From: Frey, Nathan J. < Nathan_J._Frey@omb.eop.gov > 

Sent: Tuesday, July 28, 2015 9:32 PM 

To: Culligan, Kevin; Harvey, Reid; Vasu, Amy 

Subject: Summary of Interagency Comments Under EO 12866 and 13563 -- CPP TSD on 

Incorporating RE and Demand-Side EE Impacts into State Plan Demonstrations 

Attached please find a summary of interagency comments under EO 12866 and 13563 on the CPP 

TSD on Incorporating RE and Demand-Side EE Impacts into State Plan Demonstrations. 

 

Thanks and please let me know if you have any questions. 

Nathan 

<< SummaryofinteragencycommentsunderEO12866_13563_EO 12866_RE and EE 

TSD_7282015.docx >> 

<< SummaryofinteragencycommentsunderEO12866_13563_EO 

12866_EEREimpactsTSD_CPP_7282105.docx >> 
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Review.

1

General Comments

1. Page 2 & throughout text: Reviewer recommends clarifying the text to indicate that any state

choosing a state‐measures approach must submit a CO2 emission performance projection.

Recommended text:  

“This technical support document details demonstration requirements for Clean Power Plan

(CPP) state plan submittals that must include carbon dioxide (CO2) emission projections,

primarily states adopting a state measures plan or, as identified in section VIII.D.2.a.(3) of the

preamble.”  

2. Pages 2‐3: Reviewer recommends moving the references to NERC to after the discussion of a

state using a growth rate from an organization to develop their own base case, since we do not

believe that NERC has state‐level demand projections so the only way to use this source is

applying the demand growth rate.  Additionally, reviewer is concerned with the use of a

vertically integrated utility, which is likely to be a compliance entity as an owner of affected

EGUs, to also be the source of a baseline used for the demonstration of a state plan. See below

for suggested line edits.

“A state can develop its own base case electricity demand and supply  forecast or use a

forecast from the following information sources.  

 U.S. Department of Energy, Energy Information Administration, Annual Energy

Outlook (AEO),

 North American Electric Reliability Corporation (NERC),

 Regional transmission organizations (RTOs)/independent system operators (ISOs)

(e.g., PJM Interconnection, ISO‐New England, NYISO),

 Vertically integrated utilities (e.g., a large power company that operates the

electricity system for a specific region), in combination with another source

 State energy agencies (e.g., State Energy Office or Public Utility Commission (PUC)),

and

 Regional councils that coordinate energy planning (e.g., Northwest Power and

Conservation Council)

3. Page 3: Reviewer recommends clarifying if electricity imports from other states and/or regions

should be included in the inventory of “existing generation that can be used to serve the state’s

forecasted base case demand.”

4. Page 3: Reviewer recommends the following addition to ensure that states do not artificially

inflate projected electricity demand in the base case (and thus GHG emissions savings in the

state plan case).  

“To develop its own state‐specific base case electricity demand and supply forecast, a state

would apply an annual average electricity demand growth rate derived from one of the above

data sources to state or regional specific historical electricity sales data. EPA must approve any
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Review.

2

state‐created state‐specific base case forecast.”  

5. Page 3: Reviewer recommends indicating that states may have to derive a forecast from these

sources, as many of these sources do not provide state‐specific  forecasts (i.e. AEO only provides

forecasts by NERC subregions)

6. Page 3 (third bullet at bottom of page): Reviewer suggests the following edit for clarification.  

“Forthcoming federal appliance and lighting standards,”

7. Page 4: Reviewer recommends clarifying what it means that EGUs in the state “do not need to

use” energy savings from the state’s EERS. Reviewer recommends clarifying if that means that

the state has chosen a mass emission standard or a rate emission standard that does not credit

EE or if a different scenario(s) was in mind.

8. Page 4 (footnote 1): Reviewer suggests the following edit for clarification.  

“For example, the U.S. Energy Information Agency’s (EIA) Annual Energy Outlook (AEO) says that

existing federal appliance and equipment standards for residential and commercial sectors...”

9. Page 4: Reviewer notes that AEO2013 (and all AEO projections) include embedded decreased

demand due to distributed photovoltaic generation in the demand forecast. Recommend

indicating in a footnote that if AEO demand projections are used for a base case, the amount of

distributed photovoltaics should be accounted for to avoid double‐counting of these eligible

resources in state projections.  Suggested text:  

“Note that all AEO demand projections include embedded reduced demand due to projected

deployment of distributed photovoltaic generation. States should account for this in their state

plan performance projection if AEO demand projections are used for the base case forecast to

prevent double‐counting of these eligible resources.”

10. Page 4: Reviewer recommends that an additional example of a mass based plan be included on

page 4 in the example of programs needing a projection, showing that the forecast is made for

both a mass and rate‐based plan, though actual EM&V and measurement of the savings would

not be needed for compliance.

11. Page 5: Reviewer requests clarification as to whether projections for the on‐the books policies

and programs are required for mass‐based program. For example, if a state elects to use a mass‐

based program and does not have an explicit EERS, do they need to quantify where the

emissions reductions will take place beyond the allowance system?

12. Page 5: Reviewer request clarification if the “eligible measures” referred to in the following

sentence refers to measures eligible according to EPA or according to the submitted state plan,

which may be a subset of those eligible according to EPA.  The reviewer believes the intent is to

refer to state eligible measures otherwise the EERS example that was mentioned on page 4

would also need this more extensive reporting.
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Review.

3

“RE and demand‐side EE programs that have resulted or will result in state plan eligible

measures implemented after 2012 that impact electricity in 2022 or later.”

13. Page 5‐6: Reviewer requests clarification as to what it means for RE and EE to be represented

“differently” in the state plan performance projection. It seems to the reviewer that if RE and EE

measures are represented in the base case they should not be counted again in the state plan

performance projection. Therefore, the reviewer recommends the following edits.  

“Because these one‐the‐books RE...the same impacts must not be represented differently again

in the state plan performance projection. In other words, such impacts cannot be “added” to the

base case forecast when making the state plan performance projection, because they are

already captured in that base case forecast.”

14. Page 8: Reviewer recommends clarifying the first term of this equation, perhaps by changing

“and” to “plus”: “(Incremental first‐year annual and cumulative savings of EE program) x

(effective useful life) for each interim period and final period. Determine persistent level of

savings for final period and beyond.”

15. Page 9: Reviewer requests clarification on the use of “sales”  on page 9 in “Some specify goals

based on sales from investor‐owned utilities, while others have mandated energy savings

targets based on total sales or a subset of total sales” and throughout. Does this mean sales or

MWh?  Reviewer suggests substituting “MWh sold”

16. Page 10: Reviewer recommends inserting language to indicate that the AEO2013 forecast does

not include state level EERS policies. Reviewer also recommends indicating how states should

derive the embedded AEO2013 EE savings as EE savings are not reported out in a simple table by

the AEO and are also not reported out by state but by NERC subregion. Reviewer also

recommends noting in a footnote why AEO2013 forecasts must be used for these equations.  

17. Pages 12‐13: reviewer recommends also pointing out the fact that some state RPS rules about

allowing RECs from other states may not be consistent with rules about affected EGUs claiming

credit for RE generated in another state, for example, in a mass state with no demonstration

that load was served in a rate state. Suggested text: “Further, some state RPSs allow for out‐of‐

state renewable generation to be claimed for the state’s RPS. The state must demonstrate that

provisions in the state policy allowing out‐of‐state procurement are consistent with the

provisions allowing this type of procurement, as well as the restrictions on trading of ERCs based

on state plan type, as described in the Preamble.”   

18. Page 13: Reviewer recommends indicating that state level bonuses applied to crediting RE

generation (for example, bonuses applied to in‐state generation) to RPS compliance, would not

be included in the calculations in Section C(2).

19. Reviewer recommends clarification on what happens to state RPSs that include alternative

compliance payments (ACPs)? If ERCs are purchased with ACP funds, can that be approvable?
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Review.

4

20. Reviewer suggests EPA publish a list (and note here in text its intent to do so) of methods as

they are approved to provide greater transparency and increase confidence in likelihood of

approval for states still in the submittal process.

21. Page 28: "In 2014, an LBNL analyzed the program cost of saved energy based on data from their

DSM Program Impacts Database." Reviewer recommends clarifying that the referenced LBNL

work analyzed the "program administrator" cost of saved energy.

Reviewer also recommends considering the follow‐on to this study that looked at the participant

costs, available at http://emp.lbl.gov/what‐it‐costs‐save‐energy.  Note that this newer report is

cited as "LBNL. 2015b. The Total Cost of Saving Electricity through Utility Customer‐Funded

Energy Efficiency Programs: Estimates at the National, State, Sector and Program Level.

Lawrence Berkeley National Laboratory. Available at http://emp.lbl.gov/sites/all/files/total‐cost‐

of‐saved‐energy.pdf." but doesn't appear to be referenced in the document. EPA should update

the reference.

Technical & Editorial Comments

1. Page 3: Technical edit:  “It is important to understanding which resource options are currently

available to the state for meeting future demand.”

2. Page 5: “Because these one‐the‐books RE and demand‐side EE measures or programs”

3. Page 5 & throughout text: Reviewer recommends replacing “*” and “x” in equations with

multiplication symbol “×”

4. Page 8: Reviewer recommends modifying the equation for Renewable Energy to reflect accurate

calculation of MWh:  

“(Incremental MW installed capacity) × (location and technology‐specific capacity factors) ×

(8760 h) for each interim period and final period.”

5. Page 13: Reviewer recommends updating equation to demonstrate correct calculation of annual

MWhs:

“A(t) = [f1(t) × C1(t) + f2(t) × C2(t) + f3(t) × C3(t)] × 8760 hours”
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***

Summary	of	Interagency	Working	Comments	on	Draft	Language	under

EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Review.

Technical Support Document (TSD) 

Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electricity Utility 

Generating Units 

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

Incorporating RE and Demand-Side EE Impacts into 

State Plan Demonstrations 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

July 2015 

 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***

2 

I. Introduction 

This technical support document details demonstration requirements for Clean Power Plan 

(CPP) state plan submittals that must include carbon dioxide (CO2) emission projections, as 

identified in section VIII.D.2.a.(3) of the preamble. A state’s CO2 emission projection will 

include both a base case electricity demand and supply forecast and a state plan performance 

projection. Section II below addresses important elements of a base case electricity demand and 

supply forecast. Section III covers proper characterization of renewable energy (RE) and 

demand-side energy efficiency (EE) policies and programs in a state plan CO2 emission 

performance projection, including projection approaches and documentation requirements. 

II. Base Case Electricity Demand and Supply Forecasts 

The CO2 emission performance projection of affected electric generating units (EGUs) 

requires information from an electricity demand and supply forecast as a basis for predicting 

generation and emissions during the interim and final plan performance periods. This section 

describes the steps a state should take to demonstrate that the base case demand forecast 

transparently represents future demand and supply: 

Step 1: Choose or develop a base case electricity demand and supply forecast. 

Step 2: Document renewable energy and demand-side energy programs already included 

in the base case electricity demand and supply forecast. 

Step 1: Choose or develop a base case electricity demand and supply forecast 

A state can develop its own base case electricity demand and supply forecast or use a forecast 

from the following information sources. 

 U.S. Department of Energy, Energy Information Administration, Annual Energy 

Outlook (AEO), 

 North American Electric Reliability Corporation (NERC), 

 Regional transmission organizations (RTOs)/independent system operators (ISOs) 

(e.g., PJM Interconnection, ISO-New England, NYISO), 

 Vertically integrated utilities (e.g., a large power company that operates the electricity 

system for a specific region), 

Commented [A1]: Is there any reason why EPA is 

excluding IPM as a choice for a forecast? 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***  

3

 State energy agencies (e.g., State Energy Office or Public Utility Commission 

(PUC)), and 

 Regional councils that coordinate energy planning (e.g., Northwest Power and 

Conservation Council) 

To develop its own state-specific base case electricity demand and supply forecast, a state would 

apply an annual average electricity demand growth rate derived from one of the above data 

sources to state or regional specific historical electricity sales data. For the base case supply 

forecast, a state should inventory all existing generation that can be used to serve the state’s 

forecasted base case demand. It is important to understanding which resource options are 

currently available to the state for meeting future demand. 

Step 2: Document renewable energy and demand-side energy efficiency measures included 

in base case electricity demand and supply forecast. 

Information sources reflect on-the-books demand-side EE policies to varying degrees in 

demand and supply forecasts, and a state must research and document how each RE and demandside EE program included in the demand or supply forecast used by the state is incorporated into 

that forecast. This will clarify which programs are influencing the growth rate assumptions, and 

EPA will use this information to assess whether the demand and supply forecast is reasonable. 

This also helps ensure that impacts captured in the base case forecast are not double-counted in 

the base case forecast or duplicated in the state plan performance projection. A state should work 

with the source of the forecast to understand whether and how the following policies are 

included in the base case electricity demand and supply forecast:

 EE policies or programs funded by utility ratepayers, 

 Existing federal appliance and lighting efficiency standards that are already in effect, 

 Federal appliance and lighting standards, 

 State appliance or lighting efficiency standards (if applicable), 

 State building energy codes, 

 Renewable portfolio standards and 

 Other applicable policies/programs (e.g., codified local policies). 

There are at least two ways that these programs are captured in an existing forecast: 

Deleted: the 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***

4 

1. Programs are explicitly identified, meaning the forecast shows a direct connection 

between the program and its impacts on energy demand or supply (MWhs) 

2. Programs are indirectly, and either fully or partially, captured through econometric or 

other assumptions in the economic model (e.g., as captured in National Energy Modeling 

System (NEMS)).1

For all RE and demand-side EE programs included in the base case demand forecast, a state must 

document whether the program is captured explicitly or indirectly. In addition, a state must 

include the following information for on-the-books programs that are reflected in the base case 

forecast. 

1. Policy name 

2. Whether the policy is codified in state or local rule 

3. Year enacted 

4. When the policy requirement sunsets 

The above requirements apply regardless of whether the RE or demand-side EE program is 

included as a component of the state plan. For example, assume a state with an EERS in state law 

adopts an emission standards state plan type that requires a projection. The impacts of the on-thebooks EERS will be included in the base case demand forecast. If the affected EGUs in the state 

do not need to use the energy savings from the state’s EERS to adjust their CO2 emission rates, 

then the state’s plan demonstration would include the four pieces of information above about the 

EERS to support the reasonableness of the electricity demand forecast. But if the state expects 

affected EGUs to use the EE impacts from the EERS to adjust their rates, then the state plan 

                                                            

1

 EE programs explicitly included in a demand forecast are programs that the forecast’s documentation 

specifically states directly impact future demand levels. Some EE programs, however, are indirectly 

represented in the assumption and not explicitly identified. For example, the U.S. Energy Information 

Agency’s (EIA) Annual Energy Outlook (AEO) says that federal appliance and equipment standards for 

residential and commercial sectors as well as state renewable portfolio standards are explicitly included in 

the reference case for electricity demand and supply forecast. The AEO indirectly captures some impacts 

of state EE programs in the forecast, and does not explicitly call out their impacts. Indirect impacts do not 

need to be quantified, but on a case-by case basis, a discount factor toward any incremental savings in the 

CPP performance projection may be required to adjust for potential double counting. For more 

information visit: http://www.epa.gov/statelocalclimate/state/statepolicies.html. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***  

5

should document the eight pieces of information at the end of this section. This information will 

inform the EPA's evaluation of whether the emission standards in the state plan are achievable. 

In addition to documenting whether on-the-books RE or demand-side EE measures are 

directly or indirectly captured in the base case demand and supply forecast, the state plan must 

provide additional information on certain types of on-the-books programs. There are at least two 

categories of on-the-books policies and programs that must be explicitly accounted for in the 

base case demand and/or supply forecast and in the following manner: 

 RE and demand-side EE programs that have resulted or will result in eligible measures 

implemented after 2012 that impact electricity in 2022 or later.2 

o Quantify the (annual incremental and cumulative savings or generation (MWhs)) 

x (effective useful life) to estimate the savings that impacts demand or generation 

in 2022 or later 

 RE and demand-side EE programs that have resulted or will result in implementation of 

eligible measures that meet Clean Energy Investment Partnership Program requirements 

that impacts electricity in 2020 or 2021.3

o Quantify the (annual incremental and cumulative savings or generation (MWhs)) 

x (effective useful life) to estimate the savings that impacts demand or generation 

in 2020 and 2021. 

Because these on-the-books RE and demand-side EE measures or programs are explicitly 

accounted for in the base case demand forecast, the same impacts must not be represented 

differently in the state plan performance projection. In other words, such impacts cannot be 

“added” to the base case forecast when making the state plan performance projection, because 

they are already captured in that base case forecast. For any RE and demand-side EE programs 

                                                            

2

 Section VIII.K.1.(a) of the preamble provides that eligible demand-side EE actions and RE installations 

that occur after 2012 can be applied toward adjusting a CO2 emission rate. 3

 For details refer to Section VIII.B.2 and Section VIII.K.1.a.(2)(a) of the preamble. 

Deleted: e
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***

6 

that are explicitly included in an EGU base case forecast and will be used to meet the CPP 

emission guidelines, the state must document the following information. 

1. Policy or program name 

2. Whether the program is codified in state or local rule 

3. Year enacted 

4. When the program requirement sunsets 

5. Program requirements (e.g., targets in megawatt hours (MWh) or percentage) 

6. Annual energy savings or generation base year (MWh) 

7. Annual and cumulative energy savings or generation in the future interim and 

final periods (MWh) 

8. Estimated useful lives for programs. 

III. Proper Characterization of Renewable Energy and Demand-Side 

Energy Efficiency in a State Plan Performance Projection 

Section VIII.D.2.a.(3)(a) of the preamble explains which types of state plans require CO2

emission performance projections for affected EGUs in order to show the state plan will lead to 

achievement of the CO2 emission performance rates, state goal, or other emission guideline 

requirements. State plans that require such a projection must include a base case electricity 

demand and supply forecast and supporting documentation, as explained in section II above. In 

addition, such plans must quantify the combined future impact of all the emission standards and 

state measures included in the state plan. This section explains the proper characterization of 

expected RE and demand-side EE impacts in a CO2 emission performance projection. 

States that plan to use RE and demand-side EE to meet the emission guidelines (e.g., to 

generate ERCs or as state measures) under applicable state plan types that require a performance 

projection will need to project the expected incremental direct generation impacts and electricity 

savings of RE and demand-side EE.4

 While RE and demand-side EE measures, programs and 

policies may impact the generation, construction, retirement and CO2 emissions of both affected 

and non-affected EGUs, a projection must demonstrate how RE and demand-side EE will enable 

                                                            

4

 Incremental direct effects refers to RE and demand-side EE beyond any impacts that are in the base 

case. If a new program is more stringent than an existing program already in the base case, it may not be 

appropriate to use the full magnitude of the new program. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***  

7

affected EGUs to meet the emission guidelines. There are different approaches to projecting 

electricity savings and/or renewable generation, depending upon how an RE and demand-side 

EE program requirement is designed. Regardless of the approach chosen, a state plan that 

includes RE and demand-side EE must document specific assumptions in their performance 

projections, as described below. 

A. Approaches to estimating future energy efficiency savings and renewable 

energy generation

Projections of expected annual electricity savings and/or renewable energy generation are 

necessary inputs when projecting EGU CO2 emission performance. This is because increased RE 

generation will impact the generation of affected EGUs and resulting CO2 emissions. Electricity 

savings estimates included in EE projections will lower electricity demand forecasts in the CO2

emission performance projections. The energy efficiency projection can be used as an input, or 

modifier, to various models or other tools in order to demonstrate that the state plan will achieve 

emission guideline requirements. 

A state plan performance projection must include the potential impacts of RE and demandside EE, and the state must document how those RE and demand-side EE impacts are reflected in 

the projection. The state can incorporate RE and demand-side EE impacts at the individual 

project or program level, or it can aggregate RE and demand-side EE impacts across a portfolio 

of programs. The EPA historically has accepted the estimation of RE and demand-side EE at an 

aggregated level as indicated in EPA’s Bundled Measures Guidance.5

 The state must also verify 

that the assumptions about RE and demand-side EE availability are reasonable, such as based on 

an assessment of RE and demand-side EE potential.

A state plan performance projection must not include RE and demand-side EE impacts 

captured in the base case electricity demand forecast. Consequently, RE and demand-side EE 

impacts included in the state plan performance projection must be incremental to and nonduplicative of impacts included in the base case demand forecast. The performance projections, 

for example, could include impacts from RE and demand-side EE programs not reflected in the 

                                                            

5

 www.epa.gov/ttn/oarpg/t1/memoranda/10885guideibminsip.pdf 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***

8 

base case forecast or from the expansion of existing programs beyond levels reflected in the base 

case forecast. A state must use the following general equations to quantify the expected 

incremental impacts of RE and demand-side EE during the future interim and final performance 

periods.6

Energy Efficiency: 

 (Incremental first-year annual and cumulative savings of EE program) x (effective useful 

life) for each interim period and final period. Determine persistent level of savings for 

final period and beyond. 

Renewable Energy: 

 (Incremental MW installed capacity) x (location-specific7

 and technology capacity 

factors) for each interim period and final period. Determine persistent level of renewable 

energy generation for final period and beyond.

Several tools and methods are available to help states estimate the potential direct energy 

impacts of RE and demand-side EE that will be used to adjust a state’s electricity demand and 

supply forecast. States can base their electricity savings projections on past evaluation, 

measurement and verification (EM&V) reports that document impacts of similar projects or 

programs and that have been submitted to public service commissions or evaluated by third 

parties. States also can conduct their own surveys or studies to estimate the direct energy impacts 

of EE policies and/or use sophisticated methods, such as building simulation tools, vintaging 

models, production costing, and cost-of-energy analysis models.8

 Any methodology used must 

                                                            

6

 The EPA recognizes that for unique situations, states may not be able to use these exact equations. In 

those unique circumstances, states can propose an alternative equation to EPA for approval on a case-bycase basis. 

7

 States can use location-specific capacity factors informed by historical data or weather-prediction 

models, such as the kind of data included in the National Renewable Energy Laboratory (NREL) Eastern 

Wind Integration and Transmission Study (EWITS) or in publicly available datasets from EIA and 

ISO/RTOs. 

8

 For more information about available tools for estimating direct energy impacts, see Assessing the 

Multiple Benefits Guide: A Resource for States, Chapter 2. 

http://www.epa.gov/statelocalclimate/documents/pdf/epa_assessing_benefits_ch2.pdf#page=4 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***  

9

be EPA-approved, and each state is encouraged to consult with the EPA early during the plan 

development process about the tools and methods it intends to employ.

Assessing the potential RE and demand-side EE impacts of measures, policies or programs 

can involve bottom-up economic and/or engineering-based estimation techniques that are based 

upon a representation of the fundamentals of the technology and economic behavior. These 

bottom-up approaches estimate potential energy savings at a very detailed level and roll these 

estimates up to the statewide level. Alternatively, the potential impacts of RE and demand-side 

EE can be quantified based upon the design and requirements of state-level policies and 

regulations specified over a future timeframe. The next two sections describe how a state plan 

CO2 performance projection would calculate the generation impacts of two common state 

policies: energy efficiency resource standards and renewable portfolio standards. 

B. Projecting Energy Savings from Energy Efficiency Resource Standards

Many states have adopted an energy efficiency resource standard, which is a policy that sets 

targets for energy savings over a specified time frame from demand-side EE programs operated 

by utilities or other program administrators. States typically specify annual first-year or 

cumulative targets as percentages of electricity sales or as absolute energy savings. States use 

different bases for specifying EERS goals. Some specify goals based on sales from investorowned utilities, while others have mandated energy savings targets based on total sales or a 

subset of total sales. 

A state can quantify energy savings for use in its projection using formulas specific to the 

state’s EERS, as described below.9

 For this approach a state would select the appropriate sales 

basis and, if the basis is not total sales, a state could use recent year utility-level sales data from 

EIA and growth rates from EIA, RTO, ISO, NERC or other publically available sources to 

develop base case forecasts of sales of the utilities required to comply with the EERS. The 

design of the EERS will affect whether a state should assume full achievement of the EERS 

targets. For example, it may not be appropriate to assume full achievement of an EERS that 

                                                            

9

 Savings from purely voluntary EE goals are not state enforceable measures and are not eligible for use 

in a performance projection for a state measures plan type. 

Commented [A2]: This discussion of computing savings 

from EERS should discuss how to account for the difference 

between net and gross savings where both are reported and 

where only one is 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***

10 

includes cost/rate caps or other design features that may not lead to incremental energy savings 

relative to the base case demand forecast (e.g., counting savings from building energy codes or 

historical EE programs). 

The general formulas a state must use to quantify first-year and cumulative energy savings 

from an EERS policy for each year (t) are shown below, though a state may propose a different 

methodology if it better represents the state’s EERS. 

1. EERS with Annual First-Year EE Savings Targets Specified in Percent Terms 

A(t) = r(t) * Z(t-1) 

C(t) = A(t) + A(t-1) + ... + A(t-L+1) 

I(t) = C(t) - E(t) 

Z(t) = B(t) - I(t) 

Where: 

 r is the annual first-year percent savings target, 

A is the annual first-year energy savings, 

L is the measure lifetime, 

B is the base case sales of utilities affected by these specific policies, 

C is the cumulative energy savings, 

E is the cumulative savings embedded in the AEO2013 forecast, 

I is the cumulative savings incremental to AEO2013 forecast, and 

Z is the adjusted sales after application of cumulative incremental savings. 

2. EERS with Annual First-Year EE Savings Targets Specified in Absolute Terms 

C(t) = A(t) + A(t-1) + ... + A(t-L+1) 

I(t) = C(t) - E(t) 

Z(t) = B(t) - I(t) 

Where: 

A is the annual first-year energy savings target, 

L is the measure lifetime, 

B is the base case sales of utilities affected by these specific policies, 

C is the cumulative energy savings, 

E is the cumulative savings embedded in the AEO2013 forecast, 

I is the cumulative savings incremental to AEO2013 forecast, and 

Z is the adjusted sales after application of cumulative incremental savings. 

3. EERS with Cumulative EE Savings Targets Specified in Percent Terms 

A(t) = C(t) – C(t-1) + A(t-L) 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***  

11

If r(t) available, 

C(t) = r(t) * B(t) 

I(t) = C(t) - E(t) 

Z(t) = B(t) - I(t) 

If r(t) not available, 

Z(t) calculated by interpolation 

I(t) = B(t) - Z(t) 

C(t) = I(t) + E(t) 

Where: 

r is the cumulative percent savings target, 

A is the annual first-year energy savings, 

L is the measure lifetime, 

B is the base case sales of utilities affected by these specific policies, 

C is the cumulative energy savings, 

E is the cumulative savings embedded in the AEO2013 forecast, 

I is the cumulative savings incremental to AEO2013 forecast, and 

Z is the adjusted sales after application of cumulative incremental savings. 

4. EERS with Cumulative EE Savings Targets Specified in Absolute Terms 

A(t) = C(t) – C(t-1) + A(t-L) 

If C(t) available, 

I(t) = C(t) - E(t) 

Z(t) = B(t) - I(t) 

If C(t) not available, 

Z(t) calculated by interpolation 

I(t) = B(t) - Z(t) 

C(t) = I(t) + E(t) 

Where: 

C is the cumulative energy savings target, 

A is the annual first-year energy savings, 

L is the measure lifetime, 

B is the base case sales of utilities affected by these specific policies, 

E is the cumulative savings embedded in the AEO2013 forecast, 

I is the cumulative savings incremental to AEO2013 forecast, and 

Z is the adjusted sales after application of cumulative incremental savings. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***

12 

C. Projecting Generation Impacts from Renewable Portfolio Standards 

Renewable portfolio standards (RPS) set RE targets across a specified period of time. Most 

often these state policies require that a specified percentage of the electricity sold by a utility 

come from eligible renewable technologies (e.g., wind, solar, biomass). 

A state must project annual RE generation using formulas specific to the state’s RPS policy, 

as shown below, or an EPA-approved alternative method. Similar to the EERS approach 

described above, a state would select the appropriate sales basis and, if the basis is not total sales, 

a state could use a recent year of utility-level sales data from EIA and growth rates from EIA, 

RTO, ISO, NERC or other publically available sources to develop base case forecasts of sales for 

the utilities required to comply with the RPS. 

The design of the RPS will affect whether a state can assume full achievement of the RPS 

targets. Many RPSs include provisions for alternative compliance payments, which allow an 

entity to pay a fee in lieu of achieving the RPS. Additionally, RPS policies may include sources 

that are not eligible for CPP compliance purposes. In such cases, only generation impacts from 

eligible RE sources should be included in a state plan performance projection. 10

The general formulas a state must use to quantify annual generation impacts of an RPS 

policy for each year (t) are shown below, though a state may propose a different methodology if 

it better represents the state’s RPS. 

1. RPS with Annual Targets Specified in Percent of Retail Sales Terms 

A(t) = r(t) * Z(t) – MWhineligible(t) 

Where: 

A is the total MWh of CPP-qualifying renewable generation in a future year, 

r is the annual RPS percent RE target, 

Z is the forecasted sales that fall under the RPS policy, and 

MWhineligible is the MWh of generation from technologies ineligible under CPP 

(t) is the year 

                                                            

10 RE generation from purely voluntary RE goals are not state enforceable measures and are not eligible 

for use in a performance projection for a state measures plan type. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***  

13

Note that each state should apply this general formula to its specific RPS design. For example, if 

a specified percentage of RE is required to be met by sales from investor-owned utilities and 

separate percentage from rural cooperatives, then the state should apply the formula individually 

for each class and sum the MWh for each to calculate A(t). Additionally, each state plan should 

estimate the MWh of generation from any technologies that fall within the scope of its RPS but 

outside CPP. This estimate (MWhineligible) can be based on planned and/or expected new 

capacities for these technologies and best-available historical capacity factors. 

2. RPS with Annual Targets Specified in Absolute Capacity Terms (MW) 

RPS policies often include technology “carve-outs” that specify required contributions of 

particular technology types. Even where these carve-outs are not specified, many different 

technologies can contribute to meet an RPS. The formula below illustrates three different 

technologies contributing to an RPS. The distinction between technology types is important in 

calculating RE generation from a capacity-based RPS due to the differences in the underlying 

operating characteristics of technologies (i.e., capacity factors). Each state should include the 

number of technology types that best applies to its own RPS design. In this example, each 

technology (1, 2, and 3) is an eligible RE resource per the final emission guidelines; a technology 

that is not an eligible RE resource should not be included in the formula.11

A(t) = f1(t) * C1(t) + f2(t) * C2(t) + f3(t) * C3(t) 

Where: 

A is the total MWh of eligible renewable generation in a future year, 

f1, f2, and f3 are annual effective capacity factors for eligible technologies 1, 2, and 3, 

respectively, and 

C1, C2, and C3 are the eligible renewable capacities for technologies 1, 2, and 3, respectively 

(in MW). 

The above equations are sufficient to calculate the expected annual energy output from 

renewable energy associated with an RPS. As previously noted, annual capacity factor 

                                                            

11 For more information about what renewable resources are eligible under the emissions guidelines, see 

Section VIII.K.3. 

Commented [A3]: Should this formula not include the 

hours of generation (i.e. multiply by 8760 hrs)? 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***

14 

projections vary by technology and even within a technology category, depending on the location 

of the resource. As a result, if annual energy projections are based on aggregate capacity factors, 

a state should specify the location of all assumed RE generation and the source of capacity factor 

projections. 

D. Documentation of Assumptions Related to Renewable Energy and DemandSide Energy Efficiency in a State Plan CO2 Performance Projection

As explained above, states that plan to use RE and demand-side EE policies and programs 

under a state plan approach that requires a demonstration using projections (as described in 

Section VIII.D.2.a.(3)(a) of the preamble) must quantify for each requirement and program the 

expected direct electricity savings and generation impacts on affected EGUs. Further, the state 

plan performance demonstration must document the underlying assumptions regarding the 

renewable electricity generation impacts and electricity savings on affected EGUs. Specific 

considerations and assumptions that should be described in the state plan, when relevant, include 

the following: 

 Energy efficiency and/or renewable energy requirement or program description: What is 

the requirement/program? Who will administer it? Does it require new legislation or can 

a state implement it under existing authorities? 

 Requirements/program time period: What year does each specific program start and end? 

What are the MWh targets for the interim and final performance periods, including 

interim steps and other applicable time periods? How will the program meet the 

permanent requirements in the CPP? 

 Relationship to complementary or existing requirement/program(s): Will this program 

include any federally enforceable limits? Are state measures an expansion or extension of 

existing requirements or programs? If the plan includes an expansion of an existing 

program that allows for ineligible resources or unaffected EGUs, how does the 

demonstration address these impacts? 

 Program focus: What sector or consumer type is the focus of the measure? 

 Anticipated compliance or penetration rate: Which affected EGUs will be subject to the 

RE and demand-side EE policy or program required by the state measure? Does the 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***  

15

projection reflect characteristics of the EE end-use sector/or renewable energy 

technology? 

 Technology performance: What technologies and/or generating capacity will be 

implemented? For how many years will the measure achieve electricity savings (e.g. 

measure life) or generate renewable electricity? How will measure performance degrade 

or decay over time? 

 Transmission and distribution (T&D) loss: Is there an expected increase or decrease in 

T&D losses that would require adjustment of the energy savings estimate? 

 Resource Costs: What is the cost of saved and/or generated electricity for the energy 

efficiency and/or renewable energy measures? 

 Program Costs and Funding: What is the cost of the program, including administration 

costs? How will it be funded? 

 Resource availability: Are the projected electricity savings or renewable electricity 

generation levels realistic compared to the potential available?