Regulatory Impact Analysis 

for the 

 Proposed Federal Plan Requirements for 

Greenhouse Gas Emissions from Electric 

Utility Generating Units Constructed on or 

Before January 8, 2014; Model Trading 

Rules; Amendments to Framework 

Regulations 
ii 

[This page intentionally left blank] 
iii 

EPA-452/R-15-006 

August 2015 

Regulatory Impact Analysis for the for the 

Proposed Federal Plan Requirements for Greenhouse Gas 

Emissions from Electric Utility Generating Units Constructed on or 

Before January 8, 2014; Model Trading Rule 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

Office of Air Quality Planning and Standards 

Research Triangle Park, NC 27711 
iv 

CONTACT INFORMATION 

This document has been prepared by staff from the Office of Air Quality Planning and 

Standards, the Office of Atmospheric Programs, and the Office of Policy of the U.S. 

Environmental Protection Agency. Questions related to this document should be addressed to 

Alexander Macpherson, U.S. Environmental Protection Agency, Office of Air Quality Planning 

and Standards, Research Triangle Park, North Carolina 27711 (email: 

macpherson.alex@epa.gov). 

ACKNOWLEDGEMENTS 

Thank you to the many staff who worked on this document from EPA Offices including 

the Office of Air Quality Planning and Standards, the Office of Atmospheric Programs, and the 

Office of Policy. Contributions to this report were also made by ICF International. 
v 

Table of Contents 

LIST OF TABLES ............................................................................................................................ vii

CHAPTER 1: SUMMARY OF POTENTIAL REGULATORY IMPACTS .............................................. 1-1

1.1 Introduction ................................................................................................................ 1-1

1.2 Legal, Scientific and Economic Basis for this Rulemaking ...................................... 1-2

1.2.1 Statutory Requirement .................................................................................... 1-2

1.2.2 Health and Welfare Impacts from Climate Change ........................................ 1-2

1.2.3 Market Failure ................................................................................................ 1-3

1.3 Background for the Proposed Federal plan and model trading rules ......................... 1-4

1.3.1 Definition of Affected Sources ....................................................................... 1-4

1.3.2 Trade in Compliance Instruments across States ............................................. 1-4

1.3.3 Model Trading Rule........................................................................................ 1-5

1.4 Summary of Regulatory Analysis .............................................................................. 1-5

1.4.1 Base Case and Years of Analysis ................................................................... 1-7

1.4.2 Federal Plan Approaches Examined in RIA ................................................... 1-8

1.5 Summary of Regulatory Analysis ............................................................................ 1-11

1.5.1 Emissions Reductions ................................................................................... 1-11

1.5.2 Costs ............................................................................................................. 1-14

1.5.3 Monetized Climate Benefits and Health Co-benefits ................................... 1-16

1.5.4 Net Benefits .................................................................................................. 1-27

1.5.5 Economic Impacts ........................................................................................ 1-30

1.5.6 Employment Impacts .................................................................................... 1-30 

1.5.7 Additional Analysis of Output-Based Allocation as a Means of Mitigating 

Leakage .................................................................................................................... 1-32 

1.5.8 Uncertainty Analysis .................................................................................... 1-33

1.6 References ................................................................................................................ 1-37

CHAPTER 2: STATUTORY AND EXECUTIVE ORDER REVIEWS ................................................... 2-1

2.1 Executive Order 12866: Regulatory Planning and Review and Executive Order 

13563: Improving Regulation and Regulatory Review .................................................... 2-1

2.2 Paperwork Reduction Act .......................................................................................... 2-4

2.3 Initial Regulatory Flexibility Analysis....................................................................... 2-6

2.3.1 Reasons why Action is Being Considered ...................................................... 2-6

2.3.2 Statement of Objectives and Legal Basis for Proposed Rules ........................ 2-7

2.3.3 Description and Estimate of Affected Small Entities ..................................... 2-8

2.3.4 Compliance Cost Impact Estimates .............................................................. 2-14

2.3.5 Projected Reporting, Recordkeeping and Other Compliance Requirements 2-22

2.3.6 Related Federal Rules ................................................................................... 2-23

2.3.7 Regulatory Flexibility Alternatives .............................................................. 2-23

2.4 Unfunded Mandates Reform Act (UMRA) ............................................................. 2-29

2.5 Executive Order 13132: Federalism ........................................................................ 2-29

2.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments ................................................................................................................... 2-30
vi 

2.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks .............................................................................................................. 2-32

2.8 Executive Order 13211: Actions That Significantly Affect Energy Supply, 

Distribution, or Use ......................................................................................................... 2-32

2.9 National Technology Transfer and Advancement Act (NTTAA) ........................... 2-32

2.10 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations ...................................................... 2-32
vii 

LIST OF TABLES

Table 1-1. Climate and Air Pollutant Emission Reductions for the Rate-Based Federal 

Plan Approach ................................................................................................................ 1-12

Table 1-2. Climate and Air Pollutant Emission Reductions for the Mass-Based Federal 

Plan Appproach .............................................................................................................. 1-13

Table 1-3. Projected CO2 Emission Reductions, Relative to 2005 .................................... 1-14

Table 1-4. Compliance Costs for the Federal Rate-Based and Mass-Based Plan 

Approaches .................................................................................................................... 1-15

Table 1-5. Quantified and Unquantified Benefits .............................................................. 1-17

Table 1-6. Combined Estimates of Climate Benefits and Health Co-Benefits for RateBased Approach (billions of 2011$) .............................................................................. 1-26

Table 1-7. Combined Estimates of Climate Benefits and Health Co-benefits for MassBased Approach (billions of 2011$) .............................................................................. 1-27

Table 1-8. Monetized Benefits, Compliance Costs, and Net Benefits Under the Ratebased Federal Plan Approach (billions of 2011$).......................................................... 1-28

Table 1-9. Monetized Benefits, Compliance Costs, and Net Benefits under the Massbased Federal Plan Approach (billions of 2011$).......................................................... 1-29

Table 1-10. Summary Table of Important Energy Market Impacts (Percent Change from 

Base Case) ...................................................................................................................... 1-30

Table 2-1. SBA Size Standards by NAICS Code .............................................................. 2-12

Table 2-2. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Rate-Based Federal Plan Approach in 2030 .................................................. 2-18

Table 2-3. Projected Impact on Small Entities in 2030 under Rate-Based Federal Plan 

Approach ........................................................................................................................ 2-18

Table 2-4. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Mass-Based Federal Plan Approach in 2030 ................................................. 2-19

Table 2-5. Projected Impact on Small Entities in 2030 under Mass-Based Federal Plan 

Approach ........................................................................................................................ 2-19

Table 2-6. Incremental Costs in 2030 under the Rate-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) ......... 2-20
viii 

Table 2-7. Incremental Costs in 2030 under the Mass-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) ......... 2-21
1-1 

CHAPTER 1: SUMMARY OF POTENTIAL REGULATORY IMPACTS

1.1 Introduction 

This Regulatory Impact Analysis (RIA) discusses potential benefits, costs, and economic 

impacts of for the “Proposed Federal Plan Requirements for Greenhouse Gas Emissions from 

Electric Utility Generating Units Constructed on or Before January 8, 2014; Model Trading 

Rules; Amendments to Framework Regulations” (herein also referred to as “proposed federal 

plan and model trading rules”1). In this action, the Environmental Protection Agency (EPA) is 

proposing a federal plan to implement the emission guidelines for existing fossil fuel-fired EGUs 

under the Clean Air Act (CAA). The emission guidelines were proposed in June 2014 and 

finalized on August 3, 2015 as the Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units (also referred to as the Clean Power Plan or Emission 

Guidelines). The EPA is taking comment on many of the elements of this proposal. 

This proposal presents two approaches to a federal plan (or model rule) for states and 

other jurisdictions that either chose to adopt a model rule or do not adopt and submit to the EPA 

in a timely manner an approvable state plan: a rate-based emission trading program and a massbased emission trading program. The federal plan is an important measure to ensure that 

congressionally mandated emission standards under the authority of the CAA are implemented. 

The agency is also proposing a necessary or appropriate finding for the affected EGUs in several 

areas of Indian country and is proposing the federal plan for these affected EGUs. 

The proposed federal plan is related to but separate from the final emission guidelines. 

The final emission guidelines establish the best system of emission reduction (BSER) for 

applicable fossil fuel-fired EGUs in the form of a carbon dioxide (CO2) emission performance 

rate for steam-fired EGUs and a CO2 emission performance rate for natural gas-fired combined 

cycle units, and provide guidance and criteria for the development of approvable state plans. The 

purpose of the proposed federal plan is to establish requirements directly applicable to a state’s 

affected EGUs that meet the emission performance levels in order to achieve reductions in 

 

1

 The proposed amendments to the framework regulations for section 111(d) are limited to enhancements in the 

procedure and timing of the EPA’s action on state plans. See Section VII of the preamble. They do not modify 

requirements or obligations in the CPP or other substantive rules, or directly regulate any third parties. Therefore, 

the EPA has not included these changes in its analysis in this RIA and proposes to certify that these changes will not 

have a significant impact on a significant number of small entities pursuant to the Regulatory Flexibility Act (RFA). 
1-2 

carbon dioxide (CO2) emissions in the case where a state or other jurisdiction does not submit an 

approvable plan. The stringency of the emission performance levels established in the final 

emission guidelines will be the same whether implemented through a state plan or a federal plan. 

1.2 Legal, Scientific and Economic Basis for this Rulemaking 

1.2.1 Statutory Requirement 

Section 111(d)(2) of the Clean Air Act (CAA), 42 U.S.C. 7411(d)(2) provides the EPA 

the same authority to prescribe a plan for a state in cases where the state fails to submit a 

satisfactory plan as the Agency would have under CAA section 110(c) in the case of failure to 

submit a National Ambient Air Quality Standard implementation plan. In addition, the EPA has 

authority under CAA section 111(d)(1) to prescribe regulations that establish procedures similar 

to CAA section 110 with respect to the submission of state plans, and the EPA also has general 

rulemaking authority as necessary to implement the CAA under section 301. A federal Plan 

under CAA section 111(d) applies, implements and enforces standards of performance for 

affected EGUs. Under the Clean Power Plan Emission Guidelines, state plans will be due on 

September 6, 2016. States are also allowed to seek a two year extension for a final plan 

submittal, upon submitting a satisfactory initial submittal by the same deadline. If a state fails to 

submit a final state plan or initial submittal, or if either a final state plan or an initial submittal 

does not meet the requirements of the final emission guidelines, the Agency will take the 

appropriate steps to finalize and implement a federal plan. 

States will remain free, and indeed are strongly encouraged, to submit an approvable state 

plan even after promulgation of the federal plan for their jurisdictions. Upon approval of the state 

plan by EPA, the federal plan will no longer apply to the affected EGUs covered by the approved 

state plan, starting at the initiation of the next compliance period with the limitations noted in the 

federal plan. 

1.2.2 Health and Welfare Impacts from Climate Change 

According to the National Research Council, “Emissions of CO2 from the burning of 

fossil fuels have ushered in a new epoch where human activities will largely determine the 

evolution of Earth’s climate. Because CO2 in the atmosphere is long lived, it can effectively lock 

Earth and future generations into a range of impacts, some of which could become very severe. 
1-3 

Therefore, emission reduction choices made today matter in determining impacts experienced 

not just over the next few decades, but in the coming centuries and millennia.”2 

In 2009, based on a large body of robust and compelling scientific evidence, the EPA 

Administrator issued the Endangerment Finding under CAA section 202(a)(1).3 In the 

Endangerment Finding, the Administrator found that the current, elevated concentrations of 

GHGs in the atmosphere—already at levels unprecedented in human history—may reasonably 

be anticipated to endanger public health and welfare of current and future generations in the 

United States. 

Since the administrative record concerning the Endangerment Finding closed following 

the EPA’s 2010 Reconsideration Denial, the climate has continued to change, with new records 

being set for a number of climate indicators such as global average surface temperatures, Arctic 

sea ice retreat, CO2 concentrations, and sea level rise. Additionally, a number of major scientific 

assessments have been released that improve understanding of the climate system and strengthen 

the case that GHGs endanger public health and welfare both for current and future generations. 

These assessments are from the Intergovernmental Panel on Climate Change (IPCC), the U.S. 

Global Change Research Program (USGCRP), and the National Research Council (NRC). These 

and other assessments are discussed in more detail in the Final Clean Power Plan Emission 

Guidelines preamble and in Chapter 4 of the Clean Power Plan Final Rule Regulatory Impact 

Analysis (RIA).4

1.2.3 Market Failure 

Many regulations are promulgated to correct market failures, which otherwise lead to a 

suboptimal allocation of resources within the free market. Air quality and pollution control 

regulations address “negative externalities” whereby the market does not internalize the full 

opportunity cost of production borne by society as public goods such as air quality are unpriced. 

 

2 National Research Council, Climate Stabilization Targets, p.3. 

3

 “Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air 

Act,” 74 Fed. Reg. 66,496 (Dec. 15, 2009) (“Endangerment Finding”). 

4

 U.S. Environmental Protection Agency (U.S. EPA). 2015a. Regulatory Impact Analysis for the Clean Power Plan 

Final Rule. EPA-452/R-15-003. Office of Air Quality Planning and Standards, Health and Environmental Impacts 

Division, Research Triangle Park, NC. 
1-4 

GHG emissions impose costs on society, such as negative health and welfare impacts, 

that are not reflected in the market price of the goods produced through the polluting process. 

For this regulatory action the good produced is electricity. If a fossil fuel-fired electricity 

producer pollutes the atmosphere when it generates electricity, this cost will be borne not by the 

polluting firm but by society as a whole, thus imposing a negative externality. The equilibrium 

market price of electricity may fail to incorporate the full opportunity cost to society of 

generating electricity. All else equal, given this externality, the composition of EGUs used to 

generate electricity in a free market will not be socially optimal, and the quantity of electricity 

generated may not be at the socially optimal level. Fossil fuel-fired EGUs may produce more 

electricity than would occur if they had to account for the cost associated with this negative 

externality. Consequently, absent a regulation on emissions, the composition of the fleet of 

EGUs used to generate electricity may not be socially optimal, and the marginal social cost of 

the last unit of electricity produced may exceed its marginal social benefit. In the instances where 

the agency finalizes and implements a federal plan for a state’s affected EGUs, this proposed 

regulation will work towards addressing this market failure by causing affected EGUs to begin to 

internalize the negative externality associated with CO2 emissions. 

1.3 Background for the Proposed Federal plan and model trading rules 

1.3.1 Definition of Affected Sources 

Existing fossil fuel-fired electric generating units subject to the final Clean Power Plan 

Emission Guidelines that are located in a state that does not have an EPA-approved state plan are 

potentially subject to this proposed action. Existing fossil fuel-fired EGUs are those that were in 

operation or had commenced construction on or before January 8, 2014.5

1.3.2 Trade in Compliance Instruments across States 

The EPA intends to set up and administer a program to track trading programs – both 

rate-based and mass-based – that will be available for all states that choose it. The EPA proposes 

that affected EGUs in any state covered by a federal plan could trade compliance instruments 

 

5

 An affected EGU is any fossil fuel-fired EGU that was in operation or had commenced construction as of January 

8, 2014, and is therefore an ‘‘existing source’’ for purposes of CAA section 111, and that in all other respects 

would meet the applicability criteria for coverage under the proposed GHG standards for new fossil fuel-fired 

EGUs (79 FR 1430; January 8, 2014). 
1-5 

with affected EGUs in any other state covered by a federal plan or a state plan meeting the 

conditions for linkage to the federal plan. In the proposed mass-based federal-plan trading 

program, this would mean that affected EGUs in a state covered by the federal plan or a state 

meeting the conditions for linkage to the federal plan could use, as a compliance instrument, an 

allowance distributed in any other state covered by the federal plan or a state meeting the 

conditions for linkage to the federal plan. Similarly, in the proposed rate-based federal-plan 

trading program approach, this would mean that affected EGUs in a state covered by the federal 

plan or a state meeting the conditions for linkage to the federal plan could use, as a compliance 

instrument, an ERC issued in any other state covered by the federal plan or a state meeting the 

conditions for linkage to the federal plan. EPA is proposing that an affected EGU in a state 

covered by the mass-based trading federal plan must use allowances for compliance (not ERCs). 

Similarly, an affected EGU in a state covered by the rate-based trading federal plan must use 

ERCS for compliance (not allowances). 

1.3.3 Model Trading Rule 

A state program that adheres to the model trading rule provisions specified in this 

rulemaking would be presumptively approvable. States may submit means of meeting the 

emission guidelines requirements that differ from the model trading rule provisions, so long as 

the state demonstrates to the EPA’s satisfaction in the state plan submittal that such alternative 

means of addressing requirements are at least as stringent as the presumptively approvable 

approach described here. Additionally, there are stand-alone portions of the model trading rules, 

such as the evaluation, measurement, and verification (EM&V) procedures that would be 

approvable even if a state adopted an approach that differs from the federal plan. The model 

trading rules serve as a mechanism to facilitate larger trading markets since consistency with the 

federal plan allows trading across both the state and federal programs. The EPA expects a larger 

trading region is likely to result in lower overall costs. 

1.4 Summary of Regulatory Analysis 

In accordance with Executive Order 12866, Executive Order 13563, OMB Circular A-4, 

and the EPA’s “Guidelines for Preparing Economic Analyses,” the EPA prepared this RIA for 

this “significant regulatory action.” This action is an economically significant regulatory action 

because it may have an annual effect on the economy of $100 million or more or adversely affect 
1-6 

in a material way the economy, a sector of the economy, productivity, competition, jobs, the 

environment, public health or safety, or state, local, or tribal governments or communities.6 

This action proposes a federal plan under section 111(d) of the CAA for the control of 

CO2, a greenhouse gas pollutant, from certain large emitting fossil-fuel fired power plants, in the 

event that some states do not adopt their own plans. Specifically, the EPA is proposing 

approaches in the form of mass- and rate-based trading options that provide flexibility in 

implementing emission standards for a state’s affected EGUs. Both proposed approaches to the 

federal plan would require affected EGUs to meet emission standards set using the CO2 emission 

performance rates in the emission guidelines. The federal plan will achieve the same levels of 

emissions performance as required of state plans under the emission guidelines. 

However, at the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan or adopt a model rule. Because of this lack of information, 

for this RIA, the EPA has chosen to examine two federal plan approach scenarios where all 

states of the contiguous U.S. will be regulated under a federal plan or a model rule. The first 

federal plan approach we examine in this RIA assumes all states in the contiguous U.S. are 

regulated under a rate-based federal plan or model rule. The second federal plan approach we 

examine assumes all contiguous states are regulated under a mass-based federal plan or model 

rule. These two approaches are a re-presentation of the modeling done for the Clean Power Plan 

Emission Guidelines RIA. 

This approach is consistent with the analysis presented in the RIA for the final Clean 

Power Plan Emission Guidelines (U.S. EPA 2015). As a result, this RIA for the proposed federal 

plan and model trading rules re-presents the key results from the final Clean Power Plan 

Emission Guidelines RIA. These key results encompass the potential costs, emission reductions, 

and benefits of the proposed federal plan and model trading rules, as well as the potential 

impacts on electricity markets, employment, and markets outside the electricity sector. 

The RIA also presents a discussion of limitations of the analysis and solicitations for 

public comments that will contribute to the analysis supporting the promulgation of final federal 

 

6

 The analysis in this proposal RIA constitutes the economic assessment required by CAA section 317. In the EPA’s 

judgment, the assessment is as extensive as practicable taking into account the EPA’s time, resources, and other 

duties and authorities. 
1-7 

plans (as needed) and model trading rules. In evaluating the impacts of the proposed federal plan 

and model trading rules, we address a number of uncertainties. 

It is important to note that the potential regulatory impacts presented in the Clean Power 

Plan Final Rule RIA and the RIA for this proposed rule are not additive. Both RIAs present 

estimates of the benefits and costs of achieving the emission performance rates of the Clean 

Power Plan emissions guidelines. In the case of the Clean Power Plan Final Rule RIA, the 

illustrative analysis assumes the performance rates are met under state plans. In the case of this 

RIA for the proposed federal plan and model trading rules, the same performance rates are 

accomplished but are assumed to be accomplished under the federal plan or model trading rules. 

This RIA also presents in Chapter 2 the statutory and executive order analyses that 

accompany the proposal for this action, including the Initial Flexibility Regulatory Analysis 

(IRFA). The IRFA describes the economic impact of the proposed rule on small entities and any 

significant alternatives to the proposed rule that would accomplish the objectives of the rule 

while minimizing significant economic impacts on small entities. This IRFA has been prepared 

following EPA’s guidance document for preparing initial and final regulatory flexibility 

analyses.7

1.4.1 Base Case and Years of Analysis 

The base case for this analysis, which uses the Integrated Planning Model (IPM), 

includes state rules that have been finalized and/or approved by a state’s legislature or 

environmental agencies, as well as final federal rules. The IPM Base Case v.5.15 includes the 

Cross-State Air Pollution Rule (CSAPR), the Mercury and Air Toxics Rule (MATS), the 

proposed Carbon Pollution Standards for New Power Plants, the Cooling Water Intakes (316(b)) 

Rule, the Combustion Residuals from Electric Utilities (CCR), and other state and Federal 

regulations to the extent that they contain measures, permits, or other air-related limitations or 

 

7 See “EPA’s Action Development Process: Final Guidance for EPA Rulewriters: Regulatory Flexibility Act as 

amended by the Small Business Regulatory Enforcement Fairness Act.” OPEI Regulatory Development Series. 

November 2006. Available at: <http://www.epa.gov/sbrefa/documents/Guidance-RegFlexAct.pdf>. Accessed July 

21, 2015. 
1-8 

requirements. Additional legally binding and enforceable commitments for GHG reductions 

considered in the base case are discussed in the documentation for IPM.8 

To present a complete picture of the potential costs and benefits of the proposed federal 

plan and model trading rules, this RIA presents results for the analysis years 2020, 2025, and 

2030. While 2020 is before the first year of the interim compliance period (2022), the EPA 

expects states and affected EGUs to perform voluntary activities that will facilitate compliance 

with interim and final goals. These pre-compliance period activities might include investments in 

renewable energy or demand-side energy efficiency projects, for example, that produce 

emissions reductions in the compliance period. Activities might also include preparatory 

investments in transmission capacity or monitoring, reporting, and recordkeeping systems. As a 

result, there are likely to be benefits and costs in 2020, so these are reported in this RIA. 

Meanwhile, cost and benefits are estimated in this RIA for 2025, which is intended to represent a 

central period of the interim compliance time-frame as states are on glide paths toward fully 

meeting the final CO2 emission performance goals. Lastly, the RIA presents costs and benefits 

for 2030, when the emission performance goals are fully achieved. 

1.4.2 Federal Plan Approaches Examined in RIA 

In the Final Clean Power Plan Emission Guidelines, the EPA translated the source 

category-specific CO2 emission performance rates into equivalent state-level rate-based and 

mass-based CO2 goals in order to maximize the range of choices that states will have in 

developing their plans.9

 As noted above, like the RIA for the Final Clean Power Plan Emission 

Guidelines, this RIA presents two scenarios designed to achieve these goals, which we term the 

rate-based federal plan approach and the mass-based federal plan approach. 

It is very important to note that the differences between the analytical results for the ratebased and mass-based federal plan approaches presented in this RIA may not be indicative of 

likely differences between the approaches. In other words, if one approach performs differently 

 

8

 Detailed documentation for IPM v.5.15 is available at: http://www.epa.gov/powersectormodeling. 

9

 See the preamble of the final Clean Power Plan Emissions Guidelines for these state-level rate-based and massbased CO2 goals. 
1-9 

than the other on a given metric during a given time period, this does not imply this will apply in 

all instances in all time periods in all places. 

In the rate-based approach modeled in the RIA for the final Clean Power Plan Emission 

Guidelines, avoided generation from demand-side energy efficiency is counted towards meeting 

the emission performance rates at affected EGUs. However, this federal plan and model trading 

rule proposal takes comment on whether EPA should allow demand-side energy efficiency to 

directly count toward the compliance rate of affected EGUs in a rate-based compliance approach. 

Because energy efficiency is not proposed to be eligible to generate ERCs that could be used to 

comply in the proposed rate-based federal plan, this RIA might be forecasting a different a 

generation mix and emissions levels than might occur from the proposed federal plan.10

Compliance strategies under either approach to the federal plan (mass or rate) may be anticipated 

to rely on different abatement measures than those modeled for this RIA. The climate benefits 

and health co-benefits arising from these alternative strategies may be different those presented 

here. We will update this analysis as necessary to support the final rule. 

Even without explicit incentives for energy efficiency under a rate-based federal plan, we 

believe that the increased focus that the Clean Power Plan Emission Guidelines will bring to 

considerations of CO2 emissions from EGUs will encourage states to consider more aggressive 

demand-side energy policies. Furthermore, the EPA anticipates that many states will submit 

fully-approvable plans, and that demand side energy efficiency is likely to be either an explicit 

component of, or a complimentary policy to, many of those plans. The resulting lower electricity 

demand in states not subject to a federal plan surrounding a state that is subject to a federal plan 

will likely have an impact on fossil generation and thus the cost of reducing CO2 emissions. The 

EPA takes comment on the appropriate way to factor such costs into the analysis of the final 

federal plan and model trading rules. 

In the rate-based approach modeled in the RIA for the final Clean Power Plan Emission 

Guidelines, affected EGUs may not procure emission reductions from (e.g., by averaging their 

emissions with) affected EGUs located in other states (which may also have different emission 

 

10 However, as with states subject to the mass-based approach, energy efficiency activities may be adopted by states 

subject to the rate-based approach to lower demand, which in turn may reduce the compliance cost of achieving 

the performance rates. 
1-10 

standards) in order to demonstrate compliance. As described in Section 1.3.2, in the proposed 

rate-based federal plan affected EGUs may procure ERCs from affected EGUs in other ratebased states subject to the federal plan. Furthermore, the rate-based illustrative plan in the Final 

Clean Power Plan Emission Guidelines RIA assumes that the plan applies a state’s blended ratebased goal as a requirement for affected EGUs in that state to achieve.11 Alternatively, the 

proposed federal plan specifically establishes an emissions rate performance standard that is 

applied to affected steam-fired EGUs and an emission rate performance standard that is applied 

to affected natural gas-fired combined cycle EGUs. Applying the subcategory-specific rate goal 

may alter the incentives among affected EGUs and could lead to a different generation mix and 

emission levels. The EPA will further explore the impacts of subcategory-specific rate goals in 

the analysis supporting the final rule. 

The mass-based plan approach requires affected sources in each state to limit their 

aggregate emissions not to exceed the mass goal for that state. The mass-based scenario 

presented in this chapter includes a 5 percent set-aside of allowances that would be allocated to 

recognize deployment of new renewable capacity, which is represented by lowering the capital 

cost of new renewable capacity in a compliance period by the estimated value of the allowances 

in the set-aside in that period. 

The EPA is also proposing a set-aside approach referred to as output-based allocation 

(OBA), which provides targeted allocations of a limited portion of allowances to existing NGCC 

units as a means of mitigating leakage. The EPA believes that this proposed set-aside would 

address incentives for generation to shift away from EGUs covered under mass-based plans to 

new unaffected EGUs. OBA provides an incentive for eligible EGUs in mass-based states to 

increase their generation in order to increase their allocation of allowances. This approach helps 

align the generation incentives for eligible EGUs in mass-based states with new EGUs that are 

not subject to the mass-based limits, mitigating the potential for emissions leakage. 

 

11 In the rate-based scenario in the RIA for the final Clean Power Plan Emission Guidelines, the generation-weighted 

average emission rate from affected EGUs, in which generation is inclusive of their procurement of zero-emitting 

generation or demand-side EE savings, in a state must be less than or equal to the state goal. One way for a state 

to achieve this outcome would be to assign in its plan emission rate performance standards to affected EGUs that 

equal the state emission rate goal, the incentives of which would be consistent with the analysis and results 

reported in the RIA for the final Clean Power Plan Emission Guidelines. 
1-11 

While the mass-based scenario analyzed for this proposed rule included a representation 

of the set-aside for new renewable generation, it did not quantify the effects of the OBA as 

proposed in this rulemaking. Therefore, in Section 1.5.6, the EPA conducted additional analysis 

to approximate the potential emissions reductions if the OBA set-aside were included in that 

mass-based scenario. The EPA is inviting comment on its approach to approximating the impact 

of OBA. If appropriate, the EPA will further explore OBA as a means to mitigate leakage in the 

analysis supporting the final federal plan and model trading rules. 

The EPA notes that, in this analysis, EGUs within each state comply with the applicable 

state goals without exchanging a compliance instrument with EGUs in other states. However, 

under the proposed federal plan and model trading rules if all states had a federal plan and the 

same type of goal (as they do in this analysis), then trading among EGUs in different states 

would be allowed and would lead to differences in the generation mix and emissions. The EPA is 

inviting comment on this approach to the modeling that will contribute to analysis supporting the 

final rule. 

1.5 Summary of Regulatory Analysis 

1.5.1 Emissions Reductions 

Table 1-1 shows the emission reductions associated with the modeled rate-based federal 

plan approach. 
1-12 

Table 1-1. Climate and Air Pollutant Emission Reductions for the Rate-Based Federal Plan 

Approach1

CO2

(million short tons) 

SO2

(thousand short tons) 

Annual NOX 

(thousand short tons) 

2020 Rate-Based Approach 

Base Case 2,155 1,311 1,333 

Federal Plan Approach 2,085 1,297 1,282 

Emissions Change -69 -14 -50 

2025 Rate-Based Approach 

Base Case 2,165 1,275 1,302 

Federal Plan Approach 1,933 1,097 1,138 

Emissions Change -232 -178 -165 

2030 Rate-Based Approach 

Base Case 2,227 1,314 1,293 

Federal Plan Approach 1,812 996 1,011 

Emission Change -415 -318 -282 

Source: Integrated Planning Model, 2015. Emissions change may not sum due to rounding. 

1 CO2 emission reductions are used to estimate the climate benefits of the proposed rule. SO2, and NOX reductions 

are relevant for estimating air quality health co-benefits of the proposed rule. The proposed rule is also expected to 

achieve reductions in directly emitted PM2.5, which we were not able to estimate for this RIA. 

In 2020, the EPA estimates that CO2 emissions will be reduced by 69 million short tons 

under the rate-based approach compared to base case levels. In 2025, the EPA estimates that CO2

emissions will be reduced by 232 million short tons under the rate-based approach compared to 

base case levels. CO2 emission reductions increase to 415 million short tons annually in 2030 

when compared to the base case emissions. Table 1-1 also shows emission reductions for criteria 

air pollutants. 
1-13 

Table 1-2 shows the emission reductions associated with the modeled mass-based federal 

plan approach. 

Table 1-2. Climate and Air Pollutant Emission Reductions for the Mass-Based Federal Plan 

Appproach1

CO2

(million short tons) 

SO2

(thousand short tons) 

Annual NOX 

(thousand short tons) 

2020 Mass-Based Approach 

Base Case 2,155 1,311 1,333 

Federal Plan Approach 2,073 1,257 1,272 

Emissions Change -81 -54 -60 

2025 Mass-Based Approach 

Base Case 2,165 1,275 1,302 

Federal Plan Approach 1,901 1,090 1,100 

Emissions Change -265 -185 -203 

2030 Mass-Based Approach 

Base Case 2,227 1,314 1,293 

Federal Plan Approach 1,814 1,034 1,015 

Emission Change -413 -280 -278 

Source: Integrated Planning Model, 2015. Emissions change may not sum due to rounding. 

1 CO2 emission reductions are used to estimate the climate benefits of the proposed rule. SO2, and NOX reductions 

are relevant for estimating air quality health co-benefits of the proposed rule. The proposed rule is also expected to 

achieve reductions in directly emitted PM2.5, which we were not able to estimate for this RIA. 

In 2020, the EPA estimates that CO2 emissions will be reduced by 81 million short tons under 

the mass-based approach compared to base case levels. In 2025, the EPA estimates that CO2

emissions will be reduced by 265 million short tons under the mass-based approach compared to 

base case levels. CO2 emission reductions increase to 413 million short tons annually in 2030 

when compared to the base case emissions. Table 1-2 also shows emission reductions for criteria 

air pollutants. 
1-14 

Table 1-3 presents CO2 emission reductions relative to 2005 for the two federal plan 

approaches. 

Table 1-3. Projected CO2 Emission Reductions, Relative to 2005 

 

CO2 Emissions 

(million short tons) 

CO2 Emissions: 

Change from 2005 

(million short tons) 

CO2 Emissions Reductions: 

Percent Change from 2005 

 2005 2020 2025 2030 2020 2025 2030 

Base Case 2,683 -528 -518 -456 -20% -19% -17% 

Rate-based - -598 -750 -871 -22% -28% -32% 

Mass-based - -610 -782 -869 -23% -29% -32% 

Source: Integrated Planning Model, 2015. 

In 2020, the EPA estimates that CO2 emissions will be reduced by 598 million short tons (22 

percent) under the rate-based approach compared to 2005 levels. In 2025, the EPA estimates that 

CO2 emissions will be reduced by 750 million short tons (28 percent) under the rate-based 

approach compared to 2005 levels. Under the rate-based approach, CO2 emission reductions 

increase to 871 million short tons (32 percent) in 2030 when compared to 2005 levels. 

Under the mass-based approach in 2020, the EPA estimates that CO2 emissions will be 

reduced by 610 million short tons (23 percent) under the rate-based approach compared to 2005 

levels. In 2025, the EPA estimates that CO2 emissions will be reduced by 782 million short tons 

(29 percent) under the mass-based approach compared to 2005 levels. Under the mass-based 

approach, CO2 emission reductions increase to 869 million short tons (32 percent) in 2030 when 

compared to 2005 levels. 

1.5.2 Costs 

 The compliance cost estimates in this analysis are the change in electric power 

generation costs between the base case and federal plan approach policy cases, including the cost 

of demand-side energy efficiency measures and costs associated with monitoring, reporting, and 

recordkeeping requirements (MR&R).12 In the rate-based approach, energy efficiency activities 

are modeled as being used by EGUs as a low-cost method of demonstrating compliance with 

their rate-based emissions standards. In the mass-based approach, energy efficiency activities are 

assumed to be adopted by states to lower demand, which in turn reduces the cost of achieving the 

 

12 See Chapter 3 of the Clean Power Plan Final Rule RIA for a detailed discussion of the compliance cost estimates. 
1-15 

mass limitations. The level of energy efficiency measures is determined outside of IPM and is 

assumed to be the same in the two federal plan approaches.13 The compliance assumptions, and 

therefore the projected “compliance costs” set forth in this analysis, are illustrative in nature. 

The annual compliance cost is the projected additional cost of complying with the rule in 

the year analyzed and reflects the net difference in the sum of the annualized cost of capital 

investment in new generating sources and heat rate improvements at coal steam facilities, the 

change in the ongoing costs of operating pollution controls, shifts between or amongst various 

fuels, demand-side energy efficiency measures, and other actions associated with compliance. 

The costs for both federal plan approaches are reflected in Table 1-4 below. All dollar estimates 

are in 2011 dollars. 

The EPA estimates the annual incremental compliance cost for the rate-based approach 

for the proposed federal plan and model trading rules to be $2.5 billion in 2020, $1.0 billion in 

2025 and $8.4 billion in 2030. The EPA estimates the annual incremental compliance cost for the 

mass-based approach for the federal plan and model trading rules to be $1.4 billion in 2020, $3.0 

billion in 2025 and $5.1 billion in 2030. 

Table 1-4. Compliance Costs for the Federal Rate-Based and Mass-Based Plan Approaches 

Incremental Cost from Base Case (billions of 2011$) 

Rate-based Approach Mass-based Approach 

2020 $2.5 $1.4 

2025 $1.0 $3.0 

2030 $8.4 $5.1 

Source: Integrated Planning Model, 2015, with post-processing to account for exogenous demand-side management 

energy efficiency costs and monitoring, reporting, and recordkeeping costs. See Chapter 3 of the Clean Power Plan 

Final Rule RIA for a more complete explanation. 

The costs reported in Table 1-4 represent the estimated incremental electric utility 

generating costs changes from the base case plus the estimates of demand-side energy efficiency 

program costs (which are paid by electric utilities), demand-side energy efficiency participant 

costs (which are paid by electricity consumers), and MR&R costs. For example, in 2030, under 

the rate-based approach, the incremental electric utility generating costs decline by about $18.0 

 

13 For more detailed information on demand-side energy efficiency, see U.S. EPA. 2015b. Technical Support 

Document (TSD) the Final Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility 

Generating Units. Demand-Side Energy Efficiency. 
1-16 

billion from the base case. MR&R requirements in 2030 are estimated at $16.0 million, and 

demand-side energy efficiency costs in 2030 are estimated to be $26.3 billion, split equally 

between program and participants using a 3 percent discount rate (see Chapter 3 of this RIA for 

more details on these estimates). These cost estimates sum to the $8.4 billion shown in Table 1-4 

and represent the total costs of the rate-based federal plan approach in 2030. The same approach 

applies in each year of analysis for the rate-based and the mass-based federal plan approaches. 

The compliance costs reported in Table 1-4 are not social costs. These costs represent the 

estimated expenditures incurred by EGUs, the costs to participants in demand-side energy 

efficiency programs, and states to comply with the BSER goals for the Final Clean Power Plan 

Emission Guidelines. These compliance cost estimates are compared to estimates of social 

benefits to derive net benefits of the proposed federal plan and model trading rules, which are 

presented later in this Chapter. 

1.5.3 Monetized Climate Benefits and Health Co-benefits 

The climate benefits estimates have been calculated using the estimated values of 

marginal climate impacts presented in the Technical Support Document: Technical Update of the 

Social Cost of Carbon for Regulatory Impact Analysis under Executive Order 12866 (May 2013, 

Revised July 2015), henceforth denoted as the current SC-CO2 TSD.14 Additionally, this analysis 

takes into account the social benefits of changes in emissions of non-CO2 pollutants from the 

electricity sector. The range of combined benefits reflects different concentration-response 

functions for the air quality health co-benefits, but it does not capture the full range of 

uncertainty inherent in the health co-benefits estimates. Furthermore, we were unable to quantify 

or monetize all of the climate benefits and health and environmental co-benefits associated with 

the proposed federal plan and model trading rules, including reductions in directly emitted PM2.5, 

reduced exposure to SO2, NOX, and hazardous air pollutants (e.g., mercury), as well as 

ecosystem effects and visibility improvement. The omission of these endpoints from the 

 

14 Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon, with participation by 

Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture, Department of 

Commerce, Department of Energy, Department of Transportation, Domestic Policy Council, Environmental 

Protection Agency, National Economic Council, Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (May 2013, Revised July 2015). Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf> Accessed 7/11/2015. 
1-17 

monetized results should not imply that the impacts are small or unimportant. Table 1-5 provides 

the list of the quantified and unquantified health and environmental benefits in this analysis. 

Table 1-5. Quantified and Unquantified Benefits 

Benefits Category Specific Effect 

Effect Has 

Been 

Quantified

Effect Has 

Been 

Monetized

More Information 

Improved 

Environment 

Reduced climate 

effects 

Global climate impacts from CO2 —1  SC-CO2 TSD 

Climate impacts from ozone and black carbon (directly 

emitted PM) — — 

Ozone ISA, PM 

ISA2

Other climate impacts (e.g., other GHGs such as methane, 

aerosols, other impacts) — — IPCC2

Improved Human Health (co-benefits) 

Reduced incidence of 

premature mortality 

from exposure to 

PM2.5

Adult premature mortality based on cohort study estimates

and expert elicitation estimates (age >25 or age >30)   PM ISA 

Infant mortality (age <1)   PM ISA 

Reduced incidence of 

morbidity from 

exposure to PM2.5

Non-fatal heart attacks (age > 18)   PM ISA 

Hospital admissions—respiratory (all ages)   PM ISA 

Hospital admissions—cardiovascular (age >20)   PM ISA 

Emergency room visits for asthma (all ages)   PM ISA 

Acute bronchitis (age 8-12)   PM ISA 

Lower respiratory symptoms (age 7-14)   PM ISA 

Upper respiratory symptoms (asthmatics age 9-11)   PM ISA 

Asthma exacerbation (asthmatics age 6-18)   PM ISA 

Lost work days (age 18-65)   PM ISA 

Minor restricted-activity days (age 18-65)   PM ISA 

Chronic Bronchitis (age >26) — — PM ISA2

Emergency room visits for cardiovascular effects (all ages) — — PM ISA2

Strokes and cerebrovascular disease (age 50-79) — — PM ISA2

Other cardiovascular effects (e.g., other ages) — — PM ISA3

Other respiratory effects (e.g., pulmonary function, nonasthma ER visits, non-bronchitis chronic diseases, other 

ages and populations) 

— — PM ISA3

Reproductive and developmental effects (e.g., low birth 

weight, pre-term births, etc) — — PM ISA3,4

Cancer, mutagenicity, and genotoxicity effects — — PM ISA3,4

Reduced incidence of 

mortality from 

exposure to ozone 

Premature mortality based on short-term study estimates (all 

ages)   Ozone ISA 

Premature mortality based on long-term study estimates 

(age 30–99) — — Ozone ISA2

Reduced incidence of 

morbidity from 

exposure to ozone 

Hospital admissions—respiratory causes (age > 65)   Ozone ISA 

Hospital admissions—respiratory causes (age <2)   Ozone ISA 

Emergency department visits for asthma (all ages)   Ozone ISA 

Minor restricted-activity days (age 18–65)   Ozone ISA 

School absence days (age 5–17)   Ozone ISA 

Decreased outdoor worker productivity (age 18–65) — — Ozone ISA2

Other respiratory effects (e.g., premature aging of lungs) — — Ozone ISA3

Cardiovascular and nervous system effects — — Ozone ISA3

Reproductive and developmental effects — — Ozone ISA3,4

 

 

 
1-18 

Table 1-5. Continued 

Reduced incidence of 

morbidity from 

exposure to NO2

Asthma hospital admissions (all ages) — — NO2 ISA2

Chronic lung disease hospital admissions (age > 65) — — NO2 ISA2

Respiratory emergency department visits (all ages) — — NO2 ISA2

Asthma exacerbation (asthmatics age 4–18) — — NO2 ISA2

Acute respiratory symptoms (age 7–14) — — NO2 ISA2

Premature mortality — — NO2 ISA2,3,4

Other respiratory effects (e.g., airway hyperresponsiveness 

and inflammation, lung function, other ages and 

populations) 

— — NO2 ISA3,4

Reduced incidence of 

morbidity from 

exposure to SO2

Respiratory hospital admissions (age > 65) — — SO2 ISA2

Asthma emergency department visits (all ages) — — SO2 ISA2

Asthma exacerbation (asthmatics age 4–12) — — SO2 ISA2

Acute respiratory symptoms (age 7–14) — — SO2 ISA2

Premature mortality — — SO2 ISA2,3,4

Other respiratory effects (e.g., airway hyperresponsiveness 

and inflammation, lung function, other ages and 

populations) 

— — SO2 ISA2,3

Reduced incidence of 

morbidity from 

exposure to 

methylmercury 

Neurologic effects—IQ loss — — IRIS; NRC, 20002

Other neurologic effects (e.g., developmental delays, 

memory, behavior) — — IRIS; NRC, 20003

Cardiovascular effects — — IRIS; NRC, 20003,4

Genotoxic, immunologic, and other toxic effects — — IRIS; NRC, 20003,4

Improved Environment (co-benefits) 

Reduced visibility 

impairment 

Visibility in Class 1 areas — — PM ISA2

Visibility in residential areas — — PM ISA2

Reduced effects on 

materials 

Household soiling — — PM ISA2,3

Materials damage (e.g., corrosion, increased wear) — — PM ISA3

Reduced PM 

deposition (metals and 

organics) 

Effects on individual organisms and ecosystems — — PM ISA3

Reduced vegetation 

and ecosystem effects 

from exposure to 

ozone 

Visible foliar injury on vegetation — — Ozone ISA2

Reduced vegetation growth and reproduction — — Ozone ISA2

Yield and quality of commercial forest products and crops — — Ozone ISA2

Damage to urban ornamental plants — — Ozone ISA3

Carbon sequestration in terrestrial ecosystems — — Ozone ISA2

Recreational demand associated with forest aesthetics — — Ozone ISA3

Other non-use effects Ozone ISA3

Ecosystem functions (e.g., water cycling, biogeochemical 

cycles, net primary productivity, leaf-gas exchange, 

community composition) 

— — Ozone ISA3

Reduced effects from 

acid deposition 

Recreational fishing — — NOx SOx ISA2

Tree mortality and decline — — NOx SOx ISA3

Commercial fishing and forestry effects — — NOx SOx ISA3

Recreational demand in terrestrial and aquatic ecosystems — — NOx SOx ISA3

Other non-use effects NOx SOx ISA3

Ecosystem functions (e.g., biogeochemical cycles) — — NOx SOx ISA3

 

 

 

 
1-19 

Table 1-5. Continued 

Reduced effects from 

nutrient enrichment 

Species composition and biodiversity in terrestrial and 

estuarine ecosystems — — NOx SOx ISA3

Coastal eutrophication — — NOx SOx ISA3

Recreational demand in terrestrial and estuarine ecosystems — — NOx SOx ISA3

Other non-use effects NOx SOx ISA3

Ecosystem functions (e.g., biogeochemical cycles, fire 

regulation) — — NOx SOx ISA3

Reduced vegetation 

effects from exposure 

to SO2 and NOx

Injury to vegetation from SO2 exposure — — NOx SOx ISA3

Injury to vegetation from NOx exposure — — NOx SOx ISA3

Reduced ecosystem 

effects from exposure 

to methylmercury 

Effects on fish, birds, and mammals (e.g., reproductive 

effects) — — 

Mercury Study 

RTC3

Commercial, subsistence and recreational fishing — — 

Mercury Study 

RTC2

1

 The global climate and related impacts of CO2 emissions changes, such as sea level rise, are estimated within each 

integrated assessment model as part of the calculation of the SC-CO2. The resulting monetized damages, which 

are relevant for conducting the benefit-cost analysis, are used in this RIA to estimate the welfare effects of 

quantified changes in CO2 emissions. 

2

 We assess these co-benefits qualitatively, as reported in the Chapter 4 of the Clean Power Plan Final Rule RIA, 

due to data and resource limitations for this analysis. 

3

 We assess these co-benefits qualitatively, as reported in the Chapter 4 of the Clean Power Plan Final Rule RIA, 

because we do not have sufficient confidence in available data or methods. 

4

 We assess these co-benefits qualitatively, as reported in the Chapter 4 of the Clean Power Plan Final Rule RIA, 

because current evidence is only suggestive of causality or there are other significant concerns over the strength of 

the association. 

1.5.3.1 Estimating Global Climate Benefits 

We estimate the global social benefits of CO2 emission reductions expected from this 

rulemaking using the SC-CO2 estimates presented in the current SC-CO2 TSD.15 We refer to 

these estimates, which were developed by the U.S. government, as “SC-CO2 estimates” for the 

remainder of this document. The SC-CO2 is a metric that estimates the monetary value of 

impacts associated with marginal changes in CO2 emissions in a given year. It includes a wide 

range of anticipated climate impacts, such as net changes in agricultural productivity and human 

health, property damage from increased flood risk, and changes in energy system costs, such as 

reduced costs for heating and increased costs for air conditioning. It is typically used to assess 

 

15 Also see Chapter 4 of the Clean Power Plan Final Rule RIA for more details on this assessment of climate 

benefits. 
1-20 

the avoided damages as a result of regulatory actions (i.e., benefits of rulemakings that lead to an 

incremental reduction in cumulative global CO2 emissions). 

The SC-CO2 estimates used in this analysis have been developed over many years, using 

the best science available, and with input from the public. The EPA and other federal agencies 

have considered the extensive public comments on ways to improve SC-CO2 estimation received 

via the notice and comment period that was part of numerous rulemakings. In addition, OMB’s 

Office of Information and Regulatory Affairs recently issued a response to the public comments 

it sought through a separate comment period on the approach used to develop the SC-CO2

estimates.16

An interagency working group (IWG) that included the EPA and other executive branch 

entities used three integrated assessment models (IAMs) to develop SC-CO2 estimates and 

recommended four global values for use in regulatory analyses. The SC-CO2 estimates represent 

global measures because of the distinctive nature of the climate change problem. Emissions of 

greenhouse gases contribute to damages around the world, even when they are released in the 

United States, and the world’s economies are now highly interconnected. Therefore, the SC-CO2 

estimates incorporate the worldwide damages caused by carbon dioxide emissions in order to 

reflect the global nature of the problem, and we expect other governments to consider the global 

consequences of their greenhouse gas emissions when setting their own domestic policies. See 

Chapter 4 of the final Clean Power Plan Emission Guidelines RIA for more discussion. 

The IWG first released the estimates in February 2010 and updated them in 2013 using 

new versions of each IAM. The SC-CO2 values was estimated using three integrated assessment 

models (DICE, FUND, and PAGE)17, which the IWG harmonized across three key inputs: the 

probability distribution for equilibrium climate sensitivity; five scenarios for economic, 

population, and emissions growth; and three constant discount rates. The 2010 SC-CO2

Technical Support Document (2010 SC-CO2 TSD) provides a complete discussion of the 

methodology and the current SC-CO2 TSD18 presents and discusses the updated estimates. The 

 

16 See https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-comments-final-july-2015.pdf 

17 The full models names are as follows: Dynamic Integrated Climate and Economy (DICE); Climate Framework for 

Uncertainty, Negotiation, and Distribution (FUND); and Policy Analysis of the Greenhouse Gas Effect (PAGE). 

18 The IWG published the updated TSD in 2013, then issued two minor corrections to it in July 2015. 
1-21 

four SC-CO2 estimates are as follows: $12, $40, $60, and $120 per short ton of CO2 emissions in 

the year 2020 (2011$), and each estimate increases over time.19 These SC-CO2 estimates are 

associated with different discount rates. The first three estimates are the model average at 5 

percent discount rate, 3 percent, and 2.5 percent, respectively, and the fourth estimate is the 95th

percentile at 3 percent. 

 The 2010 SC-CO2 TSD noted a number of limitations to the SC-CO2 analysis, including 

the incomplete way in which the IAMs capture catastrophic and non-catastrophic impacts, their 

incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of 

damages to high temperatures, and assumptions regarding risk aversion. Currently integrated 

assessment models do not assign value to all of the important physical, ecological, and economic 

impacts of climate change recognized in the climate change literature because of a lack of 

precise information on the nature of damages and because the science incorporated into these 

models understandably lags behind the most recent research.20 In particular, the IPCC Fourth 

Assessment Report concluded that “It is very likely that [SC-CO2 estimates] underestimate the 

damage costs because they cannot include many non-quantifiable impacts.” Nonetheless, these 

estimates and the discussion of their limitations represent the best available information about 

the social benefits of CO2 emission reductions to inform the benefit-cost analysis. 

In addition, after careful evaluation of the full range of comments submitted to OMB’s 

Office of Information and Regulatory Affairs, the IWG continues to recommend the use of these 

SC-CO2 estimates in regulatory impact analysis. With the release of the response to comments, 

the IWG announced plans to obtain expert independent advice from the National Academies of 

Sciences, Engineering, and Medicine (Academies) to ensure that the SC-CO2 estimates continue 

to reflect the best available scientific and economic information on climate change.21 The 

 

19 The 2010 and 2013 TSDs present SC-CO2 in 2007$ per metric ton. The unrounded estimates from the current 

TSD were adjusted to (1) 2011$ using GDP Implicit Price Deflator (1.061374), 

http://www.bea.gov/iTable/index_nipa.cfm and (2) short tons using the conversion factor of 0.90718474 metric 

tons in a short ton. These estimates were rounded to two significant digits. 

20 Climate change impacts and SCC modeling is an area of active research. For example, see: (1) Howard, Peter, 

“Omitted Damages: What’s Missing from the Social Cost of Carbon.” March 13, 2014, 

http://costofcarbon.org/files/Omitted_Damages_Whats_Missing_From_the_Social_Cost_of_Carbon.pdf; and (2) 

Electric Power Research Institute, “Understanding the Social Cost of Carbon: A Technical Assessment,” October 

2014, www.epri.com. 

21 See <https://www.whitehouse.gov/blog/2015/07/02/estimating-benefits-carbon-dioxide-emissions-reductions>. 
1-22 

Academies’ process will be informed by the public comments received and focus on the 

technical merits and challenges of potential approaches to improving the SC-CO2 estimates in 

future updates. 

1.5.3.2 Estimating Air Quality Health Co-Benefits 

The proposed federal plan and model trading rules would reduce emissions of precursor 

pollutants (e.g., SO2, NOX, and directly emitted particles), which in turn would lower ambient 

concentrations of PM2.5 and ozone. This co-benefits analysis quantifies the monetized benefits 

associated with the reduced exposure to these two pollutants.22 Unlike the global SC-CO2

estimates, the air quality health co-benefits are only estimated for the contiguous U.S. The 

estimates of monetized PM2.5 co-benefits include avoided premature deaths (derived from effect 

coefficients in two cohort studies [Krewski et al. 2009 and Lepeule et al. 2012] for adults and 

one for infants [Woodruff et al. 1997]), as well as avoided morbidity effects for ten non-fatal 

endpoints ranging in severity from lower respiratory symptoms to heart attacks23 (U.S. EPA, 

2012). The estimates of monetized ozone co-benefits include avoided premature deaths (derived 

from the range of effect coefficients represented by two short-term epidemiology studies [Bell et 

al. (2004) and Levy et al. (2005)]), as well as avoided morbidity effects for five non-fatal 

endpoints ranging in severity from school absence days to hospital admissions (U.S. EPA, 2008, 

2011). 

We use a “benefit-per-ton” approach to estimate the PM2.5 and ozone co-benefits in this 

RIA. Benefit-per-ton approaches apply an average benefit per ton derived from modeling of 

benefits of specific air quality scenarios to estimates of emissions reductions for scenarios where 

no air quality modeling is available. The benefit-per-ton approach we use in this RIA relies on 

estimates of human health responses to exposure to PM and ozone obtained from the peerreviewed scientific literature. These estimates are used in conjunction with population data, 

 

22 We did not estimate the co-benefits associated with reducing direct exposure to SO2 and NOX. For this RIA, we 

did not estimate changes in emissions of directly emitted particles. As a result, quantified PM2.5 related benefits 

are underestimated by a relatively small amount. In the proposal RIA, the benefits from reductions in directly 

emitted PM2.5 were less than 10 percent of total monetized health co-benefits across all scenarios and years. 

23 See Chapter 4 and Appendix 4A of the Clean Power Plan Final Rule for details on this assessment of health cobenefits. 
1-23 

baseline health information, air quality data and economic valuation information to conduct 

health impact and economic benefits assessments. 

Specifically, in this analysis, we multiplied the benefit-per-ton estimates by the 

corresponding emission reductions that were generated from air quality modeling of the 

proposed Clean Power Plan Emission Guidelines. Similar to the co-benefits analysis conducted 

for the final Clean Power Plan Emission Guidelines RIA, we generated regional benefit-per-ton 

estimates by aggregating the impacts in BenMAP24 to the region (i.e., East, West, and California) 

rather than aggregating to the nation. The benefit-per-ton for SO2 and NOx emissions used in this 

proposed rule were calculated using air quality modeling of the base case and the proposed Clean 

Power Plan (Option 1 State) scenario for 2025 as described in Appendix 4A of the final Clean 

Power Plan Emission Guidelines RIA. The benefit-per-ton values for 2020 and 2030 are based 

on applying the air quality modeling from 2025 to population and health information from 2020 

and 2030. 

To calculate the co-benefits for this proposed rule, we then multiplied the regional 

benefit-per-ton estimates for the EGU sector by the corresponding emission reductions. All 

benefit-per-ton estimates reflect the geographic distribution of the modeled emissions, which 

may not exactly match the emission reductions in this rulemaking, and thus they may not reflect 

the local variability in population density, meteorology, exposure, baseline health incidence 

rates, or other local factors for any specific location. 

Our estimate of the monetized co-benefits is based on the EPA’s interpretation of the best 

available scientific literature (U.S. EPA, 2009) and methods and supported by the EPA’s Science 

Advisory Board and the NAS (NRC, 2002). Below are key assumptions underlying the estimates 

for PM2.5-related premature mortality, which accounts for 98 percent of the monetized PM2.5

health co-benefits. 

1. We assume that all fine particles, regardless of their chemical composition, are 

equally potent in causing premature mortality. This is an important assumption, 

 

24 BenMAP is a computer program developed by the EPA that calculates the number and economic value of air 

pollution-related deaths and illnesses. The software incorporates a database that includes many of the 

concentration-response relationships, population files, and health and economic data needed to quantify these 

impacts. 
1-24 

because PM2.5 varies considerably in composition across sources, but the scientific 

evidence is not yet sufficient to allow differentiation of effect estimates by particle 

type. The PM ISA concluded that “many constituents of PM2.5 can be linked with 

multiple health effects, and the evidence is not yet sufficient to allow differentiation 

of those constituents or sources that are more closely related to specific outcomes” 

(U.S. EPA, 2009b). 

2. We assume that the health impact function for fine particles is log-linear without a 

threshold in this analysis. Thus, the estimates include health co-benefits from 

reducing fine particles in areas with varied concentrations of PM2.5, including both 

areas that do not meet the National Ambient Air Quality Standard for fine particles 

and those areas that are in attainment, down to the lowest modeled concentrations. 

3. We assume that there is a “cessation” lag between the change in PM exposures and 

the total realization of changes in mortality effects. Specifically, we assume that some 

of the incidences of premature mortality related to PM2.5 exposures occur in a 

distributed fashion over the 20 years following exposure based on the advice of the 

SAB-H1 (U.S. EPA-SAB, 2004c), which affects the valuation of mortality cobenefits at different discount rates. 

Every benefits analysis examining the potential effects of a change in environmental 

protection requirements is limited, to some extent, by data gaps, model capabilities (such as 

geographic coverage) and uncertainties in the underlying scientific and economic studies used to 

configure the benefit and cost models. Despite these uncertainties, we believe this analysis 

provides a reasonable indication of the expected health co-benefits of the air quality emission 

reductions for the proposed rule under a set of reasonable assumptions. This analysis does not 

include the type of detailed uncertainty assessment found in the 2012 PM2.5 National Ambient 

Air Quality Standard (NAAQS) RIA (U.S. EPA, 2012) because we lack the necessary air quality 

input and monitoring data to conduct a complete benefits assessment. In addition, using a 

benefit-per-ton approach adds another important source of uncertainty to the benefits estimates. 

1.5.3.3 Combined Benefits Estimates 

The EPA has evaluated the range of potential impacts by combining all four SC-CO2

values with health co-benefits values at the 3 percent and 7 percent discount rates. Different 
1-25 

discount rates are applied to SC-CO2 than to the health co-benefit estimates because CO2

emissions are long-lived and subsequent damages occur over many years. Moreover, several 

discount rates are applied to SC-CO2 because the literature shows that the estimate of SC-CO2 is 

sensitive to assumptions about discount rate and because no consensus exists on the appropriate 

rate to use in an intergenerational context. The IWG centered its attention on the average SCCO2 at a 3 percent discount rate but emphasized the importance of considering all four SC-CO2

estimates. Table 1-6 (rate-based federal plan approach) and Table 1-7 (mass-based federal plan 

approach) provide the combined climate benefits and health co-benefits for the proposed federal 

plan model trading rules estimated for 2020, 2025, and 2030 for each discount rate combination. 

All dollar estimates are in 2011 dollars. 
1-26 

Table 1-6. Combined Estimates of Climate Benefits and Health Co-Benefits for Rate-Based 

Approach (billions of 2011$)* 

SC-CO2 Discount Rate and Statistic** 

Climate 

Benefits 

Only 

Climate Benefits plus Health Co-benefits 

(Discount Rate Applied to Health Co-benefits) 

3% 7% 

In 2020 69 million short tons CO2 

5% $0.80 $1.5 to $2.6 $1.4 to $2.5 

3% $2.8 $3.5 to $4.6 $3.5 to $4.5 

2.5% $4.1 $4.9 to $6.0 $4.8 to $5.9 

3% (95th percentile) $8.2 $8.9 to $10 $8.9 to $9.9 

In 2025 232 million short tons CO2 

5% $3.1 $11 to $21 $9.9 to $19 

3% $10 $18 to $28 $17 to $26 

2.5% $15 $23 to $33 $22 to $31 

3% (95th percentile) $31 $38 to $49 $38 to $47 

In 2030 415 million short tons CO2

5% $6.4 $21 to $40 $19 to $37 

3% $20 $34 to $54 $33 to $51 

2.5% $29 $43 to $63 $42 to $60 

3% (95th percentile) $61 $75 to $95 $74 to $92 

*All benefit estimates are rounded to two significant figures. Climate benefits are based on reductions in CO2

emissions. Co-benefits are based on regional benefit-per-ton estimates. Ozone co-benefits occur in analysis year, so 

they are the same for all discount rates. The health co-benefits reflect the sum of the PM2.5 and ozone co-benefits 

and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Bell et al. (2004) to 

Lepeule et al. (2012) with Levy et al. (2005)). The monetized health co-benefits do not include reduced health 

effects from reductions in directly emitted PM2.5, direct exposure to NOX, SO2, and HAP; ecosystem effects; or 

visibility impairment. See Chapter 4 of the Clean Power Plan Final Rule RIA for more information about these 

estimates and for more information regarding the uncertainty in these estimates. 

**Unless otherwise specified, the row reflects the average SC-CO2 estimate for the specified discount rate. 
1-27 

Table 1-7. Combined Estimates of Climate Benefits and Health Co-benefits for Mass-Based 

Approach (billions of 2011$)* 

SC-CO2 Discount Rate and Statistic** 

Climate 

Benefits 

Only 

Climate Benefits plus Health Co-benefits 

(Discount Rate Applied to Health Co-benefits) 

3% 7% 

In 2020 82 million short tons CO2

5% $0.94 $2.9 to $5.7 $2.8 to $5.3 

3% $3.3 $5.3 to $8.1 $5.1 to $7.7 

2.5% $4.9 $6.9 to $9.7 $6.7 to $9.3 

3% (95th percentile) $9.7 $12 to $14 $11 to $14 

In 2025 264 million short tons CO2

5% $3.6 $11 to $21 $10 to $19 

3% $12 $19 to $29 $18 to $27 

2.5% $17 $24 to $35 $24 to $33 

3% (95th percentile) $35 $42 to $52 $42 to $51 

In 2030 413 million short tons CO2

5% $6.4 $18 to $34 $17 to $32 

3% $20 $32 to $48 $31 to $46 

2.5% $29 $41 to $57 $40 to $55 

3% (95th percentile) $60 $72 to $89 $71 to $86 

*All benefit estimates are rounded to two significant figures. Climate benefits are based on reductions in CO2

emissions. Co-benefits are based on regional benefit-per-ton estimates. Ozone co-benefits occur in analysis year, so 

they are the same for all discount rates. The health co-benefits reflect the sum of the PM2.5 and ozone co-benefits 

and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Bell et al. (2004) to 

Lepeule et al. (2012) with Levy et al. (2005)). The monetized health co-benefits do not include reduced health 

effects from reductions in directly emitted PM2.5, direct exposure to NOX, SO2, and HAP; ecosystem effects; or 

visibility impairment. See Chapter 4 of the Clean Power Plan Final Rule RIA for more information about these 

estimates and for more information regarding the uncertainty in these estimates. 

**Unless otherwise specified, the row reflects the average SC-CO2 estimate for the specified discount rate. 

1.5.4 Net Benefits 

Table 1-8 and 1-9 provide the estimates of the climate benefits, health co-benefits, 

compliance costs and net benefits of the proposed federal plan and model trading rules for ratebased and mass-based approaches, respectively. There are additional important benefits that the 

EPA could not monetize. Due to current data and modeling limitations, our estimates of the 

benefits from reducing CO2 emissions do not include important impacts like ocean acidification 

or potential tipping points in natural or managed ecosystems. Unquantified benefits also include 

climate benefits from reducing emissions of non-CO2 greenhouse gases and co-benefits from 

reducing exposure to SO2, NOX, and hazardous air pollutants (e.g., mercury), as well as 

ecosystem effects and visibility impairment. Upon considering these limitations and 

uncertainties, it remains clear that the benefits of this proposed rule are substantial and far 

outweigh the costs. 
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Table 1-8. Monetized Benefits, Compliance Costs, and Net Benefits Under the Rate-based 

Federal Plan Approach (billions of 2011$) a 

 Rate-Based Approach 

2020 2025 2030 

Climate Benefits b 

5% discount rate $0.80 $3.1 $6.4 

3% discount rate $2.8 $10 $20 

2.5% discount rate $4.1 $15 $29 

95th percentile at 3% 

discount rate $8.2 $31 $61 

Air Quality Co-benefits Discount Rate 

3% 7% 3% 7% 3% 7% 

Air Quality Health 

Co-benefits c

$0.70 to $1.8 $0.64 to $1.7 $7.4 to $18 $6.7 to $16 $14 to $34 $13 to $31 

Compliance Costs d $2.5 $1.0 $8.4 

Net Benefits e $1.0 to $2.1 $1.0 to $2.0 $17 to $27 $16 to $25 $26 to $45 $25 to $43 

Non-Monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and mercury 

Visibility impairment 

a

 All are rounded to two significant figures, so figures may not sum. 

b

 The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does 

not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SC-CO2 than to the 

other estimates because CO2 emissions are long-lived and subsequent damages occur over many years. The net 

benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount rate, however we 

emphasize the importance and value of considering the full range of SC-CO2 values. As shown in this table, climate 

benefits are also estimated using the other three SC-CO2 estimates (model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2 estimates are year-specific and increase over time. 

c The air quality health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions 

of SO2 and NOX. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These 

additional benefits would increase overall benefits by a few percent based on the analyses conducted for the 

proposed rule. The range reflects the use of concentration-response functions from different epidemiology studies. 

The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. Estimates in the table are presented for three analytical years with air quality cobenefits calculated using two discount rates. The estimates of co-benefits are annual estimates in each of the 

analytical years, reflecting discounting of mortality benefits over the cessation lag between changes in PM2.5

concentrations and changes in risks of premature death (see Chapter 4 of the Clean Power Plan Final Rule RIA for 

more details), and discounting of morbidity benefits due to the multiple years of costs associated with some 

illnesses. The estimates are not the present value of the benefits of the rule over the full compliance period. 

d Compliance costs are the compliance costs estimated using the Integrated Planning Model and a discount rate of 

approximately 5 percent. It also includes monitoring, recordkeeping, and reporting costs and demand-side energy 

efficiency program and participant costs. 

e

 The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount 

rate (model average). The Clean Power Plan Final Rule RIA includes combined climate and health estimates based 

on additional discount rates. 
1-29 

Table 1-9. Monetized Benefits, Compliance Costs, and Net Benefits under the Mass-based 

Federal Plan Approach (billions of 2011$) a 

 Mass-Based Approach 

2020 2025 2030 

Climate Benefits b 

5% discount rate $0.94 $3.6 $6.4 

3% discount rate $3.3 $12 $20 

2.5% discount rate $4.9 $17 $29 

95th percentile at 3% 

discount rate $9.7 $35 $60 

Air Quality Co-benefits Discount Rate 

3% 7% 3% 7% 3% 7% 

Air Quality Health 

Co-benefits c

$2.0 to $4.8 $1.8 to $4.4 $7.1 to $17 $6.5 to $16 $12 to $28 $11 to $26 

Compliance Costs d $1.4 $3.0 $5.1 

Net Benefits e $3.9 to $6.7 $3.7 to $6.3 $16 to $26 $15 to $24 $26 to $43 $25 to $40 

Non-Monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and 

mercury 

Visibility improvement 

a

 All are rounded to two significant figures, so figures may not sum. 

b

 The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does 

not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SC-CO2 than to the 

other estimates because CO2 emissions are long-lived and subsequent damages occur over many years. The net 

benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount rate, however we 

emphasize the importance and value of considering the full range of SC-CO2 values. As shown in this table, climate 

benefits are also estimated using the other three SC-CO2 estimates (model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2 estimates are year-specific and increase over time. 

c The air quality health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions 

of SO2 and NOX. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These 

additional benefits would increase overall benefits by a few percent based on the analyses conducted for the 

proposed rule. The range reflects the use of concentration-response functions from different epidemiology studies. 

The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. Estimates in the table are presented for three analytical years with air quality cobenefits calculated using two discount rates. The estimates of co-benefits are annual estimates in each of the 

analytical years, reflecting discounting of mortality benefits over the cessation lag between changes in PM2.5

concentrations and changes in risks of premature death (see Chapter 4 of the Clean Power Plan Final Rule RIA for 

more details), and discounting of morbidity benefits due to the multiple years of costs associated with some 

illnesses. The estimates are not the present value of the benefits of the rule over the full compliance period. 

d Compliance costs are the compliance costs estimated using the Integrated Planning Model and a discount rate of 

approximately 5 percent. It also includes monitoring, recordkeeping, and reporting costs and demand-side energy 

efficiency program and participant costs. 

e

 The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount 

rate (model average). The Clean Power Plan Final Rule RIA includes combined climate and health estimates based 

on additional discount rates. 
1-30 

1.5.5 Economic Impacts 

The federal plan approaches analyzed in this RIA indicate that the proposed federal plan 

and model trading rules may have important energy market implications. Table 1-10 presents a 

variety of important energy market impacts for 2020, 2025, and 2030 for both the rate-based and 

mass-based federal plan approaches. 

Table 1-10. Summary Table of Important Energy Market Impacts (Percent Change from 

Base Case) 

 Rate-Based Mass-Based 

 2020 2025 2030 2020 2025 2030 

Retail electricity prices 3% 1% 1% 3% 2% 0% 

Average electricity bills 3% -4% -7% 2% -3% -8% 

Price of coal at minemouth -1% -5% -4% -1% -5% -3% 

Coal production for power sector use -5% -14% -25% -7% -17% -24% 

Price of natural gas delivered to power sector 5% -8% 2% 4% -3% -2% 

Natural gas use for electricity generation 3% -1% -1% 5% 0% -4% 

Energy market impacts are discussed more extensively in Chapter 3 of the final Clean Power 

Plan Emission Guidelines RIA. As well as the above energy market impacts, Chapter 3 of the 

final Clean Power Plan Emission Guidelines RIA presents projections of power sector generation 

and capacity changes by fuel type. 

Additionally, changes in supply or demand for electricity, natural gas, and coal can 

impact markets for goods and services produced by sectors that use these energy inputs in the 

production process or that supply those sectors. Changes in cost of production may result in 

changes in price and/or quantity produced by these sectors and these market changes may affect 

the profitability of firms and the economic welfare of their consumers. Similarly, demand for 

new generation or energy efficiency, for example, can result in changes in production and 

profitability for firms that supply those goods and services. The EPA recognizes that states 

subject to the federal plan may choose to mitigate impacts to some markets outside the EGU 

sector, perhaps by implementing the guidelines through a state plan. 

1.5.6 Employment Impacts 

Executive Order 13563 directs federal agencies to consider the effect of regulations on 

job creation and employment. According to the Executive Order, “our regulatory system must 
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protect public health, welfare, safety, and our environment while promoting economic growth, 

innovation, competitiveness, and job creation. It must be based on the best available science” 

(Executive Order 13563, 2011). Although standard benefit-cost analyses have not typically 

included a separate analysis of regulation-induced employment impacts, we typically conduct 

employment analyses.25 While the economy continues moving toward full-employment, 

employment impacts are of particular concern and questions may arise about their existence and 

magnitude. 

Given the wide range of approaches that may be used to meet the requirements of the 

proposed federal plan and model trading rules, quantifying the associated employment impacts is 

difficult. The EPA’s illustrative employment analysis includes an estimate of projected 

employment impacts for the utility power sector, coal and natural gas production, and demandside energy efficiency activities. These projections are derived, in part, from the detailed model 

of the utility power sector used for this regulatory analysis, and U.S government data on 

employment and labor productivity. 

In the electricity, coal, and natural gas sectors, the EPA uses the IPM estimates of the 

changes in generation and fuel use of the proposed rule to estimate there could be a net decrease 

of approximately 25,000 job-years26 in 2025 for the proposed rule under the rate-based federal 

plan approach and approximately 26,000 job-years in 2025 under the mass-based approach. For 

2030 the estimates of the net decrease in job-years is 30,900 under the rate-based plan, and 

33,700 under the mass-based plan. The Agency is also offering an illustrative calculation of 

potential employment effects due to demand-side energy efficiency programs. Employment 

impacts from demand-side energy efficiency programs in 2030 could range from approximately 

52,000 to 83,000 jobs created under proposed federal plan and model trading rules. The IPMderived job-year numbers for the electricity, coal and natural gas sectors should not be added to 

the demand-side efficiency job impacts, since the former are reported in full-time equivalent jobyears, whereas the latter do not distinguish between full- and part-time employment. More detail 

 

25 The employment analysis in this RIA is part of EPA’s ongoing effort to “conduct continuing evaluations of 

potential loss or shifts of employment which may result from the administration or enforcement of [the Act]” 

pursuant to CAA section 321(a). 

26 Job-years are not individual jobs, but rather the amount of work performed by the equivalent of one full-time 

individual for one year. For example, 20 job-years in 2020 may represent 20 full-time jobs or 40 half-time jobs in 

that year. 
1-32 

about these analyses can be found in Chapter 6 of the final Clean Power Plan Emission 

Guidelines RIA. 

1.5.7 Additional Analysis of Output-Based Allocation as a Means of Mitigating Leakage 

The application of OBA will provide an incentive to increase generation at existing 

NGCC EGUs in place of generation at new NGCC EGUs and existing fossil steam EGUs. To 

approximate the effect of this incentive in the mass-based scenario, the EPA used IPM model 

plant results from the mass-based scenario to construct the average dispatch order for model 

plants in each IPM region. Then, based on the allowance prices for the state in which each model 

plant resides, the EPA adjusted the dispatch order in the case where existing NGCC units were 

allocated allowances at a rate of 1,030 lbs/MWh for each MWh generated above a 50 percent 

capacity factor as proposed. In cases where an existing NGCC plant moved ahead of an existing 

fossil steam plant in the dispatch order, the NGCC plant’s generation was increased while the 

existing fossil plant’s generation was reduced. The NGCC plant’s generation was increased to 

the maximum capacity factor assumed feasible within IPM while the amount of reduced 

generation at the fossil steam plant is determined by the amount that would keep the overall 

covered sources’ emissions in the region constant, so as to respect compliance with the massbased standards represented in the modeling scenario. Since the existing NGCC plant has a lower 

emissions rate than the existing fossil steam plant, the increase in generation at the NGCC plant 

is greater than the reduction in generation (because more generation is now possible from both 

plants together at the same given level of emissions). This net increase in generation from 

existing EGUs is then subtracted from new NGCC generation in the region, consistent with the 

total generation needed to meet the load assumed in the IPM modeling of the mass-based 

scenario. 

When applying this algorithm to the results from the mass-based scenario analyzed in this 

RIA, it forecasts nationally in 2030 a 10 percent increase in generation at existing NGCC EGUs, 

a 4 percent reduction in generation at existing fossil steam EGUs, and a 29 percent decrease in 

generation at new NGCC EGUs compared to the modeling scenario results presented above. The 

result of this reduction in new NGCC EGU generation is a reduction in CO2 emissions of 23 

million short tons (an amount equal to 1.3 percent of 2030 forecast emissions in mass-based 
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scenario). We do not quantify the effect of these changes in generation on SO2 and NOx

emissions, although on net additional co-benefits are expected. 

The incentives portrayed in this analysis are consistent with the incentives that would be 

realized under the OBA set-aside, and the general direction and magnitude of the results are 

likely consistent with those that would be observed had the mass-based scenario been modeled 

with the OBA set-aside. However, the results should be viewed as approximate given that 

analysis does not consider important aspects of power markets included in IPM. For example, the 

analysis does not consider any potential changes in relative fuel and allowance prices as a result 

of the OBA set-aside. The application of the OBA set-aside will place upward pressure on the 

allowance prices and therefore further incentivize a shift away from existing fossil steam 

generation. The OBA set-aside may also place upward pressure on the price of natural gas which 

would reduce the effectiveness of the set-aside at encouraging increased utilization of existing 

NGCC EGUs, but the OBA set-aside would be effective in increasing existing NGCC 

generation, the analysis does not consider the fact that electricity is traded across many IPM 

regions. The application of OBA in one state may impact the generation at EGUs in another 

state. 

1.5.8 Uncertainty Analysis 

The Office of Management and Budget’s circular Regulatory Analysis (Circular A-4) 

provides guidance on the preparation of regulatory analyses required under E.O. 12866, and 

requires an uncertainty analysis for rules with annual benefits or costs of $1 billion or more.27

This proposed rulemaking potentially surpasses that threshold for both benefits and costs. 

Throughout this RIA and the referenced final Clean Power Plan Emission Guidelines RIA, we 

considered a number of sources of uncertainty, both quantitatively and qualitatively, on benefits 

and costs. We summarize three key elements of our analysis of uncertainty here: 

 

27 Office of Management and Budget (OMB), 2003, Circular A-4, 

http://www.whitehouse.gov/omb/circulars_a004_a-4 and OMB, 2011. Regulatory Impact Analysis: A Primer.

http://www.whitehouse.gov/sites/default/files/omb/inforeg/regpol/circular-a-4_regulatory-impact-analysis-aprimer.pdf 
1-34 

• Assess uncertainty in the methods used to calculate the health co-benefits associated with 

the reduction in PM2.5 and ozone and the use of a benefits-per-ton approach in estimating 

these co-benefits. 

• Characterizing uncertainty in monetizing climate-related benefits. 

Some of these elements are evaluated using probabilistic techniques, whereas for others 

the underlying likelihoods of certain outcomes are unknown and we use scenario analysis to 

evaluate their potential effect on the benefits and costs of this rulemaking. 

1.5.8.1 Uncertainty in Costs 

Our best estimates of the costs of these illustrative scenarios are reported within the cost 

analysis of the final Clean Power Plan Emission Guidelines and are included in the cost 

modeling in this RIA for both the proposed rate-based and mass-based approaches. A source of 

uncertainty under this regulation is the ultimate approach states that are not subject to the federal 

plan or adopt the model rule will adopt in response to the guidelines, which will affect both the 

costs and benefits of this rule. For this reason we modeled the two proposed federal plan 

approaches assuming they applied to all of the states. 

1.5.8.2 Uncertainty Associated with Estimating the Social Cost of Carbon 

The 2010 SC-CO2 TSD noted a number of limitations to the SC-CO2 analysis, including 

the incomplete way in which the integrated assessment models (IAM) capture catastrophic and 

non-catastrophic impacts, their incomplete treatment of adaptation and technological change, 

uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk 

aversion.28 Currently integrated assessment models do not assign value to all of the important 

physical, ecological, and economic impacts of climate change recognized in the climate change 

literature due to a lack of precise information on the nature of damages and because the science 

incorporated into these models understandably lags behind the most recent research. These 

individual limitations do not all work in the same direction in terms of their influence on the SC-

 

28 Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866, Interagency Working Group on Social Cost of Carbon, with participation by the Council of Economic 

Advisers, Council on Environmental Quality, Department of Agriculture, Department of Commerce, Department 

of Energy, Department of Transportation, Environmental Protection Agency, National Economic Council, Office 

of Energy and Climate Change, Office of Management and Budget, Office of Science and Technology Policy, and 

Department of Treasury (February 2010). Available at: 

<http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf>. 
1-35 

CO2 estimates, though taken together they suggest that the SC-CO2 estimates are likely 

conservative. In particular, the IPCC Fourth Assessment Report (2007) concluded that “It is very 

likely that [SC-CO2 estimates] underestimate the damage costs because they cannot include 

many non-quantifiable impacts” and the IPCC Fifth Assessment report observed that SC-CO2

estimates continue to omit various impacts that would likely increase damages. The 95th

percentile estimate was included in the recommended range for regulatory impact analysis, in 

part, to address these concerns. 

The modeling underlying the development of the SC-CO2 estimates addressed 

uncertainty in several ways. An ensemble of three IAMs were used to generate the SC-CO2

estimates to capture differences in model structures that, in part, reflect uncertainty in the 

scientific literature about these relationships. Parametric uncertainty was explicitly addressed in 

each IAM, though to differing degrees, through Monte Carlo simulations in which explicit 

probability distributions for key parameters were specified, including the equilibrium climate 

sensitivity, which represents the long-run responsiveness of the climate to increasing GHG 

concentrations. Furthermore, the analysis considered five different socioeconomic and emissions 

forecasts to capture the sensitivity of the SC-CO2 estimates to key exogenous projections used in 

the modeling. Finally, the results were calculated for three discount rates, which were selected, in 

part, to reflect uncertainty about how interest rates may change over time and the possibility that 

climate damages are positively correlated with uncertain future economic activity. This analysis 

produced 45 different distributions of the SC-CO2 estimates for each emissions year. To produce 

a range of plausible estimates that are manageable in regulatory analysis but still reflects the 

uncertainty in the results four point estimates were recommended. The use of this range of point 

estimates in this rulemaking helps to reflect the uncertainty in the SC-CO2 estimates. Chapter 4 

of the final Clean Power Plan Emission Guidelines RIA provides a comprehensive discussion 

about the methodology and application of the SC-CO2; see both the 2010 TSD and current SCCO2 TSD for a full description. 

In addition, OMB’s Office of Information and Regulatory Affairs received comments 

regarding uncertainty and the SC-CO2 estimates in response to a separate request for public 

comment on the approach used to develop the estimates. Commenters discussed the analyses and 

presentation of uncertainty in the TSD as well as the implications of uncertainty for use of the 

SC-CO2 estimates in regulatory impact analysis. In their response, the interagency working 
1-36 

group (IWG) acknowledged uncertainty in the SC-CO2 estimates but disagreed with commenters 

that suggested the uncertainty undermines use of the SC-CO2 estimates in regulatory impact 

analysis. The IWG went on to note that the uncertainty in the SC-CO2 estimates is fully 

acknowledged and comprehensively discussed in the TSDs and supporting academic literature, 

and that while all regulatory impact analysis involves uncertainty, these analyses can provide 

useful information to decision makers and the public. See the IWG Response to Comments for 

the complete response.29 

1.5.8.3 Uncertainty Associated with PM2.5 and Ozone Health Co-Benefits Assessment 

EPA provides information on the relative uncertainty in the benefits estimates based on 

the 95th percentile confidence interval for avoided PM-related premature deaths and the 

associated economic valuation estimated in the benefits analysis for the recent PM NAAQS RIA 

(U.S. EPA, 2012).. In general, the 95th percentile confidence interval for monetized PM2.5

benefits ranges from approximately -90 percent to +180 percent of the central estimates based on 

the two key PM mortality studies. To further explore uncertainty in the premature mortality 

benefits, EPA provides the PM-related results using concentration-response functions from two 

key epidemiology studies, as well as alternate concentration-response relationship provided by 

an expert elicitation and alternative ozone-related results using concentration-response 

relationships provided by alternative epidemiology studies. In addition, we include an 

assessment of the distribution of population exposure in the modeling underlying the benefit-perton estimates. 

In addition to the uncertainties in the underlying concentration-response and valuation 

functions, all benefit-per-ton approaches have inherent limitations, including that the estimates 

reflect the geographic distribution of the modeled sector emissions, which may not match the 

emission reductions anticipated by this proposed rule, and they may not reflect local variability 

in population density, meteorology, exposure, baseline health incidence rates, or other local 

factors for any specific location. In addition, these estimates reflect the regional average benefitper-ton for each ambient PM2.5 precursor emitted from EGUs, which assumes a linear 

atmospheric response to emission reductions. The regional benefit-per-ton estimates, although 

 

29 See https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-comments-final-july-2015.pdf 
1-37 

less subject to these types of uncertainties than national estimates, still should be interpreted with 

caution. Even though we assume that all fine particles have equivalent health effects, the benefitper-ton estimates vary between precursors depending on the location and magnitude of their 

impact on PM2.5 levels, which drive population exposure. 

1.6 References 

40 CFR Chapter I [EPA–HQ–OAR–2009–0171; FRL–9091–8] RIN 2060–ZA14, 

“Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) 

of the Clean Air Act,” Federal Register / Vol. 74, No. 239 / Tuesday, December 15, 2009 / 

Rules and Regulations. 

75 FR 49556. August 13, 2010. “EPA’s Denial of the Petitions to Reconsider the Endangerment 

and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean 

Air Act.”

Bell, M.L., A. McDermott, S.L. Zeger, J.M. Sarnet, and F. Dominici. 2004. “Ozone and ShortTerm Mortality in 95 U.S. Urban Communities, 1987-2000.” Journal of the American 

Medical Association. 292(19):2372-8. 

Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support Document: Social Cost of 

Carbon for Regulatory Impact Analysis Under Executive Order 12866, Interagency Working 

Group on Social Cost of Carbon, with participation by the Council of Economic Advisers, 

Council on Environmental Quality, Department of Agriculture, Department of Commerce, 

Department of Energy, Department of Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and Climate Change, Office of Management 

and Budget, Office of Science and Technology Policy, and Department of Treasury (February 

2010). Available at: <http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf>. Accessed July 15, 2015. 
1-38 

Docket ID EPA-HQ-OAR-2013-0602, Technical Support Document: Technical Update of the 

Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, 

Interagency Working Group on Social Cost of Carbon, with Participation by Council of 

Economic Advisers, Council on Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, Department of Transportation, Domestic 

Policy Council, Environmental Protection Agency, National Economic Council, Office of 

Management and Budget, Office of Science and Technology Policy, and Department of 

Treasury (May 2013, Revised July 2015). Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf>. 

Accessed July 15, 2015. 

Krewski D., M. Jerrett, R.T. Burnett, R. Ma, E. Hughes, Y. Shi, et al. 2009. Extended Follow-Up 

and Spatial Analysis of the American Cancer Society Study Linking Particulate Air Pollution 

and Mortality. HEI Research Report, 140, Health Effects Institute, Boston, MA. 

Interagency Working Group on Social Cost of Carbon, with participation by Council of 

Economic Advisers, Council on Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, Department of Transportation, 

Environmental Protection Agency, National Economic Council, Office of Management and 

Budget, Office of Science and Technology Policy, and Department of Treasury. Response to 

to Comments: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866. July 2015. Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-commentsfinal-july-2015.pdf.> Accessed July 15, 2015. 

Intergovernmental Panel on Climate Change (IPCC). 2007. Climate Change 2007: Synthesis 

Report Contribution of Working Groups I, II and III to the Fourth Assessment Report of the 

IPCC. Available at: 

<http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report_synt

hesis_report.htm>. Accessed June 6, 2015. 

Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. “Chronic Exposure to Fine Particles 

and Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environmental Health Perspectives. 120(7):965-70. 

Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. “Ozone Exposure and Mortality: An 

Empiric Bayes Metaregression Analysis.” Epidemiology. 16(4):458-68. 
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Melillo, J.M., T.C. Richmond, and G.W. Yohe, Eds., 2014: Climate Change Impacts in the 

United States: The Third National Climate Assessment. U.S. Global Change Research 

Program. Available at <http://nca2014.globalchange.gov>. Accessed June 4, 2015. 

National Research Council (NRC). 2000. Toxicological Effects of Methylmercury: Committee on 

the Toxicological Effects of Methylmercury.” Board on Environmental Studies and 

Toxicology. National Academies Press. Washington, DC. 

National Research Council (NRC). 2002. Estimating the Public Health Benefits of Proposed Air 

Pollution Regulations. National Academies Press. Washington, DC. 

National Research Council. 2011. Climate Stabilization Targets: Emissions, Concentrations, and 

Impacts over Decades to Millennia. Washington, DC: The National Academies Press. 

U.S. Environmental Protection Agency (U.S. EPA). 2008a. Integrated Science Assessment for 

Sulfur Oxides—Health Criteria (Final Report). National Center for Environmental 

Assessment – RTP Division, Research Triangle Park, NC. September. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=198843>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2008b. Final Ozone NAAQS Regulatory 

Impact Analysis. EPA-452/R-08-003. Office of Air Quality Planning and Standards Health 

and Environmental Impacts Division, Air Benefit and Cost Group Research Triangle Park, 

NC. March. Available at: < http://www.epa.gov/ttnecas1/regdata/RIAs/6-

ozoneriachapter6.pdf>. Accessed June 4, 2015. 

U.S. EPA. 2008c. Integrated Science Assessment for Oxides of Nitrogen: Health Criteria (Final 

Report). Research Triangle Park, NC: National Center for Environmental Assessment. July. 

Available at < http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. 

U.S. Environmental Protection Agency (U.S. EPA). 2008c. Integrated Science Assessment for 

Oxides of Nitrogen - Health Criteria (Final Report). National Center for Environmental 

Assessment, Research Triangle Park, NC. July. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2009b. Integrated Science Assessment for 

Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for Environmental 

Assessment – RTP Division, Research Triangle Park, NC. December. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>. Accessed June 4, 2015. 
1-40 

U.S. Environmental Protection Agency (U.S. EPA). 2010d. Section 3: Re‐analysis of the Benefits 

of Attaining Alternative Ozone Standards to Incorporate Current Methods. Available at: 

<http://www.epa.gov/ttnecas1/regdata/RIAs/s3-supplemental_analysis-updated_benefits11-

5.09.pdf >. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2012a. Regulatory Impact Analysis for the 

Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. EPA452/R-12-003. Office of Air Quality Planning and Standards, Health and Environmental 

Impacts Division, Research Triangle Park, NC. December. Available at: < 

http://www.epa.gov/ttnecas1/regdata/RIAs/finalria.pdf>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2013b. Integrated Science Assessment of 

Ozone and Related Photochemical Oxidants (Final Report). EPA/600/R-10/076F. National 

Center for Environmental Assessment – RTP Division, Research Triangle Park. Available at: 

<http://cfpub.epa.gov/ncea/isa/recordisplay.cfm?deid=247492#Download>. Accessed June 4, 

2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2015a. Regulatory Impact Analysis for the 

Clean Power Plan Final Rule. EPA-452/R-15-003. Office of Air Quality Planning and 

Standards, Health and Environmental Impacts Division, Research Triangle Park. 

U.S. EPA. 2015b. Technical Support Document (TSD) the Final Carbon Pollution Emission 

Guidelines for Existing Stationary Sources: Electric Utility Generating Units. Demand-Side 

Energy Efficiency. 

Woodruff, T.J., J. Grillo, and K.C. Schoendorf. 1997. “The relationship between selected causes 

of postneonatal infant mortality and particulate air pollution in the United States.” 

Environmental Health Perspectives. 105(6): 608-612. 
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CHAPTER 2: STATUTORY AND EXECUTIVE ORDER REVIEWS

2.1 Executive Order 12866: Regulatory Planning and Review and Executive Order 

13563: Improving Regulation and Regulatory Review 

This proposed action is an economically significant regulatory action that was submitted 

to the OMB for review. Any changes made in response to OMB recommendations have been 

documented in the docket. The EPA prepared an analysis of the potential costs and benefits 

associated with this action. This analysis, which is presented in this RIA, is also available in the 

docket and is briefly summarized in section VIII of the preamble. 

Consistent with Executive Order 12866 and Executive Order 13563, the EPA estimated 

the costs and benefits for two alternative federal plan approaches to implementing the proposed 

federal plan and model trading rules. The proposed action will achieve the same levels of 

emissions performance as required of state plans under the CAA section 111(d) EGs for the 

control of CO2. Actions taken to comply with the guidelines will also reduce the emissions of 

directly-emitted PM2.5, SO2 and NOX. The benefits associated with these PM2.5, SO2 and NOX

reductions are referred to as co-benefits, as these reductions are not the primary objective of this 

rule. 

The RIA for this proposal analyzed two implementation scenarios, which we term the 

“rate-based federal plan approach” and the “mass-based federal plan approach”. It is very 

important to note that the differences between the analytical results for the rate-based and massbased federal plan approaches presented in this RIA may not be indicative of likely differences 

between the approaches if implemented by states and affected EGUs in response to the proposed 

rule. In other words, if one approach performs differently than the other on a given metric during 

a given time period, this does not imply this will apply in all instances. 

It is important to note that the potential regulatory impacts presented in the Clean Power 

Plan Final Rule RIA and this RIA are not additive. Both RIAs present estimates of the benefits 

and costs of achieving the emission performance rates of the Clean Power Plan EGs. In the case 

of the Clean Power Plan Final Rule RIA, the illustrative analysis assumes the performance rates 

are met under state plans. In the case of this RIA for the proposed federal plan and model trading 
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rules, the same performance rates are accomplished but are assumed to be achieved under the 

federal plan or model trading rules. 

The EPA has used the social cost of carbon estimates presented in the Technical Support 

Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866 (May 2013, Revised July 2015) (“current TSD”) to analyze CO2

climate impacts of this rulemaking. We refer to these estimates, which were developed by the 

U.S. government, as “SC-CO2 estimates.” The SC-CO2 is an estimate of the monetary value of 

impacts associated with a marginal change in CO2 emissions in a given year. The four SC-CO2

estimates are associated with different discount rates (model average at 2.5 percent discount rate, 

3 percent, and 5 percent; 95th percentile at 3 percent), and each increases over time. In this 

summary, the EPA provides the estimate of climate benefits associated with the SC-CO2 value 

deemed to be central in the current TSD: the model average at 3 percent discount rate. 

The EPA estimates that, in 2020, the proposal will yield monetized climate benefits (in 

2011$) of approximately $2.8 billion for the rate-based approach and $3.3 billion for the massbased approach (3 percent model average). For the rate-based approach, the air pollution health 

co-benefits in 2020 are estimated to be $0.7 billion to $1.8 billion (2011$) for a 3 percent 

discount rate and $0.64 billion to $1.7 billion (2011$) for a 7 percent discount rate. For the massbased approach, the air pollution health co-benefits in 2020 are estimated to be $2.0 billion to 

$4.8 billion (2011$) for a 3 percent discount rate and $1.8 billion to $4.4 billion (2011$) for a 7 

percent discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE 

program and participant costs and MRR costs in 2020, are approximately $2.5 billion for the 

rate-based approach and $1.4 billion for the mass-based approach (2011$). The quantified net 

benefits (the difference between monetized benefits and compliance costs) in 2020 are estimated 

to range from $1.0 billion to $2.1 billion (2011$) for the rate-based approach and from $3.9 

billion to 6.7 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model 

average). 

The EPA estimates that, in 2025, the proposal will yield monetized climate benefits (in 

2011$) of approximately $10 billion for the rate-based approach and $12 billion for the massbased approach (3 percent model average). For the rate-based approach, the air pollution health 

co-benefits in 2025 are estimated to be $7.4 billion to $18 billion (2011$) for a 3 percent 
2-3 

discount rate and $6.7 billion to $16 billion (2011$) for a 7 percent discount rate. For the massbased approach, the air pollution health co-benefits in 2025 are estimated to be $7.1 billion to 

$17 billion (2011$) for a 3 percent discount rate and $6.5 billion to $16 billion (2011$) for a 7 

percent discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE 

program and participant costs and MRR costs in 2025, are approximately $1.0 billion for the 

rate-based approach and $3.0 billion for the mass-based approach (2011$). The quantified net 

benefits (the difference between monetized benefits and compliance costs) in 2025 are estimated 

to range from $17 billion to $27 billion (2011$) for the rate-based approach and $16 billion to 

$26 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model 

average). 

The EPA estimates that, in 2030, the proposal will yield monetized climate benefits (in 

2011$) of approximately $20 billion for the rate-based approach and $20 billion for the massbased approach (3 percent model average). For the rate-based approach, the air pollution health 

co-benefits in 2030 are estimated to be $14 billion to $34 billion (2011$) for a 3 percent discount 

rate and $13 billion to $31 billion (2011$) for a 7 percent discount rate. For the mass-based 

approach, the air pollution health co-benefits in 2030 are estimated to be $12 billion to $28 

billion (2011$) for a 3 percent discount rate and $11 billion to $26 billion (2011$) for a 7 percent 

discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE program 

and participant costs and MRR costs in 2030, are approximately $8.4 billion for the rate-based 

approach and $5.1 billion for the mass-based approach (2011$). The quantified net benefits (the 

difference between monetized benefits and compliance costs) in 2030 are estimated to range 

from $26 billion to $45 billion (2011$) for the rate-based approach and from $26 billion to $43 

billion (2011$) for the mass-based approach, using a 3 percent discount rate (model average). 

Table 1-8 and Table 1-9 of this RIA provides the estimates of the climate benefits, health cobenefits, compliance costs and net benefits of the proposal for rate-based and mass-based federal 

plan approaches, respectively. 

There are additional important benefits that the EPA could not monetize. Due to current 

data and modeling limitations, our estimates of the benefits from reducing CO2 emissions do not 

include important impacts like ocean acidification or potential tipping points in natural or 

managed ecosystems. Unquantified benefits also include climate benefits from reducing 

emissions of non-CO2 GHGs (e.g., nitrous oxide and methane) and co-benefits from reducing 
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direct exposure to SO2, NOX, and HAP (e.g., mercury), as well as from reducing ecosystem 

effects and visibility impairment. Based upon the foregoing discussion, it remains clear that the 

benefits of this proposed action are substantial, and far exceed the costs. Additional details on 

benefits, costs, and net benefits estimates are provided in this RIA. 

 2.2 Paperwork Reduction Act 

The information collection requirements in this rule have been submitted for approval to 

OMB under the PRA. The Information Collection Request (ICR) document prepared by the EPA 

has been assigned EPA ICR number 2526.01. You can find a copy of the ICR in the docket for 

this rule, and it is briefly summarized here. The information collection requirements are not 

enforceable until approved by OMB. 

This rule does not directly impose specific requirements on state and U.S. territory 

governments with affected EGUs. The rule also does not impose specific requirements on tribal 

governments that have affected EGUs located in their area of Indian country. This rule does 

impose specific requirements on EGUs located in states, U.S. territories or areas of Indian 

country. 

The information collection activities in this proposed rule are consistent with those 

activities defined under the Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units finalized on August 3, 2015. The information 

collection requirements in this proposed rule have been submitted for approval to the Office of 

Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. 

The ICR document prepared by the EPA has been assigned EPA ICR number 2526.01. You can 

find a copy of the ICR in the docket for this rule, and it is briefly summarized here. 

Aside from reading and understanding the rule, this proposed action would impose 

minimal new information collection burden on affected EGUs beyond what those affected EGUs 

would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously 

approved the information collection requirements contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR part 98) under the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060–0626 and 

2060– 0629, respectively. Apart from certain reporting costs based on requirements in the NSPS 

General Provisions (40 CFR part 60, subpart A), which are mandatory for all owners/operators 
2-5 

subject to CAA section 111 national emission standards, there are no new information collection 

costs, as the information required by this proposed rule is already collected and reported by other 

regulatory programs. The recordkeeping and reporting requirements are specifically authorized 

by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the 

recordkeeping and reporting requirements for which a claim of confidentiality is made is 

safeguarded according to agency policies set forth in 40 CFR part 2, subpart B. 

Although EPA cannot determine at this time how many affected EGU respondents will 

submit information under the federal plan, EPA has estimated an “upper bound” burden estimate 

for this ICR that estimates burden should every affected EGU read and understand the rule. This 

is the only potential respondent activity that would be required under the 3-year period following 

publication of the final federal plan, so there are no obligations to respond in this period. The 

results of this “upper bound” estimate of federal plan burden are presented below: 

Respondents/affected entities: 1,028 

Respondents’ obligation to respond: Not applicable, no responses are required during the 

period covered by the ICR. 

Estimated number of respondents: Unknown at this time, but have assumed all affected 

entities are respondents for an upper bound estimate. 

Frequency of response: None, no responses are required during the period covered by the 

ICR. 

Total estimated burden: 17,133 hours (per year). Burden is defined at 5 CFR 1320.3(b). 

Total estimated cost: $1,706,501 (per year) 

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. 

Submit your comments on the agency’s need for this information, the accuracy of the 

provided burden estimates and any suggested methods for minimizing respondent burden to the 

EPA using the docket identified at the beginning of this rule. You may also send your ICRrelated comments to OMB’s Office of Information and Regulatory Affairs via email to 

oria_submissions@omb.eop.gov, Attention: Desk Officer for the EPA. Since OMB is required to 
2-6 

make a decision concerning the ICR between 30 and 60 days after receipt, OMB must receive 

comments no later than 30 days after the date of publication in the Federal Register. The EPA 

will respond to any ICR-related comments in the final rule. 

2.3 Initial Regulatory Flexibility Analysis 

The Regulatory Flexibility Act (RFA; 5 U.S.C.§ 601 et seq.), as amended by the Small 

Business Regulatory Enforcement Fairness Act (Public Law No. 104-121), provides that 

whenever an agency is required to publish a general notice of proposed rulemaking, it must 

prepare and make available an initial regulatory flexibility analysis (IRFA), unless it certifies that 

the proposed rule, if promulgated, will not have a significant economic impact on a substantial 

number of small entities (5 U.S.C. § 605[b]). Small entities include small businesses, small 

organizations, and small governmental jurisdictions. An IRFA describes the economic impact of 

the proposed rule on small entities and any significant alternatives to the proposed rule that 

would accomplish the objectives of the rule while minimizing significant economic impacts on 

small entities. Pursuant to section 603 of the RFA, the EPA prepared an initial regulatory 

flexibility analysis (IRFA) that examines the impact of the proposed rule on small entities along 

with regulatory alternatives that could minimize that impact. 

2.3.1 Reasons why Action is Being Considered 

On August 3, 2015, the EPA finalized the Clean Power Plan EGs for existing fossil-fuel 

fired EGUs (40 CFR part 60, subpart UUUU) under authority of section 111 of the CAA. The 

Guidelines apply to existing fossil-fuel fired EGUs, i.e., those that were in operation or had 

commenced construction before January 8, 2014. States with existing EGUs subject to the 

guidelines are required to submit to the EPA by September 6, 2016, a state plan that implements 

the EGs. States may also make initial plan submittals in lieu of a complete state plan, in which 

case extensions will be granted until September 6, 2018 (40 CFR &&&).30 As discussed in 

section VI.D of the preamble, Indian Tribes may, but are not required to, submit tribal plans. 

Once the EPA finds that a state has failed to submit a plan, or disapproves a state plan,31 section 

 

30 See Section VII of the preamble for additional information on proposed changes to 40 CFR 60.27 to provide 

enhancements and flexibilities to the agency’s process for review and action on state plans and promulgation of 

federal plans. 

31 If a state has submitted a complete plan, then the EPA will go through a public notice and comment process to 

fully or partially approve or disapprove the state plan. 
2-7 

111 of the CAA and 40 CFR 60.27 require the EPA to develop, implement, and enforce a federal 

plan for existing EGUs located in that state. In addition, CAA section 301(d)(2) authorizes the 

Administrator to treat an Indian Tribe in the same manner as a state for this EGU requirement. 

See 40 CFR 49.3; see also “Indian Tribes: Air Quality Planning and Management,” hereafter 

“Tribal Authority Rule,” (63 FR 7254, February 12, 1998). As discussed in section VI.D of the 

preamble, the agency in this action is proposing a necessary or appropriate finding for the 

affected EGUs in several areas of Indian country and is proposing the federal plan for these 

affected EGUs. 

The agency believes it is appropriate to propose the federal plan at this time for any states 

that may ultimately be found to have failed to submit a plan, or had their plan disapproved by the 

EPA. For some states in this situation, the federal plan may be no more than an interim measure 

to ensure that congressionally mandated emission standards under authority of section 111 of the 

CAA are implemented until they can get an approved plan in place. Other states may choose to 

rely on the federal plan and would not need to develop their own plan. This proposal also serves 

as two proposed model trading rules which states can adopt or tailor for adoption as their state 

plan. 

2.3.2 Statement of Objectives and Legal Basis for Proposed Rules 

The EPA is proposing this rulemaking for a federal plan to implement greenhouse gas 

Emission Guidelines for existing fossil fuel-fired electric generating units (EGUs). The emission 

guidelines were proposed in June 2014 as the Carbon Pollution Emission Guidelines for Existing 

Stationary Sources: Electric Utility Generating Units (79 FR 34830; the Clean Power Plan). This 

plan is part of the President’s Climate Action Plan announced in June of 2013 to reduce carbon 

emissions from the power sector by 30 percent below 2005 levels. This federal plan serves to: 1) 

provide a model rule that states can tailor for implementation, and 2) set in place a plan that EPA 

can implement for states that do not develop an approvable state plan. The EPA sees this federal 

plan as an interim measure to ensure that congressionally mandated emission standards under 

authority of section 111 of the CAA are implemented until states assume their role as the 

preferred implementers of the emission guidelines. 

The final Clean Power Plan Emission Guidelines are related to but separate from the 

proposed federal plan. The final Emission Guidelines will detail the carbon dioxide (CO2) 
2-8 

reduction goals for sources by state. The purpose of the proposed federal plan is to lay out 

mechanisms to achieve reductions in CO2 emissions from affected EGUs that are not covered by 

an EPA-approved state plan. The EPA is considering a range of options and approaches through 

which affected EGUs would meet a rate-based goal or a mass-based equivalent. The EPA intends 

to incorporate flexibility to the extent possible into the proposed federal plan so affected units 

can achieve these reductions in a cost-effective way. 

2.3.3 Description and Estimate of Affected Small Entities 

EPA conducted this regulatory flexibility analysis at the ultimate (i.e., highest) level of 

ownership, evaluating parent entities with the largest share of ownership in at least one 

potentially-affected EGU included in EPA’s Base Case using the Integrated Planning Model 

(IPM) v.5.15, used in this RIA.32 This analysis draws on the “parsed” unit-level estimates using 

IPM results for 2030, as well as ownership, employment, and financial information for the 

potentially affected small entities drawn from other resources described in more detail below. 

EPA chose to examine potential impacts in 2030 because that is when the emission performance 

goals are required to be fully achieved. Also, as presented in this RIA, 2030 is the year where the 

estimated annual compliance costs for the contiguous U.S. are at their highest.33 

This action proposes a federal plan under section 111(d) of the CAA for the control of 

CO2, a greenhouse gas pollutant, from certain large emitting fossil-fuel fired power plants, in the 

event that some states do not adopt their own plans. Specifically, the EPA is proposing 

approaches in the form of mass- and rate-based trading options that provide flexibility in 

implementing emission standards for a state’s affected EGUs. Both proposed approaches to the 

federal plan would require affected EGUs to meet emission standards set using the CO2 emission 

performance rates in the emission guidelines. The federal plan will achieve the same levels of 

emissions performance as required of state plans under the emission guidelines. 

However, at the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan or adopt a model rule. Because of this lack of information, 

for this RIA, the EPA has chosen to examine two federal plan approach scenarios where all 

 

32 See 1.4.1 of this RIA for more detail on the IPM base case used for this analysis. Detailed documentation for IPM 

v.5.15 is available at: http://www.epa.gov/powersectormodeling. 

33 See Section 1.5.2 of this RIA. 
2-9 

states of the contiguous U.S. will be regulated under a federal plan or a model rule. The first 

federal plan approach we examine in this RIA assumes all states in the contiguous U.S. are 

regulated under a rate-based federal plan or model rule. The second federal plan approach we 

examine assumes all contiguous states are regulated under a mass-based federal plan or model 

rule. We use these scenarios to inform this IRFA. 

As with the analysis in this RIA, the IRFA proceeds by examining potential costs to small 

entities under both the rate-based and mass-based approach, again under the strong assumption 

that all affected EGUs are regulated under a federal plan. The parsed unit-level estimates used in 

this IRFA are consistent with the analysis presented elsewhere in this RIA. These 2030 year IPM 

files can also be found in the docket for the rulemaking. 

EPA identified the size of ultimate parent entities by using the Small Business 

Administration (SBA) size threshold guidelines.34 The criteria for size determination vary by the 

organization/operation category of the ultimate parent entity, as follows: 

• Privately-owned (non-government) entities (see Table 2-1) 

o Privately-owned entities include investor-owned utilities, non-utility entities, and 

entities with a primary business other than electric power generation. 

o For entities with electric power generation as a primary business, small entities 

are those with less than the threshold number of employees specified by SBA for 

each of the relevant North American Industry Classification System (NAICS) 

sectors (NAICS 2211). 

o For entities with a primary business other than electric power generation, the 

relevant size criteria are based on revenue, assets, or number of employees by 

NAICS sector.35

• Publicly-owned entities 

 

34 U.S. Small Business Administration (SBA). 2014. Small Business Size Standards. Effective as of July 14, 2014. 

See: http://www.sba.gov/sites/default/files/Size_Standards_Table.pdf. 

35 Certain affected EGUs are owned by ultimate parent entities whose primary business is not electric power 

generation. 
2-10 

o Publicly-owned entities include federal, state, municipal, and other political 

subdivision entities. 

o The federal and state governments were considered to be large. Municipalities and 

other political units with population fewer than 50,000 were considered to be 

small. 

• Rural Electric Cooperatives 

o Small entities are those with fewer than the threshold level of employees or 

revenue specified by SBA for each of the relevant NAICS sectors. 

EPA examined affected EGUs included in EPA’s 2030 projections and identified the 

associated power plants. Next, we determined power plant ownership information, including the 

name of associated owning entities, ownership shares, and each entity’s type of ownership. EPA 

primarily used data from SNL and Ventyx, supplemented by limited research using publicly 

available data.36 Majority owners of power plants with affected EGUs were categorized as one of 

the seven ownership types.37 These ownership types are: 

1. Investor-Owned Utility (IOU): Investor-owned assets (e.g., a marketer, independent 

power producer, financial entity) and electric companies owned by stockholders, etc.

2. Cooperative (Co-Op): Non-profit, customer-owned electric companies that generate 

and/or distribute electric power.

3. Municipal: A municipal utility, responsible for power supply and distribution in a small 

region, such as a city.

4. Sub-division: Political subdivision utility is a county, municipality, school district, 

hospital district, or any other political subdivision that is not classified as a municipality 

under state law.

5. Private: Similar to an investor-owned utility, however, ownership shares are not openly 

traded on the stock markets.

6. State: Utility owned by the state.

 

36 SNL Financial data covers the energy market and other industries. For more information, see: www.snl.com. The 

Ventyx database consists of detailed ownership and corporate affiliation information at the EGU level. For more 

information, see: www.ventyx.com. 

37 Throughout this analysis, EPA refers to the owner with the largest ownership share as the “majority owner” even 

when the ownership share is less than 51 percent. 
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7. Federal: Utility owned by the federal government.

Required ownership information could not be determined for two committed units that 

are represented in the IPM base case modeling for this proposed rule, preventing their inclusion 

in this analysis.38

Next, EPA used the Hoover’s online database to identify the ultimate owners of power 

plant owners identified in the SNL and Ventyx databases. This was necessary, as many majority 

owners of power plants (listed in SNL or Ventyx) are themselves owned by other ultimate parent 

entities (listed in Hoover’s).39 In these cases, the ultimate parent entity was identified via 

Hoover’s, whether domestically or internationally owned. 

EPA followed SBA size standards to determine which non-government ultimate parent 

entities should be considered small entities in this analysis. These SBA size standards are 

specific to each industry, each having a threshold level of either employees, revenue, or assets 

below which an entity is considered small. SBA guidelines list all industries, along with their 

associated NAICS code and SBA size standard. Therefore, it was necessary to identify the 

specific NAICS code associated with each ultimate parent entity in order to understand the 

appropriate size standard to apply. Data from Hoover’s was used to identify the NAICS codes for 

most of the ultimate parent entities.40 In many cases, an entity that is a majority owner of a power 

plant is itself owned by an ultimate parent entity with a primary business other than electric 

power generation. Therefore, it was necessary to consider SBA entity size guidelines for the 

range of NAICS codes listed in Table 2-1. This table represents the range of NAICS codes and 

areas of primary business of ultimate parent entities which are majority owners of potentially 

affected EGUs in EPA’s IPM base case. 

 

38 The ORIS codes of these two units are 83609 and 83921. Without knowledge of entity type and size, it was not 

possible to accurately estimate revenue or costs impacts. An ORIS code is an identifying number assigned by the 

U.S. Energy Information Administration to power plants owned by utilities. 

39 The Hoover’s Inc. online platform includes company records that can contain NAICS codes, number of 

employees, revenues, and assets. For more information, see: http://www.hoovers.com. 

40 In the case of two entities, NAICS codes could not be located in Hoover’s, so publicly available information was 

used to determine the primary area of business for the ultimate parent entities. 
2-12 

Table 2-1. SBA Size Standards by NAICS Code 

Notes: 1) Based on size standards effective at the time EPA conducted this analysis (SBA size standards, effective 

July 14, 2014) 2) Small business size standards are not established for the Public Administration industry (NAICS 

code 921110). It is assumed that a comparable NAICS private sector industry is Fossil Fuel Electric Power 

Generation (NAICS code 221112). Therefore, for this analysis, the NAICS code 921110 is assumed to have a size 

standard of 750 employees. 

Source: SBA, 2014 

NAICS 

Code NAICS Description SBA Size Standard

211111 Crude Petroleum and Natural Gas Extraction 500 employees

211112 Natural Gas Liquid Extraction 500 employees

212111 Bituminous Coal and Lignite Surface Mining 500 employees

212221 Gold Ore Mining 500 employees

213112 Support Activities for Oil and Gas Operations $38.5 million in revenue

221111 Hydroelectric Power Generation 500 employees

221112 Fossil Fuel Electric Power Generation 750 employees

221113 Nuclear Electric Power Generation 750 employees

221118 Other Electric Power Generation 250 employees

221121 Electric Bulk Power Transmission and Control 500 employees

221122 Electric Power Distribution 1,000 employees

221210 Natural Gas Distribution 500 employees

238210 Electrical Contractors and Other Wiring Installation Contractors $15 million in revenue

238290 Other Building Equipment Contractors $15 million in revenue

324110 Petroleum Refineries 1,500 employees

325120 Industrial Gas Manufacturing 1,000 employees

325211 Plastics Material and Resin Manufacturing 750 employees

325320 Pesticide and Other Agricultural Chemical Manufacturing 500 employees

331110 Iron and Steel Mills and Ferroalloy Manufacturing 1,000 employees

331313 Alumina Refining and Primary Aluminum Production 1,000 employees

333613 Mechanical Power Transmission Equipment Manufacturing 500 employees

333999 All Other Miscellaneous General Purpose Machinery Manufacturing 500 employees

335312 Motor and Generator Manufacturing 1,000 employees

335999 All Other Miscellaneous Electrical Equipment and Component Manufacturing 500 employees

423610 Electrical Apparatus and Equipment, Wiring Supplies, and Related Equipment Merchant 

Wholesalers 100 employees

424720 Petroleum and Petroleum Products Merchant Wholesalers (except Bulk Stations and Terminals) 100 employees

454310 Fuel Dealers 50 employees

486210 Pipeline Transportation of Natural Gas $27.5 million in revenue

522110 Commercial Banking $550 million in assets

522220 Sales Financing $38.5 million in revenue

522320 Financial Transactions Processing, Reserve, and Clearinghouse Activities $38.5 million in revenue

523120 Securities Brokerage $38.5 million in revenue

523910 Miscellaneous Intermediation $38.5 million in revenue

523920 Portfolio Management $38.5 million in revenue

523930 Investment Advice $38.5 million in revenue

524113 Direct Life Insurance Carriers $38.5 million in revenue

524126 Direct Property and Casualty Insurance Carriers 1,500 employees

524210 Insurance Agencies and Brokerages $7.5 million in revenue

525110 Pension Funds $32.5 million in revenue

525120 Health and Welfare Funds $32.5 million in revenue

525990 Other Financial Vehicles $32.5 million in revenue

541611 Administrative Management and General Management Consulting Services $15 million in revenue

551112 Offices of Other Holding Companies $20.5 million in revenue

561110 Office Administrative Services $7.5 million in revenue

813910 Business Associations $7.5 million in revenue

921110 Public Administration 750 employees
2-13 

EPA compared the relevant entity size criterion for each ultimate parent entity to the SBA 

threshold value noted in Table 2-1. We used the following data sources and methodology to 

estimate the relevant size criterion values for each ultimate parent entity: 

1. Employment, Revenue, and Assets: EPA used the Hoover’s database as the primary 

source for information on ultimate parent entity employee numbers, revenue, and assets.41

In parallel, EPA also considered estimated revenues from affected EGUs based on 

analysis of parsed-file estimates for 2030.42 EPA assumed that the ultimate parent entity 

revenue was the larger of the two revenue estimates. In limited instances, supplemental 

research was also conducted to estimate an ultimate parent entity’s number of employees, 

revenue, or assets. 

2. Population: Municipal entities are defined as small if they serve populations of less than 

50,000. EPA primarily relied on data from the Ventyx database and the U.S. Census 

Bureau to inform this determination. Supplemental research of individual municipalities 

was also conducted in some instances. 

Ultimate parent entities for which the relevant measure is less than the SBA size criterion 

were identified as small entities and carried forward in this analysis. In the case of six entities, 

data limitations prevented the comparison of entities against their appropriate SBA size 

standards. For the purposes of this analysis, EPA assumed that these six entities are small 

entities.43

EPA identified 223 potentially affected EGUs owned by 74 small entities included in 

EPA’s 2030 projections. Fifty-nine of these potentially affected EGUs are projected to no longer 

be operating by 2030 in the Base Case of EPA’s version of IPM v.5.15.44 Twenty-four small 

 

41 Estimates of sales were used in lieu of revenue estimates when revenue data was unavailable. 

42 The methodology for the analysis of IPM results is detailed later in this IRFA. 

43 Generation from potentially affected EGUs owned by these six entities represents less than two percent of total 

generation from potentially affected EGUs owned by small entities under EPA’s base case projections. 

44 Detailed documentation for IPM v.5.15 is available at: http://www.epa.gov/powersectormodeling. 
2-14 

entities are projected to have all of their potentially affected EGUs cease operation by 2030 in 

this Base Case. 

2.3.4 Compliance Cost Impact Estimates 

2.3.4.1 Methodology for Estimating Impacts on Small Entities 

This section presents the methodology used in this analysis for estimating the compliance 

costs of this proposed rule for small entities. For the purposes of this IRFA, EPA estimated net 

compliance costs for individual EGUs of the proposed rule using the following equation: 

Cnet compliance cost = ∆ Coperating + annualized capital + ∆ Cfuel + ∆ Cdemand-side energy efficiency + ∆ R 

where C represents the components of cost as labeled, R represents revenue, and ∆ indicates the 

calculation of difference between the base case and the federal plan approach under examination. 

The specific meaning of these variables is discussed below. 

This approach to estimate net compliance costs is consistent with previous proposed 

power sector regulations that required IRFAs, such as the proposed Mercury and Air Toxics 

Rule.45 However, there is an additional component in the net compliance cost equation: the 

change in the program costs of demand-side energy efficiency programs. Investment in demandside energy efficiency results in lower electricity demand, and consequently fewer emissions as 

production is reduced to meet the lower demand, an important emission-reduction strategy 

modelled in the rate-based and mass-based federal plan approaches. 

Because this analysis evaluates the net compliance costs as a sum of the costs changes 

associated with compliance choices as well as changes in electricity revenues, it captures 

potential net compliance cost increases or decreases. For example, if under the proposed rule 

entities increase revenue more than costs, the net compliance costs will be negative. As a result, 

the approach used here to estimate net compliance costs is well-equipped to evaluate the 

potential distributional consequences of the proposed regulation. 

For this analysis, EPA used the parsed unit-level estimates mentioned before to estimate 

three of the four components of the net compliance cost equation above: the change in operating 

 

45 U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis of the Proposed Toxics 

Rule: Final Report. Office of Air Quality Planning and Standards, Health and Environmental Impacts Division, 

Research Triangle Park, NC. Available at: http://www.epa.gov/ttnecas1/regdata/RIAs/ToxicsRuleRIA.pdf. 
2-15 

and annualized capital costs, the change in fuel costs, and the change in revenue, where all 

changes are estimated as the difference between the base case and federal plan scenario. These 

impacts were then summed for each small entity, adjusting for ownership share.46 As described 

momentarily, additional analysis was performed to estimate the change in costs of demand-side 

energy efficiency that factors in IPM-projected outputs but is not directly an output of the model. 

These individual components of compliance cost were estimated as follows: 

1. Operating and capital costs: Using the IPM parsed estimates for the base case and the 

rate-based and mass-based federal plan approaches, EPA evaluated changes in operating 

and capital costs at the EGU level. The equations for calculating operating and capital 

costs were adopted from technology assumptions used in EPA’s version of IPM version 

5.15. The model calculates the capital cost (in $/MW); the fixed operation and 

maintenance (O&M) cost (in $/MW-year); and the variable O&M cost (in $/MWh). 

2. Fuel costs: Using the IPM parsed estimates for the base case and the rate-based and 

mass-based federal plan approaches, EPA evaluated projected changes in fuel cost at the 

EGU level. These projected fuel costs are based on estimated EGU-level fuel input (in 

million British thermal units, MMBtu) and delivered fuel prices ($/MMBtu). 

3. Demand-side energy efficiency program costs: Demand-side energy efficiency 

program costs are estimated and allocated to affected EGUs outside of IPM in this 

analysis. For this analysis, we assumed that IOUs, Co-Ops, Municipals, and SubDivisions are utilities that receive revenues on the basis of retail electricity rates. Retail 

electricity in this and related EPA analyses contain an energy efficiency surcharge. The 

surcharge reflects the standard mechanism by which utilities collect revenue from their 

customers to pay for energy efficiency programs. Such surcharges are approved for 

inclusion in rates by state utility commission for IOUs or the equivalent authority (e.g., 

municipal or cooperative utility board of directors) for other utility types. To be 

consistent, EPA assumes that these utilities will incur an energy efficiency surcharge as a 

cost in this analysis. The demand-side energy efficiency surcharge is state specific, being 

 

46 Unit-level cost impacts are adjusted for ownership shares for individual small entities, so as not to overestimate 

burden on each entity. 
2-16 

the estimated state demand-side energy efficiency program costs47 divided by projected 

total state sales. The cost in this analysis is the surcharge multiplied by projected sales 

from affected EGUs.48 In contrast, entities of the type Private are not assessed demandside energy efficiency program costs in this analysis.49 This distinction is made because 

EPA assumes that Private entities own non-utility EGUs that will earn wholesale 

electricity rates. Wholesale electricity rates do not include a demand-side energy 

efficiency surcharge in this or related EPA analyses.

4. Revenues: EPA estimated the value of electricity generated by multiplying the projected 

electricity generation from EPA’s IPM modeling results with the regional retail 

electricity price estimates ($/MWh), for all entities except those categorized as Private in 

Ventyx. For private entities, EPA used projected wholesale electricity price instead of 

retail electricity price estimates because most of the private entities are independent 

power producers (IPP). Since IPPs sell their electricity to wholesale purchasers and do 

not own transmission facilities, their revenue was estimated with wholesale electricity 

prices. 

2.3.4.2 Results 

This section presents the estimated net compliance cost impacts of the proposed rule on 

small entities in 2030 based on the following endpoints: 

• net compliance costs estimated for the proposed rule for potentially affected small 

entities, and 

 

47 In practice, the costs of demand-side energy efficiency programs include the costs to the utilities that are funding 

the programs (known as the program costs) and the additional cost to the end-user purchasing a more energy 

efficient technology (known as the participant costs). Based upon a literature review, the analysis supporting this 

proposed rule and the Clean Power Plan Final Rule, total costs are assumed to be divided evenly, 50 percent each, 

between program costs and participant costs. This IRFA includes only the program costs expected to be incurred 

by utilities. For more detail on how the demand-side energy efficiency costs are estimated, see U.S. EPA. 2015. 

Technical Support Document (TSD) the Final Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units. Demand-Side Energy Efficiency. 

48 For these entity types (i.e., IOUs, Co-Ops, Municipals, and Sub-Divisions), projected sales is estimated to be 7.5 

percent less than generation. This 7.5 percent reduction is added to account for estimated transmission losses. 

49 Note that in this context, “Private” is one of seven distinct ownership types introduced earlier in this chapter. 
2-17 

• the ratio of small entity compliance cost impacts to revenues from electricity generation 

at affected EGUs 

It is worth noting again that the results in this section are based on the assumption made 

for this analysis that all affected EGUs owned by small entities are subject to this proposed rule. 

EPA chose to examine this scenario because, at the time of this proposal, the EPA has no 

information on whether any or how many states will require a federal plan. 

The number of affected small entities by ownership type and the potential impact of the 

federal plan approaches are summarized in Tables 2-2 through 2-5. These tables are specific to 

either the rate-based federal plan approach (i.e., rate-based), or mass-based federal plan approach 

(i.e., mass-based). All costs are presented in 2011 dollars. 

EPA estimated the annualized net compliance cost to potentially affected small entities in 

2030 to be approximately $364 million under the rate-based approach, and $404 million under 

the mass-based approach. Results for small entities discussed here do not fully account for the 

reality that electricity markets are regulated in parts of the country. Entities operating in 

regulated or cost-of-service markets are likely able to recover compliance costs through rate 

adjustments; as a result these costs can be viewed as likely being over-estimates for this set of 

utilities.50

 

50This is similarly discussed in previous EPA analyses. For example, see section 7.4.5.2 within the Regulatory 

Impact Analysis for the Final Mercury and Air Toxics Standards. Available at: 

http://www.epa.gov/ttnecas1/regdata/RIAs/matsriafinal.pdf. 
2-18 

Table 2-2. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Rate-Based Federal Plan Approach in 2030 

EGU 

Ownership 

Type 

Number of 

Potentially 

Affected Entities 

Number of Entities 

Projected to Withdraw all 

Affected Units in Base Case 

Additional Entities Projected 

to Withdraw all Affected Units 

under Rate-Based Approach 

Co-Op 17 3 1 

IOU 8 3 1 

Municipal 24 13 1 

Private 19 5 2 

Sub-Division 6 0 2 

Grand Total 74 24 7 

Notes: 1) The number of potentially affected entities reflects those with affected EGUs that are modeled within IPM 

in 2030. 2) In this context, the term withdraw signifies that EGUs are represented in the 2030 IPM results but do not 

generate electricity. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

Table 2-3. Projected Impact on Small Entities in 2030 under Rate-Based Federal Plan 

Approach 

EGU 

Ownership 

Type

Total Net 

Compliance Costs 

(2011$ millions) 

Number of Small Entities 

with Net Compliance Costs 

> 1% of Generation 

Revenues 

Number of Small Entities 

with Net Compliance Costs 

> 3% of Generation 

Revenues 

Co-Op 109 8 3 

IOU 186 4 4 

Municipal 17 7 5 

Private 34 11 9 

Sub-Division 18 6 2 

Grand Total 364 36 23 

Notes: 1) The total number of entities with costs greater than 1 or 3 percent of revenues includes only entities 

experiencing positive net compliance costs. 2) Costs are compared to generation revenues from affected EGUs, and 

do not consider additional revenues some entities may earn from other sources. 3) Nine small entities are estimated 

to have net compliance cost savings greater than 3 percent of generation revenues from affected sources. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 
2-19 

Table 2-4. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Mass-Based Federal Plan Approach in 2030 

EGU 

Ownership 

Type 

Number of 

Potentially 

Affected Entities 

Number of Entities 

Projected to Withdraw all 

Affected Units in Base Case 

Additional Entities Projected 

to Withdraw all Affected 

Units under Mass-Based 

Approach 

Co-Op 17 3 1 

IOU 8 3 1 

Municipal 24 13 1 

Private 19 5 2 

Sub-Division 6 0 0 

Grand Total 74 24 5 

Notes: 1) The number of potentially affected entities reflects those with affected EGUs that are modeled within IPM 

in 2030. 2) In this context, the term withdraw signifies that EGUs are represented in the 2030 IPM results but do not 

generate electricity. 

Source: U.S. EPA analysis, based on IPM modeling results. 

Table 2-5. Projected Impact on Small Entities in 2030 under Mass-Based Federal Plan 

Approach 

EGU 

Ownership 

Type 

Total Net 

Compliance Costs 

(2011$ millions) 

Number of Small Entities 

with Net Compliance Costs 

> 1% of Generation 

Revenues 

Number of Small Entities 

with Net Compliance Costs 

> 3% of Generation 

Revenues 

Co-Op 133 10 4 

IOU 179 3 3 

Municipal 50 5 5 

Private 36 8 7 

Sub-Division 7 4 2 

Grand Total 404 30 21 

Notes: 1) The total number of entities with costs greater than 1 or 3 percent of revenues includes only entities 

experiencing positive net compliance costs. 2) Costs are compared to generation revenues from affected EGUs, and 

do not consider additional revenues some entities may earn from other sources. 3) Eleven small entities are 

estimated to have net compliance cost savings greater than 3 percent of generation revenues from affected sources. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

As noted earlier, there are 74 small entities with potentially affected EGUs that are 

modeled in the IPM base case in 2030. Of these, 24 small entities are projected to withdraw all of 

their potentially affected EGUs from operation under base case conditions. This leaves 50 small 

entities with potentially affected EGUs that are projected to be generating electricity in 2030. 

Under the rate-based federal plan approach, 7 of these 50 small entities are projected to withdraw 

all of their potentially affected EGUs from operation by 2030. Under the mass-based federal plan 
2-20 

approach, 5 of these 50 small entities are projected withdraw all of their potentially affected 

EGUs from operation by 2030. 

Under the rate-based federal plan approach, 23 small entities are projected to incur net 

compliance costs greater than 3 percent of generation revenues from their potentially affected 

EGUs. In contrast, 9 entities are estimated to have net compliance cost savings greater than 3 

percent of their generation revenues from affected EGUs. Under the mass-based federal plan 

approach, 21 small entities are projected to incur net compliance costs greater than 3 percent of 

generation revenues from their potentially affected EGUs. In contrast, 11 entities are estimated to 

have net compliance cost savings greater than 3 percent of generation revenues from their 

affected EGUs. 

The separate components of the net compliance costs for small entities under the 

proposed rule are summarized in Table 2-6 and Table 2-7. 

Table 2-6. Incremental Costs in 2030 under the Rate-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) 

EGU 

Ownership 

Type 

Capital + 

Operating + Fuel 

Costs ($MM) 

Energy Efficiency 

Program Costs 

($MM) 

Change in 

Electricity 

Revenue ($MM) 

Total Net 

Compliance 

Costs 

 A B C =A+B-C 

Co-Op (79) 87 (102) 109 

IOU 78 93 (15) 186 

Municipal (26) 25 (19) 17 

Private (7) 0 (40) 34 

Sub-Division (68) 16 (70) 18 

Grand Total (102) 221 (246) 364 

Note: Totals may not add due to rounding. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 
2-21 

Table 2-7. Incremental Costs in 2030 under the Mass-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) 

EGU 

Ownership 

Type 

Capital + 

Operating + Fuel 

Costs ($MM) 

Energy Efficiency 

Program Costs 

($MM) 

Change in 

Electricity 

Revenue ($MM) 

Total Net 

Compliance 

Costs 

 A B C =A+B-C 

Co-Op (178) 84 (228) 133 

IOU (17) 91 (104) 179 

Municipal (64) 23 (91) 50 

Private (2) 0 (38) 36 

Sub-Division (38) 18 (27) 7 

Grand Total (299) 215 (488) 404 

Note: Totals may not add due to rounding. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

The change in electricity revenue under the federal plan approaches take into account 

both the profit lost from units that do not operate and the difference in revenue for operating 

units. The cost of withdrawing a unit as uneconomic is estimated as the base case profit that is 

foregone by not operating under a federal plan approach. One of the primary drivers of the cost 

impacts is the reduced revenue due to decreased electricity sales related to the modeled 

implementation of demand-side energy efficiency measures. The EPA solicits comment on: 1) 

whether it is likely that small entities would consider demand-side strategies as they responded to 

a federal plan, 2) the appropriateness of considering the demand-side strategies in the analysis, 

and 3) if demand-side energy efficiency measures are considered in the final analysis, whether it 

is appropriate to consider them as a cost for a municipality or city-owned utility, as this reduced 

revenue will translate to direct cost savings for members of the community served by the 

affected units. 

There are uncertainties and limitations in this analysis that may result in estimates that 

diverge from what we might see in reality. Some of these have already been noted. Below is a 

listing of important considerations when interpreting this analysis. 

• At the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan. The rate-based and mass-based federal 

plan approaches analyzed in this IRFA are based on a scenario where all states of 

the contiguous U.S. will be regulated under a federal plan. 
2-22 

• Results for small entities discussed here do not fully account for the reality that 

electricity markets are regulated in parts of the country. Entities operating in 

regulated or cost-of-service markets are likely able to recover compliance costs 

through rate adjustments; as a result these costs can be viewed as likely being 

over-estimates for this set of utilities. 

• Small entities owning NGCC EGUs operating in competitive markets may be able 

to recover compliance costs if steam EGUs are setting the marginal price. 

• EPA has not factored in consideration of allowances that would be distributed to 

affected entities nor revenue that could be generated from the sale of ERCs in its 

analysis. EPA takes comment on how these factors should be considered in the 

final analysis. 

• In this analysis, estimated state demand-side energy efficiency program costs are 

allocated to utility EGUs owned by IOUs, Co-Ops, Municipals, and SubDivisions based on the share of forecasted total state electricity sales that they are 

projected to provide. To the extent that this differs in practice, associated costs 

incurred by small entities may be over- or under-estimated. 

• To the extent that the EGU owner information used is not reflective of reality, the 

number of small entities may be over- or under-estimated. 

• To the extent that the entity-level ownership information (i.e., NAICS code, 

number of employees, revenues, and assets) are not reflective of reality, the 

number of small entities may be over- or under-estimated. 

2.3.5 Projected Reporting, Recordkeeping and Other Compliance Requirements 

The reporting, recordkeeping and other compliance requirements are most likely covered 

under Part 75 and Part 98 programs for affected EGUs. Therefore, only a marginal additional 

cost is expected for the monitoring, reporting and recordkeeping requirements of the proposed 

federal plan for affected EGUs. 
2-23 

2.3.6 Related Federal Rules 

On September 20, 2013, EPA proposed carbon pollution standards for new fossil fuel 

fired EGUs. On June 2, 2014, the EPA, proposed carbon pollution standards for modified and 

reconstructed fossil fuel fired EGUs, in addition to the Clean Power Plan EGs, to cut carbon 

pollution from existing fossil fuel fired EGUs. These existing EGUs are, or will be, potentially 

impacted by several other recently finalized EPA rules. On February 16, 2012, the EPA issued 

the mercury and air toxics standards (MATS) rule (77 FR 9304) to reduce emissions of toxic air 

pollutants from new and existing coal- and oil-fired EGUs. On May 19, 2014, the EPA issued a 

final rule under section 316(b) of the Clean Water Act (33 U.S.C. 1326(b)). This rule establishes 

new standards to reduce injury and death of fish and other aquatic life caused by cooling water 

intake structures at existing power plants and manufacturing facilities. On June 18, 2014 (79 FR 

34830), the EPA promulgated the stream electric effluent limitation guidelines (SE ELG) rule to 

strengthen the controls on discharges from certain steam electric power plants. On April 17, 2015 

(80 FR 21302), the EPA promulgated the coal combustion residuals (CCR) rule, which 

establishes technical requirements for CCR landfills and surface impoundments under subtitle D 

of the Resource Conservation and Recovery Act (RCRA), the nation's primary law for regulating 

solid waste. 

2.3.7 Regulatory Flexibility Alternatives 

2.3.7.1 Panel Process 

Small Entity Representatives (SERs) commented on their perceptions of the adequacy of 

the SBREFA panel process for the section 111(d) federal plan. Under the statute, EPA provides 

“information on the potential impacts of the proposed rule on small entities and the type of small 

entities that might be affected.” § 609(b)(1). Then SERs are selected, and the Panel collects 

“advice and recommendations” from each SER. § 609(b)(4). The Panel reviews the SERs’ 

comments, and “any material the agency has prepared in connection with [the RFA],” and 

“report[s] on the comments of the [SERs] and its findings as to issues related to” preparation of 

an IRFA. § 609(b)(5). EPA solicited SERs comments during the course of, and after holding 

three outreach meetings. The Agency provided information to the SERs on two primary 

regulatory alternatives for the federal plan – a rate-based trading program and a mass-based 

trading program. The Agency identified specific areas under both of these alternatives where it 
2-24 

was still in the decision making process and open to recommendations. This information forms 

the basis for consideration of issues and additional regulatory options important to these small 

entities. 

Advocacy shares many of the concerns raised by the SERs (see attached letter from 

Acting Chief Counsel Claudia Rodgers to EPA Administrator Gina McCarthy). While Advocacy 

endorses the Panel recommendations, Advocacy agrees that the SERs did not have sufficient 

information to inform advice and recommendations about specific regulatory alternatives and 

flexibilities. In Advocacy’s view, this is reflected in Panel recommendations that advise EPA to 

consider issues raised by the SERs rather than to propose or consider regulatory alternatives. 

Advocacy regrets that the Panel is not able to make more specific recommendations for 

flexibilities to minimize the impacts on small entities. 

While not all members of the Panel agree with all of these concerns, the concerns of the 

SERs regarding the Panel process have been noted. Nonetheless, EPA is committed to ensuring 

that it meets the requirements of the RFA and will, to the maximum extent practicable, fully 

consider the advice and recommendations of representatives of small entities in the development 

of the proposed rule. The EPA intends to continue working on issues regarding small businesses, 

and consider appropriate flexibilities, throughout this rulemaking process. 

2.3.7.2 Remaining Useful Life 

SERs commented that EPA needed to account for remaining useful life of EGUs. 

Multiple comments addressed challenges that EPA must face in satisfying the statutory mandate 

that “in applying a standard of performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other factors, the remaining useful life of 

the existing sources to which such standard applies.” SERs are concerned that EPA will develop 

EGs under section 111(d) in a manner that either prohibits plans from providing this 

consideration or only providing for plans to “make these adjustments at the expense of other 

sources.” AEPCO comments that it has obligations under the Rural Electrification Act to operate 

under an 80-year mandate. SBA recommends EPA propose allowing for guaranteed amount of 

run-time for small entities to allow them to recoup investment. EPA believes “remaining useful 

life” is a concern directed toward plants with short remaining lives, but recognizes that there are 

concerns about economic viability of some marginal plants. 
2-25 

The Panel recommends that EPA clearly explain how it took into consideration remaining 

useful life and take comment on other ways of defining the remaining useful life consideration. 

The Panel also recommends proposing or considering economic incentives for compliance that 

could avoid early retirement or reduce the financial effects of early retirements. For instance, the 

EPA could propose continuing allocations for a set number of years to units that retire in order to 

alleviate the financial effects of the retirement. EPA should request comment on how long such 

allocations should continue. The EPA should also consider whether there are parallel 

mechanisms in a rate-based proposal that could provide similar regulatory relief or benefits for 

small entities, if appropriate. 

2.3.7.3 Design of the Compliance System 

The panel requested SER input on a number of aspects of the federal plan design, based 

on EPA’s presentation of federal plan options. SER comments ranged quite broadly. Comments 

included: 1) differing opinions within SERs on favor of rate- vs mass-based approaches, 2) 

emphasis on market liquidity in a program, 3) support for types of allocation methodologies (in a 

mass-based allowance system), 4) encouragement for early action crediting, 5) increased 

averaging and compliance times to help small entities, and 6) whether and how to consider the 

effects of credit/allowance banking, borrowing, and shelf-life on market liquidity. In some 

instances, no general consensus emerged. The Panel notes the following specific areas where it is 

making a recommendation. 

Mass-based or rate-based trading 

Various SERs favored one system over the other, and some suggested that each 

individual small entity should be able to choose the system under which they would comply. 

However, it is unclear to what extent SERs would favor such choice at the expense of a broader 

trading pool. The panel, however, notes that the idea of individual companies within a state 

choosing which system to comply would significantly limit the opportunity for intra- or interstate trading and would therefore not be consistent with other recommendations. The Panel 

recommends that EPA take comment on which approach (mass or rate) is preferable. In the 

interests of maximizing liquidity across all federal plan states, the Panel recommends that EPA 

should propose to finalize a single approach for all federal plans. 
2-26 

Allocations and credit issuance/early action 

SERs expressed a variety of views on the appropriate method of allocating allowances 

under a mass-based system or credits under a rate-based system. Some preferred allowing states 

to make these decisions. Some wanted allocations to account for early action and energy 

efficiency efforts. The Panel agrees that EPA should take comment on the use of allocations to 

minimize the impact of the federal plan on small entities. The Panel notes that the early incentive 

pool that is part of the EGs does provide credit for early action, but the SERs did not have an 

opportunity to respond to this flexibility. The panel recommends that in the federal plan the EPA 

allow credit for early action and energy efficiency efforts to the extent it is allowed under the 

guidelines. 

Non-generating party participation and market liquidity 

SERs generally supported developing a system that would ensure a sufficient supply of 

credits be available on the open market and available for free trade to ensure that they would not 

be disadvantaged by large utilities withholding excess credits generated by renewable energy in 

their portfolio. However, some SERs also expressed the need to be able to generate and use 

credits internally (particularly those with generation across multiple states) (i.e., a portfolio 

approach). Some SERs endorsed allowing non-generating parties to create and sell credits or 

allowances. Other SERs warned that third parties should not be allowed to purchase credits or 

allowances for the purpose of retiring them without offsetting GHG emissions from electricity 

generation. The Panel recommends that the EPA ensure a liquid market in compliance 

instruments, through consideration, request or comment, or proposal of several of options, 

including: allocation methods or rules that could impact liquidity, mechanisms to place 

allowances or credits into the market relatively early, requirements for public transparency of 

information related to allowance or credit issuance, tracking, transfers, and holdings, and 

whether and to what extent oversight authority exists related to measures to ensure liquid 

markets Additionally, the Panel recommends that EPA solicit comment on other approaches to 

ensure liquidity, including but not limited to the concept of an early incentive pool which would 

serve to incentivize early reductions and create a market of additional allowances. 
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2.3.7.4 Renewable Energy and Energy Efficiency 

Generally SERs encouraged EPA to incorporate existing EE efforts into the program in a 

way that gives credit for the investment and to rely on “deemed” energy savings to earn 

compliance credits. SERs raised concerns about the accounting of investments in RE and EE 

efforts in their compliance with GHG emission standards. 

SERs also expressed concern that they be able to generate and use credits across state 

lines. This is particularly important for the investment in renewables, for which the generating 

potential is highly dependent on geography and is unequally distributed among the states. Thus, 

the Panel recommends that EPA develop a credit or allowance compliance program that allows 

for interstate accounting and trading for states under the federal plan. Additionally, the Panel 

recommends that the program include opportunities for interstate trading between sources in 

states under the federal plan and states under compatible state plans. 

The Panel recommends that EPA consider the treatment of RE and EE in rate-based and 

mass-based federal plan contexts. EPA should further consider how to implement preferred 

policy options in a way that incentivizes investment and does not create unintended barriers for 

small entities. The Panel also recommends that EPA allow crediting of RE across states under 

the federal plan while soliciting comment for allowing crediting for EE across states under the 

federal plan. 

2.3.7.5 Reliability 

Multiple SERs expressed concerns that implementation of the EGs, either by states or 

through a federal plan, could have a negative impact on reliability because individual units could 

have operational obligations that conflict with the emissions requirements. In their comments, 

both the American Public Power Association (APPA) and the National Rural Electric 

Cooperative Association (NRECA) recommend Dynamic Reliability Safety Valve. EPA noted 

that the use of a reliability mechanism in the EGs is provisioned on the concern that some forms 

of state plan may create inflexible requirements that could in some limited circumstances raise a 

reliability concern. However, EPA believes the design of the federal plan as a flexible trading 

program alleviates these concerns and therefore a reliability mechanism is not needed. 
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The Panel recognizes the connection between meeting the GHG reduction goals of the 

federal plan and maintaining the reliability of the electric grid. The Panel recommends that EPA 

fully explain in the proposal and take comment on methods to address reliability and EPA should 

take comment on establishing a reliability safety valve, and whether there is a need for regulatory 

flexibility for reliability critical units beyond the flexibilities already built into the design of the 

federal plan. 

2.3.7.6 Subcategorization/Applicability/Exemptions 

SER comments on applicability reflect concerns related to the combined series of 

rulemakings affecting GHG emissions from electricity generating units: the NSPS, the EGs and 

the federal plan. SERs endorse excluding RICE and NGSC units from the combined 

rulemakings. One SER requests a subcategory that addresses the particular characteristics of 

lignite coal. Some SERs suggest special provisions for small units or utilities, including a small 

system exemption. The SBA suggested taking comment on an economic hardship exemption for 

small entities and that EPA propose a mechanism for additional compliance time when 

generation and transmission investments necessary for compliance have been delayed by 

government reviews. However, EPA noted that regulatory exemptions must be grounded in 

statute and supported by analysis, and EPA believes the design of the federal plan itself should 

maximize compliance options that are both consistent with the EGs and also should adequately 

address these concerns. 

The Panel notes that EPA must be consistent with the EGs on issues of applicability, 

which should address the SERs’ concerns with regard to inclusion of RICE or NGSC units. The 

Panel also notes that EPA is proposing a design to the federal plan that utilizes emission trading 

and thus maximizes compliance options such that individual units can take into account their 

particular characteristics in designing a compliance strategy. In EPA’s view, this makes it less 

likely that there is a need for further sub-categorization or the use of unit-specific exemptions. 

Additionally, the Panel recommends that EPA solicit comment on an alternative allocation 

methodology under the mass-based proposed federal plan that may increase allocations for small 

businesses, and consider whether there are parallel mechanisms in a rate-based proposal that 

could provide similar regulatory relief or benefits for small entities, if appropriate. 
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2.4 Unfunded Mandates Reform Act (UMRA) 

This action contains a federal mandate under UMRA, 2 U.S.C. 1531-1538, that could 

potentially result in expenditures of $100 million or more for state, local, and tribal governments, 

in the aggregate, or the private sector in any one year. This federal plan will apply only to those 

EGUs located in states that do not submit approvable state plans, which is a subset of the EGUs 

considered in the RIA for the final emission guidelines (EGs). Because it is impossible to 

determine at this time which states might be ultimately subject to a federal plan, EPA cannot 

determine whether this final rule will be subject to UMRA. However, as noted below, the 

Agency has done substantial outreach to government entities as part of both the federal plan and 

the related 111(d) rulemaking. Further, regardless of whether EPA does determine that this 

action ultimately meets the UMRA threshold, the agency intends to do additional outreach with 

government entities between now and the final rule. Additionally, the EPA has determined that 

this action is not subject to the requirements of section 203 of UMRA because it contains no 

regulatory requirements that might significantly or uniquely affect small governments. 

Nevertheless, the EPA is aware that there is substantial interest in this rule among small 

entities (e.g., municipal and rural electric cooperatives). In light of this interest, prior to this 

action, the EPA sought early input from representatives of small entities while formulating the 

provisions of the proposed regulation. Such outreach is also consistent with the President’s 

January 18, 2011 Memorandum on Regulatory Flexibility, Small Business, and Job Creation, 

which emphasizes the important role small businesses play in the American economy. This 

outreach process has enabled the EPA to hear directly from these representatives, as EPA 

developed the rule about how the EPA should approach the complex question of how to apply 

section 111 of the CAA to the regulation of GHGs from these source categories. We invite 

comments on all aspects of this proposal and its impacts, including potential adverse impacts, on 

small entities. 

2.5 Executive Order 13132: Federalism 

The EPA believes that this proposed rule may be of significant interest to state and local 

governments due to its relationship with the Clean Power Plan EGs. Therefore, the EPA has 

determined that consultations with state and local governments conducted during the Clean 

Power Plan EGs development process are also relevant to this proposed rule. Consistent with the 
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EPA’s policy to promote communications between the EPA and state and local governments, the 

EPA consulted with state and local officials early in the process of developing the Clean Power 

Plan EGs to permit them to have meaningful and timely input into its development. As described 

in the Federalism discussion in the preamble to the proposed standards of performance for GHG 

emissions from new EGUs (79 FR 1501; January 8, 2014), the EPA consulted with state and 

local officials in the process of developing the proposed standards for newly constructed EGUs. 

A detailed Federalism Summary Impact Statement (FSIS) describing the most pressing issues 

raised in pre-proposal and post-proposal comments will be forthcoming with the final Clean 

Power Plan EGs, as required by section 6(b) of Executive Order 13132. In the spirit of Executive 

Order 13132, and consistent with the EPA’s policy to promote communications between the 

EPA and state and local governments, the EPA specifically solicits comment on this proposed 

action from state and local officials. 

2.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments 

 This proposed action has tribal implications. However, it will neither impose substantial 

direct compliance costs on federally recognized tribal governments, nor preempt tribal law. The 

EGU potentially impacted by this proposed rulemaking located on Indian reservations are 

primarily owned by private entities, and in one case, partially owned by an agency of the U.S. 

government. As a result, the tribes on whose areas of Indian country those units are located will 

not be directly impacted by any costs of complying with this proposed rulemaking incurred by 

the owners/operators of those units. There would only be tribal implications in regards to 

compliance costs associated with this proposed rulemaking in the case where a tribal government 

has an ownership interest in a potentially affected EGU. A tribal government could also incur 

costs in the event that it seeks and is given delegated authority to enforce the federal plan 

proposed in this rulemaking. The EPA has, nevertheless, offered consultation to the tribes on 

whose areas of Indian country the units are located. As part of its general outreach to tribes 

regarding this proposed rulemaking, the EPA received feedback from a number of tribes 

regarding the potential overall economic impact that both the proposed Clean Power Plan and a 

proposed federal plan rulemaking may have on them. In these instances, the EPA has reached out 

to these tribes and as part of the consultation on the Clean Power Plan engaged with them on 

their concerns regarding a potential federal plan. 
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The EPA has conducted consultation with tribes on the Clean Power Plan and the 

Supplemental Proposal for the Clean Power Plan and will offer all tribes consultation on this 

proposed action. The EPA held consultations with tribes on the Clean Power Plan in the fall of 

2014 before the agency issued its Supplemental Proposal for Indian Country and U.S. Territories. 

Additionally, the EPA held consultations for tribes shortly following the release of the 

supplemental proposal. The agency also held a public hearing on the supplemental proposal on 

November 19, 2014, in Phoenix, Arizona. At the public hearing the agency received oral 

comments from community members representing a number of tribes and a number of tribal 

officials. The agency also conducted consultation with tribes in the spring and summer of 2015. 

An overview of the consultations provided as part of the Clean Power Plan is available in section 

XII.F of the final EGs. 

Additionally, the EPA engaged in meaningful dialogue with tribal stakeholders to obtain 

their feedback in the pre-proposal stages of this rulemaking. We provided an update on this 

proposed rulemaking on the May 28, 2015, National Tribal Air Association and the EPA Air 

Policy call. Additionally, staff attended the National Tribal Forum conference on May 20, 2015 

and provided an overview of the Clean Power Plan and explained that the agency would be 

proposing a federal plan. 

Consistent with previous rulemakings impacting the power sector, there is significant 

tribal interest in these rulemakings because of the potential indirect impacts that rules such as the 

Clean Power Plan and this proposed federal plan may have on tribes. The EPA specifically 

solicits additional feedback from tribal officials on all aspects of this proposed rulemaking, 

including whether tribes whose areas of Indian country contain affected EGU(s) are interested in 

developing their own plan implementing the final EGs. Additionally, tribal stakeholders will be 

included in the outreach that the agency will be conducting with those communities already 

overburdened by pollution, which are often low-income communities, communities of color, and 

indigenous communities. The actions that the agency will be taking are outlined in section IX of 

the preamble. 
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2.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks 

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those 

regulatory actions that concern health or safety risks, such that the analysis required under 

section 5–501 of the Order has the potential to influence the regulation. This action is not subject 

to EO 13045 because it does not involve decisions on environmental health or safety risks that 

may disproportionately affect children. The EPA believes that the CO2 emission reductions 

resulting from implementation of the proposed guidelines, as well as substantial ozone and 

PM2.5 emission reductions as a cobenefit, would further improve children’s health. 

2.8 Executive Order 13211: Actions That Significantly Affect Energy Supply, 

Distribution, or Use 

This action, which is a significant regulatory action under EO 12866, is likely to have a 

significant effect on the supply, distribution, or use of energy. The EPA has prepared a Statement 

of Energy Effects for this action as follows. We estimate a 1 to 2 percent change in retail 

electricity prices on average across the contiguous U.S. in 2025, and a 22 to 23 percent reduction 

in coal-fired electricity generation as a result of this rule. The EPA projects that utility power 

sector delivered natural gas prices will increase by up to 2.5 percent in 2030. For more 

information on the estimated energy effects, please refer to the economic impact analysis for this 

proposal in Chapter 1 of this RIA. 

2.9 National Technology Transfer and Advancement Act (NTTAA) 

This proposed action does not involve technical standards. 

2.10 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations 

Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive 

policy on EJ. Its main provision directs federal agencies, to the greatest extent practicable and 

permitted by law, to make EJ part of their mission by identifying and addressing, as appropriate, 

disproportionately high and adverse human health or environmental effects of their programs, 

policies, and activities on minority populations and low-income populations in the U.S. The EPA 

defines EJ as the fair treatment and meaningful involvement of all people regardless of race, 

color, national origin, or income with respect to the development, implementation, and 
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enforcement of environmental laws, regulations, and policies. The EPA has this goal for all 

communities and persons across this Nation. It will be achieved when everyone enjoys the same 

degree of protection from environmental and health hazards and equal access to the decisionmaking process to have a healthy environment in which to live, learn, and work. 

Leading up to this rulemaking the EPA summarized the public health and welfare effects 

of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment Finding, the 

Administrator considered climate change risks to minority populations and low-income 

populations, finding that certain parts of the population may be especially vulnerable based on 

their characteristics or circumstances. Populations that were found to be particularly vulnerable 

to climate change risks include the poor, the elderly, the very young, those already in poor 

health, the disabled, those living alone, and/or indigenous populations dependent on one or a few 

resources. See sections X.F and X.G of the preamble where the EPA discusses Consultation and 

Coordination with Tribal Governments and Protection of Children. The Administrator placed 

weight on the fact that certain groups, including children, the elderly, and the poor, are most 

vulnerable to climate-related health effects. 

The record for the 2009 Endangerment Finding summarizes the strong scientific evidence 

in the major assessment reports by the U.S. Global Change Research Program, the 

Intergovernmental Panel on Climate Change (IPCC), and the National Research Council of the 

National Academies that the potential impacts of climate change raise EJ issues. These reports 

concluded that poor communities can be especially vulnerable to climate change impacts because 

they tend to have more limited adaptive capacities and are more dependent on climate-sensitive 

resources such as local water and food supplies. In addition, Native American tribal communities 

possess unique vulnerabilities to climate change, particularly those impacted by degradation of 

natural and cultural resources within established reservation boundaries and threats to traditional 

subsistence lifestyles. Tribal communities whose health, economic well-being, and cultural 

traditions that depend upon the natural environment will likely be affected by the degradation of 

ecosystem goods and services associated with climate change. The 2009 Endangerment Finding 

record also specifically noted that Southwest native cultures are especially vulnerable to water 

quality and availability impacts. Native Alaskan communities are already experiencing 

disruptive impacts, including coastal erosion and shifts in the range or abundance of wild species 

crucial to their livelihoods and well-being. 
2-34 

The most recent assessments continue to strengthen scientific understanding of climate 

change risks to minority populations and low-income populations in the U.S.51 The new 

assessment literature provides more detailed findings regarding these populations’ vulnerabilities 

and projected impacts they may experience. In addition, the most recent assessment reports 

provide new information on how some communities of color may be uniquely vulnerable to 

climate change health impacts in the U.S. These reports find that certain climate change related 

impacts—including heat waves, degraded air quality, and extreme weather events—have 

disproportionate effects on low-income populations and some communities of color (in 

particular, populations defined jointly by ethnic/racial characteristics and geographic location), 

raising EJ concerns. Existing health disparities and other inequities in these communities 

increase their vulnerability to the health effects of climate change. In addition, assessment 

reports also find that climate change poses particular threats to health, well-being, and ways of 

life of indigenous peoples in the U.S. 

As the scientific literature presented above and as the 2009 Endangerment Finding 

illustrates, low income populations and some communities of color are especially vulnerable to 

the health and other adverse impacts of climate change. The EPA believes that communities will 

benefit from this proposed federal plan because this action directly addresses the impacts of 

climate change by limiting GHG emissions through the establishment of CO2 emission standards 

for existing affected fossil fuel-fired EGUs. 

In addition to reducing CO2 emissions, the guidelines finalized in this rulemaking would 

reduce other emissions from affected EGUs that reduce generation due to higher adoption of EE 

 

51 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United 

States: The Third National Climate Assessment. U.S. Global Change Research Program, 841 pp. 

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects.

Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate 

Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, 1132 pp. 

 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects. 

Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate 

Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, 688 pp.
2-35 

and RE. These emission reductions will include SO2 and NOx, which form ambient PM2.5 and 

ozone in the atmosphere, and HAP, such as mercury and hydrochloric acid. In the final rule 

revising the annual PM2.5 NAAQS,52 the EPA identified low-income populations as being a 

vulnerable population for experiencing adverse health effects related to PM exposures. Lowincome populations have been generally found to have a higher prevalence of pre-existing 

diseases, limited access to medical treatment, and increased nutritional deficiencies, which can 

increase this population’s susceptibility to PM-related effects.53 In areas where this rulemaking 

reduces exposure to PM2.5, ozone, and methylmercury, low-income populations will also benefit 

from such emissions reductions. Chapter 1 of this RIA provides additional information regarding 

the health and ecosystem effects associated with these emission reductions. 

Additionally, as outlined in the community and EJ considerations section IX of the 

preamble, the EPA has taken a number of actions to help ensure that this action will not have 

potential disproportionately high and adverse human health or environmental effects on 

vulnerable communities. The EPA consulted its May 2015, Guidance on Considering 

Environmental Justice During the Development of Regulatory Actions, when determining what 

actions to take.54 As described in the community and EJ considerations section of the preamble 

the EPA also conducted a proximity analysis, which is available in the docket of this rulemaking 

and is discussed in section IX of the preamble. Additionally, as outlined in sections I and IX of 

the preamble the EPA has engaged meaningfully with communities throughout the development 

of the CPP and has devised a robust outreach strategy for continual engagement throughout this 

rulemaking.

 

52 “National Ambient Air Quality Standards for Particulate Matter, Final Rule,” 78 FR 3086 (Jan. 15, 2013). 

53 U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for Particulate Matter 

(Final Report). EPA-600-R-08-139F. National Center for Environmental Assessment – RTP Division. December. 

Available on the Internet at http://www.cfpub.epa.gov/si/si_public_record_Report.cfm?dirEntryId=216546. 

54 Guidance on Considering Environmental Justice During the Development of Regulatory Actions. 

http://www.epa.gov/environmentaljustice/resources/policy/considering-ej-in-rulemaking-guide-final.pdf. May 

2015. 
United States 

Environmental 

Protection Agency 

Office of Air Quality Planning and Standards 

Health and Environmental Impacts Division 

Research Triangle Park, NC 

Publication No. 

EPA-452/R-15-006 

August 2015