assumptions about the level of required future generation and 

would eliminate the need for allocating emission allowances.

Comment 5: Comments stating that states should have flexibility to select either rate- or massbased limits.

Response 5: The EPA agrees with the commenters, and in the final rule, has provided states with 

the flexibility to choose either a rate-based or a mass-based plan approach. Plan approaches are 

discussed in section VIII.C of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:
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Commenters recommend that states be allowed the flexibility to select a rate-based approach or a 

mass-based emission reduction approach that best suits their specific circumstances. 

Commenters stated that there may be discrete advantages to either a rate-based or a mass-based 

emission standard. Commenters stated that for example, a rate-based standard enables states to

accommodate future load growth, while a mass-based standard would allow states to more 

readily account for unit retirements and other significant mass emissions reductions. 

Comment 6: Comments not supporting rate-based limits because commenters believed it would 

not reduce overall CO2 emissions.

Response 6: The EPA disagrees with the commenters assertions that a rate-based CO2 emission 

limit provides incentives for increasing electricity generation. First, a rate-based emission 

constraint represents a limit on emissions from EGUs that will generally increase generation 

costs for affected EGUs subject to the standard, which provides economic incentives for 

replacement of that generation with low- or non-emitting resources, such as the utilization of RE 

and demand-side EE measures. Replacement of electric generation with electric generation or 

electricity savings from other resources does not provide an incentive for increasing overall 

electric generation. In fact, to the extent that demand-side EE is used to meet a rate-based 

emission limit, this will provide an incentive for reducing overall electricity generation. Where 

affected EGUs may receive credit for emitting below a specified CO2 emission rate, this provides 

an incentive for shifting generation to lower-emitting generation sources, rather than an incentive 

for increasing electricity generation overall. While the EPA acknowledges the potential for shifts 

in generation among states, the EPA has finalized uniform rate-based CO2 emission performance 

levels for affected EGUs, which results in a decrease in disparities in translated rate-based CO2

goals among states. These issues are discussed fully in section V.A and VI.B of the preamble to 

the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters were against rate-based goals because they believe they will not reduce 

overall emissions and were concerned that in a rate-based approach emissions could actually rise. 

Commenters argued that under a rate-based standard states have two ways to reduce their 

emissions ratio: 

• they can reduce their emissions, thereby reducing the numerator; or 

• they can increase the total level of electricity generation from power 

plants with emission rates below the standard. 

Commenters noted that both measures would decrease the emission rate, but only the first 

approach would reduce the overall CO2 emissions. Commenters stated that since an increase in 

electricity generation can lower the emissions ratio, they were concerned a rate-based standard

introduces incentives to increase production. Commenters noted that a study of rate-based 

standards for transportation fuels showed that rate-based standards can cause total CO2 emissions 

to increase (see "Greenhouse Gas Reductions under Low Carbon Fuel Standards" published in 
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"American Economic Journal: Economic Policy" in 2009 and "Standards Versus Standards: The 

Effects of Different Pollution Restrictions," published in "American Economic Review," in 1991).

Commenters recommended that the EPA consider the possible unintended consequence that a 

rate-based standard for CO2 emissions in the electricity sector may increase overall CO2

emissions, but also noted that the impact of this incentive to increase production in the electricity 

sector may be less than the transportation sector due to electricity demand being relatively 

inelastic and therefore less likely CO2 emissions would increase significantly as a result of the 

rate-based standard.

Commenters were concerned the disparity among the states' goals would give some states an 

incentive to "redispatch" load from a lower-performing oil/gas or natural gas facility to a coal 

facility in a coal-dominated state that has a higher lb/MWh CO2 goal and expressed concern a 

state with excess coal capacity and little NG capacity could actually increase CO2 emissions 

while complying with the goal. 

Commenters argued that the rate-based system combined with the possibility for fossil fuel 

EGUs operating below the emission standard for their state to earn credits for every MWh of 

energy they produce creates an economic incentive for increased production and hence increased 

emissions. Commenters noted that almost half of the 43 states with NGCCs operating in 2012 

have NGCCs that already meet the state's 2030 emission goals. Commenters stated that because 

Block 1 of the Proposed Rule does not impose a ceiling on NGCC emissions, they believe these 

units will continue to generate electricity as long as there is an economic benefit. Commenters 

stated that by not capping actual emissions, they believe that increased electricity demand will be 

met by building new NGCCs instead of by RE/EE. Commenters are concerned that rate-based 

limits combined with no cap on emissions provides disincentives for investment in RE/EE and 

will result in increased emissions.

Comment 7: Comments requesting clarification to whether section 111(d) plans have to include 

enforceable EE measures for states using the rate-based limits in a non-portfolio plan.

Response 7: While the EPA is not finalizing a BSER that includes demand-side EE, the final 

rule provides states with flexibility to use demand-side EE in different ways to achieve the CO2

emission performance rates for affected EGUs or state rate-based or mass-based CO2 goals. 

Demand-side EE can be incorporated as a compliance mechanism under a rate-based emission 

standard approach, or incorporated as a state measure. Demand-side EE can also be used as a 

complementary measure (i.e., not included in a state plan) that can help affected EGUs meet a 

mass limit on CO2 emissions. Plan approaches are discussed in section VIII.C of the preamble to 

the final rule.

The following are summaries of the specific public comments under this comment:

Commenters asked whether states that pursue building block 4 must include enforceable EE 

measures in their state plan for a rate-based approach but not for a mass-based approach. 
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Comment 8: Commenters were concerned states would select rate-based plans over mass-based 

plans because there are more opportunities for REC trading than CO2 allowance trading, and 

recommended the EPA allow states adopting mass-based plans to take credit for REC purchases.

Response 8: The EPA does not agree with the concerns presented by the commenters. The EPA 

believes that there are significant benefits to mass-based plans that will encourage states to 

consider this approach. In particular, mass-based plans are significantly easier to implement and 

administer as well as avoid the need for complex provisions for quantifying and verifying MWh 

of replacement generation from measures such as RE and demand-side EE. Furthermore, under a 

mass-based emission trading approach, RE and demand-side EE can be utilized as an emission 

reduction strategy without the need for formal inclusion in the emission trading program. 

Instead, RE and demand-side EE represent complementary measures that will reduce the cost of 

meeting a mass limit on CO2 emissions, without the need for complex quantification, 

verification, and administrative provisions. Plan approaches are discussed in section VIII.C of 

the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters are concerned that states will select the rate-based based goals over mass-based 

goals because there are currently more opportunities for REC trading than for CO2 allowance 

trading. Commenters noted that only ten states currently have mass-based CO2 allowance trading 

programs, but 38 states (including the ten states with mass-based CO2 programs) have RPS 

programs that provide for REC trading. Commenters stated that the availability of REC trading 

may encourage states to select a rate-based approach, thereby undermining the flexibility that the 

EPA wants states to have. Commenters stated that to avoid this problem, they believe the EPA 

should ensure mass- and rate-based states have equal access to trading opportunities by allowing 

mass-based states to take credit for REC purchases (i.e., making REC purchase equivalent to 

CO2 reductions) and allowing rate-based states to take credit for purchases of out-of-state carbon 

allowances. If the EPA fails to take these steps, commenters were concerned that a state's choice 

of a mass-based goal could disadvantage it when it comes to compliance strategies and the result 

would be a rule that give significant incentive for states to select rate-based goals even though 

rate-based programs will be more difficult to administer and enforce. Commenters noted that the 

same situation would occur with multi-state plans and recommended that multi-state programs 

also be allowed to take credit for out-of-region emissions reductions in the same way individual 

state plans would, provided the reductions result from in-state or in-region compliance efforts.

Comment 9: Comments stating that states employing a rate-based goal should receive credit for 

retiring coal fuel-fired EGUs.

Response 9: The EPA believes that the flexibility provided for states to craft plans that are 

appropriate for their circumstances and emission reduction strategies fully recognizes the role 

that retirement of affected EGUs can play. Under a rate-based plan, retirement of a higheremitting affected EGU will reduce the weighted average CO2 emission rate of the remaining fleet 

of affected EGUs, helping a state to achieve its rate-based CO2 emission goal. States also have 

the alternative of implementing a mass-based plan, where retirement of an affected EGU will 
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help a state meet its mass-based CO2 emission goal. In both cases, retirement of an affected EGU 

is a compliance option for the owner or operator of an affected EGU, as a retired affected EGU 

will have no compliance obligation under either a rate-based or mass-based CO2 emission 

standard. Plan approaches, and the different types of emission reduction measures that they 

accommodate, are discussed in section VIII.C of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters believed states with plans employing rate-based goals should be allowed to take 

credit for the retirement of older fossil fuel-fired EGUs when the replacement generation is from 

out-of-state or a non-111(d) generating unit. Commenters stated that in states with significant 

coal-fired generation, where a coal-fired unit shuts down and is replaced with out-of-state 

generation or simply is not replaced, the pre-retirement and post-retirement emission rate for the 

state would remain largely unchanged, thereby creating an incentive for older, less efficient coalfired EGUs to continue to operate. Commenters recommended the EPA provide a mechanism for 

states and companies to receive full credit for retirements of existing coal plants in states with a 

rate-based standard. Commenters stated that by ensuring that states and companies are able to get 

full credit for retirements of coal-based units, they believe the EPA will encourage future 

retirements and gain the benefit of additional CO2 emission reductions.

Commenters stated that because the guidelines base compliance on a measure of CO2 produced 

per megawatt hour generated, utilities have no incentive to close either natural gas or coal-fired 

power plants. Commenters stated that eliminating both the emissions and the generation from the 

formula, results in no net benefit either to the utility, to the state, or allegedly to the environment. 

Commenters asserted that EPA cannot have meant to discourage the closure of power plants. 

Commenters recommended that EPA allow utilities and states to claim credit for historic CO2

emission levels from power plants for the first 10 years after the closure of the plant.

Comment 10: Comments stating that state plans with rate-based limits should not be allowed to 

make adjustments to their rates for voluntary RE programs.

Response 10: Under an emission standards plan type, any adjustment of the reported CO2

emission rate of an affected EGU would take place in the context of a federally enforceable 

emission standard applied to affected EGUs. Eligible RE measures could generate emission rate 

credits (ERCs), which could be used to adjust the reported CO2 emission rate of an affected 

EGU. Eligible measures that can generate ERCs are discussed in section VIII.K.1 of the final 

rule preamble of the CPP. Requirements for the issuance of ERCs are discussed in section 

VIII.K.2. Under a state measures plan type, state measures that use RE would need to be 

enforceable at the state level, consistent with requirements described in section VIII.C.3 of the 

preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA allow no adjustment to rates be made for voluntary RE for 

states using rate-based limits. 
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Comment 11: Comments suggest that the EPA should create "Safe Harbor" for companies 

whose average emissions rate is below the state's rate-based goal.

Response 11: The EPA disagrees that a utility company should be allowed to meet the emission 

guidelines by demonstrating that their company-wide CO2 emission rate for all generation is less 

than the state rate-based CO2 goal in the emission guidelines. Consistent with the requirements 

of CAA section 111(d), these state CO2 goals apply to affected EGUs in the source category 

subject to this final rule. See section IV.A of the preamble to the final rule for more information

on EPA’s authority under 111(d). 

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA include provisions in the final rule for a "safe harbor" that 

allows affected entities to show compliance with any state 111(d) plan through the demonstration 

of an emission rate near or below the state's emission rate goal. Commenters noted that as an 

example, Entergy Arkansas, Inc.'s utility fleet emission rate in Arkansas (Entergy's largest coal 

generation state) was 99 lbs CO2 /MWh in 2013, when nuclear generation was included and that 

by comparison, Arkansas' final 2030 emissions rate goal under the Proposed Rule will be 910 lbs 

CO2 /MWh. Commenters believed that companies that can demonstrate they are below the state 

emission rate goal should be considered to be in compliance with the state 111(d) plan.

Comment 12: Comments stating that the EPA should provide methodology for how states 

determine compliance with rate-based emission limits.

Response 12: In the final rule, the EPA has provided equations, and related examples, 

demonstrating the accounting method that must be used to adjust the reported CO2 emission rate 

of an affected EGU under a rate-based state plan. This accounting method, examples, and 

rationale, are discussed in section VIII.K.1 of the preamble to the final rule. Issuance of ERCs to 

affected EGUs that perform below a specified CO2 emission rate is discussed in section VIII.K.2

of the preamble to the final rule. This section also provides equations for the required accounting 

method, example calculations, and rationale for the required method.

The following are summaries of the specific public comments under this comment:

Commenters were concerned the EPA has not provided the methodology for states to determine 

compliance with rate-based limits. Commenters believed that rate-based emission limits may be 

more restrictive than mass-based limits depending on what method is used for determining 

compliance. Commenters were concerned that a state could be deemed out of compliance with 

its rate-based standard despite having significantly reduced its CO2 emissions and being in 

compliance under a mass-based approach. Commenters provided the following example to 

illustrate why they believe a rate-based approach could be problematic. Commenters stated that 

based on information provided in proposal and technical support documents, the 2030 goal for 

Utah is 1322 lbs of CO2 /MWh for affected EGUs, which is above the average emission rate for 

an NGCC power plant. Commenters stated that in the 2012 baseline year, the average NGCC 
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emission rate for affected EGUs located in Utah was 884 lbs CO2 /MWh. Commenters argued 

that if Utah were to adopt a mass-based limit, the allowable amount of CO2 emissions in 2030 

would be 21,747,459 tons/year. Commenters noted that if Utah's largest emitter of CO2

emissions is shutdown prior to 2030 and other affected EGUs remain operational, then Utah 

would achieve the mass-based 2030 goal of 21,747,459 tons per year because the total emissions 

for the remaining affected EGUs would be 21,108,430 tons per year. Commenters assumed that 

under a rate-based approach, states would demonstrate compliance by employing the same 

methodology EPA used to determine the rate-based goals. Commenters stated that if the MWh 

attributable to the shutdown of the high emitting plant are removed from the denominator along 

with the associated CO2 emissions from the numerator, then Utah would not be in compliance 

with the rate-based limit because Utah's emission rate of 1824 lbs of CO2 /MWh would be above 

the rate-based limit of 1322 lbs of CO2 /MWh. 

Comment 13: Comments stating that both rate- and mass-based approaches are not viable.

Response 13: The EPA disagrees with the commenters’ assertion that the rate-based and massapproaches be eliminated, and has included both mass-based and rate-based approaches in the 

final rule. The EPA discusses the basis for its determination of the BSER, including its 

achievability, in section V of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA eliminate the rate-based and mass-based approaches 

because (1) the heat rate improvements of 4-6% are largely unobtainable because utilities have 

been making efficiency improvements whenever economical and no realistic heat rate 

improvements exist, or because they might trigger New Source Review (NSR); (2) the heat rate 

improvement of 4-6% would not achieve the goals; (3) limits on generation is not practically 

achievable without impacting the reliability of the electric system; and (4) there is no 

demonstrated technology that is commercially available to control CO2 emissions.

Comment 14: Comments suggesting that extending authority for a multi-state plan could result 

in delay of implementing the state plan.

Response 14: The emission guidelines provide flexibility to states to choose different 

approaches to state plan design, and to consider a state’s particular circumstances in doing so. If 

certain plan approaches appear likely to run into roadblocks, a state may wish to choose another 

approach that is more likely to succeed.

Although the emission guidelines allow multi-state plans, such plans are not mandated. The state 

has the option of an individual state plan. The state also has the option of an individual state plan 

designed to link with other individual state plans to facilitate interstate emissions trading. See 

section VIII.C of the preamble to the final rule for a discussion of state plan approaches.

The following are summaries of the specific public comments under this comment:
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Commenters stated that even where the MPSC believes its authority to be sufficient, extending 

that authority into new areas may well lead to litigation that could delay the implementation of 

any state plan. Commenters noted that one such new area would be the extent of the inter-state 

cooperation that would be necessary for the development and implementation of a multi-state 

plan. 

5.1.2 Direct emission limits: mass-based

This section contains comments on the mass-based emission limit plan approach for meeting the 

emission guidelines.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Comments supporting mass-based limits.

Response 1: The EPA agrees generally with the commenters and has highlighted the multiple 

benefits of a mass-based plan approach, and market-based emission budget trading approaches in 

particular, in the preamble to the final rule. These benefits include greater administrative 

simplicity and economic efficiency. In the final rule, the EPA has provided mass-based state CO2

goals in the emission guidelines, to facilitate the use of mass-based plans by states. Plan 

approaches are discussed in section VIII.C of the preamble to the final rule, and implementation 

considerations for mass-based plans are further discussed in section VIII.J. The EPA also notes 

that it considers a rate-based emission trading approach to be viable, and discusses in detail 

requirements for rate-based emission trading programs in section VIII.K.2 of the preamble to the 

final rule.

The following are summaries of the specific public comments under this comment:

Several commenters supported mass-based CO2 emission limits for the following reasons:

• Efficient and cost effective method for achieving enforceable reductions.

• Simple to implement.

• Would ensure overall CO2 emissions do not increase when combined 

with an emission cap.

• Would achieve real, permanent, enforceable, and verifiable carbon 

dioxide reductions from existing sources.
14

• Can accommodate many emission reduction strategies, including energy 

efficiency, renewable power, and add-on controls, more easily than ratebased programs.

• Would enable the EPA to easily assess whether a state has attained its 

goal.

• Avoids many of the problems of the rate-based system, including 

potential double-counting due to trading of RECs among rate-based 

states and between rate-based and mass-based states, treatment of new 

gas plants, and nuclear generation. 

• Automatically accounts for RE imported from other countries 

• Easier to implement than a rate-based system.

• Would make it easier for states to take advantage of the efficiencies of 

broad interstate trading programs. 

• Would allow states to take credit for actions since 2005 that reduced 

mass emissions (e.g. coal plant retirements, efficiency improvements).

• Would focus emission reductions on affected sources.

• Would treat all compliance equally and results in compliance choices 

based on the lowest dollar per ton reduced compared with the proposed 

rate-based approach which provides "extra credit" for RE and 

incremental EE and less credit for gas switching.

• Would provide full credit for plant retirements, which is important for 

states like West Virginia and Kentucky that rely almost entirely on coalfired plants.

• Avoids estimating the reduction in electricity output associated with EE

improvements.

• Would allow voluntary energy efficiency and DSM measures to be 

treated as complementary to the plan allowing them to be change over 

time without the need to update the state plan.

• EM&V measures would not be needed for RE and EE programs.

• Provides a transparent approach to reducing emissions.

• Would maintain the integrity, security, and reliability of the electric grid.

• Allows EGUs to continue to use a diverse fuel mix.
15

• Gives states the flexibility to achieve their individual emission reduction 

goals.

• Would not discourage the use of RE and EE like more complicated ratebased plans would do.

• States have the authority to implement a mass-based limit. 

Some commenters noted that many states already have experience with mass-based CO2 limits 

and believe that this approach will make it easier for states to comply with the rule. Commenters

noted that mass-based regulatory approaches have been shown to be highly effective in 

addressing conventional air pollutants emissions, including the NOx SIP Call program and Acid 

Rain trading program. Commenters thought the EPA should be consistent with other rules that 

set mass-based limits for the electricity generation sector (e.g., CSAPR, Clean Air Interstate Rule 

(CAIR), NOx SIP Call, and the Clean Air Mercury Rule (CAMR)). Commenters believed that 

these rules demonstrate that mass-based standards are a reasonable basis for pollution control 

measures and notes that section 111(d) allows the EPA to set a mass-based standard for this 

rulemaking. Commenters recommended the EPA provide guidance that facilitates the massbased approach and encourages states considering mass-based approaches to use existing carbon 

trading markets or establish new markets using these proven frameworks.

Commenters stated that mass-based programs are more easily enforced. Commenters noted that 

complex modeling, projection, allocation and verification systems needed for a rate-based 

system are not necessary for a mass-based system and that power plant emissions are easily 

measured and recorded by widely available continuous monitoring equipment.

Commenters believe that mass-based programs are one of the most effective ways to 

transparently track and verify emissions reductions and compliance.

Commenters stated that a mass-based approach simplifies compliance and enforceability, and 

avoids legal and accounting complexities associated with other rate-based approaches. 

Commenters believed the more straightforward design of mass-based plans would make them 

less susceptible to strategic maneuvers by states than rate-based plans. Similarly, commenters

believed that a mass-based system with a cap on fossil-fueled power plant emissions would be 

inherently simple and straightforward, and that a complex rate-based system that only a few can 

understand will not meet with the same level of acceptance and support by the public.

Commenters believed a mass-based approach is more efficient than a rate-based approach.

Commenters noted that if two states have the same load but different starting emissions rates, 

then the states with the higher rate has more incentive to invest in emissions reduction, even 

though the emissions reduction are not more beneficial in one state than in the other.

Commenters supported the mass-based approach because it provides greater flexibility, easier to 

implement, and ensures emissions are reduced. Commenters believed that for emissions trading, 

rate-based programs suffer from a lack of experience, with few examples to cite (the EPA's lead 

trading program being the most prominent.) Commenters stated that a lack of familiarity within 

the trading community can be a hindrance to the early acceptance and eventual adoption of 
16

programs with tradable performance standards. Commenters noted that mass-based programs 

were designed for emissions trading, and have clearly established performance records. 

Commenters believed that the acknowledged success of the trading programs such as Title 

IV/Title I, RGGI, AB 32, etc. makes the mass-based option a logical candidate for consideration 

by many states. Commenters also noted that another disadvantage for implementation of ratebased programs is that they require mechanisms to credit energy efficiency and renewable 

generation. Commenters argued that though the crediting mechanism can be created within a 

particular state to satisfy its requirements, the necessary EM&V programs can be resource 

intensive and air pollution control agencies may not have the appropriate staffing or expertise to 

certify energy efficiency reduction credits. Commenters noted that is a particular concern for 

multi-state rate-based trading programs because the handling of these special reduction credits 

must then be coordinated to ensure consistent treatment. Commenters noted that for mass-based 

programs there is no need for credit trading because investments in these alternative resources 

are accounted for under a state budget approach by lowering overall emissions.

Comment 2: Comments stating that Tribes and territorial areas supported mass-based limits.

Response 2: The EPA agrees with commenters and has provided both rate-based and massbased goals in the final rule to allow tribes to choose the approach that is most appropriate for 

affected EGUs in their jurisdiction. The EPA worked with the Navajo Nation to determine the 

appropriate mass-based CO2 goals prior to finalizing the rule, and will continue to support and 

give guidance to the tribe during implementation of the rule.

The following are summaries of the specific public comments under this comment:

Commenters support mass-based emission goals for tribal areas and territories because massbased goals are the most effective, efficient and transparent approach to significant CO2 emission 

reductions from the designated facilities. Commenters assert that mass-based goals will allow for 

entities to more easily demonstrate compliance with the CO2 emissions reductions at the 

designated facilities using continuous emission monitoring and allows energy efficiency and 

renewable energy programs to be more easily incorporated into tribal and territorial plans 

without the need for modeling of emission reductions required for rate-based plans.

Commenters also stated that mass-based goals would better enable allowance trading 

mechanisms, which they believed would provide emission reductions at the lowest cost.

Commenters believed the mass-based limits would be the best approach for the Navajo Nation's 

power plants. Commenters stated this approach would allow them to take credit for CO2

emission reductions that have been achieved at FCPP and for reductions that will be achieved at 

NGS. Commenters requested the EPA work with the Navajo Nation to determine appropriate 

mass-based goals for the FCPP and NGS plants.
17

Comment 3: Comments suggesting that mass-based standards are more consistent with building 

blocks 2, 3, and 4.

Response 3: In the preamble to the final rule, the EPA demonstrates how the BSER is 

achievable under either a rate-based or mass-based approach. In particular, section V.A.5 of the 

preamble describes actions that affected EGUs can take to achieve standard of performance 

derived through the application of the BSER, under both a rate-based and mass-based approach.

The following are summaries of the specific public comments under this comment:

Commenters believed that a mass-based standard would be more consistent with building blocks 

2, 3, and 4 since each of these measures ensures that the highest emitting generators operate less 

frequently to reduce the mass of emissions. 

Comment 4: Comments supporting mass-based limits but recommending the final rule 

accommodate states that already comply with RGGI.

Response 4: The EPA agrees with the commenters, and in the final rule, has provided states with 

the flexibility to implement either a rate-based or mass-based plan approach. To facilitate massbased plans, the EPA has included state mass-based CO2 goals in the final rule. Plan approaches 

are discussed in section VIII.C of the preamble. The preamble to the final rule discusses the 

existing emission budget trading programs currently being implemented by California and the 

RGGI participating states, and explains available state plan pathways that would accommodate 

use of these programs to meet a state CO2 emission goal. These pathways would facilitate the 

continued implementation of these state programs and the ability to use them to meet the 

emission guidelines. These issues are discussed in section VIII.J of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters believed that mass-based emission limits are critical to helping states take 

advantage of the lowest cost carbon reduction options under the EPA's proposal, but 

recommended that the final rule accommodate states that are already complying with RGGI 

requirements (such as coverage of new units) so that duplicative regulation may be avoided. 

Comment 5: Comments stating that mass-based emission allowances should be allocated based 

on historic emissions.

Response 5: The EPA does not take a position in the final rule on how states implementing an 

emission budget trading program under either an emissions standards plan type or a state 

measures plan type must or should allocate emission allowances. States have the discretion to 

allocate allowances as they see fit considering the circumstances in their state and other policy 

considerations. Plan approaches are discussed in section VIII.C of the preamble to the final rule, 
18

and implementation considerations for mass-based plans are further discussed in section VIII.J of 

the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended mass-based emission allowances be allocated to affected sources 

based on their historic emissions. Commenters prefer this approach because it avoids 

complicated allowance allocation systems, auctions, taxes or other added costs.

Comment 6: Comments stating that states should auction emission allowances rather than 

allocating them.

Response 6: The EPA does not take a position in the final rule on how states implementing an 

emission budget trading program under either an emissions standards plan type or a state 

measures plan type must or should allocate emission allowances. States have the discretion to 

allocate allowances as they see fit considering the circumstances in their state and other policy 

considerations. Plan approaches are discussed in section VIII.C of the preamble to the final rule, 

and implementation considerations for mass-based plans are further discussed in section VIII.J of 

the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended that states adopting mass-based emission standards should auction 

allowances rather than allocating them for free. Commenters stated that auctioning allowances 

provides affected sources the ability to purchase the number of allowances they need for 

compliance and provides a fair, equitable and economically efficient method of distributing 

allowances to affected sources. 

Comment 7: Comments stating that the EPA should clarify that mass-based allowance programs 

can be used to comply with the rule.

Response 7: The final rule provides states with the flexibility to implement either a rate-based or 

mass-based plan approach. To facilitate mass-based plans, in the final rule the EPA has included 

state mass-based CO2 goals. Plan approaches are discussed in section VIII.C of the preamble to 

the final rule. Implementation considerations for mass-based plans are further discussed in 

section VIII.J of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters believed it is important for the EPA to make it clear that mass-based allowance 

programs may be used to comply with its rate-based targets, but that state emission standards 

"shall be no less stringent" than federal emission guidelines as required by section 111(d).
19

Commenters stated that, provided a state's mass-based targets have an equivalent degree of 

stringency, they believe that a wide range of design choices should be permitted. 

Comment 8: Comments stating that RGGI and other programs demonstrate that plans with 

mass-based limits would be successful.

Response 8: The EPA agrees with the commenters and has highlighted the multiple benefits of a 

mass-based plan approach, and market-based emission budget trading approaches in particular, 

in the preamble to the final rule. These benefits include greater administrative simplicity and 

economic efficiency. In the final rule, the EPA has provided mass-based state CO2 goals in the 

emission guidelines, to facilitate the use of mass-based plans by states. Plan approaches, 

including multi-state plans and multi-state coordination, are discussed in section VIII.C of the 

preamble to the final rule, and implementation considerations for mass-based plans are further 

discussed in section VIII.J of the preamble to the final rule. In addition, the preamble to the final 

rule notes, in multiple instances, the successful implementation of state emission budget trading 

programs, such as RGGI, and the potential for their incorporation in state plans.

The following are summaries of the specific public comments under this comment:

Many commenters supported a mass-based system with a cap on fossil fuel-fired power plant 

emissions. Several of these commenters specifically mentioned RGGI as an example of a 

successful mass-based program and noted that RGGI has demonstrated that a mass-based trading 

system can achieve greater emissions reductions at a lower cost, while creating jobs, maintaining 

reliability, and improving the regional economy. Commenters noted that RGGI has successfully 

reduced regional CO2 emissions by more than 40 percent from 2005 levels and that New 

Hampshire has achieved CO2 emission reductions of over 48 percent from 2005 levels. 

Commenters further emphasized that RGGI is expected to achieve an additional 14 percent 

reduction from its 2014 cap of 91 million tons by the year 2020 and that new sources are covered 

under the RGGI cap. Commenters states that "RGGI has demonstrated that, by working together, 

groups of states can achieve greater emission reductions at a lower cost, while creating jobs, 

maintaining grid reliability, and improving the regional economy." Commenters believe a massbased program like RGGI avoids many of the complications of a rate-based approach and 

simplifies compliance and enforceability. 

Commenters stated that many states and other stakeholders have requested the EPA use a massbased allowance approach because of the simplicity of this approach. Commenters noted that a 

number of states have already implemented mass-based allowance systems. Commenters noted 

that California's Global Warming Solutions Act (AB32) and to some extent Colorado's Clean 

Air, Clean Jobs Act (CACJA) included mass-based limits.

Commenters believed that a final section 111(d) rule containing an emission standard in the form 

of a mass-based system would likely be much more easily integrated into any future economy 

wide greenhouse gas legislation.

Commenters noted that a market-driven, mass-based program like RGGI also provides additional 

emission reduction benefits by leveraging the value of emission allowances. Commenters noted 
20

that the RGGI states distribute RGGI CO2 allowances primarily through regional auctions, and 

that revenues from these auctions are then used by each RGGI state to fund a variety of EE, RE, 

and other GHG emission reduction programs and projects, which yield significant additional 

GHG emission reductions in all sectors of the economy. Commenters believed other mass-based 

programs could achieve similar additional benefits through the use of allowance revenues. 

Commenters noted that RGGI has shown that mass-based programs can be used in a multiple 

ISO environment.

Comment 9: Comments stating that innovative carbon reduction programs such as RGGI should 

not be stymied by incorporating their provisions into SIPs. 

Response 9: The final rule provides for the incorporation of existing emission budget trading 

programs, such as RGGI, in state plans. These existing programs could be included in a state 

measures plan, as discussed in sections VIII.C.3 and VIII.J of the preamble to the final rule.

Under this approach, the emission budget trading program would be incorporated as a stateenforceable measure, rather than a federally enforceable emission standard. Alternatively, states 

could include emission budget trading programs as federally enforceable emission standards 

under an emission standards plan type, as discussed in section VIII.C.2 of the preamble to the 

final rule. In addition, in the final rule, the EPA has provided multiple routes for states to 

implement multi-state emission budget programs through a state plan under CAA section 111(d). 

These approaches are discussed in section VIII.C.5 of the preamble to the final rule. The EPA 

believes that these multiple plan approaches facilitate the continued implementation and 

improvement of programs such as RGGI.

The following are summaries of the specific public comments under this comment:

Commenters stated that the Regional Greenhouse Gas Initiative (RGGI) and similar programs 

have 

"demonstrated that compliance with environmental programs can be monetized 

such that it is factored into power sector economic decision making in ways that 

reduce the cost of controlling pollution, maintain electricity system reliability and 

work within the least cost dispatching principles that are key to operation of our 

electric power grid." 

Commenters stated that they are skeptical RGGI's success can be extended or duplicated through 

implementation of the 111(d) rule as proposed. Commenters stated that they are concerned that

the EPA's proposed use of SIPs to lock in federally enforceable gains will discourage new 

interstate agreements and improvements to existing ones; states could end up disassociating 

themselves from RGGI.

Comment 10: Comments stating that mass-based limits would encourage states to import 

electricity from states with rate-based limits.
21

Response 10: In response to comments, the EPA has made changes to the final emission 

guidelines to address this concern under mass-based plans. The EPA requires that mass-based 

plan must demonstrate that it has provisions that mitigate the potential for emission leakage. 

These requirements, and the rationale for their inclusion in the emission guidelines, is discussed 

in section VIII.J.2.b of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters believed that states with mass-based limits will have an incentive to import 

electricity from rate-based states.

Comment 11: Comments asking whether RE and EE programs have to be federally enforceable 

in a mass-based state plan

Response 11: In the final rule, the EPA is providing states with the flexibility to use an emission 

budget trading program that covers emission sources beyond affected EGUs subject to CAA 

section 111(d) to meet the emission guidelines. This approach may be taken through a state 

measures plan type. Under this approach, a state mass-based CO2 emission goal for affected 

EGUs must be achieved through the plan. However, an emission budget trading program used to 

achieve this goal could include emission sources beyond affected EGUs.

Under a plan that includes a mass-based emission budget trading program, RE and demand-side 

EE are complementary measures that do not need to be included in a state plan. Even though not 

included in a plan, these measures will reduce CO2 emissions, helping affected EGUs meet the 

established emission budget. Alternatively states may choose to implement a mass-based state 

measures plan type, where state measures, which may include RE and demand-side EE, are used 

to achieve a state mass CO2 goal. Under that plan approach, those state measures are not 

federally enforceable. These issues are discussed in the preamble to the final rule in sections

VIII.C and VIII.J. 

The following are summaries of the specific public comments under this comment:

Commenters asked whether meeting the mass-based emissions cap will be the only federally 

enforceable component of the states' plan under the CPP, even if the emissions cap covers new

sources or other sources that are not affected sources under the CPP. Commenters asked whether 

the EPA will only consider whether the broader regional cap is met in determining a state's 

compliance. 

Commenters asked the EPA to confirm that complementary RE and EE programs need not be 

separately quantified or accounted for, and would not become federally enforceable. 

Commenters noted that a benefit to this approach is the avoidance of a host of complexities 

associated with enforceability, accounting, and "double-counting." 
22

Comment 12: Comments stating that the EPA should clarify whether differences in applicability 

and scope will be allowed.

Response 12: In the final rule, the EPA is providing states with the ability to use emission 

budget trading programs that apply to a broader set of emission sources than just affected EGUs 

subject to CAA section 111(d) to meet the emission guidelines. State plan approaches that 

include emission budget trading programs that include a broader set of emission sources beyond 

affected EGUs are addressed in sections VIII.C.2.b and VIII.J of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters requested the EPA clarify its treatment of distinctions between state programs 

included as part of state plans and the requirements of the CPP under CAA Section 111(d). 

Commenters noted that RGGI states understand that, provided a state or region makes an 

acceptable equivalency demonstration in its plan, the EPA will allow for applicability or other 

differences between the scope of 111(d) and those of state programs. Commenters provided for 

example, if a state program has a broader applicability than the affected sources covered under 

the CPP (e.g., new as well as existing sources), that this should not create significant

complications for the EPA or the states, and can be incorporated through modeling or other 

projections used in the rate-to-mass translation. Commenters contended that as long as a state or 

region can demonstrate that its plan is projected to result in an equivalent level of emission 

reductions from affected sources without weakening the stringency of the targets, then the EPA 

compliance and enforcement requirements are satisfied. Commenters noted that this approach 

has been used before by the EPA under the CAA, including in the context of State 

Implementation Plans ("SIPs") for nitrogen oxides ("NOx").

Comment 13: Comments recommending emission allowances be auctioned and the proceeds by 

distributed to state residents.

Response 13: The EPA does not take a position in the final rule on how states implementing an 

emission budget trading program under either an emission standards plan type or a state 

measures plan type must or should allocate emission allowances. States have the discretion to 

allocate allowances as they see fit considering the circumstances in their state and other policy 

considerations. Plan approaches are discussed in section VIII.C of the preamble to the final rule, 

and implementation considerations for mass-based plans are further discussed in section VIII.J of 

the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA allow states to use "an upstream cap-and-permit system" in 

which the state would cap emissions, auction CO2 emission allowances (permits) to EGU's, and 

then the state would distribute the revenue as per capita dividend to the state's legal residents. 

Commenters stated that states would ideally coordinate with other states in their region and each 

year the number of allowances would decline until the state or regional target is 

met. Commenters recommended that no traders or speculators should be able to purchase 

allowances and no offsets should be allowed impact emissions, would be tracked using the 
23

number of allowances. Commenters also recommended that the revenue should not be 

distributed as a credit against customer's energy bills but rather as a direct rebate paid directly by 

the state to all legal residents. Commenters stated the reason for distributing dividends via direct 

payment rather than via utilities, is that credits against utility bills mask the higher cost of energy 

and thus reduce the incentive to conserve energy. 

Commenters believed that "an upstream cap-and-permit system" is preferable to a carbon tax or 

fee without an upstream cap because it sets the quantity of carbon that can be burned. 

Commenters believed that such a system would be easy to administer with the prices paid by the 

companies set by auctions rather than government. Commenters noted that the California and 

Regional Greenhouse Gas Initiative (RGGI) have shown that emission allowance auctions can be 

conducted fairly and efficiently, and noted that if predictability in prices is desired, a floor price 

on allowances could be included in the system. 

Commenters also argued against allowing auction revenues being spent by state governments on 

conservation programs, stating that the cap is the cap on emissions and the gradual annual 

reductions in the cap that reduces emissions, rather than spending of revenue on particular 

programs. 

Comment 14: Comments stating that states may be disadvantaged by setting a mass-based limit 

and supported a least cost dispatch approach.

Response 14: The EPA disagrees with the comment. A mass-based emission limit that includes 

emission trading facilitates least-cost dispatch of affected EGUs, as it establishes a market piece 

for emission allowances. This market price or allowances is in turn considered in the variable 

operation and maintenance costs for an EGU, in a manner that considers the CO2 emission rate 

of each EGU, facilitating least-cost dispatch of EGUs in meeting the mass-based emission limit.

The following are summaries of the specific public comments under this comment:

Commenters believed states may be disadvantaged by setting a mass-based target because the 

measures the EPA has considered as part of an adjusted emission rate goal may or not directly 

displace emissions from affected sources in manner proposed due to the interconnected nature of 

the electric grid. Commenters noted that under a least cost dispatch approach, emissions are 

always reduced from the marginal generating units at a specific point in time. Commenters noted 

that as an example, the increased use of renewable energy or energy efficiency measures could at 

times displace emissions from out of state generation or gas-fired generation, which they believe 

may not affect emissions from affected sources within a state to the degree proposed. 

Comment 15: Some commenters believed increases in electricity demand would make 

compliance with mass-based limits more difficult for natural gas-fired EGUs and rural electric 

companies.
24

Response 15: The EPA disagrees with the comment’s assertion that the state mass-based CO2

goals in the emission guidelines would "penalize" natural gas-fired EGUs. As discussed in 

section VII of the preamble to the final rule, the state mass-based CO2 emission goals are derived 

from the CO2 emission performance rates for NGCC and steam generating units in the emission 

guidelines.

The EPA also disagrees with the contention by commenters that growth in electricity demand 

cannot be accommodated under a mass-based plan approach. The EPA notes that under both 

rate-based and mass-based approaches, CO2 emissions reductions can be achieved while 

accommodating for growth in electricity demand. Both rate-based and mass-based approaches 

apply to CO2 emissions from existing affected EGUs. Electricity growth can be accommodated 

through a mix of electricity generation from affected EGUs, low- and non-emitting non-affected 

EGUs (including new fossil fuel-fired EGUs subject to CAA section 111(b), and reductions in 

electricity demand through demand-side EE improvements).

The following are summaries of the specific public comments under this comment:

Commenters believed mass-based limits will penalize natural gas-fired EGUs. Commenters 

noted that Coffeyville and Winfield plants in Kansas are natural gas-fired plants that are below 

the state lb/MWh goal. Commenters stated that if the goal is converted to a mass-based limit, 

then Coffeyville and Winfield would likely be forced to make reductions through demand-side 

management programs or additional investments in renewable energy, which they stated would 

have a large impact on customer electricity rates. Commenters also noted that if some coal-fired 

generators are retired, Coffeyville and Winfield may be dispatched more often and would have 

greater problems meeting a mass-based limit even though the overall amount of state GHG 

emissions will have been reduced considerably.

Commenters were concerned that increased demand for electricity from natural gas drilling and 

compression caused by Building Block 2 would likely make compliance with mass-based limits 

more difficult, especially for rural electric companies due to the increased demand for electricity 

from natural gas drilling and compression facilities in rural areas.

Comment 16: Comments stating that mass-based limits would be more expensive and make 

electricity consumers uncompetitive.

Response 16: The EPA disagrees with the commenters’ assertions that mass-based goals would 

be more expensive and make electricity uncompetitive. The EPA highlights in the preamble to 

the final rule the multiple benefits of a mass-based plan approach. There is a wide-ranging 

literature on the economic efficiency and successful implementation of mass-based emission 

budget trading programs, including successful implementation of programs by the EPA and 

states. In the final rule, the EPA has provided both rate-based and mass-based goals to allow 

states to choose the approach that is most appropriate for affected EGUs in their jurisdiction.

The following are summaries of the specific public comments under this comment:
25

Commenters believed that it would be a serious mistake for states to convert intensity goals to 

mass-based goals because the costs of achieving emissions reduction using a mass-based limit 

would more expensive than achieving the same reduction with a rate-based system. Commenters

argued that states that adopt a mass-based system place themselves at a severe competitive 

disadvantage, not only with respect to other states, but also with respect to foreign jurisdictions 

that adopt a rate-based target or no target at all. Commenters stated that mass-based limits have 

regressive distributional effects that can be avoided with a rate-based system of control. 

Commenters argued that emissions trading has been most successful when designed to achieve 

an intensity goal rather than a mass-based goal, and believed that the success of the 1980s 

program to phase out the use of tetraethyl lead as an octane booster in gasoline was due to the 

EPA's decision to adopt an intensity-based limit, rather than a mass-based limit.

Comment 17: Comments expressing concern that mass-based limits would not reduce 

emissions.

Response 17: The EPA disagrees with the commenters. Emission limits that achieve mass-based 

CO2 goals will reduce CO2 emissions from affected EGUs. The EPA notes that increased 

electricity demand could be met through a mixture of electric generation from affected EGUs, 

new EGUs subject to CAA section 111(b) (which are also subject to CO2 emission constraints, 

other low- and non-emitting generation, and demand-side EE). 

The following are summaries of the specific public comments under this comment:

Commenters argued that a mass-based goals would not result in a reduction in emissions because 

increased demand would be met with additional generation. Commenters argued that the EPA, 

Ohio EPA nor any other entity has the authority to limit generation. 

Comment 18: Comments suggesting the proposed BSER would make mass-based limits 

inflexible.

Response 18: The EPA disagrees with the commenters. Demand-side EE could be used as an 

emission reduction strategy under a mass-based plan approach, as discussed in section VIII.C.2.b

of the preamble to the final rule. The EPA also notes that a state is not required to implement in 

its state plan the measures determined by the EPA to be the BSER.

The following are summaries of the specific public comments under this comment:

Commenters believed that any state choosing a mass-based compliance approach would do so to 

avoid implementing costly and technically unreasonable EE measures and exposing electricity 

rate payers to increased costs. However, commenters believed the flexibility of the mass-based 

approach is eliminated because the states must employ the proposed BSER.
26

Comment 19: Comments stating that states using a mass-based limit should be allowed to 

expand their program to cover new natural gas plants.

Response 19: In the final rule, the EPA is providing states with the ability to use emission 

budget trading programs that apply to a broader set of emission sources than just affected EGUs 

subject to CAA section 111(d) to meet the emission guidelines. This approach is addressed in 

sections VIII.C.2.b and VIII.J.2 of the preamble to the final rule. In response to comments, the 

emission guidelines include requirements that a mass-based state plan must demonstrate that it 

includes provisions to mitigate the potential for emission leakage. One approach for meeting this 

requirement is inclusion of new EGUs in an emission budget trading program, through 

requirements under state law. These requirements, and options for meeting them, are discussed in 

section VIII.J.2.b of the preamble to the final rule.

In the final rule, the EPA does not prescribe allocation approaches for states implementing 

emission budget trading programs as part of a state plan. A state could choose to include an 

allocation "set-aside" such as the one suggested by the commenters.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA allow and encourage states that choose mass-based systems 

to expand their budgets to cover new natural gas plants and to regulate them under the same 

mass-based system the state uses to regulate existing power plants under Section 111(d). 

Commenters stated that inclusion of new natural gas plants is important because it will avoid 

creating a dispatch cost advantage for new gas power plants relative to comparable existing gas 

power plants, which would distort market outcomes and provide an incentive for operating new 

gas plants that have unregulated emissions.

Commenters also recommended that states adopting mass-based emission limits with allowance 

trading (i.e. a cap-and-trade program) should be required to include a "set-aside" mechanism for 

voluntary RE that would set aside and retire allowances for voluntary RE purchases made by 

facilities within the state. Commenters believed that without such a mechanism, voluntary 

actions to reduce emissions in capped sectors would not reduce emissions but would instead 

allow other sources to emit more. Commenters stated that a set-aside mechanism for voluntary 

RE, like those used in the California and RGGI programs, would restore the impact of the 

voluntary market to reduce total CO2 emissions. 

Comment 20: Comments stating that the EPA should require states to adjust goals to account of 

voluntary RE generation.

Response 20: The EPA disagrees with the comment. Such concerns do not warrant changing 

state CO2 goals. States can address aspects of the voluntary RE market, including provision of 

incentives for voluntary RE purchase, in the design of their state plans. In addition, private 

standards, such as Green-e, can address the issues raised by the commenter in the context of 

those private standards for the recognition of voluntary RE purchases. In addition, the 

requirements for rate-based emission trading programs in the emission guidelines, which are 
27

discussed in section VIII.K.2 of the preamble to the final rule, do not allow double counting and 

include requirements that are designed to preclude such outcomes in practice.

The following are summaries of the specific public comments under this comment:

Commenters stated that for states using a mass-based approach, the EPA should require states to 

adjust the goals to account for any voluntary RE generation within the state. Commenters noted 

that voluntary RE is already tracked using RECs and REC retirement either in RE tracking 

systems or by contractual agreements and that CRS and Green-e can report to the EPA and the 

state the quantity of certified and verified voluntary sales data annually to prevent double 

counting and ensure that this generation is not included in 111(d) compliance. 

Comment 21: Comments stating that the RE and demand-side EE programs in mass-based state 

plans should not be federally enforceable and regulated facilities should not have to quantify the 

impacts of these programs.

Response 21: Under a plan that includes a mass-based emission budget trading program, RE and 

demand-side EE are complementary measures that do not need to be included in a state plan. 

Even though not included in a plan, these measures will reduce CO2 emissions, helping affected 

EGUs meet the established emission budget. Alternatively, states may choose to implement a 

mass-based state measures plan type, where state measures, which may include RE and demandside EE, are used to achieve a state mass CO2 goal. Under that plan approach, those state 

measures are included as part of the plan but are not federally enforceable. These issues are 

discussed in the preamble to the final rule in sections VIII.C and VIII.J. 

The following are summaries of the specific public comments under this comment:

Commenters recommended that states adopting mass-based goals should be able to demonstrate 

compliance through emission monitoring at regulated facilities and should not be required to 

quantify impacts from EE and RE programs or make such EE and RE programs federally 

enforceable.

Commenters noted that RE and EE programs can act as complementary policies under a massbased program that need not be separately accounted for or made federally enforceable. 

Commenters stated that a mass-based approach also circumvents interstate issues, such as those 

regarding which state receives "credit" for various RE and EE measures. 

Similarly, commenters wanted assurance from the EPA that existing state RE and EE measures 

do not have to be federally enforceable parts of a state plan if the state plan imposes a 

sufficiently stringent mass limit on affected EGUs. Commenters noted that RE and EE programs 

have historically been solely under the purview of state law and that Illinois' existing RPS and 

Energy Efficiency Portfolio Standard were a result of state legislation and are not federally 

enforceable. Commenters recommended that such existing RE and EE measures should continue 

to be enforceable only under state law and that only the EGU emission limits should be federally 

enforceable. To maintain flexibility and autonomy, Commenters believed Illinois should not be 
28

required to make such measures federally enforceable as part of its state plan, but should be able 

to take them into account in meeting the criteria for state plan approval.

Comment 22: Comments stating that the EPA should allow states to apply mass-based limits to 

both new and existing sources.

Response 22: In the final rule, the EPA is providing states with the ability to use emission 

budget trading programs that apply to a broader set of emission sources than just affected EGUs 

subject to CAA section 111(d) to meet the emission guidelines. This includes new EGUs subject 

to emission standards under CAA section 111(b). This approach is addressed in sections 

VIII.C.2.b and VIII.J.2.b of the preamble to the final rule. 

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA allow states to use a mass-based system applied to the 

energy system as a whole so that both new and existing sources are included. Commenters 

believe a more rational and cost-effective market response will result if both new and existing 

sources are subject to the same regulatory program and market signals.

Comment 23: Comments stating that mass-based limits may act as disincentive for states to 

support electric vehicle programs.

Response 23: The EPA believes that the commenters’ concerns are not warranted, and notes that 

a state mass-based CO2 goal applies to affected EGUs, rather than all electric generation. In 

particular, the EPA disagrees with the contention by the commenters that growth in electricity 

demand cannot be accommodated under a mass-based plan approach. The EPA notes that under 

both rate-based and mass-based approaches, CO2 emissions reductions can be achieved while 

accommodating growth in electricity demand. Both rate-based and mass-based approaches apply 

to CO2 emissions from existing affected EGUs. Electricity growth can be accommodated through 

a mix of electricity generation from affected EGUs, low- and non-emitting non-affected EGUs 

(including new fossil fuel-fired EGUs subject to CAA section 111(b), and reductions in 

electricity demand through demand-side EE improvements).

The following are summaries of the specific public comments under this comment:

Commenters were concerned the increased electrical load due to additional deployment of 

electric vehicles (EVs) will make compliance more difficult for states adopting a mass-based 

goal. Commenters noted that EVs could account for 1 percent of electricity demand by 2020, and 

up to 5-7 percent of electricity used in the leading EV states by 2030. If all light duty vehicles in 

a state were converted to EVs, commenters noted that electricity consumption would rise by 

approximately 20 percent. Commenters believed this increase is large enough to impact a state's 

ability to meet a mass-based target. Commenters believed mass-based limits could act as a 

disincentive for the state or utilities in the state to actively support EVs.
29

5.1.3 Portfolio approach

This section contains general comments on the portfolio plan approach for meeting the emission 

guidelines. Specific comments on the state-driven and utility-driven portfolio approaches are 

included in subsections 5.1.4 and 5.1.5, respectively.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Comments suggesting that states should be allowed to select, and enforce EE 

programs, rather than the EPA.

Response 1: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, in particular comments raised about applying federally enforceable 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters supported the proposed portfolio approach for state implementation plans, whereby 

states have the ability to select, adopt, and enforce energy efficiency policies and programs, 

rather than the EPA enforcing them. Commenters indicated this would generate significant 

flexibility for the states, allowing for a broad range of efficiency programs to be considered for a 

state's implementation plan. 

Commenters stated that utilities are already implementing energy efficiency programs for their 

customers in a wide range of policy contexts--some states have adopted formal energy savings 

requirements (e.g., an energy efficiency resource standard, or EERS), some have set energy 

savings goals, some have adopted energy efficiency rules, some allow energy efficiency program 
30

funding and savings levels to be driven by integrated resource plans (IRPs), and some undertake 

energy efficiency program review and approval on an annual, biennial, or triennial basis, without 

any formal energy savings standards or goals. Commenters noted that all are valid approaches to 

utility energy efficiency policy and program implementation. Commenters suggested that the 

EPA allow all approaches to be included in state plans, and then used during the implementation 

phase. Commenters noted that non-utility energy efficiency programs have a proven track record 

of achieving energy savings in many states and provide a strong complement to utility programs.

As proposed, Commenters said the Clean Power Plan allows both utility and non-utility 

programs to receive compliance credit for energy savings. However, Commenters requested 

clarification on which types of programs are eligible for inclusion in state implementation plans 

for compliance with the proposed Clean Power Plan. Commenters suggested that these programs 

be considered for compliance purposes, and not impact the existing goals established for states. 

Commenters proposed the following: 

• Commenters suggested that the EPA allow states and utilities to receive 

compliance credit for a wide variety of utility programs, including but 

not limited to: measure-based incentives, behavior change programs, 

transmission and distribution system upgrades, financing programs, 

building code support programs, and incentives for CHP. Commenters

indicated that this applies to IOUs, municipal utilities, and rural electric 

cooperatives.

• Commenters suggested that non-utility state and private sector energy 

efficiency policies and programs be eligible for compliance credit and 

may include: building energy codes, lead-by-example programs, energy 

retrofit ordinances, tax incentives, financing programs, public sector 

energy efficiency improvement policies or programs, programs to spur 

market transformation, state-based appliance efficiency standards, state 

policies or programs to foster adoption of CHP systems, and state 

programs to improve industrial or agricultural efficiency. In particular, 

commenters noted the private sector plays an essential role in achieving 

higher efficiency standards through the innovation of technology and 

new products, also serving as a significant platform for economic 

development and job creation. According to the commenters, policies or 

programs adopted and/or implemented by local governments should be 

eligible for compliance credit if they are included in state 

implementation plans.

• Commenters suggested that the EPA recognize that the same type of 

energy savings may be considered as a utility program in one state and a 

non-utility energy efficiency program in another state. On the topic of 

claiming the energy savings from building energy code compliance, 

commenters noted that in Massachusetts, Rhode Island, and California, 

utilities are managing code compliance enhancement programs. 

Commenters noted that in Illinois, as part of work showing the costeffectiveness of such an initiative, it was calculated that improving code 
31

compliance to 100% (based on a 70% compliance rate) would save 

2,000,000 therms and 38,000 megawatt-hours per year. Commenters

noted that program design and pilot studies are also being done in 

Nebraska and Michigan to tailor code compliance enhancement 

programs in those states.

• Commenters suggested that compliance credit be awarded for energy 

efficiency improvements within utility T&D systems, including 

Conservation Voltage Reduction (CVR). Commenters noted that CVR 

provides energy savings for end-use consumers as well as some 

reduction in distribution system losses.

Commenters suggested that compliance credit be awarded for states that adopt minimum 

efficiency standards on products not regulated by the federal government under the National 

Appliance Energy Conservation Act (NAECA) legislation. Commenters noted that California 

and other states have adopted state efficiency standards in recent years on televisions, battery 

chargers, and other electronic products. Commenters cited the Appliance Standards Awareness 

Project (ASAP), which indicates that twelve states currently have state appliance efficiency 

standards in effect. Commenters noted ASAP's suggestion that there are twelve products 

including televisions, set-top boxes, battery chargers, commercial and industrial fans, and pumps 

that states could adopt efficiency standards for, and that doing so would provide substantial net 

economic benefits for consumers and businesses. Commenters noted that ASAP has estimated 

the energy savings potential state-by-state in 2025 and 2035, assuming that state standards on 

these twelve products are adopted in 2014. 

Commenters stated there are many different business models that can be used by a state to 

successfully deploy EE measures, including but not limited to state operated programs, 

independent third party programs, and utility-run programs. Commenters recommended that the 

EPA allow the states flexibility in determining which business models to utilize in their 

compliance plans. Commenters stated utility operated programs in particular have many 

advantages in the deployment of EE: strong community relationships, access to all customers, 

patient capital, economies of scale. Commenters stated all of these advantages are critical to the 

success of EE programs. Commenters stated additional advantages include utility bills, which 

can be used for on-bill repayment of EE upgrades, access to customer data, and utility 

brand/customer relationships. Commenters stated the opportunity for universal access provides 

another critical element of success for EE. Commenters stated as a society, we decided long ago 

that electricity, and the economic and social benefits that come with it, should be available to 

every citizen. Commenters stated the utility is the best means by which to accomplish that goal. 

Commenters believed an evolved utility model can meld the best of what we have today with 

new technologies and new thinking to reduce GHG emissions and yield EE benefits to every 

utility customer. 

Commenters stated that in addition to ESPCs, they recommended that the EPA provide specific 

guidance to states that other non-utility delivered EE can be included in state compliance plans. 

Commenters stated the EPA may wish to provide additional information in the final CPP on 

building codes; States should get credit for EE and CO2 reductions resulting from adopting, 

updating and increasing compliance with building energy codes. 
32

Commenters recommended a broad range of energy efficiency programs and policies be allowed 

in state compliance plans and that adoption and enforcement of such measures be left with the 

states, rather than the EPA. Commenters also agreed with the RGGI states that they must be 

given flexibility to modify such measures and policies, as they are meant to evolve to changing 

technologies, market circumstances, etc., and, thus, cannot remain static over the 15-year EPA 

compliance period. Commenters stated that while the EPA noted the challenges of using building 

energy codes as a compliance strategy due to EM&V issues, they felt very strongly that energy 

codes should be part of any allowable compliance strategies, as should state-based appliance 

efficiency standards. According to the commenters, other programs and policies that should also 

be considered for eligibility include state and municipal building energy standards (i.e., "leadingby-example" programs), which the Northeast has considerable experience with and which have 

produced substantial energy savings over the years; and policies that enhance private financing 

of energy efficiency projects (e.g., loan loss reserve funds, or Property Assessed Clean Energy 

Districts (PACE) initiatives). 

While energy efficiency efforts are a tried and true least cost means to achieve proposed Clean 

Power Plan goals, commenters said their inclusion in state implementation plans should be 

facilitated and the EPA requirements clarified as explained below:

• Commenters stated that the proposed portfolio approach is wise in that it 

allows efficiency measures to be considered "implementing measures" 

that are complementary to EGU limits, but not directly enforceable, 

while allowing states to adopt and enforce as appropriate (79 FR 34901-

03).

• Commenters recommended that states be able to modify the energy 

efficiency policies and programs contained in state plans during the 

implementation phase. Commenters said this would help to ensure that 

new technologies can be incorporated, ensure that results from EM&V 

work can be acted upon, and otherwise support best energy efficiency 

practices as they evolve over time. Commenters noted that energy 

efficiency policies and programs change over time, and that they are not 

set in place and left unchanged for 10 or 15 years. Commenters indicated 

that this flexibility allows states to make up for any emissions reduction 

shortfall if energy efficiency policies and programs are not as effective 

as expected, and allows for other adjustments if energy efficiency 

policies and programs turn out to be more effective than expected in the 

initial state implementation plans.

• Commenters suggested that states be required to include provisions in 

their state implementation plans to avoid double counting of energy 

savings among the various energy efficiency policies and programs 

included in the plans (e.g., for projects that participate in both utility and 

non-utility programs). Commenters recommended that states be given 

the flexibility to determine which program receives the compliance 

credit and detail how double counting will be avoided in the state 

implementation plan. 
33

Comment 2: Comments requesting clarification on whether or not plans with EE and RE have to 

also include enforceable measures for these programs in state plans using the portfolio approach

Response 2: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, in particular comments raised about applying federally enforceable 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

When a state uses a mass-based goal with enforceable measures, commenters asked if the plan 

needs to include enforceable measures for the EE, RE, and other measures that will be used to 

meet the mass-based measures or if compliance with the mass-based goals sufficient.

Commenters also asked what mechanisms the EPA envisions that could allow a state to transfer 

credit from state-implemented measures to individual EGUs and who is liable if these credits do 

not materialize. 

Comment 3: Some commenters oppose federal enforcement of state-driven portfolio measures.

Response 3: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, in particular comments raised about applying federally enforceable 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 
34

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters noted that there are two different issues under the portfolio approach. Commenters

explained that the "utility-driven" portfolio approach seems to lead to federal enforceability for 

the affected EGUs, while federal enforceability is not as clear under the "state- driven" approach. 

Commenters opposed federal enforceability for third parties that are not part of the affected 

EGUs. Commenters argued this is the responsibility of the state and enforcement on entities 

other than the affected EGUs should be the sole responsibility of the state.

Comment 4: Comments suggesting that states should be given flexibility in how they meet the 

CPP consistent with the flexibility provided states in developing CAA Section 110 SIPs to meet 

NAAQS.

Response 4: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, in particular comments raised about applying federally enforceable 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:
35

Commenters stated that consistent with the principle of cooperative federalism, the CAA 

supports providing flexibility to states to meet environmental goals. Commenters noted that 

measures provided for in Section 110 SIPs have been considered and implemented by states in 

the past in order to meet NAAQS and that section 111(d) does describe the process as SIP-like. 

Commenters agreed with this concept and supported that states have flexibility in selecting 

measures to meet the required state goals.

Comment 5: Comments suggesting that states should have flexibility to allow building codes, 

standards and behavioral programs to count toward compliance with the CPP.

Response 5: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, in particular comments raised about applying federally enforceable 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that to achieve the stated emission goals for the long term, as market 

potential for traditional programs is reduced by future regulation and efficiency improvements, it 

is likely that programs that are often outside of the scope of utility DSM programs and potential 

studies, such as local and state-level improvements to building codes and standards, as well as 

behavioral programs may be required to meet the long term goals. Commenters encouraged the 

EPA to provide flexibility to states in allowing codes, standards, and behavioral programs to 

count toward the emission reduction goals, and to work with states to establish reasonable and 

appropriately streamlined measurement and verification requirements for such programs. 
36

5.1.4 State-driven portfolio approach

This section contains comments on the proposed state-driven portfolio plan approach for meeting

the emission guidelines.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Many commenters supported the state-drive portfolio approach.

Response 1: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters supported the state-driven portfolio approach for the following reasons:

• Gives states greater flexibility and discretion for developing their state 

plans.

• Allows easier incorporation of EE/RE measures. 

• Allows states to reduce emissions through a wide array of programs that 

improve the performance of the grid as a whole.

• Many states already have programs that could be included in a portfolio 

approach, including at least thirty states with enforceable renewable 

portfolio standards, at least seven states with policy goals to increase 
37

renewable power in their states, and almost all states have implemented 

energy efficiency programs. 

• Allows measures such as EGU repowering and retirements. 

• Provides maximum flexibility to take local circumstances, economics 

and state policy into account.

Commenters supported the state-driven portfolio approach because they believe states are better 

positioned to adopt and enforce measures such as energy-efficiency programs and building codes 

and standards. Commenters believed that states should have the primary role in implementing 

section 111(d). 

Commenters recommended that the EPA ensure that its proposed Section 111(d) guidelines can 

accommodate all of the different energy efficiency and renewable energy options, including 

energy efficiency standards that reduce demand now being satisfied by fossil plants, renewable 

energy standards that increase the amount of emission-free power on the grid, and dispatch rules 

that favor lower-carbon sources of energy over higher-carbon sources. Commenters

recommended the EPA clarify how states can include third party provided energy efficiency 

programs in state plans. Commenters stated that utilities are already implementing energy 

efficiency programs for their customers in a wide range of policy contexts and noted that some 

states have adopted formal energy savings requirements (e.g., an energy efficiency resource 

standard or EERS), some have set energy savings goals, some allow energy efficiency program 

funding and savings levels to be driven by integrated resource plans (IRPs), and some simply 

undertake energy efficiency program review and approval on an annual, biennial, or triennial 

basis, without any formal energy savings standards or goals. Commenters recommended the EPA 

allow all of these approaches to be included in state plans.

Comment 2: Comments stating that states should be able to modify EE programs in state-driven 

portfolio plans.

Response 2: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 
38

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

Under the state plan approaches discussed in the final rule, demand-side EE programs addressed 

in state plans could be modified over time. Under a state measures plan approach, such 

modifications, depending on their scope, could potentially require a modification to the state 

plan, if it substantially changed a state measure and how it is quantified and verified. Under a 

rate-based emission standards plan, energy efficiency programs could generate ERCs. 

Modifications to qualifying energy efficiency programs applying for the issuance of ERCs could 

require a resubmission of an eligibility application to the administering state regulatory body, but 

would not require a revision to the state plan. State plan approaches are described in section 

VIII.C of the preamble to the final rule. Requirements for rate-based emission trading programs 

are described in section VIII.K.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended that states be able to modify energy efficiency programs contained in 

state-drive portfolio plans during the implementation phase to ensure new technologies are 

incorporated and improvements in EM&V implemented. 

Comment 3: Comments stating that the EPA should allow credit for new natural gas plants in 

state portfolio plans

Response 3: In response to comments, particularly those raised about applying federally 

enforceable CAA requirements under a state plan to non-affected EGU entities, the EPA is not 

finalizing the portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is 

discussed in section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing 

other plan approaches that would allow the same types of measures outlined by the commenters 

to be included in state plans. This includes a rate-based emission standards plan, where such 

measures could be used to adjust the reported CO2 emission rate of an affected EGU, as part of 

federally enforceable emission standards for affected EGUs, and the state measures plan 

approach, where such measures could be included as state-enforceable measures under both a 

rate-based and mass-based plan approach. These plan approaches are described in sections 

VIII.C.2 and 3 of the preamble to the final rule. Eligible measures that may be used to adjust the 

reported CO2 emission rate of affected EGUs are described in section VIII.K.1 of the preamble 

to the final rule.

In addition, the EPA is not allowing crediting for generation from new NGCC units under a ratebased emission standards plan type. This prohibition, and the rationale for it, is discussed in 

section VIII.K.1.b of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:
39

Commenters recommended states using the portfolio approach be allowed to count the emissions 

avoided by using new natural gas plants that are not regulated under 111(d) for the same reasons 

it is permissible to count emissions avoided by new energy efficiency resources or new 

renewable energy resources, which are also not regulated under Section 111(d). Commenters

noted that allowing credit for new natural gas plants recognizes the carbon budget and 

commitment accounting principles, which are critical to ensuring efficiency and effectiveness in 

mitigating climate change.

Comment 4: Comments suggesting that state-portfolio approach applied to groups of states 

submitting joint plans.

Response 4: In response to comments, particularly those comments raised regarding applying 

federally enforceable CAA requirements under a state plan to non-affected EGU entities, the 

EPA is not finalizing the portfolio approach. The EPA’s rationale for not finalizing the portfolio 

approach is discussed in section VIII.C.6.d of the preamble to the final rule. However, the EPA 

is finalizing other plan approaches that will allow for multi-state plans, as well as coordination 

among states in the implementation of individual state plans. These approaches are described in 

section VIII.J.3 and VIII.K.4 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters believed that the portfolio approach could be applied to groups of states submitting 

joint plans provided they account for the total impact of all programs on sources within their 

boundaries.

Comment 5: Comments suggesting the state-portfolio approach is natural extension of state's 

baseline modeling.

Response 5: The EPA is not providing for the "baseline emissions projection pathway" available 

for SIPs under CAA section 110, as it is not applicable for state plans under CAA section 111(d), 

which must include standards of performance for affected EGUs. State plan approaches are 

described in section VIII.C of the preamble to the final rule, which includes a discussion of the 

legal basis for these plan approaches.

The following are summaries of the specific public comments under this comment:

Commenters stated they believe that most states will select the EPA's "[b]aseline emissions 

projection pathway" and believed portfolio programs will substantially limit Section 111(d) 

source emissions. Commenters stated that the portfolio approach is a natural extension of the 

baseline modeling states routinely do when developing state implementation plans for air quality 

programs and believe many existing programs can form an important foundation for developing 

state plans based on the portfolio approach. However, the commenters recommended regular 

program evaluations and necessary revisions to the portfolio.
40

Comment 6: General comments opposing the state-driven portfolio approach.

Response 6: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

In addition, a number of commenters raised questions that implied there would be challenges 

implementing a portfolio approach given their specific state circumstances. The portfolio 

approach was one of multiple plan approaches provided to states in the proposal, which a state 

could choose to use if it aligned with state circumstances and the regulatory structure in the 

electric power sector in a state. While the EPA is not finalizing the portfolio approach, the final 

rule provides multiple plan approaches, including multi-state approaches, that accommodate the 

wide range of measures currently being implemented in the electric power sector that reduce CO2

emissions, and a wide range of differing circumstances among states, including circumstances 

described by the commenters. Finally, many of the commenters asserted that the EPA is 

requiring states to direct the dispatch of affected EGUs through their state plans. This assertion is 

false. States could implement market-based emission standards as part of their state plan that 

would incent the generation shift of affected EGUs if it is economical to meet an emission 

standard. In all cases, the owner or operator of an affected EGU would retain the decision of 

whether to dispatch the affected EGU.

The following are summaries of the specific public comments under this comment:

Several commenters did not support a state-driven portfolio approach. Commenters stated that a 

state-driven portfolio approach would be unworkable because a state cannot mandate the 

redispatch of a NGCC unit owned by one utility in one RTO to offset the retirement or reduced 

dispatch of a coal unit owned by another utility in another RTO, even if both units are located in 

the same state. Commenters believed that states would have difficultly complying with a statedriven portfolio approach because of the obligations this approach places on states to 
41

enforcement renewable portfolio standards, customer energy efficiency standards and the EPA 

market intervention to curtail existing coal dispatch to favor the dispatch of (currently) more 

expensive existing NGCC resources. 

Commenters argued that state-driven approach is based on a misapprehension that the fleet of 

generation serving any given state is both diverse and interchangeable, regardless of unit 

ownership or even location within different RTOs. Commenters stated that redispatch in 

particular would be impractical for EGUs that are located in different RTOs. Commenters 

provided the following examples of situations in which they believe a state-driven portfolio 

approach would be impractical: 

• South Dakota has only one coal plant (Big Stone) that is owned by Otter 

Tail Power, Montana-Dakota Utility Resources, and NorthWestern 

Energy and one NGCC plant (Deer Creek) that is owned by Basin 

Electric Power Cooperative. Commenters also stated that the Big Stone 

plant is located in the MISO region, while Deer Creek will be located in 

SPP.

• Wyoming has 10 coal plants that qualify as "affected units" under the 

proposal and only one 95 MW NGCC plant, all with various and 

multiple owners. Commenters noted that one unit (LRS Unit 1) located 

in SPP, and the rest of the generation in the state are tied into the 

western grid managed by the Western Electricity Coordinating Council 

in the electrically separate western interconnection.

• Missouri River Energy Resources (MRES) have just begun the 

construction of the Red Rock Hydroelectric Project near Pella in Iowa 

with the goal of reducing or offsetting the MRES CO2 emissions rate at 

their LRS plant. Commenters noted that they have no affected units 

under the CPP located in Iowa. Commenters believed that it would be 

unjust if Iowa adopted a state portfolio approach that required RE and 

EE generated and saved by MRES in Iowa to be used to achieve 

reductions of CO2 emitted by other utilities that own and operate EGUs 

in Iowa. Commenters also argued that the state-driven portfolio 

approach establishes the framework for states to violate the Fifth 

Amendment because it would allow states to take MRES property 

without compensating MRES. 

Commenters expressed concern that the EPA has provided insufficient information about how a 

state-driven portfolio approach would work. Commenters asked how state agencies, public and 

private nonprofits, and electric distribution utilities could be assigned section 111(d)-related 

responsibilities and notes that integrated resource planning ("IRP") is not available to all states. 

Commenters asked how states that do not or cannot use the IRP process would implement a 

state-driven portfolio. Commenters believed more guidance and support from the EPA is 

necessary to help states recognize emissions reductions resulting from annual energy investments 

in energy efficiency and renewable energy investments made as a part of federal, state, and local 

public facilities retrofits utilizing Energy Savings Performance Contracting and other innovative 
42

implementation mechanisms. Commenters stated that programs operated by State Energy 

Offices, the U.S. Department of Defense, General Services Administration, and U.S. Department 

of Energy achieve $7 billion of energy efficiency and renewable energy investments annually 

and rely mostly on private sector financing.

Commenters believed the portfolio approach:

• Is more restrictive option than it appears to be because factors such as 

whether a state has deregulated its electricity sector and whether a state 

has a mandatory RPS or EERS dictate how a state can incorporate RE 

and EE measures into its state plan. 

• Does not resolve how the EPA can enforce measures against entities 

over which the EPA has no jurisdiction or the mechanism by which the 

EPA would enforce against entities that do not have permits.

• Does not "accommodate a diverse range of state approaches" since a 

state must either have a legally binding RPS or EERS, rather than a 

voluntary RE or EE target, or must have a vertically integrated 

electricity sector that engages in integrated resource planning. Both of 

these options involve regulating the electricity sector. 

Commenters were concerned that Indiana would not be able to successfully regulate, implement 

and enforce a state-driven portfolio approach because: (1) the legislature would be hostile to 

demand-side energy efficiency programs (commenters noted that Indiana has eliminated its 

demand side energy efficiency programs); and (2) regulating other entities would be complicated 

because more parties would be involved. Commenters noted that a portfolio approach may 

require action from the state legislature and from the Indiana Utility Regulatory Commission.

Commenters stated that a state-driven portfolio approach is unworkable because it is based on a 

misunderstanding that power plants serving any given state are interchangeable, regardless of 

unit ownership or even location within different RTOs. Commenters stated that a state cannot 

mandate the redispatch of a NGCC unit owned by one utility in one RTO to offset the retirement 

or reduced dispatch of a coal unit owned by another utility in another RTO, even if both units are 

in that state. Commenters asserted that redispatch, could not be achieved because the two plants 

are in separate RTOs.

Comment 7: Comments suggesting that the state-driven approach is unconstitutional.

Response 7: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 
43

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

See the Legal Memorandum accompanying this rule for the EPA's discussion of the commenters' 

hypothetical concerns about the Contract Clause and Just Compensation Clause of the U.S. 

Constitution.

The following are summaries of the specific public comments under this comment:

Commenters stated that a state cannot compel a multi-state utility to reallocate to that state's 

portfolio the renewable energy credits or energy efficiency credits from the utility's out-of-state 

generation resources that the utility or another state is using toward compliance with the rule in 

the other state. Commenters believed that such as action by a state would be an "unconstitutional 

taking of the utility's property or abrogation of the utility's contracts."

Comment 8: Comments suggesting that the enforcement of EE programs in a state-driven

portfolio plan would be challenging.

Response 8: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 
44

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

In the final rule, energy efficiency mandates on electric distribution utilities (e.g., an EERS) 

could be included by a state as a state-enforceable measure under a state measures plan. In this 

example, such requirements apply to electric distribution utilities, which must design and 

implement energy efficiency deployment programs to achieve a certain amount of annual energy 

savings, as a percentage of annual utility sales. Many states currently have such requirements.

The following are summaries of the specific public comments under this comment:

Commenters were concerned about how energy efficiency mandates would be made enforceable 

under a portfolio approach when it is the customers' decision to undertake an energy efficiency 

measure. Commenters noted that emission reductions obtained through energy efficiency depend 

largely on customer investment and behavioral change and whether end-use consumers can be 

required under a state plan to undertake energy efficiency measures.

Comment 9: Comments suggesting that the EPA should allow states to use performancecontracting for demand-side EE and RE.

Response 9: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

Performance contracting approaches for both renewable energy and end-use energy efficiency 

could be incorporated under both a rate-based emission standards plan and as state measures 

under a state measures plan. These approaches are described in section VIII.K.1 of the preamble 

to the final rule.
45

The following are summaries of the specific public comments under this comment:

Commenters recommended that states include performance-contract EE and RE programs in 

their state-driven portfolio plans. Commenters also noted that states have already adopted 

performance contracting enabling legislation that would make it easy for states to include this 

approach in state-driven portfolio approach. Commenters stated that additional guidance was 

needed for states to have confidence that the EPA will recognize energy efficiency savings and 

distributed renewable energy generation delivered by performance contracting projects and also 

encouraged the EPA to approve state plans that include them. Commenters also suggested that 

the final rule:

• Identify performance-contracting as a possible compliance pathway for 

inclusion of EE and RE state plans;

• Recognize existing performance contracting EE and RE activities;

• Require states to identify sources targeted for performance-contracting

projects (e.g., state-owned, hospitals, universities, etc.);

• Require a state or national registry be set up to track avoided emissions 

from performance-contract projects;

• Identify key compliance criteria, including M&V protocols, auditing 

requirements, evaluation methods, and corrective measures;

• Allow states to take credit for actions taken after the Clean Power Plan 

was proposed and before the interim compliance period begins (2020), 

count that credit toward achievement of the state's compliance 

obligation;

• Address the stranded emission reductions penalty created when energy 

efficiency projects are implemented in electricity-importing states;

• Encourage use of tradable credits for EE and RE projects.

Comment 10: Comments suggesting that a state-driven portfolio approach that includes redispatch would be unconstitutional.

Response 10: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 
46

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The commenters’ assertion that the EPA is requiring states to direct the dispatch of affected 

EGUs through their state plans is false. States could implement market-based emission standards 

as part of their state plan that would incent the generation shift of affected EGUs if it is 

economical to meet an emission standard. In all cases, the owner or operator of an affected EGU 

would retain the decision of whether to dispatch the affected EGU. For more background, see the 

discussion of the Just Compensation Clause in the Legal Memorandum accompanying the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters argued that a state-driven approach that includes redispatch would be unworkable 

because the EPA cannot by rule give states the right to order redispatch of separately owned 

facilities "without violating basic legal and constitutional principles." Commenters believed that 

a state could not order private parties to operate their resources to meet the State's objectives 

because such an order would constitute a confiscation of private resources without 

compensation, in violation of the Fifth Amendment's Takings Clause.

Comment 11: Comments suggesting that entities regulated under the portfolio approach should 

be exempt from future regulation.

Response 11: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 
47

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA must include protections to ensure that entities regulated under 

a portfolio approach are not unfairly penalized by any future NSPS program rules. Commenters

noted that the largest consumers of electricity may have demand-side energy efficiency measures 

imposed on them under a portfolio approach. Commenters argued that if the EPA decided to also 

establish section 111 GHG standards of performance, then these same sources would be subject 

to two sets of potentially duplicative, inconsistent or incompatible requirements. Commenters

believed it is important the EPA address this issue by either: (1) including a provision in the final 

rule that exempts affected entities from future standards of performance issued under Section 

111 if they are subject to legally binding emission reductions under a State implementation plan; 

or (2) ensure that sources subject to regulation under a Section 111(d) portfolio approach will 

receive full credit for GHG emission reduction activities if new standards of performance for 

GHG emissions are imposed. 

Comment 12: Comments recommending sources subject to demand-side EE programs under 

state-driven portfolio plans be exempted from any future regulation under NSPS for GHG 

emissions.

Response 12: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.
48

The following are summaries of the specific public comments under this comment:

Commenters stated that any sources regulated under a portfolio approach (e.g., state imposed 

demand-side energy efficiency measures) should be exempt from or given credit toward any 

subsequent GHG regulations if the EPA expands the NSPS program. Commenters noted that the 

"U.S. Environmental Protection Agency Fiscal Year 2015 Justification of Appropriation 

Estimates for the Committee on Appropriations" is seeking appropriations to consider GHG 

emission limits for petroleum refining, pulp and paper facilities, municipal solid waste landfills, 

iron and steel production, animal feeding operations, and Portland cement manufacturing. 

Commenters were concerned that a source could become subject to future regulation under an 

NSPS for GHG emissions, when they are already subject to requirements under a state’s 

portfolio plan. Commenters were particularly concerned about percentage-based standards of 

performance that require sources to reduce emissions to x percent below some historical average. 

Because the emission reduction approaches identified in a BSER analysis are likely to be similar 

to those that would be targeted in a State portfolio approach, Commenters believed it is possible 

that sources located in States that adopt a portfolio approach would have already implemented 

some or all of the pollution control technologies identified. Commenters believed it would be 

arbitrary and capricious to require a source to install additional pollution control measures under 

future rulemakings if it has already installed measures to comply with a CPP state-driven 

portfolio plan.

Comment 13: Comments questioning if affected EGUs would be required to assume part of the 

responsibility for compliance under a state-driven portfolio approach

Response 13: Under the proposed portfolio approach, a state could have used a wide range of 

measures, including utility-administered RE and demand-side EE deployment programs, as well 

as other requirements and programs implemented by states. Under the portfolio approach, these 

plan measures would have been federally enforceable requirements that apply to non-EGU 

entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:
49

Commenters asked whether it is EPA's intent that each affected EGU have an emission limitation 

and assume part of the responsibility for compliance. Commenters were concerned the EPA's 

state-driven portfolio approach will put all the compliance burden on the state to reduce 

CO2 emissions under Section 111(d).

Comment 14: Numerous commenters supported state plans that include state commitments for 

EE and RE programs.

Response 14: Under the proposed portfolio approach, a state could have used a wide range of 

measures, such as those described by the commenters, in a state plan. This includes utilityadministered RE and demand-side EE deployment programs, as well as other requirements and 

programs implemented by states. Under the portfolio approach, these plan measures would have 

been federally enforceable requirements that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The EPA is not finalizing the state commitment approach, which is a variant of the portfolio 

approach. The EPA is finalizing the state measures approach, which provides for similar plan 

measures, but with federally enforceable backstop emission standards for affected EGUs that 

would be triggered if the state measures do not achieve the required level of emission 

performance for affected EGUs. As a result, the state measures plan approach provides similar 

flexibility as the state measures approach, but while assuring that the requirements of the 

emission guidelines are achieved. The state measures approach, and the EPA’s rationale for 

finalizing this approach, is described in section VIII.C.3 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters supported the state commitments option. Commenters supported state 

enforceable commitments because they believe they are a useful compliance planning tool for 

section 111(d) EGU plans and because they give states flexibility to continue to innovate and 

improve programs. Commenters stated they believed the state commitment approach would 

encourage participation in state programs because participants would no longer be concerned 

about federal enforcement under the Clean Air Act. Commenters believed this approach help 
50

incentivize states to use RPS and other state programs as compliance tools, and would facilitate 

the use of renewable energy. Commenters believed a state commitment approach is necessary 

because they believe it is not practical to make "outside the fence" measures federally 

enforceable against third parties. Commenters noted that this approach recognizes that when 

multiple measures produce emissions reductions, not all of the measures need be federally 

enforceable. Commenters noted that as an example, a statewide emission cap on EGUs could be 

supported by various energy efficiency and renewable energy policies, but the cap itself would 

be the only measure that must be federally enforceable because compliance with the cap 

accounts for the effects of the other programs. Commenters believed that regular reporting and 

contingency plans can ensure the state makes continuous progress towards meeting federal 

targets and noted that the proposed rule already includes CEMS monitoring for covered EGUs.

Commenters supported the state of Michigan commitment approach because they already have 

state RE and EE requirements that they would like to count toward compliance, but do not 

necessarily want to mandate these requirements as part of the state's section 111(d) plan. 

Commenters encouraged the EPA to finalize a rigorous state commitment-based approach as an 

option for state planning because they believe this approach enhances state's ability to deliver the 

required reductions. Similarly, commenters believed the state commitment approach to be the 

most efficient and effective method for a state to achieve its CO2 goals.

Commenters believed that many states, including their own state of Washington, would prefer to 

commit to achieving certain reductions and be held accountable to those reductions through the 

operation of renewable energy and energy efficiency programs, without making the specific 

provisions of those programs federally enforceable. Commenters believed that a commitment 

approach should be included because some states may be concerned about including state energy 

programs in their federally enforceable compliance plans. 

Commenters believed that states would be primarily committing to implementing established 

programs that are already resulting in substantial emission reductions, which means that more 

data, and experience are available to support projected emission reductions. As a result, 

commenters believed that the EPA should approve larger commitments where states have 

properly supported their proposed program by careful analysis. Commenters believed that larger 

commitments are appropriate because Congress's endorsement of substantial state flexibility in 

section 111 (d) planning. 

Commenters believe that state energy efficiency and renewable energy programs implemented or 

expanded for purposes of compliance should not be under EPA's direct enforcement authority or 

evaluated for 'adequacy' by EPA during plan approval. Commenters asserted that the state plans 

should provide sufficient assurance that overall emission targets will be met. 

Commenters supported the state commitment approach because they believe Federal 

enforceability reduces a state's flexibility to modify these programs to continue achieving state 

objectives. Commenters believed the state commitment approach would avoid repeated review, 

approval and maintenance of state 111(d) plans. Commenters stated that cap-and-trade and 

energy sector programs are complex and have to be regularly adjusted through state rulemakings, 

which would be difficult to manage if these programs became subject to additional federal 
51

oversight. Commenters supported the state commitment approach because it would avoid EPA 

enforcement of energy efficiency policies and programs included in state Section 111(d) plans. 

Commenters noted that without the state commitment approach the rule would limit the state's 

ability to modify energy efficiency policies and programs as conditions change and could result 

in enforcement actions if efficiency policies and programs are not as successful as initially 

hoped. Commenters noted that energy efficiency policies and programs are typically reviewed 

and modified at least once every five years. Commenters believed that it is essential that the EPA 

allow for modifications in energy efficiency policies and programs over time if it wants to 

encourage states to take maximum advantage of energy efficiency as a compliance strategy and 

that states should be allowed to modify their energy efficiency policies and programs without 

formal approval of the EPA as long as they comply with rules regarding which types of programs 

are eligible for savings credits, follow EM&V guidance, and take steps to prevent double 

counting of energy savings. Commenters noted that without a state commitment approach the 

rule discourages states from including energy efficiency initiatives in state Section 111(d) plans. 

Commenters recommended the EPA clarify that enforcement actions on individual energy 

efficiency policies and programs will not be taken and are not allowed as long as a state's 

emissions rate targets are being met.

Commenters recommended that states and EPA regional offices should decide which particular 

measures must be reflected in enforceable plans. Commenters wanted the EPA to work with 

states and stakeholders to determine what requirements would be needed for a state commitment 

plan, including EGU-specific measures to ensure electrical reliability and the smooth functioning 

of the market. Commenters also requested the EPA allow a wide range of backstop designs in 

state compliance plans to ensure that any compliance shortfalls from non-EGU specific programs 

are minimized. Commenters noted that these programs have the greatest potential to provide the 

most effective emissions and energy savings.

Commenters believed that a state commitment approach could also benefit other states which are 

considering enhanced energy sector programs. Commenters stated that state energy regulators

are also more likely to support a commitment approach with its balance between accountability 

and policy discretion and that energy regulators in many states have decades of experience and 

well-established policies in place to provide the accountability required in a 111 (d) compliance 

plan. 

Commenters recommended the "state commitment approach" be included as part of a new 

approach to implement Building Block 4 as "best management practices". 

Commenters recommended that a mass-based approach backed by state commitments (typically 

enforced through state legislation) should be allowed as this would provide for state flexibility 

while assuring the state goals are met and verifiable. Commenters suggested the state plan be 

allowed to serve as a "standard of performance" on its own, provided the state takes 

responsibility for meeting the goals upon itself as an entity. Commenters suggested the state's 

responsibility for its plan should be allowed for the portfolio approach or the state plan with 

commitments approach. 
52

Comment 15: Comments suggesting that section 110 of the Clean Air Act provides legal 

precedent for the state commitment approach.

Response 15: The EPA is not finalizing the state commitment approach.

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters believed there is legal precedent for using the state commitment process and stated 

that the EPA has previously approved several state implementation plans (SIPs) under Section 

110 of the Act that are structured using this commitment approach, including plans in California, 

Texas and New York. Commenters noted that these SIPs contain target-level emission reduction 

commitments; an accounting mechanism to provide for state air quality program equivalency 

demonstrations; and robust evaluation, monitoring and verification (EM&V) strategies.

Comment 16: Comments suggesting that the state commitment approach would make it easier 

for California to integrate section 111(d) guidelines with existing state programs.

Response 16: The EPA is not finalizing the state commitment approach. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.
53

The EPA believes that the state measures plan approach provides the flexibility to implement 

programs such as those in California mentioned by the commenter, and provide states with the 

ability to harmonize their energy and environmental policy mandates while meeting the emission 

guidelines.

The following are summaries of the specific public comments under this comment:

Commenters believe a commitment approach would be useful to California since it would be 

easier to integrate section 111(d) guidelines with its other programs. Commenters stated that 

commitment approach avoids direct federal enforcement of state energy programs, which helps 

place the task of harmonizing energy and environmental policy mandates at the state level. 

Commenters also noted that California's commitments would be supported by state enforcement 

authority under the following existing state laws and regulations:

• California's GHG programs contain specific reporting requirements, 

reduction targets, and deadlines for these targets to be achieved. 

• California's regulatory agencies have broad authority to enforce these 

GHG reduction measures (e.g., California law imposes significant 

criminal and civil penalties, as well as injunctive relief for violations of 

AB 32)

• California's RE standards require regulated entities to provide regular 

reports on compliance with RE requirements and requires regulatory 

agencies to enforce an entity's failure to comply. 

• The California Public Utilities Commission oversees and enforces RE 

standards applicable to investor-owned utilities, and the California 

Energy Commission and the ARB enforce the RE requirements with 

regard to local publicly-owned utilities. 

Comment 17: Comments suggesting that EPA recognition of complementary measures will help 

states design commitment-based plans.

Response 17: The EPA acknowledges the comment. Under a plan that includes a mass-based 

emission budget trading program, RE and demand-side EE are complementary measures that do 

not need to be included in a state plan. Even though not included in a plan, these measures will 

reduce CO2 emissions, helping affected EGUs meet the established emission budget. 

Alternatively, states may choose to implement a mass-based state measures plan type, where 

state measures, which may include RE and demand-side EE, are used to achieve a state mass 

CO2 goal. Under that plan approach, those state measures are included as part of the plan but are 

not federally enforceable. These topics are discussed in the preamble to the final rule in sections 

VIII.C and VIII.J.

The following are summaries of the specific public comments under this comment:
54

Commenters supported provisions that allow the EPA to recognize certain energy programs as 

"complementary" measures, because recognition of complementary measures will help states to 

design their state plans. Commenters stated that support this approach because it recognize that 

when multiple measures produce emissions reductions, not all of the measures need be federally 

enforceable. Commenters stated that as an example, a statewide emission cap on EGUs may be 

supported by various energy efficiency and renewable energy policies, but the cap itself may be 

the only measure that must be federally enforceable, since it accounts for the effects of the other 

programs. Commenters stated that this sort of analysis will help states design appropriate federal 

compliance strategies, while maintaining room for continued state-level program development to 

support their required emissions reductions.

Comment 18: Comments suggesting state commitment-based plans should have "backstop" 

requirements to ensure compliance with state goals.

Response 18: In response to comments, particularly those raised about applying federally 

enforceable CAA requirements under a state plan to non-affected EGU entities, the EPA is not 

finalizing the portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is 

discussed in section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing 

other plan approaches that would allow the same types of measures outlined by the commenters 

to be included in state plans. This includes a rate-based emission standards plan, where such 

measures could be used to adjust the reported CO2 emission rate of an affected EGU, as part of 

federally enforceable emission standards for affected EGUs, and the state measures plan 

approach, where such measures could be included as state-enforceable measures under both a 

rate-based and mass-based plan approach. These plan approaches are described in sections 

VIII.C.2 and 3 of the preamble to the final rule. Eligible measures that may be used to adjust the 

reported CO2 emission rate of affected EGUs are described in section VIII.K.1 of the preamble 

to the final rule.

In lieu of the portfolio approach, which the EPA is not finalizing, the EPA is finalizing the state 

measures plan approach. The state measures approach would provide for implementation of 

similar state and utility approaches for reducing CO2 emissions from affected EGUs as under the 

portfolio approach. However, under the state measures approach, these measures would be state 

enforceable and would be coupled with federally enforceable emission standards for affected 

EGUs that would be triggered if the required level of CO2 emission performance for affected 

EGUs is not achieved through the state measures. The state measures approach is described in 

section VIII.C.3 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters supported state-driven portfolio plans but believe that any plan adopting a 

"portfolio" of measures must also include federally enforceable emission limitations that require 

affected EGUs to demonstrate compliance with the relevant standards of performance in the 

event that the portfolio measures fail to deliver the required emission reductions. Commenters 

stated that "backstops" in state plans would require covered entities to make up the difference in 

emissions if the state falls short of its state commitments and should be automatically triggered 
55

when a short fall occurs. Commenters recommended state plans included detailed criteria for 

when the "backstops" will be implemented and could be based on tonnage reports from CEMS 

compared to the commitment trajectory. Commenters stated that as an example of a possible 

"backstop" measure, covered EGUs could be required to retire additional carbon allowances, 

acquire RECs to offset their emissions, or take similar actions. Commenters suggested that 

"backstop" provisions could be triggered when a state's emissions from affected EGUs 

significantly exceed its projected emission performance glide path for more than one year, 

including years after any interim contingency measures have been put into effect.

Commenters stated that "backstop" provisions could take the form of a requirement that 

regulated EGUs make sufficient reductions or secure sufficient credits from re-dispatch, 

renewable energy generation, and energy efficiency activities to make up the shortfall within the 

same compliance year. Commenters stated that the obligation to make up the shortfall, could be 

allocated among sources in any manner acceptable to the state. Commenters stated that the state 

should be allowed to choose the mechanism for the federally enforceable "backstop" limit and 

that it could take the form of a mass-based allowance system or a rate-based averaging system. 

Commenters stated that interim contingencies could include expansions of state program 

commitments, such as committing more of the underlying resource savings from an existing 

energy efficiency resource standard, or scaling up the state programs themselves if all underlying 

resources have been committed.

Commenters stated that "backstop" measures could be included in operating permits and should 

be enforceable by citizen suit and by the EPA under section 113 against covered EGUs when the 

criteria for implementing "backstops" are met and noted that such enforcement provisions would 

provide strong incentives to meet the commitments by both covered EGUs and states. 

Commenters recommended that if the commitment program covers a broader range of entities, 

the commitments should be reviewed and monitored with greater care and include contingency 

plans that will be triggered if the anticipated reductions do not fully materialize. Commenters

also stated that state plans that include commitments must clearly state the types of contingency 

measures that will be triggered when the emission reductions are not met.

Commenters recommended the EPA ensure that state commitment plans are either composed of 

specific federally enforceable components or contain backstops that are federally enforceable. 

Commenters considered enforceability to be a key element necessary to ensure the integrity of 

the Clean Power Plan and noted that enforceability is explicitly provided for in Section 111(d) 

(specifically 42 U.S.C. 7411(d)(1)(B) requiring state plans to "provide . . . for the 

implementation and enforcement of standards of performance" established under section 111(d)). 

The commenters said state plans composed of an emission rate trading program, an allowance 

trading program, or other requirements that apply directly to sources will provide a clear and 

traditional enforcement pathway, but expressed concern state commitment approach takes a 

different approach in which third parties other than emitting EGUs (including the state itself) 

could be responsible for emission reductions under a state plan. In order to satisfy the 

enforceability requirements of the statute and to ensure the environmental integrity of the 

standards, the commenter recommended the EPA either: (1) specific measures must be federally 

enforceable (e.g. the state's renewable portfolio standard becomes federally enforceable, or the 

delivery of a specific quantity of demand-side energy efficiency [kW of demand reduced] by an
56

energy efficiency program becomes federally enforceable); or (2) the state plan must include 

federally enforceable, backstop policy measures that will be automatically triggered and take 

effect without further action by the state or EPA should the state fail to achieve its required 

emission budget or rate by more than a de minimis percentage at any required reporting deadline. 

The commenters said the backstop must be designed by the state to secure at minimum the 

shortfall in the required emission reductions, and should apply directly to the regulated sources. 

As an example of possible backstop requirements, the commenters said that regulated sources 

could be required to secure renewable energy credits sufficient to make up the shortfall within a 

year and a half of the compliance deadline. Commenters said that such backstop requirements 

should be included in the operating permits of the regulated entities as part of the section 111(d) 

standard of performance, and would be federally enforceable by the EPA and through citizen 

suits under sections 113 and 304 of the Act, respectively. Commenters added that backstops 

would allow states to satisfy the requirement that state plans contain enforceable measures, while 

also preserving flexibility for states to adopt state commitments or portfolio approaches that are 

not themselves federally enforceable. Commenters said that backstops would provide regulated 

sources with certainty about the implications of any failure of the state to meet its compliance 

obligations. The commenters also noted that it would be important for states to take corrective 

measures to ensure that the compliance failure was not repeated. 

Comment 19: Comments suggesting that measures already implemented by state should not be 

federally enforceable.

Response 19: The approach described by the commenters is inconsistent with CAA section 

111(d), which requires states to establish standards of performance for affected EGUs. The state 

plan approaches finalized by the EPA fully accommodate the current range of existing state 

programs, under either an emission standards or state measures plan approach. State plan 

approaches are described in section VIII.C of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA recognize some measures now in force represent baseline 

measures that need not themselves be federally enforceable because they are already in force,

have been incorporated into state policy, and reflect the status quo. 

Commenters further stated that EPA had already recognized existing state programs in the 

"baseline pathway" of the roadmap for integrating renewable energy and energy efficiency into 

criteria pollutant plans, and recommended that EPA do the same in the Clean Power Plan.

Commenters added that states should have obligations to report changed circumstances to the 

EPA, but the programs should otherwise form part of the baseline analysis rather than be treated 

as new enforceable measures.

Comment 20: Comments suggesting the state commitment approach creates incentive for states 

to work with regulated entities.
57

Response 20: The EPA is not finalizing the state commitment approach. Under the proposed 

portfolio approach, a state could have used a wide range of measures, such as those described by 

the commenters, in a state plan. This includes utility-administered RE and demand-side EE 

deployment programs, as well as other requirements and programs implemented by states. Under 

the portfolio approach, these plan measures would have been federally enforceable requirements 

that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended that a properly designed state commitment approach should include 

incentives for state planners and covered entities to work together to secure reductions from the 

electric system as a whole and recommended the EPA only approve plans that are rigorous and 

include such incentives. 

Comment 21: Comments regarding state-commitments and RE/EE trading with other states.

Response 21: The EPA is not finalizing the state commitment approach. Under the proposed 

portfolio approach, a state could have used a wide range of measures, such as those described by 

the commenters, in a state plan. This includes utility-administered RE and demand-side EE 

deployment programs, as well as other requirements and programs implemented by states. Under 

the portfolio approach, these plan measures would have been federally enforceable requirements 

that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 
58

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

In addition, the EPA is providing for a range of multi-state plan approaches and multi-state 

coordination in the implementation of individual state plans. These approaches are described in 

section VIII.C.5 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended states that make individual commitments to emissions reductions be 

able to design state plans that rely in part on particular actions in other states for which both 

states have agreed credit is to be reallocated. If state A commits to reductions which are achieved 

in part by the operation of a renewable energy source in state B, then the commenters believed

state A should be able to take credit for the emissions reductions in state B provided the total 

reductions are underwritten by a federally enforceable commitment in both states and appropriate 

contingency measures and backstops are included. Although the analysis to support such plans is 

likely more complex than that required for allowance systems, the commenters believed the EPA 

should allow states to incorporate this type of approach into their section 111(d) plans.

Comment 22: Comments suggesting that states should have discretion in enforcement of RE/EE 

programs.

Response 22: The EPA is not finalizing the state commitment approach. Under the proposed 

portfolio approach, a state could have used a wide range of measures, such as those described by 

the commenters, in a state plan. This includes utility-administered RE and demand-side EE 

deployment programs, as well as other requirements and programs implemented by states. Under 

the portfolio approach, these plan measures would have been federally enforceable requirements 

that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.
59

The following are summaries of the specific public comments under this comment:

Commenters supported the state commitment approach but believed state should be given the 

discretion to decide which state agency will have the authority to enforce the requirements for 

RE and EE programs.

Comment 23: Comments suggesting that a broader approach to state commitments would 

provide greater flexibility to states.

Response 23: The EPA is not finalizing the state commitment approach. Under the proposed 

portfolio approach, a state could have used a wide range of measures, such as those described by 

the commenters, in a state plan. This includes utility-administered RE and demand-side EE 

deployment programs, as well as other requirements and programs implemented by states. Under 

the portfolio approach, these plan measures would have been federally enforceable requirements 

that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters supported the state commitment approach. Commenters stated that they consider 

the proposed limited state commitment approach under which the state assumes responsibility for 

and credits EGUs with the amount of emission reductions expected to be achieved from RE or 

demand-side EE measures to be too restrictive. Commenters stated that support a broader state 

commitment approach that would provide greater flexibility to states.

Comment 24: Comments requesting clarification on incorporating voluntary programs into state 

plans

Response 24: The EPA believes the commenters, in describing "voluntary" measures, are

referring to incentive programs to accelerate the deployment of technologies and practices, such 

as RE and demand-side EE technologies. Such programs could be incorporated in either a rate-
60

based emission standards plan approach or a state measures plan approach. Plan approaches are 

described in section VIII.C of the preamble to the final rule. Eligible measures that could be used 

to adjust the reported CO2 emission rate of an affected EGU are described in section VIII.K.1 of 

the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters wanted to know how states could incorporate energy efficiency measures into their 

section 111(d) implementation plans without imposing a federally enforceable obligation on the 

entities implementing those measures. Commenters also asked whether the EPA would allow 

states to include "voluntary" measures (such as programs that change building occupant behavior 

or incentivize private sector investment in energy efficiency) that are not enforceable against a 

particular source or implementing party in their section 111(d) plans, and if so, whether there 

will be any restrictions on the amount of credit allocated for such measures and whether 

additional EM&V requirements would apply. 

Comment 25: Comments stating that the EPA provided insufficient information on the proposed 

state commitment approach.

Response 25: The EPA is not finalizing the state commitment approach. Under the proposed 

portfolio approach, a state could have used a wide range of measures, such as those described by 

the commenters, in a state plan. This includes utility-administered RE and demand-side EE 

deployment programs, as well as other requirements and programs implemented by states. Under 

the portfolio approach, these plan measures would have been federally enforceable requirements 

that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters noted that they had difficulty understanding the two different options for state 

commitment plans described in the proposal and wanted the EPA to provide more specificity as 

to how, and what level of detail, would be required in the state plan under either option. 
61

Commenters stated that information regarding these two options is insufficient for them to be 

able to provide meaningful comments and asked the following questions:

• How do the two options differ?

• Would state plans that include one of the state commitment options have 

to include approved components such as EM&V?

• Would the "full responsibility for achieving the emission performance 

level" be applied to the EGU and would the EGU in return receive a rate 

indicative of the performance expected as a result of HRIs and EE/RE? 

• Would state commit to crediting a certain amount of EE/RE from a 

"state pool" and if so how would this work? 

• What if the state's EE/RE pool does not produce as expected? Is the 

EGU out of compliance or is the state subject to enforcement? 

Comment 26: Comments requesting guidance on measures, emissions, and enforcement in a 

state commitment approach.

Response 26: The EPA is not finalizing the state commitment approach. Under the proposed 

portfolio approach, a state could have used a wide range of measures, such as those described by 

the commenters, in a state plan. This includes utility-administered RE and demand-side EE 

deployment programs, as well as other requirements and programs implemented by states. Under 

the portfolio approach, these plan measures would have been federally enforceable requirements 

that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters wanted clarification on the following issues related to the state commitment 

approach:
62

• What types of state commitments would be acceptable?

• What quantity of emissions could be included as part of a state 

commitment? 

• How would a state commitment be structured?

• How would a state commitment be enforced?

Comment 27: Comments regarding "rate-of-progress" provisions in State Commitments.

Response 27: The EPA is not finalizing the state commitment approach. Under the proposed 

portfolio approach, a state could have used a wide range of measures, such as those described by 

the commenters, in a state plan. This includes utility-administered RE and demand-side EE 

deployment programs, as well as other requirements and programs implemented by states. Under 

the portfolio approach, these plan measures would have been federally enforceable requirements 

that apply to non-EGU entities. 

In response to comments, particularly those raised about applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be 

included in state plans. This includes a rate-based emission standards plan, where such measures 

could be used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan approach, where 

such measures could be included as state-enforceable measures under both a rate-based and 

mass-based plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters expressed concern that if Texas includes a renewable program, an efficiency 

program or an improvement in the utilization rate of gas plants in its section 111(d) plan, the 

EPA would consider these to federally enforceable. Commenters stated that Texas legislators do 

not want to mandate that a specific percentage of its energy comes from gas, efficiency or 

renewable energy. Commenters asked whether a state commitment that uses market trends to 

develop "a rate-of-progress-like provision" would be acceptable. Commenters suggested that 

under such a provision, Texas would report on its rate of adoption during the implementation 

period and promise to review and modify its plan if targets are not met. 
63

Comment 28: Comments suggesting enforcement against non-EGUs may deter states from 

selecting the portfolio approach. 

Response 28: In response to comments, in particular comments raised about applying federally 

enforceable CAA requirements under a state plan to non-affected EGU entities, the EPA is not 

finalizing the portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is 

discussed in section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing 

other plan approaches that would allow the same types of measures outlined by the commenters 

to be included in state plans. This includes a rate-based emission standards plan, where such 

measures could be used to adjust the reported CO2 emission rate of an affected EGU, as part of 

federally enforceable emission standards for affected EGUs, and the state measures plan 

approach, where such measures could be included as state-enforceable measures under both a 

rate-based and mass-based plan approach. These plan approaches are described in sections 

VIII.C.2 and 3 of the preamble to the final rule. Eligible measures that may be used to adjust the 

reported CO2 emission rate of affected EGUs are described in section VIII.K.1 of the preamble 

to the final rule. Requirements for rate-based emission trading programs are described in section 

VIII.K.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters expressed concern that the portfolio option may not be a practical option for many 

states and may be more challenging to implement and enforce than a plan with requirements 

assigned only to affected EGUs because RE and demand-side EE measures in state plans would 

be federally enforceable.

Commenters stated that such enforceability concerns, whether apt or not, (including citizen suit 

liability associated with these programs under the portfolio plan design) could deter many states 

from opting for the portfolio approach. Commenters stated that it would be unfortunate if these 

perceived plan design challenges slowed needed emissions reductions. Commenters stated that 

EPA could make the portfolio approach more attractive by recognizing that the obligations on 

affected entities in these programs may be imposed at a high level (e.g., a federally-enforceable 

obligation to participate in a state energy program, rather than federal enforcement of each 

individual program element).

Comment 29: Comments suggesting that the EPA should provide guidance to states on how to 

incorporate state EE programs without those measures becoming federally enforceable.

Response 29: In response to comments, in particular comments raised about applying federally 

enforceable CAA requirements under a state plan to non-affected EGU entities, the EPA is not 

finalizing the portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is 

discussed in section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing 

other plan approaches that would allow the same types of measures outlined by the commenters 

to be included in state plans. This includes a rate-based emission standards plan, where such 

measures could be used to adjust the reported CO2 emission rate of an affected EGU, as part of 

federally enforceable emission standards for affected EGUs, and the state measures plan 
64

approach, where such measures could be included as state-enforceable measures under both a 

rate-based and mass-based plan approach. These plan approaches are described in sections 

VIII.C.2 and 3 of the preamble to the final rule. Eligible measures that may be used to adjust the 

reported CO2 emission rate of affected EGUs are described in section VIII.K.1 of the preamble 

to the final rule. Requirements for rate-based emission trading programs are described in section 

VIII.K.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters requested that the EPA provide additional guidance on how states can include 

energy efficiency measures in their plans without those measures becoming federally 

enforceable. Commenters argued that states are concerned about including energy efficiency 

programs and measures in their Section 111(d) plans due to the prospect of having those 

programs and measures become federally enforceable. Commenters outlined the EPA's proposal 

which stated that states can avoid this problem by adopting "complementary" programs that 

would not be enforceable components of the plan but would be used to facilitate achievement of 

the required emission performance levels by affected EGUs. Commenters suggested that another 

approach states could use is inclusion of a panopoly of compliance measures in the state plan, the 

aggregate impact of which exceeds the required emission reductions. Commenters stated that this 

over-compliance would allow states to later drop one or more measures without causing a 

compliance/enforcement problem. Commenters also suggested that the EPA allow states to 

include "voluntary" measures in their Section 111(d) plans that are not enforceable against the 

implementing entity but can be used to receive some credit toward compliance with the 

emissions guidelines. Commenters stated if EPA does approve inclusion of voluntary measures 

for credit, they can introduce additional mechanisms to ensure that emission targets are met in 

the event that the voluntary measure does not result in the anticipated emission reductions.

Commenters also argued that the EPA should require state plans to include contingencies in the 

event that energy efficiency initiatives are less effective than predicted. Commenters stated that 

each state plan should include an automatic fall back plan (be self-correcting) or identify 

corrective measures to employ if milestones are not met.

5.1.5 Utility-driven portfolio approach

This section contains comments on the proposed utility-driven portfolio plan approach for 

meeting the emission guidelines.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Some commenters supported the utility-driven portfolio approach.

Response 1: In response to comments, specifically comments raised about applying federally 

enforceable CAA requirements under a state plan to non-affected EGU entities, the EPA is not 
65

finalizing the portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is 

discussed in section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing 

other plan approaches that would allow the same types of measures outlined by the commenters 

to be used in state plans. This includes a rate-based emission standards plan, where such 

measures could be used to adjust the reported CO2 emission rate of an affected EGU, as part of 

federally enforceable emission standards for affected EGUs, and the state measures plan 

approach, where such measures could be included as state-enforceable measures under both a 

rate-based and mass-based plan approach. These plan approaches are described in sections 

VIII.C.2 and 3 of the preamble to the final rule. Eligible measures that may be used to adjust the 

reported CO2 emission rate of affected EGUs are described in section VIII.K.1 of the preamble 

to the final rule. Requirements for rate-based emission trading programs are described in section 

VIII.K.2 of the preamble to the final rule.

The EPA disagrees with the commenters that the other plan approaches provided for in the final 

rule are not viable and has provided a detailed discussion of the design of these approaches and 

their implementation in section VIII of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters support the utility-driven portfolio approach. Commenters believe a utility-driven 

portfolio approach is workable because direct emission limits cannot be effectively imposed and 

met by existing plants. Commenters believed that the other approaches were not viable, stated 

that the other approaches should be withdrawn, and that the utility-driven portfolio approach be 

the only approach included in the final rule. Commenters also recommended state plans provide 

utilities with compliance options rather than mandates to use the building blocks. Commenters

believed states should allow utilities "to choose the most practical and cost effective manner of 

achieving the ...CO2 reduction goal." Commenters suggested states develop plans that include 

enforceable milestones with penalties for failure to meet those milestones. 

Comment 2: Comments suggesting that the EPA should require all states to adopt a utilitydriven portfolio plan.

Response 2: The EPA is not finalizing the portfolio approach. In response to comments, 

specifically comments raised about applying federally enforceable CAA requirements under a 

state plan to non-affected EGU entities, the EPA is not finalizing the portfolio approach. The 

EPA’s rationale for not finalizing the portfolio approach is discussed in section VIII.C.6.d of the 

preamble to the final rule. However, the EPA is finalizing other plan approaches that would 

allow the same types of measures outlined by the commenters to be used in state plans. This 

includes a rate-based emission standards plan, where such measures could be used to adjust the 

reported CO2 emission rate of an affected EGU, as part of federally enforceable emission 

standards for affected EGUs, and the state measures plan approach, where such measures could 

be included as state-enforceable measures under both a rate-based and mass-based plan 

approach. These plan approaches are described in sections VIII.C.2 and 3 of the preamble to the 

final rule. Eligible measures that may be used to adjust the reported CO2 emission rate of 

affected EGUs are described in section VIII.K.1 of the preamble to the final rule. Requirements 
66

for rate-based emission trading programs are described in section VIII.K.2 of the preamble to the 

final rule.

The EPA disagrees with the commenters that the other plan approaches provided for in the final 

rule are not viable and has provided a detailed discussion of the design of these approaches and 

their implementation in section VIII of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA to withdraw the other three approaches and require all states 

to adopt a utility-driven portfolio approach. Commenters believed the other approaches are 

unworkable and that the utility-driven approach is consistent with the manner in which the 

industry has been regulated historically. Commenters stated that the utility-driven portfolio 

approach eliminates the implementation issues with the other approaches and avoids the legal 

issue over whether the EPA and states have the authority to regulate entities other than those 

responsible for emitting CO2. Commenters noted that emissions from power plants are the target 

of this regulation and therefore, power plant sources should be the entities regulated by this rule. 

Comment 3: Comments suggesting that utility-driven portfolio approach is fair because it 

provides an even playing field for all utilities.

Response 3: The EPA is not finalizing the portfolio approach. In response to comments, 

specifically comments raised about applying federally enforceable CAA requirements under a 

state plan to non-affected EGU entities, the EPA is not finalizing the portfolio approach. The 

EPA’s rationale for not finalizing the portfolio approach is discussed in section VIII.C.6.d of the 

preamble to the final rule. However, the EPA is finalizing other plan approaches that would 

allow the same types of measures outlined by the commenters to be used in state plans. This 

includes a rate-based emission standards plan, where such measures could be used to adjust the 

reported CO2 emission rate of an affected EGU, as part of federally enforceable emission 

standards for affected EGUs, and the state measures plan approach, where such measures could 

be included as state-enforceable measures under both a rate-based and mass-based plan 

approach. These plan approaches are described in sections VIII.C.2 and 3 of the preamble to the 

final rule. Eligible measures that may be used to adjust the reported CO2 emission rate of 

affected EGUs are described in section VIII.K.1 of the preamble to the final rule. Requirements 

for rate-based emission trading programs are described in section VIII.K.2 of the preamble to the 

final rule.

The EPA disagrees with the commenters that the other plan approaches provided for in the final 

rule are not viable and has provided a detailed discussion of the design of these approaches and 

their implementation in section VIII of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters believed the utility-driven portfolio approach was a fair approach because it would 

make the emitters of CO2 directly responsible for reducing the CO2 emissions from their affected 

units and would not unjustly burden non-emitters with the expense of compliance. Commenters
67

argued that the utility-driven approach creates an even playing field in which each utility is 

treated the same regardless of their ownership structure. Commenters noted that each affected 

EGU would be responsible only for its own CO2 emissions and would not be obligated to offset 

emissions of a utility which has a significantly larger emission profile within the state.

Commenters gave the example of LRS in Wyoming which would be obligated under the utilitydriven approach to offset its CO2 emission rate and utilities with more efficient units would not 

have to meet a higher reduction due to the averaging that a state-wide approach would impose.

Comment 4: Comments suggesting generation shift and use of RE should remain the 

responsibility of utilities under a utility-driven portfolio approach.

Response 4: The EPA is not finalizing the portfolio approach. In response to comments, 

specifically comments raised about applying federally enforceable CAA requirements under a 

state plan to non-affected EGU entities, the EPA is not finalizing the portfolio approach. The 

EPA’s rationale for not finalizing the portfolio approach is discussed in section VIII.C.6.d of the 

preamble to the final rule. However, the EPA is finalizing other plan approaches that would 

allow the same types of measures outlined by the commenters to be used in state plans. This 

includes a rate-based emission standards plan, where such measures could be used to adjust the 

reported CO2 emission rate of an affected EGU, as part of federally enforceable emission 

standards for affected EGUs, and the state measures plan approach, where such measures could 

be included as state-enforceable measures under both a rate-based and mass-based plan 

approach. These plan approaches are described in sections VIII.C.2 and 3 of the preamble to the 

final rule. Eligible measures that may be used to adjust the reported CO2 emission rate of 

affected EGUs are described in section VIII.K.1 of the preamble to the final rule. Requirements 

for rate-based emission trading programs are described in section VIII.K.2 of the preamble to the 

final rule.

The EPA disagrees with the commenters that the other plan approaches provided for in the final 

rule are not viable and has provided a detailed discussion of the design of these approaches and 

their implementation in section VIII of the preamble to the final rule.

The EPA also notes that the plan approach described by the commenters is available under the 

rate-based emission standards plan approach provided for in section C.2.a of the preamble to the 

final rule.

The following are summaries of the specific public comments under this comment:

Commenters supported the utility-driven portfolio approach because they believe utilities should 

remain responsible for making decisions on redispatching NGCC resources and RE. Commenters

noted that mechanisms already exist that allow for determining compliance using redispatch and 

RE, and noted the Midwest Renewable Energy Tracking System (M-RETS) used in Illinois, 

Indiana, Iowa, Manitoba, Minnesota, Montana, North Dakota, Ohio, South Dakota, and 

Wisconsin to verify compliance with state and provincial renewable energy requirements by 

tracking Renewable Energy Credit (REC) in the form of a tradable digital certificate for each 

MWh. Commenters noted that such programs ensure that double-counting of RE does not occur 
68

and would be consistent with building block 3. Commenters believed that similar systems will 

develop for the systematic crediting of energy efficiency savings.

Comment 5: Comments suggesting that the utility-driven portfolio approach is less complicated 

than the other approaches making development and approval quicker and easier.

Response 5: The EPA is not finalizing the portfolio approach. In response to comments, 

specifically comments raised about applying federally enforceable CAA requirements under a 

state plan to non-affected EGU entities, the EPA is not finalizing the portfolio approach. The 

EPA’s rationale for not finalizing the portfolio approach is discussed in section VIII.C.6.d of the 

preamble to the final rule. However, the EPA is finalizing other plan approaches that would 

allow the same types of measures outlined by the commenters to be used in state plans. This 

includes a rate-based emission standards plan, where such measures could be used to adjust the 

reported CO2 emission rate of an affected EGU, as part of federally enforceable emission 

standards for affected EGUs, and the state measures plan approach, where such measures could 

be included as state-enforceable measures under both a rate-based and mass-based plan 

approach. These plan approaches are described in sections VIII.C.2 and 3 of the preamble to the 

final rule. Eligible measures that may be used to adjust the reported CO2 emission rate of 

affected EGUs are described in section VIII.K.1 of the preamble to the final rule. Requirements 

for rate-based emission trading programs are described in section VIII.K.2 of the preamble to the 

final rule.

The EPA disagrees with the commenters that the other plan approaches provided for in the final 

rule are not viable and has provided a detailed discussion of the design of these approaches and 

their implementation in section VIII of the preamble to the final rule.

The EPA disagrees with the commenter’s assertion that other plan approaches are more complex. 

None of the plan approaches in the final rule mandates action under any of the BSER building 

blocks. See section VIII.C in the preamble to the final rule for details on the state plan 

approaches.

The following are summaries of the specific public comments under this comment:

Commenters supported the utility-driven portfolio approach because state plans based on this 

approach would be less complicated and therefore easier to develop and implement. Commenters 

argued that states will have only one-year develop their state plans (with the potential for a 12-

month extension under certain conditions) and also noted that that the EPA has extended its

usual four-month review period to one year, which they see as "tacit acknowledgement that this 

unprecedented regulatory structure is excessively complex." Commenters believed that a utilitydriven portfolio approach that gives the utilities the flexibility to choose from among the four 

building blocks, but does not attempt to mandate action under any individual block, would avoid 

many of the complexities of the other proposed approaches.
69

Comment 6: Comments suggesting utility-driven approach maintains existing processes for 

resource planning.

Response 6: The EPA is not finalizing the portfolio approach. In response to comments, 

specifically comments raised about applying federally enforceable CAA requirements under a 

state plan to non-affected EGU entities, the EPA is not finalizing the portfolio approach. The 

EPA’s rationale for not finalizing the portfolio approach is discussed in section VIII.C.6.d of the 

preamble to the final rule. However, the EPA is finalizing other plan approaches that would 

allow the same types of measures outlined by the commenters to be used in state plans. This 

includes a rate-based emission standards plan, where such measures could be used to adjust the 

reported CO2 emission rate of an affected EGU, as part of federally enforceable emission 

standards for affected EGUs, and the state measures plan approach, where such measures could 

be included as state-enforceable measures under both a rate-based and mass-based plan 

approach. These plan approaches are described in sections VIII.C.2 and 3 of the preamble to the 

final rule. Eligible measures that may be used to adjust the reported CO2 emission rate of 

affected EGUs are described in section VIII.K.1 of the preamble to the final rule. Requirements 

for rate-based emission trading programs are described in section VIII.K.2 of the preamble to the 

final rule.

The EPA disagrees with the commenters that the other plan approaches provided for in the final 

rule are not viable and has provided a detailed discussion of the design of these approaches and 

their implementation in section VIII of the preamble to the final rule.

The EPA disagrees with the commenters that the proposed portfolio approach is the only 

approach that would provide for the use of a utility IRP process. The EPA notes that utilities 

have factored in a wide range of environmental requirements into their IRP processes and will 

continue to do so with this final rule.

The following are summaries of the specific public comments under this comment:

Commenters supported the utility-driven portfolio approach because it maintains the existing 

process by which utilities plan for resources, including the integrated resource planning 

methodologies that take into account variables such as cost, environmental requirements and 

allows states and other regulatory bodies of consumer-owned utilities to exercise their authority 

to impose specific regulatory requirements for resource planning. Commenters stated that these 

bodies ensure utilities are adequately balancing the obligation to serve the customer and provide 

cost-effective electricity with the need to observe state and federal laws and regulations, as well 

as regional transmission operator constraints. Commenters argue that this is an extensive process

that requires a complex balance of competing interests and technology. Commenters believed

that the utility-driven portfolio approach is the only approach that would continue to allow the 

utility to make its own decisions, in concert with regulators, on how best to achieve its CO2

reductions without jeopardizing reliability or affordability.

Comment 7: Comments suggesting that the utility-driven approach avoids legal issues 

associated with states confiscating RE and EE from utilities.
70

Response 7: The EPA is not finalizing the portfolio approach. In response to comments, 

specifically comments raised about applying federally enforceable CAA requirements under a 

state plan to non-affected EGU entities, the EPA is not finalizing the portfolio approach. The 

EPA’s rationale for not finalizing the portfolio approach is discussed in section VIII.C.6.d of the 

preamble to the final rule. However, the EPA is finalizing other plan approaches that would 

allow the same types of measures outlined by the commenters to be used in state plans. This 

includes a rate-based emission standards plan, where such measures could be used to adjust the 

reported CO2 emission rate of an affected EGU, as part of federally enforceable emission 

standards for affected EGUs, and the state measures plan approach, where such measures could 

be included as state-enforceable measures under both a rate-based and mass-based plan 

approach. These plan approaches are described in sections VIII.C.2 and 3 of the preamble to the 

final rule. Eligible measures that may be used to adjust the reported CO2 emission rate of 

affected EGUs are described in section VIII.K.1 of the preamble to the final rule. Requirements 

for rate-based emission trading programs are described in section VIII.K.2 of the preamble to the 

final rule.

The EPA disagrees with the commenters that the other plan approaches provided for in the final 

rule are not viable and has provided a detailed discussion of the design of these approaches and 

their implementation in section VIII of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters supported the utility-driven portfolio approach because utilities would be allowed 

under this approach to use all of their RE and EE resources regardless of the location of the 

resource to offset their CO2 emissions. Commenters also noted that the utility would continue to 

control its renewable and non-emitting resources and any RECs or other attributes that are 

associated with them, as well as maintain the savings associated with EE. Commenters noted that 

the utility-driven portfolio approach avoids potential legal issues presented by the other proposed 

approaches that would allow states to confiscate renewable energy and would interfere with 

existing contracts. Commenters further stated that the utility-driven portfolio approach prevents 

the "stranding of non-emitting assets" and avoids "the constitutional prohibition against taking 

private property without just compensation" that the commenters believed would occur with the 

other proposed approaches.

Comment 8: Comments suggesting that the utility-driven portfolio approach avoids potential 

"double regulation" of utilities.

Response 8: The EPA is not finalizing the portfolio approach. In response to comments, 

specifically comments raised about applying federally enforceable CAA requirements under a 

state plan to non-affected EGU entities, the EPA is not finalizing the portfolio approach. The 

EPA’s rationale for not finalizing the portfolio approach is discussed in section VIII.C.6.d of the 

preamble to the final rule. However, the EPA is finalizing other plan approaches that would 

allow the same types of measures outlined by the commenters to be used in state plans. This 

includes a rate-based emission standards plan, where such measures could be used to adjust the 

reported CO2 emission rate of an affected EGU, as part of federally enforceable emission 
71

standards for affected EGUs, and the state measures plan approach, where such measures could 

be included as state-enforceable measures under both a rate-based and mass-based plan 

approach. These plan approaches are described in sections VIII.C.2 and 3 of the preamble to the 

final rule. Eligible measures that may be used to adjust the reported CO2 emission rate of 

affected EGUs are described in section VIII.K.1 of the preamble to the final rule. Requirements 

for rate-based emission trading programs are described in section VIII.K.2 of the preamble to the 

final rule.

The EPA disagrees with the commenters that the other plan approaches provided for in the final 

rule are not viable and has provided a detailed discussion of the design of these approaches and 

their implementation in section VIII of the preamble to the final rule.

The EPA disagrees with the commenters’ assertion that other plan approaches would result in 

conflicting and duplicative requirements across states, and notes that the scenarios described by

the commenters are not accurate depictions of potential outcomes under the plan approaches in 

the proposed or final rule.

The following are summaries of the specific public comments under this comment:

Commenters supported the utility-driven portfolio approach because they believe this approach 

is the only approach that avoids utilities being subject to conflicting and duplicative reduction 

requirements imposed when the multiple states in which they operate choose different pathways 

that may impose a reduction obligation on an EGU in one state and a state-portfolio approach in 

another. Commenters noted that under the utility-driven portfolio approach each state plan would 

require each utility with at least one affected EGU within the state to meet the CO2 emission 

reduction goal established for the state either on a unit-by-unit basis or on average basis across 

all EGUs within the state. Commenters noted that this approach ensures that only those utilities 

responsible for the generation of CO2 emissions within the state shoulder the obligation to reduce 

the CO2 emitted in the state and further ensures that all affected units in the United States are 

subjected to a CO2 reduction requirement with no unit slipping through the cracks or being 

subject to a "double regulation" by different states.

Commenters noted that as an example of how a utility could be subject to "double regulation," if 

the Laramie River Station in Wyoming is subjected to a utility-driven portfolio approach by the 

state of Wyoming requiring this source to reduce its CO2 emissions, it would be duplicative for 

the state of Iowa to take a state-driven portfolio approach which would impose a CO2 reduction 

goal on this utility in a state where it has no affected EGU and would require the utility to 

achieve renewable energy and energy efficiency goals to meet Iowa's CO2 reduction target 

because the utility serves load in Iowa with generation from the Laramie River Station.

Commenters stated that in this situation, Laramie River Station would be required to reduce its 

CO2 emissions from the source of the generation for Wyoming but also to reduce CO2 a second 

time to meet Iowa's goal. Commenters argued that this issue could be further compounded if 

other states, such as Minnesota, North Dakota and South Dakota, also adopt the state-driven 

portfolio approach. Commenters believed this "double regulation" is fundamentally unfair and 

would cause wholesale electricity rates to increase to cover the duplicative costs.
72

Commenters also noted that if Wyoming adopts the utility-driven portfolio approach and 

Minnesota imposed both its RES mandate (Minn. Stat. section 216B.1691) as well as a CO2

reduction mandate, then the Laramie River Station would have to further reduce CO2 emissions 

to meet the Minnesota requirements in addition to the emission reduction already required to 

meet Wyoming's goal. Commenters argued that because the generation is regulated at the source 

of the emissions, the electricity that is transmitted into Minnesota has already been subject to 

significant CO2 reduction and should not be re-regulated in Minnesota merely because it is 

generated out of state. Commenters recommended that to avoid the possibility of "double 

regulation," that EPA make the utility-driven portfolio approach the only option available to 

states. 

Comment 9: Comments suggesting that the utility-driven portfolio approach forces EGUs to 

bear the burden of emissions reductions from RE and EE, would be difficult to implement, and 

would leave EGUs vulnerable to non-compliance with CPP. 

Response 9: The EPA is not finalizing the portfolio approach. In response to comments, 

specifically comments raised about applying federally enforceable CAA requirements under a 

state plan to non-affected EGU entities, the EPA is not finalizing the portfolio approach. The 

EPA’s rationale for not finalizing the portfolio approach is discussed in section VIII.C.6.d of the 

preamble to the final rule. However, the EPA is finalizing other plan approaches that would 

allow the same types of measures outlined by the commenters to be used in state plans. This 

includes a rate-based emission standards plan, where such measures could be used to adjust the 

reported CO2 emission rate of an affected EGU, as part of federally enforceable emission 

standards for affected EGUs, and the state measures plan approach, where such measures could 

be included as state-enforceable measures under both a rate-based and mass-based plan 

approach. These plan approaches are described in sections VIII.C.2 and 3 of the preamble to the 

final rule. Eligible measures that may be used to adjust the reported CO2 emission rate of 

affected EGUs are described in section VIII.K.1 of the preamble to the final rule. Requirements 

for rate-based emission trading programs are described in section VIII.K.2 of the preamble to the 

final rule.

The EPA disagrees with the commenters that the other plan approaches provided for in the final 

rule are not viable and has provided a detailed discussion of the design of these approaches and 

their implementation in section VIII of the preamble to the final rule.

The EPA notes that the commenters appear to be questioning the viability of a rate-based plan 

approach that uses RE and demand-side EE measures to adjust the reported CO2 emission rate of 

an affected EGU. The EPA disagrees with the commenters, and has described in detail how a 

rate-based emission standards or state measures approach would be implemented, including 

adjustment of the CO2 emission rates of affected EGUs. These approaches are discussed in 

sections VIII.C and VIII.K of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:
73

Commenters stated that a portfolio approach that includes renewable measures and demand-side 

energy efficiency programs would not be feasible. Commenters stated that a utility-driven 

portfolio approach would force EGUs to bear the burden for the required emission reductions 

from RE and demand-side EE and would also require new measures to track compliance. 

Commenters were concerned about how compliance would be determined and noted that the 

unpredictability of these programs makes them difficult for ensuring compliance.

Commenters thought that the EPA should provide a thorough assessment of the different plan 

types and the questions and potential problems each may pose. Commenters expressed concern 

about the following issues related to the utility-driven approach:

• How adequate RE and EE would be assured for a utility-driven portfolio 

approach. If sufficient RE and EE was not available, then EGUs could 

be vulnerable to noncompliance. 

• How a utility-driven plan would be implemented in states with unintegrated power systems having varying degrees of separate ownership 

of generation, transmission and distribution. 

• Whether adequate RE and EE would be feasible to construct or 

implement. 

Comment 10: Comments suggesting that Integrated Resource Planning (IRP) should be 

incorporated into state plans.

Response 10: The EPA disagrees that IRPs could be included in a state plan as an enforceable 

measure, as IRP is a planning process. Enforceable measures adopted as a result of an IRP 

process could potentially be included in a state plan, depending on the specifics of the measure. 

The EPA also disagrees that the emission guidelines usurp utility commission regulatory 

authority and undermine existing integrated resource planning processes. The EPA notes that 

IRPs can be used to inform the development of state plans and utility strategies for meeting 

environmental requirements at least cost.

The following are summaries of the specific public comments under this comment:

Commenters recommended the IRP be used as a compliance approach and should be 

incorporated into state plans.

Commenters stated that Block 2 usurps MN's and OH's regulatory authority over MN electricity 

resource planning and cost recovery and should be eliminated from the CPP. Commenters stated 

that the MN utilities commission has provided for implementation of a mature integrated 

resource planning and engineering review process. Commenters said that the state's utilities 

propose measures for meeting customer electricity needs and cost recovery for resource 

deployment and operation that balances the economics, reliability, environmental performance 
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and socioeconomic impacts while managing risk, consistent with state law, and these IRP 

measures include significant public stakeholder input and are subject to a transparent, robust, 

measured and just regulatory process; Commenters said they are designed to deliver universally 

available, least cost supply of reliable electricity to Minnesotans; and commenters stated, over 

the years, the IRP process has provided for the deployment of electric generation including 

provisions for recent and ongoing deployment of environmental control retrofits on fossil units 

as reviewed and recommended by the air pollution control agency. Commenters remarked that 

this state regulator review includes analysis of whether environmental measures are cost 

effective through determination of economic break points above which further action is assessed 

as uneconomic (i.e., deployment of measures through the "heel of the cost curve"). Commenters 

noted that the economic analysis includes consideration of environmental emission externality 

costs, including those for CO2, PM, SO2 and NOx.

Comment 11: Integrated Resource Planning (IRP) should not be included in state plans.

Response 11: The EPA is not finalizing the portfolio approach. In response to comments, 

specifically comments raised about applying federally enforceable CAA requirements under a 

state plan to non-affected EGU entities, the EPA is not finalizing the portfolio approach. The 

EPA’s rationale for not finalizing the portfolio approach is discussed in section VIII.C.6.d of the 

preamble to the final rule. However, the EPA is finalizing other plan approaches that would 

allow the same types of measures outlined by the commenters to be used in state plans. This 

includes a rate-based emission standards plan, where such measures could be used to adjust the 

reported CO2 emission rate of an affected EGU, as part of federally enforceable emission 

standards for affected EGUs, and the state measures plan approach, where such measures could 

be included as state-enforceable measures under both a rate-based and mass-based plan 

approach. These plan approaches are described in sections VIII.C.2 and 3 of the preamble to the 

final rule. Eligible measures that may be used to adjust the reported CO2 emission rate of 

affected EGUs are described in section VIII.K.1 of the preamble to the final rule. Requirements 

for rate-based emission trading programs are described in section VIII.K.2 of the preamble to the 

final rule.

The EPA disagrees with the commenters that the other plan approaches provided for in the final 

rule are not viable and has provided a detailed discussion of the design of these approaches and 

their implementation in section VIII of the preamble to the final rule.

The EPA generally agrees with the commenters, but notes that IRPs can be used to inform the 

development of state plans and utility strategies for meeting environmental requirements at least 

cost.

The following are summaries of the specific public comments under this comment:

Commenters were concerned that the integrated resource planning (IRP) process will be used by 

some states for imposing portfolio-type obligations because IRPs have never been used to 

establish environmental regulations. Commenters noted that in Virginia and North Carolina, the 

IRP is only a plan that does not provide approval for or commitment to build a particular 
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resource. Commenters noted that the IRP is a utility plan for meeting forecasted peak and annual 

energy demand and reserve margins using a combination of supply-side and demand-side 

resources over a specified future period and represent a snap-shot that must be periodically reevaluated and revised as circumstances change. Commenters believed that although IRPs may be 

used to provide guidance to states on setting long-term goals, they should not be used to set 

standards or regulatory requirements. For these reasons, commenters recommended that elements 

within IRPs should remain non-binding on utilities. Commenters also recommended that if the 

EPA allows states to use IRPs to establish utility portfolio requirements, the EPA allow states to 

make periodic adjustments and modifications to plans based on a utility IRP.

Comment 12: Comments suggesting that the utility-driven portfolio approach may not be 

practical for all EGUs due to factors such as amount of energy efficiency that is cost effective 

and fuel prices.

Response 12: The EPA acknowledges the comment and notes that demand-side energy 

efficiency could be used in a state plan under both an emission standards plan and a state 

measures plan in the final rule. The EPA is providing this flexibility to allow states to choose a 

plan approach that best aligns with its circumstances, regulatory structure in the electric power 

sector, and state legislation and other requirements. State plan approaches are described in 

section VIII.C of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters explained that Washington's Energy Independence Act (1-937) requires that each 

qualifying electric utility must pursue all available conservation that is cost-effective, reliable, 

and feasible. Commenters stated that the amount of energy efficiency that is achievable and costeffective varies from year to year, and from utility to utility, due to variable factors such as the 

price of fuel and the local development of the efficiency market. Commenters stated that the two 

state agencies that oversee the utilities' implementation of the Energy Independence Act (the 

Utilities and Transportation Commission and the Washington State Department of Commerce) 

do not have the statutory authority to mandate a specific percentage of a utility's load to come 

from conservation. Commenters stated that in 2012 and 2013 the state's energy efficiency 

achievement was just over one percent of retail sales.

However, Commenters stated that the utilities in aggregate are expecting about 25 percent less 

conservation for the 2014 and 2015 biennium, due to two factors; low natural gas prices reducing 

the cost-effectiveness of some energy efficiency opportunities and the historical effectiveness of 

existing energy efficiency programs.

Commenters noted that around 20 percent of Washington's load is served by utilities that do not 

meet the customer threshold in the law and are not subject to the [Washington] Energy 

Independence Act requirements. Commenters explained that these are small consumer-owned 

utilities that obtain nearly all of their energy from the Bonneville Power Administration. 

According to the commenters, with some of cheapest energy in the country, the energy efficiency 

potential is considerably less than a larger utility with more expensive power (e.g., BPA PF-14 
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Public Tier One rates in 2014 are $31.50/MWh. Commenters stated that even if the 

[Washington] Energy Independence Act was extended to these small utilities, the low avoided 

costs and relatively expensive administrative costs would prevent them from achieving costeffective conservation at the same level as the larger utilities. Commenters stated that it would 

help if the small utilities pooled their resources into a larger umbrella organization that could 

achieve the necessary efficiencies of scale.

Commenters stated, despite claiming that affected sources may implement renewable energy 

(RE, building block 3) and demand-side energy efficiency (EE, building block 4) standards, in 

actuality, such standards are promulgated and implemented by the states, not by existing sources. 

Commenters argued that states have varied regulatory frameworks for the electric industry that 

could impede their ability to enforce requirements related to building blocks 3 and 4 directly 

against many designated facilities. Commenters said certain owners and operators of EGUs are 

not subject to rate regulation or review of new resources, and have no retail customers. 

Commenters stated that such EGUs have no capability to require the addition of renewable 

resources within a state, and no ability to provide incentives for adoption of EE measures among 

retail customers. 

5.1.6 Multi-state plans

This section contains comments on multi-state plan approaches.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Numerous commenters supported the use of multi-state plans to meet the emission 

guidelines.

Response 1: The EPA generally agrees with the commenters and in the final emission guidelines 

provides for multiple multi-state plan approaches that states may take to meet the emission 

guidelines. This includes multi-state plans with joint multi-state rate- or mass-based goals and 

the ability to collaborate with other states in the implementation of rate- or mass-based emission 

trading programs though a single-state plan. These multi-state approaches are described in 

sections VIII.C.5, VIII.J.3, and VIII.K.4 of the preamble to the final rule.

With regards to the commenters’ concerns that the EPA would extend the timeframe for 

compliance for those states participating in a multi-state plan, the EPA is not finalizing different 

time frames for compliance between individual-state and multi-state plans. 

The following are summaries of the specific public comments under this comment:

Several commenters supported the EPA's decision to allow multi-state or regional plans. 

Commenters presented their reasons for supporting the multi-state option which include:
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• Ensures states have the opportunity to take advantage of low-carbon 

technologies found outside of their boundaries.

• Will result in larger emission reductions.

• More likely to reduce emissions when combined with mass-based 

targets.

• May afford timelier carbon emissions reductions than a single state plan.

• More cost effective/reduces compliance costs. 

• Provides greater flexibility/more options.

• Better able to maintain grid reliability.

• Recognizes the regional structure of the electricity market.

• Easier to implement EE and RE across state line 

• Best approach for achieving compliance with state RE targets.

• Avoids distortions and inefficiencies in the market place.

• Minimizes risks of double counting carbon reductions.

• Makes compliance easier, especially for the largest utilities that serve 

more than one state and operate under several different state regulatory 

regimes (e.g., PacifiCorp, American, Xcel Energy, and cooperatives 

such as Tri-State).

• Rewards early actors like the northeast states participating in the 

Regional Greenhouse Gas Initiative.

• Fosters greater innovation opportunities.

• Better for customers.

• Reduced administrative costs to the EPA.

• Could provide a more level playing field across states.

• Less price volatility for states using market-based trading programs.

• Distributes the burden of compliance over more states and utilities.

• Leakage may be less significant.
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• Expands the geographic size of balancing areas allowing for a greater

percentage of intermittent power sources (e.g., wind, solar).

Some commenters noted that an analysis by MISO showed that regional compliance options save 

approximately $3 billion annually compared to sub-regional (e.g. individual state plans) 

approaches

Commenters supported multi-state or regional compliance options and quoted results from recent 

modeling performed by their regional transmission organization, PJM. Commenters noted that 

they analyzed of the impacts of several different scenarios applied across the PJM's region found 

that multi-state approaches are much more cost-effective. Commenters quoted from the analysis 

stating the estimated compliance costs under a regional approach is five times less than under 

individual state plans.

Commenters supported the multi-state approach but were concerned EPA would extend the 

timeframe for compliance for those states that select the interstate approach.

Commenters supported a multi-state approach because utilities often cross several state borders. 

Commenters supported regional approaches because they offer cost-effective solutions, help 

overcome technical challenges (such as cross-state power flow and crediting), simplify 

compliance by decreasing the number of markets created, and reduces implementation costs. 

Commenters supported multi-state plans because they simplify compliance obligations and 

market structures for businesses operating in multiple states, and increase market transparency 

and competition, which they believe will ultimately lead to lower implementation costs.

Commenters believed the EPA should recognize and encourage multi-state and regional energy 

efficiency efforts and compliance strategies, particularly where those programs use harmonized, 

consistent and transparent efficiency EM&V protocols and approaches and accounting standards 

for quantifying electricity savings and CO2 reductions.

Commenters believed multi-state planning would mitigate some double counting concerns and 

inefficient dispatch created by a patchwork of state plans, especially where similar units in 

different states share a power market with substantially different CO2 costs. However, 

commenters were concerned that states may not be able to design multi-state plans in the limited 

amount of time between finalization of the guidelines and the due date for compliance plans. 

Commenters recommended the EPA incentivize multi-state planning and should not punish 

states that are unable to develop regional compliance plans by limiting their use of RE reductions 

for compliance. Commenters stated that the EPA should minimize double counting concerns by 

providing clear guidance as to how to attribute reductions associated with RE before states 

submit compliance plans because this may encourage states to develop cooperative approaches 

for addressing the interstate effects of RE generation. Commenters recommended that if states 

working on multi-state plans are not able to finalize them within the allowed time frame, then the 

EPA should grant them additional time because the benefits of multi-state plans outweigh 

reasonable delays in plan submittal. Commenters recommended the EPA allow states "broad 

flexibility to innovate and develop multi-state trading programs that take full advantage of 

opportunities for reducing costs for electric customers."
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Comment 2: Comments suggesting that multi-state programs have resulted in higher electricity 

prices.

Response 2: The EPA disagrees with the commenters and is not aware of implementation

problems, such as those described by the commenter, that have arisen as a result of the RGGI 

program. The EPA is also not aware of any reliability concerns that have emerged as a result of 

RGGI, or reliability concerns related to RGGI raised by the FERC. The final emission guidelines 

provide for multi-state plan approaches, including multi-state plans with joint multi-state rate- or 

mass-based emission trading programs through a single state plan. These multi-state approaches 

are described in sections VIII.C.5, VIII.J.3, and VIII.K.4 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters opposed to multi-state allowance trading programs like RGGI. Commenters noted 

that New England experienced problems with pipeline constraints due to the rapid conversion to 

gas and has experienced high electricity costs as a result. Commenters were concerned that 

similar problems could be encountered in other multi-state regional plans. For these reasons, 

commenters believed RGGI should not be promoted as a model program for the country and 

noted that FERC has described reliability and cost concerns with the RGGI program.

Comment 3: Comments suggesting the EPA should allow states participating in multi-state

plans to distribute CO2 emissions reductions from EE among states in the multi-state area as long 

as the total CO2 emission reductions claimed are equal to the sum of each participating states EE 

reductions.

Response 3: The EPA has clarified the treatment of EE resources across states in the final rule. 

This is discussed in section VIII.K.1.a.(2) of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters noted that the EPA would treat EE differently under multi-state plans than it would 

under single-state plans. Commenters stated that for multi-state plans, the EPA proposes to allow 

participating states "to distribute the CO2 emission reductions among states in the multi-state

area, as long as the total CO2 emission reductions claimed are equal to the total of each state's instate emissions reductions that result from demand-side EE measures implemented in those 

states." Commenters believed that attempting to limit EE in multi-state plans based on origin 

would unnecessarily complicate implementation of multi-state plans. Commenters supported

the EPA's proposed approach to allow states to determine how to distribute such EE-related 

emission reductions is appropriate.

Comment 4: Comments from Indian Tribes support multi-state approach.
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Response 4: The EPA has clarified the treatment of RE resources across states in the final rule. 

This is discussed in section VIII.K.1.a.(2) of the preamble to the final rule. The EPA has also 

clarified in section VIII.K.1.a.(d) that RE resources located in Indian country could be used to 

meet the emission guidelines in a state plan.

The following are summaries of the specific public comments under this comment:

Commenters were concerned that none of the Indian Tribes were asked to participate in EPA's 

meetings regarding multi-state plans. Commenters noted that Indian Tribes can be treated as 

states under Section 301(d) of the Clean Air Act and believed that the EPA should have involved 

them in meetings with states concerning multi-state planning efforts. Commenters stated that 

state renewable portfolio standards would allow renewable energy generated in one state to count 

toward meeting a renewable portfolio standards in another state. Commenters stated that the 

same opportunity should be given to Indian Tribes and noted that renewable energy, such as 

FCPC's biodigester and biogas generator facility in Milwaukee, WI, could be used to help 

neighboring states meet their CO2 emission reduction requirements while the Tribes could use 

the money from such sales to reinvest into their own economies. Commenters recommended that 

EPA engage Tribes in a discussion about this opportunity and how it might fit under the 

Proposed Rule.

Commenters also suggested that the five regional planning organizations (RPOs) should also be 

consulted for multi-state planning and noted that these organizations have provided financial 

support in the past, established a framework for cooperation between states and Tribes, and have 

a proven track record of using their combined technical, policy, and legal resources and expertise 

to address air quality issues effectively on a local, regional, and national level. Commenters also 

stated that some RPOs also understand and respect Tribal cultural values and practices, which 

would help in implementing the Proposed Rule across state and Tribal borders. 

Comment 5: Comments supporting multi-jurisdictional plans between states, territories, and 

areas of Indian Country.

Response 5: The EPA generally agrees with the commenters and in the final emission guidelines 

provides for multiple multi-state plan approaches that states may take to meet the emission 

guidelines. This includes multi-state plans with joint multi-state rate- or mass-based goals and 

the ability to collaborate with other states in the implementation of rate- or mass-based emission 

trading programs though a single-state plan. These multi-state approaches are described in 

sections VIII.C.5, VIII.J.3, and VIII.K.4 of the preamble to the final rule. In section VIII.A of the 

preamble to the final rule, the EPA has clarified that use of the term "state" in the preamble 

includes territories and tribes that have obtained TAS for the purpose of developing and 

submitting to the EPA for approval a tribal implementation plan implementing the final EGs.

The following are summaries of the specific public comments under this comment:

Commenters supported the EPA's proposal to allow multi-jurisdictional plans or agreements to 

be developed among states, territories, or Indian country to minimize the overall financial impact 

of 111(d) standards.
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Comment 6: Comments suggesting that RGGI demonstrates that multi-state plans can be 

successful.

Response 6: The EPA agrees with the commenters that a multi-state emission budget trading 

program, of which RGGI is an example, is a viable means of meeting the emission guidelines. In 

multiple places in the preamble, the EPA notes the successful implementation of the RGGI 

program and the advantages of a multi-state emission budget trading program approach. The 

final emission guidelines provides for multiple multi-state plan approaches that states may take 

to meet the emission guidelines. This includes multi-state plans with joint multi-state rate- or 

mass-based goals, and the ability to collaborate with other states in the implementation of rate- or 

mass-based emission trading programs though a single-state plan. These multi-state approaches 

are described in sections VIII.C.5, VIII.J.3, and VIII.K.4 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters noted that the Regional Greenhouse Gas Initiative (RGGI) has demonstrated that a 

regional approach is a practical framework for reducing carbon pollution. Commenters stated 

that that the "Regional Investment of RGGI CO2 Allowance Proceeds 2012 Report" estimated 

that "RGGI proceed investments in energy efficiency, clean and renewable energy, and other 

strategic energy programs will return more than $2 billion in lifetime energy bill savings to more 

than 3 million participating households and more than 12,000 businesses in the region" and that 

programs funded with RGGI allowance proceeds have reduced 792,000 short tons of CO2

emissions. Commenters also noted that RGGI has shown that EE and RE measures can be 

successfully implemented as part of a multi-state program.

Commenters were supportive of using RGGI as a compliance mechanism for the Northeast.

Commenters stated RGGI has demonstrated that regional plans can be successful. Commenters 

stated that the mass-based approach is a cost-effective way to achieve substantial CO2 emission 

reductions and particularly recommended the EPA facilitate the use of regional mass-based 

approaches as a means of compliance with state targets. Commenters stated that in addition to 

reducing emissions, RGGI provided the following other benefits, including: 

• An 8 percent drop in electricity rates; 

• $2.4 billion in economic development; 

• $2 billion saved through energy-efficiency measures; 

• More than 23,000 job-years of work created; and

• $10.4 billion in health benefits from 2009-2013 due to co-benefits of 

carbon pollution reduction, such as reductions in sulfur dioxide, nitrogen 

oxides and mercury reductions that has benefitted wildlife and habitat.
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Comment 7: Commenters recommend credit for reductions accrue to the state and/or utility 

customers whose actions result in the reductions, irrespective of where the actual reductions 

occur.

Response 7: The EPA notes that the basis for the comment, that credit for emission reductions 

must accrue to the state or utility customers whose actions cause the reductions, is not defined in 

practice. The final rule creates a construct for rate-based emission trading programs where ERCs 

may be issued for measures that occur inside or outside a state. Under a mass-based emission 

budget trading program, the concept in the comment is not relevant.

The EPA has clarified the treatment of RE, demand-side EE, and other resources across states in 

the final rule. This is discussed in section VIII.K.1.a.(2) of the preamble to the final rule. In 

addition, the final emission guidelines provides for multiple multi-state plan approaches that 

states may take to meet the emission guidelines. This includes multi-state plans with joint multistate rate- or mass-based goals, and the ability to collaborate with other states in the 

implementation of rate- or mass-based emission trading programs though a single-state plan. 

These multi-state approaches are described in sections VIII.C.5, VIII.J.3, and VIII.K.4 of the 

preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters support multi-state programs but recommend the EPA adhere to the principle that 

credit for reductions realized must accrue to the state and/or utility customers whose actions 

cause the reductions, irrespective of where the actual reductions occur. Commenters asserted that 

meeting this challenge may be made easier if the EPA widens the design and timing for 

allowable multi-state transactions.

Comment 8: Comments suggesting that the EPA should allow states to enter into multi-state 

plans at any time.

Response 8: States may enter into a multi-state plan subsequent to approval of a single-state 

plan, through a plan modification. The plan modification process is described in section VIII.E.7

of the preamble to the final rule. In response to comments, this section includes a discussion of 

the process and requirements that apply when a state seeks to join or exit an already approved 

multi-state plan, through a plan modification. These provisions also address the commenters’ 

concerns regarding "anti-backsliding".

The following are summaries of the specific public comments under this comment:

Commenters recommended states should be allowed to enter into multi-state compliance 

approaches at any time before or during the compliance period. Commenters also encouraged the 

EPA to include an option to allow states to change the approach by which they will meet the 

emission reduction interim and final goals. Commenters stated that for instance, if a state 

submits, and the EPA approves, a multi-state compliance plan based on BSER, states should not 

be barred from changing to a multi-state plan in later years. Commenters recommended the EPA 

include an option for states to enter into multi-state compliance approaches at any time after 
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submitting single-state compliance plans and recommended the process should be designed to be 

as simple and streamlined as possible, in order to encourage states to enter into regional 

agreements.

Commenters stated states have different legislative and regulatory processes for enacting a 

111(d) plan, and these processes may not conclude at the same time. Commenters said certain 

RGGI states, for example, entered the program at different times because of differing state law 

requirements and decision making processes. Commenters said the EPA should enable multistate collaboration by recognizing that states may arrive at the final decision to participate at 

different points in time. Commenters said the RGGI model provides a clear example of how 

states can implement a program with "on-ramps" that enable additional states to participate. .

Commenters stated just as states may join a multi-state effort at different times, the EPA should 

recognize that states in a multi-state effort will require flexibility to deal with the unexpected 

departure of a participating state. Commenters said the EPA should work with states engaged in 

a multi-state process to ensure that states can effectively address the situation of one state leaving 

a multi-state effort such as RGGI.

Commenters also recommended that the anti-backsliding provisions should not apply to states 

that seek to join a multi-state plan after initially submitting a single-state plan. 

Comment 9: Comments suggesting that the EPA should allow states to demonstrate compliance 

on a regional basis.

Response 9: The EPA agrees with the commenter and the final emission guidelines allow states 

to demonstrate compliance on a regional basis. This is described in section VIII.C.5 of the 

preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters believed the EPA should allow states to demonstrate compliance on a regional 

basis. Commenters noted that under a mass-based regional system of compliance like RGGI, 

states would pool their individual state emission budgets and comply with those emission 

budgets on a regional basis, while still allowing for enforcement by states against their own 

sources that do not have sufficient allowances. Commenters argued that although a particular 

state's actual emissions could theoretically exceed its individual state emission budget in a 

particular year, this should not affect the EPA's willingness to accept a regional program as a 

pathway for compliance. Commenters believed that as long as the regional program 

demonstrates that emissions from sources within the region will collectively meet the EPA's 

emission guideline, the plan could still serve as the basis for each state's implementation plan. 

Comment 10: Commenters supported regional plans because they would avoid many of the 

interstate issues related to EE and RE, and avoids potential market distortions.
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Response 10: The EPA has clarified the treatment of RE, demand-side EE, and other resources 

across states in the final rule. This is discussed in section VIII.K.1.a.(2) of the preamble to the 

final rule. In addition, the final emission guidelines provides for multiple multi-state plan 

approaches that states may take to meet the emission guidelines. This includes multi-state plans 

with joint multi-state rate- or mass-based goals, and the ability to collaborate with other states in 

the implementation of rate- or mass-based emission trading programs though a single-state plan. 

These multi-state approaches are described in sections VIII.C.5, VIII.J.3, and VIII.K.4 of the 

preamble to the final rule.

While the EPA believes there are advantages to multi-state plan approaches, as discussed in the 

preamble, the final emission guidelines provide a clear basis for addressing the issues raised by 

the commenters in the context of a single-state plan.

The following are summaries of the specific public comments under this comment:

Commenters noted that a regional program has the benefit of addressing some of the interstate 

issues raised by the EPA in its questions. Commenters stated, for example, that if an energy 

efficiency policy in State A leads to a reduction in emissions in neighboring State B, State A 

cannot necessarily take direct credit for those emission reductions outside its borders in its 

section 111(d) implementation plan. Commenters continued stating that likewise, because State 

B would have no basis for enforcing State A's energy efficiency program, State B cannot 

necessarily include State A's efficiency policy in its plan. Commenters believed it may be 

challenging to make a rigorous demonstration that investments in energy efficiency or renewable 

energy result in any quantifiable level of emission reductions within the state. 

Commenters stated that they prefer a regional program because emission reductions anywhere in 

the region reduce the overall demand for emission allowances, as regulated sources require fewer 

allowances for compliance. Commenters also stated they believed that allowing regional 

compliance can avoid market distortions that would result in less than optimal policy decisions. 

Commenters noted that a state that is not participating in a regional program might choose not to 

invest in energy efficiency or renewable energy if it would not be able to fully credit the benefits 

of doing so in its section 111(d) compliance plan, and instead may make less than optimal 

investments in fuel-switching or plant-specific improvements. Commenters argued that states not 

participating in a regional program may have less reduction of emissions for a given level of 

effort. 

Comment 11: Comments suggesting that regional programs better reflect the regional nature of 

electrical grid.

Response 11: While the EPA believes there are advantages to multi-state plan approaches, as 

discussed in the preamble, the final emission guidelines provide clear pathways for states to meet 

the emission guidelines through a single-state plan. States are free to assess the potential benefits 

of a multi-state plan or coordination with other states in the implementation of their single-state 

plan. The final emission guidelines provides for multiple multi-state plan approaches that states 

may take to meet the emission guidelines. This includes multi-state plans with joint multi-state 
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rate- or mass-based goals, and the ability to collaborate with other states in the implementation of 

rate- or mass-based emission trading programs though a single-state plan. These multi-state 

approaches are described in sections VIII.C.5, VIII.J.3, and VIII.K.4 of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters believed regional approaches to emission reduction better reflect the regional nature 

of the electrical grid. Commenters argued that if the EPA allows only a state-by-state compliance 

approach, it may create inefficiencies and unnecessary complications for states, and regulated 

sources. Commenters noted that regional programs like RGGI help to ensure that the most costeffective emission reductions occur across the region. Commenters noted that electricity

generation has shifted from coal-fired plants to natural gas and renewable sources located 

elsewhere in the RGGI region. Commenters also noted that emissions in Rhode Island increased 

because of the more efficient natural gas-fired power plants in that state. Commenters noted that 

if the increase in Rhode Island's generation had been constrained by a Rhode Island-specific cap, 

one or more of the coal-fired plants that closed elsewhere in New England may have had to 

remain open to meet demand, thereby increasing emissions and costs to consumers. 

Similarly, commenters supported multi-state plans for the Southeast because of the large utilities 

that operate across state lines, such as Duke Energy, Southern Company and the Tennessee 

Valley Authority (TVA). Commenters believed that by allowing states to work together to craft 

multi-state compliance plans, the EPA is acknowledging the cross-state operations of many 

major utilities.

Comment 12: Comments suggesting that states should work with ISOs, RTOs, EIM, and FERC 

to develop multi-state plans.

Response 12: In the final emission guidelines, the EPA is requiring states to consult with the 

applicable ISO, RTO, or balancing authority in which a state is located to evaluate any potential 

electric reliability concerns related to a single-state or multi-state plan. This requirement is 

discussed in section VIII.G.2 of the preamble to the final rule. The EPA also encourages states to 

consult more broadly with the applicable ISO, RTO, or balancing authority in which a state is 

located. Such organizations may be able to assist states in developing regional strategies that can 

meet the emission guidelines at lower cost than a single-state plan, and can also help facilitate 

coordination in the development and implementation of single-state plans.

The following are summaries of the specific public comments under this comment:

Commenters suggested that states work with regional grid operators (including ISOs and RTOs), 

Energy Imbalance Market (EIM), and FERC to develop regional plans. 

Commenters noted that grid operators have extensive experience with integrating new resources 

onto the grid and can help coordinate the changes necessary to integrate RE and EE in a manner 

that ensures electricity is reliable and affordable. Commenters noted that interstate collaboration 

is already required through the Federal Energy Regulatory Commission's Order 1000 which 
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requires all public utility transmission providers to participate in a regional planning process that 

considers the impacts of state and federal energy and environmental policies, such as renewable 

energy standards, state energy efficiency resource standards, and the CPP, on transmission 

system needs. Commenters argued that Order 1000 creates a mechanism for neighboring states 

and regions to plan and pay for new transmission in a way that is mutually beneficial and can 

help ramp up wind and solar power and energy efficiency.

Commenters recommended the final rule recognize the role and function of the RTOs as EGUs 

are dispatched by RTOs that cross state lines and are responsible for providing economic and 

reliable dispatch of resources within a specified region.

Comment 13: Comments suggesting that multi-state plans focused on the electricity system as 

whole will result in the greatest emission reductions.

Response 13: The EPA agrees with the commenters that a multi-state emission budget trading 

program, of which RGGI is an example, is a viable means of meeting the emission guidelines. In 

multiple places in the preamble, the EPA notes the successful implementation of the RGGI 

program and the advantages of a multi-state emission budget trading program approach. The 

final emission guidelines provides for multiple multi-state plan approaches that states may take 

to meet the emission guidelines. This includes multi-state plans with joint multi-state rate- or 

mass-based goals, and the ability to collaborate with other states in the implementation of rate- or 

mass-based emission trading programs though a single-state plan. These multi-state approaches 

are described in sections VIII.C.5, VIII.J.3, and VIII.K.4 of the preamble to the final rule. The 

EPA notes that RE and demand-side EE requirements and programs can be used as 

complementary measures that help achieve mass-based emission limits at lower cost. Such 

complementary measures do not need to be included in a state plan.

The following are summaries of the specific public comments under this comment:

Commenters stated that emission reduction programs that are focused on the electricity system as 

a whole achieve the greatest emission reductions. Commenters noted that RGGI states 

implement a suite of programs to pursue the best opportunities for emission reductions from the 

power sector, including energy efficiency goals and renewable energy standards. Commenters 

stated the price signal provided by the cost of RGGI allowances raises the relative cost of higheremitting plants, leading to increased generation at lower-emitting, more efficient plants, even as 

overall system-wide emissions have declined substantially. Commenters stated that a systembased approach is not only best-suited to realize the emission reduction potential of cleaner 

energy supplies and energy efficiency, it fits precisely within section 111(d)'s mandate to EPA to 

develop guidelines for states to implement the "best system of emission reduction."

Comment 14: Comments suggesting that the EPA should support but not require multi-state 

plans.
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Response 14: The final emission guidelines allow for, but do not require, multi-state plans. The 

final emission guidelines also provide for coordination among states in the implementation of 

single-state plans. The final emission guidelines provide for multiple multi-state plan approaches 

that states may take to meet the emission guidelines. This includes multi-state plans with joint 

multi-state rate- or mass-based goals, and the ability to collaborate with other states in the 

implementation of rate- or mass-based emission trading programs though a single-state plan. 

These multi-state approaches are described in sections VIII.C.5, VIII.J.3, and VIII.K.4 of the 

preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Some commenters believed that the EPA should not require multi-state plans, but should allow 

states to voluntarily enter into cooperative agreements it the states determine it is mutually 

agreeable and EPA determines a multi-state plan achieves the emission reduction 

goals. Commenters also stated that the EPA should not set goals that are based on an assumption 

that states will collaborate in multi-state plans.

Comment 15: Comments suggesting requirements for multi-state plans should not be overly 

burdensome.

Response 15: The EPA has finalized requirements for multi-state plans that are no more 

burdensome than those for single-state plans, considering that there are unique aspects of multistate plans and multi-state coordination in the implementation of single-state plans that must be 

addressed to assure that approved state plans achieve the CO2 emission performance rates or 

state rate-based or mass-based CO2 goals. Generally, the EPA’s goal is to facilitate and 

encourage multi-state plans and multi-state coordination, as such approaches can meet the 

emission guidelines at lower cost than single-state plans and provide mutual benefits across 

states.

The following are summaries of the specific public comments under this comment:

Commenters recommended the requirements for multi-state plans should be no more 

burdensome than those for single-state implementation plans. Commenters also suggested the 

EPA should make interstate coordination as easy and straightforward as possible. 

Comment 16: Comments that the EPA should encourage adoption of multi-state plans because 

they represent a step toward a national GHG program.

Response 16: The EPA acknowledges the comment and the commenters’ support for allowing 

states to submit multi-state plans. The final emission guidelines allow for, but do not require, 

multi-state plans. The final emission guidelines also provide for coordination among states in the 

implementation of single-state plans. The final emission guidelines provide for multiple multistate plan approaches that states may take to meet the emission guidelines. This includes multistate plans with joint multi-state rate- or mass-based goals, and the ability to collaborate with 
88

other states in the implementation of rate- or mass-based emission trading programs though a 

single-state plan. These multi-state approaches are described in sections VIII.C.5, VIII.J.3, and 

VIII.K.4 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that a national GHG program would be a more cost-effective approach since 

it would encourage the least-cost reduction in overall emissions, regardless of where in the 

nation that reduction is available. Commenters noted that they understand that a nationwide 

program is not feasible in the near term as it would require legislation; however they support the 

encouragement included in the proposal for states to join together in multi-state compliance 

plans.

Comment 17: Comments that the EPA should clarify that states may re-allocate mass-based 

targets in multi-state plans.

Response 17: In the final emission guidelines, the EPA has finalized the proposed approach 

where states may aggregate their individual state mass-based CO2 goals into a single joint goal 

that applies to the group of participating states. Under this approach, the multi-state plan must 

meet the joint goal, which applies for the group of affected EGUs in the participating states. This 

approach is described in section VIII.C.5.b of the preamble to the final rule. Since the multi-state 

plan must meet a single joint mass-based CO2 goal that applies to all affected EGUs in the group 

of states, there is no need to "reallocating" individual state mass-based CO2 goals, as suggested 

by the commenter.

The following are summaries of the specific public comments under this comment:

Commenters requested the EPA clarify that if a group of states, like the RGGI states, translate 

the regional rate target to a mass-based target those states have the option of re-allocating the 

mass-based target.

Comment 18: Comments suggesting that states with different goals would be reluctant to enter 

into multi-state plans.

Response 18: In the final emission guidelines, the EPA has made a number of revisions to the 

BSER that resulted in different state rate-based CO2 goals from those in the proposal. Generally, 

these revisions to the BSER serve to reduce the disparity among individual states’ rate-based 

CO2 goals. In the final emissions guidelines, the EPA has finalized source subcategory-specific 

CO2 emission performance rates that reflect the application of BSER to affected NGCC and 

steam units, respectively, throughout the contiguous United States. The individual states’ ratebased and mass-based goals are state-specific representations of the CO2 emission performance 

rates for the two subcategories of affected EGUs, based on the composition of the fleet of 

affected EGUs in a respective state. These revisions address a number of the concerns raised by 
89

commenters. These topics are discussed at greater length in sections V, VI, and VII of the 

preamble to the final rule.

In addition, as described by the commenters, the perceived reluctance of states with different 

CO2 goals to enter into multi-state plans, and the reasons for such reluctance, are speculative. 

The EPA is aware of multiple dialogs among states in different regions of the country about 

potential multi-state collaboration to meet the emission guidelines. There are multiple benefits to 

multi-state approaches, including analyses by ISOs and RTOs referenced in other comments. The 

comments equate the level of a state CO2 goal with compliance costs and economic impacts from 

achievement of a goal, with lower goals resulting in greater compliance costs economic impacts. 

This is a gross oversimplification that ignores potential differences in marginal emission 

abatement costs in different states based on the composition of the fleet of affected EGUs in a 

state and other factors. Also, states exist in regional electricity grids, meaning the costs of 

meeting the emission guidelines in one state may impact wholesale electricity prices in another 

state and related electricity ratepayer impacts. All of these potential dynamics create incentives 

for state collaboration in finding the most economically efficient and mutually beneficial 

methods for meeting the emission guidelines. 

The EPA provides multiple approaches in the final emission guidelines to facilitate collaboration 

among states, including approaches that will allow states to develop multi-state approaches over 

time. This includes multi-state plans with joint multi-state rate- or mass-based goals, and the 

ability to collaborate with other states in the implementation of rate- or mass-based emission 

trading programs though a single-state plan. These multi-state approaches are described in 

sections VIII.C.5, VIII.J.3, and VIII.K.4 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Some commenters stated they thought differences in state goals would make it difficult for states 

to enter into multi-state plans. Commenters were concerned that states may be reluctant to 

collaborate with other states whose reduction targets require a vastly different level of effort. 

Commenters stated the RGGI states, for example, developed their collaborative effort based on a 

shared view of the level of the regional emission reduction goals and they prefer to maintain 

those regional emission reduction goals by joining with other states that have comparable 

reduction targets. Commenters noted that states with a less ambitious reduction target may 

hesitate to join a regional program with other states that have more stringent emission reduction 

requirements. For this reason, Commenters recommended that the EPA reduce the existing 

disparity of the EPA's emission reduction targets.

Commenters asked why states with different final goals would enter into multi-state plans. As an 

example, commenters asked why Iowa with a 16% reduction goal would agree to partner with 

Minnesota with a 41 percent reduction goal. 

Commenters believed that states will be reluctant to cooperate with states that have more 

stringent goals than their own state and that there will be no cooperation unless the goals are fair 

and reasonable.
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Commenters noted that a multi-state approach would allow facilities to redispatch their coal 

generation plants from one state to their NGCC plant in other states. Commenters presented the 

example of Idaho Power, which can redispatch the coal generation it owns in Nevada (North 

Valmy Generating Station) and Wyoming (Jim Bridger Power Plant) to its Langley Gulch 

NGCC plant located in Idaho, and also the example of Avista which would be able to redispatch 

coal generation it owns at Montana's Colstrip plant to its Rathdrum NGCC plant in Idaho. 

However, commenters believed that while Idaho's multi-state utilities may seek a regional 

compliance solution, there is little incentive for Nevada, Wyoming, and Montana to collaborate 

with Idaho. Commenters believed the EPA must provide more incentives for states to participate 

in multi-state plans, because the current proposal limits Idaho's ability to take advantage of coalto-NGCC redispatching (Building Block 2), which they believe would likely leave Idaho with a 

state plan that is burdensome on ratepayers and does not reflect a BSER that has been adequately 

demonstrated for Idaho.

Commenters thought while larger groups of states may be able to create sufficient crossincentives to justify working together on a compliance plan, states finding themselves in bilateral 

electric relationships will likely be unable to partner to the same extent. Commenters argued that 

it would be illogical for a state that had an easier and more cost-effective path to compliance to 

partner with a state that found itself in a more challenging position. Commenters recommended 

the EPA should incentivize bilateral partnerships to ensure that states that are at a compliance 

disadvantage are not excluded from partnership opportunities that could substantially reduce 

compliance costs.

Similarly, commenters thought that multi-state planning would be more difficult due to 

"inequitable burdens that the Clean Power Plan creates among states" and believe that they "will 

impact whether states choose to collaborate on multi-state plans, including cap-and-trade 

programs." Commenters noted that differences in the proposed CO2 emission reductions among 

states are especially noticeable in certain regions of the country. Commenters that as an example, 

the North Central region ranges from 11 percent and 16 percent in North Dakota and Iowa to 35

percent and 41percent in South Dakota and Minnesota, respectively. Commenters believed that 

"having such a wide disparity in the state goals discourages states, such as Iowa, from joining 

together to develop multi-state plan with a state such as Minnesota, which faces a more stringent 

interim and final goal." Commenters argued that states with more stringent emission reduction 

goals will be "forced to look exclusively at developing their own individual state plans."

Commenters noted that states with a diverse mix of generating resources within their state are 

not likely to partner with a state that relies substantially on affected coal-fired EGUs, lacks 

NGCC resources, and has poor opportunities for renewable energy development, or one which 

relies heavily on hydropower. Commenters also believed that there would be too much 

uncertainty as to whether states participating in a multi-state would be able to comply with 

the goals.

Although commenters supported the multi-state approach because it would likely reduce 

compliance costs, they were concerned that the EPA's proposal had failed to recognize the 

hurdles to the implementation of a regional plan that make such an approach unlikely to work 

since it is unclear why a state would want to switch to a regional goal more stringent than its 

individual goal.
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Comment 19: Comments suggesting that states should be able to enter multi-state agreements 

without the need to combine state goals.

Response 19: In response to comments, the EPA is finalizing approaches for multi-state 

collaboration, through the interstate transfer of ERCs and emission allowances among state ratebased and mass-based emission trading programs, respectively. These multi-state approaches, 

which include the ability for states to join a multi-state approach over time, are described in 

sections VIII.C.5, VIII.J.3, and VIII.K.4 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA clarify that states may cooperate regionally without 

combining state goals into a regional goal. Commenters recommended the EPA expand the 

options to allow a variety of multi-state arrangements, and allow states to update their plans if 

they later decide to enter into multi-state agreements. Commenters stated that states in a massbased multi-state program such as RGGI should not need to combine their state emissions 

budgets into a single regional emissions budget, though states may choose to combine state 

budgets into a single regional budget. RGGI demonstrates that it is possible for individual states 

to enact individual state allowance budgets and then agree to accept the allowances from other 

states.

Comment 20: Comments that suggest the EPA should require a memorandum of understanding.

Response 20: The EPA is not requiring states that engage in a multi-state plan to enter into a 

memorandum of understanding. Such non-binding agreements often specify collaborative efforts 

among states, or the agreed outcomes of such collaboration but are not necessary for 

collaboration.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA recognize the importance of multi-state dialogues, provide 

states flexibility to participate in these multi-state processes while considering their individual 

compliance options and suggested the EPA require a "Memorandum of Understanding" or 

similar agreements for states considering a multi-state approach to encourage states to participate 

in multi-state dialogues. Commenters suggested that such an agreement should demonstrate 

meaningful commitment to a multi-state planning process and a timeline for concluding the 

process, but should not be a burdensome requirement that necessitates legislation.

Comment 21: Comments suggesting that states with approved mass-based plans should be able 

to link their plans without review/approval by the EPA.
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Response 21: In response to comments, the EPA is finalizing a "trading ready" approach for the 

linkage among rate-based and mass-based emission trading programs, respectively. This 

approach would not require further approval by the EPA, beyond its approval of individual state 

plans designated as "trading ready" in order to effectuate links among such programs. This 

approach is described in sections VIII.A, VIII.J.3, and VIII.K.4 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended states and regions with approved mass-based compliance plans 

should be able to link their approved programs without the need for further the EPA review 

provided there is no impact on the overall level of emission reductions achieved. Commenters

stated that this approach would reduce the administrative burden for implementing multi-state or 

multi-regional compliance programs, reduce compliance costs for states, and encourage larger 

groups of states to work together. 

Comment 22: Multi-state plans should include "unwinding protocols" addressing situations 

where one or more states decides to withdraw from a multi-state plan.

Response 22: The EPA acknowledges the commenters’ concerns. In order to avoid a multi-state 

plan becoming unapprovable due to one state submitting an unapprovable portion of a multi-state 

plan, withdrawing from the multi-state plan, or failing to implement the multi-state plan, states 

may include express severability clauses if their multi-state plan is able to stand without further 

revision if one of the situations described above occurs. The severability clause must specify 

how the remainder of the multi-state plan or individual state plan would continue to function 

with the withdrawal of a state or states, and may also include pre-specified revisions. The EPA 

will evaluate the appropriateness of such a clause as part of its review of the multi-state plan 

submittal. See section VIII.E of the preamble to the final rule for more details. 

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA require "unwinding protocols" be included in multi-state 

plans to allow individual states to withdraw from a multi-state plan. Commenters recommended 

that protocol be a pre-determined methodology for apportioning emission reductions between 

states in the event that a state exits a multi-state plan that should ensure electric consumers in a 

state are not surprised by higher than expected compliance costs due to their state or another 

exiting a multi-state plan.

Comment 23: Comments that the EPA should develop guidance to support states wishing to 

develop multi-state plans.

Response 23: The final emission guidelines provide for multiple multi-state plan approaches that 

states may take to meet the emission guidelines. This includes multi-state plans with joint multi-
93

state rate- or mass-based goals, and the ability to collaborate with other states in the 

implementation of rate- or mass-based emission trading programs though a single-state plan. 

These multi-state approaches are described in detail in sections VIII.C.5, VIII.J.3, and VIII.K.4

of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters requested the EPA provide additional guidance on multi-state plans. 

Commenters recommended the EPA provide additional guidance on the acceptable forms of 

multi-state approaches. Commenters recommended the EPA develop guidelines for multi-state or 

regional implementation plans that reflect best practices and optimize emissions reductions and 

cost effectiveness. Commenters requested additional guidance on the range of multi-state 

approaches that could be used and specifically requested guidance on ways in which a program 

should function, including: guidance on program administering entities and agreements; and 

possible frameworks for emission reduction crediting of renewable energy and energy efficiency.

Commenters suggested the EPA provide support for common accounting and measurement 

systems for states using the multi-state approach and also provide clear guidance on best 

practices for monitoring and verifying emissions reductions for energy efficiency and renewable 

energy programs. 

Commenters recommended the EPA provide guidelines for multi-state plans and a CO2 credit

interstate and intrastate trading program, including mechanisms for trading between rate-based 

and mass-based programs.

Commenters felt the lack of reliable information on potential costs of carbon reduction available 

in neighboring states or regions was an obstacle hindering states from considering opportunities 

for multi-state cooperation. Commenters stated that states considering multi-state plans need to 

undertake scenario modeling of power markets using such tools as the Integrated Planning 

Model. Commenters stated that the scenarios released in the regulatory impact analysis (RIA) 

which accompanied the Section 111(d) proposed guidelines provided a useful set of conceptual 

bounding cases for initial consideration of the rule, but that they believed these would not be 

sufficient for considering a particular approach taken by a given jurisdiction, (whether mass 

based or rate-based). Commenters stated that although the RIA did identify states with high 

compliance costs that would potentially benefit from multi-state cooperation, the generalized 

formulation of the initial bounding IPM scenarios does not lend itself to the kind of detailed 

consideration of alternatives needed by states to make practical decisions regarding 

implementation strategies. Commenters noted that states do not know what would happen if 

states engaged in strategic behavior. For example, commenters wondered what regional carbon 

prices would be if only the relatively higher cost entities agreed to engage in multi-state markets, 

while states with lower compliance costs developed individual state plans. Commenters also 

believed that states more than one ISO/RTO needed additional data on how the different carbon 

price signals within its jurisdiction would affect different implementation strategies. Commenters

stated that states considering multi-state plans must have a realistic baseline against which to 

gauge the effect of their proposed actions. 
94

Commenters supported multi-state or regional approach because it better reflects the electric 

infrastructure and manner in which electricity is generated and transmitted. Commenters noted 

that a multi-state or regional approach would be favored and may even be necessary in some 

areas. However, commenters were concerned that the rule contains very little guidance on the 

types of multi-state or regional plans that the EPA will consider appropriate. Commenters stated 

that an understanding of the EPA's intent as to the content and structure of an approvable multistate or regional approach is an important consideration for states in determining how to 

comment effectively and how to develop a Section 111(d) plan.

Commenters encouraged the EPA to help states see the benefits of regional compliance plans. 

Other commenters also encouraged the EPA to support regional planning. Commenters

recommended the EPA develop guidance for states, offer technical assistance to states to help 

them develop regional and multi-state plans, develop model regional and multi-state agreements, 

and set minimum standards for multi-state plan compliance. In addition, the commenters

recommended that the EPA regional offices hold stakeholder meetings to address 

implementation questions and assist states with implementation issues, such as interstate 

crediting. 

Commenters said, the EPA should include in the final plan specific multi-state arrangements that 

could be pre-approved and provide model bi-state agreements for coordinating specific plan 

elements, such as methods to allocate compliance credit for emission reductions from energy 

efficiency. Commenters said, providing States with off-the-shelf plan elements that are 

essentially pre-approved would save States valuable time developing these measures, provide 

greater consistency in how the Clean Power Plan is implemented across the country, and make it 

more likely that States are able to attain the more cost-effective emission reductions that may be 

achievable through multi-state coordination. 

Comment 24: Comments that the EPA should encourage states to implement multi-state plans 

by providing support/incentives.

Response 24: The EPA is not providing specific incentives for multi-state plans. However, the 

final emission guidelines facilitate multi-state approaches by providing a number of options for 

states, which allow states that face different circumstances to consider collaboration. The 

preamble to the final rule also explains a number of the benefits of multi-state collaboration. In 

addition, the EPA is providing resources for states to consider in the course of the development 

of their state plans. These resources are available at the Clean Power Plan Toolbox for states, 

available at <http://www2.epa.gov/cleanpowerplantoolbox>.

The following are summaries of the specific public comments under this comment:

Some commenters wanted the EPA to provide incentives for multi-state compliance plans and 

recommended the EPA provide additional support for this option. Commenters recommended the 

EPA ensure available resources for reaching and maintaining compliance are allocated and 

distributed equitably. Commenters suggested the EPA consult with RGGI states for ideas on how 

best to encourage states to develop new or join existing multi-state plans.
95

Comment 25: Comments stating that multi-state plans are beneficial for Kentucky.

Response 25: The EPA acknowledges the comment. The final emission guidelines provide for 

multiple multi-state plan approaches that states may take to meet the emission guidelines. See 

section VIII.C.5 of the preamble to the final rule for more details on multi-state plans.

The following are summaries of the specific public comments under this comment:

Commenters thought that multi-state collaborations with other states would be beneficial for 

Kentucky, where coal-fired plants have been almost the single source of electricity generation, 

because it would allow renewable energy to be implemented at a much faster rate.

Comment 26: Comments suggesting that the EPA provide a mechanism for trading between 

rate-based and mass-based multi-state programs.

Response 26: The EPA did not propose, and is not finalizing, such an approach. The final 

emission guidelines provide for the interstate transfer of ERCs among state rate-based emission 

trading programs and the interstate transfer of emission allowances among mass-based emission 

budget trading programs. See section VIII.C.5 of the preamble to the final rule for more details 

on multi-state plans. 

The following are summaries of the specific public comments under this comment:

Commenters recommended that a mechanism for trading between rate-based and mass-based 

programs in multi-state plans be included but did not provide any specific suggestions or 

recommendations. 

Comment 27: Comments suggesting multi-state plans must use common 

specifications/approach.

Response 27: The EPA did not propose, and is not finalizing, such an approach. The final 

emission guidelines provide for the interstate transfer of ERCs among state rate-based emission 

trading programs and the interstate transfer of emission allowances among mass-based emission 

budget trading programs. See section VIII.C.5 of the preamble to the final rule for more details 

on multi-state plans.

The following are summaries of the specific public comments under this comment:

Commenters recommended that states entering into multi-state plans must use common 

specifications otherwise there exists the potential for unequal quantification or double counting 
96

within the emission reduction calculation. Commenters stated that the participating states should 

use the same goal units, rate-based or mass-based, to avoid inequalities.

Comment 28: Comments on the method used to determine the emission goal under a multi-state 

program.

Response 28: For multi-state rate-based CO2 goals, the EPA is finalizing the approach, 

discussed in the proposal, where a multi-state CO2 goal is calculated based on a weighted 

average of individual state rate-based CO2 goals, with the weighting based on 2012 electric 

generation from affected EGUs. For multi-state mass-based CO2 goals, the EPA is finalizing the 

approach, discussed in the proposal, where a multi-state mass-based CO2 goal is calculated by 

summing the individual state mass-based CO2 goals. The EPA has determined that specifying a 

method in the emission guidelines for calculating multi-state CO2 goals is necessary to ensure 

that the method for calculation of multi-state CO2 goals is consistent across states and that the 

calculated multi-state goals are an equivalent aggregate representation of the individual state CO2

goals established in the emission guidelines.

The following are summaries of the specific public comments under this comment:

Commenters supported both options proposed by the EPA for determining the emission goal for 

a multi-state program and believed that states should be free to decide which approach works 

best for their region. Commenters stated that the results of either approach will differ depending 

on the mix of generation in each multi-state group. Commenters also thought states should be 

allowed to develop their own calculation method if appropriate. Commenters further argued that 

the EPA does not have a basis in section 111(d) for limiting state discretion over this matter.

Comment 29: Comments that the EPA should allow modular plans that include multi-state 

agreements.

Response 29: The final emission guidelines provide for multiple multi-state plan approaches 

that states may take to meet the emission guidelines. This includes multi-state plans with joint 

multi-state rate- or mass-based goals, and the ability to collaborate with other states in the 

implementation of rate- or mass-based emission trading programs though a single-state plan. 

These multi-state approaches are described in detail in sections VIII.C.5, VIII.J.3, and VIII.K.4 

of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Some commenters suggested the EPA allow states to cooperate on some measures without 

forming full multi-state compliance plans because they believe this approach will benefit 

regional coordination. Commenters noted that multi-state agreements on discrete issues, such as 

the treatment of interstate renewable energy flows and related accounting and compliance issues 

can help reduce interstate conflict. Commenters suggested that states be allowed to operate 

separate programs that are connected only through the mutual acceptance of each other's 
97

emissions reductions. Commenters recommended states be allowed to enter into agreements with 

other states without being required to have a joint multi-state implementation plan. 

Commenters believed that many states will seek a "modular" approach to regional planning that 

will allow for trading and reallocation between states operating under their own plans. 

Commenters stated that while the proposed rule allows states to work together in complying with 

their emission targets, they believe there are significant technical and political challenges that 

will make development and implementation of a single compliance plan for multiple states 

difficult. Commenters also stated that because of the inherent challenges of multi-state 

rulemaking, they believe development of multi-state plans will take time and in some cases states 

may not be able to overcome some of these inherent difficulties. For these reasons, commenters

support allowing regional plans to be implemented in a modular fashion and allowing states to 

develop state-specific plans that include some common plan elements, such as a common 

accounting system and compliance credits for renewable energy and/or energy efficiency credits.

Commenters stated that the "module" for renewable energy and energy efficiency would contain 

enforceable commitments and tracking provisions, and be submitted by each state as a common 

plan element between two or more larger plans, which would ensure no double counting of 

carbon reductions. Commenters stated that states might participate in agreements concerning 

specific generating facilities or renewable resources. Commenters asked the EPA to allow these 

types of modular plans that include regional elements of this kind, as part of discrete state plans. 

Commenters also requested the EPA develop clear guidance on legal responsibilities, as well as 

common accounting and measurement systems between states in order to implement this type of 

regional planning. 

Commenters believed that allowance systems will likely provide the most straightforward 

regional compliance design with state plans that can accept allowances from carbon markets in 

other states without requiring shared targets between the states. Commenters believed that 

regional partnerships will be a useful compliance tool, particularly in the western United States 

where many long distance power transfers between states occur. Commenters stated that 

California is particularly interested in cooperating with other states. Commenters noted 

that under the California Cap-and-Trade Program first deliverers of imported power must hold 

sufficient compliance instruments for the emissions associated with these imports. Commenters 

said that including importing states in a regional market program could reduce or eliminate the 

need for this requirement for first deliverers, could ensure emissions are properly credited to 

states and ratepayers responsible for emissions improvements, and could help avoid any double 

counting in a regional program. Commenters asked the EPA to confirm that plans reallocating 

compliance credit for RE and EE programs between states are approvable.

Commenters proposed states should be allowed to redispatch generation regionally without 

entering into a 111(d) multi-state compliance agreement in order to enable utilities with multistate, regional assets to work with those states to accomplish a BSER. Commenters argued that 

reducing use of fossil fuel-fired steam plants in one state and increasing capacity at NGCC 

facilities in another state would reduce emissions without negatively impacting either state and 

would keep costs to a minimum. Commenters stated that if the EPA does not allow states to 

redispatch generation regionally without having to enter into a 111(d) multi-state compliance 

agreement, , they believed the final rule would provide no compliance credit to states like Idaho 

for the redispatch to instate NGCC generation and reduction of out of state coal generation. 
98

Commenters suggested a state may want to use a multi-state approach for implementing Building 

Block 2, while the state would retain full state-specific oversight and responsibility for the 

renewable energy and demand-side energy efficiency building blocks through a statecommitment approach.

Commenters believed that for some states, a regional budgeting approach would be better than 

using RECs and recommended that states be allowed to enter into multi-state agreements that 

allow for emissions budgeting.

Commenters believed that arrangements between two states, even with respect to a single facility 

or utility, may help to harmonize the implementation of the rule in a way that is both fair, cost 

effective, and efficient. 

Commenters argued that states should have maximum flexibility to determine what kinds of 

collaborations might work for them. Commenters noted that these could include submission of 

joint plans, standardized approaches to trading renewable or energy efficiency credits, or 

negotiated agreements on how to allocate avoided emissions or generation from renewable 

energy and energy efficiency among states.

Commenters recommended that the EPA's final rule provide states and tribes with the flexibility 

necessary to work cooperatively to develop effective strategies for compliance. Commenters 

continued, stating, in addition to allowing for the blending of individual state and tribal goals 

into a region, the EPA should also consider allowing strategies that allow for cooperation on 

specific elements without requiring the combination of goals. Commenters said this flexibility 

will allow for states and tribes to work more collaboratively without mandating the complexities 

of a full regional plan.

Comment 30: Comments stating that multi-state plans should cover all section 111(d) 

requirements.

Response 30: Multi-state plans, where multiple states submit a plan to meet a joint rate-based or 

mass-based CO2 goal, must meet all of the same requirements as a single state plan to be 

approvable. State plan requirements are addressed at section VIII.D.2 of the preamble to the final 

rule. In particular, a state plan must describe the plan approach and geographic scope, as 

discussed in section VIII.D.2.a.(1) of the preamble to the final rule. In addition, states may 

collaborate in the implementation of single-state rate-based and mass-based emission trading 

programs, through the interstate transfer of ERCs and emission allowances, as discussed at 

section VIII.C.5.c of the preamble to the final rule. RECs may not be used as a compliance unit 

under a rate-based emission standards plan type, as discussed at section VIII.K.2.f of the 

preamble to the final rule. However, RECs could be used as a compliance instrument under a 

state measure, such as a state RPS, addressed in the supporting material for a state measures plan 

type.

The following are summaries of the specific public comments under this comment:
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Commenters stated that if two or more states join forces to submit a joint plan, it should cover 

the entire spectrum of responsibilities under the rule (i.e., states submitting multi-state plans 

should not be permitted to choose to only join forces for a subset of 111(d) responsibilities). As 

an example, commenters stated that if State A submitted a plan with State B with respect to 

renewable energy generation and State A and State C submitted a separate plan with respect to 

re-dispatching of power to underutilized natural gas capacity under building block two, then the 

benefit from a strong market signal would not be achieved. However, commenters disagreed that 

a multi-state compliance plan should be a prerequisite for the interstate trading of RECs.

Commenters stated that unencumbered trading of RECs is critical to facilitating integration of 

existing state renewable portfolio standards into a tool to achieve the EPA's GHG reduction 

goals.

Comment 31: Comments that states should be allowed to develop multiple state plans where 

different regions have different RTOs/ISOs.

Response 31: Under a state plan, a state has discretion to apply different emission standards to 

different affected EGUs or groups of affected EGUs. These plan approaches are discussed at 

section VIII.C of the preamble to the final rule. 

In response to comments, the EPA has also clarified that states could address different groups of 

affected EGUs in their state through different multi-state plans. This would address the scenarios 

raised by the commenters where different groups of affected EGUs in some states are located in 

different ISOs, RTOs, or balancing authorities. This approach is described in section VIII.C.5.d 

of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Some commenters were concerned that many states have multiple balancing authorities in 

different parts of the state. Commenters noted that the balancing authorities may be the RTOs, 

ISOs, or a multi-state utility (e.g., Southern Company). Commenters stated that Missouri utilities 

operate in MISO, SPP and AECI and questioned how a regional approach would work in 

Missouri. Commenters suggested that it may be more reasonable to allow states to develop 

multiple state plans applicable to meet the requirements of the different regions of the state. 

Commenters believed this approach would enable states like Missouri to better align the 

responsibilities of reliability with the applicable market structure. 

Commenters recommended the EPA allow states to develop plans that:

• Contain two or more parts, based on balancing authorities;

• Establish goals for each part, such that the parts together will meet the 

state standard (e.g., using an average of the standards for each part of the 

state weighted by the portion of the baseline EGU emissions located in 

each subpart);
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• Allow electric facilities in the state to participate in two or more 

different regional mass-based compliance plans, and/or the ability for 

part of the state to comply through a regional mass compliance plan and 

the rest of the state not to do so;

• Allow states to submit separate compliance plans for each part of the 

state.

Commenters recommended the EPA provide clear and definitive guidance on what would be 

acceptable for states that need to split their state plans between different balancing authorities. 

Comment 32: Comments requesting clarification on how states would incorporate RES into 

multiple state plans when different states have different renewable portfolio standards

Response 32: States could include an RES as a state measure under a state measures plan type, 

as described in section VIII.C.3 of the preamble to the final rule. Such a plan could be multi-state 

in nature and designed to achieve a multi-state mass-based CO2 goal. The grouping by the EPA 

of states into regions, for purposes of building block 3 in the proposal, is not relevant for 

approvable emission standards in state plans, or state measures under a state measures plan type.

The following are summaries of the specific public comments under this comment:

Commenters asked how states would incorporate a RES into a multi-state plan when different 

states have different renewable portfolio requirements. Since renewable generation is subject to 

metering, commenters stated that it should be easy to identify the source of generation and the 

EPA's pre-defined grouping of states into regions would enhance the region’s ability to 

incorporate a RES across borders. However, commenters were concerned that dividing states 

into regions may not be sufficient for Missouri where utilities operate in MISO, SPP and AECI 

and regional compliance is further complicated by a 1 percent retail rate impact. Commenters

suggested the EPA allow states like Missouri to develop multiple state plans combining states in 

the same organizational participation structure into a region. 

Comment 33: Comments suggesting jurisdictions without affected EGUs should be allowed to 

join multi-state plans.

Response 33: States and other jurisdictions without affected EGUs are not subject to the 

emission guidelines. However, state plans that meet the emission guidelines may provide 

opportunities for implementation of emission trading programs that include emission sources that 

are located in jurisdictions in the United States that are not subject to the emission guidelines.

The following are summaries of the specific public comments under this comment:

Commenters believed that section 111(d) allows jurisdictions without affected EGUs to 

voluntarily participate in multi-state plans provided affected EGUs bear the full burden of the 
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enforceable emission reduction obligations. Commenters noted that Vermont and other such 

jurisdictions that have no units are not subject to enforcement under section 111(d) and should

not be forced to join any regional plan. Commenters recommended that if a jurisdiction such as 

Vermont without affected EGUs wishes to participate in a regional plan, the EPA should permit 

it to do so, but should readjust the regional target to take into account the emission reductions 

that can be achieved from the regional fleet of EGUs as a result of the jurisdiction's entry into the 

program. Commenters believed this "buy-in" approach would quantify the emission reductions 

available in the non-covered state by "applying" Blocks 2 through 4 to that state and imposing 

the actual emission reduction obligations on affected EGUs. Commenters said that the EPA 

would calculate the EE, RE, and other emission reduction opportunities that exist in Vermont 

and would adjust the target for affected EGUs in the region accordingly. Commenters noted that 

Vermont would not be subject to 111(d), but affected EGUs in other regional states would have 

more stringent targets as a result of Vermont's voluntary entry into the program.

Commenters stated that jurisdictions (such as DC) without fossil fuel generation units subject to 

the proposed emission guidelines should be authorized to participate in multi-state and regional 

plans. Commenters noted that the EPA is soliciting comments on a supplemental proposal to 

authorize jurisdictions without EGUs subject to the proposed emissions guidelines to partner on 

developing implementation plans with other jurisdictions that do have EGUs subject to the 

guidelines. Commenters strongly supported the EPA authorizing these partnerships and 

providing guidance related to the enforceability of such multi-jurisdictional plans. Commenters

also supported the EPA's proposal to allow states to utilize trading programs to meet their 

emissions goals and urged the EPA to authorize and provide guidance for multi-state trading 

programs to incorporate jurisdictions without affected EGUs.

Commenters recommended the EPA permit jurisdictions without existing fossil fuel-fired EGUs 

subject to the CPP guidelines to partner with jurisdictions that are subject to the CPP for 

purposes of developing a multi-jurisdictional plan. Commenters stated this provision would be 

appropriate, because of the interconnectivity of the U.S. electricity grid and the participation of 

non-affected jurisdictions in our regional markets. Commenters noted that while Vermont does 

not have any affected EGUs under the proposed CPP, Vermont does have two units that are 

subject to the RGGI program. Commenters stated that the Vermont EGUs are located within the 

Independent Systems Operator (ISO) New England region and bordering the New York ISO 

region, which makes it logical to include the Vermont units. Commenters also stated that while 

generation and emissions produced in Vermont comprise only a small share of the overall 

emissions for the RGGI region, Vermont is in the process of developing and implementing an 

ambitious program to source 90% of all energy (not just electricity) from renewable sources by 

2050. Commenters stated this effort complements other initiatives in the neighboring states and 

contributes to the expansion of renewable energy generation within the region.

Comment 34: Comments requesting clarification regarding multi-state plans addressing

complexities of importer/exporter states

Response 34: One of the advantages of a multi-state approach is that it would allow states in a 

shared electric grid region to partner in the development of a multi-state plan designed to achieve 
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a multi-state rate-based or mass-based goal. By definition, such an approach would allow states 

to implicitly address net electricity flows across states. For more details on multi-state 

approaches, see VIII.C.5.

The following are summaries of the specific public comments under this comment:

Commenters questioned whether multi-state plans or mutual agreements between states could 

deal with the complexities of importer and exporter states. 

Comment 35: Comments stating that multi-state plans are not practical for Alaska.

Response 35: The EPA is not finalizing the CO2 emission performance levels for affected 

EGUs, or state rate-based or mass-based CO2 goals for affected EGUs, for Alaska, Hawaii, or the 

U.S. territories. The rationale for the EPA’s decision not to finalize emission guidelines 

requirements for these jurisdictions is discussed at section VII.F of this preamble.

The following are summaries of the specific public comments under this comment:

Commenters noted that Alaska's power grid is not connected to the Lower-48 or Canada so 

working together with other states is not an option for Alaska.

Comment 36: Commenters recommended that the EPA allow utility-specific compliance plans 

without requiring states to join multi-state plans.

Response 36: Where a utility service territory does not cross a state line, a state could provide 

for a utility-specific approach in its state plan. However, by definition, where a utility service 

territory crosses state lines, developing a utility-specific approach would require collaboration 

among states. The final emission guidelines provide for such collaboration, either in the form of 

a multi-state plan, or through coordinated implementation of individual plans, where states 

implement a rate-based emission trading program or a mass-based emission budget trading 

program. Under the later approach, states could provide for the interstate transfer of ERCs or 

emission allowances under rate-based and mass-based emission trading programs, respectively. 

These plan approaches are described in section VIII.C.5 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended states be given the option to develop utility specific compliance 

plans without the need to join multi-state plans. 

Comment 37: Comments requesting clarification on multi-state plan goal calculations
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Response 37: The final emission guidelines provide for the state plan scenarios suggested by the 

commenter. Section VIII.C.5.b of the preamble to the final rule specifies how joint multi-state

rate-based or mass-based state CO2 goals for affected EGUs would be calculated. Under the 

scenario provided by the commenter, two states could implement a multi-state rate-based 

emission trading program or linked individual rate-based emission trading programs. Both 

approaches would provide for the interstate transfer of ERCs, and would facilitate shifting of 

generation among affected EGUs in the two states in order to comply with these rate-based 

emission standards. State plan approaches involving rate-based emission standards are discussed 

in sections VIII.C.2.a and VIII.K of the preamble to the final rule.

The commenter’s questions about a state’s incentives for entering into such plan approach are 

speculative.

The following are summaries of the specific public comments under this comment:

Commenters supported multi-state plans but wondered how a multi-state plan would be 

developed that only includes a single EGU in a nearby state or states? Commenters asked 

whether an agreement that only addresses re-dispatch from a coal EGU in "State A" to a NGCC 

EGU in another "State B" would be allowed, particularly if the same utility owns both facilities. 

Commenters asked whether both States A and B would submit their own individual state plans 

but also enter into a limited multi-state plan agreement that addresses a common goal.

Commenters wondered that if a limited multi-state plan is allowed, what incentives there would 

be for states to enter into such a plan. Commenters asked if State B's NGCC capacity factor had 

been fixed at a value < 70% and could run at a higher capacity, what incentive there would be for 

a limited multi-state plan. If the NGCC and coal EGUs had been in the same state, commenters 

noted that the EPA would have already increased the capacity factor of the NGCC in State B and 

thus its baseline during the goal setting process. Commenters asked whether State B could 

increase its NGCC capacity factor through a limited multi-state plan if its NGCC increased 

utilization was being used to take up dispatch from a coal plant in another state. 

Commenters asked how two state goals would be combined to have a joint lb per MWhr goal. 

For a state with a lower than 900 lb CO2 per MWhr goal (lower than the emission rate from a 

combined cycle gas unit), commenters asked whether a partnership with a high CO2 per MWhr 

goal state provides an opportunity for new combined cycle units in the low goal state to provide 

credit for achieving the joint goal for the two states and asked how the credit would be 

calculated. Commenters wondered whether the credit would be possible if the low emitting state 

did not join with the high emitting state. 

Comment 38: Comments requesting clarification regarding the need for state legislation to 

implement a multi-state plan

Response 38: The EPA believes that some states could implement multi-state plan approaches 

without new legislation, depending on the existing statutory authority in a state to regulate EGU 

air emissions. For example, a number of the participating RGGI states implemented that program 
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under existing environmental statutory authority (some states sought new supplemental authority 

to allocate emission allowances through auction and disperse auction proceeds).

The following are summaries of the specific public comments under this comment:

Commenters asked whether there are any multi-state arrangements that the EPA believes would 

not require some implementing legislation by participating states.

Comment 39: Comments requesting clarification regarding multi-state plan submittals

Response 39: In response to comments, the EPA is not finalizing an additional extension for the 

submission of a multi-state plan. Instead, the EPA is providing three years for the submission of 

both final single-state and multi-state plans. The plan submission deadlines are discussed in 

section VIII.E.2 of the preamble to the final rule. The requirements for a multi-state plan 

submittal are discussed in section VIII.D of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters asked how narrow could a multi-state arrangement be to still qualify for the June 

2018 deadline.

Comment 40: Comments requesting clarification regarding RGGI states and multi-state plans

Response 40: The commenters’ request for clarification regarding the approvability in a state 

plan of the RGGI program generally and specific elements of the RGGI program are beyond the 

scope of this rulemaking. However, the general approach taken under the RGGI program is an 

acceptable plan approach, and the EPA discusses in numerous places in the preamble the benefits 

of such a multi-state emission trading program. 

The RGGI program is implemented based on individual state statutory and regulatory authority. 

The "bylaws" referred to by a commenter are for RGGI, Inc., the non-profit organization 

established and managed by the RGGI participating states to provide certain administrative 

infrastructure that supports state administration of their linked CO2 Budget Trading Programs.

The following are summaries of the specific public comments under this comment:

Commenters noted that the RGGI's bylaws state that it "shall have no regulatory or enforcement 

authority- and all such sovereign authority is reserved to each signatory state." Commenters 

asked the EPA to describe the steps that RGGI states would need to take to satisfy the general 

criteria for section 111(d) plans.

Commenters were concerned about the impact of Clean Power Plan on RGGI member states. 

Commenters were concerned that the RGGI Cost Containment Reserve allowances would have 

to be drawn from below the cap, rather than added to the cap as currently and noted that the 
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mass-based emissions targets in the EPA's technical support document are below the current 

RGGI cap. Commenters were also concerned about whether RGGl would be equivalent to the 

proposed guidelines and asked the following questions:

• Is a mass-based system such as RGGl preferred rather than a rate-base 

intensity?

• Would the RGGI cap be adjusted upwards to reflect the expansion of 

additional states that may seek to join RGGI as a means of complying 

with the EPA rule?

• Would the RGGI allowance budget (individual state portions of the 

RGGI cap) be equivalent to a state's interim and final goal? As noted 

above, the EPA's recently issued rate-to-mass based translation guidance 

suggests the RGGI cap would fall short of compliance with the CPP.

• Will the cost containment mechanism continue to place a ceiling on 

allowance prices?

• Will the offset provisions of RGGI need to be removed?

Commenters recommended that any RGGI features, such as cost containment mechanisms, that 

are approved as part of a RGGI state plan should be allowed in any state plan.

Comment 41: Comments requesting clarification regarding environmental dispatch protocol in a 

multi-state plan.

Response 41: The commenter’s question is beyond the scope of this rulemaking. However, the 

EPA notes that rate-based or mass-based emission trading programs would facilitate shifting the 

dispatch of affected EGUs based in part on their CO2 emission intensity. See also the response to 

comment number 15 in section 5.1.7 of this RTC document, which addresses such mechanisms 

that have been proposed by commenters.

The following are summaries of the specific public comments under this comment:

Commenters asked the EPA to explain how a multi-state plan would lay out an environmental 

dispatch protocol for a regional transmission organization.

Comment 42: Comments requesting clarification regarding different rate structures between 

states

Response 42: In response to concerns raised by commenters, the final emission guidelines only 

allow for interstate rate-based emission trading where states are implementing equivalent CO2

emission standards; either emission standards equal to the CO2 emission performance levels in 
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the emission guidelines, or under a multi-state plan where states adopt a single CO2 emission rate 

standard. Rate-based multi-state emission trading plan approaches are described in sections 

VIII.C.5 and VIII.K.4 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters asked whether different rate structures between states with multi-state plans would 

result in arbitrage. Commenters recommended that to avoid arbitrage opportunities between 

states with different rate structures, RTO dispatch formulas would need to be revised. 

Commenters also thought opportunities for arbitrage may also occur with individual state plans 

as a state could import low-cost renewable resources to replace high CO2 emitting resources. 

Commenters suggested final rules be drafted to specifically discourage such arbitrage. 

Comment 43: Comments requesting clarification on non-adjoining states in multi-state plans 

Response 43: Multi-state plans are not limited to adjoining states. In addition, where states 

collaborate in plan implementation through interstate ERC or emission allowance transfers, such 

states also do not need to be adjoining. Multi-state plan approaches are addressed in sections 

VIII.C.5, VIII.J.3, and VII.K.4 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters asked whether non-adjoining states could enter into multi-state plans. As with 

multi-state plans among neighboring states, commenters stated support for multi-state plans 

between non-adjoining states because they would allow states to achieve the required emissions 

reductions at a lower cost than could be achieved with a single-state plan. Commenters asked the 

EPA to clarify whether such arrangements would be approvable under the Proposed Rule.

Commenters asked the EPA to clarify whether partnering states must be adjacent to each other to 

be considered to be within the same region.

Comment 44: Comments requesting clarification regarding how to include tribal RE projects in 

state plans

Response 44: States would not have to enter into a multi-jurisdictional plan with the tribe in 

order to include tribal renewable projects in their goal setting activities. Geographic eligibility 

for RE resources used to adjust the reported CO2 emission rate of an affected EGU under a state 

plan is addressed in section VIII.K.1.a.(2)(c) of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters asked whether states wishing to include tribal renewable projects within their goal 

setting activities would need to enter into a multi-jurisdictional plan with the tribe, in the same 

way a state would have to engage with another state or states in a regional plan. 
107

Comment 45: Comments requesting clarification regarding affected units in multi-state plans.

Response 45: Some affected units can be included in a state plan while other affected units 

participate in a multi-state plan. The ability to use this plan approach has been clarified in 

response to comments. This is approach is described in section VIII.C.5.d of the preamble to the 

final rule.

The following are summaries of the specific public comments under this comment:

Commenters asked whether some affected units can be included in a state plan while other 

affected units participate in a multi-state plan, as long as the state can meet its compliance goal. 

Commenters recommended the EPA allow the states to use this option in their compliance plans.

Comment 46: Commenters recommended that all multi-state plans must address several factors, 

including state inequities, comply with the Dormant Commerce Clause, hold states accountable 

for actions within their state, and address any other jurisdictional issues. 

Response 46: The EPA acknowledges the comment, which addresses issues related to state 

design of specific multi-state plans. The preamble to the final rule addresses multi-state plans in 

sections VIII.C.5, VIII.J.3, and VIII.K.4. 

The following are summaries of the specific public comments under this comment:

Commenters stated that any multi-state plan would need to:

• Avoid state-to-state inequities.

• Comply with Dormant Commerce Clause doctrine under the U.S. 

Constitution. 

• Should hold states responsible only for actions taken within their own 

borders and jurisdictional authority. 

• Credits and charges must accrue to the same state - either the state of 

generation or the state of consumption. Commenters stated that there 

must be a consistent and clear rule indicating how exported dirty and 

clean energy will be charged and credited to either the generating state 

or the state where it is consumed.

• Address regional scope of RTOs and a state's authority to regulate RTOs 

that cover multiple states.
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Comment 47: Comments suggesting that multi-state programs are an opportunity for 

cooperative federalism.

Response 47: The EPA agrees with the commenter that the final rule will encourage cooperative 

approaches among federal, state, and local jurisdictions to address the environmental impact of 

the electric power sector. The EPA notes that such collaboration and dialogs have already 

increased in response to the proposed rule.

The following are summaries of the specific public comments under this comment:

Commenters believed the 111(d) rulemaking will help promote "cooperative federalism" by 

encouraging federal (e.g., the EPA, FERC), state and regional authorities (e.g., RTOs, ISOs) to 

work together on energy security, climate change, and environmental protection. Commenters

believed the EPA should actively encourage cooperative federalism. As an example of the ways 

the EPA could encourage cooperative federalism, commenters stated that the EPA could work 

with FERC and states to develop performance-based rewards for utilities that reduce GHG 

emissions through modernization of the electric grid and energy efficiency programs, collaborate 

with the states on performance measures, or assist utilities with implementation costs (e.g., 

stranded investments or loss of revenue). Commenters believe that it would be best to continue 

the same regional approach where a regional authority exists (e.g., RTO or ISO).

Comment 48: Comments suggesting an adjudication process is needed to resolve disputes 

between states.

Response 48: The EPA disagrees with the commenter that an adjudication approach is necessary 

in the emission guidelines. States already have multiple forums, legal and otherwise, to address 

potential interstate disputes related to utility assets and related investments. The preamble to the 

final rule addresses multi-state plans in sections VIII.C.5, VIII.J.3, and VIII.K.4 of the preamble 

to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA establish a default adjudication process to resolve interstate 

disputes with respect to credit for CO2 reduction compliance measures and recognize utility 

resource investments. Commenters recommended the final rule provide more detailed guidance 

on how to develop multi-state plans.

Commenters stated that EPA should establish a default adjudication process to resolve interstate 

disputes regarding GHG-reduction credit that respects corporate portfolio investments. 

Commenters stated that since the CPP's proposed state performance goals has significant 

interstate implications because these are based on system-wide emission reductions from sources 

other than affected EGUs; these interstate issues are not adequately addressed in the CPP; and 

the EPA should not base its performance goals on measures that have an interstate character 

without providing clear ground rules for allocating emission reduction credit among the relevant 

states for the purposes of their individual 111(d) state plans. Commenters stated that to avoid or 
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minimize disputes among states, the EPA should outline the operative ground rules for allocating 

credit among states and develop a dispute resolution mechanism to ensure transparency of credit 

allocation and procedural efficiency, and the EPA should also address the need for states to 

respect corporate portfolio investments in multiple states to ensure the desired degree of largescale private capital investment. Commenters explained that although the preamble 

acknowledges that the electricity system and markets are interstate in nature, the EPA offers no 

mechanism in the CPP to adjudicate disputes that will arise. Commenters offered an example 

where state A is a net importer of energy from neighboring states. State A invests heavily in a 

demand-side management (DSM), program, and this will reduce emissions in surrounding states 

where its imported energy is generated. As a result, EGU emissions may decrease in neighboring 

state B, a net exporter of energy. Commenters ask, "In the absence of a multistate agreement, 

what happens when both states disagree as to which should receive credit for the reduction?"

Commenters contended this is not a hypothetical problem: currently, many states with renewable 

portfolio standards (RPS) grant credits for renewable energy generated in other states, and this is 

important because a system that does not recognize the validity and tradability of out-of state 

credits may unduly interfere with established state laws and private contracts. 

Commenters remarked that for large, multistate energy companies with diverse portfolios, the 

problem is compounded because the most efficient compliance strategy would be for such 

companies to prioritize investment in emissions reductions or renewable energy on a fleet-wide 

basis - investing where the greatest reductions can be achieved at the lowest cost and in the least 

time. Commenters offered an example where a company may have a coal-fired power plant in 

state C, and the opportunity to invest in wind generation development in state D. The company 

will be subject to emissions reductions rules in state C, but the most efficient way to reduce 

emissions may be for the company to invest in wind generation in state D. However, such an 

efficient portfolio investment strategy would not be recognized in state C in the absence of a 

multistate agreement, and even with an agreement, disputes may arise. Commenters believed that 

the CPP will only encourage efficient, fleet-wide investments if there are rules for transferring 

corporate portfolio credit from one state to another and if there is a mechanism to resolve 

interstate disputes over credit accounting. The commenters stated the EPA must propose and 

facilitate a comprehensive solution to interstate credit allocation and develop an efficient and fair 

procedure for resolving potential interstate disputes. The commenters noted that there are a 

variety of potential components that the EPA may wish to consider as part of a dispute 

adjudication system. Commenters suggested the EPA develop a clearinghouse or multistate 

inventory for state and private entity registration of emission-reduction actions for which they 

claim credit. Commenters also suggested that state plans should include a provision outlining the 

state's own dispute resolution procedure, which should conform to the federal framework. In 

addition to notice, transparent registration and uniform state and federal procedures, commenters 

recommended the program provide for a reasonable period of repose following adjudication to 

assure states and private parties a reasonable expectation for returns on their investments. 

Comment 49: Comments stating that the interconnected power grid in Western states (other than 

California) makes implementing regional plans more difficult than other regions
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Response 49: The EPA agrees with the commenter that there are complexities in the structure of 

the electric power sector in the West. The EPA also agrees that plan design choices in one state 

can have impacts in another state. These interconnections and related impacts argue for state 

coordination in the development of individual state plans and underline the multiple benefits of a 

multi-state plan approach, as the EPA points out in multiple places in the preamble to the final 

rule. The EPA notes that in the West significant dialogs have already begun between federal and 

state entities that participate in and/or regulate aspects of the electric power system and private 

and public market participants, as well as the relevant balancing authorities that manage 

operation of the bulk power system in the Western states.

The following are summaries of the specific public comments under this comment:

Commenters stated that any regulatory approach must recognize that Western states are served 

by an interconnected power grid through which power plants in one state often serve customers 

in another state. Commenters stated that unlike other parts of the country, there is no RTO or 

ISO in the West outside of California and the Dakotas, and the 38 electricity balancing areas 

responsible for managing the Western grid do not conform to state lines. Commenters stated that 

this means that 111(d) compliance approaches in one state can impact neighboring states. 

Commenters stated that this is particularly important in the West because many of the less 

populous states generate electricity that is delivered to large population centers in other states. 

Commenters stated that in these cases, the policy decisions in the importing states can have a 

significant impact on the generation in the exporting states. Commenters stated that likewise, 

decisions made in exporting states can have a significant impact on electricity rates in importing 

states. 

Commenters explained that there is substantial variation in how power is governed in the West. 

Commenters stated that more so than in other parts of the country, public power utilities in the 

West (i.e., rural electric cooperatives, municipal utilities, and public utility districts) often have 

large service territories, significant customer bases, or both. Commenters stated that these public 

power companies are not generally regulated by state utilities commissions, which means that 

achieving cost-effective solutions will require active collaboration and coordination among a 

range of companies and state authorities.

Commenters explained that many Western utilities own generation assets that deliver power 

across state lines, highlighting the complexities involved in implementing state and regional 

plans. Commenters stated that these complexities will have to be addressed by utilities 

commissions, environmental regulators, and, in some cases, state legislatures.

Comment 50: Commenters supported multi-state plans and suggested that the EPA allow states 

with established and proven clean energy and efficiency programs to be able to build on those 

programs for compliance.

Response 50: The EPA appreciates the commenter’s support for the proposed rule, and agrees 

with the commenter that the final emission guidelines provide states with multiple approaches 

for meeting the emission guidelines. In addition, the EPA anticipates that states that have already 
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taken aggressive actions to reduce EGU CO2 emissions and accelerate the deployment of RE and 

demand-side EE technologies will leverage those actions when developing plans to meet the 

emission guidelines.

The following are summaries of the specific public comments under this comment:

Commenters supported the EPA's efforts to utilize its authority under section 111(d) of the Clean 

Air Act to reduce carbon emissions from the power sector. Commenters stated that by 

developing the building block framework as described in the Clean Power Plan proposal, the 

EPA provides states with multiple strategies for demonstrating the "best system of emission 

reduction." Commenters supported the flexibility the EPA has provided by the proposal's 

acceptance of multi-state and mass-based programs as a means of compliance with the emission 

guidelines. Commenters noted that Delaware and the RGGI states have successfully 

demonstrated the ability to coordinate across state agencies, work with independent system 

operators/regional transmission organizations as well as solicit input from stakeholders in order 

to reduce carbon emissions from their power plants cost effectively. Commenters stated that they 

have collectively reduced their power plant emissions by over 40% since the program began in 

2009. Commenters stated that Delaware along with the RGGI states continue to demonstrate that 

a regional mass-based approach is a cost effective way to achieve substantial CO2 emission

reductions, and it is important for states with established and proven clean energy and efficiency 

programs to be able to build on those programs for compliance. 

Comment 51: Comments stating that multi-state plans should include incentives for RE and EE

programs

Response 51: States have discretion to provide incentives for RE and EE through the design of 

their state plan, including incentives for early action, and the EPA has taken steps to facilitate 

such approaches. In particular, the EPA is establishing the Clean Energy Incentive Program 

(CEIP) mechanism as part of the final emission guidelines, to provide incentives for early 

investment in RE and demand-side EE before the beginning of the plan performance period in 

2022. The Clean Energy Incentive Program (CEIP) is addressed in section VIII.B.2 of the 

preamble to the final rule.

Commenters also highlight the importance of increasing low-income communities’ ability to 

access EE/RE and financial assistance programs. The EPA addresses these comments in section 

XI.C of the final rule preamble in which the EPA encourages states to take steps to make sure 

that low-income communities get more access to EE/RE benefits. In section IX.C of the 

preamble to the final rule, the EPA provides some examples of state programs including those 

conducted by Maryland, New York, and Colorado that assist communities in increasing their 

ability to access RE/EE and financial assistance programs. The EPA encourages states in the 

writing of their plans to use these and other models to address issues around increasing access to 

EE/RE and financial assistance programs for communities. Additionally, as stated in sections 

IX.C and IX.D of the preamble to the final rule, the EPA in the coming months, will continue to 

provide information resources for communities and states on existing federal, state, local, and 

other financial assistance programs to encourage EE/RE that are already available to low-income 

communities. The EPA will also provide a catalog of current or recent state and local programs 
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that have successfully helped low-income communities adopt EE/RE measures. The goal in 

providing these resources is to help communities gain the benefits of this rulemaking by 

encouraging that states use these types of tools in their state plans. The commenters also 

reference potential incentive programs that could be conducted as a result of this rulemaking. 

The following are summaries of the specific public comments under this comment:

Commenters noted that multi-state plans should include incentives for increasing renewable 

energy and energy efficiency, which can help lower the costs of reducing emissions. 

Commenters suggested where possible, these incentives should be targeted to EJ communities 

and communities where there is a need to diversify employment opportunities. Commenters 

suggested that multi-state plans should also include incentives for reducing emissions as quickly 

as possible on a multi-state basis. Commenters noted that the EPA's guidance for multi-state 

compliance plans should also include incentives for early action to encourage investments in 

renewables and energy efficiency and a shift away from fossil-fired generation after a state 

compliance plan has been approved by the EPA, as long as these incentives do not undermine the 

overall level of emissions reductions achieved by the CPP.

Comment 52: Comments supporting the proposed approach for cooperative agreements; states 

should be able to develop a variety of agreements on discrete issues (e.g. renewable energy); 

cooperative agreements could lead to regional credit markets; the EPA should encourage 

development of multi-state agreements to reduce compliance costs; the EPA should provide a 

pathway for states to form/join multi-state agreements; only states that fail to meet multi-state 

compliance agreements should be penalized.

Response 52: The final rule allows for multi-state coordination through a joint emission goal and 

among states retaining individual state goals as well as multi-state plans that address a subset of 

EGUs in a state. For more information, see section VIII.C.5 of the preamble to the final rule. 

The following are summaries of the specific public comments under this comment:

Several commenters supported the proposed approach to allow multiple states to come to 

cooperative agreements as to how they will distribute avoided carbon emissions across their 

respective EGU fleets. Commenters noted that this gives flexibility to the states to choose from a 

variety of pathways to credit emission reductions in a manner that best addresses how they want 

to distribute credits and likely will encourage multi-state or regional compliance approaches. 

Commenters noted that a regional/multi-state approach would provide greater flexibility for 

compliance entities, better align with energy markets, and lower net costs for compliance. 

Commenters stated that regional planning is required in order to support integrated carbon 

reductions across grid regions, and noted that the final rule should recognize energy import and 

export relationships between states as they work together to ensure proper crediting of emissions 

reductions, encourage increased use of renewable energy and energy efficiency, and lay the 

groundwork for multi-state partnerships. Commenters believed that states should be allowed to 

enter into multi-state agreements that allow for emissions budgeting so long as the emission 

reductions are real, verifiable, and are not being claimed by another entity or state. Commenters 
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asserted that a regional budgeting approach would make more sense than using RECs for 

compliance. Commenters noted that in the case of renewable energy, the geographic location of 

the resources may not be well matched to the states with compliance needs; commenters stated 

that variable RE resources from different regions are more effective in combination than as 

standalone resources. Commenters emphasized that this would allow states to choose from a 

variety of options to credit emissions reductions that best address the credits. Commenters urged 

that states should be allowed to distribute carbon emissions reductions in a multi-state area 

provided that the total carbon emission reductions claimed are equal to the sum of each state's instate emissions reductions. Commenters also stated that states should be able to jointly 

demonstrate carbon emissions performance by affected EGUs in a multi-state plan for a 

coterminous electric grid region, without the need to attribute emissions reductions from 

renewable energy among individual states. Commenters stated that such cooperative agreements 

could result in a regional credit market where accounting for interstate effects would be based on 

prices in the credit market. Commenters stated they support multi-state compliance programs 

that establish a price on carbon, and noted that assets already participating in regional energy 

markets (e.g., PJM and ISO-NE) already have vast experience with market-based environmental 

programs. Commenters stated that a similar compliance program included in a state plan would 

be consistent with EPA's proposed framework offering states the opportunity to coordinate their 

state plans and to engage in trading of emissions credits among regulated entities. In addition, 

commenters stressed that all sources of electricity regardless of size and capacity factor must be 

included, as well as new and existing fossil fuel-fired EGUs. 

Commenters requested that the EPA clarify that states may develop a variety of multi-state 

agreements. Specifically, commenters urged the EPA to emphasize to states that in addition to 

full multi-state compliance plans, states may choose to develop multi-state agreements on 

discrete issues such as treatment of renewable energy. Commenters urged that the EPA should 

take every reasonable measure to incentivize interstate collaboration. Commenters urged the 

EPA to emphasize that issue-specific multi-state agreements could simplify compliance 

obligations, increase market transparency and competition, and lower implementation costs. 

Commenters asked that the EPA provide a pathway for states to form and join multi-state 

compliance plans over time, such as part of the Section 111(d) review cycle. Commenters noted 

that only the state that fails to meet its obligation should be penalized under a multi-state 

approach.

Commenters believed that states will have enter into multi-state plans or coordination 

agreements to ensure that there is no double counting of the interstate emission effects of 

implementation of the plan. Commenters also believed that coordination by the states be 

necessary where neighboring states in an electrically integrated system implement a mix of ratebased and mass-based state plans.

Comment 53: The EPA should clarify details of approvable collaborative agreements; 

recommends options to consider

Response 53: The final rule allows for multi-state coordination through a joint emission goal and 

among states retaining individual state goals, including via trading programs, as well as multi-
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state plans that address a subset of EGUs in a state. For more information, see section VIII.C.5 of 

the preamble to the final rule. 

The following are summaries of the specific public comments under this comment:

Commenters requested that EPA provide guidance clarifying the degree of formality that is 

required for EPA to recognize and approve of a multistate agreement or arrangement, as well as 

the parameters that must be included in a multistate memorandum of understanding (MOU) or 

other agreement. Commenters noted that the TSD was unclear on several issues, including the

level of detail required for the agreement. Commenters made several recommendations 

including:

• Collaborating states should not be required to submit joint CPP 

compliance plans but each state's plan should list the collaborating states 

and describe the nature, mode and mechanisms of their agreement.

• States should be able to apply a range of multistate arrangements and not 

be required to meet RGGI-level formality. 

• States that opt for the same target basis (rate or mass) using compatible 

EMV should be able to trade or average their emissions or emissions 

rates based on MOU. 

• When agreeing states use rate-bases, their averaging or trading should be 

based on joint or blended (covered-) generation-weighted rate targets. 

• EPA should allow trading among non-adjacent states. 

• EPA should provide guidance on how credit trading programs among 

states participating in a regional program might include credits from EE, 

renewable energy and other approaches.

5.1.7 Other

This section contains comments on alternative plan and implementation approaches that were not 

included the EPA’s proposal. These alternative approaches include: carbon taxes, investment in 

new technologies (with funds raised through carbon taxes or through other means (e.g., financial 

instruments such as bonds or certificate of deposit purchased by electricity producers)), dispatchfee mechanisms that impose a fee on CO2 emissions based on the CO2 emission rate of each 

EGU, company-level carbon limits, carbon reduction credit programs where an EGU earns 

credits when it operates below the state emission rate and purchases credits when it operates

above the state emission rate, and an alternative compliance payment plan where EGUs that 

cannot comply with their emission limit are allowed to pay a fee. Also covered in this section are 
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comments recommending that the EPA allow states the maximum flexibility in the design and 

implementation of state plans.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Numerous commenters supported a carbon tax as a compliance approach.

Response 1: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA.

The following are summaries of the specific public comments under this comment:

Several commenters stated that support a tax or fee on carbon emissions and believe this option 

should be explicitly included in the final rule. Commenters supported a carbon tax approach for 

the following reasons:

• Effective/efficient method for reducing CO2 emissions.

• Cost effective method.

• Discourages each fuel's use in exact proportion to its damage to the 

climate. This changes the relative prices of different fuels and 

encourages all pollution reductions that cost less than the tax. 

• Incentivizes changes at power plants (for example, more efficient boilers 

and lower-carbon fuels) and greater energy efficiency by consumers. 

• Discourages use of older, more polluting EGUs and encourage 

construction of new, less polluting EGU plants.

• It promotes all of the activities in the EPA's four building blocks to the 

extent that they are cost effective. 

• It is flexible enough to be compatible with existing fuel mixes.

• It accommodates the "remaining useful life" of equipment.
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• Does not undermine electricity reliability. 

• It is broadly consistent with a wide variety of electricity market designs. 

• Encourages development of new technologies, efficiency programs, 

and/or RE.

• Easy to administer/implement. 

• States can use the revenue raised by a carbon excise tax for other 

purposes (e.g., they could lower inefficient taxes to promote growth, 

offset some of the impacts on low-income residents, etc.). 

• Could incorporate future stationary source regulations that the EPA 

promulgates under section 111(d).

• Compatible with regional approaches to 111(d) compliance because 

coordination of tax rates is both straightforward and ensures that 

efficient operation of wholesale electricity markets is unimpaired.

• Reduces emissions of other pollutants, including particulates, mercury, 

NOx, and SOx.

• Would improve public health by reducing emissions.

• Would provide economic benefits/promote economic growth.

• Provides a stable and predictable carbon price, which reduces 

uncertainty, making decisions about emissions-reducing investments 

simpler.

• Avoids potential for market manipulation that may occur with trading 

programs.

• Meets all the proposed state plan criteria at 40 CFR 60.5780(a) because 

it is "quantifiable, verifiable, non-duplicative, permanent, and 

enforceable". 

• Could provide uniform and simplified rules for companies if 

implemented on a national level.

• Avoids overly burdensome regulations, reduces administrative 

burden, and doesn't bloat bureaucracy.

Commenters support a revenue neutral carbon tax as one of the options for state compliance. 

Commenters believe that a carbon tax represents the best approach to addressing carbon 

pollution because it is economically simple and would have bipartisan support. 
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Several commenters noted that British Columbia implemented a carbon tax program in 2008 

that shows a revenue-neutral carbon tax can reduce emissions while strengthening the economy.

Commenters noted that the British Columbia programs is gradually increasing the revenue 

neutral carbon tax and has significantly reduced CO2 emissions. Commenters noted that the 

British Columbia program shows that carbon taxes can be successfully implemented on a 

regional basis. To support this assertion, commenters noted that British Columbia implemented 

the tax on a broad range of fossil fuels (gasoline, diesel, natural gas, heating oil, propane and 

coal) beginning in 2008 at C$10/ton, and increased it C$5 annually until it reached C$30/ton in 

2012. Commenters stated that in 2011 GHG emissions had declined by 10 percent in British 

Columbia, compared to a 1 percent decline for the rest of Canada. In 2012, commenters noted 

that while per capita consumption of petroleum fuels increased by 3 percent in the rest of 

Canada, they declined by more than 16 percent in British Columbia. Commenters believed the 

carbon tax did not adversely affect British Columbia's economy since GDP per capita for British 

Columbia increased during this period more than in the rest of Canada. 

Commenters noted that Australia's carbon tax of A$23/ton tax has successfully reduced EGU 

CO2 emissions. Commenters noted that within nine months, the carbon tax has reduced demand 

for power by 2.2 percent and reduced the carbon intensity of power on the national grid by about 

5 percent, from 1,840 lbs CO2 /MWh to 1,740 lbs CO2 /MWh. Commenters noted that power 

sector emissions in Australia have been decreasing since the carbon tax was implemented in 

2012 (decreasing by 6.3 percent for 2012-2013 (193.5 MMT in the year ending June 30, 2012 

compared to 181.3 MMT in the year ending June 30, 2013), and by 9 percent 2012-2014 (176 

MMT in 2014). 

Some commenters recommended the revenues from a carbon tax be returned to the public in the 

form of a dividend to protect households from rising energy costs and to stimulate the economy. 

Commenters believed that carbon tax revenues would enable states to fully compensate lowerincome households for these regressive effects and quoted a study that estimated that 11 percent 

of the carbon tax revenues would protect the bottom two deciles of households; 18 percent the 

bottom three deciles; and 35 percent would be sufficient to cover the entire bottom half of 

households. Commenters thought the revenue raised by a carbon tax should be used by states to 

overhaul and improve their exiting tax system and that such changes could potentially provide a 

pro-growth state tax system. Commenters thought that incentives could be provided for states 

that adopted a broad-based carbon tax. Commenters stated that large emitters could get less 

stringent restrictions in exchange for adopting a broader based carbon tax.

Some commenters referenced a recent report titled "The Economic, Climate, Fiscal, Power, and 

Demographic Impact of National Fee and Dividend Carbon Tax" prepared by Regional 

Economic Model, Inc. (REMI) and Synapse Energy Economics for the Citizen's Climate Lobby 

(CCL), which reviews the carbon tax approach to reducing greenhouse gas emissions. These 

commenters highlighted some or all of the following findings from this study:

• CO2 emissions decline 33 percent after only 10 years, and 52 percent

after 20 relative to baseline. 

• National employment increases by 2.1 million jobs after 10 years, and 

2.8 million after 20 years. 
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• 13,000 lives are saved annually after 10 years, with a cumulative 

227,000 American lives saved over 20 years.

• $70-$85 billion increase in GDP from 2020 on, with a cumulative 

increase in national GDP due to Funds Available for Distribution (FAD)

of $1.375 trillion.

• Size of monthly dividend for a family of 4 with two adults in 2025 = 

$288, and in 2035 = $396. Annually, this is $3,456 per family of 4 in 

2025 ($1152 per capita--children get - dividend).

• Electricity prices peak in 2026 and then start to decrease.

• Maximum cost-of-living increase by 2035 is 1.7-2.5 percent, depending 

on region.

• Real incomes increase by more than $500 per person in 2025. This 

increase accounts for cost of living increases.

• Electricity generation from coal is phased-out by 2025.

• Employment gains in healthcare, retail, and other services (excluding 

public administration) because people have more money available and 

these industries are boosted by increases in consumer spending.

• Regional Gross Product is steady or rising in 8 of 9 regions.

Commenters stated that several modeling studies have shown that a carbon tax could be used to 

successfully reduce CO2 emissions from the power sector. Commenters specifically noted the 

following reported results from several different studies: 

• MIT's Emissions Prediction and Policy Analysis ("EPPA") model has 

shown that a $15/ton tax would reduce coal-fired EGU CO2 emissions 

by almost 15 percent within five years (Commenters also cited this study 

as supporting their recommendation to adopt a carbon tax approach).

• EIA's National Energy Modeling System ("NEMS") model demonstrates 

that a national carbon tax starting at $14/ton in 2010 would reduce coalfired EGU CO2 emissions by 50 percent from the 2030 BAU 

projections.

• U.S. Regional Energy Policy Model ("REPM") demonstrates that a 

national carbon tax starting at $20/ton in 2013 would reduce CO2

emissions by 14 percent from 2006 levels by 2020.
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• Stanford-NEMS model shows that implementing a $20/ton emissions 

tax in 2014 would, by 2020, reduce EGU CO2 emissions by 17 percent 

from 2005 levels. 

• Another study by Linn et al shows that a carbon tax would be the most 

effective and cost-efficient way to decrease their heat rate. Commenters

noted that previous reports considering a carbon tax have not modeled a 

revenue-neutral carbon tax with an aggressive rate of increase and a 

100% dividend. Commenters stated where a revenue-neutral tax was 

modeled, studies found that carbon emissions were reduced and 

economic output grew. Commenters also noted that the May 2013 study 

by the Congressional Budget Office (CBO), shows that a carbon tax 

without revenue recycling is a completely different policy from a carbon 

tax that does recycle revenue. Commenters stated that the two policies, 

revenue-neutral carbon tax and a carbon tax without revenue returned 

have a different impact on the economy. Commenters further noted that 

by failing to consider a rapid rate of increase in the carbon tax previous 

studies have failed to realize the magnitude of emissions reductions and 

scale of economic benefits that could be achieved. Commenters also 

stated that the REMI study is largely consistent with previous studies in 

terms of a benefit to the economy, industry effects, and emissions 

reductions. Commenters noted as an example the May 2013 CBO study, 

which stated that a well-designed carbon tax could increase economic 

output and that a $20 per ton carbon tax would result in an 8% reduction 

in emissions. 

Commenters mentioned a REMI study that showed a revenue-neutral carbon tax could be 

constructed for Massachusetts that would reduce emissions while also not impacting GDP. 

Commenters stated that if Massachusetts were to implement at $45 per metric ton tax on CO2

emissions by 2024, state GDP would increase by $450 million a year, 11,000 jobs would be 

added, and emissions would be reduced by 82 percent of 1990 levels. 

Commenters referenced "Recommendations to Allow States to Adopt Excise Taxes to Meet 

EPA's 111(d) Emissions Guidelines" written by M. Wara (a Standford law professor) and J. 

Minor (an economist at the Brookings Institute).

Commenters noted that industry may support a national carbon tax if states begin to consider 

state-level carbon taxes so that they do not have to manage differences in carbon taxes between 

states.

Commenters believed a carbon tax approach would be a better approach than a cap-and-trade 

approach because a carbon tax would be easier to administer. Commenters noted that states 

would not have to allocate allowances, administer auctions, create an allowance registry, monitor 

trades, enforce a price floors, or require any complex coordination with other regulatory bodies. 

Commenters noted that states could monitor fuel use to determine the amount of tax to levee.

Commenters stated that coordinating carbon tax rates across states is simpler than setting up a 

multi-state trading system. Commenters suggested that states would harmonize their carbon tax 
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programs using modeling to show that a particular tax trajectory adopted by a group of states 

would allow them to meet their emission targets. Commenters argued that by adopting a 

common carbon tax states could enter into a multi-state compliance plan that avoids interstate 

transfers and requirements for tracking cross-state allowance trades, while also allowing 

abatement to occur where it is least costly. 

Commenters noted that a carbon tax is "economically analogous to a cap-and-trade system" 

because both approaches encourage regulated entities to change their production processes to 

reduce emissions to avoid paying the emissions-based fee. Commenters asserted that by raising 

these costs a carbon tax would reduce the incentive to burn fossil fuels in exactly the same way 

that cap and trade does. 

Commenters believed there is now widespread public support for a carbon tax approach.

Commenters cited a recent PPIC study that found 51 percent of Californians support a carbon tax 

and many newspaper articles have been published that support a carbon tax. Commenters also 

noted that Exxon Mobile and Shell say on their websites that they also support a carbon tax 

approach. 

Commenters recommended state plans based on a carbon tax be self-correcting with automatic 

increases in the tax rate when an annual emissions target is missed by more than a threshold 

amount. 

Comment 2: Commenters requested that the EPA provide guidance for a carbon tax approach.

Response 2: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA include guidance in the rule addressing administration, 

implementation, tax rates, and escalation rates for a carbon tax approach. Some 

commenters recommended the EPA clarify in the final rule that states are allowed to implement 

a carbon tax as a compliance option. 

Comment 3: Commenters suggested that for a carbon tax, states should use modeling to ensure 

they are achieving the same level of emission reduction as the rate-based approach.
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Response 3: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA.

As with any state plan where the plan does not ensure that the CO2 emission performance levels 

or state rate-based or mass-based CO2 goal is achieved based on affected EGU compliance with 

an emission standard (under either an emission standards state plan type or a state measures state 

plan type), the plan submittal must demonstrate that the plan will result in achievement of the 

CO2 emission performance levels or the state CO2 goal. This requirement is addressed at section 

VIII.D.3 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters were concerned that the carbon-tax be set correctly to ensure state plans based on 

carbon taxes provide the same level of emissions reduction as the rate-based goals. Commenters

stated that the carbon tax can be set using modeling, but recommended the EPA either does 

modeling itself or provides clear standards for how the modeling should completed.

Commenters acknowledged that states adopting the carbon tax approach would need to use 

modeling to demonstrate their plans would meet the state goals, but stated that the modeling 

would be a relatively simple process, that requires calculating the effect of an EGU carbon tax on 

electricity prices, and then modeling the effect of that price increase on generation mix, 

electricity demand and resulting CO2 reductions. Commenters stated that electricity pricing and 

generation demand models are readily available. Commenters noted that the EPA used the 

Integrated Planning Model for estimating the costs of the BSER redispatch from coal-fired to 

natural gas combined cycle power plants. 

Comment 4: Comments suggesting that modeling of a carbon tax approach should take into 

account other state polices to ensure those other polices do not undermine the effectiveness of 

the carbon tax.

Response 4: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 
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as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA.

As with any state plan where the plan does not ensure that the CO2 emission performance levels 

or state rate-based or mass-based CO2 goal is achieved based on affected EGU compliance with 

an emission standard (under either an emission standards state plan type or a state measures state 

plan type), the plan submittal must demonstrate that the plan will result in achievement of the 

CO2 emission performance levels or the state CO2 goal. This requirement is addressed at section 

VIII.D.3 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters were concerned that a state that doesn't want to regulate carbon could take actions 

to undermine the effectiveness of a carbon tax-based program. For example, commenters stated 

that a state carbon tax-based program could undermine their program by using the revenue to 

subsidize fossil fuels or provide some other form of "fiscal cushioning" that undermines the 

effectiveness of the carbon tax. Commenters recommended that to prevent this from happening, 

the modeling used to determine the tax-rate target must account for any other state policies that 

have a substantial effect on carbon emissions, and the modeling and carbon tax would need to be 

updated when other policies affecting the impact of the carbon tax-based program change.

Comment 5: Commenters requested changes to the proposed rule to allow states to incorporate 

carbon tax into state plans.

Response 5: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA. In the final 

emission guidelines, the EPA is not finalizing the proposed revised definition of "emission 

standard". This proposed revised definition was related to the proposed portfolio approach which 

is not being finalized.

The following are summaries of the specific public comments under this comment:

Commenters believed the proposed definition of "emission standard" would preclude states from 

imposing a carbon tax as part of section 111(d) plans. Commenters believed the proposed 

definition of "emission standard" would allow states to tax only entities upstream or downstream 

from the regulated sources. Commenters believed the existing rules and the EPA proposal 

provides a legal basis for a carbon tax approach because 40 CFR 60.21 allows states to establish 
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an allowance system. Commenters noted that an allowance system in which allowances or 

permits are sold to emitters at a pre-determined price would be equivalent to a carbon tax. 

However, Commenters were also concerned that such an approach based on this interpretation 

could be subject to legal challenge and recommended the EPA make amendments to the rule to 

specifically allow a carbon tax approach to be adopted by states. 

Commenters recommended the EPA either change the section 111(d) implementing regulations 

to clarify that any measure that is enforceable and reduces emissions can be an "emission 

standard" or revise the definition of "emission standard" to allow reductions in emissions caused 

by regulation of any affected entity, including EGUs themselves. Commenters favor the first 

approach because they believe it would also apply to other source categories in future emissions 

guidelines.

Commenters believed that precedent exists for amendments to be made to 40 CFR part 60 and 

noted that the EPA has amended 40 CFR 60.21 and 60.24(b)(1) multiple times, including in a 

2005 rulemaking in which the EPA expanded the definition of "emission standards" to include 

cap-and-trade programs for the Clean Air Mercury Rule. 

Some commenters suggested that if the EPA prefers not to modify 40 CFR 60.21 and 

60.24(b)(1), then the EPA could instead modify the definition of "emission standard" in section 

60.5820. Commenters recommended section 60.5820 to read "Emission standard means in 

addition to the definition in section 60.21, any requirement applicable to any affected entity that 

has the effect of reducing emissions of one or more affected sources, including, for example, 

renewable energy and demand-side energy efficiency requirements." Commenters stated that this 

amended language would allow states to impose a tax liability on regulated sources instead of 

upstream or downstream entities and replaces "reducing utilization" with "reducing emissions" of 

affected sources, keeping the emphasis on the objective of the rule and the EPA's role in setting 

the emissions guideline. Commenters recommended the EPA delete the phrase "other than an 

affected source" from the definition in 40 CFR 60.5820 to enable to states to include a carbon tax 

as part of their state plans.

Comment 6: Comments suggested that the EPA should include backstop requirements to ensure

carbon tax-based plans meet state goals.

Response 6: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 
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fee or tax, with respect to state or federal statutes outside the scope of the CAA.. A state 

measures type plan must include a backstop of federally enforceable emission standards for 

affected EGUs. This is discussed in section VIII.C.3 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended that state plans that use a carbon tax approach should include 

additional requirements that would be implemented if the carbon tax fails to produce the required 

emissions reduction. Commenters suggested the tax rate would increase by a specific amount, 

with the rate increase determined by a formula based on the amount of the emission performance 

shortfall. Commenters believed this approach would allow for planning certainty among the 

affected EGUs and provide minimum disruption in implementing the remedial measure. As a 

backstop, commenters also recommended the rules require the plan include specific remedial 

regulatory mandates adequate to ensure achievement of the target level of reductions, such as 

required emissions reductions from covered EGUs. Commenters recommended the backstop 

requirements automatically take effect if an automatic tax increase mechanism failed to meet the 

state target. Commenters believed the automatic backstop requirements of an increase in the tax 

rate and other regulatory mandates would remove the possibility of any individual reductions 

being reversed. 

Comment 7: Commenters stated that citizen enforcement of carbon tax-based plans is allowed 

under the CAA.

Response 7: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA. Under a state 

measures type plan, state measures, which if a state chose might include a tax for CO2 emissions 

from affected EGUs, would be state-enforceable rather than federally enforceable. As a result, 

such measures would not be subject to citizen suit enforcement provisions under CAA section 

304.

The following are summaries of the specific public comments under this comment:

Commenters noted that the Clean Air Act would permit citizen enforcement of a carbon tax 

because 42 U.S.C. section 7604(a) allows citizens to sue for violation of "an emission standard 

or limitation under this chapter" and 42 U.S.C section 7604(f)(3) and (4) defines "[e]mission 

standard or limitation under this chapter" to include "any requirement under section [111] or 
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[112] of this title (without regard to whether such requirement is expressed as an emission 

standard or otherwise)" and "any other standard, limitation, or schedule established under . . . any 

applicable State implementation plan" . Commenters argued that because the carbon tax itself 

and the reductions in emissions it would apply to have fixed numerical values, the courts would 

be able to enforce a SIP carbon tax. Commenters cited the case of Bayview Hunters Point v. 

Metro. Trans. Comm'n, 366 F.3d 692, 701 (9th Cir. 2004), which discusses "the well-established 

rule that courts may only enforce specific SIP strategies, and may not enforce a SIP's overall 

objectives or aspirational goals." 

Comment 8: Comments stating that the EPA does not have authority to impose a carbon tax

because Congress has not provided the authority.

Response 8: The EPA did not propose a carbon tax, nor do the final emission guidelines impose 

a carbon tax. If a state choose, it could include a tax for CO2 emissions from affected EGUs as a 

state measure under a state measures type plan. These state measures would be state-enforceable 

rather than federally enforceable, and would not be codified as part of the federally enforceable 

state plan under CAA section 111(d).

The EPA disagrees with the commenter’s assertion that the RGGI emission budget trading 

program imposes a carbon tax. The states participating in the RGGI program impose a limit on 

CO2 emissions for power plants and allocate emission allowances through auction and other 

mechanisms.

The following are summaries of the specific public comments under this comment:

Commenters opposed to carbon taxes and noted that Congress has not provided the authority to 

the EPA to tax CO2 emissions and the EPA cannot force states to tax CO2 emissions. 

Commenters believed that RGGI imposes a CO2 emissions tax and stated that the EPA should 

not use the RGGI approach as an example program since the RGGI "relies on voluntary carbon 

taxes that cannot be legally forced upon a state."

Comment 9: Comments supporting an output-compensated carbon tax.

Response 9: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 
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as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA.

The following are summaries of the specific public comments under this comment:

Commenters recommended a carbon tax system in which EGUs would pay a tax on carbon 

emissions into a fund. Commenters explained that EGUs with relatively high carbon emissions 

would be net payers into the fund, while those with relatively low carbon emissions would be net 

recipients. Commenters noted that this tax/subsidy system has been used to manage conventional 

NOx emissions from EGUs and other large point sources in Sweden. Commenters stated that one 

of the benefits of this approach is that it mitigates "the damage to the nation's competitiveness 

that otherwise would have been incurred as a result of an emissions tax" and creates incentives to 

substitute energy generation with lower emitting sources. Commenters stated that this approach 

would not change consumers' lifestyles and hence reduction in emissions would likely be less 

than would occur under an uncompensated carbon tax approach. 

Comment 10: Comments stating that state plans based on rebated carbon taxes could increase 

emissions.

Response 10: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA.

The following are summaries of the specific public comments under this comment:

Commenters were concerned that rebates from an income-compensated carbon tax cannot be 

easily targeted to the consumers who are bearing the impacts of the carbon tax and stated that 

"dramatic changes in tax policy have uncertain outcomes." Commenters believed that an incomecompensated carbon tax would eliminate the small consumer income effect on carbon emissions 

so that emissions would be slightly higher than they would be under an uncompensated carbon 

tax. 

Comment 11: Comments stating that the EPA should allow state-level, economy-wide carbon 

tax or other pricing mechanisms as an alternative to the proposed state plan approaches.
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Response 11: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA.

The following are summaries of the specific public comments under this comment:

Commenters supported a state-level economy-wide excise tax or other pricing mechanism on 

carbon emissions as an alternative to a state plan using the basic architecture of the fourbuilding-blocks approach. Commenters believed that this approach would address the GHG 

emissions from the transportation sector and were concerned that focusing only on the electric 

sector would lead to inefficient, ineffective and distorted outcomes. As an example, commenters 

noted that the CPP could increase electricity costs and thereby create a disincentive for the use of 

low-carbon electricity as a transportation fuel. Commenters believed that in the Pacific 

Northwest the most cost-effective GHG emission reduction measures on a dollar per ton basis 

would be in the transportation and other sectors of the economy.

Comment 12: Comments suggesting that states should adopt programs reinvested revenues in 

emission reduction programs because this approach is more cost effective and would result in 

more emission reductions.

Response 12: Such an approach could be taken by a state, depending on the programs or 

mechanisms implemented, under either an emission standards plan type or a state measures plan 

type. For more details on these state-plan approaches, see section VIII.C of the preamble to the 

final rule.

The following are summaries of the specific public comments under this comment:

Commenters believed that any market approach that reinvests the revenues raised in emission 

reduction programs would be more cost effective and would result in greater reductions in GHG 

emissions. Commenters mentioned three types of approaches they believed states should 

consider including their state plans: (1) carbon tax programs where the revenue is reinvested in 

emission reduction programs; (2) cap-and-trade programs where revenue raised through 

allowance auctions is invested in emission reduction programs; and (3) emission targets that 

require the emitter to either achieve the emission reductions or buy offsets for every ton of 

carbon emitted.
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Comment 13: Comments suggesting that carbon taxes would be unsuccessful due to market 

barriers.

Response 13: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA.

The following are summaries of the specific public comments under this comment:

Commenters believed that imposing a substantial tax on carbon would be unlikely to be 

successful because of several "significant barriers and imperfections" in the market. Specifically, 

commenters provided the following reasons for believing carbon taxes would be an ineffective 

mechanism: (1) the technologies needed to turn fossil fuels into power are comparatively simple 

and relatively inexpensive compared with lower intensity resources that require more capital 

investment to extract useful power and higher intensity resources that require much higher levels 

of capital investment to control the release of power; (2) fossil fuels are readily available and 

relatively easy to exploit; (3) any attempt to phase-out the use of fossil fuels is a dramatic 

change, compared to previous policies, that will have a larger impact on the cost of fossil fuels; 

(4) the supremacy of fossil fuels has been reinforced by investment in infrastructure to support 

fossil-fired power plants; (5) green innovations require large investments, involve a large 

component of basic research, and have highly uncertain outcomes; (6) the power sector has an 

"immense amount of political clout" and has used this power to gain "explicit and implicit 

subsidies to further reinforce their economic position;" (7) entry into the power sector is risky 

and expensive, market organization is more likely to be oligopolistic than perfectly competitive, 

and information is strategically held and difficult to obtain; (8) existing companies in energyrelated industries (i.e., those that produce energy, those that manufacture the equipment that 

produces, converts and uses energy, and those that distribute energy) have substantial incentives 

to delay the introduction of new technologies if their current technologies are more profitable 

than the new ones and if infrastructure for the existing technology required large investments that 

have already been incurred, and (9) demand-side technologies may not be adopted because of 

poor or asymmetric information available to purchasers, limits on an individual's ability to make 

rational decisions because of time or skill constraints, principal-agent incongruities between 

building owners and building residents, and lack of financing opportunities.

Commenters were concerned that underinvestment in alternative sources of electricity, combined 

with the ability of dominant incumbents to implement practices and promote policies that favor 

fossil fuel-fired generators, results in significant barriers to entry for alternative energy sources. 

As an example, commenters stated that existing power producers control access to the grid or 

dispatch. Commenters believed that "just raising the cost of the dominant fuels does not 

overcome the inertia and actually allows the gap between the incumbent and alternative 
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technologies to persist or even grow as the entrenched interests use their resource advantage and 

political power to protect their incumbency." Commenters quoted from several authors including 

Ryan Avent of the Economist (quoting from "Creating the Clean Economy," The Economist, 

June 11, 2011), David Leonhardt of the New York Times (quoting from "There's Still Hope for 

the Planet," New York Times, July 21, 2012), Roger Noll (quoting from "Comment," Energy 

Economics, 33, 2011), William Nordhaus (quoting from "Designing a Friendly Space for 

Technological Change to Slow Global Warming," Energy Economics, 33, 2011), and Jon 

Weyant ("Accelerating the Development and Diffusion of New Energy Technologies: Beyond 

the Valley of Death," Energy Economics, 33, 2011), as well as studies by Resources for the 

Future (see Gillingham, Kenneth, Richard G. Newell and Karen Palmer, "Retrospective 

Examination of Demand-side Energy Efficiency Policies," Resources for the Future, September 

2004) and Oak Ridge National Laboratory (see Brown, Marylyn et. al, "Carbon Lock-In: 

Barriers to Deploying Climate Mitigation Technologies," Oak Ridge National Laboratory, 

January 2008). Commenters stated these authors wrote about the types of barriers that exist in the 

electricity sector and how carbon taxes alone may not be able to overcome those barriers to 

change. Commenters also discussed the difficulties in pricing carbon correctly to promote 

changes in the industry and stimulate innovation in alternative electricity generation.

Comment 14: Comments suggesting that carbon taxes would impact electricity prices and make 

states less competitive.

Response 14: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA. The final 

emission guidelines provide states with flexibility to assess and implement the best strategy to 

meet the emission guidelines, considering their unique circumstances and policy goals.

The following are summaries of the specific public comments under this comment:

Commenters believed that a carbon tax would cause an increase in the price of electricity and 

reduce the competitiveness of any state that adopted the tax. Commenters argued that a tax on 

carbon emissions from EGUs would effectively translate into a tax on electricity, which would 

likely to be very unpopular and would render a state much less competitive in attracting 

businesses that use electricity, and would drive electricity-using businesses to other jurisdictions 

thereby defeating the purpose of the tax. For this reason, commenters believed a carbon tax is 

"ill-suited for use at the state level."
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Commenters stated that a carbon tax has three effects on the market: (1) a technical substitution 

effect, as electricity producers substitute lower carbon-intensity technologies for higher ones; (2) 

a consumer substitution effect by raising the price of electricity, thereby inducing consumers to 

buy more of other goods and less of electricity; and (3) a consumer income effect, as consumers 

find that higher electricity prices have left them less able to afford everything, including 

electricity. Commenters noted that the last two effects would result in lower output of electricity 

and hence lower emissions but the technical substitution effect would dominate and the income 

effect would likely have only a small impact on carbon emissions. 

Comment 15: Comments stating that the EPA should allow a dispatch fee mechanism

administered by the RTO or ISO that imposes a carbon fee on electricity generated by plants that 

emit more CO2.

Response 15: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA.

The following are summaries of the specific public comments under this comment:

Commenters supported a dispatch fee mechanism in which the fee would be set through bids in 

the competitive wholesale electricity market. Commenters believed that the fee could be 

administered by the RTO or ISO, or in vertically-integrated states, through a carbon fee added to 

the state's existing least-cost dispatch regime. Commenters believed the benefits of a carbon fee 

approach, include: 

• Greater degree of certainty as to the cost of compliance.

• Simple and efficient way for states to comply with the Clean Power 

Plan.

• Can be structured as a voluntary safe harbor for the interim years of the 

program.

• Ensures effective deployment of capital in coal units by allowing 

existing units with limited remaining operational lives to be fully 

utilized without additional costly retrofits.
131

• Provides appropriate price signals to maintain and expand clean energy 

and natural gas utilization.

• Guarantees electric reliability at both the state and regional level by 

linking greenhouse gas abatement to reliability dispatch.

• Achieves significant greenhouse gas reductions at lowest cost.

• Collected fees can be utilized to significantly offset customer costs or to 

achieve other public policy objectives at the states' discretion.

• Allows states to achieve the benefits of coordinated regional action 

without negotiating comprehensive interstate compliance agreements - a 

complex process that might take years to complete.

• Provides states and industry with a longer compliance runway, allowing 

for improved planning and regulatory certainty.

• Provides states and customers with a viable voluntary approach to 

compliance.

• Resolves, in part, the compliance questions surrounding the 

reasonableness and viability of the EPA's building blocks by providing 

another pathway to compliance during the safe harbor period.

Commenters suggested the regulated fossil fuel-fired generator pay a fee based on their 

emissions over a given period of time. Commenters stated that such an approach would include 

normal reporting, compliance, and enforcement provisions, as well as backstop requirement to 

track and regularly adjust fees annually if emissions rise above levels allowed by the state 

standard of performance.

Commenters stated that the dispatch-fee concept could be applied outside organized markets if 

the single utility dispatching multiple generation sources agrees to reflect a CO2 fee in the 

dispatch cost of its fossil generation, much like the RTO would. Commenters noted that the 

utility would then determine least-cost dispatch, including the CO2 fee and customers would pay 

rates based on the increased average fuel cost associated with the units dispatched.

Commenters recommended the EPA allow states to comply with the interim goals by choosing to 

participate in a program called "Smart System Dispatch" that uses the existing reliability-driven 

least-cost dispatch combined with a carbon fee to shift generation to lower emitting sources of 

electricity generation. Commenters stated that under this approach, the EPA would determine a 

uniform per-ton fee on CO2 emissions from power plants that would result in emissions 

reductions commensurate with the interim goals. Commenters stated that carbon-emitting 

generators in a state that opts into this program would include that carbon fee as a cost of 

operating. Commenters argued that efficient, low-emitter EGUs (e.g., NGCC plants, single-cycle 

gas turbines, and natural gas-fired steam plants) operate less frequently than higher-emitting coal 

plants because they have higher operating costs. Commenters believed that b including a carbon 
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fee in the bid price, lower-emitting units would be relatively less expensive than higher-emitting 

units and this price differential would result in lower-emitting units operating more than their 

higher-emitting counterparts. Commenters also noted that higher-emitting units would not be 

precluded from operating when they are economic, which would keep many of these plants 

available when needed to maintain reliability. Commenters noted that coal plants with lower 

CO2 emissions could be rewarded with lower carbon fees per megawatt-hour. Commenters

believed a carbon fee of about $15 to $20 per ton would be sufficient to produce emission 

reductions adequate to achieve the interim goals, based on recent modeling conducted by PJM 

(see PJM Interconnection, Inc., "EPA's Clean Power Plan Proposal, Review of PJM Analyses 

Preliminary Results" (Nov. 17, 2014), available at http://www.pjm.com/~/media/committeesgroups/committees/mc/20141117-webinar/20141117-item-03-carbon-rule-analysispresentation.ashx). Commenters stated that this same study shows that the interim goals can be 

achieved without threatening reliability and with costs comparable to the cost of other measures 

that the EPA determined to be cost-effective. Commenters noted that some states may be able to 

achieve the interim goals at a carbon fee lower than the uniform carbon fee determined by the 

EPA, which would be a disincentive to participate in a carbon fee based system. To promote 

regional approaches, commenters recommended the EPA to allow states to participate in the 

program at a lower carbon fee provided they demonstrate that the EPA's uniform carbon fee 

would reduce emissions more than 10 percent (or some other margin) below the state's emission 

goals. 

Commenters noted that the carbon fees collected by this type of program could be redistributed 

to the load-serving entities that purchase electricity on the wholesale market and could then be 

used for retail bill relief, to support investment in energy efficiency or clean demand response 

programs, or for some other mechanism to reduce total costs for consumers. Commenters stated 

that this approach could be employed by ISOs, RTOs, and vertically-integrated utilities.

Commenters stated that "Smart System Dispatch" would have the following benefits:

• Achieve emissions reductions in the most cost-effective manner. 

• Provide cost-containment for states by placing a ceiling on compliance 

costs and protecting consumers from large, rapid rate increases due to 

the Clean Power Plan.

• Allow states to participate in coordinated regional action without 

negotiating comprehensive interstate compliance agreements. 

• Minimal disruption to the existing grid management system and electric 

reliability because the system relies on existing resources and existing 

market structures to reduce emissions during the interim compliance 

period.

• Would spur investment in new clean generation resources and retain 

existing clean resources by providing the right market signals.

• Avoids setting operating hour limits for high emitting EGUs.
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• Would help mitigate the economic pressures on existing nuclear and 

hydroelectric plants, and thereby help to prevent the early retirement of 

those plants, by ensuring the cost of carbon emissions is appropriately 

reflected in market signals. 

• Would make investment in nuclear upgrades, additional renewable 

generation, and energy efficiency more profitable. 

• Would incentivize heat rate improvements.

• Would drive long-term investment in carbon capture and sequestration 

(CCS).

• Reduces the potential for "leakage" from states that participate in 

existing cap and trade programs.

Commenters also recommended the EPA provide a "safe harbor" for states by recognizing that 

state participation in this type of program provides automatic compliance with the state interim 

goals. Commenters believed the "safe harbor" would relieve states of the risk that short-term 

actions might produce unexpected adverse consequences for reliability or compliance, and would 

allow them to focus on developing their long-term plans to achieve the final emission goals by 

2030.

Commenters suggested an ISO-administered adjustable carbon fee whereby the electricity from 

affected EGUs would be priced according to the emission rate of each affected EGU and the 

affected EGUs would pay for the added carbon cost. Commenters explained that the system 

would work as follows:

• States in a region translate their emission performance goals into targets 

for the relevant regional power market; 

• An independent party facilitates the states that participate in the 

approach to translate the emissions target into a regional carbon fee;

• The ISO administers the wholesale electricity market with the added 

carbon fee;

• Affected EGUs pay the fee according to their dispatch and their 

emissions rate;

• The ISO collects the fees from the affected EGUs; and, 

• The ISO refunds the fees to load-serving entities ("LSEs") based on load 

share ratios or a similar approach.

Commenters further explained that the EPA would approve state and regional plans if they 

demonstrate the carbon fee is sufficiently stringent to achieve the state or regional emission 
134

performance goal and noted that states should be able to use modeling to predict with a high 

degree of accuracy the carbon fee level that is necessary. Commenters believed the carbon 

dispatch fee approach would provide a greater degree of certainty to affected EGUs and the 

market as a whole regarding the cost of compliance than other compliance options because the 

price would be pre-established, with upward adjustments triggered only when the affected EGUs 

fail to achieve the emissions performance goals. 

Comment 16: Comments suggesting that the EPA should not allow ISO/RTO administered

dispatch fee mechanisms.

Response 16: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA.

The following are summaries of the specific public comments under this comment:

Commenters believed that RTOs/ISOs should not be given any market-related role in 

implementing the Final Rule. Commenters believed that if a carbon fee program is implemented 

in an RTO region, it will face challenges in achieving its goals and will likely increase the costs 

to consumers. Commenters recommended states proposing a carbon fee approach should 

establish a non-RTO regional entity to manage its implementation. Commenters also discussed 

four recent studies regarding the use of ISO/RTO market-based fees to reduce CO2 emissions 

from power plants: (1) a detailed report by the Brattle Group; (2) a study by the ISO/RTO 

Council; and (3) a study by the Clean Air Task Force that includes the results of an analysis 

conducted by the NorthBridge Group that looks at the potential CO2 emissions reductions by 

2020. Commenters provided the following reasons for not supporting a RTO/ISO market-based 

approach: 

• The bid markets are not truly competitive markets. Commenters noted 

that EGU owners sometimes offer prices above or below the actual costs 

of production. Commenters gave the example of an owner of a fleet of 

plants who offers a marginal plant at a higher price to drive up the 

clearing price and thus the earnings for its other plants, even if it means 

that one plant is less likely to be dispatched (known as economic 

withholding).
135

• RTO tariffs and market rules are in flux, which creates uncertainty about 

future market design. Commenters noted that there are three open 

administrative dockets at FERC that raise fundamental questions about 

the capacity, energy, and ancillary services markets that could pave the 

way for potentially broad changes within these markets. 

• Bid markets are opaque and have limited data transparency. 

Commenters noted that offers to sell electricity are published with a 

three or four month time lag and then are only posted with the identity of 

the bidders masked. Commenters believed that such limited data makes 

it difficult for market participants and observers to determine the extent 

of deviations in market behavior from a competitive market.

• The governance structure of the RTOs does not ensure adequate 

representation of the views of all entities affected by RTO policies, 

including the states that would be charged with implementing such 

programs. Were an RTO to manage a CO2 emissions reduction program 

for a state or group of states, commenters believe it would be difficult to 

ensure that state goals would be achieved or that that the public would 

be adequately protected.

• Several states are split by RTO boundaries and some individual utilities 

must operate in more than one RTO. Commenters argued that these 

states would have to draft plans that comply with requirements of more 

than one RTO and would make some utilities operate with differing 

RTO requirements that could be incompatible.

• The EPA's legal authority may not allow a direct fee or tax on merchant 

generators to be included in the CO2 emission reduction guidelines.

• Difficult to determine an optimal carbon price that achieves emissions 

reductions while not causing a level of retirements that threatens 

reliability. 

• It may be difficult to determining the appropriate price to pay generators 

or charge load from non-participating states located within the RTO. 

• Should new generators complying with the NSPS be subject to the same 

pricing rules as existing generators? 

• How should generators with legacy long-term contracts that are priced 

outside of the RTO markets be handled?

Commenters stated that the EPA has no jurisdiction over RTOs and therefore cannot force RTOs 

to alter operations to comply with state plans. Commenters also argued that RTO expertise is in 

running electricity markets and maintaining the reliability of the grid and that RTOs have no 
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experience in monitoring or controlling emissions. Commenters believed that RTOs should 

remain focused on grid reliability and the efficient functioning of the market. 

Commenters also provided several detailed hypothetical scenarios to show the complexities of 

RTO markets and how the outcome of RTO-operated markets could be unpredictable and may 

not result in emissions reductions. Commenters noted that there are additional factors besides 

economic withholding or other forms of strategic bidding that may cause a carbon fee, working 

in conjunction with the RTO market prices, to not necessarily be the least-cost means of 

compliance for the Proposed Rule's environmental redispatch building block. Commenters stated 

that financial entities can play a significant role in the energy markets and price formation. 

Commenters stated that there are tools available in the RTO markets, such as virtual bids, that 

allow financial entities that do not own resources to "buy" and "sell" electricity, arbitraging 

prices between the real-time and day-ahead market or between two different sets of pricing 

points (such as through Up-to-Congestion transactions, referring to transmission congestion that 

can cause price differentials in the RTO energy markets). Commenters noted that because these 

sales and purchases do not involve actual generation, they can influence energy prices separately 

from any carbon pricing.

Commenters stated there are several scenarios where a generator may run even if its offer price is 

above the clearing price (also known as "out-of-merit" dispatch) because they are compensated 

for the difference between their offer and the clearing price through what are known as "uplift" 

payments. Commenters noted that this can occur when system operations are not accurately 

modeled, requiring the use of generating units that are manually dispatched in real time to ensure 

reliability, even if their offers exceeded the clearing price, while units that did clear could be 

manually curtailed. Another scenario discussed by the commenters occurs where a unit 

committed in the day-ahead market does not clear the real-time market, but must continue to run 

because of minimum run times or an inability to ramp down quickly. Commenters noted that 

such units would also receive uplift payments. Commenters stated these scenarios could result in 

the operation of higher CO2 emitting units than anticipated by the environmental dispatch 

program.

Commenters also questioned whether RTO-operated markets would shift dispatch between 

existing coal and natural gas plants. Commenters noted such a shift could be difficult to achieve 

in practice because (1) a portion of natural gas plants are best used as peaker plants because of 

their ramping capabilities and with an increase in variable, renewable energy penetration, a good 

portion of the gas-fired capacity is going to need to be used as flexible ramping capacity; (2) a 

lack of access to natural gas, due to limits on pipeline and storage capacity, can impede the 

ability to increase the dispatch of natural gas-fired units; and (3) the fee assessed on CO2

emissions to achieve an increase in dispatch of natural gas-fired units could be significant. 

Although RTOs dispatch units with the lower price offers first, commenters asserted that RTOs 

do not reduce the total costs paid for electricity. Commenters stated that if the compliance 

measures undertaken increase the costs of a marginal unit and that cost is reflected in the offer, 

then those costs would apply to all kilowatt-hours consumed within a given hour. Commenters 

stated a single-clearing price approach is inherently more expensive than a regime where cost is 

recovered only for the electricity generated by an individual plant. Commenters noted generators 

do not necessarily bid their actual costs and may decide to bid substantially above their costs.
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Commenters also disputed statements in the proposal that "operators of EGUs subject to CO2

emissions limits in RGGI now include the cost of RGGI CO2 allowances in those EGU's variable 

costs." Commenters argued that the extent to which the RGGI emission allowance prices have 

been reflected in generators' offers and therefore affect RTO dispatch does not appear to have 

been studied. Commenters noted that studies by The Analysis Group only modeled the dispatch 

in the RTO markets and did not observe actual behavior. Commenters noted that the PJM market 

monitor publishes estimates of the cost components of the marginal unit by multiplying the 

carbon emission allowance price by the emissions of that unit's technology type, and is not an 

analysis of how actual offers or the dispatch itself was affected by the carbon allowance prices. 

Commenters noted that in 2013, the CO2 emission allowance accounted for 0.3 percent of the 

LMP while the mark-up (or the difference between costs and price offers) was a negative two 

percent of the LMP. Commenters also noted that for the first half of 2014, the CO2 emission 

allowance was the same percentage while the mark-up was 2.5 percent. Commenters argued the 

markup added or subtracted from the generators' actual costs was much more of a driver of the 

offers than the emission allowance cost. Commenters believed this illustrates the complexity of 

how offers are formed and how the emission allowances affect offers.

Commenters stated they believe that a carbon tax approach offers advantages over the approach 

suggested by Great River Energy and Brattle Group which have Integrated System Operators 

(ISO) impose a carbon price on affected sources via a bid mechanism. Commenters also believed 

that although using the ISO in this way would incentivize dispatch in an economically efficient 

manner, this approach has the following four limitations:

• Would not necessarily produce retail electricity prices that reflect the 

full carbon price, which could potentially offset the incentive to reduce 

electricity use. 

• Could result in substantial transfers from ratepayers in one state to 

entities in another state, introducing potential political challenges, 

whereas a state excise tax ensures that carbon charges collected in a state 

remain in that state. 

• Many states are not completely covered by a single ISO and some states 

have more than one ISO and/or have areas in which no ISO operates. 

Commenters noted that each of these areas would require separate 

treatment in a state compliance plan. 

• Would create no administrative structure that could be used to regulate 

emissions from other stationary source categories, thereby making states 

develop compliance approaches from scratch for any future 111(d) rules. 

Commenters argue that states could easily extend an excise tax policy 

from power plants to other sources to meet other section 111(d) rules.
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Comment 17: Comments suggesting that generation shift that includes a fee mechanism would 

face legal challenges.

Response 17: Should a state choose, it could apply a fee or tax for CO2 emissions from 

affected EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from 

affected EGUs, as a state measure under a state measures type plan. Where a state applies a fee 

for CO2 emissions from an affected EGU, and the fee paid is for an emission allowance that 

allows an affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an 

emission standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not 

have a position on the design elements of a carbon fee or tax, including the entity to which a fee 

or tax is applied, the entity administering the fee or tax (the state directly or an agent of the state, 

such as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to 

apply a fee or tax, with respect to state or federal statutes outside the scope of the CAA.

The following are summaries of the specific public comments under this comment:

Commenters believed that re-dispatch approaches with fee mechanisms would likely face legal 

challenges. Commenters gave the example of a state that implements a re-dispatch plan that 

includes a CO2 tax on electricity generation in an effort to decrease the economic dispatch of that 

generation. Commenters believed that resources in the State affected by the tax, particularly 

those whose output is sold outside the state, would have a basis for a Commerce Clause 

challenge because the state is harming interstate commerce. Commenters stated that even if such 

a Commerce Clause challenge was unsuccessful, there may be a successful pre-emption 

challenge because by implementing a CO2 tax with the intent of affecting wholesale prices in the 

FERC-jurisdictional MISO market, for the purposes of changing the dispatch order of resources 

in that FERC-jurisdictional MISO market, the state could be found to have interfered with 

FERC's exclusive jurisdiction over those prices.

Commenters also noted that states could make changes to the MISO tariff as a means of 

implementing an environmental dispatch, but such tariff changes would have to be negotiated 

through the MISO stakeholder process, approved by the MISO board, approved by FERC, and 

ratified by the courts. Commenters stated that the state would have to obtain consensus among 

the 12 states served by MISO, the state-regulated utilities served by MISO, the independent 

power producers and the transmission owners and operators. Commenters noted that these 

entities have different interests and many utility owners, consumer advocates, and other states 

would likely oppose such changes. Even if a tariff change was agreed to by all parties, 

commenters believed that FERC would have to decide whether its responsibility to ensure that 

rates are just and reasonable and not unduly discriminatory would permit it to approve an 

environmental re-dispatch tariff that increases rates. Commenters argued that if FERC approved 

a tariff that discriminates against certain resources based on their emissions of CO2, it would 

likely be challenged in a court of appeals. Commenters concluded by saying that implementing a 

fee-based tariff mechanism as part of an environmental re-dispatch system would be a very slow 

process that creates significant uncertainty for the industry.
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Comment 18: Comments stating that the EPA should allow financial instruments (e.g., term 

bonds and certificate of deposit) as a compliance option. 

Response 18: Should a state choose, it could apply a fee or tax for CO2 emissions from affected 

EGUs, or related excise tax that directly or indirectly addresses CO2 emissions from affected 

EGUs, as a state measure under a state measures type plan. Where a state applies a fee for CO2

emissions from an affected EGU, and the fee paid is for an emission allowance that allows an 

affected EGU to emit a ton of CO2, such a mechanism would meet the definition of an emission 

standard in the EPA’s implementing regulations at 40 CFR 60.21(f). The EPA does not have a 

position on the design elements of a carbon fee or tax, including the entity to which a fee or tax 

is applied, the entity administering the fee or tax (the state directly or an agent of the state, such 

as an ISO or RTO), or any legal issues that might arise, based on how a state chooses to apply a 

fee or tax, with respect to state or federal statutes outside the scope of the CAA.

The following are summaries of the specific public comments under this comment:

Commenters recommended using financial instruments such as term bonds or certificate of 

deposit as a means to reducing CO2 emissions from existing utility boilers. Commenters

explained that the bond or CD would have a fixed unit price (example $25 per ton) and EGUs 

and other industries would buy these bonds or CDs from a financial institution in the amount 

equivalent to their emissions. Commenters stated that the money paid for the bonds or CDs 

would then be pooled and used to finance energy efficiency and renewable energy programs. 

Commenters explained this approach differs from other cap-and-trade programs because at the 

end of the term, the money paid for the bond or CD would be returned to the emitter with 

interest. Commenters believed this system would work well for reducing emissions since it 

allows both the EGU and their customers to share the responsibility for carbon emissions. 

Commenters further stated that customers would either buy the bonds individually or the bonds 

could be automatically purchased as part of their electricity billing. Commenters believed this

approach is better than a cap-and-trade program because (1) the price of carbon pollution is 

stable; (2) the system does not need any complex trading structure; (3) promotes investment in 

energy efficiency and renewable energy programs; and (4) makes it easier for utilities to stay 

competitive.

Commenters also suggested utilities could sell revenue bonds for the purpose of raising revenue 

for renewable energy, energy efficiency, storage, smart grids, and other greenhouse gas reduction 

projects.

Comment 19: Commenters stated that the EPA and states should invest in efficiency 

improvements, support research and development of new technologies (e.g., carbon capture and 

storage) instead of imposing emission limits on power plants.

Response 19: CAA section 111(d) requires states to establish standards of performance for 

affected sources that are consistent with emission guidelines established by the EPA.

The following are summaries of the specific public comments under this comment:
140

Commenters believed investing in efficiency improvements, deploying advanced super critical 

coal plants and supporting greater research and development towards next generation 

technologies (including carbon capture and storage) would be a better approach to reducing 

greenhouse gas emissions from power plants.

Commenters recommended that state plans be dynamic to account for innovation, changes in 

public will, and changes in government.

Comment 20: Comments suggesting that the EPA should not limit states authority, flexibility, or 

discretion to design a plan that meets the individual state needs.

Response 20: In the final emission guidelines, the EPA has provided states with a range of plan 

approaches that could be used to meet the emission guidelines. Under each approach, a state also 

has significant discretion in the types and levels of emission standards it applies to individual 

affected EGUs or groups of affected EGUs in a state plan, or the types of state measures used 

under a state measures plan type. This range of approaches and discretion in applying individual 

emission standards or state measures is discussed in section VIII.C of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters supported the flexibility for states to design their plans using a variety of different 

plan structures. Commenters believe the EPA guidelines should not limit the states' authority, 

flexibility, or discretion in the development of a state plan and should allow states to develop 

plans beyond the four proposed pathways. Commenters stated the EPA should not disapprove 

section 111(d) plans that do not conform to the plan types identified in the proposal because 

section 111(d) gives states the primary responsibility for designing their own state plans.

Similarly, commenters requested the EPA not limit the available compliance options because 

Montana needs all of the available options to design a plan that meets the proposed rule in the 

required timeframe.

Commenters believed that states should take the lead role in designing state implementation 

plans under section 111(d) and that the final rule should provide broad flexibility for each state to 

choose the approach that is most cost-effective, and that works best for each state and its 

stakeholders.

Commenters believed the CPP should allow states the flexibility to use a variety of approaches to 

reduce CO2 emissions, including rate-based limits, mass-based limits, a portfolio of other 

approaches such as RE, EE, re-powering, and coal plant retirements, or cap-and-trade programs. 

Commenters noted that their company has employed renewable energy, energy efficiency and 

conservation, and coal plant retirements and repowering to comply with measures in Minnesota, 

Colorado and other states. Commenters argued that states should have the authority to employ 

any strategies they believe will be effective and appropriate using their understanding of the 

technical and economic intricacies of the electric systems in their states. Commenters believed 

that only states will have the expertise and capabilities necessary to develop many of these 
141

programs and noted that many states have already made significant investments in reducing their 

emissions. 

Commenters stated the EPA appropriately recognizes that states have the authority to include 

non-BSER measures in compliance plans. Commenters stated the final guidelines should affirm 

the ability of states to include a wide range of non-BSER measures, both those identified by the 

EPA in the guidelines and those not specifically included, in an approvable state compliance 

plan. 

Commenters stated that a reliable and affordable energy supply is vital to any state's economic 

growth, jobs, and the overall interests of its citizens, and urged the EPA to recognize state 

authority by relying on state regulators to develop standards that take into account the unique 

policies and circumstances of each state.

Commenters stated that Austin Energy's ability to consider both demand-side and supply-side 

resources in an integrated way allows for the use of renewables and DSM to meet customers' 

needs while avoiding CO2 emissions and lowering the system-average CO2 emissions rate. 

Commenters said that Austin Energy's ratepayers continue to invest in these actions, which in 

effect help reduce the statewide average CO2 emission rate. Commenters said that Austin Energy 

operates as part of the electricity grid and market overseen by the Electric Reliability Council of 

Texas (ERCOT). Commenters said that many other generators in ERCOT do not serve retail 

customers and have not had the incentive to reduce CO2 emissions beyond-the-fence. 

Commenters said compliance flexibility at the generator level within a state will be necessary to 

ensure all generators reduce their fair share of emissions using compliance strategies available to 

their parent company. Commenters said that Austin Energy recommends that state plans include 

beyond-the-fence strategies as part of a menu of compliance options, and not limit compliance 

options to only those that are accessible to all generators.

Comment 21: Comments suggesting that the EPA should allow states to establish special 

requirements for utilities that have a disproportionate level of implementation costs.

Response 21: The EPA disagrees with the commenters that such special requirements are 

necessary to address the concerns raised by the commenter. In the final emission guidelines, the 

EPA has provided states with a range of plan approaches that could be used to meet the emission 

guidelines. Under each approach, a state also has significant discretion in the types and levels of 

emission standards it applies to individual affected EGUs or groups of affected EGUs in a state 

plan, or the types of state measures used under a state measures plan type. This range of 

approaches and discretion in applying individual emission standards or state measures is 

discussed in section VIII.C of the preamble to the final rule.

This range of plan approaches, and state discretion in applying emission standards for affected 

EGUs or state measures, provides states with significant discretion to address the types of 

concerns described by the commenters through the design of a state plan.

The following are summaries of the specific public comments under this comment:
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Commenters stated that the EPA should allow states to set up alternative compliance systems, 

subcategories, and alternative regulatory systems for public power utilities that would face a 

disproportionate stranded cost or debt to the local community, but the states should be able to 

determine how best to design, manage, and implement these systems. 

Commenters noted that many of 103 generation and transmission coops operate across state lines 

and recommended state plans be developed specific to the special needs of these generators. 

Commenters argued that many coops have recently incurred substantial debt for pollution 

upgrades for their coal plants and oppose the proposed guidelines. Commenters believed that 

coops would support the rulemaking if special rules were developed by the EPA and the USDA 

that would promote investment in RE and EE by coops. Commenters recommended that the EPA 

and USDA develop programs that would allow coops to swap coal-debt for renewable resourcesdebt. Commenters also recommended that coops be allowed to sell renewable energy to other 

coops with fewer renewable resources. Commenters noted that one third of coops already have 

good RE/EE programs, one third have public information programs only, and one third have no 

programs at all. Commenters also noted that Agriculture Secretary Tom Vilsack has created a 

new loan program to fund efficiency and renewable energy investments by coops and believed

there is significant potential to reduce energy consumption using energy efficiency retrofitting.

Comment 22: Commenters suggest that EPA allow state plans to apportion the state goal (either 

rate-based or mass-based) to energy generating utilities within the state at the company level and 

set accounting rules for RE, EE, HRI, fuel-switching or co-firing, transmission line efficiency 

improvements, distributed solar, etc.

Response 22: In the final emission guidelines, the EPA has provided states with a range of plan 

approaches that could be used to meet the emission guidelines. Under each approach, a state also 

has significant discretion in the types and levels of emission standards it applies to individual 

affected EGUs or groups of affected EGUs in a state plan, or the types of state measures used 

under a state measures plan type. This range of approaches and discretion in applying individual 

emission standards or state measures is discussed in section VIII.C of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended an alternative implementation approach in which the state 

environmental agency could apportion the state goal (rate-based or mass-based) to energy 

generating utilities in the state (at the company level) and a set of accounting rules would 

establish how to credit RE, EE, HRI, fuel-switching or co-firing, transmission line efficiency 

improvements, distributed solar, etc. and to which entity they would accrue. Commenters stated 

that utilities would decide what mix of actions would be most cost-effective for meeting the 

requirements while maintaining grid reliability, but intrastate trading of credits would be 

allowed. Commenters stated that the state would track and report progress along an established 

glide path and each utility would have a clear compliance target to meet by 2030.
143

Commenters supported company-based multi-state plans as the best approach because it would 

provide flexibility to companies that operate in more than one state.

Comment 23: Commenters requested EPA develop model rules and/or provide more guidance.

Response 23: In response to comments, the EPA is proposing model rules for rate-based and 

mass-based emission trading programs that could be included in a state plan. More details are 

available in the preamble to the proposed Federal Plan. These model rules, when finalized, 

would constitute presumptively approvable elements of a state plan. In that action, the EPA is 

also proposing rules for a rate-based and mass-based federal plan.

The EPA also notes that in the preamble to the final rule it has provided a significant level of 

detail about the approvable state plan approaches and treatment of emission reduction measures 

in state plans. These detailed descriptions of plan approaches and requirements are provided at 

sections VIII.C, VIII.D, VIII.I, VIII.J, and VIII.K of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Some commenters recommended the EPA provide more guidance and support to states to assist 

them in developing and implementing state plans. Commenters would like the EPA develop a set 

of detailed planning models and assumptions for states to use in developing their state plans. 

Commenters believed the EPA should develop a federal plan or set of plans for states to follow if 

they choose. Commenters suggested that a set of models would be the best way to allow states to 

calculate impacts of particular strategies and explore alternatives in a thorough manner. 

Commenters believed that by providing assistance to states, the EPA will avoid having to 

consider implementing a Federal Plan.

Commenters stated that the proposal leaves states in a difficult position by providing states with 

only "a bare bones description of how states might develop satisfactory plans." Commenters

believed the EPA has provided insufficient guidance on how to develop and implement a state 

plan.

Commenters suggested the EPA develop detailed guidance on state and regional policy 

approaches and develop a rate-based and a mass-based approach that can become the federal 

plan(s) if a state fails to develop a compliant state plan. Commenters stated the EPA should 

release these model plans or guidance around the same time as the guidelines are finalized.

Commenters suggested the EPA provide more guidance and examples of how states would 

implement rate-based or mass-based plans. 

Comment 24: Commenters requested that EPA develop and implement national plan to limit 

carbon emissions, promote reforestation programs, and reduce atmospheric carbon 

concentrations to 350 ppm by 2100.
144

Response 24: The EPA acknowledges the comment, but notes that the authority for the EPA to 

implement such requirements is outside the scope of CAA section 111(d).

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA immediately develop and implement a National Climate 

Recovery Plan based on the best available science to limit carbon emissions and promote 

reforestation programs to lower atmospheric carbon concentrations to 350 ppm by 2100. 

Commenters stated that delays in implementing such a plan will make it more difficult to 

administer the program and achieve necessary emissions reductions. Commenters noted that the 

plan would need to reduce national emissions by at least 7 percent per year or by 15 percent per 

year if the plan is not implemented until 2020. Commenters also provided copies of seven legal 

briefs, which the commenters stated support the need for the EPA to develop and implement a 

National Climate Recovery Plan.

Comment 25: Comments suggesting states should be able to use both rate- and mass-based 

targets in their state plans.

Response 25: In the final emission guidelines, states have discretion to implement rate-based 

and mass-based emission standards, or state measures, in a state plan, and a plan may include a 

mix of different rate-based or mass-based emission standards for different individual affected 

EGUs or groups of affected EGUs. This flexibility to apply emission standards to affected EGUs 

in different rate or mass forms under a state plan is distinct from the rate-based or mass-based 

emission performance metric for affected EGUs that a state plan must meet. A state plan must 

meet either a rate-based or mass-based emission performance metric that applies to all affected 

EGUs in a state. Clarification of these issues is provided in section VIII.C of the preamble to the 

final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA allow states to use both rate- and mass-based targets in their 

state 111(d) plans. Commenters stated they would like the EPA to include an option for states to 

be able to allow affected EGUs to meet the emission limits through either a rate- or mass-based 

standard, depending on the unique status of the affected EGU. Commenters argued that this 

approach is necessary for EGUs within a given state will be differently situated with respect to 

the types of strategies that make the most technical and economic sense to employ. Commenters 

noted that a small municipal utility with a single coal-based power plant may find it difficult to 

reduce its average emission rate through the acquisition of new renewable resources but could 

economically shut down one of the units at the facility to meet the equivalent mass-based goal, 

while a large multi-state generation and transmission company operating within the same state 

could readily reduce its emission rate by increasing its utilization of existing low-emitting gas 

resources, but could not sufficiently curtail generation to meet a mass based limit. Commenters 

suggested that rather than having to choose between these competing concerns, the EPA allow 

states to use a hybrid approach to best tailor their plans to the existing circumstances of each 

affected EGU within the state. Commenters stated that it should not matter whether different 
145

approaches are applied to utilities in the same state as long as states can demonstrate that the 

emissions achieved by their state plans are equal to or less than a rate-based or mass-based 

approach.

Commenters believed that requiring each state to choose between rate and mass-based 

approaches may result in conflict between the large utilities in Colorado and Tri-State 

Generation and Transmission (G&T) utility, which severs Colorado's 22 rural electric 

companies. Commenters believed that the larger utilities will favor the rate-based approach, 

while the smaller utilities may prefer the mass-based approach because of their greater reliance 

on coal. Commenters noted that the larger utilities have already invested in renewable energy 

and begun converting from coal to natural gas. Commenters recommended that to avoid this 

conflict, the EPA allow each utility within a state to choose the most cost-effective approach as 

long as the overall statewide goal is met. Commenters recommended each generation and 

transmission utility be given the flexibility to choose a mass-based, a rate-based, or a hybrid 

approach.

Commenters wanted to know whether a state plan can contain both rate- and mass-based limits. 

As an example, commenters asked whether a state plan could set mass-based emission limits for 

power plants "A" and "B" and a rate-based limit for other power plants (e.g., Parent company 

"C" will limit total CO2 emission rates for all of Power company "C" utilities to "Y" lb CO2

/MWh-net), provided the state plan adequately demonstrates an enforceable mechanism to meet 

the proposed EPA CO2 emission limit in 2030 and beyond and in the interim time frame of 2020-

2029. 

Comment 26: Comments suggesting that plans would more efficiently meet the EPA's goals 

than a federal plan.

Response 26: The EPA agrees with the commenter, and prefers that states develop and submit 

state plans that best address their circumstances and policy goals in meeting the emission 

guidelines.

The following are summaries of the specific public comments under this comment:

Commenters asserted that state plans would meet EPA's goals more efficiently than a federal 

plan but did not provide any details regarding how state plans would be more efficient.

Comment 27: Comments requesting additional information on the use of the Carbon Reduction 

Credit Program developed by the Western Resources Advocates (WRA)

Response 27: The EPA takes no position on the use of such a program in a state plan, but notes 

that the design of the program, as described by the commenter, differs in some respects from 

requirements for rate-based emission trading programs, as described in section VIII.K.2 of the 

preamble to the final rule. The EPA also notes that certain design elements of the program differ 
146

from basic accounting requirements for the adjustment of the reported CO2 emission rate of an 

affected EGU, as described in section VIII.K.1.a.(1) of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters asked whether the EPA will allow states to use a market-based approach developed 

by Western Resources Advocates (WRA) called the Carbon Reduction Credit (CRC) Program 

consisting of a credit-trading program in which EGUs can exchange, sell or purchase credits 

among themselves and with non-EGUs. According to the commenters, the CRC program would 

work as follows: 

• Credits would be provided to each EGU annually according to the 

formula:

• (State standard - EGU emission rate) x EGU MWh

• An EGU with an emission rate less than the state standard would earn 

credits, while those with an emissions rate greater than the state standard 

would have a credit deficit. Because they are zero emitting resources, 

eligible RE and EE providers would earn credits by the same formula, 

which simplifies to:

• (State standard) x RE (or EE ) MWh

• Each year, an affected EGU must demonstrate to the state that it has a 

credit balance greater than or equal to zero based on its own emission 

rate and acquiring and retiring an amount of credits equal to any deficit 

it has accumulated during a compliance period.

• Credit deficiencies existing after the applicable compliance period 

would be a violation of the rule and subject to enforcement.

Commenters stated that one of the advantages of the CRC program is that it can be expanded to a 

multi-state program without requiring states to adopt the same standard for the multi-state region.

Commenters noted that requiring states to adopt a single multi-state limit will discourage states 

from joining a multi-state plan since states with a less stringent standard will be reluctant to join 

with a state with a more stringent standard if a single multi-state standard is set by a weighted 

averaging methodology and will not result in the same volume of emission reductions as standalone programs. Commenters stated that for states entering into multi-state programs, that 

program credits would be transferred between member states using an exchange rate that 

accounts for the difference in state standards and avoids gaming opportunities of locating 

emission reduction systems in less stringent jurisdictions. Commenters noted that an exchange 

rate is needed since if two states agreed to accept each other's credits at face value without an 

exchange rate one MWh of renewable energy in a state with a 2000 lbs/MWh standard would 

earn twice the number of usable credits as an identical resource in a state with a 1000 lbs/MWh 

standard. Commenters noted that similar issues would arise with natural gas plants where 
147

additional credits could be earned by increasing production in one state over another. 

Commenters stated that to avoid such situations, WRA has developed an exchange rate formula 

that would adjust the CRC values when traded between states participating in multi-state

programs. Commenters asserted that the CRC program would avoid these problems, would be 

technology neutral and flexible, and would avoid issues of whether or how it is possible to hold 

non-EGUs legally responsible for compliance with the Clean Power Plan. Commenters provided 

a paper describing the CRC plan in detail and included model regulatory language that could be 

used by states when developing their state plans.

Comment 28: Commenters supported using RTOs to help with regional planning for CPP

because of established relationships between states and Tribes.

Response 28: In the final emission guidelines, the EPA is requiring states to consult with the 

applicable ISO, RTO, or balancing authority in which a state is located to evaluate any potential 

electric reliability concerns related to a single-state or multi-state plan. This requirement is 

discussed in section VIII.G.2.c of the preamble to the final rule. The EPA also encourages states 

to consult more broadly with the applicable ISO, RTO, or balancing authority in which a state is 

located. Such organizations may be able to assist states in developing regional strategies that can 

meet the emission guidelines at lower cost than a single-state plan, and can also help facilitate 

coordination in the development and implementation of single-state plans.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA should consider using the five regional planning organizations 

(RPOs) as part of its approach because these entities have existing frameworks and governance, 

established relationships between states and Tribes, and a proven track record of using their 

combined technical, policy, and legal resources and expertise to address air quality issues 

effectively on a local, regional, and national level. Commenters noted that RPOs have a good 

understanding and respect for Tribal cultural values and practices, which commenters believed 

would help in implementing the proposed rule across state and Tribal borders. Commenters 

further recommended the EPA provide sufficient funding for and work closely with the existing 

RPOs to help implement the final rule.

Comment 29: Commenters suggested that the EPA set targets but allow states to meet those 

targets using methods of their choosing.

Response 29: In the final emission guidelines, the EPA has provided states with a range of plan 

approaches that could be used to meet the emission guidelines. Under each approach, a state also 

has significant discretion in the types and levels of emission standards it applies to individual 

affected EGUs or groups of affected EGUs in a state plan, or the types of state measures used 

under a state measures plan type. This range of approaches and discretion in applying individual 
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emission standards or state measures is discussed in section VIII.C of the preamble to the final 

rule.

The following are summaries of the specific public comments under this comment:

Commenters believed the EPA should set emission targets but not specify pathways for 

compliance. Commenters believed that the authority of state utility commissions to determine the 

appropriate mix of generation resources must be preserved and that states need to be allowed 

more flexibility to determine how best to meet emission targets without imposing unnecessary 

burdens on utilities and consumers. Commenters noted that North Carolina has a large nuclear 

portfolio but that the proposed rule would allow only 5.8% of energy from nuclear generation 

facilities to be included in determining compliance. Commenters stated that this mandate 

penalizes forward-acting states such as North Carolina.

Comment 30: Comments suggesting that the EPA allow a system of alternative compliance 

payments to mitigate compliance costs.

Response 30: An alternative compliance payment approach, as described by the commenter, 

does not constitute a standard of performance under CAA section 111(d), and therefore could not 

be included in a state plan as a federally enforceable emission standard for an affected EGU. 

However, if a state chose, it could include such an approach as a state measure under a state 

measures plan type, discussed in section VIII.C.3 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA allow states to implement an alternative compliance 

payment (ACP) system under which EGUs could elect to make payments to the state as an 

alternative compliance mechanism when "on-site limitations or regulatory risks (e.g., the risks of 

triggering New Source Review) prevent on-site modifications and the costs of the credits and 

system offsets are higher than anticipated." Commenters explained that the payments collected 

would be used by the state to fund activities under building blocks 2, 3, or 4, or other qualified 

energy sector. Commenters believed this approach would be beneficial to the state because it 

would provide funding for energy sector development and beneficial to power plants because it 

would enable EGUs to comply with the rule at a reasonable cost. 

Commenters stated that a ceiling-price ACP concept was first conceived during the 1990 CAA 

Amendments stakeholder discussions and formally articulated in President Clinton's July 1997 

memorandum to the EPA (62 Fed. Reg. 38421, 38429, July 18, 1997) when the 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, commenters noted that the memorandum recommended an ACP option for sources 

facing control costs at or above a cost-effectiveness threshold to fund reductions from other 

sources and to stimulate new technologies. Commenters also noted that the EPA has approved 

ACP programs under Clean Air Act Section 110 (see, e.g., SCAQMD Rule 1121, "Control of 

Nitrogen Oxides from Residential Type, Natural Gas-Fired Water Heaters").
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Commenters recommended the near-term price for a building block 1 ACP should reflect the 

upper bound of the EPA's anticipated building block 1 cost (e.g., $6 to $12 per ton of greenhouse 

gas emissions reduction) because the ACP would serve as an alternative to building block 1. 

Commenters believed a building block 1 ACP would be unlikely to interfere with the other 

building blocks because building block 1 would be implemented in the early years of the 

program and the implementation of other building blocks would likely occur over a longer period 

of time. Commenters also suggested the ACP should be used to help EGUs comply with the 

other building blocks.

Comment 31: Comments suggesting that state plans should not require a utility that already 

meets the state goals to subsidize other utilities compliance costs.

Response 31: In the final emission guidelines, the EPA has provided states with a range of plan 

approaches that could be used to meet the emission guidelines. Under each approach, a state also 

has significant discretion in the types and levels of emission standards it applies to individual 

affected EGUs or groups of affected EGUs in a state plan, or the types of state measures used 

under a state measures plan type. This range of approaches and discretion in applying individual 

emission standards or state measures is discussed in section VIII.C of the preamble to the final 

rule.

This range of plan approaches, and state discretion in applying emission standards for affected 

EGUs or state measures, provides states with significant discretion to address the types of 

concerns described by the commenters through the design of a state plan.

The following are summaries of the specific public comments under this comment:

Commenters did not support any particular approach to state plans but were concerned that the 

plans states develop should not adversely impact companies like FPL which have made 

significant investments in clean energy technologies over the past 15 years. Commenters noted 

that customers of the other Florida companies affected by the proposed Clean Power Plan did not 

pay for FPL's investments and believed that it would be inappropriate to make FPL's customers 

subsidize other company's compliance costs. Commenters argued that "fundamental principles of 

fairness and economic efficiency should prevail in establishing those approaches" and 

recommended states develop plans that focus on the most cost-effective and efficient approaches 

to reducing emissions that does not shift compliance costs from customers in one region to those 

in another region.

Comment 32: Commenters suggested that the EPA provide guidance on how to structure state 

programs so as to promote combined heat and power (CHP) systems.

Response 32: CHP systems are an eligible resource that could be used to adjust the reported 

CO2 emission rate of an affected EGU and for which ERCs could be issued. This is discussed in 
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section VIII.K.1.a.(9) of the preamble to the final rule. CHP could also be used as an emission 

reduction strategy at an affected EGU, as described in section VIII.I.1 of the preamble to the 

final rule. The EPA has also provided a Toolbox for state plan development, which includes 

description of state requirements and policies that facilitate greater use of CHP. The Clean Power 

Plan Toolbox for States is available at <http://www2.epa.gov/cleanpowerplantoolbox>.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA provide guidance and examples of programs and policies 

that would encourage use of CHP systems. Commenters stated that such guidance and examples, 

should recognize that some states have already adopted portfolio programs and other incentives 

and policies designed to encourage CHP system deployment and should not require an overhaul 

of these programs.

Comment 33: Commenters requested clarification on if the EPA would approve a state plant 

that commits to emission reductions but does not specify how they will be achieved

Response 33: The approach described by the commenters is not an approvable plan approach. 

The approach described by the commenters generally aligns with the state commitment approach 

described in the proposal, which is a variant of the portfolio approach. The EPA is not finalizing 

the portfolio approach, or the state commitment variant of the portfolio approach. Acceptable 

plan approaches, and the rationale for these approaches, are described in section VIII.C of the 

preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters asked whether the EPA approve a state plan that commits to emission reductions 

but does not specify how they will be achieved. Commenters noted that by submitting a SIP 

states affirm their commitment to reducing the carbon emissions within their borders (or within 

the region in the case of a regional SIP). Commenters noted that the current timeline for 

individual states to submit an SIP is June of 2016, and that the EPA reviews each SIP and makes 

a determination whether or not the SIP meets the required compliance targets. 

Commenters noted that many states have voluntarily taken measures to reduce carbon pollution 

within their territory. Commenters stated that some of these measures, as is the case in 

California, involve very complex market designs that affect various industries. Given the 

complexity of these reduction programs, commenters noted that any change in conformity with 

the EPA's regulations could potentially require various impact studies and lengthy legislative or 

regulatory proceedings. 

Commenters asked that the EPA consider and comment on the acceptability of a SIP wherein a 

state submits a timely SIP and commits generally to comply with the EPA's targets, but fails to 

explicitly identify the methods by which the state will achieve compliance. 
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Comment 34: Several commenters supported energy efficiency programs as a means for states 

to comply with the CPP and provided suggestions for incorporating end-use energy efficiency 

into state plans,

Response 34: The final emission guidelines provide for the use of demand-side energy 

efficiency, under both a rate-based emission standards approach and as a state measure under a 

state measures plan type. The EPA also notes that demand-side energy efficiency could be a 

complementary measure that helps achieve mass-based emission standards, and that such energy 

efficiency measures would not be included in a state plan.

Many of the issues raised by the commenters allude to the inclusion of federally enforceable 

requirements related to demand-side EE, as part of a portfolio state plan approach. In response to 

comments, in particular those comments raised regarding applying federally enforceable CAA 

requirements under a state plan to non-affected EGU entities, the EPA is not finalizing the 

portfolio approach. The EPA’s rationale for not finalizing the portfolio approach is discussed in 

section VIII.C.6.d of the preamble to the final rule. However, the EPA is finalizing other plan 

approaches that would allow the same types of measures outlined by the commenters to be used 

in state plans. This includes a rate-based emission standards plan, where such measures could be 

used to adjust the reported CO2 emission rate of an affected EGU, as part of federally 

enforceable emission standards for affected EGUs, and the state measures plan type, where such 

measures could be included as state-enforceable measures under both a rate-based and massbased plan approach. These plan approaches are described in sections VIII.C.2 and 3 of the 

preamble to the final rule. Eligible measures that may be used to adjust the reported CO2

emission rate of affected EGUs are described in section VIII.K.1 of the preamble to the final 

rule. Requirements for rate-based emission trading programs are described in section VIII.K.2 of 

the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Many commenters supported the inclusion of the end-use energy efficiency programs as part of 

state plans because they would help states comply with the state goals and would be a costeffective means of reducing emissions. Commenters believed that the objective of reducing 

emissions from EGUs through energy efficiency is best facilitated by encouraging the "continued 

development of a vibrant and diverse energy services market." Commenters argued that EE 

should be an integral, credible part of state, regional, and tribal plans and recommended that the 

guidelines recognize the state and tribal obligation for ensuring affordable and reliable energy 

services as well as protecting the environment. Commenters noted that EE is "widely recognized 

as the least-cost electric system resource" and argued that "customers will actually experience 

lower bills if the state's plan includes a strong EE component." Commenters believed that enduse energy efficiency is one of "the least-cost compliance options" and thought it would "play a 

critical role in helping the United States meet its emission reduction policy objectives."

Commenters noted private industrial efficiency investments facilitated by state government 

agencies as programs for States to include in their compliance plans. Commenters stated that 

State Energy Offices and other state agencies have worked for decades with industrial and 

manufacturing facilities to promote "best practices" investments in process improvement that 
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result in substantial energy savings. Commenters indicated many of these programs do not rely 

on utility rebates, so the energy savings are often not tracked by utility or state programs. 

Commenters supported including state energy financing programs in state plans. Commenters

stated that the State Energy Loan Fund (SELF) database (http://www.naseo.org/state-energyfinancing-programs) shows there are 79 energy financing programs operated by 44 states and 

territories, representing over $3 billion in capital available through State Energy Offices and their 

partners for energy efficiency, renewable energy, and clean technology deployment. 

Commenters noted that this amount excludes new ratepayer and taxpayer supported "green 

banks" and special purpose financing initiatives that would add billions more to this amount.

Commenters believed that using the CO2 reductions generated through industrial energy 

efficiency (IEE) projects as a means of compliance would provide states with enhanced 

flexibility and lower compliance costs for both regulated entities and consumers. 

Commenters noted that State-led initiatives, such as commercial property assessed clean energy 

(PACE) and low-income weatherization programs, produce substantial energy savings and 

associated emissions reductions each year, and 25 states have established commercial PACE 

programs. Commenters also noted that nearly every state operates low-income and/or market rate 

residential (including multi-family) EE programs that invest billions of dollars of federal, private, 

and non-ratepayer state funds annually. Commenters stated that most of these programs have a 

history of strong M&V.

Commenters recommended the EPA allow states to include Appliance Standards in their state 

plans. Commenters indicated their state tracks programmatic energy savings from purchases of 

appliances that meet federal or more stringent state appliance efficiency standards. Commenters

noted that States can induce and track the sale and installation of new appliances meeting the 

federal standards through programmatic measures. Commenters recommended that state efforts 

done prior to federal rulemaking should be credited for the remaining life of the measure, 

specifically the efforts in the Northwest and California that adopted advanced appliance 

standards before the federal government. Commenters believed the final rule should clarify that 

appliance standards will not lower the state's baseline for calculating energy savings from a 

newly adopted federal appliance standard, and argues that if the EPA does not do so they would 

be creating disincentives for states to adopt state appliance efficiency standards. 

Commenters provided the following recommendations on how end-use energy efficiency should 

be incorporated into state plans:

• States should be encouraged to develop strong crediting, and 

administrative review and oversight of utility-, state-, and non-utilitydelivered energy efficiency activities. 

• The EPA should allow states flexibility in how they incorporate EE into 

state plans.

• The EPA should defer to state, regional, and tribal decision making as to 

how incorporate EE into state plans. 
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• The EPA should clarify how compliance measures involving federal 

entities, such as BPA, may be incorporated in a state compliance plan to 

leverage federal investments in emission reductions from energy 

efficiency.

• State plans should include policies and incentives that help utilities make 

investments in EE. 

• The EPA should clarify that energy efficiency may be included in state 

plans irrespective of how efficiency programs are designed, structured 

and administered and irrespective of the legislative, regulatory and 

contractual arrangements pursuant to which such programs operate. 

• The EPA should establish guidelines to ensure EE programs are 

adequately funded and that funding cannot be withheld or diverted to 

other uses once the programs become operational. 

• The EPA should clarify that states may include private-sector delivered

IEE in their 111(d) compliance plans 

• The EPA should describe how to include IEE as an element of a robust 

portfolio of energy efficiency measures in an approvable state plan. 

• The EPA should provide states with guidance on how to aggregate data 

from private-sector delivered IEE. 

• The EPA should identify approvable M&V approaches for inclusion of 

IEE project-related emission reductions in state plans.

• The EPA to should allow electricity savings that persist into the 

compliance period, and can be validated by an approved M&V approach

to be eligible for compliance regardless of when the measure was 

installed. 

• The EPA should provide states with flexibility to take credit for actions 

taken after the Clean Power Plan was proposed was issued and before 

the interim compliance period begins (2020) and count that credit 

toward achievement of the state's compliance obligation. 

• The EPA should remove the energy efficiency penalty created when 

energy efficiency projects are implemented in electricity-importing 

states.

• The EPA support the development and use of single-state and multi-state 

emission credit trading programs and other market-based systems. 
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• Emission reductions resulting from Appliance Standards should be an 

acceptable component of a state compliance plan.

• The EPA should allow states to include private and public-sector 

investments in commercial and residential energy retrofits facilitated 

through state programs in their state plans.

Commenters stated that the EPA suggests throughout the document that there is flexibility in 

how emission targets are achieved, and as it relates to EE, this discussion extends to whether or 

not EE is required, what entity would have such responsibility (state, utility-integrated or 

distribution-only, independent program administrator, etc.), how such credits would be realized 

(state certificates, credits purchased by EGUs, etc.), in what market such credits are fungible 

(states, RTOs, trading regions, etc.) and so on. Commenters stated unless the states are given 

absolute discretion to resolve these issues to their own satisfaction, the uncertainties associated 

with these issues amount to a federal license to reject state submissions if all of the details of the 

state's EE programs do not conform to standards that the EPA never clearly defined.

Other commenters disagree with the inclusion of EE in states plans. Commenters recommended 

the EPA not include energy efficiency in its basis for state goals or accept state plans that include 

energy efficiency as CAA enforceable programs.

Comment 35: Comments suggesting that the EPA allow states to include development of energy 

storage as part of state plans.

Response 35: Energy storage technologies could be used to facilitate achievement of the CO2

emission performance levels for affected EGUs, or a state rate-based or mass-based CO2 goal for 

affected EGUs, in the emission guidelines. However, MWh output from an energy storage 

technology could not be used to adjust the reported CO2 emission rate of an affected EGU. It 

could facilitate greater grid penetration levels of RE generating technologies that are eligible for 

use in adjusting the reported CO2 emission rate of an affected EGU. The treatment of energy 

storage under a rate-based state plan, and the rationale for this treatment is discussed in section 

VIII.K.1.a.(5) of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters believed the EPA should give careful consideration and credit for energy storage 

where states include storage as a technology to help achieve compliance. Commenters stated 

state plans that provide incentives for the expansion of storage should be considered favorably by 

the EPA. Commenters also recommended the EPA identify milestones, monitoring, and 

reporting requirements for storage and noted that corrective measures should be implemented

where storage goals are not achieved or where storage does not reinforce the attainment of 

desired environmental outcomes. 
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5.2 INCORPORATING DEMAND-SIDE ENERGY EFFICIENCY AND RENEWABLE 

ENERGY PROGRAMS AND MEASURES UNDER A RATE-BASED APPROACH

This section addresses comments on incorporating end-use energy efficiency and renewable 

energy programs and measures under a rate-based approach, and includes discussion on 

adjusting EGU CO2 emission rates and method and tools for quantifying avoided CO2

emissions. We have organized the comments in this section under six subsections, 5.2.1 to 5.2.5. 

Responses to the comment topics of these subsections are discussed below along with summaries 

of the specific public comments.

5.2.1 Adjusting EGU CO2 emission rates based on the effects of end-use energy efficiency 

and renewable energy

This section discusses the general accounting approach for adjusting the CO2 emission rate of an 

affected source. The comments and corresponding responses in this section address guidelines 

for tracking energy efficiency and renewable generation, energy efficiency and renewable 

generation impact estimations of the rate-based approach, utilizing REC trading programs to 

demonstrate compliance, and additional considerations for the denominator and numerator.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments suggesting that states should have broad discretion and flexibility on 

how to credit or adjust CO2 emissions rates; commenters argued this issue falls within the state's 

authority. 

Response 1: The EPA disagrees with the comment that the states should have broad discretion 

regarding the type of approach they use to credit RE and/or demand-side EE. In order to ensure 

consistency with the calculation of CO2 performance rates and state rate-based CO2 goals in the 

final emission guidelines, and to avoid double-counting or inconsistent adjustment approaches 

across states, the final rule prescribes a general accounting approach states must use to adjust the 

CO2 emission rate of an affected source to reflect the MWh impacts of zero-emitting and lowemitting resource. Quantified and verified MWh impacts of qualifying zero-emitting and lowemitting resources tied to a state plan may be used by an affected EGU or state to adjust a CO2

emission rate, regardless of whether the renewable generation or demand-side EE savings occur 

inside or outside the state or territory. Consistent with the EPA’s calculation of the CO2 emission 

performance rates and state rate-based CO2 goals in the final emission guidelines, the MWhs 

impacts are added to the denominator of an affected EGU’s reported CO2 emission rate, resulting 

in a lower, adjusted CO2 emission rate. The reported CO2 emissions reflect the actual emission 

reductions from the deployment of qualifying non-emitting and low-emitting resources across 

the regional grid. Further adjustment of CO2 emissions, such as through the subtraction of 

emissions from the numerator, such as those estimated by applying an emissions factor to the 
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MWhs, would double count CO2 emissions impacts across the grid and is, therefore, not 

permitted under the general accounting approach. While states may define renewable resources 

in their independent state policies different from EPA, the EPA requires that renewable energy 

resources states can use for purposes of meeting the emission guidelines must meet the eligibility 

requirements specified in the rule. These requirements align eligibility with certain factors and 

assumptions used in establishing the BSER, and by extension, application of the BSER to the 

performance levels established for affected EGUs in the guidelines. For more information about 

specific methods to adjust the CO2 emission rate of an affected EGU to reflect RE and demandside EE, see section VIII.K of the final rule preamble of the CPP. The same section also 

describes the eligibility requirements and conditions for resources to be used to adjust a CO2

emission rate, including specific discussions regarding hydroelectric power, biomass and 

combined heat and power. The rule describes the requirements and criteria related to proper 

quantification and verification of MWhs from renewable electricity generation or demand-side 

EE savings in section VIII.K.3 of the final rule preamble. 

Finally, for the reasons responded to in RTC section 1.2 regarding cooperative federalism, we 

disagree with commenters' assertions that EPA has "no authority" to evaluate the satisfactoriness 

of a state plan submitted pursuant to section 111(d).

The following are summaries of the specific public comments under this comment:

Commenters claimed that the states should have broad discretion on how to credit or adjust CO2

emission rates to incorporate renewable energy and demand-side energy efficiency measures 

under a rate-based approach. Commenters added that as long as there is reasonable assurance 

that double-counting of benefits are not occurring, this issue should be decided by individual 

states. Commenters further contended that EPA has no authority to circumscribe the mechanisms 

available to the states, and that this issue falls within the state's authority under CAA section 

111(d). Commenters favored allowing states the flexibility to choose whether RE and EE 

measures should be subtracted from the numerator or added to the denominator.

Commenters argued that the CPP should provide deference to the Ohio General Assembly's 

jurisdiction over state policy and safeguard such flexibility to avoid a scenario where a federal 

entity is forcing a state to violate its own laws. Commenters explained that the CPP adopts a onesize-fits-all policy that does not give Ohio discretion to define RE resources consistent with its 

own statutes and policies. Furthermore, commenters noted, because every state's RE and EE 

requirements are different, a wide range of options for EM&V protocols is critical so that states 

can develop plans tailored to individual state needs and conditions.

Commenters also stated that credit should be allowed for all hydroelectric generation (including 

internationally sited), nuclear power including increased capacity at existing units, carbon neutral 

biomass, combined heat and power and even new methods to be determined, with oversight to 

assure no double-counting and that the reduction credit is appropriate.

Commenters observed that EPA used the statewide rate approach for its calculations of proposed 

state goals, but proposed to provide flexibility to allow individual EGUs to make adjustments for 

RE as long as assurances can be provided that there is no double counting (i.e., the same MWh 

cannot be used to make an adjustment to the rate of individual ERUs and also for statewide 
157

adjustment as the result of a state policy like an RPS). Commenters noted that if this strategy is 

employed by states, this may result in a different rate calculation from that which will be used by 

the EPA for the state goal. Commenters added that EPA should provide additional guidance and 

encourage states to use the same calculation methods for state goals and performance as the EPA 

used in the final state goal calculations, as this will reduce the potential for gaming and 

significant differences between a state's calculation and the EPA's.

Comment 2: Comments recommending clear guidelines/additional guidance for tracking EE and 

RE measures and credits. 

Response 2: In the final rule, quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources tied to a state plan may be used by an affected EGU or state to adjust 

a CO2 emission rate, regardless of whether the renewable generation or demand-side EE savings 

occur inside or outside the state or territory. This ensures that affected EGUs receive full 

recognition for their investments even if the impacts occur elsewhere and it removes the need to 

determine exactly which EGUs reduced and changed power generation in response to the zeroemitting or low-emitting resource. This also ensures that quantified and verified MWh impacts of 

qualifying zero-emitting and low-emitting resources are applied consistently across all affected 

EGUs. Consistent with the EPA’s calculation of the CO2 emission performance rates and state 

rate-based CO2 goals in the final emission guidelines, the MWhs impacts are added to the 

denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted CO2

emission rate. The reported CO2 emissions reflect the actual emission reductions from the 

deployment of qualifying non-emitting and low-emitting resources across the regional grid.

Further adjustment of CO2 emissions, such as through the concept proposed by some 

commenters below which calls for the subtraction of CO2 reductions estimated by applying an 

emission factor conversion on the MWhs, would double count CO2 emissions impacts across the 

grid given the revised calculation of the CO2 emission performance rates and state rate-based 

CO2 goals in the final emission guidelines. These adjustments are, therefore, not permitted. 

Because of the separate accounting of MWhs and CO2 emissions, with emission impacts inherent 

in reported stack CO2 emissions and zero-emitting MWh impacts requiring explicit adjustments, 

the accounting method corresponds with the use of MWh-denominated Emission Rate Credits

(ERCs) in the rate-based emission trading framework specified in this rule. The accounting 

method only requires a quantification of the MWh generated or avoided by an eligible measure, 

and thus credits or adjustments can be denominated in MWh and do not need to represent an 

approximation of the CO2 emission reductions that result from those MWhs. This creates a 

crediting system or rate adjustment process that is simpler to implement than one that requires an 

approximation of avoided CO2 emissions. The MWh accounting method also creates a crediting 

system or rate adjustment process that is indifferent to the rate-based CO2 emission goals of 

individual states, or the specific CO2 emission rate standards that states may apply, and the 

relative stringency of those goals or standards. 

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC) or an energy efficiency credit (EEC). An ERC may be issued, however, based on the 
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same data and verification requirements used by existing REC and EEC tracking systems for 

issuance of RECs and EECs that are used to meet state renewable portfolio standards or energy 

efficiency resources standards. The EPA is aware of the potential for interactions between ERCs 

and RECs or EECs and encourages the states to consider, when developing their state plan, how 

existing instruments that are used to meet other regulatory requirements or in voluntary markets 

may interact with ERCs.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect demand-side EE and eligibility requirements for resources that can be used to adjust a 

CO2 emission rate, including eligibility dates and the types of EE savings and RE MWhs that are 

eligible, see Section VIII.K.1. Requirements for rate-based emission trading programs and the 

issuance and tracking of ERCs, including qualifying measures, programs or projects, addressing 

the potential for interactions between ERCs and RECs or EECs, are addressed in section 

VIII.K.2. Section VIII.K.3 of the preamble to the final rule describes the requirements and 

criteria related to proper ex post quantification and verification of MWhs from renewable 

electricity generation or demand-side EE savings to avoid overestimation as suggested by 

commenters. These final requirements are intended to leverage and/or closely resemble those 

already in routine use, including those by energy service companies engaging in energy savings 

performance contracts. The EPA is not providing additional guidance for incorporating methane 

utilization and reductions into state implementation plans for 111(d), as it is out of the scope for 

this rulemaking.

For information about mass-based emission standards with a market-based emission budget 

trading program, see Section VIII.C.2 and VIII.C.3. 

The following are summaries of the specific public comments under this comment:

REQUESTS FOR GUIDELINES

Commenters recommended that EPA establish clear guidelines for tracking energy efficiency 

and renewable generation. Commenters noted that the guidelines may differ depending on 

whether a state employs a mass-based program or rate-based program. 

METHANE UTILIZATION AND PRIVATE/NON-UTILITY EE

Commenters encouraged EPA to issue additional guidance for incorporating methane utilization 

and reductions into state implementation plans for 111(d). Commenters urged EPA to state 

expressly that privately or other non-utility delivered EE can be included in state compliance 

plans. 

ENERGY SAVINGS PERFORMANCE CONTRACTS (ESPC)

Commenters noted that ESPC provides measured, verified and documented reductions. 

Commenters requested that EPA provide explicit guidance to states on presumptive, approvable, 

energy efficiency programs. Commenters suggested that the criteria for approvable energy 

efficiency should have environmental rigor, quantifiable, enforceable and sustainable, 

administrative ease, clear investment goals and management requirements, and adaptability with 

periodic review of state plans, with prospective adjustments, as needed.
159

Commenters requested that EPA describe approvable approaches for aggregating Energy 

Savings Performance Contract (ESPC) project-related energy efficiency to determine the avoided 

emissions achieved. Commenters stated these data can be collected by State Energy Offices or 

other state-designated entities (directly or via a third party) or through state- or utilityadministered programs from projects that are independently directed, directed by the program, or 

bid.

Similarly, commenters strongly believed that EPA should also issue clear guidance for crediting 

ESPC programs and projects that deliver energy efficiency through third-parties and nonutilities. Commenters also suggested that states should be permitted to include emission 

reductions from Federal and public housing authority ESPC projects which occur in their 

respective states. Commenters stated this Federal data could be provided by a national registry or 

other database administered by the Federal Energy Management Program at DOE. 

Commenters recommended the following 10 items of guidance that would be applicable for 

ESPC crediting:

• Identify Approvable Pathway. Without limiting state flexibility, EPA 

can offer clarifying guidance to enable states to include performance 

contracting project-related emission reductions in their 111(d) 

compliance plans.

• Recognize All Existing Programs. EPA should acknowledge - as it did 

with energy efficiency resource standards, etc. - that existing state 

performance contracting activities provide a potentially substantial 

contribution to 111(d) compliance.

• Targeting Sources of Energy Savings. EPA should clarify how this 

requirement applies to performance contracting projects. Commenters

recommend that the states be required only to identify building types 

(e.g. state-owned, hospitals, universities etc.) targeted for performance 

contracting and a reasonable estimate of savings to be achieved from 

anticipated PC projects.

• Aggregation of ESPC-Created Emission Reductions. EPA should 

describe approvable approaches for aggregation of PC project-related 

GHG reductions for use in 111(d) compliance. A national registry could 

serve this purpose, providing efficiency and the greatest degree of 

consistency in all aspects of inclusion of project-related GHG reductions 

in 111(d) compliance. Alternately, a state energy office (or another 

designated Agency) can collect (directly or via a third party) data from 

all PC projects in the state and determine the avoided emissions 

achieved.

• Clarify Approvable Approach for Key Compliance Criteria. EPA can 

assist states by identifying approvable approaches for key compliance 

criteria that will facilitate inclusion of performance contracting project-
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related emission reductions. Key compliance criteria for which EPA 

should identify approvable approaches include M&V protocols, auditing 

requirements for state performance contracting projects, performance 

contracting program evaluation methods, and corrective measures.

• Existing Facilities/Installations. Emissions reductions from performance 

contracting projects that are validated by an approved M&V approach 

and persist into the compliance period should be eligible to contribute to 

111(d) compliance regardless of when the measure was installed.

• Create Incentives for Immediate Action to Reduce Emissions. EPA 

should provide states with flexibility to take credit for actions taken after 

the Clean Power Plan was proposed and before the interim compliance 

period begins (2020) and count that credit toward achievement of the 

state's compliance obligation. This early-action provision would help 

ensure that the states have an incentive to reduce carbon emissions prior 

to 2020 and eliminate an unintentional incentive to delay EE projects 

until after 2020.

• Contributions to Future Avoided Emissions. Avoided electricity 

consumption should be allowed to count toward 111(d) compliance for 

performance contracting projects subjected to proper M&V.

• Identify Remedies for the 111(d) State Energy Efficiency Penalty. EPA 

should address and resolve the energy efficiency penalty created when 

energy efficiency projects are implemented in electricity-importing 

states. As proposed, the rule would leave stranded and uncounted the 

emission reductions created by energy efficiency in an importing state 

because neither the importing state, nor the generating state, could claim 

credit for emissions reductions equal to 100 percent of those created by 

the energy efficiency program or project.

• Encourage the Use of Tradable Credits. EPA should support the 

development and use of single-state and multi-state credit programs and 

other market-based systems. This will encourage the use of the least-cost 

compliance options, which, in many cases, will involve comprehensive 

energy retrofits.

CREDIT TRACKING

Regarding credit tracking, commenters further recommended that rate-based compliance 

programs should credit renewable energy and energy efficiency in the form of tons of CO2 as 

opposed to trading credits of MWh through RECs or some other mechanism. Commenters 

reasoned that this approach would simplify compliance across regulated entities and avoid 

creating significant administrative challenges for state renewable portfolio standards, which in 

many states will have a different compliance entity than the state's compliance program for 

111(d). Commenters stated that RECs would therefore continue to be used by load serving 
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entities (LSE) for compliance with state renewable standards, while CO2 emissions credits would 

be used by electric generators for compliance under section 111(d).

Commenters suggested that guidance should include options for states to avoid situations in 

which different types of compliance entities at different points in the chain of custody (e.g. 

EGUs and LSEs) are competing for the same RECs/MWh. Commenters offered an example 

where the EGU is the compliance entity and the state RPS is also included in the state plan, the 

state will need to determine a method for allocating RPS reductions and RECs retired for the 

RPS to individual EGUs reporting for 111(d) compliance. Commenters warned that the creation 

of another instrument of tracking credits for this purpose should be avoided, since this would 

increase the risk of double-counting RECs.

Commenters recommended using the crediting approach EPA used under building block 3, and 

stated that to aid in states in compliance with their 111(d) obligations, it would be most be most 

efficient and equitable for the EPA to model its approach after the best practices of existing state 

RPSs. Commenters stated that relying upon existing best practices and infrastructure will aid 

states in efficiently meeting their obligations, while making double counting structurally 

impossible, thereby maintaining the integrity of the emissions reductions which will be achieved.

Commenters said, the implementation of this regulatory approach would be greatly facilitated 

were the air regulator or the EPA to create a system for registering and tracking credits related to 

renewable energy and energy efficiency projects. Commenters said, as discussed elsewhere, the 

air regulator in a state taking this approach could also ensure greater cost-effectiveness by also 

providing that it will accept credits generated within the state, within a specified set of states, or 

within any state taking a parallel rate-based approach with a plan approved by the EPA. 

Commenters said, the creation of a tracking system for credits by EPA would greatly facilitate 

interstate coordination, and ensure that credits are not double counted towards compliance. 

Commenters said, however, such a system should not require new legislation or additional action 

by a public utility commission. Commenters said, this approach is broadly similar to an August 

2014 proposal by Western Resource Advocates, describing a "carbon reduction credit" program 

that would allow affected EGUs to comply with state-wide emission standards by reducing their 

emissions using credits generated by lower-emitting EGUs, clean energy resources, and 

providers of verified energy efficiency savings.

TIME AND ORIGIN OF GENERATION

Commenters suggested that credits should be provided at the time of generation or at the time 

energy efficiency projects are verified, but also that states should be allowed to determine the 

frequency which credits are created. Commenters recommended that credits be created no less 

frequently than quarterly so that projects can quickly capitalize on the value they create.

Commenters suggested that the credit allowance be labeled in a manner that indicates its point of 

origination, which for RECs would require that a CO2 credit could be connected to a particular 

REC and its associated MWh and generating facility in one of the mandatory or voluntary 

tracking systems. Commenters also recommended that EPA design and operate a tracking system 

that states can opt to use.

BASIS OF CREDITS AND CALCULATIONS OF AVOIDED EMISSIONS
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Commenters noted that, due to the interconnected nature of the electric grid, it is not possible to 

determine which power plant reduced their generation as a result of every avoided MWh due to 

efficiency or carbon-free projects. Commenters recommended that in order to avoid 

overestimation of emission reductions from these projects, the credits be based on the emission 

standard for new natural gas plants established under section 111(b), or the state's GHG 

emissions rate for the interim control period, whichever is lower. Commenters also offered an 

alternate approach to credit the projects in an amount based on the state's GHG emissions rate for 

the interim control period or the average emissions rate in their market region (consistent with 

the regions used to establish the requirements for the renewables building block), whichever is 

lower.

Commenters insisted that there must be guidance on a consistent/common methodology used by 

all states to achieve an even playing field and avoid gaming, since different calculation 

methodologies could result in different amounts of avoided emissions. Commenters stated the 

guidance should also be developed in cooperation with transmission operators, since these 

entities have access to dispatch data. Finally, commenters also stated that the guidance should 

include a calculation methodology that is sufficiently precise. Commenters provided that as an 

example, while requiring the use of hourly transmission data may result in calculations that are 

too costly for states, an avoided emissions value should be (and certainly should only be attached 

to an individual REC if it is) reasonably accurate for that MWh. Commenters asserted that this 

would help ensure that any differences (whether positive or negative) between a state's 

calculations for the purpose of making adjustments to rates and those performed by EPA for state 

goal calculation are due to increased precision.

RATEPAYER EQUITY OF BENEFIT

Commenters expressed concerns for equity among ratepayers in a state when the benefits of 

actions in vertically integrated utilities are being claimed by the state, but the integrated utility's 

ratepayers bear the cost. Commenters recommended that, to ensure equity among ratepayers, a 

state plan should ensure utilities whose ratepayers directly invest in beyond-the-fence strategies 

receive full credit for those investments.

Comment 3: Comments on the complexities of EE/RE impact estimations of the rate-based 

approach and need for consistency - including concerns with stakeholder-proposed approaches 

and overestimation concerns.

Response 3: The final rule specifies a general accounting method for adjusting a CO2 emission 

rate. The reported CO2 emission rate of an affected EGU may be adjusted based on MWhs from 

qualifying zero-emitting and low-emitting resources, as described in section VIII.K.1 of the final 

rule preamble of the CPP, that are quantified and verified in accordance with the EM&V 

requirements specified in section VIII.K.3 of the final rule preamble. These resources, such as 

renewable energy and demand-side EE, must be tied to a state plan and can be used by an 

affected EGU or state to adjust a CO2 emission rate, regardless of whether the renewable 

generation or demand-side EE savings occur inside or outside the state or territory. Consistent 

with the EPA’s calculation of the CO2 emission performance rates and state rate-based CO2
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goals in the final emission guidelines, the MWh impacts are added to the denominator of an 

affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted CO2 emission rate. For 

more information about specific methods to adjust the CO2 emission rate of an affected EGU to 

reflect demand-side EE and eligibility requirements for resources that can be used to adjust a 

CO2 emission rate, see section VIII.K.1 of the final rule preamble. Commenters expressed 

concern regarding the analytic challenge of estimating the quantity of GHG emissions that may 

be reduced or avoided by implementing demand-side EE projects. This concern is eliminated in 

the final rule because it does not require an estimation of emissions impacts. Instead, reported 

CO2 emissions of an affected EGU reflect the actual emission reductions from the deployment of 

qualifying non-emitting and low-emitting resources across the regional grid. Further adjustment 

of CO2 emissions would double count CO2 emissions impacts across the grid. For more 

information about specific methods to adjust the CO2 emission rate of an affected EGU to reflect 

RE and demand-side EE, see section VIII.K.1.a.(3) of the final rule preamble.

The rule includes the requirements and criteria related to proper ex post quantification and 

verification of MWhs from renewable electricity generation or demand-side EE savings, and 

discusses eligible demand-side EE programs and projects in section VIII.K.3 of the final rule 

preamble. 

The following are summaries of the specific public comments under this comment:

SEPARATE ESTIMATION APPROACHES

Commenters noted that the rate-based approach is complex in several ways, one being that states 

must separately estimate impacts of EE and RE programs on fossil plant emissions, and that 

these programs do not affect the rate of emissions in a consistent manner. Commenters also 

stated that different estimation approaches may be adopted for similar programs among different 

states, and there is an obvious temptation for states to skew their estimates on the high side.

Commenters stated these increase the risks of reducing the actual emission reductions obtainable 

by the CPP and the possibility of double counting.

Commenters discussed that large utilities would likely prefer a rate-based approach, but the 

Generation and Transmission (G&T) serving rural electric coops would be better off using the 

mass-based approach. Commenters urged EPA to identify a mechanism to incorporate energy 

efficiency into the rate-based approach, possibly permitting a hybrid approach that measures the 

rate, but increases the rate permitted for each utility based on quantified energy savings. 

Commenters believed the proposed approaches needs to be more carefully thought out so that 

affected sources of all sizes can choose the most cost-effective mechanisms to reach the same 

target, and possibly surpass targets over time, all the while reducing their electric customers' 

costs.

CONCERNS WITH NRDC'S PROPOSED APPROACH TO CREDITING EE FOR 

COMPLIANCE WITH RATE-BASED TARGET

Commenters noted that several stakeholders have submitted detailed proposals for crediting 

energy efficiency improvements towards compliance with a rate-based target (i.e., NRDC and 

Hibbard & Okie (2014)). Commenters stated that these proposals provide a pathway for crediting 
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energy efficiency while ensuring that the emissions reductions from those measures are real and 

verifiable. However, commenters believed that the proposals also reflect some of the drawbacks 

of the rate-based approach. Commenters noted that as an example, these proposals only allow 

credits for a limited set of energy efficiency efforts, not the full range of measures that may be 

undertaken by states, utilities, local authorities and other entities to increase energy efficiency. 

Furthermore, commenters added, the proposals do not provide a clear pathway for crediting 

reductions from pricing policies, tax credits or education efforts that reduce electricity 

consumption. Commenters also argued that these proposals require rigorous EM&V procedures 

to confirm the actual emissions reductions that can be attributed to specific emission measures, 

and that these procedures may "increase the complexity and cost of efficiency as a compliance 

strategy relative to the mass-based emission reduction approach" which may result in states 

likely narrowing the range of efficiency programs and policies offered for efficiency credits. 

Commenters further noted that these proposal require an ex-post evaluation of emissions 

reductions generated from particular energy efficiency measures in order to determine the value 

of the emissions credit generated from those measures. Commenters believed that this creates 

uncertainty as to the emissions reduction value of any efficiency project, which may deter 

investment in such projects. Commenters noted that the proposed rule addresses each of these 

concerns by allowing states to adopt a mass-based target in lieu of a rate-based target. However, 

commenters recommended that EPA should clarify the respective requirements for states with 

rate- and mass-based targets and provide examples of acceptable EM&V protocols in both 

contexts. Commenters believed that this information will help states decide whether to convert 

their rate-based target to a mass-based target, and design an appropriate plan for EM&V of 

emissions reductions from energy efficiency measures.

ENERGY EFFICIENCY OVERESTIMATION CONCERNS

Commenters presented several concerns regarding overestimation of the gains from energy 

efficiency measures within the proposed rate-based standard. Commenters noted that accurately 

measuring how efficiency investments affect electricity demand is notoriously difficult, and 

recent studies indicate that the savings are frequently overestimated by a wide margin.

Commenters noted the importance of this since overestimation of the gains from energy 

efficiency will reduce the stringency of rate-based standards. Commenters stated that since 

avoided generation increases the denominator, with enough avoided generation from energyefficiency, any state can be brought into compliance, even a state which otherwise has taken few 

steps to reduce carbon dioxide emissions. Commenters pointed out that this problem arises with 

energy efficiency because unlike the other components of the compliance formula, avoided 

generation is not directly observed and must be estimated using engineering and econometric 

techniques.

Commenters presented several reasons why actual energy efficiency savings often end up 

smaller than predicted, including: 

• Many people counted as participants in energy-efficiency programs 

would have undertaken the energy saving behavior even in the absence 

of the program; 
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• In response to efficiency-induced reduction in cost, firms and 

households may increase demand for energy services. Therefore, a 

"rebound effect" seems to occur, and although 100 percent rebound is 

rare, it is not uncommon for as much as 30 to 40 percent of the predicted 

gains from energy-efficiency to be offset; and

• Many energy efficiency programs explicitly require ex ante estimates to 

be of a certain size in order for participants to receive subsidies. 

Therefore, there exist incentives for energy-efficiency auditors and 

investor-owned utilities for to overstate the size of efficiency reductions 

to receive subsidies or compensation.

Commenters stated that their facility is not required to submit annual M&V studies to state utility 

commissions. Commenters stated it is analytically challenging to estimate the quantity of GHG 

emissions that may be reduced or avoided by implementing demand-side EE projects.

Commenters stated that to estimate reduced GHG emissions in this context requires complex 

modeling designed to calculate (i) the change in electricity load for each hour of the day an EE 

project is expected to operate, and (ii) the marginal emissions reductions associated with the 

marginal electric generation unit in a region that can be expected to reduce its output in response 

to the change in electric load. Commenters noted that accomplishing this requires the use of 

regional electric generation dispatch modeling tools and other sophisticated analysis methods 

that not all entities have at their disposal. Commenters indicated that instead of requiring these 

burdensome methods, to the extent that states can credibly show that these emissions have been 

avoided, EPA should grant credit for these actions under a state plan. Commenters stated that 

because their facility is a wholesaler of electricity with over 150 local power companies that 

distribute their power, the business model requires collaboration from multiple parties, resulting 

in a complexity for EE that does not appear elsewhere. 

Comment 4: Comments suggesting that states and merchant facilities should have flexibility to 

use RECs as compliance mechanism.

Response 4: In the final rule, the EPA addresses the general accounting approach for adjusting a 

CO2 emission rate in section VIII.K.1.a.(1) of the preamble. The reported CO2 emission rate of 

an affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1 and in accordance with 

the EM&V requirements specified in section VIII.K.3. These MWh are added to the denominator 

of an affected EGU’s reported CO2 emission rate, resulting in a lower adjusted CO2 emission 

rate. This accounting method corresponds with the use of MWh-denominated Emission Rate 

Credits (ERCs) to represent the zero emission MWhs from the eligible renewables and energy 

efficiency. The ERCs are the tradable units that can be used in the rate-based emission trading 

framework specified in this rule.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC) or an energy efficiency credit (EEC). An ERC may be issued, however, based on the 
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same data and verification requirements used by existing REC and EEC tracking systems for 

issuance of RECs and EECs that are used to meet state renewable portfolio standards or energy 

efficiency resources standards. The EPA is aware of the potential for interactions between ERCs 

and RECs or EECs and encourages the states to consider, when developing their state plan, how 

existing instruments that are used to meet other regulatory requirements or in voluntary markets 

may interact with ERCs.

Requirements for rate-based emission trading programs and the issuance and tracking of ERCs, 

including qualifying measures, programs or projects and addressing the potential for interactions 

between ERCs and RECs or EECs, are addressed in section VIII.K.2.

The following are summaries of the specific public comments under this comment:

Commenters supported EPA allowing states to utilize REC trading programs to demonstrate 

compliance with the Clean Power Plan. Commenters understood that the proposed rule includes 

the ability for states to take credit for 111(d) compliance as well as RPS requirements without 

duplicating compliance credit. Commenters believed that the final rule should maintain and 

affirm this flexibility. Commenters further stated that this is important because under current 

market mechanisms, RECs may be generated and traded independent from a state RPS.

Therefore, commenters suggested the following components of a rate-based trading mechanism 

should be incorporated as a compliance option in the final rule:

• RECs may be surrendered by the generator or sold to another regulated 

entity for surrender. 

Commenters stated that utilities should be able to utilize RECs associated with their renewable 

generation, or acquired from third parties, to demonstrate compliance with emissions reduction 

requirements by surrendering RECs. Commenters stated EPA should acknowledge in the final 

rule that states have the flexibility to expand or implement REC trading such that RECs may be 

sold to any entity or state needing additional carbon reduction attributes to demonstrate 

compliance. Commenters stated that incorporating a tradable-REC program into a rate-based 

compliance mechanism takes advantage of existing tools and resources, and REC purchases and 

sales may be a low-cost compliance option that ultimately reduces compliance costs.

• A single REC may be utilized for compliance with multiple programs so long as it is used 

for only one state's 111(d) compliance program. 

Commenters stated that RECs should not be double counted for purposes of compliance with 

Section 111(d) emission targets. However, commenters suggested that RECs bundle together a

number of environmental attributes associated with renewable energy generation; a reduction in 

carbon emissions attributable to renewable energy generation is but one of those attributes. 

Therefore, commenters stated the final rule should specify that a single REC can be utilized for 

multiple programs so long as it is not utilized for compliance with more than one state's Section 

111(d) compliance plan. Commenters believed that this approach provides maximum flexibility 

to states and regulated parties, recognizes the importance of renewable energy generation in 
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reducing greenhouse gas emissions from the power sector, and encourages additional renewable 

energy development. 

• Companies should be able to bank RECs for future compliance 

Commenters believed the ability to bank RECs is one such appropriate method to credit early 

emission reduction actions. Commenters suggested that EPA should clarify in the final rule that 

RECs generated beginning January 1, 2013 (or, alternatively, June 2, 2014, the date of release of 

the Clean Power Plan) and not yet sold and/or retired, may be banked and utilized for 

compliance beginning in 2020. Without the ability to bank RECs, commenters believed the 

development of renewable energy projects may be stymied until 2020, halting incremental 

environmental benefits that accompany the installation of renewable energy generation.

Commenters discussed a situation where an affected merchant combined cycle natural gas unit is 

located in a state with no other company-owned generation or retail customers. In this situation, 

commenters felt that there are limited options for the unit to reduce its emission rate should 

actual emissions be greater than the limit imposed by the state. Commenters stated that several 

options which could be considered for the unit for compliance purposes include (1) closing the 

facility, (2) pursuing cost-effective heat rate improvements, if any are available, (3) acquiring 

renewable energy credits to reduce the average emission rate, or (4) building additional merchant 

renewable generation in the state. Commenters requested that EPA confirm that the acquisition 

of renewable energy credits from within or outside the state would qualify as a compliance 

mechanism for such a merchant plant to help demonstrate compliance if necessary.

Comment 5: Comments supporting the approach of adding new RE as energy to denominator;

should be consistent over time; and retired coal generation that is not replaced by fossil should 

retain MWh in denominator.

Response 5: The final rule adopts the denominator approach recommended by the reviewers.

Consistent with the EPA’s revised approach to calculating the CO2 emission performance rates 

and state rate-based CO2 goals in the final emission guidelines, quantified and verified MWh 

impacts of qualifying zero-emitting and low-emitting resources tied to a state plan can be added 

to the denominator of an affected EGU’s reported CO2 emission rate, regardless of whether the 

renewable generation, like the wind generation cited by the commenter below, or demand-side 

EE savings occur inside or outside the state or territory. This addition results in a lower, adjusted 

CO2 emission rate. The reported CO2 emissions reflect the actual emission reductions from the 

deployment of qualifying non-emitting and low-emitting resources across the regional grid.

Further adjustment of CO2 emissions, such as through the subtraction of emissions estimated by 

applying an emissions factor to the MWhs, would double count CO2 emissions impacts across 

the grid. For more information about specific methods to adjust the CO2 emission rate of an 

affected EGU to reflect RE and demand-side EE and eligibility requirements for resources that 

can be used to adjust a CO2 emission rate, see Section VIII.K.1.

Because of the separate accounting of MWhs and CO2 emissions, with emission impacts inherent 

in reported stack CO2 emissions and zero-emitting MWh impacts requiring explicit adjustments, 
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the accounting method corresponds with the use of MWh-denominated Emission Rate Credits 

(ERCs) in the rate-based emission trading framework specified in this rule. The accounting 

method only requires a quantification of the MWh generated or avoided by an eligible measure, 

and thus credits or adjustments can be denominated in MWh and do not need to represent an 

approximation of the CO2 emission reductions that result from those MWhs. 

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect renewable energy and eligibility requirements for resources that can be used to adjust a 

CO2 emission rate, including eligibility dates and the types of RE MWhs that are eligible, see 

Section VIII.K.1 of the final rule preamble of the CPP. Requirements for rate-based emission 

trading programs and the issuance and tracking of ERCs, including qualifying measures, 

programs or projects and addressing the potential for interactions between ERCs and RECs, are 

addressed in section VIII.K.2 of the final rule preamble.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect RE and demand-side EE and eligibility requirements for resources that can be used to 

adjust a CO2 emission rate, see section VIII.K.1 of the final rule preamble. 

The EPA believes that the flexibility provided for states to craft plans that are appropriate for 

their circumstances and emission reduction strategies fully recognizes the role that retirement of 

affected EGUs can play. Under a rate-based plan, the retirement of a higher-emitting affected 

EGU will reduce the weighted average CO2 emission rate of the remaining fleet of affected 

EGUs, helping a state to achieve its rate-based CO2 emission goal. 

The following are summaries of the specific public comments under this comment:

RENEWABLE ENERGY AND RECS

Commenters supported counting additional renewable energy in the denominator. Commenters

added that this allows utilities to readily demonstrate and verify renewable energy purchases by 

acquiring and retiring RECs against their SIP requirements. Commenters stated that the use of 

these tracking systems precludes double counting, and that these systems have been used for 

years to track, trade and retire RECs. Commenters added that eligibility of credited MWh must 

be limited to RECs that avoid emissions at affected EGUs, and states must demonstrate this to 

EPA. Commenters further stated that EPA could be even more stringent, in order to increase 

precision and incentivize use of the more precise method, by requiring that states demonstrate 

that all of the avoided emissions from the RE that is used for MWh crediting in fact took place at 

affected EGUs.
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ENERGY EFFICIENCY

Commenters supported adding energy efficiency savings to the denominator if a state chooses to 

comply through the rate based approach. Commenters stated that this approach is simpler and 

likely to be more accurate than estimating the CO2 emission reductions from energy efficiency 

policies and programs and subtracting this from the numerator, given the uncertainties regarding 

the actual time of energy savings and defining which specific power plants cut their generation 

as a result of end-use energy savings. 

RETIRED COAL NOT REPLACED BY FOSSIL

Commenters suggested that when a retired coal plant is not replaced by fossil generation, the 

MWh associated with the plant should remain in the denominator, similar to the treatment of 

zero-emitting resources. Commenters stated that this approach fully reflects the benefits of the 

coal plant retirement. 

CONSISTENCY WITH GOAL CALCULATIONS AND OVER TIME

Commenters also supported the MWh crediting in the denominator approach, since this is the 

method EPA has used to calculate state goals and the potential for gaming exists if states may 

choose one approach or the other. Therefore, commenters urged EPA to require that states be 

consistent within the state plan and over time in terms of which method is used, and not be 

permitted to use either method at different times or for different RE policies.

Commenters argued that there needs to be consistency between the goal calculation methodology 

and the compliance demonstration methodology and that the methods for determining actual 

carbon dioxide emissions and performance goal attainment should be the same or consistent with 

the methods used for calculating the goals.

Commenters argued that for energy efficiency (EE), whatever methodology is used for 

compliance purposes should be consistent with how the BSER was calculated. 

Commenters also recommended that for rate-based compliance plans, EPA require that avoided 

emissions from energy efficiency and renewable energy be credited by adding the avoided 

generation to the denominator of the BSER emission rate equation. Commenters noted this 

approach will ensure consistency between goal setting and goal compliance and also equity 

between states.

SUPPORT DENOMINATOR APPROACH, BUT ALTERNATIVE TREATMENT OF 

DIRECT FOSSIL REPLACEMENT DOES NOT WORK IN ALL CASES

Commenters added that location constraints on the New York system mean that all generation is 

not fungible, and that a wind farm located up-state will not offset the use of steam units in the 

New York City metro area. Commenters stated that therefore, the alterative EE and RE treatment 

of directly replacing 2012 fossil generation levels does not work for them. Commenters also 
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noted that NGCC units will be needed to balance intermittent resources such as wind and solar

and provide ancillary services during normal grid operations.

INCORPORATION OF STATE GHG RULES AND CPP FOR COMPLIANCE

Commenters noted that sources identified by EPA as affected facilities under the CPP are also 

subject to emission reductions of Hawaii's GHG Rules. As a result, commenters added, existing 

EE/RE policies can be combined with emissions limits established by Hawaii's GHG Rules to 

meet BSER goals of the CPP. Commenters suggested that federally enforceable GHG limits 

would be a component of the numerator of the calculation, while other enforceable EE/RE 

programs would be a component of the denominator of the calculation.

REASONS TO NOT RECOMMEND NUMERATOR APPROACH

Commenters did not recommend the numerator approaches, stating that under this approach, the 

renewable energy must be converted into estimates of displaced fossil fuel, and deriving 

displaced emissions is complicated and would not yield accurate results for all companies or 

circumstances. Commenters offered that, if EPA selected the numerator approach, then displaced 

emissions should be bound between the range of fossil fuel emissions for combined cycle gas 

turbines and existing coal.

Commenters supported counting additional renewable energy in the denominator. Commenters

added that this allows utilities to readily demonstrate and verify renewable energy purchases by 

acquiring and retiring RECs against their SIP requirements. Commenters stated that the use of 

these tracking systems precludes double counting, and that these systems have been used for 

years to track, trade and retire RECs.

Commenters did not recommend the numerator approaches, stating that under this approach, the 

renewable energy must be converted into estimates of displaced fossil fuel, and deriving 

displaced emissions is complicated and would not yield accurate results for all companies or 

circumstances. Commenters offered that, if EPA selected the numerator approach, then displaced 

emissions should be bound between the range of fossil fuel emissions for combined cycle gas 

turbines and existing coal.

Commenters added that accounting for renewable energy under a mass-based approach is 

simplified, and imported power could simply be assigned an emission rate of the region, utility 

or specific power plant. Commenters added that some tracking systems (for example, the 

NEPOOL GIS 1) already assign emission rates to every MWh imported into their respective 

region, whether it be a regional rate or the rate of a specific power plant, and would be well 

suited to track emissions under a mass-based approach.

Comment 6: Comments regarding increased EE lowering overall generation in the denominator, 

which increases the emissions rate in the compliance calculation.

Response 6: The final rule adopts the denominator approach recommended by the reviewers.

Consistent with the EPA’s calculation of the CO2 emission performance rates and state rate-
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based CO2 goals in the final emission guidelines, quantified and verified MWh impacts of 

qualifying zero-emitting and low-emitting resources can be added to the denominator of an 

affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted CO2 emission rate.

For more information about specific methods to adjust the CO2 emission rate of an affected 

EGU to reflect RE and demand-side EE and eligibility requirements for resources that can be 

used to adjust a CO2 emission rate, see section VIII.K.1 of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters argued that EE is equivalent to negative load growth, or fewer MWh generated, and 

that this increases the emission rate under the proposed compliance calculations. Under the 

proposed rate-based approach compliance calculation, commenters believed that EE measures 

would lower the denominator, which increases the emissions rate and compliance burden of the 

CPP and discourages aggressive EE measures, which is counter to the goal of reducing overall 

CO2 emissions.

Comment 7: Commenters suggesting RE and EE be accounted for by subtracting avoided 

emissions from the numerator.

Response 7: In the final rule, EPA adopted the denominator approach, not the numerator 

approach recommended by these reviewers that commented upon the proposed approach. EPA 

revised the methodology used to calculate CO2 emission performance rates and state rate-based 

CO2 goals from the one used in the proposal. Consistent with EPA’s calculation approach in the 

final emission guidelines, quantified and verified MWh impacts of qualifying zero-emitting and 

low-emitting resources can be added to the denominator of an affected EGU’s reported CO2

emission rate, resulting in a lower, adjusted CO2 emission rate. The reported CO2 emissions 

reflect the actual emission reductions from the deployment of qualifying non-emitting and lowemitting resources across the regional grid. Further adjustment of CO2 emissions, such as 

through the subtraction of emissions estimated by applying an emissions factor to the MWhs, 

would double count CO2 emissions impacts across the grid. For more information about specific 

methods to adjust the CO2 emission rate of an affected EGU to reflect RE and demand-side EE, 

how it ensures consistency with goal-setting calculations, and eligibility requirements for 

resources that can be used to adjust a CO2 emission rate, including new and incremental 

renewables (including hydro), nuclear and energy efficiency, see section VIII.K.1 of the final 

rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters supported accounting for renewable energy, energy efficiency, and electric 

generating unit retirements by subtracting avoided emissions from the numerator of a state's or 

entity's emission rate, rather than by adding the clean and avoided generation into the 

denominator. Commenters also supported counting the emission reductions for renewables, 

nuclear, and efficiency in the numerator of the emission rate formula rather than just the 

generation in the denominator. Commenters strongly agreed with this approach as these 
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technologies are clearly reducing CO2 by displacing fossil generation and it's a more consistent 

and equitable approach with how natural gas fuel switching is treated. Commenters argued, 

however, that only the CO2 reductions from new and incremental renewables (including hydro), 

nuclear and efficiency should be counted, as the CO2 reductions from existing renewables 

(including hydro), nuclear and efficiency are already embedded in the baseline emissions and 

generation mix.

Comment 8: Comments suggesting that the EPA's standard needs to encompass the full fuel 

cycle; clarification of renewable energy generation.

Response 8: The EPA recognizes the value of BSER and non-BSER measures, such as demandside EE and combined heat and power, to reduce CO2 emission from affected EGUs, and allows 

for the inclusion of both BSER and non-BSER measures as a part of a state’s plan to meet the 

emission guidelines. To the extent qualifying demand-side EE, renewable energy and non-BSER 

measures are tied to a state plan, the quantified and verified MWh impacts of the measures may 

be used by an affected EGU or state to adjust a CO2 emission rate, regardless of whether the 

savings occur inside or outside the state or territory. 

In response to comments, in the final rule, the EPA clarifies eligibility requirements in section 

VIII.K.1 of the final rule preamble of the CPP for BSER and non-BSER resources that can be 

used to adjust a CO2 emission rate when demonstrating compliance with the emissions 

guidelines under a rate-based approach, including requirements related to energy efficiency, 

biomass, incremental hydroelectric power, wind, geothermal, combined heat and power and 

waste heat power. EPA also clarifies which resources are ineligible from counting toward 

compliance in a state plan, such as those that reduce CO2 emissions outside the electric system.

While states may define renewable resources in their independent state policies different from 

EPA, EPA requires that renewable energy resources states can use for purposes of meeting the 

emission guidelines must meet the eligibility requirements specified in the rule. These 

requirements align eligibility with certain factors and assumptions used in establishing the 

BSER, and by extension, application of the BSER to the performance levels established for 

affected EGUs in the guidelines.

Biomass is not considered part of the best system of emission reduction in this rule and therefore 

it is not included in goal-setting or compliance evaluations. However, similar to other 

technologies outside of BSER, biomass may be considered as a part of a state’s plan to meet the 

emission guidelines.

For more information regarding Building Block 3, refer to Section V.E of the preamble. 

A discussion regarding the use of some biomass feedstocks for compliance purposes can be 

found in Section VIII.I.2.c and Section VIII.K.1 of the preamble.

The following are summaries of the specific public comments under this comment:
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Several commenters said that the EPA should clarify how renewable energy technologies are 

addressed in state compliance plans. 

Commenters argued that since emissions are directly related to energy consumption, the focus 

must be on source efficiency and EPA should embrace an efficiency standard that encompasses 

the full fuel cycle and considers the entire energy chain from source to site with rules and 

policies accordingly.

Commenters recognized that the EPA likely intends to allow states to credit the full range of 

renewable energy generation, but the EPA should clarify that all emission reductions resulting 

from a range of renewable technologies, such as biomass, incremental hydroelectric power, and 

marine renewable energy, are acceptable in a state compliance plan. Commenters agreed with the 

EPA that expanded renewable energy generation provides an important and cost-effective 

component of the Proposal and supported its inclusion in the BSER. Commenters provided a 

detailed discussion of renewable energy resources and programs in the State of Oregon. 

Commenters supported the following elements of the proposal: 

• EPA's consumption based approach to renewable energy crediting in 

state compliance plans. 

• The alternative method for renewable BSER calculation, but with a 

modification to use regional technical and economic potential for each 

technology. 

• Allowing generation from biomass in a state compliance plan similar to 

non-emitting generation and consistent with the EPA's forthcoming 

biogenic carbon dioxide accounting framework. 

Commenters noted that waste heat from industrial applications, biomass from beetle kill and 

methane from landfills and coal mining are allowed to count toward compliance with the RPS in 

Colorado, and while combustion from burning biomass and methane emits greenhouse gases, the 

overall benefit from combusting these fuels should be accounted for in the Plan. Commenters 

concluded that the Plan should encourage generation from any resource that reduces overall 

greenhouse gas emissions, specifically, any electricity generated from methane that would 

otherwise be vented to the atmosphere or flared, as waste gas should count toward the emission 

reductions contemplated by the Plan. 

Commenters said that the EPA needs to provide additional clarification on what generation, 

energy efficiency and demand side sources are considered "renewable" for purposes of the rule. 

Commenters noted that many western states, including Nevada, are experiencing increased 

implementation of Distributed Generation (DG) resources, particularly adoption of roof top solar 

installations in residential markets. Commenters asked that the EPA recognize DG as an eligible 

resource without restriction for inclusion in state compliance plans and for demonstrating 

compliance with emission reduction targets. Commenters stated that in addition to wind and 

solar resources, both existing and new geothermal resources should be treated as 100% 

renewable sources and should be available for states to include in their compliance plans. Unlike 

some renewable energy sources that are intermittent, commenters described their facility that 
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provides a more consistent output as the compressor station is expected to operate approximately

90% of the time. Commenters stated that this type of facility/process should also be recognized 

by the EPA as a qualifying renewable resource and that the EPA should not assign a discount 

rate to either geothermal sources or heat recovery resources. 

Commenters said that the CAA explicitly envisions that states will have more flexibility to 

design compliance plans than EPA does in determining BSER and the resulting emission 

limitation. Commenters stated that while an emission limitation must be achievable through 

application of BSER, the standards of performance in state compliance plans need only to 

"reflect the degree of [the] emission limitation."(See CAA section 111(a)(1)). Commenters added 

that state compliance plans, therefore, need not require use of the measures the EPA proposes to 

determine are BSER and the use of the word "degree" further reinforces that a state need not 

implement the specific system of emission reduction the EPA used to set the emission limitation. 

Commenters concluded that so long as the state plan results in emissions that are consistent with 

the state goal, the standard is consistent with the authority granted to the states under section 

111(d). Commenters added that non-BSER measures could provide important, but relatively 

small, emission reductions. 

Commenters supported allowing incremental hydroelectric power projects to provide compliance 

credit as these types of upgrades extend the hydroelectric power system and provide for real 

emission reductions. Commenters said that because the estimates and accounting for this 

technology can vary widely among operators, the EPA should consider best practices in the 

states when it develops the methodology for these calculations. Commenters added that 

incremental hydropower is an efficiency improvement and the EPA should consider providing 

states guidance on the appropriate measure life for such an upgrade. 

Commenters favored the inclusion of incremental hydropower, including new construction and 

uprates, in the RE calculation. Commenters said that the year-to-year variation in hydropower 

generation could be accommodated by using a 3-year average. Commenters recommended that 

the rule should clarify that banked generation from previous years will be counted toward a 

current year in Building Block 3. Commenters supported the use of RECs from 2012 to 2030 for 

goal compliance purposes because these RECs represent a sizable economic investment and have 

displaced carbon emitting generation. Commenters said that the same can be said for energy 

waste reductions accomplished during the years 2012 through 2030 and continuing to provide air 

quality benefits in those years. 

Commenters supported allowing offshore wind and wave and other marine renewable resources 

to provide compliance credit in the same manner as other renewable energy technologies, 

whether they are located in state territorial waters or federal waters. Commenters said that 

marine energy is an emerging renewable energy sector that offers unique benefits to coastal 

communities with limited power generation options. 

Commenters said that consideration should be given to a fifth building block based on moving 

power from a centralized power station to point of consumption with a distributed power system. 

Commenters stated that two-thirds of the energy generated by a centralized power station is 

consumed, moving the power from where it is generated to the user. Commenters stated the US 

can reduce the amount of carbon it puts in the atmosphere by supplementing centrally produced 
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power with energy produced by a distributed power system, solar, wind, and geothermal systems 

that serve individual homes and businesses. While this will not replace the base load produced by 

power plants, commenters stated, it may mitigate the need to build additional capacity to satisfy 

peak loads. Commenters added that a distributed power system has the added benefit of being 

resilient, because homes that would otherwise lose power when the grid is affected by an 

extreme weather event or other disaster may be able to provide the capability of sheltering its 

occupants in place through that disaster, reducing the need for emergency services. 

With respect to fuel cells, commenters said that the proposed rule does not indicate how fuel cell 

generation will be credited and recommended that fuel cells be treated as a renewable regardless 

of fuel source. Commenters stated that accordingly, fuel cells should be creditable in a state plan 

regardless of when installed. Commenters noted that Connecticut has limited capacity to build 

renewable generation in state, but the state has made significant investment in encouraging fuel 

cell generation as an economically viable option for reducing air pollutant emissions from instate generation. Commenters stated that the EPA has indicated that it intends on treating fuel 

cells powered by natural gas as fossil fueled generation in the final rule, and that they believe this 

is an inappropriate treatment of fuel cell technology and does not properly recognize the 

potential for this clean technology to reduce CO2 emissions from existing fossil fuel generation. 

Commenters stated that excluding natural gas fuel cells from the renewable energy generation 

definition would exclude existing units from compliance and, would not properly recognize the 

contributions of leading states like Connecticut in advancing this technology. 

Commenters applauded the EPA for providing as a compliance option an adjustment or tradable 

credit system for demand side resources, and added that this approach should be applied to all 

demand-side solutions including not only RE and EE but also other forms of generation such as 

fuel cells and CHP. Specifically, commenters stated, the EPA should include low-emissions 

distributed generation under Block 4, as these technologies represent a more efficient method of 

generating energy. Commenters said that the EPA should use the adjustment of CO2 emission 

rate based on avoided CO2 emissions approach using the marginal emissions rate inclusive of the 

avoided transmission and distribution losses inherent in generating electricity close to loads. 

Consistent with industry standards, commenters said that this is the most appropriate method for 

crediting emissions reductions resulting from demand-side measures as it allows for more 

flexibility and streamlined implementation than adjusting a specific EGU's emission rate based 

on avoided MWh. Commenters stated that if it is implemented using the appropriate marginal 

emissions rate representing the generation that is displaced at the margin for every MWh saved 

or generated on the demand-side (and not using an average emission factor), it will provide a 

high degree of accuracy and consistency with existing state programs.

Comment 9: Comments supporting inclusion of EE as a component of the BSER; demand-side 

EE programs allow states flexibility; comments requesting the EPA provide guidance to states on 

how to account for emission reductions from EE measures.

Response 9: In this final rule, EE is no longer considered part of the best system of emission 

reduction. However, demand-side EE may be included as a part of a state’s plan to meet the 

emission guidelines. To the extent demand-side EE measures are tied to a state plan, the 
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quantified and verified MWh impacts of the measures may be used by an affected EGU or state 

to adjust a CO2 emission rate, regardless of whether the demand-side EE savings occur inside or 

outside the state or territory. The addition of these MWhs to the denominator of an affected 

source’s reported CO2 emission rate results in a lower adjusted CO2 emission rate. For more 

detail on the BSER, refer to section V of the final rule preamble of the CPP. For more 

information about specific methods to adjust the CO2 emission rate of an affected EGU to reflect 

demand-side EE and eligibility requirements for resources used to adjust a CO2 emission rate, 

including but not limited to demand-side EE, see section VIII.K.1.a of the final rule preamble.

This final rule allows for the development and use of single-state and multi-state trading 

programs, as specified in section VIII.C of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated that because the proposed Clean Power Plan includes end-use EE programs 

as components of the BSER to be implemented and enforced under section 111(d) it provides 

significant flexibility for state regulators to select an optimal portfolio of pollution reduction 

strategies that includes a combination of on-site and off-site control measures. Commenters 

stated it is important for EPA to preserve this flexibility while also providing sufficient guidance 

to state regulators on how they can account for emissions reductions from EE measures in their 

initial section 111(d) plans and subsequent compliance demonstrations. Commenters stated these 

comments highlight some of the key questions that the EPA should address when issuing the 

final rule and any accompanying guidance, as well as recommendations on how EPA can 

develop a flexible regulatory framework that will allow states to experiment with a variety of 

different approaches for reducing emissions through EE. 

5.2.2 Approaches for adjusting EGU CO2 emission rates

This section discusses the basic accounting method for adjusting the reported CO2 emission rate 

of an affected EGU, through the use of measures, such as energy efficiency and renewable 

energy that substitute for or avoid generation from affected EGUs. That method is based on 

adding MWh from such measures to the denominator of an affected EGU’s reported CO2

emission rate. 

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments summarizing a variety of factors that impact adjusting EGU CO2

emission rates and/or have not been considered by EPA.

Response 1: In the final rule, the EPA provides a clear approach for demonstrating that 

renewable energy and energy efficiency project reductions are creditable. The EPA adopted the 
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denominator approach, not the numerator approach recommended by these reviewers that 

commented on the proposed approach. The EPA revised the methodology used to calculate CO2

emission performance rates and state rate-based CO2 goals from the one used in the proposal. 

Consistent with EPA’s calculation approach in the final emission guidelines, quantified and 

verified MWh impacts of qualifying zero-emitting and low-emitting resources can be added to 

the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted 

CO2 emission rate. The reported CO2 emissions reflect the actual emission reductions from the 

deployment of qualifying non-emitting and low-emitting resources across the regional grid.

Further adjustment of CO2 emissions, such as through the subtraction of emissions estimated by 

applying an emissions factor to the MWhs, would double count CO2 emissions impacts across 

the grid. 

Under a rate-based plan, the retirement of a higher-emitting affected EGU will reduce the 

weighted average CO2 emission rate of the remaining fleet of affected EGUs, helping a state to 

achieve its rate-based CO2 emission goal. 

In the final guidelines, the EPA modified its treatment of nuclear energy. As described in section 

VIII.K.1.a.(8) of the final rule preamble of the CPP, consistent with treatment of other low- and 

zero-emitting generation, new nuclear power generating capacity installed after 2012 and 

incremental generation resulting from nuclear uprates after 2012 are measures eligible for 

adjusting a CO2 emission rate. However, existing nuclear units (i.e., those that originally 

commenced operation in 2012 or earlier years) that receive operating license extensions are not 

eligible for use in adjusting a CO2 emission rate, except where such units receive a capacity 

uprate as a result of the relicensing process. Only the incremental capacity from the uprate is 

eligible for use to adjust a CO2 emission rate.

In response to comments received, the EPA makes it clear what counts as a RE for purposes of 

Section 111(d) compliance in section VIII.K.1.a.(2) of the preamble to the final rule.

In the final rule, the EPA is not allowing shifting generation to new NGCC units to be used as a 

measure for adjusting CO2 emission rates for affected EGUs in rate-based state plans, as 

described in section VIII.K.1.b of the final rule preamble.

For more information about specific methods to adjust the CO2 emission rate of an affected 

EGU to reflect RE and demand-side EE, the timing and the eligibility requirements for resources 

used to adjust a CO2 emission rate, including renewable resources such as wind, solar, biomass

and nuclear, see section VIII.K.1 of the final rule preamble. The rule describes requirements and 

criteria related to proper quantification and verification of MWhs from renewable electricity 

generation or demand-side EE savings in section VIII. K.3 of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters supported EPA's proposal that renewable energy measures may be incorporated 

into a rate-based approach through an adjustment or tradable credit system applied to an EGU's 

reported carbon emission rate. Commenters also supported EPA's alternative approach to provide 

an adjustment based on the estimated carbon emissions that are avoided from the power pool or 

identified region as a result of renewable energy.
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Commenters encouraged EPA to provide states clear guidance on the role of biomass-based and 

NGCC units before the states are required to submit state plans for approval.

Commenters claimed that EPA has failed to provide a clear approach for demonstrating that 

renewable energy and energy efficient project reductions are creditable. Commenters argued that 

power plants shutting down after the baseline date should have their emissions and energy 

contribution factored into the calculation of growth or reduction of carbon load and the clean 

power fraction.

Commenters discussed Building Block 4 compliance calculations. 

Commenters stated that increased energy efficiency is equivalent to negative load growth and 

negative load growth is equivalent to fewer megawatt-hours ("MWh") generated. Commenters 

stated that in the proposed rule's annual compliance calculation, the amount of MWh generated is 

in the denominator. Commenters noted that for compliance purposes, lowering the denominator 

lowers the overall emission rate level, which increases the compliance burden with the Clean 

Power Plan. Commenters stated that such a reality creates a disincentive to engage in aggressive 

energy efficiency measures, which is counter to the goal of reducing overall CO2 emissions.

Commenters stated that the guidelines for compliance with energy efficiency requirements 

written in the proposed Rule further complicate matters, as they impose limitations regarding 

when energy efficiency can be brought onto the electric utility system. Commenters stated that 

compliance can be demonstrated by adjusting the CO2 emission rate based on pounds per CO2 or 

MWh (lbs/ CO2 or lbs/ MWh) of affected generation that the new energy efficiency displaced. 

Commenters stated that this brings up a concern for industry regarding how the lower emission 

rate or offset of affected generation is calculated and justified.

Commenters stated that EPA should simplify in the final Rule regarding how energy efficiency is 

accounted for in the compliance calculation so that increased energy efficiency is a benefit to the 

state for compliance and not a potential detriment. 

Comment 2: Comments stating that the proposal does not provide adequate detail on how 

compliance calculations should be determined.

Response 2: In the final rule, quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources tied to a state plan may be used by an affected EGU or state to adjust 

a CO2 emission rate, regardless of whether the renewable generation or demand-side EE savings 

occur inside or outside the state or territory. Consistent with the EPA’s calculation of the CO2

emission performance rates and state rate-based CO2 goals in the final emission guidelines, the 

MWh impacts are added to the denominator of an affected EGU’s reported CO2 emission rate, 

resulting in a lower, adjusted CO2 emission rate. For more information about specific methods to 

adjust the CO2 emission rate of an affected EGU to reflect RE and demand-side EE, including 

eligibility requirements and sample calculations, see section VIII.K.1 of the final rule preamble 

of the CPP.
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For more information on the treatment of in-state and out-of-state renewable energy and energy 

efficiency impacts, see section VIII.L of the final rule preamble, Treatment of Interstate Effects. 

The rule describes requirements and criteria related to proper quantification and verification of 

MWhs from renewable electricity generation or demand-side EE savings in section VIII.K.3.

The following are summaries of the specific public comments under this comment:

Commenters requested that EPA provide model compliance calculations that include all types of 

existing and new generation sources and new energy efficiencies.

Commenters indicated a lack of clarity in EPA's calculation methodology and how a rate would 

be calculated for a utility that operates across state boarders. Commenters requested that EPA 

provide examples of the calculation methodologies for EGUs and explain how incorporating 

demand-side energy efficiency measures under a rate-based approach impacts utilities that 

operate across state boarders.

5.2.2a Adjustment of CO2 emission rate based on avoided MWh

This section discusses the measures to reduce CO2 emissions from affected EGUs by avoiding 

the need for generation altogether (in the case of resources that lower electricity demand through 

improved demand-side EE and demand-side management). 

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments suggesting that the EPA should provide more guidance on approvable 

emission crediting methodologies, and clarify that the avoided MWh approach is acceptable. 

Some commenters contend that requirements to eliminate a MWh of fossil fuel generation for 

each MWh of RE added or avoided generation will create reliability problems.

Response 1: In the final rule, quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources tied to a state plan may be used by an affected EGU or state to adjust 

a CO2 emission rate, regardless of whether the renewable generation or demand-side EE savings 

occur inside or outside the state or territory. Consistent with the EPA’s calculation of the CO2

emission performance rates and state rate-based CO2 goals in the final emission guidelines, the 

MWh impacts are added to the denominator of an affected EGU’s reported CO2 emission rate, 

resulting in a lower, adjusted CO2 emission rate. For more information about specific methods to 

adjust the CO2 emission rate of an affected EGU to reflect RE and demand-side EE, including 

eligibility requirements and sample calculations, see section VIII.K.1 of the final rule preamble 

of the CPP.

For more information on the treatment of in-state and out-of-state renewable energy and energy 

efficiency impacts, see section VIII.L of the final rule preamble, Treatment of Interstate Effects
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and Addressing Potential Leakage. The rule describes requirements and criteria related to proper 

quantification and verification of MWhs from renewable electricity generation or demand-side 

EE savings in section VIII.K.3 of the final rule preamble.

Regarding reliability, EPA officials worked closely with DOE and Federal Energy Regulatory 

Commission (FERC) officials to ensure, to the greatest extent possible, that actions taken by 

states and affected EGUs to comply with the final rule mitigate potential electric system 

reliability issues. Senior EPA officials met with each of the FERC Commissioners and EPA staff 

had frequent contact with FERC staff throughout the development the rule. FERC held four 

technical conferences to discuss implications of compliance approaches to the rule for electric 

reliability. EPA staff attended the four conferences and EPA leadership spoke at all of them. The 

EPA, DOE, and FERC will continue to work together to ensure electric grid reliability in the 

development and implementation of state plans. For more information about reliability 

considerations, see section II.D of the final rule preamble and for more detail about EPA 

consultations about reliability, see section II.K.

The following are summaries of the specific public comments under this comment:

Commenters stated that The Clean Power Plan should provide more guidance on approvable 

emission crediting methodologies, and should make clear that the avoided MWh approach is 

acceptable. Commenters added that, in order to provide certainty to states and to the advanced 

energy industry, EPA should provide clearer guidance in its final Clean Power Plan as to which 

accounting methods will be acceptable. Commenters also asked if EPA would leave it to the 

states to choose among these methods, and if the Clean Power Plan would include only a limited 

set of approvable methods rather than all methods identified in the Proposed Rule. Commenters

recommended that EPA should not wait until the plan approval process to signal what methods 

states can use.

Commenters noted that the electric grid is supplied by a wide variety of generating sources such 

as coal-fired EGUs, natural gas-fired EGUs and CCTs, nuclear, renewable energy (including 

hydro and pumped storage), and other generation (waste gases, petroleum, and storage). 

Commenters then asked what the procedure would be to estimate the avoided emissions for the 

credit. Commenters added that, since the avoided power consumption could come from any one 

of the sources of generation, how would they identify the source of the electrons that provide the 

electric energy avoided by an energy efficiency project? Commenters further posed the question 

on whether EPA's intent was to allow states to count any type of non-emitting MWh toward 

compliance, and also how to account for new low-emitting MWh (i.e., fossil with CCS). Finally, 

commenters asked for clarification on whether it is necessary for a state to provide some type of 

policy support for EE, RE, and nuclear power to be able to count associated MWh toward 

compliance with rate goals, or is the determination regarding which MWh count based entirely 

on technology type and possibly start date.

Commenters argued that requirements for states to eliminate a MWh of fossil fuel generation for 

each MWh of renewable energy added or each MWh of generation avoided through energy 

efficiency would make the current unattainable targets even more stringent, and would create 

insurmountable reliability problems. Commenters noted in particular potential problems from 
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cutting off baseload generation for intermittent renewable generation in situations where the 

renewable generation is not being facilitated (i.e., wind fails to blow or sun does not shine).

Comment 2: Comments urging the EPA to use the avoided MWh approach for zero-carbon 

generation and energy efficiency measures, consistent with target calculation methodology for 

Building Blocks 3 and 4. Comments also suggesting that emission crediting for avoided 

emissions should be based upon the marginal generating resource.

Response 2: In the final rule, the EPA adopted the denominator approach, not the numerator 

approach recommended by these reviewers that commented on the proposed approach. The EPA 

revised the methodology used to calculate CO2 emission performance rates and state rate-based 

CO2 goals from the one used in the proposal. Consistent with the EPA’s calculation approach in 

the final emission guidelines, quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources can be added to the denominator of an affected EGU’s reported CO2

emission rate, resulting in a lower, adjusted CO2 emission rate. The reported CO2 emissions 

reflect the actual emission reductions from the deployment of qualifying non-emitting and lowemitting resources across the regional grid. Further adjustment of CO2 emissions, such as 

through the subtraction of emissions estimated by applying an emissions factor to the MWhs, 

would double count CO2 emissions impacts across the grid. 

The EPA agrees that tools for estimating the timing of EE savings or RE production are welldemonstrated and reliable; they add further layers of complexity to the avoided CO2 approach. 

As indicated above, however, the EPA has adopted in the final rule the denominator or MWh 

approach instead of the avoided CO2 approach. The EPA does not require a projection of CO2

emission performance for all state plan approaches. For those that do require a projection, the 

EPA does not require that states use dispatch modeling but calls for the use of technically sound 

methods that are reliable and replicable. The EPA addresses what types of state plan approaches 

require a projection and requirements related to methods and tools in section VIII.D.2.a.(3) of the 

final rule preamble of the CPP. Because of the separate accounting of MWhs and CO2 emissions, 

with emission impacts inherent in reported stack CO2 emissions and zero-emitting MWh impacts 

requiring explicit adjustments, the accounting method corresponds with the use of MWhdenominated Emission Rate Credits (ERCs) in the rate-based emission trading framework 

specified in this rule. The accounting method only requires a quantification of the MWh 

generated or avoided by an eligible measure, and thus credits or adjustments can be denominated 

in MWh and do not need to represent an approximation of the CO2 emission reductions that 

result from those MWhs.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect RE and demand-side EE and the eligibility requirements for resources used to adjust a 

CO2 emission rate, including biomass, see section VIII.K.1 of the final rule preamble. 

Requirements for rate-based emission trading programs and the issuance and tracking of ERCs in 

rate-based emission trading programs is addressed in detail in section VIII.K.2 of the final rule 

preamble. The rule describes requirements and criteria related to proper quantification and 

verification of MWhs from renewable electricity generation or demand-side EE savings in 

section VIII.K.3 of the final rule preamble.
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The following are summaries of the specific public comments under this comment:

Commenters urged EPA to use the avoided MWh approach for zero-carbon generation and 

energy efficiency measures. Commenters stated that this approach can be with the greatest 

certainty and at the least cost, and is most likely to provide an acceptable level of emission 

reduction accuracy. Commenters added that this approach is the easier of the two possible 

approaches. Commenters also noted that this approach is consistent with the Proposed Rule's 

methodology for the calculation of BSER for Building Blocks 3 and 4. Commenters further 

stated that it would be inconsistent for EPA to find that method an acceptable means of 

estimating emission reduction from zero-carbon generation and energy savings for the purpose of 

calculating state targets but not for the purpose of determining compliance with those targets. 

Commenters recommended the final rule incorporate an emissions reduction crediting 

framework resulting from energy efficiency measure savings. Commenters further suggested that 

each state would use the value based upon the marginal generating resource, since marginal 

resource emissions reduction credit would reflect inter-regional generation and transmission 

inter-dependence and fully recognize the value of energy efficiency across the region. 

Commenters stated that this approach would also create a market based mechanism that states 

could use to meet their targets. In a similar fashion, commenters recommended that EPA always 

consider avoided emissions based upon the system's marginal emission rate. Commenters further 

stated that such an approach would produce an estimate of the emissions reductions that actually 

occur from the marginal plants that reduce output.

Commenters supported the avoided MWh approach as preferable for the following reasons, 1) 

the approach is consistent with how EPA calculated the targets for both Blocks 3 and 4 resulting 

in greater certainty about how to incorporate RE and EE into the state plans; 2) switching to a 

different methodology might mean that a States RPS might not have the impact EPA anticipated 

based on the state's emission rate; 3) the avoided MWh approach allows states to predict with 

more certainty the impact of their RE and EE measures on their plan performance demonstration; 

4) using the avoided CO2 approach requires a calculation of the CO2 emissions avoided by each 

MWh generated from a renewable resources and while the accuracy of these methodologies 

increases with their complexity and resources to execute them, for longer time horizons (as those 

in the CPP) which require states to forecast power systems dynamics 14 years out, the actual 

EGUs displaced and tons of CO2 avoided may differ significantly. In contrast the avoided MWh 

approach allows states to implement a policy designed to bring about a certain level of renewable 

energy generation and if that policy works properly, the state will be on track to meet its goals; 

5) the use of an avoided MWh approach will be more transparent to the public and to EPA. If 

system dispatch and capacity planning models are used , stakeholders seeking to review the plan 

or assess the state's compliance will have to procure expensive licenses to work with the models; 

6) the avoided MWh approach would be less expensive and complicated for state agencies to 

implement; and 7) while accounting for actual CO2 reductions attributable to specific EE and RE 

measures would be helpful, it is not necessary to satisfy the quantifiable requirement for 

emission standards under section 111(d), quantification of MWhs and treatment of those MWhs 

as zero-carbon generation as part of an overall system will satisfy the section 111(d) conditions.

Commenters also noted that while EPA proposed a range of methodologies for estimating 

avoided CO2, the ten year compliance period, combined with a four year gap between state plan 
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development and beginning of the compliance period, will require capacity expansion modeling 

in addition to system dispatch. Commenters stated this requirement will greatly increase the 

expertise and resources needed to develop the state plans and result in difficulties for 

stakeholders and EPA staff in reviewing the proprietary model inputs and outputs. Commenters

noted that were EPA to require states to use dispatch modeling to forecast emission reductions, a 

barrier to estimating avoided CO2 from renewable energy is the need for information on the day 

and time the renewable energy was generated or the MWh was saved. Commenters stated that 

existing REC tracking systems do not maintain information on the day and time that an RE 

megawatt hour was generated. Commenters stated that likewise, most EE program administrators 

do not gather information on when a particular RE measure is actually saving energy on the 

system, though estimates can be developed based on the type of EE measure. Commenters noted

that while tools for estimating the timing of EE savings or RE production are well-demonstrated 

and reliable, they add further layers of complexity to the avoided CO2 approach. Commenters 

stated that in contrast, most state RE and EE targets are either already designed around MWh 

targets or are based on percentage of load, which can be readily converted to MWhs. 

Commenters stated in most states, the officials implementing these programs have limited 

experience or a lack of tools to convert MWh savings to avoided CO2 emissions.

Commenters noted some advantages of the avoided CO2 approach, including 1) it is 

fundamentally more accurate in calculating how much CO2 is being reduced through RE and EE 

measures; and 2) under the avoided CO2 approach, not every MWh of RE and EE is equivalent 

as those that displace higher emitting affected EGUs would be more valuable and there would be 

an incentive for states and compliance entities to design RE and EE measures that achieved the 

greatest reductions in carbon emissions so applying the avoided CO2 method would help 

generate better information about which RE and EE measures are most effective at reducing 

carbon emissions.

Comment 3: Comments suggesting that states develop and manage verifiable energy efficiency 

tracking and crediting systems.

Response 3: In the final rule, quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources tied to a state plan may be used by an affected EGU or state to adjust 

a CO2 emission rate, regardless of whether the renewable generation or demand-side EE savings 

occur inside or outside the state or territory. Consistent with the EPA’s calculation approach in 

the final emission guidelines, quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources can be added to the denominator of an affected EGU’s reported CO2

emission rate, resulting in a lower, adjusted CO2 emission rate. The reported CO2 emissions 

reflect the actual emission reductions from the deployment of qualifying non-emitting and lowemitting resources across the regional grid. Further adjustment of CO2 emissions, such as 

through the subtraction of emissions estimated by applying an emissions factor to the MWhs, 

would double count CO2 emissions impacts across the grid. For more information about specific

methods to adjust the CO2 emission rate of an affected EGU to reflect RE and demand-side EE, 

see section VIII.K.1 of the final rule preamble.
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In the final rule, the EPA does require tracking systems for emission rate credits, which can be 

issued for demand-side energy efficiency and other measures. Requirements related to the 

issuance and tracking of ERCs are described in VIII.K.2 of the final rule preamble. Criteria 

related to proper quantification and verification of MWhs from renewable electricity generation 

or demand-side EE savings in section VIII.K.3.

The following are summaries of the specific public comments under this comment:

Commenters argued that states that choose to demonstrate compliance with rate-based goals 

must develop and manage verifiable energy efficiency tracking and crediting systems that are 

reliable for compliance determinations. Commenters wanted verifiable demand reductions to be 

credited and added to the total MWh sales used in the CO2 lb/MWh compliance calculation but 

is opposed to assigning a system average carbon dioxide emission reduction to the avoided MWh 

since it is unwarranted and will result in double counting.

5.2.2b Adjustment of CO2 emission rate based on avoided CO2 emissions

This section discusses measures used to reduce CO2 emissions by substituting zero- or lowemitting generation for generation from affected EGUs.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments suggesting different approaches (i.e., marginal or average emission 

rates) for states making administrative adjustments to the average carbon emission rate of 

affected EGUs and discussing the extent state plans would need to address out-of-state emission 

reductions from energy efficiency measures.

Response 1: In the final rule, the EPA allows for the adjustment of a CO2 emission rate based 

on avoided MWhs, not avoided CO2. The EPA revised the methodology used to calculate CO2

emission performance rates and state rate-based CO2 goals from the one used in the proposal. 

Consistent with the EPA’s calculation approach in the final emission guidelines, quantified and 

verified MWh impacts of qualifying zero-emitting and low-emitting resources can be added to 

the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted 

CO2 emission rate. The reported CO2 emissions already reflect the actual emission reductions 

from the deployment of qualifying non-emitting and low-emitting resources across the regional 

grid. An adjustment of CO2 emissions, such as through the subtraction of emissions estimated by 

applying an emissions factor to the MWhs, would double count CO2 emissions impacts across 

the grid. For more information about specific methods to adjust the CO2 emission rate of an 

affected EGU to reflect RE and demand-side EE and how it ensures consistency with goalsetting calculations, see section VIII.K.1 of the final rule preamble of the CPP.
185

The following are summaries of the specific public comments under this comment:

Commenters supported allowing quantified and verified renewable energy generation to be 

credited toward a demonstrated carbon emission rate for EGU compliance purposes or used by 

the state to administratively adjust the average carbon emission rate of affected EGUs.

Commenters believed that the credit should be determined based on the MWh saved or generated 

and then multiplied by a carbon emission rate for the power pool or region, and that the carbon 

emission rate should be based on the average or marginal emission rate in the power pool. 

Commenters further stated that EGUs should be able to comply with a carbon emission rate limit 

in part through the use of credits, and if a state is implementing a portfolio approach, then the 

state should administratively adjust the average carbon emission rate of affected EGUs through a 

similar process, provided that the carbon-avoiding measures are enforceable elements of the state 

plan.

Commenters encouraged EPA to adopt an adjustment of CO2 emission rate based on avoided 

CO2 emissions. Further, commenters urged EPA to consider a requirement for reporting of 

hourly energy efficiency savings to improve the estimation of avoided CO2, although 

commenters noted that this is currently not practiced in most states. Commenters stated that the 

assumption of dispatch of all EGUs being reduced uniformly under the average emission rate 

approach is not what actually happens, and therefore, calculation of avoided CO2 being used in 

the determination of state compliance should identify savings on an hourly and unit specific basis 

in order to accurately calculate avoided CO2 emissions from energy efficiency.

Commenters requested clarification on the extent state plans would need to address how energy 

efficiency measures affect out-of-state emission reductions in order to take credit for CO2

emission reductions. Commenters also asked to what degree the energy efficiency or renewable 

energy measure avoids new fossil fuel generation capacity and affects transmission or other 

system planning in order to take credit for CO2 emission reductions.

Comment 2: Comments stating that avoided emissions must equal avoided emissions at affected 

EGUs specifically.

Response 2: In the final rule, the EPA allows for the adjustment of a CO2 emission rate based 

on avoided MWhs, not avoided CO2 so avoided CO2 calculations are not necessary. For more 

information about specific methods to adjust the CO2 emission rate of an affected EGU to reflect 

RE and demand-side EE, see section VIII.K.1 of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters argued that if avoided emissions are used they must be calculated to represent 

affected EGUs only instead of a system-wide avoided emissions value.
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5.2.2c Adjustment based on the rate-based emission limit in the state plan

No comments in this section.

5.2.2d Other considerations

This section discusses other issues with adjusting CO2 emissions that states may seek to include 

in their state plans to meet the emission guidelines. The comments in this section address the use 

of alternative compliance payments as a compliance tool, enforceable measures in a state plan 

for the state to receive credit under a rate-based approach, the risk of double counting CO2

emission reductions, and potential emissions reductions at non-affected units under the rule.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments suggesting that alternative compliance payments need to be accounted 

for and are either supported or opposed as a compliance tool.

Response 1: In the final rule, only quantified and verified MWh impacts of qualifying zeroemitting and low-emitting resources tied to a state plan may be used by an affected EGU or state 

to adjust a CO2 emission rate, adding the MWhs to the denominator of an affected EGU’s 

reported CO2 emission rate. For more information about specific methods to adjust the CO2

emission rate of an affected EGU to reflect RE and demand-side EE, see section VIII.K.1 of the 

final rule preamble of the CPP. Requirements and criteria related to proper quantification and 

verification of MWhs from renewable electricity generation or demand-side EE savings are 

described in section VIII.K.3 of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA has not clearly indicated how alternative compliance payments 

(ACPs) will be accounted for and whether states will be allowed to use such payments to 

demonstrate compliance. Commenters stated they prefer that EPA minimize costs to electrical 

consumers by permitting ACPs under state programs to partially or fully offset compliance 

obligations. Commenters noted that there may need to be some consideration of whether a state 

should get credit for meeting CCPs goals from a contribution to a renewable goal and also to a 

demand-side EE goal as the same dollar is being used for both.

Commenters opposed using alternative compliance payments (ACPs) as a compliance tool.

Commenters noted that, although these ACP payments may be directed to programs to promote 

the deployment of renewable energy technologies, these payments are not equivalent to 

renewable energy generation and should not be counted as such in state plans.
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Comment 2: Comments questioning the extent of including enforceable measures in a state plan 

to qualify for credit under a rate-based approach and if it is acceptable for the state to not require 

specific and achievable energy efficiency or renewable energy amounts.

Response 2: The types of measures a state can use depend on the approach the state chooses, as 

described in Section VIII.C. In the final rule, quantified and verified MWh impacts of qualifying 

zero-emitting and low-emitting resources tied to a state plan, such as RE or demand-side EE,

may be used by an affected EGU or state to adjust a CO2 emission rate, regardless of whether 

the RE generation or demand-side EE savings occur inside or outside the state or territory. The 

MWh impacts are added to the denominator of an affected EGU’s reported CO2 emission rate, 

resulting in a lower, adjusted CO2 emission rate. For more information about specific methods 

to adjust the CO2 emission rate of an affected EGU to reflect RE and demand-side EE and 

eligibility requirements for resources used to adjust a CO2 emission rate, see section VIII.K.1 of 

the final rule preamble of the CPP. Requirements and criteria related to proper quantification and 

verification of MWhs from renewable electricity generation or demand-side EE savings are 

described in section VIII.K.3 of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters posed various questions regarding the extent of including enforceable measures in a 

state plan for the state to receive credit under a rate-based approach. Commenters presented a 

scenario where a state has codified EM&V requirements for verifying generation from RE or 

avoided generation from EE in its plan and methods of determining the amount of credit, but 

does not require specific energy efficiency or renewable energy amounts to be achieved. 

Commenters stated that instead, these provisions are included as a compliance option so EGUs 

or other entities can generate credits if they choose to do so. Commenters asked if this scenario 

would meet the enforceability requirements of the rule for these types of measures to be 

creditable. Commenters further noted that if this approach was allowed, states may not be able to 

predict future CO2 emissions, but would only be able to predict the average adjusted rate for 

EGUs, which could be based on the use of EE/RE credits. Therefore, commenters also asked 

whether the prediction of the average adjusted rate for affected EGUs, which could include the 

use of EE/RE credits, would satisfy the emission performance projection requirements of the 

proposed rule.

Commenters stated that as long as renewable energy is supplied to an electricity distribution 

system, it is displacing fossil-fired generation and the resulting avoided CO2 emissions from 

affected EGUs should be creditable under the rule. Commenters suggested crediting all 

renewable energy to a system which is supplied by one or more affected EGUs if a state has 

appropriate evaluation measurement and verification (EM&V) measures incorporated into its 

plan along with codified methods for quantifying the amount of credit to be given.

Comment 3: Comments arguing that double-counting is possible when an Independently Owned 

Utility's (IOU) sales include those resold to municipalities and cooperatives
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Response 3: The EPA agrees that it is necessary to minimize or avoid the risk of double 

counting. In the final rule, under a rate-based plan, there needs to be an explicit adjustment of 

reported CO2 emission rates from affected EGUs, to reflect the measures that substitute low- or 

zero-emitting generation or energy savings for affected EGU generation. Under all types of state 

plans, states must ensure that the measures and associated CO2 emission reductions counted as 

part of meeting their plan requirements are not duplicative of any measures that are counted by 

another state. States with rate-based plans must demonstrate that the RE and demand-side EE 

MWhs that they use to adjust their CO2 emission rate are non-duplicative and meet specific 

requirements related to quantification and verification as described in section VIII.K.3 of the 

final rule preamble of the CPP. More details about the accounting approach for adjusting the 

CO2 emission rate of an affected EGU is detailed in sections VIII.I.2 and VIII.K.1 of the final 

rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated that sales from Independently Owned Utilities (IOU) include sales to other 

entities for resale. Commenters also stated that this could result in double counting due to resale 

to municipalities and cooperatives. Commenters then asked how this reselling would impact state 

compliance especially in states where the public utility commission lacks jurisdiction over retail 

sales of municipalities and co-ops.

Comment 4: Comments concerning a lack of credit towards CO2 rate reductions for nonaffected units under the rule.

Response 4: The MWh accounting method adopted in the final rule allows for a wide range of 

measures that may be used to adjust a CO2 performance rate. While the CO2 emission 

reductions from the eligible measures may occur across the region, an affected EGU or a state 

may only take credit for the avoided CO2 emissions at that affected EGU or set of affected 

EGUs as reflected in their reported stack CO2 emissions. Through an adjustment to the 

denominator of a reported CO2 emission rate, however, affected EGUs can take full credit for 

the zero-emitting MWhs resulting from eligible measures that they are responsible for deploying, 

no matter where the eligible measures may occur across the region. For more information about 

adjustments to CO2 emission rates in rate-based plans, including the approach and description of 

eligible measures, see section VII.K.1 of the final rule preamble of the CPP. During the interim 

and compliance periods, affected EGUs will have the opportunity to adapt their investments over 

time to ensure that they meet the emission guidelines.

The following are summaries of the specific public comments under this comment:

Commenters noted that EPA states that emissions reductions will potentially occur at peaking 

and new EGUs which are non-affected units under the rule. Commenters stated that new units 

may impact which marginal EGUs go online/offline differently than were forecasted and this 

may impact the state's ability to meet its expected reductions. Commenters were concerned that 
189

states will be investing resources in emission reductions from these two building blocks and get 

very little credit toward CO2 reductions at affected units.

5.2.3 Methods and tools for quantifying avoided CO2 emissions from end-use energy 

efficiency and renewable energy

This section discusses the methods and tools for accounting and adjusting the CO2 emission rate 

from low or zero-emitting resources. The comments in this section address interstate impacts on 

emission reductions, specific methods to adjust the CO2 emission rate that can be used during 

both the compliance plan development and approval phase, eligibility dates for MWh generation 

and savings and for installation of RE/EE, and eligibility requirements for resources used to 

adjust a CO2 emission rate.

Commenters have raised a number of issues related to this subsection which are organized by

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments suggesting to use the EPA's AVERT and other tools for accounting for 

emissions from low or zero-emitting resources for evaluating state plans or during the 

compliance time period. Commenters also suggest that the EPA include a framework for 

monitoring, reporting and recordkeeping in the rule.

Response 1: In the final rule, the EPA allows for the adjustment of a CO2 emission rate based on 

avoided MWhs, not avoided CO2 so avoided CO2 calculations are not necessary. To the extent 

RE generation and demand-side EE measures are tied to a state plan, the MWh impacts of the 

measures may be used by an affected EGU or state to adjust a CO2 emission rate, regardless of 

whether the RE generation or demand-side EE savings occur inside or outside the state or 

territory. For more information about specific methods to adjust the CO2 emission rate of an 

affected EGU to reflect RE and demand-side EE, see section VIII.K.1 of the final rule preamble 

of the CPP.

The final rule provides information about approaches states can use when projecting the 

emission performance of their plan, when applicable, in section VIII.D.2.a.(3) of the final rule 

preamble. 

In response to comments about state policy and analytic needs, the EPA, in consultation with 

U.S. DOE and other federal agencies, continued to refine its toolbox of decision support 

resources at: http://www2.epa.gov/ www2.epa.gov/cleanpowerplantoolbox. The site includes 

information on regulatory requirements, including state plan guidance and state plan decision 

support. The state plan guidance section serves as a central repository for the final emission 

guidelines, RIA, guidance documents, TSDs and other supporting materials. The state plan 

decision support section includes information to help states evaluate different approaches and 

measures they might consider as they initiate plan development. This section includes, for 
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example, a summary of existing state climate and RE and demand-side EE policies and 

programs, information on electric utility actions that reduce CO2, and tools and information to 

estimate the emissions impact of RE and demand-side EE programs, including the AVERT 

model. For more information about Resources for States to Consider in Developing Plans, see 

section VIII.H of the final rule preamble of the CPP.

The final guidelines establish and describe monitoring, reporting and recordkeeping 

requirements for affected EGUs, state reporting and recordkeeping requirements and public 

participation on the state plan in section VIII.D.2.a of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters presented suggestions for accounting for emissions from low or zero-emitting 

resources. Commenters observed that accounting measures will be necessary during both the 

compliance plan development and approval phase and the compliance demonstration phase to 

ensure that the full emissions reductions associated with use of these resources are credited back 

to the entity making the investment, and that these measures will be needed under either a ratebased or a mass-based system, and for all zero- and low-emitting resources. Commenters

recommended that EPA should allow the use of a simpler but less precise accounting method 

during the plan development and approval phase, out of recognition of the fact that it is 

impossible to predict with any certainty how fuel prices, generator additions and retirements, and 

other factors affecting generator commitment and dispatch will change in the future. 

Commenters added that this could include allowing states to simply credit generation from a 

non-emitting resource at the state or regional average fossil emissions rate. Commenters also 

added that more sophisticated but easily implementable approaches, such as EPA's AVERT tool, 

could also be well suited for these calculations.

Commenters suggested that EPA could assist states by providing region-wide quantifications of 

the emissions reductions produced by non-emitting resources for the purposes of developing and 

evaluating state plans. Commenters added that, by jointly assessing state plan and/or using 

regional modeling, EPA can avoid problems whereby the emissions reductions produced by one 

state's compliance action will change due to power system changes caused by another state's 

compliance action.

Commenters stated that, for the compliance time period, more precise accounting methods can 

be used than those used for state plan development. Commenters noted that EPA's AVERT tool 

is accompanied by annual updates to the underlying dataset that statistically determines which 

power plants had their output reduced by the addition of non-emitting resources, so this updated 

data can be used during the compliance timeframe. Commenters also noted that other approaches 

for a marginal emissions calculation or power system modeling can also be made more precise 

and accurate during the compliance timeframe by incorporating empirical data on fuel prices and 

other factors affecting actual dispatch patterns.

Commenters generally noted that, as state air regulatory agencies generally have no experience 

with renewable energy or energy efficiency or their enforcement, it would seem very important 

for Subpart UUUU to provide a framework for monitoring, reporting, and recordkeeping of these 

affected entities.
191

Commenters recommended that EPA develop an EE program toolkit to support cross-state 

comparability and greater harmonization of EE approaches across jurisdictions. Commenters 

stated a three organization group (NACAA, NARUC, and NASEO) have urged EPA to 1) 

support inclusion of EE programs in state plans, 2) issue guidance providing criteria and 

methodologies for development of acceptable state efficiency programs, 3) provide examples of 

approvable efficiency strategies, and 4) support multi-state programs. Commenters stated this 

approach would benefit appliance replacement and recycling programs. Commenters requested 

that EPA develop a set of standardized and validated ERG protocols supported by key 

stakeholders and EPA/DOE. Commenters stated the protocols would not be mandatory but 

would represent a tool kit that states and utilities could incorporate into their 111(d) 

implementation plans. Commenters stated such a tool kit will reduce burdens on state resources, 

improve the likelihood that PUCs will approve the programs, that EPA will accept state plans, 

and ensure documented reductions for state taking credit in meeting the target goals. 

Commenters recommended that DOE convene a working group of key stakeholders and 

provided a key elements piece and methodology in the comment appendix as a starting point for 

developing a model protocol for linked replacement/recycling rebate programs.

Commenters recommended that EPA develop a projection tool that supports the states in 

analyzing complicated options under the rule and demonstrates that a proposed plan will meet 

the performance level over the 10-year projection period. Commenters argued that the tool 

should be at the national level to accommodate the impact of multi-state trading and interstate 

RE purchasing and to project changes to dispatching. Commenters also argued that the tool must 

be robust and accurate to project emissions under various compliance scenarios to within 10% of 

actual emissions.

Commenters requested that EPA provide further guidance under a range of plausible scenarios 

on how states should treat emission reductions from EE measures that they pay for but some or 

all of the emission reductions of the power grid are modeled to occur in a different state and a 

scenario where both the generating state and buying state might try to claim the CO2 emissions 

reductions and renewable energy credit.

Commenters expressed concern with EPA's proposed RE and EE framework since several of the 

options proposed require an analysis that will be administratively burdensome and could result in 

regulatory uncertainty if the amount of credit is unknown for a new renewable energy project or 

discourage the use of energy efficiency as a compliance option.

Commenters supported EPA's general principle of flexibility for states to design state-wide 

compliance strategies and wants states to be permitted to take full life cycle credit for emissions 

reductions resulting from energy efficiency measures implemented. Commenters noted concern 

with states only receiving credit for EE savings that can be traced back to reduction in demand at 

an in-state fossil fuel generating unit since it will limit the value of EE as a cost-effective 

compliance tool.

Comment 2: Comments asking how far into the future should activities be expected to generate 

emission reductions in a state plan.
192

Response 2: The lifetime of efficiency measures can vary by measure. The final rule specifies 

information states needs to document in their plan, including the underlying measure-related 

assumptions when demonstrating that the emission standards and/or measures contained in a plan 

are projected to achieve the CO2 emission performance rates or state CO2 emission goal. For 

more information, see section VIII.D.2.a.(3) of the final rule preamble of the CPP. Section 

VIII.K.1.a.(2) of the final rule preamble clarifies the eligibility dates under a rate-based plan for 

MWh generation and savings and for installation of RE/EE and other measures. Specific 

requirements related to quantification and verification during the compliance period are

described in section VIII.K.3 of the final rule preamble. The final rule clarifies consideration of a 

facility’s "remaining useful life" in section VIII.G.1 of the preamble.

The following are summaries of the specific public comments under this comment:

Commenters posed questions concerning how far into the future EPA expects activities to 

generate reductions in a state plan. Commenters observed that EPA indicated that energy 

efficiency measures reduce emissions for 10 years, but were unclear on how long EPA would 

expect other types of activities to generate reductions. Commenters asked whether a unit 

retirement in 2015 would reduce emissions during the interim plan period. Another question 

posed by the commenters is how far activities or measures undertaken before 2019 would count 

for compliance, and whether this depended on the remaining useful life of a unit (and, if so, who 

would make this determination).

Comment 3: Comments suggesting the EPA modify the rule to simplify the RE and EE building 

blocks to alleviate emissions tracking and multi-state issues by basing RE and EE reductions on 

a percentage of sales.

Response 3: In the final rule, to the extent RE generation and demand-side EE measures are tied 

to a state plan, the MWh impacts of the measures may be used by an affected EGU or state to 

adjust a CO2 emission rate, regardless of whether the RE generation or demand-side EE savings 

occur inside or outside the state or territory. This ensures that the affected EGUs are recognized 

for their RE generation and demand-side EE investments regardless of the location of the CO2

reduction. The reported CO2 emissions reflect the actual emission reductions from the 

deployment of qualifying non-emitting and low-emitting resources across the regional grid.

Further adjustment of CO2 emissions, such as through the subtraction of emissions estimated by 

applying an emissions factor to the MWhs, would double count CO2 emissions impacts across 

the grid. This removes the need to track the specific location of RE generation or electricity 

savings by states or quantify the avoided CO2 emissions through separate analysis using a tool 

like AVERT, as suggested by the commenter below. For more information about specific 

methods to adjust the CO2 emission rate of an affected EGU to reflect RE and demand-side EE, 

including specific geographic eligibility requirements and limitations, see section VIII.K.1 of the 

final rule preamble of the CPP.

Because of the separate accounting of MWhs and CO2 emissions, with emission impacts 

inherent in reported stack CO2 emissions and zero-emitting MWh impacts requiring explicit 

adjustments, the accounting method corresponds with the use of MWh-denominated Emission 
193

Rate Credits (ERCs) in the rate-based emission trading framework specified in this rule. The 

accounting method only requires a quantification of the MWh generated or avoided by an 

eligible measure, and thus credits or adjustments can be denominated in MWh and do not need to 

represent an approximation of the CO2 emission reductions that result from those MWhs. This 

creates a crediting system or rate adjustment process that is simpler to implement than one that 

requires an approximation of avoided CO2 emissions.

The following are summaries of the specific public comments under this comment:

Commenters urged EPA to modify the rule to simplify the RE and EE building blocks to 

alleviate emissions tracking and multi-state issues by basing RE and EE reductions on a 

percentage of sales. Commenters stated this approach inherently accounts for the impact of 

importing and exporting of electricity and states share the burden on a cost/use basis. 

Commenters stated that tracking the location of avoided generation whole not be required on a 

rigorous basis and RE generation and EE avoided generation could maintain the same EM&V 

and reporting to ensure the energy savings actually occur. Commenters stated this approach 

would make the cost to reduce CO2 from EE fair to all states regardless of whether they are 

importing or exporting and allow CO2 reductions at both peaking and base EGUs to be counted. 

Commenters stated this approach simplifies calculating BSER goals for each state and would not 

require complex negotiations between states to account for importing/exporting and avoided 

generation.

Commenters stated AVERT modeling should be sufficient to estimate the quantity of CO2

reduced for the whole country and this reduction would be allocated to each state based on the 

amount of MWhs avoided. Commenters stated the participating state's CO2 emission rate would 

then be given a credit.

Commenters also proposed a second approach to allocating avoided generation by EPA running 

IPM each year to determine the amount of avoided emissions occurring at states which are going 

beyond the requirement. Commenters stated this rule would be applied to the state's CO2

emission rate, and that out of state reductions that occur at non-participating states could be 

bought for credit by these states.

Commenters opposed allocating avoided emissions to a particular EGU or group of EGUs since 

it is complicated and has unknown accuracy levels. Commenters were concerned that using 

AVERT at this level penalizes importing states and rate payers are paying for emissions 

reductions that happen out of state and cannot take credit on their state plans for the reductions.

Comment 4: Comments suggesting that the EPA require states to conduct a comprehensive 

energy assessment.

Response 4: The final rule requires that states demonstrate in a state measures plan, and in some 

circumstances under an emissions standards approach, that the emission standards and/or 

measures contained in a plan are projected to achieve the CO2 emission performance rates and/or 

state CO2 emission goal. While the final rule is not requiring a specific type of emission 
194

quantification approach or model, it requires the states to choose technically sound methods that 

establish a clear relationship between electricity grid interactions of the state enforceable 

measures, affected EGU dispatch, generation cost and operations within the time frame outlined 

in the final guidelines. For more information about when projections are required and the related 

requirements, see section VIII.D.2.a.(3) of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters requested that EPA require states to conduct a comprehensive energy assessment 

encouraging states to maximize the "least cost option" in their low-carbon energy portfolios 

going forward. Commenters stated that EPA should assist states in understanding the true costs 

and benefits of energy development and encourage them to participate in regional compliance 

models such as renewable energy credits (RECs) trading.

Comment 5: Comments suggesting clarification on Energy Savings Performance Contract 

(ESPC) project-related emission reductions and that that all avoided electricity consumption 

from ESPC projects should be allowed to count toward CPP compliance.

Response 5: To the extent demand-side EE measures are tied to a state plan, the quantified and 

verified MWh impacts may be used to adjust a CO2 emission rate, provided they meet the 

eligibility requirements for resources used to adjust a CO2 emission rate, described in section 

VIII.K.1 of the final rule preamble of the CPP, the eligibility requirements and provisions related 

to demand-side EE programs and projects and the requirements and criteria related to proper 

quantification and verification of MWhs from demand-side EE savings are described in section 

VIII.K.3.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA should clarify that Energy Savings Performance Contract 

(ESPC) project-related emission reductions will be treated the same way as reductions achieved 

through utility ratepayer program EE activities. 

Regarding contributions to future avoided emissions, commenters stated that all avoided 

electricity consumption from ESPC projects should be allowed to count toward CPP compliance. 

Commenters noted that some have argued that building EE improves at a steady rate due to 

normal replacement of equipment, thus a discount rate should apply to building EE projects, but 

they believe that such assumptions are not necessarily sound. Commenters stated that regardless 

of how EPA considers this issue, EPA should apply the same approach to measuring EE 

contributions from ESPC projects as for ratepayer-funded programs.
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5.2.3a Average emission rate approach

This section discusses the average emission rate approach to quantify and allocate emission 

reductions, including avoided CO2 calculations using emission rates.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments opposing the average emission rate approach.

Response 1: In the final rule, the EPA is not requiring the use of an average emission rate 

approach to quantify and allocate emissions reductions. The final rule adopted the MWh 

denominator approach, not the numerator approach which might have involved the calculation of 

emission reductions using an average emission rate that commenters oppose below. Between the 

proposal and the final rule, the EPA revised the methodology used to calculate CO2 emission 

performance rates and state rate-based CO2 goals to better reflect the regional operation of the 

electricity grid. Consistent with EPA’s calculation approach in the final emission guidelines, 

quantified and verified MWh impacts of qualifying zero-emitting and low-emitting resources can 

be added to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a 

lower, adjusted CO2 emission rate. The reported CO2 emissions reflect the actual emission 

reductions from the deployment of qualifying non-emitting and low-emitting resources across

the regional grid. Further adjustment of CO2 emissions, such as through the subtraction of 

emissions estimated by applying an emissions factor to the MWhs, would double count CO2

emissions impacts across the grid and is not appropriate. For more information about specific 

methods to adjust the CO2 emission rate of an affected EGU to reflect RE and demand-side EE 

and how the methods ensures consistency with the goal setting calculations in the final rule, see 

section VIII.K.1 of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters opposed EPA's average emission rate approach to quantify and allocate emission 

reductions. 

Commenters argued that this method oversimplifies electricity dispatching, where importing 

states may not see in-state generation displacement, and could double count emissions 

reductions. Commenters noted that there is no mechanism to ensure the reductions are not being 

double counted.

Commenters requested that the provisions be based on the marginal CO2 emission rate in the 

regional transmission area and not on the average CO2 emission rate.

Commenters restated EPA's options and noted that use of a weighted average emission rate goal 

using each state's emission rate goal from the guidelines is consistent with the method used to 

calculate the state-specific, rate-based emission performance goals, but does not address that a 

weighted average emission rate performance goal for multiple states may be influenced 
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significantly by the weighting of electricity generation from affected EGUs in different states. 

Commenters presented a sample calculation using 2012 generation data from affected units for 

the states of Ohio, Pennsylvania, and New York. Commenters stated the regional goal from this 

calculation is almost double New York's individual state goal and stated this is partially due to 

New York's generation mix. Commenters argued that a weighted average goal for a group of 

states is only appropriate when source-specific goals are set for each state. Commenters stated 

the weighted average approach will disproportionately impact those state that provide power to 

New York while affording New York the opportunity to reach much of its state goal via RECs or 

similar mechanisms. Commenters noted that a more sophisticated methodology should be 

developed that accounts for the generation mix of each state and the importer/exporter status of 

each state.

Commenters also opposed EPA's second option where projected generation is used instead of a 

generation from a certain year. Commenters stated this approach helps alleviate discrepancies 

based on differing generation mixes amongst a group of states but opposes its use in setting 

federally enforceable targets. Commenters stated any potential and unforeseen difficulties arising 

from inaccurate projection would only be magnified when applied to a group of states.

5.2.3b Marginal emission rate approach

This section discusses establishing marginal emission rate factors.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments regarding the difficulties in establishing marginal emission rate factors 

for RE and EE because a state would need to know what resource was at the margin at the time 

the renewable energy or energy efficiency was created.

Response 1: : In the final rule, the EPA allows for the adjustment of a CO2 emission rate based 

on avoided MWhs, not avoided CO2 so avoided CO2 calculations using emission rates are not 

necessary. For more information about specific methods to adjust the CO2 emission rate of an 

affected EGU to reflect RE and demand-side EE and how the methods ensures consistency with 

the goal setting calculations in the final rule, see section VIII.K.1 of the final rule preamble of 

the CPP.

The following are summaries of the specific public comments under this comment:

Commenters urged EPA not to assign a CO2 value to renewable energy and energy efficiency 

measures in order to re-assess building blocks 3 and 4. In their supporting discussion, 

commenters stated that, to appropriately assign a CO2 value to RE and EE, a state would need to 

know what resource was at the margin at the time (which involves hour to hour variations) the 

renewable energy or energy efficiency was created, or EPA would have to come up with some 
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marginal emissions factor. Commenters further stated that very few studies exist on marginal 

emission factors in the US, and EPA would likely have to conduct foundational research into this 

matter. As a result, commenters concluded, EPA should treat renewable energy and energy 

efficiency as originally proposed.

Commenters reiterated EPA's discussion on the complications inherent in adjusting the emission 

rate due to the need to determine which EGU's emissions are reduced for each MWh avoided by 

RE and EE (i.e., the marginal impact of RE and EE). Commenters stated the complications in 

accounting for the impacts of RE and EE may discourage states from pursuing innovative 

demand-side EE programs that alter consumer and building occupant behavior. Commenters said 

that states may also be discouraged by additional paperwork to develop new protocols for 

quantification, monitoring, and verification to incorporate savings into the states emission rate 

calculations.

Comment 2: Comments suggesting that states be allowed to assign an energy efficiency 

emission reduction value equal to the emission rate of the power pools' marginal resources.

Response 2: In the final rule, the EPA allows for the adjustment of a CO2 emission rate based 

on avoided MWhs, not avoided CO2 so avoided CO2 calculations using emission rates are not 

necessary. For more information about specific methods to adjust the CO2 emission rate of an 

affected EGU to reflect RE and demand-side EE and how the methods ensures consistency with 

the goal setting calculations in the final rule, see Section VIII.K.1 of the final rule preamble of 

the CPP.

The following are summaries of the specific public comments under this comment:

Commenters suggested that EPA should allow each state to assign an energy efficiency emission 

reduction value equal to the emission rate of the power pools' marginal resources. Commenters

also stated that EPA should include a crediting framework for emission reductions resulting from 

energy efficiency measures in the final rule that allows each state within the power pool to use a 

rate reduction value based on the resource mix serving that power pool at the margin.

Commenters further suggested that each state should be allowed to use the marginal hourly 

emissions rate (averaged over a year) from its power pool when assigning an emission reduction 

value to energy efficiency.

Commenters suggested that if states opt for an emission rate standard, clean energy solutions 

should be credited on the basis of projected marginal emissions reduced (for example, through 

dispatch modeling or use of AVERT).

Comment 3: Comments supporting the use of a marginal emission rate for purposes of ratebased compliance plans with avoided emissions resulting from EE and RE.
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Response 3: In the final rule, the EPA allows for the adjustment of a CO2 emission rate based 

on avoided MWhs, not avoided CO2 so avoided CO2 calculations using emission rates are not 

necessary. For more information about specific methods to adjust the CO2 emission rate of an 

affected EGU to reflect RE and demand-side EE and how the methods ensures consistency with 

the goal setting calculations in the final rule, see section VIII.K.1 of the final rule preamble of 

the CPP.

The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA credit avoided emissions using the appropriate RTO 

marginal emission rate because incremental EE and RE have historically avoided generation 

from the marginal EGU. Commenters stated use of an average RTO emission rate is 

inappropriate because incremental RE and EE often reduce the rate of demand growth rather than 

displacing generation from the average unit. Commenters stated the generation that would be 

required to meet demand growth is typically supplied by the marginal unit. Commenters

presented information on New England's generating capacity by fuel type as an example.

Commenters also supported the use of multiplying the MWh of clean or avoided generation by 

the marginal emission rate for the load zone in which the EE or RE is located.

5.2.3c Calculation tool method

This section discusses calculating avoided emissions using EPA's AVERT, and other EPA and 

DOE tools to calculate energy, loads, emissions, and other critical components. 

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments asking if states choose whether energy efficiency measures could go in 

either the numerator or denominator and if the AVERT tool would satisfy EPA requirements to 

convert energy efficiency to carbon emission amounts; comments supporting to calculate 

avoided emissions using AVERT

Response 1: Consistent with the revised methodology used to calculate CO2 emission 

performance rates and state rate-based CO2 goals, in the final rule, the EPA allows for the 

adjustment of a CO2 emission rate based on avoided MWhs, not avoided CO2 emissions. It is, 

therefore, not necessary to convert energy efficiency impacts to carbon emission amounts, when 

demonstrating achievement of an emissions rate, using a tool like AVERT. For more information 

about specific methods to adjust the CO2 emission rate of an affected EGU to reflect RE and 

demand-side EE and how the methods ensures consistency with the goal setting calculations in 

the final rule, see section VIII.K.1 of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:
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Commenters asked whether energy efficiency measures could go in either the numerator or 

denominator, and whether states could choose one approach or the other. Commenters further 

asked if the AVERT tool would satisfy EPA requirements to convert energy efficiency impacts 

to carbon emission amounts.

Commenters supported calculating avoided emissions using EPA's Avoided Emissions and 

Generation Tool (AVERT) and standard technical resource manuals that project savings for 

energy efficiency technologies and programs. Commenters provided for example the Northeast 

Energy Efficiency Partnerships Mid-Atlantic Technical Reference Manual which offers guidance 

on standardized evaluation, measurement and verification methods and energy savings 

assumptions.

Comment 2: Comments suggesting the EPA and DOE tools to calculate energy, loads, 

emissions, and other critical components do not accurately treat the overall annual net energy 

reductions of GSHPs, waste energy, or hybrid GSHPs needed for emissions reductions 

quantifications.

Response 2: It is not necessary to quantify emissions reductions since, under the MWh 

accounting approach adopted in this final rule, the CO2 emission impacts of zero-emitting and 

low-emitting resources are reflected in the reported stack CO2 emissions of affected EGUs. For 

details regarding the general accounting approach for adjusting a CO2 emission rate, see section 

VIII.K.1 of the final rule preamble of the CPP.

To the extent RE and demand-side EE measures, including geothermal heat pumps, are tied to a 

state plan and meet the eligibility requirements for resources used to adjust a CO2 emission rate, 

described in section VIII.K.1.a.(2) of the final rule preamble, the eligibility requirements and 

provisions related to demand-side EE programs and projects and the requirements and criteria 

related to proper quantification and verification of MWhs from renewable electricity generation 

or demand-side EE savings are described in section VIII.K.3, the quantified and verified MWh 

impacts may be used to adjust a CO2 emission rate 

In the final rule, EPA does not require a projection of CO2 emission performance for all state 

plan approaches. For those that do require a projection, EPA does not prescribe specific EPA or 

DOE tools that states must use but gives states flexibility to choose appropriate tools provided 

they use technically sound methods that are reliable and replicable. EPA addresses what types of 

state plan approaches require a projection and requirements related to methods and tools in 

section VIII.D.2.a.(3) of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters noted that EPA and DOE tools to calculate energy, loads, emissions, and other 

critical components (including AVERT) do not accurately treat the overall annual net energy 

reductions of GSHPs, waste energy, or hybrid GSHPs needed for emissions reductions 

quantifications. Commenters also noted that there is no standard for establishing a baseline 
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system for comparing with GSHP systems to determine the energy savings and other benefits 

achieved by these systems.

5.2.3d Electricity sector modeling method

This section discusses the EPA’s alternative methodology accounting for specific fossil fuel 

emissions and proposed forecasting models.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments regarding issues with the EPA's alternative methodology accounting for 

the specific fossil fuel emissions displaced by RE and EE.

Response 1: In the final rule, the EPA changed the methodology used to establish the best 

system of emission reduction. In order to ensure consistency with the calculation of CO2

performance rates and state rate-based CO2 goals in the final emission guidelines, and to avoid 

double-counting or inconsistent adjustment approaches across states, the final rule prescribes a 

general accounting approach for adjusting the CO2 emission rate of an affected source to reflect 

the MWh impacts of zero-emitting and low-emitting resource. Quantified and verified MWh 

impacts of qualifying zero-emitting and low-emitting resources tied to a state plan may be used 

by an affected EGU or state to adjust a CO2 emission rate, regardless of whether the renewable 

generation or demand-side EE savings occur inside or outside the state or territory. Consistent 

with the EPA’s calculation of the CO2 emission performance rates and state rate-based CO2

goals in the final emission guidelines, the MWhs impacts are added to the denominator of an 

affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted CO2 emission rate.

The reported CO2 emissions reflect the actual emission reductions from the deployment of 

qualifying non-emitting and low-emitting resources across the regional grid. Further adjustment 

of CO2 emissions, such as through the subtraction of emissions estimated by applying an 

emissions factor to the MWhs, would double count CO2 emissions impacts across the grid. For 

more information about specific methods to adjust the CO2 emission rate of an affected EGU to 

reflect demand-side EE and eligibility requirements for resources that can be used to adjust a 

CO2 emission rate, see section VIII.K.1 of the final rule preamble of the CPP. The rule describes 

the requirements and criteria related to proper quantification and verification of MWhs from 

renewable electricity generation or demand-side EE savings in section VIII.K.3 of the final rule 

preamble.

The following are summaries of the specific public comments under this comment:

Commenters noted that EPA's goal calculation equation incorporates the impact of RE and EE 

by adding RE generation and EE savings to the denominator. Commenters stated for projecting 

or demonstrating compliance, a state might take an alternative approach that accounts for the 
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specific fossil fuel emissions displaced by RE and EE and this approach will generally yield a 

lower rate than EPA's goal setting methodology. Commenters employed this alternative 

calculation methodology and found that the use of the alternative methodology was helpful in 

allowing preservation of additional coal generation while still achieving the final goal, however 

makes it more difficult to achieve the interim goal without overshooting the final goal. 

Commenters noted that the alternative does not resolve the inconsistency between the BB2 

implementation date and the rule's intended flexibility.

Comment 2: Comments regarding concerns on the EPA's proposed forecasting models.

Response 2: The final rule does not require a projection for states choosing an emissions 

standard approach, unless a state chooses to apply rate-based emissions performance standards to 

individual affected EGUs or to subcategories of affected EGUs at a rate different from the CO2

emission performance rates or the state’s rate-based goal. The final rule does require that states 

demonstrate in a state measures plan that the emission standards and/or measures contained in a 

plan are projected to achieve the state CO2 emission goal. The final rule is not requiring a 

specific type of emission quantification approach or model. However, it requires the states to 

choose technically sound methods that establish a clear relationship between electricity grid 

interactions of the state enforceable measures, affected EGU dispatch, generation cost and 

operations within the time frame outlined in the final guidelines and to documents specific 

assumptions as described in section VIII.D.2.a.(3) of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters noted concerns with EPA's proposed forecasting models (e.g., IPM), including 1) 

while Method C, IPM, or other electricity forecasting models provide a robust approach for 

examining changes to dispatching, they require a significant investment of state resources due to 

the model complexities, time to coordinate and QA the data collection for annual planning and 

reporting, and coordination and execution of the modeling for the entire US; 2) states do not 

have the tools to accurately characterize state-level and regional electricity dispatching 

characteristics; 3) states do not have the methods, resources, and expertise to engage in energy 

modeling; 4) EPA's approach requires a non-proprietary and accurate model that is available for 

states to use; 5) EPA is not equipped to provide the necessary assistance to states and 6) 

commenters found assumptions for future activities in the 2018 IPM results regarding their 

EGUs that are inconsistent or inaccurate with actual plans.

5.2.3e Considerations associated with use of an avoided emissions rate

This section discusses the value and basis of avoided emissions, criteria for RE generation that 

must be met from affected EGUs using RE, parameters used for demonstrating emissions 

performance and projections, and additional consideration for energy efficiency credit.
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Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments concerning the general discussion to affirm the value of avoided 

emissions, and increased generating capacity under an emission cap program with examples of 

similar system under Section 1605(b) of the 1992 Energy Policy Act.

Response 1: In the final rule, the EPA allows for the adjustment of a CO2 emission rate based 

on avoided MWhs, not avoided CO2. EPA revised the methodology used to calculate CO2

emission performance rates and state rate-based CO2 goals from the one used in the proposal. 

Consistent with EPA’s calculation approach in the final emission guidelines, quantified and 

verified MWh impacts of qualifying zero-emitting and low-emitting resources can be added to 

the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted 

CO2 emission rate. The reported CO2 emissions already reflect the actual emission reductions 

from the deployment of qualifying non-emitting and low-emitting resources across the regional 

grid. An adjustment of CO2 emissions, such as through the subtraction of emissions estimated by 

applying an emissions factor to the MWhs, would double count CO2 emissions impacts across 

the grid. For more information about specific methods to adjust the CO2 emission rate of an 

affected EGU to reflect RE and demand-side EE and how it ensures consistency with goalsetting calculations, see section VIII.K.1 of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters presented discussion and examples to affirm the value of avoided emissions. To 

begin with, commenters stated that every megawatt-hour of electricity produced by an emissionfree generating unit, such as a nuclear plant, a hydroelectric facility or a wind farm, is a 

megawatt-hour that a fossil-fueled plant, which produces various emissions, does not produce. 

Regarding increased generating capacity under an emission cap program, commenters added that 

increases in emission-free generating capacity thus have a measurable clean air compliance 

value, and reduce the cost of compliance that would otherwise be imposed on the emitting 

generating capacity. Commenters noted that the Department of Energy operated a voluntary 

program, mandated by Section 1605(b) of the 1992 Energy Policy Act, under which companies 

could report reductions in greenhouse gas emissions. Commenters stated that the 1605(b) 

program accorded the same value to avoided emissions as to emission reductions. Furthermore, 

commenters added, the 1605(b) program defined avoided emissions and established the 

methodology for calculating them. Commenters stated these 1605(b) voluntary guidelines 

determined that the "avoided emission benchmark for electricity generation will be an 

approximation of the average emissions intensity of fossil-fired electric power generation for 

state-based regions in a recent year."
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Comment 2: Comments on how EE achievement and measurement in the Pacific Northwest is 

unique and the avoided emissions rate should be based on the generating resource displaced by 

EE and not the existing resource mix (which is predominately hydropower).

Response 2: In the final rule, the EPA allows for the adjustment of a CO2 emission rate based 

on avoided MWhs, not avoided CO2. EPA revised the methodology used to calculate CO2

emission performance rates and state rate-based CO2 goals from the one used in the proposal. 

Consistent with EPA’s calculation approach in the final emission guidelines, quantified and 

verified MWh impacts of qualifying zero-emitting and low-emitting resources can be added to 

the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted 

CO2 emission rate. The reported CO2 emissions already reflect the actual emission reductions 

from the deployment of qualifying non-emitting and low-emitting resources across the regional 

grid. An adjustment of CO2 emissions, such as through the subtraction of emissions estimated by 

applying an emissions factor to the MWhs, would double count CO2 emissions impacts across 

the grid. For more information about specific methods to adjust the CO2 emission rate of an 

affected EGU to reflect RE and demand-side EE and how it ensures consistency with goalsetting calculations, see section VIII.K.1 of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters noted that there are unique issues with the Pacific Northwest and that their avoided 

carbon emissions rate is based on the generating resource displaced by EE and not the existing 

resource mix (which is predominately hydropower). Commenters and their customers invest in 

EE because it reduces load growth, which reduces or eliminates the need to build and/or run a 

physical generating resource. Commenters stated that in the Pacific Northwest region, the 

marginal generating resources is typically a natural gas- or coal-fired power plant that is operated 

to meet load and is seldom hydropower. Commenters stated the carbon reduction value of energy 

efficiency exists in avoiding emissions associated with the marginal resource mix and not the 

reduction of emissions from the existing resource mix.

Comment 3: Comments suggesting to achieve emission reductions from affected EGUs by 

meeting RE certain criteria.

Response 3: In the final rule, the EPA allows for the adjustment of a CO2 emission rate based 

on avoided MWhs, not avoided CO2. This MWh accounting approach is indifferent to avoided 

CO2 emission rates and creates the same number of zero-emitting credits or adjustments for each 

MWh of energy generation or savings from eligible measures, wherever they occur. For more 

information on adjustments to CO2 emission rates in rate-based state plans, including the 

approach and eligible measures, see section VIII.K.1 of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters argued that the following criteria must be met in the RE generation used for 111(d) 

compliance for the CPP to achieve emission reductions from affected EGUs using RE:
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• For states using a rate-based approach, EPA must require that 

adjustments for RE may only be made for RE generation that has 

avoided emissions at affected EGUs. This will effectively limit the 

eligibility of RE and RECs under 111(d) to only those that have reduced 

emissions at affected EGUs;

• For states using a rate-based approach, EPA must require that no 

adjustments be made to an emissions rate for RE that is not identified 

and included in the state plan. This produces an incentive for states to 

implement RE policies and prevents states from claiming reductions 

from RE that was caused and claimed by another state;

• For states using a mass-based approach, EPA must require similar 

adjustments to reported masses. Since mass-based reporting will 

automatically only reflect reductions from RE that occur at affected 

EGUs, EPA need only require adjustments to masses to avoid double 

counting and to reflect the mass CO2 emissions achieved by the state 

plan;

• Because the mass-based approach will automatically reflect reductions 

from RE, EPA must require upward adjustments to masses for avoided 

emissions from RE without RECs (both power that is imported without 

the RECs and in-state RE generation where RECs are sold out of state);

• EPA must not allow states to make an adjustment to lower masses for 

RE and EE since avoided CO2 mass emissions from RE and EE are 

automatically reflected in the mass and this would result in double 

counting;

• EPA must require upward adjustments to masses for avoided emissions 

from RE that was not included in the state plan. Unless RE is included in 

a measure in its plan and the RECs for that generation have been retired 

in state, a mass-based state must demonstrate to EPA that RE is not 

affecting it mass to avoid an upward adjustment;

• Tracking RE and the avoided emissions from RE using a nationally 

uniform instrument, preferably RECs, is necessary regardless of the 

accuracy with which avoided emissions can be quantified. Challenges 

with the calculation of avoided emissions from RE are associated with 

the use of RE for 111(d) and not with the use of RECs in particular as 

the tracking mechanism; and

• EPA must require that emissions reductions from voluntary renewable 

energy (VRE) are not counted as part of other state policies included in 

111(d) plans.
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Comment 4: Comments suggesting EPA require the same parameters used in demonstrating 

emissions performance for compliance should be enforced for projections.

Response 4: When demonstrating emissions performance for compliance, states and affected 

EGUs can use quantified and verified MWh impacts to adjust a CO2 emission rate, provided that 

RE and demand-side EE measures are tied to a state plan, meet the eligibility requirements for 

resources used to adjust a CO2 emission rate, described in section VIII.K.1 of the final rule 

preamble of the CPP, the eligibility requirements and provisions related to demand-side EE 

programs and projects and the requirements and criteria related to proper quantification and 

verification of MWhs from renewable electricity generation or demand-side EE savings are 

described in section VIII.K.3. This clarification of the accounting approach creates consistency 

and minimizes opportunities for gaming. The final rule requires a projection only for states 

choosing an emissions standard approach where they apply rate-based emissions performance 

standards to individual affected EGUs or to subcategories of affected EGUs at a rate different 

from the CO2 emission performance rates or the state’s rate-based goal or for states choosing a 

state measures approach. The final rule is not requiring a specific type of emission quantification 

approach or model. However, it requires the states to choose technically sound methods that 

establish a clear relationship between electricity grid interactions of the state enforceable 

measures, affected EGU dispatch, generation cost and operations within the time frame outlined 

in the final guidelines and requires the documentation of key assumptions and parameters. 

Requirements related to projections to demonstrate emission performance are described in 

section VIII.D.2.a.(3) of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters argued that EPA should require that the same parameters used in demonstrating 

emissions performance for compliance should be enforced for projections and vice versa. This 

will provide consistency and prevent gaming.

Comment 5: Comments suggesting credit for energy efficiency to be calculated based on the 

avoided emission rate for the measure and load zone in which it is implemented.

Response 5: In the final rule, the EPA allows for the adjustment of a CO2 emission rate based 

on avoided MWhs, not avoided CO2. EPA revised the methodology used to calculate CO2

emission performance rates and state rate-based CO2 goals from the one used in the proposal. 

Consistent with EPA’s calculation approach in the final emission guidelines, quantified and 

verified MWh impacts of qualifying zero-emitting and low-emitting resources can be added to 

the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted 

CO2 emission rate. The reported CO2 emissions already reflect the actual emission reductions 

from the deployment of qualifying non-emitting and low-emitting resources across the regional 

grid. An adjustment of CO2 emissions, such as through the subtraction of emissions estimated by 

applying an emissions factor to the MWhs, would double count CO2 emissions impacts across 

the grid. For more information about specific methods to adjust the CO2 emission rate of an 
206

affected EGU to reflect RE and demand-side EE and how it ensures consistency with goalsetting calculations, see Section VIII.K.1.

The following are summaries of the specific public comments under this comment:

Commenters argued that credit for energy efficiency should be calculated based on the avoided 

emission rate for the measure and load zone in which it is implemented. Commenters stated EPA 

should ensure that credit for energy efficiency will approximate the actual carbon emissions that 

it displaces. While this is challenging, commenters believed that current EM&V protocols are 

advanced enough that EPA should be able to model the avoided emissions rates for EE measures 

in different regions with reasonable granularity. Commenters encouraged EPA to conduct or 

arrange for modeling each year to calculate a load reduction profile for all valid EE measures and 

avoided hourly emissions rates in each region.

5.2.4 EE and RE Measures that can be incorporated

This section discusses comments on the EE and RE measures that can be incorporated into state 

plans and used for compliance demonstrations.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments on the overall benefits of transmission and distribution improvements; 

comments supporting credits for T&D efficiency improvements.

Response 1: In the final rule, the EPA acknowledges the value of measures that increase 

transmission and distribution (T&D) efficiency or reduce electricity use, strengthening the 

transmission system and facilitating the transition to a new resource mix that includes more low 

and zero-emission resources. The final rule allows that the verified and quantified MWhs of 

avoided losses or reduction in end use electricity that result from T&D measures installed after 

2012 to be used to adjust a CO2 emission rate. For more information on the accounting approach 

for adjusting a CO2 emission rate and specifics on eligible transmission and distribution 

measures, see section VIII.K.1 of the final rule preamble of the CPP. For more detail on the 

requirements and criteria for proper quantification and verification of MWhs, see section 

VIII.K.3 of the final rule preamble.

In the final rule, to the extent RE generation, including solar energy, and demand-side EE 

measures are tied to a state plan, the quantified and verified MWh impacts of the measures may 

be used by an affected EGU or state to adjust a CO2 emission rate, regardless of whether the RE 

generation or demand-side EE savings occur inside or outside the state or territory. The MWh 

accounting method addresses interstate effects because it inherently accounts for how generation 

replacement and CO2 emission reduction impacts may cross state borders and is indifferent to 
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avoided CO2 emission rates, creating the same number of non-emitting credits or adjustments for 

each MWh of energy generation or savings. For more information about specific methods to 

adjust the CO2 emission rate of an affected EGU to reflect RE and demand-side EE, including 

specific geographic eligibility requirements and limitations, see section VIII.K.1 of the final rule 

preamble. For more information on the treatment of in-state and out-of-state renewable energy 

and energy efficiency impacts and interstate effects, see section VIII.L of the preamble to the 

final rule.

Regarding ensuring operational reliability, EPA officials worked closely with DOE and Federal 

Energy Regulatory Commission (FERC) officials to ensure, to the greatest extent possible, that 

actions taken by states and affected EGUs to comply with the final rule mitigate potential electric 

system reliability issues. Senior EPA officials met with each of the FERC Commissioners and 

EPA staff had frequent contact with FERC staff throughout the development the rule. FERC held 

four technical conferences to discuss implications of compliance approaches to the rule for 

electric reliability. EPA staff attended the four conferences and EPA leadership spoke at all of 

them. The EPA, DOE, and FERC will continue to work together to ensure electric grid reliability 

in the development and implementation of state plans. For more information about reliability 

considerations, see section II.D of the final rule preamble and for more detail about EPA 

consultations about reliability, see section II.K.

In response to comments received expressing concern regarding, among other things, reliability, 

feasibility, and cost related to meeting the guidelines, EPA made modifications to the timelines 

included in the proposal. The final guidelines establish three types of performance periods: 1) a 

final deadline by which and after which affected EGUs must be in compliance with the final 

reduction requirements, 2) an interim period, and, 3) within that interim period, three multi-year 

interim step periods. As discussed in sections VIII.B.1 and V of the final rule preamble, these 

performance periods are consistent with determination of the BSER and are also responsive to 

the key comments we received on this aspect of the state plans.

In the final rule energy storage is not directly recognized as an eligible measure that can be used 

to adjust a CO2 emission rate, because storage does not directly substitute for electric generation 

from the grid or avoid electricity use from the grid. However, the final rule acknowledges the 

value of energy storage as an enabling measure that facilitates greater use of RE. Additional 

information regarding energy storage is in section VIII.K.1.a.(5) of the final rule preamble.

Measures that reduce CO2 emissions outside the electric power sector, including emission 

reductions from reductions in vehicle fleet use, may not be counted toward meeting a CO2

emission performance level for affected EGUs or a state CO2 goal, under either a rate-based or 

mass-based approach, because all of the emission reduction measures included in the EPA’s 

determination of the BSER reduce CO2 emissions from affected EGUs. For more information, 

see section VIII.K.1.c of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Some commenters described how T&D improvements reduce EGU emissions "at the source" 

and others emphasized that the benefits extend to other changes contemplated in the CCP 

including renewables.
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Commenters stated that the final guidelines should affirm that states can include transmission 

and distribution efficiency improvements in compliance plans because these types of projects can 

reduce line losses and thus reduce the need for additional CO2-emitting generation from existing 

EGUs. Commenters stated that the final guidelines should help to incentivize the deployment of 

the innovative technologies to both reduce CO2 emissions and achieve the increased utilization 

of renewable generating resources, two of the objectives of the proposed guideline, by allowing 

states to include them in their compliance plans. 

Commenters described the potential environmental benefits of T&D line loss reduction practices 

and strategies to optimize power quality, which means they have to generate less power to satisfy 

demand. Commenters stated that T&D of electricity accounted, in 2005, for approximately 6% of 

net electricity loses. Commenters added that reduced demand translates into a reduction in the 

amount of coal or natural gas burned and CO2 emissions. To the extent these strategies can be 

implemented to defer investment in new generation capacity or to address reduced capacity due 

to old generating assets being taken offline, commenters added that the benefits can be enormous 

especially when load growth is small.

Commenters stated the current proposed guidelines focus solely at two portions of the electric 

supply chain; generation and consumption. Commenters said EPA ignored "outside the

fenceline" improvements that have nothing to do with neither heat rates, nor EE. Commenters 

said transmission and distribution line improvements, which are ignored in the guidelines, can 

result in as much as a 3-4% reduction in emissions by lowering need for electricity. Commenters 

suggested that EPA include within the proposed fifth building block, comments supportive of 

allowing improvements in line-loss levels at both the transmission and distribution levels.

Commenters stated the current proposed guidelines focus solely at two portions of the electric 

supply chain; generation and consumption. Commenters said EPA ignored "outside the 

fenceline" improvements that have nothing to do with neither heat rates, nor EE. Commenters 

said transmission and distribution line improvements, which are ignored in the guidelines, can 

result in as much as a 3-4% reduction in emissions by lowering need for electricity. Commenters 

suggested that EPA include within the proposed fifth building block, comments supportive of 

allowing improvements in line-loss levels at both the transmission and distribution 

levels.Commenters said that states and regional transmission organizations (RTOs) and other 

regional entities charged with regional transmission planning and coordination across multiutility markets or across multiple states can also attain the CPP's targeted reductions through 

activities beyond the Building Blocks. Commenters explained that transmission provides a range 

of benefits that is capable of contributing to the success of the CPP and reduces the chance that 

delay or insufficiency of new transmission capacity will diminish the possibility of achieving the 

CPP's goals. Commenters said that while the focal point of the CPP is understandably on shifts in 

generation resources that are central to a program of emissions reduction as well as on 

technologies that enhance the efficiency, reliability, and power transfer capabilities of high 

voltage transmission, the need for additional conventional transmission resources should also be 

considered in setting the parameters of state implementation of the CPP's Building Blocks. 

Commenters added that the adequacy and ubiquity of transmission cannot be assumed or that the 

major changes to, or utilization of, the generation fleet that the EPA' proposals envision will 

occur without also making substantial changes and investments in the high-voltage transmission 
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grid. Far from simply connecting Point A to Point B, commenters said that the transmission 

network provides an extensive portfolio of benefits, including the ability to leverage and 

aggregate new investments in advanced technologies distributed generation, storage, micro-grids, 

energy efficiency and more for the benefit of broader evolving markets. Citing an important 

study on the benefits of new transmission capacity, commenters argued that, not only will a 

robust grid deliver the low- or zero-carbon resources upon which one of the CPP's building 

blocks depend, transmission investment adds a flexibility and adaptability to the entire bulk 

power system that will smooth the transition to the new resource mix that the CPP promotes. 

Commenters noted that the EPA identifies transmission "efficiency improvements" as a measure 

that could be used to reduce CO2 emissions that was not specifically included in one of the 

Building Blocks, but commenters said that transmission delivers efficiency at a different level 

than that which the EPA contemplate. Commenters pointed to the discussion of Building Block 

4, where the EPA states: "Another way to reduce the utilization of, and CO2 emissions from, 

affected EGUs is through electricity transmission and distribution upgrades that reduce 

electricity losses during the delivery of electricity to end users. Just as end-use energy efficiency 

can reduce mass emissions from affected EGUs, so can transmission upgrades." Commenters

said that this does not entirely capture the macro-efficiencies that transmission can bring to 

regional markets in terms of cleaner generation or the option not to build generation at all. 

Commenters asked the EPA to more fully examine the efficiency potential of a strengthened 

transmission system. 

Commenters added that transmission can help ensure reliability and the efficient use of resources 

as reserve margins shrink. In developing the Rule, commenters said that the EPA assumed that 

because most regions have capacity above their target margins, most Coal Generation 

retirements will be "absorbed by a reduction in excess reserves over time." However, 

commenters noted, there are additional EPA regulations, such as Mercury and Air Toxics 

Standards, which will further reduce reserve margin, and the cumulative effects of these 

regulatory requirements have the potential to create significant reliability challenges as the states 

move to implement their plans. 

Commenters noted that high-voltage transmission is the perfect example of why the EPA must 

be permitted to look "outside the fence" in pursuing the necessary objectives of this rule: the 

transmission wires that deliver power to markets are by definition "outside the fence" of the 

power plants, but without them the power plants are useless. Commenters said that they are 

critical facilities for delivery of electricity whether it is generated with or without carbon 

emissions, and they cannot and should not be ignored in any policy that would attempt to 

facilitate a transition from carbon-emitting generation to clean energy. Commenters added that 

this obvious reality is the driving motive of Americans for a Clean Energy Grid; it should 

likewise be recognized and acted on throughout this proposed rule. Commenters described the 

benefits of transmission improvements, steps already being taken in states and regions and 

barriers to implementation (design, permitting and construction timelines). Commenters added 

that the experiences of regulators, transmission planners, and transmission owners in Texas, 

California, the Mid-Continent Independent System Operator (MISO), and the Southwest Power 

Pool (SPP) all provide powerful evidence that expanding and modernizing high-voltage 

transmission networks is a highly cost effective approach to reducing carbon emissions from the 

electricity sector and provided extensive examples of their projects. 
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Commenters explained that power system reliability encompasses both adequacy of supply to 

meet demand and operational reliability of the transmission system. Commenters added that 

power systems must be operated to ensure that supply and demand are balanced and that this 

balance is maintained respecting thermal, voltage, and frequency criteria for not only the present 

operating state but also for any single contingency and other credible contingencies beyond a 

single contingency. Commenters stated that the proposed rule considers only the adequacy 

perspective of the reliability impact of the rule but does not address the potential thermal, 

voltage, or frequency impacts, nor does the rule consider the associated potential transmission 

economic implications of additional facilities required to ensure operational reliability or 

financial implications of stranded transmission investments that become underutilized as a result 

of the change in system power flows. 

Commenters described the role that detailed reliability studies play in coordinating the 

construction of new facilities and retiring old ones. Commenters added that coordinating outages 

across many systems that are attempting to simultaneously develop new transmission facilities to 

accommodate mandated generation changes will be challenging at best and likely result in 

increased congestion costs and longer lead times to commission the new facilities as sequencing 

of outages will be required. Commenters added that it is unlikely that sufficient lead times exist 

for actually building new transmission facilities that might be required to support the change in 

generation mix to meet the rules interim goals in 2020, especially considering the challenges 

scheduling outages of existing facilities noted above. In addition to economic impacts associated 

with relieving congestion resulting from new generation, commenters noted that the retirement 

of a large number of conventional thermal generation plants may also impact transmission 

system voltage and frequency stability. Commenters described several scenarios illustrating this 

concern and concluded that most of the transmission reliability considerations noted can be 

mitigated with additional investments in transmission infrastructure, but the impact of these costs 

and timing of these facility upgrades on reliability during transitional periods should be 

considered as part of the proposed rule. 

Commenters affirmed that increased development of renewable and other electric generation will 

require adequate electrical transmission and distribution systems, e.g., expanded use of natural 

gas requires infrastructure to support the transport and supply of natural gas to new natural gas 

plants or to increase supply to existing plants. Commenters said that without adequate 

transmission and distribution systems, electric reliability is compromised. Commenters added 

that this will require significant new investment in transmission and distribution infrastructure, 

which affects not just the cost of energy but also has significant implications for how quickly the 

state could comply. Commenters stated that the EPA should clarify that any transmission 

upgrade after 2012 would be eligible to be included as a measure to meet the interim and final 

goals. 

Commenters also said that the rule should make provisions for utilities to receive credit for

improvements to distribution or transmission grids that effectively reduce CO2 emissions as well 

as customer owned generation and transmission. Commenters added that acceptable measures 

should include electrification projects, transmission projects that reduce line losses or otherwise 

specifically increase the efficiency of non-generating portions of the electric system and nuclear 

generation. 
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Commenters commented on electricity storage with respect to pumped storage. Commenters 

stated an unintended consequence of this proposed rule is penalizing using electricity storage as a 

dispatch planning and air quality mitigation strategy. Commenters stated one example of 

electricity storage is hydro-pumped storage, which is a way of storing electricity via pumping

water up during the night while electricity demand is relatively low and letting the water run 

down through the turbines during peak demand hours during the day. Commenters stated this can 

help reduce the need for peaking units to operate, which are usually among the dirtiest and least 

efficient units. Commenters stated it also helps reduce peak emissions from EGUs during the 

day, which can help control ambient concentrations of traditional pollutants, however, the use of 

pumped storage results in an efficiency loss since more electricity is required to pump the water 

up than is generated by letting the water run back down through the turbines. If the energy 

required to pump the water is generated with fossil fuels, Commenters stated this results in more 

CO2 emissions in aggregate. Commenters stated this could discourage the use of pumped 

storage, especially since the proposed rule does not allow generation from existing pumped 

storage facilities to be used for compliance purposes under a rate-based approach (because of the 

exclusion of existing hydropower). Commenters stated the Department suggests that EPA rectify 

this issue in the final rule. Commenters stated one potential remedy is to give generation credit to 

electricity storage facilities. Commenters stated the amount of generation credit for electricity 

storage facilities (such as pumped storage facilities) would be the difference between their 

consumed generation (i.e. to pump the water) and their created generation. 

Commenters supported the recommendation that efficiency improvements to utility transmission 

and distribution systems (e.g., conservation voltage reduction) starting in 2020 be eligible for the 

same energy savings credits as end-use energy efficiency measures. Commenters also 

recommended that such measures may be included in state compliance plans for incremental 

actions beyond those otherwise planned prior to development of the 111(d) compliance plan. 

Commenters said that the states' plans should account for the fact that new transmission facilities 

and upgrades to the transmission system create energy market efficiencies allowing dispatch of 

the most efficient resources available within the RTO footprint. 

Although not expressly included in the Rule's building blocks, commenters stated that 

transmission efficiency improvements can help the states meet their goals. In addition, 

commenters noted that transmission can assist in the implementation of regional compliance 

approaches, which may allow for more cost-effective solutions and address certain reliability 

concerns. To support the regional implementation of the Rule, commenters said that the EPA 

should clarify that emissions will be linked to the location of consumption. Commenters

explained that the variations in natural resources and infrastructure capabilities between states 

demand needed flexibility to allow lower-emitting generation to be transmitted to energy users, 

which would be hampered if emissions are linked to the source rather than the energy user. 

Commenters recommended that the EPA clarify, with respect to its proposed interstate 

accounting methods, the interstate effects of emission reductions. Commenters noted that the 

TSD appears to adopt an asymmetrical approach to interstate accounting for renewable energy 

versus energy efficiency measures (TSD, page 88). While different stakeholders appear to have 

differing perspectives on this issue and/or perspectives that differ from EPA's Proposed Rule, 

commenters stated that accounting for interstate and multi-state clean energy deployment and 
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energy efficiency savings, and avoiding double counting of such measures, and the related 

crediting of emission reductions is critical.

Based on experience with state policies in Arizona, New York and California, commenters said 

that energy storage should be an intrinsic part of the energy mix and SIPs. Commenters

described potential partnerships and studies to bolster the development of this technology. 

Commenters added that accounting for development and deployment of storage will serve to 

strengthen the methodology EPA chooses that in turn affirms the ability for energy storage to 

impact all four building blocks set forth in the rule. Commenters supported allowing states to 

include T&D loss factors. Commenters stated that since emissions reductions are measured from 

the location of electric generating plants, energy savings from EE should not only include enduse savings but also avoided T&D losses. Commenters said that states should be allowed to use 

their own T&D loss factors where state-specific data are available, but where state-specific data 

are not available, states should use a regional T&D loss factor such as RTO data, or EIA data. 

Commenters supported energy storage and cited Ontario as an example of an energy storage 

project that is possible to implement in the U.S.

Commenters noted that the issue of crediting for interstate transmission upgrades could be 

another fertile area for modular multi-state agreements and that the EPA should defer to such 

agreements as long as their terms appear reasonable and avoid double-counting emission 

reductions. 

Commenters described FERC rules and policies that now require transmission planners and 

owners to play an unprecedented role in developing a less carbon-intensive electricity system, 

and the decisions they make will directly impact the cost and efficacy of state implementation 

plans to comply with the proposed rule. Commenters stated that in upholding FERC's Order 

1000's requirement that transmission planners consider relevant public policies, the U.S. Circuit 

Court of Appeals for the District of Columbia found "all of the challenges to the public policy 

mandate to be without merit." Commenters stated that the EPA should follow FERC and federal 

courts by recognizing the critical interdependencies between transmission infrastructure and 

efforts to reduce carbon emissions in the power sector, requiring state compliance plans to reflect 

and incorporate relevant transmission planning analyses, and crediting low and zero carbon 

energy enabling transmission investments appropriately. 

Commenters also asked whether the EPA will allow states to count avoided T&D losses when 

accounting for EE savings, and if so, should EPA use a standard accounting of T&D losses.

Some commenters described technological improvements that will facilitate the integration of 

renewable energy (wind and solar generation), reduce transmission line losses 30-50 percent 

compared to traditional AC systems, provide increased grid flexibility and reliability and 

reinforce and debottleneck the existing AC network. Commenters pointed to the use of new 

HVDC transmission that can link several renewable energy projects together. Commenters stated 

that by connecting individual projects, HVDC transmission increases resource diversity, 

smoothing out the generation curve over the electric system and reducing the impact of shortterm fluctuations in output at any one wind farm or solar array. Commenters added that the most 

notable advantage of HVDC transmission lines is their ability to transfer power underground and 
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undersea over long distances, which could facilitate the growth of wind and solar energy by 

allowing solar energy from the Southwest or wind power from the Midwest to be transmitted to 

other parts of the country. Commenters also noted that use of higher voltage, HVDC or improved 

efficiency for distribution transformers would reduce emissions and added that the EPA should 

be discussing this option for reducing emissions with the appropriate federal agencies. 

Commenters agreed that electric utilities can improve the efficiency of their distribution systems 

by replacing distribution transformers with higher-efficiency models. For example, commenters 

stated, utilities can upgrade to transformers with amorphous metal cores, which experience noload losses that are 60-70 percent lower than those of transformers with conventional highefficiency silicon steel cores. Commenters stated that according to GE modeling of an electric 

utility that serves 500,000 customers and replaces 4,000 distribution transformers per year, the 

selection of amorphous core over conventional transformers can save 190 million kWh per year 

through reduced losses and avoid average annual CO2 emissions of 110,000 metric tons. 

Commenters said that to absorb more solar energy into the electric grid, there are certain ways 

that the electric grid can be adapted. Commenters added that as part of a balanced energy 

portfolio, solar can improve grid reliability and provide benefits to the existing energy 

infrastructure, including reducing transmission losses and relieving congestion on the grid. 

Commenters provided an extensive discussion on the benefits of integrating these technologies, 

ways to implement them, costs and benefits of integrating solar and examples of real world 

projects. 

Commenters provided an extensive discussion of the factors leading to America's inadequate 

high-voltage transmission network that limits renewable energy growth, drives developers to 

lower quality and higher cost resources, and reduces the efficiency and availability of installed 

renewable generation. Commenters explained that high-voltage transmission is essential to 

developing remote renewable resources at scales consistent with meeting long-term carbon 

emissions targets. Commenters provided examples of grid operators that are reliably and 

efficiently managing high levels of variable renewable energy thanks to transmission 

investments, improved forecasting, and other advances. 

Commenters noted that "smart" technologies will allow engineers to operate the grid even more 

efficiently. For example, commenters explained, synchrophasors monitor electrical conditions 

hundreds of times faster than current technologies and time-stamp every measurement to 

synchronize data across large regions. Commenters stated grid operators can use this information 

to detect disturbances that would have been impossible to see in the past, allowing them to 

address the disturbances before they lead to serious and costly problems like severe congestion, 

voltage reductions, or widespread losses of power (e.g. the Northeast Blackout of 2003.) 

Commenters said that synchrophasors installed on the U.S. high-voltage network increased 

nearly tenfold from just 200 in 2009 to more than 1,700 today thanks to DOE's Smart Grid 

Investment Grants (funded by the American Recovery and Reinvestment Act of 2009). 

Commenters stated that grid operators are still developing procedures to use this powerful new 

data resource, but it is certain that the information will make the grid more efficient, reliable, and 

capable of managing high levels of variable renewable generation. Commenters added that there 

are a number of other technologies, such as dynamic line ratings, synchrophasors, gridscale 

energy storage and smart solar inverters, that can help increase reliability, resiliency, and 
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efficiency, all of which ultimately contribute to reducing CO2 emissions. Commenters described 

the benefits of "smart grids" and their role in end-use efficiency, one of the Clean Power Plan's 

compliance building blocks, as well as aid the smooth integration of intermittent renewable 

energy sources and distributed energy power from rooftop solar or small-scale wind. 

Commenters described the benefits of energy storage, when paired with grid modernization, and 

said that it should be included in a new grid modernization block. Commenters said that storage 

supports renewable energy generation as a generation asset, but also enables grid 

owners/operators to deploy storage as a grid asset at the transmission and distribution levels 

(across the grid): it can help support the integration of variable resources (e.g., wind, solar), as 

well as levelize/smooth loads, increase the efficiency of baseload generation, and reduce power 

outages. Commenters stated that storage also can reduce system peak demands and the impact 

that has on peaking generation needs. Commenters added that storage also provides the 

capability for transmission and distribution system operators to optimize grid performance, 

thereby enhancing consumer reliability. 

Commenters stated EPA should explicitly state in the final rule that energy storage technologies 

can be granted credits for avoided emissions that they create. Commenters stated EPA should 

credit energy storage technologies for the emissions reductions benefits generated both directly 

by increasing the efficiency of certain coal-fired units by reducing ramping and allowing the 

units to run at their most-efficient capacities, but also indirectly through improving system 

efficiencies, such as through reducing the need for spinning reserves. 

Commenters offered specific recommendations for the agency's consideration, including the 

following:

• Support the development of state plans that anticipate a role for energy 

storage.

• Develop evaluation criteria that help states demonstrate the role that 

storage will play in the accelerated introduction of non-emitting 

technologies.

• Require states to conduct ongoing monitoring and evaluation of the role 

of energy storage in their electricity systems and introduce corrective 

measures where possible.

• Consider how emissions reductions in other sectors (such as 

transportation) might be facilitated by the introduction of technologies, 

such as electric vehicles.

• Consider the calculation of net emissions changes, including changes in 

other sectors, in state plans. 

• Assist states in accounting for the potential role of electric vehicles in 

the determination of activity levels that are used in the transition from 

rate- to mass-based standards. 
215

Commenters added that electric vehicles and electric vehicle fleets should be considered as 

"smart grid" or, grid modernization, technologies/"smart" loads that can help optimize and/or 

levelize loads in a manner that optimizes the use of low- or zero-carbon emitting generation. As 

an example, with "smart grid" technologies, commenters said that utilities can charge EVs when 

low- or zero-carbon emitting generation is available (e.g., sunny afternoons and the middle of the 

night). Moreover, commenters added that EVs and electric utility fleet trucks can be used to 

export power back to the grid (as is currently being pilot tested by some utilities in this manner) 

to help reduce and/or avoid power outages. 

In the same vein, commenters believed that consideration also should be given to utilities that 

can demonstrate emissions reductions from their vehicle fleets as a result of automating the 

control of their various grid systems. Commenters said that an example is the use of Advanced 

Metering Infrastructure (AMI) to perform remote services orders, such as "connects" and 

"disconnects." Commenters said that grid technologies that enable outage situations that are on 

the customer side of the meter versus the utility side of the meter to be diagnosed remotely can 

greatly reduce the "truck rolls" of a utility and, thereby, can dramatically reduce GHG emissions 

from these vehicles. For example, commenters said that during Superstorm Sandy, one utility 

alone reported such efforts saved more than 6,000 truck rolls. Commenters stated that the 

removal of such a substantial quantity of trucks from the road (i.e., this is just one utility during 

one extreme weather event) results in significant GHG emission reductions. Commenters added 

that new grid technologies, like smart grid sensors and distribution automation equipment, also 

can help reduce truck rolls and the number of miles utility crews must drive during power 

outages or to conduct grid maintenance, thereby, also translating to still further GHG emission 

reductions.

Commenters stated that Volt/VAR Optimization (VVO) technology can help reduce T&D line 

losses and is an important non-BSER compliance option. 

Commenters explained that VVO is a software-enabled application that allows an electric utility 

to dynamically manage and optimize voltage and reactive power levels across its distribution 

system. Commenters said that conservation voltage reduction (CVR), a specific application of 

VVO, involves the use of capacitors and localized controls to flatten and lower the voltage level 

along a distribution feeder. Commenters stated that CVR reduces end-use energy consumption 

with no noticeable impact to consumers. Commenters stated that according to GE modeling of an 

electric utility that serves 500,000 customers with 160 distribution substations, they noted that a 

two percent reduction in voltage during peak periods can result in a savings of 6 MWh per year 

per substation, which equates to an average emissions reduction of 200,000 tons of CO2 per year. 

Commenters added that allowing VVO systems to be included in compliance plans can help 

encourage wider deployment of this technology, with benefits that include improved power 

quality and reduced peak demand in addition to carbon mitigation. Commenters explained that 

the concept of Volt/VAR management or control is essential to electric utilities' ability to deliver 

power within appropriate voltage limits so that consumers' equipment operates properly, and to 

deliver power at an optimal power factor to minimize losses. Commenters added that feeder 

voltage regulation (Voltage) refers to the management of voltages on a feeder line with varying 

load conditions, and VAR refers to Volt-Ampere Reactive power, the reactive power nearly all 

power system loads require in combination with real power (Watts). Commenters stated that 
216

experience has shown that the overall costs and performance of operating a power system can be 

best managed if voltage control and reactive power control are well integrated. According to the 

commenters, the benefits of Volt/VAR management technologies are well-known, having been 

used by the power industry for over 30 years, and these technologies have advanced to include 

Volt/VAR Optimization (VVO) sensors, equipment and software. 

Commenters stated that through the use of these VVO systems, utilities can optimize voltage 

profiles and VAR flow to reduce overall distribution line losses by two to five percent through 

tight control of voltage and current fluctuations, and achieve a variety of other objectives, 

including: reducing peak demand, targeting power factor levels to minimize energy losses and 

implementing CVR. Commenters added that CVR-related strategies can lower overall system 

voltage and thereby reduce overall system demand by a factor of 0.7 to one percent for every one 

percent reduction in voltage. Commenters stated that VVO systems work in conjunction with a 

number of other technologies to optimize the electric system, including microprocessor-based 

controls and computing platforms, pervasive, high performance communications technologies, 

widely deployed sensor technology including AMI systems, and advanced software algorithms. 

See id. at 2. 

In addition to VVO systems, commenters stated there are a number of other technologies that can 

help reduce T&D losses, which in turn means utilities need to generate less power, leading to 

CO2 reduction benefits. Commenters noted that high-temperature low-sag conductors can 

increase the capacity of the transmission network by making lines more capable of carrying

higher volumes of power without overheating or sagging, which in turn can significantly reduce 

loss and increase the efficiency of the installed transmission infrastructure. Because they sag 

less, commenters said, electricity flowing through the conductor experiences less resistance, 

meaning that the conductors can also reduce transmission losses of power by 25 to 40 percent of 

what otherwise might be lost. Commenters stated if transmission losses are reduced, less 

electricity generation is required to meet the same amount of load, reducing emissions from 

generators.

Commenters stated that Building Block 4 must be finalized to ensure that system level electric 

distribution utility measures, such as lowering line losses and VOLT/VAR support at the 

distribution level, may be used as a compliance option.

Commenters stated savings from transmission and distribution system efficiency investments 

that reduce utility losses or reduce the energy used by appliances and devices by optimizing 

voltage can add an additional 0.2 percent per year. Commenters recommended savings from 

transmission and distribution efficiency improvements should be included in the BSER for Block 

4 and credited in state plans. Commenters indicated that 6.3 percent of electricity is used in 

T&D. Commenters cited an EPRI study that estimates the potential to reduce electricity use in 

this area is about 10 to 15 percent. Commenters noted that electricity losses in the distribution 

system can be reduced substantially through the use of efficient transformers, improved voltage 

control, phase balancing, and balancing of reactive power needs. In the transmission system, 

commenters noted opportunities include voltage overlays, voltage and line efficiency.

Commenters stated these measures can enhance not only the efficiency, but also the flexibility 

and reliability of the electric system, facilitating integration of renewables into the system. 

Commenters stated EPA excluded Volt VAR Optimization/Conservation Voltage Reduction, a 
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cost-effective option for states and utilities to save energy and reduce pollution. Commenters 

stated maintaining voltage in the lower half of the 114 to 126 volt range saves energy, because 

reducing voltage reduces the energy used by customer appliances and equipment. Commenters 

stated utilities often have set a strategy of "setting voltage high enough," however with recent 

advances in sensors, communication, and information processing and control techniques, utilities 

can use a process called "Volt Var Optimization," and these practices are termed "Conservation 

Voltage Reduction." Commenters stated 26 projects are funded by the Smart Grid Investment 

Grants through the ARRA implemented VVO or CVR ; AEP Ohio implemented VVO on 17 

circuits and yielded a 3 percent reduction in residential customer energy use during the test 

period (measured for those customers with AMI meters) ; and a large pilot in the Pacific 

Northwest, the Distribution Efficiency Initiative Project, tested CVR practices , and average 

energy savings using end-of-line voltage regulation was 2 and 3 percent, voltage regulation with 

minor system improvements saved 1 to 2 percent of energy use . Commenters stated the 

Regional Technical Forum of the Northwest Power & Conservation Council is developing a 

protocol for measuring the savings from Conservation Voltage Reduction. Commenters 

recommended EPA raise the best practices level of energy efficiency by 0.2 percent per year, to 

account for the savings from conservation voltage reduction and other transmission and 

distribution system investments. Commenters stated in developing EM&V Guidance, EPA's 

designated entity, should consider developing or validating a protocol for estimating savings 

from CRV and T&D system that reduce line losses.

 

Comment 2: Comments opposing requiring T&D improvements

Response 2: The final rule does not require transmission-related improvements but does 

recognize the value of measures that increase transmission and distribution (T&D) efficiency or 

reduce electricity use. It allows that the verified and quantified MWhs of avoided losses or 

reduction in end use electricity that result from T&D measures by interested states can be used to 

adjust a CO2 emission rate. For more information on the accounting approach for adjusting a 

CO2 emission rate and eligibility requirements across a range of resources that may be used to 

adjust a CO2 emission rate, see section VIII.K.1 of the final rule preamble of the CPP. 

The following are summaries of the specific public comments under this comment:

Commenters were concerned that the Rule will drive additional, costly transmission projects that 

have high ROI for transmission providers within the markets, driving up costs for consumers, 

with very little to no actual benefit. As a small municipal utility principally serving their 

community, commenters said that the transmission lines are very short distances, such that 

increasing efficiencies, even just another .09%, would be relatively impossible to achieve. 

Commenters stated the EPA's expected efficiency increase in transmission did not consider a 

small municipal utility with a small and networked transmission system in establishing the 

efficiency goal commenters concluded. 
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Comment 3: Comments on water sector efficiency programs.

Response 3: The EPA recognizes the value of energy efficiency as a low cost resource and gives 

states the flexibility to use zero-emitting resources, like energy efficiency, to achieve their CO2

emission performance rate. To the extent demand-side EE measures are tied to a state plan, the 

quantified and verified MWh impacts may be used to adjust a CO2 emission rate, provided they 

meet the general and specific eligibility requirements for resources used to adjust a CO2

emission rate. Water efficiency programs that improve EE at water and wastewater treatment 

facilities also provide demand-side EE savings opportunities that may be eligible for adjustments 

to CO2 emission rates at affected utilities. For more information about the general accounting 

approach for adjusting a CO2 emission rate and specific discussion of water system efficiency, 

see section VIII.K.1 of the final rule preamble of the CPP. The measures must also meet the 

eligibility requirements and provisions related to demand-side EE programs and projects, if 

applicable, and the requirements and criteria related to proper quantification and verification of 

MWhs from demand-side EE savings are described in section VIII.K.3 of the final rule 

preamble.

The following are summaries of the specific public comments under this comment:

Commenters said that the water sector has the potential to contribute significant carbon emission 

reductions and encouraged the EPA to clarify in the final rule that states will be allowed to 

account for measurable RE and demand-side EE measures taken by the water and wastewater 

industries (post-2012) in their CPP Section 111 (d) state plans. Commenters noted that the 

current discussions of demand side efficiency are vague and it is not currently clear if RE 

generation by any entity other than an electric utility would count at all. Without a clear signal if 

the projects will count, commenters said that it will be difficult for states and electric utilities to 

justify incentive programs and difficult for the water sector to pursue such projects. Commenters

explained that water sector renewable energy and demand-side measures may be under-utilized 

in reducing emissions due to lack of awareness of some of the efficiency opportunities among 

the sectors (for example, amongst demand side efficiency programs), competing high priority 

public health needs and necessary infrastructure upgrades, and lack of funding for the water 

sector to implement efficiency programs. If a flexible approach is adopted in the CPP, 

commenters said that EGUs, energy users and states could realize cost savings by providing 

incentives for the water sector to voluntarily increase efficiency and implement renewable 

energy generation. Commenters stated one large water company alone, serving customers in 

many states, has replaced or refurbished 140 water pumps over the last four years with more 

energy efficient pumps, saving 12 million kilowatt-hours per year, a reduction of approximately 

18 million pounds per year of carbon emissions. Also, commenters continued stating that a 

relatively modest-sized utility recently installed much more efficient blowers, mixers, and 

aeration equipment at its wastewater treatment plant, thereby reducing annual electricity use by 

about 30 percent, or about 3,000,000 kilowatt-hours a year. Commenters agreed that 

energy/water nexus provides an additional opportunity for CO2 emission reductions because 

about 2-4 percent of the total energy used in the United States is used by water and waste water 

systems, which equates to approximately 187 million MWh per year. Commenters described 

potential projects to replace or refurbish water pumps with more energy efficient pumps and the 

potential emission reductions. 
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Commenters described how Indiana has taken steps to reduce the amount of energy used by 

water and wastewater utilities. Commenters noted that energy consumption by public drinking 

water and wastewater utilities, which are primarily owned and operated by local governments, 

can represent 30-40% of a municipality's energy bill. At drinking water plants, commenters said 

that the largest energy use (about 80%) is to operate motors for pumping, while at wastewater 

treatment plants, aeration, pumping, and solids processing account for most of the electricity that 

is used. Commenters stated that the Indiana Finance Authority, in cooperation with IDEM, has 

promoted the use and installation of energy efficient pumps, pipes, treatment systems, and 

control processes as part of the state's Revolving Loan Program for financing water and 

wastewater infrastructure projects. Commenters also stated that a rule requiring water utilities to 

address unacceptable leakage from their drinking water infrastructure was promulgated to 

improve efficiency and save energy by reducing the amount of water pumped and treated. 

Commenters described new technologies to improve T&D that should be considered in the 

guidelines and suggested how to implement them in the proposed rule. 

Commenters described several emerging technologies and/or programs that will be beneficial in 

reducing emissions. 

Comment 4: Comments suggesting ways to incentive the construction of new transmission 

lines.

Response 4: This comment is outside the scope of this rulemaking. This final rule sets emission 

performance goals for states based on the BSER for existing sources under CAA section 111(d). 

In this rule, EPA is not designating which technologies or infrastructure priorities should be 

invested in. The final rule does support flexible measures to achieve CO2 emission reductions 

and the increased use of zero- and low- emitting generation. Transmission and distribution 

efficiency improvements are discussed in the preamble in section VIII.K.1.a of the final rule 

preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters described ways to incentivize the construction of new transmission lines.

Commenters noted that under typical cost-recovery rules, new generation projects must pay to 

construct their own interconnection (called a tie-line). For location-constrained renewable sites, 

commenters said that the cost of such lines can be very substantial which deters new investment. 

Commenters stated developers are reluctant to build projects with no guaranteed transmission, 

and transmission owners are reluctant to build new lines without assurance of demand from 

generators. Commenters described pioneering solutions to this problem such as California's 

Location Constrained Resource Interconnection Facility (LCRIF) program and Texas' 

Competitive Renewable Energy Zones (CREZ). Commenters said that these programs 

incentivize the construction of new transmission lines to designated resource-rich areas. By 

enabling development of projects that otherwise may be uneconomic, commenters said that these 
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programs offer a creative way to support development of renewable resources at the lowest cost. 

Commenters described key features of programs that other states might adopt to support 

interconnection of location-constrained renewable resources. 

--Create Competitive Renewable Energy Zones; a CREZ is generally a remote geographic area 

where renewable generation facilities will be constructed. In conjunction with setting up a 

CREZ, the required transmission upgrades to deliver the renewable energy generated to load 

areas are defined. Once the needed transmission upgrades are identified, the state public utility 

commission provides the necessary approvals for their construction. A bill creating a CREZ 

should grant a PUC specific authority to extend transmission construction to relieve congestion 

and transmit renewable energy to load centers and could allow utilities to include capital costs 

for transmission facilities not yet in service in their rates.

--Reduce the Time Needed for Planning, Building, and Siting Transmission; the average time it 

takes to build a new high voltage transmission line is in the range of a decade or longer for most 

planning regions. For lines crossing multiple planning regions, balancing areas, RTOS's markets 

or state boarders, the time to construction is expected to be much longer. A relatively painless 

first step for accelerating transmission siting would be to maximize the potential for joint use of 

existing rights-of-way for other transmission functions. The U.S. is crisscrossed by railroads and 

highways that already take up land. These existing rights-of-way could provide dual service as 

routes for new bulk-power transmission lines. Such dual usage could not only offer additional 

revenues to land owners, but also cut down on land-owner objections. 

--Maximize the Use of Present Infrastructure; states could encourage the maximization of present 

transmission infrastructure by seeking approval from FERC and NERC for dynamic line ratings. 

Dynamic line rating much more precisely matches the transfer capacity of high voltage lines to 

their actual operating environment in real time, increasing their transfer capacity by 10-20 

percent or more. Dynamic line ratings would increase transmission capacity of existing lines at 

extremely low cost and provide line owners with the maximum return on their investment. 

Commenters explained that investor-owned utilities lack sufficient incentives to invest in 

technologies that allow them to monitor the real-time load or reduce losses on their electric grid, 

particularly on the distribution grid, but also to some extent on the transmission grid. 

Commenters said that utilities historically have used voltage reductions in emergency situations 

to reduce load and avoid power outages. With advances in monitoring and control technologies, 

particularly on the distribution grid, commenters said that some utilities now are reducing 

voltage during peak conditions to reduce the need for peaking generation. Commenters stated 

that this capability can be expanded greatly, as incentives grow for investments in relevant 

technologies and, as changes occur over time in related business and regulatory models. Through 

the implementation of sophisticated volt-VAR management, which also will increase as these 

incentive structures change, commenters said that utilities can improve the efficiency of the grid 

during all loading conditions and can optimize voltage levels on their systems during peak and 

non-peak loading conditions, thereby optimizing the use of low- or zero-carbon emitting 

generation. Commenters added that certain grid modernization investments, e.g., in transformers, 

also help achieve structural efficiencies. Commenters concluded that the investments in the grid 

needed to help achieve efficiencies and, thereby, help reduce greenhouse gas emissions, also will 

provide benefits to customers by improving power quality. 
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Comment 5: Comments suggesting the EPA should allow financing program strategies as part 

of the implementation plans.

Response 5: EPA encourages the use of innovative EE program design and financing as

enabling measures that facilitate greater use of RE and demand-side EE. In the final rule, 

however, financing program strategies are not directly recognized as an eligible measure that can 

be used to adjust a CO2 emission rate, because financing does not directly substitute for electric 

generation from the grid or avoid electricity use from the grid.

The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA allow states to utilize financing program strategies as part 

of their implementation plans. Commenters stated that appropriate financing schemes can help 

promote many demand-side energy efficiency strategies under building block 4. Commenters

provided an example from Peoria, AZ where the local government has incentivized reductions in 

electricity consumption through low interest financing resulting in 7.7% annual electric usage 

reduction.

Commenters noted that many states have developed successful revolving loan fund (RLF) 

programs for demand-side energy efficiency and that these programs often exist outside of 

commission regulated DSM programs and do not have rigorous EM&V standards applied to 

them. However, commenters added, RLF programs are successful because they have low 

operational costs and low default rates, and they also help serve lower income residents who 

often do not have the needed cash or credit to make long term investments in energy efficiency, 

such as replacing old, inefficient, or possibly broken HVAC systems. Commenters stated that the 

EPA needs to work with states to develop approvable EM&V measures that allow for energy 

savings to be counted in state plans, but, these EM&V programs cannot be so burdensome that 

they raise the operational costs of RLFs and cause utilities and states to reconsider offering them. 

Commenters added that costs of EM&V will also often be passed along to the customers who 

greatly benefit from the programs.

Commenters stated that financing programs to enable energy efficiency improvements should 

also be credited to state plans, and there is a range of financing options available including 

revolving loan funds, state green banks funds, on-bill financing programs (23 States), propertyassessed clean energy programs (PACE) (in 9 States and District of Columbia), and others that 

result in implementation of energy efficient measures.

Commenters encouraged EPA to explicitly reference PACE financing in its final rule as a 

compliance tool available to the 31 states that have authorized it, and to encourage the remaining 

19 states that have not to authorize the use of PACE and to implement programs. 

Commenters stated the U.S.DOE issued guidelines for PACE projects in its "Guidelines for Pilot 

PACE Financing Programs." Commenters stated these DOE guidelines are intended to help 

structure projects so as to ensure that the energy savings are realized and that mortgage holders 
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are protected. Commenters stated the specific guidelines to help ensure that projects will deliver 

energy savings include, but are not limited to, the following:

• Projects should have a savings-to-investment ratio of greater than one;

• Property value should be greater than outstanding debts attached to the 

property;

• Mortgage-holders should receive notice of PACE liens;

• PACE liens should not accelerate in the event of a property owner 

default;

• Projects should be limited to 10% of the property's estimated value;

• Contractors and inspectors should be properly certified and licensed; and

• PACE programs should incorporate a debt service reserve fund to 

protect investors.

In addition to these DOE guidelines, commenters stated EPA may wish to suggest additional 

underwriting provisions for PACE projects to verify that funds are used to pay for the clean 

energy-related projects for which they are intended. 

Commenters encouraged EPA to explicitly reference revolving loan funds in its final rule as a 

compliance tool available to help all states reduce their CO2 emissions under building block four. 

Commenters stated revolving loan funds have been proven to leverage initial capital investments 

by providing low-interest loans to multiple projects and replenishing the fund with the interest 

charged to the facility owner. Commenters stated that Texas, for example, uses its LoanSTAR 

revolving loan fund to help finance energy efficiency investments in state, public school, 

university, and hospital facilities around the state, which have resulted in $395 million in low 

interest loans as of January 2014, a total of $419 million in energy savings for Texas taxpayers, 

and avoided emissions of more than 3.7 million tons of CO2. Commenters stated according to the 

National Association of State Energy Officials, as of July 2013 there were 79 revolving loan 

fund programs in operation across 44 states, which represents a total of $2 billion in energy 

efficiency financing. Commenters stated these programs should be explicitly referenced and the 

expansion of these programs should be encouraged in EPA's final rule. 

By reducing counterparty risk for lenders, commenters stated loan-loss reserve funds allow 

lenders to reduce interest rates on loans offered to building owners because they will be partially 

or fully reimbursed in the event that a borrower defaults on a loan. Commenters indicated that 

States should be allowed to and encouraged to set up and fund loan-loss reserve programs in 

order to leverage their investment and reduce the cost of delivering energy efficiency and 

reducing CO2 emissions; for example, Michigan Saves has worked with private lenders to offer a 

loan-loss reserve so that they will reduce the rates they offer to homeowners in Michigan looking 

to install energy-efficient equipment in their homes at annual interest rates of no more than 7 

percent. 
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Because loan-loss reserve funds can reduce the cost of financing energy efficiency upgrades to 

buildings, commenters encouraged EPA to explicitly reference loan-loss reserve funds in its final 

rule as a compliance tool that states can use to reduce CO2 emissions under building block four. 

By offering building and home owners tax deductions, tax credits, or rebates for installing 

certain energy-efficient technologies, commenters indicated that states can directly reduce the 

cost of investing in energy efficiency and encourage building owners to reduce their energy 

consumption and CO2 emissions. Commenters stated many states have property tax exemptions 

for energy-efficient buildings or buildings with solar photovoltaic systems, sales tax exemptions 

for certain energy-efficient technologies or renewable energy systems, personal and corporate tax 

credits or deductions for installing energy-efficient technologies or renewable energy systems, 

and/or rebate programs for energy-efficient technologies (e.g., LED lighting, solar photovoltaic 

systems, efficient hot water heaters, efficient furnaces or heat pumps, energy audits, and more). 

Commenters stated these tax incentives and rebate programs should be actively encouraged and 

specifically mentioned in EPA's final rule as compliance mechanisms for states to use to reduce 

CO2 emissions under building blocks three and four. 

Commenters emphasized that the EPA did not provide an exhaustive listing of low-cost finance 

tools available to help reduce the cost of investing in energy efficiency. To ensure maximum 

flexibility for states, commenters stated additional tools (e.g., on-bill financing, energy 

infrastructure banks, energy-efficient mortgages) should also be available to be used as 

compliance mechanisms, however, commenters believed that the aforementioned low-cost 

finance tools should be explicitly referenced in the final rule to give states additional certainty as 

to the types of programs they could implement to help reduce their CO2 emissions under building 

block four of the Clean Power Plan. 

Commenters indicated that State-level green banks are a valuable tool for scaling-up clean 

energy and will play an essential role in reducing the costs of clean energy investment, 

increasing private capital investment, lowering costs to consumers, and creating jobs. 

Commenters stated the success of the Connecticut Green Bank, the first in the nation, is strong 

evidence of the benefits of green banks in accelerating the transformation of the energy sector 

that the EPA rule envisions and provides a promising model for other states as they prepare to 

implement that rule. 

Commenters stated green banks help build the market mechanisms that connect investment with 

projects that allow consumers to save money while adopting cleaner energy. Commenters stated 

no matter the policy a state adopts to increase the deployment of renewables and energy 

efficiency, a green bank can help the state implement that policy with ample and reasonablypriced capital, and with green banks, this capital will come through public-private partnerships 

that maximize the efficiency of each public dollar while stimulating private investment. 

Commenters stated Building Blocks 3 and 4 call for increased usage of renewable power and the 

implementation of energy efficiency measures to reduce overall demand for electricity from 

carbon-emitting power plants. Commenters stated these strategies will, to a significant extent, 

fall outside of the traditional utility-financing arena and in many instances will be spearheaded 

by independent project developers dependent on access to private capital. While utilities have 

been investing in wind and solar power and energy efficiency and demand reduction programs 
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and will continue to do so, commenters stated much of the growth and innovation in these areas 

has come from outside the utility sector. 

Commenters stated the prime example is roof-top (or distributed) solar where decentralized 

entrepreneurs interfacing directly with consumers are reshaping retail power markets and 

delivering low-cost electricity. Commenters stated expanding these projects to serve a larger 

population of power users will be critically important to the success of 111(d) implementation 

plans. Commenters stated this expansion will require innovative financing approaches that 

increase the availability and lower the cost of capital and offer electricity to consumers at 

competitive prices. 

Commenters stated a green bank typically takes the form of a state chartered financing authority 

that leverages private capital with public dollars to grow clean energy markets quickly. 

Commenters stated green banks increase total clean energy investment through innovative 

financing mechanisms and stimulate demand by creating new market structures that increase 

consumer access to clean energy solutions. Commenters stated green banks lower the price of 

clean energy through better financing terms and have minimum/no long-term costs to taxpayers, 

as public dollars are returned and recycled. Commenters indicated States can authorize green 

banks to use a wide range of financing tools and apply them to a variety of clean energy 

technologies and strategies. Commenters stated green banks can optimally scale up the amount 

of clean energy in a state, efficiently using public dollars and reducing harm to consumers. 

Commenters stated green banks drive efficient and rapid deployment of clean energy by focusing 

on four main objectives, as follows: (1) accelerate market growth by delivering consumers lowcost capital for cheaper and cleaner energy; (2) fill gaps in commercial investment and maximize 

private: public leverage; (3) maximize consumer demand for clean energy by facilitating up-front 

financing and market transparency; (4) build self-sustaining loan programs to maximize 

efficiency of public dollars while holding taxpayers harmless. 

Commenters stated green banks drive efficient and rapid deployment of clean energy in four 

ways: (1) lowering the price of clean energy to allow for a higher market penetration; (2) 

reducing subsidies and offering taxpayer-neutral support for clean energy; (3) providing 

increased security for energy efficiency investment; (4) coordinating and aggregating small 

projects to attract investors. 

Commenters stated green banks do not need to rely on subsidy to grow clean energy markets, 

green banks allow states to grow clean energy markets while preserving taxpayer or ratepayer 

dollars. Commenters stated green banks loan at reasonable and for-profit rates commensurate 

with risk. Commenters stated green bank lending only finances projects that are net present value 

positive at reasonable discount rates - the projects financed by green banks produce energy 

solutions that are both cleaner and cheaper than the pre-existing energy consumption by the endusers. 

Commenters stated the green bank model works; its successful implementation across the 

country will attract more private investment and increase the deployment of energy efficiency 

measures and renewable energy technologies at low costs to consumers. Commenters stated thus, 

green banks can perform a unique function in accelerating the transition to clean energy that will 
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be required to meet the state emission reduction goals in EPA's 111(d) rule. Following and 

building on the Connecticut experience, commenters indicated states should consider creating 

green banks as an essential tool to support smart, cost-effective implementation of state plans 

developed in response to EPA's final rule. 

Commenters stated green banks are a proven tool to grow clean energy markets and reduce GHG 

without punishing consumers. Commenters stated green banks use limited public dollars to 

leverage the large amounts of private investment needed to achieve the EPA's proposed GHG 

reduction targets, and because public dollars are used for finance rather than grants, public funds 

invested in green banks are preserved and can be returned to taxpayer and/or ratepayers. 

Commenters stated this cost-effective and scalable approach to clean energy market growth 

makes green banks an ideal tool for state implementation of the proposed EPA rules. 

Commenters indicated State interest in green banks is rising rapidly, and the EPA and Obama 

Administration can support the proliferation of this successful tool by promoting green banks as 

part of state implementation plans. 

Commenters stated the EPA should provide flexibility on defining EE, to include EISA, codes 

and standards, and distribution efficiency. Commenters stated EE is a broad term which can be 

considered in different categories and quantified in different manners, including utility scale 

programs and changes in codes and standards. Commenters stated Washington's early action in 

the area of EE means that achieving future EE will be more costly than what has been achieved 

to date. In order for Washington to meet the energy efficiency targets needed to meet the 2030 

EPA final goal, commenters stated EE must be defined broadly to include all aspects of energy 

efficiency savings, whether it is by federal level, state, or regional codes and standards rather 

than just utility-run energy efficiency programs. 

To ensure states have flexibility to acquire energy efficiency using whatever means is most 

effective, commenters stated the EPA needs to clarify the following with respect to energy 

efficiency:

• Federal Energy Independence and Security Act (EISA): Savings from 

improvements in energy efficiency in the state associated with the 

Energy Independence and Security Act should count toward energy 

efficiency savings in the state. If states cannot take credit for these 

savings, EPA would be developing a policy where states will fight 

against federal efficiency standards just so the states can implement the 

same policies at a state level where they should get credit, which could 

ultimately undermine the federal standards.

Comment 6: Comments suggesting credit for nuclear investments.

Response 6: The final rule does not include nuclear generation from existing or under 

construction units in the determination of the BSER. Generation from new nuclear units and 

capacity uprates at existing nuclear units will be eligible for use in adjusting a CO2 emission 

rate, however, preserving generation from existing nuclear capacity is not eligible for use in 
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adjusting a CO2 emission rate. For more information on the treatment of nuclear when adjusting 

a CO2 emission rate, see section VIII.K.1.a.(8) of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters argued that Virginia would only get credit for 5.8% of its zero carbon nuclear 

generation based on the manner in which MWhs from zero carbon nuclear facilities are credited 

towards the state compliance goal in comparison to 100% credit to MWhs generated from wind 

and solar energy. Commenters argued that the credit for nuclear investments should be raised.

Comment 7: Comments regarding net carbon emission reductions from new carbon-emitting 

generation sources.

Response 7: In the final rule, quantified and verified MWh impacts of qualifying zero-emitting 

and low-emitting resources may be used by an affected EGU or state to adjust a CO2 emission 

rate, regardless of whether the renewable generation or demand-side EE savings occur inside or 

outside the state or territory. Consistent with the EPA’s calculation of the CO2 emission 

performance rates and state rate-based CO2 goals in the final emission guidelines, the MWhs 

impacts are added to the denominator of an affected EGU’s reported CO2 emission rate, 

resulting in a lower, adjusted CO2 emission rate. The reported CO2 emissions reflect the actual 

emission reductions from the deployment of qualifying non-emitting and low-emitting resources 

across the regional grid and so separate quantification of emission reduction is not necessary. 

Further adjustment of CO2 emissions would double count CO2 emissions impacts across the 

grid. For more information about the MWh accounting approach to adjust the CO2 emission rate 

of an affected EGU to reflect demand-side EE, see Section VIII.K.1.For more information 

regarding additional accounting and reporting requirements related to biomass, see sections 

VIII.I.2.c, VIII.K.1.a.(3)(b) and VIII.K.1.a.(9) of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters argued that EPA should only permit states to count net carbon emission reductions 

from new carbon-emitting generation sources when determining Section 111(d) compliance to 

prevent over-counting of emission reductions. Commenters stated the proposed rule 

contemplates the use of other carbon-emitting sources of energy, such as biomass, and while this 

new generation may displace power from higher carbon-intensive sources, new carbon emissions 

will also be created. Commenters argued that such sources could displace existing zero-carbon 

renewable energy sources or deployment of energy efficiency. Commenters stated that failing to 

account for emissions from new sources could also create an incentive to replace existing 

generation with equally carbon-intensive new generation, resulting in costs but no actual 

reductions in carbon emissions and potentially causing an increase in net emissions over time.

Commenters believed that the EPA's approach may have implications for states' ability to use 

their existing RPSs for Section 111(d) compliance. Commenters stated that since states take 

different approaches as to what counts as a "renewable" source, the EPA should make it clear 
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what counts as a RE for purposes of Section 111(d) compliance. Commenters also stated any 

credit earned by new carbon-emitting generation must reflect the actual net emission reduction.

Comment 8: Comments supporting the allowance of credit for a wider range of EE measures for 

both utility-sponsored and non-utility sponsored EE programs

Response 8: The EPA recognizes the value of non-BSER measures, such as demand-side EE 

and combined heat and power, to reduce CO2 emission from affected EGUs, and allows for the 

inclusion of non-BSER measures as a part of a state’s plan to meet the emission guidelines. To 

the extent qualifying demand-side EE, renewable energy and non-BSER measures are tied to a 

state plan, the quantified and verified MWh impacts of the measures may be used by an affected 

EGU or state to adjust a CO2 emission rate, regardless of whether the savings occur inside or 

outside the state or territory. This adjustment results in a lower adjusted CO2 emission rate.

Incremental emission reduction measures, such as RE and demand-side EE, installed after 2012

can be recognized as part of state plans, but only for the emission reductions they provide during 

a plan performance period. The measures must meet the general and specific eligibility 

requirements for resources used to adjust a CO2 emission rate, including but not limited to 

renewable energy, demand-side EE, water system efficiency, CHP, waste-to-energy,

transmission and distribution measures including Volt/VAR optimization, and others as

described in Section VIII.K.1 of the final rule preamble of the CPP. 

The measures must also meet the requirements and criteria related to proper quantification and 

verification of MWhs from demand-side EE savings are described in Section VIII.K.3 of the 

final rule preamble.

For more information about specific methods to adjust the CO2 emission rate of an affected 

EGU to reflect demand-side EE and eligibility requirements for resources used to adjust a CO2

emission rate, including but not limited to demand-side EE, see section VIII.K.1 of the final rule 

preamble.

Measures that reduce CO2 emissions outside the electric power sector, including emission 

reductions from reductions in vehicle fleet use, may not be counted toward meeting a CO2

emission performance level for affected EGUs or a state CO2 goal, under either a ratebased or mass-based approach, because all of the emission reduction measures included in 

the EPA’s determination of the BSER reduce CO2 emissions from affected EGUs. For 

more information, see section VIII.K.1.c of the final rule preamble.

The MWh accounting method in the final rule corresponds with the use of MWh-denominated 

Emission Rate Credits (ERCs) in the rate-based emission trading framework specified in this 

rule. The accounting method only requires a quantification of the MWh generated or avoided by 

an eligible measure, and thus credits or adjustments can be denominated in MWh and do not 

need to represent an approximation of the CO2 emission reductions that result from those 

MWhs. The final rule allows states to develop and use emissions budget and emission rate credit 

(ERC)-based trading programs depending upon the type of approach the state chooses. For more 
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information about the approaches and requirements related to trading, see section VIII.C and 

VIII.K.2 of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters encouraged EPA to ensure that all reductions in electricity demand achieved 

through energy efficiency policies can be fully counted in the denominator of the state's power 

sector emission rate, assuming proper MR&V protocols are followed. Commenters stated that in 

addition to energy efficiency resource standards qualifying demand reduction measures should 

include appliance standards, building standards, incentives for combined heat and power (CHP) 

or waste heat to power (WHP), and all financial policy tools a state may use to reduce demand, 

including grants, tax credits, and loans. .

If a state implements the Clean Power Plan in a manner that involves tradable emission or 

generation credits, commenters encouraged the EPA to allow states to fully account for, and 

assign credits to, demand reductions at large industrial or commercial facilities that are otherwise 

voluntary. Commenters stated for example, if a water utility reduces its electricity demand by 

reducing the demand for water (thereby reducing demand for pumping and treatment), this 

reduction should be creditable to the state's emission rate denominator. 

Commenters supported an "Everything-Should-Count" approach to clean energy. Commenters 

encouraged EPA to produce a final rule that provides states with ample guidance on the best 

approach to including all viable clean energy project types. While the current rule and the State 

Plan Considerations Technical Support Document outline methods for including EE and RE 

programs and projects operated by regulated utilities providers, commenters stated the current 

proposal does not provide significant guidance on including a broader range of projects, 

including private guaranteed energy performance contracts, behind-the-meter private solar 

projects, private combined heat and power projects, etc. While the inclusion of these types of 

technologies poses unique enforceability challenges, commenters stated they could significantly 

contribute to states' ability to fulfill their CPP obligations. Commenters strongly urged that EPA 

provide guidance in the final rule on how to include such technologies. 

Commenters stated that some large industrial or institutional entities and commercial retailers 

(e.g., big-box stores) may aggregate multiple facilities and be interested in going through the 

effort to get credit for energy savings they achieve on their own. Commenters stated the same 

procedures should be applied for these customers as the ones described above for energy 

performance contracting. For industrial projects, however, commenters stated there may be an 

additional need for adjustments based on actual production levels. Commenters stated the DOE 

Superior Energy Performance program has developed a methodology for estimating baseline and 

savings from industrial projects and recommended that EPA approve this methodology as 

adequate for state compliance plans.

Commenters stated that EPA should not make the eligibility of emission rate reductions 

contingent on state requirements. Commenters requested that EPA not penalize companies for 

the actions of their state governments. Specifically, commenters pointed to an example wherein 

Oklahoma has recently proposed a three-year ban on wind energy development. Commenters 
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asked that EPA's final rule not require companies to be dependent on state action, and allow 

companies as much time as possible to develop renewable energy generation.

Commenters said that energy efficiency offers an opportunity to create over 300,000 new jobs, 

save consumers $100 billion per year in energy bills, and eliminate 600 million tons of CO2

emissions each year. 

Commenters described the overall benefits to greater investment in energy efficiency, which has 

huge potential to conserve demand and can have a significant impact on greenhouse gas 

reduction from power plants, particularly when technological and cost constraints can limit the 

degree of improvements realistically possible at the plants themselves. Commenters said that 

there are several active and passive approaches to demand reduction and peak shaving at various 

stages of development or implementation today. For example, commenters said that ICAC 

members are actively involved in developing technologies for reducing energy demand by up to 

30% from commercial buildings. Commenters agreed that programs to reduce peak demand 

should count toward compliance, and that the EPA should issue guidance explaining how these 

programs could be used under this rule and detailing the EM&V procedures required for such 

compliance. 

Commenters urged the EPA to consider a diverse array of EE programs, including those beyond 

typical utility or state sponsored rebate programs that are overseen by utility commissions. 

Commenters stated building energy codes, appliance standards, RLFs, efficiency tax credits, 

building disclosure programs, behavioral modification programs, etc. are all successful and 

innovative programs that the EPA should be encouraging states to consider in CPP compliance. 

Commenters agreed that literature review indicates that building codes and appliance efficiency 

standards can, by themselves, achieve savings comparable to those EPA projects under building 

block 4, and reinforced their conclusion that the EPA's proposed savings targets are readily 

achievable. Commenters stated that it is important for the EPA to encourage states to allow for 

energy efficiency (EE) savings from a wide variety of programs, including those outside of 

typical, certified demand side management (DSM) programs. Commenters pointed to the range 

of geographic, cultural, political, and climate differences in the states and said that encouraging 

states to count EE from a wide range of programs and policies will encourage energy savings and 

innovation that might not otherwise occur in individual states. Commenters added that it is 

important for the EPA to recognize that participation in typical, certified DSM programs is a 

voluntary decision by consumers and no matter how much money is spent on marketing and 

outreach (and thus increasing program costs), some states and utilities simply might not be able 

to achieve the savings targets outlined in the CPP through typical DSM programs. 

Commenters advocated for EPA to allow a broad range of energy efficiency measures outside of 

utility-sponsored programs. Commenters maintained that more than half of current energy 

efficiency measures are delivered through nonutility programs, residential contractors operating 

outside of state programs and building and industrial facility operators. 

Commenters recommended using EM&V practices for non-ratepayer energy efficiency programs 

based on SEE Action Network Energy Efficiency Program Impact Evaluation Guide.

Commenters recommended the use of a registry to register and retire emissions from non-utility 

programs. Commenters asked that EPA clarify which types of efficiency programs could be 

credited toward compliance and the required EM&V. Commenters were concerned that certain 
230

language in the TSD about enforceability and what types of state programs are approvable seems 

to be confusing and possibly limiting in terms of the types of programs that states could use in 

their plan.

Commenters supported the current proposal to credit a range of efficiency programs including 

both utility and non-utility programs, as long as all measures include the same standards for 

EM&V. Commenters recommended a wide range of programs including behavioral programs, 

financing programs, city programs, and other voluntary programs should be credited in state 

plans. Commenters further recommended increased compliance with building codes (0.87 

percent per year in 2030) should be included in the potential emissions reductions in the BSER 

for Block 4 and both increased compliance and adoption of updated building codes by states and 

local governments should be credited in state plans. 

Commenters commented that the EPA should not consider limiting the wide variety of EE 

sources available to meet the proposed standard. Commenters provided several examples of 

several measures that should be considered as eligible to contribute toward the EE achievement 

target, including transmission and distribution line efficiency upgrades, design and operational 

practice improvements; CHP; and improved codes and standards. Commenters added that 

restricting the use of any source of EE will reduce the ability of EE to contribute to the reduction 

of emissions, and ultimately increase the costs of compliance. Commenters explained that 

transmission and distribution facility efficiency upgrades, in particular, can be a significant 

component of any EE program. Commenters stated the distribution efficiency improvements can 

result in both energy and capacity savings and provide other operational benefits. Similarly, 

commenters stated that transmission equipment efficiency improvements and practices can allow 

the grid to operate more safely and improve system utilization, thereby reducing emissions. 

Commenters stated these measures collectively could substantially contribute to EE 

achievements and should be creditable toward any reasonable EE targets that are established.

Commenters stated that as proposed, the Clean Power Plan allows both utility and non-utility 

programs to receive energy savings credits. Commenters stated however, some aspects of the 

proposal should be clarified in this regard including indicating which types of programs are 

eligible for inclusion in state plans and for energy efficiency credits, and which are not. 

Commenters made several proposals. Commenters stated the EPA should allow states and 

utilities to receive savings credits for a wide variety of utility programs, including but not limited 

to measure-based incentives, behavior change programs, transmission and distribution system 

upgrades, financing programs, building code support programs, and incentives for combined heat 

and power (CHP). Commenters stated non-utility policies and programs should be eligible for 

savings credits and may include building energy codes, energy retrofit ordinances, tax incentives, 

financing programs, public sector energy efficiency improvement policies or programs, programs 

to spur market transformation, state-based appliance efficiency standards, state policies or 

programs to foster adoption of CHP systems, and state programs to improve industrial or 

agricultural efficiency. Commenters stated policies or programs adopted and/or implemented by 

local governments should be eligible for energy savings credits if they are included in state plans 

and the energy savings are properly measured and verified according to EPA-approved 

procedures and protocols. Commenters stated for example, some states such as Arizona and 

Colorado are home rule states where by state constitution certain policies such as building codes 

are adopted and enforced at the local level, not at the state level. Commenters stated that in such 
231

cases, states should be allowed to aggregate savings across local jurisdictions, evaluate energy 

savings (if not done by local governments), and receive energy savings credits. Commenters 

stated likewise, states should be able to receive energy savings credits for public building retrofit 

or other public sector efficiency programs approved and implemented at the local level, as long 

as these programs are part of state plans and the EM&V requirements and other rules established 

by the EPA are followed. Commenters stated energy efficiency credits should only be claimed 

for energy savings resulting from policies and programs included in state compliance plans. 

Commenters stated credits should not be provided to individual energy efficiency projects as this 

would be an administrative nightmare, it would be difficult to ensure that proper EM&V 

procedures are followed, and it would be difficult to avoid double counting of energy savings 

credits between policies and programs on the one hand and individual projects on the other.

Commenters encouraged EPA to provide guidance to states to include a broad array of efficiency 

options in their plans. Commenters stated there are thousands of energy efficiency programs 

around the U.S., each focused on a different market or technology. Commenters stated that 

generally, younger programs focus on lighting retrofits, while more mature programs target 

savings opportunities "deeper" within buildings. Commenters stated the mission of FirstFuel and 

other companies is to reduce the cost to find these deeper energy savings, by deploying advanced 

data analytics and offering insights through simple, web-based tools. Commenters stated they do 

this by using data from advanced electricity and natural gas meters, which provide near-real-time 

information about a building's energy use. Commenters stated their database of Energy 

Conservation Measures (ECMs) includes hundreds of recommendations, which they consider 

each time they look for savings potential in a building. Commenters stated including a broad list 

of ECMs helps reduce the total cost of identifying energy efficiency, and reduces "stranded 

savings" in buildings -- a phenomenon whereby certain savings opportunities are cherry-picked, 

and others are ignored because they are not supported by incentives. 

As technology advances and the cost of resource alternatives change, commenters stated they 

hope that the definition of DSM/EE would also be appropriately expansive. Commenters stated 

this seems to have been recognized by U.S. EPA, but Indiana needs specific guidance 

demonstrating that U.S. EPA will be receptive to additional energy efficiency and demand 

reduction programs. 

Commenters believed State implementation plans should let all forms of energy efficiency and 

demand response activities from industrial sources ("outside-the-fence line") compete with other 

emission reduction technologies, including the following: (1) recognizing and fully valuing the 

GHG reductions of industrial demand side management activities by allowing compensation 

equal to EGU to be provided directly to DR providers; (2) encouraging existing state and 

regional GHG programs to include industrial energy efficiency and DR as offsets with 

compensation adequate to support expansion of those programs; (3) encouraging states to utilize 

market-based platforms to provide industrial consumers full value for their reductions, including 

the opportunity to use more effective mechanisms for DR aggregators; and (4) encouraging 

states to consider flexible incentive programs for EE programs, such as retrofits at facilities of 

large energy users. 

Commenters stated that assuming EPA's final rule allows credits for early action, a national ER 

program could be launched soon after the rule is promulgated, with support from their 
232

association's members, utilities, retailers and EPA/DOE. Commenters stated that this program 

could build a large bank of credits that could later be counted toward compliance with state plans 

starting in 2020 and immediately capitalize on the significant gains in efficiency from the new 

DOE standard. 

Commenters supported EPA's BSER that sets state targets by looking at real-world potential to 

reduce carbon, but believes the proposal under estimates the amount of RE that can be deployed 

at reasonable cost. Commenters said EPA excluded a number of additional opportunities such as 

building codes, transmission and distribution, voltage optimization, and combined heat and 

power. Commenters said EPA should include all available EE opportunities in its final analysis, 

and increase the targeted annual savings to at least 2% of retail sales.

Commenters recommended that EPA provide specific guidance to states that other non-utility 

delivered EE can be included in state compliance plans. Commenters stated EPA may wish to 

provide additional information in the final CPP on Financing, including that States should 

receive credit for energy savings that result from EE finance programs such as Property Assessed 

Clean Energy (PACE), and on State Tax Incentives & Rebate Programs such as providing State 

and municipal tax incentives, as regulations and product rebate programs can accelerate 

investment in EE technologies and improve EE outcomes. 

Commenters stated that the recommended types of programs to include are listed below:

• Building Energy Codes

• Energy Savings Performance Contracts (ESPCs) delivered by private 

energy service companies if verified in accordance with well -

recognized protocols such as the International Performance 

Measurement and Verification Protocol and the Federal Energy 

Management Program M&V Protocol. Commenters particularly stressed 

the importance of performance contracting to meeting the CO2 reduction 

goals. Commenters stated that EM&V conducted for typical 

performance contracts are more rigorous that what is conducted for state 

energy efficiency programs.

• Privately-Owned Commercial and Industrial Retrofit Projects verified 

using the IPMVP by either the local utility or third-party experts.

• Building Efficiency Rating Systems including U.S. EPA ENERGY 

STAR, the U.S. Green Building Council's Leadership in Energy and 

Environmental Design (LEED), and other less well-established EM&V 

rating system certifications.

• Energy savings due to superior design and construction in new and 

renovated buildings and through ongoing operations and maintenance if 

verified by third-party licensed architects and engineers, who are legally 

accountable for their work.
233

• Residential Retrofit Projects Delivered by States, Non-Profit 

Organizations, Contractors and Aggregators that provide home 

performance upgrades through incentive and labeling programs if 

verified through established EM&V methods by third-party evaluators 

utilizing energy usage data that are weather-normalized and compared to 

baseline data and control groups.

• Weatherization and other non-ratepayer programs.

• Appliance standards

• Industrial energy efficiency programs.

• Geothermal (ground source) heat pumps

• Educational and behavioral EE programs

• Electric vehicles

• Water and wastewater sector EE

• Waste to Energy electricity-generating projects

• Non-affected CHP

• Low income EE programs

• Refrigerator rebate programs

Commenters stated that voluntary and emerging EE/RE must be allowed under the rule with 

significant flexibility and without restrictions on how they can be utilized. Commenters noted 

that if EPA limits voluntary and emerging EE/RE to 6% of the total EE/RE possible measures, 

Ohio would be unable to achieve its EE/RE targets.

Commenters stated that, ultimately, the design of EE programs included in section 111(d) 

implementation plans is a decision for states required to comply with EPA's guidelines. 

Nonetheless, commenters believed certain standard design features would enhance the 

effectiveness of appliance rebate programs and facilitate their consistent and successful 

implementation on a national or regional scale. Commenters provided a number of 

recommendations for a model program, these are listed below: 

• Verification. The rebate would be provided to the consumer upon 

verification that a new refrigerator had been purchased and the older 

refrigerator removed and recycled. In all likelihood, the retailer would 

arrange for the pick-up of the old refrigerator when the new one is 

delivered, and the delivery service would complete a form documenting 

that the refrigerator has been removed and recycled. Upon receipt of the 
234

paperwork, a rebate check would be mailed to the consumer by the 

utility funding the rebate. 

• Backup Refrigerators. Some consumers may have secondary or backup 

refrigerators (or other appliances such as room air conditioners) that 

could be removed at the same time that the primary refrigerator is 

replaced. With a modest additional rebate, consumers could be 

motivated to relinquish these secondary refrigerators, which could be 

removed and recycled for a minimal additional cost and the benefits 

credited to the utility funding the rebate program. 

• Rebate Amount. The amount of the rebate may need further analysis and 

could vary from region to region, but commenters believed a rebate of 

$100 or more is likely to provide an effective incentive for purchase of 

new refrigerators and change consumer behavior more than current 

rebate levels, which are often significantly less than $100 in many state 

programs. A somewhat higher rebate could be offered to incentivize 

purchases of ENERGY STAR products. 

• Calculating Energy Savings and GHG Reductions. The energy savings 

and associated GHG benefits from linked purchase/recycling rebates 

would represent the difference in energy consumption between the new 

and replaced product, multiplied by the number of years that product 

would have remained in service in the absence of the rebate. 

Commenters believed that a straightforward formula is available to 

determine rebate-related energy savings and GHG reductions using this 

approach. In their own analysis, described more fully in the appendix to 

their comments, commenters used extensive available data on the 

efficiency of new and old appliances, the projected service life of older 

units and the likely age distribution of products that would be replaced 

to calculate an "average" energy saving and GHG reduction per unit. By 

multiplying this value by the total number of replaced units, commenters 

then determined aggregate energy savings and converted them into GHG 

reduction credits that could count toward section 111(d) compliance. 

Commenters' methodology could be readily adapted to support ER 

programs used for section 111(d) compliance. 

• Age of Eligible Units. There should be no restriction on the age of 

refrigerators eligible for rebate-induced replacements. The absence of 

such a restriction would simplify implementation and recordkeeping and 

thus avoid complexity and confusion as well as reduce the significant 

amount of EM&V resources that are diverted from direct energy 

efficiency improvements to administrative requirements. It would also 

maximize the GHG reductions achieved: even recent model refrigerators 

are markedly less efficient than new 2014 models and, because of their 

longer remaining useful lives, their replacement will yield significant 

energy savings that save consumers money and reduce GHG emissions. 
235

• Role of DOE Standards and ENERGY STAR Levels. Consumers should 

be eligible for a rebate whether the refrigerator they purchase bears the 

ENERGY STAR label or instead complies with the latest DOE 

efficiency standards. The difference in efficiency on an actual annual 

energy use basis between DOE-compliant and ENERGY STAR 

products has narrowed significantly compared to earlier years as a result 

of the significantly more stringent DOE standards. Maximizing 

consumer choice by allowing rebates for both product classes will 

increase the number of replaced products and produce greater overall 

benefits. This is because program participation will increase 

significantly with a broader range of products available for rebates and 

less complex, more inclusive eligibility criteria that encourage 

consumers to take advantage of these rebates. However, as noted above, 

purchase of higher efficiency ENERGY STAR products could still be 

encouraged by offering a somewhat higher rebate to purchasers of those 

products. 

• Duration of Program. To maximize results, annual ER rebate programs 

should be continued for at least five consecutive years and perhaps 

longer to provide a full opportunity to reach consumers who could be 

influenced by rebates to purchase new products. 

Commenters stated that, ultimately, the design of EE programs included in section 111(d) 

implementation plans is a decision for states required to comply with EPA's guidelines. 

Nonetheless, commenters believed certain standard design features would enhance the 

effectiveness of appliance rebate programs and facilitate their consistent and successful 

implementation on a national or regional scale. Commenters provided a number of 

recommendations for a model program, these are listed below: 

• Verification. The rebate would be provided to the consumer upon 

verification that a new refrigerator had been purchased and the older 

refrigerator removed and recycled. In all likelihood, the retailer would 

arrange for the pick-up of the old refrigerator when the new one is 

delivered, and the delivery service would complete a form documenting 

that the refrigerator has been removed and recycled. Upon receipt of the 

paperwork, a rebate check would be mailed to the consumer by the 

utility funding the rebate. 

• Backup Refrigerators. Some consumers may have secondary or backup 

refrigerators (or other appliances such as room air conditioners) that 

could be removed at the same time that the primary refrigerator is 

replaced. With a modest additional rebate, consumers could be 

motivated to relinquish these secondary refrigerators, which could be 

removed and recycled for a minimal additional cost and the benefits 

credited to the utility funding the rebate program. 
236

• Rebate Amount. The amount of the rebate may need further analysis and 

could vary from region to region, but commenters believed a rebate of 

$100 or more is likely to provide an effective incentive for purchase of 

new refrigerators and change consumer behavior more than current 

rebate levels, which are often significantly less than $100 in many state 

programs. A somewhat higher rebate could be offered to incentivize 

purchases of ENERGY STAR products. 

• Calculating Energy Savings and GHG Reductions. The energy savings 

and associated GHG benefits from linked purchase/recycling rebates 

would represent the difference in energy consumption between the new 

and replaced product, multiplied by the number of years that product 

would have remained in service in the absence of the rebate. 

Commenters believed that a straightforward formula is available to 

determine rebate-related energy savings and GHG reductions using this 

approach. In their own analysis, described more fully in the appendix to 

their comments, commenters used extensive available data on the 

efficiency of new and old appliances, the projected service life of older 

units and the likely age distribution of products that would be replaced 

to calculate an "average" energy saving and GHG reduction per unit. By 

multiplying this value by the total number of replaced units, commenters 

then determined aggregate energy savings and converted them into GHG 

reduction credits that could count toward section 111(d) compliance. 

The commenter' s methodology could be readily adapted to support ER 

programs used for section 111(d) compliance. 

• Age of Eligible Units. There should be no restriction on the age of 

refrigerators eligible for rebate-induced replacements. The absence of 

such a restriction would simplify implementation and recordkeeping and 

thus avoid complexity and confusion as well as reduce the significant 

amount of EM&V resources that are diverted from direct energy 

efficiency improvements to administrative requirements. It would also 

maximize the GHG reductions achieved: even recent model refrigerators 

are markedly less efficient than new 2014 models and, because of their 

longer remaining useful lives, their replacement will yield significant 

energy savings that save consumers money and reduce GHG emissions. 

• Role of DOE Standards and ENERGY STAR Levels. Consumers should 

be eligible for a rebate whether the refrigerator they purchase bears the 

ENERGY STAR label or instead complies with the latest DOE 

efficiency standards. The difference in efficiency on an actual annual 

energy use basis between DOE-compliant and ENERGY STAR 

products has narrowed significantly compared to earlier years as a result 

of the significantly more stringent DOE standards. Maximizing 

consumer choice by allowing rebates for both product classes will 

increase the number of replaced products and produce greater overall 

benefits. This is because program participation will increase 
237

significantly with a broader range of products available for rebates and 

less complex, more inclusive eligibility criteria that encourage 

consumers to take advantage of these rebates. However, as noted above, 

purchase of higher efficiency ENERGY STAR products could still be 

encouraged by offering a somewhat higher rebate to purchasers of those 

products. 

• Duration of Program. To maximize results, annual ER rebate programs 

should be continued for at least five consecutive years and perhaps 

longer to provide a full opportunity to reach consumers who could be 

influenced by rebates to purchase new products. 

PRIVATE SECTOR EE PROGRAMS

Commenters stated the rule does not account for energy efficiency projects delivered outside of 

utility programs by private sector ESCOs and stated the market for ESCO energy efficiency was 

$4.8 billion in 2012, while utility efficiency program budgets totaled $5.7 billion in the same 

year. Commenters stated the work is done through performance-based contracts (PCs) for energy 

savings, where the ESCO reduces the energy consumption of its customers by installing new 

energy efficient equipment at their facilities, and the investment is paid off over time with the 

resulting savings from the customers' utility bill. Commenters indicated the performance of the 

newly installed equipment, and the resulting energy savings for its customers, is contractually 

guaranteed by the ESCO, and the performance of the project is measured and verified (M&V) by 

professionals, using internationally established protocols. Commenters stated that accounting for 

the contributions of the well-established PC market by incorporating PCs as viable tools for state 

emission reduction under the Clean Power Plan would result in an additional cumulative savings 

of 104 to 190 million MWh by 2030.

Commenters stated that for existing and prospective programs and policies, EPA should 

acknowledge, as it did with EERS and other ratepayer programs, that actions taken pursuant to 

existing state ESPC policies and programs provide a potentially substantial contribution for CPP 

compliance. Commenters stated it should also delineate what types of legal and policy tools will 

be viewed as sufficiently enforceable for purposes of including ESPCs in compliance plans and 

by whom. Commenters stated for example, laws, regulations or executive orders requiring public 

building efficiency enhancements in a state should be deemed as sufficient for credibly 

projecting ESPC and broader public building energy savings. Commenters stated that inclusion 

of ESPCs under the umbrella of an EERS or other utility requirement or target may also be 

viewed in this way. 

Commenters stated that EPA's proposed Clean Power Plan (CPP) will enable states and market 

actors to utilize the most cost effective options to reduce power sector greenhouse gas (GHG) 

emissions, including efforts to increase demand-side energy efficiency (EE). Commenters noted 

that demand-side energy efficiency can be deployed in a variety of ways, through utility 

programs, state led programs and third-party energy efficiency projects delivered by privatesector energy service companies (ESCOs). Commenters discussed the ways in which 

performance contracting (PC) projects can support compliance with the CPP. Commenters stated 

PC projects are one of many highly-verifiable methods for implementing GHG-reducing 
238

demand-side EE and renewable energy projects. Commenters noted that much of the privatesector EE work is done through performance-based contracts for energy savings, in which the 

ESCO reduces energy consumption of its customers by installing new energy efficient equipment 

at their facilities. Commenters stated that this investment is paid off over time by the resulting 

savings in the customers' utility bill. Commenters stated that the performance of the newly 

installed energy conservation measures, and the resulting energy savings for its customer, is 

contractually guaranteed by the ESCO. Commenters stated the performance of the project is 

measured and verified (M&V) by experienced professionals, using internationally established 

protocols. Commenters stated that this rigorous level of M&V is the foundation of the 

performance contracting guarantee. 

Commenters indicated that the energy efficiency elements of the Clean Power Plan appear to 

have been developed primarily with utility energy efficiency programs in mind, despite the fact 

that energy efficiency investments through performance contracting approximate those made 

through utility programs. For example, commenters noted that performance contracting projects 

and utility programs saw around $12 billion of investment in 2012, with approximately half 

coming from performance contracting projects. Commenters stated that expressly allowing 

performance contracting to be a compliance option in the Clean Power Plan would significantly 

enhance state options for low-cost and rigorously verified GHG reductions. Commenters 

indicated it would also bring into the effort those companies most focused on producing energy 

efficiency results. 

Commenters stated that including performance contracting projects as an allowable compliance 

option for state plans is straightforward and consistent with the Clean Power Plan. Commenters 

stated it builds upon past inclusion of performance contracting projects in approved state 

implementation plans for National Ambient Air Quality Standards. In addition, commenters 

noted that all 50 states have adopted performance contracting enabling legislation, which 

provides states with an excellent platform on which to build an effective compliance plan. 

However, commenters indicated that additional guidance is needed for states to have confidence 

that EPA will recognize energy efficiency savings and distributed renewable energy generation 

delivered by performance contracting projects, and approve state plans that include them. 

Commenters said the guidance should provide states with needed clarity on the following items:

• Identify Approvable Pathway. Without limiting state flexibility, EPA 

can offer clarifying guidance to enable states to include performance 

contracting project-related emission reductions in their 111(d) 

compliance plans. (Further detail provided on page 41 of the comment.)

• Recognize All Existing Programs. EPA should acknowledge--as it did 

with energy efficiency resource standards, etc.--that existing state 

performance contracting activities provide a potentially substantial 

contribution to 111(d) compliance. (Further detail provided on page 42 

of the comment.)

• Targeting Sources of Energy Savings. EPA should clarify how this 

requirement applies to performance contracting projects. Commenters 

recommended that the states be required only to identify building types 
239

(e.g. state-owned, hospitals, universities etc.) targeted for performance 

contracting and a reasonable estimate of savings to be achieved from 

anticipated PC projects. (Further detail provided on page 42 of the 

comment.)

• Aggregation of PC-Created Emission Reductions. EPA should describe 

approvable approaches for aggregation of PC project-related GHG 

reductions for use in 111(d) compliance. A national registry could serve 

this purpose, providing efficiency and the greatest degree of consistency 

in all aspects of inclusion of project-related GHG reductions in 111(d) 

compliance. Alternately, a state energy office (or another designated 

Agency) can collect (directly or via a third party) data from all PC 

projects in the state and determine the avoided emissions achieved. 

(Further detail provided on page 42 of the comment.)

• Clarify Approvable Approach for Key Compliance Criteria. EPA can 

assist states by identifying approvable approaches for key compliance 

criteria that will facilitate inclusion of performance contracting projectrelated emission reductions. Key compliance criteria for which EPA 

should identify approvable approaches include M&V protocols, auditing 

requirements for state performance contracting projects, performance

contracting program evaluation methods, and corrective measures. 

(Further detail provided on page 43 of the comment.)

• Existing Facilities/Installations. Emissions reductions from performance 

contracting projects that are validated by an approved M&V approach 

and persist into the compliance period should be eligible to contribute to 

111(d) compliance regardless of when the measure was installed. 

(Further detail provided on page 44 of the comment.)

• Contributions to Future Avoided Emissions. Avoided electricity 

consumption should be allowed to count toward 111(d) compliance for 

performance contacting projects subjected to proper M&V. (Further 

detail provided on page 45 of the comment.)

Commenters recommended that EPA allow states to include the use of energy savings 

performance contracts (ESPCs) as a compliance mechanism under building block four. 

Commenters stated that focusing on multiple ways to deploy demand-side energy efficiency 

gives states additional options and flexibility in meeting their carbon reduction targets. 

Commenters also recommended that EPA allow states to include not only utility-run and staterun programs in their state implementation plans, but also private-sector projects in the form of 

ESPCs delivered by energy service companies (ESCOs).

Commenters stated that the energy efficiency initiative that their industry provides is known as 

guaranteed energy savings performance contracts. Commenters stated it is a procurement model 

available to federal, state, local government agencies, universities, elementary schools, and 

industry. Under this procurement model, commenters said building owners receive infrastructure 
240

replacement associated with energy consuming equipment, such as lighting, heating, and 

cooling. Commenters asserted that the replacement of the older technology systems with new 

efficient systems creates the reduction in utility consumption, which translates into less need for 

generation, hence lowering GHG emissions. 

Commenters stated that what makes energy savings performance contracting an ideal method of 

end use efficiency is that the reductions are measured, verified, and documented. Commenters 

stated these steps are necessary in every performance contract as the ESCO must guarantee to the 

billing owner that the energy consumption will be achieved each year of the contract. In this 

context, commenters recommended the following policy principles for energy efficiency as a 

compliance tool: (1) end use efficiency; (2) guidance to states on presumptive, approvable 

energy efficiency provisions in compliance plans; and (3) recognition and scaling of existing 

state utility programs. 

Commenters discussed the importance of ESPCs as part of state implementation plans. 

Commenters stated that ESPCs are comprehensive, self-funded projects where the equipment 

and technology installed to modernize buildings and facilities are paid for by guaranteed energy 

and operational savings. Commenters said that ESPCs allow for a building owner to make 

significant EE upgrades without upfront cost.

While Building Block 4 did not exclude ESPCs as a means of compliance that states can utilize, 

commenters contended that ESPCs should be explicitly called-out in the final version of the rule, 

providing sufficient guidance to states so that they can determine if ESPCs should be included in 

their implementation plans. Commenters noted that their company is part of a coalition of other 

energy service companies (ESCOs) that has developed a technical document to support this and 

other recommendations related to inclusion of ESPCs in the final CPP. Commenters stated that 

there are significant opportunities at the state level where ESPCs can be more widely adopted in 

the "MUSH" market--municipal and state governments, universities and colleges, K-12 schools, 

and hospitals--resulting in substantial decreases in energy consumption. 

Commenters stated that there is a large market potential for Performance Contracting (PC) 

projects, with an estimated worth between $71 and $133 billion dollars 

nationwide. Commenters stated that about one-third of the electricity savings produced by PC 

projects have utilized ratepayer-funded incentives or rebates. Commenters stated this means that 

the majority of electricity savings in PC projects will not be accounted for in state CPP 

compliance plans unless the plans specifically recognize PC projects as a unique delivery 

mechanism. 

Commenters went on to say that they urge the EPA to provide specific guidance to states on how 

to incorporate performance contracting projects into state plans. Without specific 

guidance, commenters feared that many states will omit performance contracting from their 

compliance plans, because they thought it would be too difficult to understand or implement, and 

deprive the states of a resource that is both low cost and low in state administrative effort. 

Despite these challenges, commenters believe that PC can be a significant resource for many 

states in meeting their CPP targets, and the value of PC can be captured by states without 

the bureaucratic burden that is required for ratepayer-funded programs.
241

Commenters urged the EPA to consider that savings from almost all PC projects is now, and has 

been for the past two decades, enforceable by contracts with public agencies, and that these 

contracts are public record, available for inspection and/or audit by state air regulators and the 

EPA. Commenters believe that this enforceability makes PC projects a reliable resource for CPP 

compliance plans. Commenters stated that almost 90% of PC projects are implemented by 

ESCOs for government agencies, pursuant to federal and state laws that permit PC projects as an 

exception to the normal process for procuring public construction projects. Commenters noted 

that, in a PC project, a government agency is permitted to procure PC on a "best value" basis that 

seeks to minimize the government's life cycle costs, rather than just its first cost. Commenters 

stated that the quid pro quo is that the PC project contract includes a savings guarantee by the 

ESCO that ensures that the energy savings will repay the full cost of the project retrofits. 

Commenters understood that some EE "experts" denigrate the value of these savings guarantees, 

which are legally enforceable and have in fact been enforced hundreds of times. Commenters 

suggested that such denigration demeans the credibility of thousands of government contract 

officers who have signed PC contracts. Commenters stated there is no comparable mechanism in 

ratepayer-funded programs that guarantees that the customer will get the estimated energy 

savings. Commenters also indicated they were not aware of any record in ratepayer-funded 

programs that is comparable to the 20-year history of ESCOs making good on their savings 

guarantees, usually with additional retrofits that true up the savings, or, if that fails, with 

financial compensation to the customer. Commenters believe that this history of enforceable 

savings guarantees should reassure the EPA and state air regulators that PC projects are a reliable 

long term resource. 

Commenters stated it appears that the energy efficiency elements of the proposed Clean Power 

Plan were developed primarily with utility energy efficiency programs in mind, despite the fact 

that energy efficiency investments through performance contracts approximate those made 

through utility programs. Commenters stated that expressly allowing performance contracts to 

be a compliance option in the Clean Power Plan would significantly enhance state options for 

low-cost and rigorously verified GHG reductions, and it would also bring to the effort those 

companies most focused on producing energy efficiency results.

Commenters stated additional guidance is needed for states to feel confident that EPA will 

recognize performance contracting projects and allow them to be included in state plans.

Commenters recommended EPA: acknowledge that existing performance contracting projects 

could provide substantial contribution to 111(d) compliance; provide guidance to enable states to 

include energy savings performance contracting in their plans; clarify how the state plan 

requirement to identify affected entities applies to performance contracting projects; describe 

approvable approaches for aggregation of performance contracting projects; identify approvable 

approaches for key compliance criteria to facilitate inclusion of emission reductions from 

performance contracting projects; identify measurement and verification protocols acceptable for 

determining energy efficiency savings from performance contracting projects; allow avoided 

electricity consumption delivered by performance contracting projects, with proper measurement 

and verification, to count toward 111(d) compliance; provide states with flexibility to take credit 

for emission reductions resulting from performance contracting projects after the CPP was 

proposed and before the interim compliance period begins (2020); resolve the energy efficiency 

penalty created when energy efficiency projects are implemented in electricity importing states; 
242

and support the development and use of single-state and multi-state credit programs and other 

market-based systems. 

Commenters stated the energy efficiency program industry, companies that offer services to 

utilities and other entities and run programs that save energy, is a robust sector that already 

operates to implement existing energy efficiency programs, and provided example services from 

this sector:

1. Energy efficiency portfolio management, Ameren Illinois Utilities contracts with 

Conservation Services Group to manage its portfolio of residential energy efficiency 

programs, including a lighting program, an appliance recycling program, an HVAC 

program, and a multifamily energy efficiency program; 

Energy efficiency portfolio management, American Municipal Power (a non-profit wholesale 

power provider) invested $15 million in an environmental mitigation project and contracted with 

the Vermont Energy Investment Corporation to manage and implement a portfolio of energy 

efficiency programs offered to AMP's member utilities ; and (3) Energy efficiency program 

management, when customers purchase a new refrigerator, Jaco Environmental has worked with 

utilities and local governments in 28 states to remove and safely recycle refrigerators to avoid 

customers continuing to operate the old refrigerator in another area of their home. 

Commenters stated these types of companies either operate or carry out a significant portion of 

today's energy efficiency programs. Commenters stated that electric utilities are responsible for 

89 percent of the total customer-funded electric efficiency investments nationwide , but some 

states, have state government service as program administrators or use independent third-parties 

(such as the Conservation Services Group and the Vermont Energy Investment Corporation) to 

design and manage program portfolios . Commenters noted that for the majority of programs that 

utilities run, a large portion of program implementation, or the delivery of programs, is carried 

out not by the utilities themselves but by third party companies. Commenters noted that this 

private sector efficiency service infrastructure is available to deliver the energy efficiency needed 

by EGUs whether or not states choose to implement or expand energy efficiency programs 

through public service commissions. Commenters indicated that the energy efficiency program 

industry is sufficiently robust to have its own publications such as E Source and Greentech 

Efficiency; conferences such as the biennial ACEEE's Energy Efficiency as a Resource 

Conference; professional organization such as the Association of Energy Service Professionals); 

and in California, a trade association, the California Energy Efficiency Industry Council.

Commenters relayed that large businesses have built or acquired energy efficiency program 

industry businesses. 

Commenters discussed privately-delivered, non-ratepayer funded carbon dioxide emission 

reductions in the residential sector. Commenters asked EPA to consider non-ratepayer funded 

solutions to energy savings. Commenters stated private sector actors have played a driving role 

in developing a market for residential solar energy installations. Commenters stated HPC and EF 

believe that the private sector could play a similar role in residential energy efficiency 

installations if appropriately structured and sized incentives were provided. Commenters stated 

EPA's 111(d) regulation could provide this market by creating a monetary value for the carbon 

dioxide emissions reductions that result from the installation of energy efficiency measures. 
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Commenters stated EPA has permitted energy efficiency to be included in state Clean Air Act 

implementation plans in the past. Commenters stated that during the late 1990s, EPA developed 

guidance along these lines, which a few states followed in their NOx SIPS in that era, however, 

the efficiency retrofit projects developed under that guidance were virtually all in commercial or 

industrial facilities. Commenters stated residential retrofits were not able to compete well in such 

markets, because of transaction costs, lack of aggregation mechanisms, and similar issues. 

Commenters requested that EPA specifically encourage residential retrofits in any private-sector 

credit mechanism provisions it includes in 111(d) guidance. 

In this case, commenters stated the private sector would be represented by for-profit and nonprofit firms that successfully deliver reductions in carbon emissions by taking actions that result 

in the installation of residential energy efficiency measures in the residential sector that would 

not have taken place in the absence of their intervention. Commenters stated these firms might be 

private contractors or firms analogous to the "aggregators" in the solar industry. Commenters 

stated these firms would not necessarily be operating within the context of a ratepayer-funded 

(utility-sponsored) energy efficiency program. However, commenters stated to realize the 

potential of the private market to contribute to the creation of residential energy efficiency 

savings, EPA must:

• Permit states to set up market mechanisms that allow private parties to 

develop and sell energy efficiency projects into such markets;

• Provide specific guidance to allow states to encourage private-sector 

undertaking or catalyzing the installation of residential energy efficiency 

measures;

• Provide details in 111(d) guidance on specifics of crediting and 

enforcement mechanisms and program implementation models that 

would be acceptable from an EPA perspective for purposes of meeting 

compliance requirements; and

• Support the creation of energy efficiency registries to ensure that the 

carbon dioxide emission reductions from energy efficiency measures is 

first registered and then retired (i.e. is not counted twice.) Presumably, 

such a registry will be necessary for the savings that result from 

ratepayer funded programs; we ask that the registry be designed to 

register and retire savings from all recognized sources, not only 

ratepayer-funded programs. 

INDUSTRIAL ENERGY EFFICIENCY

Commenters generally supported inclusion of private sector energy efficiency programs. 

Commenters said that GHG reductions from Industrial EE (IEE) are surplus emissions reductions 

under section 111(d) of the CAA and the EPA should treat IEE-derived GHG reductions in the 

same manner that the EPA proposes to treat GHG reductions created by utility-scale renewable 

energy (RE) generation. Commenters noted that many RE projects were built prior to the EPA's 

proposed CPP was made public, and many more will be built and installed going forward. All 
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installed IEE projects, once operational, will contribute verifiable reductions attributable to 

reduced demand for fossil powered electricity generation and commenters said that there is no 

basis for EPA to treat RE and IEE- related GHG emission reductions differently. 

Commenters said that without limiting state flexibility, the EPA can articulate in the final rule 

and technical support documents what will constitute an approvable pathway for states to include 

available IEE project-related emission reductions in their 111(d) compliance plans, which is 

consistent with the EPA's intent to provide states as much flexibility as possible. Commenters 

added that the EPA can enhance IEE uptake if it clarifies how the state plan requirement to 

identify affected entities applies to IEE resources. Commenters said that to the extent that a state 

has confidence that future IEE projects will be implemented (through supportive policies, 

collaboration with in-state industrial facilities, etc.), the state may include a conservative forecast 

of IEE project-related savings in its plan. Commenters stated that any EE savings or GHG 

reductions documented by IEE projects using appropriate M&V can be used to demonstrate 

compliance with state goals. Commenters said that since the EPA used utility EE programs as the 

basis for establishing BSER, any GHG reductions achieved through IEE can provide states with 

another compliance option that reduces the pressure to meet the standard using other more 

expensive emission reduction measures. For instance, commenters said, a state can use EE 

savings generated through IEE measures to mitigate the need to reduce utilization of coal units or 

construction of new gas powered generation and private sector IEE can also be a contingency or 

corrective measure that makes up shortfalls from other compliance strategies. 

Commenters suggested that the states should view private-sector delivered EE as "purchasable 

compliance" with the 111(d) goals. Commenters said that states or EGUs can "pay for savings," 

i.e., secure access to or use of the GHG emissions reductions delivered by IEE in a number of 

ways: 

• Through traditional ratepayer offerings (prescriptive incentives, custom 

incentives, etc.) 

• Through binding contracts with parties participating in the IEE initiative 

(at a whole-facility level where multiple capital projects and operational 

improvements within a facility can be bundled together) 

• Through the purchase of emission reductions credits in a GHG market 

Commenters added that IEE can serve as an easily implementable EE mechanism in states that 

do not yet have robust ratepayer-based EE programs. Commenters described the energy 

efficiency benefits in more detail and added that these IEE project activities result in 

quantifiable, additional GHG emission reductions that can contribute to 111(d) compliance. 

Should the EPA incorporate methods of accounting for emission reductions from these measures, 

commenters said that these methodologies can be applied appropriately within IEE projects to 

allow GHG benefits to be used by the state for compliance purposes. 

Commenters said that states will be more likely to include IEE projects as part of a state plan if 

the EPA clarifies that GHG emission reductions achieved as a result of private-sector delivered 

IEE with appropriate M&V is allowed to be used for CPP compliance activities. Commenters 
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said that the SEP M&V Protocol for Industry and International Performance Measurement and 

Verification Protocol (IPMVP) Option C are examples of an appropriate M&V protocol that 

establishes the electricity savings and GHG reductions from individual IEE measures as well as 

at the whole-facility level leveraging the EnPI tool. Commenters said that the level of rigor 

provided by an IEE project using such an M&V approach is sufficient to enable GHG emission 

reductions from IEE projects to be considered an appropriate form of CPP compliance. 

Commenters described several other actions that should be taken to facilitate the use of IEE 

resources including the following: 

Clarify approvable approach for key compliance criteria. 

Allow EE savings from IEE projects constructed prior to the 111(d) proposal and 

implementation be eligible to contribute to 111(d) compliance despite the fact that these projects 

were not purpose-built for 111(d) compliance. 

Create incentives for immediate action to reduce emissions. Identify remedies for the 111(d) 

state EE penalty. 

Encourage the use of tradable credits. 

Commenters also described the elements of the elements needed for state programs including the 

following: 

• State 111(d) compliance plan development should include IEE 

• Purchasable compliance, e.g., paying to increase dispatch of natural gasfired generation under a variety of mechanisms 

• State 111(d) progress reports 

• Enforceability 

• Incentives. 

Commenters summarized a report 12, "Assessing the Costs and Benefits of the Superior Energy 

Performance Program," Lawrence Berkley National Laboratory (LBNL) which included a 

methodology to quantify the costs and benefits of participation in the SEP program. Commenters 

stated that if the adoption rate of ISO 50001 (currently in its third year) mirrors the adoption 

rates of ISO 9001 and ISO 14001, it is expected that the number of companies that will adopt 

ISO 50001 will increase rapidly in the next 5-8 years). Commenters stated that if IEE resources 

are adopted as part of state 111(d) plans and receive financial incentives and other policy support 

from states, it is likely that many ISO 50001 facilities will seek SEP certification. Commenters 

said that the potential savings from IEE is significant, and the SEP performance improvements 

can be converted into absolute kWh savings. Commenters noted that the EnPI tool can break out 

plant energy performance and energy use reduction by fuel/energy source and it also includes a 

GHG calculator that computes reductions in GHG emissions based on the validated energy 

savings. Therefore, commenters concluded, the potential EE savings from the industrial sector 
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can play a very significant role in helping states comply with section 111(d) goals. Commenters 

said that examples of additional benefits include substantial reductions in GHG emissions from 

fossil fuel use at facilities, avoiding or deferring costly transmission and distribution upgrades, 

avoiding the electricity losses associated with transmission and distribution, comfort, health, 

productivity, energy security, limiting water use associated with electricity generation, lowering 

baseload and peak demand, and reducing the need for additional generation and transmission 

assets. Commenters added that IEE projects, in particular, benefit manufacturers by improving 

quality, reducing waste, increasing productivity and competitiveness, and hedging against energy 

price spikes and volatility. 

Commenters added that in Georgia and many other states, industrial customers are not part of 

commission certified EE programs and, due to the fact that many manufacturers compete with 

each other in a global market, many do not want to pay into certified DSM programs that will 

benefit their competitors. Because industrial customers implement EE measures on their own, 

commenters stated that the industrial sector represents a significant amount of savings 

opportunity, and the EPA should encourage states to find ways to incorporate these savings into 

state plans even if they are not part of a certified DSM program. Commenters agreed that 

industrial energy efficiency programs, both rate-payer programs and non-utility programs should 

be included in state plans, if those projects are using a tool that can measure and verify energy 

savings. Guaranteed Energy Savings Performance Contracting (GESPC). Commenters stated that 

Georgia's voters approved Guaranteed Energy Savings Performance Contracting (GESPC) for 

state agencies in a 2010 statewide referendum. Commenters stated the resulting program will 

save a significant amount of energy and money for Georgia's taxpayers, and it avoids a 

significant amount of carbon. By allowing GESPCs to count towards meeting the CPP, 

commenters stated that the EPA is encouraging states to grow programs that benefit both the 

environment and taxpayers.

Commenters stated that GESPCs are especially relevant because they are quantifiable and 

verifiable. Commenters said that energy services companies (ESCOs) guarantee the savings and 

require annual evaluation, measurement and verification (EM&V). Because the savings are 

guaranteed and projects represent financial risk to the ESCO, commenters noted that the EM&V 

that goes into the projects is significant. Commenters stated that the EPA should work closely 

with states to determine how GESPCs can meet the goals of the CPP and ensure full credit for 

their related emissions reductions. Commenters noted that states (Virginia, Kentucky and 

Georgia) are already starting the process of evaluating how GESPCs can and should be counted 

for CPP compliance. Commenters added that the EPA needs to also recognize that local 

governments represent a significant opportunity for GESPC savings, and the EPA should allow 

for flexible and innovative systems that allow states to count GESPCs in the local government 

sector, in addition to state government. 

Commenters agreed that ESPC projects provide economic and energy benefits along with costeffective emission reductions. Commenters were concerned that states will hesitate to pursue 

these options without clear EPA guidance regarding approvable methods for incorporating ESPC 

measures into CPP compliance plans. 

PROGRAMS BY WHOLESALE ELECTRICITY PROVIDERS
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Commenters stated that their facility, which is the wholesale electricity provider for over 99 

percent of Tennessee, offers the most substantial utility EE programming within the state through 

its EnergyRight Solutions programs. Commenters stated several EE programs targeted towards 

industrial, commercial, and residential customers are offered throughout their multi-state service 

area through their EnergyRight Solutions umbrella. Commenters stated these include programs 

such as low-interest, fixed-rate financing and contractor assistance for heat pumps, in-home 

energy evaluations, educational resources, rebates for energy-efficient equipment and models, 

and access to their-screened and -endorsed professional and contractor network. Commenters 

stated importantly, they are not a vertically integrated utility, and that with the exception of 

direct serve customers, their programs are typically available to local power companies (LPCs), 

which serve as their distributors. Commenters stated however, participation in EnergyRight 

Solutions programs is not required; it is optional. Commenters stated those LPCs who have opted 

to participate in and offer EnergyRight Solutions programs have established a more robust EE 

measure infrastructure than those choosing not to participate. Commenters stated however, given 

the sheer number and diversity of LPCs within Tennessee, the type and quality of end-user EE 

metrics and reporting is determined by their needs and the individual LPCs and may or may not 

be consistent across programs and across LPCs. 

Commenters stated Strategic Energy Management programs that follow the template laid out by 

the Consortium for Energy Efficiency should be credited to state plans. Commenters stated these 

programs can be operated by utilities, governments, or industrial companies; the savings can be 

calculated using the methods of ISO Standards 50001 and verified by third-party audits as 

required by DOE's Superior Energy Performance program, and savings can be from behavior and 

capital investments and process changes. Commenters stated that as these programs require a 

commitment by a company to improve its energy performance by a fixed target every year, the 

savings can compound strongly over 10 years. 

BEHAVIORAL PROGRAMS

Commenters stated that EPA should define EE broadly to include all programs that promote 

behavioral changes by energy consumers should be considered. Commenters stated that the 

MWh saved as a result of behavioral changes should count toward compliance with the CPP. 

Commenters stated that some of their owner-member distribution companies have implemented 

prepay programs. Commenters noted that customer usage under these prepay programs is 

regularly reduced by 12 percent as a result more energy consumption information provided to 

customers causing them being more disciplined and frugal of their use of energy. Commenters 

stated that MWh from prepay programs and other programs that promote customers using energy 

more responsibly should count for compliance. Commenters stated that EPA is penalizing 

utilities and states that implemented EE and demand side management programs before the 2012 

baseline. Commenters stated that the cost of EE programs increase exponentially once the most 

effective programs are in place. Commenters stated that this implies that utilities and states that 

have implemented EE programs before the baseline are now left to implement more expensive 

programs if they want to match the EPA assumptions for EE. 

Commenters stated EPA must allow inclusion of all EE programs and initiatives. Over the past 

several years, commenter has developed and grown a portfolio of EE programs that include more 

than twenty program offerings that fit into multiple categories. Commenters stated their portfolio 
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of programs is designed to allow all customers to participate in EE programs to help manage 

energy usage and costs. Through the refinement of Salt River Project's SPP in 2011, commenter 

stated EE offerings were expanded to include behavioral programs and market transformation 

initiatives, such as SRP's Energy Scorecard, building energy codes, and appliance standards.

Commenters stated the intent of these additions is to capitalize on new, cost-effective program 

alternatives and position SRP to meet more aggressive long-term EE goals. Commenters stated 

for example, M-Power is a prepay program that uses in-home display monitors, smart cards, and 

a payment kiosk network to put consumers in control of many aspects of their energy use, 

payments, and budget. Commenters stated as a result, analysis indicates M-Power customers, on 

average, reduce their annual energy consumption by 12%. Commenters stated they are able to 

realize these reductions by: Monitoring electricity usage with real-time information; managing 

the cost of consumption to meet personal needs; and using in-home displays that provide positive 

reinforcement and immediate feedback about energy usage. Commenters stated M-Power is 

unique in that few, if any, other utilities have similar participation levels and savings effects from 

behavioral programs of this type. Commenters stated roughly 40% of SRP's reported annual 

savings is currently attributed to the behavioral conservation impact of customers on M-Power. 

Due to its significant contribution to SRP's EE portfolio and its extreme cost-effectiveness, 

commenters stated programs like M-Power must be recognized as legitimate options. 

FEDERAL AND STATE CODES

Commenters stated that additionally, federal and state codes and standards (including appliances) 

should be considered in state compliance plans as they would increase the opportunities for EE.

Commenters stated that together with appliance efficiency standards, building codes and/or 

standards that are well designed, implemented and enforced can lead to significant energy 

savings at the time of building construction or total renovation, compared to past or prior year 

practices. Commenters stated that new building codes and appliance efficiency standards have 

the potential to reduce electricity consumption dramatically. Accordingly, commenters stated 

that the final rule should be explicit that states can include reductions from codes and standards 

in compliance plans.

Commenters stated that it is very important for EPA to encourage states to allow for energy 

efficiency (EE) savings from a wide variety of programs, including those outside of typical, 

certified demand side management (DSM) programs. Commenters stated that the draft CPP 

needs further clarification beyond acceptable EE programs.

Commenters stated that building energy codes are a significant way for states to reduce energy 

consumption and emissions, but noted the EPA's concern that building energy codes don't have 

the same track record of EM&V as typical utility DSM programs. Commenters said that it is 

important that the EPA not use the lack of current standardized EM&V protocols for building 

energy codes as a reason to impede states' use of this tool in their compliance plans. Instead, 

commenters said, the EPA should work with states to develop fair and reasonable methods to 

account for building energy code improvements in their state implementation plans. Commenters 

agreed that building code programs should be eligible for compliance with the rule to the extent 

they comply with upgraded EM&V protocols. Commenters discussed an overall approach to 

improvements or changes to many sectors of New York City's infrastructure as part of a 
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comprehensive $20 billion action plan consisting of 257 initiatives for rebuilding the 

communities impacted by Sandy and increasing the resiliency of infrastructure, neighborhoods, 

and buildings citywide. Commenters said that it is possible to design a building today using 

modern building science that will reduce the energy load by about 90 percent. In other words, 

commenters said, to heat and cool your house, it will take about 10 percent of what a code-built 

home would require. Commenters suggested that by coupling energy efficiency at various levels 

with various resources available to produce the energy and actually there may not be any need 

for regulation of future coal plants because we probably don't need what the industry is 

projecting. 

Commenters stated that for the baselines for energy codes and standards in Block 4, States 

should be given credit for actions that go beyond federal baselines. Commenters stated baselines 

for appliance standards should be current federal standards. Commenters stated actions for 

products not covered by federal standards should receive emissions credits. Commenters stated a 

letter dated December 1, 2009 published by many of their sister organizations stated:

"By accepting State Energy Program funding and submitting letters assuring the Department of 

Energy that their states would comply with the terms of Section 410, all 50 states have committed 

to do three things:

• Adopt a residential building energy code that meets or exceeds the 2009 

International Energy Conservation Code (IECC);

• Adopt a commercial building energy code that meets or exceeds the 

ANSI/American Society of Heating, Refrigerating and Air-Conditioning 

Engineers (ASHRAE)/IESNA Standard 90.1-2007; and

• Develop and implement a plan, including active training and 

enforcement provisions, to achieve 90 percent compliance with the 

target codes by 2017, including measuringcurrent compliance each 

year."

Commenters encouraged EPA to obtain the maximum environmental benefit for building energy 

efficiency programs. Commenters stated that buildings account for 74 % of electricity use, and 

the most cost effective way to reduce CO2 emissions from the power sector is through effective 

building codes. Commenters stated that more work was needed on building codes and EM&V 

methods for evaluating the benefits of the programs. Commenters cautioned about not making 

the EM&V methods for building efficiency more rigorous than for other energy efficiency 

measures such that building efficiency is too burdensome and costly to use in the state plans.

Commenters urged EPA to rely on protocols already developed by some states (e.g., California), 

NEEP, and Pacific Northwest National laboratory, and DOE's Uniform Methods Project. By 

developing reasonable standards, commenters stated that the rule would encourage better 

building codes and an expanded universe of energy efficiency activities covered by building 

permits. 

Commenters stressed the significant potential for energy savings from existing buildings and 

stated that effective building energy codes are available today from ANSI and the International 
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Energy Conservation Code. Commenters stated that even improved enforcement of currently 

adopted codes would create significant energy savings. Commenters stated that EPA might be 

discouraging the use of building energy codes as a compliance measure because the preamble 

states that EM&V are less well established for building energy codes. Commenters asked EPA to 

clarify that the status of current EM&V methods will not preclude approval of measures for 

building code adoption and enforcement in state plans.

REFRIGERATOR REBATE PROGRAMS

Commenters stated that they have modeled likely reductions in energy consumption and GHG 

emissions resulting from linked recycling and replacement rebates using data and methodologies 

developed by DOE and EPA, supplemented by extensive data from government and industry 

sources. Commenters stated this modeling was based on a prototype ER program conducted over 

a five year period with assumed rebates of $100 per unit. Commenters noted that the appendix to 

their comments describes their analysis in detail. Commenters stated that their modeling projects 

the following dramatic benefits: 

• Assuming 3 million rebates per year over five years, total energy savings 

would be 52,400 GWh. 

• This would represent avoided GHG emissions of 36.1 million metric 

tons carbon equivalent (MMtCO2Eq), or approximately 1.8 percent of 

annual GHG emissions from power plants according to the EPA 2012 

Inventory of GHG Emissions and Sinks. 

• The cost per kWh saved would be 2.5 cents/kWh. 

• Total energy savings to consumers would be $6.8 billion, greatly 

exceeding the $1.5 billion costs of the rebates. 

• The energy savings achieved by the program over five years would 

represent a significant portion of the cumulative EE targets that EPA has 

used to calculate state goals. 

Commenters stated these projections confirm that large-scale implementation of refrigerator 

replacement programs on their model will be a highly cost-effective tool for meeting section 

111(d) goals and will deliver sizable GHG reductions that utilities and states can credit toward 

section 111(d) compliance. Commenters stated that extending replacement rebate programs to 

other appliance categories will multiply these benefits. 

While the main driver for ER programs would be achievement of energy savings and GHG 

reductions, commenters indicated that other benefits will be realized as well. First, commenters 

said consumers would see declines in their electricity bills that would increase their purchasing 

power. Second, commenters said reductions in power generation from lower electricity 

consumption would translate into declining emissions of conventional pollutants and thus lower 

ambient levels of particulate matter (PM), nitrogen oxides (NOx) and sulfur dioxide (SO2), 

which are associated with known health effects and result in medical costs from mortality and 
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disease. As described in the appendix, commenters' analysis shows that the program would 

reduce SO2 and NOx emissions by 9,620 million pounds and 17.8 million pounds over five 

years, resulting in avoided adverse health effects valued at $212 million-$480 million. Finally, 

commenters said, because of the increased consumer demand for new appliances, the program 

will boost manufacturing output and retail activity, with accompanying growth in jobs.

BUILDING EFFICIENCY PROGRAMS

Commenters supported allowing credit for increased building energy efficiency through 

the improvement and adoption of energy codes and the enforcement of energy codes.

Commenters supported the use of high efficiency appliances, building efficiency improvements, 

and energy savings accomplished through energy performance contracts under which the savings 

are measured and documented. Commenters advocated that Federal appliance and equipment 

energy efficiency standards should not be included in state plans, but if states request to include 

them in state plans, they will need to work with EPA to tighten their rate or mass-based targets 

accordingly. Commenters stated that EPA's proposed rule does not include federal efficiency 

standards in setting state targets, and because federal standards are outside of the jurisdiction of 

states and are not enforceable by states, they should not be included in targets nor used as a 

means of compliance. Commenters stated that EPA should clarify how energy efficiency 

measures by federal entities (i.e. power distribution authorities like the Bonneville Power 

Administration) can be incorporated in state plans.

Commenters stated they have supported the development and adoption of building energy codes 

throughout its history. Commenters stated that confirmed by study after study, the energy codes 

and appliance standards are the most cost-effective way to achieve CO2 reductions. Commenters 

stated that in fact, the U.S. DOE uses something called the "learning curve" to calculate how 

much money is saved by consumers when codes lead to less expensive technologies and methods 

to meet the code requirements. Commenters stated extremely cost-effective energy savings are 

available through energy codes. Commenters recommended that State and city adoptions of the 

most recent model energy codes, state adoptions of the highest available appliance standards not 

pre-empted by federal law, and increased compliance levels should all qualify as a BSER. 

Commenters stated Building Block 4 savings levels should be adjusted to reflect the additional 

carbon reductions that can be achieved through codes and standards. 

Commenters stated that they have worked with numerous states and cities to develop and 

implement stretch codes and utility code programs in support of stretch codes. Commenters 

stated both of these efforts have occurred in states that far exceed the requirements of the ARRA,

and are leading to faster adoption of the most current model energy codes. Commenters 

recommended this is within the capacity of each of the 50 states, and their supporting utilities, to 

achieve this higher level of savings from codes, and that successful adoption of stretch codes and 

utility code programs should receive full emissions credits from these programs. 

Commenters stated utilities can play an important role in the development, adoption, and 

enforcement of building energy codes. Commenters indicated there is history of utility 

involvement in every stage of the building code process with established mechanisms for 

crediting energy savings from this activity. Specifically, utilities can: 
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1. participate in the code development process to strengthen the efficiency of building 

energy codes; 

2. provide technical assistance to state and local agencies in both the adoption and 

implementation of building codes; 

3. directly advocate for state and local adoption of codes;

4. conduct studies to assess compliance; 

5. train building industry professionals to improve compliance; 

6. directly support third-party compliance.

Commenters stated that to achieve energy savings, adopted codes must be enforced and energy 

efficiency measures implemented in the field. Commenters stated that studies of compliance in 

the U.S. have found that compliance is significantly less than 100 percent: 2013 Institute for 

Market Transformation (IMT) study that surveyed existing compliance studies for 45 states and 

estimated energy savings from increased compliance found that compliance rates ranged from 

zero compliance to over 90 percent compliance. Commenters stated the compliance studies done 

to date and surveyed in the IMT report do not use consistent methodologies and therefore 

findings for compliance rates across states are not necessarily comparable; in 2010, DOE 

published a methodology for determining compliance rates which should alleviate these 

inconsistencies for future compliance studies . Commenters also noted that the IMT study 

assessed potential [cost] savings from increasing compliance; based on a middle scenario that 

conservatively assumed 50 percent existing compliance rate, and found that every dollar spent to 

improve compliance yields $6 in energy savings.

Commenters stated EPA should credit savings from state programs that advance building code 

compliance and enforcement. Commenters recommended that EPA work with states on savings 

measurement methodology for building codes. Commenters further recommended EPA work 

with the U.S. DOE's Building Energy Codes Program, which is currently developing 

methodologies to advance building code compliance and savings verification. In Oregon, 

however, commenters stated robust EM&V methodology is in place to demonstrate incremental 

savings from building code compliance, and EPA should allow Oregon to credit resulting energy 

savings in its state compliance plan. 

Commenters stated several states have undertaken work in recent years to estimate energy 

savings from code compliance resulting from activities undertaken by utilities and other 

efficiency program administrators. Commenters has published a report on the topic of attributing 

savings from code support activity by utilities that EPA should use as reference in understanding 

various methodologies available to assess savings from code compliance. Commenters stated 

following that report's publication, the states of Rhode Island and Massachusetts initiated new 

programs for attributing savings from code activities undertaken by utility programs, which

provides further examples of methods for measuring and verifying savings from building energy 

code compliance.

NON-AFFECTED COMBINED HEAT AND POWER (CHP)
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Commenters focused on non-affected combined heat and power (CHP) projects, stating that, like 

other energy efficiency investments, non-affected CHP reduces demand from affected EGUs and 

therefore emissions from affected EGUs. As such, the methodology used for crediting emission 

reductions caused by new and uprated non-affected CHP should be equivalent to the 

methodology used for crediting other end-use energy efficiency measures. Commenters did not 

take a position on which of the potential methodologies EPA should take in calculating the 

emission reduction impacts of energy savings, but urged EPA to provide additional and clearer 

guidance on approvable methodologies in its final Clean Power Plan in order to provide greater 

certainty for the potential regulatory benefits of new and uprated non-affected CHP.

Commenters questioned the rationale for crediting all of the electricity produced by CHP 

systems, but only 75 percent of their useful thermal output, as found in the "net energy output" 

definition. Commenters believed that in an "output based regulation" which EPA has agreed is 

appropriate for CHP systems, a full 100 percent crediting for electricity and thermal output is 

required. Commenters also expressed concerns with the possibility of EPA only considering 

emissions displaced from EGUs, and therefore only considering the electricity production of 

CHP systems. Commenters argued that this approach would artificially and unfairly discount the 

energy savings produced by unaffected CHP Systems because it would disregard the thermal 

energy produced simultaneously with the electric energy. Commenters stated this would then 

penalize CHP systems by attributing any additional gas that may be used to produce thermal 

product. Commenters stated that, if this electricity-only approach is taken for CHP, then EPA 

should credit the 100% of the electricity production of the CHP System, without discounting for 

the additional gas usage on-site.

Commenters requested that EPA clarify the use of CHP and waste heat power (WHP) for 

compliance strategies under building blocks 3 and 4. Commenters stated that natural gas fired 

CHP units provide end-use energy efficiency carbon emission reductions and could therefore be 

a strategy for states under building block four and even CHP units below 25 MW should be 

eligible as part of state compliance strategies and given credits. Commenters stated that WHP 

and biofuel-fired CHP units are zero-carbon generating resources and that these types of units 

that already meet air quality requirements should qualify as non-hydro renewable resources 

under building block three.

Commenters commended EPA for including a line loss credit for CHP systems, but suggested 

some revisions. Commenters suggested that, to reflect the actual energy benefit of distributed 

generation, EPA should provide a 7.5% credit to distributed generation. Commenters stated that 

additionally, EPA should consider increasing the credit for distributed baseload generation 

operating during peak hours. Commenters believed that this would encourage the deployment of 

CHP systems that can provide reliable peak baseload power to off-set baseload coal plant 

closings. Commenters also recommended that the final rule should make it clear that a similar 

line-loss credit should be credited to generation from unaffected units.

TRANSPORTATION SECTOR

Commenters urged EPA to provide a mechanism to ensure that states are not penalized by efforts 

to reduce emissions from other sectors, particularly the transportation sector. Commenters noted 

that, as the electric sector decarbonizes and produces cleaner energy, electrification of more 
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carbon-intensive sectors is an effective and economic action to reduce all GHGs. Commenters 

understood that compliance for out-of-sector reductions is challenging, but argued that they 

should not be excluded if reductions can be quantified, verified and repeated. Commenters 

recommended that state plans do not dis-incentivize clean electrification. As an example, 

commenters stated that by failing to give compliance margin to states that support electric 

vehicles, EPA is discouraging the production and implementation of electric technologies that 

could play a significant role in EPA's overarching goal of CO2 reduction.

WATER AND WASTEWATER SECTOR

Commenters encouraged EPA to clarify that states should be able to account for RE and EE 

measures taken post-2012 across industries, including specifically the water and wastewater 

industry, as they develop their state plans. In doing so, commenters believed that states would 

have more options to meet the goals of the proposed rule and would have the necessary guidance 

as to what measures are appropriate for them to consider in their state plans. Commenters noted 

that pump efficiency and refurbishing efforts in the water and wastewater industry can produce 

significant energy and carbon emission savings, and that water and wastewater EE and RE 

efforts could serve dual purposes in state plans of both reducing GHG emissions, while also 

helping close the funding gap (through cost savings) that many water and wastewater utilities 

face nationwide.

Commenters stated that they and others in the industry are currently developing and testing many 

other promising technologies. Commenters stated that incentives to the water industry which can 

be provided through the state plans will help to foster such innovation. Commenters stated that 

for example, American Water has played a leading role in each of the following: using acoustic 

monitoring for more comprehensive and efficient leak detection in distribution system piping; 

optimizing pumping plant energy efficiency and performance by employing advanced analytic 

equipment and techniques for real-time pump power monitoring; reducing leakage and 

corresponding electricity use for pumps by developing advanced pressure management systems 

that reduce pressure based on consumer demand; using advanced treatment technologies, aquifer 

storage and recovery, and other innovative water reuse solutions for areas with water supply 

limitations; and recovering energy from biogases as a renewable energy source and optimizing 

treatment of wastewater using advanced technologies. Commenters stated that they are a leader 

in leveraging technology and innovation for improving water and energy efficiency. Commenters 

stated that as state agencies develop policies and incentive programs to improve efficiencies, 

opportunities to deploy emerging technology should be encouraged and flexibility provided to 

spur innovation. 

Commenters noted the EPA spends significant time in both the preamble to the proposed rule 

and in the associated Technical Support Document stressing the importance of quantification, 

monitoring, and verification of demand-side energy efficiency and renewable energy programs. 

Commenters stated that as large energy consumers who are already regulated by the states, water 

utilities such as American Water alleviate enforceability and monitoring concerns. Commenters 

stated their recent history of energy efficiency and renewable energy measures provide 

compelling examples of success for policymakers and a viable template for states. 
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As part of building block 4, commenters believed that water sector EE projects (post 2012) 

should be eligible to count towards state goals, provided the necessary monitoring and 

verification has been completed. Commenters stated the final rule should indicate that EE 

projects completed by non-electric organizations can be counted towards the overall emissions 

reductions. Commenters stated this would allow for states and the electric sector to run incentive 

programs to help foster improvements in the water sector and in other major electricity 

consumers. Commenters stated because water infrastructure is generally long lived, there are 

many pumps, motors, treatment facilities, pipes, and others systems within the water sector that 

are at several decades old. Commenters stated that in many cases, these systems are much less 

energy efficient than their modern equivalents. Commenters stated additionally, substantial 

amounts (in many cases, 15 to 20 percent or more) of treated drinking water is lost to distribution 

system leaks in many water utilities. Commenters stated every gallon of water that does not 

make it to customers means that an additional gallon must be treated and pumped to replace it, 

adding to the sector's overall electricity consumption and associated greenhouse gas emissions. 

Commenters stated incentive programs to assist the water sector with the cost of the capital 

and/or ongoing monitoring and verification costs could help to accelerate the replacement of 

aging, less efficient infrastructure where it is appropriate to do so, and in some instances increase 

both water and energy efficiency simultaneously with water loss and leak control. Commenters 

stated there are also system optimization processes and end-user water efficiency programs that 

can help to reduce electricity consumption if further advanced through incentive funding. 

Commenters stated water and wastewater utilities are particularly well suited to participating in 

EE programs. Commenters stated these organizations are ideal EE/RE demand side candidates 

because they have the ability to measure and verify actual energy savings and are professionally 

staffed, operated continuously, and present in almost every community nationwide. Commenters 

stated sourcing and conveying water, treating water to potable standards, distributing drinking

water to the public, collecting wastewater, and treating wastewater for reuse or discharge are 

inherently energy intensive processes. Commenters stated there is considerable variability of the 

embodied energy within water or treated wastewater (the energy required to produce and 

deliver/collect it) based upon source, treatment, distribution, and collection factors. Commenters 

stated there are combinations of both relatively standard and straightforward efficiency upgrades 

(e.g., swapping out pumps or fixing leaks) as well as larger custom efficiency solutions (e.g., 

instituting a system optimization program or installing new energy recapture equipment). 

Commenters stated both types of upgrades within the water sector should be eligible for state or 

ratepayer funded voluntary efficiency programs, as well as any federal assistance or technical 

support programs. Commenters stated EPA should make sure that states are aware of these 

opportunities, and Commenters encouraged EPA to mention them in the final rule, in guidance, 

and in conversation with the states. 

Commenters stated that the water sector will need a financial incentive in order to comply with 

the great increase in RE/EE programs utilizing water sources. Commenters recommended $180 

million, equal to 1.8% of the $10 billion increase in EE/RE spending anticipated by the EPA. 

Commenters stated this number comes from the percentage of total U.S. electricity consumption 

attributed to water utilities (1.8%). Commenters also stated that numerous projects are likely to 

be both capital intensive and require ongoing costs to conduct the necessary monitoring and 

verification of efficiency gains.
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Commenters asked EPA to clarify in the final rule that measurable renewable energy and 

demand-side energy efficiency measures by drinking water utilities be allowed under the Clean 

Air Act Section 111(d) state plans; however, commenters explained, EPA should also be clear 

that CPP compliance decisions should not supersede water utility decisions on how to best 

achieve water supply reliability, operational goals and compliance with Safe Drinking Water Act 

(SDWA) regulatory mandates. Commenters believed that the day-to-day operational and 

planning decisions on how to best achieve water supply reliability, public health protection goals 

and regulatory mandates should be left entirely to the discretion of the drinking water utility, and 

no entity should be granted the ability to mandate specific actions or goals for drinking water 

utilities under the CPP. Commenters remarked there is certainly potential for significant energy 

savings in the water sector from drinking water utilities and end users, but specific projects or 

goals should only be undertaken on a voluntary basis within the context of local operational 

necessities. Commenters offered that if a utility opts to participate in a CPP, then meaningful 

incentives should be provided for drinking water utilities to implement energy efficiency and 

renewable energy measures where feasible and practical from an operational standpoint -

measures such as those promoted by EPA in reports such as "Ensuring a Sustainable Future: An 

Energy Management Guidebook for Water and Wastewater Utilities" (January 2008).

BUILDING ENERGY LABELING AND BUILDING PERFORMANCE

Commenters stated that programs that focus on building energy labeling, benchmarking, 

disclosure, energy audits, commissioning, retro-commissioning, metering, sub-metering, and 

related measures will help close the gap between designed and actual performance, leading to 

increased energy savings and reduced emissions. Commenters noted that while comprehensive 

EM&V of measures such as building energy labeling and disclosure are less available, there are 

indications of their success. Commenters noted in particular a case study of ASHRAE's Building 

Energy Quotient (BEQ) Building Energy Labeling Program. Commenters encouraged EPA to 

issue specific guidance clarifying that building energy labeling, benchmarking, disclosure, 

energy audits, commissioning, retro-commissioning, metering, sub-metering, and related 

measures may all be included in state emission-reduction plans, and to publish a list of preapproved measures for state plans that includes these items. In other statements, commenters also 

stated that building professionals who participate in training and obtain certifications result in 

buildings that are designed to and perform at higher levels, saving energy and reducing 

emissions. Consequently, commenters recommended that EPA issue guidance clarifying that 

workforce training and professional certification programs may be included as an emissionsreduction strategy in state plans.

Commenters requested that advanced energy codes should be included as an important way to 

achieve energy savings. Commenters noted that many of these enhancements can also last well 

longer than 10 years. As an example, the commenters stated that passive energy efficiency 

improvements to homes and building envelopes, like insulation or air ceiling, will last for the life 

of the building and with little or no maintenance.

PRINTING INDUSTRY

Commenters urged EPA to allow the printing industry the opportunity to create trade-able 

demand-side energy savings based on per-unit of production energy use reductions. Commenters 
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noted that the American commercial printing industry is likely to face tremendous impacts under 

the CPP. Commenters explained that the printing industry is very energy intensive and has 

virtually no ability to outsource its more energy-intensive operations. Because of this and in 

order to promote energy efficiency in the commercial printing industry and many others, 

commenters requested that EPA allow companies the ability to generate demand-side savings by 

reducing their use of energy and associated carbon footprint per page produced. Commenters 

believed that this would allow printing companies to attempt to grow their operations and, 

therefore, American job opportunities while contributing to producing overall carbon emissions 

and mitigating some of the significant costs they will face under the CPP.

RENEWABLE ENERGY FROM INDIVIDUAL CUSTOMERS

Commenters suggested that EPA afford a method for utilities which receive and manage 

renewable power from individual customers such as from solar systems on individual homes 

should be afforded a method for being credited with the associated emission reductions.

GROUND SOURCE HEAT PUMPS

Commenters noted that they are working on a potentially relevant methodology for quantifying 

ground source heat pumps (GSHPs) renewable components in heating and cooling (Building 

Block 3) and an acceptable baseline method of quantifying the avoided generation associated in 

GSHP and waste energy recovery (WER) (Building Block 4). Commenters further stated that 

once quantified into relevant energy units, avoided generation and renewable components can be 

converted into avoided emissions by the relevant state entity and reported as either kWh added to 

the denominator of the Proposed Rule metric (#CO2 /kWh) or emissions subtracted from the 

numerator of the metric. Commenters stated that GSHPs, with their feature of around the clock 

reliability unaffected by the weather, help reduce utility peak loads, which in some cases may 

mean avoiding bringing on-line generation capacity with higher CO2 emission levels.

Commenters urged EPA to consider these features should develop policies that incorporate 

GSHPs into the overall energy framework for the nation. Also commenters noted the work being 

done by ASHRAE and suggested that EPA contact ASHRAE and incorporate their work into 

EPA's guidance for state plans.

WASTE TO ENERGY

Commenters requested that EPA should clarify in guidance that states retain discretion to count 

all waste-to-energy (WTE)-produced electricity - from biogenic MSW as well as anthropogenic 

MSW - toward the renewable energy component of their compliance plans. Therefore, 

commenters stated one MWh of electricity produced by a WTE facility must equal one MWh of 

compliance towards the state's carbon intensity reduction requirements. Commenters noted the 

costs of operating WTE are higher than landfilling, putting WTE at a competitive disadvantage.

Commenters stated a state's decision to include all WTE-produced electricity as renewable in its 

section 111(d) compliance plan could tip the balance in favor of continued WTE operation and 

preserving WTE technology's considerable carbon mitigation benefit. Commenters concluded 

that the requested clarification will also ensure that the final section 111(d) regulations are 

consistent with the broad array of state and federal laws that recognize all WTE-produced 

electricity as renewable energy. Commenters also noted that because WTE prevents the 
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generation of methane from waste otherwise destined for landfills, EPA has concluded that every 

ton of waste managed at a WTE facility actually reduces overall GHG emissions by a ton of 

carbon dioxide equivalents, largely as methane.

LOW INCOME EE PROGRAMS

Commenters stated the Wisconsin Focus On Energy program is just one delivery system for 

energy efficiency achievement and we should take advantage of others. Commenters stated some 

EE programs, such as certain behavior programs, lend themselves better to being run by the 

utilities themselves and we will work with the PSC and utilities to determine the most 

appropriate role for utility-run programs in Wisconsin. Commenters stated in addition, there are 

a number of opportunities for the state to increase electric efficiency that are currently being 

missed. Commenters stated a great example is the state building codes which have not been 

updated in many years. Commenters stated Wisconsin's current codes are similar to the 2009 

vintage of the International Energy Conservation Code. Commenters stated most states have 

adopted the 2012 version of that code and the 2015 version is, or will soon be, available. 

Commenters stated Wisconsin, once a building code leader, has fallen behind. Commenters 

stated EPA should provide more guidance on how energy efficiency programs run by the state, 

particularly market transformation programs, including building code adoption and enforcement, 

and efficiency standards for appliances and equipment should be structured to allow them to be 

part of a state's compliance plan. Commenters stated EPA should pay especially close attention 

to how low-income weatherization programs and other efficiency programs aimed at low-income 

communities can be included in state implementation plans. Commenters stated the final rule 

should create a strong incentive to increase investments in low-income efficiency program to 

minimize the extent to which low-income residents feel economic impacts resulting from the 

rule. 

Comment 9: Comments stating that the EPA should not limit the types of EE measures that 

count towards EE savings to only "well-established programs."

Response 9: The final rule allows the use of a wide range of EE measures, provided the 

measures meet the general and specific eligibility requirements for resources used to adjust a 

CO2 emission rate, described in section VIII.K.1 of the final rule preamble of the CPP. The 

measures must also meet the eligibility requirements and provisions related to demand-side EE 

programs and projects and the requirements and criteria related to proper quantification and 

verification of MWhs from demand-side EE savings, as described in section VIII.K.3 of the final 

rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated that in the Proposed Rule, EPA states that it does not intend to limit the types 

of demand-side EE measures and programs that can be included in a state plan provided that 

supporting evaluation, measurement, and verification (EM&V) is rigorous, complete, and 

consistent with EPA requirements and guidance established for moderately or well-established 

evaluation approaches. Commenters stated according to EPA classifications, most of SRP's EE 

programs appear to fall into the moderately or well-established categories with the exception of 
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the M-Power and Energy Scorecard behavioral programs. Commenters stated limiting eligible 

EE measures to a pre-defined list of well-understood program types would potentially eliminate 

significant savings attributable to SRP's current programs and would hamper future program 

growth strategies. Commenters stated as such, EPA must not exclude these types of programs. 

In addition to including all existing programs and practices, commenters stated EPA must 

establish an easy, straightforward, and timely method states can use to modify existing EE 

programs and add new programs to its state plan without relying on EPA approval of these 

programs before they can be implemented. Commenters stated otherwise, adoption of new 

technologies, measures, and programs will be constrained and could result in a state's inability to 

utilize EE programs to meet its CO2 reduction requirements. Commenters stated this flexibility 

will be especially important as the existing EE programs are more fully subscribed in future 

years. 

California utilities request that EPA not limit the types of EE measures that count toward EE 

savings to only well-established programs.

Commenters stated EPA should include energy efficiency opportunities such as building codes, 

state appliance standards, market transformation, transmission and distribution, voltage 

optimization, and combined heat and power as acceptable tools for delivering energy savings. 

Commenters stated EPA expresses openness to including these non-utility program savings 

opportunities if they can be adequately measured and verified (M&V). Commenters stated these 

savings markets are intrinsic to the Northwest's efficiency portfolio and the Regional Technical 

Forum has M&V protocols in place that EPA should consider. Commenters stated in fact, the 

Northwest Power and Conservation Council and Bonneville Power Administration recently 

determined that by 2029 federal efficiency standards will save the Northwest almost 800 aMW 

(http://www.nwcouncil.org/media/7094803/Appliance-?Standards-?slides-?for-?review.pdf). 

Commenters stated given the strong history of verification of these non-utility savings in the 

Northwest, EPA should be clear that all these available energy efficiency opportunities are 

acceptable for compliance under the rule. Commenters recommended that to remedy this 

problem, EPA should clarify that states can count energy savings from building codes, state 

appliance standards, transmission and distribution, voltage optimization, market transformation, 

and combined heat and power. 

Commenters stated substantial EE savings have been realized at military installations in North 

Carolina and at state government buildings. Commenters stated for example, under the Utility 

Savings Initiative, State facilities have been using energy performance contracts and other means 

to reduce energy consumption, which in fiscal 2012-13 avoided an additional 431,211 metric 

tons of CO2 air emissions. Commenters stated EPA bases the 1.5% savings rate on state 

programs for which there are reliable Evaluation, Measurement, and Verification ("EM&V") 

protocols. Whether Building Block 4 remains based on a nationally uniform incremental savings 

rate, or is refined to state-specific rates, commenters stated North Carolina should be allowed to 

count EE savings achieved by opt-out customers, military installations, and state government 

facilities when those savings are established by reliable EM&V. Commenters stated for savings 

not yet quantified, North Carolina should be allowed time to conduct appropriate EM&V and the 

results should be credited toward North Carolina's compliance with the EE savings goal of the 

Proposed Rule. 
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Commenters recommended that EPA adopt a broad view of energy efficiency and consider 

reported savings beyond well-established programs. Commenters recommended that EPA adopt 

a broad view of energy efficiency and consider reported savings beyond well-established 

programs, including: 1) changes in building codes and appliance standards should count towards 

meeting a state's target because they can achieve the broadest adoption, can be very costeffective, and provide energy efficiency benefits to both customers of large utilities that are 

running demand-side programs and small utilities (and rural states) where programs are less 

prevalent, and 2) EPA should not limit the tools available to states for achieving energy 

efficiency savings to the tools and programs they are using in 2014 as technologies will advance 

between now and 2030 and new opportunities for engaging customers will be available. 

Commenters stated that as to the level of rigor for more innovative plan programs and strategies, 

EPA must avoid imposing onerous and burdensome requirements that inhibit development of 

viable EE solutions. Commenters stated EPA should not restrict the eligible types of EE 

programs and measures that could be included in a state plan to a pre-defined list of wellunderstood program types. While this may have appeal to some because of its relative simplicity 

to administer, commenters stated it would stifle innovation. Commenters indicated the states and 

other entities must have the flexibility and incentive to develop approaches that meet the 

program's goals. 

Commenters stated that all EE should be eligible for state compliance plans. Commenters noted 

that the EPA requested comment on the use of a variety of energy efficiency technologies as 

compliance tools in the proposed rule. Commenters recommended that all energy efficiency that 

is additional and reduces carbon emissions should be eligible for state compliance plans, which 

includes building energy codes and appliance standards, combined heat and power, and more 

difficult to quantify efficiency, such as behavioral programs. Commenters further recommended 

that the EPA not limit the energy efficiency resources that states can use in their compliance 

plans because the savings are difficult to quantify.

Comment 10: Comments suggesting that the EPA should allow additional control measures in 

state plans.

Response 10 In the final rule, the EPA allows for a wide range of measures and resources to be 

used to adjust the CO2 emission rate of affected EGUs, provided they meet specific eligibility 

requirements as described in section VIII.K.1 of the final rule preamble of the CPP. In this 

section of the final rule, the EPA provides guidance regarding what measures are eligible and the 

appropriate accounting method that should be used.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA requested comment on whether measures such as electricity 

transmission and distribution efficiency improvements, retrofitting affected EGUs with partial 

carbon capture and storage, the use of biomass-derived fuels at affected EGUs, and use of new 

NGCC units are appropriate to include in a state plan to achieve CO2 emission reductions from 

affected EGUs. Commenters stated such alternative measures of reducing CO2 emissions should 
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be eligible for including in a state plan, and that EPA should develop guidance on how such 

measures should be included. The guidance should be issued concurrently with the final rule. 

Comment 11: Comments suggesting EPA allow credit for product recycling at industrial plants.

Response 11: The final rule allows the use of a wide range of measures to adjust a CO2 emission 

rate, provided the measures are tied to a state plan, achieve quantified and verified MWh impacts 

and meet the general and specific eligibility requirements described in section VIII.K.1 of the 

final rule preamble of the CPP. The measures must also meet the requirements and criteria 

related to proper quantification and verification of MWhs from demand-side EE savings, as 

described in section VIII.K.3 of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters believed credit should be given for measurable and verifiable reductions in carbon 

emissions from increased recycling at industrial facilities. Commenters stated while aluminum 

production is energy intensive, aluminum is a strong, lightweight, long-lasting and recyclable 

product that has a net carbon benefit over its life cycle. Commenters stated recycling aluminum 

saves 92% of the energy used to make primary aluminum. Commenters stated their company has 

already taken action to reduce its GHG footprint. Commenters stated that since 2005, their 

facility have reduced the GHG intensity of their refining and smelting business globally by 23% 

and they have targeted reductions of 30% by 2020 and 35% by 2030 (from this 2005 baseline). 

Comment 12: Comments stating that the EPA should allow credit for EE programs administered 

by local, city, and regional organizations.

Response 12: The final rule allows the use of a wide range of EE measures, provided the 

measures meet the general and specific eligibility requirements for resources used to adjust a 

CO2 emission rate, described in section VIII.K.1 of the final rule preamble of the CPP. The 

measures must also meet the eligibility requirements and provisions related to demand-side EE 

programs and projects and the requirements and criteria related to proper quantification and 

verification of MWhs from demand-side EE savings, as described in section VIII.K.3 of the final 

rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated that savings from local, city, and regional efforts should be credited to state 

plans, as long as they are included in the state plan and coordinated with other programs so as 

not to double count savings. Commenters stated that many cities and regions are innovators in 

tapping into energy efficiency as a resource (e.g., the City Energy Project is a joint initiative of 

NRDC and the Institute for Market Transformation 
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Comment 13: Comment suggesting establishing a baseline for EE credit.

Response 13: The final rule allows the use of a wide range of EE measures, provided the 

measures meet the general and specific eligibility requirements for resources used to adjust a 

CO2 emission rate, described in section VIII.K.1 of the final rule preamble of the CPP. The 

measures must also meet the eligibility requirements and provisions related to demand-side EE 

programs and projects and the requirements and criteria related to proper quantification and 

verification of MWhs from demand-side EE savings, as described in section VIII.K.3 of the final 

rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters recommended that since each of the 50 states have committed in writing to these 

criteria of Section 410 of ARRA, only actions in states that have met this baseline (adoption of 

the referenced codes with active programs to achieve 90 percent compliance) by 2017 should 

receive credit for emissions reduction due to code activities that reach beyond those levels 

specified in Section 410. Commenters stated the aggregate codes baseline upon which credit for 

codes is given should not in any case be calculated below these criteria. Commenters stated 

baselines for adoption of state and local appliance standards, for each specific year in 2020 to 

2030, should not be calculated below the current (in effect) federal appliance standards. 

Comment 14: Comments on promoting the incentive program.

Response 14: The EPA appreciates commenters’ commitment to collaborating with utilities, 

recyclers and retailers to aggressively promote energy efficiency incentive programs as an action 

that will complement and enhance the overall CO2 emission reductions achieved through the 

final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that outreach and advertising will obviously be critical to publicizing the 

availability of rebates and motivating consumers to take advantage of them. Particularly if the 

above elements are included, commenters said their association's members would be committed 

to collaborating with utilities, recyclers and retailers to aggressively promote the incentive 

program. Commenters stated these activities would include co-op advertising, direct mail, instore promotions and events, all designed to educate consumers about rebate opportunities, create 

excitement and drive refrigerator replacements and recycling. Commenters indicated this 

multimillion promotional campaign could be conducted in partnership with EPA and/or DOE 

and will go far to help the EPA, states and utilities meet their GHG reduction goals. If state 

programs are well-aligned and coordinated, commenters said industry promotional efforts could 

be integrated at the national level, which would maximize their effectiveness. 

While their initial focus have been on refrigerators, the commenters indicated early 

replacement/recycling model is equally applicable to other appliance classes (e.g., dishwashers, 

clothes washers, dryers, and room air conditioners), and their inclusion would yield sizable 

additional reductions in energy consumption and GHG emissions. As states develop rebate 
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programs under section 111(d), commenters asserted that expanding their scope to encompass 

additional appliances should be seriously considered. 

Comment 15: Comments suggesting demand response as an approvable compliance strategy.

Response 15: To the extent qualifying demand-side management actions are tied to a state plan 

and avoid the use of electricity by an electricity end user, the quantified and verified MWh 

impacts of the measures may be used by an affected EGU or state to adjust a CO2 emission rate. 

However, actions that shift electricity demand from one time of day to another, as described in 

Section K.K.1.a.(4) of the final rule preamble of the CPP, are not eligible as these measures do 

not avoid electricity use from the grid. 

The following are summaries of the specific public comments under this comment:

Commenters stated EPA should explicitly recognize demand response as an approvable 

compliance strategy. Commenters stated demand response should be added to the list of 

available compliance options, as it can directly and indirectly reduce carbon emissions by as 

much as 2 percent, is proven to be technically feasible, is cost-effective, and can smooth the 

transition to a lower carbon electric power system. Commenters stated demand response should 

be qualified as a compliance measure, as it meets all of EPA's criteria for BSER, and it could be 

considered for addition to Building Block 4 and at the very least should be added explicitly to the 

list of compliance measures. Commenters urged EPA to provide guidance for the inclusion of 

demand response in state compliance plans. 

Commenters stated it is important that EPA, long a leader on traditional energy efficiency 

through Energy Star and other programs, become a leader on creating an expanded and newly 

appropriate view and understanding of energy efficiency. Commenters stated it can start that 

leadership in its Clean Power Plan. Commenters stated EPA should clearly and directly expand 

the discussion of energy efficiency in its Final Rule to include demand response and smart grid, 

and should provide clear direction and guidance to states that they can consider such options for 

inclusion in their compliance plans. 

Comment 16: Comments on allowing credit for distributed generation.

Response 16: In the final rule, the EPA recognizes the value of renewable energy as part of the 

Best System of Emission Reduction. Renewable energy measures, including distributed 

renewable energy generation, that are tied to a state plan and achieve quantified and verified 

MWh savings may be used to adjust a CO2 emission rate, provided they meet the general and 

specific eligibility requirements for resources used to adjust a CO2 emission rate, described in 

section VIII.K.1 of the final rule preamble of the CPP. The measures must also meet the 

eligibility requirements and provisions related to proper quantification and verification of MWhs 

from RE generation, as described in section VIII.K.4 of the final rule preamble.
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The following are summaries of the specific public comments under this comment:

Commenters advocated that states be able to claim emissions reductions for distributed 

generation (DG). Commenters advocated that for non-renewable DG, utilities and states should 

be able to include emissions avoided as a result of DG activities in compliance plans as long as 

the avoided emissions reductions can be measured and verified. In the case of renewable DG, 

commenters urged that states and utilities should be able to treat DG generation like they would 

treat any other renewable resource, as a source of zero emissions electricity, without having to 

convert that generation into avoided emissions. Commenters stressed that it is important for EPA 

to issue clear guidance on how to incorporate DG into compliance plans.

Comment 17: Comments regarding states crediting energy savings from market transformation 

programs.

Response 17: In the final rule, EPA recognizes the value of energy efficiency as a low cost 

resource that can reduce CO2 emissions from affected EGUs. Demand-side EE and other nonBSER measures are not used in calculating the CO2 emission performance rates in the final

emission guidelines but the final rule gives states the flexibility, to use zero- and low-emitting 

resources to achieve their CO2 emission performance rate. Demand-side EE and other nonBSER measures that are tied to a state plan and achieve quantified and verified MWh savings 

may be used to adjust a CO2 emission rate, provided they meet the general and specific 

eligibility requirements for resources used to adjust a CO2 emission rate, described in section 

VIII.K.1 of the final rule preamble of the CPP. The measures must also meet the eligibility 

requirements and provisions related to demand-side EE programs and projects, if applicable, and 

the requirements and criteria related to proper quantification and verification of MWhs from 

demand-side EE savings are described in section VIII.K.4 of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated the EPA appropriately recognizes that states may, in state compliance plans, 

credit energy savings from market transformation programs. Commenters stated they have many 

years of experience to back up this statement. Commenters stated on behalf of the four 

Northwest states, they have been leading market transformation programs to deliver energy 

savings on behalf of the region. In NEEA's case, commenters stated the process of market 

transformation is best described by the theory of diffusion of innovation and expressed by a 

curve showing the increasing market share of a specific technology or practice in a market over 

time. Commenters stated market transformation activities are designed to result either in 

increased market adoption compared to what would have happened without market intervention 

(baseline), acceleration in time of adoption, or possibly both. Commenters stated this change in 

market adoption is ultimately what delivers energy savings. Commenters stated the process of 

transforming the market for a single product or service may take place over many years, 

culminating in incorporation of the energy-efficiency result into codes and standards. For 

NEEA's work on behalf of the region, commenters stated utility investment through NEEA early 

in the multiyear process yields energy savings several years in the future. Commenters stated 

these savings derive from permanent changes to markets that have been independently measured 
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and evaluated using best practices for tracking, measuring and verifying. Commenters stated the 

Northwest Power and Conservation Council's Regional Technical Forum (RTF) is the regional 

authority that develops standardized protocols for the verification and evaluation of energy 

savings. Commenters stated the RTF makes use of research and data generated by NEEA, 

Bonneville Power Administration, utilities and third party contractors. Within the Northwest, 

commenters stated these savings are counted as equal components of the regional energy 

efficiency effort alongside local utility programs, despite the difference in time of the early 

investments and the resultant energy savings. Commenters stated the regional power planning 

process recognizes market transformation savings and proportionately offset generating 

resources in the same way as savings achieved through utility end-use efficiency 

accomplishments. Accordingly, commenters stated savings from Northwest market 

transformation programs led by NEEA deserve full credit toward meeting utility energyefficiency components of state compliance plans, regardless of the starting point of the long-term 

effort that generated the market transformation. Commenters stated the region depends on 

market transformation efforts to discover new opportunities, to test and assess market potential, 

and to work to remove barriers to adoption. 

Comment 18: Comments supporting the use of Combined Heat and Power and Waste Heat 

Power in their compliance plans.

Response 18: In the final rule, the EPA recognizes the value of combined heat and power as a 

resource that can reduce CO2 emissions from affected EGUs. The EPA agrees with the 

commenter and allows for electric generation (MWhs) from CHP units to be used to adjust the 

CO2 emission rate of an affected EGU, provided that the units meet the eligibility criteria 

described under section K.1.a.(9) and the EM&V criteria described in section IV.D.8 of the 

preamble to the proposed Federal Plan. Quantified and verified electric generation from nonaffected combined heat and power units tied to a state plan may be used to adjust the CO2

emission rate of an affected EGU provided that it meets the eligibility criteria described under 

section VIII.K.1.a of the final rule preamble. Since, in most cases, a CHP unit would be a lowemitting CO2 source, the MWh output would need to be prorated to account for the emissions 

using the method described in section VIII.K.1.a.(9) of the final rule preamble. The measures 

must also meet the requirements and criteria related to proper quantification and verification of 

MWhs as described in section IV.D.8 of the preamble to the proposed Federal Plan.

When developing their plans, states planning to use waste-to-energy as an option for the 

adjustment of a CO2 emission rate should assess both their capacity to strengthen existing or 

implement new waste reduction, reuse, recycling and composting programs, and measures to 

minimize any potential negative impacts of waste-to-energy operations on such programs. See 

section VIII.K.1.a of the preamble to the final rule for more details.

In order to ensure consistency with the calculation of CO2 performance rates and state rate-based 

CO2 goals in the final emission guidelines, and to avoid double-counting or inconsistent 

adjustment approaches across states, the final rule prescribes a general accounting approach 

states must use to adjust the CO2 emission rate of an affected source to reflect the MWh impacts 

of zero-emitting and low-emitting resource. Quantified and verified MWh impacts of qualifying 
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zero-emitting and low-emitting resources tied to a state plan may be used by an affected EGU or 

state to adjust a CO2 emission rate, regardless of whether the renewable generation or demandside EE savings occur inside or outside the state or territory. Consistent with the EPA’s 

calculation of the CO2 emission performance rates and state rate-based CO2 goals in the final 

emission guidelines, the MWhs impacts are added to the denominator of an affected EGU’s 

reported CO2 emission rate, resulting in a lower, adjusted CO2 emission rate. The reported CO2

emissions reflect the actual emission reductions from the deployment of qualifying non-emitting 

and low-emitting resources across the regional grid. Further adjustment of CO2 emissions, such 

as through the subtraction of emissions from the numerator, such as those estimated by applying 

an emissions factor to the MWhs, would double count CO2 emissions impacts across the grid and 

is, therefore, not permitted under the general accounting approach. For more information about 

specific methods to adjust the CO2 emission rate of an affected EGU to reflect RE and demandside EE, see section VIII.K of the final rule preamble of the CPP. The same section also 

describes the eligibility requirements and conditions for resources to be used to adjust a CO2

emission rate, including specific discussions regarding hydroelectric power, biomass and 

combined heat and power. 

The following are summaries of the specific public comments under this comment:

Several commenters said that the EPA should encourage the states to incorporate CHP and 

WHP in their compliance plans and provide appropriate guidance and data (e.g., 

templates) supporting use of these technologies. Commenters said that this encouragement 

and guidance will be particularly important in coal-heavy states in the industrial Midwest. 

Commenters cited the potential economic and environmental benefits of including these 

technologies in state plans. For example, commenters cited a 2008 DOE Oak Ridge National 

Laboratory study that assessed the benefits of a "high deployment strategy," wherein CHP and 

WHP would provide 20 percent of U.S. electric capacity by 2030. Commenters provided several 

references supporting that this scenario is realistic and tenable given the right incentives and 

policies. Commenters added that the EPA properly recognizes EM&V protocols and procedures 

for CHP as "well established," further supporting its use as a compliance pathway for EGUs. 

Also, commenters stated that another benefit for states that include CHP and WHP as eligible 

energy-efficiency technologies is that they will be able to surpass the relatively modest 1.5 

percent annual electricity savings reflected in the targets and have less difficulty complying with 

the rule. Commenters also described the benefits of CHP and explained that states can play an 

important role in promoting CHP using strategies like Connecticut has done, including 

construction grants, standardization of interconnection protocols, low interest loans, and the 

establishment of a CHP portfolio standard. 

Commenters added that CHP/WHP facilities would be distributed energy facilities, which would 

help support grid reliability. 

Commenters said that CHP and WHP are proven and demonstrated approaches to lower 

emissions, make U.S. manufacturers more competitive, and enhance electric reliability. 

Commenters stated that the Administration has already recognized these benefits and has 

established a national goal to encourage greater deployment of CHP and WHP. Commenters 
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concluded that the EPA should leverage the Administration's earlier action and allow states to 

include the use CHP and WHP in their utilities’ reduction plans. 

Because the WHP process "fuel" is simply waste heat, commenters said, there are zero fuel costs 

and zero additional emissions, carbon or otherwise. For example, commenters said, a typical 

Ormat REG facility rated at 6 MW will avoid the generation of approximately 50,000 tons of 

CO2 annually. Commenters added that many WHP applications, including all of Ormat's units 

installed on natural gas pipelines, can continue operating and delivering power in the event of a 

grid outage. Commenters noted that this is an extremely important contribution to overall system 

reliability at a time when the U.S. electric grid grows increasingly vulnerable to cyber threats and 

extreme weather. Commenters said that the EPA has identified 10 GW of potential WHP 

opportunities, of which only a small portion has been realized to date. Commenters stated, 

industrial waste heat could provide enough emission-free electricity to power approximately 10 

million American homes, provide hundreds of thousands of new American jobs, and support 

critical U.S. manufacturing industries reduction plans. 

Commenters described how existing state RPS address WHP and existing and pending incentives 

for WHP. Commenters said that explicitly listing WHP in the rule will confirm to those states 

that already include WHP in their renewable energy and energy efficiency policies and 

programs, as well as states that don't yet have policies and programs supporting WHP, that WHP 

can be used to meet requirements of the state plan. While commenters understood from 

discussions with the EPA that the building blocks were used to establish state targets and are not 

meant to limit the technologies used for compliance, by explicitly including WHP in the rule, the 

EPA will send a signal that states should consider WHP deployment for their state plans. 

Commenters added that to incentivize additional construction of compressor engine waste heat 

generation in conjunction with ongoing natural gas development over the next several years, the 

EPA should specifically clarify in the final rule that this technology is a qualifying form of 

renewable energy.

Commenters stated under what criteria can states utilize CHP for compliance purposes?

Commenters stated that bottoming cycle cogeneration, a type of CHP and also a type of WHP, 

should qualify, along with other WHP applications, as a way to avoid affected EGU emissions. 

Commenters stated that bottoming cycle CHP, like other WHP projects, generate electricity with 

no incremental emissions, thereby reducing the demand for electricity and associated emissions 

from EGUs. Commenters stated that in conclusion, they believe EPA should explicitly list WHP 

as a zero-emitting power source states can use to offset emissions by utilities, clarify that zerocarbon generation sources of electricity, including WHP, installed at customer sites but not at 

affected EGU's, should be eligible to be counted toward the state's target, and include 

information on WHP resources in an appropriate section of the Clean Power Plan Toolbox for 

States or elsewhere as appropriate.

Commenters commented that the EPA should clarify that CHP qualifies as an efficiency resource 

and that WHP qualifies as a low or zero-carbon resource for the proposed rule. Commenters 

stated that the rule should explicitly acknowledge that the use of these technologies at unaffected 

systems is an eligible compliance strategy for EGUs and should describe the environmental, 

economic, and reliability benefits associated with these technologies. Commenters added that 
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explicit recognition of CHP and WHP will send a signal to states that they can and should 

include these technologies in their compliance plans, and, absent this, states are unlikely to look 

beyond the policies included in the building blocks. Commenters stated that the EPA should 

consider CHP as an effective energy efficiency measure and encourage the use of this highly 

efficient use of fossil fuel by allowing states to claim efficiency credit. Commenters explained 

that CHP is an efficient use of fossil fuel, and efficiencies close to 80 percent are not uncommon 

for CHP at facilities where the demand for thermal energy is high. Commenters added that 

reducing the use of a boiler, furnace, or even space conditioning units presents significant 

opportunities for emission reductions, and the 2011 Energy Master Plan for New Jersey set a 

goal for 1,500 MW of CHP capacity.

Commenters stated that EPA should make clear that adding CHP to an existing affected coal 

facility that results in efficiency gains beyond the 6 percent heat rate improvement used to 

calculate state goals is an important and approvable compliance opportunity. 

Commenters stated EPA should allow and encourage states to include CHP as a compliance 

measure in State Plans and added that the U.S. power industry is only 32.5 percent efficient and 

rejects around 24 quadrillion Btu (quads) of waste heat annually (25 percent of total U.S. energy 

use). Commenters stated that this waste heat from U.S. power generation exceeds the total 

national energy use in all but three of the world's 216 countries. Commenters presented a figure 

illustrating this comparison for the top 20 heaviest energy users as well as the average for the 

remaining 196 countries.

Commenters stated that EESI applauds EPA for including power plant efficiency as a 

compliance strategy. Commenters stated that most coal plants in the United States are only 34 

percent efficient according to the Energy Information Administration, wasting two thirds of the 

energy used to generate power in the form of heat waste. Commenters stated that District Energy 

and Combined Heat and Power (CHP) are excellent ways to boost efficiency in a power plant, 

which could allow existing plants to operate with greatly improved efficiency and reduced 

emissions. Commenters stated that CHP reclaims some of the waste energy in power plants by 

collecting vented heat in a pipe system and using it to provide heat and/or hot water to the plant. 

Commenters stated that the heated air or water collected in the CHP process can also be piped to 

nearby buildings, college campuses, urban areas, etc., in district energy systems and in 

combination, CHP and district energy can boost a power plant's efficiency to 90 percent. 

Commenters stated that there are many such examples of highly successful district energy/CHP 

systems across the country, with the potential for many more. Commenters stated EPA should 

alert states to the great potential that CHP and district energy offer as compliance strategies.

Commenters noted that references to "industrial CHP" in the Proposed Rule ignore the 

significant potential for CHP in the institutional and commercial sectors, particularly in district 

energy systems serving colleges, universities, downtown areas, hospitals, military bases and 

other multi-building settings. Commenters recommended that the Final Rule refer to "CHP" 

rather than "industrial CHP" to make clear to States that CHP systems beyond those at industrial 

facilities should be incorporated into State compliance plans. 

Commenters stated that while EPA's system-wide option should allow utilities and states to 

achieve their emission targets through investments in CHP Systems at off-site thermal hosts, 
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such as hospitals, universities and manufacturing facilities, these off-site hosts must be assured 

that they will not be disadvantaged later should EPA subsequently adopt a carbon NSPS for their 

sector. Commenters stated that EPA should clarify that measures, such as CHP Systems, which 

are installed at an off-site facility and are credited to the overall electric system under this rule 

will also be recognized as carbon emission reduction measures for the portion of the off-site 

facility, i.e. the CHP System, which is considered a part of the electric system.

Commenters stated that a requirement that CHP units account for lifecycle, non-EGU emissions 

would also be inconsistent with how EPA has directed states to consider other emission 

reduction measures. Commenters stated that EPA reasonably does not require emission reduction 

measures that displace EGU utilization via low or zero carbon generation or end-use energy 

efficiency to account for the lifecycle emissions of those units. Commenters stated that for 

example, renewable energy developers are not required to net out the upstream emissions of steel 

production used to manufacture wind turbines. Commenters stated that the Clean Power Plan 

does not propose that building efficiency measures account for on-site natural gas use. 

Commenters stated that nor does EPA account for upstream increases in methane emissions due 

to expanded use of natural gas at existing NGCC facilities. Commenters stated that non-affected 

CHP units present no unique circumstances that would require or justify disparate treatment. 

This policy should be consistently applied.

Commenters stated that EPA should expressly state that CHP and WHP at unaffected units are 

eligible compliance technologies for EGUs. Commenters stated that by generating both heat and 

electricity from a single fuel source, CHP dramatically lowers emissions and increases fuel 

efficiency - allowing utilities and companies effectively "get more with less." Commenters stated 

that CHP can use more than 70 percent of fuel inputs and presented Figure 2 which illustrates 

that total fuel use is significantly greater with conventional, separate heat and power generation 

(here 154 units) than it is with CHP (here 100 units). Commenters stated that savings are even 

larger with WHP, which captures waste heat that would typically be vented from an industrial 

facility and uses it to make electricity with no additional combustion and no incremental 

emissions. Commenters included Figure 1: Losses from Conventional Power Generation (TWh) 

and Figure 2: CHP System Efficiency. Commenters noted that by producing both heat and power 

from a single fuel source (CHP) and by capturing otherwise wasted heat from industrial 

processes to generate additional electricity (WHP), CHP and WHP dramatically lower energy 

use and associated emissions. Commenters also stated that in fact, CHP can produce one-half the 

carbon dioxide (CO2) emissions of the separate generation of heat and power to deliver the same 

amount of useful energy (Figure 3 CHP Has Significantly Lower Carbon Dioxide Emissions than 

Conventional Generation). Commenters stated WHP produces electricity with no additional 

combustion and no incremental carbon emissions. 

Commenters further stated that for these reasons, EPA should expressly identify CHP and WHP 

in the rule as a means of lowering emissions at unaffected units to help achieve our national 

goals. Commenters stated that EPA Administrator, Gina McCarthy has recognized CHP's GHG 

benefits and that for instance, upon awarding several industrial facilities for their investments in 

CHP, she recently explained, 'The CHP technology offers a strategy to help meet the goals of the 

President's Climate Action Plan for a cleaner power sector while boosting the efficiency and 

competitiveness for many U.S. manufacturers." Commenters stated that in August 2012, the 

Administration announced a goal of installing 40 gigawatts of new CHP by 2020 and that 
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achieving this goal would annually save energy users 1 quadrillion Btu and reduce CO2

emissions by 150 million metric tons. Commenters stated that under a more ambitious scenario, 

the Department of Energy estimates that increasing CHP from its current 8-percent share of U.S. 

electric power to 20 percent by 2030 would reduce CO2 emissions by more than 800 million 

metric tons per year - the equivalent of removing more than half of the current passenger 

vehicles from the road. Commenters stated this amounts to a 10-percent reduction in projected 

U.S. energy-related CO2 emissions in 2030. Commenters stated such full-scale deployment 

would be equivalent to the power produced by more than 480 conventional power plants,

displacing 5.3-quadrillion Btus of fuel from conventional sources - or half the total energy 

currently consumed by U.S. households. Commenters presented Table 1: CHP/WHP Projections 

(2030) and Environmental Benefits and stated EPA should identify CHP and WHP's emission 

benefits in the rule itself.

Commenters stated that combined heat and power facilities reduce overall fuel use and emissions 

by generating two energy sources - heat and power - with the same fuel. Commenters stated the 

EPA recognized the opportunity presented by CHP in its Clean Power Plan, noting that large 

energy users might independently see opportunities for self-generation using CHP, and 

indicating that "states can structure their plans to allow the CO2 reductions achieved at affected 

EGUs through such actions to assist in reaching compliance." Commenters stated EPA also 

asked for comment on "whether industrial CHP approaches warrant consideration as a 

potential way to avoid affected EGU emissions, and whether the answer depends on 

circumstances that depend on the type of CHP in question." 

Commenters further stated that allowing compliance via combined heat and power presents a 

win-win opportunity to lower compliance costs for covered EGUs while encouraging efficient 

use of energy at industrial, commercial and institutional facilities. Commenters stated that CCAP 

undertook a modeling study earlier this year to assess this opportunity. Commenters stated this 

study (attached) linked ICF International's CHPower and Integrated Planning Models to assess 

how much CHP would be economical under the electricity, fuel and carbon prices in our 

forecasted 111(d) rule policy scenario. Commenters stated that while the specifics of their study 

differed from EPA's proposal, the level of stringency on a national basis was comparable. 

Commenters stated that using conservative assumptions about the technical and economic 

potential of CHP, as well as conservative assumptions on the rate at which users opt to invest in 

economic CHP and the rate of CHP deployment, they found that a total of 10 GW of CHP would 

be deployed by 2030. Commenters stated that CHP was an important 111(d) compliance option 

in Midwest and Southern states that both had CHP potential and faced a higher carbon price due 

to the regulation. Commenters further stated that allowing CHP as a means of compliance also 

helped lower overall system-wide compliance costs. Commenters stated that EPA's final rule 

should encourage this win-win solution.

Commenters stated they strongly believe that CHP should be allowed and facilitated as a means 

of compliance to the degree that they displace electric generation and reduce emissions from 

affected electric generating units. Commenters stated they also believe that EPA should take into 

account the fact that most CHP facilities (other than waste heat to power) produce at least some 

incremental emissions to generate electricity. Commenters stated that to avoid emissions leakage 

through compliance via CHP, it is necessary to consider any incremental emissions at the CHP 

unit that can be attributed to electric generation. Commenters stated that EPA should specify 
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methodologies for quantifying any incremental emissions related to electricity generation that are 

additional to the business-as-usual emissions from heat production. Commenters stated such 

methodologies could be based on heat rates and should not require use of continuous emissions 

monitors for small CHP units. Commenters further stated that to facilitate CHP's participation in 

state compliance markets using a standard currency (e.g., CO2 reduced), they recommend that 

emissions reductions from CHP and other clean energy sources be reflected in the numerator of 

the lbs/MWh emissions rate, not the denominator.

Commenters stated they would like to suggest EPA consider modifying the rule to encourage 

affected EGUs to partner with a non-affected facilities in adding new (or enhance existing) 

combined heat and power ("CHP") generation capacity as an acceptable way to avoid affected 

EGU emissions. Commenters stated that the form of the CHP could be either a standalone 

natural gas fired combustion turbine with heat recovery steam generation ("CT/HRSG") or added 

turbine generators powered by a plant's existing steam header.

A commenter stated that the EPA should clarify that CHP qualifies as an EE resource in the 

proposed rule, and that WHP produces no incremental carbon emissions. Commenters noted that 

there is a single mention of CHP as an example of "demand-side energy efficiency" and no 

mention of WHP. Commenters stated that the rule should explicitly acknowledge that the use of 

these technologies at unaffected units is an eligible compliance approach that states may include 

in their compliance plans. Commenters suggested that the rule's preamble and any relevant TSDs 

or guidance should elaborate on CHP and WHP's environmental, economic and reliability 

benefits. Commenters stated that explicit recognition of these techniques will send a signal to 

states that they can and should include these technologies in their compliance plans. Absent this, 

Commenters explained that various states are unlikely to look beyond the policies explicitly 

included in the building blocks. 

Commenters stated that as a specific example, despite existing installed generation capacity, 

Purdue University's utility plant (a non-EGU) is a net purchaser of electricity to satisfy the total 

demands of the growing campus and as the University grows, but does not install commensurate 

CHP generation capacity, utility generated power demands increase for the campus. Commenters 

stated that if the increased power demand could be met with efficient on site CHP capacity rather 

than offsite less efficiently produced and transmitted power, then each MW of power required by 

campus would be supplied with a decreased associated CO2 emissions rate due to the efficiencies 

of CHP. Commenters stated that if an affected EGU could get compliance "credit" CHP capacity 

installed at non-utility facilities, this could lay the groundwork for creative partnering between 

affected EGUs and non-affected industrial facilities to bring more production capacity on line 

without increasing CO2 emissions overall.

Commenters stated that in addition to the carbon reduction benefits, adding capacity to existing 

CHP could lend itself to better coupling with intermittent renewable assets that are located near 

the CHP site for better grid stability/reliability.

Commenters said that the EPA should permit industrial CHP units to participate voluntarily 

alongside other energy sources that can reduce net GHG emissions, because such an exclusion 

would further incentivize the adoption and maintenance of efficient, reliable, and low-emission 

distributed generation. Commenters echoed the remark from other commenters stating that CHP 
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should be recognized as a voluntary compliance measure by the EPA. Commenters stated that 

adding or expanding CHP to existing fossil-fuel fired EGUs can reduce the emission rate of 

those EGUs. Commenters also noted that adding CHP to existing affected facilities reduces 

pollution by using the energy potential of the fuel input twice or three times, yielding half to a 

third of the emissions from separate applications. Commenters said that adding or expanding 

CHP at facilities other than affected EGUs (such as food processing, hospitals, industrial 

production and manufacturing, and commercial buildings) can measurably reduce demand for 

and therefore emissions from affected EGUs. Commenters said that the proposed rule needs to 

provide more clarity that CHP at a facility other than an affected EGU, qualifies as an efficiency 

resource.

Commenters said that GHPs can be effectively integrated into institutional CHP systems and 

supported the ability of states to consider institutional CHP approaches in their state plans. 

Commenters recommended that the EPA encourage states to recognize industrial, commercial 

and institutional CHP and WHP as appropriate means to avoid affected EGU emissions. Given 

the complicated process and tight timeline surrounding state plan development, commenters 

were concerned that states may be reluctant to include opportunities for CHP owners and 

operators in compliance plans without a clear signal from the EPA that CHP is an approvable 

compliance tool, and without additional guidance from the EPA on the permissible methods of 

calculating the emission reduction benefits of CHP. 

Commenters stated that the main policy question that EPA must resolve regarding CHP in the 

final rule is whether states must account for lifecycle emissions of non-affected CHP or whether 

only the emission impacts at affected EGUs should be considered. Commenters stated that EPA 

should not require states to include the CO2 emitted by CHP units located at a non-affected 

facility. According to the commenter, a policy of calculating the impact based only on the 

avoided emissions of affected EGUs is consistent with EPA's legal justification for the 

approvability of "beyond-the-fence" abatement activities, its treatment of the lifecycle emission 

reductions of other measures that reduce EGU emissions, and principles of administrability, and 

CHP promotion. Commenters offered the following points in justification:

• Commenters stated that while EPA has considered the availability of 

emission reduction measures that occur "beyond-the-fence" of fossil 

fuel-fired electric utility generating units - both for the purpose of setting 

state emission rates and for allowable compliance measures - it has done 

so only to the extent those measures reduce emissions at affected EGUs. 

Commenters stated that EPA does not allow states to count emission 

reductions in sectors other than utility EGUs when determining a state 

plan's expected compliance with its emission goal. By the same logic, 

Commenters stated that EPA is constrained from requiring states to 

account for emission increases at out-of-sector entities.

• Commenters stated that EPA reasonably does not require emission 

reduction measures that displace EGU utilization via low or zero carbon 

generation or end-use energy efficiency to account for the lifecycle 

emissions of those units (e.g., renewable energy developers are not 

required to net out the upstream emissions of steel production used to 
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manufacture wind turbines). Commenters stated that non-affected CHP 

units present no unique circumstances that would require or justify 

disparate treatment of CHP.

• Commenters stated that accounting only for displaced emissions would 

be more administratively efficient than an approach that required 

"netting" the CO2 emitted by a non-affected CHP unit. Commenters 

stated that properly evaluating the net emission impacts of new nonaffected CHP would prove challenging and expensive, and that there is 

no widely accepted methodology for fairly attributing emissions 

between electric generation and the steam utilization that would have 

occurred in absence of CHP. 

• Commenters stated that this approach is also consistent with the Federal 

Government's general policy of promoting CHP.

• Commenters noted that EPA retains authority to directly regulate 

industrial boilers and other categories of existing sources of CO2

emissions under Section 111 sometime in the future if EPA determines 

that such emissions contribute to air pollution that endangers public 

health and welfare.

Commenters advocated that the methodology for determining the compliance contribution of 

new and expanded non-affected CHP should not require accounting for the direct emission of 

CO2 from that facility. However, if EPA determines that the methodology must account for such 

emissions, Commenters urged EPA to develop a netting methodology that accounts only for the 

emissions from the non-affected CHP unit directly associated with incremental electric 

generation. Commenters further urged EPA to provide the maximum possible assurances that 

such incremental emissions are not also regulated under a future Section 111 rulemaking for 

industrial or institutional sources, otherwise it would constitute double regulation of these CHP 

units.

• Commenters suggested that if EPA requires an accounting for lifecycle 

emissions of non-affected CHP units, it should do so in a precise and 

appropriate way. For example, Commenters pointed out that waste heat 

to power systems have no net emissions associated with electricity 

generation. Similarly, for combined cycle systems, the facility would 

have combusted some fuel to produce thermal heat even if no electricity 

was produced. Therefore, Commenters stated that it would be incorrect 

to count all CO2 emitted by CHP units when determining the net 

emission impact of new or expanded non-affected CHP. 

• Commenters stated that EPA does not currently have a published 

methodology for calculating the net CO2 reduction benefits of CHP 

systems. Commenters stated that while the CHP Savings Calculation 

Methodology and associated online emission calculator. [EPA, CHP 

Emissions Calculator, http://www.epa.gov/chp/basic/calculator.html] are 
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useful tools for analyzing the total net emission savings from CHP 

compared to separately producing thermal heat and procuring electricity 

from a utility EGU, the methodology is not designed to calculate the net 

CO2 savings specific just to avoided generation in the electric sector.

• Commenters stated that if EPA determines that the CO2 emitted by a 

CHP unit located at a non-affected facility must be accounted for, the 

EPA must provide a specific methodology by which owners of CHP 

units and state regulators can predictably and easily calculate net 

emission savings from CHP. According to the commenter, this 

methodology should include only the CO2 emitted by a non-affected 

CHP unit that is additional to what would have occurred purely for 

thermal heat production purposes; i.e., only those emissions solely 

associated with the addition of electric generation should be subtracted 

from the emissions saved through the reduced utilization of affected 

EGUs.

• Commenters stated that any methodology EPA develops should 

maintain state flexibility to account for non-affected CHP emission 

reductions by adding MWhs to the denominator of an affected EGU's 

emission rate or by subtracting emissions from the numerator of the 

affected EGU's emission rate. Commenters stated, for example, if a state 

translates energy savings to emission reductions by adding MWhs of 

savings to an EGU's denominator, the number of MWhs can be 

discounted to account for CO2 emitted by the non-affected CHP unit; 

whereas if a state uses a "numerator approach," the CO2 directly emitted 

by CHP unit can be subtracted from the avoided emissions. 

• In addition, Commenters stated that if EPA determines that the 

contribution of a non-affected CHP unit must account for the CO2

directly emitted by the non-affected CHP unit, EPA should take this into 

account in any future CO2 regulation addressing emissions from that 

unit's source category. Otherwise, Commenters stated that imposing an 

additional regulatory burden on those same emissions would constitute 

double regulation and would discourage the use of new and expanded 

CHP. Commenters stated that EPA should therefore provide assurance 

that these units will not be subject to double regulation. To do this, 

Commenters stated that EPA should clearly signal that the CO2 emitted 

by non-affected CHP units credited under this rule are effectively 

emissions associated with the EGU source category and so will not be 

considered emissions associated with another industrial or institutional 

source category if EPA issues future regulations under Section 111(d) 

for that category.

Commenters recommended that EPA provide specific guidance on how to incorporate CHP into 

compliance strategies and provide model rules. Commenters recommended that EPA establish a 

5th building block for miscellaneous reductions so that states do not overlook the potential 
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emission reduction opportunities from CHP, and allow credit for equivalent emission reductions 

for process heat generated by CHP.

Commenters recommended approaches for calculating emissions reductions from CHP for five 

circumstances, as follows:

• For purposes of determining compliance with the State Goal, if an 

affected EGU under

Section 111(d) converts from power-only operation to CHP, thereby 

falling under regulation per Section 111(b), the reduction in emissions 

rate below the Section 111(b) requirement should be creditable in State 

Plans under Section 111(d). The most appropriate methodology is to:

− reduce the numerator by an amount equal to the CHP electricity output 

(adjusted for line losses) plus 100% of the useful CHP thermal output, 

multiplied by the reduction in emissions rate for the CHP plant compared with 

the relevant NSPS emission rate; and

− increase the denominator by the CHP electricity output (adjusted for line 

losses) and 100% of the useful CHP thermal output.

• For purposes of determining compliance with the State Goal, if an 

affected EGU under

Section 111(d) that is a CHP plant increases utilization and/or converts 

to a lower-carbon fuel, the numerator (metric tons of CO2) should be 

increased or decreased by the incremental change in EGU CO2

emissions and the denominator (MWh of total useful energy) should be 

increased by the incremental increase in electricity output (adjusted for 

line losses) and 100% of the increase in useful thermal output.

• If an existing CHP plant that does not qualify as an affected EGU under 

Section 111(d) increases utilization, the denominator (MWh of total 

useful energy) should be increased by the incremental increase in 

electricity output (adjusted for line losses) and 100% of the increase in 

useful thermal output. Although this approach does not account for some 

emissions increases at the CHP plant, Commenters believed this 

approach is warranted for simplicity to encourage CHP and to avoid 

making these small plants subject to onerous EM&V oversight. If EPA 

want to account for these emissions, then Commenters included a 

recommendation for an alternative calculation methodology.

• If a new CHP plant is constructed which qualifies as an affected EGU 

under Section

111(b) and will be regulated under Section 111(b), but has a lower 

emissions rate than required under Section 111(b) the reduction in 

emissions rate below the Section 111(b) requirement should be 
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creditable in State Plans under Section 111(d). The most appropriate 

methodology is to:

− reduce the numerator by an amount equal to the total useful energy output of 

the CHP plant multiplied by the reduction in emissions rate for the CHP plant 

compared with the relevant NSPS emission rate; and

− increase the denominator by the CHP electricity output (adjusted for line 

losses) and 100% of the useful CHP thermal output.

• A new CHP system that does not qualify as an EGU under either Section 

111(b) or Section 111(d) should be credited by increasing the 

denominator by an amount equal to the total useful energy output of the 

CHP plant. Although this approach does not account for some emissions 

increases at the CHP plant, Commenters believed this approach is 

warranted for simplicity to encourage CHP and to avoid making these 

small plants subject to onerous EM&V oversight. If EPA want to 

account for these emissions, then Commenters included a 

recommendation for an alternative calculation methodology.

Commenters offered specific recommendations for how to account for the benefits of CHP for 

states the use the rate-based approach:

• For CHP systems that are not covered by the rule, Commenters stated 

that credits should be given just like energy savings from end-use energy 

efficiency improvements. Commenters suggested that a utility or state 

that offers incentives for CHP be given credits for the energy savings. 

Emissions reductions would be applied to the numerator in a state's 

emissions rate calculation; electricity savings would be added as a credit 

in the denominator (analogous to other energy efficiency credits 

proposed by EPA). Commenters also recommended a negative 

adjustment for the increase in the on-site CO2 emissions at the CHP 

facility. The recommended adjustment, along with strategies for 

accounting for the efficiency effects of CHP is described in Appendix A 

to their letter and illustrated in a table with several examples.

• For CHP units that are subject to 111(d), commenter 23962 

recommended use of the Avoided Emissions approach because it most 

accurately recognizes the CO2 reductions offered by a CHP system. For 

a rate-based plan, if EPA chooses to use the equivalency approach, then 

Commenters stated that crediting only 75% of the thermal output 

undervalues the emissions benefit from CHP, but supported the use of 

75% if EPA chooses to pick a single, fixed percentage. Appendix A to 

the comment letter contained example calculations to illustrate their 

points.
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Commenters discussed how the EPA should allow states to receive credit for the electricity 

generated by unaffected CHP units. 

Commenters said that emissions reductions resulting from end users who install systems that 

take load off the central power plant and associated transmission and distribution systems should 

be credited to the state, noting that WHP projects will generally not be installed at the affected 

EGU, but rather at a location that is the source of the waste heat as well as the consumer of the 

electricity generated from the waste heat. In addition, commenters said, because WHP is 

distributed generation, located on-site where the waste heat is produced and the electricity is 

generated and used, WHP projects alleviate burdens on and minimize line losses associated with 

power transmission and distribution systems. According to commenters, the more distributed 

generation like waste heat to power is available to industry, the less need for additions and 

upgrades to transmission infrastructure. Commenters stated that, given the scope of the proposed 

rule, the EPA may be required to only consider the displaced emissions from the affected EGUs. 

Commenters stated that the full electricity output of unaffected, efficient CHP systems should be 

credited in the same manner as any other beyond-the-fence energy-efficiency measure, without 

regard to the modest increase in emissions that may result at the facility installing the CHP unit. 

According to commenters, this approach is consistent with the way a number of states such as 

Massachusetts, Maryland and Illinois have incorporated CHP into their Energy Efficiency 

Resource Standards (EERS). Where states include unaffected CHP units in their compliance 

plans, all of the electricity generated by such units should be treated as a kilowatt hour displaced 

from the grid and commenters urged the EPA to prepare guidance for states to this effect. 

Commenters said that the generation of useable energy from cogeneration is a direct capture of 

energy that would otherwise be lost to the atmosphere, and use of this energy represents a 

quantifiable reduction in demand for energy that would otherwise be generated through increased 

consumption of carbon-based fuel at the facility. Commenters said that the reduction in demand 

is equally valid whether the generating facility is new or old, modified or operating as originally 

built. Commenters recommended that heat generated in these facilities, in cases where the heat 

energy is used in product manufacture or to meet other in-house energy needs, or to produce 

electricity that is supplied to the grid for distribution to other consumers, should be specifically 

allowed in the proposed rule as an offset to CO2 emissions in a state's compliance plan. 

Commenters said that this should include existing and future cogeneration, both at affected 

EGUs and at other EGUs. Commenters stated to incentivize the addition of new cogeneration to 

existing facilities, 100% of the energy so used should be allowed as a compliance measure. 

Commenters said that the benefits of CHP coupled with the Administration's goal of deploying 

40 gigawatts of new CHP by 2020 support treating CHP at unaffected units in this manner.

Commenters added that, while CHP at unaffected units may result in modest on-site emission 

increases, these units remain subject to strict standards for criteria pollutants and must often meet 

minimum efficiency requirements to ensure they are operating cleanly and efficiently. 

Commenters suggested that states should establish minimum performance requirements for 

unaffected CHP units to ensure there are creditable savings. For example, commenters said that 

many state CHP regulations require at least 20 percent of the fuel's recovered energy to be 

thermal and an overall CHP system efficiency of 55 to 60 percent. If the EPA determines that 

electricity produced by unaffected CHP units should be discounted to account for incremental 
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on-site emissions at the CHP host facility, commenters said that the calculation must be simple, 

accurate and understandable. 

Commenters said that the EPA should provide guidance to states on the application of the 

avoided-emissions approach, which would calculate an effective emissions rate for unaffected 

CHP units based on measurement of (or reasonable assumptions about) the usable thermal output 

and characteristics of displaced onsite boilers. Commenters added that the credit awarded such 

facilities would be determined by prorating the electric output of the CHP system by comparing 

the CHP effective emissions rate to the area's 2012 average fossil emissions rate. Commenters

said that an equivalency approach to accounting for CHP benefits cannot adequately consider all 

of the potential CHP configurations. Further, commenters noted, the equivalency approach 

requires that a separate heat and power base case be developed, but in many cases an accurate 

base case cannot be established. For Great River Energy's two CHP facilities, commenters stated 

that the base case would have been to not develop the CHP relationship because the other 

potential thermal sources were not economical. According to commenters, this base case would 

have resulted in no net gain in employment, no direct economic gain for the steam hosts, and no 

indirect economic gain for the communities that support the steam hosts' operations.

Commenters added that the EPA's equivalency approach is predicated on the assumption that the 

steam host would have installed new equipment subject to an NSPS. In the case of the 

Spiritwood Station CHP facility, commenters stated that the thermal energy we export will be 

used in lieu of one host producing process heat with older, low-efficiency, high-emitting process 

heaters. Commenters noted that the Coal Creek Station sells thermal energy in the form of hot 

flue gases in addition to steam and that flue gas losses are approximately 20 percent of the 

energy losses at coal-fired power plants. Commenters stated that the environmental benefits of a 

CHP recovering and beneficially using thermal energy that would otherwise be wasted are 

indifferent to whether the thermal energy is recovered from steam or flue gases. Commenter 

concluded that the variable (Pt) PS is defined to only include the thermal output of steam, and it 

is not clear if (Pt) HR would allow for flue gas thermal sales as part of the CHP's gross energy 

output.

Commenters added that the EPA's logic is not clear for deducting the electric energy used to 

power boiler feed pumps from the definition of gross power output. Commenters said that 

deducting the boiler feedwater pump's electric energy consumption is a step that would be 

involved in a net energy output not a gross output. Furthermore, commenters stated, it appears 

that a facility with steam driven feedwater pumps would get to add, under (Pt) HR or (Pt) IE, the 

thermal energy in the steam used to drive the pump. Allowing the addition of steam energy to 

drive a boiler feedwater pump to the facility's gross energy output, while requiring the deduction 

of electric energy, double penalizes facilities with electric driven pumps commenters stated.

Commenters said that another approach could involve setting a de minimis threshold below 

which minimal incremental emissions would not result in discounting the electricity produced by 

unaffected CHP units. For a compendium of approaches suggested in the EPA's previous 

publications, see the list and URL addresses provided in Appendix E (DCN 23014-A9).

Whichever approach the EPA follows, commenters urged the EPA to provide clear guidance to 

the states so that states are encouraged to use CHP and WHP as compliance options in their 

plans. 
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Commenters said that some states, such as New Mexico, have many rural areas where costs for 

connection to the grid make distributed generation with storage capacity (off-the-grid) the most 

economic option for both residential and some commercial facilities. Commenters stated that 

New Mexico offers tax incentives for such applications. According to commenters, these 

resources, while small, still reduce the usage of fossil generation that otherwise would have been 

necessary without the installations. With proper evaluation, monitoring and verification, 

commenters said that these should be valid resources for crediting in a state plan.

Some commenters stated that it is not clear whether CHP would be subject to the same rules as 

energy efficiency (for example, in terms of timing and recommended approach to addressing 

double counting) or whether the rules would be more similar to those for renewable energy. 

Commenters explained that, while the proposal indicates that states can allow CHP to count 

towards compliance, it is not included in the main discussion of alternative compliance options 

in the proposed rule.

Commenters commented that new CHP systems (not covered under existing rule) installed by 

industrial facilities, commercial and institutional office buildings, and campuses should be 

considered as compliance measures in state compliance plans. Commenters stated that such 

systems significantly reduce the electricity demand from the utility distribution system and, 

therefore, the emissions associated with electricity production at affected EGUs. Commenters

added that this fact forms the basis for the 2012 Executive Order, Accelerating Investment in 

Industrial Energy Efficiency, which directed executive agencies, including the EPA, to use 

existing Federal authorities, programs, and policies to support investment in industrial energy 

efficiency and CHP to improve the competitiveness of U.S. manufacturing, lower energy costs, 

free up future capital for business to invest, reduce air pollution, and create jobs. Commenters

explained that these systems should be eligible for credit through a mechanism, such as an 

Energy Efficiency Resource Standard (EERS), that recognizes end-use energy efficiency gains 

and overall emission reductions. Commenters suggested that credit should only be given for the 

effective energy savings or emission reductions provided by these systems and not for their 

entire electrical output. The commented stated that, although under the scope of the proposed 

rule, the EPA may be limited to considering only the displaced emissions from affected EGUs 

and may not be able to consider the increased emissions resulting from a CHP installation 

beyond the fence, providing credit for full electric output of a CHP system without taking into 

account an increase in onsite emissions creates leakage and the potential for gaming the system. 

Commenters added that an acceptable approach to crediting CHP for reducing electric generation 

at the central station should account for any incremental increase in onsite emissions. 

Commenters described two possible approaches: (1) calculate a prorated credit for the CHP unit 

compared to the 2012 average fossil emissions rate of the compliance area, and (2) include CHP 

in a state's overall energy efficiency programs by adding the energy savings from new CHP 

systems to the savings of other energy efficiency measures implemented as part of the state 

program. Commenters also noted that the calculation of the energy savings from a CHP system 

could be determined by deeming a certain percentage of a CHP system's electric output as net 

energy savings. In addition, Commenters stated that a tiered system that ties the portion of 

electric output eligible to the CHP system's overall efficiency would allow systems with higher 

efficiency to receive more credit, would be simpler to implement, would provide an estimate of 

electricity savings, would encourage the installation of a more efficient CHP system design, and 

would have the added benefit of not requiring the consideration of emissions outside of the 
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power sector. Commenters noted that CHP can significantly increase the efficiency with which 

the required energy at an industrial facility is generated

Some commenters stated that the avoided emissions approach should be used for CHP systems 

when calculating an emissions rate that factors in both the electric and thermal outputs of the 

CHP. Commenters explained that the avoided emissions approach is more directly tied to the 

environmental benefit of the CHP system because the calculation is directly tied to the emissions 

displaced by the unit, and thus, is the preferred method for calculating an adjusted emissions rate 

under the CPP because it provides the most accurate representation of GHG benefits from CHP. 

Commenters noted that the EPA has already published a tool that can help states account for 

CHP under output-based standards and should direct states to these or other tools to help them 

account for the emissions benefits of CHP. Commenters noted that, if the equivalence approach 

is used for CHP, the EPA should provide full thermal credit for affected systems because 100 

percent thermal credit on a typical CHP system results in an effective CO2 emissions rate that 

more closely approaches the emissions rate determined by the avoided emissions method, 

whereas discounting the thermal output does not fully account for all of the benefits provided by 

CHP systems. Commenters explained that, in previous use of the equivalence approach, the EPA 

has applied a range of credits to CHP thermal output, ranging from 75 percent in the NSPS for 

Electric Utility Steam Generating Units to 100 percent in the NSPS for Stationary Combustion 

Turbines. Commenters also pointed out that a 100 percent credit has likewise been applied in 

several states that have used the equivalence approach in state regulations. Commenters noted 

that the EPA has already published a tool that can help states account for CHP under outputbased standards and should direct states to these or other tools to help them account for the 

emissions benefits of CHP. Commenters strongly advocate for the use of the avoided emissions 

approach for reasons of accuracy, reasonable simplicity, and potentially greater relevance in the 

particular regulatory context of the proposed rule. Commenters pointed out that, if the EPA 

wishes to provide guidance for the equivalence approach (for instance, if states adopt this 

approach), Commenters encouraged using a thermal credit that matches the actual design and 

operation of a particular CHP system, which has a strong bearing on system performance. 

Commenters also noted that the system-specific thermal credit could exceed the proposed 75 

percent value. In addition, one commenter stated that, for assessing performance by either the 

equivalence or avoided emission approaches, the same measurements of fuel input and useful 

electric and thermal outputs would be needed. Commenters remarked that robust evaluation, 

measurement and verification of CHP system performance would increase confidence in the 

efficiency benefits of the systems and that the thermal output from CHP systems should not be 

wasted or dissipated, but actually put to productive use. For this reason, Commenters strongly 

supported the use of independent verification (as done in other energy efficiency contexts) to 

develop an accurate picture of the realized emissions benefits from CHP systems.

Another commenter noted that CHP facilities should not be discriminated against, and that, 

assuming the sole metric for measuring carbon reductions is based on full fuel-cycle/carbon 

emissions allowances and that programs are in place to support the direct use of natural gas, 

natural gas fueled "topping-cycle" cogeneration plants should be supported rather than limited 

cogeneration from "bottoming-cycle" applications powered by waste heat. 

Commenters recommended that the Agency issue guidance on how states could obtain credit in 

their 111(d) compliance plans for CO2 reductions from CHP. A commenter explained that there 
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may be multiple viable methods for a state to obtain credit for CHP, depending on whether the 

CHP system is new or existing and whether it is large enough to be covered by GHG regulations. 

Commenters added that CHP systems may be eligible for credit for reducing an overall 

emissions rate for power generation or as an end-use energy efficiency measure by contributing 

energy savings. Commenters also pointed out that specific guidance is needed to help states 

account for the benefits of the thermal energy output of CHP. Commenters suggested that the 

EPA specify examples of how CHP can qualify for credit for achieving emission reductions and 

should describe scenarios in which CHP is an eligible pathway to compliance, both for CHP 

systems that are regulated power plants under a 111(d) rulemaking and for CHP systems that are 

not.

Several commenters stated that if the final rule continues to apply a system-wide approach, states 

will seek to achieve their emission targets through off-site energy-efficiency investments, 

hospitals, universities, manufacturing facilities, and others could help reduce emissions 

throughout the air shed by installing CHP and WHP systems. The commenters stated that while 

these investments will reduce regional emissions, because these facilities are now producing 

electricity on site, their own emissions will modestly increase. The commenters recommended 

that to encourage these investments, EPA should find a way to assure hosts that actions taken by 

facilities that are not directly covered by the rule to help states comply with the Carbon 

Guidelines will not adversely affect them under any potential future carbon pollution NSPS for 

another sector.

Commenters stated that EPA should structure the rule to better encourage the use of CHP, and 

provide specific guidance on how to incorporate the energy savings benefits of CHP into the 

building blocks. Commenter 23860 stated that EPA should provide guidance on CHP measures 

as to how they should be treated for calculations to provide states a clear path for taking 

advantage of these opportunities. Commenters 18400-18, 22758, and 24030 stated that because 

CHP accomplishes significant emission reduction, that the rule should be designed to encourage 

the use of CHP. Commenter 22758 stated that the State of New Jersey Energy Master Plan 

sets 1,500 MW goal for CHP capacity. Commenter 24030 urged EPA to issue clear guidance 

about how to incorporate CHP and waste heat to power into the building blocks. Commenter 

23962 stated that a recent study the American Council for an energy-Efficient Economy 

estimated that about 20 GW of new CHP capacity could be installed by 2030 if states would 

adopt good CHP policies under the CHP. This capacity would correspond to an energy savings 

potential of 0.15 % of retail electricity sales per year. Commenter 23341 expressed dismay and 

shock that EPA had not specifically addressed how to credit CHP in the building blocks.

Commenter stated that given that EPA is required to set a BSER for each major source of 

stationary emissions it is important that EPA not require or allow one source to count reductions 

in another source that is yet to be regulated. Commenters stated that there may be limited 

exceptions to this general rule, such as CHP. Commenters stated that the proposed rule is 

somewhat vague on the treatment of CHP and Commenters would argue that the emission 

reductions achieved by reducing fossil heating that is replaced with the waste heat from a CHP 

unit is integral to the EGU. Commenters stated that in the case of CHP units owned by utilities 

this rule seems to clearly be the best opportunity to capture those emission reductions but even in 

the case of an industrial self-generator. Commenters stated that they view this rule as an 

opportunity that such potential projects do not fall between the regulatory cracks. Commenters 
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recommended that the final rule allow states to fully count the carbon emission reductions 

resulting from the displaced fossil fuel thermal load.

Commenters presented a study to determine the viability of CHP for some states to meet their 

emission goals using ICF International's IMP and the CHPower model. Commenters found that 

CHP can offer a cost-effective solution towards achieving 111(d) compliance. Commenters said 

that a system-based 111(d) policy design puts these efficiency investments "over the top," 

shortening payback periods to the point that companies will choose to undertake projects at a 

number of industrial, commercial and institutional facilities. Commenters noted that allowing 

incremental combined heat and power to participate in 111(d) compliance alongside other clean 

energy sources will help ensure the full amounts of CHP deployment forecasted under the CHP 

Base Case and CHP 111(d) Policy Case are realized. Commenters stated that states wanting to 

foster this technology will need to consider how to fairly apportion emissions between the 

thermal and electricity energy outputs. Depending on the chosen design of the system-based 

approach, commenters said that methods may also be needed to fairly quantify emissions and 

emissions reductions. Commenters stated that additional solutions are needed to improve the 

attractiveness at the state level by lowering interconnection, standby and other costs for CHP 

units to access the grid. Moreover, commenters said that education and risk mitigation measures 

could be helpful in improving the likelihood that economical CHP will be developed. 

Commenters stated that while the EPA's draft rule encourages the use of energy efficiency and 

renewable energy as compliance options, it provides little guidance and limited support for the 

inclusion of non-ratepayer compliance options operated outside of conventional investor-owned

utility programs overseen by state public utility commissions. Commenters stated concern that in 

not adequately addressing these options, the EPA is making it extremely difficult for states to 

recognize emissions reductions resulting from the billions of dollars in annual energy 

investments in private and public-sector investments in CHP. Commenters stated that low natural 

gas prices and resilience concerns are driving new CHP investments by manufacturers, local 

governments, and educational institutions. Commenters stated State Energy Offices and others 

have worked to ensure barriers to installing CHP units are removed so that private market 

operators can advance this highly efficient, reliable heat and power option. Commenters stated, 

in fact, during Hurricane Sandy and other natural disasters, CHP systems allowed major 

hospitals and universities, for example, to operate independently of the electricity grid. 

Commenters stated the market opportunity for CHP was estimated at 130 GW in 2012. 

Commenters said that while 86% of existing U.S. CHP capacity is located at industrial facilities, 

CHP can also be an attractive resource for schools and hospitals, in district energy systems, and 

in military installations. Commenters stated that such on-site generation avoids the transmission 

and distribution (T&D) losses associated with electricity purchased via the grid from central 

stations and defers or eliminates the need for new T&D investment. Commenters said that CHP's 

inherent higher efficiency and elimination of transmission and distribution losses from the 

central station generator results in reduced primary energy use and lower greenhouse gas (GHG) 

emissions. Commenters described how distributed CHP Systems located at energy intensive 

industrial sites, large commercial buildings, and large institutional and government facilities are 

"supply side" resources with energy efficiencies of 60-80% compared to the 33% energy 

efficiency of traditional centralized electric power production.
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Commenters noted that tapping the potential of utility-owned or third party-owned CHP Systems 

at these Distributed CHP Systems are proven technologies that provide both supply-side capacity 

and demand-side reductions to the electric system. Commenters added that they provide baseload 

capacity with 95% reliability to the electric system that displaces load on existing "electric only" 

EGUs that would otherwise be dispatched in the regional electric system. 

Commenters noted three ways that voluntary actions involving CHP technology can reduce 

emissions at affected EGUs:

• Installation or uprating of CHP at an affected EGU reduces the EGU's 

emission rate by more efficiently using combusted fossil fuel. 

• Construction of new or uprating of existing CHP at facilities that are not 

affected EGUs ("non-affected CHPs") displaces electricity demand, and 

therefore emissions, from affected EGUs similar to other end-use energy 

efficiency measures. 

• Existing, as well as new, non-affected CHP facilities that primarily use 

renewable power as a fuel source ("renewable CHP") displaces 

emissions at affected EGUs similarly to other renewable energy 

measures. 

Commenters described how CHP satisfies BSER because it

1. Reduces CO2 emissions, 

2. Is cost effective, 

3. Enhances electric reliability, and

4. Is adequately demonstrated. Commenters stated that the remaining potential for CHP and 

WHP is great and evaluation, measurement and verification protocols for these 

technologies are well established. Commenters asked the EPA to highlight these benefits 

in the proposed rule and expressly state that CHP and WHP are valuable and acceptable 

compliance tools for unaffected units, notwithstanding their omission from the building 

blocks. Commenters provided extensive documentation demonstrating these points, 

especially cost effectiveness; reliability and the potential of the technologies 

Commenters provided documentation to support assertions that CHP can provide CO2

emission reductions at a lower cost than many RE technologies as well as technologies 

such as carbon capture and sequestration (CCS) that are discussed in the Proposed Rule 

as potential strategies in State Plans. 

Commenters stated that allowing CHP as a compliance mechanism will reduce the costs of 

compliance, especially in states projected to see higher than average compliance costs. 

Commenters added that CHP provides flexibility to states in cost-effectively achieving total 

emission reduction goals. Because there are significant disparities between states relative to 

renewable energy, which are not accounted for in the regional approach by the EPA in setting 

state goals for Building Block 3, commenters stated that CHP can be a useful element in any 
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state's Clean Power Plan, and it can play a particularly important role in states with low 

renewable potential.

Commenters also addressed the cost-effectiveness of CHP and provided several studies to 

document their conclusions including a Center for Clean Air Policy (CCAP) study in May 2014 

that concluded that "combined heat and power can offer a cost-effective solution towards 

achieving 111(d) compliance." Commenters also provided information on CHP and WHP.

Commenters said that many energy-intensive industries must compete in a global market. By 

reducing and stabilizing energy costs, commenters said that CHP can help U.S. industrial 

companies thrive and continue to provide jobs and tax revenue. Commenters also described how 

CHP enhances energy security and resiliency compared with large interconnected grids and 

described the economic consequences of grid failures. 

Commenters said that CHP units are capable of providing overall efficiencies of 60 to 80 

percent, leading to improved environmental performance, reduced energy consumption, and 

improved grid reliability compared with conventional generation. Commenters stated that CHP 

creates less pollution per unit of energy by using the energy potential of fuel inputs twice or three 

times, yielding half to a third of the emissions that would otherwise result from separate 

applications.

Furthermore, commenters said that the EPA should incentivize these highly efficient units by 

allowing facilities to include 100 percent of useful thermal output from CHP when calculating 

emission compliance. Commenters added that local applications of CHP also avoid transmission 

and distribution line losses, which should be consistent with average line losses for the state in 

which a particular CHP unit is located.

Some commenters stated that EPA should explicitly recognize CHP as a voluntary compliance 

option under Section 111(d),

Commenter said that the EPA must provide additional guidance for how carbon emissions from 

cogeneration facilities should be calculated because it is important that the carbon emissions and 

carbon emission rate be calculated based on the percentage of total cogeneration facility energy 

used that is directed to electricity generation. Commenter said that the percentage of carbon 

emissions associated with thermal energy used at a cogeneration facility should not have to be 

reported and should not be used in calculations for the cogeneration facilities or the state's carbon 

emission rate. 

Commenters commented that the EPA should provide appropriate and comprehensive guidance 

on how CHP can serve as a valuable compliance option towards meeting the goals of the Clean

Power Plan. Commenters noted that CHP systems may be directly affected or non-affected, 

which would result in different practical considerations (e.g., how to account for onsite emissions 

of non-affected CHP systems).

Commenters agreed that states will need guidance on how to value and count emission 

reductions from CHP. In particular, commenters said, states will need model rules detailing the 

best way to include CHP in renewable portfolio and energy efficiency standards and guidance on 

how to appropriately credit CHP output. Commenters added that these written materials could be 
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supplemented with a CHP webinar for states and other stakeholders involved in developing 

compliance plans. Commenters said that the EPA should issue a policy guidance memorandum 

from the EPA HQ to the regional offices and states that allows new industrial CHP facilities to 

perform air quality impact analyses that takes credit for regional air quality improvements due to 

offsetting emissions from EGUs. Specifically, commenters said that the EPA should allow the 

CHP units to reduce its modeled emission rates by the relative amount of avoided emissions 

when compared to electric grid emissions within the nearest sub-region of EPA's E-GRID 

database. 

Commenters recommended that the EPA allow utilities and states to receive CHP credits based 

on the net CO2 emissions reductions from a CHP system. As an alternative, commenters said, 

states could calculate an equivalent amount of net electricity savings from CHP, again based on 

the CO2 emission reductions. Commenters provided detailed recommendations about how these 

calculations could be made in separate comments on CHP, and in short, suggested that 60-80% 

of the total electrical output of the CHP system would be counted as "net electricity savings", 

with the exact value based on the type and efficiency of the overall CHP system. 

Commenters stated that CHP is considered by some states to be a renewable energy resource 

under certain circumstances and an energy efficiency resource in others. Commenters added that 

there are accepted methods for calculating the net CO2 emissions reductions from CHP systems, 

and 13 states currently permit electricity savings from CHP systems to contribute to achievement 

of energy efficiency resource standards in some manner. 

Commenters also recommended that a utility that provides CHP incentives or a state that has a 

CHP standard or incentive, financing or technical assistance program be eligible for energy 

efficiency credits, as long as the state includes the CHP policy or program in the state's section 

111(d) compliance plan. Commenters stated credits should not be provided to individual CHP 

projects, but rather to a utility or state program. Commenters suggested that the credits could 

either be CO2 emission reductions or electricity savings from a CHP system. Commenters 

explained that emissions reductions would be applied to the numerator in a state's emissions rate 

calculation; electricity savings would be added as a credit in the denominator (analogous to other 

energy efficiency credits as proposed by EPA).

Commenters agreed that it will not be difficult for states to set up CHP incentive programs to 

include CHP in their Clean Power plans, because there are many existing programs, including 

those catalogued in the EPA's 2014 report on GHG reduction programs. Commenters noted that 

states may also consider adopting other complementary policies to increase CHP and WHP 

deployment, and the EPA should provide concrete examples of these policies along with 

guidance about how they can be made enforceable, so that states can consider them when 

developing their state plans. In addition to encouraging states to utilize microturbine 

technologies, commenters said that EPA's standard should not inadvertently create disincentives 

to build or expand CHP. Instead, commenters stated that the rules should encourage the 

expansion and deployment of CHP facilities to the greatest extent practicable because using 

clean, efficient distributed generation provides secure power for critical facility loads, allowing 

some sites to eliminate or avoid using traditional backup diesel generators.
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Commenters suggested that the regulatory benefit of new and expanded CHP at non-EGU 

facilities can be treated similarly to EPA's proposed accounting for end-use energy efficiency. 

Commenters said that the electric and thermal output of such facilities can easily be quantified 

and included in the compliance calculation in the same way as energy efficiency or other clean 

generating resources. Commenters said the EPA should provide clear guidance to the states that 

expanding CHP at facilities other than affected EGUs is an approvable and cost effective 

compliance tool. Commenters said that the Final Rule should refer to "CHP" rather than 

"industrial CHP" to make clear to states that CHP systems beyond those at industrial facilities 

can and should be incorporated into State compliance plans. Commenters added that five 

categories of CHP should be creditable in State Plans: 

• Type 1. Existing power-only plant that is currently an affected EGU 

under Section 111(d). An existing power plant that is an affected EGU 

under Section 111(d) may be converted into a CHP plant, thereby 

providing useful thermal energy that had been previously wasted. Such a 

conversion would likely trigger regulation under Section 111(b) as a 

"new, modified or reconstructed" source. The increased energy 

efficiency and associated reductions in emissions in comparison with the 

Section 111(b) requirements should be creditable in State Plans. 

• Type 2. Existing CHP plant that is an affected EGU under Section 

111(d). Some CHP plants are affected EGUs under Section 111(d). 

Increased utilization of such plants, or switching to a lower carbon fuel 

(such as switching from coal to natural gas or from coal or gas to 

renewable fuels such as biomass) for such plants, should be creditable in 

State Plans. 

• Type 3. Existing CHP plant that is not an affected EGU under Section 

111(d). Most existing CHP plants do not meet the threshold for 

regulation under Section 111(d). Increased utilization of such plants 

should be creditable in State Plans because the increased generation will 

result in reduced output from affected EGUs.

• Type 4. New CHP plant that is an affected EGU under Section 111(b). 

New CHP plants may be constructed that will qualify as affected EGUs 

under Section 111(b) and will be regulated under Section 111(b). 

However, to the extent that such plants have a lower emissions rate than 

required under Section 111(b), the reduction in emissions rate below the 

Section 111(b) requirement should be creditable in State Plans under 

Section 111(d). Such highly efficient new CHP plants can be expected to 

displace generation, and thus emissions, from less efficient units that are 

affected EGUs under 111(d).

• Type 5. New CHP systems that is not an affected EGU under Section 

111(b). A new CHP plant may be constructed that does not meet the 

criteria for an affected EGU. These new systems should be treated as 

energy efficiency measures, and State plans should be able to recognize 
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the reduction of generation and associated emission reductions from 

affected EGUs that these new CHP systems provide.

Commenters said that the EPA should allow states to include the full impact of non-affected 

CHP on affected EGUs without "netting" of emissions from non-affected CHP. Commenters 

recommended an approach for CHP plants that are not regulated under Sections 111(b) or 111(d) 

of the Clean Air Act (Types 3 and 5) that does not account for marginal unregulated increases in 

CO2 emissions at the CHP plant. Although it creates a small potential for "leakage," commenters 

believed that this approach is warranted for simplicity of regulatory administration, to encourage 

CHP as a highly energy-efficient practice, and to avoid making CHP plants, many of which are 

small facilities, subject to onerous regulatory oversight beyond the existing regulations 

governing criteria pollutants. Commenters concluded that it is extremely important that if the 

output of a non-affected CHP plant is to be discounted based on CHP plant emissions, the EPA 

must take this into account in any future CO2 regulations relating the CHP plant's source 

category. 

Commenters stated that the proposed rule needs to expressly state that CHP qualifies as an 

efficiency resource at unaffected units, and the EPA should also clarify that WHP qualifies as a 

zero-carbon generation resource. Commenters described how, with limited exception, CHP is not 

expressly included in the four building blocks. Commenters stated that while CHP and WHP 

were generally not considered when setting the state emission targets, these technologies can and 

should be used to achieve them. Commenters stated that CHP and WHP can be used to reduce 

emissions at the affected facilities themselves (Building Block 1); by substituting generation at 

EGUs with expanded use of biomass CHP and WHP by other unaffected sources in the region 

(Building Block 3); or by displacing central generation by deploying CHP and WHP at hospitals, 

universities and factories (Building Block 4). Commenters were concerned that states will view 

the building blocks as a roadmap to achieve their targets and that they will not look beyond the 

limited policies that EPA expressly included therein. Commenters urged the EPA to expressly 

state the role of CHP and WHP in helping affected units achieve state emission targets and to 

provide examples of how these cleaner and more efficient power-generating systems might be 

included in state plans. 

Comment 19: Comments suggesting that states be given credit toward state's EE goals for other 

measures or programs.

Response 19: In the final rule, to the extent RE generation and demand-side EE measures are 

tied to a state plan, the quantified and verified MWh impacts of the measures may be used by an 

affected EGU or state to adjust a CO2 emission rate, regardless of whether the RE generation or 

demand-side EE savings occur inside or outside the state or territory. Consistent with the EPA’s 

calculation of the CO2 emission performance rates and state rate-based CO2 goals in the 

emission guidelines, the MWhs impacts are added to the denominator of an affected EGU’s 

reported CO2 emission rate, resulting in a lower, adjusted CO2 emission rate. The reported CO2

emissions reflect the actual emission reductions from the deployment of qualifying non-emitting 

and low-emitting resources across the regional grid. Further adjustment of CO2 emissions, such 
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as through the subtraction of emissions estimated by applying an emissions factor to the MWhs, 

would double count CO2 emissions impacts across the grid. For more information about specific 

methods to adjust the CO2 emission rate of an affected EGU to reflect RE and demand-side EE, 

including specific geographic eligibility requirements and limitations, and the eligibility 

requirements for resources that can used to adjust a CO2 emission rate, including but not limited 

to renewable energy and demand-side EE, see section VIII.K.1 of the final rule preamble of the 

CPP.

The following are summaries of the specific public comments under this comment:

Commenters requested that the proposed rule allow states to take credit for other programs or 

actions to meet their Clean Power Plan goals. In this regard, Commenters made four points. First, 

commenters stated that the state that implements an energy efficiency measure should be able to 

claim the emission reduction value of that measure, regardless of where the emission reduction 

occurs. Commenters explained that this approach provides the proper incentives for states and 

individual utilities to pursue the most cost-effective emissions reductions throughout the country 

and helps mitigate the proposed rule's inherent penalties against states, such as Oregon, that have 

decades of experience in energy efficiency. Second, commenters remarked that states should 

receive credit for energy efficiency measures that reduce the demand regardless of the type of 

generation serving the load. Commenters explained that the principles of economic dispatch 

demonstrate that fossil resources are generally the first resources to be curtailed as a result of 

energy efficiency, and even if an end-user's power is fully provided by the hydro-electric system, 

the end-user's reduced demand will extend the hydropower system and reduce output from fossil 

resources and, as a result, reduce emissions. Commenters added that the same should be true for 

energy efficiency gains that displace other types of renewable and/or non-emitting generation. 

Commenters noted that, in establishing Oregon's goal, the proposal counts energy efficiency 

from all of the state's electricity customers, even those who receive their power exclusively from 

the hydropower system, and accordingly the EPA should clarify that Oregon can take full credit 

for energy efficiency investments made by all customers, regardless of whether their power is 

provided in whole or in part by emissions-free generating resources. Third, commenter stated 

that the emission reduction value of energy efficiency measures should be equal to the emissions 

rate of the regional power pool's marginal resources. Commenters explained that energy 

efficiency reduces the demand for marginal resources within the regional power pool due to the 

interconnected nature of the electric grid and individual power pools; therefore, each state should 

be allowed to use the marginal hourly emissions rate (averaged over a year) from its power pool 

when assigning an emission reduction value to energy efficiency. Finally, commenter stated that 

states should be able to take credit for savings from demand response, enforcement of building 

codes, federal and state appliance standards, and market transformation efforts. Commenters 

explained that, while use of such measures may require further development of evaluation, 

measurement, and verification methodologies, states, such as Oregon, that lead the nation in 

energy efficiency uniformly point to such measures as the most cost effective and reliable means 

of reducing the demand for power and emissions.
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Comment 20: Comments supporting the inclusion of EE as a component of the BSER and state 

use of expanded EE measures.

Response 20: In this final rule, EE is no longer included in the determination of the best system 

of emission reduction. However, demand-side EE and other non-BSER measures may be 

included as a part of a state’s plan to meet the emission guidelines. To the extent demand-side 

EE measures are tied to a state plan, the quantified and verified MWh impacts of the measures 

may be used by an affected EGU or state to adjust a CO2 emission rate, regardless of whether 

the demand-side EE savings occur inside or outside the state or territory. This adjustment results 

in a lower adjusted CO2 emission rate. For more detail on the BSER, refer to section V of the 

preamble. For more information about specific methods to adjust the CO2 emission rate of an 

affected EGU to reflect demand-side EE and eligibility requirements for resources used to adjust 

a CO2 emission rate, including but not limited to demand-side EE, see section VIII.K.1 of the 

final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that in light of the uncertainties associated with Building Block 4, demandside EE requirements should be included as an optional means of compliance with a performance 

standard grounded in the statute. Commenters agreed that EE is an important goal and supported 

use of demand-side EE as a means of reducing demand for electricity. Commenters stated it is 

not appropriately incorporated as a requirement into a CAA section 111(d) standard of 

performance, but rather, EPA should consider EE programs, along with other measures that 

reduce emissions of CO2 discussed in the following section, as an optional means of compliance 

with a CAA section 111(d) standard. Under this scenario, commenters stated they would be able 

to adjust the emission rate based on avoided MWh across its members by adding the avoided 

MWh to the denominator of the pounds per CO2/MWh emission rate. 

Commenters stated EPA should encourage states to develop a clear path for inclusion, crediting, 

and administrative review and oversight of non-utility-delivered energy efficiency activities 

providing emissions reductions included in state plans. Commenters stated this may include 

energy savings performance contracts, low-income weatherization programs, industrial energy 

efficiency and other privately contracted and delivered energy efficiency historically 

unaccounted for in ratepayer and state programs.

Comment 21: Comments suggesting that EPA consider a centralized EE registry to facilitate 

accounting consistency.

Response 21: The final rule allows for the use of the quantified and verified MWhs from 

demand-side EE measures tied to a state plan to adjust a CO2 emission rate, provided they meet 

the general eligibility requirements outlined in section VIII.K.1 and the MWh electricity savings 

are properly quantified and verified in accordance with section VIII.K.3 of the final rule 

preamble of the CPP.
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Consistent with the EPA’s calculation of the CO2 emission performance rates and state ratebased CO2 goals in the final emission guidelines, the MWhs impacts are added to the 

denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted 

CO2 emission rate. The MWh accounting method corresponds with the use of MWhdenominated Emission Rate Credits (ERCs) in the rate-based emission trading framework 

specified in this rule. ERCs can be issued for qualifying measures as discussed at section 

VIII.K.2. (a-b) of the final rule preamble, and include RE, demand-side EE, and other measures, 

such as DSM, CHP and incremental nuclear generation.

State plans with rate-based emission trading programs must include specific provisions in their 

state plan and trading program to ensure that ERCs are properly tracked from issuance to 

submission by affected EGUs for compliance and to ensure they are only used once to meet a 

regulatory obligation. This is addressed through specific requirements for tracking account

holders, ERC issuance, ERC transfers among accounts, compliance true-up for affected EGUs,

and an accompanying tracking system infrastructure design based on business rules specified in 

the emission trading program regulations. Each issued ERC must have a unique identifier (e.g. 

serial number) and the tracking system must provide for traceability of issued ERCs back to the 

program or project for which they were issued.

In response to comments about the value of the EPA’s support in developing and/or 

administering tracking systems – either on a regional and/or national basis - to support state 

administration of rate-based emission trading systems, the EPA is exploring options for 

providing such support and is conducting an initial scoping assessment of tracking system 

support needs and functionality. For more information about the general accounting approach for 

adjusting a CO2 emission rate, see section VIII.K.1.a.(1). For more information on requirements 

for rate-based emission trading approaches and tracking requirements, see section VIII.K.2. 

The following are summaries of the specific public comments under this comment:

Commenters stated EPA should not limit EE measures to those with well-understood savings 

potential. Commenters stated instead, EPA should consider a centralized EE registry to facilitate 

accounting consistency. Commenters stated presumably, the purpose of having EE as a 

compliance measure is to promote its use and spur innovation. Commenters stated that limiting 

allowable measures would reduce the incentive for innovation and ultimately reduce possibilities 

for saved generation. Commenters stated however, they recognize that the principles of 

consistency, transparency, accuracy, and the avoidance of double counting are very important. 

Commenters stated an established centralized registry or regional registries for RECs could serve 

to standardize and verify EE savings across states. 

Comment 22: Comments on crediting energy code adoption and compliance programs.

Response 22: The final rule allows for the use of the quantified and verified MWhs from 

demand-side EE measures, potentially including building energy code and compliance programs, 

to adjust a CO2 emission rate, provided they meet the general eligibility requirements outlined in 

section VIII.K.1 and the MWh electricity savings are properly quantified and verified per the 

EM&V requirements in the final rule. For more information regarding EM&V requirements and 
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the draft EM&V guidance for demand-side EE which is being released in conjunction with the 

proposed model rule, see Ssection VIII.K.3 in the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated as a compliance mechanism under building block four, they encouraged EPA 

to explicitly allow states to count the incremental energy savings from energy code adoption and 

compliance programs. Commenters indicated States that adopt the most recent version of the 

energy code on a regular, three-year cycle reduce energy waste in both commercial and 

residential buildings. Commenters stated for example, the 2010 version of the model energy code 

ASHRAE 90.1 is 30 percent more energy efficient than the 2004 version of the same model 

code. 

Commenters stated that because energy codes only save energy if they are enforced, EPA should 

also allow states to count energy savings that result from code compliance beyond the status quo. 

Commenters stated according to the Institute for Market Transformation (IMT), energy code 

compliance can be as low as 50 percent. Commenters stated in Rhode Island, the electric utility 

National Grid conducted a survey that found energy code compliance rates for specific energy 

systems to be as low as 7 percent for bi-level lighting controls and 50 percent for lighting 

occupancy sensors. Commenters stated despite a state-wide compliance average of 70 percent, 

they found that no single building was in full compliance; in other words, buildings in Rhode 

Island are performing 30 percent worse than the code requires of them. 

Comment 23: Comments on energy code compliance.

Response 23: The final rule allows for the use of the quantified and verified MWhs from

demand-side EE measures tied to a state plan, such as building energy codes, to adjust a CO2

emission rate, provided they meet the general eligibility requirements outlined in section 

VIII.K.1 of the final rule preamble and the MWh electricity savings are properly quantified and 

verified per section VIII.K.3.

The following are summaries of the specific public comments under this comment:

Commenters stated that IMT estimates that programs targeting energy code compliance have a 

600 percent return on investment, $6 in energy savings for every $1 invested. With code 

compliance hovering around 50 percent, commenters stated there is a large opportunity for states 

to better enforce their energy codes, which will result in additional energy savings and CO2

reductions. How states approach the enforcement challenge should be decided by each state 

based on local circumstances, but commenters recommended that states focus on the following 

ways to improve energy code compliance:

• Educate and outreach to the architects, contractors, and builders with the 

responsibility to design and build and retrofit code-compliant buildings;
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• Combine both classroom and on-the-job energy code training for code 

officials with regular follow-up and continuing education, especially 

when new versions of the code are adopted;

• Provide tools for code officials to be more productive with their time so 

that they can assess energy code compliance without spending additional 

time on a job site;

• Require tests of newly constructed buildings by third-party experts to 

boost compliance by builders; and

• Hire additional code officials to support existing officials who do not 

have sufficient time to adequately inspect all of the buildings that they 

are required to inspect.

• Simply improving compliance with existing energy codes would have a 

major impact on reducing CO2 emissions for a relatively small 

investment. We recommend that EPA explicitly recommend that states 

focus on energy code compliance as a cost-effective way to drive 

investments in energy efficiency as a tool to comply with building block 

4. 

Commenters stated data from EPA's ENERGY STAR Portfolio Manager shows that buildings 

that benchmark their energy use reduce their energy consumption by seven percent over three 

years. Commenters stated that around the country, two states (i.e., Washington and California), 

one county (i.e., Montgomery County, Maryland), and ten cities (i.e., Austin, Boston, 

Cambridge, Chicago, Minneapolis, New York City, Philadelphia, San Francisco, Seattle, and 

Washington, DC) have enacted mandatory benchmarking ordinances that require certain 

buildings to measure their energy performance using ENERGY STAR Portfolio Manager. 

Commenters stated EPA's own analysis of 35,000 buildings showed that those buildings that 

benchmarked their energy use reduced their energy consumption by 2.4 percent per year on 

average with the least efficient buildings reducing their energy consumption by the greatest 

amount (12 percent over three years). Commenters recommended that EPA allow states to count 

energy savings from mandatory benchmarking programs under building block 4, so long as those 

energy savings cannot be double counted under a separate program (e.g., utility rebate program). 

Regarding building energy codes, commenters recommended that the EPA indicate that the 2009 

International Energy Conservation Code (IECC) was the national baseline code as of 2014, and 

allow states to receive energy savings credits for new homes and commercial buildings built to 

meet a code that is more stringent than this baseline. Commenters stated that the 2009 IECC was 

the code in effect in about 25 states as of mid-2014, with only a handful of states having already 

adopted the 2012 IECC.4. Commenters recommended that energy savings credits should begin in 

2020 for new buildings constructed starting in 2017 that meet an energy code that is more 

stringent than the 2009 IECC. Commenters stated that the credits would be independent of date 
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of adoption (i.e., states that adopted the 2012 or 2015 versions of the IECC prior to 2017 would 

not be penalized for doing so).

Commenters noted that states that are home rule states adopt building codes at the local level. 

Commenters noted that these states should also be allowed to receive energy savings credits, as 

long as the state includes a building energy codes initiative in its state Section 111(d) plan and 

tracks construction levels in local jurisdictions that have adopted these up-to-date codes. In 

addition, commenters recommended that the EPA allow states to receive energy savings credits 

for efforts that improve energy code enforcement and compliance rates, as measured through 

code compliance studies that are conducted in accordance with the EPA-approved protocols on 

the topic.

Commenters estimated that moving from the 2009 International Energy Conservation Code 

(IECC) to the 2015 IECC would save about 614 GWh per year in the region served by the 

commenters (AZ, CO, NM, NV, UT and WY) during 2017-2025, given projected construction 

rates and energy savings potential state-by-state. Commenters stated that this is equivalent to 

about 0.25% savings per year given projected electricity use in the region during this time period 

(which is approximately 250,000 GWh per year). Commenters stated that the 2009 IECC 

"baseline" is the building code now most prevalent in the region, although some jurisdictions 

recently adopted the 2012 IECC. Likewise, commenters noted that ACEEE estimates that 

adopting state-of-the-art building energy codes nationwide could provide incremental annual 

savings of 10,900 GWh per year in 2020 and 12,100 GWh per year in 2030 Commenters stated 

that this is equivalent to about 0.25% savings per year based on the most recent Energy 

Information Administration (EIA) forecast of future electricity consumption.

Commenters noted that States can adopt minimum efficiency standards on products not regulated 

by the federal government under the National Appliance Energy Conservation Act (NAECA) 

legislation. Commenters stated that California and other states have adopted state efficiency 

standards in recent years on televisions, battery chargers, and other electronic products. 

Commenters stated that according to the Appliance Standards Awareness Project (ASAP), 

twelve states currently have state appliance efficiency standards in effect [see State Adoption of 

Energy Efficiency Standards. Boston, MA: Appliance Standards Awareness Project. 

http://www.appliance-standards.org/states.] Commenters stated that ASAP suggests that there 

are ten products including battery chargers, commercial dishwashers, quartz halogen lamps and 

room air cleaners that are good candidates for state appliance standards at this time, and that 

adopting these standards would provide substantial net economic benefits for consumers and 

businesses. Commenters stated that other products, including televisions, set-top boxes, and 

commercial and industrial fans and pumps, may be candidates for state appliance standards in the 

future as well.

Comment 24: Comments on energy savings from federal government programs.

Response 24: The final rule allows for the use of the quantified and verified MWhs from 

demand-side EE measures tied to a state plan to adjust a CO2 emission rate, provided they meet 
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the general eligibility requirements outlined in section VIII.K.1 and the MWh electricity savings 

are properly quantified and verified per section VIII.K.3 of the final rule preamble of the CPP.

Federal measures are not tied to a state plan and therefore the associated MWhs cannot be used 

to adjust a CO2 emission rate.

The following are summaries of the specific public comments under this comment:

Commenters stated that credit should not be given for energy savings that result from federal 

appliance and equipment efficiency standards or other federal mandates. Commenters argued 

that, although these programs are worthy efforts that are reducing CO2 emissions, they are not 

occurring as a result of state or local initiatives. However, commenters recommended that 

programs that are jointly funded by states or utilities and the federal government should be 

eligible for energy savings credits for the portion of the programs that are not federally funded, 

with energy savings pro-rated on a funding share or some other appropriate basis.

Comment 25: Comments supporting the use of demand response.

Response 25: In this final rule, EPA provides states with the flexibility to use the quantified and 

verified MWhs from demand-side EE measures tied to a state plan to adjust a CO2 emission rate, 

provided they meet the general eligibility requirements outlined in section VIII.K.1 and the 

MWh electricity savings are properly quantified and verified per section VIII.K.3 of the final 

rule preamble of the CPP. 

In the final rule, avoided MWh of electricity use that result from demand-side management 

(DSM) may be used to adjust a CO2 emission rate. Eligible DSM actions are those that are nonemitting and avoid, rather than shift, the use of electricity by an electricity end-user, as discussed 

in VIII.K.1.a.(4) of the final rule preamble. Actions that shift electricity demand from one time 

of day to another are not eligible, as these measures do not avoid electricity use from the grid. 

Use of emitting generators as a DSM measure are also not eligible. The MWh that may be used 

for such an adjustment are determined based on the MW of demand reduction multiplied by the 

hours during which such a demand reduction is achieved (MW of demand reduction x hours = 

MWh avoided). DSM measures must be appropriately quantified and verified, in accordance 

with requirements in the emission guidelines, as discussed in section VIII.K.3 of the final rule 

preamble.

Energy storage may not be directly recognized as an eligible measure that can be used to adjust a 

CO2 emission rate, because storage does not directly substitute for electric generation from the 

grid or avoid electricity use from the grid. However, the final rule acknowledges the value of 

energy storage as an enabling measure that facilitates greater use of RE. Additional information 

regarding energy storage is in section VIII.K.1.a.(5) of the final rule preamble.

The final rule does not allow measures that reduce CO2 emissions outside the electric sector to be 

counted toward meeting a CO2 emission performance levels for affected EGUs or a state CO2

goal as discussed in section VIII.K.1.c.
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The following are summaries of the specific public comments under this comment:

Commenters stated demand response is demonstrably "technical feasible" based on its use today; 

FERC's recent data show there were over 28,000 MW of demand response participating in 

wholesale markets that cover the majority of the country in 2012, equaling 6 percent of total 

peak demand , and it reliably delivers over 90 percent of expected capacity. Commenters stated 

demand response's role as an ancillary resource will become increasingly valuable as more 

renewable generation comes online, and demand response becomes a means of balancing 

variable supply. Commenters provided an example where an Alcoa aluminum smelter in Indiana 

consistently provides nearly 10 percent of the spinning reserves used by the Mid-Continent 

Independent System Operator (MISO). Commenters stated that while demand response has 

become a relied-upon and widely-integrated resource, its potential remains largely untapped; the 

2009 FERC National Assessment of Demand Response Potential reported that under an 

"Expanded Business as Usual" Scenario, there will be 82 GW of peak demand reduction 

potential by 2019, and under the "Achievable" Scenario, there would be 138 GW of reduction. 

Commenters stated demand response reduces emissions the following ways: (1) directly through 

load reductions during peak periods (0.05 to 0.35 percent); (2) directly by providing ancillary 

services otherwise supplied by fossil-fueled generation (0.3 to 0.8 percent); and (3) indirectly, by 

facilitating increased penetration of renewable resources and the displacement of generation 

from older, inefficient sources (approximately 1 percent). Commenters stated that under 

emergency-based programs, instead of dispatching inefficiency units to balance supply with 

demand, grid operators and utilities can dispatch demand response and reduce demand by 

hundreds or thousands of MWs at a time. Commenters noted an example during a September 

2013 dispatch, where demand response reduced reliance on fossil-fueled units by nearly 6,000 

MW across PJM , which "represents over 1.1 million electricity customers reducing load as a 

wholesale market resource". Commenters also noted that when electricity demand is high, 

transmission and distribution equipment tends to be less efficient, resulting in greater overall 

system losses. Commenters indicated that Navigant estimated that direct emissions savings from 

load curtailments during demand response dispatches range from 0.05 to 0.35 percent of overall 

emissions even after accounting for onsite backup generation. Commenters stated demand 

response can directly reduce system CO2 emissions by 0.3 to 0.8 percent from existing EGUs by 

providing "spinning reserves," i.e., when generators are generating electricity in an amount that 

is less than their full capability so they can ramp up quickly as grid operators call on them, and 

when generators are running at these lower capacity factors, they are also less efficient and have

higher emission rates. Commenters stated demand response can serve the same function by 

quickly ramping down demand instead of ramping up generation, given that demand response is 

in many cases capable of reducing load in 30 minutes or less. Commenters indicated that 

Navigant noted that plants run less efficiently when turned down and thus emit more CO2.

Commenters stated DR-provided ancillary services can reduce CO2 emissions due to more 

efficient dispatch of generation units. Commenters stated demand response can have a large 

indirect impact on emissions in the following ways:

a. facilitating the use of renewable resources to maximize their emissions impact, 

and 
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b. contributing to the retirement of older, inefficient generating units and replacing 

them with demand resources. Commenters stated that during periods of low 

electric load and high renewable output, demand response can reduce emissions 

by as much as 10 percent, noted that Navigant indicated there may be situations 

where renewables need to be curtailed such that sufficient fossil fuel generation 

is available to provide ancillary services, and in these circumstances, DR can 

instead provide the ancillary services, thereby preventing the curtailment of 

renewable resource. Commenters noted an example for the Bonneville Power 

Administration (BPA) that has demonstrated that fast-acting demand response 

can also offset fluctuations both up and down in wind power output, where BPA 

controls were connected to half a dozen frozen food warehouses and the chillers 

were able to increase operation when wind power suddenly increased, and the 

chillers could be shut off in response to a sudden decrease in wind generation. 

Commenters stated that as the penetration of renewable generation increases, 

reserve requirements will likely increase; demand response can be deployed far 

more cost-effectively than other resources to provide reserves, rendering the 

economics of renewables more attractive.

Commenters stated emission reductions resulting from Demand Response measures should be an 

acceptable component of a State Compliance Plan. Commenters stated EPA should give special 

attention to demand response and separate its treatment for emission reduction credit from 

energy efficiency under the broad category of demand-side measures. Commenters stated 

demand response is a category and not a single type of demand-side measure; it can be used for 

the development of several types of measures capable of reducing load at specific times. 

Commenters stated demand response is capable of reducing peak demand; moving load from a 

time of higher incremental emissions to a time when emissions are lower so that overall 

emissions are reduced; and increasing shoulder hour energy use and is capable of supplying load 

drop, load balancing, and spinning reserves for ramp up or ramp down requirements. 

Commenters stated EPA should initially work with a range of Independent System Operators, 

Regional Transmission Operators, and the FERC to better understand the emission reduction 

opportunities presented by using this unique demand side measure. Commenters stated that 

where a state can demonstrate its demand response programs offset fossil-fueled balancing 

resource within the power pool serving the state, or where demand response shifts loads to a time 

of lower marginal carbon dioxide emissions, EPA should give credit for the carbon dioxide 

reductions from those measures. 

Commenters offered specific recommendations for the agency's consideration, including the 

following:

• Support the development of state plans that anticipate a role for energy 

storage.

• Develop evaluation criteria that help states demonstrate the role that 

storage will play in the accelerated introduction of non-emitting 

technologies.
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• Require states to conduct ongoing monitoring and evaluation of the role 

of energy storage in their electricity systems and introduce corrective 

measures where possible.

• Consider how emissions reductions in other sectors (such as 

transportation) might be facilitated by the introduction of technologies, 

such as electric vehicles.

• Consider the calculation of net emissions changes, including changes in 

other sectors, in state plans. 

• Assist states in accounting for the potential role of electric vehicles in 

the determination of activity levels that are used in the transition from 

rate- to mass-based standards. 

 

5.2.5 Other

This section discusses on the effects the rule will have on developing CHP systems and 

conversion of coal towards natural gas and nuclear energy sources, reduction opportunities 

available to EGU owners, defining enforcement and compliance measures, non-numeric 

emission limitations, and adding safety valve when cost and grid reliability becomes an issue. 

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments regarding the general discussion of the spectrum of reduction 

opportunities available to EGU owners and a summary of California's carbon reduction 

programs.

Response 1: The EPA agrees that there are many opportunities for affected EGUs and states to 

reduce their CO2 emissions and the final rule provides states and affected EGUs with significant 

flexibility in choosing the most appropriate measures for them to achieve their CO2 emission 

rate. For more information about the MWh accounting approach states and affected EGUs can 

use to adjust the CO2 emission rate of an affected EGU, and the eligibility requirements for 

measures and resources they can use, see section VIII.K.1 of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters strongly supported EPA's belief that owners of units operating across a wide range 

of corporate, institutional and market structures can take advantage of a broad range of reduction 

opportunities included in the building blocks. In support of this finding, Commenters discussed 

various forms of actions that can be and are taken by EGU owners and operators that allow the 

EGU to reduce utilization and ensure that foregone EGU output is replaced by lower-emitting 
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generation or offset by demand reductions. Commenters discussed a list of actions, which

included the following topics:

• Owners and operators of EGUs regularly procure renewable energy 

generation and have the capability to do so in the future. Many fossil 

fuel-fired EGU owners also own or contract for renewable energy and 

can control the dispatch mix among these sources. Integrated utilities 

can and often do own or contract for a portfolio of generation resources, 

which can include a combination of fossil fuel-fired EGUs and low- and 

zero-emitting generators. In other instances, EGUs are owned by 

generation and transmission companies that operate integrated electric 

systems that directly serve retail utilities. These utilities also have the 

ability to shift generation among resource types. In addition to 

developing and owning renewable generation facilities, these providers 

have the flexibility to sign bilateral contracts in the form of power 

purchase agreements (PPAs) for renewable generation.

• EGU owners participating in organized markets retain sufficient control 

to substitute fossil fuel-fired generation with renewable generation. The 

replacement of fossil fuel-fired EGUs with renewable generation can be 

accomplished by EGU owners, even when those EGU owners revolving

determine dispatch among energy sources. This situation is most likely 

to occur in states where utilities are participants in a regional 

transmission organization (RTO). Independent power producers (IPPs) 

also can and do own both renewable energy generation and fossil 

generation. When an IPP commits to shifting its generation portfolio, it 

can do so at reasonable cost and without reliability impacts.

• EGU owners can ensure that the interconnected electric system has 

sufficient renewable energy to accommodate reductions in the utilization 

of their own assets is by purchasing and retiring renewable energy 

credits or other environmental attributes associated with low- or zerocarbon electric generation. By purchasing and retiring RECs for each 

MWh of reduced utilization, the IPP can ensure that a MWh of 

renewable power has been generated. To date, there has not been 

significant need for merchant generators to purchase RECs. However, 

there are no legal or technical obstacles that would prevent this action.

• Owners and operators of EGUs regularly procure energy efficiency and 

have the capability of doing so in the future. EPA's determination of the 

amount of achievable, cost-effective energy efficiency as part of 

Building Block 4 serves as a quantification of the amount that fossil 

fuel-fired EGUs can reduce utilization at reasonable cost and while 

meeting energy requirements.

• EGU owners with retail customers have clear opportunities to offset 

fossil fuel-fired generation through reduced demand. Utilities that own 
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EGUs and that directly serve end-use customers provide the most 

straightforward example of the ability to pair reduced CO2 emissions 

from reduced EGU utilization with end-use energy savings. Federal 

utilities also invest in end-use energy efficiency to reduce the utilization 

of their fossil fuel-fired assets. The operation and contracting of energy 

efficiency programs and services is adequately demonstrated for a wide 

range of utilities.

• Non-utility EGU owners also provide energy efficiency services that can 

complement reductions in their fossil fuel-fired unit utilization. IPPs that 

do not directly serve customer load are still able to take actions that 

result in end-use energy savings. If they have not already invested in 

complementary business lines to provide energy efficiency directly, IPPs 

also have the legal and business flexibility to contract with third party 

energy efficiency service companies.

• EGU owners can demonstrate demand reductions through purchase and 

retirement of energy efficiency credits. Non-utility entities, including 

IPPs, can purchase and retire credits representing energy savings. This 

market is not as established as the market for RECs; however, markets 

for these credits (called "energy savings credits", "energy efficiency 

certificates" or "white tags") are developing and certainly meet the 

threshold for being "adequately demonstrated."

Commenters provided a general discussion of the State of California's carbon reduction 

programs including energy efficiency programs, renewable energy programs and a multi-sector 

cap and trade program. Commenters noted programs demonstrating the state's small renewable 

energy systems.

Comment 2: Comments with concerns that the EPA's CPP rule incentivizes conversion of coal 

towards natural gas over wind/solar power and energy efficiency (EE).

Response 2: In the final rule, the EPA recognizes the value of renewable energy as part of the 

Best System of Emission Reduction and energy efficiency as a low cost resource that can reduce 

CO2 emissions from affected EGUs. Demand-side EE is not used in calculating the CO2

emission performance rates in the final emission guidelines, however, the final rule gives states 

the flexibility to use zero- and low-emitting resources to achieve their CO2 emission performance 

rate. Renewable energy and demand-side EE measures that are tied to a state plan and achieve 

quantified and verified MWh savings may be used to adjust a CO2 emission rate, provided they 

meet the general and specific eligibility requirements for resources used to adjust a CO2 emission 

rate, described in Ssction VIII.K.1 of the final rule preamble of the CPP. The measures must also 

meet the eligibility requirements and provisions related to demand-side EE programs and 

projects, if applicable, and the requirements and criteria related to proper quantification and 

verification of MWhs from demand-side EE savings are described in section VIII.K.3 of the final 
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rule preamble. Since states and affected EGUs will need to rely upon a system of measures to 

achieve their CO2 emission performance rates or state CO2 emission goal, the final rule provides 

them with the flexibility to implement a suite of measures, including renewable energy and 

demand-side EE.

The following are summaries of the specific public comments under this comment:

Commenters argued that the EPA's proposed rule incentivizes conversion of coal towards natural 

gas and nuclear energy sources, over conversion to wind or solar power and energy efficiency. 

EPA's proposed plan only lists energy efficiency as an option and not a mandate. Commenters

noted specific concern with the efficiency factor and difficulties for states that do not have a 

diversified energy portfolio.

5.3 QUANTIFICATION, MONITORING, AND VERIFICATION OF DEMAND-SIDE

ENERGY EFFICIENCY PROGRAMS AND MEASURES

This section addresses comments on Quantification, Monitoring, and Verification of End-use 

Energy Efficiency Programs and Measures, and includes discussion on EM&V for demand-side 

EE programs, ISO forward capacity markets, accuracy of energy savings estimates, technical 

considerations, use of EM&V protocols and guidance, review of EM&V plans, and CHP. We 

have organized the comments in this section under eleven subsections, 5.3.1 through 5.3.11. 

Responses to the comment topics of these subsections are discussed below along with summaries 

of the specific public comments.

5.3.1 EM&V for demand-side energy efficiency programs overseen by state PUCs

This section summarizes comments on the requirements for EM&V for EE programs overseen 

by state PUCs.

Commenters have raised a number of issues related in this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: In developing EM&V requirements, commenters urged EPA to continue 

communicating with PUCs, DOE, and any other entities charged with oversight of demand 

reduction programs.

Response 1: The EPA recognizes that there are many established EE programs with PUC 

oversight. The EPA’s approach, as proposed in the Federal Plan, leverages existing state 

oversight, approval, and certification processes, as well as industry protocols. The EPA also 

recognizes the importance of striking a reasonable balance between EM&V rigor and credibility 

on the one hand, and the costs associated with project performance evaluation on the other. 
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Another objective for the EPA’s model rule criteria is to avoid excessive interference with 

EM&V practices that are already robust, transparent and working well. Therefore, the EPA’s 

proposed Federal Plan approach establishes a floor for EM&V practices to ensure credibility and 

certainty in savings estimates across jurisdictions. The flexibility in EPA’s proposed approach 

would allow many states to leverage their existing EM&V infrastructure with minimal additional 

effort. The EPA recognizes that excessive EM&V will discourage the implementation of EE 

programs.

The EPA thanks you for sharing North Carolina’s EM&V experience for RE and EE programs. 

Renewable energy and demand-side EE and other non-BSER measures that are tied to a state 

plan and achieve quantified and verified MWh savings may be used to adjust a CO2 emission 

rate, provided they meet the general and specific eligibility requirements for resources used to 

adjust a CO2 emission rate, described in Section VIII.K.1.a.(2) of the final rule preamble. The 

measures must also meet the eligibility requirements and provisions related to demand-side EE 

programs and projects, if applicable, and the provisions related to proper quantification and 

verification of MWhs from demand-side EE savings, described in section IV.D.8 of the preamble 

to the proposed Federal Plan. 

The following are summaries of the specific public comments under this comment:

Commenters urged EPA to continue communicating with PUCs, DOE, and any other entities 

charged with oversight of demand reduction programs. Commenters stated that if the EM&V 

methods required by EPA for compliance are significantly different from the EM&V methods 

already approved by a state PUC for established EE programs, there will be implementation 

delays. Commenters advocated that EM&V should not be required for any existing programs that 

are subject to PUC oversight because these programs are subject to public review, which leads to 

protocols with a high degree of certainty for EM&V results. Commenters stated that excessive 

EM&V sill discourage the use of emerging energy efficiency measures.

Commenters stated that a new EM&V process is not needed for any energy efficiency programs 

using building codes and standards, because the impact of codes and standards are reviewed by 

the PUC as part of the load forecasting requirements. Commenters advocated that the only 

energy efficiency measures that should be allowed for compliance are those supervised by the 

electric utility (even if actually implemented by a third party), because the effect of these 

programs have been tracked and reported to EIA.

Commenters stated there are various sources for EE data. Commenters stated that it is generally 

reported on a program by program basis and is reported as both incremental and cumulative, 

depending on the data source. Commenters stated that North Carolina requires extensive EM-V 

of each MWh of electricity generated using RE or avoided generation using EE and that each 

MWh must be certified by a third party prior to the credit being issued. Commenters stated that 

the RE and EE data is reported, tracked, banked and retired using NC RETS, their tracking 

system for RE and EE under REPS. 

Commenters stated that the utilities and service providers must compile the data for submission 

to the PUC for an annual report. Commenters stated that this report is now part of the IRP for the 
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major utilities in NC and that the PUC reviews the submitted data and compiles a report for the 

public. 

Commenters stated that in order for the service providers and utilities to recover costs associated 

with EE and RE, the RE and EE generation data, along with the associated cost data, is reported, 

reviewed and approved through the PUC docket system. Commenters stated that it allows for 

public review, comment and intervention in establishing the cost recovery riders for each EE 

program established by the utilities and service providers. Commenters stated that each EE 

program operated by the service providers has its own docket where the data is reported and 

reviewed. 

Comment 2: Comments stating that the EPA should not require a certification process for 

EM&V evaluators because this would be duplicative and unnecessary for utilities that are 

regulated by the PUC.

Response 2: The EPA is requiring the use of independent, third party verification for EM&V for 

EE/RE used to adjust a rate. Separately, the EPA recognizes that there are qualifications and 

certification options for EM&V evaluators of utility programs, and the EPA encourages states to 

leverage these existing certification processes. 

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should not require a certification process for EM&V evaluators 

because this would be duplicative and unnecessary for utilities that are regulated by the PUC. 

Commenters stated that if a regulated utility does not seek out qualified independent evaluators, 

then the performance of the utility is at risk.

Commenters stated as the volume of EE activities increase, it will be necessary to develop new 

EM&V workforce talent. Commenters stated that requiring certification of qualifications may 

discourage people from entering the EM&V field due to additional costs and regulatory 

requirements. Commenters stated there already exists an extensive industry serving EM&V 

needs and a competitive RFP process for selection of EM&V vendors helps to ensure that only 

vendors with the highest qualifications are selected to do EM&V work. Commenters stated the 

EPA has expressed a need for consistency in state reporting and planning requirements. 

Commenters stated this may be feasible, and even desirable, at a high level so that accurate 

cross-state comparisons can be made. Commenters stated however, the exact reporting and 

planning structure should contain a degree of flexibility as many states with a long history of EE 

programs have established EM&V, reporting, and planning procedures that are open and 

transparent, and have consistently been found acceptable to public utility commissions and 

independent system operators (ISOs). Commenters stated that radically changing these 

requirements for states with established procedures may impose undue resource burdens on 

program administrators without necessarily improving transparency. 
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Comment 3: Comments suggesting that Arizona utilities already have rigorous EM&V methods 

to determine energy savings from efficiency programs and demand-side management, and so 

additional federal EM&V should not be required.

Response 3: The EPA recognizes that there are many states with established EM&V methods for 

quantifying energy savings from demand-side EE programs using existing protocols, guidelines, 

and guidance documents. The EPA heard overwhelmingly from commenters that such protocols, 

guidelines, and guidance documents are currently in wide use, and that this use should be 

continued and encouraged in the context of state plans. The agency agrees with this observation 

and therefore supports their use in generating ERCs in emission standard plans and adjusting 

rates in state measures plans. The EPA’s proposed Federal Plan approach provides flexibility to 

states on EM&V approaches as long as EM&V meets a minimum level of credibility, and the 

EM&V approach is robust, transparent, and systematic. 

The following are summaries of the specific public comments under this comment:

Commenters stated that Arizona utilities already have rigorous EM&V methods to determine 

energy savings from efficiency programs and demand-side management, and so additional 

federal EM&V should not be required, because the Arizona's energy efficiency programs meet 

EPA's criteria for being quantifiable, surplus, enforceable, and permanent.

Comment 4: Comments advocating that PUCs should determine the level of documentation 

needed for their jurisdictions rather than the EPA specifying a nationwide protocol.

Response 4: The EPA agrees that excessive EM&V documentation should be avoided. By 

establishing a minimum level of documentation needed for EM&V that largely aligns with 

existing state EE and RE programs, the EPA’s proposed Federal Plan is intended to ensure a 

minimum level of credibility and transparency without overburdening states.

The following are summaries of the specific public comments under this comment:

To avoid excessive EM&V documentation, commenters advocated that PUCs should determine 

the level of documentation needed for their jurisdictions rather than EPA specifying a nationwide 

protocol.

Comment 5: Comments expressing concerns over the availability of EE credits due to 

uncertainty about the EM&V requirements, including enforcement. 

Response 5: Commenters expressed concerns over the availability of EE credits. Commenters 

stated that the EM&V requirements should be described in adequate detail for EPA and 

stakeholders to assess the rigor of establishing savings. The EPA’s proposed Federal Plan 

approach states that EM&V must be rigorous, credible, and consistent with industry-standard 
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practices. By laying out requirements at a higher level, the EPA is able to guide states in 

developing their plans while giving states flexibility, especially where state programs already 

exist.

The EPA supports the concept of states acquiring EE or RE credits through a tradable system. In 

states implementing emission standard type plans with rate-based trading, affected EGUs adjust 

their reported emission rate using emission reduction credits (ERCs), which represent MWh that 

are quantified and verified according to the EPA’s EM&V criteria. Providers of EE and RE who 

seek to earn ERCs must develop EM&V plans outlining how they will quantify and verify the 

results of their efforts. These providers are then required to submit EM&V plans as part of their 

application to the state regulatory body for project approval. Whether EE and RE credits are 

tradable or not, states or trading program administrators must implement tracking systems to 

avoid double-counting. By establishing minimum criteria for EM&V, the EPA’s proposed 

Federal Plan approach ensures a credible basis for generation of credits and avoidance of doublecounting. For more information on EM&V provisions, see section VIII.K.3 of the preamble to 

the final rule, section IV.D.8 of the preamble to the proposed Federal Plan and the draft guidance 

document. 

The EPA’s proposed approach requires an independent entity to maintain and certify an EE and 

RE registry with project level identification for each credit in order to provide assurance that 

there is no double counting of either the credits themselves or the projects that make up each 

credit. Clear and transparent attribution and ownership of each credit is also required, however, 

project level tracking is not required for building energy codes or product standards programs. 

The EPA’s draft EM&V guidance document provides more details on minimum requirements for 

an EE registry. 

The following summarizes the specific public comments under this comment:

Commenters stated that enforceability is a key question for energy efficiency components of a 

state plan. Commenters stated that while some energy efficiency programs are implemented by 

vertically integrated utilities that also own and/or operate affected EGUs, others are implemented 

by distribution-only utilities, by third-party administrators, or by state agencies. Commenters 

noted that states have landed on different strategies for implementing their EERS, resulting in a 

wide variety of entities having obligations under state law. However, commenters stated that the 

common feature of all of these programs is that they are funded by ratepayers, and therefore 

supervised by the state public utility commission or other governing body (in the case of 

municipal utilities and electric cooperatives implementing their own EE programs). 

Commenters stated that the operators of the affected EGUs in a state must be collectively 

responsible for fully achieving the state goal and that the measures to ensure compliance must be 

federally enforceable against those EGUs. Commenters stated that entities implementing the EE 

programs can but need not be subject to federal enforceability under the Clean Power Plan, 

unless that entity also happens to own or operate an affected EGU (i.e., a vertically integrated 

utility). Commenters stated that to the extent that the compliance entities use energy efficiency 

avoided megawatt-hours in order to achieve their emission target, they can acquire those EE 

credits from the EE program administrator, under guidelines established by the state and 

approved by EPA. Commenters stated that whether the state chooses to allocate non-tradable
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credits, or set up a tradable crediting system is its choice based on its existing state laws and 

considerations. 

Commenters stated that the details of the EE program must be specified in the state's plan so that 

EPA can ensure that adequate EE savings credits will be available. Most critically, commenters 

stated that the EM&V requirements must be described in adequate detail for EPA and other 

stakeholders to assess whether they are sufficiently rigorous to establish savings attributable to 

the program. Commenters stated that to ensure the availability of efficiency credits, state EE 

standards must contain penalties for non-compliance and self-correction mechanisms. 

Commenters stated that some ratepayer-funded energy efficiency programs allow the 

implementing utility to make up for shortfalls in one year with over-performance in the next. 

Commenters stated that allowing EE program administrators too much flexibility within a plan 

period could lead to inadequate EE credits being available in a given year; states must consider 

how these plan periods align with the Clean Power Plan's two-year check-in schedule. 

Commenters stated that the allocation of energy efficiency credits to affected EGUs will require 

more active state involvement than the distribution of renewable energy credits, at least in the 

early years. Commenters stated that currently, there is no platform for verification and trading of 

energy efficiency credits, equivalent to the REC trading systems for renewable energy. 

Commenters asserted that the EPA must establish standards to ensure that EE savings are 

demonstrated through EM&V meeting the best standards and are not claimed by multiple parties. 

Commenters stated that a REC equivalent for energy efficiency has been discussed over the 

years, but has never taken hold in the same way as RECs. Commenters stated that some REC 

tracking systems, including NEPOOL-GIS, NAR, and NC-RETS, track energy efficiency 

savings, but the other systems have not incorporated this feature. Commenters noted that there 

was substantial interest in developing a tradable market for EE credits in the late 2000s.

Commenters noted that the state of Connecticut had a limited intrastate EE trading market for 

several years, but it is not clear whether that market remains active. Commenters stated that 

some barriers to a viable market for energy savings credits have been identified, including: (1) 

high transactions costs, including the cost of EM&V, and (2) the absence of a nationwide 

standard-setting body for certification of ESCs (as exists for RECs).

Commenters stated that the Climate Registry, a nonprofit organization of states, provinces and 

tribal governments, has proposed that an energy efficiency registry be established to facilitate the 

use of EE for Clean Power Plan compliance. Commenters stated that this registry would serve as 

a platform for consolidation of EM&V tools, aggregate data for consistent reporting to EPA, and 

would "provide clear and transparent attribution and ownership of energy savings" to serve as the 

foundation of a trading platform for energy efficiency credits among states. Commenters 

supported creation of such a registry, which will ease the administrative burden on states, 

facilitate stakeholder review, and allow trading of energy efficiency credits which will ultimately 

expand the market for energy efficiency. Commenters stated that regardless of what system is 

used, EPA must adopt rules to specify minimum criteria to ensure that EM&V procedures are 

fully adequate and enforceable and reflect the best demonstrated system. 
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Comment 6: Comments on administration of EE programs.

Response 6: Many EE programs are administered by other agencies. These include building 

codes and appliance standards. There are also many EE programs that are funded by rate-payers 

but administered through state agencies or independent organizations set up by the state.

The following are summaries of the specific public comments under this comment:

Commenters commented on a statement in the GHG Abatement TSD indicating that EE 

programs are administered by a variety of entities and that most such programs are overseen by 

state public utility commissions. Commenters asked that the Agency explain which EE programs 

are not overseen by public utility commissions.

Comment 7: Comments stating that the EPA should work with states to operationalize EE 

crediting in states that take a rate-based with trading approach.

Response 7: While the EPA is providing states with flexibility to tailor programs to their 

specific needs, states that utilize a rate-based emission trading approach will have the 

opportunity to harmonize their EM&V approach across all participating states.

Regarding double counting, it is proposed that EM&V plans must address how double counting 

will be avoided through the use of tracking and accounting procedures to ensure that two or more 

programs do not separately claim savings from the same EE project or measure (for example, 

two EGUs claiming savings from the same lighting retrofit). Other types of double counting 

must likewise be considered and avoided. For more details on EM&V provisions, see section 

VIII.K.3 of the preamble to the final rule, section IV.D.8 of the preamble to the proposed Federal 

Plan, and the draft guidance document.

The following are summaries of the specific public comments under this comment:

Commenters stated the EPA should work with states to operationalize EE crediting in states that 

take a rate-based with trading approach, including harmonizing and assuring the quality of 

EM&V protocols across states to enable regional trading. Commenters stated responsibility for 

the application of EM&V protocols should be a component of the states' enforcement of the 

performance standards. Commenters stated similarly, that states should have the responsibility 

for designation of EE programs as a component of their compliance. Commenters stated in 

accordance with best emissions tracking and accounting practices to ensure appropriate crediting 

and to avoid double counting, the EPA should expressly allow states to credit reductions that are 

accomplished by private actors such as performance contracting projects conducted by private 

energy service companies (ESCOs) in addition to reductions resulting from utility programs and 

state-mandated programs, provided that these projects are subject to EM&V protocols. 

Comment 8: Comments stating that states should be required to put in place explicit procedures 

to allocate savings between utilities and energy service companies and prevent double counting, 
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and, and that impact evaluations could be conducted on a sample of projects at the vendor 

(ESCO), state, or even regional level, and particularly for projects without savings guarantees.

Response 8: The EPA appreciates the suggestions for EM&V for ESCOs. Additional 

implementing EM&V guidance will be provided in the draft guidance that will be released with 

the proposed Federal Plan. All EE/RE used to adjust an emissions rate must address the criteria 

established in the final emissions guidelines. EPA welcomes stakeholder input on the draft 

guidance. For more details on EM&V provisions, see section VIII.K.3 of the preamble to the 

final rule, section IV.D.8 of the preamble to the proposed Federal Plan, and the draft guidance 

document.

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect demand-side EE and eligibility requirements for resources that can be used to adjust a 

CO2 emission rate, including eligibility dates and the types of EE savings and RE MWhs that are 

eligible, see section VIII.K.1.a.(2). Requirements for rate-based emission trading programs and 

the issuance and tracking of ERCs, including qualifying measures, programs or projects, 

addressing the potential for interactions between ERCs and RECs or EECs, are addressed in 

section VIII.K.2. Section IV.D.8 of the preamble to the proposed Federal Plan describes the 

provisions related to proper ex post quantification and verification of MWhs from renewable 

electricity generation or demand-side EE savings to avoid overestimation as suggested by 

commenters. These final provisions are intended to leverage and/or closely resemble those 

already in routine use, including those by energy service companies engaging in energy savings 

performance contracts.

Regarding the issue of double counting, it is proposed that EM&V plans must address how 

double counting will be avoided through the use of tracking and accounting procedures to ensure 

that two or more programs do not separately claim savings from the same EE project or measure 

(for example, two EGUs claiming savings from the same lighting retrofit). Other types of double 

counting must likewise be considered and avoided.

The following are summaries of the specific public comments under this comment:

Commenters stated energy performance contracting can be a source of large energy savings that 

states should be able to count, and most of these savings have been in institutional facilities, with 

smaller amounts in commercial and multifamily buildings and in industrial facilities.

Commenters indicated that performance contracts often include savings guarantees, where a 

specific amount of savings is guaranteed for a specific period of time, usually measured in years.

Commenters stated that some performance contracting efforts use utility incentives and others do 

not; in states where plans include both utility and performance contracting programs, states 

should be required to put in place explicit procedures to allocate savings between utilities and 

energy service companies and prevent double counting.

Commenters stated the various IPMVP protocols are used to trigger payments under 

performance contracting, so periodic impact evaluations should be conducted to verify these 

savings estimates, and if there are discrepancies between the results of the impact evaluation and 

previous savings claims, then prospective adjustments should be made to the methods used to 

estimate savings. Commenters stated impact evaluations could be conducted on a sample of 
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projects at the vendor (ESCO), state, or even regional level, and particularly for projects without 

savings guarantees. Commenters stated that savings estimates should be based on one of two 

methods: option 1 is to establish baselines based on Table 7.1 of the SEE Action Energy 

Efficiency Program Impact Evaluation Guide, and option 2 is to use the impact evaluations to 

adjust savings estimates for all ESPCs in a state (or even in a region) as a class. Commenters 

indicated impact evaluations should include control groups of similar customers who do not have 

ESPCs or do not participate in utility or other state programs, and the control group will capture 

business-as-usual savings such as from normal equipment replacement at end of equipment life, 

and also the effects of weather and the overall economy, allowing the impact of the ESPCs to be 

isolated. 

Comment 9: Comments recommending that stand alone pricing-based policies such as inverted 

block rates or time-of-use rates not be allowed in state plans or be eligible for savings credits.

Response 9: Renewable energy, demand-side EE, and other eligible measures that are tied to a 

state plan and achieve quantified and verified MWh savings may be used to adjust a CO2

emission rate, provided they meet the general and specific eligibility requirements for resources 

used to adjust a CO2 emission rate, described in Section VIII.K.1.a.(2) in the preamble. The 

measures must also meet the eligibility requirements and provisions related to demand-side EE 

programs and projects, if applicable, and the provisions related to proper quantification and 

verification of MWhs from demand-side EE savings are described in Section IV.D.8 of the 

preamble to the proposed Federal Plan.

The following are summaries of the specific public comments under this comment:

Commenters recommended that stand alone pricing-based policies such as inverted block rates or 

time-of-use rates not be allowed in state plans or be eligible for savings credits because the 

energy savings impacts of these policies are uncertain and inherently difficult to evaluate with 

accuracy. However, commenters stated that pricing policies that are implemented along with 

enabling technologies, such as time-of-use rates or prepay meters implemented in conjunction 

with in-home energy information displays, should be eligible for energy efficiency credits as 

long as appropriate EM&V procedures and protocols are followed. 

5.3.2 EM&V for Energy Efficiency Measures used in ISO Forward Capacity Markets

This section summarizes comments on the EM&V requirements for EE used in ISO Capacity 

Markets.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.
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Comment 1: Commenters stated the rule provides little guidance and limited support for the 

inclusion of non-ratepayer compliance options operated outside of conventional investor-owned 

utility programs overseen by state public utility commissions.

Response 1: The EPA’s approach provides flexibility, through the state measures or rate-based 

emission trading approaches, for non-ratepayer mechanisms for delivering EE savings to be 

included in state plans. 

In the final rule, quantified and verified MWh impacts of qualifying zero-emitting and lowemitting resources tied to a state plan may be used by an affected EGU or state to adjust a CO2

emission rate, regardless of whether the renewable generation or demand-side EE savings occur 

inside or outside the state or territory. This ensures that affected EGUs receive full recognition 

for their investments even if the impacts occur elsewhere and it removes the need to determine 

exactly which EGUs reduced and changed power generation in response to the zero-emitting or 

low-emitting resource. This also ensures that quantified and verified MWh impacts of qualifying 

zero-emitting and low-emitting resources are applied consistently across all affected EGUs. For

more information about specific methods to adjust the CO2 emission rate of an affected EGU to 

reflect demand-side EE and eligibility requirements for resources that can be used to adjust a 

CO2 emission rate, including eligibility dates and the types of EE savings and RE MWhs that are 

eligible, see Section VIII.K.1.a.(2). Requirements for rate-based emission trading programs and 

the issuance and tracking of ERCs, including qualifying measures, programs or projects, 

addressing the potential for interactions between ERCs and RECs or EECs, are addressed in 

section VIII.K.2.

The following summarizes the specific public comments under this comment:

Commenters stated the rule provides little guidance and limited support for the inclusion of nonratepayer compliance options operated outside of conventional investor-owned utility programs 

overseen by state public utility commissions. Commenters were concerned that in not adequately 

addressing these options, EPA is making it extremely difficult for states to recognize emissions 

reductions resulting from billions of dollars in annual energy investments. 

5.3.3 EM&V for Programs and Policies Not Typically Overseen by PUCs

This section summarizes comments on the EM&V requirements for EE programs not subject to 

state PUC oversight.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments on measurement and verification issues related to T&D Improvements
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Response 1: In the final rule, the EPA acknowledges the value of measures that increase 

transmission and distribution (T&D) efficiency or reduce electricity use, strengthening the 

transmission system and facilitating the transition to a new resource mix that includes more low 

and zero-emission resources. The final rule allows that the verified and quantified MWhs of 

avoided losses or reduction in end use electricity that result from T&D measures installed after 

2012 to be used to adjust a CO2 emission rate. For more information on the accounting approach 

for adjusting a CO2 emission rate and specifics on eligible transmission and distribution 

measures, see section VIII.K.1. For more detail on the provisions for proper quantification and 

verification of MWhs, see section IV.D.8 of the preamble to the proposed Federal Plan.

The following summarizes the specific public comments under this comment:

Commenters made the following points: 

• Grid modernization technology, such as Advanced Metering 

Infrastructure (AMI), can play a substantial role in collecting data and 

thereby facilitating the accounting, and related monitoring and 

verification (M&V), of identifying where clean energy and reductions in 

energy consumption, and so on, are occurring. 

• Grid modernization technology, such as Dynamic Line Ratings (DLR), 

allows existing transmission infrastructure to carry more power over the 

existing transmission footprint, thereby helping to maximize the value of 

existing transmission lines in integrating low- and zero-emitting carbon 

generation. 

• With the help of such enhanced grid modernization technology, the 

EPA, presumably in partnership with other appropriate federal, regional, 

and state entities, should develop the requisite M&V rules, protocols, 

and/or guidelines to determine actual energy savings and GHG emission 

reductions. The EPA then will be able to determine where and how to 

accomplish this interstate accounting in the most equitable and effective 

manner possible as well as the ways in which to effectively and fairly 

allocate emission reduction credits, accordingly. 

• Such technology similarly can play a significant role in helping to 

eliminate double counting of emissions reductions. 

• Procedures for auditing the M&V results should also be developed, as 

necessary. 

Commenters supported points made by the Business Council for Sustainable Energy (BCSE) in 

its November 2014 comments with respect to energy efficiency and M&V. Commenters agreed 

that while private sector delivered efficiency initiatives, including projects implemented under 

Energy Service Performance Contracts (ESPCs), which take place outside of the regulated utility 

currently do not appear to receive the same methodological guidance, that such private sector 
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efficiency initiatives should be taken into consideration and receive such guidance, as this Rule 

becomes finalized. Commenters noted that in instances pertaining to efficiency as well as to 

renewable energy, ensuring a means by which to accomplish the EM&V and, ultimately, of 

avoiding double counting of GHG emissions reductions will be essential. Thus, commenters 

urged the EPA to consider using grid modernization technology to facilitate accounting, 

monitoring, and verification in all of these regards.

• Regional/State/Local Codes and Standards: States should have the 

flexibility to pursue energy efficiency through building codes and 

appliance efficiency standards rather than just traditional utility 

conservation programs.

• Distribution Efficiency: Reducing losses on the electrical distribution 

system saves energy just like an end-use conservation program. Such 

programs are reflected in Washington State's "RPS" (RCW 19.285). The 

state should recommend EPA clarify that states may use distributionsystem efficiency enhancements to comply with the emission rate 

targets. 

Comment 2: Commenters pointed out that adequate EM&V tools are already available for 

quantifying energy savings for efficiency programs.

Response 2: Thank you for pointing out existing tools that can be used for EM&V. The EPA’s 

proposed approach to establishing EM&V provisions and guidance leverages existing industry 

practices, protocols, and tools. The EPA will review the EM&V plans that states submit, and 

provide guidance to states administering emissions trading approaches that rely on EE savings 

and RE generation to adjust a rate.

In response to comments about state policy and analytic needs, the EPA, in consultation with 

U.S. DOE and other federal agencies, continued to refine its toolbox of decision support 

resources at: http://www2.epa.gov/ www2.epa.gov/cleanpowerplantoolbox. The site includes 

information on regulatory requirements, including state plan guidance and state plan decision 

support. The state plan guidance section serves as a central repository for the final emission 

guidelines, RIA, guidance documents, TSDs and other supporting materials. The state plan 

decision support section includes information to help states evaluate different approaches and 

measures they might consider as they initiate plan development. This section includes, for 

example, a summary of existing state climate and RE and demand-side EE policies and 

programs, information on electric utility actions that reduce CO2, and tools and information to 

estimate the emissions impact of RE and demand-side EE programs, including the AVERT 

model. For more information about Resources for States to Consider in Developing Plans, see 

Section VIII.H.

The following summarizes the specific public comments under this comment:
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Commenters stated that Adequate EM&V tools are already available for quantifying energy 

savings for efficiency programs. Commenters recommended that EPA approve a tool by the 

North American Insulation Manufacturers Association to estimate energy savings from building 

insulation programs. The tool is "3E Plus - Insulation Thickness Computer Program."

Commenters also supported the use of other EPA-developed tools, and stated the EPA should 

allow states flexibility to use any of these available tools, e.g., AVERT, "Creating an Energy 

Efficiency and Renewable Energy Set-Aside in the NOx Budget Trading Program: Evaluation, 

Measurement, and Verification of Electricity Savings for Determining Emissions Reductions 

from Energy Efficiency and Renewable Energy Actions," "Energy Efficiency and Renewable 

Energy Roadmap Manual," and Power Plant Emissions Calculator ("P-PEC").

Comment 3: Comments suggesting that the EPA provide guidance on quantifying available EE 

credit for power supplied to rural areas. 

Response 3: In the final rule, the EPA provides a clear approach for demonstrating that 

renewable energy and energy efficiency project reductions are creditable. Consistent with EPA’s 

calculation approach in the final emission guidelines, quantified and verified MWh impacts of 

qualifying zero-emitting and low-emitting resources can be added to the denominator of an 

affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted CO2 emission rate.

The reported CO2 emissions reflect the actual emission reductions from the deployment of 

qualifying non-emitting and low-emitting resources across the regional grid. Further adjustment 

of CO2 emissions, such as through the subtraction of emissions estimated by applying an 

emissions factor to the MWhs, would double count CO2 emissions impacts across the grid. 

For more information about specific methods to adjust the CO2 emission rate of an affected EGU 

to reflect RE and demand-side EE, the timing and the eligibility requirements for resources used 

to adjust a CO2 emission rate, including renewable resources such as wind, solar, biomass and 

nuclear, see Section VIII.K.1.a.(2) of the preamble. The provisions related to proper 

quantification and verification of MWhs from renewable electricity generation or demand-side 

EE savings are described in Section IV.D.8 of the preamble to the proposed Federal Plan.

The following summarizes the specific public comments under this comment:

Commenters suggested EPA provide guidance on quantifying available EE credit for power 

supplied to rural areas. Commenters stated that affected rural electric EGUs have suggested that 

certain EE projects in these areas be given special consideration and credit because of the 

increased energy savings in reducing transmission losses. 

Comment 4: Comment stating that states should be allowed to include the energy savings of 

building codes and appliance standards measures in state compliance plans.

Response 4: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1.a.(2) of the final rule preamble, and that supporting EM&V is rigorous, 
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complete and consistent with the criteria provided in the proposed Federal Plan. All EE/RE used 

to adjust an emissions rate must address the criteria established in the final emissions guidelines. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. The EPA welcomes stakeholder input on this guidance.

The EPA’s approach allows for building codes and appliance standards to be counted towards 

EE savings. Additional implementing EM&V guidance will be provided in the draft guidance 

that will be released with the proposed Federal Plan. This guidance will include specific 

guidance on building codes and appliance standards. All EE/RE used to adjust an emissions rate 

must address the provisions established in the preamble to the proposed Federal Plan, in section 

IV.D.8. The EPA welcomes stakeholder input on the draft guidance.

The following summarizes the specific public comments under this comment:

Commenters indicated states should be allowed to include the energy savings of building codes 

and appliance standards measures in their state compliance plans if they can demonstrate robust 

development and application of EM&V standards for enforcement of building codes and for state 

appliance standards.

Comment 5: Comments stating that the EPA should provide further clarification in its final CPP 

ruling as to how states will need to demonstrate evaluation, measurement, and verification on 

this process.

Response 5: EM&V guidance for building codes will be presented in the draft guidance that will 

be released with the proposed Federal Plan. The EPA welcomes stakeholder input on the draft 

guidance.

The following summarizes the specific public comments under this comment:

Commenters stated with regard to energy code compliance and enforcement, aggregate 

compliance studies have indicated 'staggering rates of non-compliance, as high as 100 percent in 

some jurisdictions." Commenters stated EPA should provide further clarification in its final CPP 

ruling as to how states will need to demonstrate evaluation, measurement, and verification on 

this process. Commenters stated in doing so, states incorporating this compliance pathway in 

their SIPs will be able to direct appropriate resources to energy code compliance to achieve 

dramatic decreases in building energy usage. 

Comment 6: Comments stating the EPA should allow states to claim credit for savings produced 

by active participation in development of federal standards.

Response 6: Additional implementing EM&V guidance will be provided in the draft guidance 

that will be released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate 

must address the criteria proposed in section IV.D.8 of the preamble to the proposed Federal 

Plan. The EPA welcomes stakeholder input on the draft guidance.
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The following summarizes the specific public comments under this comment:

Commenters stated the EPA should allow states to claim credit for savings produced by active 

participation in development of federal standards. Commenters stated a key exit strategy of many 

market transformation efforts is to provide accurate, timely data in support of the federal 

standards process. Commenters stated the Northwest, through NEEA, has deliberately designed 

and implemented programs that can provide real market data demonstrating real market 

acceptance, performance and cost-effectiveness of EE measures. Commenters stated NEEA and 

the Northwest also have partnered with other large national organizations and U.S. DOE Labs to 

collect this data and represent these perspectives in the processes establishing federal standards. 

Commenters stated the U.S. DOE frequently has cited Northwest data and comments in its final 

record-of-decision documents in numerous proceedings. Commenters stated NEEA evaluates the 

success of these efforts to address the attribution of changes relative to the level of involvement 

by the Northwest. Commenters stated NEEA in partnership with the RTF and NWPCC measures 

savings that accrue from changes in standards and incorporates these into base load forecasts for 

integrated resource planning purposes. Commenters stated the Northwest states should get credit 

for the energy savings resulting from standards changes where documentation exists of the 

effects of the direct intervention of Northwest states and utilities. 

Comment 7: Comment stating that the states should have the ability to count EE savings from 

federal and state buildings and standards for appliances and lighting.

Response 7: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the proposed Federal Plan. Additional implementing 

EM&V guidance will be provided in the draft guidance that will be released with the Federal 

Plan. All EE/RE used to adjust an emissions rate must address the provisions established in the 

preamble to the proposed Federal Plan in section IV.D.8. The EPA welcomes stakeholder input 

on the draft guidance.

Regarding using gross rather than net savings, for all EM&V submittals addressing demand-side 

EE, the applicable metric is electricity savings, which is defined as a reduction in electricity 

consumption. EE savings must be determined and reported in units of gross MWh, except in 

cases where gross savings values are not available (e.g., randomized control trials). In these 

instances, net savings can be reported.

The following summarizes the specific public comments under this comment:

Commenters stated states should have the ability to count EE savings from federal and state 

buildings and standards for appliances and lighting. To this end, commenters stated EPA should 

allow states to credit for gross rather than net energy savings from EE measures. 
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Comment 8: Comments stating that the EPA should allow savings achieved by market 

transformation organizations like NEEA that continuously demonstrate best practice EM&V to 

count toward meeting the emissions reduction targets.

Response 8: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1.a.(2) of the final rule preamble, and that supporting EM&V is rigorous, 

complete and consistent with the criteria provided in the emission guidelines and the state plan. 

All EE/RE used to adjust an emissions rate must address the provisions established in the 

preamble to the proposed Federal Plan in section IV.D.8. Additional implementing EM&V 

guidance will be provided in the draft guidance that will be released with the proposed Federal 

Plan. The EPA welcomes stakeholder input on this guidance.

The following summarizes the specific public comments under this comment:

Commenters stated the Northwest Energy Efficiency Alliance (NEEA) is a leading market 

transformation organization made up of over 100 Northwest utilities that has accelerated the 

adoption of energy efficiency measures through the introduction of emerging technologies and 

practices, as well as codes and standards. Commenters stated NEEA forecasts at least 145 aMW, 

or 1,270,200 MWh, of total regional energy savings between 2015 and 2019, at a cost of 3.5 

cents per kWh. Commenters stated that for many of the small utilities in the region, NEEA 

savings account for over half of their energy efficiency savings. Commenters stated as a result of 

a large and diverse membership structure, its EM&V protocols use the best practices in the 

industry, providing the public and its funders with regular evaluations of its programs.

Commenters stated EPA should allow savings achieved by market transformation organizations 

like NEEA that continuously demonstrate best practice EM&V to count toward meeting the

emissions reduction targets. 

Comment 9: Comment indicating that states should use as their baseline code conditions the 

building energy code in force and rate of compliance with code at the time of the CPP proposal.

Response 9: The EPA’s approach allows for building codes to be counted towards EE savings. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the provisions established in the preamble to the proposed Federal Plan, in section 

IV.D.8. The EPA welcomes stakeholder input on the draft guidance.

The following summarizes the specific public comments under this comment:

Commenters indicated states should use as their baseline code conditions the building energy 

code in force and rate of compliance with code at the time of the CPP proposal. Commenters 

indicated States can perform studies of code compliance, use historic compliance rate data or use 

conservative assumptions of current compliance as baseline compliance conditions against which 

to establish energy savings. Commenters indicated that states that opt to include building energy 
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codes in their compliance plan could be required to perform periodic evaluations to establish 

compliance rates and energy savings.

Comment 10: Comments stating that the EPA should modify wording of the proposed rule at 

Section 60.5750 ("Can I include existing requirements, programs, and measures in my state 

plan?") to clarify that for building energy codes the baseline or "business-as-usual" condition is 

meant to be the code in force and its compliance rate at the time of the CPP proposal.

Response 10: The EPA’s approach allows for building codes to be counted towards EE savings. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the provisions established in preamble to the proposed Federal Plan, in section IV.D.8. 

The EPA welcomes stakeholder input on the draft guidance.

The following summarizes the specific public comments under this comment:

Commenters stated EPA should modify wording of the proposed rule at Section 60.5750 ("Can I 

include existing requirements, programs, and measures in my state plan?") to clarify that for 

building energy codes the baseline or "business-as-usual" condition is meant to be the code in 

force and its compliance rate at the time of the CPP proposal. Commenters indicated this section 

states that emissions reduction "actions taken" after the date of rule proposal pursuant to existing 

"requirements, programs and measures" can be counted for rule compliance. Commenters stated 

this is an important and beneficial section that would allow projects and actions taken under an 

existing EERS, ESPC authority or other policy or program to be credited for savings that are 

achieved during the compliance period. Commenters stated however, that a particular concern 

with respect to building energy codes is that construction or renovation of a building under an 

existing (and perhaps old code) could be construed as an "action taken" pursuant to an existing 

"requirement." Commenters stated in other words, the current wording of Section 60.5750 can be 

interpreted as allowing a state with a weak building energy code now on the books to count 

energy savings from building to that weak code as compared to building to an even weaker 

earlier code or no code at all. Commenters stated EPA should modify wording of the rule to 

assure that states should only be able to count code savings that come about from improving 

code compliance and/or increasing code stringency over baseline code compliance and 

stringency at the time of the CPP proposal. 

Commenters indicated that savings from building codes can be determined by comparing a 

baseline of energy consumption in buildings to the energy consumption under new building 

codes; savings can be quantified by multiplying the average savings under new codes by building 

type and the number of new homes (residential sector) or square feet (commercial sector) of each 

building type built in a state each year; typically the major building types are included and minor 

building types are grouped with the most similar major building type; and adjustments will also 

need to be made for code compliance, as discussed later in this section. Commenters stated that 

for further assurance of savings from newly-adopted building energy codes, EPA can also 

reference analysis done by the Department of Energy and Pacific Northwest National Laboratory 

(PNNL) for specific states to determine energy savings from the 2012 IECC and ASHRAE 90.1 
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2010 standard, and EPA should authorize states to use this analysis in determining their savings 

estimates from code. 

Comment 11: Comments suggesting options for baseline evaluations related to building codes.

Response 11: The EPA’s approach allows for building codes to be counted towards EE savings. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the provisions established in the preamble to the proposed Federal Plan, in section 

IV.D.8. The EPA welcomes stakeholder input on the draft guidance.

The following summarizes the specific public comments under this comment:

Commenters suggested a simple option for baseline would be to evaluate building code savings 

relative to the 2004 ASHRAE 90.1 standard for commercial and high-rise residential buildings 

and relative to the 2006 IECC for low-rise residential buildings. Commenters noted that 

approximately 45 states have codes at this level or higher, in some cases through local 

jurisdictions. Commenters noted that most states have stronger codes, and thus this baseline 

would allow many states to count savings from their existing codes. Commenters stated that 

because the baseline code is less stringent than what most states now use, for evaluation purposes 

100 percent compliance with the 2004/2006 codes should be assumed in the baseline. 

Comment 12: Comments suggesting additional options for baseline evaluations related to 

building codes.

Response 12: The EPA’s approach allows for building codes to be counted towards EE savings. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the provisions established in the preamble to the proposed Federal Plan, in section 

IV.D.8. The EPA welcomes stakeholder input on the draft guidance.

The following summarizes the specific public comments under this comment:

Commenters indicated another option for baseline would be to evaluate building code savings 

relative to the 2007 ASHRAE 90.1 standard for commercial and high-rise residential buildings 

and relative to the 2009 IECC for low-rise residential buildings, as these codes are in common 

use, with about 40 states employing their equivalent or better, in some cases through local 

jurisdictions. Under the ARRA of 2009, commenters stated that all states signed certifications 

that they planned to update their codes to the IECC residential 2009 code and the ASHRAE 

90.1-2007 commercial code, or equivalent, making this a logical national baseline. Commenters 

noted that for this approach, an allowance would need to be made for less than perfect 

compliance; thus the commenters are researching this issue now, and as a preliminary estimate 

would suggest increasing baseline energy use by about 5 to 7.5 percent relative to the 2007/2009 

codes, (i.e., a compliance rate that results in energy savings of 92.5 to 95 percent of the total 
318

savings anticipated). Commenters also indicated that for this stronger base code, a state could 

alternatively conduct its own compliance study to develop a more accurate baseline.

Commenters stated the second approach to setting a baseline would limit the savings that states 

could claim more than the first, and it is more complicated, but it may better reflect the average 

efficiency of new homes and commercial buildings being constructed today.

Comment 13: Comments recommending that EPA reference specific DOE and PNNL studies 

and methods for data on commercial building floor area in the United States.

Response 13: The EPA’s approach allows for building codes to be counted towards EE savings. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the provisions established in the preamble to the proposed Federal Plan, in section 

IV.D.8. The EPA welcomes stakeholder input on the draft guidance.

The following summarizes the specific public comments under this comment:

Commenters recommended EPA make reference to DOE's "Residential Energy and Cost 

Analysis Methodology" and "Commercial Energy and Cost Analysis Methodology, which 

together account more than 80 percent of the commercial building floor area in the United States. 

Commenters noted EPA should reference and explicitly authorize use of DOE (and its 

contractor, PNNL) state-specific analyses of building-level energy savings available from 

various model building codes such as the 2012 version of the IECC and the ASHRAE 90.1-2010

standard; reference when completed the savings from the 2013 ASHRAE standard; and reference 

DOE's Building Energy Codes Program online calculator. 

Comment 14: Comments regarding second tier of EM&V requirements.

Response 14: The EPA’s approach allows for building codes and appliance standards to be 

counted towards EE savings. Additional implementing EM&V guidance will be provided in the 

draft guidance that will be released with the proposed Federal Plan. This guidance will include 

specific guidance on building codes and appliance standards. All EE/RE used to adjust an 

emissions rate must address the provisions established in the preamble to the proposed Federal 

Plan, in section IV.D.8. The EPA welcomes stakeholder input on the draft guidance.

The following summarizes the specific public comments under this comment:

Commenters recommended the EPA establish a second tier of EM&V standards for EE measures 

that are less susceptible to the highly detailed EM&V, such as building and energy codes. 

Because these codes do provide energy savings at a low cost, commenters stated EPA should 

encourage states to include these efforts in state compliance plans. Commenters stated EPA 

should adopt some minimum criteria for evaluating the impacts of building, energy, and 

appliance codes. Commenters stated these criteria should include: difference in insulation, 

lighting, ventilation, and air infiltration between the current and new code; details on the 
319

enforcement of code compliance; and a measurement of buildings using the new code standards 

during each year. Commenters stated EPA should also adopt an uncertainty metric states must 

apply to these second tier EE measures. By adopting a tiered EM&V approach with associated 

uncertainty levels, commenters stated EPA can promote a wide array of efficiency measures in 

order to support a lower emissions target, provide more flexibility for state compliance plans, 

and provide clarity for states that compliance plans which include EE will be acceptable to EPA.

Comment 15: Comments stating that energy codes do not account for occupant behavior, and 

asking the EPA to specifically reference energy and resource saving building codes in the list of 

acceptable state strategies for compliance with clean power regulations.

Response 15: The EPA’s approach allows for building codes and appliance standards to be 

counted towards EE savings. Additional implementing EM&V guidance will be provided in the 

draft guidance that will be released with the proposed Federal Plan. This guidance will include 

specific guidance on building codes and appliance standards. All EE/RE used to adjust an 

emissions rate must address the provisions established in the preamble to the proposed Federal 

Plan, in section IV.D.8. The EPA welcomes stakeholder input on the draft guidance.

The following summarizes the specific public comments under this comment:

Commenters stated energy codes do not account for occupant behavior. Commenters stated 

furthermore, a building's actual annual energy consumption is not wholly a result of the building 

design. Commenters cited the following: "Under realistic assumptions, the energy-use impact of 

items purchased by the occupant after a home is built can be twice as large as the items typically 

installed by a builder." Commenters stated additionally, occupant behavior is a significant 

indicator of energy use. Commenters stated the most energy-efficient home, as designed and 

built, can waste a tremendous amount of energy if the occupant does not subscribe to the concept 

of efficiency. Commenters stated accordingly, the potential dissonance between a building's 

design and the actual energy use over time could impede demonstration of permanent emissions 

performance. Commenters stated verification and enforceability of emissions performance due to 

building energy codes may also prove problematic, as parties responsible for emissions 

reductions from building energy codes cannot and should not be held accountable for 

performance of buildings upon occupancy. Commenters stated as one of the twelve components 

of a complete state plan is "demonstration that each emission standard is quantifiable, nonduplicative, permanent, verifiable, and enforceable," this would reinforce NAHB's argument that 

building codes should not be a permissible measure for states to include in their state plans. 

Commenters asked EPA to specifically reference energy and resource saving building codes in 

the list of acceptable state strategies for compliance with clean power regulations. Commenters 

stated in the proposed rule, EPA expressed concern as to whether there are sufficient 

measurement and verification protocols available to accurately capture the energy and carbon 

savings from building energy codes. Commenters noted the work performed by PNNL and DOE 

to assess the savings attributable to DOE's Building Energy Codes Program, which was 

published in October, 2013. Commenters stated in addition, ten states have included building 

energy code programs in their utility EE programs with different M and V protocols.
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Commenters stated there have been several research based M and V protocols, including two 

recent ones, specifically on M and V of energy codes by the Pacific Northwest National Lab, and 

a joint study by the Northeast Energy Efficiency Partnerships, the Edison Foundation, and the 

institute for market transformation. Commenters stated that in conclusion, building energy and 

resource codes are a proven way of achieving energy, carbon and resource savings cost 

effectively, using legal and enforcement processes that already exist throughout the country. 

Because green building codes and standards can help increase demand-side energy efficiency, 

protect the environment, and catalyze economic growth, commenters encouraged EPA to issue 

guidance in its final rule which clarifies that green building codes and standards may be included 

in state emission-reduction plans, and to publish a list of pre-approved measures for state plans 

that includes green building codes and standards. Commenters stated such a list would provide 

states with greater certainty when developing their emissions reduction plans. 

Comment 16: Comments stating that since compliance with codes is imperfect, it is necessary to 

evaluate the portion of the savings that is lost.

Response 16: The EPA’s approach allows for building codes to be counted towards EE savings. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. This guidance will include specific guidance on 

building codes. All EE/RE used to adjust an emissions rate must address the provisions 

established in the preamble to the proposed Federal Plan, in section IV.D.8. The EPA welcomes 

stakeholder input on the draft guidance.

The following summarizes the specific public comments under this comment:

Commenters stated that since compliance with codes is imperfect, it is necessary to evaluate the 

portion of the savings that is lost, and the key is to determine not just the percentage of buildings 

that do not fully comply but the impact of compliance on energy savings. Commenters noted a 

building may not meet all the requirements of the code but may still achieve significant energy 

savings. 

Comment 17: Comments proposing 2 options for determining compliance rate with building 

codes: conduct code compliance studies or assume a code compliance rate, and stating that States 

should also be able to propose their own approaches.

Response 17: The EPA’s approach allows for building codes to be counted towards EE savings. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. This guidance will include specific guidance on 

building codes. All EE/RE used to adjust an emissions rate must address the provisions 

established in the preamble to the proposed Federal Plan, in section IV.D.8. The EPA welcomes 

stakeholder input on the draft guidance.
321

The following summarizes the specific public comments under this comment:

Commenters proposed 2 options for determining compliance rate with building codes: conduct 

code compliance studies or assume a code compliance rate. Commenters suggested a state could 

conduct code compliance studies to estimate compliance with building codes, where states would 

determine a realization rate of energy savings, and this rate could be multiplied by the estimated 

code savings assuming full code compliance. Commenters indicated this methodology is the 

most rigorous and would apply in particular to states that are striving to improve compliance.

Commenters also noted DOE and PNNL are working to develop a methodology that EPA should 

reference once it is completed, and commenters stated States should also be able to propose their 

own approaches. Commenters proposed a default compliance rate for states that lack current 

codes and that do not undertake a code compliance study, and recommended a conservative 

default rate, one that assumes near-worst-case practice, in order to provide an incentive for these 

states to conduct their own compliance studies. Commenters suggested that two default values be 

prescribed: one assuming no or few code compliance efforts, and a second assuming that a state 

is implementing a specified list of code compliance measures. Commenters recommended a 

preliminary estimate at 50 percent code compliance rate if little effort is devoted to code 

compliance, and a rate of 75 percent if a state implements at least three out of four of the 

following measures: conduct training for at least 90 percent of code officials on the energy 

portion of the building code and key aspects that need to be inspected; establish a stakeholder 

advisory group on compliance activities that meets regularly, and act on this compliance 

collaborative ‘s recommendations; prepare and implement a compliance gap analysis, and 

develop and implement a strategic compliance plan; and implement utility code compliance 

programs, giving utilities credit for energy savings from improved code compliance. 

Commenters stated States could claim savings above the default rates in their compliance plans if 

they conducted their own compliance studies and found a higher rate in practice. Commenters 

suggested States could also conduct their own studies and potentially propose other 

methodologies. Commenters noted that several states already provide utilities with some credit 

for building-code savings when they help with code adoption and/or implementation; in these 

states methodologies have already been developed and approved by state public service 

commissions, and commenters would expect many or most of these states to continue to use their 

current methodologies. 

Comment 18: Comments stating that building codes are only effective when they are 

consistently and routinely enforced.

Response 18: The EPA’s approach allows for building codes to be counted towards EE savings. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. This guidance will include specific guidance on 

building codes. All EE/RE used to adjust an emissions rate must address the provisions 

established in the preamble to the proposed Federal Plan, in section IV.D.8. The EPA welcomes 

stakeholder input on the draft guidance.

The following summarizes the specific public comments under this comment:
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Commenters stated that building codes are only effective when they are consistently and 

routinely enforced, so credits may be contingent on proof of rigorous state enforcement. 

Commenters stated that similar to adoption and upgrades, enforcement of the strongest building 

codes should be recognized by EPA as deserving of credit in the CPP. 

Comment 19: Comments related to building codes guidance.

Response 19: The EPA’s approach allows for building codes to be counted towards EE savings. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. This guidance will include specific guidance on 

building codes. All EE/RE used to adjust an emissions rate must address the provisions 

established in the preamble to the proposed Federal Plan, in section IV.D.8. The EPA welcomes 

stakeholder input on the draft guidance.

The following summarizes the specific public comments under this comment:

Commenters recommended EPA include specific guidance on how EM&V for building energy 

codes may be conducted in State Plans. Commenters noted the EPA states in its TSD for State 

Plan Considerations that "EPA is proposing to allow a wide (or unlimited) set of energy 

efficiency program and measure types in state plans, as long as the energy savings are adequately 

documented according to rigorous EM&V methods and appropriate state regulatory oversight." 

(pg. 50) Commenters stated however, in Table 2 of the TSD, EPA notes that EM&V procedures 

and protocols are either moderately or less well established for measures such as building energy 

codes. Commenters stated the information included in this statement and table may inadvertently 

discourage states from including building energy codes in their emission reduction plans. 

Commenters stated this has the potential to reduce the energy and cost-savings benefits possible 

through such measures. To remedy this situation, commenters encouraged EPA to clarify that 

although EM&V methods may be less well developed or common for building energy code 

adoption, compliance, and enforcement of the most recent editions of the model building energy 

codes, this will not either preclude their use or discourage the inclusion of building energy codes 

in state plans as an emissions reduction approach. Commenters stated EPA should further issue 

both guidance on EM&V for building energy codes and publish a list of pre-approved measures 

for state plans that includes building energy codes. Such a list would provide states with greater 

certainty when developing their emissions reduction plans.

Commenters recommended EPA issue guidance detailing examples of how states may obtain 

credit in their 111(d) compliance plans for carbon dioxide reductions from adoption of, and 

increased compliance with, building energy codes. Commenters pointed out the adoption of 

building energy codes has varied widely among states and smaller jurisdictions, such as counties 

and municipalities, and each state is unique in its administration of building energy codes, the 

rate of new commercial and residential construction, climate zone, level of utility involvement, 

and compliance practices. Commenters suggested EPA offer guidance detailing a flexible 

approach, with specific examples concerning how a state may take credit for the energy savings 

resulting from building energy code adoption and other code-related activities. Commenters 

suggested this guidance should provide states information on code implementation, enforcement, 
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EM&V, compliance verification, and potential structures of utility involvement, all of which can 

be based on real-world practices already employed in a number of states.

Comment 20: Comments stating that current federal appliance and equipment standards have 

already been accounted for in the EIA's Annual Energy Outlook Reference Case (AEO), and, 

therefore, recommended that states using AEO as a method to forecast emissions rates in their 

compliance plans should not be allowed to claim credit for federal appliance and equipment 

standards to avoid double counting of those emissions reductions.

Response 20: The EPA’s approach allows for appliance and equipment standards to be counted 

towards EE savings. Additional implementing EM&V guidance will be provided in the draft 

guidance that will be released with the proposed Federal Plan. This guidance will include 

specific guidance on appliance and equipment standards. All EE/RE used to adjust an emissions 

rate must address the provisions established in the preamble to the proposed Federal Plan, in 

section IV.D.8. The EPA welcomes stakeholder input on the draft guidance.

The following summarizes the specific public comments under this comment:

Commenters estimated that the savings from existing and pending Federal appliance and 

equipment standards average about 0.82 percent of electricity sales for each year over the 2020 

to 2030 period. Commenters stated there is some ambiguity regarding how federal appliance and 

equipment standards will be treated and how states should account for them in their compliance 

plans and made several recommendations for addressing these standards. Commenters stated that 

current federal appliance and equipment standards have already been accounted for in the EIA's 

Annual Energy Outlook Reference Case (AEO), and, therefore, recommended that states using 

AEO as a method to forecast emissions rates in their compliance plans should not be allowed to 

claim credit for federal appliance and equipment standards to avoid double counting of those 

emissions reductions. Commenters also recommended that for cases where this does not apply, if 

states seek credit for emissions reductions that occur due to the adoption, updating, and increased 

compliance with federal appliance standards, then EPA should provide guidance for states to 

take credit for carbon reductions for federal appliance and equipment standards and those states 

should work with EPA regional offices to determine an adjusted the BSER and state goal 

reflecting this expanded scope of potential reductions. Alternatively, commenters stated EPA 

could set the BSER and state goals for all states to reflect the emissions reductions that will 

occur as a result of federal appliance and equipment standards that have already been finalized or 

that are pending and will take effect before 2030. 

Comment 21: Comments suggesting that certain energy efficiency policies should not be 

eligible for compliance, recommending that the EPA allow states to use a weight of evidence 

(WOE) approach to establish compliance with state targets, and that if states adopt mass-based 

targets, EM&V protocols do not need to be applied because compliance is measured directly 

through statewide mission levels.
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Response 21: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1 of the final rule preamble of the CPP, and that supporting EM&V is rigorous, 

complete and consistent with the criteria provided in the emission guidelines and the state plan as 

described in section VIII.K.3 of the final rule preamble. The EPA’s approach gives states 

flexibility over which EM&V standards to draw from, but encourages states to leverage existing 

industry protocols, as this will facilitate the EPA’s ability to ensure that EE measure impacts can 

be adequately quantified and verified.

The following are summaries of the specific public comments under this comment:

Commenters stated that energy savings from utility and non-utility programs alike should be 

properly measured and verified according to state and EPA approved procedures and protocols. 

Commenters argued that certain energy efficiency policies should not be eligible for compliance 

with the Clean Power Plan. Commenters recommended that compliance credit not be given for 

energy savings that result from federal appliance and equipment efficiency standards or other 

federal mandates, for the following reasons:

• According to the commenters, ACEEE and ASAP estimate that national 

electricity usage in 2010 was reduced by an estimated 7.2%, saving 

about 278 TWh per year, by federal energy efficiency standards adopted 

through that year, and that the savings from these existing standards will 

increase to 682 TWh per year by 2025, 15.6% of projected national 

electricity use that year according to the U.S. Energy Information 

Administration's most recent Annual Energy Outlook.

In addition, commenters recommended that stand alone pricing-based policies, such as inverted 

block rates or time-of-use rates, not be allowed in state implementation plans or credited because 

the energy savings impacts of these policies are uncertain and inherently difficult to evaluate 

with accuracy. However, commenters indicated that pricing policies that are implemented along 

with enabling technologies, such as time-of-use rates or prepay meters implemented in 

conjunction with in-home energy information displays, should be eligible for inclusion in a state 

implementation plan for compliance purposes.

Commenters noted that if states adopt mass-based targets, EM&V protocols for the sake of 

compliance do not need to be applied because compliance is measured directly through statewide 

CO2 emissions levels.

Commenters recommended that EPA allow states to use a weight of evidence (WOE) approach 

to establish compliance and meet the EPA established state targets. Commenters stated under the 

WOE, for a plan to meet EPA approval, each state EE compliance plan would be required to 

explain how the effect of the EE measures will be determined, and specify the analytic methods, 

assumptions and data sources that the State will use to determine energy generation savings. 

Commenters stated as described in EPA's "Roadmap for Incorporating Energy 

Efficiency/Renewable Energy Policies and Programs into State and Tribal Implementation 

Plans, Appendix H: Weight of Evidence Pathway," EPA has already established a method for 

using WOE in a state implementation plan (SIP). Commenters noted that EPA states that "[t]he 
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WOE pathway does not include federal enforceability for the measures included in the WOE 

demonstration, WOE demonstrations can include qualitative or quantitative analysis."

Commenters stated if applied to compliance with the Proposed Rule, a qualitative analysis could 

credit programs such as energy efficient building codes, where the energy saving benefits are 

difficult to quantify, and also increase the likelihood that EE savings from a broad array of EE 

actions taken across the state, and not just by jurisdictional utilities, will receive credit toward 

state emission rate compliance calculations. Commenters stated EPA recognizes that 

unquantifiable measures could have substantial impacts and the Agency appears open to 

suggestions for implementing them in state compliance plans. Commenters stated the WOE 

approach is one such way to accomplish this objective. Commenters supported the use of a broad 

range of efficiency measures in state plans provided the impacts can be adequately quantified 

with measurement and verification protocols. For instance, commenters have been actively 

promoting the PennSave program, which promotes the use of energy savings performance 

contracting as a way for schools and municipalities to finance work done by energy service 

companies (ESCOs). Commenters stated a recent report from Lawrence Berkeley National 

Laboratory estimated ESCO industry revenue could be $7.5 billion in 2014 with 85 percent of 

the revenue from energy services. Commenters said this indicates significant potential for 

efficiency improvements that may not be accounted for in utility based programs. 

5.3.4 Considerations: Accuracy of Energy Savings Estimates

This section addresses comments on the accuracy of EE savings estates. 

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Commenters suggested that deemed savings values be used until such time as a 

state program matures and has a credible EM&V program in place.

Response 1: The EPA’s proposed approach to EM&V provides flexibility for states to determine 

how to quantify the savings from EE programs. States have the option to use deemed savings, 

control group, or non-control group approaches. All approaches must be rigorous, credible, and 

consistent with industry-standard practice. If deemed savings are used, the EPA’s proposed 

approach recommends the technical reference manual for these approaches be reviewed and 

updated at least every 3 years to keep current with market trends and technology innovation. The 

EPA’s draft EM&V guidance provides information on the appropriate use of deemed savings 

estimates.

The following criteria should be addressed in the EM&V plan and documented in the EM&V 

report:
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• Descriptions of deemed savings values, the source(s) of such values, and 

how the deemed savings will and have been applied should be included 

in EM&V plans and referred to in EM&V reports, respectively.

• Deemed savings values should only be applied for the specific EE 

measures, measure/program delivery mechanism (e.g., direct install 

versus point of sale rebates), end-uses (e.g., single family versus multifamily residential), operating conditions (e.g., climate, operating hours), 

and other assumptions for which the specific deemed saving values 

where developed. 

• Deemed savings values, their applicability conditions and the work 

papers used to determine the values should be documented in a deemed 

savings database (often referred to as Technical Reference Manual -

TRM).

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the provisions established in the proposed Federal Plan. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should include deemed savings as part of an EM&V plan to 

minimize costs and assure compliance demonstration. The EPA should generate avoided 

emission rates (AER) for different regions, and conduct load reduction profiles (LRP) for 

categories of energy efficiency programs.

Commenters also supported the concept of deemed savings as part of an EM&V plan because it 

can minimize program costs while providing an adequate level of assurance for compliance 

demonstration. Commenters also supported the use of load reduction profiles if the profiles 

capture when savings occur (time of day, day of week, and season) and geographic region, so 

that the profile coupled with dispatch modeling can capture emissions impact on the plants that 

are on the margin at times that the savings accrue. Commenters suggested that the EPA serve as 

a national clearinghouse for deemed savings factors and for developing/approving load reduction 

profiles used in state plans.

Commenters suggested that deemed savings values be used until such time as a state program 

matures and has a credible EM&V program in place. Commenters stated that a deemed savings 

program should include annual reporting of results (based on self-evaluation using a technical 

resource manual or third-part evaluation), and the results be used to continuously improve the 

deemed savings estimates. Commenters advocated for EPA to develop deemed savings guidance 

with regional values for unit estimates, measure lifetime, and baselines. Commenters 

recommended that DOE develop this guidance. Commenters advocated or use of deemed savings 

for all measures during the 2016-2019 time period, if relevant deemed savings values are 

available from other states or regions.
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Commenters stated that deemed savings (statistical sampling of programs to determine the MWh 

saved) must be an acceptable method for determining the MWh to include in the denominator for 

compliance. Commenters stated that statistical sampling should use whole-home meter data from 

a sample size large enough to generate a 90 percent confidence level for the results. Commenters 

stated that deemed saving should be based on gross MWh savings instead of net MWh savings. 

Commenters noted that the onerous data gathering and surveying required for a net calculation 

applied to a gross measure inherently includes many assumptions resulting in a net multiplier 

that is subjective at best. Commenters stated that imposing an overly complex accounting for 

MWh savings for EE will stifle programs of smaller utilities and divert precious capital and 

human resources to accounting for the MWh instead of further development of EE programs. 

Commenters stated that measurement and valuation needs to be less onerous for small utilities 

than current standards like International Performance Measurement and Verification Protocols. 

Commenters advocated that small utilities (fewer than 10,000 meters) be allowed to use deemed 

savings and not be required to conduct formal EM&V, because EM&V is affordable only for 

larger utilities.

Comment 2: Commenters provided examples of effective methods to verify EE savings.

Response 2: Thank you for providing the data appendix. The EPA recognizes the maturation of 

EM&V methods for many EE and RE programs, and encourages states and EE/RE providers to 

draw on the growing body of work in this area.

The following are summaries of the specific public comments under this comment:

Commenters stated that strong EM&V methods can be developed to document the effects of 

appliance early replacement programs. Commenters included an appendix that shows that 

extensive data are available for designing effective EM&V.

Commenters stated that EPA should encourage states to use "state of the art approaches" to 

evaluate energy efficiency policies and outlined three approaches.

Comment 3: Commenters provided an example of an effective EM&V program for EE.

Response 3: Thank you for sharing your EM&V experience for EE programs. This aligns well 

with the EPA’s proposed approach of requiring states to conduct EM&V that is rigorous, 

complete and consistent with the criteria provided in the emission guidelines and the state plan. 

Similar to your experience making continuous improvements to protocols, the EPA’s guidance 

document will be a living document that is updated over time to reflect evolving approaches to 

EE and EM&V, innovation, market changes, and practical experience gained during the 

compliance period.

The following are summaries of the specific public comments under this comment:
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Commenters stated that their experience demonstrates that robust and reliable EM&V for energy 

efficiency can be developed. Commenters stated the Bonneville Power Administration and the 

Regional Technical Forum now have a long history of encouraging energy efficiency and 

operating a robust system for measuring and verifying energy savings that ensures the reliability 

of its regional energy savings achievements for various types of energy efficiency programs. 

Commenters stated the protocols for EM&V vary by three different project types: deems savings 

for certain well-established measures, specification and savings estimation protocols for some 

measures, and on-site measurement and verification for customized customer energy projects.

Commenters stated the EM&V process includes ongoing evaluation and oversight to make 

continuous improvements to protocols. Commenters stated retrospective impact evaluations are 

used to verify savings and adjust reported saving values as necessary.

Comment 4: Commenters advocated that state plans must have provisions to avoid double 

counting energy savings across different EE programs.

Response 4: The EPA’s proposed approach sets a minimum standard for EE and RE program 

tracking requirements to ensure double counting is avoided. EM&V plans must describe how 

double counting will be avoided through the use of tracking and accounting procedures to ensure 

that two or more programs do not separately claim savings from the same EE project or measure 

(for example, two EGUs claiming savings from the same lighting retrofit). Other types of double 

counting must likewise be considered and avoided.

The following are summaries of the specific public comments under this comment:

Commenters stated that state plans should include provisions to avoid double counting energy 

savings among various energy efficiency programs (e.g., utility and non-utility programs).

Comment 5: Commenters stated the strict EM&V methods are needed.

Response 5: Overestimation of savings from EE programs is a concern for the EPA. To address 

this concern, the EPA is proposing to establish an "EM&V floor" that all states must achieve to 

ensure a minimum level of credibility. While the EPA encourages states to go past the EM&V 

floor, we also recognize there are many established state programs with different EM&V 

approaches, and therefore it is appropriate to provide a reasonable degree of flexibility for these 

programs. The EPA is not requiring the rigorous EM&V approaches mentioned by the 

commenters (e.g., randomized controlled trials), since states have limited practical experience in 

this areas. 

The following are summaries of the specific public comments under this comment:

Commenters stated that energy efficiency programs often overrate their effect and so strict 

EM&V is needed. Commenters stated that energy efficiency savings are routinely overestimated 

by significant amounts for three reasons:
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• Efficiency programs often do not account for "free riders" meaning 

activities that people would perform anyway in absence of the program.

• Because efficient technologies cost less to operate, firms and people use 

them more often, and the efficiency programs do not take into account 

this "rebound" effect.

• Contractors and auditors that verify savings often inflate the up-front 

estimates of the level of energy savings likely to be realized by a 

program so that more entities qualify for the program

Commenters stated that to avoid overestimates that will not achieve real emission reductions, 

EPA should establish detailed protocols and guidance for EM&V of efficiency programs, which 

EM&V should strongly favor field-based measured savings engineering estimates, and that 

evaluators should use state-of-the-art approaches for program evaluation. Commenters believed 

that randomized controlled trials (RCTs) and quasi-experimental methods are likely to be more 

reliable than other empirical approaches to estimating realized savings and that field-based, expost empirical estimates are likely to be more reliable than engineering studies.

Comment 6: Commenters urged the EPA to adopt a mix of different EM&V protocols for 

different energy efficiency measures.

Response 6: The EPA’s proposed approach in the Federal Plan proposal allows for a mix of 

different EM&V protocols for different energy efficiency measures and practices. The EPA’s 

anticipates that its guidance document, when final, will lay out program-specific EM&V criteria. 

We are also providing the option of using emerging methods, provided that a thorough 

description of such methods is provided in EM&V plans and M&V reports. The EPA’s guidance 

document will be updated over time to reflect evolving approaches to EE and EM&V, 

innovation, market changes, and practical experience gained during the compliance period.

The following are summaries of the specific public comments under this comment:

Commenters urged EPA to adopt a mix of different EM&V protocols for different energy 

efficiency measures. Commenters stated, for example, that while deemed savings methods are 

appropriate for some measures, more robust methods based on measurements of pre-retrofit and 

post-retrofit consumption are needed for others. Commenters further stated that EM&V protocols 

are continuing to evolve and improve, and states should be allowed to adopt emerging EM&V 

approaches. Commenters stated that emerging methods are using billing data to improve savings 

estimates, but because one current barrier is the difficulty in obtaining consumption data, EPA 

should encourage the easy, rapid, and inexpensive transfer of utility data to program verifiers.

Commenters encouraged EPA to allow use of smart meters and other smart home devices to 

document energy efficiency. Commenters suggested the use of energy consumption data 

provided by utilities.
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Comment 7: Commenters advocated a uniform EM&V standard to ensure consistent 

measurement of EE and RE savings.

Response 7: The EPA appreciates your concerns in prescribing a uniform EM&V standard to 

ensure consistent measurement of EE and RE savings. While the EPA does provide flexibility to 

states under the state measures approach and EE and RE providers under the rate-based emission 

trading approach to develop their own EM&V plans, the EPA is doing several things to ensure 

states are at least meeting a minimum standard of EM&V. First, the EPA is proposing to require 

certain EM&V processes, including use of independent, third party verification. Second, we are 

providing an EM&V guidance document to elaborate on the CPP EM&V requirements and guide 

states and other EE and RE providers in developing EM&V plans to assure quality, credibility, 

and integrity. For example, the EPA’s guidance document provides guidance on how to select 

third party verifiers. Third, each EM&V plan will be subject to review and approval, by the EPA 

in the state measures approach and by the state regulatory body in the rate-based emission 

trading approach. This will ensure programs meet the minimum level of credibility. 

Nevertheless, the EPA recognizes that there will likely still be inconsistency in reporting of 

energy savings across states. The EPA has tried to balance the desire for EM&V rigor and 

consistency with a desire to reduce burden on EE and RE program providers, states, and the EPA 

in its proposal in section IV.D.8 of the preamble to the Federal Plan.

The following are summaries of the specific public comments under this comment:

Commenters advocated that for building block #4, setting nationally uniform goals is not viable 

without an existing national standard in the energy efficiency sector for training and certification, 

job scoping, cost/benefit analysis, data collection methods, or open source data 

protocols/sharing. Commenters stated that industry has had notorious difficulty in measuring 

energy savings. Despite a handful of established third party standards, commenters stated that 

there is no uniformity across current state and local programs. Commenters stated that enforcing 

the energy efficiency portion of a national regulatory goal through state programs requires at 

least a common third party standard for workers/technician certification, for energy analysis of 

buildings, and uniform open-source data reporting in order to instill confidence that each state is 

reporting consistently. Commenters stated that EPA should (1) require state plans to name the 

certification standards and the recognized accrediting bodies issuing such certifications (such as 

LIUNA's Home Performance Laborer apprenticeship) for all businesses, technicians, and 

laborers involved energy efficiency installation; and (2) establish some core standards for 

measuring energy "savings" and the cost effectiveness. Commenters stated that to allow states 

complete autonomy in this area will undermine confidence in the consistency of Block 4 

compliance outcomes across the states.

Comment 8: Commenters advocated for EPA to develop avoided emission rates for EE 

measures.

Response 8: The EPA disagrees with the comment that the EPA should develop avoided 

emission rates for EE measures. In order to ensure consistency with the calculation of CO2
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performance rates and state rate-based CO2 goals in the final emission guidelines, and to avoid 

double-counting or inconsistent adjustment approaches across states, the final rule prescribes a 

general accounting approach states must use to adjust the CO2 emission rate of an affected 

source to reflect the MWh impacts of zero-emitting and low-emitting resource. Quantified and 

verified MWh impacts of qualifying zero-emitting and low-emitting resources tied to a state plan 

may be used by an affected EGU or state to adjust a CO2 emission rate, regardless of whether the 

renewable generation or demand-side EE savings occur inside or outside the state or territory. 

Consistent with the EPA’s calculation of the CO2 emission performance rates and state ratebased CO2 goals in the final emission guidelines, the MWhs impacts are added to the 

denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower, adjusted CO2

emission rate. The reported CO2 emissions reflect the actual emission reductions from the 

deployment of qualifying non-emitting and low-emitting resources across the regional grid.

Further adjustment of CO2 emissions, such as through the subtraction of emissions from the 

numerator, such as those estimated by applying an emissions factor to the MWhs, would double 

count CO2 emissions impacts across the grid and is, therefore, not permitted under the general 

accounting approach. While states may define renewable resources in their independent state 

policies different from EPA, the EPA requires that renewable energy resources states can use for 

purposes of meeting the emission guidelines must meet the eligibility requirements specified in 

the rule. These requirements align eligibility with certain factors and assumptions used in 

establishing the BSER, and by extension, application of the BSER to the performance levels 

established for affected EGUs in the guidelines. For more information about specific methods to 

adjust the CO2 emission rate of an affected EGU to reflect RE and demand-side EE, see section 

VIII.K. The same section also describes the eligibility requirements and conditions for resources 

to be used to adjust a CO2 emission rate, including specific discussions regarding hydroelectric 

power, biomass and combined heat and power. The rule describes the provisions related to 

proper quantification and verification of MWhs from renewable electricity generation or 

demand-side EE savings in Section VIII.K.3 of the preamble to the final rule, and section IV.D.8 

of the preamble to the proposed Federal Plan.

The following are summaries of the specific public comments under this comment:

Commenters also suggested that EPA should generate the avoided emissions rates (AER) for 

energy efficiency measures using power system dispatch modeling conducted for different 

regions as defined by power system boundaries, and that AERs should vary by energy efficiency 

program and vary over time as a function of changes in energy and peak loads, generating 

resource mix, and market conditions (e.g., fuel prices).

Commenters advocated that EPA should conduct the dispatch modeling and incorporate into the 

models load reduction profiles (LRPs) for categories of energy efficiency programs within 

broadly defined segments of time for different geographic regions by taking the following steps:

• Annually reviewing LRPs for categories of energy efficiency measures 

and programs, and updating them to the extent that new information 

suggests adding new or changing existing LRPs. The basis for LRPs will 

be existing measurement and verification results from energy efficiency 
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programs, as collected and published - or proposed - by states and/or 

regional entities; 

• Annually conducting power system dispatch modeling to establish 

avoided emission rates for each relevant region, using the best (i.e., most 

granular) representation of LRPs for categories of energy efficiency 

measures and programs; 

• Annually publishing the AERs by region and program category; and 

• Identifying areas to review for improving LRP and avoided emission 

rate modeling in the coming year. EPA should convene and seek the 

assistance of a technical support group as needed to help review and 

update LRPs, and for vetting input assumptions for the power system 

dispatch model. 

Comment 9: Comments on consistency in EM&V across states.

Response 9: The EPA’s proposed approach to EM&V, as described in Section VIII.K.3 of the 

preamble to the final rule and section IV.D.8 in the preamble to the proposed Federal Plan, 

include a significant number of components and provisions that the EPA believes will result in 

enhanced consistency in how quantification and verification is performed across states and EE 

providers.

The EPA appreciates your concerns in prescribing a uniform EM&V standard to ensure 

consistent measurement of EE and RE savings. While the EPA does provide flexibility to states 

under the state measures approach and EE and RE providers under the rate-based emission 

trading approach to develop their own EM&V plans, the EPA is doing several things to ensure 

states are at least meeting a minimum standard of EM&V. First, the EPA is proposing to require 

certain EM&V processes, including use of independent, third party verification. Second, the EPA 

is providing an EM&V guidance document to elaborate on the CPP EM&V requirements and 

guide states and other EE providers in developing EM&V plans to assure quality, credibility, and 

integrity. Third, EM&V plan will be subject to review by the EPA in the state measures approach 

and by the state regulatory body in the rate-based emission trading approach. This will ensure 

programs meet the minimum level of credibility, and ensure a reasonable balance the desire for 

EM&V rigor and consistency with a desire to reduce burden on EE and RE program providers, 

states, and the EPA.

The EPA’s proposed approach requires states in the state measures approach, and EE and RE 

providers under the rate-based emission trading approach, to address the following key 

considerations in their EM&V plans:

• How significant changes in independent variable conditions (weather, 

occupancy, production rates, etc.) that affect energy consumption and 

savings estimates will be analyzed.
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• How the initial installation of EE will be verified for EE program 

categories that involve the direct installation of measures.

• How avoided T&D systems losses can be included in EE savings values.

• How the duration of EE program or project electricity savings will be 

determined using annual verification assessments, industry-standard 

persistence studies, deemed estimates of effective useful life (EUL), or a 

combination of all three.

• How the rigor of MWh savings values will be determined, and the 

methods used to control the types of bias or error relevant inherent to the 

applied EM&V techniques.

• How double counting will be avoided through the use of tracking and 

accounting procedures to ensure that two or more programs do not 

separately claim savings from the same EE project or measure.

Addressing these considerations will provide a foundation to judge the success of these 

programs.

The following are summaries of the specific public comments under this comment:

Commenters stated that ultimately, the responsibility for developing and implementing the 

section 111(d) state plan will need to align with the program design, implementation, and cost 

recovery responsibility of the utility regulators for EE/DSM programs. Commenters stated the 

success or failure of the SIPs that implement Building Block 4 must be measured consistently. 

Commenters stated lack of a consistent tool and assumptions will be problematic. Commenters 

stated EMV of EE/DSM is an important component of the effectiveness of Building Block 4.

Commenters stated EPA should work with the states to develop a consistent tool to estimate the 

success or failure of the program, using the cost and benefit impacts for EE on the statewide 

emission rate as one of the metrics. Commenters stated otherwise, there is the potential for 

estimates to be a patchwork of methodologies, assumptions, and outcomes that cannot be 

compared easily between and among states. Commenters stated participants (generators, 

regulators, customers, and others) must have a useful metric to measure the success of the 

programs. 

Commenters stated EE savings can be difficult to quantify. Commenters stated uncertainties in 

evaluating EE measures include, for example: the costs of EE savings; the inherent level of EE 

independently attributable to consumer preferences; the extent and duration of energy savings 

given the uncertain life span of electric appliances; and the ability to predict and quantify the 

effect of consumer rebates, energy audits, or other EE programs on consumer choice. 

Commenters stated indeed, EPA recognizes in the proposed rule that, notwithstanding the 

widespread use of common measurement practices, there can be "significant differences in 

claimed energy savings values for similar EE measures between states and utilities, even when 

the same measure type is installed under otherwise identical circumstances. 
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Comment 10: Comments on balance rigor and flexibility of EM&V methods

Response 10: One of the EPA’s overarching objectives for EM&V in the proposed Federal Plan 

is the importance of striking a reasonable balance between EM&V rigor and credibility on the 

one hand, and the costs associated with project performance evaluation on the other. Another 

objective for the EPA in the proposed Federal Plan is to avoid excessive interference with 

EM&V practices that are already robust, transparent and working well. Therefore, the minimum 

criteria for EM&V in an approvable state plan ensure that practices result in credibility and 

certainty in savings estimates across jurisdictions. Additional implementing EM&V guidance 

will be provided in the draft guidance that will be released with the proposed Federal Plan. The 

EPA welcomes stakeholder input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated EM&V plans for Clean Power Plan compliance need to strike a careful 

balance between ensuring the appropriate rigor of results and the flexibility necessary for 

innovation to continue in the industry. Commenters stated relying on strict, prescriptive 

evaluation techniques may have the unintended consequence of stifling new EE programs due to 

the lack of established evaluation methodologies available to estimate savings from those new 

programs. Commenters stated as the market for energy efficient equipment becomes saturated 

over time, it will be imperative that program administrators have the ability to develop new 

programs in order to meet the aggressive EE savings targets through 2030 that will be necessary 

for Clean Power Plan compliance. Commenters stated the EE industry has a tradition of 

innovation and developing new methodologies to evaluate new programs, often relying on 

established EM&V practices from other disciplines, such as the social sciences. Commenters 

stated these new practices should be acceptable under any EPA EM&V regime, but would likely 

not qualify under a strict prescriptive set of methodologies. 

Comment 11: Comments stating that the EPA should allow states to design voluntary and 

flexible programs as a further incentive to reduce electricity use under Building Block 4.

Response 11: Regarding voluntary programs, the EPA position is that any demand-side EE 

program and project that results in MWh savings is potentially eligible, provided that it meets the 

criteria for eligibility described in section VIII.K.1.a.(2) of the preamble, and that supporting 

EM&V is rigorous, complete and consistent with the criteria provided in the emission guidelines 

and the state plan.

Regarding indirect EE savings, for all EM&V submittals addressing demand-side EE, the 

applicable metric is electricity savings, which is defined as a reduction in electricity 

consumption. EE savings must be determined and reported in units of gross MWh, except in 

cases where gross savings values are not available (e.g., randomized control trials). In these 

instances, net savings can be reported.

The following are summaries of the specific public comments under this comment:
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Commenters believed that EPA should allow states to design voluntary and flexible programs as 

a further incentive to reduce electricity use under Building Block 4.

Commenters noted that EPA seeks to measure EE savings related to the actions of EE program 

participants, but not necessarily directly attributable to the efforts of Program Administrators; 

therefore it is not necessary to conduct detailed estimates of spillover and free ridership. 

Commenters also noted that methodologies can differ in the estimation of spillover and free 

ridership effects and inclusion of these adjustments will not necessarily result in more accurate 

EE savings estimates.

Comment 12: Comment suggesting that the EPA could credit states with impressive 

accomplishments on energy efficiency would be to apply a "cap" to the amount of efficiency it 

requires from any given state to achieve cumulatively.

Response 12: The EPA’s approach reflects how demand-side EE and other non-BSER measures 

that are tied to a state plan and achieve quantified and verified MWh savings may be used to 

adjust a CO2 emission rate, provided they meet the general and specific eligibility requirements 

for resources used to adjust a CO2 emission rate, described in Section VIII.K.1.a.(2). of the 

preamble.

The following are summaries of the specific public comments under this comment:

Commenters suggested that one way EPA could credit states with impressive accomplishments 

on energy efficiency would be to apply a "cap" to the amount of efficiency it requires from any 

given state to achieve cumulatively, similar to the way the proposal does for renewable energy.

Comment 13: Comments stating that accurately quantifying EE achievements is an ongoing 

challenge.

Response 13: The EPA’s approach allows deemed savings methodologies. The applicable 

criteria for using deemed savings are that all savings values must be documented in a publicly 

available database (frequently referred to as a technical reference manual, or TRM) and be 

updated at least every 3 years to keep current with market trends and technology innovation.

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the criteria established in the final emissions guidelines. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated that accurately quantifying EE achievements represents an ongoing challenge 

to determining the appropriate level of emissions savings. Commenters stated this is a 

consequence of the fact that EE benefits are evaluated against assumed baselines. Commenters 
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stated many states have adopted a Technical Reference Manual or "Deemed Savings" approach 

to attributing EE savings. Commenters stated in this approach the jurisdictional authorities 

responsible for evaluating utility EE achievements develop a generally accepted methodology for 

utilities to use in determining the appropriate amount of credit that a utility can claim from 

rebating a particular technology. Commenters stated this is usually the case for technologies that 

are rebated in large quantities, such as residential lighting measures, or weather-dependent 

technologies such as air conditioners. Commenters stated these approaches dictate the number of 

annual operating hours to be used. 

Commenters stated by way of example, consider the likely scenario of an end-use consumer 

replacing a 100-watt incandescent light bulb. Commenters stated there are a number of options 

that are available to the consumer, assuming the consumer does not have an inventory of 100-

watt incandescent light bulbs to use for replacement. Commenters provided a table illustrating 

three lighting replacement options, their wattage, credited watt savings, and incremental cost (see 

Table in comment letter). Commenters stated based on the options laid out in the table, one may 

find it difficult to make a cost-effective case for providing a utility incentive for the 18-watt LED 

light bulb. Commenters stated this is due to the fact that the incremental benefit of energy 

savings is only 6 watts, while the incremental increase in cost is $18.48. Commenters stated if 

the utility wishes to provide an incentive that would be equal to 30 percent of the incremental 

cost, or $5.54, the cost per kilowatt is $924. Commenters stated however, even though the cost of 

the CFL is equivalent to the cost of the Advanced Incandescent option, consumers may not 

choose this technology for a number of reasons. Commenters stated consumer choices regarding 

energy-consuming technologies are multi-dimensional and do not always comport to basic 

economic principles. 

Commenters stated total energy savings credited for each of the technology options is 

determined by multiplying the credited watt savings by an assumed number of operating hours 

per year. Commenters stated these assumptions are typically based on co-opted studies within the 

public domain that have been conducted within different areas of the country. Commenters stated 

the total amount of credited energy savings can vary widely depending on the study that is used 

for annual lighting hours of operation. Commenters stated in addition, the energy savings 

associated with the efficient lighting options in the above example can vary by as much as 100 

kilowatt-hours depending on where the light is installed within a home. Commenters stated a 

very granular approach to the quantification of energy savings has the potential to be both 

intrusive and costly for Great River Energy's members. 

Comment 14: Comments noting that lack of a consistent tool and assumptions will be 

problematic when evaluating EE/DSM programs.

Response 14: The EPA’s proposed approach requires states in the state measures approach, and 

EE and RE providers under the rate-based emission trading approach, to address the following 

key considerations in their EM&V plans:
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• How significant changes in independent variable conditions (weather, 

occupancy, production rates, etc.) that affect energy consumption and 

savings estimates will be analyzed.

• How the initial installation of EE will be verified for EE program 

categories that involve the direct installation of measures.

• How avoided T&D systems losses can be included in EE savings values.

• How the duration of EE program or project electricity savings will be 

determined using annual verification assessments, industry-standard 

persistence studies, deemed estimates of effective useful life (EUL), or a 

combination of all three.

• How the rigor of MWh savings values will be determined, and the 

methods used to control the types of bias or error relevant inherent to the 

applied EM&V techniques.

• How double counting will be avoided through the use of tracking and 

accounting procedures to ensure that two or more programs do not 

separately claim savings from the same EE project or measure.

Addressing these considerations will provide a foundation to judge the success of these 

programs.

The EPA’s overarching EM&V objectives in the proposed Federal Plan include the importance 

of striking a reasonable balance between EM&V rigor and credibility on the one hand, and the 

costs associated with project performance evaluation on the other. Another objective for the 

EPA’s proposed criteria is to avoid excessive interference with EM&V practices that are already 

robust, transparent and working well. Therefore, the minimum criteria for EM&V in an 

approvable state plan establish a floor for EM&V practices to ensure credibility and certainty in 

savings estimates across jurisdictions. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the criteria established in the final emissions guidelines. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters noted that ultimately, the responsibility for developing and implementing the 

111(d) state plan will need to align with the program design, implementation, and cost recovery 

responsibility of the utility regulators for EE/DSM programs. Commenters stated the success or 

failure of the SIPs that implement Building Block 4 must be measured consistently. Commenters 

noted that lack of a consistent tool and assumptions will be problematic. Commenters noted that 

evaluation, measurement, and verification ("EMV") of EE/DSM is an important component of 

the effectiveness of Building Block 4. Commenters stated that EPA should work with the states 

to develop a consistent tool to estimate the success or failure of the program, using the cost and 
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benefit impacts for energy efficiency on the statewide emission rate as one of the metrics. 

Otherwise, commenters stated, there is the potential for estimates to be a patchwork of 

methodologies, assumptions, and outcomes that cannot be compared easily between and among 

states. Commenters noted that participants (generators, regulators, customers, and others) must 

have a useful metric to measure the success of the programs. 

5.3.5 Considerations: EM&V Technical Considerations for State Plans

This section addresses comments on technical considerations for determining the level of energy 

savings that can be credited.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Commenters advocated that states must use the same procedures for forecasting 

baseline energy demand and the same EM&V protocols for determining energy savings.

Response 1: For all EM&V submittals addressing demand-side EE (as proposed in the Federal 

Plan), the applicable metric is electricity savings, which is defined as a reduction in electricity 

consumption. EE savings must be determined and reported in units of MWh. The EPA also 

specifies that "common practice baselines" should be used, estimating what a typical consumer 

would have done at the time of the project implementation without the measure in place.

The EPA received many comments suggesting that the EPA should recognize early actions for 

the emission reductions they provide prior to the performance period. The EPA recognizes the 

validity and importance of these perspectives, and as a result, the final rule contains two 

provisions that enable states to incentivize early investments in zero-emitting generation and 

demand-side EE. 

First, states adopting rate-based plans may award ERCs to qualified providers that implement 

any eligible projects from 2013 onward for the quantified and verified MWh of generation or 

savings those projects provide in 2022 and subsequent years. Affected EGUs may use ERCs 

issued under each of these provisions for compliance with their assigned emission standards or 

bank the ERCs for use in any compliance period. In a mass-based context, similar efforts will be 

inherently reflected in the affected EGUs stack emissions in 2022 forward. ERCs issued in 2022 

or a subsequent year may be carried forward and used for demonstrating compliance in a future 

year. For example, an ERC issued for a MWh of RE generation that occurs in 2022 may be 

applied to adjust a CO2 emission rate in 2023 or future years without limitation. ERCs may be 

banked from the interim plan performance period to the final plan performance period. See 

section VIII.K.2.e of the preamble to the proposed rule for more details on ERC banking.

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 
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demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2), and allocate to 

eligible projects allowances or ERCs equivalent to each MWh generated or avoided. For more 

details on this program, see section VIII.B.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that the baseline demand forecast used in the draft rule for target setting is 

from the EIA's Annual Energy Outlook, which does not include all of California's energy 

efficiency programs. Commenters asked that EPA expressly allow states to use a demand 

forecast that reflects the most current economic and demographic information available, as well 

as state data on committed energy savings, and asked that the baseline forecasts include the same 

basic load categories for each state. Commenters advocated for the use of net energy efficiency 

in state plans so that the plans account for only the energy efficiency savings that are incremental 

to energy savings that would have occurred without state energy efficiency programs. Whichever 

method EPA selects, commenters stated that all states should be required to use the same 

accounting approach (gross or net), but that both gross and net savings should be reported. 

Commenters urged that EPA require that the plan emissions projections and compliance 

demonstration both reflect the same EM&V protocol. Commenters recommended that EPA 

should define baseline as "business as usual" as defined in the SEE Action Network Impact 

Evaluation Guide and the DOE Uniform methods Project (Chapter 17).

Commenters stated that EPA should allow states to include the savings from energy efficiency 

programs that were adopted prior to 2014 as long as they continue to result in energy efficiency 

savings in 2020. Commenters advocated that energy savings achieved to date should be banked 

and credited toward compliance, and that the allowable types of programs should be very broad.

Comment 2: Comments stated that protocols for determining the impact of energy efficiency 

measures consider the entire energy chain and not just the point of energy use.

Response 2: The EPA’s approach recommends the measurement of site savings (at busbar), 

which accounts for transmission and distribution losses. In addition, the EPA allows for states to 

count savings from measures that reduce transmission and distribution losses (e.g., conservation 

voltage reduction). 

Using energy consumption provided by utilities as the basis for verifying energy efficiency is 

one methodology allowed under EPA’s approach. However, states have greater flexibility to 

include other proven EM&V methodologies such as deemed savings methodologies.

The following are summaries of the specific public comments under this comment:

Commenters advocated that in determining the emissions impact of efficiency measures that the 

protocols consider the entire energy chain and not the just the point of energy use. Commenters 

stated that the protocols should consider point of use and the energy losses associated with 

generation, transmission, and distribution of electricity, and the energy consumed in extracting, 

processing, and transporting or distributing primary fuels (e.g., losses in transmission and 
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distribution are far greater for electricity than for natural gas). Commenters urged EPA to use 

energy consumption provided by utilities as the basis for verifying energy efficiency. 

Comment 3: Comments on allowing credit for educational programs on energy efficiency under 

certain conditions.

Response 3: The EPA’s approach allows for behavior change programs as a type of indirect 

action program whose direct impact cannot be easily linked to a specific investment or change in 

practices. The EPA is proposing in the Federal Plan that EE EM&V must undergo independent, 

third party verification and EM&V plans will need to be approved, by the EPA in the state 

measures approach and by state regulatory bodies under the rate-based emission trading 

approach, to ensure a minimum level of credibility.

The following are summaries of the specific public comments under this comment:

Commenters cautioned against excessive credit for general education programs, saying that such 

programs should be limited to not more than 5 percent of total savings from energy efficiency 

programs. Commenters also stated that customer behavior programs should be allowed only if 

the projected effects and verification are conduced independently from the vendor that provides 

the program.

Commenters stated that behavioral demand-side energy efficiency programs should be included. 

Commenters stated that they and other utilities have implemented behavioral programs for years 

and performed independent, rigorous EM&V. Commenters stated that their programs and the 

EM&V associated with the programs have been under the oversight of the state public utility 

commissions in five states. Commenters stated that not only do behavioral programs produce 

results, but they also encourage customer adoption of other programs in the company's energy 

efficiency program portfolio. Commenters attached several studies and articles on the positive 

impacts of behavioral energy efficiency approaches.

Comment 4: Comments that state plans address the quality of energy savings measures not just 

through back-end inspections, but rather upfront quality control tools as well.

Response 4: Thank you for pointing out these standard and certification programs. The EPA’s 

approach gives states the flexibility on whether or not to adopt skill standards and certification 

programs such as those from the U.S. DOE and California. While these performance 

requirements will increase the robustness of state EM&V plans, the EPA is not requiring a 

particular standard or certification program for approval. 

The following are summaries of the specific public comments under this comment:

Commenters urged that the EPA require the state plans to address quality not just through backend inspections, but rather upfront quality control tools as well. Commenters suggested 

development of performance requirements for contractors performing the work and skills 
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standards for the workers they employ to carry out the work. Commenters stated that skill 

standards for energy efficiency and renewables can be based on federal or state apprenticeship 

standards for construction trades workers, and supplemental skill standards that have been 

developed for renewable energy and energy efficiency, including the skill standards currently 

being developed by the U.S. Department of Energy as well as the highly successful California 

Advanced Lighting Controls Training Program certification. Commenters said that skill 

standards and skill certifications could partially substitute for post-installation inspections, 

because they are a mechanism to insure quality.

Comment 5: Comments that effective EM&V for EE measures are not yet available.

Response 5: EM&V methods for many traditional EE measures are relatively well-established. 

For energy efficiency measures that are more recent or have higher levels of uncertainty 

associated with energy savings, the EPA’s proposed approach will still require a minimum set of 

EM&V criteria to be met. The EPA position is that any demand-side EE program and project 

that results in MWh savings is potentially eligible, provided that it meets the criteria for 

eligibility described in the preamble, section VIII.K.1.a.(2), and that supporting EM&V is 

rigorous, complete and consistent with the criteria provided in the emission guidelines and the 

state plan. The EPA’s proposed approach gives states flexibility over which EM&V standards to 

draw from, but encourages states to leverage existing industry protocols, as this will facilitate the 

EPA’s ability to ensure that EE measure impacts can be adequately quantified and verified.

The following are summaries of the specific public comments under this comment:

Commenters stated that the difficulty in quantifying these impacts of energy efficiency as part of 

a compliance strategy makes energy efficiency inappropriate as part of BSER. Commenters 

stated that an energy efficiency program, by its very nature, is a market-driven strategy that 

cannot be easily measured and quantified because it is attempting to measure something that did 

not happen. Quantification relies on a combination of engineering calculations, pre- and postmetering data, and customer surveys to determine "attribution" to the adoption of a specific 

energy efficiency and to predict the persistence of the benefits into the future. Commenters stated 

the EPA proposes to rely on nationwide EM&V standards that are currently in place or are in the 

process of being written. Commenters stated many of the EM&V protocols that EPA referenced 

are still under development and are not designed to serve as compliance tools sufficient to meet 

Clean Air Act compliance standards. Commenters stated that for example, DOE's Uniform

Methods Project, is still under review and revision, which adds uncertainty to the "value" of 

energy efficiency measures at any particular time.

Comment 6: Comments on the use of net versus gross energy efficiency.

Response 6: For all EM&V submittals addressing demand-side EE, the proposed applicable 

metric is electricity savings, which is defined as a reduction in electricity consumption. Demand-
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side EE savings must be determined and reported in units of gross MWh, except in cases where 

gross savings values are not available (e.g., randomized control trials). In these instances, net 

savings can be reported. Importantly, gross savings is the simplest and most commonly reported 

form of demand-side EE savings and shows total reductions in electricity generation, irrespective 

of cause, while there are wide variations in the definition and uncertainty of net savings.

The EPA further specifies that "common practice baselines" must be used, estimating what a 

typical consumer would have done at the time of the project implementation without the measure 

in place.

Regarding the ability of certain EE measures to count for compliance, the EPA position is that 

any demand-side EE program and project that results in MWh savings is potentially eligible, 

provided that it meets the criteria for eligibility described in section VIII.K.1.a.(2) of the 

preamble, and that supporting EM&V is rigorous, complete and consistent with the criteria 

provided in the proposed Federal Plan.

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the criteria established in the final emissions guidelines. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA should clarify whether compliance is based on net or gross 

savings, but advocated the use of gross savings.

Commenters advocated for using net energy savings to measure emission reductions.

Commenters pointed out that using gross savings will allow credit for actions that would occur in 

absence of the rule and, therefore, would result in fewer emission reductions. Commenters also 

pointed out that measuring net savings is necessary for ongoing evaluation to identify the most 

effective program designs. Commenters supported the use of net savings consistent with the SEE 

Action Network Energy Efficiency Program Impact Evaluation Guide. Commenters encouraged 

EPA to ensure no double counting of energy efficiency savings across different program 

activities and to include adjustments for measure persistence and actual savings achieved (e.g., as 

determined through billing analyses and verification of installations), and corrections to account 

for data quality control.

Commenters strongly encouraged the EPA to base accounting of energy efficiency on gross 

savings, not net savings, because gross is easier to determine and will better encourage adoption 

of efficiency programs; the protocols and methods that states currently use for net savings vary 

widely and therefore the use of net savings could lead to inconsistent treatment of energy 

efficiency measures across states; and methods for determining net efficiency are not available 

for non-utility programs (e.g., building and appliance efficiency). Commenters supported using 

verified savings based on operational data collected by site visits, sub-metering, billing analysis, 

customer surveys, or third-party impact evaluation, as long as the verification costs are capped at 

5 percent of energy efficiency spending. Commenters also advocated that the EPA clarify that 

gross savings estimates must exclude savings from programs outside those approved in the state 

plans, except for market transformation programs, and that the rule should rely on existing 
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EM&V methods for market transformation in states that currently have market transformation 

programs. Commenters stated that the EPA should not discount "free riders" because the energy 

savings from free riders are real, regardless of why they occur.

Commenters stated that there are many reasons why gross energy savings is the appropriate 

metric:

• Emissions reductions are based on gross savings, which represent the 

actual level of savings that occur (and can be measured and verified), 

rather than net savings.

• Attribution of savings under the net savings approach (i.e., applying a 

net-to-gross ratio) is both difficult to determine accurately and not 

relevant for emission reductions resulting from the adoption of EE 

measures.

• Allowing for inclusion of spillover effects as well as free ridership in the 

determination of net savings is highly subjective.

• It will be much easier for states and utilities to evaluate and use gross 

savings rather than net savings, thereby facilitating inclusion of a broad 

range of EE policies and programs in state plans. The use of a gross 

savings approach in the final guidelines would be both more realistic and 

less cumbersome for states to implement, which would facilitate and 

encourage the deployment of EE-related measures.

Commenters stated that the EPA should recognize gross savings as an appropriate metric for 

state compliance plans. Commenters noted that in the proposal, the EPA states that it calculated 

state energy efficiency goals based on net savings. Commenters noted that as the EPA states, 

"This incremental savings rate and all others discussed in this subsection 

represent net, rather than gross, energy savings. Gross savings are the changes in 

energy use (MWh) that result directly from actions taken by program participants, 

regardless of why they participated in the program. Net savings refer to the 

changes in energy use that are directly attributable to a particular energy 

efficiency program after accounting for free-ridership, spillover and other 

factors."

Commenters stated that net savings establish whether a utility expenditure caused a consumer to 

adopt an energy efficiency technology or measure. Commenters noted as such, they are a useful 

metric for determining whether a utility should receive a performance incentive or lost revenue 

adjustment for its program. Commenters stated that this is a separate issue from whether a utility 

program has the effect of reducing carbon emissions for a state carbon reduction goal. From that 

standpoint, commenters stated that any measure that actually reduces emissions by reducing the 

need for generation should count for compliance, regardless of whether the measure was 

installed by a free rider, or resulted from spillover or other factors. Accordingly, commenters 
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believed that gross savings are the appropriate metric for compliance purposes, and that the EPA 

should so clarify in the final rule.

Commenters stated that the EPA should consider incorporating the use of gross energy savings in 

back-end compliance calculations as failing to do so results in underestimation of the true 

reductions in CO2 emissions at EGUs due to EE measures and can lead to inconsistencies in EE 

savings determinations. Commenters stated that USEPA used a net energy savings methodology 

to develop the cumulative annual electricity savings for EE in state goal development. 

Commenters stated that the recognized methodologies used to determine net, as opposed to 

gross, energy savings vary from state-to-state and within states. Commenters stated that the 

differences in net energy savings can be significant. Commenters stated that these variations in 

determining net-to-gross energy savings will be a source of inequity and uncertainty as states 

develop, and USEPA reviews, their plans.

Commenters supported the use of gross energy savings as part of the EPA's requirements and 

guidance. Commenters stated that accurate estimation of free ridership (necessary to calculate 

net energy savings) is complex. Commenters stated that this is a large understatement. 

Commenters noted that it is far more accurate to develop methodologies and guidelines to 

address calculations of gross energy savings. Commenters stated that all savings due to EE 

should be counted since they all lead to reduced electricity generation and to proportionally 

reduced emissions.

Commenters stated that the EPA did not specifically seek comment on this issue, and the 

commenters disagreed with the EPA's use of net savings for purpose of target-setting. However, 

commenters stated that compliance is another issue. Commenters noted that in its State 

Considerations Technical Support Document, the EPA states that a consideration for energy 

efficiency programs in state compliance plans "is whether reporting of energy savings should be 

specified on either gross or net basis, or both, to promote consistency in measuring the impact of 

energy efficiency measures across state plans."

Commenters stated that this is not currently an issue in Alabama, as it has no utility-funded 

programs to speak of. Commenters stated that to the extent Alabama proposes utility-funded 

programs as part of its state compliance plan (and it should), it will be important to have clarity 

regarding whether the EPA accepts gross savings figures for purposes of demonstrating 

compliance.

Commenters stated that net savings establish whether a utility expenditure caused a consumer to 

adopt an energy efficiency technology or measure. As such, the commenters noted that they are a 

useful metric for determining whether a utility should receive a performance incentive or lost 

revenue adjustment for its program. Commenters stated that this is a separate issue from whether 

a utility program has the effect of reducing carbon emissions for a state carbon reduction goal. 

From that standpoint, the commenters stated that any measure that actually reduces emissions by 

reducing the need for generation should count for compliance, regardless of whether the measure 

was installed by a free rider, or resulted from spillover or other factors. Accordingly, the 

commenters believed that gross savings are the appropriate metric for compliance purposes, and 

the EPA should so clarify in the final rule.
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Commenters stated that Ohio cannot easily quantify annual incremental electricity savings in the 

manner that the CPP proposes. Commenters stated that they depend upon evaluation, 

measurement and verification (EM&V) reports that are created by an independent third party to 

determine EE savings. Commenters stated that assuming arguendo that building block 4 is 

permissible, the CPP should consider using a gross savings reporting mechanism to allow for 

maximum consideration of energy savings that may not be reflected by just considering EE on a 

net savings basis. Commenters noted that currently, they consider EE on a gross savings basis. 

Commenters stated that revising their tracking methodologies to a net savings basis would be 

costly, difficult to implement and contrary to Ohio statute.

Commenters stated that the EPA should allow states to count gross EE savings (not net savings) 

toward compliance with the rule. Commenters stated that energy efficiency savings can be 

measured as "gross" or "net" savings, where gross savings include all savings from measures 

installed under a program, and net savings represent only those measures that are due directly to 

the program excluding measures that would have been installed anyway (without the program in 

place). Commenters stated that gross savings are the appropriate measure under this rule, both 

because this rule is focused on actual emission reductions without attributing motivations (or 

"additionally") to the measures and because determination of net savings is somewhat 

subjective.

Commenters stated that the EPA should finalize a definition of "net" based on evaluated savings, 

including savings from spillover and free ridership beyond business as usual. Commenters stated 

that because the environment sees the benefits of the total energy savings (whether or not due to 

spillover or free ridership effects), the total evaluated savings of EE should be credited in the 

111(d) framework. 

Commenters stated that the basis upon which EE savings are measured for compliance should 

match the basis upon which the EE target is set. Commenters stated that adopting a compliance 

approach based on total evaluated savings would therefore require a corresponding adjustment to 

the level of the EE target used to calculate state goals. Commenters noted that in general, an EE 

approach measured on an evaluated savings basis (which includes spillover and free rider 

effects) yields a higher MWh value than the same EE approach measured using a "net" basis 

(which does not include these effects). Commenters stated that to account for this difference in 

accounting, the proposed EE target, which was set on the basis of "net" measurements should be 

recalculated using evaluated savings.

Commenters stated that the EPA can minimize the recordkeeping burden of states by allowing 

the use of gross energy savings to measure and document EE program achievements. 

Commenters stated that EPA should allow the use of gross energy savings for compliance 

purposes, rather than the proposed net energy savings. Commenters stated there are many 

reasons why gross energy savings is the appropriate metric:

• emissions reductions are based on gross savings, which represent the 

actual level of savings that occurs (and can be measured and verified), 

not net savings; 
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• attribution of savings under the net saving approach (i.e., applying a netto-gross ratio) is both difficult to determine accurately and not relevant 

for emission reductions resulting from the adoption of EE measures; 

• allowing for inclusion of spillover effects as well as free ridership in the 

determination of net savings is highly subjective; and 

• it will be much easier for states and utilities to evaluate and use gross 

savings rather than net savings, thereby facilitating inclusion of a broad 

range of EE policies and programs in state plans. Commenters stated 

that use of a gross savings approach in the final guidelines would be 

both more realistic and less cumbersome for states to implement, which 

would facilitate and encourage the deployment of EE-related measures.

Commenters stated that the EPA should recognize gross savings as an appropriate metric for 

state compliance plans. 

Comment 7: Comments that DOE should be tasked to develop the rating system for evaluating 

EM&V plans.

Response 7: The EPA’s proposed approach establishes an "EM&V floor" that all EE and RE 

programs must achieve to ensure a minimum level of credibility in their EM&V programs. State 

EM&V plans will also be subject to EPA approval under the state measures approach, while EE 

and RE providers under the ERC approach will need to get their plan approved by the state 

regulatory body for the program. Regarding the discounting of savings for less rigorous and less 

accurate methods, EE and RE providers should follow industry-standard practices and protocols 

to determine whether or not to discount savings, and report savings in gross MWh where 

possible.

The following are summaries of the specific public comments under this comment:

Commenters supported NEEP's recommendation for the EPA to engage DOE to design and 

develop a rating system (with stakeholder input) that assesses the rigor and precision of EM&V 

methods used. Commenters recommended that the method should discount credit for energy 

efficiency savings when less rigorous or less statistically accurate methods are used. 

Comment 8: Comments that EPA should not discount credit for EE measures.

Response 8: EE and RE providers should follow industry-standard practices and protocols to 

determine whether or not to discount savings. EE savings must be determined and reported in 

units of gross MWh, except in cases where gross savings values are not available (e.g., 

randomized control trials). In these instances, net savings can be reported.

The following are summaries of the specific public comments under this comment:
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Commenters stated that EPA should not discount credit for energy efficiency measures, pointing 

out that the level of discounting that they have seen in some SIPS is excessive. Commenters 

stated that if EPA is going to discount credit for energy efficiency programs, then EPA also 

should apply the discount in creating the state goals.

Comment 9: Comments objecting EPA applying a measure of lifetime to the effect of EE 

programs.

Response 9: The EPA’s approach encourages states to use established industry protocols when 

determining the lifetime of an EE measure. We do not require a particular measure lifetime to be 

used, but will be reviewing state EM&V plans to ensure they are consistent with standard 

industry practice.

The following are summaries of the specific public comments under this comment:

Commenters objected to the concept of applying a measure of lifetime to energy savings 

programs. Commenters stated that load forecasts are an integral component of Integrated 

Resource Plans by the utility and so the utility already captures any diminished impacts in their 

long-run sales forecasts. Commenters stated that it is unreasonable to require the utility to reinvest effort into a program that still is achieving energy savings and would result in double 

counting of the same savings. Commenters stated that EPA needs to take a more realistic view of 

how energy efficiency is used in the utility planning process. Commenters stated that for an 

emission reduction to be permanent, the EM&V protocols for energy efficiency programs must 

require reporting on persistence, which includes retention of the programmatic measure and 

performance degradation over time.

Commenters recommended that the EM&V should specify the equipment useful lifetime for 

energy efficiency measures rather than applying a linear decline from first year savings 

estimates.

Commenters advocated that the non-energy benefits (e.g., aesthetic enhancements) of energy 

efficiency programs should not be included in EM&V because these benefits are not easily 

measured and would increase the cost of EM&V.

Comment 10: Comments related to considering time of day for calculating avoided CO2

emissions from energy savings.

Response 10: The EPA’s approach does not directly measure the avoided CO2 from EE 

programs. Instead, the energy saved from these programs is incorporated into the denominator of 

the rate-based equation when determining compliance with the state target. In order to ensure 

consistency with the calculation of CO2 performance rates and state rate-based CO2 goals in the 

final emission guidelines, and to avoid double-counting or inconsistent adjustment approaches 

across states, the final rule prescribes a general accounting approach states must use to adjust the 
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CO2 emission rate of an affected source to reflect the MWh impacts of zero-emitting and lowemitting resource. Quantified and verified MWh impacts of qualifying zero-emitting and lowemitting resources tied to a state plan may be used by an affected EGU or state to adjust a CO2

emission rate, regardless of whether the renewable generation or demand-side EE savings occur 

inside or outside the state or territory. Consistent with the EPA’s calculation of the CO2 emission 

performance rates and state rate-based CO2 goals in the final emission guidelines, the MWhs 

impacts are added to the denominator of an affected EGU’s reported CO2 emission rate, resulting 

in a lower, adjusted CO2 emission rate. The reported CO2 emissions reflect the actual emission 

reductions from the deployment of qualifying non-emitting and low-emitting resources across 

the regional grid. For more information about specific methods to adjust the CO2 emission rate of 

an affected EGU to reflect RE and demand-side EE, see section VIII.K.

The following are summaries of the specific public comments under this comment:

Commenters stated that the calculation of avoided CO2 emissions should account for time of day 

when the savings occur. Commenters stated that their company already accounts for the hourly 

values of energy efficiency impacts. Commenters also supported the use of hourly data if 

feasible. Commenters stated that if EPA determines that states must calculate the avoided CO2

associated with each megawatt-hour saved, the agency should identify which methodologies are 

most appropriate for this purpose and how hourly savings data can be estimated if not generated 

through the state's EM&V plan. Commenters argued that using time differentiated energy 

savings was too complex and expensive. Commenters stated that savings should be based on 

annual yearly savings but states should be allowed to consider savings that occur during peak 

hours if they can provide adequate documentation. Commenters also recommended that EPA 

should ask DOE to report on the availability of load shape data across the states (and the rigor of 

such data) so that EPA can specify acceptable options for states to use for determining timedifferentiated energy savings. Commenters advocated that energy efficiency should be accounted 

for by just adding the MWh saved in the denominator of the rate-based equation.

Comment 11: Comments on accounting for transmission line losses in the calculation of energy 

savings.

Response 11: The proposed EPA’s EM&V approach allows all demand-side efficiency savings 

determined at the site of an EE action, other than CVR/volt-VAR optimization, to apply a T&D 

adder. The T&D adder must be based on the lesser of 6 percent or the calculated statewide 

annual average T&D losses expressed as a percentage and based on values in the most recent 

year and published US EIA State Electricity Profile.

In the final rule, the EPA recognizes the value of combined heat and power as a resource that can 

reduce CO2 emissions from affected EGUs. The EPA agrees with the commenter and allows for 

electric generation (MWhs) from CHP units to be used to adjust the CO2 emission rate of an 

affected EGU, provided that the units meet the eligibility criteria described under section 

K.1.a.(9) and the EM&V criteria described in section IV.D.8 of the preamble to the proposed 

Federal Plan. Quantified and verified electric generation from non-affected combined heat and 

power units tied to a state plan may be used to adjust the CO2 emission rate of an affected EGU 
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provided that it meets the eligibility criteria described under section VIII.K.1.a of the final rule 

preamble. Since, in most cases, a CHP unit would be a low-emitting CO2 source, the MWh 

output would need to be prorated to account for the emissions using the method described in 

section VIII.K.1.a.(9) of the final rule preamble. The measures must also meet the requirements 

and criteria related to proper quantification and verification of MWhs as described in section 

IV.D.8 of the preamble to the proposed Federal Plan.

The following are summaries of the specific public comments under this comment:

Commenters supported the accounting for transmission line losses in the calculation of energy 

savings because line losses contribute to the level of energy savings achieved by an efficiency 

measure. Commenters stated that EPRI has developed a framework to assess benefits, cost, and 

performance of technologies to improve T&D efficiency and utilization, and that this research 

can serve as the foundation for an EM&V protocol. Commenters stated that the calculation 

should be performed at the system wide level as a ratio of the total amount of metered generation 

relative to the total of all metered sales, because it is impossible to know which customers may 

choose to implement which energy efficiency measures, so the calculation must be done systemwide. Commenters stated that states should be allowed to use their own T&D loss factors, if 

available.

Commenters advocated against adopting a national average line loss credit. Commenters 

suggested use of average line losses for the state in which the CHP unit is located. Commenters 

pointed out that EIA currently has state-by-state line losses through 2012 (State Electricity 

Profiles, May 1, 2014). If EPA decides to adopt a single national line loss credit, the commenters 

stated that the proposed 5 percent level is too low and suggested using 7.51 percent to be 

consistent with the line loss estimate that EPA used in calculating BSER in the Goal 

Computation TSD. Commenters asked EPA to clarify whether or not generation from new or 

uprated non-affected CHP units must meet an EM&V requirement, and if so it should be 

accomplished using revenue-quality electric meters. Commenters also advocated that CO2

emitted from non-affected CHP units should not be included in the determination of the emission 

reductions credited to those units, and that however, if the final rule requires this CO2 to be 

accounted for, the rule should not require CEMS on these non-affected units.

Comment 12: Comments on a range of specific provisions that should be contained in EM&V 

plans.

Response 12: The EPA appreciates the commenters’ recommendations. With respect to thirdparty EM&V verification, the Federal Plan proposal requires third party verification for both the 

state measures and the rate-based emission trading approach and these requirements do not vary 

by state. Many states have already established credible EM&V programs that differ slight from 

each other, therefore, the EPA’s proposed approach allows states under the state measures 

approach, and EE and RE providers under an rate-based emission trading approach, flexibility to 

define their own EM&V approach as long as it is rigorous, credible, and consistent with 

industry-standard practices. A third party evaluator must not be seen to have a conflict of interest 

with the success of the project. Conflict of interest procedures must be included in EM&V plans.
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For all EM&V submittals addressing demand-side EE, the proposed applicable metric is 

electricity savings, which is defined as a reduction in electricity consumption. EE savings must 

be determined and reported in units of gross MWh, except in cases where gross savings values 

are not available (e.g., randomized control trials). In these instances, net savings can be reported. 

Importantly, gross savings is the simplest and most commonly reported form of EE savings and 

shows total reductions in electricity generation, irrespective of cause, while there are wide 

variations in the definition and uncertainty of net savings.

The EPA is providing guidance on statistical sampling in the draft guidance issued with the 

proposed Federal Plan. In particular, the guidance suggests to obtain a minimum sample size that 

provides at least 20 percent precision and 80 percent confidence.

The EPA’s approach in the final emission guidelines requires states that have an independent 

entity maintain and certify an EE registry that tracks project level identification for each credit in 

order to provide assurance that there is no double counting of either the credits themselves or the 

projects that make up each credit.

Regarding EM&V for small utilities, the EPA is providing flexibility for states and ERC 

programs to be structured in ways that allow collaboration between utilities.

States have the option to used deemed savings, control group, or non-control group approaches. 

All approaches must be rigorous, credible, and consistent with industry-standard practice. The 

EPA’s draft EM&V guidance provides information on the appropriate use of deemed savings 

estimates. If deemed savings are used, EPA’s approach recommends the technical reference 

manual for these approaches be reviewed and updated at least every 3 years to keep current with 

market trends and technology innovation

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the criteria established in the final emissions guidelines. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters provided general recommendations regarding EM&V plans. Based in large part on 

their knowledge of the EM&V practices routinely used by utilities in the Southwest, the 

commenters stated that the following provisions are feasible for both large and small utilities:

• The EPA should require third party EM&V of the total first year energy 

savings (MWh saved per year) of every energy efficiency program that 

is claiming efficiency credits at least once every three years, using EPAapproved EM&V protocols for different types of programs. 

• There should not be different EM&V requirements for those states or 

utilities that have limited experience with energy efficiency programs 

and those that have substantial experience. All are capable of hiring 

qualified EM&V experts to evaluate the energy savings of their 

efficiency programs.
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• The same EM&V requirements should apply to both utility and nonutility policies/programs, because there are many competent EM&V 

experts and firms that can perform the EM&V of non-utility programs 

once EPA issues guidance and EM&V protocols for these programs. 

• The EM&V should be based on gross savings.

• The EPA should adopt a single protocol for each type of efficiency 

measure and not be multiple sets of EM&V protocols with discounting 

of savings if utilities or states take an "easier approach." 

• The EPA should provide guidance on statistical sampling in order to 

reduce potential sampling error bias in savings estimation and to help 

ensure that energy savings evaluation is consistent across utilities and 

states. The commenters recommended a 90/10 confidence 

interval/precision as part of EM&V for programs that are contributing 

5% or more of the total energy savings of a particular utility, third party 

program administrator, or state in any one year, but allow 80/20 

confidence interval/precision for programs contributing less than 5% of 

total savings. 

• If EM&V is required only once every three years for every program, 

EM&V results may not be available when states file their annual 

compliance reports with the EPA. In this situation, EPA should allow 

annual emissions rate reporting using deemed savings values, if the 

savings values as determined by third party EM&V are not yet available, 

and require retroactive adjustment of energy efficiency credits (either up 

or down) after the required EM&V is completed. This retroactive trueup is not likely to change a state or utility from compliance to out of 

compliance because the adjusted difference is likely to be relatively 

small.

• The EPA should allow states and utilities to conduct EM&V on their 

own without necessarily complete standardization across states, as long 

as the EM&V is consistent with approved protocols. The commenters 

stated that state PUC, energy office, or other appropriate state could 

certify that appropriate EM&V protocols were followed.

• The EM&V plan should address how to avoid double counting of energy 

savings across different programs.

• To facilitate EM&V for very small utilities (small municipal or rural 

coops), EPA should allow EM&V to be carried out for multiple utilities 

jointly in collaboration with wholesale power providers or state 

associations of utilities or cooperatives.
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Commenters stated if evaluation of energy efficiency measures is required, that EPA should 

allow the same firm that assists utilities in developing the energy efficiency program to conduct 

the evaluation of efficiency results because this would reduce costs to the utility.

Comment 13: Comments on establishing a system for trading EE credits.

Response 13: The EPA’s approach allows for EE trading through the rate-based emission 

trading approach. In states implementing emission standard type plans with rate-based trading, 

affected EGUs adjust their reported emission rate using ERCs, which represent MWh that are 

quantified and verified according to the EM&V criteria included in section IV.D.8 in the 

preamble to the proposed Federal Plan. Providers of EE and RE who seek to earn ERCs must 

develop EM&V plans outlining how they will quantify and verify the results of their efforts. 

These providers are then required to submit EM&V plans as part of their application to the state 

regulatory body for project approval. 

The following are summaries of the specific public comments under this comment:

Commenters advocated that a system is needed so that reductions due to energy efficiency can be 

tradable. Commenters believed it will take time to develop a credit system for energy efficiency 

that ensures that energy efficiency credits are comparable on a one-to-one basis that trading is 

viable.

Comment 14: Comments on rigor of EM&V in states using a mass-based approach.

Response 14: EM&V is not required if a mass-based state plan approach is utilized. This is 

because the evaluation metric for these plans is achievement of a mass limit on CO2 emissions 

from affected EGUs. With the a mass-based state plan approach, EE/RE measures can provide a 

complementary role, but their effects are embodied in measurements of CO2 emissions that are 

tracked through monitoring, reporting, and record-keeping requirements on affected EGUs.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA should require less rigorous EM&V for energy efficiency 

measures in states that adopt the mass-based approach. Commenters stated that documenting 

emissions reductions is not needed to demonstrate compliance with a mass-based approach, but 

they suggested that documentation could be needed to account for interstate effects of energy 

efficiency programs. While documenting the effects of energy efficiency could be helpful in 

assessing the efficacy of these programs for purposes of improving future emissions projections, 

commenters stated that less rigorous EM&V methods seem justified. Commenters asked EPA to 

clarify how EM&V differs for mass-based approaches.
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Comment 15: Comments on the need for a consistent methodology for valuing energy 

efficiency to facilitate multi-state emissions trading and other transactions

Response 15: To accommodate states with existing EE programs, the EPA’s proposed EM&V 

approach gives states a reasonable degree of flexibility, independence, and discretion in selecting 

methods and parameters. While this approach does not resolve inconsistent methodologies across 

states, the EPA’s proposed approach does require EM&V to be rigorous, complete, and 

consistent with the criteria provided in the emission guidelines and the state plan. 

In response to comments about state policy and analytic needs, the EPA, in consultation with 

U.S. DOE and other federal agencies, continued to refine its toolbox of decision support 

resources at: http://www2.epa.gov/ www2.epa.gov/cleanpowerplantoolbox. The site includes 

information on regulatory requirements, including state plan guidance and state plan decision 

support. The state plan guidance section serves as a central repository for the final emission 

guidelines, RIA, guidance documents, TSDs and other supporting materials. The state plan 

decision support section includes information to help states evaluate different approaches and 

measures they might consider as they initiate plan development. This section includes, for 

example, a summary of existing state climate and RE and demand-side EE policies and 

programs, information on electric utility actions that reduce CO2, and tools and information to 

estimate the emissions impact of RE and demand-side EE programs, including the AVERT 

model. For more information about Resources for States to Consider in Developing Plans, see 

Section VIII.H.

The following are summaries of the specific public comments under this comment:

Commenters stressed the need for a consistent methodology for valuing energy efficiency to 

facilitate multi-state emissions trading and other transactions. Commenters stressed that the 

valuation methods should be simple and predictable, and recommended that EPA impute for 

each state an emission reduction value for energy efficiency as the emission rate of the marginal 

dispatched resource in the power pool or the average emissions rate for the state.

Commenters stated that to quantify emissions avoidance from electricity savings, States should 

be allowed to use either marginal generation and emissions calculators or dispatch models. 

Because dispatch models are often proprietary and complex, EPA should allow states the choice 

of either dispatch models or AVERT or similar tools used by utilities and regional transmission 

organizations.

5.3.6 Options: Use of EM&V protocols and guidance

This section addresses comments on the guidance that EPA should provide on acceptable 

protocols for verifying energy savings.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.
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Comment 1: Comments on the importance for the EPA to prepare clear, flexible, effective, and 

affordable guidance on EM&V as early as possible before state plans are due.

Response 1: Thank you for pointing out the various standards and guidelines that can help states 

craft their EM&V plans. The EPA’s proposed EM&V approach for EE and RE measures seeks 

to strike a balance between providing states flexibility, encouraging states and other EE and RE 

providers to implement programs, and ensuring credible reductions from these programs. The 

EPA’s proposed criteria reflect several overarching objectives and principles offered by states, 

private organizations, and the public during the comment period. One of these is the importance 

of striking a reasonable balance between EM&V rigor and credibility on the one hand, and the 

costs associated with project performance evaluation on the other. Another of the EPA’s 

proposed criteria is to avoid excessive interference with EM&V practices that are already robust, 

transparent and working well. Therefore, the minimum criteria for EM&V in an approvable state 

plan establishes a floor for EM&V practices to ensure credibility and certainty in savings 

estimates across jurisdictions. In addition, the EPA will be providing a detailed guidance 

document to assist states and other EE and RE providers in crafting EM&V plans. This guidance 

will be reviewed periodically, and the EPA welcomes stakeholder feedback.

The EPA position is that any demand-side EE program and project that results in MWh savings 

is potentially eligible, provided that it meets the criteria for eligibility described in section 

VIII.K.1.a.(2) of the preamble to the final rule, and that supporting EM&V is rigorous, complete 

and consistent with the criteria provided in the emission guidelines and the state plan.

The EPA has developed an EM&V guidance document to assist regulators. The EPA welcomes 

stakeholder feedback on this document. This document provides quantification guidelines for 

various types of RE and EE programs, and can refer regulators to relevant EM&V protocols. In 

addition, criteria making up an "EM&V floor" have been established and discussed in the 

preamble. The EPA also specifies that "common practice baselines" should be used, estimating 

what a typical consumer would have done at the time of the project implementation without the 

measure in place.

The EPA received many comments suggesting that the EPA should recognize early actions for 

the emission reductions they provide prior to the performance period. The EPA recognizes the 

validity and importance of these perspectives, and as a result, the final rule contains two 

provisions that enable states to incentivize early investments in zero-emitting generation and 

demand-side EE. 

First, states adopting rate-based plans may award ERCs to qualified providers that implement 

any eligible projects from 2013 onward for the quantified and verified MWh of generation or 

savings those projects provide in 2022 and subsequent years. Affected EGUs may use ERCs 

issued under each of these provisions for compliance with their assigned emission standards or 

bank the ERCs for use in any compliance period. In a mass-based context, similar efforts will be 

inherently reflected in the affected EGUs stack emissions in 2022 forward. ERCs issued in 2022 

or a subsequent year may be carried forward and used for demonstrating compliance in a future 

year. For example, an ERC issued for a MWh of RE generation that occurs in 2022 may be 

applied to adjust a CO2 emission rate in 2023 or future years without limitation. ERCs may be 
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banked from the interim plan performance period to the final plan performance period. See 

section VIII.K.2.e of the preamble to the proposed rule for more details on ERC banking.

Second, the EPA has developed the Clean Energy Incentive Program, an optional program 

designed to reward investment in certain RE and demand-side EE projects that commence 

construction after the effective date of this rule and that generate MWh or reduce end-use energy 

demand during 2020 and 2021. Under this program, states may set aside allowances from their 

interim targets or generate early action ERCs (as defined in section VIII.K.2), and allocate to 

eligible projects allowances or ERCs equivalent to each MWh generated or avoided. For more 

details on this program, see section VIII.B.2 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stressed the importance for EPA to prepare clear, flexible, effective, and affordable 

guidance on EM&V as early as possible before state plans are due. Commenters stressed 

that widespread incorporation of energy efficiency measure might be discouraged due to 

uncertainty over the process and cost burden for EM&V. Commenters further suggested that 

EPA should seek public comment on the guidance document, and they suggested collaboration 

with states. Commenters stressed that the guidance should be reviewed and revised periodically 

to take advantage of experience and lessons learned and that there should be a streamlined 

review process by EPA. Commenters advocated for EPA to consult with DOE on selection of the 

list of acceptable protocols and on selection of the criteria for approving additional protocols 

proposed by states. Numerous commenters stressed that flexible, innovative, and affordable 

EM&V is important for encouraging energy efficiency and renewable energy; and standards 

need to be developed in cooperation with States. Numerous commenters stressed that these 

actions are important if EPA wants to encourage a wide variety of energy efficiency and 

renewable energy measures. Commenters stated that EPA's failure to establish protocols has 

fostered uncertainty on the ability to set achievable CO2 reduction goals based on energy 

efficiency. Commenters said that EPA must clarify how states will take credit for early energy 

efficiency measures adopted in the time between proposal of the rule and either plan approval or 

the beginning of the interim compliance period

Commenters requested definition of measurement and accounting protocols for EE and the E MV elements to be included.

Commenters stated that the EPA has not defined the measurement and accounting protocols for 

energy efficiency. Commenters explained that, as a result, the actual amount of contributions that 

such measures make toward the proposed standard is uncertain, and there are substantial and 

complex issues that have no current consensus solutions.

Commenters said that "The Regional Technical Forum and Northwest Power and 

Conservation Council, as well as individual utility data, all provide real-world 

program cost numbers that EPA should use as alternatives to cost assumptions in 

its proposed rule. In addition, EPA should allow regional/state approaches to 

measurement and verification of savings but ensure use of best practices that 

result in equivalent rigor across the country." 
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Commenters went further to say that EPA should "explicitly reference the M&V 

methods used by the Regional Technical Forum or the recommendations of the 

National Energy Efficiency Evaluation, Measurement and Verification Standards 

Scoping Study, US DOE 2011."

Commenters said that "OG&E is concerned that enforcement of EE measures 

under the proposal will be open to challenge if current evaluation and verification 

("EM&V") approaches are considered inadequate. The CPP should not be 

promulgated until EPA guidance on this issue is made available for review and 

public comment."

Commenters stressed the need or consistency among states in EM&V approaches. Commenters 

stated that EM&V practices continue to vary widely among states and utilities. Commenters 

stated that the EM&V protocols for energy efficiency must be rigorous to ensure that the 

emission reductions are credible, and EPA must ensure that the rigor of the methods used to set 

the state goals and determine compliance with goals is the same. Commenters suggested that the 

guidance include analytic methods, assumptions and data sources that the state will employ to 

determine energy savings and energy generation related to renewable energy and energy 

efficiency measures. Commenters stated that EPA should establish a uniform compliance 

instrument for demand-side EE, because of the different ways that states currently account for 

energy efficiency and to address cross border effects consistently. Commenters advocated 

for consistent EM&V methods across states for all building blocks to endure consistency in level 

of emission reductions credited. Commenters recommended that while consistency is important, 

the process needs to allow for the continued evolution of EM&V practices over time as states 

gain experience, and cited a reference (Hibbard and Okie, 2012) for a possible framework that 

EPA could use. Commenters stressed the need for enforceability of energy efficiency 

requirements.

Commenters recommended that the EM&V have the following elements, based on their many 

years of experience in energy efficiency program implementation and evaluation: 

• Use established state, regional, and national EM&V programs as 

models, and delegate development of the EM&V protocol to DOE. The 

DOE has already developed evaluation protocols through the Uniform 

Methods Project and these protocols already provide high level guidance 

with appropriate program safeguards that will ensure state flexibility but 

deliver the necessary transparency and clarity required to properly 

evaluate the programs. 

• EPA should support training on the certification process so that qualified 

evaluators can be hired to support EM&V, but recommends against 

requiring a certification program for evaluators because certification 

programs are not in place now and would add additional costs.

• Allow flexibility to adopt dynamic energy efficiency programs that go 

beyond the straightforward initiatives in place today and that recognize 
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upstream and midstream programs and savings related to codes and 

standards.

• EM&V program success requires team effort, including federal and state 

support, and roles must be understood. Commenters stated that EPA 

should ensure that states consider the multiple parties that may be 

necessary for successful implementation of certain programs and ensure 

that entities are only responsible for the components in their control. 

Commenters supported the use of energy efficiency as a mean to reduce emissions from the 

power sector. Commenters recommended that, because EM&V protocols will continue to evolve 

as more states gain experience, EPA should support continued development of EM&V best 

practices over time. Commenters suggested that EPA should (1) participate in ongoing efforts , 

such as the ongoing efforts coordinated by the Department of Energy, the State and Local Energy 

Efficiency Action Network, and regional technical forums; and (2) periodically revise the M&V 

standards reflect this coordinated evolution of M&V practices over time. Commenters suggested 

that EPA should:

• Work with existing federal, regional and state efforts to improve EE 

M&V and work towards common, voluntary M&V practices. To the 

extent EPA convenes a workgroup (rather than assist existing national 

and regional efforts), states should be invited to participate fully in this 

effort. 

• Facilitate meetings, studies and analysis to achieve a framework for 

consistent national EE M&V standards. 

• Periodically develop revisions to EM&V guidance, reflecting as much as 

possible the evolution of energy efficiency EM&V for compliance, and 

the lessons learned through the coordination process. Commenters stated 

that revisions should capture elements upon which there is significant 

progress and agreement, but need not represent a specific, prescriptive 

set of EM&V standards. 

Commenters suggested a two-tiered protocol for EM&V:

• Tier 1 would adopt EM&V criteria based on the level of certainty for an 

energy efficiency measure. By specifying criteria rather than specific 

EM&V measures, EPA will encourage more innovation in energy 

efficiency.

• Tier 2 would apply to measures that are less susceptible to detailed 

EM&V, such as building, energy, and appliance codes. The tier 2 

protocol would include enforcement provisions, measurements for 

building efficiency programs, and tiered uncertainty metrics for different 

energy efficiency measures.
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Commenters stated that EPA should not default to requiring utility industry EM&V as the only 

approach because current industry protocols were designed for different purposes; and EPA 

should allow less costly and more flexible EM&V options. Commenters also stated that, states 

that require third-party EM&V should not be required to provide additional reporting and 

recordkeeping, which will only increase the cost of energy efficiency programs for utilities and 

their customers. Commenters stressed that states should have broad discretion over how to 

address EM&V.

Commenters suggested to not limit the types of demand-side energy efficiency programs or 

policies that states can incorporate in their plans, EPA should develop high-level guidelines for 

EM&V that would permit acceptance of existing state protocols that are credible, rather than 

specifying a detailed and prescriptive set of analytical methods and protocols tailored to specific 

energy efficiency measures. Commenters also recommended that the guidelines should reference 

existing EM&V programs that provide robust measurement and verification such as the 

programs in Massachusetts, Rhode Island, New York, New Jersey, Pennsylvania, Illinois, 

California, and the Northwest Energy Efficiency Alliance. Commenters recommended this 

approach because it would allow EPA to develop guidelines faster and would allow states to 

continue relying on established EM&V programs, avoiding the burden that would result from 

creating a new set of program requirements. Commenters recommended that EPA designate 

another entity to approve a list of EM&V protocols that meet the guidelines and that EPA should 

review the state's reports on verification of energy savings. Commenters supported use of "EPA's 

Roadmap for the Inclusion of Renewable Energy and Energy Efficiency in State and Tribal 

Implementation Plans." Commenters further stated that any efficiency initiative that conforms to 

ISO 5001 or the DOE Superior energy Performance Program should not require further EM&V. 

Commenters specifically supported EPA's option 3, which would establish a set of generalized, 

process-oriented EM&V requirements that apply to all energy efficiency programs and measures, 

while providing flexibility to customize EM&V approaches, as appropriate for different types of 

programs and measures, provided that EM&V meets these minimum requirements. Commenters 

pointed out that EM&V programs by states can provide a good model to follow for certain 

elements but; because the programs can vary substantially among states, EPA should publish 

baseline criteria for EM&V to address methodologies, data sources, assumptions, annual 

reporting and third party verification. Commenters supported the criteria in the comments by the 

Northeast Energy Efficiency Partnership (NEEP). Commenters recommended that EM&V 

should require annual reporting and third-party verification. Commenters advocated for a 

national registry to standardize and verify energy efficiency savings.

Commenters suggested that EPA not limit the types of demand-side energy efficiency programs 

or policies that states can incorporate in their plans provided that EPA specify a robust EM&V 

methodology.

Commenters advocated for EPA to develop a non-exclusive list of protocols that the Agency 

would approve for use and also include criteria for evaluating alternative protocols submitted by 

states. As a general principle, commenters stated that EM&V should provide reasonable 

confidence in energy savings, but should not be so onerous as to become a disincentive to 

deploying energy efficiency as a resource. Commenters pointed out as an example that the setaside for energy efficiency activities in the Acid Rain Program established such onerous criteria 

that it was more or less unused, and pointed out that the degree of precision that might be 
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necessary for health-based criteria or toxic pollutant policies is not needed for carbon pollution.

Commenters stated that EPA should publish the criteria that it would use for evaluating protocols 

not on the pre-approved list, that the criteria should be rigorous and account for uncertainty in 

energy savings estimates, and that the criteria should be most stringent for behavioral energy 

efficiency measures.

Therefore, commenters advocated that the Clean Power Plan should pre-approve a list of 

effective, low cost EM&V protocols that have been adopted by states, utilities, regional, and 

international bodies. Commenters stated that existing protocols are sufficient and no Federal 

protocols specific to this rule are necessary. Commenters suggested that EPA convene a group of 

states and EM&V professionals in early 2015 to develop the protocols in time for states to use in 

preparing their plans. Most of these commenters suggested that DOE should chair the group.

Commenters suggested that for any gaps in protocols the group would develop a schedule for 

their development. Commenters provided an appendix with specific recommendations for 

EM&V for solar power. Commenters recommended that EPA develop a uniform compliance 

protocol that would be used for all states for demand-side efficiency programs. The protocols 

suggested across commenters were:

• Department of Energy Uniform Methods Project, a standardized set of 

EM&V protocols for specific energy efficiency actions. 

• DOE Residential Energy and Cost Analysis Methodology and 

Commercial Energy and Cost Analysis Methodology.

• DOE Superior Energy Performance protocol. 

• Protocol for behavioral energy efficiency programs by the State & Local 

Energy Efficiency (SEE) Action Network. 

• International Performance Measurement and Verification Protocol, 

available from the Efficiency Valuation Organization. 

• Energy Management Systems (EnMS) under the ISO 50001 standard. 

• California Title 24 code.

• Separate protocols for efficiency projects provided to energy service 

companies through performance-based contracts. 

• Model Energy Efficiency Program Impact Evaluation Guide issued by 

the State and Local Energy Efficiency (SEE) Action Network; 

• ASHRAE Guideline 14-2002 Measurement of Energy and Demand 

Savings; and, 

• Technical Reference Manuals developed and/or adopted by states, 

utilities and regional bodies; examples include the Northwest Power and 
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Conservation Council Regional Technical Forum (RTF) and the 

Northeast Energy Efficiency Partnerships (NEEP) EM&V Forum. 

• EPA's "Roadmap for Incorporating Energy Efficiency/Renewable 

Energy Policies and Programs into State and Tribal Implementation 

Plans, Appendix H: Weight of Evidence Pathway. 

• DOE/EPA action guide, Evaluation, Measurement, and Verification 

(EM&V) of Residential Behavior-Based Energy Efficiency Programs: 

Issues and Recommendations for behavioral energy efficiency programs, 

and recommended development of a similar guide for commercial 

programs. 

• ISO New England. Connecticut Program Savings Document. USGBC 

LEED protocol for building efficiency. State of Georgia protocols. 

• Energy STAR Portfolio Manager for building efficiency ratings. Pacific 

Northwest Regional Technical Forum. Northeast Energy Efficiency 

Partnerships (NEEP) EM&V Forum.

• NAESB Wholesale/Retail Electric Quadrant Energy Efficiency M&V 

Standards (contact NAESB) 

• Northwest Regional Technical Forum (RTF) Operative Guidelines

• PJM Manual 18B: Energy Efficiency Measurement & Verification 

• California Evaluation Protocols

• Other well established protocols not listed here

Commenters recommended that EPA adopt a weight of evidence approach for calculating energy 

savings because this approach avoids many of the implementation issues and jurisdictional 

problems associated with traditional EM&V. This approach is referenced in EPA's publication, 

"Roadmap for Incorporating Energy Efficiency/Renewable Energy Policies and Programs into 

State and Tribal Implementation Plans, Appendix H: Weight of Evidence Pathway" and has been 

employed in attainment demonstrations for ozone, PM2.5, and Regional Haze.

Commenters encouraged EPA to set national EM&V standards for energy efficiency to ensure 

accurate, unbiased, and consistent emission reduction estimates for rate-based programs.

Commenters asked EPA to take the following actions and also provided the following additional 

recommendations in the appendix of their comments: 

• Promulgate detailed guidance establishing an EM&V framework 

(including definitions, evaluation methods and key assumptions, roles 

and responsibilities, peer review requirements, and transparency and 

reporting requirements) that - if used by states to estimate savings from 
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demand side energy efficiency measures - allows resulting savings 

estimates to be used to demonstrate compliance with a state plan or to 

modify an emissions rate. Create standards and requirements for state 

reporting of EM&V plans, EM&V actions, savings estimates, and 

program details that allow easy comparison of savings estimates across 

program administrators and states. 

• Encourage regional collaboration on EM&V, so that more states use 

similar analytic methods, assumptions, and data sources, and states can 

share the burden of developing resource-intensive inputs. Encourage 

states to subject savings estimates to peer review. Commit to conducting 

a thorough review of state EM&V plans, ensuring they comport with 

EM&V Guidance, and on to ensuring that states follow EM&V plans to 

estimate savings. 

• Require states to certify savings estimates in an open and transparent 

regulatory (adjudicated if requested by parties) process. 

• Consider supporting the development of a national energy efficiency 

registry (23325, 22732). 

Commenters stated that EM&V for demand side measures should be handled differently, 

because these measures shift load to a different time of day. 

Commenters advocated that national uniformity in EM&V is not needed for energy 

efficiency. Commenters stated that practices should be normalized where possible, and each state 

or region should develop EM& V protocols for measures that follow best known and acceptable 

practices for their region. Commenters stated that otherwise, the rule could create barriers to the 

use of energy efficiency and advanced EM&V for those states and regions such as the 

Northwest, California, or the Regional Greenhouse Gas Initiative (RGGI) states, where energy 

efficiency practices are more mature. For other states, commenters recommended that EPA 

should provide technical assistance in program development and begin developing develop best 

practices guidance for EM&V to assist states going forward. 

Commencers urged EPA to encourage energy efficiency because of the substantial opportunity 

for emission reductions, and that reasonable and flexible EM&V requirements are critical 

to encourage efficiency. Commenters stated that EM&V for energy efficiency and renewable 

energy should be left to the discretion of the states to account for the unique circumstances in 

each state. Commenters stated that the goals were based on existing state EM&V programs, so 

compliance should be consistent with these same methods. Commenters suggested that EPA 

should provide guidance and assistance on how to develop EM&V plans but should not impose 

specific provisions that contain costly and onerous monitoring and verification requirements. If 

EPA does not allow states to set their own protocols, then commenters stated that streamlined 

EM&V protocols should be developed for certain programs including CHP and weatherization of 

low-income homes, and efficiency upgrades by water and wastewater utilities. Commenters 

particularly stressed that CHP should not require rigorous EM&V for each project. Commenters 

stated that state discretion was particularly important because the cost impacts will be higher for 
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small utilities and their customers, while the benefits will likely be lower. Commenters asked 

EPA to publish a set of deemed savings values, which would require less rigorous EM&V 

standards. Commenters stated that simplified EM&V protocols need to be developed for any 

programs for which a formal EM&V program does not exist currently. Commenters advocated to 

not allow each state to establish their EM&V protocols because states use vastly different 

methods, resulting in significant differences among states and utilities.

Commenters stated that uncertainty over EM&V protocols makes it difficult for states to rely on 

EE programs to meet section 111(d) requirements. Commenters expressed concern about how 

end-use efficiency savings will be quantified and noted that EPA's proposal acknowledges there 

are substantial differences in how states quantify results from end-use efficiency programs, but 

provided no guidance on how states will be required to quantify end-use efficiency savings.

Commenters stated that although the EPA stated that they intent to work with states to develop 

appropriate EM&V protocols, the lack of EM&V protocols makes it difficult for states to 

determine how much they can rely on end-use efficiency programs to meet the rule's emission 

rate requirements.

Commenters restated EPA's proposal for rate-based targets or mass-based performance targets 

and credits for energy efficiency under each approach. Commenters requested that EPA provide 

guidance on evaluation measurement and verification (EM&V) protocols and requirements, 

including whether there will be different EM&V requirements for states depending on the type of 

target they adopt providing a clear compliance pathway by describing state plan approaches, 

efficiency measures, and EM&V protocols suitable for each approach; whether any trading of 

efficiency credits will be permitted between states that adopt different types of targets as, absent 

oversight, trading between such states could result in double-counting of emissions reductions; 

and, prohibit trading of energy efficiency credits between states with mass- and rate-based 

targets unless state regulators can demonstrate that there are adequate safeguards to prevent 

double-counting of emissions reductions. 

Comment 2: Comments that the selection of EM&V protocols for energy efficiency should be 

left to the States.

Response 2: The EPA’s proposed approach gives states the flexibility to develop their own 

EM&V protocols. While the agency does not plan to interfere with existing state EM&V 

approaches that are working well, state EM&V plans under the state measures approach, and 

ERC program specifications under a rate-based emission trading approach, will be subject to 

EPA approval to ensure EM&V is rigorous, complete, credible, and consistent with the criteria 

provided in the preamble and EM&V guidance document.

The following are summaries of the specific public comments under this comment:

Commenters stated that selection of EM&V protocols for energy efficiency should be left to the 

States. Commenters stated that existing protocols developed by States were designed for 

different purposes than verifying emission reductions and, therefore, might not be the most 

effective or appropriate protocols for emission reductions. Commenters stated for example, many 
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of the existing protocols were developed to ensure that cost recovery for energy efficiency 

programs by for-profit utilities is justified. Commenters stated that an NRECA study indicated 

that only a handful of states require cooperatives to conduct EM&V studies or report savings 

from energy efficiency programs. Commenters stated therefore, it is critical that EPA not 

mandate existing protocols for use by States and that EPA instead allow States flexibility to use 

methodologies that are most appropriate for their individual circumstances. Commenters stated 

in the case of statewide programs, that it may be most effective to monitor savings upstream of 

the consumer-utility relationship or at a higher level than some methodologies used by large 

IOUs that can require large sample sizes, rigorous statistical analysis, or in-home visits in some 

cases. Commenters stated that however, given that the cost of EM&V can be a barrier to 

adopting energy efficiency programs, the methodologies should be as simple as possible to meet 

specific state needs, and the states should be allowed to decide of the balance between costs and 

benefits of EM&V protocols. 

Comment 3: Comments that EM&V protocols should be developed by either ASTM or DOE.

Response 3: The EPA’s proposed approach gives states flexibility to choose from credible 

EM&V protocols, as this will not restrict states that already have established programs. 

However, the EPA specifies EM&V provisions in the preamble to the proposed Federal Plan, 

and is providing EM&V guidance to help states to determine EM&V procedures, methods, and 

parameters that are quantifiable and verifiable, and therefore more likely to be approvable. 

The following are summaries of the specific public comments under this comment:

Commenters advocated development of standardized national protocols for EMEV for renewable 

and energy efficiency, and suggested that the protocols should be developed by either ASTM or 

DOE.

Comment 4: Comments that EPA should develop the EM&V protocols.

Response 4: The EPA’s proposed approach gives states flexibility to choose from credible 

EM&V protocols, as this will not restrict states that already have established programs. 

However, the EPA specifies EM&V provisions in the preamble to the Federal Plan, and provides 

EM&V guidance to help states to determine EM&V procedures, methods, and parameters that 

are quantifiable and verifiable, and therefore more likely to be approved. Requiring a specific, 

national EM&V protocol may be too large of barrier to some states that are considering EE 

programs or have different EM&V requirements than a potential national protocol. EE and RE 

programs must report savings in gross MWh where possible, and third party verification of 

energy savings is required.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should develop EM&V protocols for energy efficiency.

Commenters asked EPA to create detailed requirements for EM&V for energy efficiency that 
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include a net savings approach, third-party verification of energy savings, and a formal state 

process to provide transparency and allow for stakeholder input. Commenters stated that most 

states currently have inadequate EM&V for energy efficiency and allowing those procedures to 

remain in place will result in non-uniform treatment across states. Commenters stated that 

approving the use of current EM&V protocols will stall adoption of innovative new practices that 

are underway in the energy efficiency industry.

Comment 5: Comments that uniform EPA guidance on acceptable EM&V protocols is 

unnecessary.

Response 5: The EPA’s proposed approach gives states flexibility to choose from credible 

EM&V protocols, as this will not restrict states that already have established programs. 

However, the EPA specifies EM&V provisions in section IV.D.8 of the preamble to the 

proposed Federal Plan, and provides EM&V guidance to help states to determine EM&V 

procedures, methods, and parameters that are quantifiable and verifiable, and therefore more 

likely to be approvable. Regarding limiting crediting to well-established programs, the EPA 

position is that any demand-side EE program and project that results in MWh savings is 

potentially eligible, provided that it meets the criteria for eligibility described in section 

VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, complete and consistent 

with the criteria provided in the emission guidelines and the state plan. Regarding the acceptance 

of current state EM&V programs, the EPA’s proposed approach in the Federal Plan leverages 

existing state oversight, approval, and certification processes as long as they meet the rule text 

requirements.

The EPA’s approach does not distinguish between energy efficiency technologies. Renewable 

energy and demand-side EE and other non-BSER measures that are tied to a state plan and 

achieve quantified and verified MWh savings may be used to adjust a CO2 emission rate, 

provided they meet the general and specific eligibility requirements for resources used to adjust a 

CO2 emission rate, described in Section VIII.K.1.a.(2) of the preamble. The measures must also 

meet the eligibility requirements and provisions related to demand-side EE programs and 

projects, if applicable, and the requirements and criteria related to proper quantification and 

verification of MWhs from demand-side EE savings are described in section VIII.K.3 of the 

preamble.

The EPA’s approach allows for building codes and appliance standards to be counted towards 

EE savings. Additional implementing EM&V guidance will be provided in the draft guidance 

that will be released with the final rule. This guidance will include specific guidance on building 

codes and appliance standards, including recommended methodologies and protocols to use. All 

EE/RE used to adjust an emissions rate must address the criteria established in the final 

emissions guidelines. The EPA welcomes stakeholder input on the draft guidance.

Electricity T&D measures that improve the efficiency of the T&D system and/or reduce 

electricity use may be used to adjust a CO2 emission rate. Additional implementing EM&V 

guidance will be provided in the draft guidance that will be released with the final rule. All 
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EE/RE used to adjust an emissions rate must address the criteria established in the final 

emissions guidelines. The EPA welcomes stakeholder input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters opposed creation of a single guidance manual for EM&V for all states for demandside energy efficiency. Commenters stated that additional guidance for utilities is unnecessary 

because EM&V vendors already use nationally accepted protocols to evaluate efficiency 

programs. Creating a single EPA protocol would be unworkable because it would require 

frequent updating to stay current. Commenters also stated that adding another layer of EM&V 

requirements would hinder development of new programs by utilities due to the additional 

complexity and cost. Commenters also objected to the concept of limiting credit to wellestablished energy efficiency programs, because it would hinder development of new and 

innovative programs.

Commenters advocated that no federal EM&V requirements are needed for any energy 

efficiency program that is subject to PUC oversight, because these programs already are subject 

to rigorous evaluation and a transparent review process. Commenters said that additional EM&V 

would impost unnecessary burden and costs. Commenters stated EPA instead should accept 

current state EM&V programs and not require third-part evaluation. Commenters stated that if a 

state requires third-part evaluation, then no additional recordkeeping or reporting should be 

required for 111(d).

Commenters supported an approach that allows for three different nationally standardized 

EM&V procedures for well-established, moderately well-established, and less well-established 

energy efficiency technologies. Commenters expressed concerns relative to new emerging 

technologies, which may be central to maintaining 1.0% or 1.5% of sales targets, and which may 

not be given a chance to develop and succeed if EM&V is too strict.

Commenters stated that the EPA should consider including codes and standards as a compliance 

option for meeting goals under Building Block 4. Commenters recommended that EPA consider 

developing guidance surrounding EM&V and limitations or requirements for including codes 

and standards as a compliance option in state compliance plans.

Commenters stated that EPA must further develop a framework for EM&V protocols that 

balance cost with credible quantification of EE, as this is necessary for ensuring such measures 

are reliable and enforceable.

Comment 6: Comments that EPA is too late in providing the needed guidance for EM&V.

Response 6: Thank you for this perspective. The EPA is issuing draft EM&V guidance with the 

final emissions guidelines, and intends to finalize that guidance as quickly as possible.

SectionIV.D.8 of the preamble to the proposed Federal Plan discusses the final EM&V 

provisions. 

The following are summaries of the specific public comments under this comment:
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Commenters stated that EPA is delinquent in providing EM&V guidance. Commenters stated 

that this guidance should have been developed and made available for comment during the 

public comment period. Commenters maintained that not only does ill-timed guidance inhibit the 

states' ability to provide meaningful comments on feasibility of EPA's goals, but ultimately it 

could jeopardize the ability of states to prepare plans that meet EPA's requirements.

Comment 7: Comments on a recommended approach for EM&V that builds on state and 

regional programs currently in place.

Response 7: Thank you for your detailed recommendations for an EE EM&V framework. The 

EPA’s proposed approach requires states in the state measures approach, and EE and RE 

providers under the rate-based emission trading approach, to address the following key 

considerations in their EM&V plans:

• How significant changes in independent variable conditions (weather, 

occupancy, production rates, etc.) that affect energy consumption and 

savings estimates will be analyzed.

• How the initial installation of EE will be verified for EE program 

categories that involve the direct installation of measures.

• How avoided T&D systems losses can be included in EE savings values.

• How the duration of EE program or project electricity savings will be 

determined using annual verification assessments, industry-standard 

persistence studies, deemed estimates of effective useful life (EUL), or a 

combination of all three.

• How the rigor of MWh savings values will be determined, and the 

methods used to control the types of bias or error relevant inherent to the 

applied EM&V techniques.

• How double counting will be avoided through the use of tracking and 

accounting procedures to ensure that two or more programs do not 

separately claim savings from the same EE project or measure.

Regarding state pathways for EM&V of specific EE measures, the EPA’s proposed approach 

gives states the flexibility to choose from a deemed savings pathway, a PUC pathway, and a 

tailored M&V pathway as long as they meet EPA’s minimum requirements for EM&V. The 

EPA disagrees with the commenter that EE credit should only be given in the state which said 

credit occurs. The EPA is finalizing that states can participate in multi-state plans (see section 

VIII.C.5).

The following are summaries of the specific public comments under this comment:
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Commenters suggested that EPA develop a framework for EM&V for energy efficiency that is 

environmentally rigorous, cost-effective, and practical to implement, while also recognizing and 

building on the considerable progress by state and regional entities. Commenters enclosed a 29-

page document describing one potential approach to such a framework. Much of the attached 

framework contained general administrative and procedural requirements for a section 111(d) 

SIP but contained a few specific recommendations as listed below:

To receive credit for an energy efficiency measure, commenters stated that a company must 

make two annual filings for approval with the State agency - a prospective compliance plan and a 

compliance demonstration. Commenters stated the recommended content of each filing is 

outlined below:

Energy Efficiency M&V Compliance Plan (filed prospectively) 

• An overview of the approach to achieving avoided emissions through 

energy efficiency programs or measures; 

• Description of specific measures and programs that are expected to be 

implemented, and a projection of the quantity to be installed; 

• If applicable, an identification of the energy efficiency services 

company(ies) that will carry out EE installations, or a description of the 

process by which the company will select EE vendors 

• Expected energy savings to result from EE installations; 

• Adjustment of EE savings based on the M&V approach used and the 

state's assigned discount factors; and 

• Complete EE M&V plan consistent with the M&V requirements of the 

state plan, including specific approach(es) taken. 

Energy Efficiency M&V Compliance Demonstration (filed retrospectively) 

• A report comprehensively documenting savings based on 

implementation of the approved M&V plan; 

• Description of any modifications to program implementation (i.e., 

measures or programs installed, numbers of installations, etc.) relative to 

that specified in the compliance plan; 

• If applicable, a description of variations between expected and realized 

savings on a program-by-program basis 

• If applicable, identification of the energy efficiency services 

company(ies) that carried out installations, and any differences between 

expected and actual energy service companies used 
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• Adjustment of actual EE savings based on the M&V approach used and 

the state's approved adjustment factors 

Commenters stated that the energy efficiency credits awarded must be adjusted to account for 

uncertainty in the EM&V approach. Commenters recommended that the uncertainty measure 

could be statistical or not but with way should be based on the following criteria:

• The amount of time and number of programs across states for which the 

M&V approach has been used; 

• Historical evaluations of the statistical certainty around savings 

estimates generated using the M&V approach; 

• The degree of consistency in results generated using the M&V method 

in question; 

• Whether the program whose savings are being measured generally 

involves the same or similar measures installed in each location, or sitespecific determinations of a variety of end-use efficiency measures; 

• The degree to which the M&V approach involves or has involved sitespecific measurement of key parameters, as opposed to relying only on 

engineering estimates; 

• Assessments by state, regional or national agencies, collaboratives 

and/or organizations about the degree of certainty associated with 

savings measured using the approach; 

• Whether the M&V approach is subject to regulation by a public utilities 

commission or similar entity that evaluates measured energy savings for 

the purpose of establishing rates or otherwise compensating a regulated 

utility. 

• If a state plan does not provide an adjustment factor for uncertainty, or 

does not provide a reasoned basis for such a factor, EPA should consider 

applying a default adjustment factor based on the average degree of 

uncertainty observed in similar EE programs in other states. 

Commenters advocated that the energy efficiency credits should have an initial sunset of 5 years 

(to account for uncertainty in the estimated emissions results), which can be extended if the SIP 

has a provision for evaluating the persistence of a savings measure. Commenters stated that the 

baseline for energy efficiency credits should vary depending on the type of measure but the SIP 

should be explicit regarding the choice of baseline for various measures.

Commenters acknowledged that it is not possible at this time to specify a single set of EM&V 

approaches because the approaches are evolving rapidly and need to vary to reflect variation 

across regions in power systems, customer characteristic, electric loads, weather, and other 
369

factors. Commenters supported any one of three broad pathways for EM&V of energy efficiency 

measures:

• Deemed Savings Pathway: Commenters stated that the Deemed Savings 

pathway should require sources or third party providers to measure and 

verify the program installations, but would rely on deemed savings 

values or calculation methods for quantifying program savings for 

compliance demonstrations. Commenters specified some additional 

conditions for deemed saving programs.

• PUC-Based Pathway: Commenters stated that the PUC-Based Pathway 

states would accept savings demonstrated through mandated M&V 

filings with the state's public utility commission for the purpose of 

approving rate recovery or otherwise compensating the regulated utility, 

with appropriate adjustments to address any residual uncertainty. 

Commenters stated entities would be required to measure and verify 

energy efficiency measure/program installations and would rely on 

PUC-approved savings values as the basis for estimating program 

savings for compliance demonstrations. Commenters specified some 

additional conditions in the commenter's framework document.

• Tailored M&V Pathway: Commenters stated that the Tailored M&V 

approach, compliance entities or energy efficiency providers would be 

required to establish and implement a comprehensive M&V plan that is 

representative of national best-practices or other approaches 

appropriately adjusted to address residual uncertainty, that meet EPAprescribed minimum standards, and that is subject to the review and 

approval of the state agency implementing the Carbon Pollution 

Standards. Commenters specified some additional conditions in the 

commenter's framework document, including specification that the 

EM&V standard used by the PUC must have been used for at least 10 

years and state must apply the protocols developed under the DOE 

Uniform Methods Project (UMP) for measurement of energy efficiency 

savings. Commenters provided in the framework document an 

alternative set of specifications to the UMP requirement.

Commenters stated that EPA as part of plan approval should require commitment of sufficient 

resources to ensure reliable administration and oversight of EM&V. 

Commenters stated that a state should not be able to take credit for emissions avoided through 

energy efficiency measures undertaken in other states, but only for EE measures and programs 

undertaken within that state. 

Commenters stated this process takes into consideration demand-side EE throughout the 

Tennessee Valley. Commenters stated that TVA has its own methodology for designing, 

evaluating and valuing EE programs and these programs, to some extent, will need to compete as 

a resource in TVA's current IRP process. Commenters supported TVA's approach to the 
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development of current and future EE programs, but recognized that its approach is unique when 

compared to how other states have driven EE efforts. Commenters stated some of this 

uniqueness likely derives from the fact that end-use customers within the Tennessee Valley use 

electricity to cool and heat their homes, differing from many other parts of the U.S. Commenters 

stated therefore, the types of programs and how these programs are structured may need to be 

unique. Commenters stated whether TVA's approach and methodology will be acceptable for use 

within a state plan and whether TVA's programs will be enough for Tennessee to achieve the 

reductions required from this building block is not yet clear. 

Comment 8: Comments stating that the EPA should allow a wide range of EE measures to be 

used, including those for which EM&V has not yet been developed.

Response 8: The EPA’s position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility discussed in 

section VIII.K.1.a.(2). of the preamble, and that supporting EM&V is rigorous, complete, and 

consistent with the criteria provided in the emission guidelines and the state plan.

The following are summaries of the specific public comments under this comment:

Commenters encouraged EPA to allow a wide range of energy efficiency measures, and stated 

that EPA should find a way to allow measures for which development of acceptable EM&V 

measures have not yet been developed.

Comment 9: Comments that EPA should provide training on how to incorporate EE into state 

plans.

Response 9: The EPA is providing a draft EM&V guidance that will detail the types of EM&V 

approaches that can be considered rigorous, credible, complete, and consistent with industrystandard practices. Stakeholder comments on this draft are welcome and encouraged.

The following are summaries of the specific public comments under this comment:

Commenters suggested that EPA should provide training on how to incorporate energy 

efficiency into state plans, including the methods for quantifying avoided emissions.

Comment 10: Comments that EM&V data should be publically available and that EM&V 

practices be subject to third-party audits.

Response 10: The EPA’s proposed approach requires that all non-confidential EM&V plans, 

M&V reports, and savings documentation be made available for public review.

The following are summaries of the specific public comments under this comment:
371

Commenters advocated that due to the complexity of the EM&V process for energy efficiency, 

all EM&V verification data should be made available to interested stakeholders and that the 

EM&V practices should be subject to periodic third-party audits.

Comment 11: Comments that third-party verification of energy savings should be required.

Response 11: The EPA’s proposed approach requires the use of independent third party 

verification.

The following are summaries of the specific public comments under this comment:

Commenters requested that EPA clarify if the proposal intended that third party verification of 

energy savings would be required as part of EM&V. Commenters stated that the language and 

terminology used in the preamble is ambiguous.

Comment 12: Comments that strict EM&V could restrict the use of programs to encourage 

increased application of ground source heat pumps.

Response 12: Regarding the inclusion of heat pumps, the EPA position is that any demand-side 

EE program and project that results in MWh savings is potentially eligible, provided that it meets 

the criteria for eligibility discussed in section VIII.K.1.a.(2). of the preamble, and that supporting 

EM&V is rigorous, complete and consistent with the criteria provided in the emission guidelines 

and the state plan.

The following are summaries of the specific public comments under this comment:

Commenters supported the use of ground source heat pumps as an energy efficiency measure for 

homes. Commenters stated that EM&V tools are available now for energy consumption at 

building sites. Commenters recommended allowing energy efficiency credit for the use of water 

source and ground source heat pumps, but stated that protocols to quantify energy savings from 

ground source heat pumps are not currently available. Commenters recommended the adoption 

of EU Commission Decision 2013/114/EU-L62/2927 and L62/2928 with modifications for use 

in the United States, and mentioned that ASHRAE currently is developing a protocol for ground 

source heat pumps that uses meters and other automated data collection to monitor energy 

savings. Commenters cautioned that imposing strict EM&V requirements could make ground 

source heat pumps less feasible.

Comment 13: Comments that third-party verification of energy savings should be required and 

that some accredited credentialing organizations already exist. 

Response 13: Thank you for pointing out the credentialing and verification resources. The 

EPA’s proposed EM&V approach requires state plans to include independent third party 
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verification for EE programs if the state is including EE in their plan. This is the case regardless 

of whether a state is using the state measures or the rate-based emission trading approach.

The following are summaries of the specific public comments under this comment:

Commenters advocated that EPA should require any state plan to include provisions for 

independent, third-party auditing and verification of energy efficiency programs. Commenters 

pointed to the instances of fraud that have come to light in the trading of renewable fuel credits 

in the Renewable Fuels Program. Commenters stated that there are nationally accredited 

credentialing organizations such as those involved in the Clean Energy Credentialing Coalition 

(http://www.cleanenergycredentials.org/) that provide third-party assessment of energy 

efficiency professionals and products. Commenters listed five organizations that currently 

provide verification services.

Comment 14: Comments that EPA should impose no additional EM&V beyond what states 

require for renewable portfolio standards.

Response 14: The EPA’s approach on RE projects is that any project is potentially allowed, 

provided it meets the criteria established by EPA, providing a floor for EM&V practices to 

ensure credibility and certainty in savings estimates across jurisdictions.

The following are summaries of the specific public comments under this comment:

Commenters stated that any renewable energy that is accepted by a state RPS should qualify for 

compliance. Commenters stated that the rule should not add additional EM&V beyond whatever 

the state requires for their RPS.

Comment 15: Comments urging the EPA to allow for use of less well-established energy 

efficiency programs to be used.

Response 15: The EPA’s position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility discussed in 

section VIII.K.l.a.(2). of the preamble, and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines and the state plan.

The following are summaries of the specific public comments under this comment:

In response to EPA's request for comment on whether state plans should be limited to energy 

efficiency and renewable energy programs that are well-established, commenters stated that 

consideration should not be limited to only the well-established programs, because this will limit 

innovation in energy efficiency.

Commenters urged EPA to allow for use of less well-established energy efficiency programs to 

be used, subject to the following caveats:
373

• The amount of credit should be discounted according to the level of 

uncertainty inherent in the underlying EM&V method.

• States should be capped to a certain maximum amount of total credit for 

programs that are subject to significant discounting of credits per #1 

above.

• States using these programs should be actively refining and improving 

EM&V for these programs to reduce uncertainty and ensure that use of 

these programs result in real reductions units.

• If EPA allows for the inclusion of less well-established EE programs, 

EPA should increase the Building Block 4 target accordingly, 

considering the uncertain results of such programs.

Commenters supported the use of EPA's second option for providing EM&V guidance, which 

would allow utilities to take credit for energy savings from mature programs approved by a state 

process, and provide generalized guidance for relatively new, innovative, or untested energy 

efficiency measures.

Comment 16: Comments on the need for EPA guidance on EM&V for EE measures.

Response 16: The EPA has developed a draft EM&V guidance document to assist regulators. 

This document provides quantification guidelines for various types of RE and EE programs, and 

can refer regulators to relevant EM&V protocols. In addition, criteria making up an "EM&V 

floor" have been established and presented in the preamble and emissions guidelines.

The following are summaries of the specific public comments under this comment:

Commenters stated that utility energy efficiency protocols for EM&V have already been 

developed and fully vetted by most public utility commissions but believed that EM&V 

protocols for emissions reductions attributable to end-use energy efficiency are not as well 

developed. Commenters were concerned that many regulators are unfamiliar with EM&V 

protocols for end-use energy efficiency and recommended the EPA develop tools to bridge this 

gap, including estimated emissions values, a scoring system, or other quantification guidelines.

Comment 17: Comments that the Wisconsin Focus on Energy program could help EPA develop 

EM&V guidance for EE.

Response 17: Thank you for your comments and offer to act as a resource to learn from the 

Focus on Energy experience. One of the primary objectives for the EPA’s proposed EM&V 

provisions is to avoid excessive interference with EM&V practices that are already robust, 

transparent and working well. Therefore, the minimum criteria for EM&V in an approvable state 

plan establish a floor for EM&V practices to ensure credibility and certainty in savings estimates 
374

across jurisdictions. The EPA agrees that as long as EE and RE providers meet the minimum 

EM&V criteria presented in the preamble and emissions guidelines, they will be given flexibility 

to tailor their EM&V plan to the circumstances of their state. The EPA position is that any 

demand-side EE program and project that results in MWh savings is potentially eligible, 

provided that it meets the criteria for eligibility in the preamble, and that supporting EM&V is 

rigorous, complete and consistent with the criteria provided in the emission guidelines and the 

state plan.

The following are summaries of the specific public comments under this comment:

Commenters noted that the "Wisconsin Focus on Energy" program has a well-established and 

rigorous approach to determine the avoided emissions from EE measures that could serve as a 

model for EPA's EM&V requirements. Commenters stated that staff from the "Focus on Energy" 

program are willing to prepare materials and/or consult with EPA to help develop EM&V 

requirements. Commenters also requested the EPA allow Wisconsin to use these previously 

established methods to verify avoided emissions and should also allow other types of EE 

programs, including voluntary programs, to qualify for compliance as long as they meet the 

same, rigorous EM&V procedures.

Comment 18: Comment that the EM&V protocol should allow for multiple EM&V methods 

because the methods are evolving.

Response 18: The EPA’s proposed approach accommodates the likelihood that industry 

standards will evolve over time as EM&V methods mature. While the emissions guidelines 

provide high-level requirements and principles to be followed regarding EM&V, the draft 

guidance document can further inform state plans will be periodically updated to reflect changes 

in industry best practices.

The following are summaries of the specific public comments under this comment:

Commenters stressed that to accommodate building energy efficiency, the EM&V protocol needs 

to allow more than one EM&V approach because EM&V for the building sector is continuing to 

evolve and needs the flexibility to innovate to develop more accurate, streamlined methods.

Commenters noted that EPA asserts that states, for the most part, already utilize demand-side EE 

programs to reduce the amount of generation required from existing EGUs through reduced 

electricity consumption. Commenters stated that while this may be the case in many states, this 

does not adequately reflect how utility EE programs operate within Tennessee. Commenters 

noted that Tennessee has no demand-side EE planning requirements or standards and TVA's IRP 

process does not utilize an "all cost-effective energy efficiency." Commenters noted further that 

Tennessee currently has no PUC-defined EM&V or related compliance and reporting 

requirements. TVA engages in EM&V for its EE programs according to its Tennessee Valley 

Authority Technical Resources Manual ("TRM"). Commenters stated that EPA acknowledges in 

the State Plan Considerations TSD that EM&V approaches vary by state based on numerous 

factors and circumstances, and the fact that TVA determined that no existing EM&V approaches 
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met their needs and found it necessary to customize its own EM&V methodology particularly for 

its service area and demand-side EE program offerings highlights that there is no "one size fits 

all" approach to EM&V that is applicable and constructive for all states. Commenters 

recommended that EPA include TVA's existing EM&V methodology as one that would be 

acceptable under the proposed guidelines. Commenters also requested that EPA acknowledge 

and allow for evolving EM&V protocols in state plans as EE programs may change or their 

understanding of how best to value and credit them may evolve.

Commenters stated that while system-wide metrics for these programs are collected by TVA in 

partnership with LPCs, they are not currently collected on a state-by-state basis and within 

Tennessee are not subject to any state-level or state-specific EM&V requirements. Commenters 

asserted that if Tennessee were to incorporate demand-side EE into its state compliance plan, it 

would need to embark upon a process of establishing an EE valuation and crediting infrastructure 

that applies to all current programs, complete with EM&V standards. Commenters were unclear 

as to what state entity would be best suited to do this, given that TVA doesn't currently provide 

this oversight. Commenters further noted that this would need to be done under a compressed 

timeframe according to the proposed guidelines and would require cooperation among hundreds 

of LPCs. 

Commenters stated they understand that TVA is the first utility in the US to treat EE as a 

selectable resource in its IRP planning and that the potential for EE to compete in utility resource 

planning as a true resource is exciting and the commenters support TVA's approach in this IRP 

process. However, commenters noted that this is a relatively new approach to EE within the 

utility space and the process is ongoing. Commenters stated that it is unclear what the valuation 

or future growth assigned to EE by TVA will look like at this point, therefore, it is difficult to 

conceptualize how a state plan may value or credit this EE.

Comment 19: Comments that EM&V for EE measures is an inappropriate burden to place on 

states.

Response 19: States have the flexibility to meet their targets using any combination of building 

blocks. To encourage states to incorporate EE and RE programs into their plans while still 

ensuring the credibility of these programs, the EPA’s proposed approach ensures a minimum 

level of EM&V rigor and quality control. The EPA is doing this by establishing an "EM&V 

floor" that all EE and RE providers must achieve to ensure credibility, while still providing states 

the flexibility to design their own tailored programs.

The following are summaries of the specific public comments under this comment:

Commenters stated that tracking, quantifying and compiling the effect of all of the essential 

BSER measures for Building Blocks 3 and 4 would be a daunting task. Commenters stated EPA 

is saddling states with an inappropriate burden.

Commenters believed that enforcement of Building Block 4 would be difficult because 

measurability and verifiability are difficult to attain and enforcement would be too difficult as 
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many of the efficiency measures are outside of the control utilities because they occur at the 

customer's premises. 

Comment 20: Comments on the degree of rigor needed for EM&V for EE programs.

Response 20: The EPA’s proposed approach balances the tradeoff between accuracy and cost by 

establishing an "EM&V floor" that all states must achieve to ensure a minimum level of 

credibility, while still providing states the flexibility to design their own tailored programs. 

States will have the flexibility to use model-based evaluations as long as they conform to 

industry standards and the EE measure impacts can be adequately quantified and verified.

The following are summaries of the specific public comments under this comment:

Commenters urged EPA to carefully consider the tradeoff between accuracy and cost in 

designing EM&V programs for energy efficiency. Commenters said to not let the perfect be the 

enemy of the good. For example, commenters recommended the use of model-based evaluations 

for energy savings as is allowed form transportation measures in SIPs.

Comment 21: Comment encouraging behavioral energy efficiency programs because EM&V 

methods are available using randomized control trials.

Response 21: Under the EPA’s approach, behavior change programs are allowed, as long as 

their impacts can be adequately quantified and verified. The EPA’s approach also no longer 

incorporates a streamlined review option, therefore behavioral energy efficiency will face the 

same level of scrutiny for approval as other forms of EE and RE. 

The following are summaries of the specific public comments under this comment:

Commenters disagreed with EPA that behavioral energy efficiency programs pose verification 

challenges and advocates for their adoption. Commenters stated that their company operates 

behavioral energy efficiency programs for utilities in 31 states and successfully use randomized 

control trials to verify savings for state energy efficiency programs. Commenters recommended 

that EPA list behavioral programs with randomized control trials as measures that will be subject 

to streamlined review in an approvable state plan.

Comment 22: Comments suggesting that EPA provide a template for state EM&V plans.

Response 22: The EPA is providing a template for an EM&V plan in its draft EM&V guidance 

document.

The following are summaries of the specific public comments under this comment:
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Commenters asked EPA to provide a template for the EM&V plan to help states know what 

needs to be included.

Comment 23: Comment that EPA should require multi-year EM&V evaluations of the 

effectiveness of EE measures.

Response 23: The EPA’s proposed EM&V approach requires that program impacts are 

determined for each year, based on annual verification of activity levels, and at least every three 

year impact evaluations to update values. The draft EM&V guidance suggests that impact 

evaluations for larger projects in the EE portfolio should be updated annually. If deemed savings 

are used, the EPA’s draft guidance recommends the technical reference manual for these 

approaches be reviewed and updated at least every three years to keep current with market trends 

and technology innovation.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EM&V plan should include a multi-year evaluation plan for updating 

the plan and the savings assumptions and reporting back to EPA, similar to the SEE Action 

Network Impact Evaluation Guide Chapter 8. Commenters stated that an evaluation every 3-5 

years should be conducted for every efficiency measure that accounts for 5-10 percent of the 

energy savings that a state claims.

Comment 24: Comments about changing EM&V protocols over time.

Response 24: The EPA’s is not approving the use of protocols that can or cannot be used, but 

offering a set of EM&V criteria in the emissions guidelines and implementing guidance (to be 

released in draft with the final rule). The approval of EM&V plans rests with states in the 

emissions-standards type state plan. For state measures plans, the EPA will work closely with 

interested states to ensure that approvable EM&V approaches – consistent with the emissions 

guidelines – are clarified. 

The following are summaries of the specific public comments under this comment:

Commenters expressed concern that EPA could, at a later date, decide that it no longer agrees 

with a particular EM&V protocol, and then reject the claimed energy efficiency savings.

Commenters stated that States and utilities need fair advance notice if EPA is going to change 

approved protocols.

Comment 25: Comments that EPS should set a specific schedule for the EM&V plan process.

Response 25: The EPA’s proposed Federal Plan and draft guidance address the following 

process steps with EM&V for EE and RE programs:
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• Completion of EM&V plans 

• Annual evaluation of MWh impacts 

• Minimum tracking requirements to avoid double counting of MWh 

• Requirements for third-party verifiers

• Public disclosure of methods and results 

• Periodic verification during the plan period to ensure EE measures are 

still in place and saving energy

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should set a schedule for the following steps:

• State submission of EM&V plan.

• EPA review of the EM&V plan (including steps for re-submittal and 

EPA approval).

• Interim reporting to EPA of energy efficiency savings and avoided 

emissions, and progress toward meeting the 2030 goals.

• State modification of EM&V plans as informed by the interim reporting.

Comment 26: Comment on consistency across states on EM&V reporting for entities that 

provide EE services in multiple states and for small entities.

Response 26: Regarding inconsistent EM&V across states, the EPA’s proposed approach allows 

states, and EE and RE providers under the rate-based emission trading approach, the flexibility to 

develop their own EM&V plans. While the EPA is proposing to establish minimum EM&V 

requirements for all EE and RE programs, and states are encouraged to work jointly to promote 

consistency, the EPA’s proposed approach does not resolve the fact that utilities may face 

different EM&V requirements applied by their public utility commissions (PUCs), for example. 

Regarding approved methodologies for states to use in their EM&V plans, the EPA is providing 

a draft EM&V guidance document that recommends industry standards for various EE and RE 

projects. With smaller utilities, the EPA’s proposed approach leaves it to the states on whether 

and how to include these utilities in their EE and RE programs.

The following are summaries of the specific public comments under this comment:

Commenters asked EPA to provide guidance on the issue of interstate entities that would be 

subject to duplicative reporting of demand-side energy efficiency efforts. Specifically, 
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commenters asked EPA to provide clarification on how certain interstate scenarios, and other 

similar situations, would be handled under the different plan types discussed in the State Plan 

Considerations TSD. Commenters stated the Agency should allow flexibility on what can be 

used for measurement and verification (M&V) at the state level. 

Commenters stated EPA should provide states with indicative approved methodologies to 

measure and verify energy savings from energy efficiency projects and programs (both single 

technology measures and whole buildings), and a process for states and industry to submit 

additional methodologies for consideration and approval. Commenters suggested these should 

include, but not be limited to: Uniform methods projects standard; International Performance 

Measurement and Verification Protocol; ASHRAE Guideline 14-2002 Measurement of Energy 

and Demand Savings; DOE's Superior Energy Performance program created an M&V protocol 

for industry; Technical Reference Manuals ("deemed savings" charts that provide statistical 

savings value for equipment upgrades); SEE Action Network and regional standards such as 

those by NEEP and the Northwest's Regional Technical Forum; ISO 50001:2011 Energy 

management systems; and Demand response measurement and verification, such as The National 

Action Plan for DR M&V element (see http://emp.lbl.gov/sites/all/files/napdr-measurementandverification.pdf.)

Commenters stated EPA should provide guidance for smaller entities that will be required under 

this rule to implement EM&V protocols for their efficiency programs. Commenters stated that 

for small utilities (e.g., a small utility could have only a few employees, less than 2,000 

customers, and multiple service responsibilities), this could easily become burdensome and 

costly since they do not have the resources (workforce, funding, etc.) to accomplish the same 

caliber of reporting and analysis as larger utilities. Commenters recommended EPA establish a 

subcategory group of utilities that will have more streamlined requirements for their EM&V 

reporting. Commenters stated the development of these protocols and methods for measuring and 

verifying energy savings will take time and the Agency should explicitly allow additional time, if 

needed, in state plans for states to set up the constructs or modify their existing programs to meet 

any additional requirements imposed by this rule. Commenters noted this conforms to the timing 

questions posed in EPA's NODA.

Comment 27: Comments advocating field-based verification rather than engineering estimates 

for EM&V.

Response 27: EM&V methods for many traditional EE measures are now well-established. For 

energy efficiency measures that are more recent or have higher levels of uncertainty associated 

with energy savings, the EPA’s proposed approach will still require a minimum set of EM&V 

criteria to be met. The EPA position is that any demand-side EE program and project that results 

in MWh savings is potentially eligible, provided that it meets the criteria for eligibility discussed 

in the preamble, section VIII.K.1.a.(2)., and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines and the state plan. The EPA’s 

proposed approach gives states flexibility over which EM&V standards to draw from, but 

encourages states to leverage existing industry protocols, as this will facilitate the EPA’s ability 
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to ensure that EE measure impacts can be adequately quantified and verified. Regarding the 

discounting of EE savings for less rigorous EM&V approaches, as long as the EM&V approach 

meets approvability criteria, energy reductions will be fully credited.

The following are summaries of the specific public comments under this comment:

Commenters recommended the EPA establish detailed protocols and guidance for evaluation, 

monitoring, and verification of efficiency programs favor field-based savings estimates over 

engineering estimates, and should encourage evaluators to take advantage of state-of- the-art 

approaches to program evaluation. Commenters also recommended states be credited for energyefficiency savings based on the rigor of the methodology used to measure the savings.

Commenters stated that randomized controlled trials (RCTs) are the most rigorous design, 

followed by quasi-experimental methods, non-experimental methods, and engineering studies. 

Commenters recommended the EPA discount estimated savings from non-RCT based 

evaluations and argued that only savings estimates from high-quality, well-executed RCTs would 

be credited at 100 percent. Commenters said that savings estimates based on engineering 

estimates or using field data and less rigorous evaluation techniques should be credited at some 

fraction (i.e., less than 100 percent) of the predicted savings with exact discount based on the 

ratio of actual savings to predicted savings in previous studies. As an example, commenters 

explained that if an engineering study predicted 450 kWh savings per year per household from 

replacing old refrigerators with energy-efficient models, but then a high-quality RCT found that 

this same program actually generated savings of only 135 kWh, then future engineering-based 

estimates for refrigerator programs should be credited at 135/450=30 percent. Commenters noted 

that states that do not like the discount can perform a high-quality RCT and then be credited with 

the full amount of savings. Commenters suggested the EPA update the discounts over time as 

more data becomes available from new studies. Commenters noted that using this approach, 

crediting would become more and more accurate over time.

Comment 28: Comments that costs for many EE measures remain uncertain.

Response 28: For the reasons discussed in section V.B of the preamble, the EPA is not including 

demand-side energy efficiency measures as part of the BSER, but are allowing demand-side 

energy efficiency as a means of compliance with the requirements of this rule. Therefore, each 

state will be able to make their own determination as to what, if any, demand-side energy 

efficiency measure they want to adopt to help EGUs comply with the rule. Simultaneous with the 

final rule, we are publishing EM&V guidance for states to use in preparing their plans 

(Evaluation, Measurement and Verification Guidance for Demand-Side Energy Efficiency –

Draft). In preparing the EM&V guidance, an objective was to avoid excessive interference with 

current EM&V practices that are already robust, transparent and working well so as to encourage 

the use of cost effective energy efficiency measures to the maximum extent practicable. 

The following are summaries of the specific public comments under this comment:

Commenters stated in devising and implementing state plans for compliance, states should keep 

in mind that the costs of many EE measures remain largely uncertain, particularly in the absence 
381

of EM&V guidance that defines the universe of acceptable, quantified measures. Commenters 

stated as the proposed rule currently stands, there is no reliable cost analysis with respect to 

potential EE measures. Commenters stated thus, there is simply insufficient data and information 

in the record to support the cost-effectiveness of emission reductions from potential EE 

measures. 

Comment 29: Comments requesting additional guidance about assessing EE programs and 

EM&V provisions to verify a state's ability to achieve and implement claimed emission 

reductions for purposes of state plan approval.

Response 29: Additional implementing EM&V guidance will be provided in the draft guidance 

that will be released with the Federal Plan. This guidance will include a state plan template 

specifying what will need to be included. The EPA welcomes stakeholder input on the draft 

guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated in sum, the EPA should provide additional guidance for how it will go about 

assessing EE programs and EM&V provisions to verify a state's ability to achieve and implement 

claimed emission reductions for purposes of state plan approval. Commenters stated to ensure 

meaningful consideration of such guidance and its implications for the EPA's promulgation of 

section 111(d) emission guidelines, the EPA further must ensure that such guidance is proposed 

and finalized following public comment prior to issuance of any final rule. 

Comment 30: Comments requesting that final rule contain a clear set of best practices for 

EM&V of EE programs.

Response 30: Additional implementing EM&V guidance will be provided in the draft guidance 

that will be released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate 

must address the criteria established in the final emissions guidelines. The EPA welcomes 

stakeholder input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA must use the final rule to establish a clear set of best practices to 

appropriately monitor, measure, evaluate, and verify the contributions of EE programs. 

Commenters stated that with a number of different programs in the baseline, states will need 

guidance to count compliance appropriately. 

Commenters suggested improvements to the rule that include clarifying a number of details on 

how building block #4 will be implemented; in particular, including good but reasonable 

procedures for evaluating and documenting EE savings. 
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Comment 31: Comments encouraging the EPA to provide guidance on SIP implementation for 

end-use EE programs.

Response 31: The EPA’s proposed approach requires states in the state measures approach, and 

EE and RE providers under the rate-based emission trading approach, to address the following 

key considerations in their EM&V plans:

• How significant changes in independent variable conditions (weather, 

occupancy, production rates, etc.) that affect energy consumption and 

savings estimates will be analyzed.

• How the initial installation of EE will be verified for EE program 

categories that involve the direct installation of measures.

• How avoided T&D systems losses can be included in EE savings values.

• How the duration of EE program or project electricity savings will be 

determined using annual verification assessments, industry-standard 

persistence studies, deemed estimates of effective useful life (EUL), or a 

combination of all three.

• How the rigor of MWh savings values will be determined, and the 

methods used to control the types of bias or error relevant inherent to the 

applied EM&V techniques.

• How double counting will be avoided through the use of tracking and 

accounting procedures to ensure that two or more programs do not 

separately claim savings from the same EE project or measure.

Additional implementing EMV guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan.

The following are summaries of the specific public comments under this comment:

Commenters stated that consistent with EPA policy, any state incorporating End-Use EE 

Programs into their section 111(d) State Implementation Programs (SIPs) should 

• permanently reduce GHG reductions that 

• would not otherwise have occurred due to existing regulations or law,

• the emissions reductions must be accurately quantified, and 

• the EE program administrators must be held accountable through a 

transparent enforcement process. 
383

Without providing prescriptive recommendations or endorsing any particular methodology, 

commenters strongly encouraged EPA to establish guidance on SIP implementation that, at a 

minimum, include the following elements and/or criteria: 

• long-term sources of identifiable, programmatic funding for EE 

programs, 

• the adoption of reasonable, reliable measurement practices that can 

determine emissions reductions attributable to the programs, and

• procedures for monitoring, record-keeping, and administration of 

penalties for non-compliance. 

Comment 32: Comments requesting guidance on EM&V, and providing some 

recommendations.

Response 32: Additional implementation EM&V guidance will be provided in the draft 

guidance that will be released with the proposed Federal Plan. All EE/RE used to adjust an 

emissions rate must address the criteria established in the final emissions guidelines. The EPA 

welcomes stakeholder input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated rigorous evaluation, measurement and verification (EM&V) for EE savings 

is a critical issue for state plans that rely on reported savings to demonstrate compliance.

Commenters looked forward to EPA's eventual guidance on EM&V. Commenters provided 

previously a brief review of the recommendations of Analysis Group on EM&V in section 

111(d) state plans, which were included in a white paper published in March 2014, to assist EPA 

in preparing such guidance. 

Comment 33: Comment stating the importance of an EM&V protocol.

Response 33: The EPA’s proposed approach recognizes states will have individual 

circumstances and provides flexibility when choosing EM&V methods. One of the EPA’s 

overarching objectives for the proposed EM&V criteria is to avoid excessive interference with 

EM&V practices that are already robust, transparent and working well at the state level. 

Therefore, the minimum criteria for EM&V in an approvable state plan establish a floor for 

EM&V practices to ensure credibility and certainty in savings estimates across jurisdictions.

The following are summaries of the specific public comments under this comment:

Commenters stated at the heart of all successful EE programs is a reliable, enforceable, EM&V 

protocol. Commenters stated protocols must balance cost with credibility, and no one protocol 

fits all programs. Commenters stated EPA rightfully acknowledged that states have adopted 

numerous EM&V protocols. Commenters noted many states will wish to maintain their 
384

jurisdiction in determining and monitoring EM&V protocols. Commenters stated in the same 

vein, states use different methods to determine the costs and benefits of EE programs under their 

jurisdiction, to ensure they are consistent with state laws and policies. Commenters stated 

therefore, EPA should not attempt to standardize EM&V protocols across all states. Commenters 

noted that the likely unintended consequence is that states may avoid the inclusion of this 

building block in their plans in order to avoid the regulatory upheaval it would create.

Comment 34: Comments recommending that the EPA develop a broad framework of EM&V 

protocols to guide states, and require state plans to provide information on the EM&V protocols 

in their SIPs.

Response 34: Rather than prescribing one EM&V protocol, the EPA’s proposed approach 

allows EE and RE providers to choose from a broad framework of EM&V protocols. Additional 

implementing EM&V guidance will be provided in the draft guidance that will be released with 

the final rule. All EE/RE used to adjust an emissions rate must address the criteria established in 

the final emissions guidelines.

The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA develop a broad framework of EM&V protocols to guide 

states, and require state plans to provide information on the EM&V protocols that will be relied 

upon by the given state(s) in its SIP. Commenters also recommended that EPA not involve itself 

in cost benefit assessments for EE programs, as they are also unique to each state and not a 

necessary element for compliance. Commenters stated so long as EPA has confidence that the 

energy savings are real, each state can assess the cost effectiveness of the programs compared 

against other options to reach its CO2 emission target. 

Comment 35: Comments stating that the EPA has failed to provide specific EM&V guidance, 

that the EPA needs to do more than "assert" that flexibility in to a building block.

Response 35: The EPA’s proposed approach provides states with flexibility to tailor their 

programs to meet the needs of their state, and continue to apply EM&V methodologies that are 

working well.

However, the EPA specifies an EM&V floor of minimum requirements states must meet to 

ensure their programs are credible and robust. Additional implementing EM&V guidance will be 

provided in the draft guidance that will be released with the proposed Federal Plan. All EE/RE 

used to adjust an emissions rate must address the criteria established in the final emissions 

guidelines. The EPA welcomes stakeholder input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA failed to establish Evaluation, Measurement and Validation (EM&V) 

protocols that need to be relied upon by states to develop state plans.
385

Commenters also commented that the EPA's lack of guidance on how to attribute, measure and 

verify EE savings creates uncertainty that could lead to substantially underestimating the needed 

amount and types of EE (leaving the state short of meeting the needed contributions from EE) or 

overestimating the needed amounts and types of EE (needlessly increasing the overall costs of 

compliance). Commenters stated that the "flexibility" built into this particular building block 

simply exposes the many substantive issues that remain unresolved, and to which the EPA 

acknowledges it does not have readily available solutions. Commenters added that the EPA must 

do more than simply "invite comments" or assert that there is "flexibility" by providing 

meaningful guidance on what will or will not be considered adequate EE measures. 

Commenters believed that in the Clean Power Plan proposal, the EPA could have provided 

additional guidance on the demand-side EE building block regarding evaluation, measurement, 

and verification. 

Comment 36: Comments encouraging the EPA to provide states with guidance regarding 

procedures related to claimed EE savings.

Response 36: Additional implementing EM&V guidance will be provided in the draft guidance 

that will be released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate 

must address the criteria established in the final emissions guidelines. The EPA welcomes 

stakeholder input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated the CPP must ensure that a state's claimed EE savings are based on sound, 

appropriate evaluation procedures. For that reason, commenters encouraged EPA to provide 

states with guidance regarding such procedures, and to seek input from experienced states in 

developing such guidance. 

Comment 37: Comment stating that modeling must be allowed to account for EM&V. 

Response 37: Regarding the inclusion of modeling methodologies to account for EE, additional 

implementing EM&V guidance will be provided in the draft guidance that will be released with 

the proposed Federal Plan. All EE/RE used to adjust an emissions rate must address the criteria 

established in the final emissions guidelines. The EPA welcomes stakeholder input on the draft 

guidance.

The following are summaries of the specific public comments under this comment:

Commenters believed modeling must be allowed to account for EM&V. Commenters stated that 

two systems they found are useful and would support are REM/RATE and REM/Design. 

Commenters stated both are designed to calculate various energy design features. Commenters 

stated REM/Design is a model for homebuilders and remodelers. Commenters stated by entering 

some simple details about a home the software automatically configures the most cost effective 
386

ways to meet the IECC. Commenters stated REM/Rate is specifically designed for Home Energy 

Rating Systems (HERS) providers. Commenters stated in addition to ensuring code compliance, 

this model can provide an EE mortgage report, energy appraisal addendum, and a utility bill 

analysis, among other things. 

Comment 38: Comments providing suggestions for specific tools to ensure GHG reductions are 

measurable and attributable to EE, specifically from insulation.

Response 38: The EPA thanks you for your recommendations on tools that will help ensure 

greenhouse gas reductions are measurable and attributable to EE. Additional implementing 

EM&V guidance will be provided in the draft guidance that will be released with the proposed 

Federal Plan, and the EPA welcomes stakeholder input on the draft guidance.

Regarding double counting, the EPA’s approach requires states in the state measures approach, 

and EE and RE providers under the rate-based emission trading approach, to show how double 

counting will be addressed in their EM&V plans. Specifically, states and EE/RE providers must 

show how double counting will be avoided through the use of tracking and accounting 

procedures to ensure that two or more programs do not separately claim savings from the same 

EE project or measure.

The following are summaries of the specific public comments under this comment:

Commenters stated there are a variety of other tools that are or will soon be helpful in ensuring 

greenhouse gas reductions are measurable and attributable to EE and specifically insulation. 

Commenters provided a few examples, as follows:

• DOE's Standard Energy Efficiency Data (SEED) Platform is a free and 

open source software tool that helps administrators of large groups of 

building manage data on EE performance. SEED software can handle 

imported data from related tools such as EPA Portfolio Manager, DOE 

Buildings Performance database and in 20l5 will include DOE's 

Commercial Building Energy Asset Score and Home Energy Score. The 

software can help state and local governments implementing regulations 

and standards keep track of these measures. http://energv.gov/eerc/ 

buildings/ standard-energy-efficiency-data-platform

• DOE's Uniform Methods will ultimately create a uniform manner to 

measure and assess EM&V in EE. The protocols that will be created will 

provide a basis for complying with resource standards and will give 

stakeholders confidence that EE goals are being met. 

http://encrgy.gov/eere/about-us/initiatives-and-projects/uniformmethods-project-determining-energy-efficiency-program-savings

• The ACEEE has created a tool they call the Local Energy Efficiency 

Policy Calculator (LEEP-C) that can be used by policy makers to 

calculate a variety of items including ways to achieve policy goals such 
387

as energy savings, pollution reduction, and net jobs. 

http://www.aceec.org/ portal/local-policy/calculator

Commenters stated this list is simply a sample of the EM&V tools that are available or are being 

developed to quantify and standardize EM&V from EE. 

Commenters recommended that the EPA appropriately account for voluntary energy efficiency 

actions by private actors not covered by the rule, so that such actions are not double counted by 

reducing any state's obligations under the rule. Commenters also recommended that the EPA not 

allow double-counting of efficiency-based reductions, including between a state using a ratebased and one using a mass-based approach.

Comment 39: Comments stating that it is analytically challenging to estimate the quantity of 

GHG emissions reduced or avoided by demand-side EE projects, and that the EPA should accept 

state conservation improvement methodologies as they currently exist.

Response 39: The EPA’s proposed overarching EM&V objectives include the importance of 

striking a reasonable balance between EM&V rigor and credibility on the one hand, and the costs 

associated with project performance evaluation on the other. Another objective for the EPA’s 

criteria is to avoid excessive interference with EM&V practices that are already robust, 

transparent and working well. Therefore, the minimum criteria for EM&V in an approvable state 

plan establish a floor for EM&V practices to ensure credibility and certainty in savings estimates 

across jurisdictions. 

After implementation has occurred, EM&V reports are required to document and describe how 

each of the criteria was applied on an ex-post basis. These reports also specify the resulting 

MWh savings or generation values per RE and EE program and project category.

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the criteria established in the final emissions guidelines. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated that TVA is not required to submit annual M&V studies to state utility 

commissions. Commenters stated it is analytically challenging to estimate the quantity of GHG 

emissions that may be reduced or avoided by implementing demand-side EE projects.

Commenters stated that to estimate reduced GHG emissions in this context requires complex 

modeling designed to calculate (i) the change in electricity load for each hour of the day an EE 

project is expected to operate, and (ii) the marginal emissions reductions associated with the 

marginal electric generation unit in a region that can be expected to reduce its output in response 

to the change in electric load. Commenters noted that accomplishing this requires the use of 

regional electric generation dispatch modeling tools and other sophisticated analysis methods 

that not all entities have at their disposal. Commenters indicated that instead of requiring these 

burdensome methods, to the extent that states can credibly show that these emissions have been 
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avoided, EPA should grant credit for these actions under a state plan. Because TVA is a 

wholesaler of electricity with over 150 local power companies that distribute TVA power, 

commenters stated the business model requires collaboration from multiple parties, resulting in a 

complexity for EE that does not appear elsewhere. 

Commenters stated EPA should broadly and explicitly accept state conservation improvement 

methodologies as they currently exist. Commenters stated at the heart of EE savings are 

assumptions about how those savings are quantified. Commenters stated these assumptions 

attempt to characterize existing use patterns, which are then applied to energy efficient 

technologies to determine the appropriate amount of savings. Commenters stated in nearly all 

cases, the measurement of EE impacts requires a comparison to a scenario that didn't happen, or 

that ceases to exist. Commenters stated this is one of the fundamental challenges of EE. 

Commenters stated attempts to resolve this inherent quantification challenge can take the form of 

measurement and verification efforts, ex-post evaluations of EE impacts, or statistical 

evaluations of the impact. Commenters stated in all cases these evaluations are costly, do not 

remove the inherent uncertainty of the measurement, and potentially take resources away from 

activities that provide direct benefit to the end-use consumer, e.g., incentives for energy efficient 

equipment. Commenters stated the necessity to look at a change in energy use from a businessas-usual scenario does not fit will with the Clean Air Act's continuous compliance assurance 

requirements. Commenters stated accordingly, EPA should recognize that state programs are 

adequate and sufficient to meet all of the Clean Air Act provisions. 

Comment 40: Comments stating that if the EPA does not help states understand how GHG 

emission reductions driven by PC projects can be counted toward CPP compliance, states will 

tend to focus on other compliance activities and neglect PC opportunities.

Response 40: Regarding the eligibility of performance contracting projects, additional 

implementing EM&V guidance will be provided in the draft guidance that will be released with 

the proposed Federal Plan. All EE/RE used to adjust an emissions rate must address the criteria 

established in the final emissions guidelines. The EPA welcomes stakeholder input on the draft 

guidance.

The following are summaries of the specific public comments under this comment:

Commenters pointed out that if states are not clear on the steps needed to include GHG emission 

reductions from PC projects into their compliance plans and reporting under the CPP, it should 

be expected that these projects are more likely to be excluded from state planning activities. 

Commenters noted that the CPP, even as nothing more than a proposed rule, is already driving 

significant activity at the state and local level to re-examine energy plans, policies and 

incentives. Commenters said it stands to reason that attention will be most likely focused on 

those activities that include the benefit increasing a state's ability to comply with the CPP. If 

EPA does not help states understand how GHG emission reductions driven by PC projects can be 

counted toward CPP compliance, commenters said they will tend to focus on other compliance 

activities and neglect PC opportunities. Commenters indicated this could inhibit demand for PC 
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projects in many states. Absent an active ESCO market, commenters said large quantities of EE 

opportunity will remain beyond reach and untouched. 

Comment 41: Comments supporting the findings of a report titled "Greenhouse Gas Reductions 

through Performance Contracting under EPA’s Clean Power Plan", in which comments request 

additional guidance from the EPA on ten key issues.

Response 41: Additional implementing EM&V guidance will be provided in the draft guidance 

that will be released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate 

must address the criteria established in the final emissions guidelines. The EPA welcomes 

stakeholder input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters supported the findings of a report (written by different commenters), titled, 

"Greenhouse Gas Reductions through Performance Contracting under EPA's Clean Power 

Plan," in where the commenters stated EPA include additional guidance in its final rule with 

respect to ten key issues. 

Comment 42: Comments suggesting the EPA should consider a variety of options initiated 

within a state.

Response 42: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines and the state plan. Additional 

EM&V guidance will be provided in the draft guidance that will be released with the proposed 

Federal Plan. All EE/RE used to adjust an emissions rate must address the criteria established in 

the final emissions guidelines. The EPA welcomes stakeholder input on the draft guidance.

Regarding the issue of double counting, EM&V plans must address how double counting will be 

avoided through the use of tracking and accounting procedures to ensure that two or more 

programs do not separately claim savings from the same EE project or measure (for example, 

two EGUs claiming savings from the same lighting retrofit). Other types of double counting 

must likewise be considered and avoided.

The following are summaries of the specific public comments under this comment:

Commenters suggested EPA should consider a variety of options as long as they are initiated 

within the state (i.e., not federal programs such as federal appliance and equipment standards), 

have the appropriate EM&V, and avoid double counting savings. 
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Comment 43: Comments urging the EPA to clarify that the same approach applies to demand 

response programs and measures in the Final Rule in this docket.

Response 43: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines and the state plan.

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the criteria established in the final emissions guidelines. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA's Proposed Rule proposes that state implementation plans be allowed to 

include "a wide (or unlimited) set of energy efficiency programs and measure types in state 

plans, as long as the energy savings are adequately documented according to rigorous evaluation, 

measurement & verification (EM&V) methods and appropriate state regulatory oversight." 

Commenters urged EPA to clarify that the same approach applies to demand response programs 

and measures in the Final Rule in this docket. Commenters stated as with energy efficiency, this 

approach will work for demand response because energy savings calculated by rigorous demand 

response EM&V methodologies subject to regulatory oversight can be used to calculate carbon 

emissions reductions. 

Comment 44: Comments stating that tested and proven demand response EM&V protocols in 

use today adequately document energy savings, as well as peak load reduction impacts, and are 

subject to state regulatory oversight.

Response 44: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines and the state plan.

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. This guidance will include recommended approaches

and protocols for various types of EE programs. All EE/RE used to adjust an emissions rate must 

address the criteria established in the final emissions guidelines. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated tested and proven demand response EM&V protocols in use today 

adequately document energy savings, as well as peak load reduction impacts, and are subject to 

state regulatory oversight; for example, the California Public Utility Commission (CPUC) 

developed its own demand response EM&V protocols to facilitate integration of demand 
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response into the California electricity system. Commenters stated CPUC requires that California 

utilities submit annual and monthly reports in compliance with the EM&V protocols which 

evaluate demand response energy savings and load reduction impacts. Commenters stated 

significantly, CPUC's EM&V protocols insure accurate measurement of energy savings from 

demand response events by addressing any issues of pre-cooling and snap back cooling as well 

as gaming of load impacts. On the other hand, commenters stated the State of Maryland has had 

success utilizing a third-party, independent evaluator model to measure and verify the energy 

impacts of demand response. Commenters stated the independent evaluator in Maryland verifies 

each utility's report on demand response energy impacts in a two-step process.

Comment 45: Comments stating that accurate evaluation of the energy impacts of demand 

response is critical to maintaining system reliability and grid stability.

Response 45: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines and the state plan.

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. This guidance will include recommended approaches 

and protocols for various types of EE programs. All EE/RE used to adjust an emissions rate must 

address the criteria established in the final emissions guidelines. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated accurate evaluation of the energy impacts of demand response is critical to 

maintaining system reliability and grid stability. Commenters stated as a result, the FERC tasked 

the North American Energy Standards Board (NAESB) to promulgate demand response EM&V 

model standards for use in wholesale and retail electricity markets. Commenters stated in FERC 

Order 676-G, FERC required RTOs and ISOs to incorporate the NAESB developed standards 

into their demand response evaluation, measurement and verification tariffs. Commenters stated 

as a result, RTOs and ISOs have developed sophisticated demand response EM&V protocols 

incorporating NAESB standards that are used to pay demand response providers for load 

reductions and other purposes.

Comment 46: Comments urging the EPA to use the approach used for energy efficiency of 

allowing states (and multi-states) to include an unlimited set of demand response measures in 

their implementation plans.

Response 46: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines and the state plan.
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Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. This guidance will include recommended approaches 

and protocols for various types of EE programs. All EE/RE used to adjust an emissions rate must 

address the criteria established in the final emissions guidelines. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated in short, demand response has established EM&V protocols that are even 

more robust than the EM&V protocols that have been used for energy efficiency. Therefore, 

commenters urged EPA to use the approach used for energy efficiency of allowing states (and 

multi-states) to include an unlimited set of demand response measures in their implementation 

plans subject to the energy savings being documented by rigorous EM&V methods and 

appropriate state regulatory oversight. 

Comment 47: Comments suggesting the EPA promote regional collaboration to develop EM&V 

methods and encourage standardization or consistency of EM&V.

Response 47: The EPA encourages states to collaborate and share EM&V best practices. 

Regarding the appropriateness of building off existing state efforts on EM&V, the EPA’s 

proposed EM&V criteria would leverage the industry-standard practices, protocols, and data-sets 

currently utilized by the majority of states currently implementing demand-side EE and RE 

programs. The EPA further noted that many state regulatory bodies and other entities already 

have significant EM&V infrastructure in place and have been applying, refining and enhancing 

their evaluation and associated quality assurance approaches for over 30 years. The EPA took 

comment on whether this infrastructure is appropriate to use as the basis for establishing 

minimum EM&V criteria for use in rate-based state plans that include RE and demand-side EE. 

The majority of commenters addressing this question indicated that existing EM&V 

infrastructure is appropriate to assure quality, credibility, and integrity. Thus, the final EM&V 

criteria reflected in section IV.D.8 of the preamble to the proposed Federal Plan herein are 

intended to be consistent with and leverage prevailing industry-standard evaluation practices.

The following are summaries of the specific public comments under this comment.

Commenters recommended the EPA encourage regional collaboration on EM&V, so that more 

states use similar analytic methods, assumptions, and data sources, and states can share the 

burden of developing resource-intensive inputs. Commenters suggested states conduct joint 

research on key savings assumptions parameters where such data is especially needed. 

Commenters believed that this type of collaboration would be beneficial because it would help 

states to leverage research funds across states and also lead to greater consistency. Commenters 

also mentioned several examples of collaborative efforts between states, including the NW 

Regional Technical Forum (covering 4 states in the northwest), the Regional EM&V Forum 

(covering 9 states in the Northeast/Mid-Atlantic regions), and the newly formed California 

Technical Forum (Cal TF), which in part models the NW RTF, and coordinates with the 

Northwest. 
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Commenters submitted comments about whether there are additional incentives that should be 

included in the Final Rule. (22 Proposed Rule at 34,899.) Whether states seek to adopt a regional 

or state-specific approach to their overall compliance obligations under the Final Rule, there are 

certain intermediate steps where coordination across a region can provide significant benefit. 

One such area is compliance measurement and verification for compliance options such as 

energy efficiency in particular. Commenters were not suggesting that a single compliance 

measurement or enforcement or other protocols should be required in the Final Rule but the 

Administrator should consider providing appropriate incentives for states to reach such regional 

agreements even if just in the area of compliance measurement and verification for specific 

building blocks so that there is an apples-to- apples comparison of reductions to achieve ratebased or mass-based targets across states. Commenters continued that standardization or 

consistency of compliance measurement and verification and enforcement are prime examples of 

areas where regional approaches can meet state needs but also provide multi-state EGUs with a 

manageable means for compliance, explaining that regional approaches to these elements can 

also help avoid the potential for perverse incentives that could lead to strategic behavior 

(gaming) regarding compliance and have detrimental market and reliability consequences that 

may otherwise occur should individual compliance measurement protocols be different in 

different states. Commenters offered the example of two states, one with a stringent, and the 

other with a lax energy efficiency protocol. The state with the stringent protocol may be forced 

to rely on greater amounts of gas re-dispatch relative to the state with the lax protocols. 

Commenters said this has an obvious market distortion impact and could lead to deployment of 

energy efficiency resources in a manner which is not necessarily cost-effective or as beneficial in 

reducing CO2 emissions, and moreover, in the absence of a regime where emissions 

rates/reductions could be exchanged across state lines, changing power flows could result in 

NERC transmission criteria violations, an undesirable reliability outcome. Commenters said that 

in the case of a regime where emissions reductions or rates could be exchanged across state lines, 

EGUs could buy credits from the state with lax protocols thereby finding a compliance loophole 

which could also change power flows in ways never envisioned resulting in transmission 

reliability issues. For this reason, Commenters posited the following potential incentives that 

should be set forth in the Final Rule which should make clear that EPA itself will undertake a 

greater degree of deference and light-handed regulation of compliance measurement and 

verification protocols against a state that is submitting these on a regional basis. Commenters 

added that a regional approach to compliance measurement and verification (preferably one that 

coincides with the dispatch of EGUs across the region) can work to avoid entities pressure on 

other states or unintended reliability outcomes such protocols between states as the entire region, 

rather than a single state, would also face a risk of non-compliance, and this degree of selfenforcement in a region is exactly the type of deferential oversight that EPA should adapt as 

states are challenged to meet the complex requirements. 

Comment 48: Comments stating that the EPA needs to provide clarification on EM&V methods 

to use for compliance need to provide clarification and the ability to incorporate codes and 

standards.

Response 48: The EPA’s approach allows for a mix of different EM&V protocols for different 

energy efficiency measures. The EPA’s guidance document lays out program-specific EM&V 
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criteria. The EPA’s approach also allows for emerging EM&V methods to be used. The EPA’s 

guidance document will also be updated over time to reflect evolving approaches to EE and 

EM&V, innovation, market changes, and practical experience gained during the compliance 

period.

Building codes and standards can be incorporated into state plans; additional implementing 

EM&V guidance will be provided in the draft guidance that will be released with the proposed 

Federal Plan.

The following are summaries of the specific public comments under this comment:

Commenters requested that the EPA provide clarification on EM&V methods and the ability to 

incorporate codes and standards in the final guidelines for how to credit CO2 emissions 

reductions for compliance. Commenters requested that the clarification cover unit retirements, 

fuel switching, new gas-fired generation, heat rate improvement projects, added renewable 

generation, and increased energy efficiency.

Commenters requested that the EPA provide clarification that green building codes and standards 

may be included in state emission reduction plans because they can help increase demand-side 

energy efficiency, protect the environment, and catalyze economic growth. Commenters also 

requested that EPA publish a list of pre-approved measures for state plans that includes green 

building codes and standards.

Commenters gave an example of a fuel-switching program in the residential sector where the 

home switches from electricity to natural gas. Commenters stated if the fuel-switching isn't 

accompanied by EE measures, like air sealing and insulation, the opportunity to achieve potential 

savings through the upgrade will be lost, and carbon emitted from the natural gas heater will not 

be accounted for. The commenters recommended that EPA proved guidance to states to include 

residential energy savings programs in their implementation plans to encourage best-practices to 

ensure all carbon is accounted for when switching to natural gas, propane, or other fuels, from 

electric energy.

5.3.7 Options: EPA review of EM&V plans as part of the state plan review process

This section addresses comments related to the EPA review and approval of EM&V plans.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments that EM&V protocols should be left to the discretion of the states.

Response 1: The EPA’s proposed approach establishes an "EM&V floor" that all states must 

achieve to ensure a minimum level of credibility. The EM&V floor needs to be sufficiently 

stringent to serve as the basis for generating EE/RE credits and supporting a functioning trading 
395

market. As part of these minimum EM&V requirements, EM&V for EE and RE projects must be 

conducted by independent third parties. For states opting for a mass-based target, EM&V is not 

required for EE and RE programs. Regarding the frequency of verifications, the EPA’s draft 

EM&V guidance suggests that program impacts are determined for each year based on periodic 

verification of activity levels, and impact evaluations every three years to update values. The 

draft guidance also suggests that impact evaluations for larger projects in the EE portfolio can be 

updated annually. If deemed savings are used, the EPA’s proposed approach recommends the 

technical reference manual for these approaches be reviewed and updated at least once every 

three years.

The following are summaries of the specific public comments under this comment:

Commenters urged that EM&V protocols should be left to the discretion of the states.

Commenters recommended that third party verification not be required for energy efficiency 

programs, because third party programs are cost prohibitive and are unnecessary because the 

state or affected utility will be required to demonstrate compliance using one of numerous 

existing mechanisms that reflect best practices in designing energy efficiency programs and their 

accompanying EM&V protocols. Commenters advocated third party verification for all energy 

efficiency measures, and (to limit burden on utilities) require verification only every 3 years.

Comment 2: Comments suggesting that the EPA provide a standardized reporting template for 

states to use.

Response 2: The EPA’s draft EM&V guidance document is providing a standardized reporting 

template for states to use.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should develop a standardized reporting template for annual 

reporting of energy efficiency savings to streamline the EPA report review process.

Comment 3: Comments suggesting that EPA offer to review and comment on state EM&V 

plans prior to submission.

Response 3: The EPA will work closely with states on EM&V plans upon request.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should offer to review and comment on state EM&V plans prior to 

submission to provide greater assurance that the plans will be accepted.

Comment 4: Comments suggesting that the EPA will need sufficient resources to 

review EM&V plans and the periodic reports of reported savings in a streamlined manner.
396

Response 4: As part of a balanced approach to EM&V, the EPA has only proposed EM&V 

criteria and submittal requirements that the EPA is realistically positioned to review.

The following are summaries of the specific public comments under this comment:

Commenters stated that to effectively implement Building Block #4, EPA will need sufficient 

resources to review EM&V plans in a streamlined manner and to review the reported savings by 

states.

Comment 6: Comments suggesting that the EPA allow each state to establish its own protocols.

Response 6: One of the primary objectives for the EPA’s proposed EM&V criteria is to avoid 

excessive interference with EM&V practices that are already robust, transparent and working 

well. Therefore, the minimum criteria for EM&V in an approvable state plan establishes a floor 

for EM&V practices to ensure credibility and certainty in savings estimates across jurisdictions. 

The EPA agrees that as long as EE and RE providers meet the minimum criteria presented in the 

preamble and rule, they will be given flexibility to tailor their EM&V plan to the circumstances 

of their state.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA should allow each state to establish its own protocols. 

Commenters believed the rigorous evaluation, measurement, and verification (EM&V) practices 

established and implemented in partnership with state commissions may need only minor 

modifications to meet EPA's guidelines. Commenters further recommended the EPA to take a 

flexible approach to EM&V and allow each state, especially those with established EM&V 

protocols, to tailor a plan that meets the needs of their unique stakeholders with the least 

disruption to existing policies and procedures. Commenters suggested the EPA rely on the 

experience of the states to determine whether EM&V protocols are acceptable. 

Comment 7: Comments stating that the proposed rule sets forth no firm criteria for evaluating 

EE programs and EM&V plans, and for determining whether they comport with section 111(d).

Response 7: EM&V criteria are proposed in the preamble to the proposed Federal Plan in 

section IV.D.8.Additional implementing EM&V guidance will be provided in the draft guidance 

that will be released with the final rule. All EE/RE used to adjust an emissions rate must address 

the requirements established in the final emissions guidelines.

The following are summaries of the specific public comments under this comment:

Commenters stated under the proposed rule, states would be required to submit an EM&V plan 

that would "specify the analytic methods, assumptions, and data sources that the state will 

employ during the state plan performance periods to determine the energy savings and energy 

generation related to [renewable energy] and demand-side [energy efficiency] measures" and 
397

that this plan would be subject to EPA approval. The EPA states that it "intends to develop 

guidance for [EM&V] of renewable energy and demand-side energy efficiency programs and 

measures incorporated in state plans." Commenters stated the proposed rule itself, however, sets 

forth no firm criteria for evaluating EE programs and EM&V plans and for determining whether 

they comport with section 111(d).

Comment 8: Comment stating that the EPA has not yet provided sufficient support for how it 

will ensure rigorous assessment of state EE programs and EM&V plans.

Response 8: EM&V requirements are proposed in the preamble to the Federal Plan. Additional 

implementing EM&V guidance will be provided in the draft guidance that will be released with 

the Federal Plan. All EE/RE used to adjust an emissions rate must address the criteria established 

in the final emissions guidelines. The EPA welcomes stakeholder input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA's State Plan Considerations Technical Support Document ("TSD") 

provides some discussion of the range of potential EM&V plan types and potential EPA approval 

criteria. Commenters stated however, EPA has not yet provided sufficient support for how it will 

ensure rigorous assessment of state EE programs and EM&V plans; for example, EPA takes the 

position that any EM&V plan must consider the level of certainty in evaluating expected EE 

savings but also must balance the degree of certainty against investments of time and money 

needed to obtain such certainty. Commenters stated in any final rule, and in approving any state 

section 111(d) plan, EPA must ensure that claimed EE savings are reliably demonstrated and 

verified on the basis of consistent methodology. In other words, the degree of certainty required 

is not a negotiable commodity; it must exist at a level of rigor and support that allows for its 

approval.

Comment 9: Comments stating that the EPA should provide guidance identifying specific, 

consistent approval criteria based on sound technical support to ensure that all EE programs and 

measures included in a state plan are proven to a required level of certainty.

Response 9: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines and the state plan. Additional 

implementing EM&V guidance will be provided in the draft guidance that will be released with 

the proposed Federal Plan. All EE/RE used to adjust an emissions rate must address the criteria 

established in the final emissions guidelines. The EPA welcomes stakeholder input on the draft 

guidance.
398

The following are summaries of the specific public comments under this comment:

Commenters noted the EPA also states, both in the proposed rule and the TSD, that it intends to 

allow wide flexibility in selection of EE measures but that measures for which EM&V standards 

and procedures are not as well developed may require additional documentation. Commenters 

stated EPA should provide guidance identifying specific, consistent approval criteria based on 

sound technical support to ensure that all EE programs and measures included in a state plan are 

proven to a required level of certainty. Commenters stated if the ability to evaluate some types of 

EE measures is insufficiently established, such measures may not be used as a basis for a state's 

section 111(d) compliance or approved as part of its state plan. Commenters stated moreover, 

without specific guidance on EM&V, it is impossible to evaluate EPA's finding that all states can 

reach annual EE levels of 1.5 percent of in-state sales. Commenters stated at a minimum, EPA 

will need to evaluate this level of potential savings against robust EM&V guidance before 

finalizing the rule as proposed. 

Comment 10: Comments questioning the planned approach for quantification and verification of 

emissions reductions from EE.

Response 10: One of the EPA’s overarching EM&V objectives is the importance of striking a 

reasonable balance between EM&V rigor and credibility on the one hand, and the costs 

associated with project performance evaluation on the other. Another objective for the EPA’s 

criteria is to avoid excessive interference with EM&V practices that are already robust, 

transparent and working well. Therefore, the minimum criteria for EM&V in an approvable state 

plan establish a floor for EM&V practices to ensure credibility and certainty in savings estimates 

across jurisdictions.

The following are summaries of the specific public comments under this comment:

Commenters questioned the planned approach for quantification and verification of emissions 

reductions from EE, and questioned what the respective roles of EPA and the states are in 

determining the scope of efficiency measures that may be included for credit in a section 111(d) 

plan or compliance demonstration. 

Comment 11: Comments stating that the final rule should clarify details on how building block 

4 will be implemented.

Response 11: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines and the state plan. One of the 

EPA’s overarching objectives for EM&V is the importance of striking a reasonable balance 

between EM&V rigor and credibility on the one hand, and the costs associated with project 

performance evaluation on the other. Another objective for the EPA’s criteria is to avoid 
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excessive interference with EM&V practices that are already robust, transparent and working 

well. Therefore, the minimum criteria for EM&V in an approvable state plan establish a floor for 

EM&V practices to ensure credibility and certainty in savings estimates across jurisdictions.

The following are summaries of the specific public comments under this comment:

Commenters stated that an important question facing states is how best to measure and verify 

energy savings if states choose to incorporate EE into their state plans. Commenters stated 

current methods of efficiency EM&V often lack the rigor necessary to meet existing EPA SIP 

guidance on enforceability. Commenters stated the final rule should clarify details on how 

building block 4 will be implemented; in particular, it should include good but reasonable 

procedures for evaluating and documenting EE savings. Commenters stated the proposed rule 

attempts to approach building block 4 in several different ways, attempting to provide flexibility. 

Commenters stated however well-intentioned, it appears that the EM&V requirements for a onestate-only plan may not be achievable with the current level of resources available. 

Comment 12: Comments stating that Section 111(d) should include EE requirements rigorous 

enough to ensure that reductions in electricity use and the resulting emissions reductions are real 

and verifiable.

Response 12 The EPA’s overarching EM&V objectives include the importance of striking a 

reasonable balance between EM&V rigor and credibility on the one hand, and the costs 

associated with project performance evaluation on the other. Another objective for the EPA’s 

criteria is to avoid excessive interference with EM&V practices that are already robust, 

transparent and working well. Therefore, the minimum criteria for EM&V in an approvable state 

plan establish a floor for EM&V practices to ensure credibility and certainty in savings estimates 

across jurisdictions. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the final rule. All EE/RE used to adjust an emissions rate must address the criteria 

established in the final emissions guidelines. The EPA welcomes stakeholder input on the draft 

guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated Section 111(d) should include EE requirements rigorous enough to ensure 

that reductions in electricity use and the resulting emissions reductions are real and verifiable. 

Commenters stated that technology and methodology exists to quantify savings. Commenters 

stated however, without strong language from the EPA, accurate measurement and verification 

of these savings across the grid will likely not be a reality.

Comment 13: Comments suggesting that each state or region should develop EM&V protocols 

that follow best known and acceptable practices.
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Response 13: The EPA’s proposed approach recognizes states will have individual 

circumstances and provides flexibility when choosing EM&V methods. The EPA’s proposed

approach also allows for a mix of different EM&V protocols for different energy efficiency 

measures. The EPA’s guidance document lays out program-specific EM&V criteria. The EPA’s 

proposed approach also allows for emerging EM&V methods to be used. The EPA’s guidance 

document will also be updated over time to reflect evolving approaches to EE and EM&V, 

innovation, market changes, and practical experience gained during the compliance period.

The EPA’s overarching EM&V objectives include the importance of striking a reasonable 

balance between EM&V rigor and credibility on the one hand, and the costs associated with 

project performance evaluation on the other. Another objective for the EPA’s criteria is to avoid 

excessive interference with EM&V practices that are already robust, transparent and working 

well. Therefore, the minimum criteria for EM&V in an approvable state plan establish a floor for 

EM&V practices to ensure credibility and certainty in savings estimates across jurisdictions. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with proposed Federal Plan. All EE/RE used to adjust an emissions rate must address 

the criteria established in the final emissions guidelines. The EPA welcomes stakeholder input on 

the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated there should not be national uniformity in EM& V practices and protocols for 

purposes of demonstrating EE savings in state compliance plans. Commenters stated practices 

should be normalized where possible, and each state or region should develop EM&V protocols 

for measures that follow best known and acceptable practices. For those states and regions such 

as the Northwest, California, or the Regional Greenhouse Gas Initiative (RGGI) states, where EE 

practices are more mature, commenters stated EPA should be careful not to create barriers to 

development of advanced measurement technologies. Commenters further stated that for those 

states that have not had substantial practice verifying EE savings, EPA should offer technical 

assistance in program development. Commenters stated that subsequent to the final Clean Power 

Plan next year, the EPA should begin a process to develop best practices for EM&V, which those 

states can use as a tool to develop their own robust EM&V practices and protocols. 

Comment 14: Comments supporting the use of flexible protocols for EM&V.

Response 14: The EPA’s overarching EM&V objectives include the importance of striking a 

reasonable balance between EM&V rigor and credibility on the one hand, and the costs 

associated with project performance evaluation on the other. Another objective for the EPA’s 

criteria is to avoid excessive interference with EM&V practices that are already robust, 

transparent and working well. Therefore, the minimum criteria for EM&V in an approvable state 

plan establish a floor for EM&V practices to ensure credibility and certainty in savings estimates 

across jurisdictions. 
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Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the criteria established in the final emissions guidelines. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters supported the use of flexible protocols for Evaluation, Measurement & Verification 

(EM&V) and established or EPA-approved protocols that result in rapid review and approval of 

state plans. Commenters stated EPA must balance this flexibility with enough detail to offer the 

states a measure of certainty as states develop their plans. Furthermore, because the EIA is the 

most likely source of data for many of the requirements of the states, commenters stated the use 

of time differentiated data should only be a part of the guidelines to the extent that it is readily 

available from EIA. Commenters stated it is critical that the cost of EM&V in verifying EE 

savings not outweigh the EE savings achieved. 

Comment 15: Comments stating that new EPA EM&V protocols will be an impediment to EE 

programs, states already have EM&V standards for EE programs, and new EM&V requirements 

would be duplicative and increase the reporting burden unnecessarily.

Response 15: The EPA’s overarching EM&V objectives include the importance of striking a 

reasonable balance between EM&V rigor and credibility on the one hand, and the costs 

associated with project performance evaluation on the other. Another objective for the EPA’s 

criteria is to avoid excessive interference with EM&V practices that are already robust, 

transparent and working well. Therefore, the minimum criteria for EM&V in an approvable state 

plan establish a floor for EM&V practices to ensure credibility and certainty in savings estimates 

across jurisdictions. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the criteria established in the final emissions guidelines. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated new EPA EM&V protocols will be an impediment to EE programs. 

Commenters pointed out that States already have EM&V standards for EE programs. 

Commenters stated that new EM&V requirements would be duplicative and increase the 

reporting burden unnecessarily. Commenters stated EPA should support the implementation of 

EE measures by recognizing existing state EM&V protocols and providing states flexibility in 

creating new EM&V standards. 
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Comment 16: Comments stating that the EPA should allow a weight-of-evidence (WOE) 

approach for EE verification, and that a traditional EM&V approach would likely be a barrier to 

capturing a significant amount of EE beyond jurisdictional utilities.

Response 16: The EPA’s overarching EM&V objectives include the importance of striking a 

reasonable balance between EM&V rigor and credibility on the one hand, and the costs 

associated with project performance evaluation on the other. Another objective for the EPA’s 

criteria is to avoid excessive interference with EM&V practices that are already robust, 

transparent and working well. Therefore, the minimum criteria for EM&V in an approvable state 

plan establish a floor for EM&V practices to ensure credibility and certainty in savings estimates 

across jurisdictions. 

Additional implementing EM&V guidance will be provided in the draft guidance that will be 

released with the proposed Federal Plan. All EE/RE used to adjust an emissions rate must 

address the criteria established in the final emissions guidelines. The EPA welcomes stakeholder 

input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA should allow a weight-of-evidence (WOE) approach for EE 

verification. Commenters stated there are two issues that could potentially limit the amount of 

EE available to meet compliance with the Proposed Rule. Commenters stated the first is 

enforceability. Commenters stated entities not subject to section 111(d) will likely be resistant to 

accepting some form of EE requirement even with the understanding it would reduce energy 

bills. Commenters stated second, and related, EPA has indicated it would follow traditional 

EM&V, but this approach is largely applied to jurisdictional utilities in Indiana, and it generally 

is not applied or required for other EE programs (e.g., rural electric cooperatives, municipal 

electric, large industrial sources). Commenters stated these sources again would likely be 

resistant to accepting enforceable EM&V. Commenters stated a traditional EM&V approach 

would likely be a barrier to capturing a significant amount of EE beyond jurisdictional utilities.

Comment 17: Comments stating that non-compliance rates with energy codes are staggeringly 

high, the EPA needs to issue guidance on EM&V or the savings will not be realized, and urging 

the EPA to develop a set of best practices for EM&V and to provide assistance to states that do 

not have substantial experience in verifying energy savings.

Response 17: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines and the state plan. EE credit for 

building codes, appliance standards, and market transformations will be allowed under the EPA’s 

approach. All EE/RE used to adjust an emissions rate must address the criteria established in the 

final emissions guidelines. Additional implementing EM&V guidance will be provided in the 
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draft guidance that will be released with the proposed Federal Plan. The EPA welcomes 

stakeholder input on this guidance.

The following are summaries of the specific public comments under this comment:

Commenters encouraged EPA to issue clear guidance on EM&V for green building codes. 

Commenters stated that non-compliance rates with energy codes are staggeringly high, and EPA 

needs to issue guidance on EM&V or the savings will not be realized.

Regarding energy efficiency, commenters advocated that EPA should allow credit in a state 

compliance plan for energy savings from demand response measures, enforcement of building 

codes, federal and state appliance standards, market transformation, and other programs that are 

not administered by the regulated utility if a state can demonstrate a robust EM&V protocol.

Commenters urged that credit for building codes be allowed, and stated that the Northwest 

Power and Conservation Council has been studying the impacts of energy efficiency policies, 

including utility and third party energy efficiency programs, state building energy codes, and 

federal appliance standards across their member states, Idaho, Montana, Washington, and 

Oregon, for more than three decades. Commenters recommended that EPA work with states on 

savings measurement methodology for building codes, and work with the U.S. Department of 

Energy's Building Energy Codes Program, which is currently developing methodologies to 

advance building code compliance and savings verification. For energy savings measures that 

were adopted prior to the section 111(d) guidelines, commenters also stated that EPA should 

allow credit for the remaining life of the measure. Commenters urged EPA to develop a set of 

best practices for EM&V and to provide assistance to states that do not have substantial 

experience in verifying energy savings.

Comment 18: Comments urging the EPA to account for all consequences of energy efficiency 

measures.

Response 18: Renewable energy and demand-side EE and other non-BSER measures that are 

tied to a state plan and achieve quantified and verified MWh savings may be used to adjust a 

CO2 emission rate, provided they meet the general and specific eligibility requirements for 

resources used to adjust a CO2 emission rate, described in Section VIII.K.1.a.(2). of the 

preamble. The measures must also meet the eligibility requirements and provisions related to 

demand-side EE programs and projects, if applicable, and the provisions related to proper 

quantification and verification of MWhs from demand-side EE savings are described in section 

IV.D.8 of the preamble to the proposed Federal Plan.

The following are summaries of the specific public comments under this comment:

Commenters urged EPA to account for all consequences of energy efficiency measures.

Commenters pointed out that some energy efficiency measures will encourage more use of 

natural gas in homes and should account for the carbon emitted from natural gas combustion and 

energy loses from lack of air sealing and insulation. Commenters urged EPA is use the Resource 

Valued Framework by the Home Performance Coalition to evaluate home energy efficiency 
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measures to account for all of the benefits of energy efficiency and, therefore, encourage deeper 

energy savings opportunities.

Comment 19: Comment encouraging the EPA to explicitly allow states to use ESPCs to comply 

with the Clean Power Plan.

Response 19: The EPA position is that any demand-side EE program and project that results in 

MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in 

section VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines and the state plan. Additional 

implementing EM&V guidance will be provided in the draft guidance that will be released with 

the proposed Federal Plan. All EE/RE used to adjust an emissions rate must address the criteria 

established in the final emissions guidelines. The EPA welcomes stakeholder input on the draft 

guidance.

The following are summaries of the specific public comments under this comment:

Commenters pointed out that, under an ESPC contract, a private ESCO agrees to deliver and 

install energy-saving measures and equipment that are paid for with energy bill savings. 

Commenters said the performance of the energy conservation measures installed, as well as the 

energy savings, are contractually guaranteed by the ESCO and are measured and verified (M&V) 

using internationally recognized protocols such as the International Performance Measurement 

and Verification Protocol (IPMVP). Commenters stated that this rigorous M&V process ensures 

that these projects deliver quantifiable and verifiable energy savings, making ESPCs an ideal 

component of any state implementation plan. 

In terms of total impact, commenters stated that ESCO activities in 2012 resulted in 

approximately the same amount of energy efficiency investment as all utility-run programs ($6 

billion each), according to Bloomberg New Energy Finance's, "Sustainable Energy in America 

Factbook." Commenters encouraged EPA to explicitly allow states to use ESPCs to comply with 

the Clean Power Plan--not doing so would result in a sizeable, low-cost source of potential 

emissions reductions being left on the table. 

5.3.8 Options: general quality standards for EM&V rigor and accuracy

This section addresses comments regarding the quality standards needed for adequately verifying 

the credits from energy savings measures.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.
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Comment 1: Comments advocating creation of an energy efficiency registry to streamline the 

reporting and auditing of claimed energy savings and to avoid double counting.

Response 1: The EPA’s proposed approach requires an independent entity to maintain and 

certify an EE and RE registry with project level identification for each credit in order to provide 

assurance that there is no double counting of either the credits themselves or the projects that 

make up each credit. Clear and transparent attribution and ownership of each credit is also 

required, however, project level tracking is not required for building energy codes or product 

standards programs. The EPA’s draft EM&V guidance document provides more details on 

minimum requirements for an EE registry. The draft guidance document also discusses 

appropriate evaluator training for conducting EM&V.

The following are summaries of the specific public comments under this comment:

Several commenters supported the creation of an energy efficiency registry as a tool for state 

compliance with Section 111(d) obligations. Commenters stated that a flexible energy efficiency 

registry would provide a centralized, transparent vehicle for projecting, estimating, reporting, 

and auditing savings from energy efficiency measures. Commenters stated that a registry would 

allow states to demonstrate their compliance in a meaningful way, save costs, reduce burden on 

states, facilitate trading, ensure no double counting across programs, and would also enable and 

expand energy efficiency programs across the United States. Commenters stated that EPA should 

provide guidance on the minimum requirements for an energy efficiency registry.

Commenters provided 6 attachments showing how different aspects of building efficiency could 

be incorporated into the CPP.

Commenters stated that EPA should promote appropriate evaluator training and experience to 

ensure qualified professionals to conduct EM&V with required minimum levels of training and 

expertise. 

Comment 2: Comments that current EM&V protocols are not adequate because they do not 

incorporate randomized control trials or quasi-experimental methods to account for the 

behavioral aspects of EE programs.

Response 2: The EPA’s proposed approach sets a medium bar with respect to EM&V stringency 

and quality control which does not go as far as some of the most comprehensive state programs. 

This approach is used to encourage states to participate using their existing or new programs 

while still ensuring credible energy savings. Although the EPA’s proposed approach does 

provide states flexibility in their choice of EM&V methodologies, all EE savings must meet 

quantifiable and verifiable criteria through EM&V that is rigorous, credible, complete, and 

consistent with industry-standard practices.

The following are summaries of the specific public comments under this comment:
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Commenters stated that EM&V protocols for energy efficiency are often lacking in the rigor 

necessary to provide a clean and unbiased estimate of energy savings. Commenters stated all 

efficiency programs have a behavioral aspect to them that current approaches to evaluation tend 

not to address very well. Commenters stated that better EM&V methods must be developed that 

include randomized control trials or quasi-experimental methods. Commenters provided a 

number of published articles about EM&V for energy efficiency.

Comment 3: Comments that the EPA should provide guidance on the appropriate benefit/cost

test for EM&V programs.

Response 3: It is the EPA’s understanding that the benefit-cost tests are applied by state public 

utility commissions (PUCs) and other oversight bodies to ensure that customer funds used to pay 

for EE programs are prudently allocated. The EPA believes that this is a state matter and 

therefore does not address benefit-cost tests in the requirements for EM&V.

Renewable energy and demand-side EE and other non-BSER measures that are tied to a state 

plan and achieve quantified and verified MWh savings may be used to adjust a CO2 emission 

rate, provided they meet the general and specific eligibility requirements for resources used to 

adjust a CO2 emission rate, described in Section VIII.K.1.a.(2) of the preamble. The measures 

must also meet the eligibility requirements and provisions related to demand-side EE programs 

and projects, if applicable, and the provisions related to proper quantification and verification of 

MWhs from demand-side EE savings are described in section IV.D.8 of the preamble to the 

proposed Federal Plan.

Additional implementing EM&V guidance that includes recommended EM&V protocols to 

follow will be provided in the draft guidance that will be released with the proposed Federal 

Plan. All EE/RE used to adjust an emissions rate must address the criteria established in the final 

emissions guidelines. The EPA welcomes stakeholder input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA needs to provide guidance for the appropriate benefit/cost test 

of EE programs. Commenters noted that typical utility EE programs are cost-share programs 

between the participant and the utility, utility rebate covers a portion of the cost to implement a 

measure. Commenters stated that the Total Resource Cost (TRC) is the general test required by 

the Kentucky state utility commission. Commenters stated that the rebate amount in that test has 

no impact on whether a program or measure has more benefit than cost from the utilities 

perspective. Commenters noted that the utility can pay $1 or 100 percent of all cost and the TRC 

Benefit to Cost (B/C) ratio will not change. Commenters noted that the Utility Cost Test (UCT) 

or Ratepayer Impact Measure (RIM) does include the rebate amount in the B/C calculation. 

Commenters noted that over half of the counties that they serve are identified by the U.S. 

government as persistent poverty counties and nearly 40 percent of all of their customers are at 

or below the poverty level and simply cannot pay for their share of the costs. Commenters stated 

that in order for them to achieve 1 percent or a stretch goal of 1.5 percent, they would be 

required to pay nearly 100 percent of most measured cost. Commenters stated that it would result 

in most programs failing the UCT or RIM B/C which would cause commenters to fail to achieve 
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the EE savings goals. Commenters stated that the program might pass the TRC, but then EE 

could be more costly than building generation. 

Comment 4: Comments suggesting that unit-specific evaluation periods should be one year and 

progress should be reported annually.

Response 4: The EPA agrees with the commenter that evaluation periods should be one year and 

progress be reported annually, as discussed in Section VIII.K of the preamble. Additional 

implementing EM&V guidance will be provided in the draft guidance that will be released with 

the proposed Federal Plan. This guidance will discuss evaluation periods for state plans 

incorporating both rate-based and mass-based goals. The EPA welcomes stakeholder input on 

the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters opposed EPA allowing differing unit-specific evaluation periods for rate-based and 

mass-based state plans and supports a one year evaluation period for all affected EGUs and 

states. Commenters argued that accommodating the enforcement periods in existing state 

programs could undermine the enforceability of the CPP's state goals.

Commenters also stated that allowing some states to apply a three-year evaluation period to their 

affected sources, in tandem with the rule's requirement that affected EGUs report hourly CO2

emissions and net electric output for each evaluation period, would render unworkable the annual 

comparison of actual and projected performance under the plan. Commenters argued that the 

proposed rule did not explore the drawbacks of allowing less frequent comparison checks for 

some states, despite the significant value in maintaining a uniform approach with annual 

comparisons. Commenters stated the annual comparisons will provide a crucial opportunity for 

the Agency and public to assess the progress of all states in meeting their goals and staggering 

some of these checks would complicate ensuring the integrity of the reported results. Requiring a 

unit-specific evaluation period of one-year for all states may require changes to some existing 

state programs, but commenters supported these changes as necessary to generate a uniform set 

of performance data for assessing progress. For similar reasons, commenters supported annual 

reporting and notes that each element of the annual report described in proposed 40 CFR 60.5815 

is needed to present an accurate picture of state's progress.

Comment 5: Comments on the verification accuracy and cost.

Response 5: One of the EPA’s overarching objectives for EM&V is the importance of striking a 

reasonable balance between EM&V rigor and credibility on the one hand, and the costs 

associated with project performance evaluation on the other. Another objective for the EPA’s 

criteria is to avoid excessive interference with EM&V practices that are already robust, 

transparent and working well. Therefore, the minimum criteria for EM&V in an approvable state 

plan establish practices that ensure credibility and certainty in savings estimates across 
408

jurisdictions. Additional implementing EM&V guidance will be provided in the draft guidance 

that will be released with the proposed Federal Plan.

The following are summaries of the specific public comments under this comment:

Commenters indicated that states enjoy considerable flexibility in developing section 111(d) 

state plans and devising strategies for compliance with EPA emission guidelines and thus may 

rely on any combination of measures to achieve required emission reductions. Commenters 

stated however, while a state may claim emission reductions through demand-side EE programs 

or measures, EPA may not approve a state plan unless EE-related emission reductions claimed 

are both real and verifiable. Commenters stated moreover, states should recognize that the costs 

of many EE measures remain uncertain. 

Commenters stated the approval and implementation of any state plan lacking adequate criteria 

to ensure that emission reductions are real and verifiable would be contrary to both section 111 

and EPA's implementing regulations. Commenters stated under the statute, states are required to 

submit to EPA "satisfactory" state plan for compliance with performance standards. Commenters 

indicated a state plan that includes unverified EE measures would not meet this standard.

Commenters stated that without rigorous review of EE measures using consistent, clear, and 

measurable criteria, claimed emission reductions may not occur, or occur in the timeframe 

predicted. Commenters stated such a result undermines Congress's statutory intent that state 

plans be "satisfactory" and that BSER be adequately demonstrated, and would stand in stark 

contrast to the real, quantifiable emission reductions achievable through increased reliance on 

clean-burning natural gas resources. 

5.3.9 EM&V Documentation in a 111(d) state implementation plan

This section addresses comments on the level of documentation needed to incorporate EE as a 

compliance strategy in state plans and to justify actual energy savings that can be credited for 

compliance.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments on some specific components that should be required for an adequate 

state plan that incorporates EE as a compliance measure.

Response 1: The EPA’s proposed EM&V approach requires states in the state measures 

approach, and EE and RE providers under the rate-based emission trading approach, to address 

the following key considerations in their EM&V plans:

• How significant changes in independent variable conditions (weather, 

occupancy, production rates, etc.) that affect energy consumption and 

savings estimates will be analyzed.
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• How the initial installation of EE will be verified for EE program 

categories that involve the direct installation of measures.

• How avoided T&D systems losses can be included in EE savings values.

• How the duration of EE program or project electricity savings will be 

determined using annual verification assessments, industry-standard 

persistence studies, deemed estimates of effective useful life (EUL), or a 

combination of all three.

• How the rigor of MWh savings values will be determined, and the 

methods used to control the types of bias or error relevant inherent to the 

applied EM&V techniques.

• How double counting will be avoided through the use of tracking and 

accounting procedures to ensure that two or more programs do not 

separately claim savings from the same EE project or measure.

Regarding the stringency of EM&V requirements, the EPA’s approach provides flexibility to 

states when developing their EM&V plans. This flexibility will make it easier for states to 

incorporate their existing programs into their state plans, and design new programs that can be 

tailored to the needs of individual states. Additional implementing EM&V guidance will be 

provided in the draft guidance that will be released with the proposed Federal Plan.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should require that state plans explain, at a minimum, the following 

points: 

• The baseline against which states claim energy efficiency savings;

• How states are factoring the effects of their program on energy 

efficiency savings (e.g. how the state represents net versus gross savings 

and takes into account market trends on claimed and evaluated savings);

• How frequently the state will project and report savings (e.g. annually, 

biannually, and with or without true-ups). States should be required to 

conduct reporting according to a consistent timeline;

• An evaluation plan that reflects one of the industry best-practice EMV 

protocols referenced in U.S. EPA's draft regulations (or a different U.S. 

EPA-certified protocol of comparable robustness), including a 

framework for how the state will prioritize what type of evaluation is 

most useful and relevant for the types of programs the state includes in 

its plan;
410

• Data collection expectations (e.g. location, measure savings, customer 

type) during implementation to enable basic evaluation after execution;

• How states model and justify claimed energy efficiency savings, 

including the granularity at which the state is evaluating savings (e.g. 

program-level savings; activity-level savings, or measure-level savings).

Commenters stated that EPA's proposed requirement for EM&V plans for energy efficiency 

measures with a rate-based approach is more stringent than EPA SIP requirements for creditable 

reductions from energy efficiency measures; and will discourage the use of energy efficiency in 

the 111(d) plans. Commenters stated the EPA should have developed the guidance for the 

EM&V plans in time for the proposal of the emission guidelines so that states could comment on 

the specific details. Commenters were concerned that the EM&V plan guidance will not be 

available until so late in the process that it will result in either a needless waste of state resources 

or the inability to incorporate the energy efficiency measures due to timeline constraints.

Comment 2: Comments that the EPA should develop an EM&V plan template and 

recommended criteria or documented energy savings.

Response 2: Regarding the suggested criteria for inclusion in state plans, all of these criteria are 

a part of the EM&V plan template the EPA is providing in the EM&V guidance document. For a 

full list of recommended criteria to include in EM&V plans, see the draft EM&V guidance 

document. With the use of consistent terminology, the EPA’s approach and terminology are 

informed by sources such as the State Energy Efficiency (SEE) Action Network Program Impact 

Evaluation Guide. For more details on how the EPA uses particular EM&V terminology, see the 

glossary section of the draft EM&V guidance document. Regarding standardized reporting 

templates, the EPA is providing these in the draft EM&V guidance document. Regarding the 

proposal of a national EE registry, the EPA’s approach provides flexibility to the states on how 

to design their registries and therefore will not require states to submit to a national registry. To 

ensure the credibility of state registries for trading programs, the EPA provides recommended 

criteria in the draft EM&V guidance document.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should develop an EM&V Plan template with specific plan 

components to guide states on what needs to be in plans. Commenters stated EPA should 

designate DOE to be the lead agency in developing reporting templates. Commenters stated that 

Connecticut believes that the following components should be included in state plans: 

• Name of organization that will prepare evaluated energy savings reports.

• Relationship of organization preparing the report to the subject energy 

efficiency program and program administrators. 
411

• Schedule of when the reports will be prepared and time period they will 

cover.

• Name of the state or regional entity that will review and certify the 

evaluated savings.

• Manner in which evaluated energy savings reports will be made publicly 

available.

• Multi-year evaluation plan, with timing of evaluation efforts and 

processes including planning, implementation, reporting, and updating.

Commenters supported EPA's proposed criteria for documentation of energy savings: 

• Energy savings documentation should be provided at a level of detail 

that allows for recalculation of programs energy savings totals; and

• EM&V information in state plans should be provided in a consistent 

manner across states to allow for comparison, benchmarking, and more 

efficient review of plans by the public and the EPA. 

To achieve these criteria, commenters recommended that, as a minimum, EPA do the following: 

• EPA should ensure consistent use of EM&V terminology in its 

guidance, and refer to the State Energy Efficiency (SEE) Action 

Network Program Impact Evaluation Guide3 Glossary as a the source of 

definitions, and direct states to use this Glossary in development of their 

EM&V plans and reporting their EE savings.

• EPA should create a standardized EE reporting form that reports energy 

savings at the program level, using existing standardized EE savings 

reporting templates or platforms (e.g., Regional Energy Efficiency 

Database (REED), EIA's Form 861 Schedule D, Consortium for Energy 

Efficiency's Annual Industry Report, LBNL EE reporting database, etc.). 

In order to support EPA's ability to recalculate claimed energy savings,

EPA should consider a reporting construct similar to the Efficiency 

Power Plant planning tool developed by the Regulatory Assistance 

Project (RAP).

• EPA should develop a standardized form for states to identify the 

EM&V approaches or methods used to evaluate their programs, building 

on existing standardized EM&V reporting forms (e.g., the recently 

developed Standardized EM&V Methods Reporting Forms by NEEP 

and the on-line format developed by the Regional EM&V Forum).

• EPA should consider supporting the development of a national EE 

registry (e.g., The Climate Registry proposed EE Registry) to support 
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state documentation of energy savings, underlying EM&V methods used 

and level of rigor (e.g., confidence/precision level and treatment of 

systemic error), and associated avoided emissions, using standardized 

forms. Such a registry could also support the exchange of tradable 

efficiency credits across states and help avoid double-counting of energy 

efficiency credits.

Commenters stated EPA should explore, via the US DOE State Energy Efficiency Action 

Network (SEE Action) and/or a professional organization such as the International Energy 

Program Evaluation Conference (IEPEC), the use of certified evaluators by states to report 

energy savings to help ensure that qualified persons with appropriate training and experience 

were responsible for managing the state's EM&V activities set forth in their EM&V plan in 

accordance with EPA's requirements and guidance. Commenters stated that as an alternative (or 

supplement) to certification, EPA should support EM&V training to help states new to EM&V to 

identify and retain qualified practitioners.

Comment 3: Comments that EM&V should be based on actual data on building performance 

and real utility bills, and listing some protocols that now exist to directly obtain utility bill data 

for evaluating residential EE based on whole house performance.

Response 3: Regarding the development of standards and protocols to evaluate EE programs, the 

EPA’s proposed approach does not prescribe particular EM&V methods, but instead 

recommends existing industry standards for certain program types that lead to rigorous and 

credible EM&V results. As EM&V methodologies for certain EE program types mature, the 

EPA will update its guidance to states and ERC programs accordingly. If deemed savings are 

used, the EPA’s approach recommends the technical reference manual for these approaches be 

reviewed and updated at least once every three years.

Regarding guidance to states and ERC programs, the EPA is providing a draft EM&V guidance 

document to states and ERC programs that describes the process and technical criteria for 

meeting the requirements for conducting EM&V of energy impacts (MWh) resulting from 

demand-side EE and RE generation programs implemented in support of state plans. The EPA’s 

proposed approach recognizes states will have individual circumstances and provides flexibility 

when choosing EM&V methods. The EPA’s proposed approach also allows for a mix of 

different EM&V protocols for different energy efficiency measures. The EPA’s guidance 

document lays out program-specific EM&V criteria. The EPA’s approach also allows for 

emerging EM&V methods to be used.

The following are summaries of the specific public comments under this comment:

Commenters stated that section 111(d) requires that plans generate reliable, verifiable and 

enforceable greenhouse gas reductions. Commenters stated that energy efficiency efforts can 

meet these requirements, and in many cases at lower cost than other options. Because energy 

efficiency programs and policies may vary significantly, commenters suggested that the EPA 

should invite multiple approaches to achieving quantifiable and reliable reductions, while 
413

encouraging a move away from deemed savings estimates to savings based on actual building 

performance and real utility bills. Commenters stated that the EPA should work with states to 

develop clear paths to evaluate and approve 111(d) plans, as well as clear and transparent 

reporting protocols to determine whether carbon reductions are occurring as planned. 

Commenters recommended that EPA work with DOE to provide guidance to states/regions/tribes 

to provide commonsense policies and protocols to allow for data transfer while addressing 

privacy and security concerns. Commenters stated that this approach would help create a 

transparent system to calculate and quantify energy savings so that utilities, investors, building 

owners, and contractors can all be accountable to actual results. 

Commenters stated that the EPA should support the integration of national energy efficiency data 

standards and savings prediction calculation standards into existing and new EM&V protocols 

and encourage reporting procedures that 1) use standardized data collection methods and data 

transfer protocols to aid in aggregating actual energy savings results from energy efficiency 

activities; 2) use actual utility bill data to provide the ability to compare apples-to-apples when 

estimating improvements and assessing results, and 3) that simplify the ability to report results to 

regulatory, legislative and consumer stakeholders in a meaningful way. Commenters stated that 

examples of such standards specifically for residential energy efficiency include: 

• BPI-2100: Standard for Home Performance-Related Data Collection

• BPI-2200: Standard for Home Performance-Related Data Transfer and

• ANSI/BPI-2400-S-2012 Standard Practice for Standardized 

Qualification of Whole-House Energy Savings Predictions by 

Calibration to Energy Use History (The Delta Standard)

Commenters stated that a large state-regulated program sponsor recently tested the application of 

these standards to real whole house program data resulted in the program predictions meeting 

actual savings at a rate of 90%. Commenters noted that while these standards have gained 

consensus they are yet to be incorporated into the state-level Technical Resource Manuals that 

guide the implementation of energy efficiency programs by regulated utilities. Commenters 

suggested that states need to be encouraged to adopt emerging EM&V approaches that can 

demonstrate improvements in the quality and accuracy of savings whole house predictions. 

Commenters stated that a system of accountability can be established by leveraging existing 

tools, such as the BPI Data Standards and DOE's Standard Energy Efficiency Database (SEED). 

Commenters stated that a move to real and verifiable savings, with data to support the results, is 

absolutely critical with the prediction tools available to assist states/regions/tribes in planning 

their initiatives. Commenters noted that also in use for residential purposes, DOE's Home Energy 

Score provides consistent, low-cost energy efficiency assessments and carbon savings estimates 

that can be validated by actual energy savings, and support installation of energy efficiency 

measures by home owners, as well as supporting appropriate valuation of energy efficient homes 

in the real estate market.
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Comment 4: Comments that suggest to encourage EE, the EPA should publish a list of 

approvable EM&V protocols for Energy Savings Performance Contracts.

Response 4: The EPA’s draft EM&V guidance published with the proposed Federal Plan

provides links to and information about specific protocols for performance contracts and other 

EE strategies. The use of protocols is also addressed in Section VIII.K of the preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA can assist states by identifying approvable approaches for key 

compliance criteria that will facilitate inclusion of Energy Savings Performance Contract (ESPC) 

project-related emission reductions. Commenters stated that the EPA, possibly in consultation 

with DOE, should identify acceptable EM&V protocols (e.g., IPMVP, FEMP M&V Protocol, 

etc.) for use on EE projects and create a process for accepting additional protocols and methods. 

In regard to auditing, commenters stated that the EPA, possibly in consultation with DOE, 

should describe model approaches for audits to ensure EM&V is properly employed. For projectlevel audits, commenters stated that the EPA should encourage states to identify types and 

formats for project data subject to audit to maximize ease and consistency of project audits. 

Commenters stated that the EPA should also suggest an appropriate approach for frequency and 

sample size of audits to ensure a balance of rigor with costs. For program-level auditing, 

commenters stated that the EPA should advise states on obligations to audit data collection and 

aggregation processes.

Comment 5: Comments suggesting that industrial customers are often unwilling to make their 

EE investments public because they consider energy usage information to be competitively 

sensitive information.

Response 5: The state measures approach allows for a statewide entity to be responsible for the 

management of EE programs. While states will interact directly with EPA to submit state plans 

and progress reports, the EPA is providing flexibility for states to decide how to best manage 

their EE programs. Under the rate-based emission trading approach, individual project providers 

will be responsible for managing EE/RE projects and programs, and submitting EM&V 

documentation to state trading programs for verification. For more information regarding the 

eligibility requirements for demand-side EE see Section VIII.K.1.a.(3). For more information 

about rate-based emission trading approach and the issuance of ERCs for demand-side EE 

measures, see Section VIII.2.

The following are summaries of the specific public comments under this comment:

Commenters stated industrial customers are often unwilling to make their energy efficiency 

investments public, because they consider their energy usage information to be competitive 

secrets. Commenters explained that " e Project Builder" (ePB) is a PC project savings 

calculation and database system that has been commissioned by the US Federal Energy 

Management Program (FEMP) and has been built and will be hosted and maintained by the 
415

Lawrence Berkeley National Laboratory (LBNL). Commenters stated that ePB is the successor 

to an ESCO Project Database of more than 5,000 projects that LBNL built and has hosted for the 

past 15 years and that ePB is ready for immediate use. Commenters added that several leading 

national EE organizations have been working with The Climate Registry on a plan for a registry 

to be used for CPP compliance that is described in a white paper available at the following URL: 

http://www.theclimateregistry.org. Commenters suggested that this registry might be developed 

for use with projects other than PC, such as non-ratepayer residential EE programs or industrial 

EE. 

5.3.10 CHP/cogeneration

This section provides comments on quantification, monitoring, and verification of CHP and 

cogeneration programs and measures.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments that the EPA should clarify whether or not generation from new or 

uprated non-affected CHP units must meet an EM&V requirement, and if so it should be 

accomplished using revenue-quality electric meters.

Response 1: The EM&V requirements for CHP are addressed in the draft guidance document 

and section IV.D.8 of the preamble to the proposed Federal Plan.

The following are summaries of the specific public comments under this comment:

Commenters asked EPA to clarify whether or not generation from new or uprated non-affected 

CHP units must meet an EM&V requirement, and if so it should be accomplished using revenuequality electric meters. Commenters also advocated that CO2 emitted from non-affected CHP 

units should not be included in the determination of the emission reductions credited to those 

units. But if the final rule requires this CO2 to be accounted for, commenters stated the rule 

should not require CEMS on these non-affected units.

Commenters stated that regardless of the amount of credit provided for thermal output, each 

EGU should be allowed to select the measurement technologies that best suit its needs under the 

circumstances, and to determine the best QA measures. Commenters stated certain technologies 

(like ultrasonic flowmeters and coriolis meters) typically are not used for steam measurements 

due to the high temperature applications and costs, and it would not be appropriate for EPA to 

attempt to impose their use. Commenters stated that although some manufacturer's may claim 

that their more complex and costly equipment provides greater accuracy than the widely used 

differential pressure type flow meters, those benefits often are not realized when the meters are 

used in real world plant applications. Commenters stated different types of meters, instruments, 

and calculation methods also provide varying levels of accuracy depending on the steam 

conditions, which can vary from source to source (e.g., some steam is supplied at conditions that 
416

are barely superheated or barely at the saturation temperature). Moreover, commenters stated

some equipment simply would not benefit from any periodic QA. Commenters stated that for 

example, thermocouples and resistance temperature detectors either work or fail completely.

Commenters added that because removing such sensors for calibration may be difficult, and even 

dangerous in high pressure processes, there is no benefit to removing them until they fail and 

have to be replaced.

Commenters also stated that manufacturers' recommendations also are not universally 

appropriate for ongoing maintenance or QA, and are not appropriate for use in rules because they 

vary from vendor to vendor and can change over time. Moreover, commenters stated the industry 

cannot comment on the reasonableness of requirements, procedures, or specifications that are not 

included in the proposed rule. Commenters also stated that ASME Performance Test Codes are 

not appropriate for ongoing QA because they were designed for performance testing, not long 

term performance. Although most flow meters probably would meet the ASME measurement of 

fluid flow in closed conduits ("MFC") standards generally, commenters stated they do not 

believe that EPA has justified imposition of such standards for this rule, and any requirement for 

their use would have to refer simply to the standard series as a whole in order to cover the entire 

range of flow meter types and conditions at existing plants.

Comment 2: Comments that the EPA should provide guidance on EM&V for CHP systems.

Response 2: The EPA’s proposed criteria for EM&V for CHP systems are discussed in section 

IV.D.8 of the preamble to the proposed Federal Plan.

The following are summaries of the specific public comments under this comment:

Commenters recommended that the EPA provide guidance on evaluation, monitoring and 

verification (EM&V) programs for CHP systems, but cautioned that such guidance should not 

preclude use of valid methodologies already in use in some states.

Commenters added that, because states may choose to adopt state-based or mass-based 

approaches to comply with the Clean Power Plan, EPA guidance will be necessary and helpful to 

states navigating the many options for compliance.

5.3.11 Other

This section addresses any other comments on EM&V for EE programs.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.
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Comment 1: Comments stating that the EPA should acknowledge and support state program 

competency in energy program design and delivery.

Response 1: One of EPA’s overarching objectives for EM&V criteria is to avoid excessive 

interference with EM&V practices that are already robust, transparent and working well at the 

state level. Therefore, the minimum criteria for EM&V in an approvable state plan establish a 

floor for EM&V practices to ensure credibility and certainty in savings estimates across 

jurisdictions. Additional implementing EM&V guidance will be provided in the draft guidance 

that will be released with the final rule.

All EE/RE used to adjust an emissions rate must address the criteria established in the final 

emissions guidelines. The EPA position is that any demand-side EE program and project that 

results in MWh savings is potentially eligible, provided that it meets the criteria for eligibility 

described in section VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, 

complete and consistent with the criteria provided in the emission guidelines and the proposed 

Federal Plan.

The following are summaries of the specific public comments under this comment:

Commenters stated the EPA should acknowledge and support state program competency in 

energy program design and delivery. Commenters noted that state EE program experience, 

energy savings goals, and structures have varied based on state circumstances. Commenters 

stated the EPA should therefore recognize:

• Historical emissions reductions: the EPA should allow states to 

recognize verifiable past emissions reductions from existing EE 

programs to the extent that EE program measures continue to provide 

quantifiable emissions reductions.

• Future emissions reductions: the EPA should allow states to recognize 

future emissions reductions from verifiable EE programs and activities 

that were initiated after the promulgation of the final rule. The EPA 

should allow states to take credit for all new activities, programs and 

installations utilizing EM&V protocols and approaches as noted in their 

comments. 

Comment 2: Comments concerning the use of existing conditions as a baseline.

Response 2: Based on public input and assessments of current practice, the EPA has determined 

that "common practice baselines" (CPB) should be used as the basis for determining savings. A 

CPB is the system or measure a typical consumer or building owner would have continued with 

or installed at the time of the project implementation, in the absence of a decision to pursue EE. 

More details regarding the CPB will be provided in the guidance document. 

The following are summaries of the specific public comments under this comment:
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Commenters discussed how to account for EE savings. Commenters stated that to encourage 

simple measurement and ensure that there are not large disparities in reported CO2 reductions 

and savings across states, energy savings should be calculated using existing conditions as the 

measurement baseline, rather than a counterfactual condition (one that may be subject to multiple 

interpretations due to baseline data and its availability). Commenters stated that using existing 

conditions to measure energy savings appropriately provides more benefit to those areas or 

technologies where the installed equipment is least efficient. Commenters noted that this is 

consistent with the CO2 reduction goals of the Proposed Rule. Commenters stated that in 

addition, while some states currently expend considerable resources to create counterfactual 

baselines, others do not. Commenters stated that a form of existing baseline is already used to 

measure EE savings in several areas including the Northeast EE Partnership, Colorado, Maine, 

New Jersey, and Michigan. Commenters stated that utilizing existing conditions to establish 

baselines will provide more consistency in implementation of the Proposed Rule across states.

Comment 3: Comments suggesting that the rule allow credit for natural gas conservation 

programs.

Response 3: The EPA recognizes the benefits of EE programs targeting the direct use of natural 

gas. However, the EPA’s approach only includes EE savings from demand side efficiency 

programs that target electricity consumption.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA's proposed regulation does not consider natural gas conservation 

programs. Commenters noted that many utilities around the country have made significant 

investments in natural gas efficiency. Commenters stated that natural gas efficiency programs are 

pertinent because methane emissions are also tied to natural gas combustion. Commenters 

recommended the EPA provide flexibility to modify the energy-efficiency programs proposed to 

comply with the Clean Power Plan over time because utilities modify current programs with state 

energy efficiency regulated cycles to account for changes in the market and available technology.

Comment 4: Comments urging the EPA, when developing the final EM&V standards, to 

encourage the use emerging software technologies that can accurately determine energy savings 

in real time.

Response 4: Thank you for pointing out the EE savings measurement software. The EPA’s 

proposed approach allows for energy modeling software to be incorporated in state EM&V plans 

as long as the software uses methods that are rigorous, credible, and consistent with industrystandard practices.

The following are summaries of the specific public comments under this comment:

Commenters urged EPA, when developing the final EM&V standards, to encourage the use 

emerging software technologies that can accurately determine energy savings in real time.
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Commenters were promoting the use of Optix Quantify, a specific software product by their 

company, Energy Savvy. Commenters stated the software creates a model that estimates energy 

usage based on an analysis of pre-project energy usage patterns at premises, and then the model 

compares actual measured energy use to modeled energy use to estimate energy savings from the 

energy efficiency measures. Commenters stated that the advantages of using the Optix model 

are:

• Better accuracy of EM&V that many current protocols.

• Speed of EM&V is much faster that after the fact evaluations.

• Transparency of the estimates.

• Consistency across similar users.

• Reduced cost of EM&V.

• Real-time feedback to the users can help increase actual energy savings 

achieved by energy efficiency programs by identifying shortfalls 

immediately.

• Integrates the measurement of effects across multiple energy efficiency 

measures.

Comment 5: Comments recommending national EM&V standards for home EE programs, and 

advocating a national registry.

Response 5: The EPA has decided not to develop a national EM&V standard and national 

registry. One of the EPA’s overarching EM&V objectives includes avoiding excessive 

interference with EM&V practices that are already robust, transparent and working well. 

Therefore, the minimum criteria for EM&V in an approvable state plan establish a floor for 

EM&V practices to ensure credibility and certainty in savings estimates across jurisdictions.

The following are summaries of the specific public comments under this comment:

Commenters recommended national EM&V standards for home energy efficiency programs, and 

advocated that a national registry is the most effective way to standardize EM&V methodologies, 

reduce the burden on states, and encourage participation by the private sector. Commenters 

encouraged EPA to review the registry program for energy efficiency recommended by The 

Climate Registry. Commenters stated that EM&V for energy efficiency measures was too 

arduous and expensive for programs other than those managed by regulated utilities. Non-utility 

providers would resist the same level of EM&V required of utilities, and it would be difficult to 

enforce because these entities are not regulated by the PUC.
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Comment 6: Comments supporting EE measures and stating the EPA should adopt two tiers of 

EE evaluation, measurement, and verification procedures to enable a wide range of efficiency 

measures. 

Response 6: The EPA’s proposed approach does not divide EE measures into tiers. The EPA 

position is that any demand-side EE program and project that results in MWh savings is 

potentially eligible, provided that it meets the criteria for eligibility described in section 

VIII.K.1.a.(2) of the preamble, and that supporting EM&V is rigorous, complete and consistent 

with the criteria provided in the emission guidelines and the state plan. Additional implementing 

EM&V guidance will be provided in the draft guidance that will be released with the proposed 

Federal Plan. All EE/RE used to adjust an emissions rate must address the criteria established in 

the final emissions guidelines. The EPA welcomes stakeholder input on the draft guidance.

The following are summaries of the specific public comments under this comment:

Commenters supported EE measures and stated EPA should adopt two tiers of EE evaluation, 

measurement, and verification procedures to enable a wide range of efficiency measures. 

Commenters stated EPA should adopt two tiers of energy efficiency EM&V procedures to 

enable a wide range of efficiency measures. Commenters stated EPA should not adopt a 

specified list of EE measures; rather adopt a specified standard for EM&V and a correlated level 

of certainty a state must provide in compliance plans. Commenters supported EPA's proposal to 

"not limit the types of demand-side EE measures and programs that can be included in a state 

plan." To enable this commenters recommended the EPA allow a tiered approach where the rigor 

of the EM&V is balanced by a range of uncertainty in the estimated impact of the EE program of 

activity. By adopting a specified list, commenters stated EPA could foreclose the development of 

innovative EE measures and programs.

Comment 7: Comments proposing a methodology to model the benefits of ER programs that is 

designed to capture only energy savings and GHG reductions that are directly induced by 

rebates.

Response 7: For all EM&V submittals addressing demand-side EE, the applicable metric is 

electricity savings, which is defined as a reduction in electricity consumption. EE savings must 

be determined and reported in units of gross MWh, except in cases where gross savings values 

are not available (e.g., randomized control trials). In these instances, net savings can be reported.

Based on public input and assessments of current practice, the EPA has determined that 

"common practice baselines" (CPB) should be used as the basis for determining savings. A CPB 

is the system or measure a typical consumer or building owner would have continued with or 

installed at the time of the project implementation, in the absence of a decision to pursue EE.
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EM&V plans must describe the baselines to be used with clear documentation and discussion of 

the rationale, applicability, and relevant data sources, protocols, and guidance documents used 

for defining the CPB.

The following are summaries of the specific public comments under this comment:

Commenters noted that their methodology to model the benefits of ER programs is designed to 

capture only energy savings and GHG reductions that are directly induced by rebates and to 

exclude "business as usual" savings that would occur because of normal product turnover in the 

marketplace. Thus, commenters said "free riders" who would purchase a new product with or 

without the rebate are not counted. As explained in the appendix to their comments, commenters 

made this calculation by expanding the methodology used by DOE in its Uniform Methods 

Project (UMP) protocol for determining free ridership in rebate-driven refrigerator recycling 

programs and taking into account several studies of free ridership in state rebate programs. 

Comment 8: Comments stating that claimed emission reductions should not be counted unless 

and until verified. 

Response 8: The agency agrees with the commenters and is finalizing that emission reductions 

must be evaluated, measured, and verified.

The following are summaries of the specific public comments under this comment:

Commenters stated that claimed emission reductions should not be counted unless and until 

verified. 

5.4 QUANTIFICATION, MONITORING, AND VERIFICATION FOR RENEWABLE 

ENERGY PROGRAMS AND MEASURES

This section addresses comments on methods for quantifying, monitoring, and verifying 

renewable energy program measures. We have organized the comments in this section under 8 

different subsections 5.4.1 to 5.4.8. Responses to the comment topics of these subsections are 

discussed below along with summaries to the specific comments.

5.4.1 Renewable portfolio standards: build renewable generating facilities

This section discusses the concerns with installing DG facilities, and also installation of newer 

technology DG installations.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.
422

Comment 1: Comments suggesting that distributed generation (DG) installations are situational 

and requirements for them should be developed at the local distribution system level rather than 

being set using a national rule.

Response 1: In section V of the preamble of the final rule the EPA addresses how the rule 

establishes emission guidelines, and the BSER is the central determination that the EPA must 

make in doing so. After identifying the BSER, the EPA determines the performance levels –- in 

this case, the CO2 emission performance rates.

In section VIII.C on state plan approaches, EPA clarifies that states may adopt and submit either 

of two different types of state plans. The first would apply all requirements for meeting the 

emission guidelines to affected EGUs in the form of federally enforceable emission standards, 

which we refer to as an "emission standards" state plan type. The second, which we refer to as a 

"state measures" plan type, would allow the state mass CO2 emission goals to be achieved by 

affected EGUs in part, or entirely, through state measures that apply to affected EGUs, other 

entities, or some combination thereof, such as a RPS. These two types of state plans and their 

respective approaches allow states to meet the statutory requirements of CAA section 111(d) 

while accommodating the wide range of regulatory requirements and other programs that states 

have deployed or will deploy in the electricity sector that reduce CO2 emissions from affected 

EGUs.

Under the emission standards state plan type, one approach is a rate-based emission standard for 

affected EGUs, which may include use of emission trading and ERCs. The EPA anticipates the 

use of emission trading in state plans, due to the advantages of this approach.

The EPA addresses considerations for the use of the BSER and non-BSER measures to achieve

an emission rate-based standard in section V.A.5 and V.A.6 of the preamble to the final rule. For 

RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either 

acquire ERCs through common ownership of RE generating capacity, a bilateral transaction with 

the owner/operator of the RE generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized market.

The following are summaries of the specific public comments under this comment:

Commenters agreed that the EPA's projection regarding additional renewable that can be added 

to the electric system to decrease future utilization of fossil-fuel generation is more workable, 

cost-efficient, realistic and practical than the alternative of subtracting from baseline generation 

raised in the NODA. However, commenters disagreed with the many of the assumptions 

embodied in EPA's method. Specifically, commenters contended that each utility has a unique 

situation that must be assessed before determining to what degree renewable energy can be 

deployed. Commenters contended that DG installations are inherently situational and need to be 

molded at the local distribution system level. Commenters explained that locally owned and 

controlled utilities know how to facilitate new, more efficient, and cleaner ways of meeting 

customer demand. Commenters stated that EPA’s proposal oversteps community-based 

initiatives in favor of a brute force modeling approach. Commenters contended that EPA should
423

recognize that utilities (and states) are in the best position to optimize the integration of 

renewable DG and maximize the flow of benefits to all customers and resulting increased costs. 

Commenters stated that forcing rapid development of renewable generating resources will result 

in a sub-optimal power cost curve for consumers. Commenters added that many attributes of a 

DG installation affect the ability of those systems to reduce integration costs or turn them into 

grid benefits and cost savings, such as location, size, and dispatchability. Commenters then 

added that to achieve maximum benefit from DG, coordinated deployment is critical. 

Commenters contended that EPA did not asses how building block 3 could create additional 

issues and costs for consumers, or how states can make optimal environmental dispatch decisions 

that properly reflect cost and power quality concerns.

Comment 2: Comments supporting the use of advance pumped storage hydro as a technology 

that could provide non-carbon based reserves.

Response 2: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. Section K.1.a

addresses how emission reduction measures that provide substitute generation for affected EGUs 

or avoid the need for generation from affected EGUs are counted in rate-based state plans. 

It specifically clarifies the treatment of energy storage in Section VIII.k.1.a.(5). Energy storage is 

not directly recognized as an eligible measure that can be used to adjust a CO2 emission rate, 

because storage does not directly substitute for electric generation from the grid or avoid 

electricity use from the grid. The electric generation that is input to an energy storage unit may 

be used to adjust a CO2 emission rate, but the output from the energy storage unit may not. 

However, the final rule acknowledges the value of energy storage as an enabling measure that 

facilitates greater use of RE, which can be used to adjust a CO2 emission rate.

The following are summaries of the specific public comments under this comment:

Commenters stated that as the U.S. shifts to a system dominated by renewable sources, there is 

an increasing need for strategically located large capacity plants that can provide short term

reserve and address unscheduled changes in output (reliability) and control (regulation) 

frequency and voltage. Commenters supported using advanced pumped storage hydro (ASPSH) 

as a technology that could provide non-carbon based reserves because its mature and tested and 

can be constructed today. Commenters stated that an executive order was issued to federal 

agencies directing them to in a collaborative effort that identifies possible locations for pumped 

storage plants within or adjacent to national parks or similar areas where the federal government 

has authority to fast track licensing and environmental approvals.

Comment 3: Comments suggesting to credit utilities when distributed generation is incentivized.

Response 3: EPA did not prescribed specific approaches or RE measures like incentivizing 

distributed generation (DG). In section VIII.C on state plan approaches, EPA clarifies that the 

types of state plans which states may adopt and submit allow states to meet the statutory 
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requirements of CAA section 111(d) while accommodating the wide range of regulatory 

requirements and other programs that states have deployed or will deploy in the electricity sector 

that reduce CO2 emissions from affected EGUs.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. For more information about specific RE 

measures to adjust the CO2 emission rate of an affected EGU to reflect RE, including eligibility 

dates and the types of RE MWhs that are eligible, see Section VIII.K.1. For EM&V requirements 

relevant to RE resources, see section VIII.K.3. Requirements for rate-based emission trading 

programs and the issuance and tracking of ERCs, including qualifying RE measures, programs or 

projects and addressing the potential for interactions between ERCs and RECs, are addressed in 

section VIII.K.2.

The following are summaries of the specific public comments under this comment:

Commenters recommended that a utility should not receive credit simply for having distributed 

generation interconnected with its system. Commenters contended that it is essential that the 

utility have offered some kind of incentive. Commenters stated that extensive experience in 

states has shown that distributed solar is most likely to be installed where net metering is 

available, and that special fees on net metering customers or failure to roll credits over from 

month to month stifle DG development. Commenters added that feed-in or value of solar tariffs 

that are less than the retail rate, or that fail to offer sufficient long-term price guarantees do not 

incentivize DG. Commenters concluded that DG installed under these circumstances should not 

be credited to the utility. Commenters noted that a new model being proposed in some states is 

for the utility to directly own and install distributed generation at its customers’ locations. 

Commenters stated that since the utility owns the system, it would clearly be able to use that 

systems output for compliance purposes. Commenters also noted the high upfront capital costs 

associated with distributed generation lend themselves to investment by third parties, including 

compliance entities. Commenters supported offering rebates for a substantial portion of the 

installation cost of a rooftop solar system should be an approved compliance measure, especially 

for EGUs that are not part of a vertically integrated utility.

Comment 4: Requiring reliable quantification and verification of distributed generation without 

requiring revenue-grade metering.

Response 4: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. The commenters will 

find the EPA has clarified which actions count and when such actions count generally in section 

VIII.K.1.for RE resources used to adjust a CO2 rate.

Evaluation, measurement, and verification (EM&V) requirements for RE are specifically 

addressed in section VIII.K.3. This section of EPA’s final emission guidelines require that all RE 

providers demonstrate that they will quantify and verify MWh using best-practice EM&V 

approaches. One way to make this demonstration is to use the presumptively approvable EM&V 

approaches specified in the proposed Model Rule in section IV.D.8. States may also submit other 
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means of meeting the EM&V requirements so long as the state satisfactorily demonstrates in the 

state plan submittal that such alternative means of addressing requirements are as stringent as the 

presumptively approvable approach.

States may leverage the programs and infrastructure they have in place for achievement of their 

RPS and take advantage of registries in place for the issuance and tracking of RECs. Many 

existing REC tracking systems already include well-established safeguards, documentation 

requirements, and procedures for registry operations that could be adapted to serve similar 

functions in relation to the final emission guidelines. With respect to actual monitoring 

requirements, many existing REC registries include provisions for the monitoring of MWh of 

generation that would be appropriate to meet state plan requirements pursuant to the final rule, 

such as requirements to use a revenue quality meter.

The following are summaries of the specific public comments under this comment:

Commenters urged EPA to include in the final rule specific requirements for reliably quantifying 

and verifying distributed generation without a requirement for revenue-grade metering. 

Commenters explained that unlike utility scale generation, or larger distributed generation 

systems installed based on PURPA or feed-in tariffs, distributed generation units do not typically 

have revenue-grade metering but rely on inverter readings of generation instead. Commenters 

added that in many cases it would be prohibitively expensive to retrofit installed DG systems 

with revenue-grade metering, or require those meters on all future installed systems, given their 

small size. Commenters added that not all REC tracking systems permit distributed generation 

systems that lack revenue-grade metering to register as REC generators. Commenters supported 

allowing a utility to use those RECs towards compliance if a DG system meets the requirements 

to register its RECs, and those requirements meet EPAs standards for data quality. Commenters 

suggested that alternative measurement and verification for DG systems should be used only 

where revenue grade metering is absent or RECs cannot otherwise be registered. 

Commenters noted that capacity-based estimates can provide a solid basis for quantifying DG 

system output, but noted that these estimates should take into account the size, orientation and 

vintage of the system, as newer systems are slightly more efficient. Commenters stated that if 

EPA allows the use of capacity-based estimates, it must require rigorous verification of those 

estimates with spot metering at a statistically-valid sampling of sites. Commenters added that 

EPA should also state whether the utility or other entity seeking credit for DG can validate 

capacity-based estimates using sophisticated software resources that report to owners and utility 

whether they are getting the expected generation from their systems or whether the system is 

experiencing a malfunction or needs maintenance. Commenters also stated that EPA should offer 

guidance on these and other methods for verifying capacity-based estimates of distributed 

generation, but must impose some kind of additional validation measures. Commenters 

concluded that when the generation of a distributed system is considered, the utility or other 

entity claiming credit should account for the fact that DG avoids line losses due to its proximity 

to load, and this should be factored in when determining the effective generation levels of these 

systems.
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5.4.2 Renewable portfolio standards: bilateral contract model

This section discusses long-term contracting and renewable energy power purchase agreements.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments supporting long-term contracting by utilities.

Response 1: EPA did not prescribed specific approaches like long-term contracting by utilities 

for RE. In section VIII.C on state plan approaches, EPA clarifies that the types of state plans 

which states may adopt and submit allow states to meet the statutory requirements of CAA 

section 111(d) while accommodating the wide range of regulatory requirements and other 

programs that states have deployed or will deploy in the electricity sector that reduce CO2

emissions from affected EGUs.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. The commenters will find the EPA has 

clarified which actions count and when such actions count generally in section VIII.K.1. and 

more specifically in section VIII.K.3 on EM&V requirements for RE resources used to adjust a 

CO2 rate. Requirements for rate-based emission trading programs and the issuance and tracking 

of ERCs, including qualifying RE measures, programs or projects and addressing the potential 

for interactions between ERCs and RECs, are addressed in section VIII.K.2.

The following are summaries of the specific public comments under this comment:

Commenters encouraged EPA to support long-term contracting by utilities. Commenters stated 

that long-term power purchase agreements (PPAs), generally for 10 to 30 years, can help create 

market security sought by project developers and their financiers. Commenters stated that 

renewable portfolio standard implementation experience shows that programs have been the 

most successful when developers have been able to secure long-term contracts with creditworthy counter-parties. Commenters stated that long-term contracting provides a major step in 

financial certainty and once that is in place, the next areas of risk then shift to consideration of 

project development and operational risk. Commenters stated that in particular, interconnection 

risk and transparency in operations have simple solutions when paired with long-term 

contracting policy solutions. Commenters explained that with regard to interconnection risk, 

mitigation in the form of a guaranteed interconnection if the PPA meets the standardized 

requirements of the long-term contracting program would be helpful. Commenters added that 

with respect to transparency in operations, making the contract price known and certain, making 

the contract duration follow the long-term financing (10-20 years), and operating a procurement 

system that is clear and easy to participate in (preferably a first-come, first-serve approach) are 

means to help the renewable developer achieve certainty in interconnection and operation, 

thereby reducing risk.
427

Comment 2: Commenters supported the EPA affirming state plans can count renewable energy 

power purchase agreements as a compliance element in the CPP.

Response 2: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. The commenters will 

find the EPA has clarified which actions count and when such actions count generally in section 

VIII.K.1 and more specifically in section VIII.K.3 on EM&V requirements for RE resources 

used to adjust a CO2 rate. Requirements for rate-based emission trading programs and the 

issuance and tracking of ERCs, including qualifying RE measures, programs or projects and 

addressing the potential for interactions between ERCs and RECs, are addressed in section 

VIII.K.2.

In section VIII.C on state plan approaches, EPA clarifies that states may adopt and submit either 

of two different types of state plans. The first would apply all requirements for meeting the 

emission guidelines to affected EGUs in the form of federally enforceable emission standards, 

which we refer to as an "emission standards" state plan type. The second, which we refer to as a 

"state measures" plan type, would allow the state mass CO2 emission goals to be achieved by 

affected EGUs in part, or entirely, through state measures that apply to affected EGUs, other 

entities, or some combination thereof, such as a RPS.

These two types of state plans and their respective approaches allow states to meet the statutory 

requirements of CAA section 111(d) while accommodating the wide range of regulatory 

requirements and other programs that states have deployed or will deploy in the electricity sector 

that reduce CO2 emissions from affected EGUs. 

Under the emission standards state plan type, one approach is a rate-based emission standard for 

affected EGUs, which may include use of emission trading and ERCs. The EPA anticipates the 

use of emission trading in state plans, due to the advantages of this approach. The EPA addresses 

considerations for the use of the BSER and non-BSER measures to achieve an emission ratebased standard in section V.A.5 and V.A.6 of the preamble to the final rule. For RE measures, 

section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either acquire ERCs 

through common ownership of RE generating capacity, a bilateral transaction with the 

owner/operator of the RE generating capacity (e.g., RE PPAs), or a transaction for ERCs through 

an intermediary, which could, but need not, involve an organized market.

The following are summaries of the specific public comments under this comment:

Commenters stated that because their utility, Platte River, is a not-for-profit public power utility, 

tax credits are not directly available to Platte River to offset costs of zero emission resources 

such as wind and solar. Commenters added that to take advantage of tax credits, Platte River 

enters into power purchase agreements (PPA) for the life of renewable resources developed by 

taxable entities, and these PPAs are an alternative to direct ownership, but provide the same 

benefit of promoting the expansion of zero emission resources. Commenters supported the CPP 

affirming that state plans can count renewable energy PPAs as a compliance element.
428

5.4.3 Renewable portfolio standards: REC model

This section discusses use of existing REC tracking systems, other approaches for accounting for 

RECs other than tracking systems, the types of RECs that can be used for the CPP, data that 

should be recorded in REC tracking systems, issues with overlapping CPP and state REC 

requirements, expiration/retirement of RECs, REC ownership and retirement ramifications, 

verification measures for existing REC tracking systems, establishing renewable energy carbon 

attributes, application of tax incentives associated with RECs, methodologies to calculate 

avoided emissions, and incorporating emission reductions from voluntary renewable energy 

programs.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments supporting allowing states to have multiple options in complying with 

the CPP.

Response 1: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. The commenters will 

find the EPA has clarified which actions count and when such actions count generally in section 

VIII.K.1 and more specifically in section VIII.K.3 on EM&V requirements for RE resources 

used to adjust a CO2 rate. Requirements for rate-based emission trading programs and the 

issuance and tracking of ERCs, including qualifying RE measures, programs or projects and 

addressing the potential for interactions between ERCs and RECs, are addressed in section 

VIII.K.2.

In section VIII.C on state plan approaches, EPA clarifies that states may adopt and submit either 

of two different types of state plans. The first would apply all requirements for meeting the 

emission guidelines to affected EGUs in the form of federally enforceable emission standards, 

which we refer to as an "emission standards" state plan type. The second, which we refer to as a 

"state measures" plan type, would allow the state mass CO2 emission goals to be achieved by 

affected EGUs in part, or entirely, through state measures that apply to affected EGUs, other 

entities, or some combination thereof, such as a RPS. These two types of state plans and their 

respective approaches allow states to meet the statutory requirements of CAA section 111(d) 

while accommodating the wide range of regulatory requirements and other programs that states 

have deployed or will deploy in the electricity sector that reduce CO2 emissions from affected 

EGUs. Under the emission standards state plan type, one approach is a rate-based emission 

standard for affected EGUs, which may include use of emission trading and ERCs. The EPA 

anticipates the use of emission trading in state plans, due to the advantages of this approach.

The following are summaries of the specific public comments under this comment:

Commenters supported allowing states with multiple options for emission reduction strategies 

and for capturing the benefits of state renewable energy programs, including RPS and voluntary 

standards.
429

Comment 2: Comments supporting the use of existing REC tracking systems for the CPP.

Response 2: In section VIII.C on state plan approaches, EPA clarifies that states may adopt and 

submit either of two different types of state plans. The first would apply all requirements for 

meeting the emission guidelines to affected EGUs in the form of federally enforceable emission 

standards, which we refer to as an "emission standards" state plan type. The second, which we 

refer to as a "state measures" plan type, would allow the state mass CO2 emission goals to be 

achieved by affected EGUs in part, or entirely, through state measures that apply to affected 

EGUs, other entities, or some combination thereof, such as a RPS. These two types of state plans 

and their respective approaches allow states to meet the statutory requirements of CAA section 

111(d) while accommodating the wide range of regulatory requirements and other programs that 

states have deployed or will deploy in the electricity sector that reduce CO2 emissions from 

affected EGUs. 

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. Evaluation, measurement, and 

verification (EM&V) requirements for RE, including tracking systems, are specifically addressed 

in section VIII.K.3.

In VIII.K.3.b in the preamble to the final rule, the EPA addresses requirements for EM&V and 

M&V submittals for energy generating resources, including RE resources. States may leverage 

the programs and infrastructure they have in place for achievement of their RPS and take 

advantage of registries in place for the issuance and tracking of RECs. Many existing REC 

tracking systems already include well-established safeguards, documentation requirements, and 

procedures for registry operations that could be adapted to serve similar functions in relation to 

the final emission guidelines. 

The state measures approach allows for a statewide entity to be responsible for the management 

of RE programs. While states will interact directly with EPA to submit state plans and progress 

reports, the EPA is providing flexibility for states to decide how to best manage their RE 

programs. Under the rate-based emission trading approach, individual project providers will be 

responsible for managing RE projects and programs, and submitting EM&V documentation to 

state trading programs for verification.

For more information on EM&V provisions, see section IV.D.8 of the preamble to the proposed 

Federal Plan and the draft EM&V guidance document.

The EPA addresses considerations for the use of the BSER and non-BSER measures to achieve 

an emission rate-based standard in section V.A.5 and V.A.6 of the preamble to the final rule. For 

RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either 

acquire ERCs through common ownership of RE generating capacity, a bilateral transaction with 

the owner/operator of the RE generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized market.
430

Requirements for rate-based emission trading programs and the issuance and tracking of ERCs, 

including qualifying RE measures, programs or projects and addressing the potential for 

interactions between ERCs and RECs, are addressed in section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

The following are summaries of the specific public comments under this comment:

Several commenters supported using existing REC tracking and accounting systems for the CPP. 

Some commenters stated that existing tracking systems are in use, widespread, and ensure each 

REC is only counted once and provided examples of existing tracking systems. Some 

commenters added that EPA only needs to build on these concepts to provide a unified system 

for tracking and trading between states. Commenters also added that not using existing tracking 

systems has the potential to create uncertainty and confusion for status quo RPS compliance. 

Commenters stated that creating new reporting systems for 111(d) could cause confusion in the 

marketplace. Commenters added that existing tracking systems are already set up to track 

compliance with existing state RES laws and verify claims for emission reductions and other 

attributes of RECs that are purchased through voluntary markets.

Commenters supported tracking systems as long as the credit for the energy resides with the 

REC owner. Commenters added that the REC holder is in the best position to determine which 

state should receive credit for incentivizing renewable energy production. Commenters cautioned 

against arguments about current REC pricing compared to the often relatively large size of other 

investments in RE in an effort to persuade EPA to assign avoided emissions from RE to the 

largest investor, regardless of whether or not they also own the RECs. Commenters stated that 

REC prices vary tremendously across the country based on regional market dynamics. 

Commenters stated EPA should make its determination about RECs as the tracking mechanism 

for avoided emissions from RE under 111(d) irrespective of current REC prices.

Commenters suggested existing REC tracking systems could be expanded to include new 

renewable that may not qualify under existing RPS state laws but do under the CPP. Commenters 

stated that through use of the REC system, EPA can ensure that when a REC is retired the same 

entity that retires the REC gets the carbon reduction credit or the state that bought the REC and 

retires it gets the credit. Commenters stated that RECs for 111(d) compliance should not be 

tracked separately from voluntary and other RECs that are not used for 111(d) compliance 

because this could increase the risk of double counting and decrease transparency.

Comment 3: Comments supporting the use of existing multi-state REC tracking systems.
431

Response 3: In section VIII.C on state plan approaches, EPA clarifies that states may adopt and 

submit either of two different types of state plans. The first would apply all requirements for 

meeting the emission guidelines to affected EGUs in the form of federally enforceable emission 

standards, which we refer to as an "emission standards" state plan type. The second, which we 

refer to as a "state measures" plan type, would allow the state mass CO2 emission goals to be 

achieved by affected EGUs in part, or entirely, through state measures that apply to affected 

EGUs, other entities, or some combination thereof, such as a RPS. These two types of state plans 

and their respective approaches allow states to meet the statutory requirements of CAA section 

111(d) while accommodating the wide range of regulatory requirements and other programs that 

states have deployed or will deploy in the electricity sector that reduce CO2 emissions from 

affected EGUs.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. Evaluation, measurement, and 

verification (EM&V) requirements for RE, including tracking systems, are specifically addressed 

in section VIII.K.3.

In VIII.K.3.b in the preamble to the final rule, the EPA addresses requirements for EM&V and 

M&V submittals for energy generating resources, including RE resources. States may leverage 

the programs and infrastructure they have in place for achievement of their RPS and take 

advantage of registries in place for the issuance and tracking of RECs. Many existing REC 

tracking systems already include well-established safeguards, documentation requirements, and 

procedures for registry operations that could be adapted to serve similar functions in relation to 

the final emission guidelines. 

The state measures approach allows for a statewide entity to be responsible for the management 

of RE programs. While states will interact directly with EPA to submit state plans and progress 

reports, the EPA is providing flexibility for states to decide how to best manage their RE 

programs. Under the rate-based emission trading approach, individual project providers will be 

responsible for managing RE projects and programs, and submitting EM&V documentation to 

state trading programs for verification.

For more information on EM&V provisions, see section IV.D.8 of the preamble to the proposed 

Federal Plan and the draft EM&V guidance document. The EPA addresses considerations for the 

use of the BSER and non-BSER measures to achieve an emission rate-based standard in section 

V.A.5 and V.A.6 of the preamble to the final rule. For RE measures, section V.A.5.a(3) specifies 

that an owner/operator of an affected EGU can either acquire ERCs through common ownership 

of RE generating capacity, a bilateral transaction with the owner/operator of the RE generating 

capacity, or a transaction for ERCs through an intermediary, which could, but need not, involve 

an organized market.

Requirements for rate-based emission trading programs and the issuance and tracking of ERCs, 

including qualifying RE measures, programs or projects and addressing the potential for 

interactions between ERCs and RECs, are addressed in section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 
432

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

The following are summaries of the specific public comments under this comment:

Several commenters supported using existing multi-state tracking systems to track RECs. 

Commenters asserted that requiring states to track and retire RECs for claimed RE generation, 

whether in-state or out-of-state, would help ensure that multiple states do not claim credit for the 

same unit(s) of RE generation. Commenters added that a REC tracking approach should be 

applied uniformly to all states regardless of whether they use a rate-based or mass-based 

approach. Commenters added that tracking systems could readily be adapted to keep track of 

certificates that may need to be monitored as part of a state's [Section] 111(d) clean power plan 

even though the certificates do not count toward the RPS (because the power comes from a 

generator whose technology is not eligible for that RPS or was built before a State's RPS became 

effective).

Commenters recommended EPA recognize multi-state tracking systems such as the Western 

Renewable Energy Generation Information System (WREGIS) and codify that renewable energy 

tracked using renewable energy credits (RECs) under an RPS program is credited to the state 

receiving the RECs unless a multi-state modular agreement is in place. Commenters contended 

that EPA must to use RECs like that provided by the Midwest Renewable Energy Tracking 

System (M-RETS) to track and account for renewable generation. Commenters described the MRETS system and how RECs work. Commenters concluded that EPA must be clear in its final 

rulemaking how a state like Minnesota could rely upon RECs tracked in M-RETS, and whether 

any additional information or changes to the system would be required for Clean Power Plan 

compliance purposes. Commenters added that systems, like M-RETS, are structured in a way 

that allows it to adapt to changes in policies and stakeholder needs. Commenters noted that 

changes are frequently made to M-RETS functionality as a result of alterations in state renewable

energy policies and could also be made to accommodate the needs of states for 111(d) 

compliance. Commenters concluded that RECs may not need to be managed any differently for 

111(d) than they are currently set up for state RPS programs. Commenters added that the systems 

are flexible, were developed with the help of stakeholder input, and are familiar to generators 

and utilities. Commenters added that using existing systems will ensure uniform standards for 

proper accounting of RECs and increase the potential for cost-effective compliance and emission 

reduction under the Clean Power Plan. Commenters concluded that including renewable 

resources as part of the Clean Power Plan without relying on the existing framework or tracking 

systems and protocols will result in confusion and wasted time and money. Commenters 

provided details on the inventorying and tracking of attributes in the New England Power Pool 

Generation Information System (NEPOOL GIS). Commenters indicated that within this system, 

qualifying generators can transfer their RECs to load serving entities that are acquiring RECs in 

order to comply with the RPS. Commenters added that the system has the ability to allow for the 

transfer of RECs to be used in another region for RPS compliance, by allowing the associated 

power to be exported to other regions so that the REC is available for compliance. Commenters 
433

also stated that the NEPOOL GIS and PJMGATS systems in the Northeastern U.S. are set-up to 

track all generation sources to support power source disclosure programs and to track CO2

emissions, other pollutants, and other power attributes, and these all generation tracking systems 

are also designed to match the emissions and other attributes of electricity supply with demand 

within a region and for imports into a region, which could also help facilitate compliance with 

state implementation plans. Commenters recommended that EPA should further reach out to 

technical professionals and stakeholders with extensive experience in using the nation's key REC 

tracking systems to ensure harmonization between EPA's compliance approaches and these 

systems. Commenters specified that the final rules should ensure that the key system in place in 

the West (WREGIS) is fully compatible with the final rule and supporting technical guidance (a 

more likely source of potential incompatibility). Commenters added that EPA should endeavor to 

ensure that any reporting or tracking systems EPA develops are able to directly import data from 

WREGIS data systems to maximize consistency and minimize administrative burden for state 

agencies.

Commenters contended that although established, the REC markets are still relatively small 

compared to other commodities, and any federal rules should not detract from the limited 

liquidity in the REC markets. Commenters recommended that the states that built the tracking 

systems collaborate to develop and implement the changes for compliance with the proposed 

rules.

Comment 4: Comments opposing establishing new regional renewables clearing houses and

supporting existing regional tracking systems.

Response 4: The EPA does not require wholesale changes to electric utility structuring. The 

EPA addresses considerations for incorporating CO2 emission reduction measures in state plans 

in section VIII.K of the preamble to the final rule. Evaluation, measurement, and verification 

(EM&V) requirements for RE, including tracking systems, are specifically addressed in section 

VIII.K.3.

In section VIII.K.3.b, the EPA clarified that for energy generating resources, including RE, states 

may leverage the programs and infrastructure they have in place for achievement of their RPS 

and take advantage of registries in place for the issuance and tracking of RECs. Many existing 

REC tracking systems already include well-established safeguards, documentation requirements, 

and procedures for registry operations that could be adapted to serve similar functions in relation 

to the final emission guidelines.

The following are summaries of the specific public comments under this comment:

Commenters opposed establishing regional renewables clearing houses because they serve to 

hamper or prevent the efficient operation of Independent System Operators whose purpose is to 

provide for least-cost power dispatch and system reliability. Commenters stated that electric 

utilities have used regional entities to track generation for renewable energy resources and 

identify parties that have received or allocated credit for these resources. Commenters added that 

this sort of tracking system has been successfully applied by MRETS, the Midwest Renewable 
434

Energy Tracking System. Commenters also added that actual power transactions are facilitated 

through the Midcontinent Independent System Operator, who has the resources for facilitation of 

reliable, least-cost dispatch to Minnesota and neighboring states and provinces. Commenters

concluded that EPA does not have the authority, nor should it attempt, to create new entities that 

would seek to displace, preempt or compete with the electric utility power market infrastructure 

managed with MISO.

Comment 5: Comments supporting using all-generation tracking systems to calculate in-state 

emissions from affected EGUs and to allocate emissions to LSEs/EDUs.

Response 5: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. Evaluation, 

measurement, and verification (EM&V) requirements for RE, including tracking systems, are 

specifically addressed in section VIII.K.3.

In VIII.K.3.b in the preamble to the final rule, the EPA addresses requirements for EM&V and 

M&V submittals for energy generating resources, including RE resources. States may leverage 

the programs and infrastructure they have in place for achievement of their RPS and take 

advantage of registries in place for the issuance and tracking of RECs, including all-generation 

tracking systems. Many existing REC tracking systems already include well-established 

safeguards, documentation requirements, and procedures for registry operations that could be 

adapted to serve similar functions in relation to the final emission guidelines. 

For more information on EM&V provisions, see section IV.D.8 of the preamble to the proposed 

Federal Plan and the draft EM&V guidance document.

The following are summaries of the specific public comments under this comment:

Commenters stated that all-generation tracking systems, though not needed to track use and 

emissions of imported and exported generation from affected EGUs since the Proposed Rule sets 

generation-based (statewide) targets and compliance for states (where they exist), can also be 

used by states to calculate in-state emissions from affected EGUs and to allocate emissions to 

LSEs/electric distribution utilities (EDUs), where these are regulated under state plans.

Comment 6: Comments supporting establishing a Renewable Energy Carbon Attribute to 

document its renewable emissions calculations.

Response 6: The EPA addresses considerations for the use of the BSER and non-BSER 

measures to achieve an emission rate-based standard in section V.A.5 and V.A.6 of the preamble 

to the final rule. For RE measures, section V.A.5.a(3) specifies that an owner/operator of an 

affected EGU can either acquire ERCs through common ownership of RE generating capacity, a 

bilateral transaction with the owner/operator of the RE generating capacity, or a transaction for 

ERCs through an intermediary, which could, but need not, involve an organized market.
435

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. As for geographic eligibility, the 

commenters will find the EPA has clarified which actions count and when such actions count 

generally in section VIII.K.1 and more specifically in section VIII.K.3 on EM&V requirements 

for RE resources used to adjust a CO2 rate. Requirements for rate-based emission trading 

programs and the issuance and tracking of ERCs, including qualifying RE measures, programs or 

projects and addressing the potential for interactions between ERCs and RECs, are addressed in 

section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA establish the concept of a Renewable Energy Carbon 

Attribute (RECA) such that one RECA represents the CO2 reduction attribute of one megawatthour from an eligible renewable energy source. Commenters added that in order for a state to 

include a specific amount of renewable energy production in its annual state emissions 

calculation, the state would provide documentation that it possesses an equivalent amount of 

RECAs. Commenters recommended that states be permitted to use RECAs from renewable 

resources in any other state with or without the actual electricity generated by the eligible 

renewable energy resource, so long as this does not create a conflict with existing state RPS 

laws, rules and regulations. 

Comment 7: Comments requesting clarification to whether states will be able to claim credit for 

tax incentives and other financial assistance programs if they do not require RE generators to 

transfer their RECs as a condition for receiving financial assistance.

Response 7: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. The commenters will 

find the EPA has clarified which actions count and when such actions count generally in section 

VIII.K.1 and more specifically in section VIII.K.3 on EM&V requirements for RE resources 

used to adjust a CO2 rate. Requirements for rate-based emission trading programs and the 

issuance and tracking of ERCs, including qualifying RE measures, programs or projects and 

addressing the potential for interactions between ERCs and RECs, are addressed in section 

VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 
436

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

The EPA addresses considerations for the use of the BSER and non-BSER measures to achieve 

an emission rate-based standard in section V.A.5 and V.A.6 of the preamble to the final rule. For 

RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either 

acquire ERCs through common ownership of RE generating capacity, a bilateral transaction with 

the owner/operator of the RE generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized market.

The EPA also addresses additional considerations for EM&V of RE included in state measures 

type plans in section VIII.K.3 of the preamble to the final rule. Under the state measures plan 

type, state measures must be satisfactorily described in the supporting material for a state plan 

submittal. The supporting material would need to demonstrate that the state measures meet the 

same integrity elements that would apply to federally enforceable emission standards. 

Specifically, the state plan submittal must demonstrate that the state measures are quantifiable, 

verifiable, enforceable, non-duplicative and permanent. These requirements are described in 

more detail at section VIII.D.2.

The following are summaries of the specific public comments under this comment:

Commenters contended that States need guidance on whether they will able to claim credit for 

tax incentives and other financial assistance programs if they do not require RE generators to 

transfer their RECs as a condition of receiving financial assistance. Commenters stated that most 

federal or state legislation that provides financial incentives for the development of renewable 

energy is silent about the ownership of associated RECs. Commenters added that RE projects 

that receive state financial incentives often retain the associated RECs rather than transfer them 

(or a portion thereof) to the incentive program administrator. Commenters continued that this is 

in part because the states objective is to allow renewable energy projects to maximize other 

revenue sources, such as REC sales, so that state subsidies can eventually be reduced, and 

because RECs have historically had little value to state incentive program administrators. 

Commenters expressed concern that States might have difficulty claiming credit under the Clean 

Power Plan for these kinds of RE policies if RECs become viewed as the sine qua non of 

entitlement to RE credit. Commenters also asked whether states offering tax incentives or other 

financial assistance must obtain a portion of the RECs from projects they fund in order to claim 

any credit under the CPP

Comment 8: Comments requesting clarification regarding if states are required to adjust their 

emission rate based on avoided CO2 emissions, whether more precise information about the time 

and location of generation will be needed than is currently tracked in REC systems.
437

Response 8: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a. These MWh are added 

to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower 

adjusted CO2 emission rate.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. Evaluation, measurement, and 

verification (EM&V) requirements for RE, including tracking systems, are specifically addressed 

in section VIII.K.3.

The following are summaries of the specific public comments under this comment:

Commenters requested clarification on if EPA requires states to adjust their emission rate based 

on avoided CO2 emissions, whether more precise information about the time and location of 

generation will be needed than is currently tracked in the REC systems. Commenters stated that 

most exchanges currently track only the month of generation, which is not detailed enough 

information to use in a dispatch model or AVERT to estimate avoided CO2 emissions, as EPA 

has suggested it might require. 

Commenters added that REC trading systems should track the date of commercial operation of a 

particular renewable energy resource to allow states and EPA to assess whether the RE 

generation comes from a resource eligible for compliance. Commenters also stated that REC 

trading systems must provide sufficient detail about the type of renewable energy resource that 

generated the electricity in order to allow states and EPA to assess whether it is an eligible 

compliance resource. Commenters contended this will be necessary if EPA allows only some 

biomass or hydropower resources to be eligible, for example, or if states choose to limit the kinds 

of resources that qualify as renewable in their plans.

Comment 9: Commenters suggested several different methods for calculating avoided emissions 

reductions.

Response 9: For RE MWhs and rate-based state plans, the EPA addresses the general accounting 

approach for adjusting a CO2 emission rate in section VIII.K.1 of the preamble to the final rule. 

The reported CO2 emission rate of an affected EGU may be adjusted based on quantified and 

verified MWh from qualifying zero-emitting and low-emitting resources, as described in sections 

VIII.K.1.a. These MWh are added to the denominator of an affected EGU’s reported CO2

emission rate, resulting in a lower adjusted CO2 emission rate. 

To the extent that qualifying zero-emitting and low-emitting resources result in reduced 

generation and CO2 emissions from an individual affected EGU, those emission impacts are 

reflected in lower reported CO2 emissions and a reduction in MWh generation from the affected 

EGU. However, while there will be a reduction in CO2 emissions at the affected EGU, the fact 

that both CO2 emissions and MWh generation are reduced means that such impacts do not alter 
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the reported CO2 emission rate of the affected EGU. As a result, the MWh of replacement 

generation must be added to the denominator of the reported CO2 emission rate, in order to 

represent those impacts in the form of an adjusted CO2 emission rate. 

The reported CO2 emissions reflect the actual emission reduction from the deployment of 

qualifying non-emitting and low emitting resources across the regional grid. Further adjustment 

of the CO2 emissions, such as through the subtraction of emissions estimated by applying an 

emission factor to the MWhs, would double count CO2 emission impacts across the grid.

Requirements for rate-based emission trading programs and the issuance and tracking of ERCs, 

including qualifying RE measures, programs or projects and addressing the potential for 

interactions between ERCs and RECs, are addressed in section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

Evaluation, measurement, and verification (EM&V) requirements for RE, including tracking 

systems, are specifically addressed in section VIII.K.3. For more information on EM&V 

provisions, see section IV.D.8 of the preamble to the proposed Federal Plan and the draft EM&V 

guidance document.

The following are summaries of the specific public comments under this comment:

Commenters contended that EPA should require states to calculate the avoided emissions 

associated with each REC based on the net emissions displaced on the margin by the RE 

generation associated with the REC. Commenters stated that this will encourage RE 

development and deployment in the most carbon-intensive regions of the country by recognizing 

and rewarding RE that displaces the greatest amount of high carbon pollution-emitting 

generation. Commenters added that while each unit of RE generation used for Section 111(d) 

compliance must have an associated REC, each REC may or may not have an equivalent avoided 

emissions value, depending on the type of RE generation represented by the REC and where it is 

located. 

Commenters recommended that EPA ensure that RECs represent actual net emission reductions 

based on the hourly marginal emission rate for the load zone in which the RE generation was 

built. Commenters added that because the point of the rule is to reduce carbon emissions, it 

makes sense for credit for renewable energy to be based on how much carbon emissions from 

affected power plants are actually reduced. Commenters also stated that electricity generation 

happens in real time, so to the extent possible, avoided emissions should be calculated based on 

real-time data. Commenters contended that this approach encourages renewable energy 

development in areas with high carbon-intensive generation, which means the RE will displace 
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more carbon emissions than if built in other areas. Commenters added that each unit of RE that 

displaces fossil-fired generation on the margin, as is often the case in the Midwest, should count 

more towards Section 111(d) compliance than RE that displaces lower-carbon forms of 

generation. Commenters stated that this approach recognizes the importance of accounting for 

the type of RE generated and where it is located to ensure the success of the Clean Power Plan in 

achieving expected emissions reductions. Commenters then added that once the avoided 

emissions for a REC are calculated and entered into an EPA-approved REC tracking system, the 

REC can be used for Section 111(d) compliance. Commenters stated that for a state using a ratebased approach, the avoided emissions represented by the REC would be subtracted from the 

numerator of an entities or the states emission rate. Commenters added that in a mass-based 

state, the avoided emissions value of an out-of-state REC would simply be used to reduce the 

overall emissions emitted by the unit or in the state.

Comment 10: Comments supporting/opposing the incorporation of emission reductions from 

voluntary renewable energy programs into the CPP.

Response 10: In section VIII.C on state plan approaches, the EPA clarifies that states may adopt 

and submit either of two different types of state plans. The first would apply all requirements for 

meeting the emission guidelines to affected EGUs in the form of federally enforceable emission 

standards, which is referred to as an "emission standards" state plan type. The second, which we 

refer to as a "state measures" plan type, would allow the state mass CO2 emission goals to be 

achieved by affected EGUs in part, or entirely, through state measures that apply to affected 

EGUs, other entities, or some combination thereof, such as a RPS. 

These two types of state plans and their respective approaches allow states to meet the statutory 

requirements of CAA section 111(d) while accommodating the wide range of regulatory 

requirements and other programs that states have deployed or will deploy in the electricity sector 

that reduce CO2 emissions from affected EGUs. 

Under the emission standards state plan type, one approach is a rate-based emission standard for 

affected EGUs, which may include use of emission trading and ERCs. The EPA anticipates the 

use of emission trading in state plans, due to the advantages of this approach.

The EPA addresses considerations for the use of the BSER and non-BSER measures to achieve 

an emission rate-based standard in section V.A.5 and V.A.6 of the preamble to the final rule. For 

RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either 

acquire ERCs through common ownership of RE generating capacity, a bilateral transaction with 

the owner/operator of the RE generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized market.

Requirements for rate-based emission trading programs and the issuance and tracking of ERCs, 

including qualifying RE measures, programs or projects and addressing the potential for 

interactions between ERCs and RECs, are addressed in section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 
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(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

The following are summaries of the specific public comments under this comment:

Several commenters contended that voluntary green power programs should not be counted 

toward compliance with the Clean Power Plan. Commenters stated that this would ensure the 

validity of renewable energy claims and would avoid double counting. Commenters added that 

customers who voluntarily purchase renewable energy want to know that they are achieving 

incremental emission reductions and other environmental benefits that go beyond what is 

required under existing laws. Commenters suggested a similar approach as the NEPOOL GIS 

and WREGIS tracking systems that make an adjustment for the voluntary market related to the 

implementation of RGGI and California cap and trade markets. Commenters stated to ensure the 

RE sought by participating ratepayers is in addition to that already compelled by the State, 

Minnesota does not allow green pricing RECs to count toward the State RES. Commenters stated 

that Minnesota utilities must create separate REC retirement accounts to avoid counting green 

pricing RECs toward the utilities' MN RES or other state's RPS and green pricing programs. 

Commenters added that if it were possible that the renewable power for which customers were 

paying a premium would have been acquired by the utility anyway for compliance with the 

Clean Power Plan, this would undermine the main attraction of green pricing programs.

Commenters supported incorporating the Voluntary Renewable Energy (VRE) market into the 

Clean Power Plan. Commenters provided background on VREs and indicated that VRE 

purchases have continued to climb with a year-on-year positive growth rate, despite the recent 

economic recession and lack of legal mandates. Commenters stated that the voluntary and 

compliance markets co-exist, and they are essential to the growth of renewable energy 

generation. Commenters requested that EPA outline a basic framework for states that will ensure 

that renewable energy purchased to meet a mandate or voluntary objective is not credited 

towards more than one state's target.

Commenters stated that in the voluntary renewable energy (VRE) market and in many state RPS 

programs across the country, RECs are already defined as including avoided emissions benefits 

such that the voluntary purchaser or RPS program (and therefore utility customers) can claim 

that their generation avoids emissions on the grid. Commenters stated that this is an important 

benefit in the voluntary market and one which eight states participating in the RGGI and 

California have recognized. Commenters added that most state and tracking system definitions of 

RECs and green attributes support the use of RECs for tracking avoided emissions from RE 

under 111(d) in that avoided emissions and other derived attributes are either already explicitly 

included in definitions of RECs or attributes or they are implicitly included in "all environmental 

benefits," "whole certificate," or similar inclusive language. Commenters added that variations in 

state REC or attribute definitions should not be used as grounds to disaggregate the REC or 

allow double counting of avoided emissions attributes under 111(d).
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Commenters stated that over 50 percent of RECs currently sold through exchanges are entered 

into voluntary markets. Commenters concluded that this represents 50 percent of the current 

renewable energy generating capacity that may not be available for CPP compliance. 

Commenters added that regulation of power plant emissions will affect the impact of voluntary 

actions to use RE or EE, and the Clean Power Plan has the potential to negatively affect the U.S. 

VRE market. Commenters explained that thousands of businesses and organizations, including 

the more than 1,300 participating in the EPA's Green Power Partnership, along with hundreds of 

thousands of individuals purchase green power and RECs in the U.S. VRE market, amounting to 

voluntary use of billions of kilowatt-hours of RE annually. Commenters added that where RE 

that has been sold in the voluntary market is included in 111(d) compliance, these voluntary 

actions to purchase and develop RE will no longer be going beyond what is required by law and 

will no longer qualify as "regulatory surplus" because they get factored into the reductions that a 

state can report to EPA. Commenters added that they will be subsidizing state compliance and 

perhaps allow others not to take action. Commenters also noted that certain VRE measures and 

programs may not meet EPA's requirement for enforceability of measures included in state plans. 

Commenters provided an example of a utility green pricing program that likely will not be 

enforceable in terms of generating reductions since states cannot "enforce or guarantee 

participation in a voluntary program, even if they require an LSE to offer such a program.

Comment 11: Comments supporting the use of in-state REC that are not connected to an 

affected EGU.

Response 11: The EPA addresses considerations for incorporating CO2 emission reduction from 

measures that are grid-connected in state plans in section VIII.K.1 of the preamble to the final 

rule. Eligible measures must be grid-connected. This eligibility criterion aligns with RE 

generation in building block 3 of the BSER, which substitutes for the need for generation from 

affected EGUs.

The following are summaries of the specific public comments under this comment:

Commenters supported allowing an in-state administrative REC that captures renewable energy 

and energy efficiency projects that are not connected to an affected EGU. Commenters stated 

that given the lack of interconnections between Alaska's EGUs and its rural electric utilities, and 

the compelling policy rationale for continued investment in rural communities, EPA should 

allow offsets for reduced or avoided carbon emissions in rural communities to count toward 

compliance. Commenters stated that such an in-state REC program would parallel the interstate 

REC programs and would recognize, but not require, reduced carbon emissions resulting from 

replacing diesel (or other fossil fuel) generation with less-carbon intensive generation, such as 

renewables. Commenters added that the quantifiable emission reductions would then be applied 

in the formula for determining compliance with the mandated state-wide emission rate. 

Commenters explained that an in-state REC for Alaska would apply to the same industry sector 

and would achieve the same goal of reducing CO2 emissions, and the emission reductions would 

be accomplished through the same mechanism of replacing or reducing fossil generation with RE 

and EE programs. Commenters added that in many cases, the off-grid projects would affect small 
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electric systems - consisting of a single, identifiable fossil-fuel powered EGU. Commenters 

concluded that there is no possibility that the new RE or EE measures would be offsetting 

emissions from a new EGU (regulated under 111(b)), offsetting other RE generation, or are 

otherwise already required by another regulatory requirement for a different source category. 

Commenters added that there would also not be a potential for double counting RE/EE credits, 

and the offset of fossil generation is direct and quantifiable. Commenters stated that this 

approach would provide Alaska greater access to building blocks 3 and 4, achieve EPA's goal of 

reducing carbon emissions from fossil fuel electric generating units, and avoid the 

counterproductive result of depriving our rural communities of state support.

Comment 12: Comments supporting/opposing the type of renewable energy measures that may 

be considered for compliance tools.

Response 12: The EPA addresses considerations for the use of the BSER and non-BSER 

measures to achieve an emission rate-based standard in section V.A.5 and V.A.6 of the preamble 

to the final rule. The EPA also addresses the use of biomass, hydroelectric power, and waste-toenergy in section VIII.K.1. (3). 

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. The commenters will find the EPA has 

clarified which actions count and when such actions count generally in section VIII.K.1. and 

more specifically in section VIII.K.3 on EM&V requirements for RE resources used to adjust a 

CO2 rate. Requirements for rate-based emission trading programs and the issuance and tracking 

of ERCs, including qualifying RE measures, programs or projects and addressing the potential 

for interactions between ERCs and RECs, are addressed in section VIII.K.2.

A discussion regarding the use of some biomass feedstocks for compliance purposes can be 

found in Section VIII.I.2.c and Section VIII.K.1 of the preamble.

A discussion regarding the current status of the development of the revised Framework for 

Assessing Biogenic CO2 Emissions from Stationary Sources and how information from the 

revised Framework and the related peer review processes could be used to inform how states and 

EPA assess biogenic CO2 can be found in Section VIII.I.2.c and Section VIII.K.1. For more 

information regarding the Framework, see: http://epa.gov/climatechange/ghgemissions/biogenicemissions.html

The following are summaries of the specific public comments under this comment:

Commenters disagreed with EPA limiting the type of renewable energy measures that may be 

considered as compliance tools. Commenters stated that by placing limitations on the types of 

renewable energy measures considered, EPA establishes a more onerous burden on states to 

comply with EPA mandates and impairs the ability of building block 3 to be implemented to its 

full potential as a low-cost means of reducing carbon emissions. Commenters supported allowing 

all emission reductions resulting from a range of renewable technologies, such as biomass, 
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incremental hydroelectric power, and marine renewable energy, to be acceptable in a state 

compliance plan. 

Commenters supported allowing generation from biomass in a state compliance plan similar to 

non-emitting generation and consistent with EPA's forthcoming biogenic carbon dioxide 

accounting framework and recommended that EPA finalize and publish this framework as soon 

as possible. Commenters added that adding carbon capture and sequestration (CCS) technology 

to a biomass facility can lead to a net sequestration of carbon and emissions from such facilities 

should be calculated in the same way as for a coal facility with CCS. Commenters stated that this 

method of calculation for a biomass facility with CCS potentially leads to negative net emissions 

from those facilities. 

Several commenters supported allowing hydroelectric power projects to provide compliance 

credit as these types of upgrades extend the hydroelectric power system and provide for real 

emission reductions. Commenters stated that the proposal appears to exclude RE MWh from 

existing hydro resources from crediting toward compliance with rate goals. Commenters 

questioned if this exclusion is intended to apply to states that count existing hydro toward the 

RPS targets that were used to set goals. Commenters recommended that EPA consider best 

practices in the states when developing the methodology for determining the estimates and 

accounting for this technology as it can vary widely among operators. Commenters also stated 

that incremental hydropower is an efficiency improvement and EPA should consider providing 

states guidance on the appropriate measure life for such an upgrade. 

Commenters supported EPA allowing offshore wind and wave and other marine renewable 

resources to provide compliance credit in the same manner as other renewable energy 

technologies, whether they are located in state territorial waters or federal waters. Commenters 

stated that marine energy is an emerging renewable energy sector that offers unique benefits to 

coastal communities with limited power generation options.

Commenters recommended that EPA only accept or certify RECs representing generation from 

carbon pollution-free wind power and solar energy. Commenters stated that in combination with 

the avoided emissions measurement criteria outlined below, this will promote consistent 

accounting for emissions reductions associated with RE across states. Commenters opposed 

allowing nuclear power generation to generate RECs for Section 111(d) compliance. 

Commenters stated that this approach would reduce confusion related to different states 

definitions of "renewable energy." Commenters contended that EPA should not accept or certify 

RECs associated with GHG-emitting sources as Section 111(d) compliant. Commenters stated 

that if EPA allows states to rely on carbon-emitting renewable energy in their SIPs, avoided 

emissions associated with a carbon-emitting REC should be net of any carbon emissions 

associated with that generation.

Comment 13: Comment s addressing RECs that expire.

Response 13: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. The commenters will 

find the EPA has clarified which actions count and when such actions count generally in section 
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VIII.K.1. and more specifically in section VIII.K.3 on EM&V requirements for RE resources 

used to adjust a CO2 rate.

The EPA addresses considerations for eligibility dates for generation and capacity in state plans 

in section VIII.K.1.a.(2) of the preamble to the final rule. Electricity generation that occurs 

during a plan performance period may be applied to adjust a CO2 emission rate. Specifically, this 

means that any quantified and verified MWh of electricity generation that occur in 2022 and 

future years, from an eligible measure, may be applied toward adjusting a CO2 emission rate. The 

eligible measures themselves may be installed in any year after 2012. Specifically, RE 

generating capacity measures that are installed after 2012 are eligible for use in adjusting a CO2

emission rate.

Requirements for rate-based emission trading programs and the issuance and tracking of ERCs, 

including qualifying RE measures, programs or projects and addressing the potential for 

interactions between ERCs and RECs, are addressed in section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

The following are summaries of the specific public comments under this comment:

Commenters noted that REC contract expirations can run the gamut from short-term contracts to 

long-term contracts up to 15 to 20 years. Commenters stated that when contracts expire, the 

ownership of the future RECs reverts back to the owner of the generating assets for deployment 

with that state for 111(d) compliance. Commenters concluded that EPA will need to consider, 

and states will need to work to address through existing systems.

Comment 14: Comments regarding the retirement of RECs for 111(d) compliance as part of the 

state plan.

Response 14: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. Evaluation, 

measurement, and verification (EM&V) requirements for RE, including tracking systems, are 

specifically addressed in section VIII.K.3.

The EPA addresses considerations for ERC issuance in section VIII.K.2 of the preamble to the 

final rule. The EPA notes that non–ERC certificates may be issued by states and other bodies for 

MWh of energy generation that are used to meet other state regulatory requirements, such as 

state RPS, or by individuals to make environmental or other claims in voluntary markets. The 

EPA defines an ERC in the emission guidelines as a tradable compliance instrument that 
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represents a zero-emission MWh from a qualifying measure that may be used to adjust the 

reported CO2 emission rate of an affected EGU subject to a rate-based emission standard in an 

approved state plan under CAA section 111(d). The sole purpose of an ERC is for use by an 

affected EGU in demonstrating compliance with a rate-based emission standard in such an 

approved state plan. An ERC is issued separately from any other instruments that may be issued 

for a MWh of energy generation or energy savings from a qualifying measure. Such other 

instruments may be issued for use in meeting other regulatory requirements (e.g., such as state 

RPS and EERS requirements) or for use in voluntary markets. An ERC may be issued based on 

the same data and verification requirements used by existing REC and EEC tracking systems for 

issuance of RECs and EECs.

The EPA addresses considerations for the use of the BSER and non-BSER measures to achieve 

an emission rate-based standard in section V.A.5 and V.A.6 of the preamble to the final rule. For 

RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either 

acquire ERCs through common ownership of RE generating capacity, a bilateral transaction with 

the owner/operator of the RE generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized market.

The following are summaries of the specific public comments under this comment:

Commenters contended that EPA should require that RECs for 111(d) compliance retired on 

behalf of a state for 111(d) compliance or a state mechanism that has been included in the state 

plan. Commenters supported requiring documentation of retirement according to tracking system 

procedures when RECs in tracking systems are used to comply with 111(d). Commenters stated 

that EPA can limit RE that is eligible for 111(d) compliance to facilities that are participating in 

tracking systems, or, where RE generation facilities are not participating in a tracking system, 

which is sometimes the case for smaller and distributed generation facilities, RECs can be 

created, transferred and retired contractually, in which case verification of unique ownership and 

complete retirement of RECs for 111(d) compliance must be performed manually. Commenters 

added that RECs may not need to be managed any differently for 111(d) than they are currently 

for a state RPS program, depending on how the RPS is set up. Commenters asserted that the state 

must demonstrate to EPA that RECs have been retired in-state for the RPS or another measure 

included the state plan. Commenters clarified that this does not require that the retiring party 

(e.g. LSEs or individual EGU owners/users complying with the RPS) have a 111(d) compliance 

obligation. Commenters stated that tracking systems can easily add a 111(d) compliance

retirement reason/category, functionality that allows a states to select both state RPS and 111(d) 

compliance as retirement reasons where RPS programs are included in state plans, new 

identifications or "tags" for RECs that have been included in state plans, additional memo fields, 

and other features to facilitate their use by states for 111(d) compliance. Commenters added that 

111(d) avoided emissions values can be tracked with individual RECs in tracking systems, 

provided that precise enough information is available.

Comment 15: Comments on the recognition of retirement of long-term REC bundled PPA's.
446

Response 15: The EPA addresses considerations for the use of the BSER and non-BSER 

measures to achieve an emission rate-based standard in section V.A.5 and V.A.6 of the preamble 

to the final rule. For RE measures, section V.A.5.a(3) specifies that an owner/operator of an 

affected EGU can either acquire ERCs through common ownership of RE generating capacity, a 

bilateral transaction with the owner/operator of the RE generating capacity, or a transaction for 

ERCs through an intermediary, which could, but need not, involve an organized market.

The EPA addresses considerations for ERC issuance in section VIII.K.2 of the preamble to the 

final rule. The EPA notes that non–ERC certificates may be issued by states and other bodies for 

MWh of energy generation that are used to meet other state regulatory requirements, such as 

state RPS, or by individuals to make environmental or other claims in voluntary markets. The 

EPA defines an ERC in the emission guidelines as a tradable compliance instrument that 

represents a zero-emission MWh from a qualifying measure that may be used to adjust the 

reported CO2 emission rate of an affected EGU subject to a rate-based emission standard in an 

approved state plan under CAA section 111(d). The sole purpose of an ERC is for use by an 

affected EGU in demonstrating compliance with a rate-based emission standard in such an 

approved state plan. An ERC is issued separately from any other instruments that may be issued 

for a MWh of energy generation or energy savings from a qualifying measure. Such other 

instruments may be issued for use in meeting other regulatory requirements (e.g., such as state 

RPS and EERS requirements) or for use in voluntary markets. An ERC may be issued based on 

the same data and verification requirements used by existing REC and EEC tracking systems for 

issuance of RECs and EECs.

The following are summaries of the specific public comments under this comment:

Commenters stated that TVA has historically entered into, and plans to continue to enter into, 

numerous long-term REC bundled PPAs representing a significant ratepayer investment. 

Commenters added that the retirement of these RECs by TVA within a particular state for 111(d) 

Block 3 compliance purposes must be recognized by EPA. Commenters also stated that if a REC 

has been exported out of a particular state via bundled PPA, that 1 MWh of renewable energy 

cannot be also counted by the generating state for 111(d) compliance purposes.

Comment 16: Comments regarding REC ownership and retirement ramifications.

Response 16: The EPA addresses considerations for the use of the BSER and non-BSER 

measures to achieve an emission rate-based standard in section V.A.5 and V.A.6 of the preamble 

to the final rule. For RE measures, section V.A.5.a(3) specifies that an owner/operator of an 

affected EGU can either acquire ERCs through common ownership of RE generating capacity, a 

bilateral transaction with the owner/operator of the RE generating capacity, or a transaction for 

ERCs through an intermediary, which could, but need not, involve an organized market.

The EPA addresses considerations for ERC issuance in section VIII.K.2 of the preamble to the 

final rule. The EPA notes that non–ERC certificates may be issued by states and other bodies for 

MWh of energy generation that are used to meet other state regulatory requirements, such as 

state RPS, or by individuals to make environmental or other claims in voluntary markets. The 

EPA defines an ERC in the emission guidelines as a tradable compliance instrument that 
447

represents a zero-emission MWh from a qualifying measure that may be used to adjust the 

reported CO2 emission rate of an affected EGU subject to a rate-based emission standard in an 

approved state plan under CAA section 111(d). The sole purpose of an ERC is for use by an 

affected EGU in demonstrating compliance with a rate-based emission standard in such an 

approved state plan. An ERC is issued separately from any other instruments that may be issued 

for a MWh of energy generation or energy savings from a qualifying measure. Such other 

instruments may be issued for use in meeting other regulatory requirements (e.g., such as state 

RPS and EERS requirements) or for use in voluntary markets. An ERC may be issued based on 

the same data and verification requirements used by existing REC and EEC tracking systems for 

issuance of RECs and EECs.

The following are summaries of the specific public comments under this comment:

Commenters stated that for states using a rate-based approach, an EPA requirement that REC 

ownership and retirement determines a claim on avoided emissions from RE for 111(d) 

compliance means that the state may not make adjustments for RE to its emission rate (for the 

purpose of either state plan development or emission performance compliance reporting) without 

RECs and unique REC retirement.

Comment 17: Comments suggesting that CPP would negatively impact utility REC based 

programs.

Response 17: The EPA addresses considerations for the use of the BSER and non-BSER 

measures to achieve an emission rate-based standard in section V.A.5 and V.A.6 of the preamble 

to the final rule. For RE measures, section V.A.5.a(3) specifies that an owner/operator of an 

affected EGU can either acquire ERCs through common ownership of RE generating capacity, a 

bilateral transaction with the owner/operator of the RE generating capacity, or a transaction for 

ERCs through an intermediary, which could, but need not, involve an organized market.

The EPA addresses considerations for ERC issuance in section VIII.K.2 of the preamble to the 

final rule. The EPA notes that non–ERC certificates may be issued by states and other bodies for 

MWh of energy generation that are used to meet other state regulatory requirements, such as 

state RPS, or by individuals to make environmental or other claims in voluntary markets. The 

EPA defines an ERC in the emission guidelines as a tradable compliance instrument that 

represents a zero-emission MWh from a qualifying measure that may be used to adjust the 

reported CO2 emission rate of an affected EGU subject to a rate-based emission standard in an 

approved state plan under CAA section 111(d). The sole purpose of an ERC is for use by an 

affected EGU in demonstrating compliance with a rate-based emission standard in such an 

approved state plan. An ERC is issued separately from any other instruments that may be issued 

for a MWh of energy generation or energy savings from a qualifying measure. Such other 

instruments may be issued for use in meeting other regulatory requirements (e.g., such as state 

RPS and EERS requirements) or for use in voluntary markets. An ERC may be issued based on 

the same data and verification requirements used by existing REC and EEC tracking systems for

issuance of RECs and EECs.
448

The following are summaries of the specific public comments under this comment:

Commenters contended that compliance with the proposed rule could negatively impact utility 

REC based programs. Commenters stated that while the Clean Power Plan leverages an RPS 

concept to set compliance targets, renewable energy is far more complex, Contractual obligations 

exists that go well beyond the state RPS concept used to create baselines and compliance targets. 

Commenters listed a number of renewable energy programs used by TVA, including Green 

Power Switch, Renewable Standard Offer, Solar Solutions Initiative, Green Power Providers, 

Dispersed Power Production Program, Distributed Generation-Integrated Value, and Wind 

Energy Contracts. Commenters stated that EPA should allow credit for compliance for all utility 

REC-based programs for which the utility owns and retires the REC.

Comment 18: Comments regarding verification measures for existing REC tracking systems.

Response 18: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. Evaluation, 

measurement, and verification (EM&V) requirements for RE, including tracking systems, are 

specifically addressed in section VIII.K.3. This section identifies and discusses the EM&V 

requirements used. States must submit these criteria as specified, or alternatively, states may 

submit certain established standard industry practices described in section VIII.K.3 as 

presumptively approvable. States may also submit other means of meeting the criteria so long as 

the state satisfactorily demonstrates in the state plan submittal that such alternative means of 

addressing criteria are as adequately stringent as the presumptively approvable approach.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should assess what type of verification measures each of the REC 

tracking systems has in place, such as gathering and making available data on how the system 

operator verifies the claims of generators, how often meters must be tested, whether generators 

are subject to occasional inspection, and other means of ensuring the accuracy of the RECs 

generated and preventing fraud. Commenters supported requiring REC system operators to 

undergo initial and periodic audits. Commenters contended that EPA should exercise due 

diligence in understanding and, if necessary, strengthening the safeguards built into these 

systems which will factor heavily into CPP compliance. Commenters added that if EPA 

determines that existing REC verification procedures are not adequate to ensure accuracy and 

avoid fraud, it should work with the RE generators and REC tracking system operators to bring 

those procedures up to standard. Commenters concluded that EPA must not allow RECs 

generated through such systems to count towards CPP compliance. Commenters stated that this 

can be ensured by requiring the REC tracking system operator to add a field to the system 

indicating whether the REC meets EPA's data quality standards.

Comment 19: Comments regarding requiring REC tracking systems to record whether a RE 

resource is eligible for CPP compliance.
449

Response 19: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a. These MWh are added 

to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower 

adjusted CO2 emission rate.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. The commenters will find the EPA has 

clarified which actions count and when such actions count generally in section VIII.K.1. and 

more specifically in section VIII.K.3 on EM&V requirements for RE resources used to adjust a 

CO2 rate. Requirements for rate-based emission trading programs and the issuance and tracking 

of ERCs, including qualifying RE measures, programs or projects and addressing the potential 

for interactions between ERCs and RECs, are addressed in section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

The following are summaries of the specific public comments under this comment:

Commenters contended that EPA must clarify that energy-producing technologies will qualify 

for Clean Power Plan compliance as a "renewable energy resources" only if they emit zero 

carbon dioxide. Commenters stated that because EPAs methodology for crediting renewable 

energy involves either adding RE MWhs to the denominator of the emission rate or subtracting 

the emissions avoided at a displaced fossil EGU from the numerator, it would not be appropriate 

for EPA to allow states to credit in this way purportedly renewable resources that generate 

carbon emissions. Commenters suggested that EPA should exclude from its definition of 

renewable resources technologies such as "clean" coal, waste coal, combustion of municipal 

solid waste and pulping process byproducts (black liquor), and biomass-generated fuels. 

Commenters suggested EPA should require REC tracking systems to add a field verifying 

whether a particular RE resources is eligible for CPP compliance to implement this limitation. 

Commenters added that REC tracking systems already contain fields to track eligibility for 

particular state RPS requirements, so should have no difficulty adding such a field for the CPP 

once provided with a definition by EPA.

Comment 20: Comments supporting the development of credit markets for 111(d) compliance.

Response 20: In section VIII.C on state plan approaches, the EPA clarifies that states may adopt 

and submit either of two different types of state plans. The first would apply all requirements for 

meeting the emission guidelines to affected EGUs in the form of federally enforceable emission 
450

standards, which we refer to as an "emission standards" state plan type. The second, which we 

refer to as a "state measures" plan type, would allow the state mass CO2 emission goals to be 

achieved by affected EGUs in part, or entirely, through state measures that apply to affected 

EGUs, other entities, or some combination thereof, such as a RPS. These two types of state plans 

and their respective approaches allow states to meet the statutory requirements of CAA section 

111(d) while accommodating the wide range of regulatory requirements and other programs that 

states have deployed or will deploy in the electricity sector that reduce CO2 emissions from 

affected EGUs. 

Under the emission standards state plan type, one approach is a rate-based emission standard for 

affected EGUs, which may include use of emission trading and ERCs. The EPA anticipates the 

use of emission trading in state plans, due to the advantages of this approach.

The EPA addresses considerations for ERC issuance in section VIII.K.2 of the preamble to the 

final rule. The EPA notes that non–ERC certificates may be issued by states and other bodies for 

MWh of energy generation that are used to meet other state regulatory requirements, such as 

state RPS, or by individuals to make environmental or other claims in voluntary markets. The 

EPA defines an ERC in the emission guidelines as a tradable compliance instrument that 

represents a zero-emission MWh from a qualifying measure that may be used to adjust the 

reported CO2 emission rate of an affected EGU subject to a rate-based emission standard in an 

approved state plan under CAA section 111(d). The sole purpose of an ERC is for use by an 

affected EGU in demonstrating compliance with a rate-based emission standard in such an 

approved state plan. An ERC is issued separately from any other instruments that may be issued 

for a MWh of energy generation or energy savings from a qualifying measure. Such other 

instruments may be issued for use in meeting other regulatory requirements (e.g., such as state 

RPS and EERS requirements) or for use in voluntary markets. An ERC may be issued based on 

the same data and verification requirements used by existing REC and EEC tracking systems for 

issuance of RECs and EECs.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.G of the preamble to the final rule. Evaluation, measurement, and 

verification (EM&V) requirements for RE, including tracking systems, are specifically addressed 

in section VIII.K.3.

The following are summaries of the specific public comments under this comment:

Commenters urged EPA to support the development of credit markets for 111(d) compliance. 

Commenters suggested that such markets should function similar to existing REC markets, 

which verify and track credits to avoid double counting, and states may elect to utilize the 

existing REC market as a component of their compliance plans to the extent that RECs have 

equivalent attributes. Commenters recommended that EPA issue guidance for state plans that 

clarifies the use of compliance markets as a part of state plans. Commenters provided an example 

of some states being interested in submitting partial joint plans that reference the use of a 

national 111(d) energy credit for compliance without entering into memoranda of understandings 

with each state that might be a generator or purchaser of renewable energy credits. Commenters 

stated that EPA should ensure it does not create a barrier for this compliance option. If requested 

by states, EPA may also want to consider developing a national tracking system for 111(d) 
451

compliance credits to facilitate this multi-state dynamic. Commenters supported the option for 

states to coordinate compliance as a means to mitigate the different treatment that results by 

using a state-by-state assessment of the technical and market potential for renewable energy to 

establish the state goals and by using RECs to demonstrate compliance.

Comment 21: Comments requesting direction on how EPA will measure compliance with Block 

3 for states that have not adopted an RPS.

Response 21: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in section VIII.K.1.a.

The EPA addresses considerations for eligibility dates for generation and capacity in state plans 

in section VIII.K.1.a.(2) of the preamble to the final rule. The eligible measures themselves may 

be installed in any year after 2012. Specifically, RE generating capacity measures that are 

installed after 2012 are eligible for use in adjusting a CO2 emission rate. Electricity generation 

that occur during a plan performance period may be applied to adjust a CO2 emission rate. 

Specifically, this means that any quantified and verified MWh of electricity generation that occur 

in 2022 and future years, from an eligible measure, may be applied toward adjusting a CO2

emission rate. 

VIII.L addresses the treatment of interstate effects, including those effects of importing RE. 

Under all types of state plans, states must ensure that the measures and associated CO2 emission 

reductions counted as part of meeting their plan requirements are not duplicative of any measures 

that are counted by another state. Interstate effects make this more difficult because states may 

be responsible for the deployment of measures that have effects on generation and emissions 

beyond the state borders. Depending on how these measures are accounted for, the reductions 

could be counted by both the state that deployed the measure, and the state that reports a 

reduction in fossil generation or reported emissions.

States with rate-based plans must demonstrate that the RE that they use to adjust their CO2

emission rate are non-duplicative. Double-counting of MWhs in the denominator can be avoided 

because adding the MWh that the affected EGU is responsible for deploying to the denominator 

is relatively straightforward to quantify and assign, and aligns well with the MWh-denominated 

trading system described in this final rule. As long as it is assured that the MWhs of RE are only 

being claimed by one state, as is outlined in section VIII.D.2.b, then there is no double-counting 

of MWh.

The EPA addresses considerations for the use of the BSER and non-BSER measures to achieve 

an emission rate-based standard in section V.A.5 and V.A.6 of the preamble to the final rule. For 

RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either 

acquire ERCs through common ownership of RE generating capacity, a bilateral transaction with 

the owner/operator of the RE generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized market.
452

Requirements for rate-based emission trading programs and the issuance and tracking of ERCs, 

including qualifying RE measures, programs or projects and addressing the potential for 

interactions between ERCs and RECs, are addressed in section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

The following are summaries of the specific public comments under this comment:

Commenters questioned how EPA will measure compliance with Block 3 for states, like 

Wyoming, that have not adopted an RPS. Commenters contended that EPAs approach is 

supported only by reaching a number that is equivalent to what an RPS could achieve. 

Commenters provided an example of a company in Wyoming that acquired wind facilities not 

due to renewable portfolio standard requirements in any state, but because they contributed to the 

company's diverse and cost-effective portfolio of resources. Commenters stated that the absence 

of a direct link between an RPS and reliable data does not mean there is no reliable data to 

support a compliance calculation. Commenters added that EPA used EIA data demonstrated 

performance to calculate a Block 3 goal, albeit not for the precise reasons EPA has articulated. 

Commenters also stated that if reported EIA data has been good enough to establish performance 

targets, both EPA and Wyoming should able to rely on this data to measure ongoing performance 

during the glide path years, whether or not Wyoming adopts an RPS. Commenters contended 

that as long as performance can be reliably measured, there is no reason why EPA needs to have 

the state control the underlying motivations and incentives that cause the performance. 

Commenters added that direct controls over new renewables credited to the state could raise 

more questions than it answers. Commenters questioned that if the State were to adopt an RPS, 

would that in some way retroactively cause performance previously unrelated to the RPS to be 

treated as being caused by the RPS and if the state failed to achieve its goal, would EPA really 

pursue enforcement against a small, recalcitrant rural utility. Commenters asked in such a case 

what compliance could it require when the company asserts that its wind acquisitions were 

motivated by practical and economic judgments unrelated to an RPS? Commenters requested 

that EPA consider it sufficient that EPA has reliable data to determine the required rate of 

emissions, which includes data concerning renewables, and therefore to determine an overall rate 

for state compliance. Commenters concluded that it should be enough that a State plan can offer 

a compliance path for its overall goal, which may include options related to other blocks or 

strictly to inside the fence measures, as long as those measures are clearly defined.

Comment 22: Comments supporting allowing only bundled RECs to be counted towards 

meeting the state carbon emission rate goals.
453

Response 22: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a.

In section VIII.C on state plan approaches, EPA clarifies that states may adopt and submit either 

of two different types of state plans. The first would apply all requirements for meeting the 

emission guidelines to affected EGUs in the form of federally enforceable emission standards, 

which we refer to as an "emission standards" state plan type. The second, which we refer to as a 

"state measures" plan type, would allow the state mass CO2 emission goals to be achieved by 

affected EGUs in part, or entirely, through state measures that apply to affected EGUs, other 

entities, or some combination thereof, such as a RPS. These two types of state plans and their 

respective approaches allow states to meet the statutory requirements of CAA section 111(d) 

while accommodating the wide range of regulatory requirements and other programs that states 

have deployed or will deploy in the electricity sector that reduce CO2 emissions from affected 

EGUs. 

Under the emission standards state plan type, one approach is a rate-based emission standard for 

affected EGUs, which may include use of emission trading and ERCs. The EPA anticipates the 

use of emission trading in state plans, due to the advantages of this approach.

The EPA addresses considerations for the use of the BSER and non-BSER measures to achieve 

an emission rate-based standard in section V.A.5 and V.A.6 of the preamble to the final rule. For 

RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either 

acquire ERCs through common ownership of RE generating capacity, a bilateral transaction with 

the owner/operator of the RE generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized market.

The following are summaries of the specific public comments under this comment:

Commenters contended that only bundled RECs should be counted towards meeting the state 

carbon emission rate goals. Commenters expressed concern that there would be an adverse effect 

on states if unbundled RECs are allowed to be counted toward a state's emission goals. 

Commenters explained that allowing an entity to count the environmental attributes of renewable 

energy without taking the energy itself may increase the build out of renewable capacity in states 

with the capacity and weather conditions to support robust wind or solar resources. Commenters 

continued that because utilities must purchase the energy produced from those intermittent 

resources pursuant to Public Utility Regulatory Policy Act rules, utilities would have to manage 

the integration of that energy onto their systems. Commenters added that the benefit of RECs 

would be retained by the owner of the systems, but the associated integration costs could be 

passed on to the local ratepayers. Other commenters supported allowing unbundled RECs to be 

eligible for compliance. Commenters stated that it is not necessary to require that RECs be 

bundled with electricity for the purposes of 111(d) compliance. Commenters added that if only 

electricity bundled with RECs determine claims on RE for 111(d) compliance (i.e. both 

electricity and the REC are required), then there is no double counting within 111(d) or with 

RPSs and the voluntary market. Commenters cautioned that this would severely limit use of RPS 

for 111(d) where state RPS programs allow unbundled RECs to be used - states could not in this 
454

case count all of their RPS toward 111(d) compliance. Commenters stated that it is the REC that 

makes bundled electricity a compliance option that avoids double counting and under the 

Proposed Rule, all that matters with respect to RE is whether the RE creates emissions reductions 

either in state or out of state and whether these reductions have been allocated without double 

counting. Commenters concluded that beyond this, for 111(d), it does not matter whether the 

state with the REC (and therefore the avoided emissions) also uses the electricity generated at the 

renewable plant.

Commenters stated that if RECs are unbundled and sold to a state outside of the region where the 

renewable generation is located, an adjustment would be needed to transfer the emission 

reductions from the generating state or region to the purchasing state. Commenters noted that 

several tracking systems already have the ability to track unbundled REC imports and exports 

between regions and tracking systems. Commenters added that while allowing the use of 

unbundled RECs for state compliance with the CPP introduces some accounting complexities, it 

has the important advantages of giving states more flexibility in complying with the rule and 

lowering the cost of compliance. Commenters continued that while states that sell RECS to other 

states would not be able to use those RECs or the associated renewable generation installed in 

their state for compliance, they would receive important economic benefits such as revenue from 

the sale of RECs as well as the construction, operation and manufacturing jobs and other local 

economic development benefits.

Comment 23: Comments opposing disaggregating avoided emissions from RECs.

Response 23: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a.

In section VIII.C on state plan approaches, EPA clarifies that states may adopt and submit either 

of two different types of state plans. The first would apply all requirements for meeting the 

emission guidelines to affected EGUs in the form of federally enforceable emission standards, 

which we refer to as an "emission standards" state plan type. The second, which we refer to as a 

"state measures" plan type, would allow the state mass CO2 emission goals to be achieved by 

affected EGUs in part, or entirely, through state measures that apply to affected EGUs, other 

entities, or some combination thereof, such as a RPS. These two types of state plans and their 

respective approaches allow states to meet the statutory requirements of CAA section 111(d) 

while accommodating the wide range of regulatory requirements and other programs that states 

have deployed or will deploy in the electricity sector that reduce CO2 emissions from affected 

EGUs. 

Under the emission standards state plan type, one approach is a rate-based emission standard for 

affected EGUs, which may include use of emission trading and ERCs. The EPA anticipates the 

use of emission trading in state plans, due to the advantages of this approach.

The EPA addresses considerations for ERC issuance in section VIII.K.2 of the preamble to the 

final rule. In that section, the EPA notes that non–ERC certificates may be issued by states and 
455

other bodies for MWh of energy generation that are used to meet other state regulatory 

requirements, such as state RPS, or by individuals to make environmental or other claims in 

voluntary markets. 

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure. Such other instruments may be issued 

for use in meeting other regulatory requirements (e.g., such as state RPS and EERS 

requirements) or for use in voluntary markets. An ERC may be issued based on the same data 

and verification requirements used by existing REC and EEC tracking systems for issuance of 

RECs and EECs. 

The EPA defines an ERC in the emission guidelines as a tradable compliance instrument that 

represents a zero-emission MWh from a qualifying measure that may be used to adjust the 

reported CO2 emission rate of an affected EGU subject to a rate-based emission standard in an 

approved state plan under CAA section 111(d). The sole purpose of an ERC is for use by an 

affected EGU in demonstrating compliance with a rate-based emission standard in such an 

approved state plan. 

The EPA addresses considerations for the use of measures to achieve an emission rate-based 

standard in section V.A.5 and V.A.6 of the preamble to the final rule. For RE measures, section 

V.A.5.a(3) specifies that an owner/operator of an affected EGU can either acquire ERCs through 

common ownership of RE generating capacity, a bilateral transaction with the owner/operator of 

the RE generating capacity, or a transaction for ERCs through an intermediary, which could, but 

need not, involve an organized market.

The following are summaries of the specific public comments under this comment:

Commenters stated that avoided emissions must not be disaggregated from RECs for 111(d) for a 

number of reasons. Commenters stated that disaggregating this benefit would not simplify 111(d) 

compliance since a tracking mechanism for avoided emissions would still be required. 

Commenters added that where only states with generation that is displaced by RE could claim 

avoided emissions from RE under 111(d), rate-based states would still need to prove that 

emissions were avoided/displaced due to RE and not counted in other states, just without using 

RECs, which is the existing and most effective instrument. Commenters also stated that 

disaggregation would disrupt state RPS programs, many of which are intended to help reduce 

emissions from electricity. Commenters explained that if emissions are displaced out of state due 

to the RPS program and those avoided emissions remained out of state, the RPS program and 

customers in the RPS state could not claim the full emissions benefit of their 

generation. Commenters added that disaggregation would limit the use of RPS programs for 

111(d) where RPS programs allow for use of unbundled RECs. Commenters also added 

disaggregation would disrupt the voluntary market by removing a critical benefit to voluntary 

consumers, "regulatory surplus," without any way to restore it using the REC, since RECs are the 

currency of RE in the voluntary market. Commenters contended that disaggregation may 

produce an "unfair" outcome if the state where the emissions are displaced is not paying for the 

attributes/reductions. Commenters concluded that disaggregation, whether this involves creating 

a new instrument or not, but especially if it involves creating a new instrument, will increase the 

costs of compliance for states, since they will have to buy the new instrument on top of the RPS 
456

or otherwise obtain avoided emissions which have been separated from the REC. Commenters 

added that for the same reasons, it is inadvisable to create or allow the use of a separate, 

alternative compliance instrument to track avoided emissions from RE, which would have the 

same effect as disaggregating the REC. Commenters cautioned that some states may oppose the 

use of RECs for 111(d) compliance and/or favor the disaggregation of avoided emissions benefit 

on the basis that RECs could be difficult or costly to obtain for some distributed generation (DG) 

solar facilities, especially where third-party solar installer companies currently retain the RECs 

for generation from leased equipment. Commenters contended that this should also not be used 

as grounds to disaggregate RECs or allow for 111(d) compliance without RECs. Commenters 

added that States could require REC purchase or create DG solar policies that include the option 

to acquire RECs from DG owners who take advantage of state incentive and other programs 

supporting the development of DG solar in order to mitigate this issue. Commenters provided an 

example where in the West there are large amounts of electricity flowing from EGUs in the 

intermountain states to the coastal states. Commenters stated that use of unbundled RECs for 

111(d) compliance would allow for RECs to flow from west to east to balance out the carbon 

emissions in the east that result from EGU power flows from east to west.

Comment 24: Comments supporting keeping RECs not used for RPS compliance separate from 

those used for RPS compliance.

Response 24: In section VIII.C on state plan approaches, EPA addresses the choice states have 

with the state plan approach they adopt and submit in section VIII.C of the preamble to the final 

rule. The EPA clarifies that states may adopt and submit either of two different types of state 

plans – emission standards plans or state measures plans. The first would apply all requirements 

for meeting the emission guidelines to affected EGUs in the form of federally enforceable 

emission standards. The second would allow the state mass CO2 emission goals to be achieved 

by affected EGUs in part, or entirely, through state measures that apply to affected EGUs, other 

entities, or some combination thereof, such as a RPS.

Under the state measures plan type, measures must be satisfactorily described in the supporting 

material for a state plan submittal. The supporting material would need to demonstrate that the 

state measures meet the same integrity elements that would apply to federally enforceable 

emission standards. Specifically, the state plan submittal must demonstrate that the state 

measures are quantifiable, verifiable, enforceable, non-duplicative and permanent. These 

requirements are described in more detail at section VIII.D.2.

Under the emission standards state plan type, one approach is a rate-based emission standard for 

affected EGUs, which may include use of emission trading and ERCs. The EPA anticipates the 

use of emission trading in state plans, due to the advantages of this approach.

The EPA addresses ERC issuance and RECs in section VIII.K.2 of the preamble to the final rule. 

In that section, the EPA notes that non–ERC certificates may be issued by states and other bodies 

for MWh of energy generation that are used to meet other state regulatory requirements, such as 

state RPS, or by individuals to make environmental or other claims in voluntary markets. An 

ERC is issued separately from any other instruments that may be issued for a MWh of energy 
457

generation or energy savings from a qualifying measure. Such other instruments may be issued 

for use in meeting other regulatory requirements (e.g., such as state RPS and EERS 

requirements) or for use in voluntary markets. An ERC may be issued based on the same data 

and verification requirements used by existing REC and EEC tracking systems for issuance of 

RECs and EECs. The EPA defines an ERC in the emission guidelines as a tradable compliance 

instrument that represents a zero-emission MWh from a qualifying measure that may be used to 

adjust the reported CO2 emission rate of an affected EGU subject to a rate-based emission 

standard in an approved state plan under CAA section 111(d). The sole purpose of an ERC is for 

use by an affected EGU in demonstrating compliance with a rate-based emission standard in 

such an approved state plan. 

These two types of state plans and their respective approaches allow states to meet the statutory 

requirements of CAA section 111(d) while accommodating the wide range of regulatory 

requirements and other programs that states have deployed or will deploy in the electricity sector 

that reduce CO2 emissions from affected EGUs.

The following are summaries of the specific public comments under this comment:

Commenters noted that many RECs are not used for RPS compliance and not all utilities in a 

state are necessarily regulated by the entities with authority to enforce an RPS requirement. 

Commenters stated that if EPA chooses to endorse or allow states to use RECs to facilitate 

renewable energy tracking/compliance related to the CPP, this compliance would need to remain 

separate from RPS compliance.

Comment 25: Comments requesting the EPA to define the unit of compliance with the CPP.

Response 25: In section VIII.C on state plan approaches, EPA addresses the choice states have 

with the state plan approach they adopt and submit in section VIII.C of the preamble to the final 

rule. The EPA clarifies that states may adopt and submit either of two different types of state 

plans – emission standards plans or state measures plans. The first would apply all requirements 

for meeting the emission guidelines to affected EGUs in the form of federally enforceable 

emission standards. The second would allow the state mass CO2 emission goals to be achieved 

by affected EGUs in part, or entirely, through state measures that apply to affected EGUs, other 

entities, or some combination thereof, such as a RPS.

In a state measures state plan type, states may allow the use of RECs to quantify and verify the 

zero-emission MWh of RE used to meet a state measure requirement, such as an RPS. Measures 

must be satisfactorily described in the supporting material for a state plan submittal. The 

supporting material would need to demonstrate that the state measures meet the same integrity 

elements that would apply to federally enforceable emission standards. Specifically, the state 

plan submittal must demonstrate that the state measures are quantifiable, verifiable, enforceable, 

non-duplicative and permanent. These requirements are described in more detail at section 

VIII.K.4.
458

Under the emission standards state plan type, one approach is a rate-based emission standard for 

affected EGUs, which may include use of emission trading and ERCs. The EPA anticipates the 

use of emission trading in state plans, due to the advantages of this approach.

The EPA addresses ERC issuance and RECs in section VIII.K.2 of the preamble to the final rule. 

In that section, the EPA notes that non–ERC certificates may be issued by states and other bodies 

for MWh of energy generation that are used to meet other state regulatory requirements, such as 

state RPS, or by individuals to make environmental or other claims in voluntary markets. An 

ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure. Such other instruments may be issued 

for use in meeting other regulatory requirements (e.g., such as state RPS and EERS 

requirements) or for use in voluntary markets. An ERC may be issued based on the same data 

and verification requirements used by existing REC and EEC tracking systems for issuance of 

RECs and EECs. The EPA defines an ERC in the emission guidelines as a tradable compliance 

instrument that represents a zero-emission MWh from a qualifying measure that may be used to 

adjust the reported CO2 emission rate of an affected EGU subject to a rate-based emission 

standard in an approved state plan under CAA section 111(d). The sole purpose of an ERC is for 

use by an affected EGU in demonstrating compliance with a rate-based emission standard in 

such an approved state plan. 

These two types of state plans and their respective approaches allow states to meet the statutory 

requirements of CAA section 111(d) while accommodating the wide range of regulatory 

requirements and other programs that states have deployed or will deploy in the electricity sector 

that reduce CO2 emissions from affected EGUs.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA should more clearly define the unit of compliance, which may, 

or may not be, consistent with the definition, scope, and objectives of state RECs. Commenters 

also agreed that there could be several different attributes associated with the generation of 

electricity from a renewable resource, one of which may be the GHG emissions reduction 

attribute. Commenters strongly encouraged the EPA to clarify that only the GHG attribute 

associated with the power generation is covered by the program, and that RECs, if used form 

compliance with the CPP, must include the GHG attribute because states' treatment of 

environmental attributes under RECs vary widely. Commenters also requested EPA to clarify 

that instruments other than a REC can be used as part of tracking and measuring compliance, 

such as an independent GHG mitigation attribute.

Comment 26: Comments requesting guidance that clarifies the use of renewable energy 

compliance markets as part of state plans.

Response 26: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. The commenters will 

find the EPA has clarified which actions count and when such actions count generally in section 
459

VIII.K.1 and more specifically in section VIII. K.3 on EM&V requirements for RE resources 

used to adjust a CO2 rate. Section VIII.L features the treatment of interstate effects.

In section VIII.C on state plan approaches, EPA addresses the choice states have with the state 

plan approach they adopt and submit in section VIII.C of the preamble to the final rule. The EPA 

clarifies that states may adopt and submit either of two different types of state plans – emission 

standards plans or state measures plans. The first would apply all requirements for meeting the 

emission guidelines to affected EGUs in the form of federally enforceable emission standards. 

The second would allow the state mass CO2 emission goals to be achieved by affected EGUs in 

part, or entirely, through state measures that apply to affected EGUs, other entities, or some 

combination thereof, such as a RPS.

Under the state measures plan type, measures must be satisfactorily described in the supporting 

material for a state plan submittal. The supporting material would need to demonstrate that the 

state measures meet the same integrity elements that would apply to federally enforceable 

emission standards. Specifically, the state plan submittal must demonstrate that the state 

measures are quantifiable, verifiable, enforceable, non-duplicative and permanent. These 

requirements are described in more detail at section VIII.D.2.

Under the emission standards state plan type, one approach is a rate-based emission standard for 

affected EGUs, which may include use of emission trading and ERCs. The EPA anticipates the 

use of emission trading in state plans, due to the advantages of this approach. Requirements for 

rate-based emission trading programs and the issuance and tracking of ERCs, including 

qualifying RE measures, programs or projects and addressing the potential for interactions 

between ERCs and RECs, are addressed in section VIII.K.2.

In that section, the EPA notes that non–ERC certificates may be issued by states and other bodies 

for MWh of energy generation that are used to meet other state regulatory requirements, such as 

state RPS, or by individuals to make environmental or other claims in voluntary markets. An 

ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA defines an ERC in the emission guidelines as a tradable 

compliance instrument that represents a zero-emission MWh from a qualifying measure that may 

be used to adjust the reported CO2 emission rate of an affected EGU subject to a rate-based 

emission standard in an approved state plan under CAA section 111(d). The sole purpose of an 

ERC is for use by an affected EGU in demonstrating compliance with a rate-based emission 

standard in such an approved state plan.

The EPA is aware of the potential for interactions between ERCs and RECs and encourages the 

states to consider, when developing their state plan, how existing instruments that are used to 

meet other regulatory requirements or in voluntary markets may interact with ERCs.

These two types of state plans and their respective approaches allow states to meet the statutory 

requirements of CAA section 111(d) while accommodating the wide range of regulatory 
460

requirements and other programs that states have deployed or will deploy in the electricity sector 

that reduce CO2 emissions from affected EGUs.

The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA issue guidance for state plans that clarifies the use of 

renewable energy compliance markets as a part of state plans. Commenters explained that States 

need guidance as to how to account for the interstate impacts of renewable energy and end-use 

efficiency, so that they can develop plans that do not risk disapproval because of a perception 

that they rely on reductions that have been double counted.

Comment 27: Comments requesting guidance in using RECs in the CPP.

Response 27: In section VIII.C on state plan approaches, EPA addresses the choice states have 

with the state plan approach they adopt and submit in section VIII.C of the preamble to the final 

rule. The EPA clarifies that states may adopt and submit either of two different types of state 

plans – emission standards plans or state measures plans. The first would apply all requirements 

for meeting the emission guidelines to affected EGUs in the form of federally enforceable 

emission standards. The second would allow the state mass CO2 emission goals to be achieved 

by affected EGUs in part, or entirely, through state measures that apply to affected EGUs, other 

entities, or some combination thereof, such as a RPS. These two types of state plans and their 

respective approaches allow states to meet the statutory requirements of CAA section 111(d) 

while accommodating the wide range of regulatory requirements and other programs that states 

have deployed or will deploy in the electricity sector that reduce CO2 emissions from affected 

EGUs.

In a state measures state plan type, states may allow the use of RECs to quantify and verify the 

zero-emission MWh of RE used to meet a state measure requirement, such as an RPS. Measures 

must be satisfactorily described in the supporting material for a state plan submittal. The 

supporting material would need to demonstrate that the state measures meet the same integrity 

elements that would apply to federally enforceable emission standards. Specifically, the state 

plan submittal must demonstrate that the state measures are quantifiable, verifiable, enforceable, 

non-duplicative and permanent. These requirements are described in more detail at section 

VIII.K.4.

The commenters will find the EPA has clarified which actions count and when such actions 

count generally in section VIII.K.1 and more specifically in section VIII.K.3 on EM&V 

requirements for RE resources used to adjust a CO2 rate. Requirements for rate-based emission 

trading programs and the issuance and tracking of ERCs, including qualifying RE measures, 

programs or projects and addressing the potential for interactions between ERCs and RECs, are 

addressed in section VIII.K.2.

In that section, the EPA notes that non–ERC certificates may be issued by states and other bodies 

for MWh of energy generation that are used to meet other state regulatory requirements, such as 

state RPS, or by individuals to make environmental or other claims in voluntary markets. An 

ERC is issued separately from any other instruments that may be issued for a MWh of energy 
461

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA defines an ERC in the emission guidelines as a tradable 

compliance instrument that represents a zero-emission MWh from a qualifying measure that may 

be used to adjust the reported CO2 emission rate of an affected EGU subject to a rate-based 

emission standard in an approved state plan under CAA section 111(d). The sole purpose of an 

ERC is for use by an affected EGU in demonstrating compliance with a rate-based emission 

standard in such an approved state plan.

The EPA is aware of the potential for interactions between ERCs and RECs and encourages the 

states to consider, when developing their state plan, how existing instruments that are used to 

meet other regulatory requirements or in voluntary markets may interact with ERCs.

The following are summaries of the specific public comments under this comment:

Commenters contended that EPA should provide clean guidance and default principles for using 

RECs. Commenters stated that EPA should provide default guidance explaining how states 

should measure the CO2 emission reductions attributable to a tier of tradable RECs as distinct 

from the actual RE generated.

Comment 28: Comments stating that EPA should recognize RECs instead of the actual RE as 

the basis for CPP compliance.

Response 28: In section VIII.C on state plan approaches, EPA addresses the choice states have 

with the state plan approach they adopt and submit in section VIII.C of the preamble to the final 

rule. The EPA clarifies that states may adopt and submit either of two different types of state 

plans – emission standards plans or state measures plans. The first would apply all requirements 

for meeting the emission guidelines to affected EGUs in the form of federally enforceable 

emission standards. The second would allow the state mass CO2 emission goals to be achieved 

by affected EGUs in part, or entirely, through state measures that apply to affected EGUs, other 

entities, or some combination thereof, such as a RPS. These two types of state plans and their 

respective approaches allow states to meet the statutory requirements of CAA section 111(d) 

while accommodating the wide range of regulatory requirements and other programs that states 

have deployed or will deploy in the electricity sector that reduce CO2 emissions from affected 

EGUs.

In a state measures state plan type, states may allow the use of RECs to quantify and verify the 

zero-emission MWh of RE used to meet a state measure requirement, such as an RPS. Measures 

must be satisfactorily described in the supporting material for a state plan submittal. The 

supporting material would need to demonstrate that the state measures meet the same integrity 

elements that would apply to federally enforceable emission standards. Specifically, the state 

plan submittal must demonstrate that the state measures are quantifiable, verifiable, enforceable, 

non-duplicative and permanent. These requirements are described in more detail at section 

VIII.K.4.
462

The commenters will find the EPA has clarified which actions count and when such actions 

count generally in section VIII.K.1 and more specifically in section VIII.K.3 on EM&V 

requirements for RE resources used to adjust a CO2 rate. Requirements for rate-based emission 

trading programs and the issuance and tracking of ERCs, including qualifying RE measures, 

programs or projects and addressing the potential for interactions between ERCs and RECs, are 

addressed in section VIII.K.2.

In that section, the EPA notes that non–ERC certificates may be issued by states and other bodies 

for MWh of energy generation that are used to meet other state regulatory requirements, such as 

state RPS, or by individuals to make environmental or other claims in voluntary markets. An 

ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA defines an ERC in the emission guidelines as a tradable 

compliance instrument that represents a zero-emission MWh from a qualifying measure that may 

be used to adjust the reported CO2 emission rate of an affected EGU subject to a rate-based 

emission standard in an approved state plan under CAA section 111(d). The sole purpose of an 

ERC is for use by an affected EGU in demonstrating compliance with a rate-based emission 

standard in such an approved state plan.

The EPA is aware of the potential for interactions between ERCs and RECs and encourages the 

states to consider, when developing their state plan, how existing instruments that are used to 

meet other regulatory requirements or in voluntary markets may interact with ERCs.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should recognize RECs, rather than the actual RE, as the most 

efficient basis for CPP compliance.

Comment 29: Comments suggesting that the EPA should ensure that state RPS policies do not 

compete with the market-based emissions reduction policies by driving very high cost CO2

emission reductions in existing CO2 trading markets

Response 29: In section VIII.C on state plan approaches, EPA addresses the choice states have 

with the state plan approach they adopt and submit in section VIII.C of the preamble to the final 

rule. The EPA clarifies that states may adopt and submit either of two different types of state 

plans – emission standards plans or state measures plans. The first would apply all requirements 

for meeting the emission guidelines to affected EGUs in the form of federally enforceable 

emission standards. The second would allow the state mass CO2 emission goals to be achieved 

by affected EGUs in part, or entirely, through state measures that apply to affected EGUs, other 

entities, or some combination thereof, such as a RPS.

These two types of state plans and their respective approaches allow states to meet the statutory 

requirements of CAA section 111(d) while accommodating the wide range of regulatory 
463

requirements and other programs that states have deployed or will deploy in the electricity sector 

that reduce CO2 emissions from affected EGUs.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should make clear that if a state were to implement a market-based 

trading program to limit CO2, care should be taken to ensure that state RPS policies do not 

compete with the market-based emissions reduction policies by driving very high cost CO2

emission reductions in existing CO2 trading markets. Commenters explained that an RPS drives 

very costly emissions reductions, bypassing more cost effective emission reduction options the 

market would otherwise implement to meet the cap. Commenters stated that EPA should assist 

states by making clear the relative costs of different approaches, including the cost implications 

of layering policies on top of market-based approaches. Commenters added that if the state does 

not implement a CO2 trading program, an RPS may be considered by some to be necessary. 

Commenters also added that if a state were to implement a CO2 trading program, it should NOT 

then implement an RPS, as this can create the distortions cited above and severely harm the cost 

effectiveness of a market-based emission reduction program.

Comment 30: Comments suggesting to revise RPS structure to address emissions that may be 

generated from fossil fuels to make up variability in renewables or give additional credit when 

baseload fossil fuels are displaced by renewable power.

Response 30: In section V.A.3.b of the preamble to the final rule, the agency stated the June 

2014 proposal's RPS-based proposed methodology is not used in the final rule. Further details 

regarding the final rule’s quantification of RE generation are provided in section V.E.

The following are summaries of the specific public comments under this comment:

Commenters stated that the proposed RPS structure needs to be adjusted to address emissions 

that may be produced from fossil fuels required to firm variable resources, and/or adjusted to 

give additional credit when baseload fossil fuels are displaced by baseload renewable power. 

(For example, a carbon-reduction multiplier could be applied.) Commenters added that RPS 

structures, which historically were designed to promote new production over existing power 

sources, should be designed to protect and sustain investment in existing renewable power 

production facilities.

Comment 31: Comments suggesting that single RECs should be able to be used for multiple 

state programs as long as it is not used for compliance with more than one state’s 111(d) 

compliance plan.

Response 31: In section VIII.D, EPA clarifies that states may allow the use of RECs in a state 

measures state plan type to quantify and verify the zero-emission MWh of RE used to meet a 

state measure requirement, such as an RPS, consistent with the requirements at section VIII.K.2 

and section VIII.L of the final preamble.
464

In section VIII.C on state plan approaches, EPA clarifies that the types of state plans which states 

may adopt and submit allow states to meet the statutory requirements of CAA section 111(d) 

while accommodating the wide range of regulatory requirements and other programs that states 

have deployed or will deploy in the electricity sector that reduce CO2 emissions from affected 

EGUs.

Under a rate-based approach, a state may include in its plan a number of provisions to facilitate 

affected EGU compliance with the emission standards. This could include implementing a 

market-based emission trading program, which enables EGUs to generate and procure Emission 

Rate Credits (ERCs), a tradable compliance unit representing one MWh of electric generation (or 

reduced electricity use) with zero associated CO2 emissions. Considerations and requirements for 

rate-based trading programs are discussed in section VIII.K

Eligible measures that may generate ERCs, as well as the accounting method for adjusting a CO2

emission rate, are discussed in section VIII.K.1. Requirements for rate-based emission trading 

approaches and addressing the potential for interactions between ERCs and RECs are discussed 

in section VIII.K.2. Quantification and verification requirements for measures eligible to 

generate ERCs are discussed in section VIII.K.3.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

For more information on EM&V provisions, see section IV.D.8 of the preamble to the proposed 

Federal Plan and the draft EM&V guidance document.

The following are summaries of the specific public comments under this comment:

Commenters stated that RECs bundle together a number of environmental attributes associated 

with renewable energy generation and a reduction in carbon emissions attributable to renewable 

energy generation is but one stick in that bundle. Commenters contended that the final rule 

should specify that a single REC can be utilized for multiple programs so long as it is not utilized 

for compliance with more than one state's Section 111(d) compliance plan. Commenters 

suggested that the same REC can be assigned attributes to comply with a states RPS programs, 

as well as a 111(d) program. Commenters stated that this approach provides maximum flexibility 

to states and regulated parties, recognizes the importance of renewable energy generation in 

reducing greenhouse gas emissions from the power sector, and encourages additional renewable 

energy development.
465

Comment 32: Commenters emphasized that REC systems need strenuous verification 

procedures.

Response 32: For RE MWhs and rate-based state plans, the EPA addresses the general 

accounting approach for adjusting a CO2 emission rate in section VIII.K.1 of the preamble to the 

final rule. The reported CO2 emission rate of an affected EGU may be adjusted based on 

quantified and verified MWh from qualifying zero-emitting and low-emitting resources, as 

described in sections VIII.K.1.a. These MWh are added to the denominator of an affected EGU’s 

reported CO2 emission rate, resulting in a lower adjusted CO2 emission rate. 

To the extent that qualifying zero-emitting and low-emitting resources result in reduced 

generation and CO2 emissions from an individual affected EGU, those emission impacts are 

reflected in lower reported CO2 emissions and a reduction in MWh generation from the affected 

EGU. However, while there will be a reduction in CO2 emissions at the affected EGU, the fact 

that both CO2 emissions and MWh generation are reduced means that such impacts do not alter 

the reported CO2 emission rate of the affected EGU. As a result, the MWh of replacement 

generation must be added to the denominator of the reported CO2 emission rate, in order to 

represent those impacts in the form of an adjusted CO2 emission rate. 

The reported CO2 emissions reflect the actual emission reduction from the deployment of 

qualifying non-emitting and low emitting resources across the regional grid. Further adjustment 

of the CO2 emissions, such as through the subtraction of emissions estimated by applying an 

emission factor to the MWhs, would double count CO2 emission impacts across the grid.

Requirements for rate-based emission trading programs and the issuance and tracking of ERCs, 

including qualifying RE measures, programs or projects and addressing the potential for 

interactions between ERCs and RECs, are addressed in section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

Evaluation, measurement, and verification (EM&V) requirements for RE, including tracking 

systems, are specifically addressed in section VIII.K.3. For more information on EM&V 

provisions, see section IV.D.8 of the preamble to the proposed Federal Plan and the draft EM&V 

guidance document.

The following are summaries of the specific public comments under this comment:

Commenters contended that nothing in the rule is as important as a system that verifies 

reductions and enforces the failure of states to meet targets. Commenters contended that the REC 

system is insufficient to verify reductions. Commenters explained that States targets must not be 
466

weakened by a REC system that allows false accounting, accounting for previous renewable 

projects, or projects that aren't a carbon benefit. Commenters stated that the rule will succeed or 

fail based upon EPAs ability to force states to transparently verify true reductions.

Comment 33: Commenters expressed concern that the public will not pay for REC usage.

Response 33: EPA did not require specific approaches like REC procurement for RE. In section 

VIII.C on state plan approaches, EPA clarifies that the types of state plans that states may adopt 

and submit allow states to meet the statutory requirements of CAA section 111(d) while 

accommodating the wide range of regulatory requirements and other programs that states have 

deployed or will deploy in the electricity sector that reduce CO2 emissions from affected EGUs. 

Under a rate-based approach, a state may include in its plan a number of provisions to facilitate 

affected EGU compliance with the emission standards. This could include implementing a 

market-based emission trading program, which enables EGUs to generate and procure Emission 

Rate Credits (ERCs), a tradable compliance unit representing one MWh of electric generation (or 

reduced electricity use) with zero associated CO2 emissions. Considerations and requirements for 

rate-based trading programs are discussed in section VIII.K. 

For RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU, 

whether regulated or unregulated, can either acquire ERCs through common ownership of RE 

generating capacity, a bilateral transaction with the owner/operator of the RE generating 

capacity, or a transaction for ERCs through an intermediary, which could, but need not, involve 

an organized market.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. For more information about specific RE 

measures to adjust the CO2 emission rate of an affected EGU to reflect RE, including eligibility 

dates and the types of RE MWhs that are eligible, see Section VIII.K.1. For EM&V requirements 

relevant to RE resources, see section VIII.K.3. Requirements for rate-based emission trading 

programs and the issuance and tracking of ERCs, including qualifying RE measures, programs or 

projects and addressing the potential for interactions between ERCs and RECs, are addressed in 

section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

Under a mass-based approach, there are incentives to take actions at affected EGUs to reduce 

CO2 emissions, as well as the use of strategies such as RE and demand-side EE as 

complementary measures that reduce CO2 emissions. However, unlike under a rate-based 
467

approach, for this latter set of measures there is no need to address and describe these state 

measures in a state plan submission or quantify and verify the RE and EE MWh of generation 

and savings.

The following are summaries of the specific public comments under this comment:

Commenters contended that although many people support the idea of renewable energy, most 

are not willing to pay for it. Commenters provided an example of lack of REC usage in South 

Carolina.

Comment 34: Comments opposing requiring REC credits be used to demonstrate compliance 

with 111(d). The EPA should not supersede State requirements and goals

Response 34: EPA did not require specific approaches like REC procurement for RE. In section 

VIII.C on state plan approaches, EPA clarifies that the types of state plans that states may adopt 

and submit allow states to meet the statutory requirements of CAA section 111(d) while 

accommodating the wide range of regulatory requirements and other programs that states have 

deployed or will deploy in the electricity sector that reduce CO2 emissions from affected EGUs. 

Under a rate-based approach, a state may include in its plan a number of provisions to facilitate 

affected EGU compliance with the emission standards. This could include implementing a 

market-based emission trading program, which enables EGUs to generate and procure Emission 

Rate Credits (ERCs), a tradable compliance unit representing one MWh of electric generation (or 

reduced electricity use) with zero associated CO2 emissions. Considerations and requirements for 

rate-based trading programs are discussed in section VIII.K. 

For RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU, 

whether regulated or unregulated, can either acquire ERCs through common ownership of RE 

generating capacity, a bilateral transaction with the owner/operator of the RE generating 

capacity, or a transaction for ERCs through an intermediary, which could, but need not, involve 

an organized market.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. For more information about specific RE 

measures to adjust the CO2 emission rate of an affected EGU to reflect RE, including eligibility 

dates and the types of RE MWhs that are eligible, see Section VIII.K.1. For EM&V requirements 

relevant to RE resources, see section VIII.K.3. Requirements for rate-based emission trading 

programs and the issuance and tracking of ERCs, including qualifying RE measures, programs or 

projects and addressing the potential for interactions between ERCs and RECs, are addressed in 

section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 
468

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

Under a mass-based approach, there are incentives to take actions at affected EGUs to reduce 

CO2 emissions, as well as the use of strategies such as RE and demand-side EE as 

complementary measures that reduce CO2 emissions. However, unlike under a rate-based 

approach, for this latter set of measures there is no need to address and describe these state 

measures in a state plan submission or quantify and verify the RE and EE MWh of generation 

and savings.

The following are summaries of the specific public comments under this comment:

Commenters opposed requiring REC credits be used to demonstrate compliance with 111(d). 

Commenters explained that RECs are created under individual state laws and are defined by 

states, typically as part of their renewable portfolio standard programs. Commenters added that 

often, states have different definitions in law or regulation as to what types of environmental 

attributes are included in a REC. Commenters also stated that some states include emission 

reductions in the definition of REC while other states do not. Commenters stated that because 

state RPS programs and 111(d) are separate programs with separate goals and requirements, 

RECs and 111(d) compliance should be considered separately. Commenters stated that North 

Carolina has adopted a state-mandated Renewable Energy and Energy Efficiency Portfolio 

Standard (REPS) under which, electric utilities in North Carolina are required to meet up to 10% 

of their energy needs through renewable energy resources or energy efficiency measures by 

2018. Commenters added that North Carolina's REPS requirement is mandated by law, 

administered by the North Carolina Utilities Commission, and tracked through the issuance of 

Renewable Energy Certificates (RECs). Commenters contended that EPA should also accept the 

methods of evaluation, monitoring and verification for renewable resources and energy 

efficiency that North Carolina has adopted as part of its REPS without any modifications. 

Commenters concluded that EPA should not supersede these goals and impose additional or 

different requirements on the state. Commenters added that stakeholders in North Carolina spent 

an enormous amount of time and effort to reach agreement on the goals established by the REPS 

and produced a REPS that would reflect the particular characteristics and needs of North 

Carolina. Commenters concluded that EPA should honor the processes in which North Carolina 

stakeholders engaged to produce a REPS Law and, therefore, should not impose any additional 

requirements.

Comment 35: Comments stating that the EPA should be clear that where a utility's REC 

retirement would comply with a state RPS but not with 111(d), the state will not be able to count 

that renewable energy.

Response 35: For RE MWhs and rate-based state plans, the EPA addresses the general 

accounting approach for adjusting a CO2 emission rate in section VIII.K.1 of the preamble to the 

final rule. The reported CO2 emission rate of an affected EGU may be adjusted based on 

quantified and verified MWh from qualifying zero-emitting and low-emitting resources, as 
469

described in sections VIII.K.1.a. These MWh are added to the denominator of an affected EGU’s 

reported CO2 emission rate, resulting in a lower adjusted CO2 emission rate. 

To the extent that qualifying zero-emitting and low-emitting resources result in reduced 

generation and CO2 emissions from an individual affected EGU, those emission impacts are 

reflected in lower reported CO2 emissions and a reduction in MWh generation from the affected 

EGU. However, while there will be a reduction in CO2 emissions at the affected EGU, the fact 

that both CO2 emissions and MWh generation are reduced means that such impacts do not alter 

the reported CO2 emission rate of the affected EGU. As a result, the MWh of replacement 

generation must be added to the denominator of the reported CO2 emission rate, in order to 

represent those impacts in the form of an adjusted CO2 emission rate. 

The reported CO2 emissions reflect the actual emission reduction from the deployment of 

qualifying non-emitting and low emitting resources across the regional grid. Further adjustment 

of the CO2 emissions, such as through the subtraction of emissions estimated by applying an 

emission factor to the MWhs, would double count CO2 emission impacts across the grid.

Requirements for rate-based emission trading programs and the issuance and tracking of ERCs, 

including qualifying RE measures, programs or projects and addressing the potential for 

interactions between ERCs and RECs, are addressed in section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

Evaluation, measurement, and verification (EM&V) requirements for RE, including tracking 

systems, are specifically addressed in section VIII.K.3. For more information on EM&V 

provisions, see section IV.D.8 of the preamble to the proposed Federal Plan and the draft EM&V 

guidance document.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should be clear that where a utility's REC retirement would comply 

with a state RPS but not with 111(d), the state will not be able to count that renewable energy. 

Commenters contended that the state must either discount the RPS for 111(d) compliance, 

modify the RPS, or require separate REC retirements in connection with 111(d) compliance. 

Commenters concluded that many states have "cost-caps" and alternative compliance payments 

or mechanisms; those off-ramps from state RPS likewise cannot be credited for 111(d).

Comment 36: Comments regarding the identification of other approaches for compliance 

instead of REC tracking.
470

Response 36: For RE MWhs and rate-based state plans, the EPA addresses the general 

accounting approach for adjusting a CO2 emission rate in section VIII.K.1 of the preamble to the 

final rule. The reported CO2 emission rate of an affected EGU may be adjusted based on 

quantified and verified MWh from qualifying zero-emitting and low-emitting resources, as 

described in sections VIII.K.1.a. These MWh are added to the denominator of an affected EGU’s 

reported CO2 emission rate, resulting in a lower adjusted CO2 emission rate. 

To the extent that qualifying zero-emitting and low-emitting resources result in reduced 

generation and CO2 emissions from an individual affected EGU, those emission impacts are 

reflected in lower reported CO2 emissions and a reduction in MWh generation from the affected 

EGU. However, while there will be a reduction in CO2 emissions at the affected EGU, the fact 

that both CO2 emissions and MWh generation are reduced means that such impacts do not alter 

the reported CO2 emission rate of the affected EGU. As a result, the MWh of replacement 

generation must be added to the denominator of the reported CO2 emission rate, in order to 

represent those impacts in the form of an adjusted CO2 emission rate. 

The reported CO2 emissions reflect the actual emission reduction from the deployment of 

qualifying non-emitting and low emitting resources across the regional grid. Further adjustment 

of the CO2 emissions, such as through the subtraction of emissions estimated by applying an 

emission factor to the MWhs, would double count CO2 emission impacts across the grid.

For RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU, 

whether regulated or unregulated, can either acquire ERCs through common ownership of RE 

generating capacity, a bilateral transaction with the owner/operator of the RE generating 

capacity, or a transaction for ERCs through an intermediary, which could, but need not, involve 

an organized market.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. 

Evaluation, measurement, and verification (EM&V) requirements for RE are specifically 

addressed in section VIII.K.3. This section of EPA’s final emission guidelines require that all RE 

providers demonstrate that they will quantify and verify MWh using best-practice EM&V 

approaches. One way to make this demonstration is to use the presumptively approvable EM&V 

approaches specified in the proposed Model Rule in section IV.D.8. States may also submit other 

means of meeting the EM&V requirements so long as the state satisfactorily demonstrates in the 

state plan submittal that such alternative means of addressing requirements are as stringent as the 

presumptively approvable approach.

States may leverage the programs and infrastructure they have in place for achievement of their 

RPS and take advantage of registries in place for the issuance and tracking of RECs. Many 

existing REC tracking systems already include well-established safeguards, documentation 

requirements, and procedures for registry operations that could be adapted to serve similar 

functions in relation to the final emission guidelines. With respect to actual monitoring 

requirements, many existing REC registries include provisions for the monitoring of MWh of 

generation that would be appropriate to meet state plan requirements pursuant to the final rule, 

such as requirements to use a revenue quality meter.
471

For more information on EM&V provisions, see section IV.D.8 of the preamble to the proposed 

Federal Plan and the draft EM&V guidance document.

Requirements for rate-based emission trading programs and the issuance and tracking of ERCs, 

including qualifying RE measures, programs or projects and addressing the potential for 

interactions between ERCs and RECs, are addressed in section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

The following are summaries of the specific public comments under this comment:

Commenters supported participation in an existing REC or generation tracking system is the 

most effective means for demonstrating compliance and avoiding double counting, but noted 

there are at least two other approaches that could also be acceptable in addition to REC tracking. 

Commenters explained this includes renewable generation from 1) power purchase agreements 

and 2) facilities owned by utilities that are being used for compliance with state RESs or to meet 

voluntary state renewable energy goals, but are not part of REC tracking systems. Commenters 

stated that to be eligible for compliance with the rule, the EPA should require states to 

demonstrate that the renewables generation and associated CO2 reduction from these approaches 

is not being claimed by another state. Commenters added that the general principle should be that 

the renewable generation and the associated CO2 reductions and other attributes should go to 

purchaser of this generation, regardless of where the generation is located. 

Comment 37: Comments stating that there should not be an issue with states getting credit for 

renewable energy built on tribal lands.

Response 37: The EPA appreciates the commenters’ response to address EPA’s concerns 

regarding RE credits built in Indian country. The EPA has clarified the treatment of RE resources 

across states in the final rule. This is discussed in section VIII.K.1.a.(2) of the preamble to the 

final rule. The EPA clarified that RE resources located in Indian country could be used to meet 

the emission guidelines in a state plan.

The following are summaries of the specific public comments under this comment:

Commenters addressed EPA's concern, that there may be a problem getting credit for renewable 

energy built on Tribal lands in-state, by their interpretation that given that the proposed rule 

strongly encourages new clean energy projects, there is every indication that states will be free to 

claim credit for Tribal projects that are built in-state and serve in-state electric load.
472

Comment 38: Comments regarding the retirement of RECs and importing renewable energy 

from other states that utilize RECs.

Response 38: In a state measures state plan type, states may allow the use of RECs to quantify 

and verify the zero-emission MWh of RE used to meet a state measure requirement, such as an 

RPS. Measures must be satisfactorily described in the supporting material for a state plan 

submittal. The supporting material would need to demonstrate that the state measures meet the 

same integrity elements that would apply to federally enforceable emission standards. 

Specifically, the state plan submittal must demonstrate that the state measures are quantifiable, 

verifiable, enforceable, non-duplicative and permanent. These requirements are described in 

more detail at section VIII.K.4.

In section V.A.3.b of the preamble to the final rule, the agency stated the June 2014 proposal's 

RPS-based proposed methodology is not used in the final rule. Further details regarding the final 

rule’s quantification of RE generation are provided in section V.E.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. For more information about specific RE 

measures to adjust the CO2 emission rate of an affected EGU to reflect RE, including eligibility 

dates and the types of RE MWhs that are eligible, see Section VIII.K.1. Requirements for ratebased emission trading programs and the issuance and tracking of ERCs, including qualifying 

RE measures, programs or projects and addressing the potential for interactions between ERCs 

and RECs, are addressed in section VIII.K.2.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure, such as a renewable energy certificate 

(REC). An ERC may be issued, however, based on the same data and verification requirements 

used by existing REC tracking systems for issuance of RECs that are used to meet state 

renewable portfolio standards. The EPA is aware of the potential for interactions between ERCs 

and RECs and encourages the states to consider, when developing their state plan, how existing 

instruments that are used to meet other regulatory requirements or in voluntary markets may 

interact with ERCs.

The EPA addresses considerations for the use of the BSER and non-BSER measures to achieve 

an emission rate-based standard in section V.A.5 and V.A.6 of the preamble to the final rule. For 

RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either 

acquire ERCs through common ownership of RE generating capacity, a bilateral transaction with 

the owner/operator of the RE generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized market.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should allow states to incorporate elements of a state's renewable 

portfolio standard into its compliance plan. Commenters explained that EPAs calculation of state 

goals does not include each states specific qualifying renewable energy for states with an RPS. 
473

Commenters stated that EPA should allow states to set state-specific renewable targets based on 

qualifying renewable energy as it is defined in that state. Commenters provided an example in 

Michigan where qualifying renewable energy includes generation from municipal solid waste, 

coke oven gas, and woody biomass and therefore these generation sources should be allowed in 

setting renewable goals for Michigan. Commenters concluded that if these sources are not 

included, then the calculation of the state renewable generation goal for building block 3 should 

be adjusted downward. 

Commenters also stated that utilities satisfy the RPS based on expiring RECs; however, RECs 

have a 3 year lifespan and as a result, utilities can comply with the RPS regulation using RECs 

from previous years. Commenters stated that retiring RECs does not necessarily equate to 

renewable generation capacity for a given year. Commenters added that Michigan grants 

incentive RECs (i.e. non-generation-based RECs) for renewable energy projects that use 

Michigan labor and materials or for certain types of generation. Commenters expressed concern 

that these RECs, which count towards RPS compliance, may be challenging to incorporate into 

an approvable Sec. 111(d) state compliance plan. 

Commenters also added that EPA should recognize that many states import renewable energy 

from other states and utilize RECs to comply with a states RPS. Commenters stated that EPA 

should not limit states ability to include renewable generation not represented by a REC in state 

111(d) compliance plans. Commenters added that RECs are not the only way in which 

compliance with RPS programs is measured, and provided an example of electric utilities 

building in-state and out-of-state renewable energy facilities and power from these facilities 

being used to satisfy RPS requirements without the creation of a REC. Commenters added that 

companies also engage in bilateral contracts for renewable energy that can be used to satisfy 

RES requirements.

5.4.4 Renewable portfolio standards: Small distributed generators

This section discusses changing generating power from big power stations to DG energy, the role 

of government in developing DG sources, how to promote DG, and the type of recordkeeping 

and verification needed for DG sources.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments supporting changing generating power from big power stations to DG

energy.

Response 1: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a. These MWh are added 
474

to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower 

adjusted CO2 emission rate.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. The commenters will find the EPA has 

clarified which actions count and when such actions count generally in section VIII.K.1. and 

more specifically in section VIII.K.3 on EM&V requirements for RE resources used to adjust a 

CO2 rate.

The following are summaries of the specific public comments under this comment:

Several commenters supported changing generating power from big power stations to distributed 

generation energy. Commenters contended that generating energy in large facilities and taking it 

miles away is inefficient.

Comment 2: Comments stating that in developing DG resources, the role of the government is 

to develop decision tools and data and not pick winners and losers.

Response 2: EPA did not prescribed specific approaches or measures like RE distributed 

generation (DG). In section VIII.C on state plan approaches, EPA clarifies that the types of state 

plans which states may adopt and submit allow states to meet the statutory requirements of CAA 

section 111(d) while accommodating the wide range of regulatory requirements and other 

programs that states have deployed or will deploy in the electricity sector that reduce CO2

emissions from affected EGUs.

Under a rate-based approach, a state may include in its plan a number of provisions to facilitate 

affected EGU compliance with the emission standards. For more information about specific 

methods to adjust the CO2 emission rate of an affected EGU to reflect RE and eligibility 

requirements for resources that can be used to adjust a CO2 emission rate, including eligibility 

dates and the types of RE MWhs that are eligible, see Section VIII.K.1. 

The following are summaries of the specific public comments under this comment:

Commenters stated that in developing DG resources, the role of the government is to develop 

decisional tools and trusted data, and not to pick winners and losers. Commenters stated that 

EPA needs to provide improved policy resources, and develop objective case study data on cross 

resource optimization. Commenters added that this type of optimization promises to allow 

communities to make objective and informed tradeoffs resulting in DG projects that are most 

beneficial to the community.

Comment 3: Comments supporting unregulated generation assets not owned and operated by a 

vertically integrated utility to be physically located in the state.
475

Response 3: In section VIII.C on state plan approaches, EPA clarifies that the types of state 

plans which states may adopt and submit allow states to meet the statutory requirements of CAA 

section 111(d) while accommodating the wide range of regulatory requirements and other 

programs that states have deployed or will deploy in the electricity sector that reduce CO2

emissions from affected EGUs.

Under a rate-based approach, a state may include in its plan a number of provisions to facilitate 

affected EGU compliance with the emission standards. For more information about specific 

methods to adjust the CO2 emission rate of an affected EGU to reflect RE and eligibility 

requirements for resources that can be used to adjust a CO2 emission rate, including eligibility 

dates and the types of RE MWhs that are eligible, see Section VIII.K.1.

For RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU, 

whether regulated or unregulated, can either acquire ERCs through common ownership of RE 

generating capacity, a bilateral transaction with the owner/operator of the RE generating 

capacity, or a transaction for ERCs through an intermediary, which could, but need not, involve 

an organized market.

The following are summaries of the specific public comments under this comment:

Commenters agreed with EPA that unregulated generation assets not owned and operated by a 

vertically integrated utility may be physically located in such a state. Commenters contended that 

the unregulated plants are often merchant generators that do not serve load. Commenters added 

that as such they have no means of implementing demand side energy efficiency and renewable 

energy programs or recovering costs (with regulated rates of return). Commenters stated that in 

recognition of the fact that such unregulated generation does exist in these states, EPA 

acknowledges that a state plan may need to treat such unregulated generation differently. 

Commenters suggested that EPA take a stronger position on this point and provide clearer 

guidance to the states. Commenters specifically suggested that that EPA direct states utilizing the 

utility-driven portfolio approach to limit compliance obligations solely to direct within the 

fenceline CO2 emission reductions and not subject them to the entire suite of obligations under a 

state plan.

Comment 4: Comments supporting cost-based principles for DG because benefits and costs to 

the distribution system vary greatly with penetration of DG.

Response 4: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a. These MWh are added 

to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower 

adjusted CO2 emission rate.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. The commenters will find the EPA has 

clarified which actions count and when such actions count generally in section VIII.K.1 and 
476

more specifically in section VIII.K.3 on EM&V requirements for RE resources used to adjust a 

CO2 rate.

The EPA addresses considerations for the use of the BSER and non-BSER measures to achieve 

an emission rate-based standard in section V.A.5 and V.A.6 of the preamble to the final rule. For 

RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either 

acquire ERCs through common ownership of RE generating capacity, a bilateral transaction with 

the owner/operator of the RE generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized market.

The following are summaries of the specific public comments under this comment:

Commenters contended that cost-based principles are critical for distributed generation because 

benefits and costs to the distribution system vary greatly with penetration of DG. Commenters 

stated that rates paid to DG customers should be consistent with conventional methods used by 

utilities to value energy resources and compensate comparable utility-scale resources. 

Commenters added that under that framework, utility-sponsored community solar is likely to 

yield greater net benefits than rooftop solar. Commenters contended that in some PV deployment 

models, the value to some individual consumers may be greater, but inequalities will be 

introduced and overall costs to the community will be higher.

Comment 5: Comments suggesting that utilities should be required to keep accurate records 

regarding installation dates of DG systems and their anticipated service life, and EPA must 

require regular and comprehensive auditing.

Response 5: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a. These MWh are added 

to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower 

adjusted CO2 emission rate.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. The commenters will find the EPA has 

clarified which actions count and when such actions count generally in section VIII.K.1. and 

more specifically in section VIII.K.3 on EM&V requirements for RE resources used to adjust a 

CO2 rate.

Evaluation, measurement, and verification (EM&V) requirements for RE, including tracking 

systems, are specifically addressed in section VIII.K.3.

The following are summaries of the specific public comments under this comment:

Commenters stated that in order for DG measures to meet the permanence requirements, utilities 

should be required to keep accurate records regarding installation dates of DG systems and their 

anticipated service life. Commenters stated that EPA must require regular, comprehensive 
477

auditing of in-place systems to ensure that damaged or disconnected systems are no longer 

counted towards the utility's compliance. Commenters stated that EPA must offer further 

guidance about the policy issues unique to distributed generation, including those topics 

highlighted above. Commenters added that without detailed guidance and some assurance about 

what kinds of distributed generation policy tools will count for compliance, states may choose 

less environmentally beneficial tools rather than DG to achieve their target emission rates.

5.4.5 Feed-in tariffs

This section discusses establishing DG sources via feed-in tariff contracts.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments supporting utilities procuring DG resources via feed-in tariff contracts.

Response 1: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a. These MWh are added 

to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower 

adjusted CO2 emission rate.

In section VIII.C on state plan approaches, EPA clarifies that states may adopt and submit either 

of two different types of state plans. The first would apply all requirements for meeting the 

emission guidelines to affected EGUs in the form of federally enforceable emission standards, 

which we refer to as an "emission standards" state plan type. The second, which we refer to as a 

"state measures" plan type, would allow the state mass CO2 emission goals to be achieved by 

affected EGUs in part, or entirely, through state measures that apply to affected EGUs, other 

entities, or some combination thereof, such as a RPS. 

Under the state measures plan type, state measures must be satisfactorily described in the 

supporting material for a state plan submittal. The supporting material would need to 

demonstrate that the state measures meet the same integrity elements that would apply to 

federally enforceable emission standards. Specifically, the state plan submittal must demonstrate 

that the state measures are quantifiable, verifiable, enforceable, non-duplicative and permanent. 

These requirements are described in more detail at section VIII.D.2.

Under the emission standards state plan type, one approach is a rate-based emission standard for 

affected EGUs, which may include use of emission trading and ERCs. The EPA anticipates the 

use of emission trading in state plans, due to the advantages of this approach. 

The following are summaries of the specific public comments under this comment:
478

Commenters supported utilities efficiently procuring distributed generation resources via feed-in 

tariff contracts, which are standard offer, fixed price, long-term power purchase agreements. 

Commenters noted that a FERC order in 2011 regarding implementation by the California Public 

Utilities Commission of a feed-in tariff to support development of combined heat and power 

generation paves the way for even greater use of feed-in tariffs to meet state RPS and other 

policy objectives. Commenters added that in this order FERC found the concept of a multi-tiered 

avoided cost rate structure to be consistent with the avoided cost rate requirements set forth in 

the Public Utilities Regulatory Policy Act (PURPA) and its subsequent regulations. Commenters 

concluded that this ruling affords states greater ability to establish feed-in tariff rates at levels 

that would support private investment, including in renewable energy generation.

5.4.6 State tax incentives

This section discusses tax incentives to promote use of renewable energy and rebates for end 

users of renewable energy.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Commenters supported tax incentives to promote use of renewable energy.

Response 1: EPA encourages the use of innovative RE program design and financing as 

enabling measures that facilitate greater use of RE. In the final rule, however, financing program 

strategies are not directly recognized as an eligible measure that can be used to adjust a CO2

emission rate, because financing does not directly substitute for electric generation from the grid 

or avoid electricity use from the grid.

For RE MWhs and rate-based state plans, the EPA addresses the general accounting approach for 

adjusting a CO2 emission rate in section VIII.K.1 of the preamble to the final rule. The reported 

CO2 emission rate of an affected EGU may be adjusted based on quantified and verified MWh 

from qualifying zero-emitting and low-emitting resources, as described in sections VIII.K.1.a. 

These MWh are added to the denominator of an affected EGU’s reported CO2 emission rate, 

resulting in a lower adjusted CO2 emission rate. 

To the extent that qualifying zero-emitting and low-emitting resources result in reduced 

generation and CO2 emissions from an individual affected EGU, those emission impacts are 

reflected in lower reported CO2 emissions and a reduction in MWh generation from the affected 

EGU. However, while there will be a reduction in CO2 emissions at the affected EGU, the fact 

that both CO2 emissions and MWh generation are reduced means that such impacts do not alter 

the reported CO2 emission rate of the affected EGU. As a result, the MWh of replacement 

generation must be added to the denominator of the reported CO2 emission rate, in order to 

represent those impacts in the form of an adjusted CO2 emission rate. 
479

The reported CO2 emissions reflect the actual emission reduction from the deployment of 

qualifying non-emitting and low emitting resources across the regional grid. Further adjustment 

of the CO2 emissions, such as through the subtraction of emissions estimated by applying an 

emission factor to the MWhs, would double count CO2 emission impacts across the grid.

For RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU, 

whether regulated or unregulated, can either acquire ERCs through common ownership of RE 

generating capacity, a bilateral transaction with the owner/operator of the RE generating 

capacity, or a transaction for ERCs through an intermediary, which could, but need not, involve 

an organized market.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. Evaluation, measurement, and 

verification (EM&V) requirements for RE are specifically addressed in section VIII.K.3. This 

section of EPA’s final emission guidelines require that all RE providers demonstrate that they 

will quantify and verify MWh using best-practice EM&V approaches. One way to make this 

demonstration is to use the presumptively approvable EM&V approaches specified in the 

proposed Model Rule in section IV.D.8. States may also submit other means of meeting the 

EM&V requirements so long as the state satisfactorily demonstrates in the state plan submittal 

that such alternative means of addressing requirements are as stringent as the presumptively 

approvable approach.

The following are summaries of the specific public comments under this comment:

Several commenters supported state tax incentives to promote renewable energy projects. 

Commenters added that States can do much to encourage and support distributed generation 

specifically, such as tax credits. Commenters affirmed that State and municipal tax incentives, 

regulations, and product rebate programs that are intended to accelerate investments in energy 

efficiency outcomes and energy-efficient technologies can reduce emissions, improve 

communities, and save consumers money. Commenters listed several tax incentives and rebate 

programs that have been implemented in a number of states, and could be easily replicated by 

others: (1) Personal and corporate tax credits and deductions: In return for investing in energy 

efficiency and/or renewable energy technologies that reduce CO2 emissions, state could offer 

individuals or corporations tax credits or deductions; (2) Property tax exemptions: For 

investments made to reduce the CO2 emissions of a property (e.g., energy efficiency or 

distributed energy generation), states or local jurisdictions could offer property tax exemptions to 

encourage the deployment of CO2 -saving technologies; (3) Sales tax exemptions: For qualifying 

purchases of CO2 -saving technologies, some states have waived sales tax; (4) Product rebates: 

Direct product rebates could be offered to consumers of CO2 -saving technologies. Commenters 

expected after the climate power plan, even more support for renewable energy resources with 

tax credits, grants, and other possibilities and not any limitation or quantity regulations. 

Commenters added that State support can address many of the market gaps in private sector 

renewable energy finance and be most helpful in accelerating private sector investment in the 

clean energy sector. Commenters explained that states provide various types of credit supports to 

stimulate private sector investment in breakthroughs, including in more established renewable 

energy technologies. Commenters stated that State aid focused on more established technologies, 

like commercial wind, solar, biomass, geothermal and other technologies, would address the 
480

short-term challenges of the present credit limitation of the tax equity market, accelerate 

conventional renewables deployment in the near term, and help ensure sufficient depth to the 

renewable project finance market. Commenters added that the lower credit risks for a portfolio of 

these technologies would allow state incentives to maximize leverage and private-sector 

financing on an aggregate level. Commenters added that States have a variety of financial tools 

at its disposal, including equity or quasi-equity instruments, letters of credits, insurance products,

and secondary market support, and would have the ability to charge revenue-generating fees or 

take equity or convertible debt stakes in lieu of credit subsidy costs. Commenters stated that the 

Proposed Rule will result in enormous expenditures for combined cycle natural gas plants over 

the course of a relatively short time frame. Commenters added that public policy should support 

the continued role of municipal power providers by helping these not-for-profit entities finance 

the plants necessary to continue their role in the power generation business. Commenters added 

that when enough financial incentive is available, solutions to problems are able to be found.

Comment 2: Comments supporting rebates for the end user of renewable energy.

Response 2: EPA encourages the use of innovative RE program design and financing as 

enabling measures that facilitate greater use of RE. In the final rule, however, financing program 

strategies are not directly recognized as an eligible measure that can be used to adjust a CO2

emission rate, because financing does not directly substitute for electric generation from the grid 

or avoid electricity use from the grid.

For RE MWhs and rate-based state plans, the EPA addresses the general accounting approach for 

adjusting a CO2 emission rate in section VIII.K.1 of the preamble to the final rule. The reported 

CO2 emission rate of an affected EGU may be adjusted based on quantified and verified MWh 

from qualifying zero-emitting and low-emitting resources, as described in sections VIII.K.1.a. 

These MWh are added to the denominator of an affected EGU’s reported CO2 emission rate, 

resulting in a lower adjusted CO2 emission rate. 

To the extent that qualifying zero-emitting and low-emitting resources result in reduced 

generation and CO2 emissions from an individual affected EGU, those emission impacts are 

reflected in lower reported CO2 emissions and a reduction in MWh generation from the affected 

EGU. However, while there will be a reduction in CO2 emissions at the affected EGU, the fact 

that both CO2 emissions and MWh generation are reduced means that such impacts do not alter 

the reported CO2 emission rate of the affected EGU. As a result, the MWh of replacement 

generation must be added to the denominator of the reported CO2 emission rate, in order to 

represent those impacts in the form of an adjusted CO2 emission rate. 

The reported CO2 emissions reflect the actual emission reduction from the deployment of 

qualifying non-emitting and low emitting resources across the regional grid. Further adjustment 

of the CO2 emissions, such as through the subtraction of emissions estimated by applying an 

emission factor to the MWhs, would double count CO2 emission impacts across the grid.

For RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can 

either acquire ERCs through common ownership of RE generating capacity, a bilateral 
481

transaction with the owner/operator of the RE generating capacity, or a transaction for ERCs 

through an intermediary, which could, but need not, involve an organized market. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the proposed rule does not contain incentives for the end user. 

Commenters supported allowing a federal rebate in lieu of a credit to the end user for purchasing 

some of their electricity from a renewable energy source. Commenters contended that if EPA 

were to allow the end user to have a rebate to pay the same price as the competitive electricity, 

the benefits would be far more than seven dollars in return for each dollar spent that is in the 

proposed rule because in addition to smog control more jobs would be created.

Comment 3: Comments supporting increasing the percentage rate applied to Federal tax credits 

for energy efficient equipment and renewable energy.

Response 3: EPA encourages the use of innovative EE and RE program design and financing as 

enabling measures that facilitate greater use of RE and demand-side EE. In the final rule, 

however, financing program strategies are not directly recognized as an eligible measure that can 

be used to adjust a CO2 emission rate, because financing does not directly substitute for electric 

generation from the grid or avoid electricity use from the grid.

For RE MWh and rate-based state plans, the EPA addresses the general accounting approach for 

adjusting a CO2 emission rate in section VIII.K.1 of the preamble to the final rule. The reported 

CO2 emission rate of an affected EGU may be adjusted based on quantified and verified MWh 

from qualifying zero-emitting and low-emitting resources, as described in sections VIII.K.1.a. 

These MWh are added to the denominator of an affected EGU’s reported CO2 emission rate, 

resulting in a lower adjusted CO2 emission rate. 

In section VIII.K.1.a.2, the EPA clarifies that all EE measures must result in electricity savings at 

a building, facility, or other end-use location that is connected to the electricity grid. EE 

measures only avoid electric generation from grid-connected EGUs if the electrical loads where 

the efficiency improvements are made are interconnected to the grid.

The following are summaries of the specific public comments under this comment:

Commenters encouraged the EPA to urge Congress to increase the percentage rate which may be 

applied to the Federal tax credit for equipment such as water heaters, wind turbines and solar 

electric generation, and extend the period in which the credit may be taken into the interim 

period to incentivize homeowners to take advantage of the tax credit and energy savings in 

addition to supporting the goal of the Clean Power Plan.

Comment 4: Comments supporting incentives for property owners to increase energy efficiency 

of property.
482

Response 4: EPA encourages the use of innovative EE program design and financing as 

enabling measures that facilitate greater use of RE and demand-side EE. In the final rule, 

however, financing program strategies are not directly recognized as an eligible measure that can 

be used to adjust a CO2 emission rate, because financing does not directly substitute for electric 

generation from the grid or avoid electricity use from the grid. 

In section VIII.K.1.a.2, the EPA clarifies that all EE measures must result in electricity savings at 

a building, facility, or other end-use location that is connected to the electricity grid. EE 

measures only avoid electric generation from grid-connected EGUs if the electrical loads where 

the efficiency improvements are made are interconnected to the grid.

The following are summaries of the specific public comments under this comment:

Commenters urged that, in an effort to include all citizens regardless of tax status from 

participation in the Clean Power Plan, the EPA encourage Congress to develop tax incentive 

programs aimed at landlords and property owners to increase the energy efficiency of their rental 

properties. Commenters stated these incentive support the goal of the Clean Power Plan and also 

improves the health and wellbeing of the Nations most underrepresented citizens who will be 

impacted the most by increased energy costs.

5.4.7 Options

This section discusses allowing states to customize monitoring, verification, and evaluation 

requirements, requests for additional guidance on acceptable renewable energy methods that can 

be included in state plans, and accounting for renewable generation.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments supporting allowing states to establish monitoring, verification, and 

evaluation requirements to customize for sources in their state.

Response 1: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. Evaluation, 

measurement, and verification (EM&V) requirements for RE, including tracking systems, are 

specifically addressed in section VIII.K.3.

This section identifies and discusses the EM&V requirements used. States must submit these 

criteria as specified, or alternatively, states may submit certain established standard industry 

practices described in section VIII.K.3 as presumptively approvable. States may also submit 

other means of meeting the criteria so long as the state satisfactorily demonstrates in the state 

plan submittal that such alternative means of addressing criteria are as adequately stringent as the 

presumptively approvable approach. Electricity T&D measures that improve the efficiency of the 

T&D system and/or reduce electricity use may be used to adjust a CO2 emission rate. This 
483

includes T&D measures that reduce losses of electricity during delivery from a generator to an 

end-user (sometimes referred to as "line losses") and T&D measures that reduce electricity use at 

the end-user, such as conservation voltage reduction (CVR).

To be eligible, T&D measures must be installed after 2012. This general eligibility requirement 

is discussed in section VIII.K.1.a.(2). The MWh of avoided losses or reduction in end-use that 

result from T&D measures must be appropriately quantified and verified, as discussed in section 

VIII.K.3.

The following are summaries of the specific public comments under this comment:

Commenters recommended that states be permitted to establish general Monitoring, Verification 

and Evaluation (MV&E) requirements and be allowed flexibility to customize approaches for 

different programs, measures and processes. Commenters added that a similar approach should 

be extended to transmission and distribution efficiencies. Commenters noted that MV&E 

standards vary broadly within the industry and standardization will be difficult due to numerous 

factors (e.g. treatment of free ridership, spillover, net to gross savings, equipment performance 

under different climate conditions, etc.) and MV&E protocol development will require a 

significant statewide effort. Commenters also noted that retention of independent third parties to 

conduct program reviews is not without cost, and may run upwards of $1 MM per year for a 

utility, thereby impacting costs to consumers.

Comment 2: Comments requesting that the EPA to develop guidance materials on acceptable 

energy methods that could be included as part of a State Plan.

Response 2: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. The commenters will 

find the EPA has clarified which actions count and when such actions count generally in section 

VIII.K.1 and more specifically in section VIII.K.3 on EM&V requirements for RE resources 

used to adjust a CO2 rate. This section identifies and discusses the EM&V requirements used. 

States must submit these criteria as specified, or alternatively, states may submit certain 

established standard industry practices described in section VIII.K.3 as presumptively 

approvable. States may also submit other means of meeting the requirements so long as the state 

satisfactorily demonstrates in the state plan submittal that such alternative means of addressing 

requirements are as adequately stringent as the presumptively approvable approach.

The following are summaries of the specific public comments under this comment:

Commenters supported EPA developing guidance materials on acceptable renewable 

energy methods that could be included as part of an approvable state plan. Commenters stated 

that the EPA should issue a guidance document as soon as possible and seek public comment on 

that document so that states will have a better idea of how to develop a state plan. Commenters 

added that such a guidance document should include the analytic methods, assumptions, and data 

sources that the state will employ during the state performance periods to determine the energy 

savings and energy generation related to renewable energy and EE measures. Commenters 
484

disagreed with limiting the type of renewable energy measures that may be considered as 

compliance tools.

Comment 3: Comments suggesting that the EPA rules should require explicit explanation of 

how integration requirements will be provided for the renewable resources proposed for 

compliance with achieving the targeted reductions in CO2.

Response 3: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a. These MWh are added 

to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower 

adjusted CO2 emission rate.

EPA addresses considerations for incorporating CO2 emission reduction measures in state plans 

in section VIII.K of the preamble to the final rule. The commenters will find the EPA has 

clarified which actions count and when such actions count generally in section VIII.K.1. and 

more specifically in section VIII.K.3 on EM&V requirements for RE resources used to adjust a 

CO2 rate. Requirements for rate-based emission trading programs and the issuance and tracking 

of ERCs, including qualifying RE measures, programs or projects and addressing the potential 

for interactions between ERCs and RECs, are addressed in section VIII.K.2.

The EPA addresses considerations for the use of the BSER and non-BSER measures to achieve 

an emission rate-based standard in section V.A.5 and V.A.6 of the preamble to the final rule. For 

RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either 

acquire ERCs through common ownership of RE generating capacity, a bilateral transaction with 

the owner/operator of the RE generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized market.

The following are summaries of the specific public comments under this comment:

Commenters recommended that the EPA rules require explicit explanation of how integration 

requirements will be provided for the renewable resources proposed for compliance with 

achieving the targeted reductions in CO2. Commenters contended that significant construction of 

new renewable or gas generating resources will generally require new transmission and/or 

pipeline infrastructure and significant construction of new large wind resources to serve the loads 

and compliance needs of other states will create major transmission costs in addition to the 

regulation needs addressed in the previous paragraph. Commenters added that these costs must 

be taken into account when selecting locations for new generation and must be reflected in the 

planning and investment decisions of the consuming utilities. Commenters stated that the 

proposed rules are silent on these issues. Commenters contended that solving this issue will 

require more than interstate cooperation on development of compliance plans; it will have to 

involve the utilities who will make the investments and whose customers will pay the bills. 

Commenters recommended that the EPA rules explicitly require projected locations of renewable 

resources proposed for Building Block 3, identification of the targeted utility that will use the 
485

power, and an evaluation of the transmission requirements and costs associated with them and an 

explanation of who will pay those costs.

Comment 4: Comments suggesting that regional modular plans should be allowed to ensure 

proper accounting for renewable generation.

Response 4: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a. These MWh are added 

to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower 

adjusted CO2 emission rate.

VIII.L addresses the treatment of interstate effects, including those effects of importing RE. 

Under all types of state plans, states must ensure that the measures and associated CO2 emission 

reductions counted as part of meeting their plan requirements are not duplicative of any measures 

that are counted by another state. Interstate effects make this more difficult because states may 

be responsible for the deployment of measures that have effects on generation and emissions 

beyond the state borders. Depending on how these measures are accounted for, the reductions 

could be counted by both the state that deployed the measure, and the state that reports a 

reduction in fossil generation or reported emissions.

States with rate-based plans must demonstrate that the RE and demand-side EE that they use to 

adjust their CO2 emission rate are non-duplicative. Double-counting of MWhs in the 

denominator can be avoided because adding the MWh that the affected EGU is responsible for 

deploying to the denominator is relatively straightforward to quantify and assign, and aligns well 

with the MWh-denominated trading system described in this final rule. As long as it is assured 

that the MWhs of RE and demand-side EE are only being claimed by one state, as is outlined in 

section VIII.C.2, then there is no double-counting of MWh.

The following are summaries of the specific public comments under this comment:

Commenters stated that to ensure proper accounting for renewable generation within a regional 

modular plans should be allowed. Commenters explained that allowing multi-state flexibility in a 

modular way could address individual renewable energy needs, would incentivize additional 

renewable energy investments, and ensure imported renewable energy dependent markets like 

California's to continue on its path towards compliance with the goal while supporting state 

energy policies. However, Commenters contended that the proposed rule is silent on the issue of 

disagreements between states that may wish to claim the same renewable resources leading to 

confusion and possible double counting.

Comment 5: Comments suggesting that only CEMS measuring CO2 emissions from existing 

non-exempted EGUs should be counted towards section 111(d) compliance regardless of 

whether the goal is based on a mass emission (tons) or lb/MWh rate limit.
486

Response 5: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a. These MWh are added 

to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower 

adjusted CO2 emission rate.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. The commenters will find the EPA has 

clarified which actions count and when such actions count generally in section VIII.K.1 and 

more specifically in section VIII.K.3 on EM&V requirements for RE resources used to adjust a 

CO2 rate. Requirements for rate-based emission trading programs and the issuance and tracking 

of ERCs, including qualifying RE measures, programs or projects and addressing the potential 

for interactions between ERCs and RECs, are addressed in section VIII.K.2.

The following are summaries of the specific public comments under this comment:

Commenters stated that only CEMS measured CO2 emissions from existing non-exempted EGUs 

should be counted towards section 111(d) compliance regardless of whether the goal is based on 

a mass emission (tons) or lb/MWh rate limit. Commenters added that CO2 emissions from 

exempted EGUs should not be counted, and CO2 emissions from new and modified EGUs are 

regulated separately and should not be considered or included in the proposed section 111(d) 

existing unit rule.

5.4.8 Other

This section discusses how utilities subsidize renewable energy through rate increases, additional 

considerations EPA must make in regarding the renewable energy and not only RECs, requests 

EPA to provide guidance on customer installed renewable resources, requests for EPA to 

develop a SIP model, recognizing the burden of state regulators to assess the CPP, incorporating 

outside the fence measures within the building bock approach to reduce emissions, incorporating 

life cycle analysis into how each type of energy production is incentivized

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments suggesting that the EPA did not consider how large scale utility projects 

are subsidized through increases in utility rates in the CPP.

Response 1: The EPA addresses the quantification of RE generation potential for the BSER in 

section V.E.6 of the preamble to the final rule. The quantification of RE potential for the BSER 

did not include distributed generation, such as PV. The analysis of RE as the BSER in section 

V.E found the costs of RE to be declining and increasing cost-competitive. In assessing the cost 
487

of CO2 emission reductions from RE in V.E.8, the EPA believes that RE generation at the levels 

represented in building block 3 can be achieved at reasonable costs.

As for RE and rate-base state plans, EPA encourages the use of innovative RE program design 

and financing as enabling measures that facilitate greater use of RE. In the final rule, however, 

financing program strategies are not directly recognized as an eligible measure that can be used 

to adjust a CO2 emission rate, because financing does not directly substitute for electric 

generation from the grid or avoid electricity use from the grid.

For RE MWhs and rate-based state plans, the EPA addresses the general accounting approach for 

adjusting a CO2 emission rate in section VIII.K.1 of the preamble to the final rule. The reported 

CO2 emission rate of an affected EGU may be adjusted based on quantified and verified MWh 

from qualifying zero-emitting and low-emitting resources, as described in sections VIII.K.1.a. 

These MWh are added to the denominator of an affected EGU’s reported CO2 emission rate, 

resulting in a lower adjusted CO2 emission rate.

The following are summaries of the specific public comments under this comment:

Commenters stated that many renewable generation projects currently benefit from various types 

of societal subsidies, such as federal and state tax credits, grants, renewable energy credits 

(RECs), and local property tax relief. Commenters added that ratemaking mechanisms such as 

net metering can lead to de facto subsidization in the form of cross-customer cost-shifting. 

Commenters explained that larger scale, utility-owned projects are effectively subsidized by all 

customers through higher utility rates when project costs exceed the economic value of the 

output. Commenters stated that these subsidies are crucial for the development of renewable 

energy sources. Commenters contended that EPA did not consider these subsidies and doesn't 

acknowledge in its proposal how rapid and disproportionately large expenditures on renewable 

projects might increase rates and significantly decrease the marginal value of such projects to the 

community. Commenters explained the subsidization that results from cross-customer cost 

shifting and stated that cost-shifting issues are particularly pronounced with net-metered projects. 

Commenters added that the subsidization arises because the generator output displaces utility 

production and sales. Commenters provided an example of when the output of the consumerowned PV system is less than or equal to the customers usage, total utility sales are reduced and 

total utility revenue declines by an amount equal to the volumetric ($/kWh or $/kW) rate under 

which the customer is taking service, times the volume of solar output. Commenters added that 

the utility's total cost will decline, by an amount equal to the projects output times the unitized 

($/kWh or $/kW) marginal costs that are avoided as a result of the solar production, which is 

likely to be less than the amount the customer avoids paying. Commenters concluded that 

revenue and cost both decline, but whenever the volumetric electric rate exceeds the unitized 

avoided cost, the utility will face a net revenue loss unless it makes up the shortfall by raising 

rates and shifting costs to its non-PV customers.

Comment 2: Comments suggesting that the EPA provide guidance to states on how to account 

for customer-installed renewable resources aside from those specifically sanctioned (and paid 

for) either by the utilities within a state or by the state itself.
488

Response 2: The EPA addresses considerations for incorporating CO2 emission reduction from 

measures that are grid-connected in state plans in section VIII.K.1.a of the preamble to the final 

rule. Eligible measures must be grid-connected. This eligibility criterion aligns with RE 

generation in building block 3 of the BSER, which substitutes for the need for generation from 

affected EGUs.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. Evaluation, measurement, and 

verification (EM&V) requirements for RE, including tracking systems, are specifically addressed

in section VIII.K.3.

The following are summaries of the specific public comments under this comment:

Commenters contended that EPA did not provide any guidance to the states on how to account 

for customer-installed renewable resources aside from those specifically sanctioned (and paid 

for) either by the utilities within a state or by the state itself. Commenters stated that where 

utilities actually provide the economic incentives for their customers to leave (in the form of 

solar rebates, special tariffs, etc.), the regulated community has access to data on installed 

capacity and net generation, and can factor these data into their RPS calculations and other 

reports to regulatory authorities. Commenters added that these utility-funded departures readily 

lend themselves to the evaluation, measurement, and verification protocols, as proposed. 

Commenters cautioned that once the price of electricity reaches a point that customers elect to 

leave the grid on their own utilities stand a high probability of losing access to these data. 

Commenters concluded that as a result, a significant amount of renewable generation data will be 

unavailable for compliance accounting, and would force utilities and states to over-comply in 

those programs for which they do have control.

Comment 3: Comments suggesting that developing a reliable, cost-effective energy supply 

requires serious evaluation of integration and reliability needs and careful, targeted procurement 

of energy resources that work well together, and cannot be accomplished by only counting 

RECs.

Response 3: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a. These MWh are added 

to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower 

adjusted CO2 emission rate.

The EPA addresses considerations for the use of the BSER and non-BSER measures to achieve 

an emission rate-based standard in section V.A.5 and V.A.6 of the preamble to the final rule. For 

RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either 

acquire ERCs through common ownership of RE generating capacity, a bilateral transaction with 

the owner/operator of the RE generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized market.
489

The following are summaries of the specific public comments under this comment:

Commenters stated that reliable, cost-effective energy supply require serious evaluation of

integration and reliability needs and careful, targeted procurement of energy resources that work 

well together. Commenters explained that renewable energy can contribute to grid reliability and 

to reasonable energy costs. Commenters stated that effective valuation of renewable energy 

measures and programs relative to all requirements-i.e., greenhouse gas reductions and a reliable, 

cost-effective energy supply-can be relatively straightforward, but it cannot be accomplished in a 

simplistic fashion, such as only counting renewable energy credits. Commenters stated that the 

effect on the grid of the variety of renewable energy measures deployed, and the resulting impact 

on the operations of EGUs, must also be assessed; the nature of renewable energy procurement, 

including diversity in location (as overconcentration of renewable energy resources in a limited 

number of areas decreases reliability) as well as energy type can then be adjusted to improve the 

emissions profile of EGUs and of the power sector as a whole.

Comment 4: Comments supporting the EPA to provide incentives to induce the public to 

increase insulation usage.

Response 4: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. Evaluation, 

measurement, and verification (EM&V) requirements for RE, including tracking systems, are 

specifically addressed in section VIII.K.3.

This section identifies and discusses the EM&V requirements used. States must submit these 

requirements as specified, or alternatively, states may submit certain established standard 

industry practices described in section VIII.K.3 as presumptively approvable. States may also 

submit other means of meeting the requirements so long as the state satisfactorily demonstrates 

in the state plan submittal that such alternative means of addressing requirements are as 

adequately stringent as the presumptively approvable approach.

The following are summaries of the specific public comments under this comment:

Commenters stated that if EPA is providing any kind of incentive or any kind of inducement to 

increase insulation the quantification and verification should be simple, streamlined and easy.

Comment 5: Comments suggesting that the EPA has not provided a model SIP for states or 

offered any guidance as to the policies allowed in a SIP.

Response 5: In section VIII.C.2, the EPA notes it is proposing model rules for both mass-based 

and rate-based emission trading programs. Regarding RE and rate-based emission plans, the EPA 

addresses considerations for incorporating CO2 emission reduction measures in state plans in 

section VIII.K of the preamble to the final rule. The commenters will find the EPA has clarified 

which RE actions count and when such actions count generally in section VIII.K.1. and more 

specifically in section VIII.K.3 on EM&V requirements for RE resources used to adjust a CO2
490

rate. For more information on EM&V provisions, see section IV.D.8 of the preamble to the 

proposed Federal Plan and the draft EM&V guidance document.

The following are summaries of the specific public comments under this comment:

Commenters contended that EPA has not provided a model SIP for states or offered any 

guidance as to the policies allowed in a SIP. Commenters stated that guidance should detail how 

states can diversify and de-carbonize their energy portfolios with renewable energy, which 

provides the greatest long-term benefit to public health, national security, and our economy.

Comment 6: Commenters stated that most of the work assessing the CPP will fall on state air 

regulators who are ill equipped for the work.

Response 6: In section VIII.C.2, the EPA notes it is proposing model rules for both mass-based 

and rate-based emission trading programs.

Regarding RE and rate-based emission plans, the EPA addresses considerations for incorporating 

CO2 emission reduction measures in state plans in section VIII.K of the preamble to the final 

rule. The commenters will find the EPA has clarified which actions count and when such actions 

count generally in section VIII.K.1 and more specifically in section VIII.K.3 on EM&V 

requirements for RE resources used to adjust a CO2 rate. Evaluation, measurement, and 

verification (EM&V) requirements for RE, including tracking systems, are specifically addressed 

in section VIII.K.3.

The following are summaries of the specific public comments under this comment:

Commenters contended that most of the work assessing the CPP will fall on state air regulators 

who are ill equipped for the work.

Comment 7: Comments stating that the EPA provided inadequate guidance and consideration of 

the regional systems currently in place to manage electricity in rural non-coal producing, no-coal 

fired generation with the boarders of Idaho.

Response 7: In section VIII.C on state plan approaches, EPA clarifies that states may adopt and 

submit either of two different types of state plans. The first would apply all requirements for 

meeting the emission guidelines to affected EGUs in the form of federally enforceable emission 

standards, which we refer to as an "emission standards" state plan type. The second, which we 

refer to as a "state measures" plan type, would allow the state mass CO2 emission goals to be 

achieved by affected EGUs in part, or entirely, through state measures that apply to affected 

EGUs, other entities, or some combination thereof, such as a RPS. These two types of state plans 

and their respective approaches allow states to meet the statutory requirements of CAA section 

111(d) while accommodating the wide range of regulatory requirements and other programs that 

states have deployed or will deploy in the electricity sector that reduce CO2 emissions from 

affected EGUs. 
491

Under the emission standards state plan type, one approach is a rate-based emission standard for 

affected EGUs, which may include use of emission trading and ERCs. The EPA anticipates the 

use of emission trading in state plans, due to the advantages of this approach.

ERCs may be issued for qualifying measures. Qualifying measures that can be used to adjust the 

CO2 emission rate of an affected EGU are discussed at subsection VIII.K.1, and include RE, 

demand-side EE, and other measures, such as DSM, CHP and incremental nuclear generation.

The EPA defines an ERC in the emission guidelines as a tradable compliance instrument that 

represents a zero-emission MWh from a qualifying measure that may be used to adjust the 

reported CO2 emission rate of an affected EGU subject to a rate-based emission standard in an 

approved state plan under CAA section 111(d). The sole purpose of an ERC is for use by an 

affected EGU in demonstrating compliance with a rate-based emission standard in such an 

approved state plan.

An ERC is issued separately from any other instruments that may be issued for a MWh of energy 

generation or energy savings from a qualifying measure. Such other instruments may be issued 

for use in meeting other regulatory requirements (e.g., such as state RPS and EERS 

requirements) or for use in voluntary markets. An ERC may be issued based on the same data 

and verification requirements used by existing REC and EEC tracking systems for issuance of 

RECs and EECs.

The EPA addresses considerations for the use of the BSER and non-BSER measures to achieve 

an emission rate-based standard in section V.A.5 and V.A.6 of the preamble to the final rule. For 

RE measures, section V.A.5.a(3) specifies that an owner/operator of an affected EGU can either 

acquire ERCs through common ownership of RE generating capacity, a bilateral transaction with 

the owner/operator of the RE generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized market.

The following are summaries of the specific public comments under this comment:

Commenters contended that there has been inadequate guidance and consideration of the 

regional systems currently in place to manage electricity in rural non-coal producing, no-coal 

fired generation with the boarders of Idaho. Commenters contended that the CPP increases 

complexity to systems that have been put into place over a long period of time and cannot be 

quickly or simply changed to obtain compliance from your new rule mandates and very shortterm compliance schedule.

Comment 8: Comments supporting the EPA to provide incentives to states that have already met 

the renewable energy target so they can continue to promote renewable energy.

Response 8: Under the emission standards state plan type, one approach is a rate-based emission 

standard for affected EGUs, which may include use of emission trading and ERCs. Under a 

mass-based emission standard, trading of emission allowance is another approach. The EPA 

anticipates the use of emission trading in state plans, due to the advantages of this approach.
492

The following are summaries of the specific public comments under this comment:

Commenters supported incentivizing states that have already met the renewable energy target to 

continue promoting renewable development and consider the "added" renewable generation as an 

overall contribution to the regional renewable energy target so it would better align with current 

market structures for RES.

Comment 9: Comments supporting incorporating outside the fence measures within the building 

block approach for reducing emissions.

Response 9: The EPA addresses the general accounting approach for adjusting a CO2 emission 

rate in section VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified MWh from qualifying zeroemitting and low-emitting resources, as described in sections VIII.K.1.a. These MWh are added 

to the denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower 

adjusted CO2 emission rate.

The following are summaries of the specific public comments under this comment:

Commenters supported incorporating outside the fence measures within the building block 

approach for reducing emissions. Commenters stated that this provides a flexible framework for 

states to decide how best to achieve their emission rate reduction targets effectively including the 

use of renewable energy and energy efficiency cost. Commenters concluded that allowing states 

to use renewables and efficiency for compliance is a smart strategy that builds on the successes 

of what states are already doing and have been doing for more than a decade.

Comment 10: Comments that the EPA should incorporate life cycle costs into how each type of 

energy production is incentivized.

Response 10: EPA did not prescribed specific approaches like life cycle cost accounting. In 

section VIII.C on state plan approaches, EPA clarifies that the types of state plans which states 

may adopt and submit allow states to meet the statutory requirements of CAA section 111(d) 

while accommodating the wide range of regulatory requirements and other programs that states 

have deployed or will deploy in the electricity sector that reduce CO2 emissions from affected 

EGUs.

Regarding RE and rate-based emission plans, the EPA addresses considerations for incorporating 

CO2 emission reduction measures in state plans in section VIII.K of the preamble to the final 

rule. The commenters will find the EPA has clarified which actions count and when such actions 

count generally in section VIII.K.1 and more specifically in section VIII.K.3 on EM&V 

requirements for RE resources used to adjust a CO2 rate. Requirements for rate-based emission 

trading programs and the issuance and tracking of ERCs, including qualifying RE measures, 

programs or projects and addressing the potential for interactions between ERCs and RECs, are 

addressed in section VIII.K.2.
493

The following are summaries of the specific public comments under this comment:

Commenters requested EPA to incorporate life cycle costs into how each type of energy 

production is incentivized.

Comment 11: Comments suggesting that the EPA clarify in its section 111(d) guidance that a 

broad variety of credible state clean energy programs are acceptable in state plans to achieve 

compliance with applicable performance standards.

Response 11: In section VIII.C on state plan approaches, the EPA clarifies that states may adopt 

and submit either of two different types of state plans. The first would apply all requirements for 

meeting the emission guidelines to affected EGUs in the form of federally enforceable emission 

standards, which we refer to as an "emission standards" state plan type. The second, which we 

refer to as a "state measures" plan type, would allow the state mass CO2 emission goals to be 

achieved by affected EGUs in part, or entirely, through state measures that apply to affected 

EGUs, other entities, or some combination thereof, such as a RPS. These two types of state plans 

and their respective approaches allow states to meet the statutory requirements of CAA section 

111(d) while accommodating the wide range of regulatory requirements and other programs that 

states have deployed or will deploy in the electricity sector that reduce CO2 emissions from 

affected EGUs. 

Under the state measures plan type, state measures must be satisfactorily described in the 

supporting material for a state plan submittal. The supporting material would need to 

demonstrate that the state measures meet the same integrity elements that would apply to 

federally enforceable emission standards. Specifically, the state plan submittal must demonstrate 

that the state measures are quantifiable, verifiable, enforceable, non-duplicative and permanent. 

These requirements are described in more detail at section VIII.D.2.

The following are summaries of the specific public comments under this comment:

Commenters requested EPA clarify through its Section 111(d) guidance that a broad variety of 

credible state clean energy programs are acceptable in state plans to achieve compliance with 

applicable performance standards. Commenters suggested that the state would work with its 

public utility commission, environmental regulator and other state institutions to develop the 

plan. Commenters continued that the state would analyze whether its current resource plans and 

state clean energy programs would meet its emission targets. Commenters added that if the 

current programs are achieving sufficient progress in reductions, the state would submit its plans. 

Commenters also stated that if the resource plans show that the current plans and state clean 

energy programs would not meet the Section 111(d)-based targets, the state would consider 

whether to adopt more or more stringent clean energy programs or whether plant-based measures 

may be necessary. 
494

5.5 REPORTING AND RECORDKEEPING FOR DEMAND-SIDE ENERGY 

EFFICIENCY PROGRAMS AND MEASURES

This section addresses comments on Reporting and Recordkeeping for Demand-Side Energy 

Efficiency Programs and Measures. We have organized the comments in this section under two 

subsections, 5.5.1 and 5.5.2. Responses to the comment topics of these subsections are discussed 

below along with summaries of the specific public comments.

5.5.1 Reporting for EE programs and measures

This section discusses the reporting requirements for energy efficiency programs and measures,

including content of reports and timing, and the broader topic of emission monitoring and 

verification (EM&V).

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments urging the EPA to defer recordkeeping and reporting requirements to 

states, since states should be allowed to implement 111(d) programs in the most efficient manner 

possible.

Response 1: The EPA disagrees with the commenters and is not deferring recordkeeping and 

reporting requirements. State plans must contain requirements for tracking and reporting actual 

plan performance during implementation, which includes reporting of CO2 emissions from 

affected EGUs. Affected EGUs must comply with emissions monitoring and reporting 

requirements that are largely incorporated from 40 CFR part 75 monitoring and reporting 

requirements. The majority of affected EGUs are already familiar with the reporting 

requirements of part 75, and because of this, the EPA has chosen to streamline the applicable 

reporting requirements for affected EGUs under the state plans in the final rule. For more 

information on recordkeeping and reporting requirements, see section VIII.F.1 of the preamble to 

the final rule.

The following are summaries of the specific public comments under this comment:

Several commenters urged, for similar reasons, for EPA to defer recordkeeping and reporting 

requirements to states, as the states should be allowed to implement 111(d) programs in the most 

efficient manner possible. Commenters argued that the proposed rule imposes excessive 

reporting requirements, and in some cases the state plan requirements being proposed go beyond 

SIP requirements for the NAAQS. Commenters further stated that some components of the 

proposed state plan requirements exceed EPA's legal authority under CAA section 111, 

continuing that EPA's role in the state plan process is oversight and approval, not 

implementation. Commenters stated that EPA's State Plan TSD did little more than summarize 

current efforts by states to address reporting and recordkeeping requirements being used to 
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implement existing RE and EE programs. Commenters contended that the TSD also suggests that 

EPA might require more information than these current programs require, but argued that EPA 

provided no basis for requiring additional information. Commenters further argued that EPA's 

goals are based on a Building Block analysis of what states are currently achieving through their 

own RE and EE programs, so therefore it is unreasonable for EPA to also find that these very 

same programs are insufficiently reliable due to their reporting and recordkeeping requirements.

Commenters stated that EPA should lower the cost of compliance by minimizing new regulatory 

burdens on states through reliance on existing reports from EE authorities within a state where 

sufficient to demonstrate implementation. 

Commenters noted that they have already developed an automated software system solution for 

EE data management and reporting, and urged EPA not to designate the use of specific software 

that would undermine the work they have already done to improve accuracy and efficiency of EE 

data collection. Commenters stated that they expect minimum reporting requirements, but 

encouraged EPA to review existing state reporting programs to help set such minimum 

requirements. Commenters offered to provide EPA more information or to arrange a 

demonstration of their EE data management and reporting system.

Commenters stated that some state-run energy efficiency programs (i.e. the Guaranteed Energy 

Savings Program (GESP) and Local Energy Efficiency Program (LEEP)), will have 

measurement and verification protocols as built in requirements. Commenters stated that it is 

their goal to aggregate these savings through the Buildings, Benchmarking and Beyond (B3) tool 

and measurement and verification reporting, and the use of designated software or reporting 

requirements by the EPA should be avoided.

Commenters recommended that EPA provide states with reporting flexibility because utilities 

may have different fiscal year periods that are used to track compliance with EE targets.

Commenters added that utilities should not be penalized with additional recordkeeping and 

reporting requirements solely because they use a different fiscal year than another utility.

Comment 2: Comments suggesting that the EPA should promote standardized data collection, 

reporting and EM&V practices for EE. Commenters recommend various existing tools and 

documents to enable this.

Response 2: The EPA appreciates this comment. The EPA recognizes that there are many states 

with established EM&V methods to determine energy savings from demand-side EE programs 

using existing protocols, guidelines, and guidance documents. The EPA heard overwhelmingly 

from commenters that such protocols, guidelines, and guidance documents are currently in wide 

use, and that this use should be continued and encouraged in the context of state plans. The 

agency agrees with this observation and therefore supports their use in generating ERCs in 

emission standard plans and adjusting rates in state measures plans. The EPA’s proposed 

approach provides flexibility to states on EM&V approaches as long as EM&V meets a 

minimum level of credibility, and the EM&V approach is robust, transparent, and systematic.
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The following are summaries of the specific public comments under this comment:

Commenters urged EPA to require standardized treatment of EE in state plans, including data 

collection, reporting, and EM&V practices.

Commenters noted that they had invested significant resources to program evaluation, and had in 

many cases enlisted regional and national groups in helping develop uniform protocols.

Commenters stated they were pleased to see their work acknowledged in the proposal, but urged 

EPA to require rigorous standardized treatment of EE in state plans. Commenters recommended 

EPA develop a common terminology among states, and suggested using the glossary developed 

by DOE/EPA State and Local Energy Efficiency Action Network in its publication, "Energy 

Efficiency Program Impact Evaluation Guide," Appendix A. The complete reference for this 

document is: Glossary of Terms, Version 2.1, A project of the Regional Evaluation, 

Measurement and Verification Forum, Prepared by Paul Horowitz PAH Associates, Facilitated 

by Northeast Energy Efficiency Partnerships. 

https://www4.eere.energy.gov/seeaction/system/files/documents/emv_ee_program_impact_guide

_0.pdf.

Commenters stated that not all EE programs are created equally, and suggested a new screening 

effort, called the Resource Value Framework (RVF) which provides a tool for public utility 

commissions to ensure their cost-effectiveness tests are balanced, transparent, and account for 

public policy goals. Commenters urged EPA to recommend states use RVF to test their 111(d) 

compliance for cost-effectiveness.

Comment 3: Comments suggesting that the EPA develop a nation-wide registry of EE measures, 

such as that proposed by The Climate Registry. Commenters also suggested recommendations on 

EE reporting for non-PUC regulated programs; additional reporting elements for EE activities; 

and interim period reporting frequency.

Response 3: Regarding the proposal of a national EE registry, the EPA’s proposed approach 

provides flexibility to the states on how to design their registries and therefore will not require 

states to submit to a national registry of EE measures. To ensure the credibility of state registries 

for trading programs, the EPA provides recommended criteria in the draft EM&V guidance 

document. The EPA is also providing a template for an EM&V plan in its draft EM&V guidance 

document.

The EPA addresses the general accounting approach for adjusting a CO2 emission rate in section 

VIII.K.1 of the preamble to the final rule. The reported CO2 emission rate of an affected EGU 

may be adjusted based on quantified and verified MWh from qualifying zero-emitting and lowemitting resources, as described in sections VIII.K.1.a. These MWh are added to the 

denominator of an affected EGU’s reported CO2 emission rate, resulting in a lower adjusted CO2

emission rate. Under all types of state plans, states must ensure that the measures and associated 

CO2 emission reductions counted as part of meeting their plan requirements are not duplicative 

of any measures that are counted by another state. Interstate effects make this more difficult 

because states may be responsible for the deployment of measures that have effects on 
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generation and emissions beyond the state borders. Depending on how these measures are 

accounted for, the reductions could be counted by both the state that deployed the measure, and 

the state that reports a reduction in fossil generation or reported emissions.

States with rate-based plans must demonstrate that the RE and demand-side EE that they use to 

adjust their CO2 emission rate are non-duplicative. Double-counting of MWhs in the 

denominator can be avoided because adding the MWh that the affected EGU is responsible for 

deploying to the denominator is relatively straightforward to quantify and assign, and aligns well 

with the MWh-denominated trading system described in this final rule. As long as it is assured 

that the MWhs of RE and demand-side EE are only being claimed by one state, as is outlined in 

section VIII.C.2, then there is no double-counting of MWh.

The following are summaries of the specific public comments under this comment:

Commenters urges EPA to develop a nation-wide registry of EE measures, such as that proposed 

by The Climate Registry (TCR). Commenters noted that a flexible nation-wide registry would 

provide a consistent framework to track and report realized EE savings and could serve as the 

foundation for an energy efficiency crediting and trading platform. Commenters stated that this 

would also provide EPA confidence that energy savings are being reported across states in a 

consistent and comparable manner. Commenters noted that TCR has established a roadmap for 

developing and implanting an EE registry in the white paper: An Energy Efficiency Registry; a 

Flexible and Transparent way to Track and Report Energy Efficiency under the Clean Power 

Plan.

Commenters said that states will need guidance from EPA on how to aggregate data from 

private-sector delivered EE, such as IEE, to be counted as a compliance mechanism. 

Commenters suggested that a national registry could be created for this purpose, as it would be 

the most efficient approach with the greatest degree of consistency in all aspects of including 

project-related GHG reductions in 111(d) compliance. Alternately, commenters said, a SEO (or 

another designated Agency) can aggregate (directly or via a third party) data from all IEE 

projects in the state and determine the avoided emissions achieved. Commenters added that a 

state could choose to have a state-run or utility-run EE program aggregate data from IEE savings 

and, in such states, the state-run or utility-run program could choose to direct additional 

incentives to IEE projects to increase the quantity of cost-effective EE delivered. Commenters 

said that a national registry would be useful in eliminating any double-counting of GHG 

emission reductions from EE projects and, by identifying those measures or projects that 

benefited from a utility rate subsidy or other incentive, aggregators can ensure that GHG 

reductions are claimed only under the appropriate EE program for compliance purposes. 

Commenters said that by using a national registry, the EPA could ensure uniformity of EEderived GHG benefits , which would allow EE credit to be applied anywhere within a regional 

electric grid without creating a concern about double-counting of GHG reductions. Commenters 

stated this approach would eliminate the need for the EE penalty. Finally, Commenters said, a 

national or state-based registry function for IEE projects through 111(d) will help EPA establish 

a set of 111(d) compliance tools that will work in either a state-driven portfolio approach or an 

EGU-obligated compliance approach. 
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Commenters agreed that that a registry of performance contracting (PC) projects, maintained by 

a reputable third party which certifies the standards for both calculating and verifying project 

savings, will allow state air regulators to use performance contracting in their compliance plans, 

and will allow the EPA to evaluate these plans with confidence. Commenters stated that M&V 

can be performed by certified third party experts that include both the staff of national 

laboratories (for federal projects) and private sector companies, many of which have been 

providing services to public sector agencies that host PC projects for more than a decade. 

Commenters added that a registry can convert energy savings into units of CO2 reduction by 

using the certified savings from each project and conversion factors specified by the EPA or state 

air regulators. Commenters noted that a registry can also provide a standard bookkeeping method 

and a database of the certified savings for the life of the project. Finally, commenters said, a 

registry that can certify their project energy savings without exposing their projects to public 

disclosure can also encourage industrial customers to allow their projects to be used for state 

CPP compliance. 

Commenters described several other actions that should be taken to facilitate the use of IEE 

resources including the following: 

• Registration and verification including some sort of centralized registry 

and a credit trading system 

• Data standardization to ensure that M&V reports are prepared in a 

manner that enables effective and efficient evaluation of the program 

Commenters suggested that a statewide entity should be responsible for managing all energy 

efficiency programs, so that the plan could account also for electricity savings associated with 

savings of natural gas or propane use from programs like duct sealing and insulation.

Commenters noted concerns about varying EM&V reporting elements from state to state, as well 

as different formats, and recommended that EPA designate US DOE to develop a sample 

template reporting form. However, commenters added, consideration should be given to not 

creating additional burden to states in developing duplicative reporting where EE program 

administrators are already reporting to PUC, Energy Information Administration (EIA) and 

regional system planners. Commenters encouraged EPA to require certification of reported EE 

savings impacts, and that EPA should consider the value and role of a national EE registry, such 

as that proposed by TCR.

Commenters further suggested that EPA recognize that EE activities not necessarily be limited to 

PUC regulated programs, but could include other types of state EE activities, such as municipal, 

community, or private investments. Commenters stated EPA should enable state plan and 

reporting requirements to incorporate or include a range of EE activities.

Commenters recommended EPA require reporting of the following additional information with 

regard to state's EE activities covered under their state plan:

• Description of any modifications to program implementation relative to that specified 

in the compliance plan (i.e., changes in measures or programs);
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• If applicable, a description of variations between expected and realized savings 

caused by either applying the latest EM&V results or on differences in the measures 

installed.

Commenters also offered suggestions on frequency of reporting, notably that EPA require 

interim reporting during the 2020-2030 timeframe so states can demonstrate progress towards 

their EE goals and avoided emissions. Commenters added that this interim reporting should be 

on a 3-year basis, starting in 2022.

5.5.2 Other

This section contains comments on reporting and recordkeeping of end-use energy efficiency 

programs and measures that do not fit in section 5.5.1.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics.

Comment 1: Comments on record retention period and opposing retention of "on site" electronic 

files when facilities use an offsite central location for electronic record storage and backup.

Response 1: The EPA is finalizing that states must include in their plans a record retention 

requirement for affected EGUs of not less than 5 years following the date of each compliance 

period, compliance true-up period, occurrence, measurement, maintenance, corrective action, 

report, or record, whichever is latest,. that affected EGUs must maintain each record onsite for at 

least 2 years after the date of the occurrence of each record and may maintain records offsite and 

electronically for the remaining years. Each record must be in a form suitable and readily 

available for expeditious review. The EPA finds that these final recordkeeping requirements are 

appropriate and consistent with the requirements for other CAA section 111(d) emission 

guidelines. See section VIII.D.2 of the preamble to the final rule for more information.

Affected EGUs must comply with emissions monitoring and reporting requirements that are 

largely incorporated from 40 CFR part 75 monitoring and reporting requirements. The majority 

of affected EGUs are already familiar with the reporting requirements of part 75, and because of 

this, the EPA has chosen to streamline the applicable reporting requirements for affected EGUs 

under the state plans in the final rule. For more information on recordkeeping and reporting 

requirements, see section VIII.F.1 of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters opposed the proposed 10-year record retention period for all of the supporting 

information, unless EPA can show a special need as required under the Paperwork Reduction 

Act regulations. 5 C.F.R. section 1320.5(d)(2)(iv). Commenters continued to explain that, unless 

the EPA or a state intend to audit the accuracy of a certified report by referencing supporting 

information, they should do so within a reasonable period of time (e.g., 3 years). Commenters 
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noted that Part 75 contains a 3-year record retention requirement, and that EPA has not provided 

any information in the proposal to suggest that this time period is not adequate. Commenters 

suggested that compliance with Part 75 recordkeeping requirements should be sufficient for state 

plan approval.

Commenters opposed the proposed on-site requirement if it means that retention of electronic 

records that can be accessed "on site" (even if they are physically located offsite) would not be 

sufficient. Commenters stated that facilities may use an offsite central location for electronic 

record storage and backup, and that as long as the facility can access the information on site, 

there is no reason for the electronic records to be physically located there.
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5.6 REPORTING AND RECORDKEEPING FOR RENEWABLE ENERGY PROGRAMS 

AND MEASURES

This section addresses comments on reporting and recordkeeping renewable energy programs 

and measures. We have organized the comments in this section under 7 different subsections, 

5.6.1 to 5.6.7. Responses to the comment topics of these subsections are discussed below along 

with summaries to the specific comments.

5.6.1 Reporting for renewable energy programs and measures

This section discusses issues with the proposed reporting requirements renewable energy 

programs. The comments in this section address quantification and verification procedures.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments suggesting that the EPA defer to states as to how emission reductions 

are verified and quantified in order to allow flexibility.

Response 1: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. Evaluation, 

measurement, and verification (EM&V) requirements for RE are specifically addressed in 

section VIII.K.3. This section of EPA’s final emission guidelines require that all RE providers 

demonstrate that they will quantify and verify MWh using best-practice EM&V approaches. One 

way to make this demonstration is to use the presumptively approvable EM&V approaches 

specified in the proposed Model Rule in section IV.D.8. States may also submit other means of 

meeting the EM&V requirements so long as the state satisfactorily demonstrates in the state plan 

submittal that such alternative means of addressing requirements are as stringent as the 

presumptively approvable approach. 

Section VIII.K.1.a addresses how emission reduction measures that provide substitute generation 

for affected EGUs are counted in rate-based state plans. This section describes the basic 

accounting method for adjusting a CO2 emission rate. The section also describes general 

eligibility requirements for measures that may be used for adjusting a CO2 emission rate. Section 

VIII.K.1.b. addresses measures that may not be used to adjust the CO2 emission rate of an 

affected EGU in a state plan, and explains the basis for this exclusion. The measures included in 

sections VIII.K.1.a.(3)-(10) are not exhaustive. A measure that is not specifically discussed in 

this section VIII.K.1 may be included in a state plan, provided the measure meets all 

requirements specified in the emission guidelines. 
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Section VIII.K.1 also discusses the basic accounting method for adjusting the reported CO2

emission rate of an affected EGU, through the use of measures that substitute for or avoid 

generation from affected EGUs. That method is based on adding MWh from such measures to 

the denominator of an affected EGU’s reported CO2 emission rate (lb CO2 /MWh). Those 

additional MWh are based on quantified and verified electricity generation or electricity savings 

from eligible measures.

The following are summaries of the specific public comments under this comment:

Commenters supported the need to ensure that greenhouse gas emission reductions are quantified 

and verified. Commenters (encouraged EPA to defer to the states as to how the quantification 

and verification are done. Commenters (stated that flexibility in determining quantification and 

verification methods and requirements will allow states to utilize, modify, add-to and build-on 

established state or multi-state practices. Commenters added that flexibility is also needed to 

account for differences among and within the building blocks, such as project scale, numbers, 

location, incremental cost implications, as well as the feasibility and availability of direct and 

indirect quantification and verification methods may vary among and within the building blocks. 

Commenters stated that tailoring of quantification and verification procedures will be especially 

important to avoid unnecessarily restricting the use of decentralized, on-site renewable energy 

and energy efficiency tools that can assist in meeting greenhouse gas emission goals when used 

in appropriate situations. Commenters suggested several sources of information for quantifying, 

monitoring and verifying renewable energy and demand-side energy efficiency for GHP systems. 

Commenters contended that GHP systems are appropriate for inclusion in State Implementation 

Plans and requested that any future EPA guidance allow for their inclusion under a streamlined 

review process. 

Commenters stated that while it is important for states to retain flexibility under the proposed 

rule, such flexibility must have limits, particularly regarding states abilities to develop their own 

evaluation, measurement and compliance calculations.

Comment 2: Comments suggesting that the EPA provide a consistent approach for states to 

calculate compliance.

Response 2: The EPA addresses considerations for incorporating CO2 emission reduction 

measures in state plans in section VIII.K of the preamble to the final rule. Evaluation, 

measurement, and verification (EM&V) requirements for RE are specifically addressed in 

section VIII.K.3. This section of EPA’s final emission guidelines require that all RE providers 

demonstrate that they will quantify and verify MWh using best-practice EM&V approaches. One 

way to make this demonstration is to use the presumptively approvable EM&V approaches 

specified in the proposed Model Rule in section IV.D.8. States may also submit other means of 

meeting the EM&V requirements so long as the state satisfactorily demonstrates in the state plan 

submittal that such alternative means of addressing requirements are as stringent as the 

presumptively approvable approach.

The following are summaries of the specific public comments under this comment:
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Commenters contended that EPA should strengthen the proposed rule by providing a consistent 

approach for states to calculate compliance. Commenters cautioned that leaving states with 

discretion regarding compliance calculations (e.g., permitting states to calculate energy 

efficiency and renewable energy using an avoided emissions or an avoided generation approach) 

may result in states seeking the compliance calculation most favorable to them and potentially 

weaken actual carbon reductions.

5.6.2 Typical Reporting and Compliance Requirements under State RPS

This section discusses reporting and recordkeeping requirements in State Plans. The comments 

in this section address incorporating new recordkeeping and reporting requirements in state 

plans, compliance during times of major interruptions, the use of alternative compliance payment 

mechanisms to support compliance, and concerns that energy efficiency improvements will 

become legally enforceable.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: State plans should/should not specify new periodic reporting requirements.

Response 1: The EPA addresses state plan performance demonstrations in section VIII.F and 

specifies reporting requirements for affected EGUs in VIII.F.1. The EPA finalizes that states can 

choose to set shorter compliance periods for their emission standards but no longer than the 

compliance periods the EPA is finalizing in this rulemaking. 

As for having affected EGUs report directly to the EPA and the state, affected EGUs must 

comply with emissions monitoring and reporting requirements that are largely incorporated from 

40 CFR part 75 monitoring and reporting requirements. The majority of affected EGUs are 

already familiar with the reporting requirements of part 75, and because of this, the EPA has 

chosen to streamline the applicable reporting requirements for affected EGUs under the state 

plans in the final rule. The EPA believes that the final monitoring and reporting requirements 

(via EPA's Emission Collection and Monitoring Plan System or ECMPS) address the issue of 

duplicative requirements and alleviate concern about lost flexibility raised by commenters.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. Evaluation, measurement, and 

verification (EM&V) requirements for RE are specifically addressed in section VIII.K.3. This 

section of EPA’s final emission guidelines require that all RE providers demonstrate that they 

will quantify and verify MWh using best-practice EM&V approaches. One way to make this 

demonstration is to use the presumptively approvable EM&V approaches specified in the 

proposed Model Rule in section IV.D.8. States may also submit other means of meeting the 

EM&V requirements so long as the state satisfactorily demonstrates in the state plan submittal 
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that such alternative means of addressing requirements are as stringent as the presumptively 

approvable approach.

The following are summaries of the specific public comments under this comment:

Commenters agreed that a state plan should specify appropriate periodic reporting requirements 

for each affected entity in a state plan that will be electronically reported at least biennially and 

disclosed on a state database accessible by the public and EPA. Commenters stated that reports 

should be submitted directly by the affected entities to EPA and the state. Commenters contented 

that there is no basis for EPA's assertion that more stringent reporting and recordkeeping 

requirements might be required than in current state programs. Commenters added that EPA's 

assertions that supplemental reporting information may be necessary or that additional 

information may be valuable do not establish that such information is actually needed or 

valuable. Commenters recommended that EPA should defer to the states, as appropriate under 

section 111(d), and refrain from attempting to circumscribe state discretion. Commenters added 

that EPA’s Plan TSD does little more than summarize current efforts by states to address 

reporting and recordkeeping requirements used to implement existing state RE and EE programs. 

Commenters contended that it was unreasonable for EPA to rely on RE and EE programs at 

states for the purpose of developing state goals, and, at the same time, to find those programs 

insufficiently reliable due to the robustness of their reporting and recordkeeping requirements.

Comment 2: Comments regarding compliance during times of major interruptions in low and no 

CO2 emitting energy generation.

Response 2: The EPA addresses considerations for short-term events in section VIII.G.2 of the 

preamble to the final rule. See Section VIII.G.2.e on a short-term reliability safety valve. As a 

result, states can draft plans that allow adequate compliance flexibility to accommodate shortterm events. Additionally, compliance can be demonstrated over 2-3 years (see section VIII.F, 

State Plan Performance Demonstrations).

The following are summaries of the specific public comments under this comment:

Commenters contended that EPA should create a mechanism or exception for compliance in the 

event of major interruptions in low- and no- CO2 emitting energy generation. Commenters stated 

that generation produced by nuclear plants, wind farms, photovoltaics, hydropower plants and 

other low- or zero-emitting sources may be reduced during an exceptional event such as 

flooding, drought, tornado, earthquake, or wildfire. Commenters concluded that such events 

should be treated similarly to exceptional events that lead to National Ambient Air Quality 

Standards violations.

Comment 3: Comments regarding the use of Alternative Compliance Payment mechanisms to 

support compliance.
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Response 3: EPA did not address specific approaches or measures like RPS policies with 

alternative compliance payments. In section VIII.C on state plan approaches, EPA clarifies that 

the types of state plans which states may adopt and submit allow states to meet the statutory 

requirements of CAA section 111(d) while accommodating the wide range of regulatory 

requirements and other programs that states have deployed or will deploy in the electricity sector 

that reduce CO2 emissions from affected EGUs.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. For more information about specific RE 

measures to adjust the CO2 emission rate of an affected EGU to reflect RE, including eligibility 

dates and the types of RE MWhs that are eligible, see Section VIII.K.1. Requirements for ratebased emission trading programs and the issuance and tracking of ERCs, including qualifying 

RE measures, programs or projects and addressing the potential for interactions between ERCs 

and RECs, are addressed in section VIII.K.2.

The following are summaries of the specific public comments under this comment:

Commenters contended that a state policy should have strong compliance enforcement 

mechanisms to ensure targets are achieved. Commenters suggested that an Alternative 

Compliance Payment (ACP) is often used to support compliance with current RPSs. 

Commenters explained that an ACP effectively establishes a market ceiling for the price paid for 

renewable energy. Commenters added that if set below the cost of renewable energy, market 

participants would likely pay the ACP amount rather than invest in actual renewable energy 

production. Commenters stated that this effect can be mitigated in the regulatory process by 

establishing different standards for rate recovery covering the utilities fixed and variable costs, 

i.e. providing greater certainty of cost recovery for energy procurement versus the ACP 

alternative. Commenters added that the ACP level will also influence the kind of renewable 

energy developed. Commenters explained that renewable energy technologies are at different 

stages of development, serve varying market needs, and often are at different price points. 

Commenters added that many states have established carve-outs or other mechanisms to develop 

a broader array of resources with ACPs set at points to move a particular market class (e.g. wind 

or solar) or segment (e.g. residential or commercial). Commenters continued that in certain 

states, ACP payments are paid into a renewable energy fund that will facilitate capital

deployment to renewable energy initiatives. Commenters then added that to the extent a state 

policy has carve-outs for specific technologies, ACP policies should also direct capital to those 

specified technologies when ACP payments are triggered. Commenters concluded that the effect 

of a wide variation in treatment by technologies is to funnel financing into proven technologies 

that are treated the same across state borders.

Comment 4: Compliance and energy efficiency improvements that become legally enforceable. 

Response 4: The EPA addresses considerations for state plan components and approvability 

criteria in section VIII.D of the preamble to the final rule. In VIII.D.1, the EPA clarified that by 

not finalizing the portfolio approach, which would have allowed states to include enforceable 

measures in a state plan that apply to entities that are not affected EGUs, the agency is not 
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providing additional guidance on federal enforceability of measures that might apply to such 

entities. As proposed, the EPA is requiring that state plans include a demonstration that plan 

measures are enforceable, which for emission standard plans is discussed in section VIII.D.2.b.4 

and for state measures plans is discussed in section VIII.D.2.c.6.

The following are summaries of the specific public comments under this comment:

Commenters stated that the rule appears likely to result in compliance obligations imposed on 

renewable energy providers and electrical power system end-users that states will draw on to 

help utilities meet their emission limits and the states targets. Commenters expressed concern 

that their mills that are able to improve their energy efficiency and could thereby help states meet 

their emission reduction goals could become subject to legally enforceable requirements attached 

to those improvements. Commenters urged EPA to assure that those facilities will not be subject 

to additional requirements in any future CO2 performance standard for their specific sector.

5.6.3 Typical Reporting for Renewable Energy Deployment Programs

The comments in this section address the use of reverse auction mechanisms as a compliance 

mechanism.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are also provided for these topics. 

Comment 1: Comments regarding the use of Reverse Auction Mechanisms.

Response 1: EPA did not prescribed specific approaches or measures like reverse auction 

mechanisms. In section VIII.C on state plan approaches, EPA clarifies that the types of state 

plans which states may adopt and submit allow states to meet the statutory requirements of CAA 

section 111(d) while accommodating the wide range of regulatory requirements and other 

programs that states have deployed or will deploy in the electricity sector that reduce CO2

emissions from affected EGUs.

The EPA addresses considerations for incorporating CO2 emission reduction measures in state 

plans in section VIII.K of the preamble to the final rule. The commenters will find the EPA has 

clarified which actions count and when such actions count generally in section VIII.K.1. and 

more specifically in section VIII.K.3 on EM&V requirements for RE resources used to adjust a 

CO2 rate.

The following are summaries of the specific public comments under this comment:

Commenters indicated that states may procure renewable energy contracts via reverse auction 

mechanisms (RAMs). Commenters stated that RAMs are intended to encourage developers to 

build projects in the highest-capacity regions, and, generally, utilities solicit developers to bid in 

projects at the lowest $/MWh price. Commenters indicated that international experience suggests 
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that (1) RAMs are successful at encouraging developers to build in the highest-capacity 

locations; and (2) RAMs, if implemented without adequate pre-screening criteria, may succeed 

in elicit low-cost bids, only to see many of these bids fail to be built as the contract prices leave 

developers without sufficient incentive to build the project to completion.

5.6.4 Reporting for utility administered renewable energy incentive programs

[No comments were received on this topic.]

5.6.5 Reporting for renewable energy incentive programs administered by non-profit or 

state entities

[No comments were received on this topic.]

5.6.6 Considerations for reporting requirements for renewable energy measures in state 

plans

[No comments were received on this topic.]

5.6.7 Other

[No comments were received on this topic.]
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