From: Higgins, Cortney <Cortney_Higgins@omb.eop.gov> 

Sent: Sunday, May 25, 2014 11:53:18 PM 

To: Wayland, Robertj 

Cc: Culligan, Kevin; Elman, Barry 

Subject: Interagency Comments -- general and on preamble 

Hi Bob, 

Attached are a set of interagency comments (#4 by my count) and also redline edits to the 

preamble. 

Regards, 

Cortney 

<< Interagency Comments under EO 12886 on RIN 2060_AR33_05225014.docx >> 

<< EO12866_2060-AR33 Proposal_May 15 2014_InteragencyCommentsUnderEO12866.docx >> 
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	EO12866	

Interagency	Review.		Subject	to	Further	Policy	Review.	

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General Comments

Biomass			

IPM results show that in the Base Case in 2030 biomass energy consumption (for electricity generation) = 839.64

TBtu  

In the Regional Case for Option 1 in 2030, biomass energy consumption = 494.68 TBtu (or 41% reduction)

In the Base Case in 2030, coal energy consumption (for elec generation) = 19374.36 TBtu

In the Regional Case for Option 1 in 2030, coal energy consumption = 14508.86 TBtu (or 25% reduction)

That result is due to EPA’s assumptions in IPM about two things that was previously commented on:

 The emission factor for biomass is close enough to coal to not select biomass as an option for achieving

reductions

 EPA assumes that biomass usage for electricity generation is relatively costly and so the model selects

away from it and towards natural gas.

These results implicitly suggest to stakeholders that EPA may not allow Renewable Energy efforts in State plans

that utilize biomass.  Commenters have requested that EPA state that biomass is an allowable option for States

to use in building block 3 as such technologies are already accepted by the majority of States that have

renewable energy goals.  Were EPA to the two assumptions listed above it is likely that there would be a much

higher usage of biomass selected in IPM to achieve reductions in GHG emissions.

Additionally, EPA has not addressed all prior comments on biomass.  we continue to believe biomass has

considerable potential to reduce emissions in a cost‐effective manner.   We thus recommend EPA take comment

on including biomass cofiring as an element of building block one subsequent to the release of guidance on

biomass emissions factors.  As it stands now it seems that EPA did not consider using bio‐mass as a BB and did

not do any analysis of the costs or benefits of this

Interim Review Prior to 2025.			

A commenter  recommends several changes to the current draft, including modifying the rule to allow for an

interim review before 2025, potentially resulting in increased stringency post‐2025.   

The commenters recommends that, akin to GHG standards for light duty vehicles, EPA commit to performing a

mid‐term review to enable strengthening the post‐2025 targets based on new information on power markets,

technologies, energy policies and climate damages. Sample language is attached.  In this context, we endorse

the EPA proposal to take comment on including an interim target with averaging from 2020‐2024 based on the

main BSER option from the proposal. This would enable adjustments to targets for the post‐2025 period

Suggested Language on an Interim Review: EPA will conduct a comprehensive mid‐term evaluation and agency

decision‐making process. As part of this undertaking, EPA will develop and compile up‐to‐date information for

the evaluation, through a collaborative, robust and transparent process, including public notice and comment.

Mid‐term evaluation of standards. No later than June 1, 2022, the Administrator proposes to determine whether

the BSER and state goals post‐2025 should be strengthened in light of the record then before the Administrator.

An opportunity for public comment would be provided. Before making such determination, if the Administrator

determines the guidelines need to be strengthened, the Administrator would initiate a rulemaking to revise the

guideline.
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	EO12866	

Interagency	Review.		Subject	to	Further	Policy	Review.	

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‘All‐of‐the‐above’ and Stringency

One  commenter sees three solutions to enhance the all‐of‐the‐above approach and increase stringency:  (1)

provide a third, more stringent BSER option in addition to the two already proposed that more fully reflects an

‘all‐of‐the‐above’ approach to emission reduction; (2) strengthen the existing main option; and (3) take

comment on a wider range of specific options and parameters used to develop particular building blocks (for

example, this commenter  has outlined in the following comments a consistent methodology for evaluating the

cost‐effective abatement potential from deploying new low‐carbon generation capacity, including new

renewable and NGCC capacity).   Our preference would be for the first of these.

New NGCC			

The commenter views natural gas as a critical component of the power sector’s compliance portfolio.   However,

the current draft does not appropriately reflect the potential for cost‐effective abatement from natural gas in

setting BSER.    

To remedy this, they request that EPA revert to its earlier language (provided below with slight modifications),

soliciting comment on including new NGCC in BSER.  

“We therefore do not propose any “best practices” quantities of new NGCC capacity to include in state

goals at this time. However, we invite comment on whether new NGCC capacity should be reflected as

an emission limitation component of the best system of emission reduction, recognizing the potential

cost effectiveness of adding and operating new NGCC capacity as a means of reducing CO2 emissions

from affected EGUs. Further, if we were to reflect quantities for new NGCC capacity in the state goals,

how should we determine those quantities – for example, through an analysis of economic potential? Or

through other means such as: the issuance of permits, a conservative percentage of historic state

additions of NGCC capacity, projections of new NGCC construction by EPA or another government

agency, or commercial projections?”

Furthermore, they note that all except six states have existing NGCC capacity, and most of the states that lack it

are planning new capacity. All states have at least some natural gas turbines. Since new natural gas combined

cycle units can be built with relatively limited initial capital investments, they do not have the same risk of

becoming stranded as more capital‐intensive units because the initial investments can be recouped relatively

quickly. In addition, when more emissions reductions are needed in later years, natural gas capacity could still be

economic at lower annual capacity factors to support renewables, if capacity is properly valued. Alternatively,

NGCC units could be retrofit with CCS (at a lower cost per MWh than for steam coal units) to further reduce

emissions.  

In addition, the commenter has provided a proposed methodology below to more accurately reflect the role of

natural gas in setting BSER.   

Proposed Methodology for Evaluating the Economic Potential for New Generation

1. Use the best available regional information (with areas excluded due to physical features and other

exclusions) and data on current technology costs and regional construction cost differences to estimate

a total cost of clean energy for each location. Note that this can include an adder for potential new

transmission or pipeline needs. The result of this is a clean energy supply curve at many locations, with

the cost and available generation for that region.
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2. Estimate the avoided energy cost. This is calculated based on the particular generation mix by region,

providing information about the generation that would be displaced by the clean energy technology.

This is composed of avoided fuel and operating costs, avoided capital costs, and potentially a range of

costs for avoided environmental externalities.

3. For each resource area, compare the cost of new clean generation found in step 1 to the avoided costs

(ie, benefits) found in step 2. If the costs are lower than avoided cost, include the generation and

capacity available in this region in the “cost‐effective potential”. Sum the supply curve for each state and

region to estimate cost‐effective potential at those scales.

They note that natural gas is widely recognized as providing significant GHG benefits in the generation mix.  To

ensure this is accurately reflected, theyrequests the following language in the preamble be deleted:

Moreover, unlike generation from other types of potential new generating capacity such as wind, solar,

and nuclear capacity, NGCC generation does produce CO2 emissions. Because of this distinction it is less

apparent that addition of new NGCC capacity, as opposed to those other types of capacity, should be a

primary building block of a strategy for reducing CO2 emissions from the power sector.

Less efficient higher emitting existing NGCC generation increases by up to 150 GWs (almost 20%), while new,

more efficient, less emitting new NGCC falls by up to 40% (250 GWs). Wouldn’t including new NGCC in the BBs

increase net benefits (and lower costs) by displacing some less efficient, higher emitting existing NGCC? Are

there IPM model runs that examine this? If not, then in the interest of determining the best policy EPA should

do these model runs.

BSER

Building Blocks 1 and 2.  for such an approach, has EPA analyzed or considered the costs and benefits of a

tradeable permit system?

Severability. While EPA has explained that the building blocks are severable, the lack of analysis providing

costs and benefits of each building block may make it harder for the public, and possibly the court, to

understand how they are severable.  Could EPA provide analysis of each of the building blocks in order to

support their claim?   This is important and we and the public need to understand the costs and benefits as well

as CO2 emission reductions resulting from each BB and only EPA can do this. The order in which the BBs are

applied probably matters for this analysis so EPA will need to do this analysis multiple ways

Renewable Energy

It is clear that renewable energy will provide an attractive, zero emissions source of power.   However, as with

natural gas, the current draft also does not appropriately reflect the potential for cost‐effective abatement from

renewables in setting BSER.    Thus, in addition to seeking comment on the cost‐effective potential approach,

DOE also requests that EPA include or take comment on alternative methodologies for deriving best practices

from existing RPSs and their associated levels of stringency.  There are several options that EPA could pursue:

 Assume that states fully implement their 2012 RE goals

 Assume states with RPSs meet their RPS goals for 2017 if they are greater than the penetration levels

determined by EPA’s methodology

 Set the regional target equal to the average RPS goal in the region 2029, not in 2020
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 Assume states with RPSs meet their RPS goals throughout the compliance period if greater than the

penetration levels determined by EPA’s methodology

 Set the regional target equal to the most aggressive existing RPS goal in the region for 2029

   

These methodologies would increase the RE part of BSER by up to 50% or more, depending on whether the

regional growth rates were also updated.  The commenter  has worked on these options, and stands ready to

provide additional detail.   

Mass Based Approach

To preserve flexibility for the final rule, commenters recommend that EPA solicit comment on developing

targets using a mass‐based approach.  If adopted, analysis suggests it might be more easily implemented, and

compliance could be more transparently evaluated.    

Existing Nuclear		

Commenters request that EPA take comment on the option of including existing nuclear generation in the

denominator of the rate calculation at 100% of its generation. This would then be consistent with EPA’s

approach to renewable capacity.

Flexibility

To fully realize the benefits of flexibility to address potential reliability concerns, commenters recommend that

EPA provide non‐binding guidance to states that their plans take advantage of available flexibilities, such as

multi‐year averaging of emissions and others suggested by the building blocks themselves, to accommodate the

possibility that the operation of more carbon‐intensive generation may be required to address system changes

and events in order to enhance system reliability. Additionally, commenters recommend that EPA provide non‐

binding guidance to states that they consult with the relevant regional transmission organization, independent

system operator, or relevant power system planning authority when developing their implementation plans.  

The commenters can provide technical information to further characterize reliability implications and the

opportunities that flexibility provides.”

Commenters would like EPA to solicit comment more explicitly on how states should engage ISO/RTOs or the

relevant planning authorities when developing state plans. In addition, commenters strongly recommends that

EPA give non‐binding guidance to states on potential options for enhancing reliability when formulating their

state plans.

Cost effectiveness versus other terms.			

General comment ‐ It appears that, in general, references to cost effectiveness (and low cost/least cost) have

been revised to refer to reasonable cost.  It is not clear if the current references to cost effectiveness, etc., are

inadvertent, or have been intentionally retained/added based upon the particular context.   

Multi state versus Regional

EPA should be consistent with labeling the “multi‐state” (as opposed to “regional”) approach. Otherwise, there

may be confusion regarding the terminology and available compliance options.

State Compliance Evaluation. How often do states need to demonstrate actual compliance by submitting

real data on CO2 emissions and generation. Do states send this data separately or as one (rate) number?  
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Interagency	Review.		Subject	to	Further	Policy	Review.	

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Importers. The justification for a reduction only for states that are net importers (p. 203) is unclear given that

flows of electricity vary, and a state may be a net importer for part of the year, day or minute, and a net

exporter at other times. Commenters would like to consult with EPA about the broad set of issues related to

accounting for imports and exports.EPA Response: We have discussed these issues with DOE, OMB and others

on the interagency workgroup.  Commenters request that EPA explain how they have change the rule in light of

comments.   

Peer Review: To what extent is the literature cited in this rule and TSDs peer‐reviewed.  EPA’s prior response

on this is unclear.  Is EPA saying that all the literature  cited in this rule and TSDs peer‐reviewed or not?

Projecting EGU performance TSD

p 3  of first draft?  “... a state plan must also include a projection used to derive the mass‐based CO2 emission

performance goal. This translation will involve a projection of CO2 emissions from affected EGUs during the plan

period, under a scenario that assumes the rate‐based goal in the emission guidelines is met.

While EPA takes comment on different approaches to developing projections, it may want to consider whether

some approaches cause unintended disincentives for employing mass‐based approaches, for example if states

must acquire the resources to conduct modeling themselves. Furthermore, it should consider whether some

approaches have greater potential to lead to inconsistencies if protocols are not sufficiently specified.  In light of

these considerations, the commenters  supports having EPA provide an optional mass‐based target for states

and asks EPA to clarify how it will ensure consistency when states provide their own analyses.  In particular,

requests that EPA address the last clause. This is relevant to the parts of the preamble where EPA requests

comment on related issues (VII.H.3).  

State Plan Considerations TSD

“It would be very helpful to have the explicit formula that is the basis for determining mass‐based equivalence. In

particular, the precise list of sources whose emissions count needs to be specified. Specific questions include: [...]”

EPA states that these comments are addressed in the projecting EGU performance TSD, but the discussion there

is unclear. Commenters  understand that, for measures outside the building blocks, EPA is requesting comment

on how to count them for compliance. However, EPA should clearly and precisely specify the formula used for

determining equivalency at least for those measures for which there is currently an answer. For example,

irrespective of the specific policy choice a state makes for compliance, presumably it must include 6% of its

existing nuclear generation and all RE generation in the denominator when demonstrating equivalence on a rate

basis, but this is never clearly stated. Preferably, such a formula would be given in the preamble.

Cost effectiveness versus other terms.  General comment ‐ It appears that, in general, references to cost

effectiveness (and low cost/least cost) have been revised to refer to reasonable cost.  It is not clear if the current

references to cost effectiveness, etc., are inadvertent, or have been intentionally retained/added based upon

the particular context.   
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	EO12866	

Interagency	Review.		Subject	to	Further	Policy	Review.	

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Line Edits

p. 3 – “Methods for estimating avoided CO2 emissions that result from EE/RE requirements and programs, for

use in projecting emission performance under a state plan and in ex post adjustment of CO2 emission rates

during plan implementation”

Commenters  appreciate the added language to the introduction, but still believes the body of the

document is confusing. In particular, the document should address whether one should subtract

“avoided emissions” from the numerator for the purposes of determining compliance. Since any

emissions avoided are already in the numerator (which presumably is all CO2 emissions), this would

appear to be double counting of emissions reduction.

p. 50 – “Table 2. Illustrative Characterization of EM&V Procedures and Protocols for Common Energy Efficiency

Programs and Polices”

Commenters  appreciate the response to the original comment and suggests that EPA should, in

addition, take comment on the categorization and content provided in Table 2 or remove the table

entirely.

From EPA’s responses to comments –  

 “Can renewable energy that is physically located in a state with a mass‐based policy be used for out‐of‐

state compliance in a state with a rate‐based policy? EPA response: This question is related to treatment

of interstate emission effects, which is addressed later in section VII of the TSD.”

Commenters  would  appreciate a specific pointer to where this is addressed in the referenced

section – and if it is not, urges that it be included.

 “A companion TSD, Projecting EGU CO2 Emission Performance in State Plans, addresses the potential

role of ISO/RTO in facilitating state plan development in a respective grid region, including the role that

an ISOs/RTOs could play in providing analytical support to states during plan development.”

This response directs us to the Projecting EGU CO2 Emissions Performance in State Plans TSD,

but this theme should be consistent across all the TSDs/related‐documents.

Appendix

p. 25 – “Transmission and distribution infrastructure improvements may also count towards EERS programs in

some states. “

Commenters  appreciate the additions and suggests a footnote giving Ohio as an example may be

helpful.

p. 40 – “A renewable portfolio standard (RPS), also known as a renewable electricity standard (RES), is a

mandatory requirement for retail electricity suppliers to supply a minimum percentage or amount of their retail

electricity load with electricity generated from eligible sources of renewable energy.”   

EPA should clarify that non‐RE resources are eligible for credit in some RPSs.
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

6560-50-P 

EO12866_GHG EGU ExistingSources 2060-AR33 Proposal_20140328 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 60 

[EPA-HQ-OAR-2013-0602; FRL-xxxx-xx]

RIN 2060-AR33 

Carbon Pollution Guidelines for Existing Power Plants: 

Emission Guidelines for Greenhouse Gas Emissions from Existing 

Stationary Sources: Electric Utility Generating Units

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: In this action, the EPA is proposing emission 

guidelines for states to follow in developing plans to address 

greenhouse gas emissions from existing fossil fuel-fired 

electric generating units. Specifically, the EPA is proposing 

state-specific rate-based goals for carbon dioxide emissions 

from the power sector, as well as guidelines for states to 

follow in developing plans to achieve the state-specific goals. 

This rule, as proposed, would would continue progress already 

underway to reduce carbon dioxide emissions from the electric 

power sector in the United States.

DATES: Comments on the proposed rule. Comments must be received 

on or before [INSERT THE DATE 60 DAYS AFTER THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE]. 

Comments on the information collection request. Under the 
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Paperwork Reduction Act (PRA), since the Office of Management 

and Budget (OMB) is required to make a decision concerning the 

information collection request between 30 and 60 days after 

[INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER OF THIS 

PROPOSED RULE], a comment to the OMB is best assured of having 

its full effect if the OMB receives it by [INSERT THE DATE 30 

DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER OF 

THIS PROPOSED RULE]. 

 Public Hearing. Public hearings will be held on [INSERT 

DATES HERE], at [INSERT LOCATIONS HERE]. The hearings will 

convene at [INSERT TIME] and end at [INSERT TIME]. Please 

contact [add name] at [phone#] or at xxx.xxx@epa.gov] to 

register to speak at one of the hearings. The last day to preregister in advance to speak at the hearing will be [INSERT DATE 

HERE]. Additionally, requests to speak will be taken the day of 

the hearing at the hearing registration desk, although 

preferences on speaking times may not be able to be fulfilled. 

If you require the service of a translator or special 

accommodations such as audio description, please let us know at 

the time of registration. 

The hearing will provide interested parties the opportunity 

to present data, views or arguments concerning the proposed 
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action. The EPA will make every effort to accommodate all 

speakers who arrive and register. Because this hearing is being 

held at U.S. government facilities, individuals planning to 

attend the hearing should be prepared to show valid picture 

identification to the security staff in order to gain access to 

the meeting room. In addition, you will need to obtain a 

property pass for any personal belongings you bring with you. 

Upon leaving the building, you will be required to return this 

property pass to the security desk. No large signs will be 

allowed in the building. Cameras may only be used outside of the 

building, and demonstrations will not be allowed on federal 

property for security reasons. 

The EPA may ask clarifying questions during the oral 

presentations but will not respond to the presentations at that 

time. Written statements and supporting information submitted 

during the comment period will be considered with the same 

weight as oral comments and supporting information presented at 

the public hearing. Written comments on the proposed rule must 

be postmarked by [INSERT DATE HERE]. Commenters should notify

[ADD NAME] if they will need specific equipment, or if there are 

other special needs related to providing comments at the 

hearing. The EPA will provide equipment for commenters to show 
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overhead slides or make computerized slide presentations if we 

receive special requests in advance. Oral testimony will be 

limited to 5 minutes for each commenter. The EPA encourages 

commenters to provide the EPA with a copy of their oral 

testimony electronically (via email or CD) or in hard copy form. 

Verbatim transcripts of the hearings and written statements will 

be included in the docket for the rulemaking. The EPA will make 

every effort to follow the schedule as closely as possible on 

the day of the hearing; however, please plan for the hearing to 

run either ahead of schedule or behind schedule. Information 

regarding the hearing (including information as to whether or 

not one will be held) will be available at: 

http://www2.epa.gov/carbon-pollution-standards/. 

ADDRESSES: Comments. Submit your comments, identified by Docket 

ID No. EPA-HQ-OAR-2013-0602, by one of the following methods: 

At the website http://www.regulations.gov: Follow the 

instructions for submitting comments. 

At the website http://www.epa.gov/oar/docket.html: Follow 

the instructions for submitting comments on the EPA Air and 

Radiation Docket website. 

Email: Send your comments by electronic mail (email) to aand-r-docket@epa.gov, Attn: Docket ID No. EPA-HQ-OAR-2013-0602. 
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Facsimile: Fax your comments to (202) 566-9744, Attn: 

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

Mail: Send your comments to the EPA Docket Center, U.S. 

EPA, Mail Code 2822T, 1200 Pennsylvania Ave., NW, Washington, DC 

20460, Attn: Docket ID No. EPA-HQ-OAR-2013-0602. In addition, 

please mail a copy of your comments on the information 

collection provisions to the Office of Information and 

Regulatory Affairs, OMB, Attn: Desk Officer for the EPA, 725 17th

St. NW, Washington, DC 20503. 

Hand Delivery or Courier: Deliver your comments to the EPA 

Docket Center, William Jefferson Clinton Building West, Room 

3334, 1301 Constitution Ave., NW, Washington, DC, 20004, Attn: 

Docket ID No. EPA-HQ-OAR-2013-0602. Such deliveries are accepted 

only during the Docket Center’s normal hours of operation (8:30 

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holidays), and special arrangements should be made for 

deliveries of boxed information. 

 Instructions: All submissions must include the agency name 

and docket ID number (EPA-HQ-OAR-2013-0602). The EPA’s policy is 

to include all comments received without change, including any 

personal information provided, in the public docket, available 

online at http://www.regulations.gov, unless the comment 
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includes information claimed to be Confidential Business 

Information (CBI) or other information whose disclosure is 

restricted by statute. Do not submit information that you 

consider to be CBI or otherwise protected through 

http://www.regulations.gov or email. Send or deliver information 

identified as CBI only to the following address: Mr. Roberto 

Morales, OAQPS Document Control Officer (C404-02), Office of Air 

Quality Planning and Standards, U.S. EPA, Research Triangle 

Park, North Carolina 27711, Attention Docket ID No. EPA-HQ-OAR2013-0602. Clearly mark the part or all of the information that 

you claim to be CBI. For CBI information on a disk or CD-ROM 

that you mail to the EPA, mark the outside of the disk or CD-ROM 

as CBI and then identify electronically within the disk or CDROM the specific information you claim as CBI. In addition to 

one complete version of the comment that includes information 

claimed as CBI, you must submit a copy of the comment that does 

not contain the information claimed as CBI for inclusion in the 

public docket. Information so marked will not be disclosed 

except in accordance with procedures set forth in 40 CFR Part 2. 

 The EPA requests that you also submit a separate copy of 

your comments to the contact person identified below (see FOR 

FURTHER INFORMATION CONTACT). If the comment includes 
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information you consider to be CBI or otherwise protected, you 

should send a copy of the comment that does not contain the 

information claimed as CBI or otherwise protected. 

 The www.regulations.gov website is an “anonymous access” 

system, which means the EPA will not know your identity or 

contact information unless you provide it in the body of your 

comment. If you send an email comment directly to the EPA 

without going through http://www.regulations.gov, your email 

address will be automatically captured and included as part of 

the comment that is placed in the public docket and made 

available on the Internet. If you submit an electronic comment, 

the EPA recommends that you include your name and other contact 

information in the body of your comment and with any disk or CDROM you submit. If the EPA cannot read your comment due to 

technical difficulties and cannot contact you for clarification, 

the EPA may not be able to consider your comment. Electronic 

files should avoid the use of special characters, any form of 

encryption and be free of any defects or viruses. 

 Docket: All documents in the docket are listed in the 

http://www.regulations.gov index. Although listed in the index, 

some information is not publicly available (e.g., CBI or other 

information whose disclosure is restricted by statute). Certain 
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other material, such as copyrighted material, will be publicly 

available only in hard copy. Publicly available docket materials 

are available either electronically in 

http://www.regulations.gov or in hard copy at the EPA Docket 

Center, William Jefferson Clinton Building West, Room 3334, 1301 

Constitution Ave., NW, Washington, DC. The Public Reading Room 

is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, 

excluding federal holidays. The telephone number for the Public 

Reading Room is (202) 566-1744, and the telephone number for the 

Air Docket is (202) 566-1742. Visit the EPA Docket Center 

homepage at http://www.epa.gov/epahome/dockets.htm for 

additional information about the EPA’s public docket. 

 In addition to being available in the docket, an electronic 

copy of this proposed rule will be available on the Worldwide 

Web (WWW) through the Technology Transfer Network (TTN). 

Following signature, a copy of the proposed rule will be posted 

on the TTN’s policy and guidance page for newly proposed or 

promulgated rules at the following address: 

http://www.epa.gov/ttn/oarpg/. 

FOR FURTHER INFORMATION CONTACT: [ADD CONTACTS] 

SUPPLEMENTARY INFORMATION: [INSERT TEXT, AS APPROPRIATE]

Acronyms. A number of acronyms and chemical symbols are 
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used in this preamble. While this may not be an exhaustive list, 

to ease the reading of this preamble and for reference purposes, 

the following terms and acronyms are defined as follows: 

ACEEE American Council for an Energy Efficient Economy 

AEO Annual Energy Outlook 

AFL-CIO American Federation of Labor and Congress of 

Industrial Organizations 

ASTM American Society for Testing of Materials 

BSER Best System of Emission Reduction 

Btu/kWh British Thermal Units per Kilowatt-hour 

CAA Clean Air Act 

CBI Confidential Business Information 

CCS Carbon Capture and Storage (or Sequestration) 

CEMS Continuous Emissions Monitoring System 

CHP Combined Heat and Power 

CO2 Carbon Dioxide 

DOE Department of Energy 

ECMPS Emissions Collection and Monitoring Plan System 

EERS Energy Efficiency Resource Standard 

EGU Electric Generating Unit 

EIA Energy Information Administration 

EM&V Evaluation, Measurement and Verification 

EO Executive Order 

EPA Environmental Protection Agency 

FR Federal Register 

GHG Greenhouse Gas 

GW Gigawatt 

HAP Hazardous Air Pollutant 

HRSG Heat Recovery Steam Generator 

IGCC Integrated Gasification Combined Cycle 

IPCC Intergovernmental Panel on Climate Change 

IPM Integrated Planning Model 

IRP Integrated Resource Plan 

ISO Independent System Operator 

kW Kilowatt 

kWh Kilowatt-hour 

lb CO2/MWh Pounds of CO2 per Megawatt-hour 

LBNL Lawrence Berkeley National Laboratory 

MMBtu Million British Thermal Units 

MW Megawatt 
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MWh Megawatt-hour 

NAAQS National Ambient Air Quality Standards 

NAICS North American Industry Classification System 

Commissioners 

NAS National Academy of Sciences 

NGCC Natural Gas Combined Cycle 

NOx Nitrogen Oxides 

NRC National Research Council 

NSPS New Source Performance Standard 

NSR New Source Review 

NTTAA National Technology Transfer and Advancement Act 

NYSERDA New York State Energy Research and Development 

Authority 

OMB Office of Management and Budget 

PM Particulate Matter 

PM2.5 Fine Particulate Matter 

PRA Paperwork Reduction Act 

PSB Public Service Board 

PUC Public Utilities Commission 

REC Renewable Energy Credit 

RES Renewable Energy Standard 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

RIA Regulatory Impact Analysis 

RPS Renewable Portfolio Standard 

RTO Regional Transmission Operator 

SBA Small Business Administration 

SBC System Benefits Charge 

SCC Social Cost of Carbon 

SIP State Implementation Plan 

SO2 Sulfur Dioxide 

Tg Teragram (one trillion (1012) grams) 

TSD Technical Support Document 

TTN Technology Transfer Network 

UMRA Unfunded Mandates Reform Act of 1995 

UNFCCC United Nations Framework Convention on Climate 

Change 

USGCRP U.S. Global Change Research Program 

VCS Voluntary Consensus Standard 

Organization of This Document. The information presented in 

this preamble is organized as follows: 
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I. General Information 

A. Executive Summary 

B. Organization and Approach for this Proposed Rule 

II. Background 

A. Climate Change Impacts from GHG Emissions 

B. GHG Emissions from Fossil Fuel-fired EGUs 

C. The Utility Power Sector 

D. Statutory and Regulatory Requirements 

III. Stakeholder Outreach and Conclusions 

A. Stakeholder Outreach 

B. Key Messages from Stakeholders

C. Key Stakeholder Proposals

D. Consideration of the Existing Range of Policies and Programs 

E. Conclusions 

IV. Rule Requirements and Legal Basis 

A. Summary of Rule Requirements 

B. Summary of Legal Basis 

V. Authority to Regulate Carbon Dioxide and EGUs, Affected 

Sources, and Treatment of Categories

A. Authority to Regulate Carbon Dioxide 

B. Authority to Regulate EGUs 

C. Affected Sources 

D. Combined Categories and Codification in the Code of Federal 

Regulations 

VI. Building Blocks for Setting State Goals and Considerations 

A. Introduction 

B. Building Blocks for Setting State Goals 

C. Detailed Discussion of Building Blocks and Other Options 

Considered 

D. Potential Combinations of the Building Blocks as Components 

of the Best System of Emission Reduction 

E. Determination of the Best System of Emission Reduction 

VII. State Goals 

A. Overview 

B. Form of Goals 

C. Proposed Goals and Computation Procedure 

D. State Flexibilities 

E. Alternate Goals and Other Approaches Considered 

F. Reliable Affordable Electricity 

VIII. State Plans 

E. Overview 

F. Approach 

G. Criteria for Approving State Plans 
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H. State Plan Components 

I. Process for State Plan Submittal and Review

J. State Plan Considerations

K. Additional Factors That Can Help States Meet Their CO2

Emission Performance Goals

L. Resources for States to Consider in Developing Plans

IX. Implications for Other EPA Programs and Rules 

A. Implications for NSR Program 

B. Implications for Title V Program 

C. Interactions with Other EPA Rules 

X. Impacts of the Proposed Action 

A. What are the air impacts? 

B. Comparision of Building Block Approaches 

C. Endangered Species Act 

D. What are the energy impacts? 

E. What are the compliance costs? 

F. What are the economic and employment impacts? 

G. What are the benefits of the proposed goals? 

XI. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory Planning and Review, and 

Executive Order 13563, Improving Regulation and Regulatory 

Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act of 1995 

E. Executive Order 13132, Federalism 

F. Executive Order 13175, Consultation and Coordination With 

Indian Tribal Governments 

G. Executive Order 13045, Protection of Children From 

Environmental Health Risks and Safety Risks 

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

I. National Technology Transfer and Advancement Act 

J. Executive Order 12898, Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

XII. Statutory Authority 

I. General Information 

A. Executive Summary
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1. Purpose of the regulatory action 

Under the authority of Clean Air Act (CAA) section 111(d), 

the EPA is proposing emission guidelines for states to use in 

developing plans to address greenhouse gas (GHG) emissions from 

existing fossil fuel-fired electric generating units (EGUs). In 

this summary, we broadly outline the proposal; discuss its 

purpose; summarize its major provisions, including its approach 

to determining goals; describe flexibilities available to 

states, including timing requirements both for states to submit 

plans and for EGUs to meet obligations under those plans; and 

briefly describe the estimated CO2 emission reductions, costs and 

benefits expected to result from full implementation of the 

proposal. 

This rule, as proposed, would continue progress already 

underway to lower the carbon intensity of power generation in 

the United States. The proposal incorporates critical elements 

that reflect the information and views shared during the 

unprecedented effort that the EPA has undertaken, beginning in 

the summer of 2013, to interact directly with and solicit input 

from a wide range of states and stakeholders. This effort 

encompassed several hundred meetings across the country with 

state environmental and energy officials, public utility 
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commissioners, system operators, utilities and public interest 

advocates, as well as members of the public. A great many 

participants submitted written material and data to the EPA as 

well. 

Nationwide, by 2030, this rule would achieve CO2 emission 

reductions from the power sector of approximately 30 percent 

from CO2 emissions levels in 2005. This goal is within reach 

because innovations in the production, distribution and use of 

electricity are already making the power sector more efficient 

and sustainable while maintaining a diverse energy mix. This 

proposed rule would reinforce and continue this progress. The 

EPA projects that, in 2030, this rule will lead to meaningful 

reductions in harmful carbon pollution resulting in net climate 

and health benefits of $47 billion to $78 billion. At the same 

time coal and natural gas will remain the two dominant sources 

of electricity generation in the U.S. with each providing more 

than 30 percent of the projected generation. 

The proposed guidelines also reinforce the steps already 

being taken by states and utilities to upgrade aging electricity 

infrastructure with 21st century technologies and ensure that 

these trends continue in ways that are consistent with the longterm planning and investment processes already used in this 
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sector. The proposal provides flexibility for states to build 

upon their progress in addressing GHGs and allows them to pursue 

policies to reduce carbon pollution that: 1) continue to rely on 

a diverse set of energy resources, 2) ensure electric 

reliability, 3) provide affordable electricity and, 4) recognize 

investments that states and power companies are already making. 

The proposal has two main elements: 1) state-specific 

goals for reductions from power plants and 2) guidelines 

for the elements needed for a state plans to be approved 

when they are submitted to the EPA for review as required 

under section 111(d). To set the state-specific goals, the 

EPA analyzed the practical and affordable strategies that 

states and utilities are already using to lower carbon 

pollution from the power sector. These strategies include 

improvements in efficiency at carbon-intensive power 

plants, programs that enhance the dispatch priority of low 

emitting and renewable power sources, and programs that 

help homes and businesses use electricity more efficiently. 

While this proposal lays out state-specific goals, it 

does not prescribe how a state should meet those goals. The 

Clean Air Act and EPA’s implementing regulation authorize 

the EPA to set these goals, and rely on states to take the 
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lead on meeting them by creating a plan that is consistent 

with the EPA’s guidelines. This approach ensures that each 

state will have the flexibility to design a program to meet 

its goal in ways that reflects its particular circumstances 

and policy objectives. Each state can do so e alone or can 

collaborate with other states on multi-state or regional 

plans that may provide additional opportunities for cost 

savings and flexibility. 

To facilitate the state planning process, this 

proposal lays out the components of a state plan to meet 

the goal, the latitude states have in developing compliance 

strategies, the flexibility they have in the timing for 

submittal of their plans and the flexibility states have in 

determining the schedule by which their sources must 

achieve the reductions required under state plans. The EPA 

recognizes that each state has different state policy 

considerations – including varying emission reduction 

opportunities and existing state programs and measures – 

and that the characteristics of the electricity system in 

each state (e.g., utility regulatory structure, generation 

mix and electricity demand) also differ. Therefore, the 

proposed guidelines provide states with options for meeting 
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the state-specific goals established by the EPA in a 

flexible manner that accommodates a diverse range of state 

approaches. This proposal also gives states considerable 

flexibility with respect to the timeframes for plan 

development and implementation, providing up to two or 

three years for submission of final plans after the 

proposed emission rate guidelines are finalized and 

providing up to fifteen years for full implementation of 

all emission reduction measures. 

The EPA believes that this proposal, which employs the 

flexibilities inherent in CAA section 111(d), will provide 

states with ample opportunity to design plans that use 

innovative, cost-effective regulatory strategies and that 

take advantage of the investments already being made in 

programs and measures that lower the carbon intensity of 

the power sector and thus reduce GHG emissions that cause 

harmful climate change. 

a. Policy context and industry conditions 

This proposal is an important step toward achieving the 

emissions reductions needed to address the serious threat of 

climate change. GHG pollution threatens the health and welfare 

of the American public by leading to potentially rapid and long 
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lasting changes in our climate that can have a range of severe 

negative effects on human health and the environment. CO2 is the 

primary GHG pollutant, accounting for nearly three-quarters of 

global GHG emissions and over 77 percent of U.S. GHG emissions. 

The President’s Climate Action Plan,1 issued in June 2013, 

recognizes that climate change comes with far-reaching harmful 

consequences and real economic costs. The Climate Action Plan 

details a broad array of actions to reduce GHG emissions that 

contribute to climate change and affect public health and the 

environment. One of the plan’s goals is to reduce CO2 emissions 

from power plants. This is because fossil fuel-fired EGUs are, 

by far, the largest emitters of GHGs, primarily in the form of 

CO2, among stationary sources in the U.S. To accomplish this 

goal, President Obama issued a Presidential Memorandum2

 directing 

the EPA to complete carbon pollution standards, regulations or 

guidelines, as appropriate, for new, modified, reconstructed and 

 

1

 The President’s Climate Action Plan, June 2013. 

http://www.whitehouse.gov/sites/default/files/image/president27s

climateactionplan.pdf 

2

 Presidential Memorandum – Power Sector Carbon Pollution 

Standards, June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards 

Comment [A1]: Please add a citation (the newest 

EPA GHG report?) 
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existing power plants, and to build on state leadership to move 

toward a cleaner power sector. 

Advancements in innovative power sector technologies, in 

the availability and cost of low carbon fuel, and in energy 

efficient demand-side technologies, as well as economic 

conditions, are already changing the way power is produced, 

distributed and used. In addition, the average age of the coalfired generating fleet is increasing. In 2025, the average age 

of the coal-fired generating fleet is projected to be 49 years 

old, and 20 percent of units would be more than 60 years old if 

they remained in operation at that time. Therefore, even in the 

absence of additional environmental regulation, states and 

utilities can be expected to be, and already are, making plans 

to address the changes necessitated by the aging of current 

assets and infrastructure. With change inevitably under way 

between now and 2030, a CAA section 111(d) rulemaking for CO2

emissions can inform current and ongoing decision making by 

states and utilities while prompting states to develop and 

implement plans that will reduce GHG emissions and lower the 

carbon intensity of the power sector, while ensuring a reliable 

supply of power at a reasonable cost. The proposed guidelines 

are designed to build on and reinforce progress by states and 
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companies on a growing variety of sustainable strategies to 

reduce power sector CO2 emissions. At the same time, the EPA 

believes that this proposal provides flexibility for states to 

develop plans that can be crafted for their individual and 

unique circumstances and that can be aligned with their other 

environmental policy and energy and economic goals. All states 

will have the flexibility to shape compliance plans as they 

believe appropriate for meeting the proposed CO2 reduction goals. 

This includes states such as Kentucky, West Virginia and 

Wyoming, with long-established reliance on coal-fired 

generation, as well as states such as Washington and Oregon with 

a commitment to promoting renewable energy (including through 

sustainable forestry initiatives). It also includes states that 

are already participating in or implementing CO2 reduction 

programs, such as the Regional Greenhouse Gas Initiative (RGGI), 

California’s AB 32, and Colorado’s “Clean Air, Clean Jobs Act”. 

To make plans to reduce CO2, states can rely on and extend 

programs they may already have created to address the power 

sector. Those states committed to Integrated Resource Planning 

(IRP) would be able to establish their CO2 reduction plans within 

that framework. Similarly, states with a more deregulated power 

sector system can develop CO2 reduction plans within that 
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framework. At the same time, states would also be able to 

address the economic interests of their utilities and ratepayers 

by using the flexibilities in this proposed action: 1) to reduce 

costs and minimize stranded assets, and 2) to work with other 

states on multi-state approaches that reflect the regional 

structure of electricity operating systems that exists in most 

parts of the country and is critical to ensuring a reliable 

supply of affordable energy. The proposed rule provides a broad 

range of compliance options for a wide and diverse range of 

companies that own and operate fossil fuel-fired EGUs, including 

vertically integrated companies in regulated markets, 

independent power producers, rural cooperatives and municipallyowned utilities. The proposal would also allow states to work 

together with individual companies on potential specific 

challenges. These and other flexibilities are discussed further 

in Section VIII of the preamble. 

b. CAA section 111(d) requirements 

Under CAA section 111(d)3

 state plans must establish 

standards of performance that reflect the degree of emission 

limitation achievable through the application of the “best 

 

3

 See also 40 CFR 60.22(b)(5).
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system of emission reduction taking into account the cost of 

achieving such reduction and any non-air quality health and 

environmental impact and energy requirements, the Administrator 

determines has been adequately demonstrated (BSER).4

 Consistent 

with CAA section 111(d), the EPA is proposing state-specific 

goals that reflect the EPA’s calculation of the emission 

reductions that the states can achieve through the application 

of BSER. 

 This calculation reflects the degree of emission limitation 

that the state plan must achieve in order to implement the BSER 

that the EPA has determined has been adequately demonstrated and 

that, in turn, would be required to be, and via the calculation, 

has been, applied to the affected EGUs in each state. . A CAA 

sectionSection 111(d) state plan will differ from requires the 

Administrator to establish a procedure similar to a state 

implementation plan (SIP) for a criteria air pollutant national 

 

4

 Under CAA section 111(a)(1) and (d), the EPA is authorized to 

determine the BSER and to calculate the amount of emission 

reduction achievable through applying the BSER; and the state is 

authorized to identify the standard(s) of performance that 

reflects that amount of emission reduction. In addition, the 

state is required to include in its state plan the standards of 

performance and measures to implement and enforce those 

standards. The state must submit the plan to the EPA, and the 

EPA must approve the plan if the standards of performance and 

implementing and enforcing measures are satisfactory. 
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ambient air quality standard (NAAQS)), although the form will 

necessarily differ) in several respects, reflecting the 

significant differences between CAA sections 110 and 111. A CAA 

section 110 SIP must be designed to meet a specific ambient air 

quality level -- the NAAQS for the criteria air pollutant -- for 

a particular area (not for a source category) within a timeframe 

specified in the CAA, and the NAAQS, in turn, is based on the 

current body of scientific evidence and, by law, does not 

reflect consideration of cost. A CAA section 111(d) state plan 

must be designed to meet a level specific to emissions from a 

particular source category within a timeframe determined by the 

Administrator and, to some extent, by each state. Moreover, the 

emission levels for the source category reflect a determination 

of BSER, which incorporates consideration of cost, technical 

feasibility and other factors. 

To determine BSER for reducing CO2 emissions at affected 

EGUs, the EPA considered numerous measures that are already 

being implemented, and can be implemented more broadly, to 

improve emission rates and to reduce overall CO2 emissions from 

fossil fuel-fired EGUs. These measures fall into four main 

categories or “building blocks.” Overall, the BSER proposed here 

is based on a range of measures that comprise improved 
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operations at EGUs, dispatching lower-emitting EGUs and zeroemitting energy sources, and end use energy efficiency, all of 

which have been amply demonstrated via their current widespread 

use by utilities and states. 

The proposed guidelines are structured so that states 

would not be required to use each and every one of the 

measures that the EPA determines constitute BSER or to 

apply any one of those measures to the same extent that the 

EPA determines is achievable and cost-effective with 

respect to that measure. Instead, in developing its plan, 

each state will have the flexibility to select the measure 

or combination of measures it prefers in order to achieve 

its CO2 emission reduction goal. Thus, a state could choose 

to achieve more reductions from one measure encompassed by 

BSER and less from another, or it could choose to include 

measures that were not part of the EPA’s BSER 

determination, as long as the state achieves the CO2

reductions necessary to meet its goal. As explained in 

further detail in Sections VI, VII and VIII of this 

preamble regarding the agency’s determination of BSER, the 

EPA is offering the opportunity via this proposal to 

comment on the key assumptions, the methodology, and the 
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specific data used to calculate the state-specific CO2

goals, and on the broad flexibilities provided to meet the 

goals and ensure states the necessary tools to address any 

distinctive circumstances (such as the remaining useful 

life of certain EGUs) without adjusting the underlying 

targets. 

This proposed rule sets forth the state goals that 

reflect BSER and guidelines for states to use in developing 

their plans to reduce CO2 from fossil fuel-fired EGUs. The 

preamble describes the proposed expectations for state 

plans and discusses options that the EPA has considered. It 

also explains the EPA’s authority to define BSER, as well 

as state goals and the states’ responsibility to develop 

and implement standards of performance consistent with 

BSER. Additional detail on various aspects of the proposal 

is included in several technical support documents (TSDs), 

which are available in the rulemaking docket. The proposal 

was substantially informed by the extensive input from 

states and a wide range of stakeholders that the EPA sought 

and has received since the summer of 2013. The EPA invites 

comment on all aspects of this proposal. 

2. Summary of the major provisions 

Comment [A2]: What does this mean? It seems 

to imply no change to the state emissions rates in the 

final rule, which is contrary to the APA. Please 

clarify. 
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a. Approach 

In developing this proposed rulemaking, the EPA is 

implementing provisions that have been in place since Congress 

first enacted the CAA in 1970 and that have been implemented 

pursuant to regulations promulgated in 1975 and followed in 

previous CAA section 111(d) rulemakings since then. These 

provisions ensure that, in concert with the provisions of CAA 

sections 110 and 112, new and existing major stationary sources 

address significant air pollutants that are harmful to public 

health and the environment. These requirements call on the EPA 

to develop emission guidelines, which reflect EPA’s determination 

of BSER, for states to follow in formulating compliance plans to 

implement standards of performance to achieve emissions 

reductions consistent with BSER.. In following these provisions, 

the EPA is proposing a BSER based on strategies currently being 

used by states and companies to reduce CO2 emissions from EGUs in 

the power sector.5

 

 

5

 The final emission guidelines for landfill gas emissions from 

municipal solid waste landfills, published on March 12, 1996 and 

amended on June 16, 1998 (61 FR 9905 and 63 FR 32743, 

respectively), allow either of two approaches for controlling 

landfill gas – by recovering the gas as a fuel, for sale, and 

removing from the premises, or by destroying the organic content 

of the gas on the premises using a control device. Recovering 
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The CAA, as interpreted by the courts, identifies several 

factors for the EPA to consider in a BSER determination: 

technical feasibility, costs, size of emission reductions and 

technology (i.e., whether the system promotes the implementation 

and further development of technology). To determine BSER, the 

EPA considered the reductions achievable through measures that 

reduce CO2 emissions from existing fossil fuel-fired EGUs either 

by reducing the CO2 emission rate at those units or by reducing 

the units’ CO2 emission total by shifting generation from higheremitting fossil fuel-fired EGUs to lower- or zero-emitting 

options (including both low- or zero-emitting generation and 

demand-side energy efficiency). As the EPA has done in making 

BSER determinations in the past, the agency considered the types 

of strategies that states and operators are already employing to 

reduce the covered pollutant (in this case, CO2) from affected 

sources (in this case, fossil fuel-fired EGUs). For this 

pollutant and source category, many states and companies are 

already taking action that will lead to reduce reductions in

GHGs. For example, currently 10 states have market-based GHG 

emission programs, 29 states have implemented renewable 

 

the gas as a fuel source was a practice already being used by 

some affected sources prior to promulgation of the rulemaking.

Comment [A3]: While some of the actions 

enumerated have been taken expressly to reduce 

GHGs, some have not. Edit made to clarfy that. 
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portfolio standards, and utilities in 48 states run demand-side 

energy efficiency programs. Many individual companies also have 

significant voluntary GHG emission reduction programs. Such 

strategies and the proposed BSER determination reflect the fact 

that, in almost all states, the production, distribution and use 

of electricity are undertaken in ways that accommodate 

reductions in both pollution emissions rates and total 

emissions. Specifically, electricity production, at least to 

some extent, takes place interchangeably between and among 

multiple generation facilities and different types of 

generation, a fact that Congress, the EPA and the states have 

long since relied on in enacting or promulgating programs, such 

as Title IV of the CAA, the NOx SIP call, the Cross State Air 

Pollution Rule (CSAPR) and RGGI. 

As a result, the agency, in quantifying state goals, 

assessed what combination of electricity production or energy 

demand reduction across generation facilities can offer the most 

cost-effective approach to achieving CO2 emission reductions. 

States, in turn, will be able to look broadly at opportunities 

across their electricity system in devising plans to meet their 

goals. Importantly, states may rely on measures that they 

already have in place, including renewable energy standards and 
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demand-side energy efficiency programs, and the proposal details 

how such existing state programs can be incorporated into state 

plans. 

To determine BSER for reducing CO2 emissions at 

affected EGUs, and to establish the numerical goals that 

reflect BSER, the EPA considered numerous measures that can 

and are being implemented to improve emission rates and to 

reduce or limit mass CO2 emissions from fossil fuel-fired 

EGUs. These measures encompass two basic approaches: 1) 

reducing the carbon intensity of certain affected EGUs by 

improving the efficiency of their operations, and 2) 

addressing affected EGUs’ mass emissions by varying their 

utilization levels. For purposes of expressing BSER as an 

emissions limitation, in this case in the form of statelevel goals, we propose to group these measures into four 

main categories, or “building blocks”., These building 

blocks can also be used as a guide to states for 

constructing broad-based, cost-effective, long-term 

strategies to reduce CO2 emissions. The EPA believes that 

the application of measures from each of the building 

blocks can achieve CO2 emission reductions at fossil fuelfired EGUs such that, when combined with measures from 
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other building blocks, the measures represent the “best 

system of emission reduction ... adequately demonstrated” 

for fossil fuel-fired EGUs. The building blocks are: 

1. Reducing the carbon intensity of generation at 

individual affected EGUs through heat rate 

improvements. 

2. Reducing emissions from the most carbonintensive affected EGUs in the amount that results 

from substituting generation at those EGUs with 

generation from less carbon-intensive affected EGUs 

(including NGCC units under construction). 

3. Reducing emissions from affected EGUs in the 

amount that results from substituting generation at 

those EGUs with expanded generating low- or zerocarbon generation. 

4. Reducing emissions from affected EGUs in the 

amount that results fromthe use of demand-side energy 

efficiency that reduces the amount of generation 

required. 

The four building blocks are described in detail in 

Sections VI and VII of this preamble. As those sections 

explain, while the EPA found that each of the building 
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blocks met the attributes of BSER, combining all four 

blocks best represents BSER because it achieves greater 

emission reductions, is more cost effective and takes 

better advantage of the wide range of measures already in 

use at the state and company level to reduce CO2 from EGUs. 

Those sections also explain how the EPA considered more 

aggressive application of measures in each block. This 

includes consideration of options in some blocks that the 

EPA determined not to represent BSER for existing sources 

(such as the inclusion of retrofit carbon capture and 

storage or sequestration (CCS) on existing units), as well 

as consideration of more aggressive application of measures 

that the EPA determined do represent a component of BSER 

(such as more aggressive application of demand-side 

measures). While the EPA made these determinations by 

applying the BSER factors to each measure, the EPA also 

considered the impacts of combining each of the measures 

into a unified BSER. 

As part of the BSER determination, the EPA considered 

the impacts that implementation of the emission reductions 

required by the combination of the blocks would have on the 

cost of electricity and on system reliability. As the 
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preamble details, the EPA believes that, both individually 

and in combination, the costs associated with the BSER we 

are proposing today are reasonable. Importantly, the 

proposed BSER, expressed as a numeric goal for each state, 

provide states with the flexibility to determine how to 

achieve the reductions (i.e., greater reductions from one 

building block and less from another) and to adjust the 

timing in which reductions are achieved, in order to 

address key issues such as cost to consumers, reliability 

and “remaining useful life.” 

In sum, the EPA believes that the BSER for purposes of 

CAA section 111(d), as applied to the sources in the power 

sector, is a combination of measures that reduce CO2

emissions and CO2 emission rates and reflect or encompass 

all four building blocks. A range of amounts of reductions 

can be achieved by application of each building block. In 

determining BSER, we have considered these ranges, in light 

of statutory factors, and we have identified goals that we 

believe best satisfy those criteria. Relying on all four 

building blocks to characterize the combination of measures 

that reduce CO2 emissions and CO2 emission rates at affected 

EGUs as BSER is consistent with strategies, actions and 
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measures that companies and states are already undertaking 

to reduce GHG emissions and with current trends in the 

electric power sector, driven by efforts to reduce GHGs, as 

well as by other factors, such as advancements in 

technology. Reliance on all four building blocks in this 

way also supports the goals of achieving meaningful, and 

technically feasible reductions of CO2 at a reasonable cost, 

while also promoting technology and approaches that are 

important for achieving further reductions, all while 

providing the states with a balance of flexibility and 

direction. Finally, the EPA believes that the inherent 

flexibility of the measures encompassed in the four 

building blocks reinforces the inherent flexibility of the 

current electricity system operations and the system’s 

capacity to deliver affordable and reliable electricity 

because these measures rely on the flexibility of the 

electricity system itself. 

In addition to proposing the four building blocks as 

the basis for BSER, the EPA is also soliciting comment on 

application of only the first two building blocks as BSER, 

while noting that application of only the first two 
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building blocks achieves fewer CO2 reductions at a higher 

cost. 

The EPA recognizes that states differ in important 

ways, including in their mix of existing EGUs and in the 

policy priorities that they are pursuing. Consequently, 

opportunities and preferences for reducing emissions, as 

reflected in each of the building blocks, vary across 

states. While the state-specific goals that the EPA is 

proposing in this rule are based on consistent application 

of a goal setting methodology across all states, they are 

designed to account for these key differences. The statespecific CO2 reduction requirements and CO2 rate-based goals 

derived from application of the methodology vary because, 

in setting the goals for a state, the EPA used data 

specific to each state’s EGUs and certain other attributes 

of its electricity system (e.g., current mix of generation 

resources). 

This approach and incorporation of the measures in 

each of the building blocks reflect information provided 

and priorities expressed during the EPA’s recent, extensive 

public outreach process. These ranged from the states’ 

desires for flexibility and recognition of varying state 
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circumstances to the success that states and companies have 

had in adopting a range of pollution- and demand-reduction 

strategies. The state-specific approach embodied in both 

CAA section 111(d) and this proposal recognizes that 

ultimately states are the most knowledgeable about their 

specific circumstances and are best positioned to evaluate 

and leverage existing and new generation capacity and 

programs to reduce CO2 emissions. To meet its goal, each 

state will be able to design programs that use the measures 

it selects, and these may include the combination of 

building blocks most relevant to its specific circumstances 

and policy preferences. They may also identify technologies 

or strategies that are not explicitly mentioned in any of 

the four building blocks and may use those technologies or 

strategies as part of their overall plan. Further, this 

approach allows regional compliance strategies. The agency 

also recognizes the important functional relationship 

between the period of time over which measures are deployed 

and the stringency of emission limitations those measures 

can achieve. Because, for its primary proposal, the EPA is 

proposing a 10-year period over which to achieve the full 

required CO2 reductions, a period that begins more than five 
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years from the date of this proposal, a state could take 

advantage of this relationship in the design of its program 

by using relevant combinations of building blocks to 

achieve its state goal in a timely and cost-effective 

manner. 

b. State goals and flexibilities 

In this action, the EPA is proposing state-specific 

rate-based goals to guide states in the development of 

their plans. These state-specific goals are based on an 

assessment of the amount of emissions that can be reduced 

at high-emitting facilities through application of BSER, as 

contemplated and required under CAA section 111. The agency 

is proposing state-specific interim and final goals that 

must be achieved by no later than the year 2030. The 

proposed final goals reflect the EPA’s quantification of 

adjusted state-average emission rates from affected EGUs 

that could be achieved at reasonable cost by 2030 through 

implementation of the four building blocks described above. 

The proposed interim goals would apply over a 2020-2029 

phase-in period. They reflect the level of reductions in CO2

emissions and emission rates and the extent of the 

application of the building blocks that would be 
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presumptively approvable in a state plan during the ramp-up 

to achieving the final goal. 

The EPA is proposing to allow each state flexibility 

with regard to the form of the goal. Under this proposal, a 

state would not be obligated to adopt the rate-based form 

of the goal established by the EPA. A state plan submittal 

reflecting a mass-based form of the goal or a regional 

approach based upon either rate or mass would be approvable 

based upon a demonstration that the submittal is equivalent 

in stringency, including compliance timing, to the statespecific rate-based goal set by the EPA. 

We believe that this approach to establishing 

requirements for states in developing their plans responds 

both to the needs of an effectively implemented program and 

to the range of viewpoints expressed by stakeholders 

regarding the simultaneous need for both flexibility and 

clear guidance on what would constitute an approvable state 

plan. We likewise believe that this approach represents a 

reasonable balance between two competing objectives 

grounded in CAA section 111(d) - a need for rigor and 

consistency in calculating emission reductions and a need 

for flexibility in establishing and implementing the 
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standards of performance that reflect those emission 

reductions. The importance of this balance is heightened by 

the fact that the operations of the electricity system 

itself rely on the flexibility made available and achieved 

through dispatching between and among multiple 

interconnected EGUs, demand management and end use energy 

efficiency. We view the proposed goals as providing this 

rigor where required by the statute with respect to the 

amount of emissions reductions, while providing states with 

flexibility where permitted by the statute, particularly 

with respect to the development and implementation of 

performance standards and the overall compliance plans. 

This approach recognizes that state plans for emission 

reductions can, and must, be consistent with a vibrant and 

growing economy and supply of reliable, affordable 

electricity to support that economy. It further reflects 

the growing trend, as exemplified by many state and local 

clean energy policies and programs, to shift energy 

production away from carbon-intensive fuels to a more 

sustainable system that puts greater reliance on renewable 

energy and energy efficiency. 

c. State plans 

Comment [A4]: Consider broadened this 

sentence in scope to reflect recent trends outside of 

RE and EE. For example, the term “renewable 

energy” could be replaced with “low-carbon 

energy.” 
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i. Approach 

Each state will determine, and include in its plan, 

emissions performance levels for its affected EGUs that are 

equivalent to the state-specific CO2 goal in the emission 

guidelines, as well as the measures needed to achieve those 

levels and the overall goal. As part of determining this 

level, the state will decide whether it will adopt the 

rate-based form of the goal established by the EPA or 

translate the rate-based goal to a mass-based goal. The 

state must then establish a standard, or set of standards, 

of performance, as well as implementing and enforcing 

measures, to achieve the emission performance level 

specified in the state plan. The state may choose the 

measures it will include in its plan to achieve its goal. 

The state may use the same set of measures as in the EPA’s 

approach to setting the goals, or the state may use other 

or additional measures to achieve the required reductions. 

The plan must include a process for reporting on plan 

implementation, progress toward achieving CO2 goals, and 

implementation of corrective actions, if necessary. No less 

than every two years, beginning January 1, 2022, the state 

will be required to compare emission performance achieved 
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by affected EGUs in the state with the emissions 

performance projected in the state plan, and report that to 

the EPA. 

In this action, the EPA is also proposing guidelines 

for states to use in developing their plans. These 

guidelines include approvability criteria, requirements for 

state plan components, the process and timing for state 

plan submittal and the process and timing for demonstrating 

achievement of the CO2 emission performance level in the 

state plan. The proposed guidelines provide states with 

options for meeting the state-specific goals established by 

the EPA in a flexible manner that accommodates a diverse 

range of state approaches. The plan guidelines provide the 

states with the ability to achieve the full reductions over 

a multi-year period, through a variety of reduction 

strategies, using state-specific or regional approaches 

that can be achieved on either a rate or mass basis. They 

also address several key policy considerations that states 

will have to contemplate in developing their plans. 

With respect to the structure of the state plans, the EPA, 

in its extensive outreach efforts, heard from a wide range of 

stakeholders that the EPA should authorize state plans to 

Comment [A5]: Let’s discuss how compliance 

will be demonstrated – is the comparison at the state 

level, and if it exceeds 10% at the state level, then 

further explanation or corrective action is necessary? 
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include a portfolio of actions that encompass a diverse set of 

programs and measures that achieve either a rate-based or massbased emission performance level for affected EGUs but that do 

not place legal responsibility for achieving the entire amount 

of the emission performance level on the affected EGUs. In view 

of this strong sentiment from stakeholders, the EPA is proposing 

that state plans that take this portfolio approach would be 

approvable, provided that they meet other key requirements such 

as achieving the required emission reductions over the 

appropriate timeframes. Plans that do directly assure that 

affected EGUs achieve all of the required emission reductions 

(such as the mass-based programs being implemented in California 

and the RGGI states) would also be approvable provided that they 

meet other key requirements, such as achieving the required 

emission reductions over the appropriate timeframes. 

ii. State plan components 

The EPA is proposing to evaluate and approve state 

plans based on four general criteria: 1) enforceable 

measures that reduce EGU CO2 emissions; 2) projected 

achievement of emission performance equivalent to the goals 

established by the EPA, on a timeline equivalent to that in 

the emission guidelines; 3) quantifiable and verifiable 
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emission reductions; and 4) a process for biennial 

reporting on plan implementation, progress toward achieving 

CO2 goals, and implementation of corrective actions, if 

necessary. In addition, each state plan must follow the EPA 

framework regulations at 40 C.F.R. 60.23. The proposed 

components of states plans are: 

• Identification of affected entities 

• Description of plan approach and geographic scope 

• Identification of state emission performance level 

• Demonstration that plan is projected to achieve emission 

performance level 

• Identification of emission standards 

• Demonstration that each emission standard is quantifiable, 

non-duplicative, permanent, verifiable, and enforceable 

• Identification of monitoring, reporting, and recordkeeping 

requirements 

• Description of state reporting 

• Identification of milestones 

• Identification of backstop measures 

• Certification of hearing on state plan 

• Supporting material 

iii. Process for state plan submittal and review 

In accordance with the President’s Climate Action 

Plan,6

 the EPA expects to finalize this rulemaking by June 

1, 2015. The Climate Action Plan also calls for a deadline 

of June 30, 2016, for states to submit their state plans. 

 

6

 The President’s Climate Action Plan, June 2013, available at 

http://www.whitehouse.gov/sites/default/files/image/president27s

climateactionplan.pdf
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The EPA is proposing that each state must submit a plan to 

the EPA by June 30, 2016 rather than the 9 months specified 

in the EPA framework regulations at 40 C.F.R. 60.23. 

However, the EPA recognizes that some states may need more 

than one year to develop a final state plan in order to 

provide sufficient time for technical work, state 

legislative and rulemaking schedules, coordination with 

third parties, and coordination among states involved in 

multi-state plans. Therefore, the EPA is proposing an 

optional two-phased submittal process for state plans. Each 

state would be required to submit its plan by June 30, 

2016. However, if a state needs additional time to submit a 

complete plan, then the state must notify the EPA by letter 

of such intent by no later than April 1, 2016. In this 

letter, the state must adequately explain why more time is 

needed to submit a complete plan, outline the actions it is 

currently taking to develop a plan and commit to meet all 

of the requirements for an initial submittal by June 30, 

2016. To be approvable, the initial plan must include 

specific components, including a description of the plan 

approach, initial quantification of the level of emission 

performance that will be achieved in the plan, a commitment 
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to maintain existing measures that limit CO2 emissions, and 

an explanation of the path to completion, as described in 

Section VIII.E of this preamble. 

If the initial plan includes those components, the EPA 

will approve the initial plan and provide an extension of 

time to submit a complete plan. If given an extension, a 

state would have until June 30, 2017, to submit a complete 

plan if the geographic scope of the plan is limited to that 

state. However, if the state develops a plan that includes 

a multi-state approach, then it would have until June 30, 

2018 to submit a complete plan. Further, the EPA is 

proposing that states participating in a multi-state plan 

may submit a single joint plan on behalf of all of the 

participating states. 

Following submission of final plans, the EPA will 

review plan submittals for approvability. Given the diverse 

approaches states may take to meet the emission performance 

goals in the emission guidelines, and the potential 

complexity of the plans the EPA anticipates receiving, the 

EPA is proposing to extend the period of the EPA review of 

plans from the four month period provided in the EPA 
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framework regulations to a six month review and approval 

period. 

v. Timing of compliance 

 The agency is proposing that states must begin to make 

reductions by 2020 and achieve compliance with the CO2 emission 

performance level in the state plan by no later than 2030. Under 

this proposed option, a state would need to meet an interim CO2 

emission performance level on average over the 10-year period 

from 2020-2029, as well as achieve its final CO2 emission 

performance level by 2030 and maintain that level subsequently. 

This proposed option is based on the application of a range of 

measures from all four building blocks, and the agency believes 

that this approach for compliance timing would best support the 

optimization of overall CO2 reductions. The agency is also 

requesting comment on two alternative options. The first 

alternative option includes the addition of a required second 

submittal by each state in 2025 showing whether its plan 

measures would maintain the final emission performance level 

after 2030. The second alternative option is a 5-year period for 

compliance, in combination with a less stringent set of CO2 

emission performance levels. These options are fully described 

in Section VIII of this preamble. 
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The EPA is also proposing that measures that a state takes 

after the date of this proposal, and which result in CO2 emission 

reductions during the plan period, would apply toward 

achievement of the state’s CO2 emission goal. Thus, states with 

existing programs and policies, and states that put in place new 

programs and policies early, will be better positioned to 

achieve the goals. 

vi. Resources for states 

To respond to requests from states for methodologies, tools 

and information to assist them in designing and implementing 

their plans, the EPA, in consultation with the U.S. Department 

of Energy and other federal agencies, as well as states, is 

collecting and developing available resources and is making 

those resources available to the states..7

 

3. Projected national-level emission reductions 

Under the proposed guidelines, the EPA projects annual 

CO2 reductions of 26 to 30 percent below 2005 levels. These 

guidelines will also result in important reductions in 

emissions of criteria air pollutants, including sulfur 

 

7 www2.epa.gov/carbonpollutionstandardstoolbox
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dioxide (SO2), nitrogen oxides (NOx) and directly emitted 

fine particulate matter (PM2.5). 

4. Costs and benefits 

Actions taken to comply with the proposed guidelines 

will reduce emissions of CO2 and other air pollutants, 

including SO2, NOx and PM2.5, from the electric power 

industry. States will make the ultimate determination as to 

how the emission guidelines are implemented. Thus, all 

costs and benefits reported for this action are 

illustrative estimates. 

Assuming that states comply with the guidelines 

collaboratively (referred to as the regional compliance 

approach), the EPA estimates that, in 2020, this proposal will 

yield monetized climate benefits of approximately $17 billion 

(2011$) using a 3 percent discount rate (model average) relative 

to the 2020 base case.8

 The air pollution health co-benefits 

 

8

 The EPA has used the U.S. government’s social cost of carbon 

(USG SCC) estimates — i.e., the monetary value of impacts 

associated with a marginal change in CO2 emissions in a given 

year — to analyze CO2 climate impacts of this rulemaking. The 

four USG SCC 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 SCC value deemed to be 

Comment [A6]: Can we get a table in the Exec 

Summary of the costs and benefits? 
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associated with reducing exposure to ambient PM2.5 and ozone 

through emission reductions of precursor pollutants in 2020 are 

estimated to be $15 billion to $34 billion using a 3 percent 

discount rate and $13 billion to $31 billion (2011$) using a 7 

percent discount rate relative to the 2020 base case. The annual 

compliance costs are estimated using the Integrated Planning 

Model (IPM) and include demand-side energy efficiency program 

and participant costs as well as monitoring and reporting costs. 

Total compliance costs of this proposal are approximately $5.4 

billion (2011$) in 2020. The quantified net benefits (the 

difference between monetized benefits and compliance costs) in 

2020 are estimated to be $26 billion to $46 billion (2011$) 

using a 3 percent discount rate (model average). Climate 

benefits are approximately $30 billion in 2030 using a 3 percent 

discount rate (model average, 2011$) relative to the 2030 base 

case assuming a regional compliance approach for the proposal. 

Health co-benefits are estimated to be approximately $24 to $55 

billion (3 percent discount rate) and $21 to $50 billion (7 

percent discount rate) relative to the 2030 base case (2011$). 

 

central by the USG: the model average at 3 percent discount 

rate. 

Comment [A7]: Option 2 costs, should this be 

$7.4B for Option 1? 
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In 2030, total compliance costs for the proposed option regional 

approach are approximately $7.3 billion (2011$). The net 

benefits for this proposal increase to approximately $47 billion 

to $78 billion (3 percent discount rate model average, 2011$) in 

2030 for the proposed option regional compliance approach. 

In comparison, if states choose to comply with the 

guidelines on a state-specific basis (referred to as state 

compliance approach), rather than collaboratively the climate 

benefits in 2020 are expected to be approximately $18 billion (3 

percent discount rate, model average, 2011$). Health co-benefits 

are estimated to be $15 to $36 billion (3 percent discount rate) 

and $14 to $33 billion (7 percent discount rate). Net benefits 

are estimated to range from $26 to $46 billion (3 percent model 

average discount rate, 2011$). Climate benefits are 

approximately $31 billion in 2030 using a 3 percent discount 

rate (model average, 2011$) relative to the 2030 base case 

assuming a state compliance approach. Health co-benefits are 

estimated to be approximately $25 to $58 billion (3 percent 

discount rate) and $23 to $53 billion (7 percent discount rate) 

relative to the 2030 base case (2011$). In 2030, total 

compliance costs for the state approach are approximately $8.8 

billion (2011$). In 2030, these net benefits are estimated to be 

Comment [A8]: While it’s explained in the RIA, 

does EPA explain somewhere in the preamble why 

the state compliance reductions are greater than at 

the regional level. 
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approximately $47 to $80 billion (3 percent discount rate, 

2011$) assuming a state compliance approach. 

There are additional important benefits that the EPA 

could not monetize. These unquantified benefits include 

climate benefits from reducing emissions of non-CO2

greenhouse gases (e.g., nitrous oxide and methane)9

 and cobenefits from reducing direct exposure to SO2, NOx and 

hazardous air pollutants (e.g., mercury and hydrogen 

chloride), as well as from reducing ecosystem effects and 

visibility impairment. 

Based upon the foregoing, it is clear that the monetized 

benefits of this proposal are substantial and far outweigh the 

costs. 

B. Organization and Approach for this Proposed Rule 

This action presents the EPA’s proposed emission guidelines 

for states to consider in developing plans to reduce GHG 

emissions from the electric power sector. Section II provides 

 

9 Although CO2 is the predominant greenhouse gas released by the 

power sector, electricity generating units also emit small 

amounts of nitrous oxide and methane. See RIA Chapter 2 for more 

detail about power sector emissions and the U.S. Greenhouse Gas 

Reporting Program’s power sector summary, 

http://www.epa.gov/ghgreporting/ghgdata/reported/powerplants.htm

l
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background on climate change impacts from GHG emissions, GHG 

emissions from fossil fuel-fired EGUs and the utility power 

sector and CAA section 111(d) requirements. Section III presents 

a summary of the EPA’s stakeholder outreach efforts, key 

messages provided by stakeholders, state policies and programs 

that reduce GHG emissions, and conclusions. In Section IV of the 

preamble, we present a summary of the rule requirements and the 

legal basis for these, followed by identification of affected 

sources and the proposed treatment of source categories in 

Section V. Section VI describes the use of building blocks for 

setting state goals and key considerations in doing so. 

Sections VII and VIII provide explanations of the proposed state 

goals and the proposed requirements for state plans, 

respectively. Implications for the new source review and Title V 

programs and potential interactions with other EPA rules are 

described in Section IX. Impacts of the proposed action are then 

described in Section X, followed by a discussion of statutory 

and executive order reviews in Section XI and the statutory 

authority for this action in Section XII. 

We note that this rulemaking overlaps in certain respects 

with two other related rulemakings: the January 2014 proposed 

rulemaking that the EPA published on January 8, 2014 for CO2
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emissions from newly constructed affected sources10, and the 

rulemaking for modified and reconstructed sources that the EPA 

is proposing at the same time as this rulemaking. Each of these 

three rulemakings is independent of the other two, and each has 

its own rulemaking docket. Accordingly, commenters who wish to 

comment on any aspect of this rulemaking, including a topic that 

overlaps an aspect of one or both of the other two related 

rulemakings, should make those comments on this rulemaking. 

II. Background 

 In this section, we discuss climate change impacts from GHG 

emissions, both on public health and public welfare, present 

information about GHG emissions from fossil-fuel fired EGUs, and 

summarize the statutory and regulatory requirements relevant to 

this rulemaking. 

A. Climate Change Impacts from GHG Emissions

In 2009, the EPA Administrator issued the document known as 

the Endangerment Finding under CAA section 202(a)(1).11 In the 

Endangerment Finding, which focused on public health and public 

welfare impacts within the United States, the Administrator 

 

10 79 FR 1430 11 “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”).
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found that elevated concentrations of GHGs in the atmosphere may 

reasonably be anticipated to endanger public health and welfare 

of current and future generations. We summarize these adverse 

effects on public health and welfare briefly here. 

1. Public health impacts detailed in the 2009 Endangerment 

Finding12

Climate change caused by human emissions of GHGs threatens 

public health in multiple ways. By raising average temperatures, 

climate change increases the likelihood of heat waves, which are 

associated with increased deaths and illnesses. While climate 

change also increases the likelihood of reductions in coldrelated mortality, evidence indicates that the increases in heat 

mortality will be larger than the decreases in cold mortality in 

the United States. Compared to a future without climate change, 

climate change is expected to increase ozone pollution over 

broad areas of the U.S., including in the largest metropolitan 

areas with the worst ozone problems, and thereby increase the 

risk of morbidity and mortality. Other public health threats 

also stem from projected increases in intensity or frequency of 

 

12 “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”).
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extreme weather associated with climate change, such as 

increased hurricane intensity, increased frequency of intense 

storms, and heavy precipitation. Increased coastal storms and 

storm surges due to rising sea levels are expected to cause 

increased drownings and other health impacts. Children, the 

elderly, and the poor are among the most vulnerable to these 

climate-related health effects. 

2. Public welfare impacts detailed in the 2009 Endangerment 

Finding13

Climate change caused by human emissions of GHGs also 

threatens public welfare in multiple ways. Climate changes are 

expected to place large areas of the country at serious risk of 

reduced water supplies, increased water pollution, and increased 

occurrence of extreme events such as floods and droughts. 

Coastal areas are expected to face increased risks from storm 

and flooding damage to property, as well as adverse impacts from 

rising sea level, such as land loss due to inundation, erosion, 

wetland submergence and habitat loss. Climate change is expected 

to result in an increase in peak electricity demand, and extreme 

 

13 “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”).
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weather from climate change threatens energy, transportation, 

and water resource infrastructure. Climate change may exacerbate 

ongoing environmental pressures in certain settlements, 

particularly in Alaskan indigenous communities. Climate change 

also is very likely to fundamentally rearrange U.S. ecosystems 

over the 21st century. Though some benefits may balance adverse 

effects on agriculture and forestry in the next few decades, the 

body of evidence points towards increasing risks of net adverse 

impacts on U.S. food production, agriculture and forest 

productivity as temperature continues to rise. These impacts are 

global and may exacerbate problems outside the U.S. that raise 

humanitarian, trade, and national security issues for the U.S. 

3. New scientific assessments 

As outlined in Section VIII.A. of the 2009 Endangerment 

Finding, the EPA’s approach to providing the technical and 

scientific information to inform the Administrator’s judgment 

regarding the question of whether GHGs endanger public health 

and welfare was to rely primarily upon the recent, major 

assessments by the U.S. Global Change Research Program (USGCRP), 

the Intergovernmental Panel on Climate Change (IPCC), and the 

National Research Council (NRC) of the National Academies. These 

assessments addressed the scientific issues that the EPA was 
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required to examine, were comprehensive in their coverage of the 

GHG and climate change issues, and underwent rigorous and 

exacting peer review by the expert community, as well as 

rigorous levels of U.S. government review. Since the 

administrative record concerning the Endangerment Finding closed 

following the EPA’s 2010 Reconsideration Denial, a number of 

such assessments have been released. These assessments include 

the IPCC’s 2012 “Special Report on Managing the Risks of Extreme 

Events and Disasters to Advance Climate Change Adaptation” 

(SREX) and the 2013-2014 Fifth Assessment Report (AR5), the 

USGCRP’s 2014 “Climate Change Impacts in the United States” 

(Climate Change Impacts), and the NRC’s 2010 “Ocean 

Acidification: A National Strategy to Meet the Challenges of a 

Changing Ocean” (Ocean Acidification), 2011 “Report on Climate 

Stabilization Targets: Emissions, Concentrations, and Impacts 

over Decades to Millennia” (Climate Stabilization Targets), 2011 

“National Security Implications for U.S. Naval Forces” (National 

Security Implications), 2011 “Understanding Earth’s Deep Past: 

Lessons for Our Climate Future” (Understanding Earth’s Deep 

Past), 2012 “Sea Level Rise for the Coasts of California, 

Oregon, and Washington: Past, Present, and Future”, 2012 

“Climate and Social Stress: Implications for Security Analysis” 
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(Climate and Social Stress), and 2013 “Abrupt Impacts of Climate 

Change” (Abrupt Impacts) assessments. 

The EPA has reviewed these new assessments and finds that 

the improved understanding of the climate system they present 

strengthens the case that GHGs endanger public health and 

welfare. 

In addition, these assessments highlight the urgency of the 

situation as the concentration of CO2 in the atmosphere continues 

to rise. Absent a reduction in emissions, a recent National 

Research Council of the National Academies assessment projected 

that concentrations by the end of the century would increase to 

levels that the Earth has not experienced for millions of 

years.14 In fact, that assessment stated that “the magnitude and 

rate of the present greenhouse gas increase place the climate 

system in what could be one of the most severe increases in 

radiative forcing of the global climate system in Earth 

history.”15

What this means, as stated in another NRC assessment, is 

that: 

 

14 National Research Council, Understanding Earth’s Deep Past, p. 

1.

15 Id., p.138.
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Emissions of carbon dioxide 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 carbon dioxide 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. Therefore, 

emission reductions choices made today matter in 

determining impacts experienced not just over the next 

few decades, but in the coming centuries and 

millennia.16 

Moreover, due to the time-lags inherent in the Earth’s 

climate, the Climate Stabilization Targets assessment notes that 

the full warming from any given concentration of CO2 reached will 

not be realized for several centuries. 

The recently released USGCRP “Climate Change Impacts” 

assessment17 emphasizes that climate change is already happening 

 

16 National Research Council, Climate Stabilization Targets, 

p. 3. 17 U.S. Global Change Research Program, Climate Change Impacts in 

the United States: The Third National Climate Assessment. 

Available at http://nca2014.globalchange.gov/. 
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now and it is happening in the United States. The assessment 

documents the increases in some extreme weather and climate 

events in recent decades, the damage and disruption to 

infrastructure and agriculture, and projects continued increase 

and more severe changes across a wide range of peoples, sectors, 

and ecosystems. 

These assessments underscore the urgency of reducing 

emissions now: today’s emissions will otherwise lead to raised 

atmospheric concentrations for thousands of years, and raised 

Earth system temperatures for even longer. Emission reductions 

today will benefit the public health and public welfare of 

current and future generations. 

Finally, it should be noted that the concentration of 

carbon dioxide in the atmosphere continues to rise dramatically. 

In 2009, the year of the Endangerment Finding, the average 

concentration of carbon dioxide as measured on top of Mauna Loa 

was 387 parts per million.18 The average concentration in 2013 

was 396 parts per million. And the monthly concentration in 

April of 2014 was 401 parts per million, the first time a 

monthly average has exceeded 400 parts per million since record 

 

18 

ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt
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keeping began, in ####, and for at least the past 800,000 years 

according to ice core records.19

B. GHG Emissions from Fossil Fuel-fired EGUs 

Fossil fuel-fired electric utility generating units (EGUs) 

are by far the largest emitters of GHGs, primarily in the form 

of CO2, among stationary sources in the U.S., and among fossil 

fuel-fired units, coal-fired units are by far the largest 

emitters. This section describes the amounts of those emissions 

and places those amounts in the context of the national 

inventory of GHGs. 

The EPA prepares the official U.S. Inventory of Greenhouse 

Gas Emissions and Sinks20 (the U.S. GHG Inventory) to comply with 

commitments under the United Nations Framework Convention on 

Climate Change (UNFCCC). This inventory, which includes recent 

trends, is organized by industrial sectors. It provides the 

information in Table 1 below, which presents total U.S. 

 

19 http://www.esrl.noaa.gov/gmd/ccgg/trends/ 20 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 

2012”, Report EPA 430-R-14-003, United States Environmental 

Protection Agency, April 15, 2014. 

Comment [A9]: Please add. 
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anthropogenic emissions and sinks21 of GHGs, including CO2

emissions, for the years 1990, 2005 and 2012. 

Table 1. U.S. GHG Emissions and Sinks by Sector (teragram carbon 

dioxide equivalent (Tg CO2 Eq.))22

SECTOR 1990 2005 2012 

Energy 5,260.1 6,243.5 5,498.9

Industrial Processes 316.1 334.9 334.4

Solvent and Other 

Product Use 4.4 4.4 4.4 

Agriculture 473.9 512.2 526.3 

Land Use, Land-Use 

Change and Forestry 13.7 25.5 37.8 

Waste 165.0 133.2 124.0 

Total Emissions 6,233.2 7,253.8 6,525.6

Land Use, Land-Use 

Change and Forestry 

(Sinks) (831.3) (1,030.7) (979.3)

Net Emissions (Sources 

and Sinks) 5,402.1 6,223.1 5,546.3

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to 

 

21 Sinks are a physical unit or process that stores GHGs, such as 

forests or underground or deep sea reservoirs of carbon dioxide.

22 From Table ES-4 of “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2012, Report EPA 430-R-14-003, United States 

Environmental Protection Agency, April 15, 2014. 
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total U.S. GHG emissions, representing 77.7 percent of total 

2012 GHG emissions.23 In 2012, fossil fuel combustion by the 

electric power sector –- entities that burn fossil fuel and 

whose primary business is the generation of electricity –- 

accounted for 38.7 percent of all energy-related CO2 emissions.24

Table 2 below presents total CO2 emissions from fossil fuel-fired 

EGUs, for years 1990, 2005 and 2012. 

Table 2. U.S. GHG Emissions from Generation of Electricity from 

Combustion of Fossil Fuels (Tg CO2)25

C. The Utility Power Sector 

 

23 From Table ES-2 “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2012”, Report EPA 430-R-14-003, United States 

Environmental Protection Agency, April 15, 2014. 

24 From Table 3-1 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2012”, Report EPA 430-R-14-003, United States 

Environmental Protection Agency, April 15, 2014. 

25 From Table 3-5 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2012”, Report EPA 430-R-14-003, United States 

Environmental Protection Agency, April 15, 2014. 

GHG EMISSIONS 1990 2005 2012

Total CO2 from fossil fuel 

combustion EGUs 1,820.8 2,402.1 2,022.7 

 - from coal 1,547.6 1,983.8 1,511.2

 - from natural gas 175.3 318.8 492.2 

 - from petroleum 97.5 99.2 18.8 
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Electricity in the United States is generated by a range of 

sources -- from power plants that use fossil fuels like coal, 

oil, and natural gas, to non-fossil sources, such as nuclear, 

solar, wind and hydroelectric power. Currently, the majority of 

power in the U.S. is generated from the combustion of coal, 

natural gas, and other fossil fuels. In recent years, though, 

the proportion of new renewable generation coming on line has 

increased dramatically. For instance, one-third of new 

generating capacity built in 2013 used renewable power 

generation technologies (EIA, 2014). 

This range of different power plants generates electricity 

that is transmitted and distributed through a complex system of 

interconnected components to industrial, business, and 

residential consumers. 

The utility power sector is unique in that, unlike other 

sectors where the sources operate independently and on a local 

scale, power sources operate in a complex, interconnected grid 

system that typically is regional in scale. In addition, the 

U.S. economy depends on this sector for a reliable supply of 

power at a reasonable cost. 

In the U.S., much of the existing power generation fleet in 

the infrastructure is aging. There has been, and continues to 
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be, technological advancement in many areas, including energy 

efficiency, solar power generation, and wind power generation.

Advancements and innovation in power sector technologies provide 

the opportunity to address CO2 emission levels at affected power 

plants while at the same time improving the overall power system 

in the U.S. by lowering the carbon intensity of power 

generation, and ensuring a continued reliable supply of power at 

a reasonable cost.

D. Statutory and Regulatory Requirements 

Clean Air Act section 111, which Congress enacted as part 

of the 1970 Clean Air Act Amendments, establishes mechanisms for 

controlling emissions of air pollutants from stationary sources. 

This provision requires EPA to promulgate a list of categories 

of stationary sources that the Administrator, in his or her 

judgment, finds “causes, or contributes significantly to, air 

pollution which may reasonably be anticipated to endanger public 

health or welfare.”26 EPA has listed more than 60 stationary 

source categories under this provision.27 Once EPA lists a source 

category, EPA must, under CAA section 111(b)(1)(B), establish 

“standards of performance” for emissions of air pollutants from 

 

26 CAA §111(b)(1)(A). 27 See 40 CFR 60 subparts Cb – OOOO. 
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new sources in the source categories. 28 These standards are 

known as new source standards of performance (NSPS), and they 

are national requirements that apply directly to the sources 

subject to them. 

When the EPA establishes NSPS for new sources in a 

particular source category, the EPA is also required, under CAA 

section 111(d)(1), to prescribe regulations for states to submit 

plans regulating existing sources in that source category for 

any air pollutant that, in general, is not regulated under the 

CAA section 109 requirements for the NAAQS or regulated under 

the CAA section 112 requirements for hazardous air pollutants 

(HAP). CAA section 111(d)’s mechanism for regulating existing 

sources differs from the one that CAA section 111(b) provides 

for new sources because CAA section 111(d) contemplates states 

submitting plans that establish “standards of performance” for 

the affected sources and that contain other measures to 

implement and enforce those standards. 

“Standards of performance” are defined under CAA section 

111(a)(1) as standards for emissions that reflect the emission 

limitation achievable from the “best system of emission 

 

28 CAA §111(b)(1)(B), 111(a)(1). 
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reduction,” considering costs and other factors, that 

“the Administrator determines has been adequately demonstrated.” 

CAA section 111(d)(1) grants states the authority, in applying a 

standard of performance to particular sources, to take into 

account the source’s remaining useful life or other factors. 

Under CAA section 111(d), a state must submit its plan to 

the EPA for approval, and the EPA must approve the state plan if 

it is “satisfactory.” 29 If a state does not submit a plan, or if 

the EPA does not approve a state’s plan, then the EPA must 

establish a plan for that state.30 Once a state receives the 

EPA’s approval for its plan, the provisions in the plan become 

federally enforceable against the entity responsible for 

noncompliance, in the same manner as the provisions of an 

approved SIP under CAA section 110. In the case of a tribe that 

has one or more affected EGUs located in its area of Indian 

country,31 the tribe would have the opportunity, but not the 

 

29 CAA section 111(d)(2)(A). 30 CAA section 111(d)(2)(A). 31 The EPA is aware of at least four affected sources located in 

Indian Country: two on Navajo lands – the Navajo Generating 

Station and the Four Corners Generating Station; one on Ute 

lands – the Bonanza Generating Station; and one on Fort Mojave 

lands, the South Point Energy Center. The affected EGUs at the 

first three plants are coal-fired EGUs. The fourth affected EGU 

is an NGCC facility. 
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obligation, to establish a CO2 performance standard and a plan 

for its tribal lands. 

The EPA issued regulations implementing CAA section 111(d) 

in 1975,32 and has revised them in the years since.33 (We refer to 

the regulations generally as the implementing regulations, and 

we refer to the 1975 rulemaking as the framework regulations.) 

These regulations provide that, in promulgating requirements for 

sources under CAA section 111(d), the EPA first develops 

regulations known as “emission guidelines,” which establish 

binding requirements that states must address when they develop 

their plans.34 The implementing regulations also establish 

timetables for state and EPA action: states must submit state 

plans within 9 months of the EPA’s issuance of the guidelines,35

and the EPA must take final action on the state plans within 4 

months of the due date for those plans,36 although the EPA has 

 

32 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53,340 (Nov. 17, 1975). 

33 [Cites] 34 40 CFR 60.22. In the 1975 rulemaking, the EPA explained that 

it used the term “emissions guidelines” – instead of emissions 

limitations – to make clear that guidelines would not be binding 

requirements applicable to the sources, but instead are 

“criteria for judging the adequacy of State plans.” 40 Fed. Reg. 

at 53,343. 

35 40 CFR 60.23(a)(2). 36 40 CFR 60.27(b). 
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authority to extend those deadlines.37 In the present rulemaking, 

the EPA is following the requirements of the implementing 

regulations, and is not re-opening them, except that the EPA is 

extending the timetables, as described below. 

Over the last forty years, under CAA section 111(d), the 

agency has regulated four pollutants from five source categories 

(i.e., sulfuric acid plants (acid mist), phosphate fertilizer 

plants (fluorides), primary aluminum plants (fluorides), Kraft 

pulp plants (total reduced sulfur), and municipal solid waste 

landfills (landfill gases)).38 In addition, the agency has 

regulated additional pollutants under CAA section 111(d) in 

conjunction with CAA section 129.39 The agency has not previously 

regulated CO2 or any other greenhouse gas under CAA section 

111(d). 

The EPA’s previous CAA section 111(d) actions were 

necessarily geared towards the pollutants and industries 

regulated. Similarly, in the present rulemaking, in defining CAA 

section 111(d) goals and guidelines for the states, the EPA 

believes it is necessary to take into account the particular 

 

37 See 40 CFR 60.27(a). 38 [Cites] 39 [Cites] 
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characteristics of carbon pollution and the interconnected 

nature of the power sector and the manner in which EGUs are 

currently operated such that operators themselves treat 

increments of generation as interchangeable between and among 

sources in a way that creates options for relying on varying 

utilization levels, lowering carbon generation, and reducing 

demand as components of the overall method for reducing CO2

emissions. Doing so results in a broader, forward-thinking 

approach to the design of programs to yield critical CO2

reductions that improve the overall power system by lowering the 

carbon intensity of power generation, while offering continued 

reliability and cost-effectiveness. 

In this action, the EPA is proposing emission guidelines 

for states to use in developing their plans to reduce emissions 

of CO2 from the electric power sector. 

III. Stakeholder Outreach and Conclusions 

A. Stakeholder Outreach 

1. The President’s call for engagement 
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Following the direction of the Presidential Memorandum to 

the Administrator (June 25, 2013),40 this proposed rule was 

developed after extensive and vigorous outreach to stakeholders 

and the general public. The Presidential Memorandum instructed 

the Administrator to inaugurate the process for developing 

standards through direct engagement with the states and a full 

range of stakeholders: 

“Launch this effort through direct engagement with States, 

as they will play a central role in establishing and 

implementing standards for existing power plants, and, at 

the same time, with leaders in the power sector, labor 

leaders, non-governmental organizations, other experts, 

tribal officials, other stakeholders, and members of the 

public, on issues informing the design of the program.” 

2. Educating the public and stakeholder outreach 

To carry out this stakeholder outreach, the EPA embarked on 

an unprecedented pre-proposal outreach effort. From consumer 

groups to states to power plant owner/operators to technology 

innovators, the EPA sought input from all perspectives. 

 

40 Presidential Memorandum – Power Sector Carbon Pollution 

Standards, June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards
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The EPA began the outreach efforts with a webinar and 

associated teleconferences to establish a common understanding 

of the basic requirements and process of CAA section 111(d). The 

August 27, 2013 overview presentation was offered as a webinar 

for state and tribal officials, “Building a Common 

Understanding: Clean Air Act and Upcoming Carbon Pollution 

Guidelines for Existing Power Plants.” 

The EPA followed up on the presentation by offering four 

national teleconference calls with representatives from states, 

tribes, industry, environmental justice organizations, community 

organizations and environmental representatives. The 

teleconferences offered a venue for stakeholders to ask 

questions of the EPA about the overview presentation and for the 

EPA to gather initial reactions from stakeholders. Stakeholders 

and members of the public continued to view and refer to the 

overview presentation throughout the outreach process. By 

February 2013, the presentation had been viewed more than 4,400 

times. 

The agency also provided mechanisms for anyone from the 

public to provide input during the pre-proposal development of 

this action. The EPA set up two user-friendly options to accept 

input during the pre-proposal period – a new email account: 
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carbonpollutioninput@epa.gov; and a web-based form: 

http://www2.epa.gov/carbon-pollution-standards/forms/carbonpollution-standards-contact-us. These links, along with policy, 

program, and technical information about this rulemaking effort, 

are available on the EPA’s website at: 

http://www2.epa.gov/carbon-pollution-standards. The EPA has 

received more than 2,000 emails offering input into the 

development of these guidelines. 

These emails and other materials provided to the EPA are 

posted on line as part of a non-regulatory docket, EPA Docket ID 

No. EPA-HQ-OAR-2014-0020, at www.regulations.gov. All of the 

documents on which this proposal is based are available at 

Docket ID No. EPA-HQ-OAR-2013-0602, at www.regulations.gov.

However, while the information collected through extensive 

outreach helped the agency formulate this proposal, we are not 

relying on all of the documents, emails, and other information 

included in the informational docket that was established as a 

part of that outreach effort, nor will the EPA be responding to 

specific comments or issues raised during the outreach effort. 

Rather, we have included in the docket for this proposal all of 

the information we relied on for this action. 
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The agency has encouraged, organized, and participated in 

hundreds of meetings about CAA section 111(d) and reducing 

carbon pollution from existing power plants. Attendees at these 

various meetings have included states and tribes, members of the 

public, and representatives from multiple industries, labor 

leaders, environmental groups and other non-governmental 

organizations. The direct engagement has brought together a 

variety of states and stakeholders to discuss a wide range of 

issues related to the electricity sector and the development of 

emission guidelines under CAA section 111(d). The meetings 

occurred in Washington, DC, and at locations across the country. 

The meetings were attended by the EPA Regional Administrators, 

managers and staff and who are playing or will play key roles in 

developing and implementing the rule 

Part of this effort included the agency’s holding of 11 

public listening sessions; one national listening session in 

Washington, DC and 10 listening sessions in locations in the EPA 

regional offices across the country. All of the outreach 

meetings were designed to solicit policy ideas, concerns and 

technical information from stakeholders about using CAA section 

111(d). 
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This outreach process has produced a wealth of information 

which has informed this proposal significantly. The pre-proposal 

outreach efforts far exceeded what is required of the agency in 

the normal course of a rulemaking process, and the EPA expects 

that the dialog with states and stakeholders will continue 

throughout the process and even after the rule is finalized. The 

EPA recognizes the importance of working with all stakeholders, 

and in particular with the states, to ensure a clear and common 

understanding of the role the states will play in addressing 

carbon pollution from power plants. 

3. Public listening sessions 

More than 3,300 people attended the public listening 

sessions held in 11 cities across the country. Holding the 

listening sessions at the EPA’s regional offices offered 

thousands of people from different parts of the country the 

opportunity to provide input to EPA officials in accessible 

venues. In addition to being well located, holding the sessions 

in regional offices also allowed the agency use resources 

prudently and enabled a variety of the EPA staff involved in the 

development and ultimate implementation of this upcoming rule to 

attend and learn from the views expressed. 
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More than 1,600 people spoke at the 11 listening sessions. 

Speakers included Members of Congress, other public officials, 

industry representatives, faith-based organizations, unions, 

environmental groups, community groups, students, public health 

groups, energy groups, academia and concerned citizens. 

Participants shared a range of perspectives. Many were concerned 

by the impacts of climate change on their health and on future 

generations, others worried about the impact of regulations on 

the economy. Their support for the agency’s efforts varied. 

Summaries of these 11 public listening sessions are 

available at www.regulations.gov at EPA Docket ID No. EPA-HQOAR-2014-0020. 

4. State officials 

Since fall 2013, the agency provided multiple opportunities 

for the states to inform this proposal. In addition, the EPA 

organized, encouraged and attended meetings to discuss multistate planning efforts. Because of the interconnectedness of the 

power sector, and the fact that electricity generated at power 

plants crosses state lines, states, utilities and ratepayers may 

benefit from states working together to address the requirements 

of this rulemaking implementation. The meetings provided state 

leaders, including governors, environmental commissioners, 
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energy officers, public utility commissioners, and air 

directors, opportunities to engage with the EPA officials. 

Agency officials listened to ideas, concerns and details 

from states, including from states with a wide range of 

experience in reducing carbon pollution from power plants. The 

agency has collected policy papers from states with overarching 

energy goals and technical details on the states’ electricity 

sector. The agency has engaged, and will continue to engage 

with, all of the 50 states throughout the rulemaking process. 

5. Tribal officials 

 The EPA conducted significant outreach to tribes, who are 

not required to – but may – develop or adopt Clean Air Act 

programs. The EPA is aware of three coal-fired power plants and 

one natural gas-fired EGU located in Indian country but is not 

aware of any EGUs that are owned or operated by tribal entities. 

The EPA conducted outreach to tribal environmental staff 

and offered consultation with tribal officials in developing 

this action. Because the EPA is aware of tribal interest in this 

proposed rule, the EPA offered consultation with tribal 

officials early in the process of developing the proposed 

regulation to permit tribes to have meaningful and timely input 

into its development. 
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The EPA sent consultation letters to 584 tribal leaders. 

The letters provided information regarding the EPA’s development 

of emission guidelines for existing power plants and offered 

consultation. None have requested consultation. Tribes were 

invited to participate in the national informational webinar 

held August 27, 2013. In addition, a consultation/outreach 

meeting was held on September 9, 2013, with tribal 

representatives from some of the 584 tribes. The EPA 

representatives also met with tribal environmental staff with 

the National Tribal Air Association, by teleconference, on 

December 19, 2013. In those teleconferences, the EPA provided 

background information on the GHG emission guidelines to be 

developed and a summary of issues being explored by the agency. 

In addition, the EPA held a series of listening sessions 

prior to development of this proposed action. Tribes 

participated in a session on September 9, 2013 with the state 

agencies, as well as in a separate session with tribes on 

September 26, 2013. 

6. Industry representatives 

Agency officials have engaged with industry leaders and 

representatives from trade associations in scores of one-on-one 

and national meetings. Many meetings occurred at the EPA 
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headquarters and in the EPA’s Regional Offices and some were 

sponsored by stakeholder groups. Because the focus of the 

standard is on the electricity sector, many of the meetings with 

industry have been with utilities and industry representatives 

directly related to the electricity sector. The agency has also 

met with energy industries such as coal and natural gas 

interests, as well as companies that offer new technology to 

prevent or reduce carbon pollution, including companies that 

have expertise in renewable energy and energy efficiency. Other 

meetings have been held with representatives of energy intensive 

industries, such as the iron and steel and aluminum industries 

to help understand the issues related to large industrial users 

of electricity. 

7. Electric utility representatives 

Agency officials participated in many meetings with 

utilities and their associations. The meetings focused on the 

importance of the utility industry in reducing carbon emissions 

from power plants. Power plant emissions are central to this 

rulemaking. The EPA encouraged industry representatives to work 

with state environmental and energy officers. 

The electric utility representatives included private 

utilities or investor owned utilities. Public utilities and 
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cooperative utilities were also part of in-depth conversations 

about CAA section 111(d) with EPA officials. 

The conversations included meetings with the EPA 

headquarters and Regional offices. State officials were included 

in many of the meetings. Meetings with utility associations and 

groups of utilities were held with key EPA officials. The 

meetings covered technical, policy, and legal topics of interest 

and utilities expressed a wide variety of support and concerns 

about CAA section 111(d). 

8. Electricity grid operators 

The EPA had a number of conversations with the Independent 

System Operators and Regional Transmission Organizations (ISOs 

and RTOs) to discuss the rule and issues related to grid 

operations and reliability. EPA staff met with the ISO/RTO 

Council on several occasions to collect their ideas. The EPA 

Regional Offices also met with the ISOs and RTOs in their 

regions. System operators have offered suggestions in using 

regional approaches to implement CAA section 111(d) while 

maintaining reliable, affordable electricity. 

9. Representatives from non-governmental organizations 

Agency officials engaged with representatives of 

environmental justice organizations during the outreach effort, 
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for example, we engaged with the National Environmental Justice 

Advisory Council members in September 2013. The NEJAC is 

composed of stakeholders, including environmental justice 

leaders and other leaders from state and local government and 

the private sector. 

 The EPA has also met with a number of environmental groups 

to provide their ideas on how to reduce carbon pollution from 

existing power plants using section 111(d) of the CAA. 

Many environmental organizations discussed the need for 

reducing carbon pollution. Meetings were technical, policy and 

legal in nature and many groups discussed specific state 

policies that are already in place to reduce carbon pollution in 

the states. 

 A number of organizations representing religious groups 

have reached out to the EPA on several occasions to discuss 

their concerns and ideas regarding this rule. 

 Public health groups discussed the need for protection of 

children’s health from harmful air pollution. Doctors and health 

care providers discussed the link between reducing carbon 

pollution and air pollution and public health. Consumer groups 

representing advocates for low income electricity customers 

discussed the need for affordable electricity. They talked about 
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reducing electricity prices for consumers through energy 

efficiency and low cost carbon reductions. 

10. Labor 

A number of labor unions invited EPA officials to their 

meetings to give presentations and engage in discussions about 

reducing carbon pollution using CAA section 111(d). EPA senior 

officials and staff met with union representatives that included 

the United Mine Workers of America, SMART, the International 

Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, 

Forgers and Helpers, United Association, the International 

Brotherhood of Electrical Workers, the Utility Workers Union of 

America. In addition, agency leaders participated in a meeting 

of the Presidents of several unions at the AFL-CIO. 

B. Key Messages from Stakeholders

Many stakeholders stated that opportunities exist to reduce 

the carbon emissions from existing power generation through a 

wide range of measures, from measures that are implementable via 

physical changes at the source to those that also are 

implementable across the broader power generation system. 

Opinions varied about how broader system measures could factor 

into programs to reduce carbon pollution. Some stakeholders 

recommended that system-wide measures be allowed for compliance, 
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but not factored into the carbon improvement goals the EPA 

establishes, while others recommended that system-wide measures 

be factored into the goals. Among the arguments and information 

offered by stakeholders who suggested that states be encouraged 

to incorporate system-wide measures into their state plans and 

that EGU operators be encouraged to rely on such measures were 

examples and discussions of the significant extent to which 

dispatch, end use energy efficiency and renewable energy had 

already proven to be successful strategies for reducing EGU CO2 

emissions. Some state and industry representatives favored goals 

that they described as based on measures implementable only 

within the facility “fence line” (i.e., measures implementable 

only at the source). Many stakeholders stated that the EPA 

should not require the state plans to impose on the affected 

EGUs legal responsibility for the full amount of required CO2

emissions reductions, and instead, the EPA should authorize the 

state plans to include requirements on entities other than the 

affected EGUs that would have the effect of reducing utilization 

and therefore emissions, from the affected EGUs. 

Views on the form and stringency of the goal or guidelines 

varied. Some stakeholders preferred a rate-based form of the 

goal, while others preferred a mass-based form. In addition, 
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some stakeholders recommended that the EPA let the states have 

the flexibility to either choose among multiple forms of the 

goals or to set their own goals. With regard to the stringency 

of the goal, some stakeholders recommended that the stringency 

of the goals vary by state, to account for differences in state 

circumstances. 

Many stakeholders recognized the value of allowing states 

flexibility in implementing the goals the EPA establishes. For 

example, states highlighted the importance of the EPA 

recognizing existing state and regional programs that address 

carbon pollution, including market-based programs, and allowing 

credit for prior accomplishments in reducing CO2 emissions. Many 

states and other stakeholders noted the importance of the EPA 

allowing flexibility in compliance options such that states 

could use approaches such as demand-side management to attain 

the goals. 

Many stakeholders recommended that states be allowed to 

develop multi-state programs. It was frequently noted that such 

regional approaches could offer cost-effective carbon pollution 

solutions. 

There was broad agreement that most states would need more 

than one year to develop and submit their complete plans to the 
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EPA. For some states, more time is necessary because of the 

state legislative schedule and/or regulatory process. In some 

cases, approval of a plan through a state’s legislative or 

regulatory process could take one year or more after the plan 

has already been developed. Additional time would also allow and 

encourage multi-state and regional partnerships and programs. 

Many stakeholders also supported flexibility in the timing 

of implementation of the state plans and power sector compliance 

with the goals in the state plans. Such flexibility, some 

stakeholders asserted, would accommodate the diverse GHG 

mitigation potential of states and support more cost-effective 

approaches to achieving CO2 reductions. 

During the outreach process, some stakeholders raised 

general concerns that the rulemaking could have a negative 

impact on jobs and ratepayers. Some stakeholders also expressed 

concerns about potential adverse effects on electric system 

reliability. Some stakeholders were concerned that meeting the 

goals could potentially result in stranded generation assets. To 

prevent this from occurring, some stakeholders suggested varying 

the stringency of standards to account for individual state 

circumstances and variation.
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The EPA has given stakeholder input careful consideration 

during the development of this proposal and, as a result, this 

proposal includes features that are intended to be responsive to 

many stakeholder concerns.

C. Key Stakeholder Proposals 

During the EPA’s public outreach in advance of this 

proposal, a number of ideas were put forward that are not fully 

reflected in this proposal. We invite public comment on these 

ideas. These ideas include those outlined below. 

1. Model rule on interstate emissions credit trading and price 

ceiling 

Some groups thought that EPA should put forward a model 

rule for an interstate emissions credit trading program that 

could be easily adopted by states who wanted to use such a 

program for its plan. One group suggested the model rule should 

include a provision to allow the state to compensate merchant 

generators as well as retail rate payers. Another group 

specified that the model rule would also include a ceiling-price 

called an alternative compliance payment that would fund state 

directed clean technology investment. Facilities that face costs 

that exceed the ceiling price could opt to pay into the fund as 

a way of complying. 
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2. Equivalency tests 

One group recommended that state programs be allowed to 

demonstrate equivalency using one of three tests: rate-based 

equivalency via a demonstration that the state program achieves 

equivalent or better carbon intensity for the regulated sector; 

mass-based equivalency via a demonstration that the program 

achieves equal or greater emission reductions relative to what 

would be achieved by the federal approach; or a market pricebased equivalency via a demonstration that the program reflects 

a carbon price comparable to or greater than the costeffectiveness benchmark used by the EPA in designing the 

program. The EPA is proposing a way to demonstrate equivalency 

and that is discussed in Section VIII. 

3. Power plant-specific assessment 

Other stakeholders suggested that an “inside the fence” 

plant- or unit-specific assessment linked to the availability of 

control at the source such as heat rate improvements should be 

considered. They indicated that once plant-specific goals are 

established based on on-site CO2 reduction opportunities, the 

source should have the flexibility to look “outside the fence” 

for the means to achieve the goals, including the use of 

emissions trading, and averaging. 
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EPA invites comment on these suggestions. 

D. Consideration of the Range of Existing State Policies and 

Programs 

Across the nation, many states and regions have shown 

strong leadership in creating and implementing policies and 

programs that reduce GHG emissions from the power sector while 

achieving other economic, environmental, and energy benefits. 

Some of these activities, such as market-based programs and GHG 

performance standards, directly require GHG emission reductions 

from EGUs. Others reduce GHG emissions by reducing utilization 

of fossil fuel-fired EGUs through, for example, renewable 

portfolio standards (RPS) and energy efficiency resource 

standards (EERS), which alter the mix of energy supply and 

reduce energy demand. States have developed their policies and 

programs with stakeholder input and tailored them to their own 

circumstances and priorities. Their leadership and experiences 

provided the EPA with important information about best practices 

to build upon in this proposed rule. As directed by the 

Presidential Memorandum,41 the EPA is, with this proposal to 

 

41 Presidential Memorandum – Power Sector Carbon Pollution 

Standards, June 25, 2013. http://www.whitehouse.gov/the-press-
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reduce power plant carbon pollution, building on actions already 

underway in states and the power sector. 

1. Market-based emission limits 

 Nine states actively participate in the Regional Greenhouse 

Gas Initiative (RGGI), a market-based CO2 emission reduction 

program addressing EGUs that was established in 2009.42 Through 

RGGI, the participating states are implementing coordinated CO2

emission budget trading programs. In aggregate, these programs 

establish an overall limit on allowable CO2 emissions from 

affected EGUs in the participating states. Participating states 

issue CO2 allowances in an amount up to the number of allowances 

in each state’s annual emission budget. At the end of each 

three-year compliance period, affected EGUs must submit CO2

allowances equal to their reported CO2 emissions. CO2 allowances 

may be traded among both regulated and non-regulated parties, 

creating a market for emission allowances. This market creates a 

price signal for CO2 emissions, which factors into the dispatch 

of affected EGUs. A price signal for CO2 emissions also allows 

 

office/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards 

42 The nine states include Connecticut, Delaware, Maine, 

Maryland, Massachusetts, New Hampshire, New York, Rhode Island, 

and Vermont.
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sources flexibility to make emission reductions where reduction 

costs are lowest, and encourages innovation in developing 

emission control strategies. 

 Approximately 90 percent of CO2 allowances are distributed 

by the RGGI participating states through auction.43 From 2009 

through 2012, the nine RGGI states invested auction proceeds of 

more than $700 million in programs that lower costs for energy 

consumers and reduce CO2 emissions.44 Through 2012, for example, 

the RGGI states invested approximately $460 million of proceeds 

into energy efficiency programs.45 The participating RGGI states 

estimate that those investments are providing benefits to energy 

consumers in the region of more than $1.8 billion in lifetime 

energy savings.46

 

43 Regional Greenhouse Gas Initiative 2013 Allowance Allocation 

http://rggi.org/design/overview/allowance-allocation/2013-

allocation. 

44 Regional Investments of RGGI CO2 Allowance Proceeds, 2012 

(2014), available at http://www.rggi.org/docs/Documents/2012-

Investment-Report.pdf 

45 Of the $707 million in auction proceeds invested by RGGI 

participating states through 2012, 65 percent supported end-use 

energy efficiency programs. See Regional Greenhouse Gas 

Initiative, “Regional Investments of RGGI CO2 Allowance Proceeds, 

2012” (2014), available at) 

http://www.rggi.org/docs/Documents/2012-Investment-Report.pdf 

46 Id.
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Between 2005, when an agreement to implement RGGI was 

announced, and 2012, power sector CO2 emissions in the RGGI 

participating states fell by more than 40 percent.47 RGGI was not 

the primary driver for these reductions but the reductions led 

RGGI-participating states to adjust the CO2 emission limits. 

downward?.48 In January 2014, the participating states lowered 

the overall allowable CO2 emission level in 2014 by 45 percent, 

setting a multi-state CO2 emission limit for affected EGUs of 91 

million short tons of CO2 in 2014 and 78 million short tons of 

CO2 in 2020, more than 50 percent below 2008 levels.49 

 Similarly, California established an economy-wide marketbased GHG emissions trading program under the authority of its 

2006 Global Warming Solutions Act, which requires the state to 

reduce its 2020 GHG emissions to 1990 levels.50 While 

California’s emission trading program, like its state emission 

 

47 Regional Greenhouse Gas Initiative, Report on Emission 

Reduction Efforts of the States Participating in the Regional 

Greenhouse Gas Initiative and Recommendations for Guidelines 

under Section 111(d) of the Clean Air Act (2013).

48 The first three-year control period under RGGI, establishing 

CO2 emission limits for EGUs, began on January 1, 2009. 49 RGGI Press Release, January 13, 2014, 

http://www.rggi.org/docs/PressReleases/PR011314_AuctionNotice23.

pdf. 

50 State of California Global Warming Solutions Act of 2006, 

Assembly Bill 32, Chapter http://www.leginfo.ca.gov/pub/05-

06/bill/asm/ab_0001-0050/ab_32_bill_20060927_chaptered.pdf 

Comment [A10]: Please clarify how they were 

adjusted. 
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limit, is multi-sector in scope, the state projects that the 

emissions trading program and related complementary measures 

will reduce power sector GHG emissions to less than 80 million 

metric tons of CO2 equivalent by 2025, a 25 percent reduction 

from 2005 power sector emission levels. 51 Prior to the 

implementation of the emission trading program, California 

reports that it reduced CO2 power sector emissions by 16 percent 

from 2005 to a 2010-2012 averaging period, a reduction of 16 

million metric tons of CO2 equivalent.52 

2. GHG performance standards 

Four states, California, New York, Oregon and Washington, 

have enacted GHG emission standards that impose enforceable 

emission limits on new and/or expanded electric generating 

units. For example, since 2012, New York requires new or 

expanded baseload plants that are greater than 25 Megawatts(MW) 

to meet an emission rate of either 925 pounds CO2/Megawatt 

hour(MWh) (based on output) or 120 pounds of CO2/ Million British 

 

51 Preliminary California Air Resources Board analyses, based in 

part on CARB 2008 to 2012 Emissions for Mandatory GHG reporting 

Summary (2013), cited in Letter to the EPA Administrator, 

“States' Roadmap on Reducing Carbon Pollution,” December 16, 

2013, 

http://www.georgetownclimate.org/sites/default/files/EPA_Submiss

ion_from_States-FinalCompl.pdf 

52Id.
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Thermal Units (MMBtu) (based on input). Similarly, non-baseload 

plants in New York of at least 25 MW or larger must meet an 

emission rate of either 1450 pounds CO2/MWh (based on output) or 

160 pounds of CO2/MMBtu (based on input).53 

Three states, California, Oregon and Washington, have 

enacted GHG emission performance standards that set an emission 

rate for electricity purchased by electric utilities. In both 

Oregon and Washington, for example, electric utilities may enter 

into long term power purchase agreements for baseload power only 

if the electric generator supplying the power has a CO2 emission 

rate of 1,100 pounds of CO2 per MWh or less.54 

3. Utility planning approaches 

Two states, Minnesota and Colorado, have worked 

collaboratively with their investor-owned utilities to develop 

multi-pollutant emission reduction plans on a utility-wide 

basis. This multi-pollutant, collaborative approach enables 

utilities to determine the least cost way to meet long term and 

comprehensive energy and environmental goals.

 

53 6 New York CoCodes, Rules & Regulations. Part 251 (Adopted 

June 28, 2012) 

54 OR SB 101 (2000); Washington Revised Code ch.80.80 (2013); 

Wash SB 6001 (2007) 
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 Colorado’s Clean Air Clean Jobs Act of 2010, for example, 

required Colorado investor-owned utilities with coal plants to 

develop a multi-pollutant plan to meet existing and reasonably 

foreseeable federal CAA requirements.55 The utilities were not 

required to adopt a specific plan set by the state but were, 

instead, required to work collaboratively with the Colorado 

Department of Public Health and Environmental and Colorado 

Public Utility Commission to develop an acceptable plan. Xcel 

Energy, Colorado’s largest investor-owned utility, submitted a 

plan that was approved in 2010. With this plan, Xcel Energy is 

projected to reduce its CO2 emissions from generation in Colorado 

by 28 percent by 2020.56 

4. Renewable portfolio standards 

 More than 25 states have mandatory renewable portfolio 

standards that require retail electricity suppliers to supply a 

minimum percentage or amount of their retail electricity load 

with electricity generated from eligible sources of renewable 

energy.57 These standards have been established via utility 

 

55 Colorado Clean Air Clean Jobs Act, HB1365 56 Xcel Energy, Colorado Clean Air-Clean Jobs Plan, available at 

http://www.xcelenergy.com/Environment/Doing_Our_Part/Clean_Air_P

rojects/Colorado_Clean_Air_Clean_Jobs_Plan. 

57 http://www.dsireusa.org/ 
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regulatory commissions, legislatures and citizen ballots and 

requirements vary from state to state. State RPS typically 

specify the types of renewable energy, or other energy sources, 

that qualify for use toward achievement of the standard, and 

often allow for the use of qualifying renewable energy resources 

located outside of the state. They reduce utilization of fossil 

fuel-fired EGUs and, thereby, lead to reductions in GHG 

emissions by meeting a portion of the demand for electricity 

through renewable or other energy sources. 

 In 2007, the Minnesota legislature amended the state’s 2001 

renewable energy objective and established a renewable energy 

standard (RES) requiring at least 25 percent of all electricity 

generated or purchased in Minnesota to come from renewable 

energy , including biomass, by 2025. The standard sets 

requirements and timetables, beginning in 2010, that vary based 

on the provider. For example, in 2011, Xcel Energy had a 

requirement to generate or purchase 15 percent of its total 

retail sales from renewable energy while all other utilities had 

a target of 7 percent of total retail sales. According to the 

latest Minnesota Department of Commerce report to the 

legislature on progress, all utilities subject to the standard 

Comment [A11]: Consider adding biomass as an 

example here 

Comment [A12]: Added text 
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met it for 2011 and were on track to meet their 2012 goals.58 The 

2012 requirement increased to 18 percent of total retail sales 

for Xcel Energy and 12 percent for all other utilities.59 In 

2013, the Minnesota legislature expanded the RES with solar 

incentives and a specific solar energy standard requiring 

Minnesota utilities to ensure that at least 1.5 percent of their 

retail electricity sales in 2020 come from solar energy.60

 The Oregon Renewable Portfolio Standard (RPS) is another 

example of a state requirement for renewables. Originally 

enacted in 2007, it requires that all utilities serving 

OregonloadOregonloadOregon loadOregonload meet a percentage of 

their retail electricity needs with qualified renewable 

resources, including biomass. Like in Minnesota, the percentage 

varies across utilities with the three largest utilities 

required to reach five percent from renewable energy sources 

starting in 2011, 15 percent in 2015, 20 percent in 2020, and 25 

 

58 Report to the Minnesota Legislature: Progress on Compliance By 

Electric Utilities With The Minnesota Renewable Energy Objective 

and the Renewable Energy Standard, Prepared by: The Minnesota 

Department of Commerce, Division of Energy Resources January 

14, 2013; 

http://mn.gov/commerce/energy/images/2013RESLegReport.pdf

59 Id. 60 Minnesota Statutes 2013, Section 216B.1691, Subdivision 2f. 

Solar Energy Standard 

https://www.revisor.mn.gov/statutes/?id=216b.1691

Comment [A13]: Added 

Formatted: Default Paragraph Font, Font:

Times New Roman, 10 pt
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percent in 2025. Other electric utilities in the state are 

required to reach levels of five percent or ten percent by 2025, 

depending on their size. According to the latest RPS compliance 

reports submitted by the largest utilities for the state, each 

had achieved the five percent target as of the end of 2012.61 

5. Demand-side energy efficiency programs 

Many electric utilities, third-party administrators, and 

states implement demand-side energy efficiency programs to 

reduce generation from EGUs by reducing electricity use, 

including peak demand. These programs use a variety of energy 

efficiency measures to target a variety of end uses and are 

often driven by existing state standards and programs, such as 

policies requiring utilities to obtain “all cost-effective 

energy efficiency” through long-term integrated resource 

planning (IRP), renewable portfolio standards (RPS) that include 

efficiency as a qualifying resource, energy efficiency resource 

standards (EERS), public benefit funds, and other demand-side 

planning requirements. 

 

61 Eugene Water Electric Board Oregon Renewable Portfolio 

Standard 2012 Compliance Report and 2013 – 2030 Implementation 

Plan, June 1, 2013. PacifiCorp's Renewable Portfolio Standard 

Oregon Compliance Report for 2012, May 31, 2013. PGE 2012 

Renewable Portfolio Standard Compliance Report, June 1, 2013. 

Comment [A14]: Just highlighting that here EPA 

is more accurately describing the reason for these 

programs, rather than to reduce CO2. EPA sure be 

sure they present a consistent explanation. 
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The purposes of demand-side energy efficiency programs 

vary; goals include to reduce GHG emissions by reducing fossilfired generation, help states achieve energy savings goals, save 

energy and money for consumers and improve electricity 

reliability. They are typically funded through a small fee or 

surcharge on customer electricity bills, but can also be funded 

by other sources, such as from RGGI CO2 allowance auction 

proceeds mentioned above. 

Nationally, total spending on electric ratepayer-funded 

energy efficiency programs was about $5 billion in 2012.62 Based 

on Lawrence Berkeley National Laboratory (LBNL) projections, 

spending is projected to reach $8.1 billion in 2025.63 

Electricity savings from energy efficiency programs are 

also growing. In 2011, electricity savings from these programs 

 

61 Consortium for Energy Efficiency Annual Industry Report: 2013 

State of the Efficiency Program Industry – Budgets, Expenditures 

and Impacts, 2014. 

http://library.cee1.org/sites/default/files/library/11350/CEE_20

13_Annual_Industry_Report.pdf

63 Lawrence Berkeley National Laboratory (LBNL) The Future of 

Utility Customer-Funded Energy Efficiency Programs in the United 

States: Projected Spending and Savings to 2025 

(http://emp.lbl.gov/sites/all/files/lbnl-5803e.pdf) 
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totaled approximately 22.9 million MWh, a 22 percent increase 

from the previous year.64 

California has been advancing energy efficiency through 

utility-run demand-side energy efficiency programs for decades 

and considers energy efficiency “the bedrock upon which climate 

policies are built.”65 It requires its investor-owned utilities 

to meet electricity load “through all available energy 

efficiency and demand reduction resources that are costeffective, reliable and feasible.”66 The California Public 

Utility Commission works with the California Energy Commission 

to determine the amount of cost-effective reduction potential 

and establishes efficiency targets. A recent energy efficiency 

potential study found that, even after years of running 

programs, California can still tap “tens of thousands of GWh in 

potential savings... over the next decade.”67 Investor-owned 

 

64 American Council for an Energy Efficient Economy (ACEEE) 2013 

State Scorecard 

http://www.aceee.org/sites/default/files/publications/researchre

ports/e13k.pdf 

65 December 27, 2013 Letter from Mary D. Nichols, Chairman of 

California Air Resources Board, to EPA Administrator Gina 

McCarthy.

66 Cal Pub. Utility Code §454.5 (a)(9)(C). 67 Cited in December 27, 2013 Letter from Mary D. Nichols, 

Chairman of California Air Resources Board, to EPA Administrator 

Gina McCarthy.
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utilities use demand-side energy efficiency programs to achieve 

their targets and currently “save about 3,000 GW per year, 

enough savings to power about 600,000 households.”68 Between 2010 

and 2011, these programs are estimated to have reduced CO2 by 3.8 

million tons.69 

 In Vermont, for example, the Vermont Legislature and the 

Vermont Public Service Board (PSB) established the first 

statewide “energy efficiency utility” in 1999 to provide energy 

efficiency services to residences and businesses throughout the 

state.70 Vermont law requires that the energy efficiency utility 

budgets be set at a level to achieve “all reasonably available, 

cost-effective energy efficiency” and then specific energy (kWh) 

and peak demand (kW) savings levels are negotiated every three 

years.71 In 2013, Efficiency Vermont, the PSB-appointed energy 

efficiency utility, achieved annual savings of 1.66 percent of 

the state’s electricity sales, at a cost of 4.1 cents per 

 

68 Id. 69 Id. 70 State of Vermont Public Service Board, Energy Efficiency 

Utility Creation and Structure. 

http://psb.vermont.gov/utilityindustries/eeu/generalinfo/ 

creationandstructure

71 Vermont Statute, Title 30: Public Service, 30 V.S.A. § 209 

(d)3(B). 

http://www.leg.state.vt.us/statutes/fullsection.cfm?Title=30&Cha

pter=005&Section=00209 
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kilowatt‐hour, lower than the cost of comparable electric supply 

in the same year, which was 8.4 cents per kWh.72 Efficiency 

Vermont projects a net lifetime economic value to Vermont of 

more than $60 million from the 2013 energy efficiency 

investments.73 

6. Energy efficiency resource standards 

 More than 20 states have energy efficiency resource 

standards (EERS) that require utilities to save a certain amount 

of energy each year or cumulatively.74 They are typically multiyear requirements expressed as a percentage of annual retail 

electricity sales or as specific electricity savings amounts 

over a long term period relative to a baseline of retail sales. 

Over the compliance period, an EERS reduces fossil-fired EGU 

generation through reductions in electricity demand, thereby 

reducing CO2 emissions from the power sector. 

 

72 Efficiency Vermont Savings Claim Summary 2013, Reported to the 

Vermont Public Service Board and to the Vermont Public Service 

Department, 2014, 

https://www.efficiencyvermont.com/docs/about_efficiency_vermont/

annual_summaries/2013_savingsclaim_summary.pdf. 

73 Id. 74 State Energy Efficiency Resource Standards: Policy Design, 

Status, and Impacts, D.C. Steinberg, O. Zinaman, NREL Technical 

Report NREL/TP-6A20-61023, April 2014.
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In Arizona, for example, the Arizona Corporation Commission 

(ACC) adopted rules in 2010 requiring all investor-owned 

utilities to achieve 22 percent cumulative electricity savings 

by 2020, making it one of the highest standards in the nation.75

The rule required utilities to achieve 1.25 percent electricity 

savings in 2011 compared to electricity sales in the previous 

year, ramping up the savings each year until 2020 according to a 

designated timetable.76 In 2012, for example, investor-owned 

utilities were required to achieve energy savings equivalent to 

1.75 percent of the 2011 sales, leading to a cumulative savings 

requirement of 3 percent by the end of 2012 (an average of 1.5% 

annually over the 2 year period).77 Utilities can meet the energy 

savings requirements through a variety of means, including costeffective energy efficiency programs, as well as load management 

and demand response programs.78 Arizona Public Service Company 

(APS), the largest utility in Arizona, achieved cumulative 

 

75 Arizona Corporation Commission, Docket RE-OOOOOC-09-0427, 

August 2010., Available at 

http://images.edocket.azcc.gov/docketpdf/0000116125.pdf

76 Id. 77 Arizona Corporation Commission, Docket RE-OOOOOC-09-0427, 

August 2010., Available at 

http://images.edocket.azcc.gov/docketpdf/0000116125.pdf

78 Id. 
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energy savings equivalent to 3.2 percent of retail sales from 

2011 to 2012, exceeding the 3 percent savings target, and 

reported a net benefit to consumers of more than $200 million 

for the year 2012 alone.79

E. Conclusions 

States have taken a leadership role in mitigating GHG 

emissions and have demonstrated the potential for national 

application of a number of approaches. Throughout the 

development of this proposed rule, the EPA considered the 

states’ experiences and lessons learned regarding the design and 

implementation of successful GHG mitigation programs. The agency 

also fully considered input from stakeholders during the 

development of this proposed rulemaking. 

Considering all input from stakeholders, the agency 

recognizes that the most cost-effective approach to reducing GHG 

emissions from the power sector under CAA section 111(d) is to 

follow the lead of numerous states and not only to identify 

improvements in the efficiency of fossil fuel-fired EGUs as a 

component of BSER, but also include in the BSER determination 

 

79 Arizona Public Service Company 2012 Demand Side Management 

Annual Progress Report, March 1, 2013 website, 

http://www.aps.com/en/ourcompany/aboutus/energyefficiency/Pages/

home.aspx 
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the EGU-emissions-reduction opportunities that states have 

already demonstrated to be successful in relying on lower- and 

zero-emitting generation and reduced electricity demand. 

CAA section 111(d) sets up a partnership between the EPA 

and the states. In the context of that partnership, the EPA 

recognizes the importance of each state having the flexibility 

to design a cost-effective program tailored to its own specific 

circumstances. The agency also recognizes, as many states have, 

the value of regional planning in designing approaches to 

achieve cost-effective GHG reductions. To support state 

flexibility and encourage multi-state coordination in the 

development of multi-state and regional programs and policies, 

the EPA recognizes that flexibility in both the timing of plan 

submittal and the timing of CO2 emission reductions will be 

necessary. 

IV. Rule Requirements and Legal Basis 

A. Summary of Rule Requirements 

The EPA is proposing emission guidelines for each state to 

use in developing plans to address greenhouse gas emissions from 

existing fossil fuel-fired electric generating units. The 

emission guidelines are based on the EPA’s determination of the 

“best system of emission reduction... adequately demonstrated” 
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(BSER), and include: state-specific goals, general approvability 

criteria for state plans, requirements for state plan 

components, and requirements for the process and timing for 

state plan submittal and compliance. 

Under CAA section 111(d), the states must establish 

standards of performance that reflect the degree of emission 

limitation achievable through the application of the “best 

system of emission reduction” (BSER) that, taking into account 

the cost of achieving such reduction and any non-air quality 

health and environmental impact and energy requirements, the 

Administrator determines has been adequately demonstrated. 

Consistent with CAA section 111(d), the EPA is proposing statespecific goals that reflect the EPA’s calculation of the 

emission reductions that a state can achieve through the costeffective application of BSER. 

Under CAA section 111(d), each state must develop, adopt, 

and then submit its plan to the EPA. To do so, the state would 

determine the emission performance level it will include in its 

plan by deciding whether it will adopt the rate-based CO2 goal 

set by the EPA or translate the rate-based goal into a massbased goal. The state would then establish a standard of 

performance or set of standards of performance (known as 
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emission standards under the existing 111(d) framework 

regulations), along with implementing and enforcing measures, 

that will achieve a level of emission performance that equals or 

exceeds the level specified in the state plan. 

The EPA is proposing to determine the “best system of 

emission reduction ... adequately demonstrated” (BSER) as the 

combination of emission rate improvements and limitations on 

overall emissions at affected EGUs that can be accomplished 

through the following four sets of measures, or building blocks: 

1. Reducing the carbon intensity of generation at 

individual affected EGUs through heat rate improvements. 

2. Reducing emissions of the most carbon-intensive affected 

EGUs in the amount that results from substituting 

generation at those EGUs with generation from less carbonintensive affected EGUs (including NGCC units that are 

under construction). 

3. Reducing emissions of affected EGUs in the amount that 

results from substituting generation at those EGUs with 

expandedlow- or zero-carbon generation. 

4. Reducing emissions from affected EGUs in the amount that 

results from the use of demand-side energy efficiency that 

reduces the amount of generation required. 
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The proposed state goals reflect the following stringency 

of application of the measures in each of the building blocks: 

Block 1, improving average heat rate of coal-fired steam EGUs by 

six percent; block 2, displacing coal-fired steam and oil/gasfired steam generation in each state by increasing generation 

from existing NGCC capacity in that state toward a 70 percent 

target utilization rate; block 3, including some amount of 

generation from nuclear units under construction, avoiding 

retirement of about eight percent of existing nuclear capacity, 

and increasing renewable electricity generation over time 

through the use of state-level renewable generation targets 

consistent with renewable generation portfolio standards that 

have been established by states in the same region; and block 4, 

increasing state demand-side energy efficiency efforts to reach 

1.5 percent annual electricity savings in the 2020-2029 period. 

Based on the EPA’s application of the BSER to each state, 

the EPA is proposing to establish, as part of the emission 

guidelines, state-specific goals, expressed as average emission 

rates for fossil fuel-fired EGUs. Each state’s goals comprise 

the EPA’s determination of the emission limitation achievable 

through application of the BSER in that state. For each state, 

the EPA is proposing an interim goal for the phase-in period 
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from 2020 to 2029 and the final goal that applies beginning in 

2030. The proposed goals for each state are listed in Section 

VII, below. The EPA is proposing that measures that a state 

takes after the date of this proposal, and which result in CO2 

emission reductions during the plan period, would apply toward 

achievement of the state’s CO2 goal. 

The EPA is further proposing, as part of the plan 

guidelines, timetables for states to submit their plans. The

agency expects to finalize this rulemaking by June 2015, and we 

are proposing to require that each state submit its plan to the 

EPA by June 30, 2016. However, if a state needs additional time 

to submit a complete plan, then the state must notify the EPA by 

letter of such intent by no later than April 1, 2016. In this 

letter, the state must adequately explain why more time is 

needed to submit a complete plan, outline the actions it is 

currently taking to develop a plan and commit to meet all of the 

requirements for an initial submittal by June 30, 2016. A state 

that submits an initial plan with the proper components will 

receive an extension of time to submit a complete plan. If such 

a state is developing a plan limited in geographical scope to 

the individual state, then the state would have until June 30, 

2017, to submit a complete plan. A state that is developing a 

Comment [A15]: 2016? Then why are they 

submitting a letter of intent to EPA? 
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plan that includes a multi-state approach would have until June 

30, 2018, to submit a complete plan. 

The EPA is further proposing, as part of the emission 

guidelines, to allow states the option of translating the EPAdetermined goal, which will be rate-based, to a mass-based goal. 

For states participating in a multi-state approach, the 

individual state performance goals in the emission guidelines 

would be replaced with an equivalent multi-state performance 

goal. The EPA is also proposing that in their plans, whether 

single state or multi-state, states may not adjust the 

stringency of thehave less stringent goals than those set by the 

EPA. 

Under CAA section 111(d)(1) and the implementing 

regulations, with the state emission performance level in place, 

the state must adopt a state plan that establishes a standard of 

performance or set of standards of performance, along with 

implementing and enforcing measures, that will achieve that 

emission performance level. The EPA is further proposing, as 

part of the guidelines, to authorize the state to submit either 

of two types of measures to achieve the performance level: 1) a 

set of measures that we refer to as “portfolio” measures, which 

include a combination of emission limitations that apply 

Comment [A16]: How and when is this 

determined? Is it a weighted average based on each 

state’s generation? 

Comment [A17]: States can be more stringent 

than EPA, right? 
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directly to the affected sources and other measures that have 

the effect of limiting generation by, and therefore emissions 

from, the affected sources; or 2) solely emission limitations 

that apply directly to the affected sources. 

The EPA is also proposing, as part of the plan guidelines, 

that a complete state plan include the following twelve 

components: 

 Identification of affected entities 

 Description of plan approach and geographic scope 

 Identification of state emission performance level 

 Demonstration that plan is projected to achieve emission 

performance level 

 Identification of emissions standards 

 Demonstration that each emissions standard is 

quantifiable, non-duplicative, permanent, verifiable, 

and enforceable 

 Identification of monitoring, reporting, and 

recordkeeping requirements 

 Description of state reporting 

 Identification of milestones 

 Identification of backstop measures 

 Certification of hearing on state plan 

 Supporting material 

The EPA is also proposing, as part of its emission 

guidelines, that plan approvability be based on four general 

criteria: 1) enforceable measures that reduce EGU CO2 emissions; 

2) projected achievement of emission performance equivalent to 

the goals established by the EPA, on a timeline equivalent to 
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that in the emission guidelines; 3) quantifiable and verifiable 

emission reductions; and 4) a process for reporting on plan 

implementation, progress toward achieving CO2 goals, and 

implementation of corrective actions, if necessary.

 The EPA is also proposing, as part of its plan guidelines, 

requirements for the process and timing for demonstrating 

achievement of the required emission performance level, 

including performance and emission milestones. The proposed 

option would require each state to achieve its ultimate CO2 

emission performance level by 2030 and, in addition, provide an 

initial, phase-in compliance period of up to 10 years, from 2020 

up to 2029, for a state and/or other responsible parties to 

comply with the emission performance level in the state plan. A 

state would need to meet its interim 2020-2029 CO2 emission 

performance level on average over the 10-year phase-in 

compliance period and also achieve its final CO2 emission 

performance level by 2030 and maintain it thereafter. 

 If a state with affected EGUs does not submit a plan, or if 

the EPA does not approve a state’s plan, then, under CAA section 

111(d)(2)(A), the EPA must establish a plan for that state. 

 A state that has no affected EGUs must document this in a 

formal letter submitted to the EPA by June 30, 2016. In the case 
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of a tribe that has one or more affected EGUs in its area of 

Indian country,80 the tribe would have the opportunity, but not 

the obligation, to establish a CO2 emission performance standard 

and a CAA section 111(d) plan for its area of Indian country. 

B. Summary of Legal Basis 

The EPA believes that today’s proposed action is consistent 

with the requirements of CAA section 111(d) and the framework 

regulations. As an initial matter, the EPA reasonably interprets 

the provisions concerning the air pollutants covered under CAA 

section 111(d) to authorize the EPA to regulate CO2 from EGUs. We 

recognize that CAA section 111(d) applies to sources that, if 

they were new sources, would be covered under a CAA section 

111(b) rule. The EPA intends to complete the CAA section 111(b) 

rulemaking regulating CO2 from new EGUs, and that rulemaking will 

provide the requisite predicate for this rulemaking. 

A key step in promulgating requirements under CAA section 

111(d) is determining the “best system of emission reduction ... 

 

80 The EPA is aware of at least four affected EGUs located in 

Indian country: two on Navajo lands, the Navajo Generating 

Station and the Four Corners Generating Station; one on Ute 

lands, the Bonanza Generating Station; and one on Fort Mojave 

lands, the South Point Energy Center. The affected EGUs at the 

first three plants are coal-fired EGUs. The fourth affected EGU 

is an NGCC facility. 
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adequately demonstrated” (BSER). In promulgating the framework 

regulations, the EPA explicitly stated that it is authorized to 

determine BSER;81 Accordingly, in this rulemaking, the EPA is 

determining BSER. 

The four building blocks include two types of measures 

that, together, comprise BSER for fossil-fired EGUs. Building 

block 1 provides the basis for identifying carbon intensity 

improvements as a component of BSER. Building blocks 2, 3, and 4 

provide the foundation for the achievability of mass emissions 

limits at these EGUs. The EPA reasonably identified both types 

of measures as components of BSER based on the factors that the 

EPA is required to consider and the EPA’s authority to weigh 

those factors. 

In addition, the measures in building blocks 2, 3, and 4 

may be viewed as separate measures that reduce emissions by 

replacing the demand for generation at coal-fired EGUs. Because 

of the integration of the electricity system and the fungibility 

of electricity, these measures must be considered part of the 

system of emission reduction for fossil-fired EGUs. 

 

81 The EPA is not re-opening that interpretation in this 

rulemaking. 
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Moreover, the measures in each of the building blocks are 

“adequately demonstrated,” including as being technically 

feasible and reasonable in terms of cost. Heat improvement 

measures are well-recognized as feasible within the industry. 

The measures that entail dispatch changes from coal-fired EGUs 

to NGCC units, investments in renewable energy, and demand-side 

energy efficiency are each well-established in numerous states, 

and many of them have already been relied on to reduce GHGs and 

other air pollutants from fossil fuel-fired EGUs. Further, all 

of the measures achieve an important degree of emission 

reduction. In addition, they are not unreasonably costly, 

particularly when considered on the level of the nation’s 

electricity system. Importantly, the measures encourage the 

development and expansion of technology and practices to reduce 

CO2 and are consistent with current trends in the electricity 

sector. 

After determining BSER, the EPA is authorized under the 

framework regulations, as an integral component to setting 

emission guidelines, to apply the BSER to each state and 

determine the resulting emission limitation for each state. 

 With the promulgation of the emission guidelines, each 

state must develop a plan to achieve its emission performance 
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level. The state plans must establish standards of performance 

and include measures that implement and enforce those measures. 

Based on requests from stakeholders, the EPA is proposing 

that states be authorized to submit state plans that do not 

impose legal responsibility on the affected EGUs for the 

entirety of the emission performance level, but instead impose 

requirements on other affected entities – for requirements, such 

as renewable energy and demand-side energy efficiency measures, 

that would avoid reduce CO2 emissions from the affected EGUs. 

The EPA solicits comment on whether such requirements on other 

affected entities may be authorized as standards of performance 

or implementing measures in a state’s CAA section 111(d) plan. 

The EPA also solicits comment on whether state plans must impose 

all of the legal responsibility for achieving the emission 

performance level on the affected EGUs. We note that even if as 

a legal matter states would be required to impose responsibility 

in such a way, the state plan – and state policy – nevertheless 

still could include requirements on other affected entities in 

order to facilitate, as a practical and economic matter, 

implementation of measures that avoid CO2 emissions from affected 

EGUs. We emphasize that the states have discretion as to the 

Comment [A18]: This is awkward – see 

suggested edit. 
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form of the standards of performance and may include emission 

trading programs. 

 To comply with the applicable standards of performance, 

sources may rely on any efficacious means of emission reduction, 

regardless of whether the EPA identifies those measures as part 

of BSER. 

 In this rulemaking, the EPA proposes reasonable deadlines 

for state plan submission and the EPA’s action. The proposed 

deadlines vary from those in the framework regulations. 

V. Authority to Regulate Carbon Dioxide, Affected Sources, 

Treatment of Categories

A. Authority to Regulate Carbon Dioxide 

The EPA has the authority to regulate, under CAA section 

111(d), CO2 emissions from EGUs, under the Agency’s construction 

of the ambiguous provisions in CAA section 111(d)(1)(A)(i) that 

identify the air pollutants subject to CAA section 111(d). The 

ambiguities stem from apparent drafting errors that occurred 

during enactment of the 1990 CAA Amendments, which revised 

section 111(d). 

During the 1990 CAA Amendments, the House of 

Representatives and the Senate each passed an amendment to CAA 

section 111(d)(1)(A)(i). The two amendments differed from each 
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other, and were not reconciled during the Conference Committee 

and, as a result, both were enacted into law. As amended, CAA 

section 111(d)(1) requires states to submit standards of 

performance for existing sources “for any air pollutant (i) for 

which air quality criteria have not been issued or which is not 

included on a list published under [CAA] section 108(a)... [or 

emitted from a source category which is regulated under section 

112]82 [or 112(b)]83... ” The bracketed and emphasized provisions 

set forth the House and Senate versions, respectively. The two 

versions conflict with each other and thus are ambiguous. Under 

these circumstances, the EPA may reasonably construe the 

provision to authorize the regulation of GHGs under CAA section 

111(d). 

It should be noted that the U.S. Supreme Court’s holding in 

American Electric Power Co. v. Connecticut, 131 S. Ct. 2527, 

2537-38 (2011), that “the Clean Air Act and the EPA actions it 

authorizes displace any federal common law right to seek 

abatement of carbon-dioxide emissions from fossil fuel-fired 

power plants” was premised on the Court’s understanding that CAA 

 

82 Pub. L. No. 101-549, §108(g), 104 Stat. at 2467 (Nov. 15, 

1990).

83 Pub. L. No. 101-549, §302(a), 104 Stat. at 2574 (Nov. 15, 

1990).
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section 111, including CAA section 111(d), applies to carbon 

dioxide emissions from those sources. 

We discuss this issue in more detail in the Legal Memorandum.

B. Authority to Regulate EGUs 

Before the EPA finalizes this CAA section 111(d) rule, the 

EPA will finalize a CAA section 111(b) rulemaking regulating CO2

emissions from new EGUs, which will provide the requisite 

predicate for applicability of CAA section 111(d). 

 CAA section 111(d)(1) requires the EPA to promulgate 

regulations under which states must submit state plans 

regulating “any existing source” of certain pollutants “to which 

a standard of performance would apply if such existing source 

were a new source.” A “new source” is “any stationary source, 

the construction or modification of which is commenced after the 

publication of regulations (or, if earlier, proposed 

regulations) prescribing a standard of performance under [CAA 

section 111] which will be applicable to such source.” It should 

be noted that these provisions make clear that a “new source” 

includes one that undertakes either new construction or a 

modification. It should also be noted that EPA’s implementing 

regulations define “construction” to include “reconstruction,” 

which the implementing regulations go on to define as the 
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replacement of components of an existing facility to an extent 

that (i) the fixed capital cost of the new components exceeds 50 

percent of the fixed capital cost that would be required to 

construct a comparable entirely new facility, and (ii) it is 

technologically and economically feasible to meet the applicable 

standards. 

 Under CAA section 111(d)(1), in order for existing sources 

to become subject to that provision, the EPA must promulgate 

standards of performance under CAA section 111(b) to which, if 

the existing sources were new sources, they would be subject. 

Those standards of performance may include ones for sources that 

undertake new construction, modifications, or reconstructions. 

The EPA is in the process of promulgating two rulemakings under 

CAA section 111(b) for CO2 emissions from affected sources. The 

EPA proposed the first, which applies to affected sources 

undertaking new constructions, by notice dated January 8, 2014, 

which we refer to as the January 2014 Proposal. The EPA is 

proposing the second, which applies to affected sources 

undertaking modifications or reconstructions, concurrently with 

this CAA section 111(d) proposal. The EPA will complete one or 

both of these CAA section 111(b) rulemakings before or 

concurrently with this CAA section 111(d) rulemaking, which will 
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provide the requisite predicate for applicability of CAA section 

111(d). 

C. Affected Sources 

The EPA is proposing that, for the emission guidelines, 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 1429; January 8, 2014). 

The January 8, 2014 proposed GHG standards for new EGUs 

generally define an affected EGU as any boiler, integrated 

gasification combined cycle (IGCC), or combustion turbine (in 

either simple cycle or combined cycle configuration) that (1) is 

capable of combusting at least 250 million Btu per hour; (2) 

combusts fossil fuel for more than 10 percent of its total 

annual heat input; (3) sells the greater of 219,000 MWh per year 

or one-third of its potential electrical output to a utility 

distribution system; and (4) was not in operation or under 

construction as of January 8, 2014 (the date the proposed GHG 

standards of performance for new EGUs were published in the 

Federal Register). The minimum fossil fuel consumption condition 
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applies over any consecutive three-year period (or as long as 

the unit has been in operation, if less). The minimum 

electricity sales condition applies over rolling three-year 

periods (or as long as the unit has been in operation, if less). 

The rationale for this proposal concerning applicability is 

the same as that for the January 8, 2014 proposal, sections V.AB. See 79 FR at 1,459/1 – 1,461/2. We incorporate that 

discussion by reference here. 

D. Combined Categories and Codification in the Code of Federal 

Regulations 

In this rulemaking, the EPA is co-proposing combining the 

two existing categories for the affected EGUs into a single 

category for purposes of facilitating emission trading among 

sources in both categories. The EPA is also co-proposing 

codifying all of the proposed requirements for the affected EGUs 

new subpart UUUU of 40 CFR part 60. 

As discussed in the January 2014 proposal for the CAA 

section 111(b) standards for GHG emissions from EGUs, in 1971 

the EPA listed fossil-fuel fired steam generating boilers as a 

new category subject to section 111 rulemaking, and in 1979 the 

EPA listed fossil fuel-fired combustion turbines as a new 

category subject to the CAA section 111 rulemaking. In the 
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ensuing years, the EPA has promulgated standards of performance 

for the two categories, and codified those standards, at various 

times, in 40 CFR part 60 subparts D, Da, GG, and KKKK. In the 

2014 proposal, the EPA proposed separate standards of 

performance for sources in the two categories and proposed 

codifying the standards in the same Da and KKKK subparts that 

currently contain the standards of performance for conventional 

pollutants from those sources. In addition, the EPA co-proposed 

combining the two categories into a single category solely for 

purposes of the CO2 emissions from new construction of affected 

EGUs, and codifying the proposed requirements in a new 40 CFR 

part 60 subpart TTTT. The EPA solicited comment on whether 

combining the categories for new sources is necessary in order 

to combine the categories for existing sources. 

In the present rulemaking, the EPA is proposing emission 

guidelines for the two categories and is co-proposing to combine 

the two categories into a single category for purposes of the CO2 

emissions from existing affected EGUs. The EPA solicits comment 

on whether combining the two categories would offer additional 

flexibility, for example, by facilitating implementation of CO2

mitigation measures, such as shifting generation from higher to 

lower-carbon intensity generation among existing sources (e.g., 
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shifting from boilers to NGCC units) or facilitating emissions 

trading among sources. Because the two categories are preexisting and the EPA would not be subjecting any additional 

sources to regulation, the combined category would not be 

considered a new category that the EPA must list under CAA 

section 111(b)(1)(A). As a result, this proposal does not list a 

new category under section 111(a)(1)(A), nor does this proposal 

revise either of the two source categories – steam-generating 

boilers and combustion turbines – that the EPA has already 

listed under that provision. Thus, the EPA would not be required 

to make a finding that the combined category causes or 

contributes significantly to air pollution which may reasonably 

be anticipated to endanger public health or welfare. 

In addition, the EPA is co-proposing two options for 

codifying the emission guidelines for affected sources. Under 

the first option, the EPA is proposing to codify the standards 

of performance for the respective sources within existing 40 CFR 

part 60 subparts: subpart Da, electric utility steam generating 

units, which includes steam electric utility boilers and IGCC 

units, and subpart KKKK, stationary combustion turbines, which 

includes both simple cycle and combined cycle stationary 

combustion turbines. Emission guidelines for electric utility 
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steam generating units would be included in subpart Da and 

emission guidelines for stationary combustion turbines would be 

included in subpart KKKK. 

Under the second option, the EPA is proposing to create a 

new subpart UUUU and to include all GHG emission guidelines for 

the affected sources -- utility boilers and IGCC units as well 

as natural gas-fired stationary combustion turbines -- in that 

newly created subpart. We believe that combining the emission 

guidelines for affected sources into a new subpart UUUU is 

appropriate because the emission guidelines the EPA is 

establishing do not vary by type of source. 

We solicit comment on the relative merits of each approach. 

In particular, we seek comment on whether the co-proposal to 

combine the categories and codify the GHG emission guidelines 

for all existing affected sources in subpart UUUU would offer 

any additional flexibility in the ways described above. 

VI.Building Blocks for Setting State Goals and Considerations 

A. Introduction 

Based on the experiences of states and the industry and the 

EPA’s outreach with stakeholders as described above, the EPA has 

identified multiple measures currently in use for achieving CO2
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emissions from existing fossil fuel-fired EGUs. For purposes of 

determining the “best system of emission reduction ... 

adequately demonstrated” (BSER) and developing state emission 

performance goals, we have screened the measures and grouped 

those we are proposing to consider further at this time into 

four categories, which we call “building blocks.” We provide an 

overview of these building blocks in subsection VI.B. and more 

detailed discussion of each block in subsection VI.C. In 

subsection VI.D. we discuss possible combinations of the 

building blocks, and in subsection VI.E., we explain why as a 

legal matter all four building blocks, taken together, 

constitute the basis for the BSER, which in turn serves as the 

basis for the standards of performance that the states must 

include in their state plans, as CAA section 111(d) requires. 

As discussed in Section III, we are mindful of numerous and 

varied stakeholder concerns, including the need to achieve 

meaningful CO2 emission reductions and to recognize and take 

advantage of the progress already made by existing programs. 

Like stakeholders, we are attentive to the need to maintain 

electric system reliability and to minimize adverse impacts on 

electricity and fuel prices and on assets that have already been 

improved by installation of controls for other kinds of 
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pollution. Many of these considerations align with our approach 

to applying the building blocks, as discussed more in Section 

VII, and we consider several of these to be key principles in 

this application. As discussed in Sections VII and VIII, we 

acknowledge and appreciate the advantages of allowing and 

promoting flexibility for states in crafting their programs. We 

recognize the knowledge that states have about their specific 

situations and their ability to evaluate and leverage existing 

and new capacity and programs to ultimately reduce EGU CO2

emissions. 

Similarly, we recognize and appreciate that states operate 

with differing circumstances and policy preferences. For 

example, states have differing access to specific fuel types, 

and the variety of types of EGUs operating in different states 

is broad and significant. States are part of assorted EGU 

dispatch systems and vary in the amounts of electricity that 

they import and export. For these reasons, we also recognize and 

appreciate the value in allowing and promoting regional and 

multi-state reduction strategies. Some states already 

participate in a regional program that reduces CO2 emissions, the 

RGGI, and we have noted the success of that program for those 

states. 
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Another key consideration in application of these building 

blocks, as discussed more in the following sections, is the 

relationship between the timing of measures and their 

effectiveness in limiting emissions. For example, actions that 

can occur in the near-term, such as improvements to individual 

EGU heat rates, may fail to achieve the cumulative emissions 

reductions that sustained implementation of other actions, such 

as demand-side energy efficiency programs, may achieve over 

time. 

B. Building Blocks for the Best System of Emission Reduction

This subsection summarizes the EPA’s analytic approach to 

determining the best system of emission reduction (BSER) for CO2

emissions from existing EGUs. Further discussion of particular 

measures and how they form the basis of the BSER is provided 

below in subsections VI.C and VI.D, respectively. 

1. Overview of approach 

 In considering the appropriate scope of the proposed BSER, 

the EPA evaluated three basic groupings of strategies for 

reducing CO2 emission from EGUs: (i) reductions achievable 

through improvements in individual EGUs’ emission rates 

(referred to throughout this preamble as "building block 1"); 

(ii) EGU CO2 emissions reductions achievable through re-dispatch 
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from affected steam EGUs to affected NGCC units ("building block 

2"); and (iii) EGU CO2 emissions reductions achievable by 

meeting demand for electricity or electricity services through 

expanded use of low- or zero-carbon generating capacity 

(“building block 3”) and of increased demand-side energy 

efficiency (“building block 4”). 

As described in the remainder of this section, the EPA 

concluded that while certain strategies within the first 

grouping clearly should be part of the BSER, it was not 

appropriate to limit consideration of the BSER to this first 

grouping, for several reasons. First, we determined that some 

strategies available in the other two groupings can reduce CO2

emissions from the fossil fuel-fired EGUs by significant amounts 

and at lower costs than some of the strategies in the first 

grouping. Second, we observed that strategies in all three 

groupings were already being pursued by states and sources 

taking advantage of the integrated nature of the electricity 

system, at least in part for the purpose of reducing CO2

emissions. Third, we were concerned that if measures from the 

first grouping that improve heat rates at coal-fired steam EGUs 

were implemented in isolation, without additional measures that 

encourage substitution of less carbon-intensive ways of 
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providing electricity services for more carbon-intensive 

generation, the resulting increased efficiency of coal-fired 

steam units would provide incentives to operate those EGUs more, 

leading to smaller overall reductions in CO2 emissions.84 These 

factors reinforced the appropriateness of our considering 

strategies from all three groupings for purposes of determining 

the BSER. 

2. CO2 reductions achievable through improvements in individual 

EGUs’ emission rates 

The first grouping of CO2 emission reduction options that 

EPA evaluated as potential options for the BSER consists of 

measures that can reduce individual EGUs’ CO2 emission rates 

(i.e., the amount of CO2 emitted per unit of electricity85

output). These measures included improving the efficiency with 

which EGUs convert fuel heat input to electricity output (i.e., 

heat rate improvements), applying carbon capture and storage 

(CCS) technology, and substituting lower-carbon fuels such as 

 

84 The potential for efficiency improvements to lead to increased 

utilization is generally described as a “rebound effect.” 

85 For simplicity, in this subsection we refer to the energy 

output produced by EGUs as electricity, recognizing that some 

EGUs produce a portion of their energy output in other forms, 

such as steam for heating or process uses. The discussion here 

applies to both EGUs that produce only electricity and EGUs that 

produce a combination of electricity and other energy output. 
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natural gas for higher-carbon fuels such as coal (i.e., natural 

gas co-firing or conversion). 

Our assessment of heat rate improvements showed that these 

measures would achieve CO2 emission reductions at low costs, 

although compared to other measures, the available reductions 

were relatively limited in quantity. Specifically, our analysis 

indicated that average CO2 emission reductions of 1.3 to 6.7 

percent could be achieved by coal steam EGUs through adoption of 

best practices, and that additional average reductions of up to 

four percent could be achieved through equipment upgrades.86 Heat 

rate improvements pay for themselves at least in part through 

reductions in fuel costs, generally making this a relatively 

inexpensive approach for reducing CO2 emissions. We estimated 

that CO2 reductions of between four and six percent from overall 

heat rate improvements could be achieved on average across the 

nation’s fleet of coal steam EGUs for net costs in a range of $6 

to $12 per metric ton.87

 

86 These estimated ranges are averages applicable to the fleet of 

coal steam EGUs as a whole. Potential improvements at individual 

EGUs could be higher or lower. 

87 As noted above, in the absence of other kinds of CO2 emission 

reduction measures, the emission reductions achievable through 

heat rate improvements could be offset to some extent by 
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The EPA also examined application of CCS technology at 

existing EGUs. CCS offers the technical potential for CO2

emission reductions of over 90 percent, or smaller percentages 

in partial applications. In the recently proposed Carbon 

Pollution Standards for new fossil fuel-fired EGUs (79 FR 1430), 

we found that partial CCS was adequately demonstrated for new 

fossil fuel-fired steam EGUs and integrated gasification 

combined cycle (IGCC) units. We also found that for these new 

units the costs were not unreasonable, either for individual 

units or on a national basis, and we proposed to find that 

application of partial CCS is the BSER. However, application of 

CCS at existing units would entail additional considerations 

beyond those at issue for new units. Specifically, the cost of 

integrating a retrofit CCS system into an existing facility 

would be expected to be substantial, and some most existing EGUs 

might have space limitations. Further, the aggregated costs of 

applying CCS as a component of the BSER for the large number of 

existing fossil fuel-fired steam EGUs would be substantial and 

would be expected to affect the cost and potentially the supply 

of electricity on a national basis. For these reasons, although 

 

increased utilization of EGUs making the improvements (a 

“rebound effect”). 

Comment [A19]: How does EPA know this is 

“some” and not “most” 
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some individual facilities may find implementation of CCS to be 

a viable CO2 mitigation option in their particular 

circumstances,88 the EPA is not proposing and does not expect to 

finalize CCS as a component of the BSER for existing EGUs in 

this rulemaking.89

Natural gas co-firing or conversion at coal-fired steam 

EGUs offers greater potential CO2 emission reductions than heat 

rate improvements, but at a higher cost (although less than the 

cost of applying CCS technology). Because natural gas contains 

less carbon than an energy-equivalent quantity of coal, 

converting a coal-fired steam EGU to burn only natural gas would 

reduce the unit’s CO2 emissions by approximately 40 percent. The 

CO2 reductions are generally proportional to the amount of gas 

substituted for coal, so if instead the EGU continued to burn 

mostly coal while co-firing natural gas as, for example, 10 

percent of the EGU’s total heat input, the CO2 emission 

reductions would be approximately four percent. The EPA 

determined that the most significant cost associated with 

 

88 CCS already has been or is being implemented at some existing 

EGUs, as noted in the discussion of CCS later in the preamble. 

89 As noted later in this preamble, we are nevertheless seeking 

comment on the extent to which existing EGUs could implement CCS 

in order to improve our understanding. 
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natural gas conversion or co-firing is likely to be the 

incremental cost of natural gas relative to the cost of coal. 

Using Energy Information Administration (EIA) fuel price 

projections, we estimated that the CO2 reductions achieved 

through natural gas conversion or co-firing at an average coalfired steam EGU would have costs ranging from approximately $83 

to $150 per metric ton.90 Thus, although there have been past 

instances where coal-fired steam EGUs have been converted to 

natural gas, and we expect some additional future conversions 

where circumstances at individual EGUs make the option 

particularly attractive, for the industry as a whole we would 

expect that other approaches could reduce CO2 emissions from 

existing EGUs at lower cost. However, as noted later in the 

preamble, we are seeking comment on whether this option should 

be considered part of the BSER. 

3. CO2 emission reductions achievable through re-dispatch from 

steam EGUs to NGCC units 

The second grouping of CO2 emission reduction options 

evaluated by the EPA in the BSER analysis involves reducing 

 

90 The lower end of the range is for conversion to 100 percent 

natural gas, which would allow EGUs to eliminate certain fixed 

operating and maintenance costs associated with coal use but not 

natural gas use. 

Comment [A20]: Can you point the reader to 

where they find this analysis (in text or in the 

footnote)? 
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emissions by shifting generation among affected EGUs. An obvious 

alternative to substituting natural gas for coal at individual 

steam EGUs through conversion or co-firing is instead to use 

natural gas to generate electricity at a different affected EGU 

with a better heat rate – notably a natural gas combined cycle 

(NGCC) unit – and to substitute that electricity for electricity 

from the coal-fired steam EGU, thus resulting in lower emissions 

from the coal-fired steam EGU and lower emissions from the set 

of affected EGUs overall.91 The electricity system is physically 

interconnected or networked and operated on an integrated basis 

across large regions. System operators routinely increase or 

decrease the electricity output of individual EGUs to respond to 

changes in electricity demand, equipment availability, and 

relative operating costs (or bid prices) of individual EGUs 

while observing reliability-related constraints. It has long 

been common industry practice for system operators to choose 

from among multiple EGUs when deciding which EGU to “dispatch” 

to generate the next increment of electricity needed to meet 

demand. Thus, the well-established practices of the industry 

 

91 Strategies in this grouping also include shifting generation 

from steam EGUs burning oil or natural gas to more efficient 

NGCC units. 

Comment [A21]: A question for clarification --Is 

it a better heat rate, or rather lower CO2 emission 

rate per unit of generated power? 
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support our evaluation of “re-dispatch” of generation from steam 

EGUs to NGCC units as a potential component of the BSER for 

reducing CO2 emissions from existing EGUs. 

NGCC units can produce as much as 46 percent more 

electricity from a given quantity of natural gas than steam 

EGUs,92 making the re-dispatch approach a significantly less 

expensive way to reduce CO2 emissions than conversion or cofiring of coal-fired steam EGUs to burn natural gas. For 

example, using the same EIA fuel cost projections as were used 

above to estimate the costs of natural gas conversion or cofiring, we estimated that the cost of CO2 reductions achievable 

by substituting electricity from an existing NGCC unit for 

electricity from an average coal-fired steam EGU would be 

approximately $30 per metric ton. 

Our analysis indicated that the potential CO2 reductions 

available through re-dispatch from steam EGUs to NGCC units are 

substantial. As of 2012, there was approximately 245 GW of NGCC 

capacity in the United States, 196 GW of which was placed in 

 

92 This estimate assumes an average heat rate of 10,434 Btu/kWh 

for coal fossil fuel-fired steam units between 400 and 600 MW 

and 7,130 Btu/kWh for NGCC units between 400 and 600 MW. See 

NEEDSv.5.13 at 

http://www.epa.gov/powersectormodeling/BaseCasev513.html. 
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service between 2000 and 2012.93 In 2012, the average utilization 

rate of U.S. NGCC capacity was 46 percent, well below the 

utilization rates the units are capable of achieving. In 2012 

approximately 10 percent of NGCC plants operated at annual 

utilization rates of 70 percent or higher, and 19 percent of 

NGCC units operated at utilization rates of at least 70 percent 

over the summer season. Average reported availability generally 

exceeds 85 percent. We recognize that the ability to increase 

NGCC utilization rates may also be affected by infrastructure 

and system considerations, such as limits on the ability of the 

natural gas industry to produce and deliver the increased 

quantities of natural gas, the ability of steam EGUs to reduce 

generation while remaining ready to supply electricity when 

needed in peak demand hours, and the ability of the electric 

transmission system to accommodate the changed geographic 

pattern of generation. However, these considerations have not 

limited past rapid increases in NGCC generation levels, as 

indicated by a 20 percent increase in natural gas consumption 

 

93 EIA Form 860. In comparison, in 2012 there was 336 GW of coal 

steam capacity, of which 22 GW was placed in service between 

2000 and 2012. Id. 
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for electricity generation from 2011 to 2012.94 Further, the 

proposal’s compliance schedule provides flexibility and time for 

investment in additional natural gas and electric industry 

infrastructure if needed. 

As discussed below in subsection VI.C.2, the above facts 

support our assessment that an average NGCC utilization rate in 

a range of 65 to 75 percent is a reasonable target for the 

amount of additional NGCC generation that could be substituted 

for higher carbon generation from steam EGUs as part of the 

BSER.95 If re-dispatch consistent with a target average NGCC 

utilization rate of 70 percent had been achieved in 2012, the 

combined CO2 emissions of steam EGUs and NGCCs would have been 

reduced by approximately 13 percent. 

Finally, we also note that mechanisms for encouraging redispatch as a CO2 reduction measure have already been developed 

and applied in the industry. Under both RGGI and AB32, shifting 

generation from more carbon-intensive EGUs to less carbonintensive EGUs is a way to facilitate compliance with regulatory 

requirements. In both cases, the industry has demonstrated the 

 

94 EIA Form 923. 95 Substitution would only occur to the extent that there is both 

NGCC capacity whose generation could be increased and steam EGUs 

whose generation could be decreased. 

Comment [A22]: Where can the reader find the 

“EIA Form 923” data? 
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ability to respond to the regulatory requirements of these state 

programs. 

4. CO2 emission reductions achievable through other actions 

underway in the industry 

The third grouping of CO2 emission reduction options the 

EPA evaluated in the BSER analysis encompassed other measures 

already used in the industry and not included in the first two 

groupings. From our evaluation of re-dispatch as an option for 

reducing CO2 emissions, it was apparent that relevant factors for 

consideration include the integrated nature of the electricity 

system and the fact that particular measures capable of reducing 

CO2 emissions at EGUs were already being used and would continue 

to be used throughout the industry, at least potentially for the 

purpose of compliance with CO2 emission reduction requirements. 

That observation led us to consider what other potential actions 

and options the industry was already using that had resulted in 

or could result in the reduction of CO2 emissions at EGUs. 

Again, many instances were observed as taking place incidental 

to the ongoing operation of the electricity system as well as 

taking place in response to specific CO2 emissions limits in 

place in states that have been implementing CO2 emissions 

reduction programs affecting the power sector. We concluded 
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that there are two principal types of such potential options for 

measures that result in CO2 emission reductions at EGUs affected 

under this proposal: ongoing development and use of low- and 

zero-carbon generating capacity, and ongoing development and 

application of demand-side energy efficiency measures. 

Low-and zero-carbon generating capacity provides 

electricity that can be substituted for generation from more 

carbon-intensive EGUs. More than half the states already have 

established some form of state-level renewable energy 

requirements, with targets calling on average for almost 20% of 

2020 generation to be supplied from renewable sources. The EPA 

is unaware of analogous state policies to support development of 

new nuclear units, but 30 states already have nuclear EGUs (with 

five units under construction) and the generation from these 

units is currently helping to avoid CO2 emissions from fossil 

fuel-fired EGUs. Policies that encourage development of 

renewable energy capacity and discourage premature retirement of 

nuclear capacity could be useful elements of CO2 reduction 

strategies and are consistent with current industry behavior. 

Costs of CO2 reductions achievable through these policies have 

been estimated in a range from $10 to $40 per metric ton. 
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Demand-side energy efficiency programs reduce the demand 

for generation from existing fossil fuel-fired EGUs, and 

therefore eliminate the CO2 emissions associated with the avoided 

generation as well, by producing electricity-dependent services 

with less electricity. More than 40 states already have 

established some form of demand-side energy efficiency polices, 

and individual states have avoided up to 13% of their 

electricity demand. Again, policies that encourage demand-side 

energy efficiency could be useful elements of CO2 reduction 

strategies and are consistent with current industry behavior. 

Using conservatively high estimates of the costs of demand-side 

energy efficiency, the EPA estimates that the costs of CO2 

emission reductions achievable consistent with such policies 

would be in a range of $16 to $24 per metric ton. 

5. Summary of building blocks for the best system of emission 

reduction 

Based on the analytic approach summarized above, the EPA 

has identified the following four principal categories – 

“building blocks” – of measures that provide the foundation of 

our BSER determination for CO2 emissions from existing EGUs: 

1. Reducing the carbon intensity of generation at 

individual affected EGUs through heat rate improvements. 

Comment [A23]: With or without energy savings 

included? 
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2. Reducing emissions from the most carbon-intensive 

affected EGUs in the amount that results from substituting 

generation at those EGUs with generation from less carbonintensive affected EGUs (including NGCC units under 

construction). 

3. Reducing emissions from affected EGUs in the amount that 

results from substituting generation at those EGUs with 

expanded low- or zero-carbon generation. 

4. Reducing emissions from affected EGUs in the amount that 

results from the use of demand-side energy efficiency that 

reduces the amount of generation required. 

Since they result either in improved operating efficiency 

or in reductions in mass emissions at existing EGUs, each of the 

four building blocks represents a demonstrated approach for 

reducing CO2 emissions from affected EGUs that is already being 

pursued in the power sector. In the next subsection, we discuss 

each of the building blocks at length. Our approach for applying 

the building blocks to each state’s circumstances in order to 

develop state goals is described in Section VII of this 

preamble. 

C. Detailed Discussion of Building Blocks and Other Options 

Considered 
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In this section we discuss each of the building blocks in 

turn. For each building block, we provide our proposed 

assessment of the technical potential of the building block and 

the reasonableness of its costs within the context of the BSER 

determination, and we describe how we developed the data inputs 

used in the computations of state goals described in section 

VII. We also discuss certain measures that we are not proposing 

to consider part of the best system of emission reduction. 

Additional detail is provided in the Greenhouse Gas Abatement 

Measures TSD. 

It is worth noting that although the discussion below 

necessarily addresses the building blocks individually, states 

are not required to pursue plans involving any given building 

block or to do so at any particular level of stringency, but 

rather have flexibility to establish plans to meet their goals 

using their own preferred combinations and stringencies of 

measures. The EPA expects that states and affected EGUs are 

unlikely to limit themselves to the measures in any single 

building block, but instead are likely to pursue portfolios of 

measures from a combination of the actions encompassed in the 

building blocks. In developing the data inputs to be used in 

computing state goals, the EPA has estimated reasonable rather 
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than maximum possible implementation levels for each building 

block in order to establish overall state goals that are 

achievable while allowing states to take advantage of the 

flexibility to pursue some building blocks more aggressively, 

and others less aggressively, than is reflected in the goal 

computations, according to each state’s needs and preferences. 

1. Building block 1 - heat rate improvements 

 The first category of approaches to reducing CO2 emissions 

at affected fossil fuel-fired EGUs consists of measures that 

reduce the carbon intensity of generation at individual coalfired steam EGUs96 by improving heat rate. Heat rate improvements 

are changes that increase the efficiency with which an EGU 

converts fuel energy to electric energy (and useful thermal 

 

96 A “steam EGU” is an EGU that combusts fuel in a boiler and 

uses the combustion heat to create steam which is then used to 

drive a steam turbine that drives a generator to create 

electricity. In contrast, a “combined cycle EGU” combusts fuel 

in a combustion turbine that directly drives a generator, and 

the waste heat is then used to create steam which is used to 

drive a steam turbine that drives a generator to create more 

electricity. Steam EGUs can combust a wide variety of fuels 

including coal and natural gas. Combined cycle EGUs are more 

efficient at converting fuel energy to electric energy but are 

limited to gaseous or liquid fuels, most commonly natural gas or 

distillate oil. Almost all existing coal-fired EGUs are steam 

EGUs (the exceptions are integrated gasification combined cycle 

(IGCC) units where coal is processed to create a gaseous fuel 

that is then combusted in a combined cycle unit). 
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energy in the case of units that cogenerate steam for process 

use as well as electricity), thereby reducing the amount of fuel 

needed to produce the same amount of electricity and lowering 

the amount of CO2 produced as a byproduct of fuel combustion. 

Heat rate improvements yield important benefits to affected 

sources by reducing their fuel costs. 

The EPA is aware of the potential for “rebound effects” 

from improvements in heat rates at individual EGUs. In this 

context, a rebound effect would occur where, because of an 

improvement in its heat rate, an EGU experiences a reduction in 

variable operating costs that makes the EGU more competitive 

relative to other EGUs and consequently raises the EGU’s 

generation output. The increase in the EGU’s CO2 emissions 

associated with the increase in generation output would offset 

the reduction in the EGU’s CO2 emissions caused by the decrease 

in its heat rate and rate of CO2 emissions per unit of generation 

output. The extent of the offset would depend on the extent to 

which the EGU’s generation output increased (as well as the CO2

emission rates of the EGUs whose generation was displaced). The 

EPA considers the rebound effect to be a potential concern if 

heat rate improvements were the only approaches being considered 

for the BSER, but believes that the effect can be addressed by 
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establishing the BSER as a combination of approaches that 

includes not only heat rate improvements but also approaches 

that will prevent or discourage increases in generation output 

from coal-fired steam EGUs on average. The topic of potential 

rebound effects is discussed further in section VI.B above and 

sections VI.D and VI.E below. For purposes of the remainder of 

this subsection, no rebound effect is assumed. 

 Although heat rate improvements have the potential to 

reduce CO2 emissions from all types of affected EGUs, the EPA’s 

analysis indicates the potential is significantly greater for 

coal-fired steam EGUs than for other EGUs, and for purposes of 

determining the best system of emission reduction EPA has 

therefore conservatively based its estimate of CO2 emission 

reductions from heat rate improvements on coal-fired steam EGUs 

only.97 The remainder of this section focuses primarily on the 

EPA’s analysis of potential heat rate improvements from coalfired steam EGUs. In the final subsection below we discuss our 

analysis of potential heat rate improvements from other types of 

affected EGUs. 

 

97 States and EGUs would also be able to rely on CO2 emission 

reductions achieved through heat rate improvements at other 

types of EGUs. 
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a. Ability of heat rate improvements to reduce CO2 emissions 

 The heat rate of an EGU is the amount of fuel energy input 

needed (Btu, higher heating value basis) to produce 1 kWh of net 

electrical energy output (and useful thermal energy in the case 

of cogeneration units).98 The current weighted-average annual 

heat rate of U.S. coal-fired EGUs in the range of 400 to 600 MW 

is approximately 10,434 Btu per net kWh.99 Because an EGU’s CO2

emissions are driven primarily by the amount of fuel consumed, 

at any fossil fuel-fired EGU there is a strong correlation 

between potential heat rate improvements and potential 

reductions in carbon-intensity.100

 Several studies have examined the opportunities to employ 

heat rate improvements as a means of reducing CO2 emissions from 

 

98 Heat rate can also be expressed on a gross basis – i.e., fuel 

input per kWh of gross electricity generated – instead of a net 

basis – i.e., fuel input per kWh of net electricity sent to the 

grid. The difference between gross and net electricity is the 

amount of electricity used at the plant to operate components 

such as pumps, fans, motors, and pollution control devices.

99 See NEEDSv.5.13 at 

http://www.epa.gov/powersectormodeling/BaseCasev513.html. 

100 A small portion of some fossil fuel-fired EGU’s CO2 emissions 

may come from sources other than fuel, such as limestone or 

other carbonates used to capture sulfur dioxide (SO2) and/or 

hydrogen chloride (HCl) in a scrubber or dry injection system. 

However, CO2 emissions from these reagents will also tend to be 

reduced by heat rate improvements, because reagent usage, and 

the associated CO2 emissions, will decrease when the amount of 

fuel used decreases. 
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coal-fired power plants.101 Among these, a 2009 study by the 

engineering firm Sargent & Lundy used bottom-up engineering 

approaches evaluating potential heat rate improvements from 

specific best practices and equipment upgrades, including 

upgrades to boilers, steam turbines, and control systems. Based 

on this study, the EPA believes that implementation of all 

identified best practices and equipment upgrades at a facility 

could provide total heat rate improvements in a range of 

approximately 4 to 12 percent. (We recognize that individual 

EGUs would only be able to implement the best practices or 

upgrades that were applicable to their specific designs or fuel 

types and that had not already been implemented.) 

 In addition to the Sargent & Lundy study, which looked 

generically at the types of improvements that can be made at 

specific types of EGUs, historical heat rate data also provides 

a basis for discerning the existence and possible magnitude of 

potential heat rate improvements. Many EGUs regularly report to 

both the EPA and the U.S. Department of Energy’s Energy 

Information Administration (EIA) CO2 emissions and generation 

data, from which heat input and heat rate data can be computed. 

 

101 See chapter 2 of the GHG Abatement Measures TSD for details. 
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We have reviewed these data and have identified several “data 

apparent” instances where an EGU’s heat rate experienced a 

substantial improvement in a short time – presumably because of 

equipment upgrades installed at that point in time – that was 

then sustained. These heat rate improvements ranged from 3 to 8 

percent. In combination with bottom-up engineering analysis and 

the further, more detailed EPA analysis of hourly data 

summarized below, the individual EGU heat rate histories provide 

a strong basis for considering heat rate improvement as a 

meaningful potential approach to reducing the carbon intensity 

of generation at individual affected fossil fuel-fired EGUs. 

b. Amounts of heat rate improvements 

 In order to estimate the technical potential of heat rate 

improvement opportunities at existing fossil fuel-fired EGUs 

suggested by the discussion above, the EPA pursued two principal 

areas of analysis. The first area concerned the heat rate 

improvements that could be achieved by reducing heat rate 

variability at individual coal-fired EGUs through adoption of 

best practices for operation and maintenance. The second area 

concerned heat rate improvement opportunities that could be 

achieved through further equipment upgrades. Both analyses are 
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summarized below along with our conclusions, and are discussed 

in greater detail in the GHG Abatement Measures TSD. 

 For the best practices analysis, the EPA worked with the 

hourly data reported to the EPA by affected EGUs subject to the 

monitoring and reporting requirements of 40 CFR Part 75. The 

reported data include hourly heat input and, for most reporting 

EGUs, hourly gross generation, making it possible to compute 

hourly gross heat rates. We used the hourly data to assess 

variability in the hourly gross heat rates of approximately 900 

individual coal-fired steam EGUs over the period from 2002 to 

2012. Specifically, the EPA evaluated the consistency with which 

individual EGUs maintained their hourly heat rates over time. We 

expected that a certain degree of short-term heat rate 

variability was caused by factors beyond operators’ control, 

notably variation in hourly ambient temperature and hourly load, 

and preliminary analysis confirmed our expectation. We therefore 

controlled for variation in those factors by grouping the 

observed hourly heat rate data for each EGU into subsets 

corresponding to ranges of hourly ambient temperatures and 
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hourly load levels.102 We believe that the amount of residual 

variability within each data subset is an indication of the 

degree of technical potential to improve the consistency with 

which optimal heat rate performance is achieved by adopting 

operating and maintenance best practices. For example, optimal 

heat rate performance could be achieved with greater consistency 

through practices such as turning off unneeded pumps at reduced 

loads, installation of digital control systems, more frequent 

tuning of existing control systems, or earlier like-kind 

replacement of worn existing components. (Upgrades to existing 

equipment are considered below.) By applying best practices to 

their operating and maintenance procedures, owners and operators 

of EGUs could reduce heat rate variability relative to average 

heat rates and, because the deviations generally result in 

performance worse than the optimal heat rates, improve the EGUs’ 

average heat rates. Assuming that between 10 percent and 50 

percent of the deviation from top decile performance in each 

subset of hourly heat rate observations within defined ranges of 

 

102 Temperature data are from the National Oceanic and 

Atmospheric Administration’s Integrated Surface Data, 

http://www.ncdc.noaa.gov/data-access/land-based-stationdata/land-based-datasets/integrated-surface-database-isd. 

Electrical generation data are from EPA’s Air Markets Program 

Data, http://ampd.epa.gov/ampd/. 

Formatted: Default Paragraph Font, Font:

Times New Roman, 10 pt
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temperature and load could be eliminated through adoption of 

best practices, the result is a corresponding estimated range of 

1.3 percent to 6.7 percent technical potential for improvement 

in the average heat rate of the entire fleet of coal-fired 

EGUs.103 Based on this analysis, we believe a reasonable estimate 

for purposes of developing state-specific goals is that affected 

coal-fired steam EGUs on average could achieve a four percent 

improvement in heat rate through adoption of best practices to 

reduce hourly heat rate variability. This estimate corresponds 

to the elimination, on average across the fleet of affected 

EGUs, of 30 percent of the deviation from top-decile performance 

in the hourly heat rate for each EGU not attributable to hourly 

temperature and load variation. We also solicit comment on the 

use of estimates up to six percent, reflecting elimination on 

average of 50 percent of the deviation from top-decile 

performance. 

 For the equipment upgrade analysis, we evaluated potential 

opportunities to improve heat rates at affected EGUs through 

specific upgrades identified in the 2009 Sargent & Lundy study. 

 

103 We examined whether the potential for heat rate improvement 

varied based on EGU characteristics such as capacity, boiler 

type, and location, and found no meaningful differences. 

Formatted: Highlight

Comment [A24]: Should this be 6%? 
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In that study, Sargent & Lundy estimated ranges of potential 

heat rate improvement achievable through a variety of equipment 

upgrades. We screened the upgrades from the study to identify 

what we consider to be a reasonable subset of equipment upgrades 

that would generally be beyond the scope of investments we would 

expect to be made for purposes of achieving the best-practices 

heat rate improvements discussed above. Based on the average of 

the study’s ranges of potential heat rate improvements from the 

various upgrades in this subset, implementation of the full 

subset of appropriate opportunities at a single EGU could be 

expected to result in an aggregate heat rate improvement of 

approximately four percent (incremental to the improvement 

achievable from adoption of best practices). However, we 

recognize that this total may overstate the average equipment 

upgrade opportunity across all EGUs because some EGUs may have 

already implemented some of these upgrades. We therefore propose 

to use as a data input for purposes of developing state goals an 

estimate that, on average across the fleet of affected EGUs, 

only half of the full equipment upgrade opportunity just 

described remains – i.e., that for the fleet of affected EGUs as 

a whole, the technical potential for heat rate improvements from 

equipment upgrades incremental to the best-practices opportunity 
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is on average two percent rather than four percent. We solicit 

comment on increasing this figure up to four percent. 

 Some of the measures available to EGUs for reducing their 

carbon intensity affect net heat rates rather than gross heat 

rates. Various EGU components such as pumps, fans, motors, and 

pollution control devices use electricity, a factor that is not 

accounted for in gross heat rates (that is, fuel used per unit 

of gross energy output) but is accounted for in net heat rates 

(that is, fuel used per unit of net energy output sent to the 

electric grid or used for thermal purposes). The electricity 

used by these components, referred to as auxiliary or parasitic 

load, may represent from 4 to 12 percent of gross generation at 

a coal-fired steam EGU.104 The analysis of technical potential to 

reduce heat rate variability discussed above was based on gross 

heat rate data. Like gross heat rate, parasitic load can be 

addressed both through adoption of best practices and through 

equipment upgrades, and some measures undertaken at EGUs may 

affect parasitic load as well as gross heat rate. Because the 

hourly generation data reported to the EPA represent gross 

 

104 Electric Power Research Institute 2011 Technical Report – 

Program on Technology Innovation: Electricity Use in the 

Electric Sector (Opportunities to Enhance Electric Energy 

Efficiency in the Production and Delivery of Electricity). 
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generation, we have less data available to directly analyze 

potential net heat rate improvements than gross heat rate 

improvements. We have therefore not included any separate 

estimate of parasitic load reductions achievable through best 

practices in our goal-setting data inputs. However, these 

opportunities would be available as a mechanism for reducing 

carbon-intensity at affected EGUs and thus provide more 

flexibility and opportunities for sources to improve their heat 

rates cost effectively.105 

 The total of the estimated potential heat rate improvements 

from adoption of best practices to reduce heat rate variability 

and implementation of equipment upgrades as discussed above is 

six percent. Because of the close relationship between an EGU’s 

fuel consumption and its CO2 emissions, a six percent heat rate 

improvement would be associated with a reduction in CO2 emissions 

of approximately six percent. We believe that this represents a 

reasonable estimate of the technical potential for CO2 emission 

 

105 As proposed, the state-specific goals are expressed in the 

form of CO2 emissions per net MWh, and reporting requirements for 

sources would be in the same form, allowing parasitic load 

reductions to contribute to improved measured heat rates. If 

goals and reporting requirements were changed to a gross MWh 

basis in the final rule, accounting for parasitic load 

reductions as a source of CO2 reductions would require additional 

procedures.
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reductions that would be achievable from affected coal-fired 

EGUs, on average, through heat rate improvements as an element 

of the best system of emission reduction. 

 For purposes of developing the alternate set of goals on 

which we are taking comment we have used an estimate of a four 

percent heat rate improvement from affected coal-fired EGUs on 

average. This level of improvement would be consistent with 

those EGUs on average implementing best practices to reduce heat 

rate variability without making further equipment upgrades, or 

would be consistent with those EGUs on average implementing both 

best practices and equipment upgrades, but to a lesser degree 

than we have projected as being achievable for purposes of our 

proposal. We view the four percent estimate as a reasonable 

minimum estimate of the technical potential for heat rate 

improvement on average across affected coal-fired EGUs. 

 It should be noted that we have not evaluated the technical 

and economic potential for analogous heat rate improvements at 

types of EGUs other than coal-fired steam EGUs. We have 

therefore not identified such improvements as part of this 

building block. 

c. Costs of heat rate improvements 
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 By definition, any heat rate improvement made for the 

purpose of reducing CO2 emissions will also reduce the amount of 

fuel the EGU consumes to produce its electricity output. The 

cost attributable to CO2 emission reductions therefore would be 

at most the net cost to achieve the heat rate improvement after 

any savings from reduced fuel expense. As summarized below, we 

estimate that, on average, the savings in fuel cost associated 

with a six percent heat rate improvement would be sufficient to 

cover much of the associated costs, with the result that the net 

costs of heat rate improvements associated with reducing CO2

emissions from affected EGUs are relatively low. 

 The EPA’s most detailed estimates of the average costs 

required to achieve the full range of heat rate improvements 

come from the 2009 Sargent & Lundy study discussed above. The 

study estimated that for a range of heat rate improvements from 

415 to 1205 Btus per kWh, corresponding to percentage heat rate 

improvements of 4 to 12 percent for a typical coal-fired EGU, 

the required capital costs would range from $40 to $150 per kW. 

To correspond to the average heat rate improvement of six 

percent we have estimated to be achievable through the 

combination of best practices and equipment upgrades, we have 

estimated an average cost of $100 per kW, slightly above the 
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midpoint of the Sargent & Lundy study’s range. At an estimated 

annual capital charge rate of 14.3 percent, the carrying cost of 

an estimated $100 per kW investment would be $14.30 per kW-year. 

For a coal-fired EGU with a heat rate of 10,450 Btu per kWh, a 

utilization rate of 78 percent, and a coal price of $2.62 per 

MMBtu, a six percent heat rate improvement would produce fuel 

cost savings of approximately $11.20 per kW-year,106 leaving 

approximately $3.10 per kW-year of carrying cost not recovered 

through fuel cost savings. At an average CO2 emission rate of 

0.976 metric tons per MWh, the same six percent heat rate 

improvement would reduce CO2 emissions by 0.40 metric tons per 

kW-year.107 Thus, the average cost of CO2 reductions from heat 

rate improvements would be approximately $7.75 per metric ton of 

CO2 ($3.10 / 0.40). If the average heat rate improvement 

achievable for the $100 per kW investment were only four 

percent, consistent with the heat rate improvement estimate in 

 

106 10,450 Btu/kWh * 8760 hours/year * 78% utilization * $2.62 

per MMBtu * 6% improvement * 0.000001 MMBtu/Btu = $11.2 per kWyear. Data inputs for average coal-fired EGU heat rate, average 

coal-fired EGU utilization, and average coal price are from the 

IPM 5.13 base case for 2020. 

107 8760 hours/year * 78% utilization * 0.976 metric tons/Mwh * 

6% improvement * 0.001 MW/kW = 0.40 metric tons of CO2 per kWyear. The estimated average coal-fired EGU CO2 emission rate per 

MWh is from the IPM 5.13 base case for 2020.
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the alternate goals on which we seek comment, the average cost 

of CO2 reductions would be $11.63 per metric ton.108 On the other 

hand, if an average heat rate improvement of four percent could 

be achieved for an average investment of $50 per kW, reflecting 

an assumption that the first improvements pursued would be the 

least expensive ones, the average cost of CO2 reductions would 

fall to $5.81 per metric ton.109 

 The EPA recognizes that the simplified cost analysis just 

described will represent the costs for some EGUs better than 

others because of differences in EGUs’ individual circumstances. 

We further recognize that reductions in the utilization rates of 

coal-fired EGUs anticipated from other components proposed for 

inclusion in the best system of emission reduction would tend to 

reduce the fuel savings associated with heat rate improvements, 

thereby raising the effective cost of achieving the CO2 emission 

reductions from the heat rate improvements. Nevertheless, we 

still expect that the majority of the investment required to 

capture the technical potential for CO2 emission reductions from 

heat rate improvements would be offset by fuel savings, and that 

 

108 $7.75 per metric ton of CO2 * 6% / 4% = $11.63 per metric ton 

of CO2. 109 $11.63 per metric ton of CO2 * $50 / $100 = $5.81 per metric 

ton of CO2.
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the net costs of heat rate improvements as an approach to 

reducing CO2 emissions from existing fossil fuel-fired EGUs are 

reasonable. 

 Based on the analyses of technical potential and cost 

summarized above, we propose to find that a six percent 

reduction in the CO2 emission rate of the coal-fired EGUs in a 

state, on average, is a reasonable estimate of the amount of 

heat rate improvement that can be implemented at a reasonable 

cost.110 

We invite comment on all aspects of our analyses and 

findings related to heat rate improvements, both as summarized 

here and as further discussed in the Greenhouse Gas Abatement 

Measures TSD. As noted earlier, we specifically request comment 

on increasing the estimates of the amounts of heat rate 

improvement achievable through adoption of best practices for 

operation and maintenance and through equipment upgrades up to 

six percent and four percent, respectively, particularly in 

 

110 We note that although we expect that heat rate improvements 

are also available from other fossil fuel-fired EGUs, because we 

have less data from which to estimate those improvements we have 

conservatively not included CO2 emission rate reductions for 

those EGUs in the state goals. However, states and sources would 

be free to use heat rate improvements at those other units to 

help reach the state goals.
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light of the reasonable cost of heat rate improvements. We also 

solicit comment on the quantitative impacts on the net heat 

rates of coal-fired steam EGUs of operation at loads less than 

the rated maximum unit loads. 

d. Assessment of heat rate improvement opportunities at 

gas- and oil-fired steam EGUs and NGCC units 

The EPA also assessed opportunities to improve heat rates 

at affected EGUs other than coal-fired steam units. This 

assessment, which is documented in a Technical Memorandum 

included as an appendix to the GHG Abatement Measures TSD, 

considers the potential extent of heat rate improvements and CO2

reductions that could be reasonably available from oil/gas-fired 

steam EGUs, NGCC units, and combustion turbine units. For these 

non-coal technologies, the EPA concludes that the total 

additional potential CO2 reductions are very small compared to 

the potential CO2 reductions achievable at coal-fired steam EGUs. 

For this reason, the EPA does not propose to include heat rate 

improvement opportunities at oil/gas-fired steam EGUs or NGCC 

units as an element of the BSER for CO2 emissions from affected 

EGUs. However, the EPA expects that for some individual oil/gasfired steam EGUs, NGCC units, and combustion turbine units, 

attractive heat rate improvement opportunities will exist. We 
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note that under the proposed flexible approach to state plans 

described later in this preamble, CO2 reductions achieved through 

such opportunities could be used to help meet state goals. 

2. Building block 2 – dispatch changes among affected EGUs 

 The second element of the foundation for EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired EGUs goes to the achievement of reductions in mass 

emissions at certain affected EGUs – in particular, fossil fuelfired steam EGUs - and entails an analysis of the extent to 

which generation at the most carbon-intensive affected EGUs – 

again, in particular, fossil fuel-fired steam EGUs – can be 

replaced with generation at less carbon-intensive affected 

fossil fuel-fired EGUs – in particular, NGCC units that were in 

operation or had commenced construction as of January 8, 2014, 

and are therefore affected units for purposes of this rule. 

a. Ability of re-dispatch to reduce CO2 emissions 

 The nation’s EGUs are interconnected by transmission grids 

extending over large regions. EGU owners and grid operators, 

subject to various reliability and operational constraints, use 

the flexibility provided by these interconnections to prioritize 

among available EGUs when deciding which units should be called 

upon (i.e., “dispatched”) to increase or decrease generation in 

Comment [A25]: One sentence – consider 

breaking apart. 
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order to meet electricity demand at any point in time. Treating 

increments of generation as to some extent interchangeable, 

dispatch decisions are based on electricity demand at a given 

point in time, the variable costs of available generating 

resources, and system constraints. Electricity demand varies 

across geography and time in response to numerous conditions, 

such that EGU owners and grid operators are constantly 

responding to changes in demand and “re-dispatching” to meet 

demand in the most reliable and cost-effective manner possible. 

Operators of EGUs subject to existing market-based programs to 

limit emissions of pollutants such as SO2 and NOx have for many 

years factored directly into dispatch decisions the costs 

associated with the EGUs’ emission rates of those pollutants 

because each ton of emissions requires an emission allowance 

that has an economic cost. Operators of EGUs subject to CO2 

emissions limits in RGGI have also relied on replacing 

generation at higher-emitting EGUs with generation from loweremitting sources to reduce emissions at the former. Reducing or 

limiting emissions at high carbon-intensity EGUs by replacing 

generation at those EGUs with generation at less carbonintensive EGUs clearly has the technical capability to reduce 

overall power sector CO2 emissions. 

Comment [A26]: Can EPA provide a citation for 

this statement? 
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WeWhile not required for a BSER determination, we have also 

analyzed potential upstream net methane emissions impact from 

natural gas and coal for the impacts analysis. This analysis 

indicated that any net impacts from methane emissions are likely 

to be small compared to the CO2 emissions reduction impacts of 

shifting power generation from coal-fired steam EGUs to NGCC 

units. Further information on our analysis of upstream impacts 

can be found in the Appendix 3A of the RIA.

b. Magnitude of re-dispatch 

 Having identified replacing generation at higher-emitting 

EGUs with generation at lower-emitting EGUSEGUSEGUsEGUS as a 

technically feasible CO2 emissions reduction strategy, we turn 

in our BSER determination to the quantity of replacement 

generation that may be relied upon at reasonable costs. The 

U.S. electric generating fleet includes EGUs employing a variety 

of generating technologies. EGUs using technologies with 

relatively low variable costs, such as nuclear units, are for 

economic reasons generally operated at their maximum output 

whenever they are available. Renewable EGUs such as wind and 

solar units also have low variable costs, but in any event are 

generally operated when wind and sun conditions permit rather 

than at operators’ discretion. In contrast, fossil fuel-fired 

Comment [A27]: Being explicit that LCA is not 

required for BSER determinations. 
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EGUs have higher variable costs and are also relatively 

flexible. Fossil fuel-fired EGUs are therefore generally the 

units that operators use to respond to intra-day and intra-week 

changes in demand. Because of these typical characteristics of 

the various EGU types, the primary re-dispatch opportunities 

among existing units available to EGU owners and grid operators 

generally consist of opportunities to shift generation among 

various fossil fuel-fired units, in particular between coalfired EGUs (as well as oil- and gas-fired steam EGUs) and NGCC 

units. In the short-term – that is, over time intervals shorter 

than the time required to build a new EGU – fossil fuel-fired 

units consequently tend to compete more with one another than 

with nuclear and renewable EGUs. The amount of re-dispatch from 

coal-fired EGUs to NGCC units that takes place as a result of 

this competition is highly relevant to overall power sector GHG 

emissions, because a typical NGCC unit produces less than half 

as much CO2 per MWh of electricity generated as a typical coalfired EGU. 

 In order to estimate the potential magnitude of the costeffective opportunity to reduce power sector CO2 emissions 

through re-dispatch among existing EGUs, the EPA first examined 

information on the design capabilities and availability of NGCC 
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units. This examination showed that, although most NGCC units 

have historically been operated in intermediate-duty roles for 

economic reasons, they are technically capable of operating in 

base-load roles at much higher annual utilization rates. Average 

annual availability (that is, the percentage of annual hours 

when an EGU is not in a forced or maintenance outage) for NGCC 

units in the U.S. generally exceeds 85 percent, and can exceed 

90% for some groups.111 

 We also researched historical data to determine the 

utilization rates that NGCC units have already been demonstrated 

capable of sustaining. Over the last several years, EGU owners 

and grid operators have engaged in considerable re-dispatch 

among various types of fossil fuel-fired units relative to 

historical dispatch patterns, with NGCC units increasing 

generation and many coal-fired EGUs reducing generation. In 

fact, in April 2012, for the first time ever the total quantity 

of electricity generated nationwide from natural gas was 

 

111 See, e.g., North American Electric Reliability Corp., 2008-

2012 Generating Unit Statistical Brochure – All Units Reporting, 

http://www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx; Higher 

Availability of Gas Turbine Combined Cycle, Power Engineering 

(Feb. 1, 2011), http://www.power-eng.com/articles/print/volume115/issue-2/features/higher-availability-of-gas-turbinecombined-cycle.html.
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approximately equal to the total quantity of electricity 

generated nationwide from coal.112 These changes in generation 

patterns have been driven largely by changes over time in the 

relative prices of natural gas and coal, in addition to lower 

overall demand for electricity. Although the relative fuel 

prices vary by location, as do the recent patterns of redispatch, this trend holds across broad regions of the U.S. In 

aggregate the historical data provide ample evidence indicating 

that, on average, existing NGCC units can achieve and sustain 

utilization rates higher than their present utilization rates. 

 The experience of relatively heavily used NGCC units 

provides an additional indication of the degree of increase in 

average NGCC unit utilization that is technically feasible. 

According to the historical NGCC unit utilization rate data 

reported to the EPA, in 2012 roughly 10 percent of existing NGCC 

units operated at annual utilization rates of 70 percent or 

higher.113 In effect, these units were being dispatched to 

provide base-load power. In addition to the 10 percent of NGCC 

units that operated at a 70 percent utilization rate on an 

 

112 Today in Energy, EIA (June 6, 2012) (http://www.eia.gov/todayinenergy/detail.cfm?id=6990). 113 The corresponding percentages of NGCC units that in 2012 

operated at annual utilization rates of at least 65 percent and 

at least 75 percent were 16 percent and 6 percent, respectively. 
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annual basis, some NGCC units operated at high utilization rates 

for shorter, but still sustained, periods of time in response to 

high cyclical demand. For example, on a seasonal basis, a 

significant number of NGCC units have achieved utilization rates 

between 50 and 80 percent; over the 2012 winter season (December 

2011-February 2012) and summer season (June-August 2012), about 

16 percent and 19 percent of NGCC units, respectively, operated 

at utilization rates of 70 percent or more across these entire 

seasons.114 During the spring and fall periods when electricity 

demand levels are typically lower, these units were sometimes 

idled or operated at much lower capacity factors. Nonetheless, 

the data clearly demonstrate that a substantial number of 

existing NGCC units have proven the ability to sustain 70 

percent utilization rates for extended periods of time. We view 

this as strong evidence that increasing the utilization rates of 

existing NGCC units to 70 percent, not in every individual 

instance but on average, as part of a comprehensive approach to 

reducing CO2 emissions from existing high carbon-intensity EGUs, 

would be technically feasible. 

 

114 Air Markets Program Data (at http://ampd.epa.gov/ampd/). 
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For purposes of establishing state goals, historical (2012) 

electric generation data was used to apply each building block 

and develop each state’s goal (expressed as an adjusted CO2 

emission rate in lbs per MWh).115 In 2012, electric generation 

from existing NGCC units was 959 TWh.116 After the application of 

NGCC re-dispatch toward a 70 percent target utilization rate, 

these existing sources were calculated to collectively generate 

1,390 TWh. Adding in the existing sources that were under 

construction in 2012 but not yet in operation increases total 

NGCC generation calculated in the goal setting to 1,443 TWh. 

Although states may choose to comply with state goals 

through a variety of abatement measures and achieving upwards of 

1,400 TWh of NGCC generation in 2020 is therefore not actually 

required, the EPA nevertheless believes that producing this 

quantity of generation is feasible for this set of NGCC units. 

As a reference point, NGCC generation increased by approximately 

430 TWh (an 80% increase) between 2005 and 2012. The EPA 

calculates that NGCC generation in 2020 could increase by 

approximately 50 percent from today’s levels. This reflects a 

 

115 See section VII for further explanation of how goals were 

computed. 

116 For covered sources. 
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smaller ramp rate in NGCC generation than has been observed from 

2005 to 2012. We also regardexpect these changes aswill not 

impairing power system reliability. As we note in the TSD on 

Resource Adequacy and Reliability, the level of potential redispatch can be accommodated within the flexible compliance 

requirements of the rule. Similar conclusions have been reached 

in recent studies of the potential impact of emissions reduction 

from existing power plants.117

 The EPA also examined the technical capability of the 

natural gas supply and delivery system to provide increased 

quantities of natural gas and the capability of the electricity 

transmission system to accommodate shifting generation patterns. 

For several reasons, we conclude that these systems would be 

capable of supporting the degree of increased NGCC utilization 

needed for states to achieve the proposed goals. First, the 

natural gas system is already supporting national average NGCC 

utilization rates of 60 percent or higher during peak hours, 

which are the hours when constraints on pipelines or electricity 

transmission networks are most likely to arise. NGCC unit 

 

117 See Greenhouse Gas Emission Reductions From Existing Power 

Plants: options to Ensure Electric System Reliability (Analysis 

Group, Inc, May 2014). Also see the Resource Adequacy Technical 

Support Document. 
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utilization rates during the range of peak daytime hours from 10 

a.m. to 9 p.m. are typically 15 to 20 percentage points above 

their average utilization rates (which have recently been in the 

range of 40 to 50 percent).118 Fleet-wide combined-cycle average 

monthly utilization rates have reached 65 percent,119 showing 

that the pipeline system can currently support these rates for 

an extended period. If the current pipeline and transmission 

systems allow these utilization rates to be achieved in peak 

hours and for extended periods, it is reasonable to expect that 

similar utilization rates should also be possible in other hours 

when constraints are typically less severe, and be reliably 

sustained for other months of the year. The second consideration 

supporting our view that gas and electric system infrastructure 

would be capable of supporting increased NGCC unit utilization 

rates is the flexibility of the emission guidelines. The state 

goals do not require any particular NGCC unit utilization rate 

to be achieved in any hour or year of the initial plan period. 

 

118 EIA, Average utilization of the nation’s natural gas 

combined-cycle power plant fleet is rising, Today in Energy, 

July 9,2011, 

http://www.eia.gov/todayinenergy/detail.cfm?id=1730#; EIA, Today 

in Energy, Jan. 15, 2014, 

http://www.eia.gov/todayinenergy/detail.cfm?id=14611 (for recent 

data).

119 EIA, Electric Power Monthly, February, 2014. Table 6.7.A. 
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Thus, even if isolated gas or electric system constraints were 

to limit NGCC unit utilization rates in certain locations in 

certain hours, this would not prevent an increase in NGCC 

generation overall across a state or broader region and across 

all hours. The third consideration supporting a conclusion 

regarding the adequacy of infrastructure is that pipeline and 

transmission planners have repeatedly demonstrated the ability 

to methodically relieve bottlenecks and expand capacity.120

Natural gas pipeline capacity is regularlyhas been added in 

response to increased gas demand and supply, such as the 

addition of large amounts of new NGCC capacity in 2001 to 2003, 

or the delivery to market of unconventional gas supplies since 

2008. These pipeline capacity increases have added significant 

deliverability to the natural gas pipeline network to meet the 

potential demands from increased use of existing NGCCs. Over a 

longer time period, much more significant pipeline expansion is 

possible. In previous studies, when the pipeline system was 

expected to face very large demands for natural gas use by 

 

120 See, e.g., EIA, Natural Gas Pipeline Additions in 2011, Today 

in Energy; INGAA Foundation, Pipeline and Storage Infrastructure 

Requirements for a 30 Tcf Market (2004 update); INGAA 

Foundation, North American Midstream Infrastructure Through 2035 

- A Secure Energy Future Report (2011). 

Comment [A28]: Correction of tense 
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electric utilities about ten years ago, increases of up to 30 

percent in total deliverability out of the pipeline system were 

judged to be possible by the pipeline industry.121 There have 

also been notable capacity expansions over the past five years, 

in response to increased natural gas supply estimates and 

advances in drilling techniques.122 Further, as discussed below 

in section VII.D on state flexibilities and section VIII on 

state plans, we believe the flexible nature of the goals 

provides time for infrastructure improvements to occur should 

they prove necessary in some locations.123 Combining these 

factors of currently observed utilization rates of up to 65 

percent on a monthly basis and time flexibility to address 

existing infrastructure limitations, it is reasonable to 

conclude that the natural gas supply system can reliably deliver 

sufficient supplies to allow average annual NGCC utilization 

rates of 65 percent, and, given the flexible compliance 

 

121 Pipeline and Storage Infrastructure Requirements for a 30 Tcf 

Market, INGAA Foundation, 1999 (Updated July, 2004); U.S. gas 

groups confident of 30-tcf market, Oil and Gas Journal, 1999. 

122 Energy Information Administration, 

http://www.eia.gov/naturalgas/data.cfm 

123 See section VII.D and section VIII below for discussion of 

timing flexibility. 
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potential, to move beyond this level to 70 percent utilization 

rates. 

 We recognize that re-dispatch does contemplate an 

associated increase in natural gas production. The EPA expects 

the growth in NGCC generation assumed in goal setting to be 

feasible and consistent with domestic natural supplies. 

Increases in the natural gas resource base have led to 

fundamental changes in the outlook for natural gas. There is 

general agreement that recoverable natural gas resources will be 

substantially higher for the foreseeable future than previously 

anticipated, exerting downward pressure on natural gas prices. 

According to EIA, natural gas proved reserves have doubled 

between 2000 and 2012. Domestic production has increased by 32 

percent over that same timeframe (from 19.2 TCF in 2000 to 25.3 

in 2012 TCF). EIA’s Annual Energy Outlook for 2014 projects 

that production will further increase to 29.1 TCF, as a result 

of increased supplies and favorable market conditions. For 

comparison, NGCC generation growth of 450 TWh (calculated in 

goal setting) would result in increased gas consumption of 

roughly 3.5 TCF for the electricity sector. 

The EPA notes that the assessments described above 

regarding the ability of the electricity and natural gas 

Comment [A29]: Clarification and dates based 

on text. g 
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industries to achieve the levels of performance indicated for 

building block 2 in the state goal computations are supported by 

analysis that has been conducted using the Integrated Planning 

Model (IPM). IPM is a multi-regional, dynamic, deterministic 

linear programming model of the U.S. electric power sector that 

the EPA has used for over two decades to evaluate the economic 

and emission impacts of prospective environmental policies. To 

fulfil its purpose of producing projections related to the 

electric power sector and its related markets - including least 

cost capacity expansion and electricity dispatch projections – 

that reflect industry conditions in as realistic a manner as 

possible, IPM incorporates representations of fuel supply, 

transmission, dispatch, and reliability constraints. The model 

includes a detailed representation of the natural gas pipeline 

network and the capability to project economic expansion of the 

network based on pipeline load factors. At the EGU level, IPM 

includes detailed representations of key operational limitations 

such as turn-down constraints, which are designed to account for 

the cycling capabilities of EGUs to ensure that the model 

properly reflects the distinct operating characteristics of 

peaking, cycling, and base load units. 
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As described in more detail below, the EPA used IPM to 

assess the costs of requiring increasing levels of re-dispatch 

from higher- to lower-emitting EGUs, and to that end, EPA 

developed a series of modeling scenarios that explored shifting 

generation from existing coal-fired EGUs to existing NGCC units 

on a 1:1 basis within defined areas.124 By the nature of IPM’s 

design, those scenarios necessarily also require compliance with 

the constraints just described (as implemented for any specific 

scenario). IPM was able to arrive at a solution for scenarios 

reflecting average NGCC utilization rates of 65, 70, and 75 

percent, while observing the market, technical, and regulatory 

constraints embedded in the model. Such a result is consistent 

with EPA’s determination that increasing the utilization rates 

of existing NGCC units to 70 percent, not in every individual 

instance but on average, as part of a comprehensive approach to 

reducing CO2 emissions from existing high carbon-intensity EGUs, 

would be technically feasible. 

c. Cost of re-dispatch 

 Having established the technical feasibility and 

quantification of replacing incremental generation at higher-

 

124 See Chapter 3 of the Regulatory Impact Analysis for more 

detail.
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emitting EGUs with generation at NGCC facilities as a CO2 

emissions reduction strategy, we next turn in our BSER 

determination to the question of cost. The cost of the power 

sector CO2 emission reductions that can be achieved through redispatch among existing fossil fuel-fired EGUs depends on the 

relative variable costs of electricity production at EGUs with 

different degrees of carbon intensity. These variable costs are 

driven by the EGUs’ respective fuel costs and by the 

efficiencies with which they can convert fuel to electricity 

(i.e., their heat rates). Historically, natural gas has had a 

higher cost per unit of energy content (e.g., MMBtu) than coal 

in most locations, but for NGCC units this disadvantage in fuel 

cost per MMBtu relative to coal-fired EGUs is typically offset 

in significant part, and sometimes completely, by a heat rate 

advantage. 

 The EPA has conducted two sets of extensive analyses to 

help inform the development of the state-specific emission goals 

described in this proposal, including analysis of the 

opportunity to reduce CO2 emissions through re-dispatch. The 

first set was a dispatch-only set that provided a framework for 

understanding the broader economic and emissions implications of 

shifting generation to NGCC units from more carbon-intensive 
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EGUs without consideration of emission reduction measures 

reflected in the other building blocks. The second set included 

additional refinements and more closely reflected all the 

characteristics of the proposed goals that were used as the 

basis for assessing the costs and benefits of the overall 

proposal.125 Both sets of analyses were conducted using IPM. 

 The first set – the dispatch-only analyses - explored the 

magnitude and cost of potential opportunities to shift 

generation from existing coal-fired EGUs to existing NGCC units 

within defined areas. The purpose of analyzing these scenarios 

was to understand and demonstrate to what extent existing NGCC 

units could increase their dispatch cost-effectively and without 

significant impacts on other economic variables such as the 

prices of natural gas and electricity. To evaluate how EGU 

owners and grid operators could respond to a state plan’s 

possible requirements, signals, or incentives to re-dispatch 

from more carbon-intensive to less carbon-intensive EGUs, the 

EPA analyzed a series of scenarios in which the fleet of NGCC 

units nationwide was required, on average, to achieve a 

 

125 See Regulatory Impact Analysis for more detail.
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specified annual utilization rate.126 Specifically, the scenarios 

required average NGCC unit utilization rates of at least 65, 70, 

and 75 percent, respectively. For each scenario, we identified 

the set of dispatch decisions that would meet electricity demand 

at the lowest total cost, subject to all other specified 

operating and reliability constraints for the scenario, 

including the specified constraints and requiring re-dispatch to 

occur exclusively within a region’s existing fleet.127 

The costs and economic impacts of the various scenarios 

were evaluated by comparing the total costs and emissions from 

each scenario to the costs and emissions from a business-asusual scenario. For the scenario reflecting a 70 percent NGCC 

utilization rate, comparison to the business-as-usual case 

indicates that the average cost of the CO2 reductions achieved 

over the 2020-2029 period was $30 per metric ton of CO2.128 We 

 

126 The utilization rate constraint applied on average to all 

NGCC units nationwide and did not apply to individual NGCC units 

or to the fleets of NGCC units within individual states. 

127 To best reflect the integrated nature of the electric power 

sector EPA defined six regions for this analysis, the borders of 

which are informed by North American Electric Reliability (NERC) 

regions and Regional Transmission Organizations (RTOs). See 

Chapter 3 of the Regulatory Impact Analysis for more detail.

128 The analogous costs for the scenarios with 65 and 75 percent 

NGCC utilization rates were $21 and $40 per metric ton of CO2, 

respectively. 

Comment [A30]: Please note what this assumes 

about natural gas prices. 
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view these estimated costs as not unreasonable and therefore as 

supporting the use of a 70 percent utilization rate target for 

purposes of quantifying the cost-effective emission reductions 

achievable through the application of the BSER. 

However, we also note that the costs just described are 

higher than we would expect to actually occur in real-world 

compliance with this proposal’s goals. One reason for this is 

that the 70 percent utilization rate in the scenario exaggerates 

the stringency with which building block 2 is actually reflected 

in the state goals: while the goal computation procedure uses 70 

percent as a target NGCC utilization rate for all states, for 

only 29 states do the goals actually reflect reaching that 

target NGCC utilization, with the result that the average NGCC 

utilization rate reflected in the computed state goals is only 

64 percent.129 Also, at least some states may be able to achieve 

additional emission reductions through other components of the 

BSER, and those other components may be relatively inexpensive. 

The dispatch-only analyses were focused on evaluating the 

potential impacts of re-dispatch in particular, and as a result, 

 

129 For further explanation of the state goal computation 

methodology, see section VII of the preamble and the Goal 

Computation TSD. 
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they reflect an assumption that even in a state where redispatch might be relatively expensive compared to other 

available CO2 reduction measures that are part of the BSER, the 

state would seek to meet its emission reduction obligations 

using re-dispatch to the same extent as other states. In 

practice, under these circumstances, states would have 

flexibility to choose among alternative CO2 reduction strategies 

that were part of the BSER, instead of employing re-dispatch to 

the maximum extent. 

 The EPA also analyzed dispatch-only scenarios where 

shifting of generation among EGUs was limited by state 

boundaries. In these scenarios with less re-dispatch 

flexibility, the cost of achieving the quantity of CO2 reductions 

corresponding to a nationwide average NGCC unit utilization of 

70% was $33 per metric ton. Combining the results of the 

modeling with the factors likely to be present in the real world 

reinforces the support we expressed above for the 70 percent 

utilization rate. We remain concerned, however, that higher NGCC 

utilization rates could be harder to sustain and could exert 

further upward pressure on prices. 

We invite comment on whether the regional or state 

scenarios should be given greater weight in establishing the 
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appropriate degree of re-dispatch to incorporate into the state 

goals for CO2 emission reductions, and in assessing costs. 

 We also conclude from our analysis that the extent of redispatch estimated in this building block can be achieved 

without causing significant economic impacts. For example, in 

both of the 70 percent NGCC unit utilization rate scenarios – 

with re-dispatch limited to regional and state boundaries, 

respectively – delivered natural gas prices were projected to 

increase by an average of no more than ten percent over the 

2020-2029 period, which is well within the range of historical 

natural gas price variability.130 Projected wholesale electricity 

price increases over the same period were less than seven 

percent in both cases, which similarly is well within the range 

of historical electric price variability.131 We view these 

projected impacts as not unreasonable and as supporting use of a 

70 percent NGCC utilization rate target for purposes of 

 

130 According to EIA data, year-to-year changes in natural gas 

prices at Henry Hub averaged 29.9 percent over the period from 

2000 to 2013. http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm. 

131 For example, year-on-year changes in PJM wholesale 

electricity prices averaged 19.5 percent over the period from 

2000 to 2013. Ventyx Velocity Suite, ISO real-time data for all 

hours. Price variability for other eastern ISO regions (NYISO, 

ISO-NE, and Midcontinent ISO) was similar. Id. 
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quantifying the emission reductions achievable through 

application of the BSER. 

However, for the same reasons discussed above with respect 

to estimated costs per ton of CO2, in actual implementation we 

again expect that the economic impacts shown in these scenarios, 

including natural gas price impacts, are overstated compared to 

the impacts that would actually occur in real-world compliance 

with this rule’s proposed goals. Consistent with this 

expectation, the comprehensive analyses used to assess the 

compliance costs and benefits of this proposal, which reflect a 

more complete representation of the additional flexibility 

available to states, show significantly smaller economic 

impacts. These analyses are discussed below in section X on the 

regulatory impacts analysis. 

 Based on the analyses summarized above, the EPA proposes 

that for purposes of establishing state goals, a reasonable 

estimate regarding the degree of mass emission reductions 

achievable at fossil fuel-fired steam EGUs can be determined by 

the degree of re-dispatch that can be implemented at reasonable 

cost such that electricity generation could be shifted from more 

carbon-intensive EGUs to less carbon-intensive EGUs within the 

state. The increment of emission reductions incorporated in this 
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component of our proposed BSER determination is commensurate 

with an annual utilization rate for the state’s NGCC units of up 

to 70 percent, on average across all the NGCC units in the 

state. 

For purposes of the alternative set of goals on which we 

are seeking comment, we have used the less stringent target of a 

65 percent average utilization rate for NGCC units. In 2012, 

approximately 16 percent of existing NGCC plants larger than 25 

megawatts had utilization rates equal to or higher than this 

level. Also, as noted earlier, average NGCC utilization 

nationwide is already over 60 percent in some peak hours. We 

therefore view 65 percent as a reasonable lower-bound estimate 

of an achievable average NGCC utilization rate, and we would 

expect the costs and economic impacts from re-dispatch 

associated with a 65 percent NGCC utilization target to be lower 

than the costs and impacts associated with the 70 percent 

utilization target. 

We also specifically invite comment on raising the NGCC 

utilization rate target to a level higher than 70 percent, and 

in particular 75 percent. As noted above, six percent of NGCC 

Comment [A31]: We suggest leaving this ask for 

comment open ended. to encourage comments on a 

range of utilization rates above 70 percent. It is also 

important for EPA to note NGCC units are not just 

peaking units and are in fact designed to operate as 

baseload capacity. 

Another commenter suggests the following: 

“We also specifically invite comment on raising the 

NGCC utilization rate target to levels higher than 

70%, including 75% and 80%.” 
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plants operated at or above a 75 percent utilization rate in 

2012.132 

We invite comment on these proposed findings and on all 

other issues raised by the discussion above and the related 

portions of the Greenhouse Gas Abatement Measures TSD. 

3. Building block 3 – using an expanded amount of less carbonintensive generating capacity 

 The third element of the foundation for EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired EGUs also goes to the achievement of reductions in mass 

emissions, but in this case the reductions would occur at all 

affected EGUs, and entails an analysis of the extent to which 

generation at the affected EGUs can be replaced by using an 

expanded amount of lower-carbon generating capacity to produce 

replacement generation. Below we discuss two types of generating 

capacity that can play this role: renewable generating capacity 

and new and preserved nuclear capacity. 

a. Renewable generating capacity 

 

132 For further analysis related to the use of a 75 percent 

target utilization rate for NGCC units, see chapter 3 of the GHG 

Abatement Measures TSD. 
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Renewable electricity (RE) generating technologies are a 

well-established part of the U.S. power sector. In 2012, 

electricity generated from renewable technologies, including 

conventional hydropower, represented 12 percent of total U.S. 

electricity generation, up from 9 percent in 2005. More than 

half the states have established renewable portfolio standards 

(RPS) that require minimum proportions of electricity sales to 

be supplied with generation from renewable generating 

resources.133 Production of this renewable generation displaces 

predominantly fossil fuel-fired generation and thereby avoids 

the CO2 emissions from that displaced generation. EPA believes 

that renewable electricity generation is a proven way for states 

to reduce CO2 emissions at affected EGUs at a reasonable cost.134

To estimate the CO2 emission reductions from affected EGUs 

achievable through increases in renewable generation, EPA has 

estimated a “best practices” scenario for renewable capacity 

development based on the RPS requirements already established by 

a majority of states. EPA views the existing RPS requirements as 

 

133 Database of State Incentives for Renewables & Efficiency 

(DSIRE), 

http://www.dsireusa.org/summarymaps/index.cfm?ee=0&RE=0. 

134 For discussion of how states and sources might use RE in 

state plans, see section VIII below. 
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a reasonable foundation upon which to develop such a scenario 

for two principal reasons. First, in establishing the 

requirements, states have already had the opportunity to assess 

those requirements against a range of policy objectives 

including both feasibility and costs. These prior state 

assessments therefore support the feasibility and cost of the 

best practices scenario as well. Second, renewable resource 

development potential varies by region, and the RPS requirements 

developed by the states necessarily reflect consideration of the 

states’ own regional contexts.135 

The EPA has not assumed any specific type of renewable 

generating technology for the best practices scenario. Also, the 

scenario is not an EPA forecast of renewable capacity 

development and neither establishes RPS requirements that any 

state must meet nor makes any determinations regarding allowable 

RE compliance measures. Rather, it represents a level of 

renewable resource development for individual states - with 

recognition of regional differences - that we view as reasonable 

 

135 EPA recognizes that individual RPS policies vary in their 

specification of where qualifying RE generation must occur. 

However, EPA believes the regional structure of this estimation 

exercise supports a broad interpretation of RPS requirements 

across states within a region as a proxy for cost-effective RE 

generation potential within the same region. 
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and consistent with policies that a majority of states have 

already adopted based on their own policy objectives and 

assessments of feasibility and cost effectiveness. 

As noted above, renewable resource potential varies 

regionally. This geographic pattern is reflected in the existing 

RPS requirements of the various states. Recognizing this 

pattern, EPA has grouped the states into six regions for 

purposes of developing the best practices scenario.136 By 

comparing each state to a set of neighbors rather than to a 

single national standard, we are able to take regional variation 

into account while still maintaining a level of rigor for the 

scenario’s targets. The regional structure is informed by North 

American Electric Reliability Corporation (NERC) regions and 

Regional Transmission Organizations (RTOs), with adjustments to 

align regional borders with state borders and to group Florida 

and Texas with neighboring states.137 This structure accounts for 

 

136 Given their unique locations, Alaska and Hawaii are not 

grouped with other states into these regions. As a conservative 

approach to estimating cost-effective RE generation potential in 

Alaska and Hawaii, EPA has developed RE generation targets for 

each of those states based on the lowest values for the six 

regions evaluated here. 

137 The regions are the same as those used in regional modeling 

of this rule; see the Regulatory Impact Analysis for more 

information on the regional modeling. 

Comment [A32]: It appears that, in general, 

references to cost effectiveness (and low cost/least 

cost) have been revised to refer to reasonable cost. It 

is not clear if the current references to cost 

effectiveness, etc., are inadvertent, or have been 

intentionally retained/added based upon the 

particular context. 
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similar power system characteristics as well as geographic 

similarities in RE potential. The grouping of states into the 

six regions is shown in Table 3 below. 

Table 3: Regions for Development of Best Practices RPS 

Scenario 

Region States 

East Central Delaware, District of Columbia*, Maryland, New 

Jersey, Ohio, Pennsylvania, Virginia, West 

Virginia 

North Central Illinois, Indiana, Iowa, Michigan, Minnesota, 

Missouri, North Dakota, South Dakota, Wisconsin 

Northeast Connecticut, Maine, Massachusetts, New 

Hampshire, New York, Rhode Island, Vermont* 

South Central Arkansas, Kansas, Louisiana, Nebraska, Oklahoma, 

Texas 

Southeast Alabama, Florida, Georgia, Kentucky, 

Mississippi, North Carolina, South Carolina, 

Tennessee 

West Arizona, California, Colorado, Idaho, Montana, 

Nevada, New Mexico, Oregon, Utah, Washington, 

Wyoming 
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* Because Vermont and the District of Columbia lack affected 

sources, no goals are being proposed for these jurisdictions. 

The best practices scenario for each state consists of 

growing annual levels of RE generation estimated based on 

application of an annual RE growth factor to the state’s 

historical RE generation, subject to a maximum RE generation 

target. The annual RE growth factors and maximum RE generation 

targets were developed separately for each of the six regions. 

Our procedure for determining these elements is described in the 

Greenhouse Gas Abatement Measures TSD and summarized below. 

The EPA first quantified the amount of renewable generation 

in 2012 in each state. EPA then summed these amounts for all 

states in each region to determine a regional starting level of 

renewable generation prior to implementation of the best 

practices scenario. Most hydropower generation is excluded from 

this existing 2012 generation for purposes of quantifying BSERrelated RE generation potential because state RPS requirements 

typically exclude the historical output at pre-existing 

hydropower facilities from qualifying. Additionally, building 

the methodology from a baseline that includes large amounts of 

existing hydropower generation could distort goals for states 

Comment [A33]: Is the historical output at preexisting solar, wind, geothermal, biomass, etc. (i.e. 

non-hydro renewable) facilities excluded here? 

Including the historical output at pre-existing nonhydro renewable facilities could also distort goals. 

Please address. 

Comment [A34]: Recommend explaining why 

this is the case - 

RPS policies are designed to stimulate the 

development of new RE generation - therefore preexisting hydroelectric facilities are generally 

excluded from RPS accounting. 
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with large amounts of existing hydropower capacity as well as 

for their regional neighbors lacking that existing capacity. 

(The exclusion of pre-existing hydropower generation from the 

baseline of this goal-setting framework does not exclude ititnew 

hydropower generation capacityit as an option for state 

compliance.) 

Next, EPA estimated the aggregate target level of RE 

generation in each of the six regions assuming that all states 

within each region can achieve the RE performance represented by 

an average of RPS requirements in states within that region that 

have adopted such requirements. For this purpose, EPA averaged 

the existing RPS percentage requirements that will be applicable 

in 2020 and multiplied that average percentage by the total 2012 

generation for the region. We also computed each state’s maximum 

RE generation target in the best practices scenario as its own 

2012 generation multiplied by that average percentage. (For some 

states that already have RPS requirements in place, these 

amounts are less than their RPS targets for 2030.) 

For each region we then computed the regional growth factor 

necessary to increase regional RE generation from the regional 

starting level to the regional target through investment in new 

RE capacity, assuming that the new investment begins in 2017, 
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the year following the initial state plan submission deadline,138

and continues through 2029. This regional growth factor is the 

growth factor used for each state in that region to develop the 

best practices scenario. 

Finally, we developed the annual RE generation levels for 

each state. To do this, we applied the appropriate regional 

growth factor to that state’s initial RE generation level, 

starting in 2017, but stopping at the point when additional 

growth would cause total RE generation for the state to exceed 

the state’s maximum RE generation target. For computation of the 

proposed state goals discussed in section VII.C below, we used 

the annual amounts for the years 2020 through 2029. For 

computation of the alternate state goals discussed in section 

VII.E below on which we are seeking comment, we used the annual 

amounts for the years 2020 through 2024. 

Alaska and Hawaii are treated as separate regions. Their RE 

targets are based on the lowest regional RE target among the 

continental U.S. regions and their growth factors are based upon 

historical growth rates in their own RE generation. We invite 

 

138 See Section VIII below for further discussion of timing 

requirements for state plan submittals. 
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comment regarding the treatment of Alaska and Hawaii as part of 

this method. 

For details on the targets and growth factors applied, 

please refer to Chapter 4 of the GHG Abatement Measures TSD. 

The cumulative RE amounts for each state, represented as 

percentages of total generation, are shown in Table 4. 

 Table 4: State RE Generation Levels for State Goal 

Development (Percentage of Annual Generation)139

State 2012 Proposed Goals Alternate Goals 

Interim 

Level 

Final 

Level 

Interim 

Level 

Final 

Level 

 Alabama 2% 6% 9% 4% 5% 

 Alaska 1% 2% 2% 1% 1% 

 Arizona 2% 3% 3% 2% 3% 

 Arkansas 3% 5% 7% 4% 5% 

 California 15% 20% 21% 20% 21% 

 Colorado 12% 19% 21% 17% 19% 

 Connecticut 2% 5% 9% 4% 5% 

 Delaware 2% 7% 12% 4% 5% 

 

139 Vermont and the District of Columbia are excluded from this 

table because we are not proposing goals for those 

jurisdictions. 

Comment [A35]: EPA should request comment 

on more ambitious RE, based on technical feasibility 

and cost considerations At a minimum EPA should 

not set final RE goals below 2012 levels – see IA, 

ME, MN and SD. 

Formatted Table
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 Florida 2% 6% 10% 4% 6% 

 Georgia 3% 8% 10% 6% 7% 

 Hawaii 9% 10% 10% 10% 10% 

 Idaho 16% 21% 21% 21% 21% 

 Illinois 4% 7% 9% 6% 7% 

 Indiana 3% 5% 7% 4% 5% 

 Iowa 25% 15% 15% 15% 15% 

 Kansas 12% 19% 20% 19% 20% 

 Kentucky 0% 1% 2% 1% 1% 

 Louisiana 2% 5% 7% 4% 4% 

 Maine 28% 25% 25% 25% 25% 

 Maryland 2% 10% 16% 6% 8% 

 Massachusetts 5% 15% 24% 11% 13% 

 Michigan 3% 6% 7% 5% 6% 

 Minnesota 18% 15% 15% 15% 15% 

 Mississippi 3% 8% 10% 6% 8% 

 Missouri 1% 2% 3% 2% 2% 

 Montana 5% 8% 10% 7% 7% 

 Nebraska 4% 8% 11% 6% 7% 

 Nevada 8% 15% 19% 12% 14% 

 New Hampshire 7% 19% 25% 15% 19% 
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 New Jersey 2% 8% 16% 5% 7% 

 New Mexico 7% 12% 16% 10% 12% 

 New York 4% 11% 18% 8% 10% 

 North Carolina 2% 7% 10% 5% 6% 

 North Dakota 15% 15% 15% 15% 15% 

 Ohio 1% 6% 11% 4% 5% 

 Oklahoma 11% 19% 20% 18% 20% 

 Oregon 12% 19% 21% 17% 20% 

 Pennsylvania 2% 9% 16% 5% 7% 

 Rhode Island 1% 4% 6% 3% 3% 

 South Carolina 2% 7% 10% 5% 6% 

 South Dakota 24% 15% 15% 15% 15% 

 Tennessee 1% 3% 6% 2% 3% 

 Texas 8% 16% 20% 13% 15% 

 Utah 3% 5% 6% 4% 5% 

 Virginia 3% 12% 16% 9% 12% 

 Washington 7% 12% 16% 10% 12% 

 West Virginia 2% 8% 14% 5% 6% 

 Wisconsin 5% 8% 11% 7% 8% 

 Wyoming 9% 15% 20% 13% 15% 
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We note that the RE generation levels represent total 

amounts of RE generation, rather than incremental amounts. As a 

result, this RE generation can be supplied by any RE capacity 

regardless of its date of installation. This approach is 

therefore focused on quantifying the fulfillment of each state’s 

potential to deploy RE as part of BSER using a methodology that 

does not require discriminating between RE capacity that was 

installed before or after any given date. Under this approach, 

states in a given region that have already achieved a higher 

proportion of their generation from renewable resources are 

assumed to have less additional renewable generation to deploy 

as part of the BSER framework informing state goals, in 

comparison to states in that region that have not achieved as 

high a share of RE generation to date. That being said, the 

assumptions of RE generation used to develop the state goals do 

not impose any specific RE generation requirements on any state; 

they are only used to inform the quantification of state goals 

to which states may respond with whatever emission reduction 

measures are preferred. 

The EPA believes that RE generation at the levels 

represented in the best practices scenario can be achieved at 

reasonable costs. According to an EPA analysis based on EIA 
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levelized costs, the cost to displace emissions through RE 

ranges from $10 to $40 per metric ton of CO2.140 Analysis of RE 

development in response to state RPS policies also finds 

historical and projected costs of RPS-driven RE deployment to be 

modest. One comparative analysis that "synthesize[d] and 

analyze[d] the results and methodologies of 28 distinct state or 

utility-level RPS cost impact analyses" projected the median 

change in retail electricity price to be $0.0004 per kilowatthour (a 0.7 percent increase), the median monthly bill impact to 

be between $0.13 and $0.82, and the median CO2 reduction cost to 

be $3 per metric ton.141 This finding has been confirmed with 

more recent RPS cost data, including a report that determined 

2010-2012 retail electricity price impacts due to state RPS 

policies to be less than two percent, with only two states 

experiencing price impacts of greater than three percent.142

 

140 This analysis is based upon EIA’s AEO 2014 Estimated Levelized 

Costs of Electricity for New Generation Sources, available at 

http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.

141 Chen et al., "Weighing the Costs and Benefits of State 

Renewable Portfolio Standards: A Comparative Analysis of StateLevel Policy Impact Projections," Lawrence Berkeley National 

Laboratory, March 2007, available at 

http://emp.lbl.gov/publications/weighing-costs-and-benefitsstate-renewables-portfolio-standards-comparative-analysis-s. 

142 Galen Barbose, “Renewables Portfolio Standards in the United 

States: A Status Update,” Lawrence Berkeley National Lab, 
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Additionally, the National Renewable Energy Laboratory has 

projected low incremental costs for a range of scenarios 

reflecting significant increases in RE penetration, including 

scenarios that increase RE penetration to a range of 30 to 40 

percent of national generation, levels higher than those 

projected in our state-based best practices scenario.143

While RPS requirements will continue to grow over time, EPA 

does not expect this anticipated expansion to fall outside the 

historical norms of deployment or to create unusual pressure for 

cost increases. Full compliance with current RPS goals through 

2035 would require approximately 4 to 4.5 GW of new renewable 

capacity per year. Average deployment of RPS-supported renewable 

capacity from 2007-2012 has exceeded 6 GW per year.144 In 

addition, recent improvements in RPS compliance rates indicate 

to EPA the reasonableness of current RPS growth 

trajectories. Weighted average compliance rates among all states 

 

November 2013. Also to be published in Heeter et al., 

“Estimating the Costs and Benefits of Complying with Renewable 

Portfolio Standards: Reviewing Experience to Date” [review draft 

title]. UNPUBLISHED. National Renewable Energy Laboratory and 

Lawrence Berkeley National Laboratory.

143 NREL, “Renewable Electricity Futures Study”, NREL/TP-6A20-

52409, 2012, http://www.nrel.gov/analysis/re_futures/.

144 Galen Barbose, “Renewables Portfolio Standards in the United 

States: A Status Update,” Lawrence Berkeley National Laboratory, 

November 2013. 
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have improved in each of the past three reported years (2008 - 

2011) from 92.1 percent to 95.2 percent despite a 40 percent 

increase in RPS obligations during this period.145 

We invite comment on this approach to treatment of 

renewable generating capacity as an emission limitation 

component of the best system of emission reduction and a basis 

for quantification of state goals. 

[PLACEHOLDER FOR SOLICITATION OF COMMENT ON AN ALTERNATIVE 

METHOD OF QUANTIFYING BSER RE GENERATION THAT IS CURRENTLY UNDER 

DEVELOPMENT WITH INTERAGENCY REVIEWERS] 

b. New and preserved nuclear capacity 

 Nuclear generating capacity facilitates CO2 emission 

reductions at fossil fuel-fired EGUs by providing carbon-free 

generation that can replace generation at those EGUs. Because of 

their relatively low variable operating costs, nuclear EGUs that 

are available to operate typically are dispatched before fossil 

fuel-fired EGUs. Increasing the amount of nuclear capacity 

relative to the amount that would otherwise be available to 

 

145 http://emp.lbl.gov/rps, retrieved March 2014. The RPS 

compliance measure cited is inclusive of credit multipliers and 

banked RECs utilized for compliance, but excludes alternative 

compliance payments, borrowed RECs, deferred obligations, and 

excess compliance. This estimate does not represent official 

compliance statistics, which vary in methodology by state.

Comment [A36]: We request comment, 

in particular, on the use of 

biomass-derived fuels, in place of 

affected EGUs, as a measure to 

include in a mass-based plan to 

achieve CO2 emission reductions. 

While RE generation from states 

renewable energy efforts qualifies 

as BSER in reducing fossil fuel 

generated electricity, quantifying 

the mass-based reduction from RE 

efforts should a state choose a 

mass-based goal require additional 

considerations. 

Burning biomass-derived fuels for 

energy recovery can yield climate 

benefits as compared to burning 

conventional fossil fuels. For 

example, sustainable forestry and 

agriculture can improve resiliency 

to climate change, be part of a 

national strategy to reduce 

dependence on fossil fuels, and 

contribute to climate change 

mitigation by acting as a “sink” 

for carbon. The plant growth 

associated with producing many of 

the biomass-derived fuels can, to 

varying degrees for different 

biomass feedstocks, sequester 

carbon from the atmosphere, 

effectively recycling the carbon 

emitted when that feedstock is 

combusted to produce electricity. 

Because of the positive attributes 

of biomass-derived fuels, the EPA 

recognizes that biomass-derived 

fuels will play an important role 

in carbon dioxide (CO2) emission 

reduction strategies. We anticipate 

that states will consider biomassderived fuels in energy production 

as a way to mitigate the CO2

emissions attributed to the energy 

sector and include them as part of 

their plans to meet the emission 

reduction requirements of this 

rule. 

One method could be to determine 

the total emissions by adjusting 

the rate-based goal for the state 

identified in Table 1 for renewable 

energy BSER efforts and then using 

§ 60.5770 to convert the remaining 

portion of the rate based goal into ... [1]

Comment [A37]: Will this be framed as an 

alternative, or as EPA’s primary proposal? We 

would reiterate myriad concerns with the original 

proposal to use state RPS without any direct technoeconomic considerations, but understand that the 

alternative is still being formulated and as such we 

concede it probably makes sense to lead with the 

state RPS approach despite its many drawbacks. 
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operate is therefore a technically viable approach for reducing 

CO2 emissions from affected fossil fuel-fired EGUs. 

 One way to increase the amount of available nuclear 

capacity is to build new nuclear EGUs. However, in addition to 

having low variable operating costs, nuclear generating capacity 

is also relatively expensive to build compared to other types of 

generating capacity, and little new nuclear capacity has been 

constructed in the U.S. in recent years; instead, most recent 

generating capacity additions have consisted of NGCC or 

renewable capacity. Nevertheless, five new nuclear EGUs at three 

plants are currently under construction: Watts Bar 2 in 

Tennessee, Vogtle 3-4 in Georgia, and Summer 2-3 in South 

Carolina. The EPA believes that since the decisions to construct 

these units were made prior to this proposal, it is reasonable 

to view the incremental cost associated with the CO2 emission 

reductions available from completion of these units as zero for 

purposes of setting states’ CO2 reduction goals (although EPA 

acknowledges that the planning for those units likely included 

consideration of the possibility of future regulation of CO2

emissions from EGUs). Completion of these units therefore 

represents a highly cost-effective opportunity to reduce CO2

emissions from affected fossil fuel-fired EGUs. For this reason, 
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we are proposing that the emission reductions achievable at 

affected sources as a result of the generation provided at the 

identified new nuclear units should be factored into the state 

goals for the respective states where these new units are 

located. However, the EPA also realizes that reflecting 

completion of these units in the goals has a significant impact 

on the calculated goals for the states in which these units are 

located. If one or more of the units were not completed as 

projected, that could have a significant impact on the state’s 

ability to meet the goal. We therefore take comment on whether 

it is appropriate to reflect completion of these units in the 

state goals and on alternative ways of considering these units 

when setting state goals. 

 Another way to increase the amount of available nuclear 

capacity is to preserve existing nuclear EGUs that might 

otherwise be retired. The EPA is aware of six nuclear EGUs at 

five plants that have retired or whose retirements have been 

announced since 2012: San Onofre Units 2-3 in California, 

Crystal River 3 in Florida, Kewaunee in Wisconsin, Vermont 

Yankee in Vermont, and Oyster Creek in New Jersey. While each 

retirement decision is based on the unique circumstances of that 

individual unit, the EPA recognizes that a host of factors – 
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increasing fixed operation and maintenance costs, relatively low 

wholesale electricity prices, and additional capital investment 

associated with ensuring plant security and emergency 

preparedness – have altered the outlook for the U.S. nuclear 

fleet in recent years. Reflecting similar concern for these 

challenges, EIA in its most recent Annual Energy Outlook has 

projected an additional 5.7 GW of capacity reductions in the 

existing nuclear fleet. EIA describes the projected capacity 

reductions – which are not tied to the projected retirement of 

any specific unit – as necessary to recognize the “continued 

economic challenges” faced by the higher-cost nuclear units.146

Likewise, without making any judgment about the likelihood that 

any individual EGU will retire, we view this 5.7 GW, which 

comprises an approximately six percent share of nuclear 

capacity, as a reasonable proxy for the amount of nuclear 

capacity at risk of retirement. 

We have determined that, based on available information 

regarding the cost and performance of the nuclear fleet, 

preserving the operation of this existing, at-risk nuclear 

capacity is likely to be a relatively cost-effective approach to 

 

146 Jeffrey Jones and Michael Leff, EIA, “Implications of 

accelerated power plant retirements,” (April 2014). 
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achieving CO2 reductions from affected EGUs. For example, 

retaining the estimated seven percent of at-risk nuclear 

capacity could avoid 200 to 300 million metric tons of CO2 over 

an initial compliance phase-in period of ten years.147 According 

to a recent report, nuclear units may be experiencing up to a 

$6/MWh shortfall in covering their operating costs with 

electricity sales.148 Assuming that such a revenue shortfall is 

representative of the incentive to retire at-risk nuclear 

capacity, one can estimate the value of offsetting the revenue 

loss at these at-risk nuclear units to be approximately $12 to 

$17 per metric ton. EPA views this cost as reasonable. We 

therefore propose that the emission reductions achievable by 

retaining in operation six percent of each state’s existing 

nuclear capacity should be factored into the state goals for the 

respective states. 

 For purposes of goal computation, generation from new and 

preserved nuclear capacity is based on an estimated 90 percent 

average utilization rate for U.S. nuclear units, consistent with 

 

147 Assuming replacement power for at-risk nuclear capacity is 

sourced from new NGCC capacity at 800 lbs/MWh or the power 

system at 1127 lbs CO2/MWh (average 2020 power sector emissions 

intensity as projected in EPA’s IPM Base Case). 

148 “Nuclear... The Middle Age Dilemma?” Eggers, et al., Credit 

Suisse, February 2013 

Comment [A38]: Can EPA add a url to the 

footnote 
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long-term average annual utilization rates observed across the 

nuclear fleet. The methodology for taking this generation into 

account for purposes of setting state emission rate goals is 

described below in section VII on state goals and in the Goal 

Computation TSD. 

 We invite comment on all aspects of the approach discussed 

above. In addition, we specifically request comment on whether 

we should include in the state goals an estimated amount of 

additional nuclear capacity whose construction is sufficiently 

likely to merit evaluation for potential inclusion in the goalsetting computation. 

4. Building block 4 – demand-side energy efficiency 

The fourth element of the foundation for EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired EGUs also reduces mass emissions at all affected EGUs, and 

entails an analysis of the extent to which generation at the 

affected EGUs can be reduced by reducing the demand for 

generation at those EGUs through measures that reduce the 

overall quantity of generation demanded by end-users.149 

 

149 Electricity end-users and electricity end-use referred to 

throughout this section includes the residential, commercial and 

industrial sectors. 

Comment [A39]: Can EPA please explain 

why these details were removed? We believe 

they are important and should be kept. 

Comment [A40]: Consider tightening/clarifying 

this sentence. 
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a. Benefits of demand-side energy efficiency 

 Reducing demand for generation at affected EGUs through 

policies to improve demand-side energy efficiency is a proven 

method of reducing CO2 emissions at those EGUs. Every state has 

established demand-side energy efficiency policies, and many 

stakeholders emphasized the success of these policies in 

reducing electricity consumption by large amounts. For example, 

data reported to the U.S. Energy Information Administration 

(EIA) show that in 2012 California and Minnesota avoided 12.5 

percent and 13.1 percent of their electricity demand, 

respectively, through their demand-side efficiency programs.150

Additionally, multiple studies have found that significant 

improvements in end-use energy efficiency can be realized at 

less cost than the savings from avoided power system costs.151

 By reducing electricity consumption, energy efficiency 

avoids greenhouse gas emissions associated with electricity 

generation. Because fossil fuel-fired EGUs typically have higher 

 

150 Energy Information Administration Form 861, 2012, available 

at http://www.eia.gov/electricity/data/eia861/.

151 See, e.g., Electric Power Research Institute, U.S. Energy 

Efficiency Potential Through 2035 (Final Report, April 2014); 

Wang, Yu and Marilyn A. Brown, Policy Drivers for Improving 

Electricity End-Use Efficiency in the U.S.: an EconomicEngineering Analysis (Energy Efficiency, 2014). 
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variable costs than other EGUs (such as nuclear and renewable 

EGUs), their generation is typically the first to be displaced 

when demand is reduced. Consequently, reductions in fossil fuelfired utilization may be achieved cost-effectively by reducing 

electricity consumption and, by the same token, reductions in 

electricity consumption generally cause reductions in the amount 

of fossil fuel-fired generation, thereby avoiding the CO2

emissions associated with the avoided generation. In this 

manner, in 2011, state demand-side energy efficiency programs 

are estimated to have reduced CO2 emissions by 75 million metric 

tons.152 And when integrated into a comprehensive approach for 

addressing CO2 emissions, demand-side energy efficiency 

improvements offer even more potential to improve the carbon 

profile of the electricity supply system. For example, if 

incentives exist to shift generation to lower carbon-intensity 

EGUs, and those EGUs are fully utilized, reducing demand can 

further reduce carbon intensity. This potential effect 

reinforces the appropriateness of incorporating demand-side 

 

152 Innovation, Electricity, Efficiency (an Institute of the 

Edison Foundation), Summary of Customer-Funded Electric 

Efficiency Savings, Expenditures, and Budgets (2011-2012) (March 

2013), available at 

http://www.edisonfoundation.net/iei/ourwork/Pages/issuebriefs.as

px. 
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efficiency improvements in a comprehensive approach to address 

power sector CO2 emissions. In addition to reducing the CO2 

emissions and carbon intensity of the power sector, because it 

drives reductions in fossil fuel usage at EGUs, demand-side 

energy efficiency also reduces criteria pollutant emissions, 

cooling water intake and discharge, and solid waste production 

associated with fossil fuel combustion. By reducing electricity 

usage significantly, energy efficiency also commonly reduces the 

bills of electricity customers. 

b. “Best practices” for demand-side energy efficiency 

 To estimate the potential CO2 reductions at affected EGUs 

that could be achieved through implementation of demand-side 

energy efficiency policies as a part of state goals, the EPA 

developed a “best practices” demand-side energy efficiency 

scenario. This scenario provides an estimate of the potential 

for sources and states to implement policies that increase 

investment in cost-effective demand-side energy efficiency 

technologies and practices. It does not represent an EPA 

forecast of business-as-usual impacts of state energy efficiency 

policies or an EPA estimate of the full potential of end-use 

energy efficiency available to the power system, but rather 

represents a feasible policy scenario showing the reductions in 
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fossil fuel-fired electricity generation resulting from 

accelerated use of energy efficiency policies in all states 

consistent with a level of performance that has already been 

achieved or required by policies (e.g., energy efficiency 

resource standards) of the leading states. The data and 

methodology used to develop the best practices scenario are 

summarized below. 

 We have not assumed any particular type of demand-side 

energy efficiency policy. States with leading energy efficiency 

performance have employed a variety of strategies that are 

implemented by a range of entities including investor-owned, 

municipal and cooperative electric utilities as well as state 

agencies and third-party administrators. These include energy 

efficiency programs,153 building energy codes, state appliance 

 

153 Energy efficiency programs are driven by a variety of state 

policies including energy efficiency resource standards, 

requirements to acquire all cost-effective energy efficiency, 

integrated resource planning requirements, and demand-side 

management plans and budgets. Funding for energy efficiency 

programs is provided through a variety of mechanisms as well, 

including per kilowatt-hour surcharges and proceeds from forward 

capacity market and emission allowance auctions. The programs 

are implemented by a range of entities including investor-owned, 

municipal, and cooperative electric utilities, state agencies, 

and designated third-party administrators. All end-use sectors 

(residential, commercial, and industrial) are targeted by energy 

efficiency programs and numerous strategies are employed, 
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standards (for appliances without federal standards), tax 

credits, and benchmarking requirements for building energy 

use.154 Energy efficiency policies are designed to accelerate the 

deployment of demand-side energy efficiency technologies, 

practices, and measures by addressing market barriers and market 

failures that limit their adoption. Some states have adopted 

energy efficiency resource standards155 (EERS) to drive 

investment in energy efficiency programs; some have relied on 

other strategies; most states are using multiple policy 

approaches. Based on historical data on energy efficiency 

program savings and analysis of the requirements of existing 

state energy efficiency policies, twelve leading states have 

either achieved – or have established requirements that will 

lead them to achieve - annual incremental savings rates of at 

 

including targeted rebates for high-efficiency appliances; 

energy audits with recommendations for cost-effective, energysaving upgrades; and processes to certify energy efficiency 

service providers.

154 See the Existing State Actions TSD for descriptions of the 

full array of demand-side energy efficiency policies currently 

employed by states. 

155 EERS establish specific, long-term targets for energy savings 

that utilities or non-utility program administrators must meet 

through customer energy efficiency programs. EERS, as well as 

requirements that utilities acquire all cost-effective energy 

efficiency, have been the most impactful state energy efficiency 

strategies in recent years.
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least 1.5 percent of the electricity demand that would otherwise 

have occurred.156 The 1.5 percent savings rate is inclusive of, 

not additional to, existing state energy efficiency 

requirements. These savings levels are realized exclusively 

through the adoption and implementation of energy efficiency 

programs. The energy savings data underpinning these analyses 

are derived from energy efficiency program reports required by 

state public utility commissions and other entities with a 

similar oversight role.157 These state commissions define and 

oversee the analysis and reporting requirements for energy 

efficiency programs as part of their role of overseeing rates 

for utility customers in their states. One typical requirement 

is the application of recognized evaluation, measurement, and 

validation (EM&V) protocols that specify industry-preferred 

 

156 The historical data used are reported to the Energy 

Information Administration through Form EIA-861. The analysis 

and summary of state energy efficiency policies is from the 

American Council for an Energy-Efficient Economy (ACEEE), State 

EERS Activity Policy Brief (February 24, 2014). See the 

Greenhouse Gas Abatement Measures TSD for more information.

157 E.g., energy efficiency programs operated by municipal and 

cooperative utilities may report their program results to their 

Boards of Directors rather than to a state utility commission. 
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approaches and methodologies for estimating savings from 

efficiency programs.158 

While EM&V data reflect documented electricity savings from 

energy efficiency programs, they typically do not account for 

potential electricity savings available from additional stateimplemented policies for which EM&V protocols are less 

consistently required or applied, such as building energy codes. 

Thus, we consider the 1.5 percent annual incremental savings159

rate to be a reasonable estimate of the energy efficiency policy 

performance that is already achieved or required by leading 

states and that can be achieved cost-effectively by all states 

given adequate time. If we were to capture the potential for 

additional policies, such as the adoption and enforcement of 

state or local building energy codes, to contribute additional 

reductions in electricity demand beyond those resulting from 

 

158 See the EM&V section of the state Plan TSD for more 

information on EE program evaluation. 

159 This incremental savings rate and all others discussed in 

this section represent net, rather than gross, energy savings. 

Gross savings are the changes in energy use (MWh) that result 

directly from program-related actions taken by program 

participants, regardless of why they participated in a program. 

Net savings refer to the changes in energy use that are directly 

attributable to a particular energy efficiency program after 

accounting for free-ridership, spillover, and other factors. 

Comment [A41]: Question for understanding: 

Does this include business and residential 

geothermal efficiency heat pumps? Is geothermal 

energy reduction currently captured under RE or EE, 

the latter seeming more appropriate? This would 

seem like a vast source of cost-effective EE savings, 

hence the question around building energy codes. 
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energy efficiency programs, we could reasonably increase the 

targeted annual incremental savings rate beyond 1.5 percent. 

 For states with more limited EE program experience, 

reaching a best-practices level of performance requires 

undertaking a set of activities that takes some time to plan, 

implement, and evaluate. For the best practices scenario, we 

have therefore estimated that each state’s annual incremental 

savings rate increases from its 2012 annual saving rate160 to a 

rate of 1.5 percent over a period of years starting in 2017. 

(Thus, the goal for each state differs to reflect the assumption 

that a state already close to a 1.5 percent annual incremental 

savings rate can expand its energy efficiency programs to reach 

that rate sooner than a state that is further from that rate.) 

The pace at which states are estimated to increase their savings 

rate level is 0.2 percent per year. This rate is consistent with 

past performance and future requirements of leading states.161

For states already at or above the 1.5 percent annual 

incremental savings rate (based on 2012 reported data), we 

estimate that they would realize a 1.5 percent rate in 2017 and 

 

160 2012 is the most recent year for energy efficiency program 

incremental savings data reported using EIA Form 861.

161 See the Greenhouse Gas Abatement Measures TSD for more 

information. 
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maintain that rate through 2029. For all states we assume the 

initial savings rate (the lower of their 2012 value or 1.5 

percent) is realized in 2017 and increases each year by 0.2 

percent until the target rate of 1.5 percent is achieved162 and 

is then maintained at that level through 2029 The savings from 

energy efficiency programs are cumulative, meaning that, in 

simplified terms, a state implementing a sustained program with 

a 1.5 percent annual incremental savings rate could expect 

cumulative annual savings of approximately 1.5 percent after the 

first year, 3.0 percent after the second year, 4.5 percent after 

the third year, and so on. Savings from the first year would 

drop off at the end of the average life of the energy efficiency 

program portfolio (typically about ten years). Accordingly, we 

have projected the cumulative annual savings for each state that 

would be achieved for the period 2020 to 2029 based on the 

state’s reaching and then sustaining the best practices annual 

incremental savings rate through 2029. These values, for each 

 

162 For example, a state with a reported savings rate of 0.5% in 

2012 is assumed to realize a 2017 savings rate of 0.5% and their 

savings rates for 2018, 2019, 2020, 2021 and 2022 are calculated 

to be 0.7%, 0.9%, 1.1%, 1.3%, and 1.5%, respectively. By this 

method, all states have reached the 1.5% target rate by 2017 at 

the earliest and by 2025 at the latest. 
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state and for each year (2020-2029), are used in the procedure 

for computing the state goals described in section VII.C below. 

 As discussed in section VII.E below, the EPA is also taking 

comment on a less stringent alternative for setting state goals. 

Under this alternative, the demand-side energy efficiency 

requirement is relaxed by using 1.0 percent (rather than 1.5 

percent) annual incremental savings as representative of the 

best-practices level of performance. In addition, the pace at 

which incremental savings levels are increased from their 

historical levels is relaxed slightly to 0.15 percent per year 

(rather than 0.2 percent). The 1.0 percent rate of savings is a 

level of performance that has been achieved - or that 

established state requirements will cause to be achieved - by 20 

states.163 As is done with the more stringent goal-setting 

approach for energy efficiency, the cumulative percentages for 

each state are derived and multiplied by the state’s 2012 

historical electricity sales as reflected in the EIA detailed 

state data, in this case for the period from 2020 to 2024. 

 The state-specific cumulative annual electricity saving 

data inputs for both the proposed approach and the less 

 

163 See the Greenhouse Gas Abatement Measures TSD for more 

information.
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stringent alternative are discussed in the Greenhouse Gas 

Abatement Measures TSD and summarized in Table 5. 

Table 5: Demand-Side Energy Efficiency State Goal Development: 

Cumulative Annual Electricity Savings (Percentage of Annual 

Sales) Resulting from Best Practices Scenario164

State 1.5% Savings 

Target Scenario 

1.0% Savings 

Target Scenario 

2020 2029 2020 2024 

 Alabama 1.4% 9.5% 1.1% 3.9% 

 Alaska 1.2% 9.5% 0.9% 3.7% 

 Arizona 5.2% 11.4% 3.5% 6.0% 

 Arkansas 1.5% 9.7% 1.2% 4.1% 

 California 5.0% 11.6% 3.6% 6.1% 

 Colorado 3.9% 11.0% 3.3% 5.9% 

 Connecticut 4.7% 11.9% 3.6% 6.3% 

 Delaware 1.1% 9.5% 0.9% 3.6% 

 Florida 2.0% 10.0% 1.8% 4.7% 

 Georgia 1.8% 9.8% 1.5% 4.4% 

 Hawaii 1.3% 9.5% 1.0% 3.8% 

 Idaho 3.8% 11.1% 3.5% 5.9% 

 Illinois 4.4% 11.6% 3.5% 6.2% 

 Indiana 3.2% 11.1% 2.9% 5.7% 

 

164 Vermont and the District of Columbia are excluded from this 

table because we are not proposing goals for those 

jurisdictions. 
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 Iowa 4.7% 11.7% 3.6% 6.0% 

 Kansas 1.2% 9.5% 0.9% 3.7% 

 Kentucky 1.9% 10.0% 1.6% 4.6% 

 Louisiana 1.1% 9.3% 0.9% 3.6% 

 Maine 5.4% 12.1% 3.6% 6.3% 

 Maryland 4.2% 11.5% 3.5% 6.1% 

 Massachusetts 4.4% 11.8% 3.6% 6.2% 

 Michigan 4.6% 11.8% 3.6% 6.2% 

 Minnesota 4.8% 11.7% 3.6% 6.2% 

 Mississippi 1.4% 9.6% 1.1% 3.9% 

 Missouri 1.6% 9.9% 1.3% 4.2% 

 Montana 3.4% 10.9% 3.0% 5.7% 

 Nebraska 2.2% 10.4% 1.9% 4.9% 

 Nevada 3.0% 10.7% 2.7% 5.5% 

 New Hampshire 2.8% 11.0% 2.6% 5.5% 

 New Jersey 1.3% 9.6% 1.0% 3.7% 

 New Mexico 3.1% 10.6% 2.8% 5.5% 

 New York 4.4% 11.8% 3.5% 6.2% 

 North Carolina 2.4% 10.3% 2.1% 5.0% 

 North Dakota 1.4% 9.7% 1.1% 4.0% 

 Ohio 4.2% 11.6% 3.5% 6.1% 

 Oklahoma 1.9% 10.0% 1.6% 4.5% 

 Oregon 4.7% 11.4% 3.6% 6.1% 

 Pennsylvania 4.7% 11.7% 3.6% 6.2% 

 Rhode Island 3.9% 11.6% 3.4% 6.1% 
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 South Carolina 2.3% 10.2% 2.0% 4.9% 

 South Dakota 1.6% 9.9% 1.3% 4.2% 

 Tennessee 2.2% 10.3% 1.9% 4.9% 

 Texas 1.8% 9.9% 1.5% 4.4% 

 Utah 3.6% 11.0% 3.2% 5.8% 

 Virginia 1.2% 9.3% 1.0% 3.7% 

 Washington 4.2% 11.3% 3.5% 6.0% 

 West Virginia 1.8% 10.1% 1.5% 4.4% 

 Wisconsin 4.7% 11.8% 3.6% 6.2% 

 Wyoming 1.6% 9.7% 1.3% 4.2% 

 
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c. Costs of demand-side energy efficiency 

 The EPA expects implementation of demand-side energy 

efficiency policies as reflected in the best practices scenario 

to be achievable at reasonable costs and believes that this 

represents a technically feasible approach to reducing 

greenhouse gas emissions from the existing fossil fuel-fired 

EGUs. EPA finds support for the reasonableness of the costs of 

this building block from two perspectives. First, the specific 

savings levels represented by this building block were developed 

based upon the experience and success of states in developing 

and implementing energy efficiency policies that they undertake 

primarily for the purpose of providing economic benefits to 

electricity consumers in their state. Secondly, even with 

notably conservative assumptions about the costs of achieving 

the levels of electricity savings associated with this building 

block, EPA’s analysis of the power sector indicates that the 

costs are reasonable. 

The processes by which states develop funding for energy 

efficiency programs typically require the application of costeffectiveness tests to ensure that adopted program portfolios 

lead to lower costs than the use of generation sources that 
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would otherwise be required to meet the associated electricity 

service demands. Indeed, a major reason for the widespread 

presence and rapid growth of demand-side energy efficiency 

programs is the strong evidence of their cost-effectiveness even 

before the additional benefit of CO2 reductions is considered.165

Independent studies have found that end-users’ needs for energydependent services (e.g., heating, cooling, lighting, motor 

output, and information and entertainment services) frequently 

can be satisfied at lower cost by improving the efficiency of 

electricity consumption rather than by increasing the supply of 

electricity.166 These factors indicate that the cost of CO2

reductions achieved through implementation of demand-side energy 

efficiency at the levels reflected in the best practices 

scenario are likely to be very reasonable, typically resulting 

in reductions in average electricity bills across all end-use 

sectors.167

 

165 Some states do include a valuation of CO2 benefits as part of 

their evaluations of cost effectiveness.

166 E.g., Electric Power Research Institute, U.S. Energy 

Efficiency Potential Through 2035 (Final Report, April 2014); 

Northwest Power and Conservation Council, Sixth Northwest 

Conservation and Electric Power Plan (Feb. 2010), available at 

http://www.nwcouncil.org/energy/powerplan/6/plan/.

167 As described below and in the Goal Computation TSD, in the 

case of a state that is a net importer of electricity, the 
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 Another approach to evaluating the reasonableness of the 

costs associated with this building block is to compare the 

demand-side energy efficiency costs to the avoided power system 

costs as represented within the EPA’s modeling of the power 

sector. The costs associated with the best practices scenario 

were estimated based upon a synthesis of data and analysis of 

the factors that impact energy efficiency program costs as 

calculated using an engineering-based, bottom-up approach that 

is standard for state and utility analysis of these policies. 

These factors include the average energy efficiency program 

costs per unit of first-year energy savings ($/MWh), the ratio 

of program to participant costs, and the lifetimes of energy 

efficiency measures across the full portfolio of programs. In 

addition, EPA has included a cost escalation factor to represent 

the possibility of increased costs associated with higher levels 

of incremental energy savings rates and the national scope of 

 

proposed goal computation procedure includes an adjustment to 

account for the possibility that some of the generation and 

emissions avoided due to the state’s demand-side energy 

efficiency programs may occur at EGUs in other states. Given the 

extremely low cost of CO2 emission reductions achievable through 

demand-side energy efficiency programs, implementation of such 

programs is likely to be a highly cost-effective approach to 

reducing CO2 emissions even for a state whose own affected EGUs 

achieve only part of the CO2 emission reduction benefit from the 

state’s demand-side energy efficiency efforts. 
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the best practices scenario. EPA has taken a conservative 

approach to each of these factors, selecting values that are at 

the higher-cost end of reasonable ranges of estimated values. 

The combination of these factors is reflected in the value EPA 

has derived for the levelized cost per MWh of saved energy. This 

value includes both the program costs paid by utilities for 

implementing energy efficiency programs and the amounts that 

program participants pay for their own energy efficiency 

improvements beyond the program costs. These costs are levelized 

across the measure lifetimes of a full portfolio of energy 

efficiency programs. This analysis provides a levelized cost of 

saved energy (LCOSE) range of $85/MWh to $90/MWh ($2011) over 

the 2020 to 2030 period. This range of LCOSE is notably 

conservative (leading to higher costs) in comparison with most 

utility and state analysis. For example, a 2014 analysis by the 

American Council for an Energy-Efficient Economy (ACEEE) 

surveyed program and participant cost results across seven 

states and found a comparable LCOSE value of $54/MWh (2011$).168 

 

168 American Council for an Energy-Efficient Economy (ACEEE), 

The Best Value for America’s Energy Dollar: A National Review of 

the Cost of Utility Energy Efficiency Programs (Report No. 

U1402, March 2014). 

Comment [A42]: Can EPA please explain 

why the LCOSE numbers have increased? 

Also, can these be expressed per kWH instead of 

MWH. 
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 To estimate the reductions in power system costs and CO2

emissions associated with the best practices level of demandside energy efficiency described above, EPA analyzed a scenario 

incorporating the resulting reduction in electricity demand and 

compared the results with the business-as-usual scenario. Both 

analyses were conducted using the Integrated Planning Model 

(IPM) described previously. Combining the resulting power system 

cost reductions with the energy efficiency cost estimates 

associated with the best practices scenario, EPA derived net 

cost impacts for 2020, 2025, and 2030. Dividing these net cost 

impacts by the associated CO2 reductions for each year, EPA found 

that the average cost of the CO2 reductions achieved ranged from 

$16 to $24 per metric ton of CO2. . EPA views these estimated 

costs as reasonable. Together with the history of demonstrated 

successful state implementation of cost-effective demand-side 

energy efficiency programs discussed above, this analysis 

supports the reasonableness of the level of demand-side energy 

efficiency represented by the best practices scenario and, by 

extension, the reasonableness of the emission reductions at 

affected EGUs that can be achieved consistent with achievement 

of that level of demand-side energy efficiency. 

Comment [A43]: Please explain why this will 

not result in an over-estimate of the cost-savings 

given that up to 40% of the best practice EE 

measures are already in the baseline. 

Comment [A44]: What is the marginal cost? 

Comment [A45]: Please explain how you 

calculated these average cost numbers. Does this 

imply that the energy savings is on average roughly 

$65 per metric tonne? 

Does this also assumes that the EE measures are 

100% effective? Given the uncertainty in the 

effectiveness of EE programs (see Levinson NBER 

WP #19123) it would be a good idea to present a 

sensitivity analysis assuming less than 100% 

effectiveness of the EE measures. 

Comment [A46]: Can EPA please cite any 

independent peer-reviewed analyses that indicates 

that state DSM programs have been successful? 
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 Further details regarding the data and methodology used to 

evaluate the potential for demand-side energy efficiency 

programs to substitute for generation at affected EGUs and 

thereby facilitate reductions of power sector CO2 emissions at 

reasonable costs are provided in the Greenhouse Gas Abatement 

Measures TSD. We invite comment on all aspects of our data and 

methodology as discussed above and in the TSD, as well as on the 

level of reductions we propose to define as best practices 

suitable for representation consistent with the best system of 

emission reduction and the level reflected in the less stringent 

scenario. We also specifically invite comment on several issues: 

1) increasing the annual incremental savings rate to 2.0 percent 

and the pace of improvement to 0.25 percent per year to reflect 

an estimate of the additional electricity savings achievable 

from state policies not reflected in the 1.5 percent rate and 

the 0.20 percent per year pace of improvement, such as building 

energy codes and state appliance standards, 2) alternative 

approaches and/or data sources (i.e., other than EIA Form 861) 

for determining each state’s current level of incremental annual 

electricity savings, and 3) alternative approaches and/or data 

sources for evaluating costs associated with implementation of 

state demand-side energy efficiency policies. 
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5. Potential emission reduction measures not used to set 

proposed goals 

 There are three additional potential measures for reducing 

GHG emissions from EGUs that the EPA does not propose to 

consider part of the best system of emission reduction for 

existing EGUs at this time and therefore has not used for goalsetting purposes, but that merit discussion here: fuel switching 

at individual EGUs, carbon capture and storage (CCS), and 

reducing emissions at affected fossil fuel-fired steam EGUs by 

using expanded amounts of less carbon-intensive new NGCC 

capacity to provide replacement generation. 

 a. Fuel switching at individual units 

 One technically feasible approach for reducing CO2 emissions 

per MWh of generation from an EGU designed for coal-fired 

generation is to substitute natural gas for some or all of the 

coal. Most existing coal-fired steam EGU boilers can be modified 

to switch to 100 percent gas input or to co-fire gas with coal 

in any desired proportion. For certain individual EGUs, 

switching to or co-firing with gas may be an attractive option 

for reducing CO2 emissions. 

 Changing the type of fuel burned at a steam EGU typically 

requires certain plant modifications (e.g., new burners) and may 
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have some negative impact on the net efficiencies of the boiler 

and the overall generation process. If the plant lacks existing 

gas pipeline infrastructure capable of delivering the necessary 

quantities of natural gas to the boiler, installation of a new 

pipeline lateral would also be required. 

 The capital costs of plant modifications required to switch 

a coal-fired EGU completely to natural gas are roughly $100-

300/kW, excluding pipeline costs. For plants that require 

additional pipeline capacity, the capital cost of constructing 

new pipeline laterals is approximately $1 million per mile of 

pipeline built. Offsetting these capital costs, conversion to 

100 percent gas input would typically reduce the EGU’s fixed 

operating and maintenance costs by about 33 percent due mainly 

to certain equipment retirements and a reduction in staffing, 

while non-fuel variable costs would be reduced by about 25 

percent due to reduced maintenance and waste disposal costs. 

However, in most cases, the most significant cost change 

associated with switching from coal to gas in a coal-fired 

boiler is likely to be the difference in fuel cost. Using EIA’s 

projections of future coal and natural gas prices, switching a 

steam EGU’s fuel from coal to gas typically would more than 

double the EGU’s fuel cost per MWh of generation. 
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 The CO2 reduction potential of natural gas co-firing or 

conversion is due largely to the different carbon intensities of 

coal and natural gas and is directly related to the proportion 

of gas burned. Greater reductions in the CO2 emission rate are 

achieved at higher proportions of gas usage. For example, at ten 

percent gas co-firing, the net emission rate (e.g., pounds of CO2

per net MWh of generation) of a typical steam EGU previously 

burning only coal would decrease by approximately four percent. 

At 100 percent gas burn, the net emission rate of a typical 

steam EGU previously burning only coal would decrease by 

approximately 40 percent. 

 For a typical base-load coal-fired EGU, and reflecting 

EIA’s projected future natural gas and coal prices, the average 

cost of CO2 reductions achieved through gas conversion or cofiring ranges from $83 per metric ton to $150 per metric ton. 

The low end of the range of CO2 reduction costs represents a 100 

percent switch to gas, because in instances where a combination 

of coal and gas is burned, the EGU would continue to bear the 

fixed costs associated with equipment needed for coal 

combustion, raising the cost per ton of CO2 reduced. 

 The EPA’s economic analysis suggests that there are more 

cost effective opportunities for coal-fired utility boilers to 
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reduce their CO2 emissions than through natural gas conversion or 

co-firing. As a result, the EPA has not proposed at this time to 

include this option in the BSER and has not incorporated 

implementation of the option into the proposed state goals. 

However, the EPA believes that there are a number of factors 

that warrant further consideration in determining whether the 

option should be included. First, the EPA is aware that a number 

of utilities have reworked some of their coal-fired units to 

allow for some level of natural gas co-firing (and in some cases 

have converted the units to fire entirely on natural 

gas). Second, the EPA is aware of several possible reasons 

beyond reduction of CO2 emissions that may make natural gas cofiring economic in some circumstances. One example is that 

natural gas reburn strategies that involve co-firing with 10 to 

20 percent natural gas can be an effective control strategy for 

NOx emissions and, thus, can offset operational (and in some 

cases, capital) costs associated with other NOx controls such as 

SCR or SNCR. A second example suggested by some vendors is that 

the capability to burn natural gas in a coal-fired boiler can 

improve economics because it allows the boiler to operate more 

effectively at lower loads. A third example, applicable to units 

that run infrequently but may be needed for reliability 
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purposes, is that converting to or co-firing with natural gas 

may be more economic than either installing non-CO2 emission 

controls or taking other measures, such as transmission 

upgrades, that could be associated with retiring the 

unit. Finally, beyond the reasons just described why EGU owners 

may find natural gas co-firing to be cost-effective, there are 

also potentially significant health co-benefits associated with 

burning natural gas instead of coal. 

We solicit comment on whether natural gas co-firing or 

conversion should be part of the BSER. We also request comment 

regarding whether, and, if so, how we should consider the cobenefits of natural gas co-firing in making that determination. 

 b. Carbon capture and storage 

 Another possible approach for reducing CO2 emissions from 

existing fossil fuel-fired EGUs is through the application of 

carbon capture and storage169 technology (CCS). In the recently 

proposed standards of performance for new fossil fuel-fired EGUs 

(79 FR 1430), the EPA proposed to find that the best system of 

emission reduction for new fossil fuel-fired boilers and IGCC 

units is partial application of CCS. In that proposal, the EPA 

 

169 This is also sometimes referred to as “carbon capture and 

sequestration.”
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found that, for new units, partial CCS has been adequately 

demonstrated; it is technically feasible; it can be implemented 

at costs that are not unreasonable; it provides meaningful 

emission reductions; and its implementation will serve to 

promote further development and deployment of the technology. 

The EPA also noted in the proposal that most of the relatively 

few new boiler and IGCC EGU projects currently under development 

are already planning to implement CCS; and, as a result, the 

proposed standard would not have a significant impact on 

nationwide energy prices. 

In contrast, the EPA did not identify full or partial CCS 

as the BSER for new natural gas-fired stationary combustion 

turbines, noting technical challenges to implementation of CCS 

at NGCC units as compared to implementation at new solid fossil 

fuel-fired sources. The EPA also noted that, because virtually 

all new fossil fuel-fired power projects are projected to use 

NGCC technology, requiring full or partial CCS would have a 

greater impact on the price of electricity than requiring CCS at 

the few projected coal plants, and the larger number of NGCC 

projects would make a CCS requirement difficult to implement in 

the short term. 
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 Partial CCS has been demonstrated at existing EGUs. It has 

been demonstrated at a pilot-scale at Southern Company’s Plant 

Barry; it is being installed for large-scale demonstration at 

NRG’s W.A. Parish facility; and it is expected soon to be 

applied at commercial-scale as a retrofit at SaskPower’s 

Boundary Dam plant in Canada. However, the costs of integrating 

a retrofit CCS system into an existing facility would be 

expected to be substantial. For example, some existing sources 

have a limited footprint and may not have the land available to 

add a CCS system. Moreover, there are a large number of existing 

fossil-fired EGUs. Accordingly, the overall costs of requiring 

CCS would be substantial and would affect the nationwide cost 

and supply of electricity on a national basis. 

For the reasons just described, based on the information 

available at this time, the EPA does not propose to find that 

CCS is a component of the best system of emission reduction for 

CO2 emissions from existing fossil fuel-fired EGUs. The EPA does 

solicit comment on all aspects of applying CCS to existing 

fossil fuel-fired EGUs, but does not expect to finalize CCS as a 

component of BSER in this rulemaking. It should be noted, 

however, that in light of the fact that several existing fossilfired EGUs are currently being retrofitted with CCS, the 
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implementation of partial CCS may be a viable GHG mitigation 

option at some facilities, and as a result, emission reductions 

achieved through use of the technology could be used to help 

meet the emission performance level required under a state plan. 

Additional discussion can be found in the Greenhouse Gas 

Abatement Measures TSD. We invite comment on this proposed 

finding. 

c. New NGCC capacity 

 In subsection 2 above, we discussed the opportunity to 

reduce CO2 emissions by replacing generation at high carbonintensity affected EGUs with generation from lower-carbon 

generation from existing NGCC units.170 From a technical 

perspective, the same potential would exist to replace highemitting generation with generation from additional NGCC 

capacity that may be built in the future; the analysis above 

regarding the feasibility of policies to increase utilization 

rates of existing NGCC units on average to 70 percent applies 

equally to new NGCC units.171 We view the opportunity to reduce 

 

170 For purposes of this proposal, NGCC units that have commenced 

construction as of January 8, 2014 are “existing” units. 

171 Whether and to what extent adding new NGCC capacity is likely 

to lead to CO2 reductions depends on what incentives would exist 

to operate that new capacity in preference to more carbon-
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CO2 emissions at affected EGUs by means of addition and operation 

of new NGCC capacity as clearly feasible. 

Compared to the opportunity to reduce CO2 emissions at 

affected EGUs by means of re-dispatch to existing NGCC capacity, 

the parallel opportunity involving new NGCC capacity could be 

somewhat more costly. Some amount of new NGCC capacity (beyond 

the units that were already under construction as of January 8, 

2014 and are “existing” units for purposes of this proposal) 

would likely be built to meet perceived electricity market 

demand or to replace less economic capacity regardless of this 

proposal. The costs of achieving CO2 emission reductions through 

re-dispatch to these new NGCC units and through re-dispatch to 

existing NGCC units would be comparable. However, in the case of 

any new NGCC units that would not have been built if not for 

this proposal, and that were built in part for the purpose of 

achieving CO2 reductions at affected EGUs, some portion of their 

construction or fixed operating costs might also be attributable 

to the CO2 reduction opportunity, increasing to some uncertain 

 

intensive existing EGUs. Because the proposed state goals also 

reflect the opportunity to reduce utilization of high carbonintensity EGUs by shifting generation to less carbon-intensive 

EGUs, we believe that in the context of a comprehensive state 

plan, the necessary incentives would likely exist, in which case 

adding new NGCC capacity would tend to reduce CO2 emissions. 
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extent the cost of the CO2 reductions at affected EGUs achieved 

through re-dispatch to those new NGCC units. 

Moreover, unlike generation from other types of potential 

new generating capacity such as wind, solar, and nuclear 

capacity, NGCC generation does produce CO2 emissions. Because of 

this distinction it is less apparent that addition of new NGCC 

capacity, as opposed to those other types of capacity, should be 

a primary building block of a strategy for reducing CO2 emissions 

from the power sector. We therefore do not propose any “best 

practices” quantities of new NGCC capacity to include in state 

goals. 

D. Potential Combinations of the Building Blocks as Components 

of the Best System of Emission Reduction

This subsection summarizes the EPA’s examination of 

combinations of the building blocks as components of the BSER, 

comparing the merits of a potential BSER that is comprised only 

of building blocks 1 and 2 with the merits of a BSER that is 

comprised of all four building blocks - the preferred option in 

this proposal. (A more detailed discussion of how we evaluated 

each option against the criteria to be considered the BSER 

follows in section VI.E.) 

1. Reasons for considering combinations of building blocks 

Comment [A47]: NGCC is a dispatchable 

technology which is a compliment to all forms of 

intermittent renewables and is part of the President’s 

all-of-the-above energy strategy. 

NGCC also has the potential to be close to zero CO2 

emissions when combined with CCS which both 

OSTP and DOE think is feasible in the next N years. 

We also believe that including new NGCC has the 

potential for reducing the costs of the rule and 

increasing net benefits as it displace older higher 

emitting less efficient NGCC. Therefore we feel 

strongly that EPA provide IPM modeling runs with 

NGCC in the BSER and take comment on including 

it in the BSER. 
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As previously described, the building blocks can be 

summarized as follows: 

Building block 1: Reducing the carbon intensity of 

generation at individual affected EGUs through heat rate 

improvements. 

Building block 2: Reducing emissions from the most carbonintensive affected EGUs in the amount that results from 

substituting generation at those EGUs with generation from 

less carbon-intensive affected EGUs (including NGCC units 

under construction). 

Building block 3: Reducing emissions from affected EGUs in 

the amount that results from substituting generation at 

those EGUs with expanded low- or zero-carbon generation. 

Building block 4: Reducing emissions from affected EGUs in 

the amount that results from the use of demand-side energy 

efficiency that reduces the amount of generation required. 

The EPA initially considered a BSER comprised of only 

strategies within building block 1. As described earlier in 

subsection VI.B, the EPA concluded that certain strategies 

within building block 1 – specifically heat rate improvements at 

individual coal-fired steam EGUs - should be a component of the 

BSER determination, as they are technically feasible and can be 
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implemented at a reasonable cost. However, the EPA further 

concluded that, while heat rate improvements qualify as a system 

of emission reduction, they are not in themselves the BSER as 

there are additional strategies that can be utilized in 

combination with building block 1 that are technically feasible, 

can be implemented at reasonable cost, and result in greater 

emission reductions than would be achieved through building 

block 1 strategies alone. The EPA is also concerned that if the 

measures that improve heat rates at coal-fired steam EGUs in 

building block 1 are implemented in isolation, without 

additional measures that reduce overall electricity demand or 

encourage substitution of less carbon-intensive generation for 

more carbon-intensive generation, the resulting increased 

efficiency of coal-fired steam units would provide incentives to 

operate those EGUs more, leading to smaller overall reductions 

in CO2 emissions. Further, in listening sessions and other 

outreach meetings, the EPA learned that states and other sources 

were already implementing and pursuing strategies in the other 

building blocks for the purpose, at least in part, of reducing 

CO2 emissions. 

2. A combination of building blocks 1 and 2 as the Best System 

of Emission Reduction 

Comment [A48]: What does this mean vis a vis 

the severability argument? Or does EPA think some 

or none, but not one? 

Comment [A49]: This makes sense but does it 

undercut the argument that the building blocks are 

severable and that BB1 would stand on its own legs 

if 2-4 are invalidated? 
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We considered a BSER that is comprised of strategies from 

building blocks 1 and 2. In this system, emission reductions at 

the most carbon-intensive individual affected EGUs would occur 

through a combination of heat rate improvements (resulting in a 

decrease in emission rates) and substitution of generation at 

less carbon-intensive affected EGUs, notably existing NGCC 

units. One reason for considering a BSER comprised of these two 

building blocks is that it involves only affected EGUs and 

generation from affected EGUs. 

The EPA believes that the combination of building blocks 1 

and 2 would be a “system of emission reduction” capable of 

achieving significant reductions in CO2 emissions from affected 

EGUs at a reasonable cost. As discussed in subsection VI.C 

above, each of the two building blocks independently would be 

capable of achieving meaningful CO2 emission reductions at 

reasonable costs. In combination, the need to achieve the level 

of emission reductions achievable through use of building block 

2 can mitigate the concern that building block 1, implemented 

alone, would make coal-fired EGUs more economically competitive 

and lead to increased generation that would offset the emission 

reduction benefits of the carbon-intensity improvements. While 

combining the building blocks may also raise the cost per ton of 
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emission reductions achieved through heat rate improvements (by 

reducing the quantity of MWh generated from the EGUs with 

improved heat rates and therefore also reducing the aggregate 

emission reductions achieved at those EGUs by the heat rate 

improvements), the costs of heat rate improvements are low 

enough that we believe their cost per ton of emission reduction 

would remain reasonable. 

Nevertheless, the EPA is not proposing that a combination 

of building blocks 1 and 2 is the BSER, because it fails to 

encompass the additionalwe have identified as already in use,

measures –in building blocks 3 and 4 – that we and stakeholders 

have identified as already in use andare capable of achieving 

even greater CO2 emission reductions from affected EGUs at 

reasonable costs. The state-specific goals that would be 

computed consistent with a BSER based on the combination of 

building blocks 1 and 2 (i.e., goals computed using the goal 

computation methodology discussed in section VII below, except 

for the omission of building blocks 3 and 4) are presented in 

the Goal Computation TSD available in the docket. Further 

information on the EPA’s evaluation of this combination is 

available in the “Analysis of Emission Reductions, Costs, 

Benefits and Economic Impacts Associated with Building Blocks 1 

Comment [A50]: Suggested edits to clarify this 
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and 2” available in the docket. We invite comment on a potential 

BSER comprised of a combination of building blocks 1 and 2. 

3. A combination of all four building blocks as the Best System 

of Emission Reduction 

Our proposal for the BSER is a combination of all four 

building blocks. As discussed in subsection VI.C above, each of 

the four building blocks is a proven way to support either 

improvements in emissions rates at affected EGUs or reductions 

in EGU mass emissions; each is in widespread use and is 

independently capable of supporting significant CO2 reductions 

from affected EGUs, either on an emission rate or mass-emissions 

basis, at a reasonable cost consistent with ensuring system 

reliability. As discussed in subsection VI.E below, the emission 

reductions achievable with the support of the combination of all 

four building blocks satisfies the legal criteria to be 

considered the BSER. Further, as discussed in section X below, 

the combination of all four building blocks can achieve greater 

overall CO2 emission reductions from affected EGUs, at a lower 

cost per unit of CO2 eliminated, than the combination of building 

blocks 1 and 2. 

In the large and highly integrated electric system, where 

electricity is fungible and the demand for electricity services 
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can be met in many ways (including through demand-side energy 

efficiency), states and the industry have long pursued a wide 

variety of strategies for ensuring that the demand for 

electricity services is met reliably, at reasonable costs, and 

in a manner consistent with evolving constraints, including 

environmental objectives. These strategies have long extended to 

the measures in all four building blocks. We believe the 

combination of all four building blocks fairly represents the 

range of measures that states and the industry will consider 

when developing state plans and strategies for reducing CO2

emissions from affected EGUs while continuing to meet demand for 

electricity services reliably and affordably. As such, we 

believe it is appropriate to consider that same combination as 

the BSER upon which the required CO2 standards of performance for 

affected EGUs should be based. 

E. Determination of the Best System of Emission Reduction 

1. Overview 

 The EPA is proposing that the measures in the four building 

blocks described in the preceding subsections are essential 

features of the “best system of emission reduction ... 

adequately demonstrated” (BSER) for the standards of performance 

that the section 111(d) state plans must apply to affected EGUs. 
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Specifically, the EPA is proposing alternative formulations for 

the BSER. Under one approach, emission rate improvements and 

mass emission reductions facilitated through the adoption of the 

four building blocks themselves meet the criteria for the BSER 

because they will amount to substantial reductions in CO2

emissions achieved while maintaining fuel diversity and a 

reliable, affordable electricity supply for the United States. 

Under an alternate approach, BSER consists of building block 1 

coupled with reduced utilization in specified amounts from 

higher-emitting EGUs. Under this latter approach, the measures 

in building blocks 2, 3, and 4 serve to justify those amounts 

and the “adequate[] demonstrat[ion]” because they are proven 

measures that are already being pursued by states and the 

industry, at least in part for the purpose of reducing CO2

emissions from affected EGUs. 

 The remainder of this discussion is organized into nine 

subsections. Subsection 2 contains a summary of relevant 

considerations for the BSER as defined in the statute and 

further interpreted in court decisions. Subsection 3 discusses 

characteristics of the electricity industry relevant to 

interpretation of the BSER for purposes of this proposal, most 

notably the industry’s highly interconnected and integrated 
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nature. Subsection 4 provides a discussion of how the building 

blocks would satisfy the BSER criteria in isolation or support 

the alternative formulation of the BSER as including reduced 

utilization in specified amounts. Subsection 5 evaluates two 

combinations of building blocks – a combination of building 

blocks 1 and 2, and the proposed combination of all four 

building blocks – against the BSER criteria, and explains why we 

propose that the combination of all four is the BSER. In 

subsection 6, we describe and seek comment on the alternate 

interpretation that the BSER includes, in addition to one or 

more of the building blocks, a component consisting of reduced 

generation from affected EGUs, with the measures in the other 

building blocks serving as the basis for quantifying the amounts 

of generation reductions and consequent CO2 emission reductions 

that can be achieved while continuing to meet the demand for 

electricity services in a reliable and affordable manner. In 

subsection 7 we discuss the discretion that the case law gives 

us in weighing the various criteria to determine the BSER. The 

final three subsections address the topics of combining source 

categories, severability, and certain other specific issues on 

which we are seeking comment. Additional discussion is provided 

in the Legal Memorandum available in the docket. 
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2. Statutory and regulatory provisions related to determination 

and application of the BSER 

 The EPA’s explanation for this BSER proposal begins with 

the statutory definition of a “standard of performance”: 

The term “standard of performance” means a standard for 

emissions of air pollutants which reflects the degree of 

emission limitation achievable through the application of 

the best system of emission reduction which (taking into 

account the cost of achieving such reduction and any nonair 

quality health and environmental impact and energy 

requirements) the Administrator determines has been 

adequately demonstrated. 

42 U.S.C. 7411(a)(1). 

The U.S. Court of Appeals for the D.C. Circuit (D.C. 

Circuit or Court) has handed down case law over a 40-year period 

that interprets this CAA provision, including its component 

elements.172 Under this case law, the EPA determines the BSER 

based on the following key considerations, among others: 

 

172 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, (D.C. 

Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 

1981); Portland Cement Ass’n v. EPA, 665 F.3d 177 (D.C. Cir. 

2011). 
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 The system of emission reduction must be technically 

feasible. 

 The EPA must consider the amount of emission reductions 

that the system would generate. 

 The costs of the system must be reasonable. The EPA may 

consider costs at the source level, the industry level, 

and, at least in the case of the power sector, the national 

level in terms of the overall costs of electricity and the 

impact on the national economy over time.173 

 The EPA must also consider that CAA section 111 is designed 

to promote the development and implementation of 

technology. 

Another consideration particularly relevant to this 

rulemaking is energy impacts, which, as with costs, EPA may 

 

173 As discussed in the January 2014 Proposal, the D.C. Circuit’s 

case law formulates the cost consideration in various ways: the 

costs must not be “exorbitant[]”, Essex Chemical Corp. v. 

Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), see Lignite 

Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999); 

“greater than the industry could bear and survive,” Portland 

Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975); or 

“excessive” or “unreasonable,” Sierra Club v. Costle, 657 F.2d 

298, 343 (D.C. Cir. 1981). In the January 2014 Proposal, the EPA 

stated that “these various formulations of the cost standard ... 

are synonymous,” and, for convenience, we used “reasonableness” 

as the formulation. We take the same approach in this 

rulemaking. 
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consider at the source level, the industry level, and the 

national level over time. In the context of the electricity 

industry and this proposal, EPA believes that the scope of 

energy impacts that may be considered encompasses assurance of 

the continued ability of the industry to meet the evolving 

demand for electricity services in a reliable manner. 

Importantly, the EPA has discretion to weigh these various 

considerations, may determine that some merit greater weight 

than others, and may vary the weighting depending on the source 

category. 

The EPA discussed the CAA requirements and Court 

interpretations of the BSER at length in the January 2014 

Proposal, 79 FR at 1,462/1 – 1,467/3, and incorporates by 

reference that discussion in this rulemaking. 

 3. The interconnected nature of the U.S. electricity 

sector 

The U.S. electricity system is a highly interconnected, 

integrated system in which large numbers of EGUs using diverse 

fuels and generating technologies are operated in a coordinated 

manner to produce fungible electricity services for customers. 

Because electricity is costly to store, the amounts of 

electricity demanded and supplied must be continuously matched, 

Comment [A51]: Suggest instead: Because 

electricity storage has not been widely deployed... 
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and system operators typically have flexibility to choose among 

multiple EGUs when selecting where to obtain the next MWh of 

generation needed. Coordination over short- and long-term time 

scales is accomplished through a variety of institutions 

including vertically integrated utilities, state regulatory 

agencies, independent system operators and regional transmission 

organizations (ISO/RTOs), and market mechanisms. The electricity 

sector is both critical to the nation’s economy and the source 

of more than 30 percent of U.S. greenhouse gas emissions, 

predominantly in the form of CO2. 

The integrated electricity system allows increased 

generation from less carbon-intensive NGCC units to substitute 

for generation from more carbon-intensive steam EGUs (building 

block 2), thereby lowering CO2 emissions from the group of 

affected EGUs as a whole. The electricity system similarly 

allows increased generation resulting from expansion of the 

amount of available low- or zero-carbon generating capacity 

connected to the electric grid (building block 3), as well as 

avoided generation resulting from reductions in electricity 

demand (building block 4), to substitute for fossil fuel-fired 

generation, thereby reducing CO2 emissions from affected EGUs. 

Each of these measures already routinely occurs within this 
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integrated system for providing electricity and electricity 

services. 

The integrated nature of the electricity system has long 

played a central role in the industry’s continuing efforts to 

assure reliability and to manage costs generally. Specifically 

in the area of pollution control, state governments and the 

federal government have repeatedly taken advantage of the 

integrated nature of the electricity system when designing 

programs to allow the industry to meet the pollution control 

objectives in a least-cost manner. Examples include several capand-trade programs to reduce national or regional emissions of 

SO2 and NOx: the SO2–related portion of the CAA Title IV Acid 

Rain Program, the Ozone Transport Commission (OTC) NOx Budget 

Program, the NOx SIP Call NOx Budget Trading Program, and the 

Clean Air Interstate Rule (CAIR) annual SO2, annual NOx, and 

ozone-season NOx trading programs. While the Acid Rain Program 

was created by federal legislation, the OTC NOx Budget Program 

was developed primarily through the joint efforts of a group of 

northeastern states. In the NOx SIP Call and CAIR programs, the 

federal government set emission budgets and developed trading 
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programs that states could use as a compliance option.174 Each of 

these programs was designed to take advantage of the fact that 

in an integrated electricity system, some EGUs can reduce 

emissions more cost-effectively than others, and that by 

allowing the industry to determine through market mechanisms 

which EGUs to control, and potentially operate more, and which 

to leave uncontrolled, and potentially operate less, overall 

compliance costs can be reduced. The integrated electricity 

system plays the important function of allowingallows some EGUs 

to reduce their generation while ensuring that overall 

electricity demand can be reliably met. It is worth noting that 

adoption by affected EGUs of any of the measures in the building 

blocks could be (or could have been) used to facilitate 

compliance with each of the programs just described. 

Some states are already relying on the integrated nature of 

the electricity system to establish the policy contexts within 

which affected EGUs will reduce their CO2 emissions.175 California 

 

174 In the Regional Greenhouse Gas Initiative, described in more 

detail below, participating states use emission budgets and a 

trading program to address CO2 emissions from the electricity 

sector. 

175 A number of utilities also have climate mitigation plans. 

Examples include National Grid, 

http://www2.nationalgrid.com/responsibility/how-were-doing/gridComment [A52]: Suggested edit, since units 

have differences in emissions regardless of control, 

and you don’t have to limit the example to those 

cases only. 

Comment [A53]: Can you add a parenthetical 

(e.g. CAIR, NOx SIP Call, Acid Rain) 
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and Colorado provide two examples of how statewide targets (or 

company-wide targets within a state) can be designed with 

consideration of the wide range of CO2 mitigation options and 

affected EGUs’ flexibility to use those options. 

California enacted its Global Warming Solutions Act (also 

known as AB32) in 2006, requiring the state to reduce its GHG 

emissions to 1990 levels by 2020 and 80 percent below 1990 

levels by 2050.176 According to California, “the integrated 

nature of the grid means that policies which displace the need 

for fossil generation can often cut emissions from covered 

sources more deeply, and more cost-effectively, than can 

engineering changes at the plants alone, though these source-

 

data-centre/climate-change/; Exelon, 

http://www.exeloncorp.com/newsroom/pr_20140423_EXC_Exelon2020.as

px; PG&E, http://www.pge.com/about/environment/pge/climate/; and 

Austin Energy, 

http://austinenergy.com/wps/portal/ae/about/environment/austinclimate-protectionplan/!ut/p/a0/04_Sj9CPykssy0xPLMnMz0vMAfGjzOINjCyMPJwNjDzdzY0sDB

zdnZ28TcP8DAMMDPQLsh0VAU4fG7s!/. 

176 State of California Global Warming Solutions Act of 2006, 

Assembly Bill 32, Chapter http://www.leginfo.ca.gov/pub/05-

06/bill/asm/ab_0001-

0050/ab_32_bill_20060927_chaptered.pdfhttp://www.leginfo.ca.gov/

pub/05-06/bill/asm/ab_0001-

0050/ab_32_bill_20060927_chaptered.pdf. 
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level control efforts are a vital starting point.”177 California 

therefore relied on a suite of mechanisms to provide fossil 

fuel-fired generation substitutes and incentives for EGUs to 

reduce their emissions, including demand-side energy efficiency 

programs, renewable energy programs, and an economy-wide capand-trade program, along with other programs.178 The California 

plan has put in place mechanisms that through market dynamics 

affect both companies’ longer-term planning decisions and their 

short-term dispatch decisions. The need to hold emissions 

allowances and the reduced demand from demand-side energy 

efficiency programs impact longer-term decisions companies make 

about investment in both existing and new EGUs. The price of 

emission allowances also impacts hourly dispatch decisions; 

where emission allowance requirements are in effect, EGU owners 

routinely recognize the costs of emission allowances as 

components of the variable operating costs that are relied on 

 

177 December 27, 2013 Letter from Mary D. Nichols, Chairman of 

California Air Resources Board, to EPA Administrator Gina 

McCarthy. 

178 See Cal. Air Res. Bd., Climate Change Scoping Plan 31-32, 41-

46 (2008), available at 

http://www.arb.ca.gov/cc/scopingplan/document/adopted_scoping_pl

an.pdf. 
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for these decisions.179 In this manner, allowance prices 

constitute market signals encouraging reduced use of higheremitting EGUs and increased use of lower-emitting EGUs. 

The Colorado Clean Air Clean Jobs Act (CACJA), signed into 

law on April 19, 2010, required each investor-owned utility with 

coal-fired EGUs to submit to the state a multi-pollutant plan 

for meeting current and foreseeable EPA standards for emissions 

of NOx, SO2, particulates, mercury, and CO2. Rather than fully 

prescribing specific control technologies, the law provided 

flexibility for each utility to select the best set of measures 

to achieve the emission reductions.180 For example, a utility 

could choose to retrofit or repower EGUs, or it could choose to 

retire higher-emitting EGUs and replace them with NGCC units and 

other low- or non-emitting energy plants or with end-use 

efficiency measures.181 The Colorado plan generally focused more 

on impacting companies’ longer-term planning decisions than on 

 

179 The requirement to hold allowances covering their CO2

emissions went into effect for EGUs in California on January 1, 

2013. 

180 The law also set some explicit requirements, such as 

requirements for development of new renewable generating 

capacity and requirements to phase out older coal-fired EGUs. 

181 See State of Colorado House Bill 10-1365, available at 

http://www.leg.state.co.us/clics/clics2010a/csl.nsf/fsbillcont/0

CA296732C8CEF4D872576E400641B74?Open&file=1365_ren.pdf. 
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affecting short-term dispatch decisions. In response, Colorado 

utilities have adopted a mix of measures including retrofits, 

natural gas conversions and retirements of coal-fired EGUs, as 

well as construction of new NGCC units. 

Regional mechanisms with analogous impacts on both longerterm planning decisions and short-term dispatch decisions have 

also been put in place. For example, nine northeastern and MidAtlantic States182 participate in the Regional Greenhouse Gas 

Initiative (RGGI), a market-based emissions budget trading 

program that sets an aggregate limit on CO2 emissions from fossil 

fuel-fired EGUs in the participating states. To comply with the 

program, each EGU must acquire allowances equal to its emissions 

in each compliance period - through purchases or by allocation 

from the state – and must surrender the allowances at the end of 

the period. The RGGI program offers flexibility to regulated 

parties through provisions for multi-year compliance periods, 

allowance banking, offsets, an auction reserve price, and a 

cost-containment reserve of allowances, and further encourages 

emission allowance market development by authorizing trading 

 

182 Participating states include Connecticut, Delaware, Maine, 

Maryland, Massachusetts, New Hampshire, New York, Rhode Island, 

and Vermont. 
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between regulated and non-regulated parties.183 Operating in this 

regime, EGUs take a variety of compliance actions, including 

replacing generation at higher-emitting EGUs with generation at 

lower-emitting EGUs or achieving emissions reductions at EGUs by 

means of end-use energy efficiency programs. 

An approach to determination of the BSER that recognizes 

the integrated nature of the electric system is also consistent 

with the way in which the electricity industry already addresses 

resource planning issues. For example, in states where the price 

of EGUs’ generation remains subject to regulation, utilities 

generally prepare integrated resource plans setting forth their 

strategies for meeting future electricity demand in a costeffective manner. These plans may include measures from building 

blocks 2, 3, and 4. In most states where generation is no longer 

subject to price regulation, regional transmission organizations 

(RTOs) or independent system operators (ISOs) ensure the 

adequacy of future generation supplies by administering auctions 

for forward capacity. In these auctions, owners of existing EGUs 

(with consideration of building blocks 1 and 2),184 developers of 

 

183 See RGGI website at http://www.rggi.org/rggi. 184 Potential heat rate improvements create opportunities for EGU 

owners to reduce their variable costs, which increase potential 
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new EGUs including renewable generating capacity (building block 

3), and developers of demand-side resources (building block 4) 

all compete to provide potential resources for meeting the 

projected demand for electricity services. 

As indicated by the foregoing discussion, in the U.S. 

electricity system the demand for electricity services is met, 

on both a short-term and longer-term basis and in both regulated 

and deregulated contexts, through integrated consideration of a 

wide variety of possible options, coordinated by some 

combination of utilities, regulators, system operators, and 

market mechanisms. The EPA believes that the BSER for CO2

emissions from existing EGUs should reflect this integrated 

character. 

Importantly, experience has shown that because the grid is 

interconnected, CO2 emissions reductions can be achieved through 

several different mechanisms, which differ primarily in their 

timing and in the extent of their advance planning: (i) 

Establishing and implementing a plan in advance under which a 

specific amount of generation from higher-emitting fossil fuel-

 

operating profits from generation and thereby create 

opportunities to lower the prices at which the owners would bid 

the capacity of their EGUs into the auctions. 
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fired EGUs is substituted for the same amount of generation 

from, or avoided from, specific measures in building blocks 2, 

3, and 4. (ii) Instituting measures in building blocks 2, 3, and 

4, which, because of the interconnected nature of the grid, 

result in drawing utilization away from higher-emitting fossil 

fuel-fired EGUs, even in the absence of a plan in advance that 

targets those EGUs. (iii) Reducing utilization from higheremitting fossil fuel-fired EGUs, which because of the 

interconnected nature of the grid and its operation in the 

regulated markets, leads to the measures in building blocks 2, 

3, and 4 that develop or utilize replacement generation or 

demand-side energy efficiency, even in the absence of a plan in 

advance that includes those measures. The existence of these 

mechanisms supports what we propose in this rulemaking as the 

two alternative “best system[s] of emission reduction ... 

adequately demonstrated,” as discussed below. 

4. Evaluation of individual building blocks against the BSER 

criteria 

In this section we explain why (i) the individual building 

blocks meet the criteria to qualify as components of the “best 

system of emission reduction ... adequately demonstrated” and 

(ii) why, under the alternative formulation of BSER as including 

Comment [A54]: How are (ii) and (iii) different? 
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reduced utilization of higher-emitting generating capacity in 

specified amounts, building blocks 2, 3, and 4 serve as the 

basis for those amounts and why the reduced utilization is 

“adequately demonstrated.” 

a. Building block 1 – heat rate improvements 

Building block 1 - reducing the carbon intensity of 

generation at individual affected coal-fired steam EGUs through 

heat rate improvements - is a component of the BSER because the 

measures the affected sources may undertake to achieve heat rate 

improvements are technically feasible and of reasonable cost, 

and meet the other requirements to qualify as a component of the 

BSER. 

The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of CO2 emission reductions 

achievable through heat rate improvements are discussed in 

section VI.C.1 above. We consider heat rate improvement to be a 

common and well-established practice within the industry. 

 Other BSER criteria also favor building block 1 as a 

component of BSER. For example, with respect to non-air health 

and environmental impacts, heat rate improvements cause fuel to 

be used more efficiently, reducing the volumes of and therefore 

the adverse impacts associated with disposal of coal combustion 
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waste products. With respect to technological innovation, 

building block 1 encourages the spread of more advanced 

technology to EGUs currently using components with older 

designs. The EPA has not considered whether enhanced maintenance 

practices leading to heat rate improvements might also lead to 

electric reliability improvements, but does not expect there 

would be any negative impact on reliability. 

 As noted above, the EPA is concerned about the potential 

“rebound effect” associated with building block 1 if applied in 

isolation. More specifically, we noted that in the context of 

the integrated electricity system, absent other incentives to 

reduce generation and CO2 emissions from coal-fired EGUs, heat 

rate improvements and consequent variable cost reductions at 

those EGUs would cause them to become more competitive compared 

to other EGUs and increase their generation, leading to smaller 

overall reductions in CO2 emissions (depending on the CO2

emission rates of the displaced generating capacity). However, 

we believe that this concern can be readily addressed by 

ensuring that the BSER also reflects other CO2 reduction 

strategies that discourage overall increases in coal-fired 

generation or fossil fuel-fired generation, thereby allowing 
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building block 1 to be considered part of the BSER for CO2

emissions at affected EGUs. 

b. Building block 2 – re-dispatch 

Building block 2 – reducing CO2 emissions at, and 

substituting for, generation from the most carbon-intensive 

affected EGUs with generation from less carbon-intensive 

affected EGUs (including NGCC units under construction) – is a 

component of the BSER because the shifts in generation that it 

involves demonstrate that reducing mass CO2 emissions at higheremitting EGUs is technically feasible, will not jeopardize 

system reliability, is of reasonable cost, and meets the other 

requirements for a component of the BSER. 

The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of CO2 emission reductions 

achievable at high-emitting EGUs through re-dispatch among 

affected EGUs are discussed in section VI.C.2 above. We consider 

re-dispatch among the large number of diverse EGUs that are 

linked to one another and to customers by extensive regional 

transmission grids to be a routine and well-established 

operating practice within the industry that is used to 

facilitate the achievement of a wide variety of objectives, 

including environmental objectives, while meeting the demand for 
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electricity services. As discussed above, in the interconnected 

and integrated electricity industry, fossil fuel-fired steam 

EGUs are able to reduce their generation and NGCC units are able 

to increase their generation in a coordinated manner through 

mechanisms – in some cases centralized and in others not - that 

regularly deal with such changes on both a short-term and a 

longer-term basis. There ishas been a long-term trend in the 

industry trend away from coal-fired generation and toward NGCC 

generation, largely because of relative fuel costs. States can 

encourage this trend in a variety of ways. First, a state could 

use its permitting authority to impose limits on the hours of 

operation (or emissions) of individual steam generating units 

over a given time period. Second, a state could change the 

relative costs of generation for more carbon-intensive and less 

carbon-intensive generating units by imposing a cost on carbon 

emissions. A state could do so through any of several marketbased mechanisms. One would be to adopt an allowance-based 

system. An example is the Regional Greenhouse Gas Initiative, an 

allowance-based system in which sources purchase allowances in 

periodic auctions. Another way would be through a tradable 

emission rate system, under which the state would impose an 

emission rate limit on the steam generating unit that the unit 
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could meet only by purchasing the right to average its emission 

rate with a unit with a lower rate, such as an NGCC unit. Most 

broadly, an allowance system would provide the greatest 

incentive for the most carbon-intensive affected sources to 

reduce emissions as much as possible so as to reduce their need 

to purchase allowances (or to allow them to sell un-needed 

allowances), and the same would be true for a tradable emission 

rate system. 

The emission reductions achievable or supported by the 

application of building block 2 also perform well against other 

BSER criteria. For example, we expect that building block 2 

would have positive non-air health and environmental impacts. 

Coal combustion for electricity generation produces large 

volumes of solid wastes that require disposal, with some 

potential for adverse environmental impacts; these wastes are 

not produced by natural gas combustion. The intake and discharge 

of water for cooling at many EGUs also carries some potential 

for adverse environmental impacts; NGCC units generally require 

less cooling water than steam EGUs.185 As already noted, with 

respect to energy impacts, the EPA believes that building block 

 

185 Some NGCC units use air rather than water for cooling 

purposes. 

Comment [A55]: How many? How well 

substantiated? 
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2 (at least at the level of stringency proposed for purposes of 

establishing state goals) would not pose risks to reliability. 

Building block 2 also promotes greater use of the advanced NGCC 

technology installed in the existing fleet of NGCC units. 

It should be observed that, by the building block’s 

definition, the shifts in generation taking place under building 

block 2 occur entirely among existing EGUs subject to this 

rulemaking.186 Through application of this building block 

considered in isolation, some affected sources – mostly coalfired steam EGUs - would reduce their generation and CO2

emissions, while other affected sources – NGCC units – would 

increase their generation and CO2 emissions.187 However, because 

for each MWh of generation, NGCC units produce less CO2 emissions 

than coal-fired steam EGUs, the total quantity of CO2 emissions 

from all affected sources in aggregate would decrease. In the 

context of the integrated electricity system, where the 

 

186 For purposes of this rulemaking, “existing” EGUs include 

units under construction as of January 8, 2014, the date of 

publication in the Federal Register of the Carbon Pollution 

Standards for new fossil fuel-fired EGUs. 

187 Because building blocks 3 and 4 reduce generation and CO2

emissions from all fossil fuel-fired affected EGUs as a group, 

including NGCC units, the increase in generation and CO2

emissions from NGCC units under building block 2 is mitigated to 

some extent by including those building blocks in the BSER along 

with building block 2. 
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operation of affected EGUs of multiple types is routinely 

coordinated to provide a fungible service, and in the context of 

CO2 emissions, where location is a less important factor than is 

the case for other pollutants, the EPA believes that a measure 

that takes advantage of that integration to reduce CO2 emissions 

from the overall set of affected EGUs is readily encompassed 

within the meaning of a “system of emission reduction” for CO2

emissions at affected EGUs even if the measure would increase CO2

emissions from a subset of those affected EGUs. Emission trading 

or averaging approaches can facilitate the implementation of 

such a “system” and have already been used in the electricity 

industry to address CO2 as well as other pollutants, as discussed 

above. 

Finally, the EPA notes that the alternative interpretation 

of the BSER discussed later is based in part on the re-dispatch 

measures in building block 2. In this alternative, reduced 

generation from fossil fuel-fired steam EGUs is a component of 

the BSER. The potential to use increased generation from less 

carbon-intensive NGCC units would serve as a basis for 

quantifying the amounts of generation reductions and CO2 emission 

reductions at more carbon-intensive EGUs that could be achieved 

while continuing to meet the demand for electricity services in 
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a reliable and affordable manner. This alternative is discussed 

further in section VI.E.6 below. 

c. Building block 3 – use of expanded low- and zero-carbon 

generating capacity 

 Building block 3 – reducing CO2 emissions at and 

substituting for generation from affected EGUs by using expanded 

amounts of low- and zero-carbon generating capacity – is a 

component of the BSER because the expansion and use of renewable 

generating capacity, completion and use of new nuclear capacity, 

and avoidance of nuclear capacity retirements all establish the 

foundation for a determination that mass emission reductions 

from affected EGUs are technically feasible, do not jeopardize 

system reliability, are of reasonable cost, and meet the other 

requirements for a component of the BSER. 

The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of the measures in building 

block 3 are discussed in section VI.C.3 above. We consider all 

of these measures to be proven, well-established practices 

within the industry, and development of renewable capacity in 

particular is consistent with recent industry trends. States can 

and do establish targets for procurement of renewable generating 

capacity. Moreover, a market for renewable energy certificates, 
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which facilitates investment in renewable energy, is already 

well-established. In addition, as noted above with re-dispatch, 

an allowance system or tradable emission rate system would 

provide incentives for sources to reduce their emissions as much 

as possible, including by substituting for their generation with 

generation from renewable energy. In addition, owners of 

existing nuclear units and new nuclear units under construction 

can take action to complete or preserve that capacity, the 

generation from which likewise can be dispatched in a 

coordinated manner to substitute for fossil fuel-fired 

generation. As discussed above, coordination of these decisions 

in the integrated electricity system can occur through a variety 

of mechanisms, some centralized and some not. 

 The renewable capacity measures in building block 3 

generally perform well against other BSER criteria. For example, 

incentives for expansion of renewable capacity encourage 

technological innovation in improved renewable technologies as 

well as more extensive deployment of current advanced 

technologies. Generation from wind turbines (the most common 

renewable technology) does not produce solid waste or require 

cooling water, a better environmental outcome than if that 

amount of generation had instead been produced at a typical 
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range of fossil fuel-fired EGUs. Although the intermittent 

nature of generation from renewable resources such as wind and 

solar units requires special consideration from grid operators, 

as discussed above renewable generation has grown quickly in 

recent years, and the EPA has seen no evidence that operators 

will be less able to cope with future growth than they have with 

rapid past growth. Further, if a state were concerned that 

increasing the use of NGCC capacity might create risks to 

reliability in the form of potential inadequacies in natural gas 

infrastructure, use of expanded renewable generation capacity 

could help address that concern. 

The EPA believes that the performance of the nuclear 

measures in building block 3 against the other BSER measures is 

acceptable. With respect to encouragement of technological 

innovation, incentives for completion of new nuclear capacity 

encourage deployment of nuclear unit designs that reflect 

advances over earlier designs. The nation’s nuclear fleet today 

routinely operates at high average utilization rates, suggesting 

no reason to expect adverse reliability consequences from 

completion or preservation of additional nuclear capacity. Use 

of expanded nuclear capacity would be another way for a state to 

address any concern that increasing the use of NGCC capacity 
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might create risks to reliability in the form of potential 

inadequacies in natural gas infrastructure. New nuclear units 

would have closed-cycle cooling systems with lower cooling water 

usage than some existing fossil fuel-fired EGUs; existing 

nuclear units may use amounts of cooling water comparable to the 

amounts used by those fossil fuel-fired steam EGUs. The EPA 

recognizes that nuclear generation poses unique waste disposal 

issues (although it avoids the solid waste issues specific to 

coal-fired generation). However, we do not consider that 

potential disadvantage of nuclear generation relative to fossil 

fuel-fired generation as outweighing nuclear generation’s other 

advantages as an element of building block 3. For all these 

reasons, we consider building block 3 to be a component of the 

“best system of emission reduction ... adequately demonstrated.” 

Finally, the EPA notes that under alternative BSER 

discussed later would include a component consisting of reduced 

generation from affected EGUs, with the measures in building 

block 3 serving as a basis for quantifying the amount of reduced 

generation and consequent CO2 emission reductions. Because of 

the availability of those measures, the amount of reduced 

generation can be achieved while continuing to meet the demand 

Comment [A56]: Can EPA please explain the 

basis for this statement? 
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for electricity services in a reliable and affordable manner. 

This alternative BSER is discussed in section VI.E.6 below. 

d. Building block 4 – increased demand-side energy 

efficiency 

Building block 4 – reducing CO2 emissions at and reducing 

generation from affected EGUs by promoting demand-side energy 

efficiency that reduces the amount of generation required from 

affected EGUs – is a component of the BSER because the demandside energy efficiency is technically feasible and of reasonable 

cost, and meets the other requirements for a component of the 

BSER. 

The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of the building block 4 are 

discussed in section VI.C.4 above. We consider demand-side 

energy efficiency programs to be proven, well-established 

practices within the industry that are consistent with industry 

trends. States can and do authorize or require implementation of 

demand-side energy efficiency programs. Fossil fuel-fired EGUs 

can reduce their generation. Owners of affected EGUs as well as 

other parties can contract for demand-side energy efficiency. As 

discussed above, coordination of these decisions in the 

integrated electricity system can occur through a variety of 
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mechanisms, some centralized and some not. For example, an 

allowance system or tradable emission rate system would provide 

incentives that promote the measures in building block 4 in the 

same manner as discussed above for other building blocks. 

 Building block 4 is also very attractive under other BSER 

criteria. Demand-side energy efficiency avoids the non-air 

health and environmental effects of the fossil fuel-fired 

generation for which it substitutes. Further, by reducing the 

overall amount of electricity that needs to be transmitted 

between EGUs and customers, demand-side energy efficiency tends 

to relieve stress on the grid, thereby increasing system 

reliability. Creating incentives for additional demand-side 

energy efficiency is also consistent with the goals of 

encouraging technological innovation in energy efficiency and 

encouraging deployment of current advanced technologies. For all 

these reasons, the measures in building block 4 qualify as a 

component of the “best system of emission reduction ... 

adequately demonstrated.” 

The EPA notes that the alternative BSER discussed later 

would include a component consisting of reduced generation from 

affected EGUs, with demand-side energy efficiency serving as a 

basis for quantifying the amounts of generation reductions and 
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consequent CO2 emission reductions that can be achieved while 

continuing to meet the demand for electricity services in a 

reliable and affordable manner. This alternate interpretation of 

the BSER is discussed in section VI.E.6 below. 

5. Evaluation of building block combinations against the BSER 

criteria 

a. Combination of building blocks 1 and 2 

 The EPA has considered whether a combination of building 

blocks 1 and 2 would be the BSER. As described in section VI.D 

above, we believe that such a combination is technically 

feasible and would be a “system of emission reduction” capable 

of achieving meaningful reductions in CO2 emissions from affected 

EGUs at a reasonable cost. The combination would also satisfy 

other BSER criteria. Nevertheless, we do not propose that this 

combination should be the BSER because the proposed combination 

of all four building blocks is capable of achieving greater 

reductions in CO2 emissions from affected EGUs at a lower cost. 

 The EPA believes that both building blocks 1 and 2 

individually satisfy the BSER criteria identified by the statute 

and the D.C. Circuit, with one possible concern noted earlier. 

That concern is the potential for the heat rate improvements in 

building block 1, if implemented in isolation, to make coal-
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fired steam EGUs more competitive compared to other EGUs and 

cause them to increase their generation, creating a “rebound 

effect” that would make building block 1 less effective at 

reducing CO2 emissions. As discussed above, building blocks 1 and 

2 each appear attractive or neutral with respect to each of the 

other BSER criteria. 

With respect to most of the BSER criteria, there is no 

reason to expect that the combination of building blocks 1 and 2 

would be evaluated differently than the individual building 

blocks. However, as noted earlier, the combination addresses the 

concern about building block 1 regarding a potential rebound 

effect, and in that important respect it performs better than 

building block 1 considered in isolation. The substitution of 

NGCC generation for generation from coal-fired and other steam 

EGUs ensures that generation from coal-fired EGUs, as a group, 

would not increase as a result of their improved variable costs, 

with the result that the reduction in CO2 emission rates of coalfired EGUs brought about by heat rate improvements would on 

average be accompanied by a reduction in CO2 emissions from those 

EGUs. The combination of building blocks would therefore be 

capable of achieving greater reductions in CO2 emissions from 

affected sources than either building block in isolation. 
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By reducing overall generation from coal-fired EGUs, the 

combination of building blocks 1 and 2 also has the potential to 

raise the cost of emission reductions achievable through heat 

rate improvements relative to the cost if building block 1 were 

implemented in isolation.188 However, the EPA believes that the 

cost of emission reductions achieved through heat rate 

improvements would remain reasonable for two reasons. First, as 

discussed in section VI.C.1 above, the cost of CO2 emission 

reductions achievable through heat rate improvements is quite 

low, and that cost would remain reasonable even if substantially 

increased. Second, although under the combination of building 

blocks 1 and 2 the volume of coal-fired generation would 

decrease, that decrease is unlikely to be spread uniformly among 

all coal-fired EGUs. It is more likely that some coal-fired EGUs 

would decrease their generation slightly while others would 

decrease their generation by larger percentages or cease 

operations altogether. Some coal-fired EGUs could increase their 

 

188 If an EGU produces less generation output, then an 

improvement in that EGU’s heat rate and rate of CO2 emissions per 

unit of generation produces a smaller reduction in CO2 emissions. 

If the investment required to achieve the improvement in heat 

rate and emission rate is the same regardless of the EGU’s 

generation output, then the cost per unit of CO2 emission 

reduction will be higher when the EGU’s generation output is 

lower. 
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generation. We would expect EGU owners to take these changes in 

EGU operating patterns into account when considering where to 

invest in heat rate improvements, with the result that there 

would be a tendency for such investments to be concentrated in 

EGUs whose generation output was expected to decrease the least 

(or to increase). This enlightened bias in spending on heat rate 

improvements would tend to mitigate any deterioration in the 

cost of CO2 emission reductions achievable through heat rate 

improvements. 

As noted above, the EPA invites comment on a potential BSER 

comprised of building blocks 1 and 2, in light of the 

considerations that could support this approach. 

b. Combination of all four building blocks 

 The EPA’s proposed BSER is a combination of all four 

building blocks. For the reasons described below, and like each 

of the building blocks, the combination must be considered a 

“system of emission reduction.” Moreover, as also discussed 

below, the combination qualifies as the “best” system that is 

“adequately demonstrated.” The combination is technically 

feasible; it is capable of achieving meaningful reductions in CO2

emissions from affected EGUs at a reasonable cost; it satisfies 

the other BSER criteria as well; and it is well-established. 

Comment [A57]: What does EPA mean? 
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Further, because the combination of all four building blocks 

would achieve greater CO2 emission reductions at a lower cost 

than the combination of building blocks 1 and 2 described above, 

and would also perform better against other BSER criteria, we 

propose to find the combination of all four building blocks to 

be the “best system of emission reduction ... adequately 

demonstrated” for reducing CO emissions at affected EGUs.189 

 Because the measures in building blocks 2, 3, and 4 involve 

the interconnected electricity grid, evaluating them against the 

criteria for the BSER involves certain considerations. The EPA 

discusses these in the Legal Memorandum, and summarizes them 

briefly below. 

The EPA’s proposal that the “system of emission reduction” 

includes the measures in building blocks 2, 3, and 4 is grounded 

in the EPA’s interpretation of the key CAA provisions: section 

111(d)(1), which requires that each state’s plan “establish[] 

standards of performance for any existing source” for certain 

types of air pollutants; and section 111(a)(1), which defines a 

 

189 The analysis of the interactions among building blocks 

provided above for the combination of building blocks 1 and 2 

applies to the combination of all four building blocks as well. 

The EPA believes that in combination, each of the four building 

blocks would achieve substantial reductions in CO2 emissions from 

affected EGUs at a reasonable cost. 
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“standard of performance” as “a standard for emissions ...which 

reflects the degree of emission limitation achievable through 

the application of the best system of emission reduction ... 

adequately demonstrated.” These provisions require that, in this 

rulemaking, the affected sources must be subject to emissions 

standards, but the basis for those standards – the “system of 

emission reduction” – may be any system that reduces the 

affected sources’ emissions. As discussed in the Legal 

Memorandum, the EPA is justified in adopting this interpretation 

under the first step of the framework for administrative 

agencies to construe statutes that the U.S. Supreme Court 

established in Chevron U.S.A. Inc. v NRDC, 467 U.S. 837, 842-844 

(1984) (Chevron), which we refer to as Chevron step 1. 

Specifically, the term “system,” which is not defined in 

the CAA, is broad: “a set of things working together as parts of 

a mechanism or interconnecting network.”190 The remaining 

provisions of the definition of “standard of performance” do not 

include any constraints on the “set of things” that may 

constitute a “system of emission reduction.” Nor does the 

 

190 Oxford Dictionary of English (3rd ed.) (published 2010, 

online version 2013), 

http://www.oxfordreference.com.mutex.gmu.edu/view/10.1093/acref/

9780199571123.001.0001/acref-9780199571123. 
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context in which “standard of performance” is found – the 

provisions of section 111(d)(1) – add constraints on the things 

that may constitute such a system. Rather, it is clear from 

these CAA provisions that anything that reduces the emissions of 

affected sources may be considered a “system of emission 

reduction” for those sources. For this reason, the measures in 

building blocks 2, 3, and 4 must be considered components of 

such a system. 

 Even if these CAA provisions leave room for interpretation 

as to whether those measures must be considered components of 

such a system, the EPA’s interpretation that they do is 

reasonable. As discussed in the Legal Memorandum, the EPA is 

justified in adopting this interpretation under the second step 

of the Chevron framework, which we refer to as Chevron step 2. 

There are several reasons. In enacting the CAA, Congress 

established “pollution prevention” as a “primary goal” of the 

Act, and described it as “the reduction or elimination, through 

any measures, of the amount of pollutants produced or created at 

the source.”191 Building blocks 2, 3, and 4 are pollution 

prevention measures, and, in light of the importance of 

 

191 CAA §101(a)(3), (c). 
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pollution prevention in the CAA, it is reasonable to interpret 

“system of emission reduction” in section 111 to incorporate 

those measures. In addition, the breadth of “system of emission 

reduction” is confirmed by contrasting it with other provisions 

in the CAA that prescribe specific types of controls as the 

basis for emission limits.192 Further support is found in Title 

IV of the CAA, in which Congress established the program that 

regulates fossil fuel-fired power plants to reduce their 

emissions of SO2 and NOx, the precursors to acid deposition. In 

designing Title IV, Congress recognized the integrated nature of 

the electricity sector and how that integration could be 

harnessed to reduce air pollutant emissions; and, in fact, 

Congress included provisions to encourage re-dispatch to loweremitting sources, renewable energy, and demand-side energy 

efficiency, all of which are measures in those building 

 

192 For example, as discussed in the Legal Memorandum, CAA 

§407(b)(2) requires the EPA to base the nitrogen oxides (NOx) 

emission limits for certain types of boilers “on the degree of 

reduction achievable through the retrofit application of the 

best system of continuous emission reduction ...;” and further 

requires the EPA to revise previously promulgated emission 

limits for certain types of boilers “to be more stringent if the 

[EPA] determines that more effective low NOx burner technology 

is available.” (Emphasis added.) 
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blocks.193 All this supports the reasonableness of interpreting 

“system of emission reduction” in section 111 to incorporate 

those measures. It should also be noted that a number of 

commentators in the private sector and academia have indicated 

support for interpreting the term, “system of emission 

reduction” to base the section 111(d) standards of performance 

on measures such as re-dispatch, renewable energy, and demandside energy efficiency.194 Some stakeholders have as well.195

 

193 CAA §401(b), 404(f)-(g). 194 See Nordhaus R., Gutherz I., “Regulation of CO2 Emissions from 

Existing Power Plants Under §111(d) of the Clean Air Act: 

Program Design and Statutory Authority,” Environmental Law 

Reporter, 44: 10366, 10384 (May 2014) (“strong arguments for” 

interpreting “system” to include measures such as the addition 

of new zero-carbon generating capacity and increases in end-user 

energy efficiency); Sussman R., “Power Plant Regulation Under 

the Clean Air Act: A Breakthrough Moment for U.S. Climate 

Policy?” Virginia Environment Law Journal, 32:97, 119 (2014) 

(“EPA would seem to have discretion to define ‘system’ to 

include any mix of strategies effective in reducing 

emissions.”); Konschnik K., Peskoe A., “Efficiency Rules: The 

Case for End-Use Energy Efficiency Programs in the Section 

111(d) Rule for Existing Power Plants,” Harvard Law School 

Environmental Law Program – Policy Initiative 4 (March 3, 2014) 

(EPA is authorized to “consider[] ... the entire [electricity 

grid] system when setting performance standards.”); Monast J., 

Profeta T., Pearson B., Doyle J., “Regulating Greenhouse Gas 

Emissions From Existing Sources: Section 111(d) and State 

Equivalency,” Environmental Law Reporter, 42: 10206, 10209 

(March 2012) (“Demand-side energy-efficiency programs and 

renewable energy generation may fit within the §111 framework, 

however, because both reduce the utilization of power plants .... 

According to this reasoning, emission reductions are occurring 
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 As described earlier with respect the individual building 

blocks, the measures in each of building blocks 2, 3, and 4 

qualify as components of the “best system of emission reduction 

... adequately demonstrated.” The evaluations above of the 

individual building blocks against the criteria for the BSER 

generally apply to the combination of all four building blocks 

as well. 

In addition, the measures in building blocks 2, 3, and 4 

are “adequately demonstrated” because, as discussed, due to the 

integrated nature of the electricity system, they have long been 

relied on to reduce costs in general, assure reliability, and 

implement pre-existing pollution control requirements in the 

least cost manner. As also noted elsewhere in the preamble, some 

utilities, states and regions are already relying on these 

 

within the source category, because of changes in generation at 

the power plant.”). 

195 Ceronsky M., Carbonell T., “Section 111(d) of the Clean Air 

Act: The Legal Foundation for Strong, Flexible & Cost-Effective 

Carbon Pollution Standards for Existing Power Plants,” 

Environmental Defense Fund, at 9 (Oct. 2013), available at

http://www.edf.org/sites/default/files/111-clean_air_actstrong_flexible_costeffective_carbon_pollution_standards_for_existing_power_plants.p

df; Doniger D., “Questions and Answers on the EPA’s Legal 

Authority to Set ‘System Based’ Carbon Pollution Standards for 

Existing Power Plants under Clean Air Act Section 111(d),” NRDC 

[Natural Resources Defense Council] Issue Brief (Oct. 2013). 
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measures for the specific purpose of reducing CO2 emissions from 

EGUs. 

 Further, measures in building blocks 2, 3, and 4 may be 

undertaken by the affected EGUs themselves, which confirms that 

these measures are “adequately demonstrated.” 

Each state’s electric utility sector has unique 

circumstances, and the EPA’s proposal ensures that states retain 

flexibility to craft standards of performance that can 

accommodate characteristics including fuels sources, types of 

EGU owners within a state (e.g., investor-owned, municipal, and 

cooperative utilities, and independent power producers), and 

regulatory structure (e.g., regulated or restructured). States 

can tailor their regulatory mechanisms to recognize differences, 

for example by creating budgets on a company-wide basis or using 

market-based mechanisms such as mass-based trading systems, to 

ensure that requirements are achievable. 

The proposal also recognizes that states have different 

resource bases and energy policies in place. For instance, while 

the EPA’s BSER assumptions consider re-dispatch to NGCC units, 

they do not consider re-dispatch beyond the NGCC capacity 

already existing in a state. In that way, the proposal does not 

Comment [A58]: EPA should clarify this here 

and in other locations where similar language is 

used. Does EPA mean that the measures may be 

undertaken or invested in by the owners of the 

affected EGUs? 
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presume that states with limited natural gas generation or 

infrastructure will have to develop those resources. 

Furthermore, while the BSER reflects best practices for 

both renewables and energy efficiency, it also recognizes that 

some states have made more progress than others in these areas. 

The BSER allows time for states to ramp up to greater levels of 

energy efficiency and use and development of renewable energy 

resources, should they choose those approaches. With respect to 

renewable energy, the proposal also recognizes that different 

areas of the country have different resource bases and does not 

presume that a uniform level of penetration of renewable 

generation is appropriate for every state. 

 The EPA also believes that owners of units operating 

across a wide range of corporate, institutional and market 

structures (e.g., vertically integrated utilities in regulated 

markets, independent power producers, municipal utilities, and 

rural cooperatives) can take advantage of a broad range of 

reduction opportunities included in the building blocks. Because 

of the proposed compliance time-frame, owners can consider 

longer-term options such as implementing energy efficiency 

programs or replacement of older generating resources with more 

modern types of generation, as well as shorter-term options such 
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as heat rate improvements and re-dispatch. Many companies, for 

example, already factor a carbon cost adder into their long-term 

planning decisions. 

Large vertically integrated utilities generally have 

options within all four building blocks. They tend to have large 

and, as a general matter, at least somewhat diverse generation 

fleets. For their higher-emitting units, they have opportunities 

to use measures that reduce the units’ CO2 emission rates, such 

as heat rate improvements, co-firing, or fuel switching. While 

this proposal preserves fuel diversity, with over 30 percent of 

projected 2030 generation coming from coal and over 30 percent 

from natural gas, even companies that have traditionally 

depended upon coal to supply the majority of their generation 

are diversifying their fleets, increasing their opportunities 

for re-dispatch.196 Within the 5-to-15-year planning horizon 

established in this proposal to begin in June 2015, most of 

these companies are likely to be investing in new generation and 

can consider options such as increased reliance on new renewable 

generating capacity. They also run energy efficiency programs 

for their customers. 

 

196 http://online.wsj.com/article/PR-CO-20140508-915605.html. 
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Municipal utilities and rural cooperatives that own their 

own generation also have multiple options for reducing CO2

emissions, particularly generation and transmission cooperatives 

and larger municipal utilities. The can implement unit-specific 

improvements, re-dispatch to lower emitting resources, employ 

energy efficiency and renewable energy strategies, and explore 

longer-term capacity planning strategies. For cooperatives and 

municipal utilities with smaller fleets, re-dispatching among 

their own units may not provide as many opportunities, 

particularly in the short term. But because of the timing 

flexibility in the guidelines, these owners can use both shortterm dispatch strategies and longer-term capacity planning 

strategies to reduce GHG emissions. At the same time, in 

formulating their compliance plans, states will be in a position 

to recognize the distinctive attributes of smaller utilities – 

and, of course, may consider participating in integrated multistate compliance strategies to increase the flexibility and 

cost-saving opportunities that would be available to the covered 

EGUs. 

Municipal utilities and rural cooperatives can face other 

challenges as well. In deregulated areas, even though they may 

be fully vertically integrated entities, they may not have as 
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much flexibility to control dispatch because they are operating 

in a competitive market, where they can be in a position where 

they need to operate if called upon. Even in this case, the 

timing flexibility of the rule allows them to consider longer 

term capacity planning strategies. These can include building or 

contracting for electric supply from lower-emitting sources, use 

of distributed renewable technologies, and use of demand-side 

energy efficiency measures. There are a number of municipal 

utilities and rural cooperatives that are already aggressively 

pursuing such strategies.197

Independent power producers (IPPs) may also face unique 

challenges but nevertheless have options. Most IPP generating 

units are natural gas-fired, but IPP owners with coal-fired EGUs 

can implement efficiency improvements as well as other unitlevel compliance options such as co-firing or fuel switching. 

While these types of companies do not use the integrated 

resource planning process that many vertically integrated 

utilities use, they still do long-term business planning and 

therefore are in a position to consider different long-term 

 

197 For examples, see Large Public Power Council, Energy 

Efficiency Working Group, Second Annual Energy Efficiency 

Benchmarking Report (2013); https://www.nreca.coop/nreca-on-theissues/energy-operations/energy-efficiency/. 
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strategies related to their generating assets. Many IPPs are 

actively developing renewable generating capacity and natural 

gas-fired generating capacity. In addition, many IPPs 

participate in markets that allow both generating resources and 

demand-side resources to compete, so even though they do not 

directly serve customers, they have opportunities to participate 

in demand-side energy efficiency programs. 

In a regulated state, if a company’s compliance strategies 

included reducing generation at higher-emitting EGUs, it would 

work through its state’s integrated planning process to ensure 

that adequate generation was available through a combination of 

all four building blocks. In a restructured state, even if 

affected companies responded to the guidelines by reducing 

generation without themselves replacing that generation, the 

electricity markets that have developed would react to ensure 

the availability of replacement generation. Other companies 

would see opportunities to build or ramp up existing loweremitting generation, and in some markets that treat demand-side 

resources on par with supply side resources, energy service 

companies would likely see opportunities. In all types of market 

structures, large energy users might independently see 

additional energy efficiency opportunities or opportunities for 
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self-generation using options such as combined heat and power, 

solar, or power purchase agreements. As discussed in earlier 

portions of this section and elsewhere in the preamble, each of 

the building blocks is already being widely implemented, is 

consistent with industry trends, and consists of well-accepted 

CO2 reduction methods in the eyes of various stakeholders, as was 

clear from views expressed in our outreach process. 

Moreover, there are mechanisms through which states could 

require measures from any of the building blocks in state plans. 

In fact, the state plan formulation process through which 

section 111(d) is implemented reinforces the determination that 

these measures are components of the BSER. For example, states 

would have authority to impose measures such as best practices 

for operation and maintenance of EGUs, dispatch limits, 

renewable energy resource requirements, and demand-side energy 

efficiency requirements. States also would have authority to 

establish requirements that change the relative costs of 

generation from more carbon-intensive and less carbon-intensive 

EGUs, for example by creating emission allowance systems that 

cause market participants and system operators to take account 

of CO2 emission rates as an element of variable operating costs. 

Such an approach can encourage measures from all of the building 
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blocks simultaneously. As noted elsewhere in the preamble, many 

states have already pursued one or more of these approaches.198 

As has also been discussed in earlier portions of the 

preamble, the costs and energy impacts of each of the four 

building blocks individually are not unreasonable when viewed 

either at the individual source level or through the lens of the 

electricity system as a whole, a conclusion that holds for the 

combination of the building blocks as well. Moreover, the 

flexibility available to states and regulated entities to rely 

more extensively in their plans and strategies on whichever 

measures best suit their particular circumstances will further 

improve cost-effectiveness. The analysis the EPA performed to 

assess the costs, benefits, and other impacts of the proposed 

goals reflects this compliance flexibility, along with 

transmission and pipeline capabilities and constraints, fuel 

market and electricity dispatch dynamics, and seasonal 

electricity load requirements. As described below in section X, 

the results indicate that the proposed state goals (discussed in 

section VII) are readily achievable with no adverse impacts on 

electric system reliability, and that impacts on retail 

 

198 See the discussions of California AB32 and RGGI above in this 

section and elsewhere in the preamble. 
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electricity prices are modest and fall within the range of price 

variability seen historically in response to changes in factors 

such as weather and fuel supply. Further, the costs tend to 

decline over time as states and regulated entities take 

advantage of the available flexibility and expand deployment of 

more cost-effective measures (notably demand-side energy 

efficiency). The EPA considers this analysis strong confirmation 

of the cost effectiveness of the measures in the four building 

blocks in combination as the best system of emission reduction. 

We note that some stakeholders have argued that section 

111(a)(1) does not authorize the EPA to identify re-dispatch, 

low- or zero-emitting generation, or demand-side energy 

efficiency measures (building blocks 2, 3, and 4) as components 

of the “best system of emission reduction ... adequately 

demonstrated.” According to these stakeholders, as a legal 

matter, the BSER is limited to measures that may be undertaken 

at the affected units, and not measures that are beyond the 

affected units; the measures in building blocks 2, 3, and 4 are 

“beyond-the-unit” measures because they are implemented outside 

of the affected units and outside their control; and as a 

result, those measures cannot be considered components of the 

BSER. 
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We welcome comment on this issue. As discussed above, we 

propose that the provisions of section 111 do not by their terms 

preclude the BSER from including those types of measures. In 

addition, as noted above, under our proposed approach, affected 

sources may themselves implement the measures included in 

building blocks 2, 3, and 4, so that those measures are within 

their control with the result of their application being 

emissions reductions at affected EGUs. Moreover, under our 

alternative approach, the “system of emission reduction” 

includes reductions in utilization at the affected sources 

themselves.199 It should also be noted that, as discussed above, 

 

199 Commenters have critiqued this “at-the-unit” and “beyond-theunit” distinction as follows: 

There is an argument that the at-the-unit/beyond-the-unit 

distinction is not a meaningful one. Specifically, it could 

be argued that the distinction between at-the-unit and 

beyond-the-unit measures is largely artificial, because all 

of the emission reductions under consideration—whether from 

at-the-unit measures (e.g., fuel-switching or efficiency 

upgrades) or from beyond-the-unit measures—are, in fact, 

emission reductions at or from electric generating units on 

the interconnected electric grid. For example, neither the 

addition of renewable generation nor the reduction of enduser demand directly reduces atmospheric emission of CO2; 

rather these measures permit fossil EGUs to reduce their 

own output and emissions. It can be argued that all of the 

systems of emission reduction here contemplated—whether 

they involve end-use energy efficiency, displacing highemission generation with lower emission generation, fuelComment [A59]: In the footnote – although the 

general effect of the proposed 111(d) action might be 

for “EGUs to curtail their output of electricity”, it 

doesn’t actually mandate this because it is rate based 

and implemented on a state basis. So, if the state or 

coal-EGU were to increase BBs 3 and 4, or close 

another coal EGU, there might not necessarily be a 

curtailment of electricity from a specific coal EGU. 
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the re-dispatch measures in building block 2 are limited to 

affected sources. Thus, the proposed approach and alternative 

described above respond to these stakeholder concerns. 

6. Alternate interpretation of the best system of emission 

reduction 

As an alternative to the approach described above for 

determining the “best system of emission reduction ... 

adequately demonstrated,” the EPA believes the “system of 

emission reduction” may be identified as including, in addition 

to building blocks 1 and 2, the reduction of EGUs’ mass 

emissions achievable through reductions in generation of 

specified amounts from fossil fuel-fired EGUs. Under this 

 

switching, heat-rate improvements, etc.—are effectively atthe-unit measures that ultimately reduce emissions solely 

from regulated EGUs. If energy-efficiency programs, added 

renewable energy, and redispatch from higher emitting 

facilities to lower emitting facilities are viewed as atthe-unit systems of emission reduction, the at-theunit/beyond-the-unit distinction arguably becomes 

irrelevant—at least from a legal perspective. Rather, the 

real issue may come down to whether §111(d) authorizes EPA 

to require EGUs to curtail their output of electricity as a 

means of complying with the rule. 

Nordhaus R., Gutherz I., “Regulation of CO2 Emissions from 

Existing Power Plants Under §111(d) of the Clean Air Act: 

Program Design and Statutory Authority,” Environmental Law 

Reporter, 44: 10366, 10383 n. 133 (May 2014). 
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approach, the measures in building blocks 3 and 4 would not be 

components of the BSER but instead would serve as bases for 

quantifying the reduction in emissions resulting from the 

reduction in generation at affected EGUs, and assuring that the 

reduced generation is “adequately demonstrated” because it could 

be achieved while continuing to meet the demand for electricity 

services in a reliable and affordable manner. Specifically, the 

amount of generation from the use of expanded low- and zerocarbon generating capacity that could be provided, and the 

amount of generation from fossil fuel-fired EUGs that could be 

avoided through the promotion of demand-side energy efficiency, 

would determine the amount of the fossil fuel-fired generation 

reduction component of the BSER. 

In a variation of this alternate interpretation of the 

BSER, instead of including building block 2 in the BSER, only 

the portion of building block 2 consisting of reductions in 

generation at higher-emitting affected fossil fuel-fired steam 

EGUs would be included in the BSER. The portion of building 

block 2 consisting of increased generation at lower-emitting 

affected NGCC units would not be included in the BSER, but 

instead would serve as a basis for quantifying the amount of 

reduction in generation at higher-emitting affected EGUs that 
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could be achieved while continuing to meet the demand for 

electricity services in a reliable and affordable manner. Under 

this variation, to ensure that demand for electricity services 

can be met reliably, we propose that the amount of reduced 

generation from affected fossil fuel-fired steam EGUs is the 

amount of incremental generation that can be provided from 

affected NGCC units, and similarly we propose to find the cost 

of reduced generation from affected fossil fuel-fired steam EGUs 

reasonable only to the extent that the cost of the incremental 

generation from affected NGCC units is reasonable. 

Reduced generation is encompassed by the clear terms of the 

phrase “system of emission reduction” because, in accordance 

with the above-discussed definition of “system,” reduced 

generation is a “set of things” – which include reduced use of 

generating equipment and reduced fuel input – that the affected 

source may take to reduce its CO2 emissions.200 If that phrase is 

not considered clear by its terms, then it may reasonably be 

interpreted to include reduced generation.201 As discussed in the 

Legal Memorandum, the legislative history of the CAA indicates 

 

200 For this reason, under a Chevron step 1 interpretation, 

“system of emission reduction” includes reduced generation. 

201 For these reasons, under a Chevron step 2 interpretation, 

“system of emission reduction” includes reduced generation. 
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that Congress recognized that emitting sources could comply with 

pollution control requirements by reducing production, including 

retiring. As also noted in the Legal Memorandum, examples of 

reduced utilization as a means of reducing emissions are found 

in settlement agreements between the EPA and fossil fuel-fired 

EGUs to resolve alleged violations of the CAA new source review 

(NSR) requirements.202 

Reduction of, or limitation on, the amount of generation is 

already a well-established means of reducing emissions of 

pollutants in the electric sector and not merely a theoretical 

option that is unavailable as a practical matter for sources 

that may have to operate to ensure system reliability. For 

example, reduced generation by higher-emitting sources is one of 

the compliance options available to, and used by, EGUs to comply 

with the Clean Air Act acid rain program in CAA title IV, as 

well as the transport rules that we refer to as the NOx SIP 

Call203 and the Clean Air Interstate Rule (CAIR).204 Reduction in 

 

202 See, e.g., Consent Decree, United States v. Wis. Power & 

Light Co., No. 13-cv-266 (W.D. Wis. filed Apr. 22, 2013), at 18, 

section IV, available at 

http://www2.epa.gov/sites/production/files/documents/wisconsinpo

wer-cd.pdf.

203 63 FR 57356 (Oct. 27, 1998). 204 70 FR 25162 (May 12, 2005). 

Field Code Changed
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generation is also a possible means by which an EGU can achieve 

compliance with its requirements under RGGI. 

Reduced generation in specified amounts is the “best” 

system of emission reduction that is “adequately demonstrated” 

because it is technically feasible due to the source’s ability 

to limit its own operations. In addition, the amounts of 

generation and emission reductions may be determined with 

precision through the application of building block 2, 3, and 4 

measures for increased generation from low- or zero-emitting 

sources and increased demand-side energy efficiency, which, in 

turn, ensure the reliability of the electricity grid and the 

affordability of electricity to business and consumers. 

Likewise, we propose to find the cost of reduced generation from 

affected EGUs reasonable only to the extent that the costs of 

the measures meeting the demand for energy services in the 

absence of that reduced generation are reasonable. 

The levels of reduced generation proposed meet the criteria 

for the “best system of emission reduction ... adequately 

demonstrated.” The costs of the proposed levels of reduced 

generation are reasonable for the affected source category and 

the nation-wide electricity system, do not jeopardize 

reliability, and do promote the development and implementation 
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of technology that is important for continued emissions 

reductions. This is because the extent to which the electrical 

grid operates through integrated generation, transmission and 

distribution networks creates fungibility for electricity and 

electricity services , which allows decreases in generation at 

one affected EGU to be seamlessly replaced by increased 

generation at a low- or zero-carbon EGU (building block 3) or by 

decreased demand (building block 4), or, in the variation 

described above, allows decreases in generation at affected 

fossil fuel-fired steam EGUs to be replaced by increases in 

generation at affected NGCC units (building block 2). These 

characteristics of the integrated electric system thereby make 

reduced generation a viable approach for achieving CO2 emission 

reductions by affected EGUs. 

As noted above, the measures in building blocks 2, 3, and 4 

are already in widespread use in the industry. At the levels 

proposed, they have the technical capability to substitute for 

reduced generation at some or all affected EGUs at reasonable 

cost. The NGCC capacity necessary to accomplish the levels of 

generation reduction proposed for building block 2 is already in 

operation or under construction. Moreover, it is reasonable to 

expect that the incremental resources reflected in building 
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blocks 3 and 4 will develop at the levels requisite to ensure an 

adequate and reliable supply of electricity at the same time 

that higher-emitting EGUs may choose or be required to reduce 

their CO2 emissions by means of reducing their utilization. There 

are two reasons for this. First, the affected sources themselves 

could invest in new renewable energy resources and demand-side 

energy efficiency, as discussed above.205 Second, the states, as 

part of their plans, have mechanisms available to put these 

substitutes in place: they could establish requirements or 

incentives that would result in new renewable energy and demandside energy efficiency programs, as also discussed above.206 

7. EPA’s discretion in applying the criteria for the best system 

of emission reduction 

As discussed above, each of the approaches to determining 

the “best system of emission reduction ... adequately 

 

205It should be noted that in light of the low current and 

projected near term prices for natural gas, market forces may 

lead investors to choose to build new NGCC units, rather than 

new renewable resources. This result would not call into 

question the technical feasibility of a BSER that included 

reductions in fossil fuel-fired generation by the amount of a 

specified amount of new renewable resources. This is because 

under these circumstances, the fossil fuel-fired generators 

could still reduce their generation without causing reliability 

or other problems in the electric power system. 

206 The nuclear generating capacity reflected in building block 3 

is already in operation or under construction. 
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demonstrated” entails applying the criteria described in the 

D.C. Circuit case law for evaluating BSER. It should be 

emphasized that under the case law, the EPA has significant 

discretion in weighing the different criteria, and may weigh 

them differently in different rulemakings. 

In the present rulemaking, the EPA is heavily weighting two 

criteria in particular: the amount of emissions reduction and 

the promotion of technology implementation – while also noting 

that the proposed BSER determination readily meets the other 

criteria as well. The EPA considers it especially important in 

this rulemaking, while ensuring that costs are not unreasonable, 

to achieve a significant amount of emissions reductions in 

response to the urgency and the magnitude of the need to 

mitigate climate change. Above, the EPA discusses this in the 

sections concerning the scientific background for this 

rulemaking. The EPA also considers it especially important in 

this rulemaking to promote technological innovation and 

development of, in particular, the measures in building blocks 3 

and 4 (to reiterate, low- or zero-carbon electricity generation 

and demand-side energy efficiency, respectively). Promoting 

innovation in, and market penetration of, these technologies and 

practices is critical to making the substantial reductions in 
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emissions that will be required during the next few decades to 

reduce the risks of dangerous climate change. 

In addition, in this rulemaking, the EPA is determining the 

BSER in a manner that is consistent with, and that provides 

further impetus for, current trends in the nation’s electricity 

system that offer promise to reduce the carbon intensity of the 

system over the near- and long-term, while maintaining 

reliability and affordability. This approach is consistent with 

the case law, which authorizes the EPA to determine BSER by 

“balanc[ing] long-term national and regional impacts,” and by 

“using a long-term lens with a broad focus on future costs, 

environmental and energy effects of different technological 

systems....”207

8. Combined categories 

 As discussed above, the EPA is co-proposing combining the 

category of steam-generating EGUs and the category of combustion 

turbines (which include NGCC units) into a single category for 

fossil fuel-fired EGUs, for purposes of promulgating emission 

guidelines for CO2 emissions. The EPA solicits comment on whether 

combining the categories is, as a legal matter, a prerequisite 

 

207 Sierra Club v. Costle, 657 F.2d 298, 331 (D.C. Cir. 1981). 
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for (i) identifying as a component of the BSER re-dispatch 

between sources in the two categories (i.e., re-dispatch between 

steam-generating EGUs and NGCC units), or (ii) facilitating 

averaging or trading systems that include sources in both 

categories, which states may wish to adopt. 

9. Severability 

We consider our proposed findings of the BSER with respect 

to the various building blocks to be severable, such that in the 

event a court were to invalidate our finding with respect to any 

particular building block, we would find that the BSER consists 

of the remaining building blocks. The state goals that would 

result from any combination of the building blocks can be 

computed from data included in the Goal Computation TSD and its 

appendices using the methodology described in the preamble and 

that TSD. 

10. Solicitation of comment 

 We invite comment on all aspects of our proposed 

interpretation of the BSER for CO2 emissions from existing fossil 

fuel-fired EGUs, both as identified above and as further 

discussed in the Legal Memorandum in the docket, although, as 

noted, we are not soliciting comment on issues that were 

resolved by the implementing regulations and therefore are not 
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being re-opened here. In particular, we invite comment on our 

analysis of the four building blocks as components of the BSER, 

whether any other potential measures should be considered, and 

the legal, technical, and economic bases of our conclusions. 

With regard to comments received during the stakeholder 

meetings, some commenters noted that trading programs like RGGI 

have been successful at reducing GHGs, and other commenters 

provided specific BSER proposals based on trading and/or 

emissions averaging approaches. We specifically request comment 

on whether any of these approaches should be considered as the 

BSER. We also specifically invite comment on the question, 

raised by some stakeholders, as to whether if measures may be 

relied on in the state plan to achieve emissions reductions, 

they cannot be excluded from the scope of the BSER solely 

because they involve actions by entities or at locations other 

than affected sources. 

VII. State Goals 

A. Overview 

In this section, the EPA sets out proposed state-specific 

CO2 emission performance goals to guide states in development of 

their state plans. The proposed goals reflect the EPA’s 

quantification of each state’s average emission rate from 
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affected EGUs that could be achieved by 2030 and sustained 

thereafter, with interim goals that would apply over a 2020-2029 

phase-in period, through reasonable implementation, considering 

the unique circumstances of each individual state, of the four 

building blocks described above. In addition, we are taking 

comment on a second set of state-specific goals that would 

reflect less stringent application of the same four building 

blocks, in this case by 2025, with interim goals that would 

apply over a 2020-2024 phase-in period. As promulgated in the 

final rule following consideration of comments received, the 

interim and final goals will be binding emission guidelines for 

state plans. 

 The proposed goals are expressed in the form of statespecific, adjusted208 output-weighted-average CO2 emission rates 

for affected EGUs. However, states are authorized to translate 

 

208 As described below, the emission rate goals include 

adjustments to incorporate the potential effects of emission 

reduction measures that address power sector CO2 emissions 

primarily by reducing the amount of electricity produced at a 

state’s affected EGUs (associated with, for example, increasing 

the amount of new low- or zero-carbon generating capacity or 

increasing demand-side energy efficiency) rather than by 

reducing their CO2 emission rates per unit of energy output 

produced. 
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the form of the goal to a mass-based form, as long as the 

translated goal achieves the same degree of emission limitation. 

 The EPA is proposing that measures that a state takes after 

the date of this proposal and prior to the beginning of the plan 

period in 2020, and which result in CO2 emission reductions 

during the plan period, would apply toward achievement of the 

state’s CO2 goal. Thus, states with existing programs and 

policies, and states that put in place new programs and policies 

early, will be better positioned to achieve the goals. 

At this time, the EPA is not proposing CO2 emission 

performance goals for either Indian country or U.S. territories. 

The EPA does plan to establish CO2 emission goals for both Indian 

country and territories. Emission goals for Indian country will 

be established in the future as necessary or appropriate, as 

provided for in the Tribal Authority Rule. 

With respect to Indian country, the EPA is soliciting 

comment on the application of the four BSER building blocks to 

determine CO2 emission performance goals for Indian country with 

affected EGUs. The EPA notes that some present and future 

actions taken to reduce criteria pollutants from EGUs in Indian 

Comment [A60]: Please provide a citation 
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country will result in significant CO2 emission reductions.209 As 

the EPA has done in setting state goals, the EPA would set 

emission performance goals for Indian country in a manner that 

would allow the jurisdictional authority to meet the goals 

through the use of a wide range of policies and practices 

capable of achieving CO2 emission reductions. If the EPA develops 

one or more federal plans for EGUs located in Indian country, we 

are currently considering doing so on a regional basis in 

coordination with plans being developed for neighboring states. 

The EPA solicits comment on such an approach for a federal plan. 

With respect to territories, the EPA requests comment on 

the appropriateness of the four building block approach for 

territories. In particular, the EPA solicits comment on 

appropriate alternatives for territories that do not have access 

to natural gas as well as on ways to determine appropriate 

renewable targets in the absence of the types of data used to 

develop the renewable component of BSER for states. 

 

209 For example, a plan currently being implemented at the Four 

Corners plant to satisfy regional haze requirements calls for 

reduction of NOx emissions to be achieved in part by shutting 

down a portion of the plant’s generating capacity, and a similar 

plan has been proposed for the Navajo plant. See 78 FR 62509 

(October 22, 2013). 
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The remainder of this section addresses five sets of 

topics. First, we discuss several issues related to the form of 

the goals. Second, we describe the proposed state goals and the 

computation procedure. Third, we discuss several types of state 

flexibility with respect to the goals. Fourth, we describe the 

alternate set of goals offered for comment and certain other 

approaches we considered. Finally, we discuss the proposal’s 

compatibility with the need to ensure a reliable, affordable 

supply of electricity. 

 Some of the topics addressed in this section are addressed 

in greater detail in supplemental documents available in the 

docket for this rulemaking, including the Goal Computation TSD 

and the Greenhouse Gas Abatement Measures TSD. Specific topics 

addressed in the various TSDs are noted throughout the 

discussion below. 

B. Form of goals 

 The proposed goals are presented in the form of adjusted 

output-weighted-average CO2 emission rates that the affected 

fossil fuel-fired EGUs located in each state could achieve, on 

average, through implementation of the four building blocks (or 

alternative control methods). Several aspects of this proposed 

form of goal are worth noting at the outset: the use of an 
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emission rate-based form (e.g., the quantity of CO2 per MWh of 

electricity generated), with the opportunity for the state to 

adopt a mass-based form (e.g., a cap on the tonnage of CO2

emissions); the use of output-weighted-average emission rates 

for all affected EGUs in a state rather than nationally uniform 

emission rates for all affected EGUs of particular types; the 

use of adjustments to accommodate measures that reduce CO2

emissions by reducing the quantity of fossil fuel-fired 

generation rather than by reducing the CO2 emission rate per MWh 

generated by affected sources; the use of emission rates 

expressed in terms of net rather than gross energy output; and 

the adjustability of the goals based on the severability of the 

underlying building blocks. 

 First, the EPA proposes to use an emission rate-based form 

for the state-specific goals included in the guidelines, and to 

give each state the opportunity to translate its rate-based goal 

to an equivalent mass-based form for state plan purposes. Each 

of the two forms of goals presents advantages. Defining emission 

performance levels in a rate-based form provides flexibility to 

accommodate changes in the overall quantities of electricity 

generated in response to increases in electricity demand. 

Defining emission performance levels in a mass-based form 
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provides relative certainty as to the absolute emission levels 

that would be achieved as well as relative simplicity in 

accommodating and accounting for the emission impacts of a wide 

variety of emission reduction strategies. In light of these 

respective advantages, we propose to set an emission rate-based 

form of goal, and to allow any state to translate the rate-based 

goal to an equivalent mass-based emission performance level for 

state plan purposes. This approach allows each state to maximize 

the advantages it considers optimal and is consistent with the 

state flexibility principle that is central to the EPA’s 

development of this program. 

 The second aspect noted above concerns the proposed choice 

of state-specific output-weighted-average emission rates for all 

affected EGUs in each state rather than nationally uniform 

emission rates for particular types of affected EGUs. Here, the 

EPA’s main consideration has been to ensure that the proposed 

goals reflect opportunities to manage CO2 emissions by shifting 

generation among different types of EGUs. Specifically, because 

CO2 emission rates differ widely across the fleet of affected 

EGUs, and because transmission interconnections typically 

provide system operators with choices as to which EGU should be 

called upon to provide the next MWh of generation needed to meet 
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demand, opportunities exist to manage utilization of high 

carbon-intensity EGUs based on the availability of less carbonintensive generating capacity. For states and generators, this 

means that CO2 emission reductions can be achieved by shifting 

generation from EGUs with higher CO2 emission rates, such as 

coal-fired EGUs, to EGUs with lower CO2 emission rates, such as 

NGCC units. Our analysis indicates that shifting generation 

among EGUs offers opportunities to achieve large amounts of CO2

emission reductions at reasonable costs. These opportunities can 

be reflected in a goal established in the form of an outputweighted-average emission rate for multiple affected EGU types. 

Our approach is also consistent with the fact that the 

proportions of different EGU types and hence the magnitudes of 

the generation-shifting opportunities vary across states, and 

that CAA section 111(d) calls for standards of performance to be 

established in state plans rather than on a nationwide basis. 

 The third aspect noted above regarding the proposed form of 

the goals concerns the adjustments made to the output-weightedaverage emission rates in order to accommodate reduced 

utilization associated with measures such as increases in lowand zero-carbon generating capacity and demand-side energy 

efficiency. We recognize that these measures reduce overall CO2
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mass emissions from affected EGUs by reducing the quantity of 

generation from affected EGUs without necessarily reducing the 

weighted-average CO2 emission rates of affected EGUs. 

Accordingly, we have constructed the emission rate goals in a 

manner that is intended to account for these generation 

quantity-reducing measures by making adjustments to the values 

used in the emission rate computations. The specific adjustments 

are summarized below in the context of the goal computation 

methodology and are described in greater detail in the Goal 

Computation TSD. As described below in section VIII on state 

plans, we are proposing that a state choosing a rate-based form 

of goal would be able to make analogous adjustments when 

assessing monitored emission performance so that measures that 

avoid generation at affected EGUs could be used to help the 

state meet the rate-based emission performance level reflected 

in its plan. We note that adjustments of this nature are not 

necessary when a plan’s emission performance level is based on 

the mass of CO2 emissions210 rather than on CO2 emission rates, 

 

210 We also recognize that even under a mass-based approach, 

adjustments may be appropriate in some circumstances to address 

interstate effects, such as when measures undertaken pursuant to 

one state’s plan are expected to be associated with decreases in 
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because the emission-reducing effects of reduced generation at 

affected EGUs are evident in the EGUs’ reported CO2 mass 

emissions. 

 The fourth aspect noted above concerns the proposed 

expression of the goals in terms of net energy output – that is, 

energy output encompassing net MWh of generation measured at the 

point of delivery to the transmission grid rather than gross MWh 

of generation measured at the EGU’s generator.211 (As discussed 

below in section VIII on state plans, we are similarly proposing 

that states choosing a rate-based form of emission performance 

level for their plans should establish a requirement for 

affected EGUs to report hourly net energy output.) The 

difference between net and gross generation is the electricity 

used at a plant to operate auxiliary equipment such as fans, 

pumps, motors, and pollution control devices. Improvements in 

the efficiency of these devices represent opportunities to 

reduce carbon intensity at affected EGUs that would not be 

captured in measurements of emissions per gross MWh. Further, 

 

fossil fuel-fired generation and CO2 emissions in another state. 

These issues are discussed below in section VIII on state plans. 

211 For some EGUs, total net or gross energy output also includes 

useful thermal output, in addition to either net or gross 

electric energy output. 
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nearly all EGUs already have in place the equipment necessary to 

determine and report hourly net generation, and we believe that 

the proposed reporting requirement would therefore not be 

burdensome. However, we also recognize that at present EGUs 

report gross rather than net load212 to us under 40 CFR Part 75, 

and that the proposed GHG standards of performance for new EGUs 

are expressed in terms of gross generation (although we sought 

comment on the use of net generation instead). We therefore 

specifically seek comment on whether the goals and reporting 

requirements for existing EGUs should be expressed in terms of 

gross generation instead of net generation for consistency with 

existing reporting requirements and with the proposed 

requirements under the GHG standards of performance for new 

EGUs. 

 The final aspect noted above has to do with the 

severability of the four building blocks, discussed in section 

VI above, upon which the goals are based. Because the building 

blocks are independent of each other and the goals are the sum 

of the emission reductions from all of the building blocks, if 

any of the building blocks are found to be invalid bases for the 

 

212 Some EGUs report gross steam output instead of gross 

electrical load. 
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“best system of emission reduction ... adequately demonstrated,” 

the goals would be adjusted to reflect the emissions reductions 

from the remaining building blocks. As noted above, the state 

goals that would result from any combination of the building 

blocks can be computed from data included in the Goal 

Computation TSD and its appendices using the methodology 

described below and in that TSD. 

We invite comment on all aspects of the proposed form of 

the goals, including suggestions for specific alternative forms 

of goals not discussed above that may also merit consideration. 

C. Proposed goals and computation procedure 

 The EPA has developed proposed goals for state plans 

reflecting use of all four building blocks described earlier. 

The goals are intended to represent CO2 emission rates achievable 

by 2030 after a 2020-2029 phase-in period on an output-weightedaverage basis collectively by all of a state’s affected EGUs, 

with certain computation adjustments described below to reflect 

the potential to achieve mass emission reductions by avoiding 

fossil fuel-fired generation. In addition to the final goals, 

EPA has developed interim goals that would apply during the 

2020-2029 period on a cumulative or average basis as states 

progress toward the final goals. The proposed goals are set 
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forth in Table 6 below, followed by a description of the 

computation methodology. (The issue of how states could 

demonstrate emission performance consistent with the interim and 

final goals is addressed in Section VIII on state plans.) 

Table 6: Proposed State213 Goals (Adjusted Output-WeightedAverage Pounds of CO2 Per Net MWh From All Affected Fossil FuelFired EGUs) 

State Interim Goal Final Goal 

Alabama 1,147 1,059 

Alaska 1,097 1,003 

Arizona * 735 702 

Arkansas 968 910 

California 556 537 

Colorado 1,159 1,108 

Connecticut 597 540 

Delaware 913 841 

Florida 794 740 

Georgia 891 834 

 

213 The EPA has not developed goals for Vermont and the District 

of Columbia because current information indicates those 

jurisdictions have no affected EGUs. Also, as noted above, EPA 

is not proposing goals for Indian country or U.S. territories at 

this time. 

Comment [A61]: We think this table is 

mislabeled. It should be “Table 6: Proposed State 

Goals (Adjusted Output-Weighted-Average Pounds 

of CO2 Per Net MWh From All Affected Generation 

Fossil Fuel-Fired EGUs). How can any fossil source 

meet a 537lbs/Mwh standard? 

Including the initial state rates based on all affected 

generation which includes fossil, nuclear and 

renewables in this table would be useful. This would 

provide useful information to the reader regarding 

how much individual states need to do to comply 

with 111(d). 
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Hawaii 1,378 1,306 

Idaho 244 228 

Illinois 1,366 1,271 

Indiana 1,607 1,531 

Iowa 1,341 1,301 

Kansas 1,578 1,499 

Kentucky 1,844 1,763 

Louisiana 948 883 

Maine 393 378 

Maryland 1,347 1,187 

Massachusetts 655 576 

Michigan 1,227 1,161 

Minnesota 911 873 

Mississippi 732 692 

Missouri 1,621 1,544 

Montana 1,882 1,771 

Nebraska 1,596 1,479 

Nevada 697 647 

New Hampshire 546 486 

New Jersey 647 531 

New Mexico * 1,107 1,048 
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New York 635 549 

North Carolina 1,077 992 

North Dakota 1,817 1,783 

Ohio 1,452 1,338 

Oklahoma 931 895 

Oregon 407 372 

Pennsylvania 1,179 1,052 

Rhode Island 822 782 

South Carolina 840 772 

South Dakota 800 741 

Tennessee 1,254 1,163 

Texas 853 791 

Utah * 1,378 1,322 

Virginia 884 810 

Washington 264 215 

West Virginia 1,748 1,620 

Wisconsin 1,281 1,203 

Wyoming 1,808 1,714 

* Excludes EGUs located in Indian country within the state. 

 The proposed goals are expressed as adjusted outputweighted-average emission rates for all affected EGUs in a 

state. As discussed earlier in this section, a goal expressed as 
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an unadjusted output-weighted-average emission rate would fail 

to account for mass emission reductions from reductions in the 

total quantity of fossil fuel-fired generation associated with 

state plan measures that increase low- or zero carbon generating 

capacity or demand-side energy efficiency. Accordingly, under 

the proposed goals, the emission rate computation includes an 

adjustment designed to reflect those mass emission reductions. 

The adjustment is made by estimating the annual net generation 

associated with an achievable amount of qualifying new lowcarbon and zero-carbon generating capacity, as well as the 

annual avoided generation associated with an achievable 

portfolio of demand-side energy efficiency measures, and adding 

those MWh amounts to the energy output from affected units that 

would have been used in an unadjusted output-weighted-average 

emission rate computation.214 Mathematically, this adjustment has 

the effect of spreading the measured CO2 emissions from the 

state’s affected EGUs over a larger quantity of energy output, 

thus resulting in an adjusted emission rate lower than the 

unadjusted emission rate. (As discussed below in section VIII on 

 

214 In the case of new capacity that is not zero-carbon, an 

adjustment would also be required to the emissions value used in 

computing the weighted-average emission rate. This procedure is 

discussed further in the Goal Computation TSD. 
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state plans, we are proposing that a state could make analogous 

adjustments to compliance measurement approaches under its state 

plan, thereby enabling the state to adopt an emission rate-based 

form of emission performance level while still being able to 

rely on low- or zero-carbon capacity deployment programs and 

demand-side energy efficiency as components of its plan.) 

 The methodology used to compute each state’s proposed goal 

is summarized on a step-by-step basis below. The methodology is 

described in more detail in the Goal Computation TSD, which 

includes a numerical example illustrating the full procedure. 

The development of the data inputs used in the computation 

procedure is discussed in section VI above and in the Greenhouse 

Gas Abatement Measures TSD. 

 Step 1 (compilation of baseline data). On a state-by-state 

basis, we obtained total annual quantities of CO2 emissions, net 

generation (MWh), and capacity (MW) from reported 2012 data for 

all affected EGUs.215 For each state, we aggregated the 2012 data 

for all coal-fired steam EGUs as one group, all oil- and gas-

 

215 EGUs whose capacity, fossil fuel combustion, or electricity 

sales were insufficient to qualify them as affected EGUs were 

not included in the goal computations. Most simple cycle 

combustion turbines were excluded on this basis. See the 

applicability criteria described in Section V.B. above. 
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fired steam EGUs as a second group, and all NGCC units as a 

third group. We aggregated the 2012 data for all remaining 

affected EGUs (i.e., integrated gasification combined-cycle 

(IGCC) units and any simple-cycle combustion turbines satisfying 

the size and electricity sales thresholds for qualification as 

affected EGUs) as a fourth, “other” group.216 To these totals for 

affected EGUs operating in 2012, we added estimates for other 

EGUs not yet in operation in 2012 that are affected EGUs for 

purposes of this emission guideline.217 Capacity and emission 

rate data inputs for the post-2012 affected EGUs were obtained 

from the NEEDS database maintained by the EPA for use with the 

Integrated Planning Model (IPM). Generation data inputs for the 

post-2012 affected EGUs were estimated based on the average 2012 

utilization rates for recently constructed EGUs of the same 

types; for example, we estimated in this step that the post-2012 

NGCC units would operate at a 55 percent utilization rate on 

average. 

 

216 The emission and generation totals for the “other” group also 

reflect the portion of affected cogeneration units’ total CO2

emissions and total energy output corresponding to those units’ 

useful thermal output. 

217 Assuming it meets other applicability criteria, an EGU would 

be affected if it had commenced construction by January 8, 2014 

(the data of Federal Register publication of the proposed GHG 

NSPS for new EGUs). 
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 Step 2 (application of building block 1). The total CO2

emissions amount for the coal-fired steam EGU group in each 

state from Step 1 was reduced by six percent, reflecting our 

assessment of the average opportunity to reduce CO2 emission 

rates across the existing fleet of coal-fired steam EGUs through 

heat rate improvements that is technically achievable at a 

reasonable cost. 

 Step 3 (application of building block 2). If the generation 

data for the NGCC group in a state developed in Step 1 showed 

average annual utilization below 70 percent of those units’ 

maximum possible output, and the generation data developed in 

Step 1 also included generation from the coal-fired steam or 

oil/gas-fired steam EGU groups in that state, the generation and 

emissions figures for the NGCC group were increased, and the 

generation and emissions figures for the coal-fired and oil/gasfired steam EGU groups from Step 2 were proportionately218

decreased, to reflect an estimated potential increase in 

 

218 For example, if the data developed in Step 1 showed equal 

quantities of MWh generated by the coal-fired steam EGU group 

and the oil/gas-fired steam EGU group, then any overall 

reduction in the MWh generated by these two groups due to a 

commensurate increase in the MWh generated by the less carbonintensive NGCC group would be split equally between the coalfired steam group and the oil/gas-fired steam group. 
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utilization of the NGCC group to a maximum of 70 percent. In 

this step, the total (across all four groups) of the state’s 

fossil fuel-fired generation was maintained at the amount 

computed in Step 1, but to the extent that in the analysis a 

portion of the total fossil generation was shifted from the 

coal-fired and oil/gas-fired steam EGU groups, which have higher 

CO2 emission rates, to the NGCC group, which has a lower CO2

emission rate, the total (across all four groups) of the state’s 

CO2 emissions was reduced.219 

 Step 4 (application of building block 3). We estimated the 

total quantities of generation from renewable generating 

capacity and new or preserved nuclear capacity for each state 

under the “best practices” approaches discussed in section 

VI.C.3 above. Separate estimates of renewable generation were 

computed for each year of the plan period for each state based 

on the state’s 2012 renewable generation and a regional growth 

factor. Nuclear generation was estimated as the amount of new 

and preserved nuclear capacity for each state operated at a 

 

219 We did not estimate any change in utilization, generation, or 

emissions for the state’s “other” group of IGCC units and 

simple-cycle combustion turbines in Step 3. 
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utilization rate of 90 percent, consistent with recent industrywide average utilization rates for nuclear units. 

 Step 5 (application of building block 4). We estimated the 

total MWh amount by which generation from each state’s affected 

EGUs would be cumulatively reduced in each year of the plan 

period by implementation in that state of a comprehensive “best 

practices” approach to demand-side energy efficiency programs 

resulting in annual incremental reductions in the state’s 

electricity usage (relative to usage absent those programs) of 

1.5 percent each year. Separate estimates were developed for 

each year to reflect the fact that energy efficiency programs 

that are implemented on an ongoing basis would be expected to 

produce larger cumulative impacts on total annual electricity 

usage over time. For states that are net importers of 

electricity, the estimated reduction in the generation by the 

state’s affected EGUs was scaled down to reflect an expectation 

that a portion of the generation avoided by the demand-side 

energy efficiency would occur at EGUs in other states. 

 Step 6 (computation of annual rates). We computed adjusted 

output-weighted-average CO2 emission rates for each state by 

dividing (1) the total CO2 emissions for the coal-fired steam 

EGU, oil- and gas-fired steam EGU, NGCC unit, and “other” 
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affected fossil EGU groups from Step 3 above by (2) the total of 

(a) the total net energy output (expressed in MWh) for the four 

groups from Step 1 above plus (b) the estimated annual net 

generation from renewable and nuclear generating capacity from 

Step 4 above plus (c) the estimated cumulative annual MWh amount 

saved through demand-side energy efficiency from Step 5 above.220

We performed these computations separately for each year from 

2020 to 2029, using the respective cumulative annual MWh savings 

figures developed in Steps 4 and 5. 

 Step 7 (computation of interim and final goals). The final 

2030 goal for each state is the annual rate computed for 2029 

for the state from Step 6 above. We computed the 2020-2029 

interim goal for each state as the simple average of the annual 

rates computed for each of the years from 2020 to 2029 for the 

state from Step 6 above. 

 It bears emphasis that the procedure described above is 

proposed to be used only to determine state goals, and the 

 

220 Expressed as a formula, the equation for the annual rate 

computation is: 

[(Coal gen. x Coal emission rate) + (OG gen. x OG emission rate) 

+ (NGCC gen. x NGCC emission rate) + “Other” emissions] / [Coal 

gen. + OG gen. + NGCC gen. + “Other” gen. + Nuclear gen. + RE 

gen. + EE gen.] 

Comment [A62]: If a formula is to be included 

here, it should be precise. This formula is too 

schematic as it stands. For example, it does not 

distinguish between existing nuclear gen (credited at 

a small fraction) and new nuclear gen and all RE gen 

(credited fully). In addition, “Other” should be 

described. 
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particular data inputs used in the procedure are not intended to 

represent specific requirements that would apply to any 

individual EGU or to the collection of EGUs in any state. The 

specific requirements applicable to individual EGUs, to the EGUs 

in a given state collectively, or to other affected entities in 

the state would be based on the standards of performance 

established through that state’s plan. The details of how states 

could attain emission performance levels consistent with the 

goals through different state plan approaches that recognize 

emission reductions achieved through all the building blocks are 

discussed further in section VIII on state plans. 

 We invite comment on all aspects of the goal computation 

procedure. (Note that we also invite comment on certain specific 

alternate data inputs to the procedure in Section VI.C above.) 

We also specifically invite comment on the state-specific 

historical generation and capacity data to which the building 

blocks are applied in order to compute the state goals, as well 

as the state-specific data used to develop the state-specific 

data inputs for building blocks 3 and 4. These data are 

contained in the Goal Computation TSD and the Greenhouse Gas 

Abatement Measures TSD. 
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With respect to building block 2, we specifically request 

comment on the following alternate procedure: in Step 3, to the 

extent that generation from a state’s NGCC group was increased 

consistent with the NGCC utilization rate target, in order to 

maximize the resulting emission reductions, we would decrease 

generation from the state’s coal-fired steam group first, and 

then decrease generation from the state’s oil/gas-fired steam 

group (instead of decreasing generation from the coal-fired 

steam and oil/gas-fired steam groups proportionately). 

With respect to building block 4, we specifically invite 

comment on the alternative in Step 5 of scaling up the estimated 

reduction in the generation by affected EGUs in net electricityexporting states to reflect an expectation that a portion of the 

generation avoided by the demand-side energy efficiency efforts 

of other, net electricity-importing states would occur at those 

EGUs, analogous to the proposed adjustment for net importing 

states described in Step 5. We also request comment on the 

alternative of making no adjustment in Step 5 for either net 

electricity-importing or net electricity-exporting states. These 

alternatives are discussed in the Goal Computation TSD. 
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We also request comment on whether CO2 emission reductions 

from other measures not currently included in any of the four 

proposed building blocks should be included in the state goals. 

D. State flexibilities 

 As promulgated in the final rule following consideration of 

comment, the state-specific goals will be binding emission 

guidelines. States’ ability to achieve emission performance 

levels consistent with the binding goals is enhanced by several 

distinct types of flexibility: (i) choices as to the measures 

employed, including the timing of their implementation; (ii) the 

ability to translate from a rate-based form of goal to a massbased form of goal; and (iii) the opportunity to pursue multistate compliance approaches. 

 First, a core flexibility provided under CAA section 111(d) 

is that while states are required to establish standards of 

performance that reflect the degree of emission limitation from 

application of the control measures that the EPA identifies as 

the BSER, they need not mandate the particular control measures 

the EPA identifies as the basis for its BSER determination. In 

developing the building block data inputs applied to each 

state’s historical capacity and generation data to develop the 

goals, the EPA targeted reasonably achievable rather than 
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maximum performance levels. The overall goals therefore 

represent reasonably achievable emission performance levels that 

provide states with flexibility to pursue some building blocks 

more extensively and others less extensively than the degree 

reflected in EPA’s data inputs while meeting the overall goals. 

States can also choose to include in their plans measures that 

are not included in the building blocks. 

Further, by allowing states to demonstrate compliance over 

a multi-year interim plan period of as long as ten years, the 

EPA’s proposed approach increases states’ flexibility to choose 

among alternative potential measures. For example, by taking 

advantage of the multi-year flexibility, a state could choose to 

rely more heavily in its plan on measures whose effectiveness 

tends to grow over time, such as demand-side energy efficiency 

programs. This flexibility could also help states address 

concerns about stranded assets, for example, by enabling states 

to defer imposition of requirements on EGUs that may be 

scheduled to retire after 2020 but before 2029. 

 The second type of flexibility noted above is that while 

the EPA is proposing to establish goals in an emission ratebased form, we are also proposing to provide states with the 

flexibility to translate the rate-based goals to mass-based 

Formatted: Highlight
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goals in order to accommodate states’ potential interest in 

having emission performance requirements measured in absolute 

tons. For example, the northeastern states that currently 

participate in the mass-based Regional Greenhouse Gas Initiative 

(RGGI) may choose to develop state plans establishing mass-based 

emission performance levels designed to be met at least in part 

through standards of performance based on RGGI’s existing 

market-based CO2 emission budget program. Because the use of 

mass-based plans can simplify the process of accounting for the 

CO2 reduction impacts of a variety of measures, the EPA believes 

the flexibility to adopt mass-based emission performance levels 

can facilitate plan development and could be attractive to 

states that do not already participate in mass-based programs as 

well. 

Third, the EPA’s approach allows states to submit multistate plans. The EPA expects this flexibility to reduce the cost 

of achieving the state goals and therefore expects it to be 

attractive to states. For example, the RGGI-participating states 

could choose to submit a multi-state mass-based plan that 

demonstrates emission performance on a multi-state basis. 

Additional states may also choose to join a multi-state plan. 

The mechanics of translating rate-based goals into mass-based 

Formatted: Highlight
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goals and demonstrating equivalency between the two forms and 

issues related to multi-state plans are discussed below in 

Section VIII on state plans. 

Some stakeholders have suggested that states themselves 

should be allowed to quantify the level of emission reduction 

resulting from the application of BSER or, if the EPA 

establishes goals, the states should be allowed to adjust the 

goals or to treat the goals established by the EPA as advisory 

rather than binding. Consistent with the existing implementing 

regulations for CAA section 111(d) at 40 CFR part 60, this 

quantification is the EPA’s role.221 As discussed in the Legal 

Memorandum, CAA section 111(d) directs the EPA to “prescribe 

regulations which shall establish a procedure similar to that 

provided by [CAA section 110) under which each State shall 

submit” a section 111(d) state plan. As noted in preamble 

section II.D above, the EPA promulgated implementing regulations 

in 1975, and has revised parts of them since. The regulations 

set out a multi-step process for the development and approval of 

state plans, and assign responsibility for the various steps in 

the process to the EPA or the states. The regulations provide 

 

221 40 CFR 60.22(b)(5). We do not propose to re-open that portion 

of the implementing regulations in this rulemaking. 
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that the EPA is to promulgate an “emission guideline that 

reflects the application of the best system of emission 

reduction (considering the cost of such reduction) that has been 

adequately demonstrated for” affected sources.222 In this manner, 

the regulations make clear that the EPA determines the BSER. In 

this rulemaking, as discussed above, the EPA identifies the 

BSER. In addition, in this rulemaking, the EPA applies the BSER 

to each state, and then, for each state, calculates the average 

emission rate that, in the words of the regulations just quoted, 

“reflects the application of the [BSER].” That average emission 

rate is the state goal. 

By the same token, because the state goals are an integral 

part of the emission guidelines that the framework regulations 

authorize EPA to establish, the goals are binding, and the 

states, in their CAA section 111(d) plans, must meet those goals 

and may not make them less stringent. This matter, too, is 

resolved by the implementing regulations.223 To reiterate, the 

proposed state goals represent the level of performance that is 

achievable through application of the BSER to the pertinent data 

 

222 Id. 223 Id. We do not propose to re-open that portion of the 

implementing regulations in this rulemaking. 
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for each individual state. States have the opportunity to 

comment on the proposed BSER, the proposed methodology for 

computing state goals based on application of the BSER, and the 

state-specific data that is proposed for use in the 

computations. We expect that the states will have an adequate 

opportunity to comment on the state goals during the comment 

period. Once the final goals have been promulgated, the states 

will be able to meet them because they will represent the 

application of BSER to the states’ affected sources. In 

addition, states have several types of flexibilities in 

developing their state plans: they have flexibility regarding 

the selection of the measures upon which they choose to rely and 

a 10-year time period over which to reach full implementation, 

and they can use rate-based or mass-based approaches. In 

addition, as we have noted, multi-state coordination offers 

states an opportunity to achieve additional emission reductions 

and reduce implementation costs. These flexibilities, discussed 

further in Section VIII of this preamble, ensure that states 

will be able to achieve their final CO2 emission performance 

goals and that no special provision for state adjustment of 
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goals outside the normal notice-and-comment rulemaking process 

is warranted.224

E. Alternate goals offered for comment and other approaches 

considered 

 In addition to the proposed state-specific emission ratebased goals described above, the EPA has developed for public 

comment an alternate set of goals reflecting less stringent 

application of the building blocks and a shorter implementation 

period. The alternate final goals represent emission performance 

that would be achievable by 2025, after a 2020-2024 phase-in 

period, with interim goals that would apply during the 2020-2024 

period on a cumulative or average basis as states progress 

toward the final goals. 

 The alternate goals reflect several differences in data 

inputs from the proposed goals. Specifically, a value of four 

percent (instead of six percent) was used for the potential 

improvement in carbon intensity of coal-fired EGUs in Step 2; a 

value of 65 percent (instead of 70 percent) was used for the 

 

224 In the event that a state becomes concerned about its ability 

to meet the goal that the EPA promulgates for it, the state may 

submit to the EPA a petition for reconsideration, if that 

petition is based on relevant information not available during 

the comment period. See CAA §307(d)(7)(B). 
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potential annual utilization rate of NGCC units in Step 3; and a 

value of one percent (instead of 1.5 percent) was used for the 

annual incremental electricity savings achievable through a best 

practices portfolio of demand-side energy efficiency programs in 

Step 5. (No change was made to the data inputs regarding less 

carbon-intensive generating capacity in Step 4.) As noted above, 

the alternate goals also reflect a shortening of the proposed 

phase-in period from ten years (2020-2029) to five years (2020-

2024) to reflect an expectation that less stringent goals could 

be achieved in less time. Steps 5, 6, and 7 of the goal 

computation procedure therefore were performed for the span of 

years from 2020 to 2024 rather than for the span from 2020 to 

2029. The alternate goals are set forth in Table 7 below. 

Table 7: Alternate State225 Goals (Adjusted Output-WeightedAverage Pounds of CO2 Per Net MWh From All Affected Fossil FuelFired EGUs) 

State Interim Goal Final Goal 

Alabama 1,270 1,237 

Alaska 1,170 1,131 

Arizona * 779 763 

 

225 See footnote accompanying Table 6 above. 
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Arkansas 1,083 1,058 

California 582 571 

Colorado 1,265 1,227 

Connecticut 651 627 

Delaware 1,007 983 

Florida 907 884 

Georgia 997 964 

Hawaii 1,446 1,417 

Idaho 261 254 

Illinois 1,501 1,457 

Indiana 1,715 1,683 

Iowa 1,436 1,417 

Kansas 1,678 1,625 

Kentucky 1,951 1,918 

Louisiana 1,052 1,025 

Maine 418 410 

Maryland 1,518 1,440 

Massachusetts 715 683 

Michigan 1,349 1,319 

Minnesota 1,018 999 

Mississippi 765 743 
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Missouri 1,726 1,694 

Montana 2,007 1,960 

Nebraska 1,721 1,671 

Nevada 734 713 

New Hampshire 598 557 

New Jersey 722 676 

New Mexico * 1,214 1,176 

New York 736 697 

North Carolina 1,199 1,156 

North Dakota 1,882 1,870 

Ohio 1,588 1,545 

Oklahoma 1,019 986 

Oregon 450 420 

Pennsylvania 1,316 1,270 

Rhode Island 855 840 

South Carolina 930 897 

South Dakota 888 861 

Tennessee 1,363 1,326 

Texas 957 924 

Utah * 1,478 1,453 

Virginia 1,016 962 
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Washington 312 284 

West Virginia 1,858 1,817 

Wisconsin 1,417 1,380 

Wyoming 1,907 1,869 

* Excludes EGUs located in Indian country in the state. 

The EPA has considered other approaches to setting goals. 

In particular, given the interconnected nature of the power 

sector and the importance of opportunities for shifting 

generation among EGUs, we considered whether goals should be set 

on a multi-state basis reflecting the scope of existing regional 

transmission control areas. We also considered whether goals 

should be set on a state-specific basis, but the estimated 

opportunities to reduce utilization of the most carbon-intensive 

EGUs by shifting generation to less carbon-intensive EGUs should 

be based on regional evaluations rather than state-specific 

evaluations. A potential advantage of using regional evaluations 

is the ability to recognize additional cost-effective emission 

reduction opportunities based on a more complete representation 

of the capabilities of existing infrastructure to accommodate 

shifts in generation among EGUs in multiple states. We request 

comment on whether, and if so how, the EPA should incorporate 

greater consideration of regional approaches into the goal-
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setting process, and on the issue of whether, and if so how, the 

potential cost savings associated with regional approaches 

should be considered in assessing the cost effectiveness of 

state-specific goals. 

F. Reliable Affordable Electricity 

Many stakeholders raised concerns that this regulation 

could affect the reliability of the electric power system. The 

EPA agrees that reliability must be maintained and in designing 

this proposed rulemaking has paid careful attention to this 

issue. EPA has met on several occasions with staff and managers 

from the Department of Energy and the Federal Energy Regulatory 

Commission to discuss our approach to the rule and its potential 

impact on the power system. EPA staff and managers have also had 

numerous discussions with state public utility commissioners and 

their staffs to get their suggestions and advice concerning this 

rule, including how to address reliability concerns. 

In addition, the EPA met with independent system operators 

several times to discuss any potential impact of this rule on 

grid reliability. The ISO/RTO Council, a national organization 

of electric grid operators, offered analytic support to help 

states design programs that do not compromise the regional bulk 

power system. They also offered to help states develop regional 
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approaches which may reduce costs and strengthen the reliability 

of the electricity grid. Specifically, the ISO/RTO Council has 

suggested that ISOs and RTOs could provide analytic support to 

help states develop and implement their plans. The ISOs and RTOs 

have the capability to model the system-wide effects of 

individual state plans. Providing assistance in this way, they 

felt, would allow states with borders that fall within an ISO or 

RTO footprint to assess the system-wide impacts of potential 

state plan approaches. In addition, as the state implements its 

plan, ISO/RTO analytic support would allow the state to monitor 

the effects of its plan on the regional electricity system. 

ISO/RTO analytic capability could help states assure that their 

plans are consistent with region-wide system reliability. The 

ISO/RTO Council suggested that the EPA ask states to consult 

with the applicable ISO/RTO in developing their state plans. 

The EPA has met with the U.S. Department of Agriculture as 

well to discuss how we can address the concerns of small 

isolated power generators in rural America and especially the 

electric cooperatives. Many of these entities have special 

challenges, as they may have small, older carbon-intensive 

assets and might have particular challenges meeting carbon 

requirements. 

Comment [A63]: Can EPA please explain 

why comment is no longer requested on this 

suggestion? In earlier comments, it was 

suggested that EPA expand comment here. 
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With all of this in mind, the EPA in determining the BSER 

looked specifically at the cost effectiveness of control options 

in part to ensure that the options would not have a negative 

effect on system reliability. Each of the building blocks was 

determined to have reasonable costs. Further, under the Clean 

Air Act the states are given the flexibility to design state 

plans that include any measure or combination of measures to 

achieve the required emission limitations. States are not 

required to use each of the measures that the EPA determines 

constitute BSER or use those measures to the same degree or 

extent that the EPA determines is achievable at a reasonable 

cost. Thus, each state has the flexibility to choose measures 

that are cost effective given that state’s energy profile and 

economy, as long as the state achieves the reductions necessary 

to meet its goal. Many market-based approaches which states may 

choose reduce the costs of compliance. They can allow certain 

units that are seldom used to remain in operation if they are 

needed for reliability purposes. Regional approaches also reduce 

costs and stress on the grid and so can help to reduce any 

concern about electricity reliability. 

States may choose measures that would ease pressures on 

system reliability. This is true for many demand-side management 

Formatted: Highlight
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approaches, including programs to encourage end-use energy 

efficiency, distributed generation, and combined heat and power, 

which actually reduce demand for centrally generated power and 

thus relieve pressure on the grid. 

The EPA is proposing a 10-year period over which to achieve 

the full required CO2 reductions, and we would expect this to 

further relieve any pressure on grid reliability. This 

relatively long planning and implementation period provides 

states with substantial flexibility regarding methods and timing 

of achieving emission reductions. In addition, states can make 

adjustments to their implementation approaches along the way, 

and in doing so can consider changed conditions and whether any 

adjustments would help to ensure that their plans achieve the 

goals without jeopardizing the grid. 

The EPA’s supporting analysis for this rule includes an 

examination of the effects of the rule on regional resource 

adequacy. The EPA’s analysis looked at the types of changes in 

the generation fleet that were projected to occur through 

retirements, additional generation and energy efficiency. The 

analysis did not raise concerns over regional resource adequacy. 

The EPA further examined how the policy options impacted the 

flows and transfers of electricity that occur to meet reserve 
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margins. None of the interregional changes in the policy cases 

suggested that there would be increases in flows that would 

raise significant concerns about grid congestion or grid 

management. Moreover, the time horizon for compliance with this 

rule will permit environmental and reliability planners to 

coordinate these changes and address potential concerns before 

they arise. 

The EPA concludes that the proposed rule will not raise 

significant concerns over regional resource adequacy or raise 

the potential for interregional grid problems. The EPA believes 

that any remaining local issues can be managed through standard 

reliability planning processes. The flexibility inherent in the 

rule is responsive to the CAA’s recognition that state plans for 

emission reduction can, and must, be consistent with a vibrant 

and growing economy and reliable, affordable electricity to 

support that economy. The EPA welcomes comments and suggestions 

on this issue. 

VIII. State Plans 

A. Overview 
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After the EPA establishes the state-specific rate-based CO2

goals in the emission guidelines, as described in Section VII 

above, each state must then develop, adopt, and submit its state 

plan under CAA section 111(d). To do so, the state must first 

determine the emission performance level it will include in its 

plan, which entails deciding whether it will adopt the ratebased CO2 goal set by the EPA or translate the rate-based goal to 

a mass-based goal. 

The state must then establish a standard of performance or 

set of standards of performance, along with implementing and 

enforcing measures, that will achieve a level of emission 

performance that is equal to or better than the level specified 

in the state plan. 

The state must then adopt the state plan through certain 

procedures, which include a state hearing. Within the time 

period specified in the emission guidelines (from as early as 

June 30, 2016 to as late as June 30, 2018, depending on the 

state’s circumstances), the state must submit its complete state 

plan to the EPA. The EPA then must determine whether to approve 

or disapprove the plan. If a state does not submit a plan, or if 

the EPA does not approve a state’s plan, then the EPA must 

establish a plan for the state. 

Formatted: Highlight
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In the case of a tribe that has one or more affected EGUs 

located in its area of Indian country, as described in the 

Tribal Authority Rule, the tribe would have the opportunity, but 

not the obligation, to establish a CO2 performance standard and 

develop a CAA section 111(d) plan for its area of Indian 

country. The CAA allows the EPA to treat tribes “in the same 

manner as states” for the purpose of implementing CAA programs, 

while providing flexibility for tribes to develop a program 

tailored to their specific circumstances. A tribe that develops 

a CAA section 111(d) tribal plan will actively contribute to 

helping reduce greenhouse gas emissions. Though the EPA is aware 

of three coal-fired EGUs and one natural gas-fired EGU located 

in Indian country, the agency is not proposing specific goals 

for areas of Indian country containing affected EGUs in this 

action. The EPA will coordinate with those tribes wishing to 

develop and implement a CAA section 111(d) tribal plan by 

determining BSER for the CAA section 111(d) affected units 

located on the tribe’s area of Indian country. As an 

alternative, the EPA is soliciting comment on whether tribes 

wishing to develop and implement a CAA section 111(d) plan 

should have the option of including the EGUs located on their 

area of Indian country in a multi-state plan (i.e., treating the 
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tribal lands as an additional state).). If a tribe chooses not 

to submit a plan, or if the EPA does not approve a tribe’s plan, 

then the EPA would need to determine if it is necessary or 

appropriate to establish a federal plan for affected EGUs 

located in Indian country. 

This section is organized into six parts. First, we discuss 

the types of plans that we propose states could submit. Second, 

we address timing for plan implementation and achievement of 

state emission performance goals for affected EGUs. Third, we 

discuss the proposed state plan approvability criteria. Fourth, 

we summarize the proposed components of an approvable state 

plan. Fifth, we address the proposed process and timing for 

submittal of state plans. Sixth, we identify several key 

considerations for states in developing and implementing plans, 

including: affected entities with obligations under a plan; 

treatment of existing state programs; incorporation of renewable 

energy (RE) and demand-side energy efficiency (EE) programs in 

certain plans; quantification, monitoring, and verification of 

RE and demand-side EE measures; reporting and recordkeeping for 

responsible parties; treatment of interstate effects; and, 

projecting emission performance. Finally, we discuss a number of 

additional factors that could help states meet their CO2 emission 

Comment [A64]: EPA should clarify or take 

comment on whether a tribe and a state by 

themselves can form a multi-state plan. 
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performance goals, and we note certain resources that are 

available to facilitate plan development and implementation. 

Additional discussion of some of the topics covered in this 

section can be found in the State Plan Considerations TSD and 

Projecting EGU CO2 Emission Performance in State Plans TSD, both 

of which are in the rulemaking docket. 

B. Approach 

 In this action, the EPA is proposing emission guidelines in 

the form of state-specific CO2 emission performance goals. In 

addition, the EPA is proposing guidelines for states to follow 

in developing plans to establish and implement CO2 standards of 

performance for affected EGUs. The proposed plan guidelines 

include four general plan approvability criteria, twelve 

required components for a state plan to be approvable, the 

process and timing for state plan submittal and review, and the 

process and timing for demonstrating achievement of the CO2 goal. 

These are described below. 

The EPA recognizes that each state has different state 

policy considerations – including varying emission reduction 

opportunities and existing state programs and measures – and 

that the characteristics of the electricity system in each state 

(e.g., utility regulatory structure, generation mix, electricity 
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demand) also differ. The agency also anticipates – and supports 

– states’ commitments to a wide range of policy preferences that 

could encompass those of states like Kentucky. West Virginia and 

Wyoming seeking to continue to feature significant reliance on 

coal-based generation, states like Minnesota, Colorado, 

California and the nine RGGI states seeking to build on actions 

and policies they have already undertaken, and states like 

Washington and Oregon seeking to integrate sustainable forestry 

and renewable energy strategies. The proposed plan guidelines 

provide states with options for establishing performance 

standards in a manner that accommodates a diverse range of state 

approaches. Each state will be able to determine how to best 

achieve the CO2 goals in light of its specific circumstances, 

including addressing concerns particular to the state, such as 

employment transition issues, as they design and implement their 

plans over multiple years. As an example, the RGGI states’ 

implementation of their mass-based allowance trading program 

featured the raising of proceeds through allowance auctions and 

the use of those proceeds to advance policies promoting and 

expanding end-use energy efficiency. States could address 

analogous priorities, such as employment transition, through a 

similar mechanism. 
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The proposed plan guidelines would also allow states to 

collaborate and to develop plans that provide for demonstration 

of emission performance on a multi-state basis, in recognition 

of the fact that electricity is transmitted across state lines, 

and that state measures may impact, and may be explicitly 

designed to reduce, regional EGU CO2 emissions. The EPA also 

recognizes that multi-state collaboration would likely offer 

lower-cost approaches to achieving CO2 emission reductions. With 

this in mind, we are proposing to provide states with additional 

time to submit complete plans if they do so as part of a multistate plan, and we solicit comment on other potential mechanisms 

for fostering multi-state collaboration. 

1. State plan approaches 

a. Overview 

We believe that different types of state CAA section 111(d) 

plans could be constructed that make use of the diversity of 

measures that comprise the BSER.[add examples – RGGI, AB32,...]. 

Based on EPA’s outreach efforts, it is clear that states are 

considering different types of plans. 

Three important issues in the design of state plans 

include: whether the plan should require the affected EGUs to be 

subject to emission limits that assure that the emissions 

Comment [A65]: This statement could be 

interpreted as saying states can only use measures 

that are part of the BSER. Elsewhere EPA has been 

careful to clearly state a wider range of measures 

could be used for compliance, even if they are not 

part of BSER. This sentence should be amended to 

maintain clarity around that issue. 
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performance level is achieved, or instead, whether the plan 

could rely on measures, such as renewable energy (RE) or demandside energy-efficiency (EE), to assure the achievement of part 

of the emission performance level; 2) whether the responsibility 

for all of the measures other than emission limits should fall 

on the affected EGUs, or, instead, fall on entities other than 

affected EGUs; and 3) the fact that requiring all measures 

relied on to achieve the emission performance level to be 

included in the state plan renders those measures federally 

enforceable. These issues and the proposed approach are 

addressed in detail in the sections that follow. 

The EPA is proposing that all measures relied on to achieve 

the emission performance level be included in the state plan, 

and that inclusion in the state plan renders those measures 

federally enforceable. 

In light of current state programs, and of stakeholder 

expressions of concerns over those issues and legal 

considerations, the EPA is proposing to authorize states either 

to submit plans that hold the affected EGUs fully and solely 

responsible for achieving the emission performance level, or to 

submit plans that rely in part on measures imposed on entities 

other than affected EGUs to assure that at least part of that 
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level is achieved, as well as on affected EGUs for the balance 

of compliance. The EPA requests comment on this approach, as 

opposed to the approach under which state plans simply would be 

required to hold the affected EGUs fully and solely responsible 

for achieving the emission performance level. 

In addition, the EPA is soliciting comment on several other 

types of state plans that may assure the requisite level of 

emission performance without rendering certain types of measures 

federally enforceable and to limit the obligations of the 

affected EGUs. 

b. Portfolio approach 

 In assessing the types of state plans to authorize, the EPA 

reviewed existing state programs designed to reduce CO2 emissions 

from fossil fuel-fired power plants. Existing state programs are 

particularly informative for this purpose in light of the fact 

that section 111(d) gives states the primary responsibility for 

designing their own state plans for submission to the EPA. Many 

of these existing state programs, as summarized above, include 

measures such as renewable energy (RE) and demand-side energy 

efficiency (EE) programs, which impose responsibilities on a 

range of entities, including state agencies, for assuring 

implementation of actions that result in reduced utilization of, 

Comment [A66]: What does this mean, esp. in 

relation to the prior paragraph? 
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and therefore reduced emissions from, fossil fuel-fired EGUs, 

and do not impose legal responsibilities for those emission 

reductions on the EGUs themselves. 

In addition, during the EPA’s extensive outreach efforts, 

many stakeholders expressed concern over the extent of 

responsibility that fossil fuel-fired EGUs would be required to 

bear for the required emission reductions, in particular, those 

associated with RE and demand-side EE measures. These 

stakeholders recommended that the EPA authorize states to 

achieve emission reductions from RE and demand-side EE measures 

by imposing requirements on entities other than fossil fuelfired EGUs, and without imposing legal responsibility for these 

emission reductions on those EGUs. We request comment generally 

on this approach.

 Accordingly, the EPA is proposing to authorize a state plan 

to adopt what we refer to as a “portfolio approach,” in which 

the plan would include emission limits for affected EGUs along 

with other enforceable measures, such as RE and demand-side EE 

measures, that reduce CO2 emissions. Under this approach, all of 

the measures combined would be designed to achieve the required 

emission performance level for affected EGUs. However, the 

emission limits enforceable against the affected EGUs would not, 
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on their own, assure achievement of the emission performance 

level. Rather, the state plan would include measures enforceable 

against other entities that support reduced generation by, and 

therefore CO2 emission reductions from, the affected EGUs. As 

noted, these other measures would be federally enforceable 

because they would be included in the state plan. A portfolio 

approach could be used for state plans that establish the 

emission performance level on either an emission rate basis or a 

mass emissions basis. 

In addition, a portfolio approach could either be what we 

refer to as ”utility-driven” or ”state-driven,” depending on the 

utility regulatory structure in a state. Under a utility-driven 

approach, a state plan may include, for example, measures 

implemented consistent with a utility integrated resource plan, 

including both measures that directly apply to affected EGUs 

(e.g., repowering or retirement of one or more EGUs) as well as 

RE and demand-side EE measures that avoid EGU CO2 emissions.226

Under a state-driven approach, the measures in a state plan 

would include emission limits for affected EGUs, as well as 

 

226 In the case of a utility-driven portfolio approach, the 

vertically integrated electric utility implementing portfolio 

measures is also the owner and operator of affected EGUs.
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requirements that apply directly to entities other than affected 

EGUs, for example, renewable portfolio standards or end-use 

energy efficiency resource standards (EERS), both of which often 

apply to electric distribution utilities.227

It should be evident that these plan approaches differ 

substantially in the mechanics used to achieve the required 

level of emission performance for affected EGUs, including 

necessary plan elements and the relative degree of plan 

complexity. The plan approaches also differ with regard to the 

entity or entities that are responsible for achievement of the 

required level of emission performance. As a result, a state may 

develop an approach for cost-effectively reducing EGU CO2

emissions that best suits its circumstances and may select 

whether elements of the state approach are enforceable 

components of a plan or complementary to an enforceable measure 

in a plan. 

c. Obligations on affected EGUs 

Although the EPA is proposing to authorize state plans to 

adopt the portfolio approach, we are mindful that it presents a 

 

227 A state-driven portfolio approach is more likely in states 

that have instituted electricity sector restructuring, where 

electric utilities have typically been required by states to 

divest electric generating assets. 
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legal issue that bears further analysis. We describe, and 

solicit comment on, that issue below. In brief, it may be 

possible to read CAA section 111(d)(1) as requiring that, when 

the EPA promulgates emission guidelines to achieve emission 

reductions from a particular source category, thereby triggering 

state obligations to adopt plans that include standards of 

performance as well as implementing and enforcing measures, the 

standards of performance must impose the responsibility for 

achieving the required emission reductions on the sources in the 

affected source category. Accordingly, as noted below, we are 

soliciting comment on whether state plans must require the 

affected EGUs to be legally responsible for achieving the 

emission performance level. 

We note that some existing state programs, such as RGGI in 

the northeastern states, do impose the ultimate responsibility 

on fossil fuel-fired EGUs to achieve the required reductions, 

but are also designed to work either concurrently, or in an 

integrated fashion, with RE and demand-side EE programs that 

reduce the cost of meeting those emission limitations. These 

existing programs offer a possible precedent for another type of 

CAA section 111(d) state plan. Such a plan approach could rely 

on CO2 emission limits enforceable against affected EGUs — 
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whether in the form of emission rates or mass limits — to ensure 

achievement of the required emission performance level, but also 

include enforceable or complementary RE and demand-side EE 

measures that lower cost and otherwise facilitate EGU emission 

reductions. Depending on the type of plan, these RE and demandside EE measures could be either enforceable components of the 

plan or complementary to the plan. In this manner, RE and 

demand-side EE measures could be a major component of a state’s 

overall strategy for reducing EGU CO2 emissions at a reasonable 

cost. 

It should be noted that state plans that impose legal 

responsibility on the affected EGUs to achieve the full level of 

required emissions performance could incorporate enforceable RE 

and demand-side EE measures regardless of whether the standards 

of performance that those plans apply to the affected EGUs take 

the form of an emissions rate or a mass limit. Plans with ratebased emission limits could incorporate enforceable RE and 

demand-side EE measures by adjusting an EGU’s CO2 emission rate 

when demonstrating compliance through either an administrative 

adjustment by the state or use of a tradable credit approach. 

(These actions would need to be enforceable components of a 

state plan to facilitate EGU compliance with emission rate 
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limits and ensure that actions are properly quantified, 

monitored, and verified.) A state plan that imposes a mass limit 

on affected EGUs that is sufficiently stringent to achieve the 

emission performance level would not need to include RE or 

demand-side EE measures as an enforceable component of the plan 

to assure the achievement of that performance level. The mass 

limit itself would suffice. However, the state may wish to 

implement RE and demand-side EE measures as a complement to the 

plan to support achievement of the mass limit at lesser cost. 

d. Federal enforceability 

 Another concern expressed by some stakeholders is that 

including RE and demand-side EE measures in state plans would 

render those measures federally enforceable and thereby extend 

federal presence into areas that, to date, largely have been the 

exclusive preserve of the state and, in particular, state public 

utility commissions and the electric utility companies they 

regulate. These stakeholders point out that states could rely on 

RE and demand-side EE programs as complementary measures to 

reduce costs for, and otherwise facilitate, EGU emission limits 

without including those measures in the CAA section 111(d) state 

plan. Under those circumstances, the EGU emission limits would 

be federally enforceable but RE and demand-side EE measures 
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would serve as complementary measures and would not be 

enforceable under federal law; instead, they would remain 

enforceable under state law. According to stakeholders, those 

types of state programs, particularly because they are wellestablished, can be expected to achieve their intended results. 

Thus, the states could conclude that those RE and demand-side EE 

measures would be beneficial in assuring the achievement of the 

required emission performance level by the affected EGUs 

specified in the CAA section 111(d) state plan, even without 

including those measures in the plan. 

e. Plans with state commitments 

As another vehicle for approving CAA section 111(d) plans 

for states that wish to rely on state RE and demand-side EE 

programs but do not wish to include those programs in their 

state plans, the EPA requests comment on what we refer to as a 

“state commitment approach.” This approach differs from the 

proposed portfolio approach, described above, in one major way: 

under the state commitment approach, the state requirements for 

entities other than affected EGUs would not be components of the 

state plan and therefore would not be federally enforceable. 

Instead, the state plan would include an enforceable commitment 

by the state itself to implement state-enforceable (but not 
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federally enforceable) measures that would achieve a specified 

portion of the required emission performance on behalf of 

affected EGUs. The agency requests comment on the 

appropriateness of this approach. The agency also requests 

comment on the policy ramifications of the following: under this 

approach, the state programs upon which the state bases its 

commitment may, in turn, rely on compliance by third parties, 

and if those state programs fail to achieve the expected 

emission reductions, the state could be subject to challenges – 

including by citizen groups – for violating CAA requirements 

and, as a result, could be held liable for CAA penalties. 

We also solicit comment on a variation of this state 

commitment plan approach that is also designed to address 

stakeholder concerns, noted above, about imposing legal 

responsibility on affected EGUs for ensuring the emissions 

performance level. With this variation, the state plan would in 

effect shift a portion of that responsibility to the state, in 

the following manner: the state plan would impose the full 

responsibility for achieving the emission performance level on 

the affected EGUs, but the state would credit the EGUs with the 

amount of emission reductions expected to be achieved from, for 

example, RE or demand-side EE measures. The state would then 
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assume responsibility for that credited amount of emission 

reductions in the same manner as the state commitment plan 

approach discussed above. We solicit comment on whether, if the 

EPA were to conclude that CAA section 111(d) requires state 

plans to include standards of performance applicable to affected 

EGUs that achieve the emission performance level, this type of 

state plan would meet that requirement while also assuring those 

EGUs an important measure of support. 

f. Legal issues 

[NOTE: PER THE ADMINISTRATOR’S REQUEST, OGC HAS EXPANDED 

THE DISCUSSION OF THE POSSIBLE LEGAL INTERPRETATIONS OF 111(d). 

OGC IS CONTINUING TO WORK ON SEVERAL ASPECTS OF THIS. FURTHER 

DISCUSSIONS ON TONE MAY BE NEEDED.] The EPA is required to 

promulgate emission guidelines for state plans to address 

emissions from sources in a source category for which the EPA 

has promulgated requirements under CAA section 111(b). CAA 

section 111(d)(1) requires that the state plans “(A) establish[] 

standards of performance for any existing source [for certain 

air pollutants] . . . and (B) provide[] for the implementation 

and enforcement of such standards of performance.” CAA section 

111(a)(1) defines a “standard of performance” as “a standard for 

emissions of air pollutants which reflects the degree of 
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emission limitation achievable through the application of the 

best system of emission reduction ... adequately demonstrated.” 

These provisions make clear that emission limits that are 

enforceable against affected EGUs appropriately belong in state 

plans because they clearly are “standards of performance.” 

However, important issues with respect to the portfolio approach 

discussed in this proposed rulemaking concern (1) whether, in 

addition to such emission limits on affected EGUs, state plans 

may include other measures for achieving the emission 

performance level, and (2) whether entities other than affected 

EGUs may be subject to requirements that contribute to reducing 

EGU emissions. We discuss these issues below, and, in doing so, 

solicit comment on possible interpretations that we could adopt 

as a basis for the portfolio approach. 

The resolution of these issues depends in part on the 

threshold question of whether the phrases “standards of 

performance for any existing source” and “the implementation and 

enforcement of such standards of performance” can be read to 

encompass the various components of the portfolio approach. In 

looking at this threshold question, we solicit comment on 

interpreting the phrases “standards of performance” and 

“implementation and enforcement of such standards” in CAA 
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section 111(d) to authorize the portfolio approach described 

above. CAA section 111(d) requires states to set performance 

standards “for” affected sources. Standards could be interpreted 

to be “for” fossil fuel-fired EGUs if they were to result in 

reduced emissions from fossil fuel-fired EGUs, even if the 

standards did not apply directly to fossil fuel-fired EGUs. 

Under this interpretation, renewable energy and demand-side 

energy efficiency requirements could be standards “for” existing 

EGUs. Implementation and enforcement measures could also be 

interpreted to include measures such as RE and demand-side EE 

that reduce emissions from fossil fuel-fired plants. We request 

comment on these interpretations, as well as the following 

specific issues. 

First, we solicit comment on whether the definition in CAA 

section 111(a)(1) could be interpreted so that standards of 

performance could include measures that are not enforceable 

against the affected EGUs or whether it must be interpreted so 

that the standards of performance may only consist of emission 

limitations on affected sources and must achieve the full degree 

of emission limitation that results from application of BSER. 

Second, we solicit comment on whether the requirement that 

the plan include “standards of performance for [affected 
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sources]” could be interpreted to include the emission 

performance level – that is, the adjusted, average emission rate 

for affected EGUs in the state – on grounds that the level is “a 

standard for emissions” because it is in the nature of a 

requirement that concerns emissions and it is “for” the affected 

sources because it helps determine their obligations under the 

plan. Interpreting the requirement in this manner could provide 

a basis for the portfolio approach because RE and demand-side EE 

measures could be considered measures that implement the 

emission performance level. 

Third, we solicit comment on whether the requirement that 

the plan include “standards of performance for [affected 

sources]” could be interpreted to include measures such as RE 

and demand-side EE measures, even if they may not directly 

reduce emission rates of the affected EGUs or are not 

enforceable against the affected EGUs, on grounds that they 

indirectly reduce CO2 emissions from affected EGUs. 

Fourth, the EPA is soliciting comment on whether measures 

such as RE and demand-side EE measures, even if they are not 

enforceable against the affected EGUs, may be included in the 

state plan as measures that “implement[] and enforce[]” the 

plan’s standards of performance. For example, if the plan 
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achieves the emission performance level through rate-based 

emission limits applicable to the affected sources, coupled with 

a crediting mechanism for RE and demand-side EE measures, it may 

be argued that RE and demand-side EE measures may be included in 

the plan as “implement[ing]” measures because they facilitate 

the sources’ compliance with their standards of performance. We 

solicit comment on whether measures such as RE and demand-side 

EE may be considered “implement[ing]” measures in state plans if 

they are not directly tied to emission reductions that affected 

sources are required to make through emission limits. 

Fifth, the EPA solicits comment on whether state plans may 

include, either as standards of performance or as 

“implement[ing]” measures, requirements on entities other than 

the affected sources. 

Finally, in light of these legal issues, we solicit comment 

on whether, in the final rule, we should authorize different 

approaches in the alternative. For example, we could authorize 

the portfolio approach, but further provide that if legal 

challenges were successful, then, without the need for further 

notice-and-comment rulemaking by the EPA, states would be 

required to submit plans that achieve the emission performance 

level through emission limits on the affected sources. It should 
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be noted that we consider those two approaches, as well as the 

other approaches for which we solicit comment, to be severable 

from each other. 

Alternatively, the EPA acknowledges that commenters may 

argue that the conclusion to the threshold question is that the 

components of the portfolio approach are not all within the 

scope of “standards of performance for any existing source” 

and/or “the implementation and enforcement of such standards of 

performance.” In that case, the question becomes whether CAA 

section 111(d)(1) could be read to allow state plans to include 

the components of the portfolio approach because they are 

measures that would reduce emissions from affected sources, even 

if those measures are neither “standards of performance for 

existing sources” nor measures “for the implementation and 

enforcement of such standards of performance.” If not, must the 

agency interpret CAA section 111(d) to prohibit state plans from 

including measures that are neither standards of performance nor 

measures to implement or enforce them? No specific language in 

CAA section 111(d) prohibits states from including measures 

other than performance standards and implementation and 

enforcement measures. EPA specifically requests comment on 

whether there is any other basis for concluding that CAA section 
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111(d) allows or precludes state plans from including other 

measures provided that they would result in the reduction of 

emissions from existing sources. The EPA notes that cooperative 

federalism, which is one of the foundational principles of the 

Clean Air Act, includes providing flexibility to states to meet 

environmental goals (provided minimum CAA statutory requirements 

are met). The EPA takes comment on whether this general 

principle, especially when combined with the statutory directive 

that CAA section 111(d) regulations shall establish procedures 

“similar to that provided by section 110” supports an 

interpretation of CAA section 111(d) that allows states 

sufficient flexibility in meeting CAA section 111(d) to include 

in their CAA section 111(d) plans other measures (i.e., measures 

that are neither performance standards nor measures that enforce 

or implement performance standards). Finally, the EPA solicits 

comment on all other aspects of this question concerning the 

scope of measures allowed in state plans under CAA section 

111(d). 

Notwithstanding the specific requests for comment above, 

the EPA solicits comment on all legal issues under CAA section 

111(d)(1) with respect to the portfolio approach and the types 

of state plans and measures that are discussed in this preamble. 
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g. Ongoing applicability of CAA section 111(d) state plan 

The EPA is proposing that an existing source that becomes 

subject to requirements under CAA section 111(d) will continue 

to be subject to those requirements even after it undertakes a 

modification or reconstruction. Under this interpretation, a 

modified or reconstructed source would be subject to both (1) 

the CAA section 111(d) requirements that it had previously been 

subject to and (2) the modified source or reconstructed source 

standard being promulgated under CAA section 111(b) 

simultaneously with this rulemaking. It should be noted that 

this proposal applies to any existing source subject to any CAA 

section 111(d) plan, and not only existing sources subject to 

the CAA section 111(d) plans promulgated under this rulemaking. 

As noted above, a “new source” is defined under CAA section 

111(a)(2) as “any stationary source, the construction or 

modification of which is commenced after,” in general, a 

proposed or final CAA section 111(b) rule becomes applicable to 

that source; and under section 111(a)(6), an “existing source” 

is defined as “any stationary source other than a new source.” 

Under these definitions, an “existing source” that commences 

construction of a modification or reconstruction after the EPA 

has proposed or finalized a CAA section 111(b) standard of 
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performance applicable to it, becomes a “new source.” However, 

CAA section 111(d) is silent on whether requirements imposed 

under a CAA section 111(d) plan continue for a source that 

ceases to be an existing source because it modifies or 

reconstructs. For example, CAA section 111(d) provides that the 

state plans will “establish[] standards of performance for any 

existing source” but does not say whether, once a standard of 

performance is established for a given source, that standard is 

lifted if the source ceases to be an existing source. Similarly, 

no other provisions of CAA section 111 address whether the 

imposition of a CAA section 111(b) standard on a modified or 

reconstructed source ends the source’s obligation to meet any 

applicable CAA section 111(d) requirements. 

Because CAA section 111(d) does not address whether an 

existing source that is subject to a CAA section 111(d) program 

remains subject that program even after it modifies or 

reconstructs, the EPA has authority to provide a reasonable 

interpretation, under the Supreme Court’s decision in Chevron 

U.S.A. Inc. v NRDC, 467 U.S. 837, 842-844 (1984). The EPA’s 

interpretation is that under these circumstances, the source 

remains subject to the CAA section 111(d) plan, for two reasons. 

The first is to assure the integrity of the CAA section 111(d) 
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plan. The EPA believes that many States will develop integrated 

plans that include all of their EGUs, such as rate- or massbased trading programs. Uncertainty about whether units would 

remain in the program could be very disruptive to the operation 

of the program. The second reason is to avoid creating 

incentives for sources to seek to avoid their obligations under 

a CAA section 111(d) plan by undertaking modifications. The EPA 

is concerned that owners or operators of units might have 

incentives to modify purely because of potential discrepancies 

in the stringency of the two programs, which would undermine the 

emission reduction goals of CAA section 111(d). The EPA invites 

comments on this interpretation, including whether this 

interpretation is supported by the statutory text and whether 

this interpretation is sensible policy and will further the 

goals of the statute. 

2. Timing for implementation and achievement of goals 

 This section describes proposed state plan requirements 

related to the timing of achieving emission performance goals, 

including performance demonstrations, performance periods, and 

interim progress milestones. 

As previously discussed, the goals are derived from 

application of four “building blocks.” The EPA has based the 
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application of some of these measures to reduce CO2 emissions, 

particularly blocks 3 (expansion of cleaner generating capacity) 

and 4 (increasing demand-side energy efficiency), on forwardlooking, longer-term assumptions. For example, the EPA expects 

technologies to reduce carbon emissions to more fully develop 

over time and acknowledges the cumulative effects of 

implementation of EE programs and addition of RE generating 

capacity over time. Therefore, the EPA is not proposing to 

require each state to meet its full, final goal immediately, but 

rather to meet it by 2030. The EPA realizes, however, that 

states can achieve emission reductions from those and other 

measures in the short-term. Therefore, the EPA is proposing that 

states begin meeting interim goals, beginning in 2020. The EPA 

also believes that timing flexibility in implementing measures 

provides significant benefits that allow states to develop plans 

that will help states achieve a number of goals, including: 

reducing cost, addressing reliability concerns, and addressing 

concerns about stranded assets. Therefore, the EPA is also 

proposing to allow states flexibility to define the trajectory 

of emission performance between 2020 and 2029, as long as the 

interim emission performance level is met on a 10-year average 

or cumulative basis and the 2030 emission performance level is 
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achieved. The EPA is also proposing that states submitting 

complete plans by June 30, 2016 have the option to begin meeting 

interim goals earlier than 2020 and that the average emission 

performance through 2029 could reflect a higher emission rate 

reflective of the longer trajectory for achievement of the final 

CO2 goal by 2030. 

 The subsections below contain proposals for: a) state plan 

performance demonstrations, b) the start date for the interim 

goal performance period, c) the duration of the performance 

periods for the final and interim goals, d) interim progress 

milestone requirements, and e) out-year requirements for states 

to maintain over time CO2 emission performance levels consistent 

with the final goal. In subsection f, the agency requests 

comment on alternative requirements aimed at continued emission 

performance improvement after 2029. Subsection g proposes 

flexibility for states to change from mass-based to rate-based 

goals in different performance periods, and subsection [VII.G] 

takes comment on planning requirements that match the option of 

alternative, less stringent state goals. 

a. Performance demonstrations 

 As described previously, the agency is proposing final 

state-specific goals (specified in Table 5) that represent 
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emission rates to be achieved by 2030, as well as interim goals, 

to be achieved on average over the 10-year period from 2020-

2029. The agency is also proposing that emission performance 

levels consistent with the final state-specific goals be 

maintained after 2030. 

 This relatively long planning and implementation period 

provides states with substantial flexibility regarding methods 

and timing of achieving emission reductions. States may wish to 

make adjustments to their implementation approaches along the 

way, or as conditions change may need to make adjustments to 

ensure that their plans achieve the goals as intended. As a 

result, the agency envisions that the EPA, states, and regulated 

entities will have an ongoing relationship in the course of 

implementing this program. 

 The EPA proposes that a state plan must demonstrate 

projected achievement of the emission performance levels in the 

plan, and these emission performance levels must be equivalent 

to or better than the interim and final goals established by the 

EPA. Specifically, the state plan must demonstrate that the 

projected emission performance level of affected EGUs in the 

state will be equivalent to or better than the applicable 

interim goal during the 2020-2029 period, and equivalent to or 
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better than the applicable final goal during the year 2030. The 

state plan must identify requirements that continue to apply 

after 2030 and are likely to maintain continued emission 

performance by affected EGUs that meets the final goal; however, 

quantitative projections of emission performance by affected 

EGUs beyond 2030 would not be required. Instead, the EPA 

proposes that the state plan would be considered to provide for 

maintenance of emission performance consistent with the final 

goal if the plan measures used to demonstrate achievement of the 

final goal by 2030 will continue in force and not sunset. 

 In addition to demonstrating that projected plan 

performance will meet the interim and final state goals, the EPA 

proposes that state plans must contain requirements for tracking 

actual plan performance during implementation. For plans that do 

not include enforceable requirements for affected EGUs that 

ensure achievement of the full level of required emission 

performance and interim progress, the state plan would be 

required to include periodic program implementation milestones 

and emission performance checks, and include corrective measures 

to be implemented if mid-course corrections are necessary. The 

state plan would provide for continued tracking of emission 

performance after 2030, and for corrective measures if the 

Formatted: Highlight
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emission performance of affected EGUs in the state did not 

continue to meet the 2030 final goal during any three-year 

performance period. 

 The rationale for this approach is that it would ensure 

that states design their plans in a way that considers both the 

interim and final goals. If only the interim goal were 

considered, a state plan might not be sufficient to achieve the 

final goal.228 

 The agency requests comment on a second option in which, in 

addition to submitting a plan demonstrating emission performance 

over the 2020-2030 period, states would be required to make a 

second submittal in 2025 showing whether their plan measures 

would maintain the final-goal level of emission performance over 

time (under one of the out-year approaches described in the 

relevant section below). If not, the state submittal would be 

 

228 The 2020-2029 interim goal is expressed as a 10-year average 

emission rate to provide states with flexibility in designing 

their plans. Due to the potential for continued end-use energy 

efficiency improvements, the 2029 BSER-based level is a more 

stringent level than the 2020-2029 average BSER-based level. The 

purpose of the final goal to be achieved and maintained is to 

ensure that each state ultimately achieves the emission 

performance level for affected EGUs that is achievable by 2029 

through application of BSER. Depending on the emission 

performance improvement trajectory required by a state plan, a 

state plan that will achieve the 2020-2029 interim goal may or 

may not also result in meeting the 2030 final goal.
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required to strengthen or add to measures in the state plan to 

the extent necessary to maintain that level of performance over 

time. 

 The EPA also requests comment on whether 2025, or an 

earlier or later year, would be the optimal year for a second 

plan submittal under the second option. 

b. Start date for performance period for interim goal 

 A performance period is a period for which the state plan 

must demonstrate that the required emission performance level 

will be met. The EPA proposes a start date of January 2020 for 

the interim goal plan performance period.229 The agency generally 

requests comment on the appropriate start date and rationale. 

In considering the start date, it is relevant to consider 

the due dates for state plan submittals and the amount of time 

available for program implementation by the start date. January 

2020 is 3.5 years from the proposed June 2016 deadline for 

initial plan submittals, 2.5 years from the proposed June 2017 

extended deadline for complete plans from states not 

 

229 The start date for a plan performance period must match the 

start date of the corresponding state emission performance goal. 

If a start date other than January 2020 were selected, the EPA 

would recompute the state goals consistent with the selected 

start date.
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participating in a multi-state plan, and 1.5 years from the 

proposed June 2018 extended deadline for complete plans from 

states participating in a multi-state plan. The EPA suggests 

that affected entities may have greater lead time for compliance 

than might be implied by the plan submittal dates referenced 

above. Affected entities will have knowledge of state 

requirements as they are adopted, and the state must adopt rules 

and requirements in advance of submitting its complete plan to 

the EPA. Also, as explained in detail in subsection c, states 

may choose a different emission performance improvement 

trajectory from that which the EPA assumes for purposes of 

calculating state goals, achieving lesser levels of performance 

in early years and more in later years. 

The EPA proposes that a 2020 start date for the interim 

goal plan performance period is achievable in light of the 

following additional considerations. First, existing state 

programs will play a role in helping to achieve this rule’s 

proposed emission performance levels. Second, in advance of this 

proposal, many states already were contemplating design of 

strategies that would achieve CO2 reductions equivalent to those 

that could be required by CAA section 111(d) emission 

guidelines. Third, for inclusion in the building blocks, the EPA 
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considered only those emission abatement measures that are 

technically feasible and broadly applicable, and can provide 

reductions in CO2 emissions from affected EGUs at reasonable 

cost. 

For example, the EPA expects that many EGUs will meet their 

requirements in part by implementing heat rate improvements, and 

those actions may be undertaken promptly. The plant operations 

and maintenance (O&M) and engineered solutions used to improve 

heat rates at existing EGUs have long been commercially 

available and have been implemented at EGUs for many years. 

Further, the relatively modest capital costs (average $100/kW) 

and significant fuel savings associated with a suite of heat 

rate improvement (HRI) methods result in this measure being a 

low-cost approach to reducing CO2 emissions from existing EGUs. 

HRI “best practices” (e.g., installation of modern control 

systems, operator training, smart soot blowing) are the leastcost HRI methods and can be applied quickly, without lengthy EGU 

outages. The somewhat more costly HRI “upgrades” (e.g., steam 

turbine upgrade, boiler draft fan/driver upgrade) may require 

modest EGU outages to implement, but have also been applied on 

numerous EGUs to improve or maintain performance. Drawing on the 

power sector’s extensive experience with HRI methods, and the 
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many existing supply chains already supporting these methods, 

the EPA expects that it would be feasible to implement HRI 

projects (i.e., building block 1) by 2020. 

Dispatch changes, which are largely driven by the variable 

cost of operating a given EGU, occur on an hourly basis in the 

power sector. The average availability factor for NGCCs in the 

U.S. generally exceeds 85 percent, and can exceed 90 percent for 

selected groups230. In addition, the existing natural gas 

pipeline and electricity transmission networks are already 

connected to every existing NGCC facility, and can support 

aggregate operation of the NGCC fleet at 70 percent (or above) 

at the state level, or can be reasonably expected to do so in 

the time frame for compliance with this rule. Therefore, 

building block 2, which represents shifting of generation from 

steam fossil EGUs to existing NGCCs, is a viable method for 

providing CO2 reductions at existing EGUs by the 2020 compliance 

start date. 

Building Block 3 is based on shifting generation from 

affected fossil units to new renewable energy generating 

capacity, which is added over time, and new or preserved nuclear 

 

230 Source: NERC, 2008-2012 Generating Unit Statistical Brochure
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capacity, all of which is expected to be in place by 2020 (see 

the GHG Abatement Measures TSD for more information). 

Finally, there is considerable experience with the states 

and the power sector in designing and implementing demand-side 

energy efficiency improvement strategies and programs. It is 

also well accepted that such improvements can achieve reductions 

in CO2 emissions from existing EGUs at a reasonable cost. 

Building block 4 represents a feasible pathway for reducing 

utilization of carbon-emitting EGUs by implementing improvements 

in demand-side energy efficiency. This building block is based 

on a “best practices” scenario where all states achieve a level 

of performance – matching a level achieved or committed to by 

twelve leading states – of 1.5 percent annual incremental 

electricity savings as a percentage of retail sales. For the 

best practices scenario, all states achieve this level of 

performance no later than 2025, with leading states reaching 

this level sooner. Each state’s current level of performance is 

taken into account, with states achieving lower levels of 

performance being allowed more time to reach the best practice 

level. 

c. Duration of performance periods for final and interim goals 
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 The EPA recognizes that a state’s circumstances and choice 

of emission reduction strategies may affect the timing of CO2 

emission performance improvement within a multi-year planning 

period. States can be expected to select various combinations of 

measures and those measures may vary in the time needed to reach 

full implementation. The agency recognizes that certain emission 

reduction measures and programs (e.g., heat rate improvements) 

are generally easier to implement in the near term, while others 

(e.g., renewable portfolio standards, demand-side energy 

efficiency programs) may require several years to implement 

because of the time necessary to establish the proper 

infrastructure if a state does not already have such programs in 

place. Though some states have already implemented such programs 

that are achieving results, other states may have to establish 

them for the first time. New single and multi-state programs, as 

well as existing single and multi-state programs that are adding 

or revising measures, may need time for implementation to 

achieve the required level of emission performance. 

 As described in Section VII of the preamble, the EPA is 

proposing state-specific CO2 emission performance goals in a 

multi-year format to provide states with flexibility for the 

timing of programs and measures that improve EGU emission 

Comment [A67]: Some interagency commenters 

request EPA not singling out EE in this context 
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performance, while ensuring an overall level of performance 

consistent with the application of BSER. Specifically, the 

agency is proposing the state-specific goals (shown in Table 5) 

which represent emission rates to be achieved by 2030 (final 

goal) and emission rates to be achieved on average over the 

2020-2029 period (the interim goal). 

 The EPA proposes the following as the preferred option for 

the final and interim goal performance periods. As further 

explained below, this option reflects three main objectives: (1) 

provide states with timing flexibility during the interim goal 

period to accommodate differences in state adoption processes 

and types of state programs, (2) ensure that state plans are 

designed to achieve the final goal no later than 2030, and (3) 

provide flexibility for year-to-year variation in actual 

emission performance that may occur as the electricity system 

responds to economic fluctuations. 

Interim goal – Projected plan performance demonstration: To be 

approvable, a state plan must demonstrate that the emission 

performance of affected EGUs will meet the interim emission 

performance level on average over the 2020-2029 period. 

Interim goal – Actual plan performance check: In 2030, the 

emission performance of affected EGUs during the period 2020-
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2029 must be compared against the interim goal. (In addition, as 

described separately below, interim emission performance checks 

will occur during this 10-year period.) 

Final goal – Projected plan performance demonstration: To be 

approvable, a state plan must demonstrate that the emission 

performance of affected EGUs will meet the final emission 

performance level no later than 2030, on a single-year basis. 

Final goal – Actual plan performance check: Starting at the end 

of 2032, emission performance of affected EGUs must be compared 

against the final goal on a three-year rolling average basis 

(i.e., 2030-32, 2031-33, 2032-2034, etc.). 

 This proposed approach provides a 10-year performance 

period for the interim performance level. The 10-year period 

allows states flexibility for timing of program implementation 

as the state ramps up its programs to achieve the final 

performance level. Using the single year 2030 as the projected 

year for achievement of the final goal ensures that state plans 

are designed to achieve the final goal no later than 2030; 

providing a multi-year time frame for projected plan performance 

would inappropriately delay the requirement for a final-goal 

level of performance that the EPA’s analysis shows is achievable 

at the end of the 10-year interim ramp-up period. Using 2030 
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also avoids overlap with the interim goal performance period. 

The rolling three-year performance periods for measuring actual 

plan performance against the final goal performance level are 

proposed in light of year-to-year variability in economic and 

other factors, such as weather, that influence power system 

operation and affect EGU CO2 emissions. The choice of 2030-2032 

avoids overlap with the 2020-2029 interim goal performance 

period. 

 For a rate-based plan, 2020-2029 emission performance is an 

average CO2 emission rate for affected EGUs representing 

cumulative CO2 emissions for affected EGUs over the course of the 

10-year performance period divided by cumulative MWh energy 

output231 from affected EGUs over the 10-year performance period, 

with rate adjustments for qualifying end-use energy efficiency 

and renewable energy measures as described in Section VIII.F. 

For a mass-based plan, 2020-2029 emission performance is total 

tons of CO2 emitted by affected EGUs over the 10-year performance 

period. 

 

231 For EGUs that produce both electric energy output and other 

useful energy output, there would also be a credit for nonelectric output, expressed in MWh.
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 The EPA also requests comment on a second approach to state 

plan performance periods. Under this approach, in addition to 

the requirements the proposal, a state plan also would also need 

to achieve a five-year average emission performance level 

reflecting application of BSER for the 2020-2024 period. This 

five-year performance period would nest within the 10-year 

performance period for the 2020-2029 period. The purpose of this 

approach would be to ensure greater emission performance 

improvement during the first five years of the interim goal plan 

performance period by precluding states from significantly 

delaying compliance obligations until the last five years. 

However, this approach also would reduce states’ flexibility for 

the timing of emission improvements over the 2020-2029 period. 

 The agency invites comment on any other approaches to 

specifying performance periods for state plans. 

d. Program implementation milestones and tracking of emission 

performance 

 The EPA recognizes the importance of ensuring that, during 

the proposed 10-year performance period (2020-2029) for the 

interim goal, a state is making steady progress toward achieving 

the required level of emission performance. The EPA is proposing 

that certain types of state plans be required to have program 
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implementation milestones to ensure interim progress, as well as 

periodic checks on overall emission performance leading to 

corrective measures if necessary. 

 Some types of plans are “self-correcting” in that they 

inherently would assure interim performance and full achievement 

of the state plan’s required level of emission performance 

through requirements that are enforceable against affected EGUs. 

One example is a state plan with a rate-based emission 

performance level that requires affected EGUs collectively to 

meet, on a three-year average basis, an emission rate consistent 

with the state’s required emission performance level, and allows 

EGUs to comply through an emission rate averaging system. 

Another example is a plan that includes measures or actions 

(e.g., emission limits that apply to affected EGUs and ensure 

full plan performance) that take effect automatically if the 

plan’s required emission performance level is not met, in 

accordance with a specified milestone. The EPA requests comment 

on whether there are other types of state plans that should be 

considered “self-correcting.” 

 The EPA proposes that self-correcting plans need not 

contain interim milestones consisting of program implementation 

steps, because these state plans inherently require both interim 
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progress and achievement of the full level of required emission 

performance in a manner that is federally enforceable against 

affected EGUs. 

 For plans that are not self-correcting, the EPA proposes 

that the state plan must identify periodic program 

implementation milestones (e.g., start of an end-use energy 

efficiency program, retirement of an affected EGU, or increase 

in portfolio requirements under a renewable portfolio standard) 

that are appropriate to the programs and measures included in 

the plan. If, during plan implementation, a state were to miss 

program implementation milestones in its plan, it would need to 

report the delay to EPA, explain the cause, and describe the 

steps the state will take to accelerate subsequent 

implementation to achieve the planned improvements in emission 

performance. Depending on the severity of delay and the 

explanation, the EPA could ultimately evaluate actions under CAA 

authorities to ensure timely program implementation. 

 In addition, we propose that the state and the EPA would 

track state plan emission performance on an ongoing basis, with 

states reporting performance data to EPA annually by July 1. 

During the interim performance period, the state would be 

required to include a comparison of emission performance 
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achieved to performance projected in the state plan each year 

from the end of 2022 through the end of 2028. Each comparison 

would cover the preceding two-year period. The EPA may also 

approve regular, periodic emission comparison checks with a 

different frequency or comparison period to reflect the design 

of a state’s programs (e.g., compliance periods for EGUs under 

an emission limit). 

 If actual emission performance of affected EGU was not 

within 10 percent of plan projections, the state would be 

required in its submission to explain reasons for the deviation 

(e.g., energy efficiency program not working as effectively as 

expected, prolonged extreme weather that had been unanticipated 

in electricity demand projections) and specify the corrective 

measures that will be taken to ensure that the required level of 

emission performance in the plan will be met. The state also 

would be required to implement those corrective measures as 

expeditiously as practical. 

 The EPA proposes that the corrective measures to be 

triggered in case of an emission performance deficiency must be 

adopted as enforceable measures included in the original state 

plan. These previously adopted corrective measures would reduce 

the delay between the time an emission performance deficiency is 
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discovered, and the time that corrective action can begin. 

Alternatively, the agency requests comment on whether states 

should be allowed to identify and adopt corrective measures 

after a performance deficiency is found. 

 At the end of the 2020-2029 performance period, the EPA 

proposes that the state be required to compare actual emission 

performance achieved during the performance period against the 

interim goal. As noted above, beginning after 2032, EPA proposes 

that the state be required to compare actual emission 

performance achieved against the final goal on a rolling threeyear average basis (e.g., 2030-32, 2031-33, etc.). 

 The EPA also requests comment on the milestone approach and 

emission performance checks outlined above in the context of 

Option B and the planning approach for alternative state goals, 

which is described below. 

e. Consequences if actual emission performance does not meet 

state goal 

 There are scenarios under which an approved state plan 

might fail to achieve a level of emission performance by 

affected EGUs that meets the state goal. Under some types of 

plans, a possible scenario is that despite successful plan 

implementation, emissions under the plan turn out to be higher 
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than projected at the time of plan approval because actual 

economic conditions vary from economic assumptions used when 

projecting emission performance. State officials have raised the 

possibility that achieved emission performance might not meet 

projected performance if, for example, planned retirements of 

EGUs were postponed because severe weather produced greaterthan-expected electricity generation needs. In addition, 

emissions could theoretically exceed projections because 

affected entities under a state plan did not fulfill their 

responsibilities, or because the state did not fulfill its 

responsibilities. 

 The EPA believes that the emission guidelines should 

specify the consequences in the event that actual emission 

performance under a state plan does not meet the applicable 

interim goal in 2020-2029, or does not meet the applicable final 

goal in 2030-2032 or later, because CAA section 111(d) is not 

specific on this point. The agency requests comment on how the 

consequences should vary depending on the reasons for a 

deficiency in performance. 

 Specifically, the agency requests comment on whether 

consequences should include the triggering of corrective 

measures in the state plan, or plan revisions to adjust 
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requirements or add new measures. The agency also requests 

comment on whether corrective measures, in addition to ensuring 

future achievement of the state goal, should be required to 

achieve additional emission reductions to offset any emission 

performance deficiency that occurred during a performance period 

for the interim or final goal. This concept has been applied, 

for example, in the acid rain sulfur dioxide program; a source 

that has sulfur dioxide emissions exceeding the emission 

allowances that it holds at the end of the period for 

demonstrating compliance is required subsequently to obtain 

additional emission reductions to offset its excess emissions. 

The agency also requests comment on the process for invoking 

requirements for implementation of corrective measures in 

response to a state plan performance deficiency. 

 The EPA further requests comment on whether the agency 

should promulgate a mechanism under CAA section 111(d) similar 

to the SIP call mechanism in CAA section 110. Under this 

approach, after the agency made a finding of the plan's failure 

to achieve the state goal during a performance period, EPA would 

require the state to cure the deficiency with a new plan within 

a specified period of time (e.g., 18 months). If the state still 

lacked an approved plan by the end of that time period, the EPA 
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would have the authority to promulgate a federal plan under 

section 111(d)(2)(A). 

f. Out-year requirements: Maintaining or improving the level of 

performance required by the final goal 

 The agency is determining state goals for affected EGU 

emission performance based on application of BSER during 

specified time periods. This raises the question of whether 

affected EGU emission performance should only be maintained -- 

or instead should be further improved -- once the final goal is 

met in 2030. This involves questions of goal-setting as well as 

questions about state planning. In this section, the EPA 

proposes that a state must maintain the required level of 

performance, and requests comment on the alternative of 

requiring continued improvement. 

 The EPA believes that Congress intended the emission 

performance improvements required under CAA section 111(d) to be 

permanent. Other CAA section 111(d) emission guidelines set 

emission limits to be met permanently. Therefore, the EPA is 

proposing that the level of emission performance for affected 

EGUs represented by the final goal should continue to be 

maintained in the years after 2030. The EPA is proposing a 
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mechanism for implementing this objective, and is taking comment 

on an alternative option. 

 As noted above, the EPA proposes that the state plan must 

demonstrate that plan measures are projected to achieve the 

final emission performance level by 2030. In addition, the state 

plan must identify requirements that continue to apply after 

2030 and are likely to maintain affected EGU emission 

performance meeting the final goal; however, quantitative 

projections of emission performance beyond 2030 would not be 

required under the proposed option. Instead, EPA proposes that 

the state plan would be considered to provide for maintenance of 

emission performance consistent with the final goal if the plan 

measures used to demonstrate projected achievement of the final 

goal by 2030 will continue in force and not sunset.232 After 

 

232 This is straightforward for plans with EGU emission limits 

that ensure the full level of performance required. For 

renewable energy programs, the agency suggests that the state 

could continue to require the renewable portfolio percentage 

level that was relied upon to demonstrate projected achievement 

of the final goal performance level in 2030. For plans that rely 

in part on end-use energy efficiency programs and measures, the 

EPA requests comment on what a state would need to require in 

its plan to show that performance will be maintained after 2030. 

End-use energy efficiency programs and measures often involve an 

annual energy savings requirement or goal, and some types 

require additional monetary expenditures each year to meet those 

savings requirements or goals. 
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implementation, the state would be required to compare actual 

plan performance against the final goal on a rolling three-year 

average basis starting in 2030, and to implement corrective 

measures if necessary. 

 The EPA also requests comment on an alternative approach to 

a state’s pre-implementation demonstration that the final-goal 

level of performance will be maintained after 2030. Under this 

alternative, the state plan would be required to include 

projections demonstrating that emission performance would 

continue to meet the final goal for up to 10 years beyond 2030). 

This approach could be implemented through a second round of 

state plan analysis and submittals in 2025 to make the 

demonstration and strengthen or add measures if necessary. The 

EPA generally requests comment on appropriate requirements to 

maintain the emission performance of affected EGUs in years 

after 2030. 

 The EPA also requests comment on whether we should 

establish BSER-based state emission performance goals for 

affected EGUs that extend further into the future (e.g., beyond 

the proposed planning period), and if so, what those levels of 

 
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improved performance should be. Under this alternative, the EPA 

would apply its goal-setting methodology based on application of 

BSER in 2030 and beyond to a specified time period and final 

date. The agency requests comment on the appropriate time 

period(s) and final year for the EPA’s calculation of state 

goals that reflect application of BSER under this approach. 

g. State flexibility to choose mass-based and rate-based goals 

after 2029 

 The EPA proposes that states have flexibility to choose 

between a rate-based and mass-based performance level for each 

performance period. For example, if a state plan used a massbased performance level for the 2020-2029 period, the state plan 

may still use a rate-based performance level for final goal 

performance periods, or vice versa. 

 A state that adopted a mass-based performance level for 

2020-2029 would have two options for addressing any perceived 

need for emissions flexibility in light of anticipated economic 

growth after 2029. The state either could adopt a rate-based 

performance level consistent with the final goal, or could adopt 

a new mass-based performance level based on a translation of the 

rate-based final goal to a mass-based goal. 

h. Planning approach for alternative state goals 
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 In Section VII, the EPA requests comment on alternative, 

five-year state emission performance goals for affected EGUs 

shown in Table 6. The alternative goals represent emission rates 

achievable on average during the 2020-2024 period, as well as 

emission rates to be achieved and maintained after 2024. These 

alternative goals are less stringent than the proposed goals in 

Table 5.

 To accompany the alternative goals, the EPA requests 

comment on another approach for state plan performance periods. 

This approach would require state plans to demonstrate that the 

required interim emission performance level will be met on 

average by affected EGUs during the five-year 2020-2024 interim 

period, and that the alternative final goal be met no later than 

2025. After plan implementation, actual emission performance 

would be compared with the alternative final goal on a threeyear rolling average basis, starting with 2025-2027, in light of 

year-to-year variability in economic and other factors, such as 

weather, that influence power system operation and affect EGU CO2

emissions. 

 In connection with the alternative state goals, for the 

years after 2027, the EPA requests comment on the same “outyear” issues and concepts for maintaining or improving emission 
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performance over time that are described above in subsection e. 

The EPA requests comment on whether state plans should provide 

for emission performance after 2025 solely through postimplementation emission checks that do not require a second plan 

submittal, or a whether states should also be required to make a 

second submittal prior to 2025 to demonstrate that its programs 

and measures are sufficient to maintain performance meeting the 

final goal for at least 10 years. In addition, the agency 

requests comment on the appropriate date for any second state 

plan submittal designed to maintain emission performance after 

the 2025 performance level is achieved. 

C. Criteria for Approving State Plans 

The EPA is proposing to require the twelve plan components 

discussed in Section VIII.D of this preamble. We will evaluate 

the sufficiency of each plan based on the plan addressing those 

components and on four general criteria for a state plan to be 

approvable. First, a state plan must contain enforceable 

measures that reduce EGU CO2 emissions. Second, these enforceable 

measures must be projected to achieve emission performance 

equivalent to the applicable state-specific CO2 goal on a 
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timeline equivalent to that in the emission guidelines.233 Third, 

EGU CO2 emission performance under the state plan must be 

quantifiable and verifiable. Fourth, the state plan must include 

a process for state reporting of plan implementation (at the 

level of the affected entity), verified CO2 emission performance 

outcomes, and implementation of corrective actions, if 

necessary. The EPA requests comments on all aspects of these 

general criteria and the ten specific plan components described 

below. 

The agency also notes that a CAA section 111(d) state plan 

is not a CAA section 110 state implementation plan 

(SIP). Although there are similarities in the two programs, 

approvability criteria for CAA section 111(d) plans need not be 

identical to approvability criteria for SIPs. 

1. Enforceable measures 

In developing its plan, to ensure that the plan is 

enforceable and in conformance with the CAA, a state should 

follow established EPA guidance on enforceability.234 This 

 

233 Flexibilities provided to states in meeting this general 

approvability criterion are discussed below in Section 

VIII.B.2., emission performance.

234 Enforceability guidance includes:(1) September 23, 1987 

memorandum and accompanying implementing guidance, “Review of 

Comment [A68]: Perhaps not necessary but 

useful to clarify that measures not only be verifiable, 

but also that outcomes from those measures actually 

be verified.
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guidance serves as the foundation for the types of emission 

limits that the EPA has found can be enforced as a practical 

matter and sets forth the general principle that a requirement 

that is enforceable as a practical matter is one that is 

quantifiable, verifiable, straightforward, and calculated over 

as short a term as reasonable. 

A state plan must include enforceable CO2 emission limits 

(either rate-based or mass-based) that apply to affected EGUs. 

As noted above, the EPA is proposing that a state plan may take 

a portfolio approach, which could include enforceable CO2

emission limits that apply to affected EGUs as well as other 

enforceable measures, such as RE and demand-side EE measures, 

that avoid EGU CO2 emissions and are implemented by the state or 

by another entity assigned responsibility by the state. As noted 

above, we are proposing that state plans are not required to 

impose emission limits on affected EGUs that in themselves fully 

achieve the emission performance level. However, we are seeking 

 

State Implementation Plans and Revisions for Enforceability and 

Legal Sufficiency,” (2) August 5, 2004 “Guidance on SIP Credits 

for Emission Reductions from Electric-Sector Energy Efficiency 

and Renewable Energy Measures,” and (3) July 2012 “Roadmap for 

Incorporating Energy Efficiency/Renewable Energy Policies and 

Programs into State and Tribal Implementation Plans, Appendix 

F.”
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comment on whether, for state plans where emission limits 

applicable to affected EGUs alone would not assure full 

achievement of the required level of emission performance, the 

state plan should include additional measures that would apply 

if any of the other portfolio of measures in the plan are not 

fully implemented, or if they are, but the plan fails to achieve 

the required level of emission performance.235 

The EPA recognizes that a portfolio approach may result in 

enforceable state plan obligations accruing to a diverse range 

of affected entities beyond affected EGUs, and that there may be 

challenges to practically enforcing against some such entities 

in the event of noncompliance. We request comment on all aspects 

associated with enforceability of a state plan and how to ensure 

compliance. We are also seeking comment on enforceability 

considerations under different state plan approaches, which is 

addressed below in VIII.F. 

2. Emission performance 

The second criterion for approvability is that the 

projected CO2 emission performance by affected EGUs (taking into 

 

235 This could include, for example, an expansion of the scope 

or an increase in stringency of the current measures in the 

plan, a second set of measures that avoid EGU CO2 emissions, or 

emissions limits that apply to affected EGUs.
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account the impacts of plan measures that are associated with 

reducing utilization from affected EGUs) must be equivalent to, 

or better than, the required CO2 emission performance level in 

the state plan. State plans that are projected to achieve an 

average CO2 emission rate (expressed in, for example, lb CO2/MWh) 

or tonnage CO2 emission outcome by all affected EGUs equal to, or 

lower than, the required level of CO2 emission performance in the 

plan would meet this approvability criterion. 

We are proposing that states may demonstrate such emission 

performance by affected EGUs either on an individual state basis 

or jointly on a multi-state basis. All of the emission reduction 

measures included in the agency’s determination of BSER reduce 

CO2 emissions from affected EGUs. As a result, the EPA is not 

proposing that out-of-sector GHG offsets couldcannot be applied 

to demonstrated CO2 emission performance by affected EGUs in a 

state plan. The EPA specifically seeks comment on alternatives 

to this proposal, including allowing the use of state plan 

components incorporating out-of-sector offsets financed by 

affected EGUs to comply with CO2 emission performance goals 

established by this rule

However, states could stillStates that include offsets for 

compliance in their plansplans’ emission limits for affected 

Comment [A69]: Suggested addition. 
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EGUs that include the abilitywill need to use GHG offsets for 

compliance, provided those emission limits would achieveremove 

offset reductions when assessing the required level of emission 

performance in a state plan. . All existing state emission 

budget trading programs addressing GHG emissions include out-ofsector project-based emission offsets, which may be used to 

cover a portion of the compliance obligation of affected 

sources. OtherWhile the EPA proposes to exclude the use of outof-sector GHG offsets to meet required levels of emission 

performance, other states may want to take a similar 

approachallow offsets in their state plans to, for example, to 

incentivize GHG emission reductions from land use and 

agricultural waste management. HowEPA requests comments on how

to address GHG offsets included in EGU emission limits when 

projecting emission performance under a state plan isas

addressed in the Projecting EGU CO2 Emission Performance in State 

Plans TSD. 

The ISO/RTO Council, an organization of electric grid 

operators, has suggested that ISOs and RTOs could play a 

facilitative role in developing and implementing region-wide, 

multi-state plans, or coordinated individual state 

plans. Existing ISOs and RTOs provide a structure for achieving 

Comment [A70]: The reasoning here and the 

proposal are not clear. States can’t include offsets in 

state plans but states can allow EGUs to use offsets 

to meet emission limits? Consider clarifying. 

Comment [A71]: This statement is confusing as 

drafted. It is designed to make it appear that offsets 

can be used for compliance with the Clean Air Act – 

when in fact, the opposite is true. EPA should make 

clear what they are proposing. See suggested edits. 
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efficiencies by coordinating the state plan approaches applied 

throughout a grid region. Just as the ISO/RTO regions today 

share the benefits and costs of efficient EGU dispatch across 

state boundaries, there are significant efficiencies that could 

be captured by coordinating individual state plans or 

implementing multi-state plans within a grid region. that could 

achieve significant carbon dioxide emission reductions at the 

lowest possible cost. Under one variant of this approach, states 

would implement a multi-state plan and jointly demonstrate CO2

emission performance by affected EGUs across the entire ISO/RTO 

footprint. States with borders that cross the boundary of one or 

more ISO or RTO footprints would need to include multiple plan 

components that address affected EGUs in each respective ISO or 

RTO. The EPA is seeking comment on this idea. In that manner 

the RTOs could implement an "emission constrained dispatch" 

algorithm in these power markets. That algorithm would include 

consideration of a power plant's carbon dioxide emissions into 

the regional plant dispatch algorithm, achieving a reduction in 

emissions at the lowest possible cost. If that algorithm were 

deployed across the entire RTO service area which spans several 

states, reductions in carbon dioxide emissions could be achieved 

efficiently. The EPA is seeking comment on this idea and others 
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that would use an RTO approach to demonstrate compliance at 

least cost. 

3. Quantifiable and verifiable emission performance 

The third criterion for approvability is that a state 

planspecifyplanspecifyplan specifyplanspecify how the effects of 

each state plan measure will be quantified and verified. At a 

minimum, the EPA proposes that all plans must specify how CO2

emissions from affected EGUs are monitored and reported. The EPA 

is proposing that both mass-based and rate-based plans must 

include CO2 emission monitoring, reporting, and recordkeeping 

requirements for affected EGUs, as specified in the emission 

guidelines. A rate-based plan must also include monitoring, 

reporting, and recordkeeping requirements for useful energy 

output from affected EGUs (electricity and useful thermal 

output), as specified in the emission guidelines. With one 

exception, these proposed requirements are consistent with those 

in the proposed EGU Carbon Pollution Standards for New Power 

Plants. See 79 FR 1430-1519 (January 8, 2014). The exception is 

that we are proposing that useful energy output be measured in 

terms of net output rather than gross output, as discussed 

below. 

Comment [A72]: Suggested addition. 
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For state plans that include other measures that avoid EGU 

CO2 emissions, such as RE and demand-side EE measures, the state 

will also need to include quantification, monitoring, and 

verification provisions in its plan for these measures, which 

may vary depending on the types of requirements included in the 

specific plan, as specified in the emission guidelines. This may 

include, for example, quantification, monitoring, and 

verification of RE generation and demand-side EE energy savings 

under a rate-based approach.236

4. Reporting and corrective actions 

The fourth criterion for approval is that a state plan (i) 

specify a process for periodic reporting to the EPA of overall 

plan performance and implementation (including compliance of 

affected entities with applicable standards of performance) 

during the plan period, and (ii) include a process and schedule 

for modification if reporting shows that the plan is not 

achieving the projected level of emission performance. We 

solicit comment on whether the latter process should include the 

 

236 Considerations for quantification, monitoring, and 

verification of RE and demand-side EE measures are addressed in 

Section VII.E of this preamble and in the State Plan 

Considerations TSD. 
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adoption of new plan measures and subsequent resubmission of the 

plan to the EPA for review and approval, or whether the process 

should specify the implementation of measures that are already 

included in the approved plan in the event that the projected 

level of performance is not being achieved. We also solicit 

comment on the point at which such a process and schedule would 

be triggered, such as at the end of a multi-year plan 

performance period if emission performance is not met, or at 

specified interim stages within a multi-year plan performance 

period. For plans with self-correcting mechanisms, the agency is 

not proposing that requirements for modification be included in 

the plan. All of these considerations are addressed in more 

detail below in Section VIII.F. 

The agency is also proposing that a state plan specify 

appropriate periodic reporting requirements for each affected 

entity in a state plan that will be reported at least annually, 

electronically, and disclosed on a state database accessible by 

the public and EPA. The EPA is requesting comment on the 

appropriate scope of these reporting requirements and whether 

the reports should also be directly submitted by the affected 

entities to the EPA, as well as to the state. 

D. State Plan Components 
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The EPA is proposing that an approvable plan must meet the 

approvability criteria described above and include the twelve 

state plan components summarized below, consistent with 

additional specific requirements explained elsewhere in this 

notice. Plans must comply with the EPA framework regulations at 

40 C.F.R. 60.23–60.29, except as specified otherwise by these 

emission guidelines. These requirements apply both to individual 

state plans and multi-state plans. 

For states wishing to participate in a multi-state plan, 

the EPA is proposing that only one multi-state plan would be 

submitted on behalf of all participating states. The joint 

submittal would be signed by authorized officials for each of 

the states participating in the multi-state plan and would have 

the same legal effect as an individual submittal for each 

participating state. The joint submittal would adequately 

address plan components that apply jointly for all participating 

states and for each individual state in the multi-state plan, 

including necessary state legal authority to implement the plan, 

such as state regulations and statutes. Because the multi-state 

plan functions as a single plan, each of the required plan 

components described below (e.g., plan performance levels, 

program implementation milestones, emission performance checks, 
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and reporting) would be designed and implemented by the 

participating states on a multi-state basis. 

The EPA proposes that each plan must have the following 

twelve components: 

1. Identification of affected entities (affected EGUs and other 

responsible parties) 

 The state plan must list the individual affected EGUs in 

the state that are subject to the plan and provide an inventory 

of CO2 emissions from those units (for the most recent calendar 

year prior to plan submission for which data are available), and 

identify any other affected entities in a state plan with 

responsibilities for implementation and enforcement of the plan. 

2. Description of plan approach and geographic scope 

 The state plan must describe its approach and geographic 

scope, including whether the state will achieve its required 

level of CO2 emission performance on an individual state basis or 

jointly through a multi-state demonstration. 

3. Identification of state emission performance level 

The state plan must identify the state’s proposed emission 

performance level, which will either be the rate-based CO2

emission goal identified for the state in the emission 
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guidelines or a translation of the rate-based goal to a massbased goal. 

A state plan must identify the rate-based or mass-based 

level of emission performance that must be met through the plan, 

(expressed in numeric values, including the units of measurement 

for the level of performance, such as pounds of CO2 per net MWh 

of useful energy output or tons of CO2 per year). As noted, in 

the emission guidelines, EPA will establish the state goal in 

the form of a CO2 emission rate, and the state may, for its 

emission performance level, either adopt that rate or translate 

it into a mass-based goal. If the plan adopts a mass-based goal, 

the plan must include a description of the analytic process, 

tools, methods, and assumptions used to translate from the ratebased goal to the mass-based goal. 

The EPA is proposing that multiple states could jointly 

demonstrate emission performance by affected EGUs. For these 

multi-state approaches, states would demonstrate emission 

performance by affected EGUs in aggregate with partner states. 

For states participating in a multi-state approach, the 

individual state performance goals in the emission guidelines 

would be replaced with an equivalent multi-state performance 

goal. For example, states taking a rate-based approach would 

Formatted: Highlight

Formatted: Highlight
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demonstrate that all affected EGUs subject to the multi-state 

plan achieve a weighted average CO2 emission rate that is 

consistent, in aggregate, with an aggregation of the statespecific rate-based CO2 emission performance goals established in 

the emission guidelines that apply to each of the participating 

states. If states were taking a mass-based approach, 

participating states would demonstrate that all affected EGUs 

subject to the multi-state plan emit a total tonnage of CO2

emissions consistent with a translated multi-state mass-based 

goal. This multi-state mass-based goal would be based on 

translation of an aggregation of the state-specific rate-based 

CO2 emission performance goals established in the emission 

guidelines that apply to each of the participating states. 

The EPA is seeking comment on two options for calculating a 

weighted average rate-based CO2 emission performance goal for 

multiple states. Under the first option, the weighted average 

emission rate goal for a group of participating states is 

computed using each state’s emission rate goal from the emission 

guidelines and the quantity of electricity generation by 

affected EGUs in each of those states during the 2012 base year 

that the EPA used in calculating the state-specific goals. 

Different levels would be computed for the interim and final 
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goals. This approach is consistent with the method used to 

calculate the state-specific rate-based emission performance 

goals. However, it does not address the fact that the weighted 

average emission rate performance goal for multiple states may 

be influenced significantly by the weighting of electricity 

generation from affected EGUs in different states. This mix of 

generation among affected EGUs in different states could differ 

significantly during the plan performance periods from that 

during the 2012 base year. 

Under the second option, the weighted average emission rate 

goal for a group of participating states is computed using each 

state-specific emission rate goal and the quantity of projected 

electricity generation by affected EGUs in each state. The 

calculation would be performed for the 2020 through 2029 period 

to produce a multi-state interim goal, and for 2030 to produce a 

multi-state final goal. This projection of electricity 

generation by affected EGUs would be for a reference case that 

does not include application of either the state-specific ratebased emission performance goals for the participating states or 

the requirements, programs, and measures included in the multistate plan. This approach addresses the fact that the mix of 

generation among affected EGUs in different states could differ 

Formatted: Indent: First line: 0"
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significantly during the plan performance periods from that 

during the 2012 base year. As a result, it would base the 

weighted average goal in part on the anticipated business-asusual mix of generation by affected EGUs across the multiple 

states during the plan performance period. However, this 

approach could also significantly alter the weighted average 

performance goal based on projected retirements of affected EGUs 

in one or more states. 

Under both options, the rate-based multi-state goal could 

be translated to a mass-based goal. These options, and the 

procedure for translation to a mass-based goal, are discussed in 

more detail in the Projecting EGU CO2 Emission Performance in 

State Plans TSD. 

We are requesting comment on whether, to assist states that 

seek to translate the rate-based goal into a mass-based goal, 

the EPA should provide a presumptive translation of rate-based 

goals to mass-based goals for all states, for those who request 

it, and/or for multi-state regions. As another alternative, the 

EPA could provide guidance for states to use in translating a 

rate-based goal to a mass-based goal for individual states and 

for multi-state regions. This could include information about 

acceptable analytical methods and tools, as well as default 
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input assumptions for key parameters that will likely influence 

projections, such as electricity load forecasts and projected 

fossil fuel prices. Under this approach, the EPA might also 

provide a coordinating function in addressing the assumptions 

applied by multiple states within a grid region, acknowledging 

that assumptions about state programs across a broader grid 

region that are included in an analysis scenario will influence 

projections of CO2 emissions by affected EGUs in any particular 

state. The agency is seeking comment on the process for 

establishing mass-based emission goals, including the options 

summarized above for the EPA’s and states’ roles in the 

translation process. 

Technical considerations involved in translating from ratebased goals to mass-based goals are discussed in detail in the 

Projecting EGU CO2 Emission Performance in StatePlans TSD. The 

TSD includes a discussion of possible acceptable analytical 

methods, tools, and key assumption inputs that will influence 

projections. The agency invites comment on these technical 

considerations. 

4. Demonstration that the plan is projected to achieve the 

state’s emission performance level 
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A state plan must demonstrate that the actions taken 

pursuant to the plan are, when taken together, projected to 

achieve the state’s emission performance level within the plan 

performance period. This demonstration will include a detailed 

description of the analytic process, tools and assumptions used 

to project future CO2 emission performance by affected EGUs under 

the plan and the results of the analysis. 

5. Milestones 

As described in greater detail in Section VIII.A.2.d., 

state plans must include periodic programmatic milestones to 

show progress in program implementation if the plan is not selfcorrecting (i.e., does not inherently require both interim 

progress and the full level of required emission performance in 

a manner that is federally enforceable against affected EGUs). 

These programmatic milestones with specific dates for 

achievement should be appropriate to the programs and measures 

included in the plan. 

In addition, the state plan demonstration will indicate the 

plan’s intended trajectory of emission performance improvement. 

As described in Section VIII.A.2.d., no less than every two 

years, beginning January 1, 2022, the state must compare 

emission performance achieved by affected EGUs in the state with 
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performance projected in the state plan. If actual emission 

performance is not within 10 percent of original projections, 

the state must submit a report by July 1 of the relevant year to 

explain reasons for the deviation and specify the corrective 

actions that will be taken to ensure that the required level of 

emission performance in the plan will be met. 

6. Corrective measures 

For a plan that does not include self-correcting 

mechanisms, the plan must also specify corrective measures that 

have been or will be implemented if the state’s progress in 

achieving its level of performance for affected EGUs falls short 

of what is projected under the plan, as well as a process and 

schedule for implementing any such measures. The agency requests 

comment on the amount of emission rate improvement or emission 

reduction that the corrective measures included in the plan must 

achieve (e.g., measures sufficient to address a 10 percent 

performance deficiency). 

7. Identification of standards of performance and any other 

measures 

A state plan must identify the affected entities to which 

each standard of performance applies (e.g., individual affected 

EGUs, groups of affected EGUs, all the state’s affected EGUs in 
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aggregate, other affected entities that are not EGUs), as well 

as any implementing and enforcing measures for such standards, 

and describe each standard of performance and the process for 

demonstrating compliance with it pursuant to state regulations 

or another legal instrument, including the schedule for 

compliance for each affected entity. In its January 2014 

proposed Carbon Pollution Standards, the EPA proposed that the 

appropriate standard of performance for new EGUs be no longer 

than 12 months (on average or cumulative calendar year basis). 

Similarly, the EPA proposes here that an appropriate averaging 

time for any rate-based standard of performance for affected 

EGUs and/or other affected entities subject to a state plan is 

no longer than 12 months within the plan period and no longer 

than three years for a mass-based standard. We also solicit 

comment on longer and shorter averaging times for a standard of 

performance included in a state plan. To maximize flexibility 

for the states, and in recognition that certain portfolio 

components may take longer to begin to achieve emission 

reductions than others, the EPA further proposes that such 

annual compliance timeframes may change over time (e.g., become 

more or less stringent in subsequent years), provided that the 
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state plan demonstrates ultimate achievement of the state’s 

level of performance as described previously in this preamble. 

8. Demonstration that each standard of performance is 

quantifiable, non-duplicative, permanent, verifiable, and 

enforceable 

In developing its CAA section 111(d) plan, to ensure that 

the plan is enforceable and in conformance with the CAA, a state 

should follow the EPA’s prior guidance on enforceability.237 This 

guidance serves as the foundation for the types of monitoring, 

reporting, and limits that EPA has found can be, as a practical 

matter, enforced, and set forth the general principle that a 

requirement that is enforceable as a practical matter is one 

that is quantifiable, verifiable, straightforward and is 

calculated over as short a term as reasonable. As reflected in 

section VIII.F.2.c.4 of this preamble, the EPA recognizes that 

states have a diversity of experiences with RE and demand-side 

 

237 EPA guidance on enforceability includes: (1) September 23, 

1987 memorandum and accompanying implementing guidance, “Review 

of State Implementation Plans and Revisions for Enforceability 

and Legal Sufficiency,” (2) August 5, 2004 “Guidance on SIP 

Credits for Emission Reductions from Electric-Sector Energy 

Efficiency and Renewable Energy Measures,” and (3) July 2012 

“Roadmap for Incorporating Energy Efficiency/Renewable Energy 

Policies and Programs into State and Tribal Implementation 

Plans, Appendix F.” 
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EE measures, and we are seeking comment on whether the EPA 

should establish further guidance on the quantification, 

monitoring and verification of such measures. 

For each standard of performance, a plan must describe how 

it is quantifiable, non-duplicative, permanent, verifiable, and 

enforceable with respect to an affected entity. A standard of 

performance is quantifiable if it can be reliably measured, 

using technically sound methods, in a manner that can be 

replicated. These issues are discussed further in Section 

VIII.F.4 and in the State Plan Considerations TSD. A standard of 

performance is non-duplicative with respect to an affected 

entity if it is not already incorporated in another state plan, 

except in instances where incorporated in another state as part 

of a multi-state plan. An example of a duplicative standard of 

performance would occur where recognition of avoided CO2

emissions from, for example, a wind farm, could be applied in 

more than one state’s CAA section 111(d) plan, except in the 

case of a multi-state plan where recognition is assigned among 

states or emission performance is demonstrated jointly for all 

affected EGUs subject to the multi-state plan. This does not 

mean that measures in a standard of performance cannot also be 

used for other purposes. For example, if a state wished to take 
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credit for CO2 emissions avoided due to electric generation from 

a new wind farm, those avoided emissions could be considered 

non-duplicative and included for purposes of CAA section 111(d), 

even if electric generation from that wind farm was also being 

used to generate renewable energy certificates (RECs) to comply 

with the state’s RPS requirements. It also does not mean that a 

single affected entity could not be subject to similar standards 

of performance in different state plans. For example, an 

affected entity might be an electric distribution utility that 

has a service territory that crosses state lines. This entity 

might be subject to a separate state demand-side EE requirement 

for electricity supplied in each of the states where it serves 

electricity customers. In this instance, the same company could 

be an affected entity subject to a different state demand-side 

EE requirement in each state plan, without these standards of 

performance in each plan being considered duplicative. The EPA 

solicits comment on whether an emission reduction becomes 

duplicative (and therefore cannot be used for demonstrating 

performance in a plan) if it is used as part of another state’s 

demonstration of emission performance under its CAA section 

111(d) plan. 
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A standard of performance is permanent if the standard of 

performance must be met by each applicable compliance year, or 

replaced by another standard of performance in a plan revision, 

or the state demonstrates in a plan revision that the emission 

reductions from the standard of performance are no longer 

necessary for the state to meet its emission performance level. 

A standard of performance is verifiable if adequate monitoring, 

recordkeeping and reporting requirements are in place to enable 

the state and the Administrator to independently evaluate, 

measure, and verify compliance with it. This is discussed 

further in Section VIII.F.4 and in the State Plan Considerations 

TSD. A standard of performance is enforceable if: (1) it 

represents a technically accurate limitation or requirement and 

the time period for the limitation or requirement is specified, 

(2) compliance requirements are clearly defined, (3) the 

affected entities responsible for compliance and liable for 

violations can be identified, (4) each compliance activity or 

measure is practically enforceable in accordance with EPA 

guidance on practicable enforceability (listed in Section 

VIII.C.1 of this preamble), and the Administrator and the state 

maintain the ability to enforce against violations and secure 
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appropriate corrective actions pursuant to Sections 113(a)–(h) 

of the CAA. 

9. Identification of monitoring, reporting, and recordkeeping 

requirements 

The state plan must describe the CO2 emission monitoring, 

reporting, and recordkeeping requirements for affected EGUs, 

including requirements for monitoring and reporting of useful 

energy output if a state plan is taking a rate-based approach. 

The EPA is proposing that each plan include monitoring, 

reporting, and recordkeeping requirements for CO2 emissions and 

useful energy output (if applicable) that are materially 

consistent with the requirements specified in the emission 

guidelines. State plans with a rate-based form of the emission 

performance level must require affected EGUs to report hourly 

net energy output (including net MWh generation, and where 

applicable, useful thermal output) to the EPA on an annual 

basis. 

Most affected EGUs already monitor CO2 emissions under 40 

CFR Part 75 and report the data using the EPA’s Emission 

Collection and Monitoring Plan System (ECMPS), which would 

generally satisfy CO2 reporting requirements under the proposed 

guidelines. However, we are seeking comment on two possible 
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adjustments to the Part 75 Relative Accuracy Test Audit (RATA) 

requirements for steam EGU stack gas flow monitors that can 

affect reported CO2 emissions. The first possible adjustment 

would be to require use of the most accurate RATA reference 

method for specific stack configurations, while the second 

possible adjustment would be to require a computation adjustment 

when an EGU changes RATA reference methods. The rationale for 

these possible adjustments is described further in the Part 75 

Monitoring and Reporting Considerations TSD available in the 

docket. 

We are also proposing monitoring and reporting protocols 

for net energy output under 40 CFR Part 75 that would allow the 

ECMPS to be used for purposes of meeting the net energy output 

reporting requirement. The proposed protocols include a default 

apportionment procedure for multi-EGU facilities under which the 

net generation of each EGU at the facility would be determined 

as the net generation of the facility times the ratio of the 

EGU’s gross generation to the sum of the gross generation for 

all EGUs at the facility. (In the case of EGUs producing both 

electric energy output and useful thermal output, the 

apportionment procedure would include a thermal-to-electric 

energy conversion calculation as provided in the proposed EGU 
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GHG NSPS regulations.238) In addition, the protocol would allow 

facilities to use alternative apportionment procedures with EPA 

approval. We invite comment on the proposal for reporting of net 

rather than gross energy output and on the proposed protocols. 

Specifically, we are seeking comment on: any existing protocols 

for reporting net output (FERC, NERC, etc.); electricity meter 

specifications; electricity meter quality assurance testing and 

reporting procedures; apportionment procedures for parasitic 

load at multi-unit plants; treatment of externally provided 

electricity; and monitoring and quality assurance testing and 

reporting procedures for non-electric energy output at CHP 

units. (Options regarding these topics are discussed in the TSD 

mentioned above.) Also, consistent with the requests for comment 

in the proposed GHG NSPS regulations for new, modified, and 

reconstructed sources, we invite comment here on a range of twothirds to 100 percent credit for useful thermal output in the 

final rule, or other alternatives to better align incentives 

with avoided emissions. 

 A state plan that contains other standards of performance 

in addition to emission limits applicable to affected EGUs must 

 

238 70 FR 1429-1519; January 8, 2014. 
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include additional reporting and recordkeeping requirements 

related to these other measures. These recordkeeping 

requirements will consist of the data necessary for each 

affected entity to demonstrate compliance with its obligations. 

This could include, for example, reporting of MWh electricity 

savings achieved by an electric distribution utility under an 

end-use energy efficiency resource standard and utility 

compliance with requirements of the standard. These requirements 

might also include comparable reporting by an electric 

distribution utility of renewable energy certificates (RECs) 

held, or renewable energy purchased or generated, under a 

renewable energy portfolio standard, and compliance with the 

standard. This is discussed further in Section VIII.F.4 and the 

State Plan Considerations TSD. 

The EPA is proposing to require state plans to include a 

record retention requirement of ten years and requests comment 

on this proposed timeframe. The EPA is also soliciting comment 

on whether these reports should be submitted electronically, to 

streamline transmission, and made publicly available. 

10. Description of state reporting 

 A state plan must provide that the state will submit 

periodic reports to the EPA detailing plan implementation and 
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progress, including the actions taken by the state, affected 

EGUs, and any other affected entities under the plan; the status 

of compliance by affected EGUs and any other affected entities 

with their obligations under the plan; current aggregate and 

individual CO2 emission performance by affected EGUs during the 

reporting year and prior reporting years; and any additional 

measures applied under the plan during the reporting period. The 

state plan must describe the process, timing, and content for 

these reports. 

The EPA is soliciting comment on whether these reports 

should be submitted electronically, to streamline transmission, 

and made publicly available. 

11. Certification of state plan hearing 

A state plan must provide certification that a hearing on 

the state plan was held, a list of witnesses and their 

organizational affiliations, if any, appearing at the hearing, 

and a brief written summary of each presentation or written 

submission pursuant to the requirements of the EPA framework 

regulations at 40 CFR 60.23. 

12. Supporting material 

The state must provide supporting material and technical 

documentation related to applicable components of the plan. In 
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its plan, a state must adequately demonstrate that it has the 

legal authority for each implementation and enforcement 

component that it proposes to include in its plan as part of a 

federally enforceable standard of performance. A state can make 

such a demonstration by providing supporting material related to 

the state’s legal authority used to implement and enforce each 

component of the plan, such as statutes, regulations, public 

utility commission orders, and any other applicable legal 

instruments. 

A state plan must also provide analytical materials used in 

translating a rate-based goal to a mass-based goal (if a 

translation is included), analytical materials used in 

projecting emission performance that will be achieved through 

the plan, relevant implementation materials, and any additional 

technical requirements and guidance the state proposes to use to 

implement elements of the plan. 

E. Process for State Plan Submittal and Review

1. Overview 

Under the framework regulations, state plans would be due 

nine months after finalization of the emission guidelines. 40 

CFR 60.23(a)(1). During the outreach process, many states 

expressed concern that this was not sufficient time to prepare 
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and submit a state plan to the EPA. States commented that 

additional time was needed to accommodate, among other things, 

state legislative and rulemaking schedules, coordination among 

states involved in multi-state plans, coordination with third 

parties, and the complex technical work needed to develop a 

state plan. The EPA recognizes that state administrative 

procedures can be lengthy, some states may need new legislative 

authority, and that states planning to join in a multi-state 

plan will likely need more than thirteen months to get necessary 

elements in place. Balanced against that concern, however, is 

the urgency of addressing carbon emissions and the fact that 

there are certain steps we believe states can take within 

thirteen months to set themselves on a clear path to adoption of 

a complete plan. Therefore, the EPA is proposing a plan 

submittal process with a submittal date of June 30, 2016 

(thirteen months after the expected finalization date of the 

emission guidelines), that provides additional time to submit a 

complete plan to the EPA after June 30, 2016, when justified. 

Part of that justification would include the state’s 

demonstration of having taken meaningful steps during the first 

thirteen months toward implementingimplementingsubmitting a 

complete plan. This approach involves the option that we refer 

Comment [A73]: We assume this is what EPA 

meant to say. 
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to as an initial submittal, followed by submittal of a complete 

state plan no later than either June 30, 2017 for single-state 

plans or June 30, 2018 for multi-state plans. . 

In addition, for states wishing to participate in a multistate plan, the EPA is proposing that only one multi-state plan 

would be submitted on behalf of all participating states, 

provided it is signed by authorized officials for each of the 

states participating in the multi-state plan and contains the 

necessary regulations, laws, etc. for each state in the multistate plan. In this instance, the joint submittal would have the 

same legal effect as an individual submittal for each 

participating state. 

2. State plan submittal and timing 

The EPA framework regulations (40 CFR 60.23) require that 

state plans be submitted to the EPA within nine months of 

promulgation of the emission guidelines, unless EPA specifies 

otherwise.239 In view of the complexity of these plans, we are 

proposing to extend the submittal date. We are proposing that 

each state must submit a plan to the EPA by June 30, 2016, which 

is more than one year after the expected finalization date of 

 

239 40 CFR 60.23(a)(1). 
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the emission guidelines. The state may submit a complete plan, 

or if justified, an initial plan that documents the state’s 

progress in preparing a complete plan. If a state intends to 

make an initial submittal by June 30, 2016, in lieu of a 

complete plan, the state must notify the EPA by letter of such 

intent by no later than April 1, 2016. In this letter, the state 

must adequately explain why more time is needed to submit a 

complete plan, outline the actions it is currently taking to 

develop a plan and commit to meet all of the requirements for an 

initial plan submittal by June 30, 2016. 

The EPA will respond to a state’s notice that it intends to 

request an extension of the plan submittal date within 45 days 

through a letter response. The EPA will acknowledge receipt of 

the state’s April notice and advise the state whether the 

outline of actions the state is currently undertaking to develop 

a plan indicate that the state is on track to submit an 

approvable initial submittal. The EPA’s response to the state’s 

April notice letter will be advisory only and will not 

constitute final agency action. The EPA will act to approve or 

disapprove a state’s request for a date extension in response to 

the state’s initial submittal. 
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The EPA proposes that approvable justifications for seeking 

an extension include: a state’s required schedule for 

legislative approval and administrative rulemaking, the need for 

multi-state coordination in the development of an individual 

state plan, or the process and coordination necessary to develop 

a multi-state plan. The EPA is requesting comment on other 

circumstances for which an extension of time would be 

appropriate. We are also seeking comment on whether to limit the 

types of justifications that the EPA should not consider as 

warranting an extension. 

If a state submits an initial state plan by June 30, 2016, 

and it meets the minimum requirements for an initial state plan, 

as specified in the plan guidelines, then the EPA will notify 

the state by letter, within 60 days, that it has received the 

initial state plan and determine whether it meets the minimum 

requirements. The EPA’s letter acting on the initial submittal 

will specify whether the new due date for the state’s complete 

plan is June 30, 2017 or June 30, 2018. The EPA believes this 

approach is authorized by, and consistent with, section 60.27(a) 

of the implementing regulations. 

 If the EPA approves a two-year extension to June 30, 2018, 

for a state developing a multi-state plan, the state would be 

Comment [A74]: The original text made sense. 

“limit the types EPA should not consider” is not 

what EPA intends to say, I believe. But rather to 

limit the types EPA would or should consider. In 

other words, EPA is taking comment on whether 

some justifications for extension should not be 

permissible. 
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required to provide one update, on June 30, 2017, on its 

progress toward milestones and schedules for developing and 

submitting a complete plan.240 We are requesting comment on this 

approach and the timing and frequency of updates that the state 

must provide. 

3. Components of an initial state plan submittal and 

approvability criteria 

As noted, if a state is unable to prepare and submit a 

complete plan by June 30, 2016, the state must make an initial 

submittal by that date. To be approved, the EPA proposes that 

the initial plan must address all components of a complete plan, 

including identifying which components are not complete. For 

incomplete components, an approvable initial submittal must 

contain a comprehensive roadmap outlining the path to 

completion, including milestones and dates. We recognize that 

certain options that states may choose involve more analytic 

effort to precisely demonstrate sources of reductions than other 

options. The initial plan, the initial plan must include the 

following information: 

 

240 This update would only apply to states that receive a twoyear extension for the submission of a complete plan, by June 

30, 2018. 
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 A description of the plan approach and progress to date in 

developing a complete plan 

 Initial quantification of the level of emission performance 

that will be achieved through the plan 

 A commitment to maintain existing measures that limit or 

avoid CO2 emissions (e.g., renewable energy standards, unitspecific limits on operation or fuel utilization), at least 

until the complete plan is approved 

 A comprehensive roadmap for completing the plan, including 

process, analytical methods, and schedule (with milestones) 

specifying when all necessary plan components will be 

complete (e.g., demonstration of projected plan 

performance; implementing legislation, regulations and 

agreements; any necessary approvals) 

 Identification of existing programs, if any, the state 

intends to rely on to meet its emission performance level 

 Identification of executed agreements with other states 

(e.g., memorandum of understanding (MOU)), if a multi-state 

approach is being pursued 

 A commitment to submit a complete plan by no later than the 

applicable required date and explanation of actions the 
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state will take to show progress in addressing incomplete 

plan components. 

 A description of all steps the state has already taken in 

furtherance of actions needed to finalize a complete plan. 

The EPA is soliciting comment on whether there are other 

elements that a state must include in its initial submittal to 

qualify for a date extension. 

For states participating in a multi-state program, the 

initial submittal should include executed agreements among the 

participating states and a road map for both design of the 

multi-state program and its implementation at the state level. 

The RGGI provides an example of such an approach. The RGGI 

participating states signed a Memorandum of Understanding (MOU) 

in December 20, 2005, in which the states “express[ed] their 

mutual understandings and commitments”.241 The MOU included a 

detailed outline of the multi-state emission budget trading 

program, which served as a guide for drafting a model rule. The 

 

241 Regional Greenhouse Gas Initiative Memorandum of 

Understanding, available at http://rggi.org/design/history/mou. 

Two states subsequently signed the original MOU in early 2007 

and a third joined the program later that year through an 

amendment of the MOU; one of the original states withdrew from 

the MOU in late 2011. 
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MOU also included commitments by the participating states to 

draft and finalize the model rule by specified dates, and a 

commitment to seek to establish in statute and/or legislation a 

program materially consistent with the model rule in each state 

by a specified date.242 The MOU also included a commitment to 

launch the program by January 1, 2009 in all states and 

specified a process for establishing a non-profit organization 

to assist the states in administering the regional aspects of 

the program. In addition, prior to execution of the MOU, the 

RGGI states committed, through letters from the Governors of 

participating states, to engage in the development of a marketbased program to reduce CO2 emissions from power plants. This was 

followed by publication of an action plan for tasks leading up 

to agreement on the basic structure of the program, which was 

ultimately formalized in the MOU. 

4. Process for EPA review of state plans 

 

242 The model rule specified elements that needed to be 

consistent across states for the program to function, as well as 

areas were state rules could differ (e.g., the method used for 

allocating CO2 allowances). For more information, see Regional 

Greenhouse Gas Initiative Model Rule, available at 

http://rggi.org/docs/ProgramReview/_FinalProgramReviewMaterials/

Model_Rule_FINAL.pdf. 
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Following the June 30, 2016, deadline for state plan 

submittals, the EPA will review plan submittals for 

approvability. For a state that submits an initial state plan by 

June 30, 2016, and requests an extension of the deadline for the 

submission of a complete state plan, the EPA will determine if 

the initial plan submittal meets the minimum requirements for an 

initial state plan. If it meets the minimum requirements for an 

initial state plan, as specified in the emission guidelines, 

then the EPA will notify the state by letter, within 60 days, 

that it has received the plan and that the initial state plan 

meets the minimum requirements. The letter will also specify 

whether the complete plan must be submitted to the EPA by no 

later than June 30, 2017, or June 30, 2018. 

After receipt of a complete plan submittal, the EPA will 

review the plan and, within six months, approve or disapprove 

the plan through a notice-and-comment rulemaking process, 

similar to that used for approving state implementation plan 

submittals under section 110 of the Act. 

F. State Plan Considerations 

The EPA is proposing to give states broad discretion to 

develop plans that best suit their circumstances and policy 

objectives. In developing its plan, astate will need to make a 
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number of decisions that will require careful consideration, in 

order to ensure that its plan both meets a state’s policy 

objectives and is approvable by the EPA. In this section, we 

identify several key decision points and factors that states 

should consider when developing their plans. 

The EPA has also prepared a TSD, titled “State Plan 

Considerations,” that provides further information on these 

topics. The agency is seeking comment on the contents of this 

TSD and all aspects of the state plan decision points and 

factors below. 

1. Affected entities other than affected EGUs 

A state will need to identify each affected entity 

responsible for meeting compliance obligations under its plan 

and the means by which compliance with each plan requirement 

will be met, as well as demonstrate that it has the legal 

authority to subject such entities to the federally enforceable 

requirements specified in its state plan. We are proposing that 

affected entities in an approvable state plan may include: an 

owner or operator of an affected EGU, other affected entities 

with responsibilities assigned by a state (e.g., an entity that 

is regulated by the state, such as an electric distribution 

utility, or a private or public third-party entity), and the 
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state agency, authority or entity. We are seeking comment on 

other appropriate examples of affected entities beyond the 

affected EGU. 

While the EPA seeks to provide states with broad discretion 

to develop plans that best suit their circumstances and policy 

objectives, a plan that assigns responsibility to affected 

entities other than affected EGUs may be more challenging to 

implement and enforce than a plan with requirements assigned 

only to affected EGUs. 

Furthermore, it may be more challenging for a state to 

demonstrate that it has sufficient legal authority to subject 

such affected entities other than affected EGUs to the federally 

enforceable requirements specified in its state plan. We seek 

comment on whether the EPA should provide guidance on the 

ability of a state to include requirements for affected entities 

other than EGUS, and if so, which such entities, and the 

justification for the limitations on the entities. The State 

Plan Considerations TSD provides illustrative examples of 

possible entities and legal mechanisms. 

2. Treatment of existing state programs 

a. Framing considerations 
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Many state officials and stakeholders have said that the 

EPA should avoid structuring the CAA section 111(d) emission 

guidelines in a way that would disadvantage states that already 

have adopted programs that reduce CO2 emissions. The EPA agrees 

with that policy principle. 

There is much less agreement among states and stakeholders 

on the specifics of how existing state programs should be 

treated in a demonstration that a proposed state plan will 

achieve the required level of emission performance. 

The EPA, starting from recent historical data, has 

identified the affected EGU emission performance improvements 

and resulting average emission performance levels for affected 

EGUs that are achievable, considering cost, in each state over 

the 2020-2029 period, with achievement of the final CO2 emission 

performance level by 2030. 

As explained in Section VII above, the EPA’s proposed 

state-specific goals reflect actions that many states have 

already taken to reduce or avoid EGU CO2 emissions. CO2 emission 

reductions due to shifts to lower CO2-emitting power generation 

are also represented in the 2012 base period that was used to 
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assess certain building blocks that are applied in calculating a 

state emission performance goal.243

The agency recognizes that states that have already shifted 

toward lower carbon-intensity generation or ramped up demandside EE programs are better positioned to meet state-specific 

goals. For example, states where significant shifts in 

generation to NGCC units have already occurred would be closer 

to the generation mix reflected in the state goals than states 

where NGCC capacity is not yet being operated to the same 

degree. Likewise, states with relatively well-established 

demand-side EE programs would be able to build on those programs 

more quickly than states with less established programs, and 

would be closer to, or in some cases already achieving, the 

level of demand-side energy efficiency reflected in the state 

goals. 

b. Proposed approach for treatment of existing state programs 

and measures in an approvable state plan 

 

243 For example, in such instances a significant shift to NGCC 

generation prior to 2012 may result in a lower potential for 

further re-dispatch to these units, as witnessed in the 2012 

base period data. This would influence the calculated rate-based 

emission goal for the state, reducing the percentage improvement 

required relative to the base period CO2 emission rate.
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The EPA is proposing that existing state programs, 

requirements, and measures,244 may qualify for use in showing 

that a state plan will achieve the required level of emission 

performance, provided they meet the approvability requirements 

in the emission guidelines (summarized above in Section VIII.B) 

and relevant requirements for plan components in the emission 

guidelines (described above in Section VIII.C). Several options 

for treatment of existing programs and measures are described 

below. 

Specifically, the EPA is proposing that, for an existing 

state requirement, program, or measure, a state may apply toward 

its required emission performance level the emission reductions 

that existing state programs and measures achieve during the 

plan performance period as a result of actions taken after the 

date of this proposal.245 This proposed policy would recognize 

 

244 An “existing measure” refers to a state or utility 

requirement, program, or measure that is currently “on the 

books.” For the purposes of this discussion, this may include a 

legal requirement that includes current and future obligations 

or current programs and measures that are in place and are 

anticipated to be continued or expanded in the future in 

accordance with established plans. Existing measures may have 

past, current, and future impacts on EGU CO2 emissions. 245 We are also proposing that this proposed limitation would not 

apply to existing renewable energy requirements, programs and 

measures because existing renewable energy generation prior to 

Comment [A75]: A commenter suggests moving 

this important clarification to the main body of the 

text. 
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beneficial emission impacts from existing state programs and 

measures during the plan period. It would do so in a way that 

may be generally compatible with the forward-looking methodology 

that the EPA used to propose state emission performance goals 

based on BSER. By making actions taken after proposal eligible 

to help meet a state’s required emission performance level, this 

approach would support early beneficial emission-reducing 

actions. This option would ensure that actions taken after 

proposal of the emission guidelines and prior to 2020 as a 

result of requirements in a state plan, could be recognized as 

contributing toward meeting a state’s required emission 

performance level for affected EGUs. 

In general, the agency has identified two broad options for 

treatment of existing state programs and measures. As noted 

above, the EPA proposes that emission reductions that existing 

state requirements, programs, or measures achieve during the 

plan performance period due to actions taken after a specified 

date may be recognized in determining emission performance under 

a state plan. While proposing that the “specified date” would be 

the date of proposal of these emission guidelines, the EPA also 

 

the date of proposal of the emission guidelines was factored 

into the state-specific CO2 goals as part of building block 3. 
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requests comment on the following alternatives: the start date 

of the plan performance period, the date of promulgation of the 

emission guidelines, the end date of the base period for the 

EPA’s BSER-based goals analysis (e.g., beginning of 2013 for 

blocks 1-3 and beginning of 2017 for block 4, end-use energy 

efficiency), the end of 2005, or another date. 

For this option, we are seeking comment on the point in 

time after which such actions should be able to qualify for use 

during a plan performance period, considering the method used to 

set state goals. Whether this option is consistent in practice 

with the EPA’s application of BSER may depend on the date or 

dates that are applied for qualifying actions under existing 

state programs, requirements, and measures. For example, 

implementation of measures subsequent to the proposal or 

promulgation of the emission guidelines may be consistent with a 

forward-looking goal setting approach, as these actions may be 

necessary to meet a required level of emission performance 

during the plan performance period or will put a state in a 

better position to meet the required level of performance. An 

example is the EPA’s treatment of end-use energy efficiency 

potential in state goal setting, where the energy savings 

achievable during the plan performance period are premised in 
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part on a ramping up of end-use energy efficiency programs and 

cumulative energy savings prior to the beginning of the plan 

performance period. Earlier dates may also be consistent with a 

forward-looking goal setting approach, if the goal-setting 

approach is premised in part on actions that could be taken 

prior to the plan period. However, inconsistency issues may 

arise if the selected date is not adequately synchronized with 

the goal-setting method. The EPA requests comment on whether 

there is a rational basis for choosing a date that predates the 

base period from which the EPA used historical data to derive 

state goals. The agency generally requests comment on the 

appropriate date to select under this option. 

The EPA also solicits comment on a second broad option. 

This option would recognize emission reductions that existing 

state requirements, programs, or measures achieved starting from 

a specified date prior to the plan performance period, as well 

as emission reductions achieved during a plan performance 

period. The specified date could be, for example: the date of 

promulgation of the emission guidelines; the date of proposal of 

the emission guidelines; the end date of the base period for the 

EPA’s BSER-based goals analysis (e.g., beginning of 2013 for 
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blocks 1-3 and beginning of 2017 for block 4, end-use energy 

efficiency); the end of 2005; or another date. 

The EPA requests comment on this option -- that emission 

reduction effects that occur prior to the beginning of the plan 

performance period could be applied toward meeting the required 

level of emission performance in a state plan. The agency also 

requests comment on the alternative dates listed above in 

connection with this option. We also request comment on whether 

this option is inconsistent with the forward-looking method that 

the EPA has proposed for establishing state goals based on the 

application of BSER. 

The agency is seeking comment on whether some variation of 

this approach could be justified as consistent with the EPA’s 

proposed goal-setting approach, as well as the general concept 

of BSER and its application in establishing state goals. In 

particular, we are seeking comment on whether emission effects 

of actions that are taken after proposal or promulgation of the 

emission guidelines or the approval of a state plan, but which 

occur prior to the beginning of the state plan performance 

period, could be applied toward meeting the required level of 

emission performance in a state plan. 
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c. Application of options under rate-based and mass-based plan 

approaches 

Under a rate-based approach, the options described above 

would address the eligibility date for qualifying demand-side EE 

measures that, through MWh savings, avoid CO2 emissions from 

affected EGUs. Measures installed after the eligibility date 

could generate MWh savings during a plan performance period, and 

related avoided CO2 emissions, that could be applied toward 

meeting a required rate-based emission performance level. Under 

the proposed option, the eligibility date would be the date of 

these proposed emission guidelines. For example, under this 

approach, new demand-side EE measures installed in 2015 or later 

to meet an existing, on-the-books energy efficiency resource 

standard would be a qualifying measure. However, only MWh 

savings beginning in 2020 and related avoided CO2 emissions could 

be applied toward meeting a required emission rate performance 

level. 

Under a mass-based approach, the options described above 

would be applied when establishing a reference case scenario 

projection that is used to translate a rate-based goal to a 

mass-based goal. For example, demand-side EE measures after a 

respective eligibility date would not be included in the 
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scenario that is used to project CO2 emissions from affected EGUs 

when establishing a translated mass-based emission goal. This 

could be achieved by not including the incremental requirements 

of an end-use energy efficiency resource standard requirement in 

a reference case projection, beginning at a specified date. 

These considerations are addressed in more detail in Section 

VIII.F.7. below and in the Projecting CO2 Emission Performance in 

State Plans TSD. 

3. Incorporating RE and demand-side EE measures under a ratebased approach 

 We are proposing that RE and demand-side EE measures may be 

incorporated into a rate-based approach through an adjustment or 

tradable credit system applied to an EGU’s reported CO2 emission 

rate.246 Under such a process, measures that avoid CO2 emissions 

from affected EGUs, such as quantified and verified end-use 

energy savings and renewable energy generation, could be 

credited toward a demonstrated CO2 emission rate for EGU 

compliance purposes or used by the state to administratively 

 

246 We are also proposing that RE and demand-side EE measures 

could be used under a mass-based portfolio approach in an 

approvable state plan. However, the focus of this section is 

limited to application of such measures under a rate-based 

approach.
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adjust the average CO2 emission rate of affected EGUs when 

demonstrating achievement of the required emission rate 

performance level in a state plan. 

 Under this approach, affected EGUs247 could comply with a CO2

emission rate limit in part through the use of credits for 

actions that avoid CO2 emissions from affected EGUs. If a state 

is implementing a portfolio approach, then the state could 

administratively adjust the average CO2 emission rate of affected 

EGUs through a similar process, provided that the CO2-avoiding 

measures are enforceable elements of the state plan. 

We are seeking comment on different approaches for 

providing such crediting or administrative adjustment of EGU CO2

emission rates, which are elaborated further in the State Plan 

Considerations TSD. 

Credits or adjustment might represent avoided MWh of 

electric generation or avoided tons of CO2 emissions. The 

approach chosen could have significant implications for the 

amount of adjustment or credit provided for RE and demand-side 

EE measures. If adjustment or credits represent avoided MWh, 

 

247 This could include an individual affected EGU or group of 

affected EGUs if a rate-based averaging or trading approach is 

used.
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they would be added to the denominator when determining an 

adjusted lb CO2/MWh emission rate. If adjustment or credits 

represent avoided CO2 emissions, they would be subtracted from 

the numerator when determining an adjusted lb CO2/MWh emission 

rate. 

A MWh crediting or adjustment approach implicitly assumes 

that the avoided CO2 emissions come directly from the particular 

affected EGU (or group of EGUs) to which the credits are 

applied. It assumes, in effect, that an additional emission-free 

MWh is being generated by that respective EGU, and that the RE 

or demand-side EE measure reduces CO2 emissions from that 

individual EGU or group of EGUs.248 In practice, the average or 

marginal CO2 emission rate in the power pool or identified region 

– representing the avoided CO2 emissions from the generating 

sources being displaced by a MWh of energy savings or a MWh of 

renewable energy generation – could differ significantly from 

the calculated avoided CO2 emissions derived by adjusting the MWh 

output of an affected EGU. 

 

248 As a result, the assumed avoided CO2 emissions from an 

individual MWh of energy savings or MWh of generation from 

renewable energy will differ based on the reported CO2 emission 

rate of the individual EGU to which the MWh is applied as an 

adjustment to its MWh output.
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An alternative approach is to provide an adjustment based 

on the estimated CO2 emissions that are avoided from the power 

pool or identified region as a result of RE and demand-side EE 

measures. This approach implicitly assumes that the avoided CO2 

emissions come from the electric power pool or other identified 

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

emissions are determined based on the MWh saved or generated, 

multiplied by a CO2 emission rate for the power pool or region. 

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

emission rate in the power pool or region, or could be the 

emission rate that represents the required rate-based emission 

performance level in the plan. We invite comment on each of 

these possible approaches. 

In addition, because some of the CO2 emissions avoided 

through RE and demand-side EE measures may be from non-affected 

EGUs, we are seeking comment on how this might be addressed in a 

state plan, whether when adjusting or crediting CO2 emission 

rates of affected EGUs based on the effects of RE and demandside EE measures or otherwise. How these dynamics might be 

addressed, both in projections of plan performance and in actual 

demonstration of performance achieved under a plan, is further 

discussed in the State Plan Considerations TSD. 
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4. Quantification, monitoring, and verification of RE and demandside EE measures 

 A key consideration for state plans is the process and 

requirements under a state plan for quantifying, monitoring, and 

verifying the effect of RE and demand-side EE measures that 

result in electricity generation or electricity savings. 

The EPA is proposing that a state plan that includes 

enforceable RE and demand-side EE measures must include an 

evaluation, measurement, and verification (EM&V) plan that 

explains how the effect of these measures will be determined in 

the course of plan implementation. An EM&V plan will specify the 

analytic methods, assumptions, and data sources that the state 

will employ during the state plan performance periods to 

determine the energy savings and energy generation related to RE 

and demand-side EE measures. An EM&V plan would be subject to 

EPA approval as part of a state plan. As discussed below, the 

EPA intends to develop guidance on acceptable EM&V methods that 

could be incorporated in an approvable EM&V plan included as 

part of an approvable state plan. 

Utilities and states have conducted ongoing EM&V of demandside energy efficiency and renewable energy measures and 

programs for several decades. Current practice with EM&V for 
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demand-side energy efficiency and renewable energy programs in 

the U.S. is primarily defined by state public utility commission 

(PUC) requirements for customer-funded energy efficiency 

programs, as well as related compliance and reporting 

requirements for energy efficiency resource standards (EERS) and 

renewable energy portfolio standards (RPS). 

The level of PUC oversight of demand-side energy efficiency 

programs varies from state to state, but this oversight process 

has generated the majority of the industry guidance and 

protocols for documenting energy savings from EE programs. 

Typically, impact evaluation reports are responsive to 

requirements established by PUCs and submitted (usually 

annually) for PUC review, approval, and use in resource planning 

and performance assessment. These PUC requirements generally 

rely upon a well-defined set of industry-standard practices and 

procedures. In states with the most experience implementing and 

overseeing EE programs, this typically includes: use of one or 

more of industry-standard EM&V protocols or guidelines; use of 

“deemed savings values,”249 where appropriate, for well-

 

249 Deemed savings are measure-specific stipulated values based 

on historical and verified data. Unlike other EM&V approaches, 

deemed savings approaches involve limited or no measurement 
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understood energy efficiency measures; consideration of local 

factors, such as climate, building type, and occupancy; 

involvement of stakeholders and solicitation of expert advice 

regarding EM&V processes and resulting energy savings impacts; 

conduct of EM&V activities (e.g., direct equipment measurements, 

application of deemed savings, and reporting of impacts) on a 

regular basis; and provision of interim and annual reporting of 

achieved energy savings. 

Despite this well-defined and generally accepted set of 

industry practices, many states with energy efficiency programs 

use different input values and assumptions in applying these 

practices (e.g., net versus gross savings250, run-time of 

equipment, measure lifetime). This can result in significant 

differences in claimed energy savings values for similar energy 

efficiency measures between states and utilities, even when the 

same measure type is installed under otherwise identical 

circumstances. In response to a growing awareness of this lack 

 

activities, and are therefore a common and relatively low-cost 

strategy for documenting energy savings. 

250 Gross savings are the change in energy use (MWh) and demand 

(MW) that results directly from program-related actions taken by 

program participants, regardless of why they participated in a 

program. Net savings refer to the change in energy use and 

demand that is directly attributable to a particular energy 

efficiency program. 
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of cross-state comparability, policy makers, regulatory 

agencies, and other stakeholders are increasingly advocating for 

the use of common evaluation approaches across jurisdictions. A 

number of states and utilities in different regions of the 

country are already working to develop such common approaches.

For renewable energy measures and programs, EM&V employed 

by states and utilities commonly relies upon a set of standard 

practices and procedures, such as the use of revenue-quality 

meters for quantifying RE generation. As a result, existing state 

and utility requirements and processes for quantification, 

monitoring, and verification of RE programs and measures 

generally provide a solid foundation for minimum requirements or 

guidance established by EPA for state plans. 

For both RE and demand-side EE measures included in state 

plans, additional information and reporting may be necessary to 

accurately quantify the avoided CO2 emissions associated with 

these measures , such as information on the location and the 

hourly, daily, or seasonal basis of renewable energy generation 

or energy savings. 

Current state and utility EM&V approaches for RE and 

demand-side EE programs and mandates are discussed in more 

detail in the State Plan Considerations TSD. We are seeking 
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comment on the suitability of these approaches in the context of 

an approvable state plan, and on whether harmonization of state 

approaches, or supplemental actions and procedures, should be 

required in an approvable state plan. In particular, we intend 

to establish guidance for acceptable quantification, 

monitoring, and verification of RE and demand-side EE measures 

for an approvable EM&V plan, and are seeking comment on critical 

features of such guidance, including scope, applicability, and 

minimum requirements.251 We are also seeking comment on the 

appropriate basis for and technical resources used to establish 

such guidance, including consideration of existing state and 

utility protocols, as well as existing international, national, 

and regional consensus standards or protocols.252 The EPA’s goal 

in developing such guidance is to assure that it is consistent 

with industry-standard EM&V approaches for both RE and demandside EE measures and programs, leverages the EM&V resources and 

infrastructure already in place in many states, and strikes a 

reasonable balance between EM&V costs, rigor, and the value of 

resulting information, while considering the specific use of 

 

251 Section 4 of the State Plan Considerations TSD includes a 

detailed description of these EM&V parameters.

252 A list of these protocols is provided in Section 3.1 of the 

State Plan Considerations TSD.
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such information in assessing avoided CO2 emissions from affected 

EGUs. 

In developing guidance, the agency does not intend to limit

the types of RE and demand-side EE measures and programs that 

can be included in a state plan, provided that supporting EM&V 

is rigorous, complete, and consistent with EPA’s guidance. This 

approach recognizes differences among RE and demand-side EE 

programs and measures with respect to implementation history and 

experience, existence of applicable EM&V protocols and methods, 

and the nature and type of program oversight (e.g., whether or 

not a program is subject to PUC oversight). The EPA is 

requesting comment on the merits of this approach, including 

whether such guidance should identify types of RE and demandside EE measures and programs for which evaluation of results is 

relatively straightforward and which are appropriate for 

inclusion in a state plan. Such approaches might be subject to 

streamlined review of EM&V protocols included in an approvable 

plan, provided that such protocols are applied in accordance 

with industry best practices. For example, many utilities have 

implemented a similar core set of RE and demand-side EE measures 

and programs for utility customers. For these types of measures 

and programs, a substantial base of experience has been 
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established nationally for the evaluation of measure and program 

outcomes. Other types of measures and programs, such as those 

that seek to alter consumer and building occupant behavior may 

pose quantification and verification challenges. Still other 

types of measures, such as state energy-efficient appliance 

standards and building codes, have not typically been subject to 

similar evaluation of energy savings results. These types of 

approaches may have substantial impacts, and the EPA does not 

want to discourage their implementation in state plans, but they 

may require development of appropriate quantification, 

monitoring, and verification protocols. The EPA and its federal 

partners intend to discuss the development of appropriate EM&V 

protocols for such measures with states in the coming years. 

As an alternative to the EPA’s proposed approach of 

allowing a broad range of RE and demand-side EE measures and 

programs to be included in state plans, provided that supporting 

EM&V documentation meets applicable minimum requirements, EPA is 

requesting comment on whether guidance should limit 

consideration to certain well-established programs, such as 

those characterized in Section 4.2.1 of the State Plan 

Considerations TSD. 
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5. Reporting and recordkeeping for affected entities implementing 

RE and demand-side EE measures 

If a state plan incorporates RE and demand-side EE measures 

under a rate-based approach or implements a mass-based portfolio 

approach with such measures, reporting and recordkeeping 

requirements for an approvable plan would differ from those 

applicable to an affected EGU. For example, these requirements 

may include compliance reporting by an electric distribution 

utility subject to an end-use energy efficiency resource 

standard (EERS) or renewable portfolio standard (RPS). They may 

also include reporting by a vertically integrated utility 

implementing an approved integrated resource plan. In the latter 

instance, the utility may also be the owner and operator of 

affected EGUs, but additional reporting of quantified effects of 

RE and demand-side EE measures under the utility plan would be 

necessary to demonstrate emissions performance under the state 

plan. In other instances, a state agency or entity or a private 

or public third-party entity may be implementing programs and 

measures that support the deployment of end-use energy and clean 

energy technologies that are incorporated into a state plan. In 

each of these instances, reporting of program compliance or 
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program outcomes is a necessary part of an approvable plan to 

demonstrate performance under the plan. 

Examples of potential reporting obligations for affected 

entities implementing RE and demand-side EE measures in an 

approvable state plan are provided in the State Plan 

Considerations TSD. We are seeking comment on the examples and 

suitability of potential approaches described in the TSD and any 

other appropriate reporting and recordkeeping requirements for 

affected entities beyond affected EGUs. 

6. Treatment of interstate effects 

The electricity system and wholesale electricity markets 

are interstate in nature. EGUs in one state provide electricity 

to customers in neighboring states. Power companies often own 

EGUs in more than one state and manage them as a system. EGUs 

are dispatched both within and across state borders. 

Similarly, programs and measures in a state plan, such as 

RE and demand-side EE measures, may affect the performance of 

the interconnected electricity system beyond a state border. In 

addition, many state programs allow for actions in neighboring 

states to meet the in-state requirement or explicitly address CO2

emissions in neighboring states. For example, many state 

renewable portfolio standards allow for generation by qualifying 
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renewable energy sources in other states to count toward meeting 

the state portfolio requirement. Some states also apply CO2

emission requirements related to the generation of power 

purchased by regulated utilities, including power imported from 

out of state. 

The agency recognizes the complexity of accounting for 

interstate effects associated with measures in a plan in a 

consistent manner, to allow state to take into account the CO2

emission reductions resulting from these programs, while 

minimizing the likelihood of double counting. We also realize 

that interstate effects on CO2 emissions from affected EGUs could 

be attributed in different manners in the context of an 

approvable state plan. The agency is seeking comment on the 

options summarized below, as well as alternatives. These options 

and alternatives, and how they might apply to both projections 

of plan performance and reporting of achieved plan performance, 

are addressed in the State Plan Considerations TSD. 

The EPA is proposing that, for demand-side EE measures, 

consistent with the approach used in determining BSER, a state 

could take into account in its plan only those CO2 emission 

reductions occurring (or projected to occur) in the state that 

result from demand-side EE measures implemented in the state. 
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The agency is also proposing that, for states that participate 

in multi-state plans, the states would have the flexibility to 

distribute the CO2 emission reductions among states in the multistate area, as long as the total CO2 emission reductions claimed 

are equal to the total of each state’s in-state emissions 

reductions that result from demand-side EE measures implemented 

in those states. We are also proposing that states could jointly 

demonstrate CO2 emission performance by affected EGUs through a 

multi-state plan in a contiguous electric grid region, in which 

case attribution among states of emission reductions from 

demand-side EE measures would not be necessary. We also request 

comment on whether a state should be able to take credit for 

emission reductions out of state due to in-state EE measures if 

the state can demonstrate that the reductions will not be 

double-counted when the relevant states report on their achieved 

plan performance, and on what such a demonstration should 

entail. We request comment on these and other approaches for 

taking into account CO2 reductions from demand-side EE measures 

in state plans. 

The EPA is also proposing that, for renewable energy 

measures, consistent with existing state RPS policies, a state 

could take into account all of the CO2 emission reductions from 
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renewable energy measures implemented by the state, whether they 

occur in the state and/or in other states. The EPA is also 

seeking comment on how to avoid double counting emission 

reductions using this proposed approach. The EPA is also 

proposing that states participating in multi-state plans could 

distribute the CO2 emission reductions among states in the multistate area, as long as the total CO2 emission reductions claimed 

are equal to the total of each state’s in-state emission 

reductions for renewable energy measures. We also request 

comment on the option of allowing a state to take into account 

only those CO2 emission reductions occurring in its state. We are 

also proposing that states could jointly demonstrate CO2 emission 

performance by affected EGUs through a multi-state plan in a 

contiguous electric grid region, in which case attribution among 

states of emission reductions from renewable energy measures 

would not be necessary. We also request comment on whether a 

state should be able to take credit for emission reductions out 

of state due to renewable energy measures if the state can 

demonstrate that the reductions will not be double-counted when 

the relevant states report on their achieved plan performance, 

and on what such a demonstration should entail. We request 

Comment [A76]: The commenter appreciates the 

answer to this question in the response to comments 

and suggests that it may be worthwhile including it 

in the preamble. 
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comment on these and other approaches for taking into account CO2

emission reductions from renewable energy measures. 

7. Projecting emission performance 

As proposed, an approvable state plan will include a 

projection of CO2 emissions performance by affected EGUs under 

the plan. In addition, a state plan that is using a mass-based 

goal in determining the required level of emission performance 

under the plan will include a translation of the rate-based 

emission goal in the emission guidelines to a mass-based goal. 

This translation will involve a projection of CO2 emissions from 

affected EGUs during the plan period, under a scenario that 

assumes the rate-based goal in the emission guidelines is met. 

The EPA is striving to find a balance between providing 

state implementation flexibility and ensuring that the emission 

performance required by CAA section 111(d) is properly defined 

in state plans and that plan performance projections have 

technical integrity. Each state plan must include a projection 

of CO2 emission performance from affected EGUs during the multiyear plan period that will result from implementation of the 

plan. Depending on the type of plan approach, this will include 

either a projection of the average CO2 emission rate achieved by 

affected EGUs or total CO2 emissions from affected EGUs. 
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The credibility of state plans under CAA section 111(d) 

will depend in large part on ensuring credible and consistent 

emission performance projections in state plans. Therefore, the 

use of appropriate methods, tools, and assumptions for such 

projections is critical. 

Considerations for projecting emission performance under a 

state plan will differ depending on the type of plan. This 

includes differences in how inputs to projections are derived; 

how projections are conducted, including tools,methods, and 

assumptions; and, how aspects of a plan are represented in these 

projections. 

In general, as with projections used to determine a massbased goal, projections of emission performance under a state 

plan could be conducted using historical data and parameters for 

estimating the future impact of individual state programs and 

measures. Alternatively, a projection could include modeling, 

such as use of a capacity planning and dispatch model.253 This 

latter approach would be able to capture dynamic interactions 

within the electricity sector, based on system operation and 

 

253 In many cases, this approach will also require the 

development of parameters for estimating the effect of 

individual state programs and measures, for use as input 

assumptions for modeling.
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market forces, including interactions among state programs and 

measures and the dynamics of market-based measures. 

These considerations, and considerations for projecting 

emission performance under different types of state plan 

approaches, are discussed in detail in the Projecting EGU CO2

Emission Performance in State PlansTSD. 

We are seeking comment on the considerations discussed in 

this TSD, including options presented for how projections might 

be conducted in an approvable state plan, and how different 

types of state plan approaches are represented in these 

projections. We are further seeking comment on whether the EPA 

should develop guidance that describes acceptable projection 

approaches, tools, and methods for use in an approvable plan, as 

well as provide technical resources for conducting projections. 

The ISO/RTO Council, an organization of electric grid 

operators, has suggested that ISOs and RTOs could provide 

analytic support to help states develop and implement their 

plans. The ISOs and RTOs have the capability to model the 

system-wide effects of individual state plans. Providing 

assistance in this way, they felt, would allow states with 

borders that fall within an ISO or RTO footprint to assess the 

system-wide impacts of potential state plan approaches. In 
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addition, as the state implements its plan, ISO/RTO analytic 

support would allow the state to monitor the effects of its plan 

on the regional electricity system. ISO/RTO analytic capability 

could help states assure that their plans are consistent with 

region-wide system reliability. The ISO/RTO Council suggested 

that the EPA ask states to consult with the applicable ISO/RTO 

in developing their state plans. 

8. Consideration of measures that the EPA did not include in the 

BSER determination 

States may include measures in their plans beyond those 

that the EPA included in its determination of the BSER. A wide 

range of other measures that could lead to CO2 emission 

reductions. These include, for example, transmission 

improvements, retrofitting EGUs with partial CCS, the use of 

biomass-derived fuels, use of new NGCC units online, and new 

hydroelectric power and increments, and they are among the 

measures that states might consider for inclusion in their 

plans. The agency solicits comment on whether these measures are 

appropriate to include in a state plan to achieve CO2 emission 

reductions. We also request comment on other measures that would 

be appropriate. In addition, should the EPA provide specific 

guidance on these measures? 
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We request comment, in particular, on the use of biomassderived fuels, in place of affected EGUs, as a measure to 

include in a state plan to achieve CO2 emission reductions. 

Through President Obama’s Climate Action Plan, the 

Administration is working to identify new approaches to protect 

and restore our forests, as well as other critical landscapes 

including grasslands and wetlands, in the face of a changing 

climate. Sustainable forestry and agriculture can improve 

resiliency to climate change, be part of a national strategy to 

reduce dependence on fossil fuels, and contribute to climate 

change mitigation by acting as a “sink” for carbon. The plant 

growth associated with producing many of the biomass-derived 

fuels can, to varying degrees for different biomass feedstocks, 

sequester carbon from the atmosphere. For example, America’s 

forests currently play a critical role in addressing carbon 

pollution, removing nearly 12 percent of total U.S. greenhouse 

gas emissions each year. As a result, broadly speaking, burning 

biomass-derived fuels for energy recovery can yield climate 

benefits as compared to burning conventional fossil fuels. 

Many states have recognized the importance of forests and 

other lands for climate resilience and mitigation and have 

developed a variety of different sustainable forestry policies, 
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renewable energy incentives and standards and greenhouse gas 

accounting procedures. Because of the positive attributes of 

certain biomass-derived fuels, the EPA also recognizes that 

biomass-derived fuels can play an important role in carbon 

dioxide (CO2) emission reduction strategies. We anticipate that 

states will likely consider biomass-derived fuels in energy 

production as a way to mitigate the CO2 emissions attributed to 

the energy sector and include them as part of their plans to 

meet the emission reduction requirements of this rule and we 

think it is important to define a clear path for states to do 

so. 

To better understand the impacts of using different types 

of biomass-derived fuels, the EPA is assessing the use of 

biomass feedstocks for energy recovery by stationary sources and 

developed a draft accounting framework which EPA’s Science 

Advisory Board (SAB) has reviewed. The draft framework concluded 

that while biomass and other biogenic feedstocks have the 

potential to reduce the overall level of CO2 emissions resulting 

from electricity generation, the contribution of biomass-derived 

fuels to atmospheric CO2 is sensitive to the type of biomass 

feedstock used, and the way in which the feedstock is grown, 

processed, and ultimately combusted as a fuel for energy 
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production. The SAB in its review similarly found that there are 

circumstances in which biomass is grown, harvested and combusted 

in a carbon neutral fashion but commented that additional 

considerations are warranted. 

The EPA is in the process of revising the draft framework 

and considering next steps, taking into account both the 

comments provided by the SAB and feedback from 

stakeholders. Once finalized, the EPA’s biogenic CO2 accounting 

framework is expected to provide important information regarding 

the scientific basis for assessing these biomass-derived fuels 

and their net atmospheric contribution of CO2 related to the 

growth, harvest and use of these fuels. This information should 

assist both states and the EPA in assessing the impact of the 

use of biomass fuels in reaching emission reduction goals in the 

energy sector under state plans to comply with the requirements 

in the emission guidelines. 

9. Consideration of a facility’s “remaining useful life” in 

applying standards of performance 

In this section, the EPA discusses the relevance to this 

rule of the statutory provision that requires EPA regulations 

implementing CAA section 111(d) to “permit the State in applying 

a standard of performance to any particular source under a 

Comment [A77]: Move this text to 

page ~200 as reflected above
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[111(d)] plan . . . to take into consideration, among other 

factors, the remaining useful life of the existing source to 

which such standard applies.” 

As the EPA recognized in 1975 when it adopted framework 

regulations for implementation of CAA section 111(d) including 

the “remaining useful life” statutory provision, application of 

the implementing provisions in the framework regulations may not 

be appropriate in every instance.254 For the reasons discussed 

below, the EPA is proposing that, in this case, the flexibility 

provided in the state plan development process adequately allows 

for consideration of the remaining useful life of the affected 

facilities and other source-specific factors and, therefore, 

that separate application of the remaining useful life provision 

by states in the course of developing and implementing their CAA 

section 111(d) plans is unnecessary. The agency is requesting 

comment on its analysis below of the implications of the EPA’s 

existing regulations interpreting “useful life” and “other 

factors” for purposes of this rulemaking. The agency also 

requests comment on whether it would be desirable to include any 

 

254 The agency is not reopening or considering changes to the 

existing framework regulations. 
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aspects of this analysis in regulatory text of this emission 

guideline. 

This section addresses the legal background concerning 

facility-specific considerations and the implications for 

implementation of these emission guidelines, including state 

emissions performance goals. 

a. Legal background 

As reflected in the framework regulations, the EPA believes 

that Congress included the remaining useful life provision in 

CAA section 111(d) to avoid imposition of unreasonable costs on 

an existing source that has a limited remaining useful life. 

This could occur if a rule imposed high capital costs that would 

normally be amortized over long periods of time. If a facility 

will cease operation in the near future, it may have little time 

to earn revenue to help pay for the pollution control 

investment, and the facility’s retirement may occur before that 

debt is paid off. In addition, the impact of the controls in 

reducing emissions may be short-lived. As a result, it could be 

unreasonable for a facility with a short remaining useful life 

to incur the same pollution control costs that are reasonable 

for a facility with a long remaining useful life. Thus, 

remaining useful life could affect the determination of what 
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requirements are appropriate for a facility with a short 

remaining useful life. 

The EPA’s 1975 framework regulations contain the following 

provision,255 which addresses remaining useful life and other 

facility-specific factors that might affect requirements for an 

existing source under section 111(d): 

“Unless otherwise specified in the applicable subpart, 

on a case-by-case basis for particular designated 

facilities, or classes of facilities, States may provide 

for the application of less stringent emission standards or 

longer compliance schedules than those otherwise required 

by paragraph (c) of this section256, provided that the state 

demonstrates with respect to each such facility (or class 

of facilities): 

(1) Unreasonable cost of control resulting from plant 

age, location, or basic process design; 

(2) Physical impossibility of installing necessary 

control equipment; or 

(3) Other factors specific to the facility (or class 

of facilities) that make application of a less stringent 

standard or final compliance time significantly more 

reasonable. 

The reference to “[u]nreasonable cost of control resulting 

from plant age” reflects the statutory provision on remaining 

useful life. The language concerning plant location, basic 

 

255 40 CFR Section 60.24(f) 256 Paragraph (c) requires that for pollutants that endanger 

public health, standards of performance in state plans must be 

as stringent as EPA’s emission guidelines.
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process design, physical impossibility of installing controls, 

and “other factors” addresses facility-specific issues other 

than remaining useful life that in some circumstances can affect 

the reasonableness of a control measure for a particular 

existing source. 

This regulatory provision provides the EPA’s default 

structure for implementing the remaining useful life provision 

of CAA section 111(d). The opening clause, however, which 

provides that this provision is applicable “unless otherwise 

specified in the applicable subpart” makes clear that this 

structure may not be appropriate in each case and that the EPA 

has discretion to alter the extent to which states may authorize 

relaxations to standards of performance that would otherwise 

apply to a particular source or source category, if appropriate 

under the circumstances of the specific source category and 

proposed guidelines. 

b. Implications for implementation of this emissions guideline 

In general, the EPA notes that the framework regulation 

provisions for remaining useful life and other facility-specific 

factors are relevant for emission guidelines in which the EPA 

specifies a presumptive standard of performance that must be 

fully and directly implemented by each individual existing 
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source within a specified source category. Such guidelines are 

much more like a CAA section 111(b) standard in their form. For 

example, the EPA emission guidelines for sulfuric acid plants, 

phosphate fertilizer plants, primary aluminum plants, and Kraft 

pulp plants specify emission limits for sources.257 In the case of 

such emission guidelines, some individual sources, by virtue of 

their age or other unique circumstances, may warrant special 

accommodation. 

In the guidelines for state plans to limit CO2 from affected 

EGUs that the EPA is proposing, the agency does not take that 

approach. Instead, the EPA is proposing to establish state 

emissions performance goals for the collective group of affected 

EGU in a state, and leaving to each state the design of the 

specific requirements that fall on each affected EGU. Due to the 

inherent flexibility in the EPA’s approach to establishing the 

state-specific goals, and the flexibility provided to states in 

developing approvable CAA section 111(d) plans to achieve those 

goals, no relief for individual facilities is needed from 

requirements in the EPA’s guidelines, because the EPA’s 

 

257 [cites] 
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guideline contains no emissions standards that the state must 

apply directly to a specific EGU. 

Rather, because of the flexibility for states to design 

their own standards, the states have the ability to address the 

issues involved with “remaining useful life” and “other factors” 

in the initial design of those standards, which would occur 

within the framework of the section 111(d) plan development 

process. States are free to specify requirements for individual 

EGUs that are appropriate considering remaining useful life and 

other facility-specific factors. 

Therefore, to the extent that a performance standard that a 

state may wish to adopt for affected EGUs raises facilityspecific issues, the state would be authorized to make 

adjustments to a particular facility’s requirements on facilityspecific grounds, so long as any such adjustments are reflected 

(along with any necessary compensating emission reductions), as 

part of the state’s CAA section 111(d) plan submission. The 

agency requests comment on its interpretation. 

c. Relationship to state emission performance goals and timing 

of achievement 

The EPA also believes that remaining useful life and other 

facility-specific considerations should not affect the 
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determination of a state’s rate-based or mass-based emission 

performance goal or the state’s obligation to develop and submit 

an approvable CAA section 111(d) plan that achieves that goal by 

the applicable deadline. 

Under the proposed guideline, states would have the 

flexibility to adopt a state plan that relies on emissionreducing requirements that do not require affected EGUs with a 

short remaining useful life to make major capital expenditures258

or incur unreasonable costs. Indeed, the EPA’s proposal would 

provide states with broad flexibility regarding ways to improve 

emission performance through utilizing the emissions reduction 

methods represented by the four “building blocks.” Of the four 

building blocks considered by the EPA in developing state goals, 

only the first block, heat rate improvements, involves capital 

investments at the affected EGUs. The other building blocks – 

re-dispatch among affected sources, addition of new generating 

capacity, and improvement in end-use energy efficiency – do not 

 

258 The agency requests comment on whether there are circumstances other than a 

major capital investment that could lead to a prospective state plan imposing 

unreasonable costs considering a facility’s remaining useful life. Where 

annual costs predominate and/or capital costs do not constitute a major 

expense, the EPA believes that the remaining useful life of an affected EGU 

will not significantly affect its annualized cost of control and therefore 

should not be a factor in determining control requirements for the EGU. 
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generally involve capital investments by the owner/operator at 

an affected EGU. 

In the case of heat rate improvements at affected EGUs, the 

assumed 6 percent heat rate improvement in the EPA’s proposed 

BSER determination would be applicable to affected EGUs on a 

state-wide average basis, allowing the state to require a 

greater or lesser degree of heat rate improvement from any 

individual EGU in light of that EGU’s remaining useful life or 

any other source-specific factors that the state deemed 

appropriate to consider.259 The agency notes that any capital 

expenditures would be much smaller than capital expenditures 

required for example, for purchase and installation of scrubbers 

to remove sulfur dioxide; a fleet-wide average cost for heat 

rate improvements at coal-fired generating units is $100/kW, 

compared with a typical SO2 scrubber cost of $500/kw (costs vary 

 

259 Where states are unable to achieve the average 6 percent heat 

rate improvement assumed in the EPA’s BSER determination in 

light of the remaining useful life of one or more of their 

affected EGUs or for any other reasons (or where state so choose 

based on other considerations), they may adopt plan provisions 

that will obtain a lesser degree of average heat rate 

improvement from affected EGUs. A state is not required to 

achieve the same level of emission reductions with respect to 

any one building block as assumed in the EPA’s BSER analysis, as 

long as they provide additional compensating emission reductions 

with respect to the other three building blocks. 
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with unit size).260 In addition, the proposed guideline allows 

states to regulate affected EGUs through flexible regulatory 

approaches that do not require affected EGUs to incur large 

capital costs (e.g., averaging and trading programs). Under 

EPA’s proposed approach -- establishing state goals and 

providing states with flexibility in plan design – states have 

flexibility to avoid requirements that would result in stranded 

assets. 

Remaining useful life and other factors, because of their 

facility-specific nature, are potentially relevant in 

determining requirements that are directly applicable to 

affected EGUs. For all of the reasons above, the agency believes 

that the issue of remaining useful life will arise infrequently 

in the development of state plans to limit CO2 emissions from 

affected existing EGUs. Even if relief is due a particular 

facility, the state has an available toolbox of emission 

reduction methods that it can use to develop a section 111(d) 

plan that meets its emissions performance goal on time. The EPA 

 

260 Heat rate improvement methods and related capital costs are 

discussed in the GHG Abatement Measures TSD; SO2 scrubber capital 

costs are from the documentation for EPA’s IPM Base Case v5.13, 

Chapter 5, Table 5-3, available at 

http://www.epa.gov/powersectormodeling/BaseCasev513.html Field Code Changed
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therefore proposes that the remaining useful life of affected 

EGUs, and the other facility-specific factors identified in the 

existing framework regulations, should not be considered as a 

basis for adjusting a state emission performance goal or for 

relieving a state of its obligation to develop and submit an 

approvable plan that achieves that goal on time. The agency 

solicits comment on this position. 

G. Additional Factors That Can Help State Meet Their CO2 Emission 

Performance Goals 

A resource available from the EPA for states pursuing marketbased approaches is the EPA’s data and experience in support of 

state trading programs and emissions data collection. For states 

needing technical assistance with data or operation of marketbased programs, existing EPA data systems are a resource that 

have been used to collect emissions data, track allowances and 

transfers, and determine compliance for state programs. For 

example, New Hampshire was part of the Ozone Transport 

Commission (OTC) trading program but was not included in the NOx 

SIP Call. Because the state wanted its sources to continue to 

participate in a state trading program, the EPA operated the 

emissions trading program for New Hampshire sources, from 

allocating allowances to compliance determination. 
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Additionally, as noted elsewhere in this preamble, more than 

25 states have mandatory renewable portfolio standards and other 

states have voluntary renewable programs and goals. There is 

considerable diversity among the states in the scope and 

coverage of these standards, in particular in how renewable 

resources are defined. At the federal level, the EPA has 

considered the greenhouse gas implications related to biomass 

use at stationary sources through several actions, including a 

call for information from stakeholders and the development and 

review of the “Accounting Framework for Biogenic CO2 Emissions 

from Stationary Sources,” issued in September 2011. That study 

was reviewed by the EPA’s Science Advisory Board in 2011 and 

2012 and the agency continues to assess the framework and 

consider the latest scientific analyses and technical input 

received from stakeholders. The EPA expects that the framework, 

when finalized, will be a resource that could help inform states 

in the development of their CAA section 111(d) plans. 

H. Resources for States to Consider in Developing Their Plans 

As part of the stakeholder outreach process, the EPA asked 

states what the agency could do to facilitate state plan 

development and implementation. Some states indicated that they 

wanted the EPA to create resources to assist with state plan 
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development, especially resources related to accounting for enduse energy efficiency and renewable energy (EE/RE) in state 

plans. They requested clear methodologies for measuring EE/RE 

policies and programs, so that these could be included as part 

of their compliance strategies. Stakeholders said that these 

tools and metrics should build upon the EPA’s “Roadmap for 

Incorporating Energy Efficiency/Renewable Energy Policies and 

Programs into State and Tribal Implementation Plans,”261 as well 

as the State Energy Efficiency Action Network’s “Energy 

Efficiency Program Impact Evaluation Guide.”262 The EPA also 

heard that states would like examples of effective state 

policies and programs. 

As a result of this feedback, in consultation with U.S. 

Department of Energy and other federal agencies, the EPA has 

developed a toolbox of decision support resources, and this is 

available at [http://www2.epa.gov/carbon-pollutionstandards/toolbox]. Current resources on the site focus on 

approaches states and other entities have already taken that 

reduce CO2 emissions from the electric utility sector. 

 

261 http://epa.gov/airquality/eere/ 262

http://www1.eere.energy.gov/seeaction/pdfs/emv_ee_program_impact

_guide.pdf

Comment [A78]: What will be in this toolbox? 
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For the final rulemaking, the EPA plans to organize 

resources around the following two categories: state plan 

guidance and state plan decision support. The state plan 

guidance section will serve as a central repository for the 

final emission guidelines, regulatory impact analysis, technical 

support documents, and other supporting materials. The state 

plan decision support section will include information to help 

states evaluate different approaches and measures they might 

consider as they initiate plan development. This section will 

include, for example, a summary of existing state climate and 

EE/RE policies and programs,263 National Action Plan for Energy 

Efficiency (Action Plan),264 information on electric utility 

actions that reduce CO2, and tools and information to assist with 

translating energy savings into emission reductions. 

We note that our inclusion of a measure in the toolbox does 

not mean that a state plan must include that measure. In fact, 

inclusion of measures provided at the website does not 

necessarily imply the approvability of an approach or method for 

use in a state plan. States will need to demonstrate that any 

 

263 Appendix, State Plan Considerations TSD 264 http://www.epa.gov/cleanenergy/energyprograms/suca/resources.html
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measure included in a state plan meets all relevant 

approvability criteria and adequately addresses elements of the 

plan components discussed in Section VIII of this preamble. 

The EPA solicits comment on this approach and the 

information currently included, and planned for inclusion, in 

the Decision Support Toolbox. 

IX. Implications for Other EPA Programs and Rules 

A. Implications for New Source Review Program 

 The new source review (NSR) program is a preconstruction 

permitting program that requires major stationary sources of air 

pollution to obtain permits prior to beginning construction. The 

requirements of the NSR program apply both to new construction 

and to modifications of existing major sources. Generally, a 

source triggers these permitting requirements as a result of a 

modification when it undertakes a physical or operational change 

that results in a significant emission increase and a net 

emissions increase. NSR regulations define what constitutes a 

significant net emissions increase, and the concept is 

pollutant-specific. For GHG emissions, the PSD applicability 

analysis is described in the Prevention of Significant 

Deterioration and Title V Greenhouse Gas Tailoring Rule (FR 75 

31514, June 3, 2010). As a general matter, a modifying major 
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stationary source would trigger PSD permitting requirements for 

GHGs if it emits GHGs in excess of 100,000 tons per year (tpy) 

of carbon dioxide equivalents (CO2e), and it undergoes a change 

or change in the method of operation (modification) resulting in 

an emissions increase of 75,000 tpy CO2e as well as an increase 

on a mass basis. Once it has been determined that a change 

triggers the requirements of the NSR program, the source must 

obtain a permit prior to making the change. The pollutant(s) at 

issue and the air quality designation of the area where the 

facility is located or proposed to be built determine the 

specific permitting requirements. 

As part of its CAA section 111(d) plan, a state may require 

an affected EGU to undertake a physical or operational change to 

improve the unit’s efficiency that results in an increase in the 

unit’s dispatch and an increase in the unit’s annual emissions. 

If the emissions increase associated with the unit’s changes 

exceeds the thresholds in the NSR regulations discussed above 

for one or more regulated NSR pollutants, the EGU would trigger 

NSR. 

As previously discussed in this preamble, states have 

considerable flexibility in selecting varied measures as they 

develop their plans to meet the goals of the emissions 
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guidelines. One of these flexibilities is the ability of the 

state to establish the standards of performance in their CAA 

section 111(d) plans in such a way so that their affected 

sources, in complying with those standards, in fact would not 

have emissions increases that trigger NSR. To achieve this, the 

state would need to conduct an analysis consistent with the NSR 

regulatory requirements that supports its determination that as 

long as affected sources comply with the standards of 

performance in their CAA section 111(d) plan, the source’s 

emissions would not increase in a way that trigger NSR 

requirements. 

For example, a state could decide to adjust its demand side 

measures or increase reliance on renewable energy as a way of 

reducing the future emissions of an affected source initially 

predicted (without such alterations) to increase its emissions 

as a result of a CAA section 111(d) plan requirement. In other 

words, a state plan’s incorporation of expanded use of cleaner 

generation or demand-side measures could yield the result that 

units that would otherwise be projected to trigger NSR through a 

change in dispatch would not, in fact, increase their emissions, 

due to reduced demand for their operation. The state could also, 

as part of its CAA section 111(d) plan, develop conditions for a 
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source expected to trigger NSR that would limit the unit’s 

ability to move up in the dispatch enough to result in a 

significant net emissions increase that would trigger NSR 

(effectively establishing a synthetic minor limit). If we are 

satisfied with the state’s showing that the standards of 

performance in its plan, if complied with, will not have 

emissions increase that trigger NSR, we will approve this 

provision in the state plan. 

We request comment on whether, with adequate record 

support, the state plan could include a provision stating that 

an affected source that complies with its applicable standard 

would be treated as not increasing its emissions, and if so, 

whether such a provision would mean that, as a matter of law, 

the source’s actions to comply with its standard would not 

subject the source to NSR. We also seek comment on the level of 

analysis that would be required to support a state’s 

determination that sources will not trigger NSR when complying 

with the standards of performance included in the state’s CAA 

section 111(d) plan and the type of plan requirements, if any, 

that would need to be included in the state’s plan. 
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As a result of such flexibility and anticipated state 

involvement, we expect that a limited number of affected sources 

would trigger NSR when states implement their plans. 

B. Implications for Title V Program 

The preamble to the re-proposed EGU NSPS (70 FR 1429-1519; 

January 8, 2014) explained that regulating GHGs for the first 

time under section 111 of the CAA would make GHGs “regulated air 

pollutants” for the first time under the operating permit 

regulations of 40 CFR parts 70 and 71. This would result in GHGs 

becoming “fee pollutants” in certain state part 70 permit 

programs and in the EPA’s part 71 permit program, thus requiring 

the collection of fees for GHG emissions in these 

programs. Where title V fees would be required for GHGs, they 

would typically be charged at the same rate ($ per ton of 

pollutant) as all other fee pollutants. This would likely result 

in excessive and unnecessary fees being charged to subject 

sources. To avoid this situation, we proposed to exempt GHGs 

from the fee rates in effect for other fee pollutants, while 

proposing an alternative fee that would be much lower than the 

fee charged to other fee pollutants, yet sufficient to cover the 

costs of addressing GHGs in operating permits. 

This title V fee issue is a one-time occurrence resulting 
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from the promulgation of the first CAA section 111 standard to 

regulate GHGs (the EGU NSPS for new sources) and is not an issue 

for any other subsequent section 111 regulations, so there is no 

need to address any title V fee issues in this proposal. Thus, 

we are not re-visiting these title V fee issues in this 

proposal, and we are not proposing any additional revisions to 

any title V regulations as part of this action. 

The title V regulations require each permit to include 

emission limitations and standards, including operational 

requirements and limitations that assure compliance with all 

applicable requirements. Requirements resulting from this rule 

that are imposed on affected EGUs or any other potentially 

affected entities that have title V operating permits are 

applicable requirements under the title V regulations and would 

need to be incorporated into the source’s title V permit in 

accordance with the schedule established in the title V 

regulations. For example, if the permit has a remaining life of 

3 years or more, a permit reopening to incorporate the newly 

applicable requirement shall be completed no later than 18 

months after promulgation of the applicable requirement. If the 

permit has a remaining life of less than 3 years, the newly 

applicable requirement must be incorporated at permit renewal. 
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C. Interactions with Other EPA Rules 

Existing fossil fuel-fired EGUs, such as those covered in 

this proposal, are or will be potentially impacted by several 

other recently finalized or proposed EPA rules.265 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. The MATS rule 

will reduce emissions of heavy metals, including mercury (Hg), 

arsenic (As), chromium (Cr), and nickel (Ni); and acid gases, 

including hydrochloric acid (HCl) and hydrofluoric acid (HF). 

These toxic air pollutants, also known as hazardous air 

pollutants or air toxics, are known or suspected of causing 

damage to the nervous system, cancer, and other serious health 

effects. The MATS rule will also reduce SO2 and fine particle 

pollution, which will reduce particle concentrations in the air 

and prevent thousands of premature deaths and tens of thousands 

of heart attacks, bronchitis cases and asthma episodes. 

The EPA is closely monitoring MATS compliance and finds 

that the industry is making substantial progress. Plant owners 

 

265 We discuss other rulemakings solely for background purposes. 

The effort to coordinate rulemakings is not a defense to a 

violation of the CAA. Sources cannot defer compliance with 

existing requirements because of other upcoming regulations. 
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are moving proactively to install controls that will achieve the 

MATS performance standards. Certain units, especially those that 

operate infrequently, may be considered not worth investing in 

given today’s electricity market, and those are closing. 

Existing sources subject to the MATS rule are given until 

April 16, 2015 to comply with the rule's requirements. The final 

MATS provided a foundation on which states and other permitting 

authorities could rely in granting an additional, 4th year for 

compliance provided for by the Act. States report that these 4th

year extensions are being granted. In addition, the EPA issued 

an enforcement policy that provides a clear pathway for 

reliability-critical units to receive an administrative order 

that includes a compliance schedule of up to an additional year, 

if it is needed to ensure electricity reliabilityOn [INSERT 

PUBLICATION DATE OF FINAL RULE (which should be finalized in 

April)], the EPA issued a final rule under section 316(b) of the 

Clean Water Act (33 U.S.C. 1326(b)) (referred to hereinafter as 

the 316(b) rule). This rule includes new standards to reduce 

injury and death of fish and other aquatic life caused by 

cooling water intake structures at existing power plants and 
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manufacturing facilities.266 The 316(b) rule subjects existing 

power plants and manufacturing facilities that withdraw in 

excess of 2 million gallons per day (MGD) of cooling water, and 

use at least 25 percent of that water for cooling purposes, to a 

national control requirement that limits the number of fish 

destroyed through impingement, as well as site-specific 

entrainment mortality standards. Certain plants that withdraw 

very large volumes of water will also be required to conduct 

studies for use by the permit authority in determining the sitespecific entrainment mortality standards for such facilities. 

The rule provides significant flexibility for compliance with 

the impingement standards and, as a result, is not projected to 

impose a substantial cost burden on affected facilities. With 

respect to entrainment, the rule calls upon the permitting 

authority to exercise best professional judgment in establishing 

appropriate site-specific standards, taking into account, among 

other factors, compliance costs, facility reliability and grid 

reliability. Existing sources subject to the 316(b) rule are 

 

266 CWA section 316(b) provides that standards applicable to 

point sources under sections 301 and 306 of the Act must require 

that the location, design, construction and capacity of cooling 

water intake structures reflect the best technology available 

for minimizing adverse environmental impacts.
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given until [INSERT DATE] (i.e., 8 years from the rule's 

effective date) to comply with the rule's impingement standards. 

They must comply with applicable site-specific entrainment 

mortality standards based on the schedule of requirements 

established by the permitting authority. 

The EPA is also reviewing public comments and working to 

finalize two proposed rules which will also impact existing 

fossilfuel-fired EGUs: the steam electric effluent limitation 

guidelines (SE ELG) rule and the coal combustion residuals (CCR) 

rule. These proposed rules are summarized below. 

On June 7, 2013 (78 FR 34432), the EPA proposed the SE ELG 

rule to strengthen the controls on discharges from certain steam 

electric power plants by revising technology-based effluent 

limitations guidelines and standards for the steam electric 

power generating point source category. The current regulations, 

which were last updated in 1982, do not adequately address the 

toxic pollutants discharged from the electric power industry, 

nor have they kept pace with process changes that have occurred 

over the last three decades. Existing steam electric power 

plants currently contribute 50-60 percent of all toxic 

pollutants discharged to surface waters by all industrial 

categories regulated in the United States under the Clean Water 
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Act. Furthermore, power plant discharges to surface waters are 

expected to increase as pollutants are increasingly captured by 

air pollution controls and transferred to wastewater discharges. 

This proposed regulation, which includes new requirements for 

both existing and new generating units, would reduce the amount 

of toxic metals and other pollutants discharged to surface 

waters from power plants. 

 On June 21, 2010 (75 FR 35128), the EPA proposed the CCR 

rule, which co-proposed two approaches to regulating the 

disposal of coal combustion residuals (CCRs) generated by 

electric utilities and independent power producers. CCRs are 

residues from the combustion of coal in steam electric power 

plants and include materials such as coal ash (fly ash and 

bottom ash) and flue gas desulfurization (FGD) wastes. Under one 

proposed approach, the EPA would list these residuals as 

“special wastes,” when destined for disposal in landfills or 

surface impoundments, and would apply the existing regulatory 

requirements established under Subtitle C of RCRA to such 

wastes. Under the second proposed approach, the EPA would 

establish new regulations applicable specifically to CCRs under 

subtitle D of RCRA, the section of the statute applicable to 

solid (i.e., non-hazardous) wastes. Under both approaches, CCRs 
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that are beneficially used would remain exempt under the Bevill 

exclusion.267 While the agency is still evaluating all the 

available information and comments, and while a final risk 

assessment for the CCR rule has not yet been completed, reliance 

on data and analyses discussed in the preamble to the recent 

Steam Electric ELG proposal may have the potential to lower the 

CCR rule risk assessment results by as much as an order of 

magnitude. If this proves to be the case, EPA’s current thinking 

is that the revised risks, coupled with the ELG requirements 

that the agency may promulgate, and the increased federal 

oversight such requirements could achieve, could provide strong 

 

267 Beneficial use involves the reuse of CCRs in a product to 

replace virgin raw materials that would otherwise be obtained 

through extraction. The EPA encourages the beneficial use of 

CCRs in an appropriate and protective manner, because this 

practice can produce environmental, economic, and performance 

benefits. The Agency recently evaluated the environmental 

impacts associated with encapsulated beneficial uses of fly ash 

used as a direct substitute for Portland cement in concrete, and 

FGD gypsum used as a replacement for mined gypsum in wallboard. 

The EPA concluded that the beneficial use of CCRs in concrete 

and wallboard is appropriate because the environmental releases 

of constituents of potential concern (COPC) during use by the 

consumer are comparable to or lower than those from analogous 

non-CCR products, or are at or below relevant regulatory and 

health-based benchmarks for human and ecological receptors. See

U.S. Environmental Protection Agency, Coal Combustion Residual 

Beneficial Use Evaluation: Fly Ash Concrete and FGD Gypsum 

Wallboard (2014). 
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support for a conclusion that regulation of CCR disposal under 

RCRA Subtitle D would be adequate.268 The EPA is under a courtordered deadline to complete the CCR rulemaking by December 19, 

2014. 

 The EPA recognizes the importance of assuring that each of 

the rules described above can achieve its intended environmental 

objectives in a commonsense, cost-effective manner consistent 

with underlying statutory requirements and while assuring a 

reliable power system. Executive Order (EO) 13563, “Improving 

Regulation and Regulatory Review,” issued on January 18, 2011, 

states that “[i]n developing regulatory actions and identifying 

appropriate approaches, each agency shall attempt to promote... 

coordination, simplification, and harmonization. Each agency 

shall also seek to identify, as appropriate, means to achieve 

regulatory goals that are designed to promote innovation.” 

Within the EPA, we are paying careful attention to the 

 

268 U.S. EPA. September 2013. Regulatory Impact Analysis for the 

Proposed Standards of Performance for Greenhouse Gas Emissions 

for New Stationary Sources: Electric Utility Generating Units. 

EPA-452/R-13-003. Available at 

http://www2.epa.gov/sites/production/files/2013-

09/documents/20130920proposalria.pdf 

 
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interrelatedness and potential impacts on the industry, 

reliability and cost that these various rulemakings can have. 

As discussed in Sections VII and VIII of this preamble, the 

EPA is proposing to give states broad flexibility in developing 

approvable plans under CAA section 111(d), including the ability 

to adopt rate-based or mass-based emission performance goals, 

and to rely on a wide variety of CO2 emission reduction measures. 

The EPA is also proposing to give states considerable 

flexibility with respect to the timeframes for plan development 

and implementation, with up to two or three years permitted for 

final plans to be submitted after the proposed GHG emission 

guidelines are finalized, and up to fifteen years for all 

emission reduction measures to be fully implemented. In light of 

these flexibilities, we believe that states will have ample 

opportunity, when developing and implementing their CAA section 

111(d) plans, to coordinate their response to this requirement 

with source and state responses to any obligations that may be 

applicable to affected EGUs as a result of the MATS, 316(b), SE 

ELG and CCR rules – all of which are or will be final rules 

before this rulemaking is finalized – and to do so in a manner 

that will help reduce cost and ensure reliability, while also 
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ensuring that all applicable environmental requirements are 

met.269

The EPA is also endeavoring to enable EGUs to comply with 

applicable obligations under other power sector rules as 

efficiently as possible (e.g., by facilitating their ability to 

coordinate planning and investment decisions with respect to 

those rules) and, where possible, implement integrated 

compliance strategies. For example, in the proposed SE ELG rule, 

the EPA describes its current thinking on how it might 

effectively harmonize the potential requirements of that rule 

with the requirements of the final CCR rule, to the extent that 

both rules may regulate or affect the disposal of coal 

combustion wastes to and from surface impoundments at power 

plants.270 The EPA’s goal in exploring how it might harmonize the 

SE ELG and CCR rules is to minimize the overall complexity of 

 

269 It should be noted that regulatory obligations imposed upon 

states and sources operate independently under different 

statutes and sections of statutes; the EPA expects that states 

and sources will take advantage of available flexibilities as 

appropriate, but will comply with all relevant legal 

requirements.

270 See: Federal Register Vol. 78, No. 110; June 7, 2013. Page 

34441. 
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the two regulatory structures and avoid creating unnecessary 

burdens.271

In addition to the power sector rules discussed above, the 

development of SIPs for criteria pollutants (PM2.5, ozone and SO2) 

and regional haze may also have implications for existing 

fossil-fired EGUs. 

On June 6, 2013, the EPA proposed an implementation rule 

for the 2008 ozone National Ambient Air Quality Standards 

(NAAQS), to provide rules and guidance to states on the 

development of approvable state implementation plans (SIPs), 

including SIPs under CAA section 110 (infrastructure SIPs) and 

 

271 [We could include some or all of the following modified 

language from proposed the SE ELG rule as a footnote:] In 

considering how to coordinate the potential requirements between 

the SE ELG and CCR rules, the EPA stated that it is guided by 

the following policy considerations: first and foremost, the EPA 

intends to ensure that its statutory responsibilities to restore 

and maintain water quality under the CWA and to protect human 

health and the environment under RCRA are fulfilled. At the same 

time, the EPA would seek to minimize the potential for 

overlapping requirements to avoid imposing any unnecessary 

burdens on regulated entities and to facilitate implementation 

and minimize the overall complexity of the regulatory structure 

under which facilities must operate. Based on these 

considerations, the EPA stated that it is exploring two primary 

means of integrating the two rules: (1) through coordinating the 

design of any final substantive CCR regulatory requirements, and 

(2) through coordination of the timing and implementation of 

final rule requirements to provide facilities with a reasonable 

timeline for implementation that allows for coordinated planning 

and protects electricity reliability for consumers. 
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section 182 (ozone nonattainment SIPs). This rule addresses the 

statutory requirements for areas EPA has designated as 

nonattainment for the 2008 ozone standard. The agency is 

currently working to finalize that rule. The EPA is also working 

on a proposed transport rule that would identify the obligations 

of upwind states that contribute to those downwind state ozone 

nonattainment areas. This rule is scheduled for proposal in 2014 

and to be finalized by 2015. 

The EPA is developing a proposed implementation rule to 

provide guidance to states on the development of SIPs for the 

2012 PM2.5 NAAQS. 

The SO2 NAAQS was revised in June 2010 to protect public 

health from the short-term effects of SO2 exposure. In July 2013, 

the EPA designated 29 areas in 16 states as nonattainment for 

the SO2 NAAQS. The EPA based these nonattainment designations on 

the most recent set of certified air quality monitoring data as 

well as an assessment of nearby emission sources and weather 

patterns that contribute to the monitored levels. The EPA 

intends to address the designations for all other areas in 
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separate actions in the future272. The EPA has proposed the data 

requirements rule for the 1-hour SO2 NAAQS to require states to 

characterize air quality more extensively using ambient 

monitoring or air quality modeling approaches. 

The EPA requires SIP updates every 10 years for regional 

haze, as required by the EPA’s Regional Haze Rule which was 

promulgated in 1999. The next 10-year SIP revision for regional 

haze, covering the time period through 2028, is due from each 

state by July 2018. Each SIP must provide for reasonable 

progress towards visibility improvement in protected scenic 

areas. 

The development of these SIPs may, where applicable, have 

significant implications for existing fossil fuel-fired EGUs, as 

well as for the states that are responsible for developing them. 

The timeframes for submittal of SIPs for the various programs 

and the timeframes we are proposing for submittal of the CAA 

section 111(d) state plans will allow considerable time for 

coordination by states in the development of their respective 

 

272 The EPA has developed a comprehensive implementation 

strategy for these future actions that focuses resources on 

identifying and addressing unhealthy levels of SO2 in areas where 

people are most likely to be exposed to violations of the 

standard. The strategy is available at: 

http://www.epa.gov/airquality/sulfurdioxide/implement.html.
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plans. The EPA is willing to work with states to assist them in 

coordinating their efforts across these planning processes. The 

EPA believes that CAA section 111(d) efforts and actions will 

tend to contribute to overall air quality improvements and thus 

should be complementary to criteria pollutant and regional haze 

SIP efforts. 

In light of the broad flexibilities we are proposing in 

today’s action, we believe that states will have ample 

opportunity to design CAA section 111(d) plans that use 

innovative, cost-effective regulatory strategies and that spark 

investment and innovation across a wide variety of clean energy 

technologies. We also believe that the broad flexibilities we 

are proposing in this action will enable states and affected 

EGUs to build on their longstanding, successful records of 

complying with multiple CAA, CWA, and other environmental 

requirements, while assuring an adequate, affordable, and 

reliable supply of electricity. 

X. Impacts of the Proposed Action273

 

273 The impacts presented in this section of the preamble 

represent an illustrative implementation of the guidelines. As 

states implement the proposed guidelines, they have sufficient 

flexibility to adopt different state-level or regional 
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A. What are the air impacts? 

The EPA anticipates significant emission reductions under 

the proposed guidelines. for the power sector. CO2 emissions are 

projected to be reduced, relative to 2005 emissions, by 26 

percent to 27 percent in 2020 and about 30 percent in 2030 under 

Option 1. Option 2 reflects reductions of about 23 percent in 

2020 and 22 percent to 23 percent in 2030. The guidelines are 

projected to result in substantial co-benefits through 

reductions of SO2, PM2.5 and NOx that will have direct public 

health benefits by lowering ambient levels of these pollutants 

and ozone. Tables 7 and 8 show expected CO2 and other air 

pollutant emission reductions in the base case, with the 

proposed Option 1 and regulatory alternative Option 2, 

respectively, for 2020, 2025, and 2030. 

Table 7 – Summary of CO2 and Other Air Pollutant Emission 

Reductions with Option 1 

 

approaches that may yield different costs, benefits, and 

environmental impacts. For example, states may use the 

flexibilities described in these guidelines to find approaches 

that are more cost effective for their particular state or 

choose approaches that shift the balance of co-benefits and 

impacts to match broader state priorities. 

Comment [A79]: One suggestion for providing 

the comparison baseline 

Comment [A80]: Please clarify what this is 

relative to. 
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CO2

(million 

metric 

tons) 

SO2

(thousands 

of tons) 

NOX 

(thousands 

of tons) 

PM2.5 

(thousands 

of tons) 

2020 Regional Compliance Approach 

Base Case 2,161 1,476 1,559 N/A

Proposed 1,790 1,184 1,213 

Guidelines 

Emission 

Reductions 

 -371 -292 -345 

2025 Regional Compliance Approach 

Base Case 2,231 1,515 1,587 

Proposed 1,730 1,120 1,166 N/A

Guidelines 

Emission 

Reductions 

 -501 -395 -421 

2030 Regional Compliance Approach 

Base Case 2,256 1,530 1,537 N/A

Proposed 1,711 1,106 1,131 

Guidelines 

Emission 

Reductions 

 -545 -424 -407 

2020 State Compliance Approach 

Base Case 2,161 1,476 1,559 

Proposed 

Guidelines 1,777 1,140 1,191 N/A

Emission 

Reductions -383 -335 -367 

2025 State Compliance Approach 

Base Case 2,231 1,515 1,587 N/A

Proposed 

Guidelines 1,724 1,090 1,151 

Emission 

 Reductions 

 -506 -425 -436 

2030 State Compliance Approach 

Base Case 2,256 1,530 1,537 N/A

Proposed 

Guidelines 1,701 1,059 1,109 

Emission 

Reductions -555 -471 -428 

Source: Integrated Planning Model, 2014. 

N/A – not yet available. 
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Table 8 - Summary of CO2 and Air Pollutant Emission Reductions 

with Option 2 

CO2

(million 

metric 

tons) 

SO2

(thousands 

of tons) 

NOX 

(thousands 

of tons) 

PM2.5 

(thousands 

of tons) 

2020 Regional Compliance Approach 

Base Case 2,161 1,476 1,559 N/A 

Proposed 

Guidelines 1,878 1,231 1,290 

Emissions 

Reductions -283 -244 -268 

2025 Regional Compliance Approach 

Base Case 2,231 1,515 1,587 

Proposed 

Guidelines 1,862 1,218 1,279 N/A 

Emissions 

Reductions -368 -297 -309 

2030 Regional Compliance Approach 

Base Case 2,256 1,530 1,537 

Proposed 

Guidelines 1,903 1,243 1,286 N/A 

Emissions 

Reductions -353 -287 -252 

2020 State Compliance Approach 

Base Case 2,161 1,476 1,559 

Proposed 

Guidelines 1,866 1,208 1,277 

Emissions 

Reductions -295 -267 -281 N/A 

2025 State Compliance Approach 

Base Case 2,231 1,515 1,587 

Proposed 

Guidelines 1,855 1,188 1,271 

Emissions 

Reductions -376 -327 -317 N/A 

2030 State Compliance Approach 

Base Case 2,256 1,530 1,537 

Proposed 

Guidelines 1,882 1,209 1,264 
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Emissions 

Reductions -373 -321 -274 N/A 

Source: Integrated Planning Model, 2014. 

N/A – not yet available. 

The reductions in these tables do not account for 

reductions in hazardous air pollutants (HAPs) that may occur as 

a result of this rule. For instance, the fine particulate 

reductions presented above only partly reflect reductions in 

many heavy metal particulates. 

B. Comparison of Building Block Approaches 

Though the EPA has determined that the 4-building block 

approach is BSER, we did analyze the impacts of both a 

combination of building blocks 1 and 2 and the combination of 

all four building blocks. The analysis indicates that the 

combined strategies of heat rate improvements (building block 1) 

and re-dispatch (building block 2) would result in overall CO2

emission reductions of approximately 22 percent in 2020 

(compared to 2005 emissions and assuming state-level 

compliance). This compares to expected CO2 emission reductions 

of approximately 27 percent for the four-block BSER approach 

discussed below. The EPA analysis also estimates 24 – 32 GW of 

additional coal-fired EGU retirements in 2020 (compared to 46 – 
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49 GW for the four-block approach) and an additional 3 – 5 GW of 

oil/gas steam EGUs (compared to 16 GW for the four-block 

approach). For both the two-block and the four-block approach, a 

decrease in coal production and price is predicted in 2020. The 

decrease in production is predicted at 20 – 23 percent for the 

two-block approach, compared to a decrease of 25 – 27 percent 

for the four-block approach. A 12 percent decrease in coal 

prices is predicted for the two-block approach; while the fourblock approach results in a 16 to 18 percent decrease. Under 

both approaches, the shifting in generation from higher-emitting 

steam EGUs to lower-emitting NGCC units results in an increase 

in natural gas production and price. The two-block approach 

results in a production increase of 19 – 22 percent and a price 

increase of 10 – 11 percent. The four-block approach results in 

a production increase of 12 – 14 percent and a price increase of 

9 – 12 percent. Both the two-block and the four-block approaches 

result in construction of additional NGCC capacity by 2020, with 

11 – 18 GW of new NGCC for the two-block approach and 20 – 22 GW 

of new NGCC capacity for the four-block approach. However, while 

the two-block approach results in 5 – 17 GW of new NGCC capacity 

in 2030, the four-block approach results in 32 – 35 GW less NGCC 

capacity in 2030 (due to increased use of renewable energy 
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sources and decreased demand from implementation of demand side 

energy efficiency measures). Also, significantly, the two-block 

approach results in less than 500 MW of new renewable energy 

capacity; while the four-block option results in approximately 

12 GW of new renewable generating capacity. 

The EPA projects that the annual incremental compliance 

cost for the building block 1 and 2 approach is estimated to be 

$3.2 to $4.4 billion in 2020 and $6.8 to $9.8 billion (2011$) in 

2030, excluding the costs associated with monitoring, reporting, 

and recordkeeping (MRR). 

The total combined climate benefits and health co-benefits 

are estimated to be $21 to $40 billion in 2020 and $32 to $63 

billion in 2030 (2011$ at a 3-percent discount rate [model 

average]). The net benefits are estimated to be $18 to $36 

billion in 2020 and $25 to $53 billion in 2030 (2011$ at a 3-

percent discount rate [model average]). For the purposes of this 

summary, we list the climate benefits associated with the 

marginal value the model average at 3% discount rate, however we 

emphasize the importance and value of considering the full range 

of SCC values. 

C. Endangered Species Act 

Comment [A81]: requests that EPA provide a 

comparison of costs and benefits of the 2 building 

block approach with the 4 building block 

approach, since comparisons are being made. 
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Consistent with the requirements of section 7(a)(2) of the 

Endangered Species Act (ESA), the EPA has also considered the 

effects of this proposed rule and has reviewed applicable ESA 

regulations, case law, and guidance to determine what, if any, 

impact there may be to listed endangered or threatened species 

or designated critical habitat. Section 7(a)(2) of the ESA 

requires federal agencies, in consultation with the U.S. Fish 

and Wildlife Service (FWS) and/or the National Marine Fisheries 

Service, to ensure that actions they authorize, fund, or carry 

out are not likely to jeopardize the continued existence of 

federally listed endangered or threatened species or result in 

the destruction or adverse modification of designated critical 

habitat of such species. 16 U.S.C. § 1536(a)(2). Under relevant 

implementing regulations, section 7(a)(2) applies only to 

actions where there is discretionary federal involvement or 

control. 50 CFR § 402.03. Further, under the regulations 

consultation is required only for actions that “may affect” 

listed species or designated critical habitat. 50 CFR § 402.14. 

Consultation is not required where the action has no effect on 

such species or habitat. Under this standard, it is the federal 

agency taking the action that evaluates the action and 

determines whether consultation is required. See 51 FR 19926, 
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19949 (June 3, 1986). Effects of an action include both the 

direct and indirect effects that will be added to the 

environmental baseline. 50 CFR § 402.02. Indirect effects are 

those that are caused by the action, later in time, and are 

reasonably certain to occur. Id. To trigger a consultation 

requirement, there must thus be a causal connection between the 

federal action, the effect in question, and the listed species, 

and the effect must be reasonably certain to occur. 

The EPA has considered the effects of this proposed rule 

and has reviewed applicable ESA regulations, case law, and 

guidance to determine what, if any, impact there may be to 

listed species or designated critical habitat for purposes of 

section 7(a)(2) consultation. The EPA notes that the projected 

environmental effects of this proposal are positive: reductions 

in overall GHG emissions, and reductions in PM and ozoneprecursor emissions (SOx and NOx). With respect to the projected 

GHG emission reductions, EPA does not believe that such 

reductions trigger ESA consultation requirements under section 

7(a)(2). In reaching this conclusion, the EPA is mindful of 

significant legal and technical analysis undertaken by FWS and 

the U.S. Department of the Interior in the context of listing 

the polar bear as a threatened species under the ESA. In that 
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context, in 2008, FWS and DOI expressed the view that the best 

scientific data available arearewereare insufficient to draw a 

causal connection between GHG emissions and effects on the 

species in its habitat.274 The DOI Solicitor concluded that where 

the effect at issue is climate change, proposed actions 

involving GHG emissions cannot pass the “may affect” test of the 

section 7 regulations and thus are not subject to ESA 

consultation. The EPA has also previously considered issues 

relating to GHG emissions in connection with the requirements of 

ESA section 7(a)(2). Although the GHG emission reductions 

projected for this proposal are large (the highest estimate is 

reductions of 555 MMT of CO2 in 2030 – see Table 7 above), the 

EPA evaluated larger reductions in assessing this same issue in 

the context of the light duty vehicle GHG emission standards for 

model years 2012-2016 and 2017-2025. There the agency projected 

emission reductions roughly double and four times those 

projected here over the lifetimes of the model years in 

 

274 See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum from 

David Longly Bernhardt, Solicitor, U.S. Department of the 

Interior re: “Guidance on the Applicability of the Endangered 

Species Act’s Consultation Requirements to Proposed Actions 

Involving the Emission of Greenhouse Gases” (Oct. 3, 2008). 
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question275 and, based on air quality modeling of potential 

environmental effects, concluded that “EPA knows of no modeling 

tool which can link these small, time-attenuated changes in 

global metrics to particular effects on listed species in 

particular areas. Extrapolating from global metric to local 

effect with such small numbers, and accounting for further links 

in a causative chain, remain beyond current modeling 

capabilities.” EPA, Light Duty Vehicle Greenhouse Gas Standards 

and Corporate Average Fuel Economy Standards, Response to 

Comment Document for Joint Rulemaking at 4-102 (Docket EPA-OARHQ-2009-4782. The EPA reached this conclusion after evaluating 

issues relating to potential improvements relevant to both 

temperature and oceanographic pH outputs. The EPA’s ultimate 

finding was that “any potential for a specific impact on listed 

species in their habitats associated with these very small 

changes in average global temperature and ocean pH is too remote 

to trigger the threshold for ESA section 7 (a)(2).” Id. The 

EPA believes that the same conclusions apply to the present 

proposal, given that the projected CO2 emission reductions are 

less than those projected for either of the light duty vehicle 

 

275 See 75 FR at 25438 Table I.C 2-4 (May 7, 2010); 77 FR at 

62894 Table III-68 (Oct. 15, 2012). 
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rules. See, e.g., Ground Zero Center for Non-Violent Action v. 

U.S. Dept. of Navy, 383 F. 3d 1082, 1091-92 (9th Cir. 2004) 

(where the likelihood of jeopardy to a species from a federal 

action is extremely remote, ESA does not require consultation). 

With regard to non-GHG air emissions, the EPA is also 

projecting substantial reductions of SOx and NOx as a collateral 

consequence of today’s proposal. Preamble Table 7. However, 

CAA section 111(d)(1) standards cannot directly control 

emissions of criteria pollutants. Consequently, section 111(d) 

provides no discretion to adjust the standard based on potential 

impacts to endangered species of reduced criteria pollutant 

emissions. Section 7(a)(2) consultation thus is not required 

with respect to the projected reductions of criteria pollutant 

emissions. See 50 CFR § 402.03; see also, National Lime Ass’n 

v. EPA, 233 F. 3d 625, 638-39 (D.C. Cir. 2000)(although CAA 

section 112(b)(2) prohibits the EPA from listing criteria 

pollutants as hazardous air pollutants, the EPA may use PM as a 

surrogate for metal hazardous air pollutants, and reductions in 

PM do not constitute impermissible regulation of a criteria 

pollutant). 

Moreover, there are substantial questions as to whether any 

potential for relevant effects results from any element of the 
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proposed rule or would result instead from the separate actions 

of States establishing standards of performance for existing 

sources and implementing and enforcing those standards. Cf. 

American Trucking Assn’s v. EPA, 175 F. 3d 1027, 1043-45 (D.C. 

Cir. 1999), rev’d on different grounds sub nom., Whitman v. 

American Trucking Assn’s, 531 U.S. 457 (2000) (National Ambient 

Air Quality Standards have no economic impact, for purposes of 

Regulatory Flexibility Act, because impacts result from the 

actions of States through their development, implementation and 

enforcement of state implementation plans). Thus, for example, 

although questions may exist whether actions such as increased 

utilization of solar or wind power could have effects on listed 

species, the EPA believes that such effects (if any) would 

result from decisions and actions by states in developing, 

implementing and enforcing their plans. The precise steps States 

choose to take in that regard cannot be determined or ordered by 

this federal action, and they are not sufficiently certain to be 

attributable to this proposed rule for ESA purposes. 

Consequently, for this additional reason, the EPA does not 

believe that this proposed rule (if enacted) would have effects 

on listed species that would trigger the section 7 (a)(2) 

consultation requirement. 
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D. What are the energy impacts?

 The proposed guidelines have important energy market 

implications. Under Option 1, average nationwide retail 

electricity prices are projected to increase by roughly 6 to 7 

percent in 2020, and by roughly 3 percent in 2030 (contiguous 

U.S.). Average monthly electricity bills are anticipated to 

increase by roughly 3 percent in 2020, but decline by 

approximately 9 percent by 2030. The decreased projection in 

these two metrics is a result of the increasing penetration of 

demand-side programs that more than offset increased prices to 

end users by their expected savings from reduced electricity 

use. 

 The average delivered coal price to the power sector is 

projected to decrease by 16 to 17 percent in 2020 and roughly 18 

percent in 2030, relative to the base case for Option 1. The EPA 

also projects that electric power sector-delivered natural gas 

prices will increase by 9 to 12 percent in 2020, with negligible 

changes by 2030. Natural gas use for electricity generation will 

increase by as much as 1.2 trillion cubic feet (BCF) in 2020 

relative to the base case, declining over time. 

 These figures reflect EPA’s illustrative modeling that 

presumes policies that lead to dispatch changes in 2020 and 
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growing use of energy efficiency and renewable electricity 

generation out to 2029. If states make different policy choices, 

impacts could be different. For instance, if states implement 

renewable and/or energy efficiency policies on a more aggressive 

time-frame, impacts on natural gas and electricity prices would 

likely be less. Implementation of other measures not included in 

EPA’s BSER calculation or compliance modeling, such as nuclear 

uprates, transmission system improvements, use of energy storage 

technologies or retrofit CCS, could also mitigate gas price 

and/or electricity price impacts. 

 The EPA projects coal production for use by the power 

sector, a large component of total coal production, will decline 

by roughly 25 to 27 percent in 2020 from base case levels. The 

use of coal by the power sector will decrease roughly 30 to 32 

percent in 2030. Renewable energy capacity is anticipated to 

increase by roughly 12 GW in 2020 and by 9 GW in 2030 under 

Option 1. Energy market impacts from the guidelines are 

discussed more extensively in the RIA found in the docket for 

this rulemaking. 

E What are the compliance costs? 

 The ‘‘compliance costs’’ of this proposed action are 

represented in this analysis as the change in electric power 
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generation costs between the base case and policy case in which 

states pursue a distinct set of strategies beyond the strategies 

taken in the base case to meet the terms of the EGU GHG emission 

guidelines, and include cost estimates for demand-side energy 

efficiency. The compliance assumptions – and, therefore, the 

projected “compliance costs” - set forth in this analysis are 

illustrative in nature and do not represent the full suite of 

compliance flexibilities states may ultimately pursue. These 

illustrative compliance scenarios are designed to reflect, to 

the extent possible, the scope and the nature of the proposed 

guidelines. However, there is considerable uncertainty with 

regards to the precise measures that states will adopt to meet 

the proposed requirements, because there are considerable 

flexibilities afforded to the states in developing their state 

plans. 

 The EPA projects that the annual incremental compliance 

cost of Option 1 is estimated to be between $5.5 and $7.5_ 

billion in 2020 and between $7.3 and $8.8 billion (2011$) in 

2030, including` the costs associated with monitoring, 

reporting, and recordkeeping (MRR). The incremental compliance 

cost of Option 2 is estimated to be between $4.3 and $5.5 

billion in 2020, including MRR costs. In 2030, the estimated 
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compliance cost of Option 2 is estimated to be between $1.9 and 

$3.1 billion (with the assumed levels of end-use energy 

efficiency). These important dynamics are discussed in more 

detail in the RIA in the rulemaking docket. The annualized 

incremental cost is the projected additional cost of complying 

with the guidelines in the year analyzed, and includes the 

amortized cost of capital investment, needed new capacity, 

shifts between or amongst various fuels, deployment of energy 

efficiency programs, and other actions associated with 

compliance. MRR costs are estimated to be $61.6 million (2011$) 

in 2020 for Options 1 and 2 and $8.2 million for both Options 1 

and 2 in 2025 and 2030. More detailed cost estimates are 

available in the RIA included in the rulemaking docket. 

F. What are the economic and employment impacts? 

The proposed standards are projected to result in certain 

changes to power system operation as a result of the application 

of state emission rate goals. Overall, we project dispatch 

changes, changes to fossil fuel and retail electricity prices, 

and some additional coal retirements. Average electric power 

sector-delivered natural gas prices are projected to increase by 

roughly 9 to 12 percent in 2020 in Option 1, with negligible 

changes by 2030. Under Option 2, electric power sector natural 
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gas prices are projected to increase by roughly 8 percent in 

2020, on an average nationwide basis, and decrease in 2030. The 

average delivered coal price to the power sector is projected to 

decrease by 16 to 17 percent in 2020 under Option 1, and 

decrease by roughly 14 percent under Option 2, on a nationwide 

average basis. Retail electricity prices are projected to 

increase 6 to 7 percent under Option 1 and increase by roughly 4 

percent under Option 2, both in 2020 and on an average basis 

across the contiguous U.S. By 2030 under Option 1, electricity 

prices are projected to increase by about 3 percent. Under 

Option 1, the EPA projects 46 to 50 GW of additional coal-fired 

generation may be uneconomic to maintain and may be removed from 

operation by 2030. The EPA projects that under Option 2, 30 to 

33 GW of additional coal-fired generation may be uneconomic to 

maintain and may be removed from operation by 2030. 

 It is important to note that the EPA’s modeling does not 

necessarily account for all of the factors that may influence 

business decisions regarding future coal fired capacity. By 

2025, the average age of the coal-fired fleet will be 49 years 

old and twenty percent of the fleet will be more than 60 years 

old. Many power companies already factor a carbon price into 

their long term capacity planning that would further influence 
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business decisions to replace these aging assets with modern, 

and significantly cleaner generation. 

The compliance modeling done to support the proposal 

assumes that overall electric demand will decrease 

significantly, as states ramp up programs that result in lower 

overall demand. End-use energy efficiency levels increase such 

that they achieve about an 11 percent reduction on overall 

electricity demand levels in 2030 for Option 1, and 

approximately an 8 percent reduction in 2030 for Option 2. In 

response, there are anticipated to be notable changes to costs, 

prices, and electricity generation in the power sector as more 

end-use efficiency is realized. 

Changes in price or demand for electricity, natural gas, 

coal, can impact markets for goods and services produced by 

sectors that use these energy inputs in the production process 

or supply those sectors. Changes in cost of production may 

result in changes in price, changes in quantity produced, and 

changes in profitability of firms affected. The EPA recognizes 

that these guidelines provide significant flexibilities and 

states implementing the guidelines may choose to mitigate 

impacts to some markets outside the EGU sector. Similarly, 

demand for new generation or energy efficiency can result in 
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shifts in production and profitability for firms that supply 

those goods and services, and the guidelines provide flexibility 

for states that may want to enhance demand for goods and 

services from those sectors. 

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 

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, during 

periods of sustained high unemployment, employment impacts are 

of particular concern and questions may arise about their 

existence and magnitude. 

 States have the responsibility and flexibility to implement 

policies and practices for compliance with Proposed Electric 

Generating Unit Greenhouse Gas Existing Source Guidelines. 

Quantifying the associated employment impacts is complicated 

by the wide range of approaches that States may use.. As such, 

EPA’s employment analysis includes projected employment impacts 
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associated with illustrative compliance scenarios for these 

guidelines for the electric power industry, coal and natural gas 

production, and demand side energy efficiency activities. These 

projections are derived, in part, from a detailed model of the 

electricity production 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 

estimates that these guidelines could have an employment impact 

of roughly 25,900to900to900 to900to 28,000 job-years increase in 

2020 for Option 1, state to regional compliance approach, 

respectively. For Option 2, the state and regional compliance 

approach estimates are 26,700 to 29,800 job-years increase in 

2020. Demand-side energy efficiency employment impacts are 

approximately an increase 78,800 jobs in 2020 for Option 1 and 

57,000 increased jobs for Option 2. By its nature, energy 

efficiency reduces overall demand for electric power. The EPA 

recognizes as more efficiency is built into the U.S. power 

system over time, lower fuel requirements may lead to fewer jobs 

in the coal and natural gas extraction sectors, as well as in 

EGU construction and operation than would otherwise have been 

expected. The EPA also recognizes the fact that, in many cases, 

employment gains and losses that might be attributable to this 

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Comment [A82]: Consider adding the following 

sentence, “On the other hand, EPA also recognizes 

that lower energy-service costs can lead to economic 

growth and job creation.” 

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rule would be expected to affect different sets of people. 

Moreover, workers who lose jobs in these sectors may find 

employment elsewhere just as workers employed in new jobs in 

these sectors may have been previously employed elsewhere. 

Therefore the numbers reported in these sectors may have been 

previously employed elsewhere. Therefore the numbers reported 

here should not be interpreted as a net national employment 

impact. G. What are the benefits of the proposed goals? 

Implementing the proposed standards will generate benefits 

by reducing emissions of CO2 as well as criteria pollutants and 

their precursors, including SO2, NOx and directly emitted 

particles. SO2 and NOx are precursors to PM2.5 (particles smaller 

than 2.5 microns), and NOx is a precursor to ozone. The 

estimated benefits associated with these emission reductions are 

beyond those achieved by previous EPA rulemakings including the 

Mercury and Air Toxics Standards. The health and welfare 

benefits from reducing air pollution are considered co-benefits 

for these standards. For this rulemaking, we were only able to 

quantify the climate benefits from reduced emissions of CO2 and 

the health co-benefits associated with reduced exposure to PM2.5 

and ozone. In summary, we estimate the total combined climate 

benefits and health co-benefits for Option 1 to be $32 billion 
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to $51 billion in 2020 and $54 billion to $86 billion in 2030 

assuming a regional compliance approach (2011 dollars at a 3-

percent discount rate [model average]). If states comply using a 

state-specific compliance approach, these climate and health cobenefits estimates are estimated to be $33 to $54 billion in 

2020 and $56 to $89 billion in 2030 (2011 dollars at a 3-percent 

discount rate [model average]. We also estimate the total 

combined climate benefits and health co-benefits for Option 2 to 

be $25 billion to $41 billion in 2020 and $35 billion to $56 

billion in 2025 (regional compliance approach, 2011 dollars at a 

3-percent discount rate [model average]). Assuming a state 

compliance approach, the total combined climate benefits and 

health co-benefits for Option 2 are estimated to be $26 billion 

to $42 billion in 2020 and $35 billion to $57 billion in 2025 

(2011 dollars at a 3-percent discount rate [model average]). A 

summary of the emission reductions and monetized benefits 

estimated for this rule at all discount rates and additional 

analysis years is provided in Tables 9 through 14 of this 

preamble. 
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Table 9 Summary of the Monetized Global Climate Benefits for the 

Proposed Option 1 (billions of 2011 dollars)a

Discount Rate 

(Statistic) 

Monetized Climate Benefits 

2020 Regional 

Compliance

State 

Compliance

CO2 Reductions 

(million 

metric tons) 

371 383 

5 percent (average 

SCC) 

$4.7 $4.9 

3 percent (average 

SCC) 

$17 $18 

2.5 percent (average 

SCC) 

$25 $26 

3 percent (95th

percentile SCC) 

$51 $52 

2025 Regional 

Compliance 

State 

Compliance 

CO2 Reductions 

(million 

metric tons) 

501 506 

5 percent (average 

SCC) 

$7.5 $7.6 

3 percent(average SCC) $25 $25 

2.5 percent (average 

SCC) 

$37 $37 

3 percent (95th

percentile SCC) 

$76 $77 

2030 Regional 

Compliance 

State 

Compliance 

CO2 Reductions 

(million 

metric tons) 

545 555 

5 percent (average 

SCC) 

$9.3 $9.5 

3 percent(average SCC) $30 $31 

2.5 percent (average 

SCC) 

$44 $44 

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3 percent (95th

percentile SCC) 

$92 $94 

a

 Climate benefit estimates reflect impacts from CO2 emission 

changes in the analysis years presented in the table and do not 

account for changes in non-CO2 GHG emissions. These estimates are 

based on the federal government’s global social cost of carbon 

(SCC) estimates for the analysis years (2020, 2025, 2030) and 

are rounded to two significant figures. 
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Table 10 Summary of the Monetized Global Climate Benefits for 

the Option 2 (billions of 2011 dollars)a

Discount Rate 

(Statistic) 

Monetized Climate Benefits 

2020 Regional 

Compliance

State 

Compliance

CO2 Reductions 

(million 

metric tons) 

283 295 

5 percent (average 

SCC) 

$3.6 $3.8 

3 percent (average 

SCC) 

$13 $14 

2.5 percent (average 

SCC) 

$19 $20 

3 percent (95th

percentile SCC) 

$39 $40 

2025 Regional 

Compliance 

State 

Compliance 

CO2 Reductions 

(million 

metric tons) 

368 376 

5 percent (average 

SCC) 

$5.5 $5.6 

3 percent(average SCC) $18 $19 

2.5 percent (average 

SCC) 

$27 $28 

3 percent (95th

percentile SCC) 

$56 $57 

2030 Regional 

Compliance 

State 

Compliance 

CO2 Reductions 

(million 

metric tons) 

353 373 

5 percent (average 

SCC) 

$6.0 $6.4 

3 percent(average SCC) $20 $21 

2.5 percent (average 

SCC) 

$28 $30 

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3 percent (95th

percentile SCC) 

$60 $63 

a

 Climate benefit estimates reflect impacts from CO2 emission 

changes in the analysis years presented in the table and do not 

account for changes in non-CO2 GHG emissions. These estimates are 

based on the federal government’s global SCC estimates for the 

analysis years (2020, 2025, 2030) and are rounded to two 

significant figures. 
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Table 11 Summary of the Monetized Health Co-Benefits for the 

Proposed Standards Option 1 Regional Compliance Approach in the 

U.S. (billions of 2011 dollars)a 

Pollutant 

National 

Emission 

Reductions 

(thousands of 

short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

Option 1 Regional Compliance Approach 2020 

PM2.5 precursors b 

SO2 292 $12 to $26 $11 to $24 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 345 $2.2 to $5.0 $2.0 to 

$4.5 

Ozone precursor c 

NOx 146 $0.63 to 

$2.7 

$0.63 to 

$2.7 

Total Monetized Health Co-benefits $15 to $34 $13 to $31 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$32 to $51 $30 to $48 

Option 1 Regional Compliance Approach 2025 

PM2.5 precursors b 

SO2 395 $17 to $38 $15 to $35 

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

 

Directly emitted PM2.5 

(crustal) 

NOx 421 $3.0 to $6.8 $2.7 to 

$6.1 

Ozone precursor c 

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NOx 180 $1.0 to $4.3 $1.0 to 

$4.3

Total Monetized Health Co-benefits $21 to $50 $19 to $45 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$46 to $75 $44 to $70 

Option 1 Regional Compliance Approach 2030 

PM2.5 precursors b

SO2 424 $20 to $44 $18 to $40 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 407 $3.0 to $6.7 $2.7 to 

$6.1 

Ozone precursor c

NOx 176 $1.1 to $4.5 $1.1 to 

$4.5 

Total Monetized Health Co-benefits $24 to $55 $21 to $50 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$54 to $86 $52 to $81 

a

 [Emission reductions of directly emitted particles are not yet 

available but will be added to the totals above.] All estimates 

are for the analysis years (2020, 2025, 2030) and are rounded to 

two significant figures, so estimates may not sum. It is 

important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct 

exposure to NO2, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b

 The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. PM co-benefits are shown as a range reflecting the 

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use of two concentration-response functions, with the lower end 

of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). 

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. 

c

 The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d

 We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent), which each increase over time. For the purposes of 

this table, we show the benefits associated with the model 

average at 3% discount rate, however we emphasize the importance 

and value of considering the full range of SCC values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 
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Table 12 Summary of the Monetized Health Co-Benefits in the U.S. 

for the Proposed Guidelines Option 1 State Compliance Approach 

(billions of 2011 dollars)a

Pollutant 

National 

Emission 

Reductions 

(thousands of 

short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

Option 1 State Compliance Approach in 2020 

PM2.5 precursors b 

SO2 335 $13 to $29 $11 to $26 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 367 $2.2 to 

$4.9 

$2.0 to 

$4.4 

Ozone precursor c 

NOx 157 $0.64 to 

$2.7 

$0.64 to 

$2.7 

Total Monetized Health Co-benefits $15 to $36 $14 to $33 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$33 to $54 $32 to $50 

Option 1 State Compliance Approach in 2025 

PM2.5 precursors b 

SO2 425 $18 to $40 $16 to $36 

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

 

Directly emitted PM2.5 

(crustal) 

NOx 436 $2.9 to 

$6.5 

$2.6 to 

$5.8 

Ozone precursor c 

Formatted Table
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NOx 190 $1.0 to 

$4.4

$1.0 to 

$4.4

Total Monetized Health Co-benefits $22 to $51 $20 to $46 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$47 to $76 $45 to $71 

Option 1 State Compliance Approach in 2030 

PM2.5 precursors b

SO2 471 $21 to $47 $19 to $43 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 428 $2.9 to 

$6.6 

$2.6 to 

$6.0 

Ozone precursor c

NOx 187 $1.1 to 

$4.6 

$1.1 to 

$4.6 

Total Monetized Health Co-benefits $25 to $58 $23 to $53 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$56 to $89 $53 to $84 

a

 [Emission reductions of directly emitted particles are not yet 

available but will be added to the totals above.] All estimates 

are for the analysis years (2020, 2025, 2030) and are rounded to 

two significant figures, so estimates may not sum. It is 

important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct 

exposure to NO2, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b

 The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. PM co-benefits are shown as a range reflecting the 

use of two concentration-response functions, with the lower end 

of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). 

Formatted Table
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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. 

c

 The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d

 We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent), which each increase over time. For the purposes of 

this table, we show the benefits associated with the model 

average at 3% discount rate, however we emphasize the importance 

and value of considering the full range of SCC values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 
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Table 13 Summary of the Monetized Health Co-Benefits in the U.S. 

for the Option 2 Regional Compliance Approach 

(billions of 2011 dollars)a

Pollutant 

National 

Emission 

Reductions 

(thousands of 

short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

 Option 2 Regional Compliance Approach 2020 

PM2.5 precursors b 

SO2 244 $9.8 to $22 $8.9 to $20 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 268 $1.7 to 

$3.9 

$1.6 to 

$3.5 

Ozone precursor c 

NOx 111 $0.47 to 

$2.0 

$0.47 to 

$2.0 

Total Monetized Health Co-benefits $12 to $28 $11 to $25 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$25 to $41 $24 to $38 

Option 2 Regional Compliance Approach in 2025 

PM2.5 precursors b 

SO2 $13 to $29 $12 to $26 

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

297 

Directly emitted PM2.5 

(crustal) 

NOx 309 $2.2 to 

$5.0 

$2.0 to 

$4.5 

Ozone precursor c 
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NOx 129 $0.73 to 

$3.1

$0.73 to 

$3.1

Total Monetized Health Co-benefits $16 to $37 $14 to $34 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$34 to $56 $33 to $52 

Option 2 Regional Compliance Approach in 2030 

PM2.5 precursors b

SO2 287 $13 to $30 $12 to $27 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 252 $1.8 to 

$4.2 

$1.7 to 

$3.8 

Ozone precursor c

NOx 110 $0.66 to 

$2.8 

$0.66 to 

$2.8 

Total Monetized Health Co-benefits $16 to $37 $14 to $34 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$35 to $56 $34 to $53 

a

 [Emission reductions of directly emitted particles are not yet 

available but will be added to the totals above.] All estimates 

are for the analysis years (2020, 2025, 2030) and are rounded to 

two significant figures, so estimates may not sum. It is 

important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct 

exposure to NO2, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b

 The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. PM co-benefits are shown as a range reflecting the 

use of two concentration-response functions, with the lower end 

of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). 
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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. 

c

 The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d

 We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent), which each increase over time. For the purposes of 

this table, we show the benefits associated with the model 

average at 3% discount rate, however we emphasize the importance 

and value of considering the full range of SCC values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 

Table 14 Summary of the Monetized Health Co-Benefits in the U.S. 

for Option 2 State Compliance Approach (billions of 2011 

dollars)a

Pollutant 

National 

Emission 

Reductions 

(thousands of 

short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

Option 2 State Compliance Approach in 2020 

PM2.5 precursors b 

SO2 267 $10 to $23 $9.1 to $21 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 
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NOx 281 $1.7 to 

$3.8

$1.5 to 

$3.4

Ozone precursor c 

NOx 119 $0.48 to 

$2.1 

$0.48 to 

$2.1 

Total Monetized Health Co-benefits $12 to $29 $11 to $26 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$26 to $42 $25 to $40 

Option 2 State Compliance Approach in 2025 

PM2.5 precursors b 

SO2 327 $14 to $30 $12 to $27

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

 

Directly emitted PM2.5 

(crustal) 

NOx 317 $2.1 to 

$4.7 

$1.9 to 

$4.2 

Ozone precursor c 

NOx 136 $0.72 to 

$3.1 

$0.72 to 

$3.1 

Total Monetized Health Co-benefits $16 to $38 $15 to $35 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$35 to $57 $34 to $54 

Option 2 State Compliance Approach in 2030 

PM2.5 precursors b

SO2 321 $14 to $32 $13 to $29 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 274 $1.9 to 

$4.2 

$1.7 to 

$3.8 

Ozone precursor c
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NOx 120 $0.68 to 

$2.9

$0.68 to 

$2.9

Total Monetized Health Co-benefits $17 to $39 $15 to $36 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$37 to $60 $36 to $56 

a

 [Emission reductions of directly emitted particles are not yet 

available but will be added to the totals above.] All estimates 

are for the analysis years (2020, 2025, 2030) and are rounded to 

two significant figures, so estimates may not sum. It is 

important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct 

exposure to NO2, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b

 The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. PM co-benefits are shown as a range reflecting the 

use of two concentration-response functions, with the lower end 

of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). 

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. 

c

 The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d

 We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent), which each increase over time. For the purposes of 

this table, we show the benefits associated with the model 

average at 3% discount rate; however, we emphasize the 

importance and value of considering the full range of SCC 
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values. We provide combined climate and health estimates based 

on additional discount rates in the RIA. 

The EPA has used the U.S. government’s SCC estimates to 

analyze CO2 climate impacts of this rulemaking. The U.S. 

government first published the federal SCC estimates in 2010 

following an interagency process that included the EPA and other 

executive branch entities; the process used three integrated 

assessment models (IAM) to develop SCC estimates and selected 

four global values for use in regulatory analyses. The U.S. 

government recently updated these estimates using new versions 

of each integrated assessment model and published them in 2013. 

The 2013 update did not revisit the 2010 modeling decisions 

(e.g., with regard to the discount rate, reference case 

socioeconomic and emission scenarios or equilibrium climate 

sensitivity). Rather, improvements in the way damages are 

modeled are confined to those that have been incorporated into 

the latest versions of the models by the developers themselves 

and published in the peer-reviewed literature. The 2010 SCC 

Technical Support Document (2010 SCC TSD) provides a complete 

discussion of the methods used to develop these estimates and 
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the 2013 SCC TSD presents and discusses the updated 

estimates.276,277 

The EPA and other agencies have sought public comments on 

the USG SCC estimates as part of various rulemakings. In 

addition, OMB’s Office of Information and Regulatory Affairs 

recently sought public comment on the approach used to develop 

 

276 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). 

Also available at: 

<http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf>. 

277 Docket ID EPA-HQ-OAR-2013-0495, 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 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 (May 2013, Revised 

November 2013). Also available at: 

<http://www.whitehouse.gov/sites/default/files/omb/assets/infore

g/technical-update-social-cost-of-carbon-for-regulator-impactanalysis.pdf>. 
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the estimates. The comment period ended on February 26, 2014, 

and OMB is reviewing the comments received. 

The four SCC estimates, updated in 2013, are as follows: 

$13, $46, $68, and $137 per metric ton of CO2 emissions in the 

year 2020 (2011 dollars).278 The first three values are based on 

the average SCC from the three IAMs, at discount rates of 5, 3, 

and 2.5 percent, respectively. SCCs at several discount rates 

are included because the literature shows that the SCC is quite 

sensitive to assumptions about the discount rate, and because no 

consensus exists on the appropriate rate to use in an 

intergenerational context (where costs and benefits are incurred 

by different generations). The fourth value is the 95th

percentile of the SCC from all three models at a 3 percent 

discount rate. It is included to represent higher-than-expected 

impacts from temperature change further out in the tails of the 

SCC distribution (representing less likely, but potentially 

catastrophic, outcomes). 

The 2010 SCC TSD noted a number of limitations to the SCC 

analysis, including the incomplete way in which the integrated 

 

278 The 2010 and 2013 TSDs present SCC in $2007. The estimates 

were adjusted to 2011$ using the GDP Implicit Price Deflator. 

Also available at: http://www.gpo.gov/fdsys/pkg/ECONI-2013-

02/pdf/ECONI-2013-02-Pg3.pdf. 
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assessment models 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. Current 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 for various reasons, including the inherent 

difficulties in valuing non-market impacts and the fact that the 

science incorporated into these models understandably lags 

behind the most recent research. 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. Model developers 

continually update the models to incorporate recent research. 

The new versions of the models used to estimate the values 

presented in this rulemaking offer some improvements in these 

areas identified above, although further work is warranted. 

Accordingly, the EPA and other parties continue to conduct 

research on modeling and valuation of climate impacts with the 

goal of improving these estimates. Additional details are 

provided in the SCC TSDs. 
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 The health co-benefits estimates represent the total 

monetized human health benefits for populations exposed to 

reduced PM2.5 and ozone resulting from emission reductions under 

illustrative compliance options for the proposed standards. 

Unlike the global SCC estimates, the air pollution health cobenefits are estimated for the contiguous U.S. only. We used a 

“benefit-per-ton” approach to estimate the benefits of this 

rulemaking. To create the PM2.5 benefit-per-ton estimates, this 

approach uses a model to convert emissions of PM2.5 precursors 

into changes in ambient PM2.5 levels and another model to 

estimate the changes in human health associated with that change 

in air quality, which are then divided by the emissions in 

specific sectors. National average benefit-per-ton estimates for 

the EGU sector were derived using the approach published in Fann 

et al. (2012),279 but they have since been updated to reflect the 

studies and population data in the 2012 PM NAAQS RIA and were 

separated into regional estimates to provide greater spatial 

 

279 Fann, N., K.R. Baker and C.M. Fulcher. 2012. “Characterizing 

the PM2.5-related health benefits of emission reductions for 17 

industrial, area and mobile emission sectors across the U.S.” 

Environment International 49 41–151. 

Comment [A83]: Given the magnitude of these 

co-benefits relative to CO2 benefits EPA should 

commit to doing air quality modelling on the model 

scenarios for the final rule 
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resolution.280 In addition, we generated regional benefit-per-ton 

estimates for changes in ozone exposure. The ozone estimates 

used the ozone information from the sector modeling for the EGU 

sector described in Fann et al. (2012) and the health impact 

assumptions used in the Ozone NAAQS RIAs.281,282 To calculate the 

co-benefits for the proposed standards, we multiplied the 

regional benefit-per-ton estimates for the EGU sector by the 

corresponding emission reductions.283 All benefit-per-ton 

 

280 U.S. Environmental Protection Agency (U.S. EPA). 2012. 

Regulatory Impact Analysis for the Final Revisions to the 

National Ambient Air Quality Standards for Particulate Matter. 

Research Triangle Park, NC: Office of Air Quality Planning and 

Standards, Health and Environmental Impacts Division. (EPA 

document number EPA-452/R-12-003, December). Available at: 

<http://www.epa.gov/pm/2012/finalria.pdf>. 

281 U.S. Environmental Protection Agency (U.S. EPA). 2008b. Final 

Ozone NAAQS Regulatory Impact Analysis. Research Triangle Park, 

NC: Office of Air Quality Planning and Standards, Health and 

Environmental Impacts Division, Air Benefit and Cost Group 

Research. (EPA document number EPA-452/R-08-003, March). 

Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. 

282 U.S. Environmental Protection Agency (U.S. EPA). 2010. 

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>. 

283 U.S. Environmental Protection Agency. 2013. Technical support 

document: Estimating the benefit per ton of reducing PM2.5

precursors from 17 sectors. Research Triangle Park, NC: Office 

of Air and Radiation, Office of Air Quality Planning and 

Standards, January. Available at: 
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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. More information regarding the derivation of 

the benefit-per-ton estimates is available in the RIA. 

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 effects estimates by 

particle type. Even though we assume that all fine particles 

have equivalent health effects, the benefit-per-ton estimates 

vary between precursors depending on the location and magnitude 

of their impact on PM2.5 levels, which drive population exposure. 

It is important to note that the magnitude of the PM2.5 and 

ozone co-benefits is largely driven by the concentration 

response functions for premature mortality and the value of a 

statistical life used to value reductions in premature 

mortality. For PM2.5, we cite two key empirical studies, one 

 

<http://www.epa.gov/airquality/benmap/models/Source_Apportionmen

t_BPT_TSD_1_31_13.pdf>. 
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based on the American Cancer Society cohort study284 and the 

extended Six Cities cohort study.285 We present the PM2.5 cobenefits results as a range based on the concentration-response 

functions from these two epidemiology studies, but this range 

does not capture the full range of uncertainty inherent in the 

co-benefits estimates. In the RIA for this rule, which is 

available in the docket, we also include PM2.5 co-benefits 

estimates derived from expert judgments (Roman et al., 2008)286

as a characterization of uncertainty regarding the PM2.5-

mortality relationship. For the ozone co-benefits, we present the 

results as a range reflecting the use of several different 

concentration-response functions for mortality, with the lower 

 

284 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. Health Effects Institute. (HEI Research Report 

number 140). Boston, MA: Health Effects Institute. 

285 Lepeule, J.; F. Laden; D. Dockery; 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 Perspective, 120(7), July, pp. 965-970. 286 Roman, H., et al. 2008. “Expert Judgment Assessment of the 

Mortality Impact of Changes in Ambient Fine Particulate Matter 

in the U.S.” Environmental Science & Technology, Vol. 42, No. 7, 

February, pp. 2268 – 2274. 
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end of the range based on a function from Bell et al. (2004)287

and the upper end based on a function from Levy et al. (2005)288. 

Similar to PM2.5, the range of ozone co-benefits does not capture 

the full range of inherent uncertainty. 

In this analysis, the EPA assumes that the health impact 

function for fine particles is without a threshold. This is 

based on the conclusions of EPA’s Integrated Science Assessment 

for Particulate Matter,289 which evaluated the substantial body 

of published scientific literature, reflecting thousands of 

epidemiology, toxicology, and clinical studies that documents 

the association between elevated PM2.5 concentrations and adverse 

health effects, including increased premature mortality. This 

assessment, which was twice reviewed by the EPA’s independent 

Science Advisory Board, concluded that the scientific literature 

 

287 Bell, M.L., et al. 2004. “Ozone and Short-Term Mortality in 

95 U.S. Urban Communities, 1987-2000.” Journal of the American 

Medical Association, 292(19), pp. 2372-8. 288 Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. “Ozone 

exposure and mortality: an empiric bayes metaregression 

analysis.” Epidemiology. 16(4): p. 458-68. 289 U.S. Environmental Protection Agency. 2009. Integrated 

Science Assessment for Particulate Matter (Final Report). 

Research Triangle Park, NC: National Center for Environmental 

Assessment, RTP Division. (EPA document number EPA-600-R-08-

139F, December). Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>. 
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consistently finds that a no-threshold model most adequately 

portrays the PM-mortality concentration-response relationship. 

In general, we are more confident in the magnitude of the 

risks we estimate from simulated PM2.5 concentrations that 

coincide with the bulk of the observed PM concentrations in the 

epidemiological studies that are used to estimate the benefits. 

Likewise, we are less confident in the risk we estimate from 

simulated PM2.5 concentrations that fall below the bulk of the 

observed data in these studies. 

For this analysis, policy-specific air quality data are not 

available,290 and thus, we are unable to estimate the percentage 

of premature mortality associated with this specific rule’s 

emission reductions at each PM2.5 level. As a surrogate measure of 

mortality impacts, we provide the percentage of the population 

exposed above the lowest measured PM2.5 level (LML) in each of the 

studies from which we obtained concentration-response functions 

for PM2.5 mortality, using the estimates of PM2.5 from the source 

apportionment modeling used to calculate the benefit-per-ton 

estimates for the EGU sector. Using the Krewski et al. (2009) 

study, 93 percent of the population is exposed to annual mean 

 

290 In addition, site-specific emission reductions will depend upon how states 

implement the guidelines. 
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PM2.5 levels at or above the LML of 5.8 micrograms per cubic 

meter (μg/m3

). Using the Lepeule et al. (2012) study, 67 percent 

of the population is exposed above the LML of 8 μg/m3

. It is 

important to note that baseline exposure is only one parameter 

in the health impact function, along with baseline incidence 

rates, population, and change in air quality. Therefore, caution 

is warranted when interpreting the LML assessment for this rule 

because these results are not consistent with results from rules 

that had air quality modeling. 

Every benefit 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 the air 

quality co-benefit analysis for this rule provides a reasonable 

indication of the expected health benefits of the air pollution 

emission reductions for the illustrative compliance options for 

the proposed standards 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 
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necessary air quality input and monitoring data to conduct a 

complete benefits assessment. In addition, using a benefit-perton approach adds another important source of uncertainty to the 

benefits estimates. The 2012 PM2.5 NAAQS benefits analysis 

provides an indication of the sensitivity of our results to 

various assumptions. 

We note that the monetized co-benefits estimates shown here 

do not include several important benefit categories, including 

exposure to SO2, NOx, and hazardous air pollutants (e.g., mercury 

and hydrogen chloride), as well as ecosystem effects and 

visibility impairment. Although we do not have sufficient 

information or modeling available to provide monetized estimates 

for this rule, we include a qualitative assessment of these 

unquantified benefits in the RIA for these proposed amendments. 

For more information on the benefits analysis, please refer 

to the RIA for this rule, which is available in the rulemaking 

docket. 

XI. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory Planning and Review, and 

Executive Order 13563, Improving Regulation and Regulatory 

Review 
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Under Section 3(f)(1) of Executive Order 12866 (58 FR 

51735, October 4, 1993), this action is an "economically 

significant regulatory action” because it is likely to have an 

annual effect on the economy of $100 million or more or 

adversely affect 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. The $100 million threshold can be triggered by 

either costs or benefits, or a combination of them. Accordingly, 

the EPA submitted this action to OMB for review under Executive 

Orders 12866 and 13563 (76 FR 3821, January 21, 2011), and any 

changes made in response to OMB recommendations have been 

documented in the docket for this action. 

 The EPA also prepared an analysis of the potential costs 

and benefits associated with this action. This analysis is 

contained in the RIA for this proposed rule. A copy of the 

analysis is available in the docket for this action.

 Consistent with EO 12866 and EO 13563, the EPA estimated 

the costs and benefits for illustrative compliance approaches of 

implementing the proposed guidelines. This proposal sets goals 

to reduce CO2 emissions from the electric power industry. Actions 

taken to comply with the proposed guidelines will also reduce 
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the emissions of directly emitted PM2.5, sulfur dioxide (SO2) and 

nitrogen oxides (NOX). The benefits associated with these PM, SO2

and NOX reductions are referred to as co-benefits, as these 

reductions are not the primary objective of this rule. 

 The EPA has used the U.S. government’s social cost of 

carbon (USG SCC) estimates — i.e., the monetary value of impacts 

associated with a marginal change in CO2 emissions in a given 

year, to analyze CO2 climate impacts of this rulemaking. The four 

USG SCC 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 SCC value deemed to be central by 

the USG: the model average at 3% discount rate. For the regional 

compliance approach, the EPA estimates that in 2020 this Option 

1 proposal will yield monetized climate benefits (in 2011$) of 

approximately $17 billion (3 percent model average). The air 

pollution health co-benefits in 2020 are estimated to be $15 

billion to $34 billion (2011$) for a 3 percent discount rate and 

$13 billion to $31 billion (2011$) for a 7 percent discount 

rate. The annual, illustrative compliance costs estimated by IPM 

and inclusive of demand side energy efficiency program and 
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participant costs and MRR costs, are approximately $5.5 billion 

(2011$) in 2020. The quantified net benefits (the difference 

between monetized benefits and costs) in 2020 are estimated to 

be $26 billion to $46 billion assuming a regional compliance 

approach (2011$) using a 3 percent discount rate (model 

average). This range of net benefits is also estimated to be $26 

billion to $45 billion assuming a state compliance approach 

(2011$) using a 3 percent discount rate (model average). Table 

15 shows the climate benefits, health co-benefits, cost and net 

benefits for Option 1 in 2020 for state and regional compliance 

approaches. Table 16 shows similar estimates for 2030. 

 For Option 1 in 2030 assuming a regional compliance 

approach, the EPA estimates this proposal will yield monetized 

climate benefits (in 2011$) of approximately $30 billion (3 

percent, model average). The air pollution health co-benefits in 

2030 are estimated to be $24 billion to $55 billion (2011$) for 

a 3 percent discount rate and $21 billion to $50 billion (2011$) 

for a 7 percent discount rate. The annual illustrative 

compliance costs estimated using IPM, inclusive of a demand-side 

energy efficiency program and participant costs and MRR costs, 

are approximately $7.3 billion (2011$) in 2030. The quantified 

net benefits (the difference between monetized benefits and 
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costs) in 2030 are estimated to be $47 billion to $78 billion 

(2011$) using a 3 percent discount rate (model average). The EPA 

estimates that this proposal will yield monetized climate 

benefits (in 2011$) of approximately $31 billion (3 percent, 

model average) for Option 1 state compliance approach in 2030. 

The air pollution health co-benefits in 2030 are estimated to be 

$25 billion to $58 billion (2011$) for a 3 percent discount rate 

and $23 billion to $53 billion (2011$) for a 7 percent discount 

rate. The annual illustrative compliance costs estimated using 

IPM, inclusive of demand side energy efficiency program and 

participant costs and MRR costs, are approximately $8.8 billion 

(2011$) in 2030. The quantified net benefits (the difference 

between monetized benefits and costs) in 2030 are estimated to 

be $47 billion to $80 billion (2011$) using a 3 percent discount 

rate (model average) assuming a state compliance approach. Based 

upon the foregoing discussion, it remains clear that the 

benefits of the proposal Option 1 are substantial and far exceed 

the costs. 

TABLE 15—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – OPTION 1 IN 2020a

[Billions of 2011$] 
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Option 1 Regional Compliance Approach

 3% Discount rate 7% Discount rate 

Climate benefits b $17 

Air pollution health 

co-benefits c

$15 to $34 $13 to $31 

Total Compliance 

Costs d

$5.5 $5.5 

Net Monetized 

Benefits e

$26 to $45 $25 to $42 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

1.3 tons of Hg 

Ecosystem Effects 

Visibility impairment 

Option 1 State Compliance Approach

Climate benefits b $18

Air pollution health 

co-benefits c

$15 to $36 $14 to $33

Total Compliance 

Costs d

$7.5 $7.5

Net Monetized 

Benefits e

$26 to $46 $24 to $43
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Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

1.5 tons 

Ecosystem Effects 

Visibility impairment 

a

 All estimates are for 2020, and 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 SCC than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SCC estimated by the USG for a 3% discount rate, however 

we emphasize the importance and value of considering the full 

range of SCC values. As shown in the RIA, climate benefits are 

also estimated using the other three USG SCC estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SCC estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 90 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. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

proposed option and a discount rate of approximately 5%. This 

estimate 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 social cost of carbon at a 3 percent 

discount rate (model average). The RIA includes combined climate 

and health estimates based on these additional discount rates. 
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TABLE 16—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – OPTION 1 IN 2030a

[Billions of 2011$] 

Option 1 Regional Compliance Approach 

 3% Discount rate 7% Discount rate 

Climate benefits b $30 

Air pollution health 

co-benefits c

$24 to $55 $21 to $50 

Total Compliance 

Costs d

$7.3 $7.3 

Net Monetized 

Benefits e

$47 to $78 $44 to $73 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

1.7 tons of Hg and 580 tons of HCl 

Ecosystem Effects 

Visibility impairment 

Option 1 State Compliance Approach 

Climate benefits b $31 

Air pollution health 

co-benefits c

$25 to $58 $23 to $53 

Total Compliance $8.8 $8.8 
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Costs d

Net Monetized 

Benefits e

$47 to $80 $45 to $75 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

2.1 tons ofHg and 590 tons of HCl 

Ecosystem Effects 

Visibility impairment 

a

 All estimates are for 2030, and 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 SCC than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SCC estimated by the USG for a 3% discount rate, however 

we emphasize the importance and value of considering the full 

range of SCC values. As shown in the RIA, climate benefits are 

also estimated using the other three USG SCC estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SCC estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 90 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. 
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d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

proposed option and a discount rate of approximately 5%. This 

estimate 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 social cost of carbon at a 3 percent 

discount rate (model average). The RIA includes combined climate 

and health estimates based on these additional discount rates. 

 The estimated costs and benefits for the regulatory 

alternative – Option 2 regional and state compliance approaches 

are shown in Tables 17 and 18. As these tables reflect, net 

benefits in 2020 are estimated to be $21 to $37 billion (3 

percent discount rate) and $20 to $34 billion (7 percent 

discount rate) for Option 2 assuming regional compliance. These 

Option 2 net benefit estimates become $20 to $37 billion (3 

percent discount rate) and $19 to $34 billion 7 percent discount 

rate) with the state compliance approach. In 2025, net benefits 

are estimated to be $30 billion to $51 billion (3 percent 

discount rate) and from $28 billion to $48 billion (7 percent 

discount rate)assuming a regional compliance approach and $30 

billion to $52 billion (3 percent discount rate) and from $28 

billion to $48 billion (7 percent discount rate) assuming a 

state compliance approach. 

 The EPA could not monetize important benefits of proposed 

Option 1 and regulatory alternative Option 2. Unquantified 
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benefits 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 and 

hydrogen chloride), as well as ecosystem effects and visibility 

impairment. 

TABLE 17 — SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – OPTION 2 IN 2020a

[Billions of 2011] 

Option 2 Regional Compliance Approach 

 3% Discount rate 7% Discount rate 

Climate benefits b $13 

Air pollution health 

co-benefits c

$12 to $28 $11 to $25 

Total Compliance 

Costs d

$4.3 $4.3 

Net Monetized 

Benefits e

$21 to $37 $20 to $34 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

0.9 tons of Hg 

Ecosystem Effects 

Visibility impairment 
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Option 2 State Compliance Approach 

Climate benefits b $14 

Air pollution health 

co-benefits c

$12 to $29 $11 to $26 

Total Compliance 

Costs d

$5.5 $5.5 

Net Monetized 

Benefits e

$20 to $37 $19 to $34 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2 

1.2 tons of Hg 

Ecosystem Effects 

Visibility impairment 

 

 a All estimates are for 2020, and 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 SCC than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SCC estimated by the USG for a 3% discount rate, however 

we emphasize the importance and value of considering the full 

range of SCC values. As shown in the RIA, climate benefits are 

also estimated using the other three USG SCC estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SCC estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 
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emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 90 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. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

proposed option and a discount rate of approximately 5%. This 

estimate 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 social cost of carbon at a 3 percent 

discount rate (model average). The RIA includes combined climate 

and health estimates based on these additional discount rates. 

TABLE 18 — SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – OPTION 2 IN 2025a (Billions 

of 2011$) 

Option 2 Regional Compliance Approach 

 3% Discount rate 7% Discount rate 

Climate benefits b $18 

Air pollution health 

co-benefits c

$16 to $37 $14 to $34 

Total Compliance 

Costs d

$4.5 $4.5 

Net Monetized 

Benefits e

$30 to $51 $28 to $48 
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Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

1.3 tons of Hg 

Ecosystem Effects 

Visibility impairment 

Option 2 State Compliance Approach 

Climate benefits b $19 

Air pollution health 

co-benefits c

$16 to $38 $15 to $35 

Total Compliance 

Costs d

$5.5 $5.5 

Net Monetized 

Benefits e

$30 to $52 $28 to $48 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2 

1.7 tons of Hg 

Ecosystem Effects 

Visibility impairment 

a

 All estimates are for 2025, and 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 SCC than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SCC estimated by the USG for a 3% discount rate, however 
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we emphasize the importance and value of considering the full 

range of SCC values. As shown in the RIA, climate benefits are 

also estimated using the other three USG SCC estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SCC estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 90 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. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

proposed option and a discount rate of approximately 5%. This 

estimate 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 social cost of carbon at a 3 percent 

discount rate (model average). The RIA includes combined climate 

and health estimates based on these additional discount rates. 

B. Paperwork Reduction Act 

 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 Information Collection Request (ICR) 

document prepared by the EPA has been assigned the EPA ICR 

number [insert #]. 
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The information collection requirements are based on the 

recordkeeping and reporting burden associated with developing, 

implementing, and enforcing a state plan to limit CO2 emissions 

from existing sources in the power sector. These 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. 

The annual burden for this collection of information for 

the states (averaged over the first 3 years following 

promulgation of this proposed action) is estimated to be a range 

of 315,554 hours at a total annual labor cost of $22,334,119, to 

632,338 hours at a total annual labor cost of $44,755,317. The 

lower bound estimate reflects the assumption that some states 

already have energy efficiency and renewable energy programs in 

place. The higher bound estimate reflects the assumption that no 

states have energy efficiency and renewable energy programs in 

place. The annual burden for this collection of information for 

the states (averaged over the first 3 years following 

promulgation of this proposed action) is estimated to be a range 
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of 315,554 hours at a total annual labor cost of $22,334,119, to 

632,338 hours at a total annual labor cost of $44,755,317. The 

lower bound estimate reflects the assumption that some states 

already have energy efficiency and renewable energy programs in 

place. The higher bound estimate reflects the assumption that no 

states have energy efficiency and renewable energy programs in 

place. The total annual burden for the federal government 

(averaged over the first 3 years following promulgation of this 

proposed action) is estimated to be 53,267 hours at a total 

annual labor cost of $2,958.005Burden means the total time, 

effort, or financial resources expended by persons to generate, 

maintain, retain, or disclose or provide information to or for a 

Federal agency. This includes the time needed to review 

instructions; develop, acquire, install, and utilize technology 

and systems for the purposes of collecting, validating, and 

verifying information, processing and maintaining information, 

and disclosing and providing information; adjust the existing 

ways to comply with any previously applicable instructions and 

requirements; train personnel to be able to respond to a 

collection of information; search data sources; complete and 

review the collection of information; and transmit or otherwise 

disclose the information. 
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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 are listed in 40 CFR part 9 

and 48 CFR chapter 15. 

To comment on the agency's need for this information, the 

accuracy of the provided burden estimates, and any suggested 

methods for minimizing respondent burden, the EPA has 

established a public docket for this rule, which includes this 

ICR, under Docket ID Number EPA-HQ-OAR-2013-0602. Submit any 

comments related to the ICR to the EPA and OMB. See the 

ADDRESSES section at the beginning of this notice for where to 

submit comments to the EPA. Send comments to OMB at the Office 

of Information and Regulatory Affairs, Office of Management and 

Budget, 725 17th Street, NW, Washington, DC 20503, Attention: 

Desk Office for the EPA. Since OMB is required to make a 

decision concerning the ICR between 30 and 60 days after [INSERT 

DATE OF PUBLICATION IN THE FEDERAL REGISTER], a comment to OMB 

is best assured of having its full effect if OMB receives it by 

[INSERT DATE 30 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. 

The final rule will respond to any OMB or public comments on the 

information collection requirements contained in this proposal. 
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C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) generally requires an 

agency to prepare a regulatory flexibility analysis of any rule 

subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless the 

agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities. Small 

entities include small businesses, small organizations, and 

small governmental jurisdictions. 

For purposes of assessing the impacts of this rule on small 

entities, small entity is defined as: 

(1) A small business that is defined by the SBA’s 

regulations at 13 CFR 121.201 (for the electric power generation 

industry, the small business size standard is an ultimate parent 

entity with less than 750 employees. The NAICS codes for the 

affected industry are in Table 19 below); 

(2) A small governmental jurisdiction that is a government 

of a city, county, town, school district or special district 

with a population of less than 50,000; and 

(3) A small organization that is any not-for-profit 

enterprise which is independently owned and operated and is not 

dominant in its field. 
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Table 19. Potentially Regulated Categories and Entitiesa

 

Category NAICS 

Code 

Examples of Potentially Regulated 

Entities 

Industry 

 

221112 

 

Fossil fuel electric power generating 

units. 

State/Local 

Government 

 

221112b

 

Fossil fuel electric power generating 

units owned by municipalities. 

a

 Include NAICS categories for source categories that own and 

operate electric power generating units (includes boilers and 

stationary combined cycle combustion turbines). 

b

 State or local government-owned and operated establishments are 

classified according to the activity in which they are engaged. 

After considering the economic impacts of this proposed 

rule on small entities, I certify that this action will not have 

a significant economic impact on a substantial number of small 

entities. 

The proposed rule will not impose any requirements on small 

entities. Specifically, emission guidelines established under 

CAA section 111(d) do not impose any requirements on regulated 

entities and, thus, will not have a significant economic impact 

upon a substantial number of small entities. After emission 

guidelines are promulgated, states establish standards on 

existing sources and it is those state requirements that could 

potentially impact small entities. Our analysis here is 
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consistent with the analysis of the analogous situation arising 

when the EPA establishes NAAQS, which do not impose any 

requirements on regulated entities. As here, any impact on small 

entities would only arise when states take subsequent action to 

maintain and/or achieve the NAAQS through their state 

implementation plans. See American Trucking Assoc. v. EPA, 175 

F.3d 1029, 1043-45 (D.C. Cir. 1999) national standards for 

allowable concentrations of particulate matter in ambient air as 

required by section 109 of the CAA. See also American Trucking 

Associations v. EPA. 175 F.3d at 1044–45 (NAAQS do not have 

significant impacts upon small entities because NAAQS themselves 

impose no regulations upon small entities). 

Nevertheless, the EPA is aware that there is substantial 

interest in the proposed rule among small entities (municipal 

and rural electric cooperatives). As detailed in Section 

III.A.of this preamble, the EPA has conducted an unprecedented 

amount of stakeholder outreach on setting emission guidelines 

for existing EGUs. While formulating the provisions of the 

proposed rule, the EPA considered the input provided over the 

course of the stakeholder outreach. Section III.B of this 

preamble describes the key messages from stakeholders. In 

addition, as described in the RFA section of the preamble to the 
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proposed standards of performance for GHG emissions from new 

EGUs (79 FR 1499-1500, January 8, 2014), the EPA conducted 

outreach to representatives of small entities while formulating 

the provisions of the proposed standards. Although only new EGUs 

would be affected by those proposed standards, the outreach 

regarded planned actions for new and existing sources. We invite 

comments on all aspects of the proposal and its impacts, 

including potential impacts on small entities. 

EPA specifically asks for comment on ways that EPA can 

provide flexibility to States with significant rural areas that 

have older EGU facilities that may or may not be undergoing 

upgrades to meet the MATS requirements. Those areas typically 

have a higher percentage of poverty relative to urban areas and 

also pay generally higher electricity bills each month. Because 

of that situation, the requirements in this rule will likely 

increase the cost to those ratepayers more than ratepayers in 

urban areas, which raises Environmental Justice issues. 

Furthermore, those rural areas may have less access to building 

blocks 1 – 4 to improve existing EGU performance. 

EPA has used other flexibilities in previous rulemakings 

that are both consistent with the 42 U.S. Code 7411 and with the 
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processes outlined in 42 U.S. Code 7410 and asks for comment on 

whether those could be applied to this situation. For example, 

would it be feasible for EPA to extend compliance past 2030 for 

certain regions within a state; i.e., for a specific portion of 

the State’s goal? In that case how could EPA weigh 

considerations such as the remaining useful lives of sources in 

those areas, particularly if they have invested in upgrades to 

meet the recently promulgated MATS rule? Treatment of regions 

differently for compliance purposes is consistent with the 

concept of economic development zones and rural transport areas 

that are found in CAA section 182. 

EPA also requests for comment on whether it can use Sec 112 

flexibilities to grant an extension permitting existing sources 

up to 1 additional year to comply with standards if such 

additional period is necessary for the installation of controls. 

Or additional extension of up to 3 years may be added for to 

address useful life and other issues, such as rural areas with 

persistent poverty. 

D. Unfunded Mandates Reform Act

This proposed action does not contain a federal mandate that 

may result in expenditures of $100 million or more for State, 

Comment [A84]: Suggested edits to address rural 

communities 
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local, and tribal governments, in the aggregate, or the private 

sector in any one year. Specifically, emission guidelines 

established under CAA section 111(d) do not impose any direct 

compliance requirements on regulated entities. Thus, this proposed 

rule is not subject to the requirements of section 202 or section 

205 of UMRA. 

This proposed rule is also not subject to the requirements 

of section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments. 

In light of the interest among governmental entities, the 

EPA initiated consultations with governmental entities while 

formulating the provisions of the proposed standards for new 

EGUs. Although only new EGUs would be affected by those proposed 

standards, the outreach regarded planned actions for new and 

existing sources. As described in the UMRA discussion in the 

preamble to the proposed standards of performance for GHG 

emissions from new EGUs (79 FR 1500-1501, January 8, 2014), the 

EPA consulted with the following 10 national organizations 

representing state and local elected officials: 1) National 

Governors Association; 2) National Conference of State 

Legislatures, 3) Council of State Governments, 4) National 

Comment [A85]: This rule could have impacts of 

more than $100 million for certain small 

governments with a high degree of reliance on rural 

cooperatives or municipal EGUs that do not have 

easy access to the BSER buildng blocks. EPA 

should do an UMRA analysis. 
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League of Cities, 5) U.S. Conference of Mayors, 6) National 

Association of Counties, 7) International City/County Management 

Association, 8) National Association of Towns and Townships, 9) 

County Executives of America, and 10) Environmental Council of 

States. On February 26, 2014, the EPA re-engaged with those 

governmental entities to provide a pre-proposal update on the 

emission guidelines for existing EGUs and emission standards for 

modified and reconstructed EGUs. 

While formulating the provisions of these proposed emission 

guidelines, the EPA also considered the input provided over the 

course of the extensive stakeholder outreach conducted by the 

EPA (see Sections III.A. and III.B. of this preamble). 

E. Executive Order 13132, Federalism 

Under Executive Order 13132, EPA may not issue an action 

that has federalism implications, that imposes substantial 

direct compliance costs, and that is not required by statute, 

unless the Federal government provides the funds necessary to 

pay the direct compliance costs incurred by State and local 

governments, or the EPA consults with state and local officials 

early in the process of developing the proposed action.

 The EPA has concluded that this action may have federalism 

implications, because it may impose substantial direct 
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compliance costs on State or local governments, and the Federal 

government will not provide the funds necessary to pay those 

costs. As discussed in the Supporting Statement found in the 

docket for this rulemaking, the development of state plans will 

entail many hours of staff time to develop and coordinate 

programs for compliance with the proposed rule, as well as time 

to work with state legislatures as appropriate, and develop a 

plan submittal.

The EPA consulted with state and local officials early in 

the process of developing the proposed action 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. This outreach regarded 

planned actions for new, reconstructed, modified and existing 

sources. The EPA invited the following 10 national organizations 

representing state and local elected officials to a meeting on 

April 12, 2011, in Washington DC: (1) National Governors 

Association; (2) National Conference of State Legislatures, (3) 

Council of State Governments, (4) National League of Cities, (5) 
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U.S. Conference of Mayors, (6) National Association of Counties, 

(7) International City/County Management Association, (8) 

National Association of Towns and Townships, (9) County 

Executives of America, and (10) Environmental Council of States. 

These 10 organizations representing elected state and local 

officials have been identified by the EPA as the “Big 10” 

organizations appropriate to contact for purpose of consultation 

with elected officials. On February 26, 2014, the EPA re-engaged 

with those governmental entities to provide a pre-proposal 

update on the emission guidelines for existing EGUs and emission 

standards for modified and reconstructed EGUs. In addition, 

extensive stakeholder outreach conducted by the EPA allowed 

state leaders, including governors, environmental commissioners, 

energy officers, public utility commissioners, and air 

directors, opportunities to engage with EPA officials and 

provide input regarding reducing carbon pollution from power 

plants.

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 rule, 

as required by section 6(b) of Executive Order 13132. In the 

spirit of Executive Order 13132, and consistent with EPA policy 
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to promote communications between EPA and State and local 

governments, EPA specifically solicits comment on this proposed 

action from State and local officials.

F. Executive Order 13175, Consultation and Coordination with 

Indian Tribal Governments 

This action does not have tribal implications, as specified 

in Executive Order 13175 (65 FR 67249, November 9, 2000). It 

would not impose substantial direct compliance costs on tribal 

governments that have affected EGUs located in their area of 

Indian country. Tribes are not required to, but may, develop or 

adopt CAA programs. Tribes are not required to develop plans to 

implement the guidelines under CAA section 111(d) for affected 

EGUs. To the extent that a tribal government seeks and attains 

treatment in a manner similar to a state (TAS) status for that 

purpose and is delegated authority for air quality planning 

purposes, these proposed emission guidelines would require that 

planning requirements be met and emission management 

implementation plans be executed by the tribes. The EPA is aware 

of three coal-fired EGUs and one natural gas-fired EGU located 

in Indian country but is not aware of any affected EGUs that are 

owned or operated by tribal entities. The EPA notes that this 

proposal does not directly impose specific requirements on EGU 
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sources, including those located in Indian country, such as the 

three coal-fired EGUs and one natural gas-fired EGU, but 

provides guidance to any tribe with delegated authority to 

address CO2 emissions from EGU sources found subject to section 

111(d) of the CAA. Thus, Executive Order 13175 does not apply to 

this action. 

The EPA conducted outreach to tribal environmental staff 

and offered consultation with tribal officials in developing 

this action. Because the EPA is aware of tribal interest in this 

proposed rule, prior to the April 13, 2012 proposal (77 FR 

22392-22441), the EPA offered consultation with tribal officials 

early in the process of developing the proposed regulation to 

permit them to have meaningful and timely input into its 

development. The EPA's consultation regarded planned actions for 

new and existing sources. In addition, on April 15, 2014, prior 

to proposal, the EPA met with Navajo Energy Development Group 

officials. For this proposed action for existing EGUs, a tribe 

that has one or more affected EGUs located in its area of Indian 

Country291 would have the opportunity, but not the obligation, to 

 

291 The EPA is aware of at least four affected EGUs located in 

Indian country: two on Navajo lands, the Navajo Generating 

Station and the Four Corners Generating Station; one on Ute 
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establish a CO2 performance standard and a CAA section 111(d) 

plan for its area of Indian country. 

Consultation letters were sent to 584 tribal leaders. The 

letters provided information regarding the EPA's development of 

both the NSPS and emission guidelines for fossil fuel-fired EGUs 

and offered consultation. No tribes have requested consultation. 

Tribes were invited to participate in the national informational 

webinar held August 27, 2013. In addition, consultation/outreach 

meeting was held on September 9, 2013, with tribal 

representatives from some of the 584 tribes. The EPA also met 

with tribal environmental staff via National Tribal Air 

Association teleconferences on July 25, 2013, and December 19, 

2013. In those teleconferences, the EPA provided background 

information on the GHG emission guidelines to be developed and a 

summary of issues being explored by the agency. Tribes have 

expressed varied points of view. Some tribes raised concerns 

about the impacts of the regulations on EGUs and the subsequent 

impact on jobs and revenue for their tribes. Other tribes 

 

lands, the Bonanza Generating Station; and one on Fort Mojave 

lands, the South Point Energy Center. The affected EGUs at the 

first three plants are coal-fired EGUs. The fourth affected EGU 

is an NGCC facility. 
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expressed concern about the impact the regulations would have on 

the cost of water to their communities as a result of increased 

costs to the EGU that provide energy to transport the water to 

the tribes. Other tribes raised concerns about the impacts of 

climate change on their communities, resources, life ways and 

hunting and treaty rights. The tribes were also interested in 

the scope of the guidelines being considered by the agency 

(e.g., over what time period, relationship to state and multistate plans) and how tribes will participate in these planning 

activities. In addition, the EPA held a series of listening 

sessions prior to development of this proposed action. In 2013, 

tribes participated in a session with the state agencies, as 

well as a separate session with tribes. 

During the public comment period for this proposal, the EPA 

will hold meetings with tribal environmental staff to inform 

them of the content of this proposal, as well as offer further 

consultation with tribal elected officials where it is 

appropriate. We specifically solicit comment from tribal 

officials on this proposed rule. 

G. Executive Order 13045, Protection of Children from 

Environmental Health Risks and Safety Risks 

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) 
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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 co-benefit, would further improve 

children’s health. 

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

Executive Order 13211 (66 FR 28355; May 22, 2001) requires 

the EPA to prepare and submit a Statement of Energy Effects to 

the Administrator of the Office of Information and Regulatory 

Affairs, OMB, for actions identified as ‘‘significant energy 

actions.’’ 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. We have prepared a 

Statement of Energy Effects for this action as follows. We 

estimate a 4 to 7 percent increase in retail electricity prices, 

on average, across the contiguous U.S. in 2020, and a 16 to 22 
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percent reduction in coal-fired electricity generation as a 

result of this rule. The EPA projects that electric power sector 

delivered natural gas prices will increase by about 8 to 12 

percent in 2020. For more information on the estimated energy 

effects, please refer to the economic impact analysis for this 

proposal. The analysis is available in the RIA, which is in the 

public docket.

I. National Technology Transfer and Advancement Act 

Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 

15 U.S.C. 272 note) directs the EPA to use Voluntary Census 

Standards in their regulatory and procurement activities unless 

to do so would be inconsistent with applicable law or otherwise 

impractical. Voluntary consensus standards are technical 

standards (e.g., materials specifications, test methods, 

sampling procedures, business practices) developed or adopted by 

one or more voluntary consensus bodies. The NTTAA directs the 

EPA to provide Congress, through annual reports to the OMB, with 

explanations when an agency does not use available and 

applicable VCS. This proposed rulemaking does not involve 

technical standards. 

The EPA welcomes comments on this aspect of the proposed 

rulemaking and specifically invites the public to identify 
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potentially-applicable VCS and to explain why such standards 

should be used in this action. 

J. 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 environmental justice. 

Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental 

justice 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. 

Section II.A of this preamble summarizes the public health 

and welfare impacts from GHG emissions that were detailed in the 

2009 Endangerment Finding under CAA section 202(a)(1).292 As part 

of the Endangerment Finding, the Administrator considered 

climate change risks to minority or low-income populations, 

finding that certain parts of the population may be especially 

 

292 “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”). 

Comment [A86]: Can EPA add more to this 

section in response to the following comment: 

However, this rule will have a 

disproportional impact on rural 

America. Compliance with the 

proposed EPA GHG rule will result 

in higher electricity prices 

nationwide. Rural consumers 

already use more electricity than 

their urban counterparts. For 

instance, RUS records indicate that 

average monthly consumption for all 

US consumers is $107.28 vs. $133.78 

for rural consumers. This is due, 

in part, to the fact that rural 

consumers often are limited to 

substandard, inefficient housing 

choices. There are far fewer rural 

consumers to absorb rate increases 

and rural Americans have lower 

incomes than their urban 

counterparts. Also, persistent 

poverty counties are mostly located 

in rural areas. 

A greater portion of rural America 

is reliant on the electricity 

generated by fossil-fired power 

plants, in particular coal-fired 

units. For example, rural 

electric cooperatives generate 

about 70% of their baseload power 

from coal units. Various other EPA 

regulations either proposed or 

implemented over the past few years 

have forced electric cooperatives 

to make difficult choices to 

sustain an adequate amount of 

reliable and affordable power to 

meet the needs of its 

consumers. For example, the 

Mercury and Air Toxics Standards 

(MATS) and rules with respect to 

attaining and maintaining National 

Ambient Air Quality Standards 

(NAAQS) have resulted in the 

decision to either shut down 

certain coal-fired units or, in 

most cases, to implement expensive 

upgrades to meet the intended 

emission requirements of the 

rules. Therefore, rural electric 

cooperatives have already committed 

a relatively large amount of 

capital to continue to operate 

coal-fired plants that will now be 

subjected to further emission 

requirements under the proposed 

111(d) rule. Rural electric 

cooperatives may be required to 

curtail the operation of these 

units or prematurely retire the 

units earlier than originally 

anticipated prior to the enactment 

of the proposed rule. As a result, ... [2]
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vulnerable based on their circumstances. These 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. 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. 

Strong scientific evidence that the potential impacts of 

climate change raise environmental justice issues is found in 

the major assessment reports by the U.S. Global Change Research 

Program (USGCRP), the Intergovernmental Panel on Climate Change 

(IPCC), and the National Research Council (NRC) of the National 

Academies, summarized in the record for the Endangerment 

Finding. Their conclusions include 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 on established reservations that are restricted to 

reservation boundaries and therefore have limited relocation 

options. Tribal communities whose health, economic well-being, 
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and cultural traditions depend upon the natural environment will 

likely be affected by the degradation of ecosystem goods and 

services associated with climate change. Southwest native 

cultures are especially vulnerable to water quality and 

availability impacts. Native Alaskan communities are likely to 

experience disruptive impacts, including shifts in the range or 

abundance of wild species crucial to their livelihoods and wellbeing. The most recent assessments continue to strengthen 

scientific understanding of climate change risks to minority and 

low-income populations. 

This proposed rule limits GHG emissions by establishing CO2 

emission guidelines for existing fossil fuel-fired EGUs. In 

addition to reducing CO2 emissions, implementing the proposed 

rule would reduce other emissions from EGUs which are dispatched 

less under a state’s 111(d) program because of their relatively 

low energy efficiency. These emission reductions will include SO2

and NOx, which form ambient PM2.5 and ozone in the atmosphere, and 

hazardous air pollutants (HAP), such as mercury. In the final 

rule revising the annual PM2.5 standard293, the EPA identified 

 

293 U.S. EPA (2013). National Ambient Air Quality Standards for 

Particulate Matter, Final Rule. Federal Register 78 (15 January 

2013): 3086-3287. 
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persons with lower socioeconomic status as an at-risk population 

for experiencing adverse health effects related to PM exposures. 

Persons with lower socioeconomic status 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 risk to PMrelated and ozone-related effects.294 Therefore, in areas where 

this rulemaking reduces exposure to PM2.5, ozone, and 

methylmercury persons with low socioeconomic status would also 

benefit. The regulatory impact analysis (RIA) for this 

rulemaking, included in the docket for this rulemaking, provides 

additional information regarding the health and ecosystem 

effects associated with these emission reductions. 

While there will be many locations with improved air 

quality for PM2.5, ozone, and methylmercury, there may also be 

EGUs whose emissions of one or more of these pollutants or their 

precursors increase as a result of the proposed emission 

guidelines for existing fossil fuel-fired EGUs. This may occur 

 

294 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://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
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at EGUs that are dispatched more intensively than in the past 

because they become more energy efficient. The EPA has 

considered the potential for such increases and the 

environmental justice implications of such increases. 

As we noted in the NSR discussion in this preamble, as part 

of a state’s CAA section 111(d) plan, the state may require an 

affected EGU to undertake a physical or operational change to 

improve the unit’s efficiency that results in an increase in the 

unit’s dispatch and an increase in the unit’s annual emissions 

of GHGs and/or other regulated pollutants. As we noted in the 

NSR discussion in this preamble, a state can take steps to avoid 

increased utilization of particular EGUs and thus to avoid any 

significant increases in emissions including emissions of other 

regulated pollutants whose environmental effects would be more 

localized around the affected EGU. To the extent that states 

take this path, there would be no new environmental justice 

concerns in the areas near such EGUs. For any EGUs that make 

modifications that do trigger NSR permitting, the applicable 

local, state, or federal permitting program will ensure that 

there are no new NAAQS violations and that no existing NAAQS 

violations are made worse. For those EGUs in a permitting 

situation for which the EPA is the permit reviewing authority, 
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the EPA will consider environmental justice issues as required 

by Executive Order 12898. 

In addition to some EGUs possibly being required by a state 

to make modifications for increased energy efficiency, another 

effect of the proposed CO2 emission guidelines for existing 

fossil fuel-fired EGUs would be increased utilization of other, 

unmodified EGUs with relatively low GHG emissions per unit of 

electrical output, in particular high efficiency gas-fired EGUs. 

Because such EGUs would not have been modified physically nor 

changed their method of operation, they would not be subject to 

review in the NSR permitting program. Such plants would have 

more hours in the year in which they operate and emit 

pollutants, including pollutants whose environmental effects if 

any would be localized rather than global as is the case with 

GHG emissions. Changes in utilization already occur now as 

demands for and sources of electrical energy evolve, but the 

proposed CO2 emission guidelines for existing fossil fuel-fired 

EGUs can be expected to cause more such changes. Because gasfired EGUs emit essentially no mercury, increased utilization 

would not increase methylmercury concentrations in their 

vicinities. Increased utilization generally would not cause 

higher peak concentrations of PM2.5, NOx, or ozone around such 
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EGUs than is already occurring because peak hourly or daily 

emissions generally would not change, but increased utilization 

may make periods of relatively high concentrations more 

frequent. It should be noted that the gas-fired sources that are 

likely to be dispatched more frequently than at present have 

very low emissions of primary particulate matter, SO2 and 

hazardous air pollutants per unit of electrical output, such 

that local (or regional) air quality for these pollutants is 

likely to be affected very little. For natural gas-fired EGUS, 

the EPA found that regulation of HAP emissions “is not 

appropriate or necessary because the impacts due to HAP 

emissions from such units are negligible based on the results of 

the study documented in the utility RTC” 65 FR 79831. In studies 

done by DOE/NETL comparing cost and performance of coal- and NGfired generation, they assumed SO2, PM (and Hg) emissions to be 

“negligible.” Their studies predict NOx emissions from a NGCC 

unit to be approximately 10 times lower than a subcritical or 

supercritical coal-fired boiler. Many are also very well 

controlled for emission of NOx through the application of after 

combustion controls such as selective catalytic reduction, 

although not all gas-fired sources are so equipped. Depending on 

the specificity of the state CAA section 111(d) plan, the state 
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may be able to predict which EGUs and communities may be in this 

type of situation and to address any concerns about localized NO2

concentrations in the design of the CAA section 111(d) program, 

or separately from the CAA section 111(d) program but before its 

implementation. In any case, existing tracking systems will 

allow states and the EPA to be aware of the EGUs whose 

utilization has increased most significantly, and thus to be 

able to prioritize our efforts to assess whether air quality has 

changed in the communities in the vicinity of such EGUs. There 

are multiple mechanisms in the CAA to address situations in 

which air quality has degraded significantly.In conclusion, this 

proposed rule will result in regional and national pollutant 

reductions; however, there likely will also be some locations 

with more times during the year of relatively higher 

concentrations of pollutants with potential for effects on 

localized communities than would be experienced in the absence 

of the proposed rule. The rule may also disproportionately raise 

electricity costs in rural areas that already have higher levels 

of poverty than other parts of the country.The EPA cannot 

exactly predict how emissions from specific EGUs would change as 

an outcome of the proposed rule nor how costs may be passed 

along to ratepayers due to the state-led implementation. 
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Therefore, the EPA has concluded that it is not practicable to 

determine whether there would be disproportionately high and 

adverse human health, economic, or or environmental effects on 

minority, low income, or indigenous populations from this 

proposed rule. 

In order to provide opportunities for meaningful 

involvement early on in the rule making process, the EPA has 

hosted webinars and conference calls on August 27, 2013 and 

September 9, 2013 on the proposed rule specifically for 

environmental justice communities and has taken all comments and 

suggestions into consideration in the design of the emission 

guidelines. 

The public is invited to submit comments or identify peerreviewed studies and data that assess effects of exposure to the 

pollutant addressed by this proposal. 

XII. Statutory Authority 

The statutory authority for this action is provided by 

sections 111, 301, 302, and 307(d)(1)(V) of the CAA, as amended 

(42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(V)). This action is also 

subject to section 307(d) of the CAA (42 U.S.C. 7607(d)). 

Formatted: Font color: Red
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List of Subjects in 40 CFR Part 60 

Environmental protection, Administrative practice and 

procedure, Air pollution control, Intergovernmental relations, 

Reporting and recordkeeping requirements. 

___________________ 

Dated: 

____________________ 

Gina McCarthy, 

Administrator. 
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For the reasons stated in the preamble, title 40, chapter I, 

part 60 of the Code of the Federal Regulations is proposed to be 

amended as follows: 

1. Section 60.27 is amended by revising paragraph (b) to read as 

follows: 

* * * * * 

(b) After receipt of a plan or plan revision, the 

Administrator will propose the plan or revision for approval or 

disapproval. The Administrator will, within four months after 

the date required for submission of a plan or plan revision, 

approve or disapprove such plan or revision or each portion 

thereof, except as provided in §60.5715. 

* * * * * 

2. Part 60 is amended by adding subpart UUUUU to read as 

follows:

Subpart UUUU: Emission Guidelines for Greenhouse Gas Emissions 

and Compliance Times for Electric Utility Generating Units 

Sec. 

Introduction 

60.5700 What is the purpose of this subpart? 

60.5705 What greenhouse gases are regulated by this subpart? 

60.5710 Am I affected by this subpart? 

60.5715 What is the review and approval process for my state 

plan? 

60.5720 What if my state plan is not approvable? 

60.5725 In lieu of a state plan submittal, are there other 

acceptable option(s) for a state to meet its section 

111(d) obligations? 

60.5730 Is there an approval process for a negative 

declaration letter? 

60.5735 What authorities will not be delegated to state, 

local, or tribal agencies? 

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space between Latin and Asian text, Adjust

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State Plan 

60.5740 What must I include in my state plan? 

60.5745 Can I work with other states to develop a multi-state 

plan? 

60.5750 Can I include existing requirements, programs, and 

measures in my state plan? 

60.5755 What are the timing requirements for submitting my 

state plan? 

60.5760 What must I include in an initial submittal in lieu of 

a complete state plan? 

60.5765 What are the state rate-based CO2 emission performance 

goals? 

60.5770 What is the procedure for converting my state ratebased CO2 emission performance goal to a mass-based CO2

emissions performance goal? 

60.5775 What schedules, performance periods, and compliance 

periods must I include in my state plan? 

60.5780 What emission standards and enforcing measures must I 

include in my plan? 

60.5785 What is the procedure for revising my state plan? 

Applicability of State Plans to Affected EGUs

60.5790 Does this subpart directly affect EGU owners and 

operators in my state? 

60.5795 What affected EGUs must I address in my state plan? 

60.5800 What affected EGUs are exempt from my state plan? 

60.5805 What applicable monitoring, recordkeeping, and 

reporting requirements do I need to include in my 

state plan for affected EGUs? 

Recordkeeping and Reporting Requirements 

60.5810 What are my state recordkeeping requirements? 

60.5815 What are my state reporting requirements? 

Definitions 

60.5820 What definitions apply to this subpart? 

Introduction 

§ 60.5700 What is the purpose of this subpart?

 This subpart establishes emission guidelines and approval 

criteria for state plans that establish standards of performance 

limiting the control of greenhouse gas emissions from an 
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affected steam generating unit, integrated gasification combined 

cycle (IGCC), or stationary combustion turbine. An affected 

steam generating unit, IGCC, or stationary combustion turbine 

shall, for the purposes of this subpart, be referred to as an 

affected EGU. These emission guidelines are developed in 

accordance with sections 111(d) of the Clean Air Act and subpart 

B of this part. To the extent any requirement of this subpart is 

inconsistent with the requirements of subpart A of this part, 

the requirements of this subpart will apply. 

§ 60.5705 What greenhouse gases are regulated by this subpart? 

 The greenhouse gas regulated by this subpart is carbon 

dioxide (CO2). 

§ 60.5710 Am I affected by this subpart? 

 If you are the Administrator of an air quality program in a 

state with one or more affected EGUs that commenced construction 

on or before [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], you must submit a state plan to U.S. Environmental 

Protection Agency (EPA) that implements the emission guidelines 

contained in this subpart. You must submit a negative 

declaration letter in place of the state plan if there are no 

affected EGUs for which construction commenced on or before 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] in your 

state. 
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§ 60.5715 What is the review and approval process for my state 

plan? 

The EPA will review your state plan according to §60.27 

except that under paragraph §60.27(b) the Administrator will 

have six months after the date required for submission of a plan 

or plan revision to approve or disapprove such plan or revision 

or each portion thereof. If you submit a request for extension 

under § 60.5760 in lieu of a complete state plan the 

Administrator will have six months after the date required for 

submission to approve or disapprove the request. 

§ 60.5720 What if I do not submit a plan or my plan is not 

approvable? 

If you do not submit an approvable state plan the EPA will 

develop a Federal plan for your state according to §60.27 to 

implement the emission guidelines contained in this subpart. 

Owners and operators of affected entities not covered by an 

approved state plan must comply with a Federal plan implemented 

by EPA for the state. The Federal plan is an interim action and 

will be automatically withdrawn when your state plan is 

approved. 

§ 60.5725 In lieu of a state plan submittal, are there other 

acceptable options for a state to meet its section 111(d) 

obligations? 

 No. 
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§ 60.5730 Is there an approval process for a negative 

declaration letter? 

No. The EPA has no formal review process for negative 

declaration letters. Once your negative declaration letter has 

been received, EPA will place a copy in the public docket and 

publish a notice in the FEDERAL REGISTER. If, at a later date, an 

affected EGU for which construction commenced on or before 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] is found in 

your state, a Federal plan implementing the emission guidelines 

contained in this subpart would automatically apply to that 

affected EGU until your state plan is approved. 

§ 60.5735 What authorities will not be delegated to state, 

local, or tribal agencies?

The authorities that will not be delegated to State, local, 

or tribal agencies are specified in paragraphs (a) of this 

section. 

(a) Approval of alternatives, not already approved by this 

subpart, to the emissions performance goals in Table 1 to this 

subpart established under §60.5755. 

State Plan 

§ 60.5740 What must I include in my state plan? 

(a) You must include the elements described in paragraphs 

(a)(1) through (a)(11) of this section in your state plan. 
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(1) Identification of affected entities, including an 

inventory of CO2 emissions from affected EGUs during the most 

recent calendar year prior to the submission of the plan for 

which data is available. 

(2) A description of plan approach and the geographic scope 

of a plan (state or multi-state), including, if relevant, 

identification of multi-state plan participants and geographic 

boundaries related to plan elements. 

(3) Identification of the state emission performance level 

for affected entities that will be achieved through 

implementation of the plan. 

(i) The plan must specify the average emissions performance 

that the plan will achieve for the following periods: 

(A) The 10 year interim plan performance period of 2020 

through 2029. 

(B) The single projection year of 2030. 

(ii) The identified emission performance level for each 

plan performance period in paragraph (i) must be equivalent to 

or better than the levels of the rate-based CO2 emission 

performance goals in Table 1 of this Subpart for affected 

entities in your state. The emission performance levels may be 

in either a rate-based form or a mass based form which is 

calculated according to § 60.5770. The CO2 emission performance 
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level specified must include either of the following as 

applicable: 

(A) For a rate-based CO2 emission performance level, the 

identified level must represent the CO2 emissions rate, in pounds 

of CO2 per MWh of net energy output that will be achieved by 

affected entities 

B) For a mass-based CO2 emission performance level, the 

identified level of performance must represent the total tons of 

CO2 that will be emitted by affected entities during each plan 

performance period. 

(iii) For the interim plan performance period you must 

identify the emission performance levels anticipated under the 

plan during each year 2020 through 2029. 

(4) A demonstration that the plan is projected to achieve 

each of the state’s emission performance levels for affected 

entities according to paragraph (a)(3) of this section. 

(5) Identification of emission standards for each affected 

entity, compliance periods for each emission standard, and 

demonstration that the emission standards are, when taken 

together, sufficiently protective to meet the state emissions 

performance level. 

(6) A demonstration that each emission standard is 

quantifiable, non-duplicative, permanent, verifiable, and 

enforceable with respect to an affected entity. 
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(7) If your state plan does not require achievement of the 

full level of required emission performance, and the identified 

interim increments of performance in section (a)(3)(iii), 

through emission limits on EGUs, the plan must specify the 

following: 

(i) Program implementation milestones (e.g., start of an 

end-use energy efficiency program, retirement of an affected 

EGU, or increase in portfolio requirements under a renewable 

portfolio standard) and milestone dates that are appropriate to 

the requirements, programs, and measures included in the plan. 

(ii) Corrective measures that will be implemented in the 

event that the comparison required by § 60.5815(b) of projected 

versus actual emissions performance of affected entities shows 

that actual emissions performance is greater than 10 percent in 

excess to projected plan performance for the period described in 

§ 60.5775(c)(1), and a process and schedule for implementing 

such corrective measures. 

(8) Identification of applicable monitoring, reporting, and 

recordkeeping requirements for each affected entity. If 

applicable, these requirements must be consistent with the 

requirements specified in § 60.5810.

(9) Description of the process, contents, and schedule for 

annual state reporting to the EPA about plan implementation and 

progress including information required under § 60.5815. 
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(10) Certification that the hearing on the state plan was 

held, a list of witnesses and their organizational affiliations, 

if any, appearing at the hearing, and a brief written summary of 

each presentation or written submission. 

(11) Supporting material including: 

(i) Materials demonstrating the state's legal authority to 

carry out each component of its plan, including emissions 

standards; 

(ii) Materials supporting the projected emissions 

performance level that will be achieved by affected entities 

under the plan, according to paragraph (a)(4); 

(iii) Materials supporting the projected mass-based 

emission performance goal, calculated pursuant to § 60.5770, if 

applicable; and 

(iiii) Materials necessary to support evaluation of the 

plan by EPA. 

(b) You must follow the requirements of subpart B of this 

part (Adoption and Submittal of state plans for Designated 

Facilities) and demonstrate that they were met in your state 

plan. 

§ 60.5745 Can I work with other states to develop a multi-state 

plan? 

 (a) A multi-state plan may be submitted, provided it is 

signed by authorized officials for each of the states 
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participating in the multi-state plan. In this instance, the 

joint submittal will have the same legal effect as an individual 

submittal for each participating state. A multi-state plan will 

include all the required elements for a single-state plan 

specified in § 60.5740(a). States may submit a multi-state plan 

that: 

(b) Demonstrates CO2 emission performance jointly for all 

affected entities in all states participating in the multi-state 

plan, as follows: 

(i) For states demonstrating performance based on the CO2

emission rate, the level of performance identified in the multistate plan pursuant to 60.5740(a)(3) will be a weighted (by net 

energy output) average lb CO2/MWh emission rate to be achieved by 

all affected EGUs in the multi-state area during the plan 

performance period; or 

(ii) For states demonstrating performance based on mass CO2

emissions, the level of performance identified in the multistate plan pursuant to 60.5740(a)(3) will be total CO2 emissions 

by all affected EGUs in the multi-state area during the plan 

performance period. 

(c) Assigns among states, according to a formula in the 

multi-state plan, avoided CO2 emissions resulting from emission 

standards contained in the plan, from affected entities in 

states participating in the multi-state plan. 
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§ 60.5750 Can I include existing requirements, programs, and 

measures in my state plan? 

 (a) Yes, you may include existing requirements, programs 

and measures in your plan according to paragraphs (b)-(d) of 

this section. 

 (b) Existing state programs, requirements, and measures, 

may qualify for use in demonstrating that a state plan achieves 

the required level of emission performance specified in a plan, 

according to § 60.5740(a)(3). 

(c) Existing state programs, requirements, and measures, 

may qualify for use in projecting that a state plan will achieve 

the required level of emission performance specified in a plan, 

according to § 60.5740(a)(4). 

 (d) Emission impacts of existing programs, requirements, 

and measures that occur during a plan performance period may be 

recognized in meeting or projecting CO2 emission performance by 

affected EGUs according to § 60.5740(a)(3) and (4), as long as 

they meet the following requirements: 

 (i) Actions taken pursuant to an existing state program, 

requirement, or measure, such as compliance with a regulatory 

obligation or initiation of an action related to a program or 

measure, must occur after [INSERT DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]; and 

(ii) The existing state program, requirement, or measure, 
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and any related actions taken pursuant to such program, 

requirement, or measure, meet the applicable requirements 

pursuant to § 60.5740(a) and § 60.5780. 

§ 60.5755 What are the timing requirements for submitting my 

state plan? 

(a) You must submit your state plan with the information in 

§ 60.5740 by June 30, 2016 unless you are submitting a request 

for extension according to paragraphs (b) or (c). 

(b) For a state seeking a one year extension for a complete 

plan submittal you must include the information in § 60.5760(a) 

in a submittal by June 30, 2016 to receive an extension to 

submit your complete state plan by June 30, 2017. 

(c) For states in a multi-state plan seeking a two year 

extension for a complete plan submittal you must include the 

information in § 60.5760(a) in a submittal by June 30, 2016 to 

receive an extension to submit your complete multi-state plan by 

June 30, 2018. 

§ 60.5760 What must I include in an initial submittal in lieu of 

a complete state plan? 

(a) If a state needs additional time to submit a complete 

plan, then the state must notify the EPA by letter of such 

intent by no later than April 1, 2016. In this letter, the state 

must explain why more time is needed to submit a complete plan, 

outline the actions it is currently taking to develop a plan and 
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commit to meet all of the requirements for an initial submittal, 

listed in paragraph (b) of this section, by June 30, 2016. 

(b) You must include the following required elements in an 

initial submittal in lieu of a complete state plan if your 

request for extension in paragraph (a) of this section has been 

approved: 

(1) A description of the plan approach and progress made to 

date in developing each of the plan elements in § 60.5740; 

(2) An initial projection of the level of emission 

performance that will be achieved by affected EGUs under the 

complete plan; 

(3) A commitment by the state to maintain existing state 

programs and measures that limit or avoid CO2 emissions from 

affected EGUs, which must at a minimum apply during the interim 

period prior to state submission and EPA approval of a complete 

plan, and must continue to apply in lieu of a complete plan if 

one is ultimately not submitted and approved; 

(4) Justification of why additional time is needed to 

submit a complete plan; 

(5) A comprehensive roadmap for completing the plan, 

including process, analytical methods and schedule (including 

milestones) specifying when all necessary plan components will 

be complete (e.g., projection of emission performance; 
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implementing legislation, regulations and agreements; necessary 

approvals); 

(6) Identification of existing and future programs, 

requirements, and measures the state intends to include in the 

plan; 

(7) If a multi-state plan is being developed, an executed 

agreement(s) with other states (e.g., MOU) participating in the 

development of the multistate plan; and 

(8) A commitment to submit a complete plan by June 30, 

2017, for a single-state plan, or June 30, 2018, for a multistate plan, and actions the state will take to show progress in 

addressing incomplete plan components prior to submittal of the 

complete plan. 

§ 60.5765 What are the state rate-based CO2 emissions performance 

goals? 

(a) The annual average state rate-based CO2 emission 

performance goals for the interim performance periods of 2020 

through 2029, and the final 2030 and thereafter period are 

respectively listed in Table 1 of this Subpart. The state ratebased CO2 emission performance goal may be converted to a massbased emission performance goal according to § 60.5770. 

§ 60.5770 What is the procedure for converting my state ratebased CO2 emissions performance goal to a mass-based CO2

emissions performance goal? 
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 (a) If the plan adopts a mass-based goal according to § 

60.5740(a)(3), the plan must identify the mass-based goal, in 

tons of CO2 emitted by affected EGUs over the plan performance 

period, and include a description of the analytic process, 

tools, methods, and assumptions used to convert from the ratebased goal for the state identified in Table 1 of this Subpart 

to an equivalent mass-based goal. The conversion process must 

include following requirements: 

(b) The process, tools, methods, and assumptions used in 

the conversion of the rate-based goal must be included in your 

state plan according to § 60.5740(a)(10). 

(c) The material supporting the conversion of the ratebased goal, including results, data, and descriptions, must be 

include in a state plan according to § 60.5740(a)(10). 

(d) The conversion must represent the tons of CO2 emissions 

that are projected to be emitted by affected EGUs, in the 

absence of emission standards contained in the plan, if the 

affected EGUs were to perform at an average lb CO2/MWh rate equal 

to the rate-based goal for the state identified in Table 1 of 

this Subpart. 

§ 60.5775 What schedules, performance periods, and compliance 

periods must I include in my state plan? 

(a) Your state plan must include a schedule of compliance 

for each affected entity regulated under the plan.
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(b) Your state plan must include compliance periods, as 

defined in section § 60.5820, for each affected entity regulated 

under the plan. 

(c) For the interim performance period of 2020-2029 your 

state must meet the requirements in paragraphs (c)(1) and (c)(2) 

of this section 

 (1) Your state plan must include increments of emissions 

performance (either rate based or mass based with respect to the 

interim level of performance set in the state plan) within the 

interim performance period for every 2-rolling calendar years 

starting January 1, 2020 and ending in 2028 (i.e. 2020-2022, 

2021-2023, 2022-2024, etc.), unless other periods that ensure 

regular progress in the interim period are approved by the 

Administrator. 

2) At the end of 2029 your state must meet the interim 

emissions performance level specified in § 60.5740(a)(3) as 

averaged over the plan performance period 2020-2029. 

 (d) During the final performance period, 2030 and 

thereafter, your state must meet the final emission performance 

level specified in § 60.5740(a)(3) on a 3-calendar year rolling 

average starting January 1, 2030 (i.e., 2030-2032, 2031-2033, 

2032-2034, etc.). 

(e) You must include the provisions of your state plan 

which demonstrate progress and compliance with the requirements 
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in this section and section § 60.5740 in your state’s annual 

report required in section § 60.5815. 

§ 60.5780 What emissions standards and enforcing measures must I 

include in my plan? 

(a) Your state plan shall include emission standard(s) that 

are quantifiable, verifiable, non-duplicative, permanent, and 

enforceable with respect to each affected entity. The plan shall 

include the methods by which each emission standard meets each 

of the following requirements in paragraphs (b)-(f). 

(b) An emission standard is quantifiable with respect to an 

affected entity if it can be reliably measured, in a manner that 

can be replicated. 

(c) An emission standard is verifiable with respect to an 

affected entity if adequate monitoring, recordkeeping and 

reporting requirements are in place to enable the state and the 

Administrator to independently evaluate, measure, and verify 

compliance with the emission standard. 

(d) An emission standard is non-duplicative with respect to 

an affected entity if it is not already incorporated as an 

emission standard in another state plan unless incorporated in 

multi-state plan.

(e) An emission standard is permanent with respect to an 

affected entity if the emission standard must be met for each 

compliance period, or unless it is replaced by another emission 
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standard in an approved plan revision, or the state demonstrates 

in an approved plan revision that the emissions reductions from 

the emission standard are no longer necessary for the state to 

meet its state level of performance. 

(f) An emission standard is enforceable against an affected 

entity if: 

(1) A technically accurate limitation or requirement and 

the time period for the limitation or requirement is specified; 

(2) Compliance requirements are clearly defined; 

(3) The affected entities responsible for compliance and 

liable for violations can be identified; 

(4) Each compliance activity or measure is enforceable as a 

practical matter; and 

(5) The Administrator and the state maintain the ability to 

enforce violations and secure appropriate corrective actions 

pursuant to Sections 113(a) – (h) of the Act. 

§ 60.5785 What is the procedure for revising my state plan? 

 State plans can only be revised with approval by the 

Administrator. If one (or more) of the elements of the state 

plan set in § 60.5740 require revision with respect to reaching 

the emission performance goal set in § 60.5765 a request may be 

submitted to the Administrator indicating the proposed 

corrections to the state plan to ensure the emission performance 

goal is met. 
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Applicability of State Plans to Affected EGUs

§ 60.5790 Does this subpart directly affect EGU owners and 

operators in my state? 

(a) This subpart does not directly affect EGU owners and 

operators in your state. However, EGU owners and operators must 

comply with the state plan a state develops to implement the 

emission guidelines contained in this subpart. 

(b) If a state does not submit an approvable plan or 

initial submittal to implement and enforce the emission 

guidelines contained in this subpart by June 30, 2016, EPA will 

implement and enforce a Federal plan, as provided in §60.5740, 

to ensure that each affected EGU within the state that commenced 

construction on or before [DATE OF PROPOSED RULE PUBLICATION IN 

THE FEDERAL REGISTER] reaches compliance with all the provisions 

of this subpart. 

§ 60.5795 What affected EGUs must I address in my state plan? 

The EGUs that must be addressed by your state plan are any 

affected steam generating unit, IGCC, or stationary combustion 

turbine that commences construction before [DATE OF PROPOSED 

RULE PUBLICATION IN THE FEDERAL REGISTER] 

§ 60.5800 What affected EGUs are exempt from my state plan? 

Affected EGUs that are exempt from your state plan include 

1) those that are subject to subpart TTTT as a result of 

commencing construction after the subpart TTTT applicability 
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date and 2) those subject to subpart TTTT as a result of 

commencing modification or reconstruction prior to the EPA 

approving the applicable state plan. 

§ 60.5805 What applicable monitoring, recordkeeping, and 

reporting requirements do I need to include in my state plan for 

affected EGUs? 

(a) A state plan must include monitoring that is no less 

stringent that what is described in (a)(1) through (6). 

(1) If an affected EGU is required to meet a rate based 

emission standard they must prepare a monitoring plan in 

accordance with the applicable provisions in § 75.53(g) and (h) 

of this chapter. 

(2) An affected EGU must measure the hourly CO2 mass 

emissions from each affected unit using the procedures in 

paragraphs (2)(i) through (v) of this section, except as 

provided in paragraph (a)(3) of this section. 

(i) An affected EGU must install, certify, operate, 

maintain, and calibrate a CO2 continuous emissions monitoring 

system (CEMS) to directly measure and record CO2 concentrations 

in the affected EGU exhaust gases emitted to the atmosphere and 

an exhaust gas flow rate monitoring system according to § 

75.10(a)(3)(i) of this chapter. If an affected EGU measures CO2

concentration on a dry basis, they must also install, certify, 
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operate, maintain, and calibrate a continuous moisture 

monitoring system, according to § 75.11(b) of this chapter. 

(ii) For each monitoring system an affected EGU uses to 

determine the CO2 mass emissions, they must meet the applicable 

certification and quality assurance procedures in § 75.20 of 

this chapter and Appendices B and D to part 75 of this chapter. 

(iii) An affected EGU must use a laser device to measure 

the dimensions of each exhaust gas stack or duct at the flow 

monitor and the reference method sampling locations prior to the 

initial setup (characterization) of the flow monitor. For 

circular stacks, an affected EGU must measure the diameter at 

three or more distinct locations and average the results. For 

rectangular stacks or ducts, an affected EGU must measure each 

dimension (i.e., depth and width) at three or more distinct 

locations and average the results. If the flow rate monitor or 

reference method sampling site is relocated, an affected EGU 

must repeat these measurements at the new location. 

(iv) An affected EGU must use only unadjusted exhaust gas 

volumetric flow rates to determine the hourly CO2 mass emissions 

from the affected facility; an affected EGU must not apply the 

bias adjustment factors described in section 7.6.5 of Appendix A 

to part 75 of this chapter to the exhaust gas flow rate data. 

(v) If an affected EGU chooses to use Method 2 in Appendix 

A-1 to this part to perform the required relative accuracy test 
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audits (RATAs) of the part 75 flow rate monitoring system, they 

must use a calibrated Type-S pitot tube or pitot tube assembly. 

An affected EGU must not use the default Type-S pitot tube 

coefficient. 

(3) If an affected EGU exclusively combusts liquid fuel 

and/or gaseous fuel as an alternative to complying with 

paragraph (b) of this section, they may determine the hourly CO2

mass emissions by using Equation G-4 in Appendix G to part 75 of 

this chapter according to the requirements in paragraphs (3)(i) 

and (ii) of this section. 

(i) An affected EGU must implement the applicable 

procedures in appendix D to part 75 of this chapter to determine 

hourly unit heat input rates (MMBtu/h), based on hourly 

measurements of fuel flow rate and periodic determinations of 

the gross calorific value (GCV) of each fuel combusted. 

(ii) An affected EGU may determine site-specific carbonbased F-factors (Fc) using Equation F-7b in section 3.3.6 of 

appendix F to part 75 of this chapter, and may use these Fc

values in the emissions calculations instead of using the 

default Fc values in the Equation G-4 nomenclature. 

(4) An affected EGU must install, calibrate, maintain, and 

operate a sufficient number of watt meters to continuously 

measure and record on an hourly basis net electric output. 

Further, an affected EGU that is a combined heat and power 
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facility must install, calibrate, maintain and operate equipment 

to continuously measure and record on an hourly basis useful 

thermal output and, if applicable, mechanical output, which are 

used with net electric output to determine net energy output. 

(5) In accordance with § 60.13(g), if two or more affected 

EGUs that implement the continuous emissions monitoring 

provisions in paragraph (a)(2) of this section share a common 

exhaust gas stack and are subject to the same emissions 

standard, they may monitor the hourly CO2 mass emissions at the 

common stack in lieu of monitoring each EGU separately. If an 

affected EGU chooses this option, the hourly net electric output 

for the common stack must be the sum of the hourly net electric 

output of the individual affected facility and you must express 

the operating time as “stack operating hours” (as defined in § 

72.2 of this chapter). 

(6) In accordance with § 60.13(g), if the exhaust gases 

from an affected EGU that implements the continuous emissions 

monitoring provisions in paragraph (a)(2) of this section are 

emitted to the atmosphere through multiple stacks (or if the 

exhaust gases are routed to a common stack through multiple 

ducts and you elect to monitor in the ducts), they must monitor 

the hourly CO2 mass emissions and the “stack operating time” (as 

defined in § 72.2 of this chapter) at each stack or duct 

separately. In this case, an affected EGU must determine 
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compliance with an applicable emissions standard by summing the 

CO2 mass emissions measured at the individual stacks or ducts and 

dividing by the net energy output for the affected EGU. 

(b) An affected EGU must maintain records for at least 10 

years following the date of each occurrence, measurement, 

maintenance, corrective action, report, or record. 

(1) An affected EGU must maintain each record on site for 

at least 2 years after the date of each occurrence, measurement, 

maintenance, corrective action, report, or record, according to 

§ 60.7. An affected EGU may maintain the records off site and 

electronically for the remaining year(s). 

(c) An affected EGU must include in a report required by 

the state plan covering each compliance period to the delegated 

authority all hourly CO2 emissions and all hourly net electric 

output and all hourly net energy output measurements for a CHP 

facility calculated from data monitored according to paragraph 

(a) of this section. 

Recordkeeping and Reporting Requirements 

§ 60.5810 What are my state recordkeeping requirements? 

(a) States must keep records of all plan components, plan 

requirements, supporting documentation, and the status of 

meeting the plan requirements defined in the state plan on an 

annual basis during the interim plan performance period from 

2020-2029. After 2029 states must keep records of all 
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information that is used to support any continued effort to meet 

the final emissions performance goal. 

(b) States must keep records of all data submitted by each 

affected entity that is used to determine compliance with each 

affected entity’s emissions standard. 

(c) If a state has a requirement for hourly CO2 emissions 

and net generation information to be used to calculate 

compliance with an annual emissions standard for affected EGUs, 

any information that is submitted to the EPA electronically 

pursuant to requirements in Part 75 would meet the recordkeeping 

requirement of this section and a state would not need to keep 

records of information that would be in duplicate of paragraph 

(b) of this section. 

(d) A state must keep records at minimum for 20 years. 

§ 60.5815 What are my state reporting requirements? 

(a) You must submit an annual report covering each calendar year 

no later than July 1 of the following year, starting July 1 

2021. The annual report must include the following: 

(1) The level of emissions performance achieved by all 

affected entities and identification of whether affected 

entities are on schedule to meet the applicable level of 

emissions performance for affected entities during the plan 

performance period and compliance periods, as specified in the 

plan. 
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(2) The level of emissions performance achieved by all 

affected EGUs during the reporting period, and prior reporting 

periods, expressed as average CO2 emissions rate or total mass 

CO2 emissions, consistent with the plan approach, and 

identification of whether affected EGUs are on schedule to meet 

the applicable level of emissions performance for affected EGUs 

during the plan performance period, as specified in the plan. 

 (3) A list of affected entities and their compliance status 

with the applicable emissions standards specified in the state 

plan. 

(4) A list of all affected EGUs and their reported CO2

emissions performance for each compliance period during the 

reporting period, and prior reporting periods. 

 (5) All other required information, as specified in your 

state plan according to §60.5740(a)(9). 

 (6) All information required by § 60.5775(e). 

(b) For each two-year period in § 60.5775(c)(1), you must 

compare the CO2 emission performance achieved by affected EGU in 

the state versus the CO2 emission performance projected in the 

state plan. If actual emission performance is greater than 10 

percent in excess to projected plan performance for a two-year 

comparison period, you must explain the reasons for the 

deviation and specify the corrective actions that will be taken 

to ensure that the required interim and final levels of emission 
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performance in the plan will be met. The information required in 

this paragraph must be included in the annual report required by 

paragraph (a) of this section. 

 (c) You must include in your 2029 annual report (which is 

subsequently due by July 1, 2030) the calculation of average 

emissions over the 2020-2029 interim performance period used to 

determine compliance with your interim emission performance 

level. The calculated value must be in units consistent with 

your interim emission performance level. 

(d) You must include in each report, starting with the 2032 

annual report (which is subsequently due by July 1, 2033), a 3-

calendar year rolling average used to determine compliance with 

the final emission performance level. The calculated value must 

be in units consistent with your final emission performance 

level. 

Definitions 

§ 60.5820 What definitions apply to this subpart? 

As used in this subpart, all terms not defined herein will 

have the meaning given them in the Clean Air Act and in subparts 

A (General Provisions of this part) and B. 

Affected electric generating unit or Affected EGU means a 

steam generating unit, an IGCC facility, or a stationary 
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combustion turbine that serves a generator capable of selling 

greater than 25 MW to a power distribution system. 

Affected Entity shall mean any of the following: an 

affected EGU, or another entity with obligations under this 

subpart for the purpose of meeting the emissions performance 

goal requirements in these emission guidelines. 

Base load rating means the maximum amount of heat input 

(fuel) that a steam generating unit can combust on a steady 

state basis, as determined by the physical design and 

characteristics of the steam generating unit at ISO conditions. 

For a stationary combustion turbine, base load rating means 100 

percent of the design heat input capacity of the simple cycle 

portion of the stationary combustion turbine at ISO conditions 

(heat input from duct burners is not included). 

CO2 emissions performance goal means the rate-based CO2

emissions performance goal specified for a state in Table 1 of 

this subpart, or a translated mass-based form of that goal. 

Coal means all solid fuels classified as anthracite, 

bituminous, subbituminous, or lignite by the American Society of 

Testing and Materials in ASTM D388 (incorporated by reference, 

see § 60.17), coal refuse, and petroleum coke. Synthetic fuels 

derived from coal for the purpose of creating useful heat, 

including but not limited to solvent-refined coal, gasified coal 

(not meeting the definition of natural gas), coal-oil mixtures, 
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and coal-water mixtures are included in this definition for the 

purposes of this subpart. 

Combined cycle facility means an electric generating unit 

that uses a stationary combustion turbine from which the heat 

from the turbine exhaust gases is recovered by a heat recovery 

steam generating unit to generate additional electricity.

Combined heat and power facility or CHP facility, (also 

known as “cogeneration”) means an electric generating unit that 

that use a steam-generating unit or stationary combustion 

turbine to simultaneously produce both electric (or mechanical) 

and useful thermal energy from the same primary energy source. 

Compliance Period means the period of time, set forth by a 

state in its state plan, during which each affected entity must 

demonstrate compliance with an applicable emissions standard, 

and shall be no greater than a three year period for a massbased plan, and shall be no greater than a one year period for a 

rate-based plan.

Distillate oil means fuel oils that contain no more than 

0.05 weight percent nitrogen and comply with the specifications 

for fuel oil numbers 1 and 2, as defined by the American Society 

of Testing and Materials in ASTM D396 (incorporated by 

reference, see § 60.17); diesel fuel oil numbers 1 and 2, as 

defined by the American Society for Testing and Materials in 

ASTM D975 (incorporated by reference, see § 60.17); kerosene, as 
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defined by the American Society of Testing and Materials in ASTM 

D3699 (incorporated by reference, see § 60.17); biodiesel as 

defined by the American Society of Testing and Materials in ASTM 

D6751 (incorporated by reference, see § 60.17); or biodiesel 

blends as defined by the American Society of Testing and 

Materials in ASTM D7467 (incorporated by reference, see § 

60.17). 

Emission performance level in a state plan means the level 

of emissions performance for affected entities specified in a 

state plan, according to § 60.5745. 

Emission standard means in addition to the definition in § 

60.21, any requirement applicable to any affected entity other 

than an affected source that has the effect of reducing 

utilization of one or more affected sources, thereby avoiding 

emissions from such sources, including, for example, renewable 

energy and demand-side energy efficiency measures requirements. 

Excess emissions means a specified averaging period over 

which the CO2 emissions rate is higher than an applicable 

emissions standard or an averaging period during which an 

affected EGU is not in compliance with any other emission 

limitation specified in an emission standard. 

Existing state program, requirement, or measure means, in 

the context of a state plan, a regulation, requirement, program, 

or measure administered by a state, utility, or other entity 
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that is currently established. This may include a regulation or 

other legal requirement that includes past, current, and future 

obligations, or current programs and measures that are in place 

and are anticipated to be continued or expanded in the future, 

in accordance with established plans. An existing state program, 

requirement, or measure may have past, current, and future 

impacts on EGU CO2 emissions. 

Fossil fuel means natural gas, petroleum, coal, and any 

form of solid, liquid, or gaseous fuel derived from such 

material for the purpose of creating useful heat. 

Gaseous fuel means any fuel that is present as a gas at ISO 

conditions and includes, but is not limited to, natural gas, 

refinery fuel gas, process gas, coke-oven gas, synthetic gas, 

and gasified coal. 

 Heat recovery steam generating unit (HRSG) means a unit in 

which hot exhaust gases from the combustion turbine engine are 

routed in order to extract heat from the gases and generate 

useful output. Heat recovery steam generating units can be used 

with or without duct burners. 

Integrated gasification combined cycle facility or IGCC facility 

means a combined cycle facility that has a base load rating for 

fossil fuel of greater than 73 MW (250 MMBtu/h), that was 

constructed for the purpose of supplying more than one-third or 

more of its potential electric output and more than 219,000 MWh 
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net-electric output to a utility distribution system on an 

annual basis and that is designed to burn fuels containing 50 

percent (by heat input) or more solid-derived fuel not meeting 

the definition of natural gas plus any integrated equipment that 

provides electricity or useful thermal output to either the 

affected facility or auxiliary equipment. The Administrator may 

waive the 50 percent solid-derived fuel requirement during 

periods of the gasification system construction, startup and 

commissioning, shutdown, or repair. No solid fuel is directly 

burned in the unit during operation. 

ISO conditions means 288 Kelvin (15o C), 60 percent relative 

humidity and 101.3 kilopascals pressure. 

Liquid fuel means any fuel that is present as a liquid at 

ISO conditions and includes, but is not limited to, distillate 

oil and residual oil. 

Mechanical output means the useful mechanical energy that 

is not used to operate the affected facility, generate 

electricity and/or thermal energy, or to enhance the performance 

of the affected facility. Mechanical energy measured in 

horsepower hour should be converted into MWh by multiplying it 

by 745.7 then dividing by 1,000,000. 

Natural gas means a fluid mixture of hydrocarbons (e.g., 

methane, ethane, or propane), composed of at least 70 percent 

methane by volume or that has a gross calorific value between 35 
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and 41 megajoules (MJ) per dry standard cubic meter (950 and 

1,100 Btu per dry standard cubic foot), that maintains a gaseous 

state under ISO conditions. In addition, natural gas contains 

20.0 grains or less of total sulfur per 100 standard cubic feet. 

Finally, natural gas does not include the following gaseous 

fuels: landfill gas, digester gas, refinery gas, sour gas, blast 

furnace gas, coal-derived gas, producer gas, coke oven gas, or 

any gaseous fuel produced in a process which might result in 

highly variable sulfur content or heating value. 

Net-electric output means the amount of gross generation 

the generator(s) produce (including, but not limited to, output 

from steam turbine(s), combustion turbine(s), and gas 

expander(s)), as measured at the generator terminals, less the 

electricity used to operate the plant (i.e., auxiliary loads); 

such uses include fuel handling equipment, pumps, fans, 

pollution control equipment, other electricity needs, and 

transformer losses as measured at the transmission side of the 

step up transformer (e.g., the point of sale). Measurements must 

be performed using 0.2 accuracy class electricity metering 

instrumentation and calibration procedures as specified under 

ANSI Standards No. C12.20. 

Net energy output means: 

(1) the net electric or mechanical output from the affected 

facility, plus 75 percent of the useful thermal output measured 
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relative to ISO conditions that is not used to generate 

additional electric or mechanical output or to enhance the 

performance of the unit (e.g., steam delivered to an industrial 

process for a heating application). 

(2) For combined heat and power facilities where at least 

20.0 percent of the total gross energy output consists of 

electric or direct mechanical output and 20.0 percent of the 

total gross energy output consists of thermal output on a 

rolling 3 year basis, the net electric or mechanical output from 

the affected facility divided by 0.95, plus 75 percent of the 

useful thermal output measured relative to ISO conditions that 

is not used to generate additional electric or mechanical output 

or to enhance the performance of the unit (e.g., steam delivered 

to an industrial process for a heating application). 

Oil means crude oil or petroleum or a fuel derived from 

crude oil or petroleum, including distillate and residual oil, 

and gases derived from solid oil-derived fuels (not meeting the 

definition of natural gas). 

Solid fuel means any fuel that has a definite shape and 

volume, has no tendency to flow or disperse under moderate 

stress, and is not liquid or gaseous at ISO conditions. This 

includes, but is not limited to, coal, biomass, and pulverized 

solid fuels. 

Stationary combustion turbine means all equipment, 
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including but not limited to the turbine engine, the fuel, air, 

lubrication and exhaust gas systems, control systems (except 

emissions control equipment), heat recovery system, fuel 

compressor, heater, and/or pump, post-combustion emissions 

control technology, and any ancillary components and subcomponents comprising any simple cycle stationary combustion 

turbine, any combined cycle combustion turbine, and any combined 

heat and power combustion turbine based system plus any 

integrated equipment that provides electricity or useful thermal 

output to the combustion turbine engine, heat recovery system or 

auxiliary equipment. Stationary means that the combustion 

turbine is not self-propelled or intended to be propelled while 

performing its function. It may, however, be mounted on a 

vehicle for portability. If a stationary combustion turbine 

burns any solid fuel directly it is considered a steam 

generating unit. 

Steam generating unit means any furnace, boiler, or other 

device used for combusting fuel and producing steam (nuclear 

steam generators are not included) that has a base load rating 

for fossil fuel of greater than 73 MW (250 MMBtu/h) and that was 

constructed for the purpose of supplying more than one-third or 

more of its potential electric output and more than 219,000 MWh 

net-electric output to a utility distribution system on an 

annual basis plus any integrated equipment that provides 
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electricity or useful thermal output to the affected facility or 

auxiliary equipment. 

Thermal output for this subpart means the energy in 

recovered thermal output measured against the energy in the 

thermal output at ISO conditions. 

Useful thermal output means the thermal energy made 

available for use in any industrial or commercial process, or 

used in any heating or cooling application, i.e., total thermal 

energy made available for processes and applications other than 

electric generation, mechanical output at the affected facility, 

or to directly enhance the performance of the affected facility 

(e.g., thermal energy used to reduce fuel moisture is considered 

useful thermal output). 
Page 197: [1] Comment [A36] Author 

We request comment, in particular, on the use of biomass-derived 

fuels, in place of affected EGUs, as a measure to include in a massbased plan to achieve CO2 emission reductions. While RE generation from 

states renewable energy efforts qualifies as BSER in reducing fossil 

fuel generated electricity, quantifying the mass-based reduction from 

RE efforts should a state choose a mass-based goal require additional 

considerations. 

Burning biomass-derived fuels for energy recovery can yield 

climate benefits as compared to burning conventional fossil fuels. For 

example, sustainable forestry and agriculture can improve resiliency 

to climate change, be part of a national strategy to reduce dependence 

on fossil fuels, and contribute to climate change mitigation by acting 

as a “sink” for carbon. The plant growth associated with producing 

many of the biomass-derived fuels can, to varying degrees for 

different biomass feedstocks, sequester carbon from the atmosphere, 

effectively recycling the carbon emitted when that feedstock is 

combusted to produce electricity. 

Because of the positive attributes of biomass-derived fuels, the 

EPA recognizes that biomass-derived fuels will play an important role 

in carbon dioxide (CO2) emission reduction strategies. We anticipate 

that states will consider biomass-derived fuels in energy production 

as a way to mitigate the CO2 emissions attributed to the energy sector 

and include them as part of their plans to meet the emission reduction 

requirements of this rule. 

One method could be to determine the total emissions by adjusting 

the rate-based goal for the state identified in Table 1 for renewable 

energy BSER efforts and then using § 60.5770 to convert the remaining 

portion of the rate based goal into a mass-based emissions goal. EPA 

requests comment on that approach. 

Another approach would be to convert the states rate based goal from Table 1 into a 

mass-based emissions goal using § 60.5770. Calculations of the amount of emissions 

reduced through various low or zero carbon renewable energy efforts would require the 

state to describe the assumptions used to demonstrate equivalent compliance with the 

rate-based goal. Many states have already recognized the importance of forests and 

other lands for climate resilience and mitigation and have developed a variety of 

different sustainable forestry policies, renewable energy incentives and standards and 

greenhouse gas accounting procedures. To better understand the impacts of using 

different types of biomass-derived fuels, the EPA is assessing the use of different 

biomass feedstocks in different regions for energy recovery by stationary sources. The 

EPA is in the process of developing a biogenic CO2 accounting framework is expected to 

provide important information regarding the scientific basis for assessing these 

biomass-derived fuels and their net atmospheric contribution of CO2 related to the 

growth, harvest and use of these fuels. That information should assist both states and 

the EPA in assessing the impact of the use of biomass fuels in reaching mass-based 

emission reduction goals in the energy sector under state plans to comply with the 

requirements in the emission guidelines. EPA requests comment on that approach. 

Page 573: [2] Comment [A86] Author 

Can EPA add more to this section in response to the following comment: 

However, this rule will have a disproportional impact on rural America. Compliance 

with the proposed EPA GHG rule will result in higher electricity prices nationwide. 

Rural consumers already use more electricity than their urban counterparts. For 

instance, RUS records indicate that average monthly consumption for all US consumers 

is $107.28 vs. $133.78 for rural consumers. This is due, in part, to the fact that 

rural consumers often are limited to substandard, inefficient housing choices. There 
are far fewer rural consumers to absorb rate increases and rural Americans have lower 

incomes than their urban counterparts. Also, persistent poverty counties are mostly 

located in rural areas. 

A greater portion of rural America is reliant on the electricity generated by fossilfired power plants, in particular coal-fired units. For example, rural electric 

cooperatives generate about 70% of their baseload power from coal units. Various 

other EPA regulations either proposed or implemented over the past few years have 

forced electric cooperatives to make difficult choices to sustain an adequate amount 

of reliable and affordable power to meet the needs of its consumers. For example, the 

Mercury and Air Toxics Standards (MATS) and rules with respect to attaining and 

maintaining National Ambient Air Quality Standards (NAAQS) have resulted in the 

decision to either shut down certain coal-fired units or, in most cases, to implement 

expensive upgrades to meet the intended emission requirements of the 

rules. Therefore, rural electric cooperatives have already committed a relatively 

large amount of capital to continue to operate coal-fired plants that will now be 

subjected to further emission requirements under the proposed 111(d) rule. Rural 

electric cooperatives may be required to curtail the operation of these units or 

prematurely retire the units earlier than originally anticipated prior to the 

enactment of the proposed rule. As a result, the cooperatives will be faced with 

potentially high stranded costs and be required to seek more expensive replacement 

power. Since 2009, rural generation and transmission cooperatives (RUS borrowers) 

have invested over $1.75 billion in power plant emissions controls and rural residents 

had to absorb with the associated impact on electricity rates. 

Many rural residents across America are served by rural electric cooperatives. In 

fact 42 million people in 47 states in 2,500 counties are served by cooperatives. 

This electric service is provided by 55 generation and transmission cooperatives in 

conjunction with 840 distribution cooperatives. On average, investor-owned utilities 

serve 34 consumers per mile of electric line while electric cooperatives serve only 

7.4 consumers per line. As such, meeting this rule will likely result in higher costs 

being passed along to rural ratepayers. EPA is requesting comment on additional 

flexibilities to insure economic impacts on rural households will not be 

disproportionately higher than in urban areas.