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 2014DRAFT, DELIBERATIVE

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2 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 Stat e 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 Efficien cy and Renewable Energy Programs and Measures under a Rate-Based Approach ......................................................................19 A. Concept of Adjusting EGU CO 2 Emission Rates based on the Effects of End-Use Energy Efficiency and Renewable Energy ..................................................................19 B. Approaches for Adjusting EGU CO 2 Emission Rates ............................................20 C. Methods and Tools for Quantifying Avoided CO 2 Emissions from End-Use Energy Efficiency and Renewable Energy .........................................................................23 V. Quantification, Monitoring, and Verifica tion of End-Use Energy Efficiency and Renewable Energy Programs and Measures .................................................................32 A. Quantification, Monitoring, and Verifi cation for End-Use Energy Efficiency .....35 B. Quantification, Monitoring, and Verifi cation 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 Effi ciency Programs and Measures .....................72 B. Reporting for Renewable En ergy Programs and Measures ...................................74 VII. Treatment of Interstate Emission Effects ......................................................................79 A. Background ............................................................................................................81 B. Summary of Possible Approaches for Tr eatment of Interstate Emission Effects..83 VIII. Appendix ...................................................................................................................... .....92DRAFT, DELIBERATIVE

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3 I. Introduction

As discussed in the preamble, in section V III.F, the EPA is proposing to give states broad discretion to develop state plans that best suit their circumstances a nd policy objectives. In developing its plan, a state will need to make a number of deci sions that will require careful consideration, in order to ensure that its plan both meets a st ate’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 differe nt types of state plan appro aches. This includes a number of

considerations related to appropriate approaches, methods, a nd materials that are submitted for state plan components in an appr ovable plan, under different types of state plans. This technical support document (TSD) explains and discusses th ese considerations in depth, and elaborates options proposed in the preamble where releva nt. Topics addressed in this TSD include:

 Description of stat e plan pathways

o Provided as context for the discussion of applied cons iderations that follows

 Enforceability considerations under different plan scenarios

o Summary of potential enforceable m echanisms under different state plan

scenarios

 Incorporating energy efficiency and re newable energy (EE/RE) requirements and programs in state plans, including:

o Options for adjusting EGU CO 2 emission rates based on the effect of EE/RE requirements and programs

o Methods for estimating avoided CO 2 emissions that result from EE/RE requirements and programs

 Quantification, monitoring, and verificati on of EE/RE requirements and programs

o Survey of quantification, monitoring, and verifica tion under existing state and utility EE/RE requirements and programsDRAFT, DELIBERATIVE

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4 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 exis ting state processes and infrastructure

o Discussion of areas where supplementa l information would be useful for estimating avoided CO 2 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 stat e processes and infrastructure

o Discussion of areas where supplementa l information would be useful for estimating avoided CO 2 emissions from EE/RE requirements and programs

 Treatment of interstate emission effects

o Further elaboration of proposed approach es and alternatives discussed in the preamble

It should be noted that the preamble discu sses, and solicits comment on, legal issues concerning whether CAA section 111( d) authorizes some of the type s 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, assu mes 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 requirement s, programs, and measures, through two basic approaches – direct emission limits and a por tfolio approach. These two basic approaches provide four distinct state plan “pathways” under CAA section 111(d). These pathways include:DRAFT, DELIBERATIVE

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5  Rate-based CO 2 emission limits applied to affected EGUs;

 Mass-based CO 2 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 combin ation of measures that reduce

CO 2 emissions at affected EGUs through the appli cation of emission limits as well as measures

that involve actions within the in terconnected electricity system that reduce utilization at affected EGUs and thereby avoid EGU CO 2 emissions. Examples of thes e latter measures include, among others, end-use energy efficiency resource standa rds and renewable energy portfolio standards, as well as certain components of ut ility integrated resource plans. A state could either rely solely

on CO 2 emission limits that are enforceable against affected EGUs or, alternatively, rely on a portfolio approach, which would include those li mits as well as other enforceable measures. Table 1 provides practical examples of possibl e state plan approaches under each of these pathways, which are discusse d in more detail below.

This section elaborates the different plan a pproaches that are discussed in section VIII.B of the preamble, to provide context for the app lied 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 CO 2 emission limits for affected EGUs that also provide for the adjustment of CO 2 emission rates based on the effect of enforceable end-use energy efficiency and rene wable 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 woul d apply to states implementing a rate-based emission limit approach that provides for adjustment of CO 2 emission rates based on the effect of end-use energy efficiency and renewable energy, as well as states implemen ting utility- or state-DRAFT, DELIBERATIVE

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6 driven portfolio approaches that incorporate end-use energy efficiency and renewable energy requirements and programs. Likewi se, section VI of this TSD addresses considerations for reporting and recordkeeping for end-use energy e fficiency and renewable energy requirements and programs, which would apply fo r these types of state plans.

Table 1. Different Illustrative Plan Approaches

A. Direct Emission Limits

The first basic state plan approach is CO 2 emission limits that apply directly to affected EGUs, and includes two pathways: 1.) rate-based CO 2 emission limits applied to affected EGUs; and 2.) mass-based CO 2 emission limits applied to affected EGUs. For both types of emission limits, end-use energy efficiency and rene wable energy measures that avoid EGU CO 2 emissions could be a major component of a state’s overal l strategy for cost-effect ively reducing EGU CO 2 emissions.DRAFT, DELIBERATIVE

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7 1. Rate-Based CO 2 Emission Limits Applied to Affected EGUs

Rate-based emission limits would apply a lb CO 2 /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 sour ces, or the use of tradable credits for avoided

CO 2 emissions resulting from end-use energy e fficiency and renewable energy measures as discussed below. In the case of the latter appr oach, such credits could be used by an affected EGU to adjust its CO 2 emission rate when demonstrating co mpliance with a rate-based emission

limit. 1 Rate-based emission limits could be implem ented on a state-by-state basis, or through multi-state averaging or trading. Rate-based em ission 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 pe rformance 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 incorpor ate end-use energy efficiency and renewable energy measures that avoid EGU CO 2 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 CO 2 emission rate. 3 Under this approach, end-use energy efficiency and renewable energy m easures that avoid EGU

CO 2 emissions would be enforceable components of a state plan. These actions would need to be enforceable components of a state plan to pr ovide assurance that a sufficient amount of

1 Section IV of this TSD discusses possi ble approaches for such adjustments. 2 Under a tradable credit system, a state would issue adjustment credits based on avoided CO 2 emissions achieved through end-use energy efficiency and renewable ener gy measures. EGUs could then apply these tradable adjustment credits when demonstrating compliance with a rate-based CO 2 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. Un der an administrative adjustment appr oach, a state program administrator might administratively adjust an affected EGU’s CO 2 emission rate based on avoided CO 2 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 metr ic. Affected EGUs would then begin with an adjusted CO 2 emission rate when considering additional actions necessary for compliance with the rate-based CO 2 emission limit. 3 Section IV of this TSD discusses po ssible approaches for such adjustments.DRAFT, DELIBERATIVE

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8 adjustment credits will be available to facili tate EGU compliance with the emission rate limit, and that end-use energy efficiency and renewabl e energy measures that generate adjustment credits are properly quantified, monitored, and verified. 4

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

Mass-based emission limits would a pply either an individual limit on CO 2 tons emitted

from an affected EGU or establish a finite CO 2 emissions budget for a group of affected EGUs. The latter approach is typically implem ented through a tradable allowance system.

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

CO 2 emissions could be a major component of a state’s overall strate gy for cost-effectively reducing EGU CO 2 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 CO 2 emissions limits, or to ach ieve other policy goals, but CO 2 emissions performance would be assured throug h 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 aff ected 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 renewabl e energy measures that avoid EGU CO 2 emissions. A portfolio approach could be state-driven or u tility-driven, depending on the utility regulatory

structure in a state.

In general, a portfolio approach is disti nguished 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.DRAFT, DELIBERATIVE

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9 specified in the plan is not ensu red through the application of dire ct emission limits that apply to

affected EGUs.

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

EGUs and other indirect m easures that avoid EGU CO 2 emissions. Under a portfolio approach, end-use energy efficiency and renewabl e energy measures that avoid EGU CO 2 emissions would be enforceable components of a state plan. Th is would be necessary because the emission limit applied directly to affected E GUs would not assure full achieve ment of the required level of emission performance specified in the state plan. 5

As discussed below, due to differences in st ate utility regulatory st ructure, a portfolio approach implemented in a restructured state with retail competition will likely look quite different from one implemented in a state with ve rtically integrated, regul ated electric utilities. This includes the process for developing th e portfolio approach, the mechanisms for implementing it, the responsible parties, and the regulatory and legal rela tionships among parties and state regulators.

1. State-Driven Portfolio Approach

A state-driven portfolio appro ach – rather than a utility-dri ven 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 s upply retail customers with electricity. 6 Electric

distribution utilities in these states typically purchase electri city 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

5 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 em ission limit to a subset of affected EGUs. Both scenarios would necessitate inclusion of supplemental measures, such as end-use energy efficiency and renewable ener gy, or other measures that directly apply to affected EGUs (e.g., repowering or re tirement 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 instance s, there typically are legal provisions in place that mandate the independent management and operation of generation and distribution assets.DRAFT, DELIBERATIVE

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10 portfolio approach, are much more common in states with regulated vertically integrated utilities that own and operate elec tric generating assets.

In restructured states, policies for increas ing end-use energy effi ciency and renewable energy are often established through regulations that apply to electr ic distribution utilities, such as end-use energy efficiency resource standard s and renewable portfolio standards. Many of

these states have also establis hed independent non-profit entities to administer end-use energy efficiency and renewable energy deployment programs funded through re gulated electricity

rates.

Under a state-driven portfo lio 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 distri bution 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-regulate d electric utilities is more likely to adopt a utility-driven portfolio approac h. In such states, private util ities own and operate electric generation, transmission, and distribution system s 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, al ong with a specified financial ra te of return, through regulated retail electricity rates. State utility commissions of ten require regulated uti lities to engage in an integrated resource planning (IRP) process, which s eeks to identify the least-cost set of resources available to provide electricity to retail cust omers over a multi-year period, and often includes

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

7 In some instances these regulated utilities may supplemen t electric generation with purchases through wholesale electricity markets and may also sell surplus generation in these wholesale markets on a competitive basis.DRAFT, DELIBERATIVE

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11 renewable energy. 8 Once an IRP is approved by a state publ ic 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 pr ocess 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 le vel for affected EGUs among utilities.

A utility plan under this approach might re ly 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 reti rement of high-emitting units. Such plans might

also include direct emission limits on affected EGUs, or implementation of an environmental dispatch approach that incorporates CO 2 emission rate into the disp atch protocol used by the utility to schedule electric generation. 10

Under a utility-driven portfolio approach, the entire suite of obliga tions 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 CO 2 emission performance by these affected EGUs.

A similar approach could be taken by munici pally owned utilities or utility cooperatives, which often also engage in an IRP process. Ho wever, state public util ity commissions (PUCs)

8 Depending on the state, an IRP process may also asse ss factors such as fuel diversity and environmental performance, among others, when identifying th e least-cost mix of resources for a utility. 9 In some cases, an IRP prescribes or authorizes specific actions. In others, an IRP serv es as a guide for the utility and the public utility commission when evaluating acquisitio n or implementation of specific utility resources or programs. In such cases, the specific resource or program is approved thro ugh a PUC order that authorizes or requires actions and identifies performance obligations. Th ese orders may or may not be fully consistent with provisions in an IRP. 10 Vertically integrated utilities, even if they operate w ithin the footprint of a competitive wholesale electricity market, may self-schedule generation assets.DRAFT, DELIBERATIVE

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12 often do not regulate these utilities. As a result, implementatio n of a portfolio approach by these entities would introduce practical enforceab ility considerations under a state plan. III. Enforceability Considerations under Different State Plan Scenarios

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

include enforceable measures. To ensure that it s 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 aff ected EGUs are not in compliance with plan requirements or if other entities fail to meet enforceable plan obligations

As discussed in the preamble, responsible enti ties in an approvable state plan may include an owner or operator of an affect ed EGU, other entities with res ponsibilities assigned by a state, or the state itself. Other entities might include an en tity that is regulated by the state, such as an electric distribution utility, or a private or publ ic third-party entity. St ate responsibility might include obligations that are assume d directly by a state agency, aut hority, or other state entity to carry out aspects of a state plan.

While this approach provides states with br oad discretion to devel op plans that best suit their circumstances and policy ob jectives, assigning re sponsibility to other parties regulated by the state, private or public third-party entitie s, or state entities raises enforceability

considerations. This section disc usses how the general enforceability approach discussed in the preamble, and described above, might apply in practice under different state plan approaches.

This section describes possibl e scenarios of responsible en tities and legal mechanisms and approaches that might be used to address enforceability considerations under different types of state plans. These scenarios we re developed to capture the range of entities that are currently implementing end-use energy efficiency and renewa ble energy deployment programs in states, or are subject to states requirements such as e nd-use energy efficiency resource standards (EERS)DRAFT, DELIBERATIVE

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13 or renewable portfolio standards (RPS). For each of these examples, this section describes current legal relationships between these entiti es 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 t hose obligations. The mechanisms discussed take different forms, but would specify the three el ements described above: obligations, compliance demonstration, and enforcement mechanisms. Th is 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 incl usion of enforceable obligations for stateregulated entities other than affected EGUs. An exam ple 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 th e deployment of end-use energy efficiency and renewable energy technologies.

Another example is where a vertically inte grated, 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 (L DCs). 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.DRAFT, DELIBERATIVE

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14 1. Electric Distribution Utility with Obligatio ns to Meet an EERS or RPS Pursuant to State Regulations

EERS and RPS requirements are typically im plemented through state regulations, but may also be implemented through a public util ity commission order. State EERS and RPS regulations provide legal instruments generally comparable in enforceability to regulatory emission limits applied to EGUs. These regula tions typically specify compliance obligations, reporting, and enforcement. However, many stat e RPS regulations and some EERS regulations include alternative compliance payment (ACP) provi sions that provide the utility with the option of making a payment in lieu of full compliance w ith the portfolio require ment. 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 CO 2 emissions, and may also include compliance with EERS and RPS regulations. Broadly, IRPs may prescribe or auth orize actions for which utilities can recover capital investments and operating costs th rough 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 enfo rceability 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 CO 2 emissions include somewhat similar provisions. For example, both the RGGI state CO 2 emission budget trading programs and the California GHG emission budget trading program include cost containment prov isions where more emission allowances are made available to affected sources at certain allowance price thre sholds. In both these instances, such relevant characteristics of the state regulations would need to be take n into account when projecting the CO 2 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 serv es as a guide for the utility and the public utility commission when evaluating acquisitio n or implementation of specific utility resources or programs. In such cases, the specific resource or program is approved thro ugh a PUC order that authorizes or requires actions and identifies performance obligations. Th ese orders may or may not be fully consistent with provisions in an IRP.DRAFT, DELIBERATIVE

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15 certain actions, beyond denial of rate recovery or a change to utility tariffs if a utility fails to meet specified obligations in th e IRP. If so, this may require state legislation to provide additional authority to state public utility comm issions 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 pub lic or private third-party entities with enforceable obligations under a state plan. A private or public third-party enti ty could be a utility entity that is not regulated by a state public utility commission, su ch as a municipal utility or a utility cooperative. 14 It could also be a private non-profit en tity 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-prof it entities are created by state legislation and overseen by state public utility commissions or state-regulated private utilities.

An appropriate legal instrument or agreemen t applicable to such entities included in a state plan might include legal arrangements si milar to those currently used to establish independent entities that expend electricity ratepa yer dollars in multiple st ates. For entities not subject to state oversight, such a m echanism might also include mechanisms where an entity voluntarily submits to the authority of a state, pu rsuant to state statutor y 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 auth ority as a condition of receiving certain funds, such as state appropriated funds or funds coll ected through state-regula ted electricity rates. Alternatively, a municipal utility or utility cooperative might volunt arily submit to state authority as a condition of the state agreeing to let the entit y implement a portfolio a pproach, in lieu of the application of certain direct CO 2 emission limits for affected E GUs owned and operated by such entities through a state regulation. In some cases, new state statut ory authority might be enacted

14 Here, “not regulated” refers to regu lation of electricity rates by a state public utility commission. To the extent that such entities are owners and operators of affected E GUs, 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 Dela ware Sustainable Energy U tility, and Efficiency Vermont.DRAFT, DELIBERATIVE

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16 to support a state plan, specifying enforceable oblig ations 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 en ergy efficiency deployment pr ogram, should specify a stable budget authority and funding source through each pl an performance period. Such authority and funding might be necessary to ensu re that suitable funds are made available to achieve the level of energy savings or renewable energy deploymen t 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 co mponent 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 indepe ndent 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 stat e 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) stat e 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).DRAFT, DELIBERATIVE

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17 An additional consideration is whether such legal arrangements, if related to a renewable energy or end-use energy effi ciency deployment program, shoul d 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 w ould demonstrate emission performance from affected EGUs in aggregate jointly with partner states. For states participating in a multi-state approach, the individual state pe rformance 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 E GUs subject to the multi-state plan achieve a weighted average CO 2 emission rate that is c onsistent, in aggregate, w ith an aggregation of the state-specific rate-based CO 2 emission performance goals estab lished in the emission guidelines that apply to each of the part icipating states. If states were taking a mass-based approach, participating states would demonstrate that all a ffected EGUs subject to the multi-state plan emit a total tonnage of CO 2 emissions consistent with a transl ated multi-state mass-based goal. This multi-state mass-based goal would be based on transl ation of an aggregation of the state-specific

rate-based CO 2 emission performance goals established in the emission guidelines that apply to each of the partic ipating states.

1. Multi-State Emission Budget or Ra te-Based Emission Trading Programs

The Regional Greenhouse Gas Initiative (RGGI) is an example of a multi-state approach to regulation of CO 2 emissions. Through this initiative, ni ne states are currently implementing

coordinated CO 2 emission budget trading programs. Th e program works as a coordinated regional whole through a shared emission and allowance tracking system and allowance auction process, but is implemented in accordance w ith materially consistent stand-alone state regulations and individual statutory authority. Thes e regulations recognize CO 2 allowancesDRAFT, DELIBERATIVE

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18 issued by other participating states for use by a ffected EGUs when complying with each state’s emission limitation, but contain all the necessa ry components to administer the program requirements on an individual state basis. 18 As a result, while the initiative is implemented regionally, each CO 2 emission budget trading program regulati on is enforceable against affected

EGUs at the state level and func tions as a discrete program.

As a result, a multi-state emission budget trad ing 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 enforceab ility considerations. If it were based on interdependent em ission 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 pa rt, on actions taken in ot her participating states. If a state (or states) failed to implement comm itments under the multi-state plan, this raises the question of whether the EPA shoul d address non-performance of one or more participating states in the context of failure to achieve the requi red level of multi-state emission performance under the plan, or instead enforce actions at the individu al state level for those st ates that are failing to meet commitments under the multi-state plan.

18 The emission limitation consists of a requirement to submit CO 2 allowances equal to reported CO 2 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 CO 2 emission constraint is regional, based on the sum of state CO 2 emission budgets. 19 Enforceability would be contingent , in part, on states having comparable enforcement mechanisms.DRAFT, DELIBERATIVE

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19 IV. Incorporating End-Use Energy Efficiency a nd Renewable Energy Programs and Measures under a Rate-Based Approach

A. Concept of Adjusting EGU CO 2 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 measur es may be incorporated into a rate-based plan approach. 20 Measures that avoid CO 2 emissions from affected EGUs, such as quantified and verified end-use energy savings and renewable energy generation, co uld be used to adjust the

CO 2 emission rate of an affected EGU when de monstrating compliance with a rate-based CO 2 emission limit. Alternatively, a state could use the effect of such measures as a basis for administratively adjusting the average CO 2 emission rate of affected EGUs when demonstrating achievement of the required emission ra te performance level in a state plan.

Under this approach, affected EGUs could comply with a rate-based CO 2 emission limit through actions at the EGU, 21 as well as through the use of credits 22 for actions that occur

elsewhere in the interconnected electricity system that avoid CO 2 emissions from affected EGUs. If a state is implementing a portf olio approach, then the state c ould administratively adjust the average CO 2 emission rate of affected EGUs thr ough a similar process when demonstrating achievement of the required emission rate performance level in the state plan.

This section explores in depth the mechanic s and implications of the different possible approaches for adjusting CO 2 emission rates that are summari zed in the preamble. Aspects of this discussion may apply to both retrospective demonstration of CO 2 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. Ho wever, 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.DRAFT, DELIBERATIVE

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20 achieved by affected EGUs under an appr oved state plan and projections of CO 2 emission performance by affected EGUs included in a submitted state plan.

B. Approaches for Adjusting EGU CO 2 Emission Rates

As discussed in the preamble, credits or adjustment to an EGU CO 2 emission rate, based on the effect of RE and demand-side EE program s and measures, might represent avoided MWh of electric generation or avoided tons of CO 2 emissions. 23 If adjustment or credits represent avoided MWh, they would be added to the denominator of the lb CO 2 /MWh emission rate when determining an adjusted lb CO 2 /MWh emission rate. If adjustment or credits represent avoided

CO 2 emissions, they would be subtracted from th e numerator when determining an adjusted lb

CO 2 /MWh emission rate. The approach chosen coul d affect the amount of credit or adjustment provided for RE and demand-side EE programs and measures. Thes e implications are discussed

below.

1. Adjustment of CO 2 Emission Rate based on Avoided MWh

One approach is to adjust an EGU’s CO 2 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 appro ach implicitly assumes that the avoided

CO 2 emissions come directly from the particular affected EGU (or group of EGUs) to which the adjustment or credits are applie d. It assumes, in effect, that an additional emission-free MWh is being generated by that respective EGU, and th at the RE or demand-side EE measure reduces

CO 2 emissions from that indivi dual EGU or group of EGUs. 25 In practice, the average or marginal CO 2 emission rate in the power pool or iden tified region – representing the avoided

CO 2 emissions from the generating sources being displaced by a MWh of energy savings or a

23 The preamble solicits comment on the ap propriateness of these different appr oaches, 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 CO 2 emission performance goals for affected EGUs. As discussed in the preamble, states may have flexibility to use a diff erent approach when demonstr ating the effect of these measures in a rate-based state plan. 25 As a result, the assumed avoided CO 2 emissions from an individual MWh of energy savings or generation from renewable energy will differ based on the reported CO 2 emission rate of the individual EGU to which the MWh is applied as an adjustment to its MWh output.DRAFT, DELIBERATIVE

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21 MWh of renewable energy generation – could diff er significantly from the calculated avoided

CO 2 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 CO 2 /MWh generates 1,000 MWh. Also assume that 1,000 emission-free MW h credits for the effect of demand-side EE measures are added to the denominator when calculating the EGU’s adjusted CO 2 emission rate. The adjusted CO 2 emission rate is 1,500,000 lb CO 2 divided by 2,000 MWh, which equals a

CO 2 emission rate of 750 lb CO 2 /MWh. In this example, each MW h credit represents 750 lb of

avoided CO 2 emissions.

Example 2 : The same calculation applied to an affected EGU with a 2,000 lb CO 2 /MWh rate would yield a different result. In this in stance the adjusted emission rate is 2,000,000 lb CO 2 divided by 2,000 MWh, which equals a CO 2 emission rate of 1,000 lb CO 2 /MWh. In this example, each MWh credit represents 1,000 lb of avoided CO 2 emissions.

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

An alternative approach is to provide an adjustment to the CO 2 emission rate of an EGU, or cohort of EGUs, based on the estimated CO 2 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 CO 2 emissions may come from the electric power pool or other identified region as a whole, rather than an individual EGU. The avoided CO 2 emissions are determined based on the MWh saved or generated, multiplied by a CO 2 emission rate for the power pool or region.

This CO 2 emission rate could be based on the aver age or marginal emission rate in the power pool, region, or state. A marg inal avoided emission rate repr esents 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 ra te is based on either all fossil generation in a region or total generation. This approach assu mes that every MWh saved or generated equally displaces generation from every gene rator in a power pool or region.DRAFT, DELIBERATIVE

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22 Another approach that has been suggeste d 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 pe rformance for affected EGUs specified in a state plan). For example, under this approach, if th e emission rate limit were 1,500 lb CO 2 /MWh, one MWh of energy savings or renewable energy generati on would result in a credit or adjustment representing 1,500 lb of CO 2 that could be subtracted from the numerator of an EGU’s CO 2 emission rate. This approach assumes that affected EGUs jointly emit CO 2 from the stack on an average basis at this required compliance leve l (i.e., consistent with a “closed” averaging system), and that a MWh saved or generated avoids CO 2 emissions from affected EGUs at this average compliance level. 26

3. Other Considerations

Some of the CO 2 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-aff ected 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 stan dards under CAA section 111(b). Furthermore, as the fleet capital stock slowly tu rns over, affected EGUs under s ection 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 wh en crediting or adjusting CO 2 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 di stinctions 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 meas ures. 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.DRAFT, DELIBERATIVE

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23 C. Methods and Tools for Quantifying Avoided CO 2 Emissions from End-Use Energy Efficiency and Renewable Energy

1. Introduction

There are a number of approach es for quantifying the avoided CO 2 emissions resulting from end-use energy efficiency and renewabl e energy (EE/RE) programs, requirements and

measures 27 in the electric sector. These approaches ra nge from the application of basic avoided emission rates to using sophisti cated electric sector models. 28 Annual average avoided emission rates have often been used for rough approximations of CO 2 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 c ohort 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 firs t unit(s) to be brought offline when electricity load is reduced.

The primary question underlying estimating CO 2 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 approach es, their underlying assumptions,

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

2. Average Emission Rate Approach

An average emission rate (typi cally expressed in tons of CO 2 /MWh) is usually understood to mean the average of all genera tors’ emissions rates, weighted by annual generation. The rate (r avg ) 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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24 ݎ

௔௩௚ ൌ ∑ ݁ ௜ ௜ ∑ ݃ ௜

௜ Where:

e = annual emissions (tCO 2 ) 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, hyd ro, wind, and solar resour ces operate at a very low cost, 31 they are generally dispatch ed 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 st ates 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 le ss 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 supp orting 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 re sources when more energy is produced than required, and due to operational constraints, where wi nd 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 ca nnot be called upon to run when the renewable energy resource is unavailable. However, here we refer to econ omic 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.DRAFT, DELIBERATIVE

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25 3. Marginal Emission Rate Approach

A marginal emission rate represents the emi ssion 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 electr icity demand and the first unit to be brought offline when electricity load is re duced. Due to constraints on generating unit ramp

rates 35 and transmission availability, it is not unc ommon for multiple units to be dispatched incrementally simultaneously, thus creating a cohor t of marginal units. Marginal unit(s) change on a moment-to-moment basis, determined by load requirements and the va riable cost of each unit available to generate anothe r unit of power. A marginal un it can either be a unit brought online to meet load or may be an EGU that is al ready operating, but that is dispatched at a greater level of output to meet load.

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

of the difference between two distin ct 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:

e ref and e EERE = emissions (tCO 2 ) from EGUs i in hour t in the reference case ( ref ) and the change case ( EERE ), respectively; and g ref and g EERE = 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 Implementa tion Plans: Appendix B, available at http://www.epa.gov/statelocalclimate/docum ents/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.DRAFT, DELIBERATIVE

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26 The magnitude of the EE/RE program and the EE/RE load impact shape 36 is a key element in determining marginal emissions reducti ons. 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 refl ects 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 ma rginal 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 meas ures results in a specific marginal avoided emission rate. Applying an annual marginal avoide d emission rate calculated based on the impact of one specific set of EE/RE programs and meas ures to another set of EE/RE programs and measures that is substantively different in tim ing 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 disp atch simulation model. These mech anisms rely on historic hourly generation and emissions data, collected by EP A’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 ve rify or validate without the benefit of a formal model and (b) rely on historical data and patter ns of dispatch, which ma y not represent future patterns of dispatch.

36 The load impact shape of an EE/RE pr ogram 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 re duce 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 ov ernight “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.DRAFT, DELIBERATIVE

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27 4. Methods and Tools for Estimating Avoided CO 2 Emission Rates and Avoided CO 2 Emissions

4.1. Calculation Tool Method

The EPA has developed a user- friendly tool to estimate th e emission reduction impacts of EE/RE requirements, programs and measures. The AVoided Emissions and geneRation Tool (AVERT) 38 was developed to help air quali ty planners quantify NOx and SO 2 emission impacts, as specified in EPA’s Roadmap for Inco rporating EE/RE Programs in NAAQS SIPs. 39 AVERT can also be used to quantify the displaced CO 2 emissions of EE/RE measures within the

continental United States.

The AVERT method uses historical hourly emi ssions rates based on recent the EPA data on fossil fuel-fired EGUs’ hourly generation an d emissions reported through EPA’s Acid Rain Program. 40 This method couples historical hourly gene ration and emissions w ith 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 cu rrent 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 l onger-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 technolog ies, affect the magnit ude and location of CO 2 emissions at the county, state, and regional le vel. AVERT has a flexible framework with a simple user interface designed speci fically 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/.DRAFT, DELIBERATIVE

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28 AVERT may be used to derive marginal emi ssion reductions from hi storical generation and emissions data, which can be used to derive a marginal avoided CO 2 emission rate. However, AVERT does not quantify average emi ssions rates. AVERT approximates historical dispatch behavior using a statis tical algorithm. It does not repres ent transmission constraints, or significant changes in grid structures or fu ture economic conditions. To estimate a recent historical marginal CO 2 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 r ecord the emissions incrementally added in the

tool. 41 The calculated marginal CO 2 emission rate is the incremental CO 2 emissions added by AVERT, based on historical EGU dispatch pattern s, divided by the incremental MWh of EE/RE savings or generation input to AVERT as an increas e in electricity load. This approach reflects the marginal impact of EE/RE measures based on historical recorded pa tterns of emissions and generation. 42

4.2. Electricity Sector Modeling Method

Quantification of avoided CO 2 emissions from EE/RE requirements, programs, and measures can be achieved through retrospective modeling approaches. Models can be used to

calculate avoided CO 2 emissions by comparing actual realized EGU CO 2 emissions to projected

EGU CO 2 emissions that would have occurred in a hi storical reference case that does not include implementation of the EE/RE that is being eval uated. The appropriate choice of model depends on the look-back period. For short look-back periods of one to thre e years, an electricity system simulation dispatch model can determine the marg inal generation contribu tion to emissions in a

41 Because AVERT represents a historical baseline year, EE and RE programs that o ccurred in a past year are already recorded by the statistics of AVERT. To estimate the emissions impact s 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 disp atch based on future economic or regulatory conditions, such as expected fuel prices, emissi on allowance prices, or specific emissions limits. AVERT should not be used for this type of analysis. When used to review historical da ta, AVERT will capture the impact of historical fuel prices and other impacts on the variable cost of production, but cannot capture specific emission limits.DRAFT, DELIBERATIVE

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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 E GU 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 tran smission and distribution infrastructure, and its impact on generation between th e historical reference case an d actual realized historical

outcome.

Electricity System Simulation Dispatch Models Quantifying the CO 2 emissions reductions achiev ed by EE/RE measures through

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

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

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

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

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

appropriate spatial scale. 44

Simulation dispatch models can be readily r un for historical years provided they are loaded with the accurate input assumptions, in cluding 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 a dditional incremental carbon emi ssions 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 cons iderations not reflected in the model. Therefore, a comparison at an individual EGU scale may not be meanin gful, but aggregate emissions at a state or regional scale should be expected to be comparable.DRAFT, DELIBERATIVE

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30 Simulation dispatch models may be most rele vant as part of ex-post plan reporting, for estimating the avoided CO 2 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 CO 2 emissions reductions achiev ed by EE/RE measures through modeling over a longer-term look- back period requires a counterfact ual historical reference case model run, which examines how the electric syst em would have operated and have been built out, in the absence of the EE/RE measures under consideration. Th e critical difference between this type modeling approach and the use of a si mulation 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 ex isting 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 co mparing the outcome of that model run against actual realized generation and emissions at an appropriate spatial scale.

Capacity expansion and dispatch planni ng models could be run for a longer-term historical period to better reflect what the el ectricity 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 mode ls will reflect how these resources have avoided new power plants, retrofits, or fuel switch decisi ons. Some models may also be able to reflect avoided transmission

investments.

Capacity expansion and dispatch planning mode ls may be more relevant than simulation dispatch models for projecting the emission perf ormance 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 CO 2 emissions as the result of EE/RE measures.DRAFT, DELIBERATIVE

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31 5. Considerations Associated with us e 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 oper ational margin. Deployment of significant

EE/RE measures over time often im pacts decisions to build new fo ssil generating capacity, retire existing aging generating capacit y, and make different decision s 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 aggressi ve 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 calcu lated based on the operational margin alone may fail to represent the impact of EE/RE meas ures that occur at th e build margin. This differentiation is particularly important in re gions where the pursuit of EE/RE measures may result in the retirement of high-emitting, non-eco nomic generating assets. The use of a capacity expansion and dispatch planning model would he lp accurately assess avoided emissions due to changes at both the build and operational margins.DRAFT, DELIBERATIVE

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32 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 us e 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 stat e versus emissions reduc tions 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 emi ssions 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 pur sue mass-based emissions reductions approaches through their state plans while othe r states pursue rate-based appro aches that include adjustment or crediting for avoided CO 2 emissions from implementati on 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 sec tion VII of this TSD.

V. Quantification, Monitoring, and Verifi cation 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, monito ring, 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 Renewabl e 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 locat ed outside of the state. Conversely, a state with significant marginal fossil genera ting capacity might realize reductions in emissions from EE/RE measures implemented in other states. These complica tions 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.DRAFT, DELIBERATIVE

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33 savings. 48 In the preamble, the EPA seeks comment on th e suitability of current state and utility quantification, monitorin g, 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 pr ocedures, should be requ ired in an approvable state plan. The preamble also discusses gene rally whether the EPA should establish good practice guidance for quantific ation, monitoring, and verifica tion 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 s ection 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 pl an approach. For states implementing a massbased portfolio approach, the effect of rene wable energy and demand-si de energy efficiency requirements, programs, and measures in helping to achieve the required level of CO 2 emission performance under a state plan will be directly evident in reductions in the monitored CO 2 emissions from affected EGUs. 49 In effect, the overall impact of these measures could be tracked through CO 2 emission monitoring, reporting, and reco rd-keeping requireme nts applied to affected EGUs. However, for states implementi ng a rate-based plan approach, an approvable plan will need to include quantification, mon itoring, and reporting requirements related to RE and demand-side EE requirements, programs, a nd measures incorporated in a state plan.

Utilities and states have conducted ongoing eval uation of end-use energy efficiency and renewable energy measures and programs for several decades. These evaluations, which include quantification, monitoring and ve rification 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 impl ementing a rate-based emission limit approach that provides for adjustment of CO 2 emission rates based on the effect of end-use energy efficiency and renewable energy, as well as states implementing utility- or state-driven portfolio ap proaches that incorporate end-use energy efficiency and renewable energy requirements and programs. 49 There could be exceptions, for ex ample where a state plan includes acknowledgement of avoided CO 2 emissions that occur outside state borders as a re sult of state plan measures. See section VII of this TSD for further discussion of the treatment of interstate effects.DRAFT, DELIBERATIVE

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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 disc usses current state and util ity evaluation, monitoring, and verification approaches for end-use energy e fficiency and renewable energy programs and

mandates. This section also discu sses the potential suitability of these approaches in the context of an approvable state plan, and whether harm onization of state approaches, or supplemental actions and procedures, might be warranted in an approvable state plan. In particular, this section

discusses considerations relate d to the establishment of good pr actice 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 st ate and utility protocols, as well as any international, national, and regional consensus standards or protocols.

This section also discusses the types of e nd-use energy efficiency and renewable energy measures and programs for which quantificati on, monitoring, and verification of results is relatively straightforward. Such approaches mi ght be subject to streamlined review of quantification, monitorin g, and verification protocols include d in an approvable plan, provided that such protocols are applie d in accordance with industry be st 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 estab lished nationally for quan tification, monitoring, and verification of measure and program outcomes. Ot her types of measures and programs, such as

those that seek to al ter consumer and building occupant behavior may pose quantification and verification challenges. Still othe r types of measures, such as state energy-efficient appliance standards and building codes, ha ve not typically been subject to similar evaluation of energy savings results. These types of approaches ma y have substantial impacts, but may require development of appropriate quantificati on, monitoring, and verification protocols.DRAFT, DELIBERATIVE

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35 A. Quantification, Monitoring, and Veri fication 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 implementa tion 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 func tion is typically addressed th rough an evaluation, measurement, and verification plan (EM&V plan). This sec tion discusses current state and utility EM&V practice for end-use energy efficiency programs a nd 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, Monitorin g, and Verification (EM&V) of Energy Efficiency Measures

From the time that demand-side energy effici ency (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 w ith measurement and verification (M&V) of individual projects, these effort s have evolved to the point wh ere there is now a mature and rigorous evaluation, measurement, and verifica tion (EM&V) industry. This industry includes many professional firms, protocols and guide lines, training and certification programs, regulatory oversight, and estab lished 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 efficien cy measure” or “energy efficiency measure” to refer to an end-use energy efficiency requirement (such as an EERS), and energy efficiency progra m, 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 Effi ciency Action Network. 2012. Energy Efficiency Program Impact Evaluation Guide

. Prepared by Steven R. Schiller, Sc hiller Consulting, Inc., available at http://www.seeaction.energy.gov

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36  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, pr ior to independent evaluation of savings

 Evaluated savings: values reported by an i ndependent third-party evaluator after the efficiency activities and an impact evaluation have been completed.

Both claimed and evaluated energy savings involve real-time a nd/or retrospective assessments of the performance and implementa tion 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, hea lth benefits, job creation and local economic development, energy security, tr ansmission and distribution benef its, and water savings). Impact evaluations also support cost-eff ectiveness analyses aimed at de termining the value of energy efficiency programs to utility customers and identifying relative program costs and benefits of energy efficiency compared to other energy re sources, including both demand- and supply-side options.

Regardless of how the energy savings of an en ergy efficiency measure are determined, all energy savings values are estimates of savings and not direct ly measured. Savings are determined by comparing energy use after an ener gy 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 ba seline). Savings therefor e depend critically on baseline assumptions, which are necessarily esti mated with varying degrees of accuracy. Figure 1-1 illustrates this concept.DRAFT, DELIBERATIVE

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37 Figure 1. Energy Use Before, During, and After an Energy Efficiency Project is Installed 53

3. Current EM&V Practices in States

3.1 EM&V for Demand-Side Energy Effici ency 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 va ries from state to state, but this oversight process has generated the majo rity of the industry guidance and protocols for documenting energy savings from energy efficiency program s. 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 performan ce assessment. According to a recent survey, most states (79 percent) rely on independent c onsultants and contractors to conduct evaluations, while some states (21 percen t) 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 Numb er U122 Available at http://www.aceee.org/ re search-report/u122.DRAFT, DELIBERATIVE

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38 The range of EM&V budgets varies significan tly between states, typically from two percent to six percent of total en ergy efficiency program expenditures. 56 The average EM&V budget in 2011 was about 3.6 percent of program e xpenditures. 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 expenditu res and energy savings impacts increase, and as states and utilities gain e xperience in implementing energy efficiency programs.

States at the low end of this EM&V e xpenditure range typically rely heavily on deemed savings approaches, which are a common and relativ ely low-cost strategy for documenting energy savings. Deemed savings are measure-sp ecific stipulated values based on historical and verified data (in some cases using the result s 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 meas ures implemented is veri fied (e.g., number of motors installed correctly, number of energy-effi cient 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 meas ures 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-u pon (stipulated) engineeri ng algorithms used to generate energy and/or demand savings associated with energy efficiency measures. These calculations may include predetermined assump tions for one or more parameters in the algorithm, but typically require us ers to input data associated w ith the actual installed measure into the algorithm. 57

56 Wallace, P.; Forster, H.J. (2012). State of the Efficiency Program In dustry 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 evaluate d using deemed savings valu es and calculations include energy-efficient washing machines, com puter equipment, and refrigerators, an d lighting retrofit projects with wellunderstood operating hours. For deemed savings calculati ons, evaluators collect information about the actual installed measures -- such as hours of usage, watta ge, and/or equipment capacity -- and combine this with predetermined assumptions in the algorithm.DRAFT, DELIBERATIVE

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39 The deemed savings values, themselves, are typically centrally located in a “Technical Reference Manual” (TRM). The content and form at of these TRMs vary, but in most cases consists of a database of standardized, state- or region-specific algorith ms (deemed calculations) and associated energy savings estimates (deemed sa vings 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 rang e of energy efficiency programs in place. The benefits to energy efficiency program administ rators of using a TRM include reduced EM&V costs and greater certainty rega rding projected, claimed, and ev aluated energy savings values (see definitions above). Ther e are about 20 states curre ntly using TRM databases. 58

It should be noted that TRM values for i ndividual 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 vari ations 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 calcula tion errors. In the context of state plans, this variation, and in particular data quality issues with some TRMs, raises consideration of whether comple te reliance on existing TRM resour ces for state plans is prudent and appropriate, including how such relian ce 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 grea ter extent on a variety of dir ect measurement approaches for documenting energy savings. Rather than mandati ng which EM&V methods must be used in a particular situation, PUCs typica lly allow utilities and other progr am administrators to select

58 State and Local Energy E fficiency 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/emvsc oping__databasefeasibility.pdf. 59 State and Local Energy E fficiency Action Network, Energy Efficiency Program Impact Evaluation Guide

, prepared by Steven R. Schiller, Schille r Consulting, Inc. (2012), available at http://www.seeaction.energy.gov

. 60 Ibid.DRAFT, DELIBERATIVE

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40 from a range of appropriate EM&V approaches that are consistent with standard practice in the energy efficiency industry. EM&V analyses and cal culations are then carri ed out, in most cases by an independent, third-party ev aluator, through a pro cess that is unbiase d, 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 base d upon the following industry best practices:

 Use of one or more of the industry-standa rd 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 fact ors, such as climate, bu ilding type, and occupancy.

 Involvement of stakeholders and solicitation of expert advice rega rding EM&V processes and resulting energy savings impacts.

 Conduct of EM&V activities (e.g., direct e quipment measurements, application of deemed savings, and reporting of impacts) on a regular basis.

 Provision of interim and annual re porting of achieved energy savings.

Despite this well-defined and generally accep ted set of industry best practices, many states with energy efficiency programs use diffe rent input values and assumptions (e.g., net versus gross savings, run-time of equipment, meas ure lifetime) in applying these practices. This can result in significant differences in claime d 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 awarene ss of this lack of cross-state comparability, policy makers, regulatory agencies, and other stakeholders are increasingly advocating for the use of common evaluation appr oaches 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 Engla nd, New York, and the Mid-Atlantic, and theDRAFT, DELIBERATIVE

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41 Pacific Northwest’s Regional Technical Forum (RTF ). Both efforts aim to promote multi-state coordination in EM&V practices, make EM&V resu lts more transparent and publicly available, and support the adoption of similar defi nitions, 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, so me 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 Measuremen t and Verification Protocol (IPMVP) 62

b. DOE Uniform Methods Project (UMP) Protocols 63

c. Federal Energy Management Program (FEMP) M&V Guidelines 64

d. American Society of Heating, Refrigerat ing and Air-Conditioning Engineers (ASHRAE) Guideline 14, Measurement of Energy and Demand Savings 65

e. California Evaluation Protocols 66

f. ISO New England (ISO-NE) Manual for M easurement & Verification of Demand

Resources 67

g. PJM Energy Efficiency Measurement and Verification Manual 68

61 For a list of EM&V resources, including more info rmation about these regional EM&V collaboratives, see http://www1.eere.e nergy.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-p roject-determining-e nergy-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/EvaluatorsProto cols_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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42 h. State and Local Energy Efficiency Action Ne twork, Energy Efficiency Program Impact

Evaluation Guide 69

While many states are currently relying upon these protocols and guide lines, 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 imp act evaluations achieve ±10 percent statistical precision at the 80% confidence interv al (see below for more on FCMs).

Regardless of the evaluation approach follo wed, the majority of state PUCs and energy efficiency program administrators aim to stri ke a balance between the transaction costs of EM&V activities (i.e., expense, time, staff e ffort) and the resulting re liability, validity, and usefulness of the estimated energy savings re sults. The appropriate balance between EM&V costs and the rigor of EM&V – and the related ce rtainty of energy savings estimates – is often determined based on the type of program (i ncluding 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) resp onsible for operating regional electricity grids and overseeing wholesale electricity mark ets in certain regions of the country have established forward capacity markets (FCMs) that pay suppliers to ensu re sufficient electric generating capacity is available to meet futu re 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 res ources to compete directly with electric generators to meet the regional capacity needs. One re quirement 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 pl an “qualifies” energy efficiency programs and pr ojects 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 Effi ciency 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.DRAFT, DELIBERATIVE

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43 delivered over the contract peri od (typically three years into th e future), and documents how the requirements of the ISO’s M&V standards manual will be satisfied.

Based on experience to-date, st ates bidding their energy effici ency programs into both the ISO-NE and PJM forward capacity markets are ty pically 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 eval uation protocols and procedures for documenting the cost-effectiveness of annual energy (MWh ) savings, FCMs require the measurement and verification of capacity (MW) sa vings during specific peak de mand hours. In addition to the evaluation of energy savings, a separate set of measurement technique s and data collection protocols are required to document peak demand reduction impacts. Furthermore, attaining the level of statistical precision and confidence de scribed above typically requires additional sampling 70 than is required by PUCs. One considerat ion is whether EM&V requirements in ISO capacity markets include components that woul d facilitate better estimation of avoided CO 2 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 challenge s encountered with FCM participation.

70 With additional sampling requirements, energy efficiency program evaluators are typically required to measure a larger percentage of the energy efficien cy 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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44 3.3 EM&V for Programs and Policies Not Typically Overseen by PUCs

In contrast to energy efficiency program s 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 electric ity ratepayer dollars. Examples include building energy codes, appl iance efficiency standards, various energy efficiency financing programs , behavioral change programs, and market transformation programs that target both the suppliers of energy-efficient pr oducts and increasing consumer demand for those products. While these approach es may have substantial impacts in reducing energy use, many currently face EM&V challeng es. In some cases, appropriate evaluation protocols and approaches have not been develo ped for some programs and measures. In cases where appropriate EM&V methods do exist, ther e may also be less experience applying them. 72

4. Considerations for EM&V of End-Use Ener gy Efficiency Programs and Measures in

State Plans

4.1 Accuracy of Energy Savings Estimates

To document and verify that avoided CO 2 emissions from energy efficiency programs and measures are real and persistent, impact eval uation must be rigorous a nd 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 CO 2 emissions resulting from energy efficiency programs and measures in a state pl an will depend upon the leve l of accuracy of this information. Therefore, evaluation results shoul d 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 pr ograms and measures in state plans are similar to those faced in the design of any program evalua tion approach: (1) the level of certainty that is required given a program’s objectives and requir ements, 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.DRAFT, DELIBERATIVE

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45 necessary level of certainty is balanced with the amount of effo rt (e.g., resources, time, money)

used to obtain that level of certainty.

4.2 EM&V Technical Considerations for State Plans

Using energy efficiency requi rements, programs, and measures as an emission reduction approach in state plans requires considera tion of several evaluation-related technical considerations. The following sections describe these considerations.

4.2.1 Qualifying Demand-Side Energy Efficiency ActionsDRAFT, DELIBERATIVE

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46 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 gr eater levels of measurement preci sion and certainty than others, based in part on the EM&V procedures currently in place. For example, energy efficiency programs subject to PUC oversi ght and review are frequently evaluated using rigorous evaluation procedures that are based upon severa l decades of research and experience. These energy efficiency programs are subject to a qu asi-judicial, public, a nd 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 effi ciency requirements and measures, some of which may result in very significant and cost-effective energy sa vings (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 so me newer EE program designs (e.g., behaviorbased programs and various market transformation programs 73 ) 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 protoc ols less well established – for example, building disclosure and labeling programs

73 Behavior-based energy efficiency programs aim to affect cons umer energy-use behaviors in order to achieve energy and/or peak demand savings. Techniques to measure the impacts of th ese 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.DRAFT, DELIBERATIVE

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47 Table 4.1 provides an illustra tive characterization of the relative level of EM&V uncertainty for different types of energy effici ency programs and measures under this approach. This information is illustrative and generalized. In particular, there are numerous exceptions to the categorization of the relativ e 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 Polices 74

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 pro cedures 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 pr e-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 sh ould 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.DRAFT, DELIBERATIVE

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48 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 m easure types, as long as the energy savings are adequately documented according to rigorous EM&V methods and appropriate regulatory oversight. The former option potentially redu ces measurement uncertainty, while the latter approach may provide more flexibility.

4.2.2 Avoided Transmission and Distributi on (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 deli vered to an end-user constitutes transmission and distribution (T&D) line losses. 76 According to EIA data, na tionally, 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 ot herwise 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 progr ams, and actively credit program energy savings results to account fo r program contributions to avoide d 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, a nd how to do so in a consistent manner across

states.

75 This includes energy effi ciency programs and measures for which th ere 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 elect ricity 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 questio n, 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.pdfDRAFT, DELIBERATIVE

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49 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 CO 2 emissions impacts, it may be useful to utilize time-differentiated (i.e ., hourly, seasonal) energy savings data. 78 Information about the timing of ener gy savings has direct implications for estimating the avoided CO 2 emissions that result from an e fficiency 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. Fo r example, air conditioner programs save energy primarily on hot summer days, whereas a refrigerator program saves energy every hour of the year. Time-diffe rentiated information related to electricity generation is useful in estimating avoided CO 2 emissions. In particular tim e-differentiated data is necessary to estimate the marginal avoided CO 2 emissions related to electric generation, as

discussed above in section IV.C.3.

In practice, state PUCs around the country have substantiall y different requirements and recommendations for evaluating and reporting time- differentiated energy savings. Some energy efficiency program administrators report annua l energy savings impacts, where savings are typically based on either tracking data (i.e., data used to es timate savings for planning purposes) or evaluated (i.e., ex-post) sa vings 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 ha ve provided generation in the absence of the energy savings. This supplemental data can be used to more accurately estimate avoided CO 2 emissions that result from program energy savi ngs. Due to improved evaluation software and data availability, it is increasingly common fo r 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 re quirements or guidance for state plans is the

extent to which time-differentiated data on en ergy savings from energy efficiency programs is available, and whether states can readily acq uire 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 efficien cy measure.DRAFT, DELIBERATIVE

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50 A related consideration is metr ics reported for electricity savings. The primary metric required to understand the avoided CO 2 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 bui ld margin. This information is necessary to estimate the marginal avoided CO 2 emissions related to electr ic generation, when reporting on

avoided CO 2 emissions achieved through energy efficien cy programs and measures during a plan reporting period, as discussed above in secti on 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 achieve d 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 ener gy savings, or both. Gross savings are the change in energy use (MWh) and dema nd (MW) that results directly from programrelated actions taken by program pa rticipants, regardless of why th ey participated in a program. Net savings refer to the change in energy use a nd demand that is direct ly attributable to a particular energy efficiency program. 79 Reporting of net savings help s a PUC ensure that energy efficiency program budgets are being used to pr omote 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 pl ans is whether required reporting of energy

79 Calculations of net energy savings involve excluding ener gy efficiency measur es undertaken by "free riders" (i.e., EE program participants who receive a program rebate ev en though they would have taken the efficiency action anyway), or adjusting energy savings estimates to account for these e ffects. 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 asse ssment of "free drivers" (s ometimes 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). Accura te estimation of free ridership and spillover effects is complex, especially in areas of the c ountry with robust energy efficiency markets with multiple non-program influences compe ting for customers’ attention.DRAFT, DELIBERATIVE

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51 savings should be specified on either a gross or net basis, or both, to promote national consistency in measuring the impact of ener gy efficiency measures across state plans. 80

4.2.5 “Measure Life” and Persistence of Savings

Measure life and persistence of energy sa vings describe the ongoing effects of an installed energy efficiency measure, in cluding 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 ad ministrators estimate the impact of energy efficiency programs in terms of first-year savi ngs (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 prac tice, evaluators determine measure li fetimes on the basis of engineering judgment, manufacturer specifications, and some empirical field studies. These values are frequently entered into PUC-managed state tech nical databases for ongoing and repeated use in evaluation studies. For state plans, a key consid eration is whether measure life and persistence values for energy efficiency measures docum ented by states are accurate, up-to-date, and

consistent with those utilized in other states (after accounting for appropr iate 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 e nd-use energy efficiency and renewable energy measures and programs for several decades. Th ese evaluations, which include quantification, monitoring and verification of results, genera lly rely upon a well-defined set of industry -standard practices and procedures. As a result, exis ting state and utility EM&V requirements and processes generally provide a so lid 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 transp arency of reported energy savings estimates, but only one savings value would be used to evaluate the effect of en ergy efficiency programs and measures on CO 2 emissions from affected EGUs.DRAFT, DELIBERATIVE

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52 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 im pacts. 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, curre nt state EM&V best practices require the level of EM&V effort (i.e., rigor, reliability, valid ity, and uncertainty of energy sa vings estimates) to be aligned with the required level of certainty of evaluati on results and the magnitude of energy efficiency program impacts. These best prac tices 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 releva nt for documenting energy efficiency savings from measures in state plans.

Options for EM&V requirements or guidan ce for state plans that incorporate energy efficiency requirements, progr ams, and measures include:

 Establishing specific EM&V re quirements 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 fo r 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 t ypes of programs and measures, provided that EM&V meets these minimum requirementsDRAFT, DELIBERATIVE

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53 At one end of this spectrum, establishing sp ecific 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. Howeve r, this approach may require significant effort by the EPA to establish such re quirements, and could potentially duplicate state efforts currently under way to harmonize EM&V pr actices. 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 coul d be included in a state plan, and could also inhibit the development of innovative EM&V appr oaches that improve the accuracy of energy savings estimates. At the othe r 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 devel opment 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 effici ency programs and measures. States would have some level of certainty about acceptable EM&V approaches in st ate 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 prep are energy savings documentation, and specify their needed qualifications. This approach is analogous to professional certification requirements in the accounting and engineering fiel ds, in which a minimum level of credibility, rigor, and accountability is imparted to the services provid ed by qualified individuals and firms. Criteria for eligible evaluators might incl ude a demonstration of independe nce from those implementing or administering the energy efficiency programs and measures ( i.e. , identification and mitigation of potential conflicts of intere st) and required minimum levels of training, experience, or certification. This approach rec ognizes that the qualifications , integrity, and independence ofDRAFT, DELIBERATIVE

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54 those conducting EM&V of energy efficiency programs and measures, and preparing energy savings estimates, is critical to assuring best-practi ce 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 a nd protocols, most of which have been established for utility-customer funded en ergy 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 pl ans. However, existing state and utility EM&V infrastructure and protocols ma y not be applicable to the fu ll 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 protocol s were established to su pport the goals of state energy efficiency programs, in current form they may not adequately sup port 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 repor ting necessary to ev aluate avoided CO 2 emissions that result from energy efficiency programs and measure included in state plans.

5.2 EPA Review of EM&V Plans as Pa rt of the State Plan Review Process

Development of EM&V plans that are included in a state pl an 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 a pproach, states would develop EM&V plans as part of the state plan developm ent 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 EPADRAFT, DELIBERATIVE

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55 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 approa ch 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 approach es used in state plans. At the same time, existing state EM&V processes curr ently vary in the level of re gulatory 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, th e EPA may need to id entify and establish minimum requirements for EM&V rigor, accura cy and reliability, and quality control. Requirements could be (a) a single set of requi rements that apply to all energy efficiency programs and measures in all states or (b) a va riable or flexible set of requirements with increasing levels of EM&V effort and rigor de pending on the relative degr ee of uncertainty of energy savings from the energy efficiency program s 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 straightforwar d energy efficiency programs and measures, such as lighting retrofits might require only verification that meas ures 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 de tailed 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 certain ty 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 effo rt” could refer to greater reliance on deemed savings values, smaller sample sizes for measured savings, fewer direct measurements, and pro portionately greater reliance on ex-ante estimates. “Medium” and “hig h” levels of EM&V effort could require incrementally more effort in each of these areas. Other interpretations of this concept are possible.DRAFT, DELIBERATIVE

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56 states. A flexible EM&V approach, based on an individual assessment of the measurement uncertainty related to the energy e fficiency programs and measures included in a state plan could provide states with greater flexibility when se lecting energy efficiency programs and measures. However, the lack of a prescribed EM&V a pproach could increase uncertainty about the approvability of differe nt plan approaches.

6. EM&V Documentation in a 111( d) State Implementation Plan

EM&V documentation will be an important co mponent of state plans that incorporate energy efficiency programs and measures, beca use 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 appr opriate increments dur ing 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 a nd greater transparency, and the level of EM&V effort required. Excessive documentation requirements may not a dd value in terms of transparency, but may discourage the inclusion of cost-effective energy e fficiency options in state plans. However, two

basic criteria for EM&V documentation should be applied in state plans:

 Energy savings documentation should be provid ed at a level of detail that allows for recalculation of program en ergy savings totals; and

 EM&V information in state plans should be pr ovided 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 outl ine of the types of in formation that might be included in an EM&V plan for energy effici ency 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 measur es during a state plan performance period. AnDRAFT, DELIBERATIVE

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57 EM&V plan could apply to utilit y energy efficiency programs that are incorporated into a state plan on a stand-alone basis, a nd 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 subj ect 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 MW h, monthly MWh, hourly MWh, average MW), and whether gross or net savings, or both, will be reported

 Name of impact evaluation protocols, guida nce documents, and other methods that will be followed in preparing eval uated energy savings reports

 Description of the range of uncertainty for energy savi ngs estimates indicated in evaluated energy savings reports, including sources of uncertainty

 Description of assumptions c oncerning availability of data and data collection methods

 Indicate how the following issues, if applicab le, will be addressed in the claimed and evaluated savings estimates:

o Inclusion of estimates of avoided electr icity transmissions a nd distribution losses

o Adjustment of gross savings estimates to net savings estimates (if applicable

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58 B. Quantification, Monitoring, and Veri fication 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 impl ementation 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 relate d to possible acceptabl e quantification, monito ring and verification approaches for a state plan under CAA section 111(d).

States and utilities use a variet y of policy instruments to in crease the production and use of renewable energy. The principal mechanisms include: renewable portfolio standards (RPSs), feed-in tariffs (FITs), tax incentives (e.g., pr operty tax exemptions; production-based tax incentives; etc.), financial a ssistance programs (e.g., grants, loan s, and other direct financial assistance based on generating cap acity or investment level), and other policies (R&D support; manufacturing incentives; workforc e training; net metering; etc.). Experience to date indicates that RPSs have led to the vast majority of th e increase in renewable energy generating capacity and generation resulting from st ate 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 rene wable energy. Further, these types of programs rely on m easurable electric generation as the basis for compliance or incentive payments. As a result, the following discussion focuses on qua ntification, monitoring,

and verification mechanisms related to these stat e 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 modifi ed 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 “ren ewable 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.DRAFT, DELIBERATIVE

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59 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 el ectricity retail sales is required to be produced or acquired from renewa ble 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 ty pically investor-owned electric distribution utilities, because most RPS apply to entities under the jurisdiction of stat e PUCs. In a number of states, municipally-owned utilitie s and electric cooperatives are exempt from state RPS, have lower RPS requirements, or are required to de velop their own renewable energy procurement targets. Additionally, some states have created separate renewable energy requirements for each

of their affected di stribution utilities.

The absolute amount of renewable energy that each distribution util ity 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 pe rcentage of retail sales.

There are several pathways that affected distri buted utilities typically have to meet state RPS requirements, including building and opera ting renewable energy generating capacity, purchasing electricity from renewable energy ge nerators, and purchasing the attributes from renewable energy generation. Many st ate RPSs take this latter a pproach. 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-servi ng entities that supply electricity to retail customers. 84 “Voluntary” renewable energy purchases, as used here, re fers to renewable energy purchases in addition to the renewable energy required by RPSs.DRAFT, DELIBERATIVE

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60 each distribution utility to generate electricity from its own renewable energy facilities or purchase electricity from a renewable facility owned by others, many stat es require distribution utilities to acquire renewable ener gy 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 genera tors can sell RECs as another product bundled with the underlying power they pr oduce 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, monitorin g, 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 CO 2 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 ener gy (e.g., waste coal, coal-bed methane, and fuel cell operation using fo ssil-fuel feedstocks).

 Existing and new resources. RPS-eligible re sources 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 attri butes 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 diff erent 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 attr ibutes of the remaining syst em mix of power, after the assignment of attributes as described above. 87 In the preamble, the EPA is proposing that, for an existing state requiremen t, program or measure, a state may apply toward its required emission performance level the emission reductions that existing state programs andDRAFT, DELIBERATIVE

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61  Scope of coverage . In some states a RPS applies to all re tail sales in a state, but in others only a subset of retail sales (e.g., only investor-o wned utility retail sale s) are subject to a

RPS.

 Credit multipliers . Some states provide additional incentives for specific eligible

resources in the form of bonus credit to ward compliance in their RPS accounting framework. For example, these states may fa vor certain resources (e.g., distributed solar PV), or locally-important resources or t echnologies. 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 re newable energy produced in one year to satisfy RPS requirements in a subsequent year. Accounting for y ear-to-year carryover should be addressed in a st ate plan, in order to determine the renewable energy generation that occurred in a respectiv e reporting year or compliance period.

 Alternative compliance payments (ACP) . Many states allow a compliance alternative which requires obligated entitie s to pay a predetermined fee to the state for each MWh of RPS shortfall. Although these ACP payments ma y be directed to programs to promote the deployment of renewable energy technologies, these payments are not equivalent to renewable energy generation and sh ould not be accounted as such.

 Interstate issues . While treatment of interstate emission effects is discussed in detail in section VII, for quantification, monitori ng, and verification of renewable energy

measures achieve during the plan peri od due to actions taken after the date on which the emission guidelines are proposed (i.e., from June 2014 onward).DRAFT, DELIBERATIVE

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62 generation under a RPS it is important to note that most states allow use of eligible renewable energy resources loca ted in other states to sati sfy the state RPS requirements. 88

Considerations related to the quantification, m onitoring, 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 oblig ations by building and operating their own renewable energy genera ting facilities, entering into bilateral contracts with other parties to purchase renewable energy, and participating in th e REC market. Each compliance method has specific implications for the qua ntification, monitoring, and verification of renewable energy generation used to meet RPS obligations. Imp lications under these different pathways are discussed below.

Build renewable generating facilities In many states, utilities with RPS obliga tions may build, own, and operate their own renewable energy generating facili ties. This pathway is often used by vertically integrated utilities subject to a RPS. For large renewa ble energy generating f acilities, production is measured through a revenue-grade utility mete r as it enters the grid at the point of interconnection. This meter is subject to the same verification standa rds 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 faciliti es. 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 genera tors are registered with a REC tracking system and the generation output is verified accord ing to tracking system and RPS rules.

88 This may also include international renewable energy re sources, 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.DRAFT, DELIBERATIVE

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63 Bilateral contract model Under the bilateral contract model, distribut ion utilities with RPS obligations contract with renewable energy generators for supply. Thes e contracts typically sp ecify a delivery amount in MWh over a specified contract period. These s upply contracts may be short- or long-term, may specify generation from certain renewabl e energy EGUs, and may be solicited through an RFP or entered into through negotiation. Quan tification of renewabl e energy generation (in MWh) is accomplished through the use of a reve nue-grade meter that measures the flow of electricity from the generator into the transm ission 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 gr id and the point of receipt at a utility transmission or distribut ion system. A renewable energy s upply 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 th e purchase of the electricity, in order for the utility to satisfy its RPS ob ligations through the contract. 90

State RPS compliance processes may provide for PUC review of supply contracts, including inspection of meters a nd verification of electricity deliv ery from the generator to the utility distribution network th rough a specified contract pa th (e.g., through evidence of transmission rights held or scheduled). The pur chasing utility also re ports their purchase and delivery of RPS-compliant renewable energy purs uant to the contract to the state agency responsible for RPS enforcement, typically the state PUC or stat e energy office. Verification is accomplished by audit of electricity supply contra cts 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 qualifyi ng 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 verifi cation of electricity delivery is typically done by the REC tracking system admini strator before issuing RECs for the imported energy. Verification can be provided, for exampl e, by demonstration of scheduled delivery

90 This ensures that multiple parties are not using the sa me MWh of renewable energy generation to comply with their RPS obligations.DRAFT, DELIBERATIVE

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64 through the ISO or RTO serving th e state or region, through demons tration that the seller holds transmission rights for delivery or po ssession 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, retire d, claimed, represented as part of energy sold elsewhere, or used to satisfy obligations in another jurisdiction.

REC model Under the REC model, renewable energy genera tors register their EGU with a renewable energy tracking system, which have been establis hed by several regional groupings of states, as

well as a few individual states. 92 The registration process coll ects data about the generator’s attributes: type of resource (e.g., wind), plant-level emissions, geographic location, nameplate capacity (MW), commercial operatio n date, ownership, and the elig ibility for RPS compliance or voluntary market certification. Af ter the generator is register ed, 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 par ticipating 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, resour ce type, and the month in which the MWh was generated, and the month or quarter in which the certificate was issue d. The renewable energy

91 A NERC Tag, sometimes referred to as an E Tag, is an el ectronic tag that is used to track wholesale electricity transactions that involve the transfer of electricity across or through cont rol areas. NERC Tags allow transmission system operators to track electricity tr ansactions 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 fi nancial path, including all parties to a transaction. All wholesale electricity transactions that will result in the transfer of electricity from one contro l area to another, or that involve transfers through a co ntrol area, must be accompanied by a NERC Tag. Based on a real-time assessment of NERC Tags, system operators can curtail transfers if reliabi lity issues would arise as a result of the transfer. NERC tags are issued through an electronic system in accordan ce 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 Re newable 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 Renewabl es Registry (NARR), Mich igan 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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65 generator can then sell the rene wable electricity as a bundle (bot h 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 bei ng used to satisfy a state RPS, or as a result of a voluntary buyer retiring the REC to demons trate 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 minimi zes the opportunity for renewable energy to be double-counted across, for example, two diffe rent state RPSs, or between two voluntary purchasers. In recent years, the various tracki ng 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 interc hange 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 tr ansmission rights for deliv ery of the accompanying electricity from the renewable energy generato r into the respective ISO/RTO system or grid system in which a state is located.

Small distributed generators Smaller distributed generators, such as reside ntial rooftop solar PV systems of less than 10 kW capacity, often don’t have discrete me tering of their total generation. State RPS requirements may permit these distributed genera tors to qualify for use in meeting utility RPS obligations based on an engine ering estimate of their renewa ble energy generation output , provided the distributed generators are registered with a REC tr acking 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 bein g established. More information can be found at http://www.narecs.com/res ources/registries/DRAFT, DELIBERATIVE

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66 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 electricit y supply. Note also that many utilitysponsored renewable energy incentive programs stipul ate 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 receip t and review of obligat ed 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 th rough state legislation, bu t 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 certifyi ng the eligibility of specific generators to participate in the RPS a nd for making siting determinations. In New York, for example, the New York State Energy Resear ch and Development Authority (NYSERDA) is responsible for the centralized pr ocurement of the renewable ener gy needed to meet the RPS for

all of the state’s invest or-owned utilities.

2. Feed-in Tariffs

Feed-in tariffs (FITs) are o ffered by some individual elect ric distribution utilities and some states for renewable energy syst ems 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 Ca lifornia, Hawaii, Maine, Oregon, Rhode Island, South Carolina, Vermont and Washington, as well as numerous electric utilities.DRAFT, DELIBERATIVE

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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 th e tariff as a whole (in total dollars spent or in specified retail rate impacts allowable), and may al so 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 different iated by resource or that change through time as specified benchmarks are achieved (e.g., MW of re newable energy generating capacity subject to the FIT, amount of electricity purch ased through a FIT as a percentage of utility sales, or retail rate impact level reached). Typi cally, the tariff treats all simila rly-situated generators in a

consistent manner.

Quantification of renewable energy genera tion 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 sp ecify 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 c onnected 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 pr ecisely and accurately through time.

Both the utility and the state will need to consider the ownership of the environmental attributes arising from the re newable 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 separate ly as another renewable ener gy program in a state plan.

State agency role FITs are usually authorized by state statutes th at specify which utilities must offer a FIT, eligibility criteria (e.g., renewa ble energy resource type, lo cation, project MW generating capacity limits), and sometimes overall program targets (e.g., to tal installed MW of generating capacity subject to the FIT). State statutes may al so specify whether the utilities offering a FIT will receive the RECs related to purchased elect ricity generation output for use in complyingDRAFT, DELIBERATIVE

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68 with a state RPS, and whether customers recei ving FIT payments may also receive incentives under other utility and stat e programs. Typically state statutes leave implementation details to the PUC (or other utility governing bod y, if applicable, for municipal and cooperative utilities), but may provide guidance on what to consider in se tting FIT payment levels. Based on this statutory authority, PUCs develop detailed rules govern ing implementation, which can include payment levels and contract length. PUCs may direct the affected utilities to de velop standard contracts with all the terms and conditions spelled out, a nd these standard contr acts must be approved by the PUC. As with state RPS, the PUC is respon sible for receipt and review of the utility’s periodic status reports, approving changes to a tariff if needed, a nd evaluating the impacts of the tariff on retail prices, generation diversit y, and electricity system operations.

Several FITs are offered by distribution utilit ies not overseen by PUCs, such as municipal

utilities and rural electr ic cooperatives. These utilities have a variety of governance structures ( e.g. , municipal government, cooperative board of di rectors). The utility governing bodies in these situations will be responsible for receipt an d review of the utility’s status reports, taking corrective action if needed, and ev aluating the impacts of the tariff.

3. State Tax Incentives

Several states offer a variety of tax incen tives to promote the production and use of renewable energy. These currently include sales tax exemptions fo r certain kinds of equipment (e.g., PV panels), property tax abatement for improve ments to a building or facility related to the asset value of the renewable energy generati ng 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 cred it 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 re newable energy generator might claim a tax credit for each MWh of qualifying renewable en ergy 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 usedDRAFT, DELIBERATIVE

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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 pr imarily 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 incentive s, 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 mi ght 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 th e owner and operators of renewable energy generators and be responsible for determining whethe r the taxpayer’s claim for tax incentives is supported by the MWh generation evidence. Assuming the state revenue authority re tains its ability to audit the taxpayer’s return, it could veri fy claimed MWh generation.

As with FITs, the renewable energy gene ration resulting from production-based tax incentives might be used for RPS compliance. If th at were to become the case, then it should not be counted separately in a stat e 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 re newable energy measures and programs for several decades. These evaluations, which includ e quantification, monitori ng and verification of results, generally rely upon a set of standard practices and procedur es. In addition, states have designed and implemented REC tracking systems to facilitate compliance w ith state RPS. This resource provides the ability to track the locati on and attributes of renewable energy generators,DRAFT, DELIBERATIVE

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70 and the electric generation from these generators , as well as the partie s that use RECs for compliance with state RPS. As a result, existing state and utility requirements and processes for quantification, monitori ng, and verification of renewable energy programs and measures generally provide a solid founda tion for minimum requirements or guidance that might be established by the EPA for state plans.

The programs discussed above (RPS, FIT, a nd performance-based tax incentives) all require quantification, monitori ng, and verification of electrici ty generation from renewable energy generators, as well as provisions of othe r 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. Thes e data are essential to program management, verification of compliance or payments, budget c ontrol, and tracking progress toward goals. For example, PUCs overseeing compliance with st ate 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 rece ived payments under either a FIT or tax

incentive. These data are essential for nor mal 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 effectiv e regulatory oversight. Typically, avoiding CO 2 emissions, while considered a releva nt 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 CO 2 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 precisi on requirements or other specifications. 96 Compliance status will also consider the application of credit multipliers or alternative compliance payments, if relevant under an RPS.DRAFT, DELIBERATIVE

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71 renewable energy generated through an RPS, FI T, 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

CO 2 emission estimates related to renewable en ergy requirements, programs, and measures included in a state plan. For example, inform ation on the location of the renewable energy generation (e.g., in-by state or within a specified grid region) of the re newable energy generation used for compliance with state requirements and programs would be helpful in determining

avoided CO 2 emissions. Information about the location of electric generators that supplied electricity generation that was imported to a stat e or grid region, will also be important. Timedifferentiated information related to electricity generation is also useful in estimating avoided

CO 2 emissions. In particular time-differentiated data is necessary to estimate the marginal

avoided CO 2 emissions related to electric generation. Such time-differentiated data could be based on metering or engineering estimates fo r a technology type that indicate the typical generation profile for the renewable energy reso urce. 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 E nd-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 re quirements and programs will be an important component of certain types of sa te plans. If a state plan inco rporates renewable energy and demand-side energy efficiency requirements a nd 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 applicab le to an affected EGU. For example, these requirements may include complian ce reporting by an electr ic distribution utility subject to an end-use energy efficiency resour ce standard (EERS) or renewable portfolio standard (RPS). They may also include reporting by a vertically integrated utility implementingDRAFT, DELIBERATIVE

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72 an approved integrated resource plan. In the latter instance, the utility may also be the owner and operator of affected EGUs, but a dditional 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 ener gy technologies that are incorpor ated in a state plan. In each of these instances, reporting of program complian ce or program outcomes is a necessary part of an approvable plan to demonstr ate performance under the plan.

In the preamble, the EPA seeks comment on appropriate reporting and recordkeeping requirements for entities implementing end-us e energy efficiency and renewable energy programs included as enforceable measures in a stat e 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 r ecordkeeping under state energy efficiency requirements and programs, such as EERS, RPS, and utility and state deployment programs for energy efficiency and renewable energy. The sect ion then examines the suitability of these reporting and recordkeeping practices as potenti al 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 ad ministrators document energy (MWh) and demand (MW) savings. These reports serve as basis for PUC review of total achieved energy savi ngs relative to program goals or regulatory requirements, as well as fo r determining financial performance incentives for utilities, where they exist.

In most states, impact reporting is initia lly conducted at the level of efficiency “programs” (each consisting of numerous “project” installations or efficiency measures occurring at individual homes, co mmercial buildings, or industrial facilities). Program level dataDRAFT, DELIBERATIVE

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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 jurisd iction for the timeframe of interest.

Impacts reports are typically submitted annually, but in some cases program administrators also provide interim (e.g., quarter ly) reports. This added step can help inform progress towards goals, as well as provide for co rrections in cases wher e evaluated (ex-post) energy savings are not achieving projected or claimed (ex-ante) savings levels.

The information provided below presents a range of common re porting elements and common practices implemented by state PUCs. Thes e reporting elements and practices – which raise important considerations for the reporting of energy-effici ency impacts in state plans –

include:

 State EM&V guidelines, protoc ols, and/or framework ut ilized, where applicable

 Energy efficiency policy or program informa tion reported to PUCs in annual reports:

o Short description of the polic ies or programs implemented

o Implementation schedules and timeframes

 Energy-savings impacts reported to PUCs in annual reports:

o Incremental annual and lifetime MWh savi ngs for reporting (in the case of an energy efficiency program) or compliance ye ars ( 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 in stallation of energy efficiency measures occurred, and the installed measures ar e capable of genera ting energy savings

 EM&V process followed:

o Date and location of on-site facili ty visits and field observations

o Description of public process for revi ew of overall EM&V approach, EM&V plan, and EM&V resultsDRAFT, DELIBERATIVE

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74 o Information about evaluators:

 Name of firms and individuals performing EM&V activities, and qualifications

 Certification that evaluators were se lected 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, a nd 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, sta ndards, 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., in formation describing the sample size and sampling procedures used)

o Whether net or gross energy savings 98 are estimated, definitions used for gross and net savings, and the basis for gro ss to net calculations, if applicable

o Avoided transmission and distribution (T &D) impacts assumptions, if applied

The energy savings EM&V reporting elements li sted above vary from state to state in terms of type and level of documentation, and report s are provided in different formats from state to state. This significant vari ation among states in reporting cont ents and format raises several

considerations for states utiliz ing 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 contex t 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.DRAFT, DELIBERATIVE

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75 consideration is whether lead state agencies that oversee energy efficiency programs should be required to certify reported energy efficiency savi ngs impacts on behalf of the state, potentially including certification that the values are appropriate and conser vative, and meet their approval.

A final consideration is whethe r and how energy savings impact reports are made available for public input and comment prior to finalization, recognizing that im pact reports in many states exist but are not easily located or widely acce ssible 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 Complian ce Requirements under State RPS

Each state has different reporting and complian ce 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 oblig ations are typically sp ecified 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 dist ribution utilities to provide an implementation plan describing how they will comp ly with the state RPS rules in the future.

Data requirements for reporting may vary ba sed on the design and implementation of a RPS. However, for nearly all state RPS require ments, annual compliance report data is based on measurable electric generation results a nd verified through tracking system data. 99 In some states, compliance reports may also include st ate-level projections of renewable energy generation resulting from current or proposed state RPS policies.

The most common form of tracking system fo r 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 typi cally provided with a unique iden tification number and may be certified by a third-party veri fier. Annual compliance reports containing REC data typically

include the number of RECs th e utility or load-serving entity procured and retired, what

99 Some state RPS require electric utilities to procure a sp ecified 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.DRAFT, DELIBERATIVE

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76 renewable energy generators supplied the RECs, and how much the utility spent on procuring the

RECs.

2. Typical Reporting for Renewa ble Energy Deployment Programs 100

Renewable energy deployment pr ograms involve the provision of a payment or credit for a renewable energy project, or for a quantified am ount of electricity gene ration, in the case of performance-based incentives. Qu alification of eligible projects and payment for qualifying electric generation (or related a ttributes) require reporting of elect ric generation and other project for each specific program. Program administrators use this information to track program progress and report to PUCs or other ove rsight entities. The summary be low addresses typical reporting required for utility-administered programs, as well as programs administered by non-profit entities and state agenci es and authorities.

Reporting for utility administered re newable 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 easie r to quantify the renewable electri city generation resulting from some programs than it is for others. Utilities ad ministering FITs, for example, will track the number of customer contracts, resource type , capacity of each cont racted project, MWh generated, and utility ex penditures 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 pr ojects, and the amount of rebates paid or loans provided. Measuri ng 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. Howeve r, 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 deploy ment of renewable energy technologies.DRAFT, DELIBERATIVE

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77 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 pr oduction 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 gene ration from the renewable energy system, unless

two meters are installed – one to measure tota l output from the customer-sited system, and

another to measure the total electr icity purchased from the utility.

Many of these renewable energy deployment programs are developed as part of requirements by PUCs, and therefore utilities mu st provide reporting on a routine basis to the PUC about program expenditures and outcomes (typi cally quarterly or an nually). These records should be readily accessible to states for es timating the impacts of their renewable energy deployment programs included in a state plan. Ho wever, some utility incentive programs are administered by distribution util ities 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 sepa rately required by a state if such programs are included in a state plan.

Renewable energy deployment programs may be designe d and implemented under the auspices of a utility inte grated 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 ty pically mandated thr ough 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 rene wable energy generation trends in subsequent years, and are a good re source for the developmen t of state plans.

101 IRPs are typically required in states with vertically inte grated electric utilities, but are less common in states that have deregulated their electricity sectors and introduced comp etition for the supply of electricity to retail customers.DRAFT, DELIBERATIVE

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78 Reporting for renewable energy incentive progr ams administered by non-profit or state

entities State renewable energy financial incentives ar e typically administered by a PUC, state revenue agency, other state agency (e.g., state en ergy office), or a private non-profit or for-profit entity contracted by a state agency. These progr ams 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 pr oduction tax incentive). Applications to incentive programs are good sources of data, and program administrators usually compile data from approved applications to trac k program status. Additional reporting data is also typically required to receiv e the incentive. For example, a production-based tax incentive is calculated based on the amount of electricity ge nerated 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 regul ar public program reporting, could form much of the basis for reporting under state plans for such measures.

3. Considerations for Reporting Requirem ents 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 in centives, such as FITs, net metering, and performance-based tax incentives, also requi re 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 th ose 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 CO 2 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.DRAFT, DELIBERATIVE

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79 may not currently be sufficient for repor ting under a state plan . Additional reporting requirements may be necessary if these programs ar e included as enforceable measures in a state plan.

In addition to the reporting states curren tly require for renewable energy requirements and programs, supplemental reporting information or adjustments may be necessary for state plans to demonstrate the avoided CO 2 emissions associated with these requirements, programs, and measures. States may need to require additi onal reporting detail, su ch as the location of renewable energy generating units that supplied output used to comply with a state RPS. Additional reporting detail about when renewable en ergy was generated may also be valuable for estimating the avoided CO 2 emissions from renewable energy generation, especially if a marginal avoided emission rate approach is used. This includes re porting of the typical generating profile of a renewable energy genera ting unit, group of units, or renewable energy resource type. 104 For distributed renewable energy resour ces, reporting of the MW capacity of generating systems that are installed as a resu lt of state requirements or programs during a reporting period would also be us eful for estimating avoided CO 2 emissions. These distributed resources, since they are located “behind” the ut ility meter at a customer location, have a similar effect in reducing the demand for electricity supp lied from the grid as en d-use energy efficiency

measures.

Example reporting requirements that provide sufficient data for estimating the avoided

CO 2 emissions from renewable energy requirement s and programs might include the following:

 Metered MWh generation, using a revenue qualit y meter, or estimates of annual output for small systems below 10 kW in capacity

 MW capacity of “behind-the-meter” distri buted 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.DRAFT, DELIBERATIVE

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80  For renewable energy resources reported, including through REC data, the typical generating profile of a renewable energy gene rating 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, geogra phic 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 interconnect ed 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 CO 2 emissions in neighboring stat es. For example, many state renewable portfolio standards allow for gene ration by qualifying renewable energy sources in other states to count toward meeting the state po rtfolio requirement. Some states also apply CO 2 emission requirements related to the generati on 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 as sociated 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 CO 2 emissions from affected EGUs could be attributed in different ways in the context of an approvable state plan. This se ction discusses in more detail the options and

alternatives for treatment of interstate CO 2 emission effects presented in the preamble. These options and alternatives coul d be applied to both projecti ons of plan performance and demonstration of achieved emission performance under a plan. These opti ons and alternatives may not be mutually exclusive – in some inst ances states could appl y different approaches, without introducing the potential for double counti ng of emission effects. One option presented could lead to double counting of em ission effects, and we highlight these aspects of this option in

the discussion below.DRAFT, DELIBERATIVE

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81 In general, the options and alte rnatives address different possi ble state plan scenarios, and consider the range of interstate approaches that states are currently using to implement electricity sector policies, such as multi-state emissi on budget trading programs and regional renewable energy certificate markets for state RPSs. Th e options and alternatives reflect possible accounting approaches for interstate emission effects under CAA section 111(d) that could potentially align with these curr ent 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 importe rs of electricity on an annual basis. Reducing electricity load through improved e nd-use energy efficiency (e.g., th rough state energy efficiency programs) or deploying new re newable energy electric generati ng capacity (e.g., through a state RPS) therefore can result in CO 2 emission effects that are real ized outside the state that implements the regulation or program that produ ces the effects. Reducin g 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 program s often have regional effects on electricity ge neration and avoided CO 2 emissions. In addition, many state regulations explicitly address CO 2 emissions in neighboring states, or al low 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 meeti ng 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 CO 2 emissions from specific in-state EGUs. More often, reduction of electricity load will impact EGU dispatch across a regionalDRAFT, DELIBERATIVE

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82 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 measur es will affect electric ity generation in the state that reduces load, as well as in neighboring states.

State RPS regulations also impact electricit y generation at a regiona l level. Over time,

state RPSs result in the introducti on of new, incremental renewabl e energy generating capacity to regional generation control areas, which affects E GU dispatch at the regional level. State RPSs are typically applied to electric distribution utilities as a percen tage 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 renewa ble energy electric generation to take place within the state, or even be de livered into the state, but instea d require that the renewable energy be supplied within (or delivered into) the ISO/RTO in which th e state resides. Often, utility compliance with state RPS is through the submi ssion of renewable energy credits (RECs), which represent the attributes of renewable energy gene ration 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 diffe r in vertically integrated, cost-of-service

states where the distribution ut ility also owns electric gene rating capacity and dispatches generation resources within its se rvice territory. In such cases, th e 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 re newable energy generating ca pacity located inside

the state. Most of these carve-outs are for di stributed solar photovolta ic 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, base d on electricity demand, transmission constraints, and generation economics of individual pow er plants necessary for meeting de mand (e.g., in competitive wholesale markets, these factors are represente d through locational marginal prices (LMPs), which determine dispatch).DRAFT, DELIBERATIVE

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83 homes and commercial buildings). 106 Distributed solar PV capacity of ten provides benefits to the electric distribution system by improving distributi on system reliability and avoiding the need for distribution system capacity upgrades. This type of distributed renewa ble 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 CO 2 emissions, beyond

the state border.

B. Summary of Possible Approaches for Trea tment of Interstate Emission Effects

As discussed in the preamble, the EPA is pr oposing a set of approaches for addressinginterstate emission effects that result from the implementation of state plans that incorporate enduse energy efficiency and renewable energy pr ograms. The preamble also solicits comment on additional alternatives. The proposed a pproaches in the preamble include:

 For EE programs and measures:

o A state may take into account in its plan only those CO 2 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 w ould have the flexibility to distribute the

CO 2 emission reductions among states in the multi-state area.

o States could jointly demonstrate CO 2 emission performance by affected EGUs through a multi-state plan in a contiguous electric grid region, in which case attribution among states of emissi on 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 renewa ble energy resources, typically those where there is a significant renewable energy resource lo cated in the state. An example is car ve-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 time s of the day and year, solar PV systems supply electricity back to the grid, when PV system out put exceeds building electricity demand.DRAFT, DELIBERATIVE

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84 o Consistent with existing state RPS policies, a state could take into account all of

the CO 2 emision reductions from renewable energy programs and measures implemented by the state, whether they occu r in the state and/or in other states.

o States participating in multi-state plans w ould have the flexibility to distribute the

CO 2 emission reductions among states in the multi-state area.

o States could jointly demonstrate CO 2 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 potentia l 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 CO 2 emissions For plan measures such as end-use energy e fficiency and renewable energy regulations and programs, estimating the avoided CO 2 emissions from in-state versus out-of-state EGUs could be addressed through modeling, othe r analytical tools, or proxy metrics (e.g., net import factor).

 State that implements the measure cl aims 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-sta te generation) claims the avoided CO 2 emissions, regardless of where they occur.

 Cooperative multi-state accounting Multiple states are allowed to mutually ag ree to how they will distribute avoided CO 2 emissions from state plan measures (e.g., end-use energy efficien cy and renewable energy regulations or programs, or an em ission limit that addresses out-of-state generation) across their resp ective EGU fleets. Avoided CO 2 emissions are distributed among states by agreed formula they derive – an accounting “credit” in one state forDRAFT, DELIBERATIVE

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85 out-of-state avoided CO 2 emissions is complemented by an accounting “debit” in

the other state where the avoided CO 2 emissions occurred (i.e., through an increase in reported CO 2 emissions or CO 2 emission rate).

 Tradable regional EE/RE credit market

This is a variant of the multi-state accounti ng approach, which could be applicable where multiple states in a region are implementing ra te-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 allowe d to generate credits, based on MWh of energy savings or renewable energy generati on. These credits, which are denoted in

avoided tons of CO 2 or avoided MWh, could be used by affected EGUs toward demonstration of compliance with state rate-based CO 2 emission limits within a designated region. EE/RE credit issuance coul d be on a project and/or program basis. State accounting for interstate emission eff ects would be addresse d 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 demonstrat e emission performance by affected EGUs. Stets jointly demonstrate emission performan ce for affected EGUs, in terms of total CO 2 emissions (under a mass-based multi-state plan) or weighted average CO 2 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 e ffects on a regional basis duri ng 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 a ggregated identified pe rformance levels for affected EGUs in individual state plans). Alte rnatively, the EPA requires plan revisions if regional performance falls short of the aggr egated regional performance level (i.e., the aggregated identified performance levels for a ffected EGUs in indi vidual state plans).

Table 3 includes illustrative ex amples of the application of some of the different approaches for addressing interstate emission e ffects summarized above. The table explains howDRAFT, DELIBERATIVE

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86 these approaches might be applied in different state plan contexts. The illustrative examples consider the range of approaches states are cu rrently using to implement electricity sector policies, all of which in terstate effects, such as multi-state emission budget trading programs, regional renewable energy certificate markets us ed for state RPS compliance, and end-use energy efficiency programs.

Table 3. Applied Examples of Intersate Emission Effects A ttribution Approaches

1. State May Claim the Im pact of a Measure on CO 2 Emissions from Affected EGUs

Within its Borders

Under this approach, the effect of a state m easure could be applied to help demonstrate emission performance by affected EGUs in the state if it has the effect of avoiding CO 2 emissions from those in-state EGUs. This could be done regardless of whether the action taken to implement the state measure occurs within or ou tside the state. For example, renewable energy generation that occurs outside the state as a result of a state renewable portfolio standardDRAFT, DELIBERATIVE

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87 obligation would still be a valid state plan action, provided th e out-of-state renewable energy generation has the e ffect of avoiding CO 2 emissions from affected EGUs inside the state. As another example, for a state that is a net impor ter 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 el ectricity demand reductions could be applied to help demonstrate emission performance by aff ected EGUs in the state if the reduction in electricity demand has the effect of avoiding CO 2 emissions from those in-state EGUs.

Estimating the effect of RE and demand-side EE measures on in-state versus out-of-state

EGU CO 2 emissions could be addressed through m odeling, other analytical tools, or proxy metrics such as a net import factor.

Modeling could be used to assess the inters tate effects of state measures on EGU CO 2 emissions, both for projections of emissi on performance under the plan and ex post demonstration of performance achieved. Under th is approach, both projected plan performance and performance achieved is asse ssed 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 CO 2 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 CO 2 emissions from its own in-state EGUs, these effects could be applied to meet the required level of CO 2 emission performance for affected EGUs in the state plan. (See section IV.C of this TSD for a full di scussion of using a dispatch modeling approach to projected avoided CO 2 emissions that will be achieved through a plan.)

Ex post demonstration of plan performance To assess the state-by-state avoided CO 2 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 woul d assess the avoided CO 2 emissions resulting from reported MWh of energy savings and MWh of reported renewable en ergy generation, as a result of implementationDRAFT, DELIBERATIVE

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88 of EE/RE measures in the plan. Under a rate-based plan approac h, modeled estimates of avoided

CO 2 emissions, based on reported EE savings and RE generation, could be applied through an administrative adjustment by the state program admi nistrator or through the issuance of tradable EE/RE credits within the state. For ex post de monstration under a mass-based plan approach, performance would be determined based on reported stack CO 2 emissions from affected EGUs— no further analysis would be necessary. (See sect ion IV.C of this TSD for a full discussion of using a modeling look-back appr oach to estimate avoided CO 2 emissions.)

Use of simplified proxy metrics to apportion effects among states Simplified metrics, such as a net electricity im port or export factor, might also be applied to assess the impact of state actions in avoiding CO 2 emissions from in-state affected EGUs. For example, in a state that imports 30% of electricity on average dur ing a year, energy savings from EE measures might be multiplied by a factor of 0.70. 108 Avoided CO 2 emissions might then be calculated by multiplying this adjusted energy savings number by the average or marginal CO 2 emission rate for affected EGUs in the state. Th is type of approach could be employed in both projections of plan performance and ex post de monstrations of performance. However, this method would be subject to uncertainty, as elect ricity net imports may vary significantly on an annual basis, due to changes in system dispatc h. (See section IV.C of th is TSD for a discussion of dispatch dynamics that affect avoided CO 2 emissions.)

This approach would avoid double counting of emission effects of state measures among states. However, it could reduce incentives for st ates to employ measures that have a systemwide, regional effect in reducing EGU CO 2 emissions. In effect, because an adjustment factor would be applied to energy savi ngs under this approach, a net importer state would need to achieve greater energy savings through end-use en ergy efficiency requirements and programs to

achieve a ton of avoided CO 2 emissions under its plan than a st ate 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 CO 2 emissions from out-of-state EGUs that serv e electricity load in the importing state.DRAFT, DELIBERATIVE

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89 2. State that Implements the Measure Claims the Emission Effects

Under this approach, the state that implement s the measure (e.g., an EERS or RPS, or an

emission limit that addresses the at tributes of purchased electricity from out-of-state generation)

claims the avoided CO 2 emissions, regardless of where they occur.

If the avoided CO 2 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 adjust ment approach, out-of-state avoided emissions would be applied to the in-state EGU fleet by the state program administrator when determining average

fleet CO 2 emission rate or tonnage CO 2 emissions. Under a tradable credit approach, credits

would be issued for all avoided CO 2 emissions resulting from applicable state plan measures, without regard to where the avoided emissions occurred. Since the tradab le 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 lim its would functionally apply the avoided CO 2 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 CO 2 emissions on a system-wide, regional ba sis. 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 CO 2 emissions reductions from aff ected EGUs, without raising the prospect of double counting of emission effects among state.DRAFT, DELIBERATIVE

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90 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 CO 2 emissions from RE and demand-side EE measures across their respective EGU fleets. Avoided CO 2 emissions would be distributed among states according to a formula that they specify. Based on this agreed fo rmula, each state would adjust its demonstrated emission performance by affected EGUs accordingl y. In effect, a “credit” for out-of-state emission effects in one state would be compleme nted 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 c ounting of interstate emission effects among states. However, this approach is premised on regional collabor ation among all states in a grid region. Not all states in a grid region may be willing to coopera te in implementing such an accounting approach.

4. Tradable Regional EE/RE Credit Market

Under this approach, RE and demand-side EE ac tions that meet appl icable quantification, monitoring, and verification requirem ents would be issued tradable credits that could be applied by affected EGUs to their reported CO 2 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 premis ed 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 determin ed by economic factors such as credit prices and

109 These credits might be denoted in avoided CO 2 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 an d its plan approach, these tradable credits might represent a new instrument created for use under a state plan, or a state mi ght 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.DRAFT, DELIBERATIVE

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91 EGU marginal emissions abatement costs. In eff ect, accounting of interstate effects would be allocated among states based on prices in the credit market.

This approach is applicable if multiple stat es 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 e ffects 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 st ates implementing a mass-based approach, where

credits for avoided CO 2 emissions are transferred to affected EGUs located in another state for compliance purposes, the state from which credits were transferred would adjust its reported CO 2 mass emission from affected EGUs when de monstrating achievement of the required CO 2 emission performance level by affected EGUs identified in the state plan. 111

5. Regional Demonstration by St ates of Emission Performance

Under this approach, multiple states would demonstrate CO 2 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 CO 2 emissions. Instead, states would asse ss the impact of state measures in avoiding CO 2 emissions from the fleet of affected EGUs in the multi-state region.

This approach creates incentives for the impl ementation of system-based approaches that collaboratively reduce EGU CO 2 emissions on a regional basis, wh ile also avoiding the need to

attribute interstate emission e ffects among states. However, regi onal collaboration will require more time for the development of multi-state pl ans. This approach is also premised on the

111 Note that in this example, state reporting of overall achieved CO 2 emission performance by affected EGUs under a state plan is distinct from demonstration of compliance by affected EGUs subject to a mass-based CO 2 emission limit. For EGU compliance, no adjustment would be made to CO 2 emissions reported by affected EGUs subject to the mass-based emission limit, even though emissions from these a ffected 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 CO 2 emissions from the affected fleet to account for the “export” of avoided CO 2 emission credits, in order to demonstrate the overall level of CO 2 emission performance that is assume d to have been achieved by the affected EGU fleet under the plan. 112 This approach could be applied for CO 2 emission performance on e ither a rate or mass basis.DRAFT, DELIBERATIVE

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92 willingness of all states in a grid region to par ticipate in the development and implementation of a multi-state plan. Some states in a grid regi on 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, consideri ng the measures contained in the group of state plans for a respective grid region. Under this approach, the EP A might conduct an analys is that considers all of the state program measures together on a co mbined basis and evaluates projected emissions performance achieved by affected EGUs in the region.

To the extent that all affected EGUs in a re gion are projected to ach ieve the required level of performance represented in i ndividual state plans, or are proj ected to achieve an aggregate regional level of performance consistent with th e level of required perf ormance included in all state plans in the region, instan ces of double counting of interstate effects among states are less important. The EPA could indicate as part of plan approval that it wi ll review actual emission performance achieved by affected EGUs duri ng the plan period on a regional basis.

VIII. Appendix

Survey of Existing State Policies and Programs that Reduce Power Sector CO 2 Emissions

[This appendix will include the content in the do cument, Survey of Existing State Policies and Programs that Reduce Power Sector CO 2 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.