Technical Support Document (TSD) for 

Carbon Pollution Guidelines for Existing Power Plants: 

Emission Guidelines for Greenhouse Gas Emissions from Existing Stationary Sources: Electric 

Utility Generating Units 

Docket ID No. EPA-HQ-OAR-2013-0602 

State Plan Considerations 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

June 2014 

 
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Table of Contents 

I. Introduction ........................................................................................................................3 

II. Description of State Plan Pathways .................................................................................4 

A. Direct Emission Limits .............................................................................................6 

B. Portfolio Approach ....................................................................................................8 

III. Enforceability Considerations under Different State Plan Scenarios .........................12 

A. Parties Regulated by the State other than Affected EGUs ......................................13 

B. Private or Public Third-Party Entity not Regulated by the State ............................15 

C. State Agency, Authority, or Entity ..........................................................................16 

D. Multi-State Approaches ..........................................................................................17 

IV. Incorporating End-Use Energy Efficiency and Renewable Energy Programs and 

Measures under a Rate-Based Approach ......................................................................19 

A. Concept of Adjusting EGU CO2 Emission Rates based on the Effects of End-Use 

Energy Efficiency and Renewable Energy ..................................................................19 

B. Approaches for Adjusting EGU CO2 Emission Rates ............................................20 

C. Methods and Tools for Quantifying Avoided CO2 Emissions from End-Use Energy 

Efficiency and Renewable Energy .........................................................................23

V. Quantification, Monitoring, and Verification of End-Use Energy Efficiency and 

Renewable Energy Programs and Measures .................................................................32 

A. Quantification, Monitoring, and Verification for End-Use Energy Efficiency .....35 

B. Quantification, Monitoring, and Verification for Renewable Energy Measures ...45 

VI. Reporting and Recordkeeping for End-Use Energy Efficiency and Renewable 

Energy Programs and Measures ....................................................................................71 

A. Reporting for End-Use Energy Efficiency Programs and Measures .....................72 

B. Reporting for Renewable Energy Programs and Measures ...................................74 

VII. Treatment of Interstate Emission Effects ......................................................................79 

A. Background ............................................................................................................81 

B. Summary of Possible Approaches for Treatment of Interstate Emission Effects..83 

VIII. Appendix ...........................................................................................................................92 

 
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I. Introduction

As discussed in the preamble, in section VIII.F, the EPA is proposing to give states 

broad discretion to develop state plans that best suit their circumstances and policy objectives. In 

developing its plan, a state will need to make a number of decisions that will require careful 

consideration, in order to ensure that its plan both meets a state’s policy objectives and is 

approvable by EPA. The preamble, in section VIII.F, identified several key decision points and 

factors that states should consider when developing their plans. In this section of the preamble, 

the EPA also raised a number of considerations for how it will apply the proposed general plan 

approvability criteria to different types of state plan approaches. This includes a number of 

considerations related to appropriate approaches, methods, and materials that are submitted for 

state plan components in an approvable plan, under different types of state plans. This technical 

support document (TSD) explains and discusses these considerations in depth, and elaborates 

options proposed in the preamble where relevant. Topics addressed in this TSD include: 

 Description of state plan pathways 

o Provided as context for the discussion of applied considerations that follows 

 Enforceability considerations under different plan scenarios 

o Summary of potential enforceable mechanisms under different state plan 

scenarios 

 Incorporating energy efficiency and renewable energy (EE/RE) requirements and 

programs in state plans, including: 

o Options for adjusting EGU CO2 emission rates based on the effect of EE/RE 

requirements and programs 

o Methods for estimating avoided CO2 emissions that result from EE/RE 

requirements and programs 

 Quantification, monitoring, and verification of EE/RE requirements and programs 

o Survey of quantification, monitoring, and verification under existing state and 

utility EE/RE requirements and programs 
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o Discussion of possible approaches for minimum requirements or guidance for 

quantification, monitoring, and verification for EE/RE requirements and programs 

included in state plans, building off existing state processes and infrastructure 

o Discussion of areas where supplemental information would be useful for 

estimating avoided CO2 emissions from EE/RE requirements and programs 

 Reporting and recordkeeping for responsible parties subject to EE/RE requirements or 

implementing EE/RE programs included in state plans 

o Survey of reporting and recordkeeping under existing state and utility EE/RE 

requirements and programs 

o Discussion of possible approaches for EE/RE reporting requirements for state 

plans, building off existing state processes and infrastructure 

o Discussion of areas where supplemental information would be useful for 

estimating avoided CO2 emissions from EE/RE requirements and programs 

 Treatment of interstate emission effects 

o Further elaboration of proposed approaches and alternatives discussed in the 

preamble 

It should be noted that the preamble discusses, and solicits comment on, legal issues 

concerning whether CAA section 111(d) authorizes some of the types of state plans described in 

this TSD and whether it authorizes state plans to include some of these types of measures. This 

TSD does not further discuss those legal issues, but solely for the purpose of describing all of the 

available types of state plans and measures, assumes that all of them are authorized under CAA 

section 111(d). 

II. Description of State Plan Pathways

As discussed in the preamble, the EPA is proposing a state plan approach that could 

accommodate a diverse set of state requirements, programs, and measures, through two basic 

approaches – direct emission limits and a portfolio approach. These two basic approaches 

provide four distinct state plan “pathways” under CAA section 111(d). These pathways include: 
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 Rate-based CO2 emission limits applied to affected EGUs; 

 Mass-based CO2 emission limits applied to affected EGUs; 

 A state-driven portfolio approach 

 A utility-driven portfolio approach 

Under this flexible approach, a state plan could include a combination of measures that reduce 

CO2 emissions at affected EGUs through the application of emission limits as well as measures 

that involve actions within the interconnected electricity system that reduce utilization at affected 

EGUs and thereby avoid EGU CO2 emissions. Examples of these latter measures include, among 

others, end-use energy efficiency resource standards and renewable energy portfolio standards, 

as well as certain components of utility integrated resource plans. A state could either rely solely 

on CO2 emission limits that are enforceable against affected EGUs or, alternatively, rely on a 

portfolio approach, which would include those limits as well as other enforceable measures. 

Table 1 provides practical examples of possible state plan approaches under each of these 

pathways, which are discussed in more detail below. 

This section elaborates the different plan approaches that are discussed in section VIII.B 

of the preamble, to provide context for the applied considerations that are discussed throughout 

the remainder of the TSD. In particular, some of these considerations apply to different types of 

state plan approaches. For example, section III of this TSD addresses enforceable legal 

mechanisms that might apply under different types of state plans, such as utility- and state-driven 

portfolio approaches, which would apply enforceable obligations to different entities. Section IV 

of this TSD applies to state plans that implement rate-based CO2 emission limits for affected 

EGUs that also provide for the adjustment of CO2 emission rates based on the effect of 

enforceable end-use energy efficiency and renewable energy requirements and programs that are 

incorporated in a plan. Section V of this TSD addresses quantification, monitoring, and 

verification of end-use energy efficiency and renewable energy programs and measures. 

Considerations addressed in this section would apply to states implementing a rate-based 

emission limit approach that provides for adjustment of CO2 emission rates based on the effect of 

end-use energy efficiency and renewable energy, as well as states implementing utility- or state-
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driven portfolio approaches that incorporate end-use energy efficiency and renewable energy 

requirements and programs. Likewise, section VI of this TSD addresses considerations for 

reporting and recordkeeping for end-use energy efficiency and renewable energy requirements 

and programs, which would apply for these types of state plans. 

Table 1. Different Illustrative Plan Approaches 

 

A. Direct Emission Limits 

The first basic state plan approach is CO2 emission limits that apply directly to affected 

EGUs, and includes two pathways: 1.) rate-based CO2 emission limits applied to affected EGUs; 

and 2.) mass-based CO2 emission limits applied to affected EGUs. For both types of emission 

limits, end-use energy efficiency and renewable energy measures that avoid EGU CO2 emissions 

could be a major component of a state’s overall strategy for cost-effectively reducing EGU CO2

emissions. 
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1. Rate-Based CO2 Emission Limits Applied to Affected EGUs 

Rate-based emission limits would apply a lb CO2/MWh emission limit to affected EGUs. 

Depending on a state’s approach, compliance flexibility could be provided through different 

mechanisms, such as averaging among affected sources, or the use of tradable credits for avoided 

CO2 emissions resulting from end-use energy efficiency and renewable energy measures as 

discussed below. In the case of the latter approach, such credits could be used by an affected 

EGU to adjust its CO2 emission rate when demonstrating compliance with a rate-based emission 

limit.1

 Rate-based emission limits could be implemented on a state-by-state basis, or through 

multi-state averaging or trading. Rate-based emission limits might also be a component of a 

portfolio approach (described below), where the emission rate limit would not assure full 

achievement of the required level of emission performance specified for affected EGUs in the 

state plan, in which case the emission limit would be supplemented with other enforceable 

measures. 

Rate-based emissions limits could incorporate end-use energy efficiency and renewable 

energy measures that avoid EGU CO2 emissions, through an administrative adjustment by the 

state or tradable crediting system.2 These adjustment credits could be used by an affected EGU to 

comply with the rate-based emission limit, by adjusting the unit’s reported CO2 emission rate.3

Under this approach, end-use energy efficiency and renewable energy measures that avoid EGU 

CO2 emissions would be enforceable components of a state plan. These actions would need to be 

enforceable components of a state plan to provide assurance that a sufficient amount of 

                                                            

1

 Section IV of this TSD discusses possible approaches for such adjustments. 2

 Under a tradable credit system, a state would issue adjustment credits based on avoided CO2 emissions achieved 

through end-use energy efficiency and renewable energy measures. EGUs could then apply these tradable 

adjustment credits when demonstrating compliance with a rate-based CO2 emission limit. These tradable credits 

might be issued to affected EGUs for free or through purchase. Alternatively, end-use energy efficiency and 

renewable energy actions undertaken by private parties (including EGU owners and operators) might be eligible for 

the issuance of adjustment credits. Under an administrative adjustment approach, a state program administrator 

might administratively adjust an affected EGU’s CO2 emission rate based on avoided CO2 emissions achieved 

through state end-use energy efficiency and renewable energy deployment programs or utility compliance with 

energy efficiency resource standards or renewable energy portfolio standards. These adjustments might be 

apportioned to affected EGUs based on a predetermined metric. Affected EGUs would then begin with an adjusted 

CO2 emission rate when considering additional actions necessary for compliance with the rate-based CO2 emission 

limit. 

3

 Section IV of this TSD discusses possible approaches for such adjustments. 
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adjustment credits will be available to facilitate EGU compliance with the emission rate limit, 

and that end-use energy efficiency and renewable energy measures that generate adjustment 

credits are properly quantified, monitored, and verified.4

2. Mass-Based CO2 Emission Limits Applied to Affected EGUs 

Mass-based emission limits would apply either an individual limit on CO2 tons emitted 

from an affected EGU or establish a finite CO2 emissions budget for a group of affected EGUs. 

The latter approach is typically implemented through a tradable allowance system. 

With mass-based emission limits, end-use energy efficiency measures that avoid EGU 

CO2 emissions could be a major component of a state’s overall strategy for cost-effectively 

reducing EGU CO2 emissions, but would be complementary to the enforceable state plan (i.e., 

not included as enforceable measures in a state plan). These actions could be used to help a state 

cost-effectively achieve the CO2 emissions limits, or to achieve other policy goals, but CO2

emissions performance would be assured through the enforceable limit on mass emissions from 

affected EGUs. 

B. Portfolio Approach 

The second basic state plan approach uses a portfolio of actions, in which a state plan 

includes multiple programs and measures that are designed to achieve either a rate-based or 

mass-based emissions performance goal for affected EGUs. This approach includes two 

pathways: 1.) a state-driven portfolio approach; and 2.) a utility-driven portfolio approach. A 

portfolio approach would include emission limits for affected EGUs along with other enforceable 

end-use energy efficiency and renewable energy measures that avoid EGU CO2 emissions. A 

portfolio approach could be state-driven or utility-driven, depending on the utility regulatory 

structure in a state. 

In general, a portfolio approach is distinguished from an emission limit approach by the 

fact that achievement of the full level of required emission performance for affected EGUs 

                                                            

4

 Section V of this TSD addresses considerations for quantification, monitoring, and verification of end-use energy 

efficiency and renewable energy measures. 
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specified in the plan is not ensured through the application of direct emission limits that apply to 

affected EGUs. 

A portfolio approach would include both direct emission limits that apply to affected 

EGUs and other indirect measures that avoid EGU CO2 emissions. Under a portfolio approach, 

end-use energy efficiency and renewable energy measures that avoid EGU CO2 emissions would 

be enforceable components of a state plan. This would be necessary because the emission limit 

applied directly to affected EGUs would not assure full achievement of the required level of 

emission performance specified in the state plan.5

As discussed below, due to differences in state utility regulatory structure, a portfolio 

approach implemented in a restructured state with retail competition will likely look quite 

different from one implemented in a state with vertically integrated, regulated electric utilities. 

This includes the process for developing the portfolio approach, the mechanisms for 

implementing it, the responsible parties, and the regulatory and legal relationships among parties 

and state regulators. 

1. State-Driven Portfolio Approach 

 A state-driven portfolio approach – rather than a utility-driven approach – is more likely 

to be adopted in a state with a restructured electricity sector. In these states, rate-regulated 

electric utilities have typically divested electric generation assets and there is often also retail 

competition where non-utility entities can supply retail customers with electricity.6

 Electric 

distribution utilities in these states typically purchase electricity from competitive wholesale 

markets. As a result, utilities in these states typically do not engage in a utility integrated 

resource planning (IRP) process. IRP processes, which are a natural fit for implementing a 

                                                            

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 Under a portfolio approach, either a rate-based or mass-based emission limit might be applied. Such plans might 

also include application of a direct emission limit to a subset of affected EGUs. Both scenarios would necessitate 

inclusion of supplemental measures, such as end-use energy efficiency and renewable energy, or other measures that 

directly apply to affected EGUs (e.g., repowering or retirement of one or more high-emitting EGUs), in order to 

achieve the required level of emission performance for affected EGUs specified in the state plan. 6

 In some restructured states, the holding company that owns the distribution utility may also own generating assets 

which are operated on a competitive basis. In these instances, there typically are legal provisions in place that 

mandate the independent management and operation of generation and distribution assets. 
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portfolio approach, are much more common in states with regulated vertically integrated utilities 

that own and operate electric generating assets. 

In restructured states, policies for increasing end-use energy efficiency and renewable 

energy are often established through regulations that apply to electric distribution utilities, such 

as end-use energy efficiency resource standards and renewable portfolio standards. Many of 

these states have also established independent non-profit entities to administer end-use energy 

efficiency and renewable energy deployment programs funded through regulated electricity 

rates. 

Under a state-driven portfolio approach a mix of entities might have enforceable 

obligations under a state plan. This includes owners and operators of affected EGUs subject to 

direct emission limits, as well as electric distribution utilities, private or public third-party 

entities, and state agencies or authorities that administer end-use energy efficiency and 

renewable energy deployment programs or are subject to portfolio requirements. 

2. Utility-Driven Portfolio Approach 

A state with vertically integrated, state-regulated electric utilities is more likely to adopt a 

utility-driven portfolio approach. In such states, private utilities own and operate electric 

generation, transmission, and distribution systems necessary to supply retail customers with 

electricity.7

 These utilities are overseen by state public utility commissions that approve utility 

capital investments and oversee utility operations, and allow utilities to recover approved 

investments and operating costs, along with a specified financial rate of return, through regulated 

retail electricity rates. State utility commissions often require regulated utilities to engage in an 

integrated resource planning (IRP) process, which seeks to identify the least-cost set of resources 

available to provide electricity to retail customers over a multi-year period, and often includes 

evaluation of measures such as end-use energy efficiency, demand-side management, and 

                                                            

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 In some instances these regulated utilities may supplement electric generation with purchases through wholesale 

electricity markets and may also sell surplus generation in these wholesale markets on a competitive basis. 
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renewable energy.8 Once an IRP is approved by a state public utility commission, a utility’s cost 

recovery and rate of return is often linked to identified measures and metrics in the IRP.9

Under a utility-driven portfolio approach, a vertically integrated utility would develop 

and implement a portfolio of measures designed to meet the rate-based or mass-based emission 

performance level for its affected EGUs specified in the state plan. This plan would likely be 

developed and approved through an IRP-like process overseen by the state public utility 

commission. If there is more than one rate-regulated electric utility in the state, the state might 

apportion the state emission performance level for affected EGUs among utilities. 

A utility plan under this approach might rely heavily on end-use energy efficiency and 

renewable energy actions, but also might focus on direct actions at affected EGUs, such as 

repowering to fire a lower-carbon fuel or retirement of high-emitting units. Such plans might 

also include direct emission limits on affected EGUs, or implementation of an environmental 

dispatch approach that incorporates CO2 emission rate into the dispatch protocol used by the 

utility to schedule electric generation.10

Under a utility-driven portfolio approach, the entire suite of obligations under the plan 

would be enforceable against the utility company, which would also be an owner and operator of 

affected EGUs. If there are other affected EGUs in the state that are not owned and operated by a 

vertically integrated utility, a state plan might need to include other measures that address CO2

emission performance by these affected EGUs. 

A similar approach could be taken by municipally owned utilities or utility cooperatives, 

which often also engage in an IRP process. However, state public utility commissions (PUCs) 

                                                            

8

 Depending on the state, an IRP process may also assess factors such as fuel diversity and environmental 

performance, among others, when identifying the least-cost mix of resources for a utility. 9

 In some cases, an IRP prescribes or authorizes specific actions. In others, an IRP serves as a guide for the utility 

and the public utility commission when evaluating acquisition or implementation of specific utility resources or 

programs. In such cases, the specific resource or program is approved through a PUC order that authorizes or

requires actions and identifies performance obligations. These orders may or may not be fully consistent with 

provisions in an IRP.

10 Vertically integrated utilities, even if they operate within the footprint of a competitive wholesale electricity 

market, may self-schedule generation assets.
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often do not regulate these utilities. As a result, implementation of a portfolio approach by these 

entities would introduce practical enforceability considerations under a state plan. 

III. Enforceability Considerations under Different State Plan Scenarios 

As discussed in the preamble of the proposal, in section VIII.F.1, a state plan must 

include enforceable measures. To ensure that its plan is enforceable, a state will need to: 

 Identify in its plan the entity or entities responsible for meeting compliance and other 

enforceable obligations under the plan 

 Include mechanisms for demonstrating compliance with plan requirements or 

demonstrating that other binding obligations are met 

 Provide a mechanism(s) for legal action if affected EGUs are not in compliance with plan 

requirements or if other entities fail to meet enforceable plan obligations 

As discussed in the preamble, responsible entities in an approvable state plan may include 

an owner or operator of an affected EGU, other entities with responsibilities assigned by a state, 

or the state itself. Other entities might include an entity that is regulated by the state, such as an 

electric distribution utility, or a private or public third-party entity. State responsibility might 

include obligations that are assumed directly by a state agency, authority, or other state entity to 

carry out aspects of a state plan. 

While this approach provides states with broad discretion to develop plans that best suit 

their circumstances and policy objectives, assigning responsibility to other parties regulated by 

the state, private or public third-party entities, or state entities raises enforceability 

considerations. This section discusses how the general enforceability approach discussed in the 

preamble, and described above, might apply in practice under different state plan approaches. 

This section describes possible scenarios of responsible entities and legal mechanisms 

and approaches that might be used to address enforceability considerations under different types 

of state plans. These scenarios were developed to capture the range of entities that are currently 

implementing end-use energy efficiency and renewable energy deployment programs in states, or 

are subject to states requirements such as end-use energy efficiency resource standards (EERS) 
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or renewable portfolio standards (RPS). For each of these examples, this section describes 

current legal relationships between these entities and the state, and discusses possible legal 

instruments that might provide the state with the authority to ensure that obligations in a state 

plan are met and to address failure to meet those obligations. The mechanisms discussed take 

different forms, but would specify the three elements described above: obligations, compliance 

demonstration, and enforcement mechanisms. This section also discusses enforceability 

considerations in cases where states act jointly through a multi-state plan. 

A. Parties Regulated by the State other than Affected EGUs 

One likely state plan scenario involves inclusion of enforceable obligations for stateregulated entities other than affected EGUs. An example of a state-regulated entity that is not an 

owner or operator of affected EGUs may be an electric distribution utility.11 These entities are 

typically regulated by a state public utility commission. An example of an enforceable state plan 

measure that might apply to an electric distribution utility is a compliance obligation under a 

state end-use energy efficiency resource standard (EERS) or renewable portfolio standard (RPS), 

or implementation of incentive programs for the deployment of end-use energy efficiency and 

renewable energy technologies. 

Another example is where a vertically integrated, state-regulated utility implements a 

portfolio of enforceable actions under a state plan, which may include actions that apply directly 

to affected EGUs as well other actions such as end-use energy efficiency and renewable energy 

deployment programs. While vertically integrated utilities may own and operate affected EGUs, 

some of the measures implemented may require different enforceability mechanisms than an 

emission limit applied to an affected EGU. 

 

                                                            

11 Electric distribution utilities are also often referred to as local distribution companies (LDCs). Here we refer to an 

electric distribution utility as an entity that owns and operates an electric distribution network but is not the owner 

and operator of EGUs. As discussed further, vertically integrated utilities own and operate electric distribution 

networks as well as EGUs. 
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1. Electric Distribution Utility with Obligations to Meet an EERS or RPS Pursuant 

 to State Regulations 

EERS and RPS requirements are typically implemented through state regulations, but 

may also be implemented through a public utility commission order. State EERS and RPS 

regulations provide legal instruments generally comparable in enforceability to regulatory 

emission limits applied to EGUs. These regulations typically specify compliance obligations, 

reporting, and enforcement. However, many state RPS regulations and some EERS regulations 

include alternative compliance payment (ACP) provisions that provide the utility with the option 

of making a payment in lieu of full compliance with the portfolio requirement. Thus, state EERS 

and RPS mandates may not guarantee achievement of a given level of end-use energy efficiency 

or renewable energy deployment during a plan performance period.12

2. Vertically Integrated Electric Utility with Obligations under a State-Approved 

Integrated Resource Plan 

A utility integrated resource plan (IRP) may include a number of direct and indirect 

actions that affect EGU CO2 emissions, and may also include compliance with EERS and RPS 

regulations. Broadly, IRPs may prescribe or authorize actions for which utilities can recover 

capital investments and operating costs through regulated retail electricity rates.13 This creates 

strong financial incentives for implementing an action, but may not mandate an action. 

For a state plan under this scenario, an enforceability consideration is whether an IRP, 

and related public utility commission orders, must include additional requirements to implement 

                                                            

12 We note that some direct emission limits for CO2 emissions include somewhat similar provisions. For example, 

both the RGGI state CO2 emission budget trading programs and the California GHG emission budget trading 

program include cost containment provisions where more emission allowances are made available to affected 

sources at certain allowance price thresholds. In both these instances, such relevant characteristics of the state 

regulations would need to be taken into account when projecting the CO2 emission performance that will be 

achieved by affected EGUs under the state plan. 

13 In some cases, an IRP prescribes or authorizes specific actions. In others, an IRP serves as a guide for the utility 

and the public utility commission when evaluating acquisition or implementation of specific utility resources or 

programs. In such cases, the specific resource or program is approved through a PUC order that authorizes or 

requires actions and identifies performance obligations. These orders may or may not be fully consistent with 

provisions in an IRP. 
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certain actions, beyond denial of rate recovery or a change to utility tariffs if a utility fails to 

meet specified obligations in the IRP. If so, this may require state legislation to provide 

additional authority to state public utility commissions in some states, or confer additional 

authority to other agencies (e.g., a state environmental agency). 

B. Private or Public Third-Party Entity not Regulated by the State 

Another state plan scenario involves public or private third-party entities with 

enforceable obligations under a state plan. A private or public third-party entity could be a utility 

entity that is not regulated by a state public utility commission, such as a municipal utility or a 

utility cooperative.14 It could also be a private non-profit entity established to administer end-use 

energy efficiency and renewable energy deployment programs.15 In most cases, since they often 

expend electricity ratepayer funds, such non-profit entities are created by state legislation and 

overseen by state public utility commissions or state-regulated private utilities. 

An appropriate legal instrument or agreement applicable to such entities included in a 

state plan might include legal arrangements similar to those currently used to establish 

independent entities that expend electricity ratepayer dollars in multiple states. For entities not 

subject to state oversight, such a mechanism might also include mechanisms where an entity 

voluntarily submits to the authority of a state, pursuant to state statutory or regulatory authority 

specified in a state plan. Such agreements might be attached to a funding source. For example, 

the entity would voluntarily submit to such authority as a condition of receiving certain funds, 

such as state appropriated funds or funds collected through state-regulated electricity rates. 

Alternatively, a municipal utility or utility cooperative might voluntarily submit to state authority 

as a condition of the state agreeing to let the entity implement a portfolio approach, in lieu of the 

application of certain direct CO2 emission limits for affected EGUs owned and operated by such 

entities through a state regulation. In some cases, new state statutory authority might be enacted 

                                                            

14 Here, “not regulated” refers to regulation of electricity rates by a state public utility commission. To the extent 

that such entities are owners and operators of affected EGUs, these EGUs may be subject to state environmental and 

other regulations. In some cases these utility entities are also subject to state EERS and RPS regulations, as specified 

under state law. 

15 Examples include the Energy Trust of Oregon, the Delaware Sustainable Energy Utility, and Efficiency Vermont. 
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to support a state plan, specifying enforceable obligations for these private or public third-party 

entities under the plan. 

An additional consideration is whether such legal instruments or agreements, if related to 

a renewable energy or end-use energy efficiency deployment program, should specify a stable 

budget authority and funding source through each plan performance period. Such authority and 

funding might be necessary to ensure that suitable funds are made available to achieve the level 

of energy savings or renewable energy deployment projected in the state plan, which may be 

necessary to achieve the level of emission performance by affected EGUs that is projected will 

be achieved through implementation of the plan. 

C. State Agency, Authority, or Entity 

 

This state plan scenario involves a state entity with an enforceable obligation in a state 

plan. For example, state authorities in some states implement renewable energy and end-use 

energy efficiency deployment programs.16 In this scenario, the requirement for the state entity 

would be an enforceable component of the state plan. 

One type of legal arrangement that might be applied under this scenario is legislation 

directing state executive branch agencies or independent state authorities to follow through on 

obligations under a state plan. 

Such legislation might provide independent legal authority under state law to compel 

executive branch actions, or actions by independent state authorities under the plan, if 

obligations are not met. Depending on the form of legislation, this could also provide citizens 

with the ability to compel state action under state law, if obligations are not met under a state 

plan.17

                                                            

16 A prominent example is the New York State Energy Research and Development Authority (NYSERDA), which 

administers energy efficiency and renewable energy deployment programs. 

17 We note that under the CAA, measures included in an approved 111(d) state plan would be federally enforceable 

by EPA, and that citizens would also have the ability to file citizen suits to compel enforcement of state plan 

obligations, under CAA Section 304 (42 U.S. Code Section 7604). 
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An additional consideration is whether such legal arrangements, if related to a renewable 

energy or end-use energy efficiency deployment program, should also specify a stable budget 

authority and funding source through the plan performance period, or other provisions, to ensure 

that programs are implemented as projected under the state plan. 

D. Multi-State Approaches 

 As discussed in the preamble, in section VIII.F.1, multi-state approaches introduce crosscutting enforceability considerations. 

For these multi-state approaches, states would demonstrate emission performance from 

affected EGUs in aggregate jointly with partner states. For states participating in a multi-state 

approach, the individual state performance goals in the emission guidelines would be replaced 

with an equivalent multi-state performance goal. For example, states taking a rate-based 

approach would demonstrate that all affected EGUs subject to the multi-state plan achieve a 

weighted average CO2 emission rate that is consistent, in aggregate, with an aggregation of the 

state-specific rate-based CO2 emission performance goals established in the emission guidelines 

that apply to each of the participating states. If states were taking a mass-based approach, 

participating states would demonstrate that all affected EGUs subject to the multi-state plan emit 

a total tonnage of CO2 emissions consistent with a translated multi-state mass-based goal. This 

multi-state mass-based goal would be based on translation of an aggregation of the state-specific 

rate-based CO2 emission performance goals established in the emission guidelines that apply to 

each of the participating states. 

1. Multi-State Emission Budget or Rate-Based Emission Trading Programs 

 

The Regional Greenhouse Gas Initiative (RGGI) is an example of a multi-state approach 

to regulation of CO2 emissions. Through this initiative, nine states are currently implementing 

coordinated CO2 emission budget trading programs. The program works as a coordinated 

regional whole through a shared emission and allowance tracking system and allowance auction 

process, but is implemented in accordance with materially consistent stand-alone state 

regulations and individual statutory authority. These regulations recognize CO2 allowances 
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18 

issued by other participating states for use by affected EGUs when complying with each state’s 

emission limitation, but contain all the necessary components to administer the program 

requirements on an individual state basis.18 As a result, while the initiative is implemented 

regionally, each CO2 emission budget trading program regulation is enforceable against affected 

EGUs at the state level and functions as a discrete program. 

As a result, a multi-state emission budget trading program approach, such as RGGI, is 

enforceable in practice at the state level. A multi-state rate-based emission trading program could 

also be established in much the same manner as a multi-state emission budget trading program, 

and could therefore be enforceable at the state level.19

2. Multi-State Portfolio Approaches 

 

A multi-state portfolio approach could introduce novel enforceability considerations. If it 

were based on interdependent emission reduction strategies among states that are not tied to 

emission limits that directly apply to affected EGUs, the emission performance of affected EGUs 

in one participating state may be dependent, in part, on actions taken in other participating states. 

If a state (or states) failed to implement commitments under the multi-state plan, this raises the 

question of whether the EPA should address non-performance of one or more participating states 

in the context of failure to achieve the required level of multi-state emission performance under 

the plan, or instead enforce actions at the individual state level for those states that are failing to 

meet commitments under the multi-state plan. 

 

                                                            

18 The emission limitation consists of a requirement to submit CO2 allowances equal to reported CO2 emissions 

during a compliance period. While states have individual emission budgets, representing the total number of 

allowances issued for a given year that are available for allocation, there are no individual state emission limits. The 

CO2 emission constraint is regional, based on the sum of state CO2 emission budgets. 

19 Enforceability would be contingent, in part, on states having comparable enforcement mechanisms. 
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19 

IV. Incorporating End-Use Energy Efficiency and Renewable Energy Programs and 

 Measures under a Rate-Based Approach 

A. Concept of Adjusting EGU CO2 Emission Rates based on the Effects of End-Use 

 Energy Efficiency and Renewable Energy 

As discussed in the preamble, in section VIII.F.3, the EPA is proposing that RE and 

demand-side EE requirements, programs, and measures may be incorporated into a rate-based 

plan approach.20 Measures that avoid CO2 emissions from affected EGUs, such as quantified and 

verified end-use energy savings and renewable energy generation, could be used to adjust the 

CO2 emission rate of an affected EGU when demonstrating compliance with a rate-based CO2

emission limit. Alternatively, a state could use the effect of such measures as a basis for 

administratively adjusting the average CO2 emission rate of affected EGUs when demonstrating 

achievement of the required emission rate performance level in a state plan. 

 Under this approach, affected EGUs could comply with a rate-based CO2 emission limit 

through actions at the EGU,21 as well as through the use of credits22 for actions that occur 

elsewhere in the interconnected electricity system that avoid CO2 emissions from affected EGUs. 

If a state is implementing a portfolio approach, then the state could administratively adjust the 

average CO2 emission rate of affected EGUs through a similar process when demonstrating 

achievement of the required emission rate performance level in the state plan. 

 This section explores in depth the mechanics and implications of the different possible 

approaches for adjusting CO2 emission rates that are summarized in the preamble. Aspects of 

this discussion may apply to both retrospective demonstration of CO2 emission performance 

                                                            

20 The EPA is also proposing that RE and demand-side EE measures could be used under a mass-based portfolio 

approach in an approvable state plan. However, the focus of this section is limited to application of such measures 

under a rate-based approach. 

21 This could include an individual affected EGU or group of affected EGUs if a rate-based averaging or trading 

approach is used. 

22 These credits could be tradable, or represent non-tradable credits administratively apportioned to affected EGUs. 

This latter approach effectively represents an administrative adjustment applied by the state. 
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20 

achieved by affected EGUs under an approved state plan and projections of CO2 emission 

performance by affected EGUs included in a submitted state plan. 

B. Approaches for Adjusting EGU CO2 Emission Rates 

As discussed in the preamble, credits or adjustment to an EGU CO2 emission rate, based 

on the effect of RE and demand-side EE programs and measures, might represent avoided MWh 

of electric generation or avoided tons of CO2 emissions.23 If adjustment or credits represent 

avoided MWh, they would be added to the denominator of the lb CO2/MWh emission rate when 

determining an adjusted lb CO2/MWh emission rate. If adjustment or credits represent avoided 

CO2 emissions, they would be subtracted from the numerator when determining an adjusted lb 

CO2/MWh emission rate. The approach chosen could affect the amount of credit or adjustment 

provided for RE and demand-side EE programs and measures. These implications are discussed 

below. 

1. Adjustment of CO2 Emission Rate based on Avoided MWh 

One approach is to adjust an EGU’s CO2 emission rate based on avoided MWh of 

generation from an EGU, or cohort of EGUs, resulting from RE and demand-side EE programs 

and measures.24 A MWh crediting or adjustment approach implicitly assumes that the avoided 

CO2 emissions come directly from the particular affected EGU (or group of EGUs) to which the 

adjustment or credits are applied. It assumes, in effect, that an additional emission-free MWh is 

being generated by that respective EGU, and that the RE or demand-side EE measure reduces 

CO2 emissions from that individual EGU or group of EGUs.25 In practice, the average or 

marginal CO2 emission rate in the power pool or identified region – representing the avoided 

CO2 emissions from the generating sources being displaced by a MWh of energy savings or a 

                                                            

23 The preamble solicits comment on the appropriateness of these different approaches, which are further elaborated 

in this section. 

24 It should be noted that this was the process used by EPA for incorporating end-use energy efficiency, renewable 

energy, and nuclear energy when calculating state CO2 emission performance goals for affected EGUs. As discussed 

in the preamble, states may have flexibility to use a different approach when demonstrating the effect of these 

measures in a rate-based state plan. 

25 As a result, the assumed avoided CO2 emissions from an individual MWh of energy savings or generation from 

renewable energy will differ based on the reported CO2 emission rate of the individual EGU to which the MWh is 

applied as an adjustment to its MWh output. 
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21 

MWh of renewable energy generation – could differ significantly from the calculated avoided 

CO2 emissions derived by adjusting the MWh output of an affected EGU. The following 

examples highlight these concepts. 

Example 1: Assume an EGU with a stack emission rate of 1,500 lb CO2/MWh generates 

1,000 MWh. Also assume that 1,000 emission-free MWh credits for the effect of demand-side 

EE measures are added to the denominator when calculating the EGU’s adjusted CO2 emission 

rate. The adjusted CO2 emission rate is 1,500,000 lb CO2 divided by 2,000 MWh, which equals a 

CO2 emission rate of 750 lb CO2/MWh. In this example, each MWh credit represents 750 lb of 

avoided CO2 emissions. 

Example 2: The same calculation applied to an affected EGU with a 2,000 lb CO2/MWh 

rate would yield a different result. In this instance the adjusted emission rate is 2,000,000 lb CO2

divided by 2,000 MWh, which equals a CO2 emission rate of 1,000 lb CO2/MWh. In this 

example, each MWh credit represents 1,000 lb of avoided CO2 emissions. 

2. Adjustment of CO2 Emission Rate based on Avoided CO2 Emissions 

An alternative approach is to provide an adjustment to the CO2 emission rate of an EGU, 

or cohort of EGUs, based on the estimated CO2 emissions that are avoided in the power pool or 

identified region as a result of RE and demand-side EE programs and measures. This approach 

acknowledges that the avoided CO2 emissions may come from the electric power pool or other 

identified region as a whole, rather than an individual EGU. The avoided CO2 emissions are 

determined based on the MWh saved or generated, multiplied by a CO2 emission rate for the 

power pool or region. 

This CO2 emission rate could be based on the average or marginal emission rate in the 

power pool, region, or state. A marginal avoided emission rate represents the generation that is 

displaced at the margin for every MWh saved or generated through an RE or demand-side EE 

program or measure. An average avoided emision rate is based on either all fossil generation in a 

region or total generation. This approach assumes that every MWh saved or generated equally 

displaces generation from every generator in a power pool or region. 
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Another approach that has been suggested by some stakeholders is crediting or 

adjustment based on the level of the rate-based emission limit for affected EGUs (or the overall 

rate-based level of emission performance for affected EGUs specified in a state plan). For 

example, under this approach, if the emission rate limit were 1,500 lb CO2/MWh, one MWh of 

energy savings or renewable energy generation would result in a credit or adjustment 

representing 1,500 lb of CO2 that could be subtracted from the numerator of an EGU’s CO2

emission rate. This approach assumes that affected EGUs jointly emit CO2 from the stack on an 

average basis at this required compliance level (i.e., consistent with a “closed” averaging 

system), and that a MWh saved or generated avoids CO2 emissions from affected EGUs at this 

average compliance level.26

3. Other Considerations 

Some of the CO2 emissions avoided through RE and demand-side EE measures may be 

from non-affected EGUs. This may result because affected EGUs are only a subset of the fossil 

fuel-fired EGU fleet, which also includes (or will include) existing non-affected fossil fuel-fired 

EGUs, such as simple-cycle combustion turbines used to meet peak demand, as well as new 

fossil fuel-fired EGUs subject to emission standards under CAA section 111(b). Furthermore, as 

the fleet capital stock slowly turns over, affected EGUs under section 111(d) will comprise a 

slowly shrinking subset of the total fossil fuel-fired EGU fleet. These dynamics may need to be 

addressed in a state plan when crediting or adjusting CO2 emission rates of affected EGUs based 

on the effects of RE and demand-side EE measures. The approaches described in more detail 

later in this section may be able make these distinctions between affected and non-affected fossil 

fuel-fired EGUs. 

 

                                                            

26 This outcome might be expected in a closed averaging system, without the use of crediting or adjustment for the 

avoided emission effects of RE and demand-side EE measures. In this instance an EGU that emitted above the 

compliance rate would need to average its performance with (or submit tradable credits obtained from) an EGU that 

performed below the required rate. On balance, all EGUs subject to the emission rate limit would perform at or 

below the compliance rate. 
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C. Methods and Tools for Quantifying Avoided CO2 Emissions from End-Use Energy 

 Efficiency and Renewable Energy 

1. Introduction 

There are a number of approaches for quantifying the avoided CO2 emissions resulting 

from end-use energy efficiency and renewable energy (EE/RE) programs, requirements and 

measures27 in the electric sector. These approaches range from the application of basic avoided 

emission rates to using sophisticated electric sector models.28 Annual average avoided emission 

rates have often been used for rough approximations of CO2 emissions avoided from reduced 

electric energy use.29 An annual average avoided emission rate assumes that EE/RE programs 

and measures reduce electric generation from all generating types on a proportional basis 

consistent with the generation mix in a region. A marginal emission rate represents the emission 

rate of an electric generating unit (EGU) or cohort of EGUs likely to be displaced by EE/RE 

measures (i.e., a marginal avoided emissions rate), based on the last unit(s) to come online to 

meet electricity load and the first unit(s) to be brought offline when electricity load is reduced. 

The primary question underlying estimating CO2 emissions reductions from EE/RE 

measures is the determination of which electric generators will be displaced (i.e., cease 

generation or reduce generation output) in the presence of incremental EE/RE. This section 

briefly describes a range of avoided emission rates approaches, their underlying assumptions, 

and considerations associated with the use of different avoided emission rate approaches. 

2. Average Emission Rate Approach 

An average emission rate (typically expressed in tons of CO2/MWh) is usually 

understood to mean the average of all generators’ emissions rates, weighted by annual 

generation. The rate (ravg) is calculated as: 

                                                            

27 As used here, the term “EE/RE measures” refers to any program actions or regulatory requirements that result in 

the increased use of energy-efficient equipment or practices, or renewable energy generating resources. 

28 Electric sector models include simulation dispatch models (i.e. production-cost models) and capacity expansion 

planning models. 

29 See, for example, EPA “Household Carbon Footprint Calculator,” available at 

http://www.epa.gov/climatechange/ghgemissions/ind-calculator.html. 
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ݎ௔௩௚ ൌ ∑௜ ݁௜

∑௜ ݃௜

Where: 

e = annual emissions (tCO2) from all sources i and 

g = annual generation (MWh) from all sources i. 

Because the average emission rate puts the sum of all generation in the denominator (as MWh), 

including nuclear, hydroelectric, and renewable generating resources, the rate fundamentally 

assumes that EE/RE reduces all generating types by an equal proportion, regardless of their type 

or contribution to the margin.30 EGUs are generally dispatched on an economic merit order, 

where the least-cost EGUs (on a variable cost basis) are dispatched first, and higher cost 

resources are dispatched later. Since nuclear, hydro, wind, and solar resources operate at a very 

low cost,31 they are generally dispatched before most fossil units.32 Under current and historical 

operating conditions, there are few circumstances in which non-fossil resources reduce output in 

the presence of lower demand. As a result, in states with a moderate contribution of non-emitting 

resources to total generation, the average emission rate may be lower than could reasonably be 

expected for reductions from EE/RE programs and measures.33 Conversely, in states that have 

significant baseload fossil generation and few non-emitting resources, a state-average emission 

rate may reflect an emission rate that is too high. This may occur by incorporating emissions 

from coal-fired EGUs that are less likely to reduce generation with a reduction in electricity load, 

compared with other lower-emitting fossil fuel-fired EGUs. 

                                                            

30 In other words, a two-percent reduction in energy use would cause all EGUs in the system to reduce generation 

output by two percent, including coal, gas, nuclear, hydro, and renewable generating resources. 

31 For representative variable costs for new EGU, see supporting documentation for the Electricity Market Module 

of the Annual Energy Outlook (AEO) 2013, table 8.2., “Cost and performance characteristics of new central station 

electricity generating technologies”. Geothermal, wind, and solar generating resources are assumed to have a 

variable operating cost of $0/MWh. Hydroelectric generating resources have an assumed variable operating cost of 

$2.60/MWh and incur no fuel cost, while nuclear generating resources have an assumed variable operating cost of 

$2.10/MWh (exclusive of fuel costs). In contrast, gas and coal units are assumed to have variable operating costs 

from $3-$7/MWh (exclusive of fuel costs. 

32 The exception is rare curtailment events for renewable resources when more energy is produced than required, and 

due to operational constraints, where wind turbines are stalled to maintain system energy balance. Renewable energy 

generators, such as wind and solar, are sometimes referred to as “non-dispatchable” resources, since the renewable 

energy resource is intermittent and these generators cannot be called upon to run when the renewable energy 

resource is unavailable. However, here we refer to economic dispatch of these resources at times when the 

renewable energy resource is available. In these instances, these generators are often one of the first resources to be 

called upon, due to their low variable operating costs. 

33 Counting hydroelectric, nuclear, and renewable resources in the denominator would render the emissions rate too 

low, and thus the avoided emissions smaller than actually realized. 
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3. Marginal Emission Rate Approach 

A marginal emission rate represents the emission rate of the EGU or cohort of EGUs 

likely to be displaced by EE/RE (i.e., an avoided emission rate). A marginal unit is the highestcost unit dispatched at any point in time.34 Under most circumstances, and at any given time, the 

marginal unit is the last unit to be brought online to meet electricity demand and the first unit to 

be brought offline when electricity load is reduced. Due to constraints on generating unit ramp 

rates35 and transmission availability, it is not uncommon for multiple units to be dispatched 

incrementally simultaneously, thus creating a cohort of marginal units. Marginal unit(s) change 

on a moment-to-moment basis, determined by load requirements and the variable cost of each 

unit available to generate another unit of power. A marginal unit can either be a unit brought 

online to meet load or may be an EGU that is already operating, but that is dispatched at a greater 

level of output to meet load. 

The marginal emission rate (rmarginal) can be expressed for any given hour (t) as a function 

of the difference between two distinct cases – the reference case (i.e., in the absence of 

incremental EE/RE programs and measures) and the change case, where the EE/RE programs 

and measures have been implemented. A formula describing this rate is written as follows: 

ݎ௟௔௡௜௚௥௔௠,௧ ൌ ∑௜ ݁௥௘௙,௜,௧ െ ∑௜ ݁ாாோா,௜,௧

∑௜ ݃௥௘௙,௜,௧ െ ∑௜ ݃ாாோா,௜,௧

Where: 

eref and eEERE = emissions (tCO2) from EGUs i in hour t in the reference case (ref) and the change 

case (EERE), respectively; and 

gref and gEERE = generation (MWh) from EGUs i in hour t in the reference case (ref) and the 

change case (EERE), respectively. 

                                                            

34 See EPA’s Roadmap for Incorporating EE/RE Policies and Programs in State Implementation Plans: Appendix B, 

available athttp://www.epa.gov/statelocalclimate/documents/pdf/overview_paper_4-28-2011.pdf 35 Ramp rate refers to the ability of an EGU to respond to increasing load, based on its ability to increase output. 

Ramp rates are typically determined by technology type, with some technologies, such as combustion turbines, able 

to more quickly increase output in response to increasing load. 
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26 

The magnitude of the EE/RE program and the EE/RE load impact shape36 is a key 

element in determining marginal emissions reductions. In order to obtain a valid estimate of the 

emission reduction effect of an EE/RE program, an annual marginal avoided emission rate 

should be calculated that reflects the EE/RE program’s load impact shape and magnitude. This 

annual marginal avoided emission rate may then be applied to other EE/RE programs with 

similar load impact shapes and magnitudes. The marginal emission rate is highly time sensitive, 

as are the impacts of EE/RE programs and measures. For example, the EGU that is on the margin 

and is most likely to be displaced from EE/RE in each hour of the year. In addition, different 

EE/RE programs may have very different load impact shapes,reducing energy requirements in 

different hours of the year. The interaction between the pattern of EGUs on the margin and the 

load impact shape of EE/RE programs and measures results in a specific marginal avoided 

emission rate. Applying an annual marginal avoided emission rate calculated based on the impact 

of one specific set of EE/RE programs and measures to another set of EE/RE programs and 

measures that is substantively different in timing or magnitude of energy savings or generation 

(i.e., with a different load impact shape and magnitude) may result in erroneous results (i.e. the 

assumption that the wrong EGUs are displaced).37

Several mechanisms have been proposed to estimate the marginal emission rate without 

the use of a formal electric dispatch simulation model. These mechanisms rely on historic hourly 

generation and emissions data, collected by EPA’s Clean Air Markets Division, to estimate 

hourly marginal emissions rates for a past historical year. The benefit of these mechanisms is that 

they are simple to apply, but (a) are difficult to verify or validate without the benefit of a formal 

model and (b) rely on historical data and patterns of dispatch, which may not represent future 

patterns of dispatch. 

                                                            

36 The load impact shape of an EE/RE program or measure is the hourly (or, if necessary, daily or seasonal) pattern 

of either energy savings from an EE program or measure, or generation from an RE generator that is supplied to the 

grid. 

37 For example, an EE program focused on measures that reduce peak electricity demand, such as more efficient air 

conditioning, or a solar RE program, may result in significant reductions in electricity use from the grid during peak 

demand hours, and little electricity use reduction during overnight “trough” hours. In contrast, an industrial EE 

program may result in a relatively constant electricity load reduction over most hours. An EE program focused on 

peak reduction measures may reduce generating output from primarily peaking units, while an EE program targeting

EE measures with a more constant load impact shape may significantly reduce baseload generation during overnight 

trough hours.
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4. Methods and Tools for Estimating Avoided CO2 Emission Rates and Avoided 

 CO2 Emissions 

4.1. Calculation Tool Method 

The EPA has developed a user-friendly tool to estimate the emission reduction impacts of 

EE/RE requirements, programs and measures. The AVoided Emissions and geneRation Tool 

(AVERT)38 was developed to help air quality planners quantify NOx and SO2 emission impacts, 

as specified in EPA’s Roadmap for Incorporating EE/RE Programs in NAAQS SIPs.39 AVERT 

can also be used to quantify the displaced CO2 emissions of EE/RE measures within the 

continental United States. 

The AVERT method uses historical hourly emissions rates based on recent the EPA data 

on fossil fuel-fired EGUs’ hourly generation and emissions reported through EPA’s Acid Rain 

Program.40 This method couples historical hourly generation and emissions with the hourly load 

reduction profiles of EE/RE programs and measures to determine hourly emissions reductions on 

the margin. AVERT can be used to estimate EE/RE-related emissions reductions in a current or 

near-future year. However, AVERT estimates for current or future years are based on historical 

behavior rather than projected economic behavior. As a result, AVERT does not use projections 

of future fuel or electricity market prices that affected EGU dispatch, and is therefore not an 

appropriate tool for longer-term projections. 

Users of AVERT can analyze how the different load profiles of a variety of EE programs 

and measures, as well as wind and solar technologies, affect the magnitude and location of CO2

emissions at the county, state, and regional level. AVERT has a flexible framework with a 

simple user interface designed specifically to meet the needs of state air quality planners and 

other interested stakeholders. 

                                                            

38 More information about AVERT, including documentation and a user’s manual, is available at 

(http://www.epa.gov/avert). 

39 See Appendix I of the Roadmap for Incorporating Energy Efficiency/Renewable Energy Policies and Programs, 

available at http://epa.gov/airquality/eere/pdfs/appendixI.pdf), for details about how this approach can be used in 

the different NAAQS SIP pathways. 

40 http://ampd.epa.gov/ampd/.
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28 

AVERT may be used to derive marginal emission reductions from historical generation 

and emissions data, which can be used to derive a marginal avoided CO2 emission rate. 

However, AVERT does not quantify average emissions rates. AVERT approximates historical 

dispatch behavior using a statistical algorithm. It does not represent transmission constraints, or 

significant changes in grid structures or future economic conditions. To estimate a recent 

historical marginal CO2 emissions reduction from existing EE/RE programs or measures, a user 

would input the MWh related to results from EE/RE programs or measures (representing either 

MWh of electricity savings or MWh of generation) in a representative historical baseline year as 

a positive increment to electricity load, and record the emissions incrementally added in the 

tool.41 The calculated marginal CO2 emission rate is the incremental CO2 emissions added by 

AVERT, based on historical EGU dispatch patterns, divided by the incremental MWh of EE/RE 

savings or generation input to AVERT as an increase in electricity load. This approach reflects 

the marginal impact of EE/RE measures based on historical recorded patterns of emissions and 

generation.42

4.2. Electricity Sector Modeling Method 

Quantification of avoided CO2 emissions from EE/RE requirements, programs, and 

measures can be achieved through retrospective modeling approaches. Models can be used to 

calculate avoided CO2 emissions by comparing actual realized EGU CO2 emissions to projected 

EGU CO2 emissions that would have occurred in a historical reference case that does not include 

implementation of the EE/RE that is being evaluated. The appropriate choice of model depends 

on the look-back period. For short look-back periods of one to three years, an electricity system 

simulation dispatch model can determine the marginal generation contribution to emissions in a 

                                                            

41 Because AVERT represents a historical baseline year, EE and RE programs that occurred in a past year are 

already recorded by the statistics of AVERT. To estimate the emissions impacts of historic EE/RE programs, a user 

would increase the load by the EE/RE increment to estimate what generation and emissions would have been in the 

reference case look-back year. 

42 AVERT reflects fuel and emission control technologies to the extent they have influenced dispatch during the 

base year chosen. However, AVERT cannot change dispatch based on future economic or regulatory conditions, 

such as expected fuel prices, emission allowance prices, or specific emissions limits. AVERT should not be used for 

this type of analysis. When used to review historical data, AVERT will capture the impact of historical fuel prices 

and other impacts on the variable cost of production, but cannot capture specific emission limits. 
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29 

historical reference case (i.e. absent incremental EE/RE programs).43 Over the short term, 

simulation dispatch models properly account for EGU economic dispatch considerations, such as 

fuel and emission allowance prices, and operational constraints, such as ramp rates, outages, and 

heat rate curves. Look-back periods beyond three to five years would benefit from use of a 

utility-scale capacity expansion and dispatch planning model to understand the change in build 

out of new generating capacity, as well as transmission and distribution infrastructure, and its 

impact on generation between the historical reference case and actual realized historical 

outcome. 

Electricity System Simulation Dispatch Models 

Quantifying the CO2 emissions reductions achieved by EE/RE measures through 

modeling of a near-term look-back period requires a counterfactual historical reference case 

model run, which examines how the electric system would have operated in the absence of the 

EE/RE emission reduction measures under consideration. The emissions projected in this model 

run may be compared against actual realized emissions during the historical period. The lookback model should be calibrated by running the same model with the EE/RE measures in place 

and comparing the outcome of that model against realized generation and emissions at an 

appropriate spatial scale.44

Simulation dispatch models can be readily run for historical years provided they are 

loaded with the accurate input assumptions, including actual historic fuel costs, emission 

allowance prices, and transmission constraints. While these models will not choose economically 

optimal EGU retrofit or retirement decisions, they will provide a change in EGU dispatch and the 

associated change in emissions across a large region in a more detailed manner than capacity 

expansion planning models. 

                                                            

43 “Reference case” here refers to the case in which additional incremental carbon emissions reduction mechanisms 

are not employed, in this case resulting from EE/RE programs and measures.

44 Generally, simulation models will not capture exact output of individual EGUs relative to reality due to a variety 

of factors, including outages and other non-economic considerations not reflected in the model. Therefore, a 

comparison at an individual EGU scale may not be meaningful, but aggregate emissions at a state or regional scale 

should be expected to be comparable. 
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30 

Simulation dispatch models may be most relevant as part of ex-post plan reporting, for 

estimating the avoided CO2 emissions from affected EGUs that occurred as a result of EE/RE 

measures included in a plan, during a specified plan reporting period. 

Utility-Scale Capacity Expansion and Dispatch Planning Models 

Quantifying the CO2 emissions reductions achieved by EE/RE measures through 

modeling over a longer-term look-back period requires a counterfactual historical reference case 

model run, which examines how the electric system would have operated and have been built 

out, in the absence of the EE/RE measures under consideration. The critical difference between 

this type modeling approach and the use of a simulation dispatch model is the assessment of 

changes made at the “build margin” – i.e., new additions to generating capacity that may have 

been avoided or compelled, or retirements of existing units that may not have occurred in the 

reference case. The emissions projected in this model run may be compared against actual 

realized emissions during the historical period. The look-back model should be calibrated by 

running the same model with the EE/RE measures in place and comparing the outcome of that 

model run against actual realized generation and emissions at an appropriate spatial scale. 

Capacity expansion and dispatch planning models could be run for a longer-term 

historical period to better reflect what the electricity system would have looked like in the 

absence of the EE/RE measures. When EE or RE resources have been added over the course of 

three to five years, these models will reflect how these resources have avoided new power plants, 

retrofits, or fuel switch decisions. Some models may also be able to reflect avoided transmission 

investments. 

Capacity expansion and dispatch planning models may be more relevant than simulation 

dispatch models for projecting the emission performance that will be achieved by affected EGUs 

under a plan. As discussed below, these models are able to assess both the “operating” and 

“build” margins that impact EGU CO2 emissions as the result of EE/RE measures. 

 
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31 

5. Considerations Associated with use of an Avoided Emissions Rate 

Operational versus Build Margin 

Avoided emission rates approaches that do not include a capacity expansion model all 

assume that EE/RE measures only impact the operational margin – i.e., they impact moment-tomoment operations of EGUs in the existing grid. While this is true, deployment of EE/RE over a 

period of years may have impacts beyond the operational margin. Deployment of significant 

EE/RE measures over time often impacts decisions to build new fossil generating capacity, retire 

existing aging generating capacity, and make different decisions about transmission expansion. 

These different decisions about what infrastructure to build or retire are known as the “build 

margin,” and may ultimately have a greater impact on long-term emissions outcomes than the 

operational margin. 

While a new wind farm brought online next year has an impact on patterns of generation 

from existing fossil EGUs, decadal-scale planning associated with a policy meant to encourage 

EE/RE has an impact on the choice of whether or not to pursue the construction of new fossil 

generating capacity. A utility pursuing aggressive EE/RE programs may avoid the construction 

of new fossil generating capacity and expansion of transmission and distribution capability, and 

may even allow the utility to retire non-economic generating units no longer required for 

generation or reliability purposes. 

The use of an avoided emissions rate calculated based on the operational margin alone 

may fail to represent the impact of EE/RE measures that occur at the build margin. This 

differentiation is particularly important in regions where the pursuit of EE/RE measures may 

result in the retirement of high-emitting, non-economic generating assets. The use of a capacity 

expansion and dispatch planning model would help accurately assess avoided emissions due to 

changes at both the build and operational margins. 

 
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Quantifying In-State versus Out-of-State Emissions Reductions 

The electric system is not confined by state boundaries, and emissions displaced by 

EE/RE measures may occur over a wide geographic area,45 including outside of the state that 

implemented the EE/RE measures. Without the use of a simulation dispatch model (or, under 

some circumstances, use of a tool such as AVERT)46 it can be challenging to attribute emissions 

reductions that occur within the implementing state versus emissions reductions that occur across 

state boundaries. If a state sought to recognize the effect of EE/RE measures and quantified 

emissions reductions using an approach that did not account for avoided emissions at an 

appropriate spatial scale, it may inappropriately account for emissions reductions that occur in 

other states, or conclude that all emissions reductions occur within the state’s boundaries.47 In 

interconnected areas in which some states pursue mass-based emissions reductions approaches 

through their state plans while other states pursue rate-based approaches that include adjustment 

or crediting for avoided CO2 emissions from implementation of EE/RE measures, avoiding 

double-counting of emission effects among states will be an important consideration when 

quantifying the avoided emissions resulting from EE/RE measures. These considerations are 

discussed below in section VII of this TSD. 

V. Quantification, Monitoring, and Verification of End-Use Energy Efficiency and 

Renewable Energy Programs and Measures 

As discussed in the preamble, in section VII.F.4, a key consideration for state plans is the 

process and requirements for quantifying, monitoring, and verifying the effect of renewable 

energy and demand-side energy efficiency measures that result in electricity generation or 

                                                            

45 See California Energy Commission, Emissions Reductions from Renewable Energy and Energy Efficiency in 

California Air Quality Management Districts (2011), available at 

(http://ucciee.org/downloads/CAEmissionsReductions.pdf). 46 AVERT captures the magnitude of in-state versus out-of-state emissions reductions, but may not be an accurate 

assessment tool for edge-cases –i.e. states that fall near the boundaries of the AVERT regions – because AVERT 

does not capture inter-regional transmission. 

47 In the simplest case, a state without any fossil generating capacity that implements EE/RE measures would cause 

emissions reductions in neighboring states, and none within its own borders. Similarly, a state with significant, 

predominantly baseload fossil generation may also cause little in-state emissions reductions from implementation of 

EE/RE measures because those emissions reductions may occur at marginal generators located outside of the state. 

Conversely, a state with significant marginal fossil generating capacity might realize reductions in emissions from 

EE/RE measures implemented in other states. These complications may arise regardless of if a state is a net importer 

or net exporter of energy. The key differentiation is if the state’s EGUs are generally on the margin relative to 

interconnected EGUs in neighboring states.
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33 

savings.48 In the preamble, the EPA seeks comment on the suitability of current state and utility 

quantification, monitoring, and verification approaches for end-use energy efficiency and 

renewable energy in the context of an approvable state plan, and on whether harmonization of 

state approaches, or supplemental actions and procedures, should be required in an approvable 

state plan. The preamble also discusses generally whether the EPA should establish good 

practice guidance for quantification, monitoring, and verification of renewable energy and 

demand-side energy efficiency measures included in an approvable state plan, and solicits 

comment on the content of such guidance. This section further elaborates these considerations 

discussed in the preamble. 

The type of quantification, monitoring, and verification for RE and demand-side EE 

programs and measures will depend on the state plan approach. For states implementing a massbased portfolio approach, the effect of renewable energy and demand-side energy efficiency 

requirements, programs, and measures in helping to achieve the required level of CO2 emission 

performance under a state plan will be directly evident in reductions in the monitored CO2

emissions from affected EGUs.49 In effect, the overall impact of these measures could be tracked 

through CO2 emission monitoring, reporting, and record-keeping requirements applied to 

affected EGUs. However, for states implementing a rate-based plan approach, an approvable 

plan will need to include quantification, monitoring, and reporting requirements related to RE 

and demand-side EE requirements, programs, and measures incorporated in a state plan. 

Utilities and states have conducted ongoing evaluation of end-use energy efficiency and 

renewable energy measures and programs for several decades. These evaluations, which include 

quantification, monitoring and verification of results, generally rely upon a well-defined set of 

industry-standard practices and procedures. However, measurement approaches vary by state 

based on multiple factors, including the measure and program type being evaluated, the level and 

                                                            

48 In particular, this consideration applies to states implementing a rate-based emission limit approach that provides 

for adjustment of CO2 emission rates based on the effect of end-use energy efficiency and renewable energy, as well 

as states implementing utility- or state-driven portfolio approaches that incorporate end-use energy efficiency and 

renewable energy requirements and programs. 

49 There could be exceptions, for example where a state plan includes acknowledgement of avoided CO2 emissions 

that occur outside state borders as a result of state plan measures. See section VII of this TSD for further discussion 

of the treatment of interstate effects. 
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34 

nature of regulatory oversight, the degree of state and utility experience with these measures and 

programs, and the overall magnitude of program impacts. 

This section of the TSD discusses current state and utility evaluation, monitoring, and 

verification approaches for end-use energy efficiency and renewable energy programs and 

mandates. This section also discusses the potential suitability of these approaches in the context 

of an approvable state plan, and whether harmonization of state approaches, or supplemental 

actions and procedures, might be warranted in an approvable state plan. In particular, this section 

discusses considerations related to the establishment of good practice guidance or requirements 

for quantification, monitoring, and verification of end-use energy efficiency and renewable 

energy measures for an approvable state plan. It also discusses the possible appropriate basis for 

and resources used to establish such guidance, if the EPA were to take this approach. This 

discussion includes consideration of existing state and utility protocols, as well as any 

international, national, and regional consensus standards or protocols. 

This section also discusses the types of end-use energy efficiency and renewable energy 

measures and programs for which quantification, monitoring, and verification of results is 

relatively straightforward. Such approaches might be subject to streamlined review of 

quantification, monitoring, and verification protocols included in an approvable plan, provided 

that such protocols are applied in accordance with industry best practices. For example, many 

utilities have implemented a similar core set of end-use energy efficiency and renewable energy 

measures and programs for utility customers. For these types of measures and programs, a 

substantial base of experience has been established nationally for quantification, monitoring, and 

verification of measure and program outcomes. Other types of measures and programs, such as 

those that seek to alter consumer and building occupant behavior may pose quantification and 

verification challenges. Still other types of measures, such as state energy-efficient appliance 

standards and building codes, have not typically been subject to similar evaluation of energy 

savings results. These types of approaches may have substantial impacts, but may require 

development of appropriate quantification, monitoring, and verification protocols. 

 
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A. Quantification, Monitoring, and Verification for End-Use Energy Efficiency 

1. Introduction 

For rate-based state plans, a key element of the plan is a demonstration of how the state, 

and related entities with enforceable obligations under the plan, will measure and verify energy 

savings to be achieved the through the implementation of end-use energy efficiency measures 

incorporated in the plan.50 In the context of demand-side energy efficiency programs currently 

overseen by state PUCs, this function is typically addressed through an evaluation, measurement, 

and verification plan (EM&V plan). This section discusses current state and utility EM&V 

practice for end-use energy efficiency programs and discusses considerations related to possible 

acceptable EM&V plan and protocol approaches for a state plan under CAA section 111(d). 

2. Background on Evaluation, Monitoring, and Verification (EM&V) of Energy 

 Efficiency Measures 

From the time that demand-side energy efficiency (EE) emerged as an important energy 

strategy in the 1970s,51 efforts to evaluate the impacts of EE actions have been critical to their 

success, credibility, and expansion. Starting with measurement and verification (M&V) of 

individual projects, these efforts have evolved to the point where there is now a mature and 

rigorous evaluation, measurement, and verification (EM&V) industry. This industry includes 

many professional firms, protocols and guidelines, training and certification programs, 

regulatory oversight, and established conferences with a rich library of published reports and 

publically available data and analyses. 

State agencies responsible for planning, implementing, and evaluating demand-side 

energy efficiency programs and policies utilize EE savings values, as follows:52 

                                                            

50 In this section we use the term “end-use energy efficiency measure” or “energy efficiency measure” to refer to an 

end-use energy efficiency requirement (such as an EERS), and energy efficiency program, or individual installed 

energy efficiency measure, such as installation of an energy-efficient air conditioner through an energy efficiency 

program. 

51 National Energy Program Fact Sheet on the President's Program, April 20, 1977. 52 State and Local Energy Efficiency Action Network. 2012. Energy Efficiency Program Impact Evaluation Guide. 

Prepared by Steven R. Schiller, Schiller Consulting, Inc., available at http://www.seeaction.energy.gov. 
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 Projected savings: values reported by a program implementer or administrator before the 

efficiency activities are completed 

 Claimed savings: values reported by a program implementer or administrator after the 

efficiency activities have been completed, prior to independent evaluation of savings 

 Evaluated savings: values reported by an independent third-party evaluator after the 

efficiency activities and an impact evaluation have been completed. 

 Both claimed and evaluated energy savings involve real-time and/or retrospective 

assessments of the performance and implementation of an energy efficiency program or a 

portfolio of programs. Important impacts for evaluation include energy and demand savings and 

non-energy benefits (e.g., avoided emissions, health benefits, job creation and local economic 

development, energy security, transmission and distribution benefits, and water savings). Impact 

evaluations also support cost-effectiveness analyses aimed at determining the value of energy 

efficiency programs to utility customers and identifying relative program costs and benefits of 

energy efficiency compared to other energy resources, including both demand- and supply-side 

options. 

Regardless of how the energy savings of an energy efficiency measure are determined, all 

energy savings values are estimates of savings and not directly measured. Savings are 

determined by comparing energy use after an energy efficiency project or measure is installed 

(the reporting period) with what is assumed to be the energy use in the absence of the project or 

measure (the “counterfactual” scenario, or baseline). Savings therefore depend critically on 

baseline assumptions, which are necessarily estimated with varying degrees of accuracy. Figure 

1-1 illustrates this concept. 
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Figure 1. Energy Use Before, During, and After an Energy Efficiency Project is Installed53

3. Current EM&V Practices in States 

3.1 EM&V for Demand-Side Energy Efficiency Programs Overseen by State PUCs 

Current practice with EM&V for demand-side energy efficiency programs in the U.S. is 

primarily defined by state utility commission (PUC)54 requirements for customer-funded 

efficiency programs. The level of PUC oversight varies from state to state, but this oversight 

process has generated the majority of the industry guidance and protocols for documenting 

energy savings from energy efficiency programs. Typically, impact evaluation reports are 

prepared based on the requirements established by PUCs and submitted (usually annually) for 

PUC review, approval, and use in resource planning and performance assessment. According to a 

recent survey, most states (79 percent) rely on independent consultants and contractors to 

conduct evaluations, while some states (21 percent) use utility and/or government agency staff.55 

                                                            

53 Ibid. 

54 In some states these government entities are referred to as a public service commission (PSCs) or board of public 

utilities (BPU), as well as other names. 

55 Kushler, M.; Nowak, S.; Witte, P. , A National Survey of State Policies and Practices for the Evaluation of 

Ratepayer-Funded Energy Efficiency Programs, American Council for an Energy-Efficient Economy (ACEEE) 

(February 2012), Report Number U122 Available at http://www.aceee.org/ research-report/u122. 
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The range of EM&V budgets varies significantly between states, typically from two 

percent to six percent of total energy efficiency program expenditures.56 The average EM&V 

budget in 2011 was about 3.6 percent of program expenditures. Reasons for this disparity may 

include the fact that as states expand energy efficiency programs, they may implement more 

complex programs, which require additional EM&V. EM&V effort in states also typically 

increases as the magnitude of program expenditures and energy savings impacts increase, and as 

states and utilities gain experience in implementing energy efficiency programs. 

States at the low end of this EM&V expenditure range typically rely heavily on deemed 

savings approaches, which are a common and relatively low-cost strategy for documenting 

energy savings. Deemed savings are measure-specific stipulated values based on historical and 

verified data (in some cases using the results of prior EM&V studies). Unlike other EM&V 

approaches, with deemed savings there are no – or very limited – measurement activities. 

Instead, only the quantity of energy efficiency measures implemented is verified (e.g., number of 

motors installed correctly, number of energy-efficient air conditioners that were purchased using 

a program rebate). The verified installed energy efficiency measures are then multiplied by the 

estimated (or deemed) energy savings per measure to derive energy savings for each measure 

and energy savings for the total number of measures installed through an energy efficiency 

program. The use of deemed energy savings is only considered appropriate for efficiency actions 

with well-known characteristics. A variant of this approach is the deemed savings calculation, 

which involves the use of one or more agreed-upon (stipulated) engineering algorithms used to 

generate energy and/or demand savings associated with energy efficiency measures. These 

calculations may include predetermined assumptions for one or more parameters in the 

algorithm, but typically require users to input data associated with the actual installed measure 

into the algorithm. 57 

                                                            

56 Wallace, P.; Forster, H.J. (2012). State of the Efficiency Program Industry Budgets, Expenditures, and Impacts 

2011. Consortium for Energy Efficiency. www.cee1.org/files/2011 CEE Annual Industry Report.pdf . 57 Examples of equipment types that are commonly evaluated using deemed savings values and calculations include 

energy-efficient washing machines, computer equipment, and refrigerators, and lighting retrofit projects with wellunderstood operating hours. For deemed savings calculations, evaluators collect information about the actual 

installed measures -- such as hours of usage, wattage, and/or equipment capacity -- and combine this with 

predetermined assumptions in the algorithm. 
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The deemed savings values, themselves, are typically centrally located in a “Technical 

Reference Manual” (TRM). The content and format of these TRMs vary, but in most cases 

consists of a database of standardized, state- or region-specific algorithms (deemed calculations) 

and associated energy savings estimates (deemed savings values) for energy efficiency measures. 

TRMs also include various data assumptions, sample calculations, and other inputs that the state 

uses to develop energy savings values for the range of energy efficiency programs in place. The 

benefits to energy efficiency program administrators of using a TRM include reduced EM&V 

costs and greater certainty regarding projected, claimed, and evaluated energy savings values 

(see definitions above). There are about 20 states currently using TRM databases.58

It should be noted that TRM values for individual energy efficiency measures are not 

always formally vetted in a regulatory process, although this is a good practice.59 A recent 

survey of TRMs found that deemed energy savings values for comparable energy efficiency 

measures vary across states and regions.60 The reasons for these variations include the use of 

different calculation methodologies, technical assumptions, and input variables. Some of these 

differences are expected based on relevant differences in weather and baseline assumptions (e.g., 

existing building stock and common practices vary from one state to another). However, other 

differences are related to out-of-date input assumptions and calculation errors. In the context of 

state plans, this variation, and in particular data quality issues with some TRMs, raises 

consideration of whether complete reliance on existing TRM resources for state plans is prudent 

and appropriate, including how such reliance could or should be circumscribed. 

 In addition to the use of deemed savings, states on the higher end of the EM&V 

expenditure range rely to a greater extent on a variety of direct measurement approaches for 

documenting energy savings. Rather than mandating which EM&V methods must be used in a 

particular situation, PUCs typically allow utilities and other program administrators to select 

                                                            

58 State and Local Energy Efficiency Action Network, Scoping Study to Evaluate Feasibility of National Databases 

for EM&V Documents and Measure Savings, prepared by Jayaweera, T.; Haeri, H.; Lee, A.; Bergen, S.; Kan, C.; 

Velonis, A.; Gurin, C.; Visser, M.; Grant, A.; Buckman, A.; The Cadmus Group Inc. (June 2011), available at 

http://www.eere.energy. gov/seeaction/pdfs/emvscoping__databasefeasibility.pdf. 

59 State and Local Energy Efficiency Action Network, Energy Efficiency Program Impact Evaluation Guide, 

prepared by Steven R. Schiller, Schiller Consulting, Inc. (2012), available at http://www.seeaction.energy.gov . 60 Ibid. 
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from a range of appropriate EM&V approaches that are consistent with standard practice in the 

energy efficiency industry. EM&V analyses and calculations are then carried out, in most cases 

by an independent, third-party evaluator, through a process that is unbiased, uses technically 

rigorous methods, effective peer review, and is subject to public review and comment. In 

addition, energy savings are frequently certified by the PUC as compliant with requirements 

defined in a pre-approved EM&V plan. 

 EM&V requirements in states with the most experience implementing and overseeing 

energy efficiency programs are typically based upon the following industry best practices: 

 Use of one or more of the industry-standard EM&V protocols or guidelines (listed 

below), as well as the use of deemed savings values for well-understood energy 

efficiency programs and measures 

 Consideration of local factors, such as climate, building type, and occupancy. 

 Involvement of stakeholders and solicitation of expert advice regarding EM&V processes 

and resulting energy savings impacts. 

 Conduct of EM&V activities (e.g., direct equipment measurements, application of 

deemed savings, and reporting of impacts) on a regular basis. 

 Provision of interim and annual reporting of achieved energy savings. 

 Despite this well-defined and generally accepted set of industry best practices, many 

states with energy efficiency programs use different input values and assumptions (e.g., net 

versus gross savings, run-time of equipment, measure lifetime) in applying these practices. This 

can result in significant differences in claimed energy savings values for similar energy 

efficiency measures between states, even when the same measure type is installed under 

otherwise identical circumstances. In response to a growing awareness of this lack of cross-state 

comparability, policy makers, regulatory agencies, and other stakeholders are increasingly 

advocating for the use of common evaluation approaches across jurisdictions. Several national 

and regional EM&V efforts have emerged to promote collaboration and information sharing 

across states. These initiatives include the Northeast Energy Efficiency Partnership’s (NEEP) 

EM&V Forum, which is active in New England, New York, and the Mid-Atlantic, and the 
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Pacific Northwest’s Regional Technical Forum (RTF). Both efforts aim to promote multi-state 

coordination in EM&V practices, make EM&V results more transparent and publicly available, 

and support the adoption of similar definitions, methods, and input assumptions.61 

 In addition to stakeholder efforts to promote EM&V collaboration and information 

sharing, a growing number of EM&V protocols and guidelines, some of which have recently 

been developed, are being used in the U.S. to promote greater consistency of measurement 

techniques and methodologies: 

a. International Performance Measurement and Verification Protocol (IPMVP)62

b. DOE Uniform Methods Project (UMP) Protocols63

c. Federal Energy Management Program (FEMP) M&V Guidelines64

d. American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE) 

Guideline 14, Measurement of Energy and Demand Savings65

e. California Evaluation Protocols66

f. ISO New England (ISO-NE) Manual for Measurement & Verification of Demand 

Resources67

g. PJM Energy Efficiency Measurement and Verification Manual68

                                                            

61 For a list of EM&V resources, including more information about these regional EM&V collaboratives, see 

http://www1.eere.energy.gov/seeaction/evaluation.html. 62 Efficiency Valuation Organization (EVO), International Performance Measurement and Verification 

Protocol (2012), available at: http://www.evo-world.org/. 63 U.S. Department of Energy (DOE), Uniform Methods Project (April 2013), available at: 

http://energy.gov/eere/about-us/initiatives-and-projects/uniform-methods-project-determining-energy-efficiencyprogram-savings. 64 FEMP, M&V Guidelines: Measurement and Verification for Federal Energy Projects, Version 3.0 (April 2008), 

available at: https://www1.eere.energy.gov/femp/pdfs/mv_guidelines.pdf. 65 American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE), Guideline 14: 

Measurement of Energy and Demand Savings (June 2002), available at: 

https://gaia.lbl.gov/people/ryin/public/Ashrae_guideline14-

2002_Measurement%20of%20Energy%20and%20Demand%20Saving%20.pdf. 66 California Public Utilities Commissions (CPUC), California Energy Efficiency Evaluation Protocols: Technical, 

Methodological, and Reporting Requirements for Evaluation Professionals (2006), available 

at: http://www.calmac.org/events/EvaluatorsProtocols_Final_AdoptedviaRuling_06-19-2006.pdf.

67 ISO-New England (ISO-NE), Measurement and Verification of Demand Reduction Value from Demand 

Resources (2013), available at http://www.iso-ne.com/rules_proceds/isone_mnls/MMVDR/index.html. 

68 PJM, Manual 18B: Energy Efficiency Measurement & Verification (2010), available at 

http://www.pjm.com/~/media/documents/manuals/m18b.ashx. 
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h. State and Local Energy Efficiency Action Network, Energy Efficiency Program Impact 

Evaluation Guide69

 While many states are currently relying upon these protocols and guidelines, other states 

and regional organizations (e.g., ISOs and RTOs) specify accuracy and uncertainty requirements 

for energy savings estimates. For example, ISO-NE requires that energy efficiency bids into its 

Forward Capacity Market (FCM) ensure that impact evaluations achieve ±10 percent statistical 

precision at the 80% confidence interval (see below for more on FCMs). 

 

 Regardless of the evaluation approach followed, the majority of state PUCs and energy 

efficiency program administrators aim to strike a balance between the transaction costs of 

EM&V activities (i.e., expense, time, staff effort) and the resulting reliability, validity, and 

usefulness of the estimated energy savings results. The appropriate balance between EM&V 

costs and the rigor of EM&V – and the related certainty of energy savings estimates – is often 

determined based on the type of program (including program purpose and goals), level of 

program expenditures, and magnitude of anticipated energy savings. 

3.2 EM&V for Energy Efficiency Measures used in ISO Forward Capacity Markets

 

Two Independent System Operators (ISOs) responsible for operating regional electricity 

grids and overseeing wholesale electricity markets in certain regions of the country have 

established forward capacity markets (FCMs) that pay suppliers to ensure sufficient electric 

generating capacity is available to meet future peak electricity demand. In operating these 

markets, ISO New England (ISO-NE) and PJM both allow demand-side energy efficiency 

programs and other demand-side resources to compete directly with electric generators to meet 

the regional capacity needs. One requirement for utilities and other energy efficiency program 

administrators seeking to bid into the market is to submit an evaluation plan. ISO acceptance of 

this evaluation plan “qualifies” energy efficiency programs and projects as prospective market 

resources. The evaluation plan specifies the amount of energy and demand savings to be 

                                                            

69 U.S. DOE State and Local Energy Efficiency Action Network (SEE Action), Energy Efficiency Program Impact 

Evaluation Guide (December 2012), available 

at: http://www1.eere.energy.gov/seeaction/pdfs/emv_ee_program_impact_guide.pdf.
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delivered over the contract period (typically three years into the future), and documents how the 

requirements of the ISO’s M&V standards manual will be satisfied. 

Based on experience to-date, states bidding their energy efficiency programs into both the 

ISO-NE and PJM forward capacity markets are typically subjected to EM&V requirements that 

go beyond the evaluation already conducted for the purpose of meeting PUC requirements. This 

is because, while PUCs typically require evaluation protocols and procedures for documenting 

the cost-effectiveness of annual energy (MWh) savings, FCMs require the measurement and 

verification of capacity (MW) savings during specific peak demand hours. In addition to the 

evaluation of energy savings, a separate set of measurement techniques and data collection 

protocols are required to document peak demand reduction impacts. Furthermore, attaining the 

level of statistical precision and confidence described above typically requires additional 

sampling70 than is required by PUCs. One consideration is whether EM&V requirements in ISO 

capacity markets include components that would facilitate better estimation of avoided CO2

emissions related to energy efficiency programs include in state plans. 

For the states located in ISO-NE and PJM, the common evaluation requirements for FCM 

participation have created an impetus for regional collaboration on EM&V practices. New 

England and Mid-Atlantic states continue to work together to establish consistent evaluation 

protocols through the creation of an “EM&V Forum,” which is convened by the Northeast 

Energy Efficiency Partnerships (NEEP) and supports common evaluation methods, reporting 

metrics, and cost sharing on research studies.71 The Forum also serves as a venue for information 

exchange to address common EM&V challenges encountered with FCM participation. 

                                                            

70 With additional sampling requirements, energy efficiency program evaluators are typically required to measure a 

larger percentage of the energy efficiency measures installed within the total population of all measures installed 

through an energy efficiency program. 

71 More information about the EM&V Forum is available through Northeast Energy Efficiency Partnerships, at 

https://neep.org/emv-forum/index. 
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3.3 EM&V for Programs and Policies Not Typically Overseen by PUCs 

In contrast to energy efficiency programs overseen by PUCs, EM&V is less common for 

other types of energy efficiency requirements or programs, especially for minimum energy 

efficiency requirements that do not involve the expenditure of electricity ratepayer dollars. 

Examples include building energy codes, appliance efficiency standards, various energy 

efficiency financing programs, behavioral change programs, and market transformation 

programs that target both the suppliers of energy-efficient products and increasing consumer 

demand for those products. While these approaches may have substantial impacts in reducing 

energy use, many currently face EM&V challenges. In some cases, appropriate evaluation 

protocols and approaches have not been developed for some programs and measures. In cases 

where appropriate EM&V methods do exist, there may also be less experience applying them.72

4. Considerations for EM&V of End-Use Energy Efficiency Programs and Measures in 

 State Plans 

4.1 Accuracy of Energy Savings Estimates 

To document and verify that avoided CO2 emissions from energy efficiency programs 

and measures are real and persistent, impact evaluation must be rigorous and transparent. Impact 

assessment should also consider the appropriate balance between certainty of results and the 

EM&V costs to achieve a specified level of certainty. Because energy savings data are estimates, 

their use as part of the basis for determining the avoided CO2 emissions resulting from energy 

efficiency programs and measures in a state plan will depend upon the level of accuracy of this 

information. Therefore, evaluation results should be reported as “expected values”—that is, 

energy savings values are expected to be correct within an associated range of certainty. Key 

considerations for EM&V of energy efficiency programs and measures in state plans are similar 

to those faced in the design of any program evaluation approach: (1) the level of certainty that is 

required given a program’s objectives and requirements, and (2) how achievement of that 

 

                                                            

72 Examples of such EM&V methods are described in the PNNL report, “Building Energy Codes Program: National 

Benefits Assessment: 1992-2040.”; and in Meyers et al, “Energy and Economic Impacts of U.S. Federal Energy and 

Water Conservation Standards Adopted From 1987 through 2012” LBNL-6217E. 
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necessary level of certainty is balanced with the amount of effort (e.g., resources, time, money) 

used to obtain that level of certainty. 

4.2 EM&V Technical Considerations for State Plans 

Using energy efficiency requirements, programs, and measures as an emission reduction 

approach in state plans requires consideration of several evaluation-related technical 

considerations. The following sections describe these considerations. 

4.2.1 Qualifying Demand-Side Energy Efficiency Actions 
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States are currently implementing a wide range of demand-side energy efficiency 

requirements, programs, and measures. However, EM&V of some of these programs and 

measures are associated with greater levels of measurement precision and certainty than others, 

based in part on the EM&V procedures currently in place. For example, energy efficiency 

programs subject to PUC oversight and review are frequently evaluated using rigorous 

evaluation procedures that are based upon several decades of research and experience. These 

energy efficiency programs are subject to a quasi-judicial, public, and transparent review 

process, which can lead to adoption of EM&V protocols that convey a relatively high level of 

certainty for EM&V results. 

In contrast, other energy efficiency requirements and measures, some of which may result 

in very significant and cost-effective energy savings (e.g., building energy codes, local tax 

credits, EE loan programs, etc.), are not subject to PUC oversight and typically have comparably 

fewer EM&V requirements. There are also some newer EE program designs (e.g., behaviorbased programs and various market transformation programs73) for which rigorous EM&V 

methodologies or a track record of energy savings persistence do not yet exist. 

One option for organizing these variations in EM&V practices is with a qualitative 

hierarchy, as follows: 

 EM&V procedures and protocols well established – for example, rebate and direct 

install programs for appliances, HVAC, and lighting equipment 

 EM&V procedures and protocols moderately well established – for example, 

building codes and standards 

 EM&V procedures and protocols less well established – for example, building 

disclosure and labeling programs 

                                                            

73 Behavior-based energy efficiency programs aim to affect consumer energy-use behaviors in order to achieve 

energy and/or peak demand savings. Techniques to measure the impacts of these program designs are emerging and 

currently under development. Market transformation programs are characterized by strategic intervention in a 

market to address market barriers and market failures to accelerate market adoption of energy-efficient technologies 

and practices, and create lasting market change. While market transformation approaches can have very high energy 

savings impacts, by creating sustained deployment of energy-efficient technologies and practices, evaluation of 

these strategies is challenging due to the involvement of numerous market players and the multi-year timeframe for 

achieving energy savings.
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Table 4.1 provides an illustrative characterization of the relative level of EM&V 

uncertainty for different types of energy efficiency programs and measures under this approach. 

This information is illustrative and generalized. In particular, there are numerous exceptions to 

the categorization of the relative uncertainty of EM&V results for different types of programs 

and measures listed in Table 4.1. 

Table 2. Illustrative Characterization of EM&V Procedures and Protocols for 

 Common Energy Efficiency Programs and Polices74 

EM&V Procedures and 

Protocols Well Established 

EM&V Procedures and 

Protocols Moderately Well 

Established 

EM&V Procedures and 

Protocols Less Well 

Established 

 Direct install incentive 

programs for building 

equipment (retrofits and 

new construction), 

including: 

o lighting 

o heating, 

ventilation, and 

air conditioning 

(HVAC) 

o refrigeration 

o motors 

 Electrical distribution 

system and transmission 

system upgrades 

 Building energy codes 

(requirements and incentive 

programs for new 

construction, remodels) 

 State government 

building/operations 

programs (procurement, 

design standards, etc.) 

 Product-specific mid-stream 

and upstream market 

transformation programs 

 Building commissioning 

and retro-commissioning 

 Industrial energy efficiency 

new construction or retrofits 

 Combined heat and power 

(CHP) installations/retrofits 

 General education 

programs for consumers, 

contractors, distributers, 

suppliers 

 Targeted training 

programs 

 Building labeling and 

disclosure programs 

 Point-of-sale product 

sales 

 Targeted consumer 

behavior programs 

Recognizing these variations in EM&V procedures and protocols, one option for EM&V 

requirements or guidance for state plans is to limit the eligible types of energy efficiency 

programs and measures that could be included in a state plan to a pre-defined list of wellunderstood program types for which evaluation is straightforward and energy savings results are 

                                                            

74 This table is intended as a generalized description, based upon numerous conversations with professional energy 

efficiency program evaluators. It should be noted that there are states with building energy codes, behavior 

programs, and market transformation programs that are well documented and subject to rigorous EM&V. 
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subject to a relatively low level of uncertainty.75 An alternative approach is to allow a wide (or 

unlimited) set of energy efficiency program and measure types, as long as the energy savings are 

adequately documented according to rigorous EM&V methods and appropriate regulatory 

oversight. The former option potentially reduces measurement uncertainty, while the latter 

approach may provide more flexibility. 

4.2.2 Avoided Transmission and Distribution (T&D) Losses from End-Use Energy 

 Efficiency Measures 

In general, the difference between the amount of electricity input to the transmission 

system by an EGU and the amount ultimately delivered to an end-user constitutes transmission 

and distribution (T&D) line losses.76 According to EIA data, nationally, annual electricity 

transmission and distribution losses are equivalent to about seven percent of the electricity that is 

input to the transmission system in the United States. For every unit of energy use avoided at the 

end-use site, energy efficiency also avoids the losses that would otherwise occur as electricity is 

delivered to consumers through the T&D system.77 Many state PUCs are aware of this 

additional benefit of demand-side energy efficiency programs, and actively credit program 

energy savings results to account for program contributions to avoided line losses, albeit using a 

range of measurement approaches and calculations. A consideration for EM&V in state plans is 

whether to account for avoided T&D losses, and how to do so in a consistent manner across 

states. 

                                                            

75 This includes energy efficiency programs and measures for which there is significant experience with EM&V, a 

robust set of existing EM&V studies and reports, and relatively straightforward EM&V approaches. 

76 The T&D system includes all the power lines and related equipment used to deliver electricity from an electric 

generating plant to an end-use site. Along the way, some of the supplied by the generator is lost due to the resistance 

of the wires and equipment that the electricity passes through, as well as reactive power losses in alternating current 

systems due to inductance and capacitance. Most of this lost energy is converted to heat. The magnitude of losses in 

the T&D system depends on the physical characteristics of the system in question, as well as how it is operated. 77 U.S. EPA, Assessing the Multiple Benefits of Clean Energy: A Resource for States (February 2010), available at: 

http://epa.gov/statelocalclimate/documents/pdf/epa_assessing_benefits_ch3.pdf 
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4.2.3 Reported Energy Savings Values 

Energy savings results for energy efficiency programs are often expressed in terms of 

annual MWh of savings per year. However, for an assessment of the associated avoided CO2

emissions impacts, it may be useful to utilize time-differentiated (i.e., hourly, seasonal) energy 

savings data.78 Information about the timing of energy savings has direct implications for 

estimating the avoided CO2 emissions that result from an efficiency program or portfolio of 

programs. The temporal energy savings profile that results from the application of energyefficient technologies and practices to different end-uses can vary significantly. For example, air 

conditioner programs save energy primarily on hot summer days, whereas a refrigerator program 

saves energy every hour of the year. Time-differentiated information related to electricity 

generation is useful in estimating avoided CO2 emissions. In particular time-differentiated data is 

necessary to estimate the marginal avoided CO2 emissions related to electric generation, as 

discussed above in section IV.C.3. 

In practice, state PUCs around the country have substantially different requirements and 

recommendations for evaluating and reporting time-differentiated energy savings. Some energy 

efficiency program administrators report annual energy savings impacts, where savings are 

typically based on either tracking data (i.e., data used to estimate savings for planning purposes) 

or evaluated (i.e., ex-post) savings data. Other programs supplement reporting of annual energy 

savings with data on the timing of energy savings, which can be used to identify the marginal 

EGU or cohort of marginal EGUs that would have provided generation in the absence of the 

energy savings. This supplemental data can be used to more accurately estimate avoided CO2

emissions that result from program energy savings. Due to improved evaluation software and 

data availability, it is increasingly common for energy efficiency program EM&V plans to 

include calculation of estimated seasonal or even hourly energy savings as part of the program 

evaluation process. A consideration for EM&V requirements or guidance for state plans is the 

extent to which time-differentiated data on energy savings from energy efficiency programs is 

available, and whether states can readily acquire such data and information for use in 

implementing their state plans. 

                                                            

78 This is often referred to as the “load shape” of energy savings achieved through an energy efficiency measure. 
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 A related consideration is metrics reported for electricity savings. The primary metric 

required to understand the avoided CO2 emissions impacts of energy efficiency programs and 

measures is annual MWh of energy saved. In addition, a secondary metric is MW demand 

reduction impacts, which may be desirable because it is helpful in identifying the marginal EGU 

or cohort of EGUs, in particular units on the build margin. This information is necessary to 

estimate the marginal avoided CO2 emissions related to electric generation, when reporting on 

avoided CO2 emissions achieved through energy efficiency programs and measures during a plan 

reporting period, as discussed above in section IV.C.3. Identifying EGUs on the build margin, 

based on estimates of MW demand savings that will be achieved through the implementation of 

energy efficiency programs and measures included in a state plan, may also be useful in 

projecting emission performance by affected EGUs that will be achieved under the state plan. 

4.2.4 Savings Definitions: Net and Gross Savings 

As described above, state PUCs typically specify whether energy efficiency program 

administrators are required to report either gross or net energy savings, or both. Gross savings 

are the change in energy use (MWh) and demand (MW) that results directly from programrelated actions taken by program participants, regardless of why they participated in a program. 

Net savings refer to the change in energy use and demand that is directly attributable to a 

particular energy efficiency program.79 Reporting of net savings helps a PUC ensure that energy 

efficiency program budgets are being used to promote technologies and practices that are not 

otherwise being adopted in the marketplace. A consideration for EM&V of energy efficiency 

requirements and programs included in state plans is whether required reporting of energy 

                                                            

79 Calculations of net energy savings involve excluding energy efficiency measures undertaken by "free riders" (i.e., 

EE program participants who receive a program rebate even though they would have taken the efficiency action 

anyway), or adjusting energy savings estimates to account for these effects. Free riders increase program costs 

without producing additional energy savings impacts beyond what would have occurred in the absence of the EE 

program. Free ridership may also be addressed in the setting of baselines that are used to calculate energy savings. 

Estimates of net energy savings may also involve an assessment of "free drivers" (sometimes referred to as 

"spillover effects"). These are individuals who do not directly participate in an EE program, but who undertake 

efficiency actions in response to program activity (e.g., marketing/advertising, greater availability of energyefficient equipment in a marketplace as the result of EE programs). Accurate estimation of free ridership and 

spillover effects is complex, especially in areas of the country with robust energy efficiency markets with multiple 

non-program influences competing for customers’ attention.
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savings should be specified on either a gross or net basis, or both, to promote national 

consistency in measuring the impact of energy efficiency measures across state plans.80

4.2.5 “Measure Life” and Persistence of Savings

Measure life and persistence of energy savings describe the ongoing effects of an 

installed energy efficiency measure, including the retention of the measure (i.e., is it still in 

place) and the performance degradation of that measure, which reduces a measure’s achieved 

energy savings over time. Typically, program administrators estimate the impact of energy 

efficiency programs in terms of first-year savings (in MWh), plus the cumulative MWh savings 

realized from that program (or measure) over an assumed “measure lifetime”. Depending on the 

mix of energy efficiency measures and their assumed measure lives, these energy-savings 

benefits may extend from 10 to 15 years, or more into the future from the point of measure 

installation. In practice, evaluators determine measure lifetimes on the basis of engineering 

judgment, manufacturer specifications, and some empirical field studies. These values are 

frequently entered into PUC-managed state technical databases for ongoing and repeated use in 

evaluation studies. For state plans, a key consideration is whether measure life and persistence 

values for energy efficiency measures documented by states are accurate, up-to-date, and 

consistent with those utilized in other states (after accounting for appropriate non-energy factors, 

such as weather and building occupancy type). 

5. Options for EM&V Requirements and Guidance for State Plans 

As summarized in the preamble, and discussed in more depth in this section, utilities and 

states have conducted ongoing evaluation of end-use energy efficiency and renewable energy 

measures and programs for several decades. These evaluations, which include quantification, 

monitoring and verification of results, generally rely upon a well-defined set of industry-standard 

practices and procedures. As a result, existing state and utility EM&V requirements and 

processes generally provide a solid foundation for minimum EM&V requirements that might be 

established by the EPA for state plans. However, measurement approaches vary by state based 

                                                            

80 If both gross and net savings were required to be reported, this would increase the transparency of reported energy 

savings estimates, but only one savings value would be used to evaluate the effect of energy efficiency programs and 

measures on CO2 emissions from affected EGUs. 
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on multiple factors, including the measure and program type being evaluated, the level and 

nature of regulatory oversight, the degree of state and utility experience with these measures and 

programs, and the overall magnitude of program impacts. Due to this variation in state EM&V 

approaches, as well as the specific objectives of a state plan under CAA section 111(d), 

harmonization of state EM&V approaches, or inclusion of supplemental EM&V actions and 

procedures, may be warranted in an approvable state plan.

As discussed previously, current state EM&V best practices require the level of EM&V 

effort (i.e., rigor, reliability, validity, and uncertainty of energy savings estimates) to be aligned 

with the required level of certainty of evaluation results and the magnitude of energy efficiency 

program impacts. These best practices are consistent with credible environmental results, ensure 

minimum levels of cross-state consistency, and encourage the use of state energy efficiency 

requirements, programs, and measures in state plans. To support these objectives, the following 

process considerations are relevant for documenting energy efficiency savings from measures in 

state plans. 

Options for EM&V requirements or guidance for state plans that incorporate energy 

efficiency requirements, programs, and measures include: 

 Establishing specific EM&V requirements with a level of defined rigor for all energy 

efficiency programs and measures; 

 Establishing no EM&V requirements at all, beyond basic requirements to quantify and 

verify energy savings, and allowing states to establish their own EM&V protocols; 

 Establishing specific EM&V requirements for certain types of widely used energy 

efficiency programs and measures 

 Establishing a set of minimum specified 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 
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At one end of this spectrum, establishing specific EM&V requirements provides certainty 

to states in terms of required energy savings documentation, and do so in a manner that ensures a 

consistent level of EM&V rigor across all state plans. However, this approach may require 

significant effort by the EPA to establish such requirements, and could potentially duplicate state 

efforts currently under way to harmonize EM&V practices. This approach may also limit the 

variety of valid EM&V approaches applied at the state level, and by extension the types of 

energy efficiency programs and measures that could be included in a state plan, and could also 

inhibit the development of innovative EM&V approaches that improve the accuracy of energy 

savings estimates. At the other end of the spectrum, if no specific EM&V requirements are 

established, then a state has maximum flexibility, but also faces increased uncertainty about 

whether the EM&V approach included in a proposed state plan will be approved by the EPA. 

This could increase the transaction costs incurred by states during the development of their plans, 

and could possibly delay the full implementation of energy efficiency programs incorporated in 

state plans. 

In the middle of the spectrum, some minimum EM&V criteria could be specified for all 

energy efficiency programs and measures, using general guidance, and/or establishing EM&V 

criteria for specific widely used energy efficiency programs and measures. States would have 

some level of certainty about acceptable EM&V approaches in state plans, as well as some 

flexibility in establishing appropriate EM&V approaches for the types of energy efficiency 

programs and measures included in their plan. 

A supplemental approach, in addition to those described above, is to prescribe who can 

conduct EM&V activities and prepare energy savings documentation, and specify their needed 

qualifications. This approach is analogous to professional certification requirements in the 

accounting and engineering fields, in which a minimum level of credibility, rigor, and 

accountability is imparted to the services provided by qualified individuals and firms. Criteria for 

eligible evaluators might include a demonstration of independence from those implementing or 

administering the energy efficiency programs and measures (i.e., identification and mitigation of 

potential conflicts of interest) and required minimum levels of training, experience, or 

certification. This approach recognizes that the qualifications, integrity, and independence of 
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those conducting EM&V of energy efficiency programs and measures, and preparing energy 

savings estimates, is critical to assuring best-practice EM&V. However, such requirements alone 

may not ensure sufficient evaluation rigor. 

5.1 Use of EM&V Protocols 

Establishing requirements or guidance for EM&V of energy efficiency programs and 

measures included in state plans may involve: 

 Relying on existing EM&V infrastructure and protocols, most of which have been 

established for utility-customer funded energy efficiency programs overseen by state 

PUCs 

 Establishing new protocols and procedures 

Relying on existing approaches has the benefit of utilizing existing resources that can be 

relatively quickly ramped up for use in state plans. However, existing state and utility EM&V 

infrastructure and protocols may not be applicable to the full range of energy efficiency 

programs and measures that a state may want to include in its plan. In addition, because existing 

state and utility EM&V infrastructure and protocols were established to support the goals of state 

energy efficiency programs, in current form they may not adequately support the level of EM&V 

required for state plans under CAA section 111(d). In particular, this may include the form and 

precision of energy savings data and reporting necessary to evaluate avoided CO2 emissions that 

result from energy efficiency programs and measure included in state plans. 

 5.2 EPA Review of EM&V Plans as Part of the State Plan Review Process 

Development of EM&V plans that are included in a state plan could rely primarily on 

state- or utility-level review and approval processes, with open public involvement and state 

lead-agency approval of energy savings reported. Under this approach, states would develop 

EM&V plans as part of the state plan development process. The EPA would then review these 

EM&V plans as part of its review of a submitted state plan. Using existing state processes may 

better ensure that energy savings estimates are transparent, peer reviewed, and address 

stakeholder input. Using state processes also minimizes duplication of state and the EPA 
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requirements, and balances the need for EM&V credibility and rigor with an interest in 

encouraging the deployment of cost-effective energy efficiency programs and measures through 

incorporation in state plans. However, this approach could create uncertainty for states about the 

approvability of a proposed EM&V approach in a state plan, and could also reduce the 

consistency and comparability of EM&V approaches used in state plans. At the same time, 

existing state EM&V processes currently vary in the level of regulatory oversight, which could 

necessitate establishment of minimum criteria for EM&V plans. 

5.3 General Quality Standards for EM&V Rigor and Accuracy 

 Since existing state EM&V process vary, the EPA may need to identify and establish 

minimum requirements for EM&V rigor, accuracy and reliability, and quality control. 

Requirements could be (a) a single set of requirements that apply to all energy efficiency 

programs and measures in all states or (b) a variable or flexible set of requirements with 

increasing levels of EM&V effort and rigor depending on the relative degree of uncertainty of 

energy savings from the energy efficiency programs and measures in a state plan. For example, 

well understood energy efficiency measures with a higher degree of energy savings certainty 

might require a lower level of EM&V effort, while measures with greater complexity or 

uncertainty of energy savings effects would require greater EM&V effort.81

 Simple, well-understood and straightforward energy efficiency programs and measures, 

such as lighting retrofits might require only verification that measures were installed and the use 

of deemed energy savings values (lower EM&V effort level), while less well-understood or more 

complex energy efficiency programs and measures, such as behavior programs and market 

transformation programs, would require more detailed EM&V (high level of EM&V effort). 

 A prescribed EM&V approach for all types of energy efficiency programs and measures 

would provide states with certainty while supporting a consistent level of EM&V rigor across all 

                                                            

81 For the purposes of this discussion, lower, medium, and high levels of “EM&V effort” are intentionally 

indeterminate. One possibility is that “lower EM&V effort” could refer to greater reliance on deemed savings 

values, smaller sample sizes for measured savings, fewer direct measurements, and proportionately greater reliance 

on ex-ante estimates. “Medium” and “high” levels of EM&V effort could require incrementally more effort in each 

of these areas. Other interpretations of this concept are possible. 
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states. A flexible EM&V approach, based on an individual assessment of the measurement 

uncertainty related to the energy efficiency programs and measures included in a state plan could 

provide states with greater flexibility when selecting energy efficiency programs and measures. 

However, the lack of a prescribed EM&V approach could increase uncertainty about the 

approvability of different plan approaches. 

6. EM&V Documentation in a 111(d) State Implementation Plan 

EM&V documentation will be an important component of state plans that incorporate 

energy efficiency programs and measures, because transparency and reproducibility increase 

overall confidence in reported energy savings results. A crucial component of this EM&V 

documentation is an EM&V plan, which specifies a priori how achieved energy savings will be 

retrospectively evaluated at appropriate increments during the plan period. Decisions about the 

level of EM&V documentation that is necessary in a state plan must consider tradeoffs between 

provision of more information and greater transparency, and the level of EM&V effort required. 

Excessive documentation requirements may not add value in terms of transparency, but may 

discourage the inclusion of cost-effective energy efficiency options in state plans. However, two 

basic criteria for EM&V documentation should be applied in state plans: 

 Energy savings documentation should be provided at a level of detail that allows for 

recalculation of program 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 EPA 

6.1 Illustrative Example of an EM&V Plan for End-Use Energy Efficiency Programs 

 Measures in a State Plan 

The following is an example of a possible outline of the types of information that might 

be included in an EM&V plan for energy efficiency programs and measures included in a state 

plan. An EM&V plan would specify how EM&V activities will be conducted and reported for 

relevant energy efficiency programs and measures during a state plan performance period. An 
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EM&V plan could apply to utility energy efficiency programs that are incorporated into a state 

plan on a stand-alone basis, and might also apply to such programs when used to meet 

mandatory energy efficiency requirements, such as an EERS, that are incorporated into a state 

plan. 

Who Will Document Savings and When

 Name of the organization that will prepare evaluated energy savings reports and their 

 Relationship of the organization to the subject energy efficiency program(s) and program 

administrator(s) 

 Schedule of when the reports will be prepared and what period of time they will cover 

 Name of the state or regional government entity, or non-governmental entity, which will 

review and certify the evaluated savings 

 How evaluated energy savings reports will be made publicly available and what the 

primary use of the reports will be 

 

Documentation Procedures

 List of energy savings metrics to be reported (e.g., annual MWh, monthly MWh, hourly 

MWh, average MW), and whether gross or net savings, or both, will be reported 

 Name of impact evaluation protocols, guidance documents, and other methods that will 

be followed in preparing evaluated energy savings reports 

 Description of the range of uncertainty for energy savings estimates indicated in 

evaluated energy savings reports, including sources of uncertainty 

 Description of assumptions concerning availability of data and data collection methods 

 Indicate how the following issues, if applicable, will be addressed in the claimed and 

evaluated savings estimates: 

o Inclusion of estimates of avoided electricity transmissions and distribution losses 

o Adjustment of gross savings estimates to net savings estimates (if applicable 

o Sources of uncertainty 

 
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B. Quantification, Monitoring, and Verification for Renewable Energy Measures 

For rate-based state plans, a key element of the plan is a demonstration of how the state, 

and related entities with enforceable obligations under the plan, will measure and verify electric 

generation that is achieved through the implementation of renewable energy measures 

incorporated in the plan.82 This section discusses current state and utility quantification, 

monitoring, and verification practices for renewable energy measures, and discusses 

considerations related to possible acceptable quantification, monitoring and verification 

approaches for a state plan under CAA section 111(d). 

States and utilities use a variety of policy instruments to increase the production and use 

of renewable energy. The principal mechanisms include: renewable portfolio standards (RPSs), 

feed-in tariffs (FITs), tax incentives (e.g., property tax exemptions; production-based tax 

incentives; etc.), financial assistance programs (e.g., grants, loans, and other direct financial 

assistance based on generating capacity or investment level), and other policies (R&D support; 

manufacturing incentives; workforce training; net metering; etc.). Experience to date indicates 

that RPSs have led to the vast majority of the increase in renewable energy generating capacity 

and generation resulting from state policies. However, FITs and production-based tax incentives 

have been among the most important incentives used by states and utilities to help achieve RPS 

requirements, as well as to spur additional production and use of renewable energy. Further, 

these types of programs rely on measurable electric generation as the basis for compliance or 

incentive payments. As a result, the following discussion focuses on quantification, monitoring, 

and verification mechanisms related to these state policies. Other types of programs (e.g., certain 

grant and rebate programs) may not currently quantify electric generation output from funded 

renewable energy projects. However, if such programs were modified to require the collection of 

such data, many of the quantification, monitoring, and verification considerations discussed in 

this section would also generally apply. 

                                                            

82 In this section we use the term “renewable energy measure” to refer to a renewable energy requirement (such as 

an RPS), a renewable energy deployment program, or individual installed renewable energy measures, such as 

installation of a solar photovoltaic system through a renewable energy deployment program. 
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1. Renewable Portfolio Standards 

A RPS is designed to increase the amount of renewable energy a distribution utility or 

load-serving entity provides to retail electricity customers.83. This increased customer demand in 

turn increases the production of renewable energy to meet demand. To achieve compliance with 

a RPS, an increasing share of a distribution utility’s electricity retail sales is required to be 

produced or acquired from renewable energy resources and delivered to customers. To verify 

compliance, RPSs have been complemented by tracking systems for renewable energy 

generation and use. These tracking systems account for the growing amount of renewable energy 

that is produced for obligated retail sellers as well as large and small retail energy consumers that 

purchase renewable energy on a voluntary basis.84

The point of regulation for state RPSs is typically investor-owned electric distribution 

utilities, because most RPS apply to entities under the jurisdiction of state PUCs. In a number of 

states, municipally-owned utilities and electric cooperatives are exempt from state RPS, have 

lower RPS requirements, or are required to develop their own renewable energy procurement 

targets. Additionally, some states have created separate renewable energy requirements for each 

of their affected distribution utilities. 

The absolute amount of renewable energy that each distribution utility is obligated to 

deliver will vary, with requirements in the form of a fixed amount of renewable energy (either 

MWh or MW of capacity) or percentage of retail sales. 

There are several pathways that affected distributed utilities typically have to meet state 

RPS requirements, including building and operating renewable energy generating capacity, 

purchasing electricity from renewable energy generators, and purchasing the attributes from 

renewable energy generation. Many state RPSs take this latter approach. Rather than requiring 

                                                            

83 In states that have restructured their electricity sectors and introduced retail competition, entities other than a 

utility may supply electricity to a retail customer. These entities use a regulated distribution utility’s network to 

deliver electricity to a retail consumer. These entities either generate their own electricity or contract for supply from 

wholesale electricity market participants. In this section, we use the term “distribution utility” to refer broadly to 

both local distribution companies (LDCs) and other load-serving entities that supply electricity to retail customers. 84 “Voluntary” renewable energy purchases, as used here, refers to renewable energy purchases in addition to the 

renewable energy required by RPSs. 
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each distribution utility to generate electricity from its own renewable energy facilities or 

purchase electricity from a renewable facility owned by others, many states require distribution 

utilities to acquire renewable energy certificates (RECs) that represent the attributes of the unit of 

renewable electricity produced.85 

By allowing REC trading, many states have created markets for RECs based on specific 

state RPS requirements. Renewable energy generators can sell RECs as another product bundled 

with the underlying power they produce or sell RECs separately to different customers. Once the 

RECs are separated from the power generated, the power has no attributes associated with it and 

is considered generic or “null” power.86 

There are a number of key aspects of RPS design and implementation that affect the 

quantification, monitoring, and verification of renewable energy generation used to meet a RPS: 

 Eligible renewable energy resources. While most RPS-eligible resources in most states 

will result in avoided CO2 emissions from fossil fuel-fired EGUs, some RPS-eligible 

resources in some states are responsible for greenhouse gas (GHG) emissions or do not 

meet common definitions of renewable energy (e.g., waste coal, coal-bed methane, and 

fuel cell operation using fossil-fuel feedstocks). 

 Existing and new resources. RPS-eligible resources can include facilities that began 

operation prior to the enactment of the RPS and, more importantly, prior to the proposal 

of the emission guidelines by EPA. 87

                                                            

85 RECs are contractual instruments that convey ownership of the attributes of a unit of energy generated, but do not 

represent the energy itself. The attributes conveyed with RECs include information about the generator, such as: 

type of resource (e.g., wind), plant-level air emissions (if any), geographic location, nameplate capacity (MW), 

commercial operation date, ownership, and the eligibility for RPS compliance or voluntary market certification. 86 These distinctions are typically made as part of utility disclosure to customers about the energy resource mix and 

emissions of the electricity used by a customer that was supplied from by the distribution utility. “Generic power” or 

“null power” refers to energy that has no generation attributes or descriptive information (i.e., the remaining system 

mix of power, after assignment of specified power to different utility customers, through power purchase contracts 

or purchase of generation attributes through RECs). For electricity labeling, disclosure to customers, or other market 

claims, generic or null power is typically assigned the attributes of the remaining system mix of power, after the 

assignment of attributes as described above. 

87 In the preamble, the EPA is proposing that, for an existing state requirement, program or measure, a state may 

apply toward its required emission performance level the emission reductions that existing state programs and 
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 Scope of coverage. In some states a RPS applies to all retail sales in a state, but in others 

only a subset of retail sales (e.g., only investor-owned utility retail sales) are subject to a 

RPS. 

 Credit multipliers. Some states provide additional incentives for specific eligible 

resources in the form of bonus credit toward compliance in their RPS accounting 

framework. For example, these states may favor certain resources (e.g., distributed solar 

PV), or locally-important resources or technologies. The MWh produced or renewable 

energy certificates (RECs) related to MWh production from such facilities may be 

counted twice or three times toward compliance with a RPS in such states. However, 

these credit multipliers and bonuses are not an accurate representation of the amount of 

renewable energy generation that is attributable to a RPS. For the purpose of quantifying 

the amount of renewable energy produced as a result of a RPS included as a measure in a 

state plan, only the actual renewable energy generation used to comply with an RPS is 

relevant. 

 Banking. Some states permit the carryover of renewable energy produced in one year to 

satisfy RPS requirements in a subsequent year. Accounting for year-to-year carryover 

should be addressed in a state plan, in order to determine the renewable energy 

generation that occurred in a respective reporting year or compliance period. 

 Alternative compliance payments (ACP). Many states allow a compliance alternative 

which requires obligated entities to pay a predetermined fee to the state for each MWh of 

RPS shortfall. 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 accounted as such. 

 Interstate issues. While treatment of interstate emission effects is discussed in detail in 

section VII, for quantification, monitoring, and verification of renewable energy 

                                                                                                                                                                                               

measures achieve during the plan period due to actions taken after the date on which the emission guidelines are 

proposed (i.e., from June 2014 onward). 
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generation under a RPS it is important to note that most states allow use of eligible 

renewable energy resources located in other states to satisfy the state RPS requirements.88

Considerations related to the quantification, monitoring, and verification of renewable 

energy generation used to meet a RPSs depends on the design and implementation of the RPS. 

Distribution utilities subject to a RPS may meet their RPS obligations by building and operating 

their own renewable energy generating facilities, entering into bilateral contracts with other 

parties to purchase renewable energy, and participating in the REC market. Each compliance 

method has specific implications for the quantification, monitoring, and verification of 

renewable energy generation used to meet RPS obligations. Implications under these different 

pathways are discussed below. 

Build renewable generating facilities

In many states, utilities with RPS obligations may build, own, and operate their own 

renewable energy generating facilities. This pathway is often used by vertically integrated 

utilities subject to a RPS. For large renewable energy generating facilities, production is 

measured through a revenue-grade utility meter as it enters the grid at the point of 

interconnection. This meter is subject to the same verification standards as for any other 

generator participating in the wholesale market. 

Some utilities with RPS obligations also build, own, and operate smaller distributed 

renewable energy generating facilities. Smaller generators, such as residential rooftop solar PV 

systems of less than 10 kW capacity, often don’t have discrete metering of their total 

generation.89 State RPS requirements may permit these distributed generators to qualify for use 

in meeting utility RPS obligations based on an engineering estimate of their renewable energy 

generation output , provided the distributed generators are registered with a REC tracking system 

and the generation output is verified according to tracking system and RPS rules. 

                                                            

88 This may also include international renewable energy resources, such as Canadian hydroelectric and wind energy 

resources, which may be used to comply with some state RPSs. 

89 Metered data for these PV systems may only track net electricity supply to or from the grid, representing either 

surplus generation that is not used to serve on-site electricity load or additional net electricity supplied from the grid 

if the system does not meet a building’s total electricity load. 
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Bilateral contract model 

Under the bilateral contract model, distribution utilities with RPS obligations contract 

with renewable energy generators for supply. These contracts typically specify a delivery amount 

in MWh over a specified contract period. These supply contracts may be short- or long-term, 

may specify generation from certain renewable energy EGUs, and may be solicited through an 

RFP or entered into through negotiation. Quantification of renewable energy generation (in 

MWh) is accomplished through the use of a revenue-grade meter that measures the flow of 

electricity from the generator into the transmission grid. A contract may also stipulate an 

adjustment to the metered MWh generation data to account for transmission losses that occur 

between the point of injection of electricity to the transmission grid and the point of receipt at a 

utility transmission or distribution system. A renewable energy supply contract also generally 

addresses the ownership of the RECs related to the renewable energy generation. Under such a 

contract, purchase of the RECs should accompany the purchase of the electricity, in order for the 

utility to satisfy its RPS obligations through the contract.90 

State RPS compliance processes may provide for PUC review of supply contracts, 

including inspection of meters and verification of electricity delivery from the generator to the 

utility distribution network through a specified contract path (e.g., through evidence of 

transmission rights held or scheduled). The purchasing utility also reports their purchase and 

delivery of RPS-compliant renewable energy pursuant to the contract to the state agency 

responsible for RPS enforcement, typically the state PUC or state energy office. Verification is 

accomplished by audit of electricity supply contracts along with REC tracking system reports of 

RECs held by the utility and submitted for retirement by the tracking system administrator. Some 

state RPS require that electricity from qualifying renewable energy sources be produced within 

the state or a specified grid region, or if outside the state or specified grid region, that electricity 

be delivered to the state or grid region. In such cases, the verification of electricity delivery is 

typically done by the REC tracking system administrator before issuing RECs for the imported 

energy. Verification can be provided, for example, by demonstration of scheduled delivery 

                                                            

90 This ensures that multiple parties are not using the same MWh of renewable energy generation to comply with 

their RPS obligations. 
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through the ISO or RTO serving the state or region, through demonstration that the seller holds 

transmission rights for delivery or possession of NERC tags for the energy.91 Bilateral contracts 

also typically require certification by the seller that attributes related to the sold electricity have 

not been and will not be otherwise sold, retired, claimed, represented as part of energy sold 

elsewhere, or used to satisfy obligations in another jurisdiction. 

REC model

Under the REC model, renewable energy generators register their EGU with a renewable 

energy tracking system, which have been established by several regional groupings of states, as 

well as a few individual states.92 The registration process collects data about the generator’s 

attributes: type of resource (e.g., wind), plant-level emissions, geographic location, nameplate 

capacity (MW), commercial operation date, ownership, and the eligibility for RPS compliance or 

voluntary market certification. After the generator is registered, revenue-meter data is 

transmitted to the tracking system. Meter accuracy is verified for renewable energy generators in 

the same manner as for any other generator participating in wholesale electricity markets. 

Each MWh of renewable energy generation reported to the tracking system by a 

registered generator results in the issuance of a REC, with its own unique serial number and 

information about the generator, location, resource type, and the month in which the MWh was 

generated, and the month or quarter in which the certificate was issued. The renewable energy 

                                                            

91 A NERC Tag, sometimes referred to as an E Tag, is an electronic tag that is used to track wholesale electricity 

transactions that involve the transfer of electricity across or through control areas. NERC Tags allow transmission 

system operators to track electricity transactions in real time in order to assess any potential reliability implications 

of scheduled power transactions. NERC Tags define the physical path of an electricity transaction from the point of 

generation to the point of receipt, and also define the financial path, including all parties to a transaction. All 

wholesale electricity transactions that will result in the transfer of electricity from one control area to another, or that 

involve transfers through a control area, must be accompanied by a NERC Tag. Based on a real-time assessment of 

NERC Tags, system operators can curtail transfers if reliability issues would arise as a result of the transfer. NERC 

tags are issued through an electronic system in accordance with specifications established by the North American 

Electric Reliability Corporation (NERC). 

92 Currently, nine regional renewable energy certificate (REC) tracking systems operate in different regions of 

North America, including: Texas Renewable Energy Credit Program, run by the Electric Reliability Council of 

Texas (ERCOT), NEPOOL Generation Information System (GIS), PJM Generation Attribute Tracking System 

(PJM-GATS), Western Renewable Energy Generation Information System (WREGIS), Midwest Renewable Energy 

Tracking System (M-RETS), North American Renewables Registry (NARR), Michigan Renewable Energy 

Certification System (MIRECS), Nevada Tracks Renewable Energy Credits (NVTREC), and North Carolina 

Renewable Energy Tracking System (NC-RETS). For more information see 

http://apps3.eere.energy.gov/greenpower/markets/certificates.shtml?page=3 . 
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generator can then sell the renewable electricity as a bundle (both the commodity electricity and 

the associated REC) or unbundle the RECs from the electricity and sell the two products 

separately. Other market participants, such as brokers, REC marketers, and load-serving entities 

also maintain accounts with the tracking system so that REC electronic transactions can be 

recorded within the tracking system platform. The system tracks each REC through these 

transactions and ultimately “retires” the REC when the final purchaser designates it for 

retirement. Retirement could result from the REC being used to satisfy a state RPS, or as a result 

of a voluntary buyer retiring the REC to demonstrate that they had purchased and used 

renewable energy to meet their electricity demand. 

Because the tracking system follows the REC from the point of issuance to retirement, 

including all interim transactions, it minimizes the opportunity for renewable energy to be 

double-counted across, for example, two different state RPSs, or between two voluntary 

purchasers. In recent years, the various tracking systems have developed interchange standards 

so that RECs generated within one tracking system can be transferred to and used within another 

tracking system.93 Note that not every potential interchange possibility is currently supported, 

and that many states have additional eligibility restrictions within their RPS that may limit the 

use of RECs related to electric generation from distant locations. These include requirements in 

some state RPSs for the seller to hold firm transmission rights for delivery of the accompanying 

electricity from the renewable energy generator into the respective ISO/RTO system or grid 

system in which a state is located. 

Small distributed generators

Smaller distributed generators, such as residential rooftop solar PV systems of less than 

10 kW capacity, often don’t have discrete metering of their total generation. State RPS 

requirements may permit these distributed generators to qualify for use in meeting utility RPS 

obligations based on an engineering estimate of their renewable energy generation output , 

provided the distributed generators are registered with a REC tracking system and the generation 

output is verified according to tracking system and RPS rules. Where such projects are third-

                                                            

93 Additional linkages between tracking systems are being established. More information can be found at 

http://www.narecs.com/resources/registries/ 
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party owned and operated, the project developer will own the RECs and factor their revenue 

value into their pricing offered to the site host for electricity supply. Note also that many utilitysponsored renewable energy incentive programs stipulate that all RECs resulting from the project 

must be transferred from the generation owner to the utility as a condition of participation in the 

incentive program. These RECs can then be used by the utility to meet its RPS obligations, or 

can be sold to other parties. 

State agency role 

In many states, the Public Utilities Commission (PUC) or its equivalent is responsible for 

establishing the detailed rules and procedures that obligated parties must follow to comply with a 

RPS. The PUC is usually responsible for receipt and review of obligated parties’ periodic 

compliance reports, imposing compliance penalties as needed, and for evaluating the impacts of 

the program on energy costs, generation diversity, and market operations. The list of eligible 

resources and MWh requirements are often set through state legislation, but these decisions may 

also be delegated to the PUC for study and promulgation through regulations of commission 

orders. 

In some states the energy office may be responsible for certifying the eligibility of 

specific generators to participate in the RPS and for making siting determinations. In New York, 

for example, the New York State Energy Research and Development Authority (NYSERDA) is 

responsible for the centralized procurement of the renewable energy needed to meet the RPS for 

all of the state’s investor-owned utilities. 

2. Feed-in Tariffs 

Feed-in tariffs (FITs) are offered by some individual electric distribution utilities and 

some states for renewable energy systems that meet eligibility criteria.94 Under a FIT, the utility 

offers to purchase specific kinds of electricity (e.g., solar) from sellers at posted prices or under a 

                                                            

94 There are several states that offer FITs, including California, Hawaii, Maine, Oregon, Rhode Island, South 

Carolina, Vermont and Washington, as well as numerous electric utilities. 
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67 

published pricing formula for a specified period of time. FITs typically have caps on the amount 

of renewable energy that will be purchased by a utility (in MWh of energy or MW of capacity). 

FITs may also include customer impact caps for the tariff as a whole (in total dollars spent or in 

specified retail rate impacts allowable), and may also have limits on the size of any participating 

renewable energy generator from which the utility will purchase electricity through the FIT. FITs 

may also have pricing formulae that are differentiated by resource or that change through time as 

specified benchmarks are achieved (e.g., MW of renewable energy generating capacity subject to 

the FIT, amount of electricity purchased through a FIT as a percentage of utility sales, or retail 

rate impact level reached). Typically, the tariff treats all similarly-situated generators in a 

consistent manner. 

Quantification of renewable energy generation output under a FIT is accomplished 

through the use of a revenue-grade meter to measure the generator’s injection of electricity into 

the grid. The utility’s tariff will typically specify the minimum performance characteristics 

and/or certifications that a meter must meet in order to be used on its system. Utilities retain the 

right to inspect and test the calibration of meters connected to their systems. As the utility will be 

paying the generator each month based on the meter reading, it is in the utility’s interest to 

ensure that the meter is reading precisely and accurately through time. 

Both the utility and the state will need to consider the ownership of the environmental 

attributes arising from the renewable energy generation purchased by a utility through a FIT, and 

whether the renewable energy can be counted toward RPS compliance. If renewable energy 

generation purchased by a utility through a FIT may be counted toward RPS compliance, then it 

should not be counted separately as another renewable energy program in a state plan. 

State agency role 

FITs are usually authorized by state statutes that specify which utilities must offer a FIT, 

eligibility criteria (e.g., renewable energy resource type, location, project MW generating 

capacity limits), and sometimes overall program targets (e.g., total installed MW of generating 

capacity subject to the FIT). State statutes may also specify whether the utilities offering a FIT 

will receive the RECs related to purchased electricity generation output for use in complying 
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with a state RPS, and whether customers receiving FIT payments may also receive incentives 

under other utility and state programs. Typically state statutes leave implementation details to the 

PUC (or other utility governing body, if applicable, for municipal and cooperative utilities), but 

may provide guidance on what to consider in setting FIT payment levels. Based on this statutory 

authority, PUCs develop detailed rules governing implementation, which can include payment 

levels and contract length. PUCs may direct the affected utilities to develop standard contracts 

with all the terms and conditions spelled out, and these standard contracts must be approved by 

the PUC. As with state RPS, the PUC is responsible for receipt and review of the utility’s 

periodic status reports, approving changes to a tariff if needed, and evaluating the impacts of the 

tariff on retail prices, generation diversity, and electricity system operations. 

Several FITs are offered by distribution utilities not overseen by PUCs, such as municipal 

utilities and rural electric cooperatives. These utilities have a variety of governance structures 

(e.g., municipal government, cooperative board of directors). The utility governing bodies in 

these situations will be responsible for receipt and review of the utility’s status reports, taking 

corrective action if needed, and evaluating the impacts of the tariff. 

3. State Tax Incentives 

Several states offer a variety of tax incentives to promote the production and use of 

renewable energy. These currently include sales tax exemptions for certain kinds of equipment 

(e.g., PV panels), property tax abatement for improvements to a building or facility related to the 

asset value of the renewable energy generating system, and income tax credits for the 

installation of renewable energy systems based on capacity or investment level. Several states 

provide a renewable energy production tax credit based on the amount of renewable energy 

generated. This approach is useful because it results in a measureable quantity of renewable 

energy electricity generation. 

With a production-based tax incentive, the renewable energy generator might claim a tax 

credit for each MWh of qualifying renewable energy generation within the state. One design 

consideration for a production-based tax incentive that affects quantification of renewable energy 

generation output is whether the electricity must be sold to a third party as opposed to being used 
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69 

by the site host. In the former case, a revenue-grade utility meter would be present at the point of 

interconnection to the electricity grid, which provides measurement of MWh generation output 

for tax compliance purposes. Site-host use might necessitate the installation of an additional 

meter within the project site to permit reliable measurement of the renewable energy generator’s 

output. 

State agency role

Currently, existing state tax policies are primarily under the authority of the state revenue 

agency. The state revenue agency might have the primary responsibility for establishing the rules 

for production-based tax incentives, although it may seek advice from state energy agencies 

regarding the technical aspects of renewable energy generator operation and the behavior of 

energy markets. The renewable energy generator might claim the tax incentive through the state 

tax collection process and report MWh generation to claim the tax credit. The revenue agency 

could receive tax filings from the owner and operators of renewable energy generators and be 

responsible for determining whether the taxpayer’s claim for tax incentives is supported by the 

MWh generation evidence. Assuming the state revenue authority retains its ability to audit the 

taxpayer’s return, it could verify claimed MWh generation. 

As with FITs, the renewable energy generation resulting from production-based tax 

incentives might be used for RPS compliance. If that were to become the case, then it should not 

be counted separately in a state plan from MWh generation used to comply with a state RPS. 

4. Options for Quantification, Monitoring, and Verification of Renewable Energy 

 Measures in State Plans 

As summarized in the preamble, and discussed in more depth in this section, utilities and 

states have conducted ongoing evaluation of renewable energy measures and programs for 

several decades. These evaluations, which include quantification, monitoring and verification of 

results, generally rely upon a set of standard practices and procedures. In addition, states have 

designed and implemented REC tracking systems to facilitate compliance with state RPS. This 

resource provides the ability to track the location and attributes of renewable energy generators, 
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and the electric generation from these generators, as well as the parties that use RECs for 

compliance with state RPS. As a result, existing state and utility requirements and processes for 

quantification, monitoring, and verification of renewable energy programs and measures 

generally provide a solid foundation for minimum requirements or guidance that might be 

established by the EPA for state plans. 

The programs discussed above (RPS, FIT, and performance-based tax incentives) all 

require quantification, monitoring, and verification of electricity generation from renewable 

energy generators, as well as provisions of other key information, to determine eligibility and 

track program activity or compliance with regulatory requirements (if applicable). Quantification 

of electricity generation is typically through the use of revenue-quality meters,95 or engineering 

estimates for small distributed generators. These data are essential to program management, 

verification of compliance or payments, budget control, and tracking progress toward goals. For 

example, PUCs overseeing compliance with state RPS receive compliance information from 

each obligated utility, including retail sales, compliance status based on MWh of electricity 

generated by eligible utility-owned renewable energy sources, or electricity or RECs purchased 

from eligible renewable energy generators, which may also consider application of multipliers or 

alternative compliance payments.96 PUCs overseeing utility FIT and state agencies overseeing 

performance-based tax incentives managers receive reports containing MWh of electric 

generation from qualified electric generators that received payments under either a FIT or tax 

incentive. These data are essential for normal program management and accountability. 

Current state data requirements under RPS, FIT, and production-based tax incentives are 

tailored to the objectives of these programs and facilitating effective regulatory oversight. 

Typically, avoiding CO2 emissions, while considered a relevant co-benefit, is not a primary 

objective of these regulations and programs. As a result, additional information and reporting 

may be necessary to accurately quantify the avoided CO2 emissions associated with the 

                                                            

95 “Revenue-quality meter” refers to a meter used for billing purposes in wholesale electricity markets, which 

typically need to meet ISO or RTO precision requirements or other specifications. 96 Compliance status will also consider the application of credit multipliers or alternative compliance payments, if 

relevant under an RPS. 
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renewable energy generated through an RPS, FIT, or production-based tax incentive that is 

included in a state plan. 

The following types of information will increase the accuracy and verifiability of avoided 

CO2 emission estimates related to renewable energy requirements, programs, and measures 

included in a state plan. For example, information on the location of the renewable energy 

generation (e.g., in-by state or within a specified grid region) of the renewable energy generation 

used for compliance with state requirements and programs would be helpful in determining 

avoided CO2 emissions. Information about the location of electric generators that supplied 

electricity generation that was imported to a state or grid region, will also be important. Timedifferentiated information related to electricity generation is also useful in estimating avoided 

CO2 emissions. In particular time-differentiated data is necessary to estimate the marginal 

avoided CO2 emissions related to electric generation. Such time-differentiated data could be 

based on metering or engineering estimates for a technology type that indicate the typical 

generation profile for the renewable energy resource. This could include time differentiation on 

an hourly, daily, or seasonal basis. If RECs can be banked and used or RPS compliance at a later 

time than the year in which the electricity generation related to the REC occurred, information 

about the quantity and vintage of RECs from prior year(s) generation that is used for RPS 

compliance will also be useful. 

VI. Reporting and Recordkeeping for End-Use Energy Efficiency and Renewable 

 Energy Programs and Measures

As discussed in the preamble, in section VIII.F.5, reporting and recordkeeping for enduse energy efficiency and renewable energy requirements and programs will be an important 

component of certain types of sate plans. If a state plan incorporates renewable energy and 

demand-side energy efficiency requirements and programs under a rate-based approach or 

implements a mass-based portfolio approach with such measures, reporting and recordkeeping 

requirements for an approvable plan would differ from those applicable to an affected EGU. For 

example, these requirements may include compliance reporting by an electric distribution utility 

subject to an end-use energy efficiency resource standard (EERS) or renewable portfolio 

standard (RPS). They may also include reporting by a vertically integrated utility implementing 
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an approved integrated resource plan. In the latter instance, the utility may also be the owner and 

operator of affected EGUs, but additional reporting of quantified effects of renewable energy and 

demand-side energy efficiency measures under the utility plan would be necessary to 

demonstrate emissions performance under the state plan. In other instances, a state agency or 

entity or a private or public third-party entity may be implementing programs and measures that 

support the deployment of clean energy technologies that are incorporated in a state plan. In each 

of these instances, reporting of program compliance or program outcomes is a necessary part of 

an approvable plan to demonstrate performance under the plan. 

In the preamble, the EPA seeks comment on appropriate reporting and recordkeeping 

requirements for entities implementing end-use energy efficiency and renewable energy 

programs included as enforceable measures in a state plan, or for entities subject to requirements, 

such as an EERS or RPS, that are included as an enforceable state plan measure. This section 

provides examples of current reporting and recordkeeping under state energy efficiency 

requirements and programs, such as EERS, RPS, and utility and state deployment programs for 

energy efficiency and renewable energy. The section then examines the suitability of these 

reporting and recordkeeping practices as potential approaches in an approvable state plan. 

A. Reporting for End-Use Energy Efficiency Programs and Measures

Reporting requirements and time frames (i.e. how often reports are required) for entities 

implementing energy efficiency programs and measures are key considerations for state plans. In 

a state-regulatory context with PUC oversight, impact reports are the mechanism by which 

utilities and other program administrators document energy (MWh) and demand (MW) savings. 

These reports serve as basis for PUC review of total achieved energy savings relative to program 

goals or regulatory requirements, as well as for determining financial performance incentives for 

utilities, where they exist. 

In most states, impact reporting is initially conducted at the level of efficiency 

“programs” (each consisting of numerous “project” installations or efficiency measures 

occurring at individual homes, commercial buildings, or industrial facilities). Program level data 
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73 

are then aggregated to the “portfolio” level to capture the full impact of energy efficiency 

investments occurring under a PUC’s jurisdiction for the timeframe of interest. 

Impacts reports are typically submitted annually, but in some cases program 

administrators also provide interim (e.g., quarterly) reports. This added step can help inform 

progress towards goals, as well as provide for corrections in cases where evaluated (ex-post) 

energy savings are not achieving projected or claimed (ex-ante) savings levels. 

The information provided below presents a range of common reporting elements and 

common practices implemented by state PUCs. These reporting elements and practices – which 

raise important considerations for the reporting of energy-efficiency impacts in state plans – 

include: 

 State EM&V guidelines, protocols, and/or framework utilized, where applicable 

 Energy efficiency policy or program information reported to PUCs in annual reports: 

o Short description of the policies or programs implemented 

o Implementation schedules and timeframes 

 Energy-savings impacts reported to PUCs in annual reports: 

o Incremental annual and lifetime MWh savings for reporting (in the case of an 

energy efficiency program) or compliance years ( in the case of utility compliance 

with a multi-year Energy Efficiency Resource Standard) 

o Peak demand (MW) impacts (reported in many, but not all states) 

 Verification documentation, which shows that installation of energy efficiency measures 

occurred, and the installed measures are capable of generating energy savings 

 EM&V process followed: 

o Date and location of on-site facility visits and field observations 

o Description of public process for review of overall EM&V approach, EM&V 

plan, and EM&V results 
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o Information about evaluators: 

 Name of firms and individuals performing EM&V activities, and 

qualifications 

 Certification that evaluators were selected through a public bid process, 

and are third-parties unaffiliated with efficiency program administrators or 

the state government 

 EM&V methods used: 

o Deemed savings values - name, date, and public location of technical reference 

manual (TRM)97 used for deemed savings values 

o Direct measurement approaches - description of the measurement approaches and 

reference to the EM&V protocols, standards, and guidance documents used 

 Other documentation: 

o Data about the quantity of measures/projects on which the full program-level 

energy savings impacts are based (i.e., information describing the sample size and 

sampling procedures used) 

o Whether net or gross energy savings98 are estimated, definitions used for gross 

and net savings, and the basis for gross to net calculations, if applicable 

o Avoided transmission and distribution (T&D) impacts assumptions, if applied 

The energy savings EM&V reporting elements listed above vary from state to state in 

terms of type and level of documentation, and reports are provided in different formats from state 

to state. This significant variation among states in reporting contents and format raises several 

considerations for states utilizing demand-side energy efficiency programs in state plans. One is 

whether the reporting processes, timeframes, and documentation required by state PUCs, 

described above, are sufficient and appropriate in the context of state plans. Another 

                                                            

97 A technical reference manual (TRM) is a document consisting of predetermined savings values, assumptions, 

methods, and calculation approaches for conducting EM&V of state demand-side energy efficiency programs. Most 

states with robust efficiency programs rely on a TRM. 

98 Gross savings are the change in energy use and/or energy demand that results directly from program-related 

actions taken by program participants, regardless of why they participated in the program. Net savings refer to the 

change in energy use and/or energy demand that is directly attributable to a particular energy efficiency program. 
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consideration is whether lead state agencies that oversee energy efficiency programs should be 

required to certify reported energy efficiency savings impacts on behalf of the state, potentially 

including certification that the values are appropriate and conservative, and meet their approval. 

A final consideration is whether and how energy savings impact reports are made available for 

public input and comment prior to finalization, recognizing that impact reports in many states 

exist but are not easily located or widely accessible by the public, nor are they provided in 

consistent formats from state to state. 

B. Reporting for Renewable Energy Programs and Measures 

1. Typical Reporting and Compliance Requirements under State RPS 

Each state has different reporting and compliance requirements for its RPS, but all states 

with mandatory RPS require obligated entities to provide compliance reports to the state PUC or 

equivalent state oversight agency. Compliance obligations are typically specified in authorizing 

legislation, regulations, or PUC orders. Compliance is typically on an annual basis, and includes 

a list of required reporting elements. Some states also require distribution utilities to provide an 

implementation plan describing how they will comply with the state RPS rules in the future. 

Data requirements for reporting may vary based on the design and implementation of a 

RPS. However, for nearly all state RPS requirements, annual compliance report data is based on 

measurable electric generation results and verified through tracking system data.99 In some 

states, compliance reports may also include state-level projections of renewable energy 

generation resulting from current or proposed state RPS policies. 

The most common form of tracking system for RPS compliance is a regional or state 

REC tracking system or registry. These systems track RECs for both the compliance and 

voluntary markets. RECs are typically provided with a unique identification number and may be 

certified by a third-party verifier. Annual compliance reports containing REC data typically 

include the number of RECs the utility or load-serving entity procured and retired, what 

                                                            

99 Some state RPS require electric utilities to procure a specified amount of renewable energy generating capacity, 

rather than supply a specified number of MWh or percentage of electricity supply from renewable energy generation 

to retail customers. 
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renewable energy generators supplied the RECs, and how much the utility spent on procuring the 

RECs. 

2. Typical Reporting for Renewable Energy Deployment Programs100 

Renewable energy deployment programs involve the provision of a payment or credit for 

a renewable energy project, or for a quantified amount of electricity generation, in the case of 

performance-based incentives. Qualification of eligible projects and payment for qualifying 

electric generation (or related attributes) require reporting of electric generation and other project 

for each specific program. Program administrators use this information to track program progress 

and report to PUCs or other oversight entities. The summary below addresses typical reporting 

required for utility-administered programs, as well as programs administered by non-profit 

entities and state agencies and authorities. 

Reporting for utility administered renewable energy incentive programs 

Some utilities offer incentives to electricity consumers to accelerate the deployment of 

renewable energy technologies, such as rebates, feed-in tariffs, and net metering programs. As 

mentioned previously, it is easier to quantify the renewable electricity generation resulting from 

some programs than it is for others. Utilities administering FITs, for example, will track the 

number of customer contracts, resource type, capacity of each contracted project, MWh 

generated, and utility expenditures for that generation under the tariff. In contrast, utilities 

administering a rebate or loan program are more likely to track the number of customer 

participants, the type and size of the projects, the cost of the projects, and the amount of rebates 

paid or loans provided. Measuring the electric generation output of these projects may not 

necessary to evaluate program status. 

Net-metering is a renewable energy incentive program that is based on performance, but 

where the total output of the net-metered device is often unknown. Utilities reporting on netmetering programs track the number of participating customers, the type and size of net-metered 

systems, and overall net-metered capacity. However, the gross amount of electricity generated 

                                                            

100 In this section, “deployment programs” refers to incentive programs and market transformation programs 

designed to accelerate the market deployment of renewable energy technologies. 
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may not be known if a single bi-directional meter is used. Such meters only record net electricity 

withdrawn from the grid or net electricity production supplied to the grid during an identified 

time period. Utilities and the customers where the renewable energy generating system is located 

may not necessarily know the total electric generation from the renewable energy system, unless 

two meters are installed – one to measure total output from the customer-sited system, and 

another to measure the total electricity purchased from the utility. 

Many of these renewable energy deployment programs are developed as part of 

requirements by PUCs, and therefore utilities must provide reporting on a routine basis to the 

PUC about program expenditures and outcomes (typically quarterly or annually). These records 

should be readily accessible to states for estimating the impacts of their renewable energy 

deployment programs included in a state plan. However, some utility incentive programs are 

administered by distribution utilities that are not regulated by a state PUC (e.g., municipal and 

cooperative electric utilities). In these instances program reporting data may not be readily 

available to a state, unless separately required by a state if such programs are included in a state 

plan. 

Renewable energy deployment programs may be designed and implemented under the 

auspices of a utility integrated resource plan (IRP).101 IRPs document how a utility will meet 

forecasted annual peak and energy demand over a defined period of time through a combination 

of supply-side and demand-side resources. IRPs are typically mandated through state legislation 

or PUC orders and may include renewable energy generation planning, particularly as it relates 

to compliance with in-state requirements. IRPs are typically submitted on an annual basis to a 

state utility commission and/or other state entity, and address a multi-year period (e.g., 10 years 

is a typical period for an IRP). IRPs are a good resource for tracking and forecasting utility 

renewable energy developments within a state. Though they may not include renewable energy 

production data, data included in IRPs may help states project renewable energy generation 

trends in subsequent years, and are a good resource for the development of state plans. 

                                                            

101 IRPs are typically required in states with vertically integrated electric utilities, but are less common in states that 

have deregulated their electricity sectors and introduced competition for the supply of electricity to retail customers. 
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Reporting for renewable energy incentive programs administered by non-profit or state 

entities 

State renewable energy financial incentives are typically administered by a PUC, state 

revenue agency, other state agency (e.g., state energy office), or a private non-profit or for-profit 

entity contracted by a state agency. These programs may include an administrative process for 

pre-qualification, which in some instances may be competitive (e.g., performance-based 

contracts) or available on a first-come, first-serve basis (e.g., capped production tax incentive). 

Applications to incentive programs are good sources of data, and program administrators usually 

compile data from approved applications to track program status. Additional reporting data is 

also typically required to receive the incentive. For example, a production-based tax incentive is 

calculated based on the amount of electricity generated by a renewable energy installation, which 

may be tracked and verified through utility or third-party metering protocols. These reports, 

which are currently used for internal reporting for budgetary control and performance evaluation, 

and to track other performance metrics for regular public program reporting, could form much of 

the basis for reporting under state plans for such measures. 

3. Considerations for Reporting Requirements for Renewable Energy Measures 

 in State Plans 

State renewable energy requirements, such as RPS and FITs, and incentive programs 

typically include robust reporting requirements. For nearly all state RPS requirements, annual 

compliance report data is based on measureable electric generation, using revenue quality 

meters, and verified through tracking system data.102 Other requirements and programs that 

provide performance-based payments and incentives, such as FITs, net metering, and 

performance-based tax incentives, also require reporting of metered generation output.103 State 

and utility incentive programs where payment of incentives is not based on electric generation 

                                                            

102 Small distributed renewable energy systems, such as those below 10 kW in capacity, are often allowed to use 

engineering estimates to determine annual output. 

103 Some of these programs, such as net metering, may also require supplemental reporting in order to track total 

generation that avoids CO2 emissions. In many instances, net metering programs only track the net electricity 

supplied to a customer or supplied to the grid by the renewable energy system, rather than total generation output. 
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may not currently be sufficient for reporting under a state plan. Additional reporting 

requirements may be necessary if these programs are included as enforceable measures in a state 

plan.

In addition to the reporting states currently require for renewable energy requirements 

and programs, supplemental reporting information or adjustments may be necessary for state 

plans to demonstrate the avoided CO2 emissions associated with these requirements, programs, 

and measures. States may need to require additional reporting detail, such as the location of 

renewable energy generating units that supplied output used to comply with a state RPS. 

Additional reporting detail about when renewable energy was generated may also be valuable for 

estimating the avoided CO2 emissions from renewable energy generation, especially if a 

marginal avoided emission rate approach is used. This includes reporting of the typical 

generating profile of a renewable energy generating unit, group of units, or renewable energy 

resource type.104 For distributed renewable energy resources, reporting of the MW capacity of 

generating systems that are installed as a result of state requirements or programs during a 

reporting period would also be useful for estimating avoided CO2 emissions. These distributed 

resources, since they are located “behind” the utility meter at a customer location, have a similar 

effect in reducing the demand for electricity supplied from the grid as end-use energy efficiency 

measures. 

Example reporting requirements that provide sufficient data for estimating the avoided 

CO2 emissions from renewable energy requirements and programs might include the following: 

 Metered MWh generation, using a revenue quality meter, or estimates of annual output 

for small systems below 10 kW in capacity 

 MW capacity of “behind-the-meter” distributed renewable energy generating systems 

added during a reporting period as the result of a state program 

                                                            

104 This might include information about the seasonal or daily generating profile of the generating unit or renewable 

energy resource type. 
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 For renewable energy resources reported, including through REC data, the typical 

generating profile of a renewable energy generating unit, group of units, or renewable 

energy resource type 

 For REC data, information including the following generator attributes: type of resource 

(e.g., wind), plant-level emissions, geographic location, nameplate capacity (MW), 

commercial operation date, ownership, and the eligibility for RPS compliance or 

voluntary market certification 

VII. Treatment of Interstate Emission Effects 

Programs and measures in a state plan, such as RE and demand-side EE measures, may 

affect the emission performance of the interconnected electricity system beyond a state border. In 

addition, many state measures allow for actions in neighboring states to meet the in-state 

requirement, or explicitly address CO2 emissions in neighboring states. For example, many state 

renewable portfolio standards allow for generation by qualifying renewable energy sources in 

other states to count toward meeting the state portfolio requirement. Some states also apply CO2

emission requirements related to the generation of power purchased by regulated utilities, 

including power imported from out of state. 

As discussed in the preamble to the proposal, in section VIII.F.6, the EPA recognizes the 

complexity of accounting for interstate effects associated with measures in a state plan in a 

consistent manner, to minimize the likelihood of double counting. The EPA also realizes that 

interstate effects on CO2 emissions from affected EGUs could be attributed in different ways in 

the context of an approvable state plan. This section discusses in more detail the options and 

alternatives for treatment of interstate CO2 emission effects presented in the preamble. These 

options and alternatives could be applied to both projections of plan performance and 

demonstration of achieved emission performance under a plan. These options and alternatives 

may not be mutually exclusive – in some instances states could apply different approaches, 

without introducing the potential for double counting of emission effects. One option presented 

could lead to double counting of emission effects, and we highlight these aspects of this option in 

the discussion below. 
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In general, the options and alternatives address different possible state plan scenarios, and 

consider the range of interstate approaches that states are currently using to implement electricity 

sector policies, such as multi-state emission budget trading programs and regional renewable 

energy certificate markets for state RPSs. The options and alternatives reflect possible 

accounting approaches for interstate emission effects under CAA section 111(d) that could 

potentially align with these current state programs and measures that we anticipate states may 

want to include in a state plan. 

A. Background 

Electricity flows across state lines. Often electricity load centers (i.e., areas of high 

electricity demand) in one state are supplied in part by generating units in another state. As a 

result, some states are net exporters or importers of electricity on an annual basis. Reducing 

electricity load through improved end-use energy efficiency (e.g., through state energy efficiency 

programs) or deploying new renewable energy electric generating capacity (e.g., through a state 

RPS) therefore can result in CO2 emission effects that are realized outside the state that 

implements the regulation or program that produces the effects. Reducing electricity demand or 

increasing available electric generating capacity also often impacts the economic dispatch curve 

and locational economics that are used to dispatch EGUs on a regional basis. As a result, state 

end-use energy efficiency and renewable energy regulations and programs often have regional 

effects on electricity generation and avoided CO2 emissions. In addition, many state regulations 

explicitly address CO2 emissions in neighboring states, or allow for actions in neighboring states 

to meet an in-state regulatory requirement. For example, many state RPS allow for generation in 

other states to count toward meeting a utility portfolio requirement. 

End-use energy efficiency actions reduce electricity load, and ultimately impact electric 

generation. In some instances improving end-use energy efficiency will reduce electric 

generation nearby a load center (e.g., in the case of a load pocket with limited access to 

electricity transmission capacity). In such cases, it may be feasible to directly link in-state enduse energy efficiency programs and measures to avoided CO2 emissions from specific in-state 

EGUs. More often, reduction of electricity load will impact EGU dispatch across a regional 
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generation control area, based on factors such as power plant economics and electricity 

transmission capability, and could also impact flows between control areas.105 In these cases, 

state end-use energy efficiency programs and measures will affect electricity generation in the 

state that reduces load, as well as in neighboring states. 

State RPS regulations also impact electricity generation at a regional level. Over time, 

state RPSs result in the introduction of new, incremental renewable energy generating capacity to 

regional generation control areas, which affects EGU dispatch at the regional level. State RPSs 

are typically applied to electric distribution utilities as a percentage of sales (e.g., a specified 

percentage of delivered electricity must come from qualifying renewable energy sources). Many 

state RPSs do not require the qualifying renewable energy electric generation to take place 

within the state, or even be delivered into the state, but instead require that the renewable energy 

be supplied within (or delivered into) the ISO/RTO in which the state resides. Often, utility 

compliance with state RPS is through the submission of renewable energy credits (RECs), which 

represent the attributes of renewable energy generation but not the actual electricity generated. 

As a result, in many cases the intent of the state policy is often to affect the characteristics of the 

regional electric generation mix, rather than the state generation mix. 

The approach to implementing an RPS may differ in vertically integrated, cost-of-service 

states where the distribution utility also owns electric generating capacity and dispatches 

generation resources within its service territory. In such cases, the RPS may require a utility to 

increase its renewable energy generating capacity, rather than supplying a percentage of the 

electricity it delivers to retail customers from renewable energy sources to meet load. A number 

of state RPS also include “carve-outs” or “set-asides” where a portion of the renewable energy 

supplied to retail customers must come from renewable energy generating capacity located inside 

the state. Most of these carve-outs are for distributed solar photovoltaic generating capacity, 

which are located at the point of customer end-use (e.g., rooftop mounted solar PV on residential 

                                                            

105 Often these dispatch economics differ by location, based on electricity demand, transmission constraints, and 

generation economics of individual power plants necessary for meeting demand (e.g., in competitive wholesale 

markets, these factors are represented through locational marginal prices (LMPs), which determine dispatch). 
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homes and commercial buildings).106 Distributed solar PV capacity often provides benefits to the 

electric distribution system by improving distribution system reliability and avoiding the need for 

distribution system capacity upgrades. This type of distributed renewable energy generation has 

effects similar to end-use energy efficiency, as it reduces the customer electricity load that must 

be met through large EGUs connected to the grid.107 Regardless of the approach taken, state RPS 

regulations typically have impacts on EGU dispatch, and related avoided CO2 emissions, beyond 

the state border. 

B. Summary of Possible Approaches for Treatment of Interstate Emission Effects 

As discussed in the preamble, the EPA is proposing a set of approaches for addressing 

interstate emission effects that result from the implementation of state plans that incorporate enduse energy efficiency and renewable energy programs. The preamble also solicits comment on 

additional alternatives. The proposed approaches in the preamble include: 

 For EE programs and measures: 

o A state may take into account in its plan only those CO2 emission reductions 

occurring in the state that result from demand-side energy efficiency programs 

and measures implemented in the state. 

o States participating in multi-state plans would have the flexibility to distribute the 

CO2 emission reductions among states in the multi-state area. 

o States could jointly demonstrate CO2 emission performance by affected EGUs 

through a multi-state plan in a contiguous electric grid region, in which case 

attribution among states of emission reductions from demand-side energy 

efficiency measures would not be necessary. 

 For RE programs and measures: 

                                                            

106 A number of RPS also have carve-outs for other renewable energy resources, typically those where there is a 

significant renewable energy resource located in the state. An example is carve-outs for offshore wind energy in 

coastal states. 

107 Distributed solar PV is also typically peak coincident, meaning it provides its greatest electric generation output 

at times of peak system electricity demand. At many times of the day and year, solar PV systems supply electricity 

back to the grid, when PV system output exceeds building electricity demand. 
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o Consistent with existing state RPS policies, a state could take into account all of 

the CO2 emision reductions from renewable energy programs and measures 

implemented by the state, whether they occur in the state and/or in other states. 

o States participating in multi-state plans would have the flexibility to distribute the 

CO2 emission reductions among states in the multi-state area. 

o States could jointly demonstrate CO2 emission performance by affected EGUs 

through a multi-state plan in a contiguous electric grid region, in which case 

attribution among states of emission reductions from renewable energy measures 

would not be necessary 

This section surveys the range of potential approaches that could be applied for 

individual state plans, as well as approaches that could be applied on a regional basis. The 

surveyed approaches include those proposed, as well as alternatives. These basic approaches, 

including variants of some approaches, include: 

 State may only claim the impact of a measure in reducing in-state EGU CO2 emissions 

For plan measures such as end-use energy efficiency and renewable energy regulations 

and programs, estimating the avoided CO2 emissions from in-state versus out-of-state 

EGUs could be addressed through modeling, other analytical tools, or proxy metrics (e.g., 

net import factor). 

 State that implements the measure claims the emissions reduction benefit 

Under this approach, the state that implements the measure (e.g., end-use energy 

efficiency and renewable energy regulations or programs, or an emission limit that 

addresses out-of-state generation) claims the avoided CO2 emissions, regardless of where 

they occur. 

 Cooperative multi-state accounting 

Multiple states are allowed to mutually agree to how they will distribute avoided CO2 

emissions from state plan measures (e.g., end-use energy efficiency and renewable 

energy regulations or programs, or an emission limit that addresses out-of-state 

generation) across their respective EGU fleets. Avoided CO2 emissions are distributed 

among states by agreed formula they derive – an accounting “credit” in one state for 
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out-of-state avoided CO2 emissions is complemented by an accounting “debit” in 

the other state where the avoided CO2 emissions occurred (i.e., through an increase in 

reported CO2 emissions or CO2 emission rate). 

 Tradable regional EE/RE credit market 

This is a variant of the multi-state accounting approach, which could be applicable where 

multiple states in a region are implementing rate-based state plans. Under this approach, 

state end-use energy efficiency and renewable energy regulations and programs that meet 

EM&V guidelines or requirements are allowed to generate credits, based on MWh of 

energy savings or renewable energy generation. These credits, which are denoted in 

avoided tons of CO2 or avoided MWh, could be used by affected EGUs toward 

demonstration of compliance with state rate-based CO2 emission limits within a 

designated region. EE/RE credit issuance could be on a project and/or program basis. 

State accounting for interstate emission effects would be addressed through the credit 

market and determined based on credits held by affected EGUs. 

 Regional demonstration by states of EGU emission performance 

States are allowed to regionally demonstrate emission performance by affected EGUs. 

Stets jointly demonstrate emission performance for affected EGUs, in terms of total CO2 

emissions (under a mass-based multi-state plan) or weighted average CO2 emission rate 

(under a rate-based multi-state plan). 

 The EPA jointly assesses regional performance achieved in aggregate by all individual 

state plans in a grid region 

The EPA assesses interstate effects on a regional basis during the plan review process. 

The EPA requires states to agree to an interstate attribution process only if necessary (i.e., 

if regional performance falls short of the aggregated identified performance levels for 

affected EGUs in individual state plans). Alternatively, the EPA requires plan revisions if 

regional performance falls short of the aggregated regional performance level (i.e., the 

aggregated identified performance levels for affected EGUs in individual state plans). 

Table 3 includes illustrative examples of the application of some of the different 

approaches for addressing interstate emission effects summarized above. The table explains how 
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these approaches might be applied in different state plan contexts. The illustrative examples 

consider the range of approaches states are currently using to implement electricity sector 

policies, all of which interstate effects, such as multi-state emission budget trading programs, 

regional renewable energy certificate markets used for state RPS compliance, and end-use 

energy efficiency programs. 

Table 3. Applied Examples of Intersate Emission Effects Attribution Approaches 

1. State May Claim the Impact of a Measure on CO2 Emissions from Affected EGUs 

 Within its Borders 

Under this approach, the effect of a state measure could be applied to help demonstrate 

emission performance by affected EGUs in the state if it has the effect of avoiding CO2

emissions from those in-state EGUs. This could be done regardless of whether the action taken to 

implement the state measure occurs within or outside the state. For example, renewable energy 

generation that occurs outside the state as a result of a state renewable portfolio standard 
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obligation would still be a valid state plan action, provided the out-of-state renewable energy 

generation has the effect of avoiding CO2 emissions from affected EGUs inside the state. As 

another example, for a state that is a net importer of electricity, improvements in demand-side 

EE and related reductions in electricity demand may reduce the need for generation from both 

affected in-state and out-of-state EGUs. These electricity demand reductions could be applied to 

help demonstrate emission performance by affected EGUs in the state if the reduction in 

electricity demand has the effect of avoiding CO2 emissions from those in-state EGUs. 

Estimating the effect of RE and demand-side EE measures on in-state versus out-of-state 

EGU CO2 emissions could be addressed through modeling, other analytical tools, or proxy 

metrics such as a net import factor. 

Modeling could be used to assess the interstate effects of state measures on EGU CO2

emissions, both for projections of emission performance under the plan and ex post 

demonstration of performance achieved. Under this approach, both projected plan performance 

and performance achieved is assessed on a state-by-state basis. 

 Ex ante projections of plan performance 

 To project the effect of EE/RE measures under a state plan, a dispatch model would be 

applied to a grid region to estimate the marginal or average avoided CO2 emissions impact of the 

plan measures on a state-by-state basis within the region. To the extent that a state’s EE/RE 

measures were projected to avoid CO2 emissions from its own in-state EGUs, these effects could 

be applied to meet the required level of CO2 emission performance for affected EGUs in the state 

plan. (See section IV.C of this TSD for a full discussion of using a dispatch modeling approach 

to projected avoided CO2 emissions that will be achieved through a plan.) 

Ex post demonstration of plan performance

To assess the state-by-state avoided CO2 emissions that result from the implementation of 

a plan, a dispatch model would also be applied to a grid region, on a retrospective “look-back” 

basis. This modeling would assess the avoided CO2 emissions resulting from reported MWh of 

energy savings and MWh of reported renewable energy generation, as a result of implementation 
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of EE/RE measures in the plan. Under a rate-based plan approach, modeled estimates of avoided 

CO2 emissions, based on reported EE savings and RE generation, could be applied through an 

administrative adjustment by the state program administrator or through the issuance of tradable 

EE/RE credits within the state. For ex post demonstration under a mass-based plan approach, 

performance would be determined based on reported stack CO2 emissions from affected EGUs—

no further analysis would be necessary. (See section IV.C of this TSD for a full discussion of 

using a modeling look-back approach to estimate avoided CO2 emissions.) 

Use of simplified proxy metrics to apportion effects among states

Simplified metrics, such as a net electricity import or export factor, might also be applied 

to assess the impact of state actions in avoiding CO2 emissions from in-state affected EGUs. For 

example, in a state that imports 30% of electricity on average during a year, energy savings from 

EE measures might be multiplied by a factor of 0.70.108 Avoided CO2 emissions might then be 

calculated by multiplying this adjusted energy savings number by the average or marginal CO2

emission rate for affected EGUs in the state. This type of approach could be employed in both 

projections of plan performance and ex post demonstrations of performance. However, this 

method would be subject to uncertainty, as electricity net imports may vary significantly on an 

annual basis, due to changes in system dispatch. (See section IV.C of this TSD for a discussion 

of dispatch dynamics that affect avoided CO2 emissions.) 

This approach would avoid double counting of emission effects of state measures among 

states. However, it could reduce incentives for states to employ measures that have a systemwide, regional effect in reducing EGU CO2 emissions. In effect, because an adjustment factor 

would be applied to energy savings under this approach, a net importer state would need to 

achieve greater energy savings through end-use energy efficiency requirements and programs to 

achieve a ton of avoided CO2 emissions under its plan than a state that is not a net importer. 

 

                                                            

108 In this instance, it would be assumed that 30% of the reduction in electricity load resulted in avoided CO2

emissions from out-of-state EGUs that serve electricity load in the importing state. 
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2. State that Implements the Measure Claims the Emission Effects 

Under this approach, the state that implements the measure (e.g., an EERS or RPS, or an 

emission limit that addresses the attributes of purchased electricity from out-of-state generation) 

claims the avoided CO2 emissions, regardless of where they occur. 

If the avoided CO2 emissions from state plan measures at the regional level are greater 

than avoided emissions from affected EGUs within the state, these interstate effects would need 

to be accounted for and applied to affected EGUs within the state. This could be achieved 

through an administrative adjustment by the state, or through a tradable credit system that is 

limited to affected EGUs in the state. 

Under an administrative adjustment approach, out-of-state avoided emissions would be 

applied to the in-state EGU fleet by the state program administrator when determining average 

fleet CO2 emission rate or tonnage CO2 emissions. Under a tradable credit approach, credits 

would be issued for all avoided CO2 emissions resulting from applicable state plan measures, 

without regard to where the avoided emissions occurred. Since the tradable credit system would 

be limited to affected EGUs in the state, use of the credits by affected EGUs when demonstrating 

compliance with a rate-based emission limits would functionally apply the avoided CO2

emissions to the state that was responsible for the measure. 

This approach provides a clear policy signal and incentives that reward state actions that 

reduce EGU CO2 emissions on a system-wide, regional basis. However, this approach, absent 

cooperative accounting among states in a grid region, as described below, will likely lead to 

double counting of emission impacts among states, which could reduce the overall emissions 

reductions achieved through state plans on a national basis under CAA section 111(d). We also 

note below that other approaches could also provide incentives for a regional, system-based 

approach to achieving CO2 emissions reductions from affected EGUs, without raising the 

prospect of double counting of emission effects among state. 

 
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3. Cooperative Multi-State Accounting of Interstate Emission Effects 

Under this approach, multiple states would be allowed to mutually agree on how they 

will distribute avoided CO2 emissions from RE and demand-side EE measures across their 

respective EGU fleets. Avoided CO2 emissions would be distributed among states according to a 

formula that they specify. Based on this agreed formula, each state would adjust its demonstrated 

emission performance by affected EGUs accordingly. In effect, a “credit” for out-of-state 

emission effects in one state would be complemented by a “debit” for such effects in another 

state. 

This approach provides states with discretion about how to attribute interstate effects, 

based on their situations and policy preferences in a grid region. Importantly, this approach also 

avoids the potential for double counting of interstate emission effects among states. However, 

this approach is premised on regional collaboration among all states in a grid region. Not all 

states in a grid region may be willing to cooperate in implementing such an accounting approach. 

4. Tradable Regional EE/RE Credit Market 

Under this approach, RE and demand-side EE actions that meet applicable quantification, 

monitoring, and verification requirements would be issued tradable credits that could be applied 

by affected EGUs to their reported CO2 emission rates when demonstrating compliance with an 

emission limitation in a state plan.109 A credit issued in one state could be used by an affected 

EGU in another state toward meeting its respective rate limit.110

A regional credit market would be premised on agreement among states that credits 

issued throughout a region could be used in multiple states. The distribution among different 

states of usage of the credits would be determined by economic factors such as credit prices and 

                                                            

109 These credits might be denoted in avoided CO2 emissions or MWh of electricity savings or electricity generation, 

as described above in Section VI.E.3., incorporating RE and demand-side EE measures under a rate-based approach. 

Depending on a state’s circumstances and its plan approach, these tradable credits might represent a new instrument 

created for use under a state plan, or a state might use an existing instrument, such as RECs. 

110 Credits could be issued on a program or project basis. The types of measures for which credits could be issued 

and the basis for issuing credits would be an enforceable element of a state plan. 
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EGU marginal emissions abatement costs. In effect, accounting of interstate effects would be 

allocated among states based on prices in the credit market. 

This approach is applicable if multiple states are implementing rate-based state plans. 

Where states were implementing a mix of rate-based and mass-based state plans in a shared grid 

region, this approach would lead to double counting of emission effects among plans, unless this 

market-based EE/RE credit approach was also coupled with a cooperative accounting agreement 

among states. In this latter instance, for states implementing a mass-based approach, where 

credits for avoided CO2 emissions are transferred to affected EGUs located in another state for 

compliance purposes, the state from which credits were transferred would adjust its reported CO2

mass emission from affected EGUs when demonstrating achievement of the required CO2

emission performance level by affected EGUs identified in the state plan.111

5. Regional Demonstration by States of Emission Performance 

Under this approach, multiple states would demonstrate CO2 emission performance by 

affected EGUs on a regional basis.112 This could allow states in a contiguous grid region to 

implement a portfolio of RE and demand-side EE measures without the need for state-by-state 

attribution of avoided CO2 emissions. Instead, states would assess the impact of state measures in 

avoiding CO2 emissions from the fleet of affected EGUs in the multi-state region. 

This approach creates incentives for the implementation of system-based approaches that 

collaboratively reduce EGU CO2 emissions on a regional basis, while also avoiding the need to 

attribute interstate emission effects among states. However, regional collaboration will require 

more time for the development of multi-state plans. This approach is also premised on the 

                                                            

111 Note that in this example, state reporting of overall achieved CO2 emission performance by affected EGUs 

under a state plan is distinct from demonstration of compliance by affected EGUs subject to a mass-based CO2

emission limit. For EGU compliance, no adjustment would be made to CO2 emissions reported by affected EGUs 

subject to the mass-based emission limit, even though emissions from these affected EGUs may have been reduced 

as a result of EE/RE regulations and programs implemented in a neighboring state. In this case, the state would 

adjust the overall CO2 emissions from the affected fleet to account for the “export” of avoided CO2 emission credits, 

in order to demonstrate the overall level of CO2 emission performance that is assumed to have been achieved by the 

affected EGU fleet under the plan. 

112 This approach could be applied for CO2 emission performance on either a rate or mass basis. 
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willingness of all states in a grid region to participate in the development and implementation of 

a multi-state plan. Some states in a grid region may be unwilling to collaborate regionally. 

6. Assessment of Interstate Effects by the EPA in the Course of State Plan Review 

Under this approach, the EPA would evaluate interstate effects on a regional basis during 

the plan review process.113 The EPA would assess the emissions performance of affected EGUs 

on a regional basis, considering the measures contained in the group of state plans for a 

respective grid region. Under this approach, the EPA might conduct an analysis that considers all 

of the state program measures together on a combined basis and evaluates projected emissions 

performance achieved by affected EGUs in the region. 

To the extent that all affected EGUs in a region are projected to achieve the required level 

of performance represented in individual state plans, or are projected to achieve an aggregate 

regional level of performance consistent with the level of required performance included in all 

state plans in the region, instances of double counting of interstate effects among states are less 

important. The EPA could indicate as part of plan approval that it will review actual emission 

performance achieved by affected EGUs during the plan period on a regional basis. 

VIII. Appendix 

Survey of Existing State Policies and Programs that Reduce Power Sector CO2 Emissions 

[This appendix will include the content in the document, Survey of Existing State Policies and 

Programs that Reduce Power Sector CO2 Emissions. This draft document was submitted to OMB 

on April 3, 2014.] 

                                                            

113 For example, this assessment could be for a multi-state region that generally aligns with a contiguous grid 

region.