UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

RESEARCH TRIANGLE PARK, NC  27711

MEMORANDUM

To:     Docket EPA‐HQ‐OAR‐2015‐0199

From:    ToniJones,U.S. Environmental Protection Agency

Date:    August 25, 2015

Subject: Clean Power Plan (CPP) Federal Plan – Summary of EPA Interagency Communications

This memorandum summarizes the EPA’s interagency communications regarding development

of a proposed federal plan for the Clean Power Plan.  The table below lists the topics covered in

each attachment. Some attachments, due to size or the file type, are submitted to the docket

as separate entries identified as an attachment to this memorandum.

Attachment Topic Date/Time of

Email

A Email thread of correspondence between EPA and OMB staff

regarding possible times for an overview of the CPP federal plan

July 6, 2015

11:56 AM –

3:46 PM (ET)

B Email thread of correspondence between EPA and OMB staff

regarding interagency review comments on the CPP federal plan

proposal package  

July 18, 2015

4:23 PM (ET) –  

July 19, 2015

9:04 PM (ET)

B.1 File attached to B with filename

SummaryofInteragencyCommentsUnderEO12866_13563_Federal

PlanNPRM_7182015.docx

C Email correspondence between EPA and OMB staff regarding

interagency review comments on the CPP federal plan proposal

package

July 25, 2015

5:36 PM (ET)

C.1 File attached to C with filename

SummaryofInteragencyCommentsUnderEO12866_13563_Federal

PlanNPRM_7252015.docx

D Email correspondence between EPA and OMB staff providing the

CPP federal plan preamble, CPP federal plan rule text, and a

document of responses to OMB comments on the rule package

July 27, 2015

4:55 PM (ET)

1
Attachment Topic Date/Time of

Email

D.1 File attached to D with filename EO12866_CPP Federal Plan 2060

AS47 NPRM_20150727 RLSO.docx [preamble]

D.2 File attached to D with filename CPP Federal Plan Model Rule OMB

7_27_15 clean.docx [rule text]

D.3 File attached to D with filename EO12866 13563 Federal Plan

NPRM Response to OMB Comments 072715.docx [response to

OMB comments]

E Email correspondence between EPA and OMB staff regarding

interagency review comments on the CPP federal plan proposal

package

July 28, 2015

1:19 PM (ET)

E.1 File attached to E with filename

SummaryofInteragencyCommentsUnderEO12866_13563_Federal

PlanNPRM_7282015.docx

F Email thread of correspondence between EPA and OMB staff

regarding interagency review comments on the CPP federal plan

proposal package

July 28, 2015

1:20 PM – 3:38

PM (ET)

G Email correspondence between EPA and OMB staff regarding

interagency review comments on the CPP federal plan proposal

package

July 28, 2015

6:49 PM (ET)

G.1 File attached to G with filename

SummaryofInteragencyCommentsUnderEO12866_13563_Federal

PlanNPRM_7282015_650pm.docx

H Email correspondence between EPA and OMB staff providing the

draft CPP federal plan RIA and draft RIA spreadsheet for ROCIS

July 28, 2015

9:26 PM (ET)

H.1 File attached to H with filename

EO12866_CPP_Federal_Plan_2060_AS47_RIA Final_20150728.docx

[RIA]

H.2 File attached to H with filename

EO12866_CPP_Federal_Plan_2060_AS47_RIA_Spreadsheet

Final_20150728.xlsx [RIA spreadsheet]

I Email correspondence between EPA and OMB staff providing CEIP

text

July 29, 2015

1:54 PM (ET)

I.1 File attached to I with filename CEIP language FP 7.28.15_clean

1043pm.docx

J Email correspondence between EPA and OMB staff regarding

interagency review comments on the CPP federal plan proposal

package

July 29, 2015

5:30 PM (ET)

J.1 File attached to J with filename

SummaryofInteragencyCommentsUnderEO12866_13563_Federal

PlanRIA_7292015.docx

2
Attachment Topic Date/Time of

Email

K Email correspondence between EPA and OMB staff regarding

interagency review comments on the CPP federal plan RIA

July 29, 2015

8:01 PM (ET)

K.1 File attached to K with filename

SummaryofInteragencyCommentsUnderEO12866_13563_Federal

Plan_RIA_7292015.docx

L Email thread of correspondence between EPA and OMB staff

regarding interagency review comments on CPP federal plan

documents

July 29, 2015

8:05 PM (ET)

M Email correspondence between EPA and OMB staff providing

responses to OMB comments and the CPP federal plan preamble

July 29, 2015

10:36 PM (ET)

M.1 File attached to M with filename EO12866 13563 Federal Plan

NPRM Response to OMB Comments 072915 final.docx [response to

OMB comments]

M.2 File attached to M with filename EO12866_CPP Federal Plan 2060

AS47 NPRM_20150729 RLSO.docx [preamble]

N Email correspondence between EPA and OMB staff regarding TSDs July 30, 2015

6:30 PM (ET)

O Email correspondence between EPA and OMB staff providing

responses to OMB comments on the CPP federal plan RIA and the

CPP federal plan rule text

July 30, 2015

7:19 PM (ET)

O.1 File attached to O with filename EO12866_CPP Federal Plan

RIA_20150730 Response to Comments.docx [response to OMB

comments]

O.2 File attached to O with filename CPP Federal Plan Model Rule OMB

7_30_15 clean.docx [rule text]

P Email correspondence between EPA and OMB staff regarding

interagency review comments on the CPP federal plan proposal

package

July 31, 2015

8:48 AM (ET)

P.1 File attached to P with filename

SummaryOfInteragencyCommentsUnder_EO12866_13563_Federal

Plan.docx

Q Email correspondence between EPA and OMB staff providing the

CPP federal plan preamble, CPP federal plan rule text, and

responses to OMB comments on the rule package

July 31, 2015

5:42 PM (ET)

Q.1 File attached to Q with filename EO12866_CPP Federal Plan 2060

AS47 NPRM_20150731.docx [preamble]

Q.2 File attached to Q with filename EO12866_CPP Federal Plan 2060

AS47 NPRM_20150731 RLSO.docx [preamble with redline strike

out]

Q.3 File attached to Q with filename EO12866_CPP Federal Plan 2060

AS47 NPRM_20150731 Rule Text.docx [rule text]

3
Attachment Topic Date/Time of

Email

Q.4 File attached to Q with filename EO12866_CPP Federal Plan 2060

AS47 NPRM_20150731 Rule Text_RLSO.docx [rule text with redline

strike out]

R Email correspondence between EPA and OMB staff providing the

CPP federal plan RIA documents

July 31, 2015

8:08 PM (ET)

R.1 File attached to R with filename

EO12866_CPP_Federal_Plan_2060_AS47_RIA Final_20150731.docx

[RIA]

R.2 File attached to R with filename

EO12866_CPP_Federal_Plan_2060_AS47_RIA

Final_20150731_RLSO.docx [RIA with redline strike out]

R.3 File attached to R with filename

EO12866_CPP_Federal_Plan_2060_AS47_RIA_Spreadsheet

Final_20150731.xlsx [RIA spreadsheet]

S Email correspondence between EPA and OMB staff providing the

CPP federal plan preamble, CPP federal plan rule text, and CPP

federal plan RIA

August 1, 2015

4:43 PM (ET)

S.1 File attached to S with filename EO12866_CPP Federal Plan 2060

AS47 NPRM_20150801 Preamble.docx [preamble]

S.2 File attached to S with filename EO12866_CPP Federal Plan 2060

AS47 NPRM_20150801 Preamble RLSO.docx [preamble with redline

strike out]

S.3 File attached to S with filename EO12866_CPP Federal Plan 2060

AS47 NPRM_20150801 Rule Text.docx [rule text]

S.4 File attached to S with filename EO12866_CPP Federal Plan 2060

AS47 NPRM_20150801 Rule Text RLSO.docx [rule text with redline

strike out]

S.5 File attached to S with filename

EO12866_CPP_Federal_Plan_2060_AS47_RIA

Final_20150731_Clean.docx [RIA]

T Email thread of correspondence between EPA and OMB staff

regarding the CPP federal plan proposal package documents

August 1, 2015

5:15 PM (ET)

U Email thread of correspondence between EPA and OMB staff

regarding the completion of review of the CPP federal plan

proposal package

August 2, 2015

10:37 AM (ET)

4
Attachment A.

5
From: Jones, Toni <Jones.Toni@epa.gov>

Sent: Monday, July 6, 2015 3:46 PM

To: Frey, Nathan J.

Cc: Culligan, Kevin; Vasu, Amy

Subject: Possible times for overview of the CPP federal plan

  

Hi Nathan,

As Amy mentioned in her previous email, I am following‐up with some potential dates and times for a

teleconference to give an overview of the CPP federal plan.  I am currently holding the following on the

calendars of the appropriate EPA staff:

Wednesday, 7/8, 11:00 – 12:00

Thursday, 7/9, 1:00 – 2:00

Tuesday, 7/14 11:30 ‐12:30

Please let me know which of these works best, and I will follow‐up with a call‐in number.

Kind regards,

Toni

Toni Wyche Jones, EI, CFM | Fuels & Incineration Group | Sector Policies & Programs Division - Mail Code E143-

05 | Office of Air Quality Planning & Standards | U.S. Environmental Protection Agency | RTP, NC 27711 | Phone: 

(919) 541-0316 |

From: Frey, Nathan J. [mailto:Nathan_J._Frey@omb.eop.gov]  

Sent: Monday, July 06, 2015 1:52 PM

To: Vasu, Amy

Cc: Culligan, Kevin; Jones, Toni

Subject: RE: Possible times for update on changes to CPP preamble & reg text

  

Hi Amy,

We’ve settled on Tuesday 11:30‐1:00 for the briefing on CPP rule changes.  Can you send call‐in info

when available?  Thanks,

Nathan

From: Vasu, Amy [mailto:Vasu.Amy@epa.gov]  

Sent: Monday, July 06, 2015 11:56 AM

To: Frey, Nathan J.

Cc: Culligan, Kevin; Jones, Toni

Subject: Possible times for update on changes to CPP preamble & reg text

  

Nathan,

Possible times for the update on changes to the CPP preamble & reg text since 5/29/15 are:

6
+ Tuesday, July 7, 11:30am‐1:00pm (preferred; we’d like to provide this sooner than later)

+ Friday, July 10, 9:30‐11:00am

+ Friday, July 10, 12:30‐2:00pm

We will follow up with you separately about scheduling a briefing on the federal plan.

Thank you.

Amy

~~~~~~~~~~~~~~~~~~~~~~~

Amy B. Vasu

U.S. EPA / OAQPS

Sector Policies and Programs Division

email:  vasu.amy@epa.gov

phone:  919.541.0107

  

7
Attachment B.

8
From: Vasu, Amy <Vasu.Amy@epa.gov>

Sent: Sunday, July 19, 2015 9:04 PM

To: Jones, Toni; Boswell, Colin; Swanson, Nicholas

Cc: Culligan, Kevin

Subject: Additional comments ‐‐ Summary of Interagency Comments Under EO12866 and 13563 ‐‐ 

Federal Plan Requirements for GHG emissions from Electric Utility Generating Units

  

All,

Attached are additional comments on the federal plan.

Thank you.

Amy

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

Sent: Saturday, July 18, 2015 4:23 PM

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

Cc: Szabo, Aaron; Grossman, Andrea

Subject: Summary of Interagency Comments Under EO12866 and 13563 ‐‐ Federal Plan Requirements

for GHG emissions from Electric Utility Generating Units

  

Attached please find an additional summary of interagency comments under EO 12866 and 13563 on

EPA’s draft NPRM: Federal Plan Requirements for Greenhouse Gas Emissions from Electric Utility

Generating Units Constructed on or Before January 8, 2014; Model Trading Rule.

  

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

  

Nathan

9
Attachment B.1

10
RIN 2060-AS47 

Federal Plan Requirements for Greenhouse Gas Emissions from Electric Utility Generating Units 

Constructed on or Before January 8, 2014; Model Trading Rule

1) Mass. Reviewer recommends that EPA propose only a mass-based plan for the federal plan. To 

the extent that some states may select a state rate-based plan, reviewer recommends leaving in 

the requirements necessary to submit an approvable state rate-based plan as a model ratebased trading rule. If EPA does propose both, reviewer recommends putting the mass-based 

implementation approach before the rate approach, making their discussion and outline 

parallel, and highlighting the lower administrative burden for mass-based plans with respect to 

allowance tracking compared to rate-based plans with respect to ERC generation and tracking.

Reviewer notes that given EPA’s stated view that it would like to enable as much trading 

between states as possible (which would be enhanced by coordination on mass vs rate), there is 

value in proposing only a mass-based plan now rather than a year from now when the states 

have to submit initial plans.

2) Technology Neutral. Reviewer recommends proposing (rather than taking comment on) that all 

non-BSER technologies and measures that are acceptable to generate ERCs in the emission 

guidelines (EGs) be proposed as approved under a federal plan. That would include, but not be 

limited to, distributed RE generation, demand side energy efficiency, new or up-rated nuclear 

generation, offshore wind, and CCS retrofits. Not allowing certain abatement measures to be 

credited reduces the cost effectiveness of the policy. EM&V requirements for state plans on 

non-BSER technologies are the same as the requirements for the federal plan, so comments 

should be requested on the EM&V methodologies, and not on which technologies and 

measures should be valid compliance mechanisms. Reviewer also notes that EPA takes 

comment on what the process should be for demonstrating the “appropriateness” of additional 

technologies, but never explains what the “appropriateness” standard requires. All technologies 

and measures could be held to a strict standard to be quantifiable, verifiable, and additional. 

Any technology or measure that can pass the requirements should be permitted to generate 

credits under a federal plan. 

Reviewer recommends that the allowances that are set-aside for low- or zero-emission activities 

be distributed using a technology-neutral methodology and not reserved exclusively for RE. 

(Reviewer notes that selecting only RE for a set aside, as suggested in the current version of the 

plan, is selecting particular technologies without sufficient justification.) Reviewer suggests that 

EPA take comment on a proposed federal plan that is technology neutral. Reviewer also 

recommends renaming this group of allowances as the Clean Energy Set-Aside to avoid 

confusion with the set-aside for existing NGCC. 

It should be explicitly stated on pages 99, 103 and 110-120 that incremental, new nuclear after 

2012 should be afforded equal treatment with renewable energy under this rulemaking 

consistent with the final Clean Power Plan. The nuclear units that are currently under 

construction represent a significant amount of zero-emitting baseload capacity that should be 

allowed to create ERCs in the federal plan and model trading rule.

11
3) Set-aside. Reviewer recommends that the RE set-aside be changed in the proposed federal plan 

such that allowances be set aside for low- and zero-emitting generation and be distributed to 

those low- and zero-emitting EGUs or projects in the first two interim compliance periods (i.e., 

2022-2024 and 2025-2027) in proportion to the incremental generation of those EGUs or 

projects during the 2020 and 2021 years (relative to historic generation between 2010 and 

2012). This would have the added benefit of incentivize clean energy builds in 2020 and 2021.

4) ERC Issuance to NGCC. Reviewer recommends clarifying the formula for calculating ERC 

issuance from NGCC because the current formula and data available in previously released TSDs 

do not enable the reviewer to arrive at the same result of 0.09 ERCs/MWh NGCC.

General Comments

1) Page 12, 85, “The EPA is strongly considering taking a single approach (i.e., either the massbased or rate-based approach) for every state in which it promulgates a federal plan, and we are 

inviting comment on this. We also invite comment on which approach, mass-based or ratebased, should be selected if we opt to finalize a single approach.”

Comment: Reviewer recommends that EPA propose only a mass-based plan for the federal plan. 

To the extent that some states may select a state rate-based plan, reviewer recommends 

leaving in the requirements necessary to submit an approvable state rate-based plan as a model 

rate-based trading rule. Reviewer also recommends putting the mass-based implementation 

approach before the rate approach, making their discussion and outline parallel, and 

highlighting the lower administrative burden for mass-based plans with respect to allowance 

tracking compared to rate-based plans with respect to ERC generation and tracking. Reviewer 

notes that given EPA’s stated view that it would like to enable as much trading between states 

as possible (which would be enhanced by coordination on mass vs rate), there is value in 

proposing only a mass-based plan now rather than a year from now when the states have to 

submit initial plans.

2) Page 147, 224. “The EPA requests comment on whether there are reasons that a state should be 

allowed to transition from a federal plan to a state plan in the middle of a compliance period 

and if so what requirements should be put in place to do so while ensuring the integrity of both 

the federal plan and the state plan and while enabling the affected EGUs covered by the plans to 

understand and meet their compliance requirements.”

Comment: Reviewer recommends that states not be allowed to switch plans within a 

compliance period (either from a state plan to a federal plan or from a federal plan to a state 

plan) because, in rate-based plans, that would greatly complicate compliance given differences 

in ERC generation options between the Federal plan and possible state plans or, in mass-based 

plans, the federal plan allocates all allowances for the compliance period at the beginning of the 

period. 

Reviewer also recommends that any state that switches between a federal plan and a state plan 

or a rate plan and a mass plan needs to demonstrate a strategy for accounting for banked 

ERCs/Allowances that maintains the environmental integrity of the program. 

3) Page 175. “The agency requests comment on the idea of auctioning all, or a portion of, each 

state’s allowances in the proposed federal plan, on how much of each state’s allowances to 

12
auction if not the entire amount, on the frequency (e.g., yearly or every few years), design of 

auctions (e.g., spot or advance) and who may participate in the auction.”

Comment: Reviewer recommends that the Federal mass-based plan encourage (but not require) 

states to auction at least a portion of their allowances instead of freely allocating all of them to 

affected EGUs and the set-aside. Periodic auctions are done in many other mass-based 

environmental compliance programs (California’s AB32, RGGI, the EU Emission Trading Program) 

because they facilitate allowance price discovery by market participants and allow for the 

efficient distribution of allowances. Reviewer acknowledges that EPA may not be able to run the 

auction on behalf of states, but reviewer recommends that EPA set up the auction infrastructure 

– for example, by establishing a turnkey auction platform with one of the many auction platform 

providers on the market – that can be used by states who choose to adopt the federal plan or a 

state plan. Reviewer recommends that the auctions should be online, multi-round, uniform 

price auctions. A standard auction platform would reduce transaction costs for EGUs that 

operate across multiple states as well as reduce the likelihood of technical glitches in some state 

auctions.

4) Page 215 – 216. “The EPA requests comment on this proposed approach for addressing leakage 

in a state allowance-distribution methodology and on any other approaches for doing so.... In 

this federal plan proposal, the EPA requests comment on an alternative option where a state 

that chooses to submit a state allowance-distribution methodology could provide a 

demonstration that leakage will not occur (without implementing the allocation strategies 

specified here) due to specific characteristics of the state.”

Comment: Reviewer recommends that the federal mass-based plan include an option whereby 

new NGCC is included under the mass goal as a mechanism for addressing leakage. Such an 

example would include the methodology for adjusting the state mass goal to reflect emissions 

from new NGCC.

 

5) Page 223. “The EPA requests comment on other approaches to provide a smooth transition 

from federal-plan implementation to implementation by state plans, and on its proposed 

approach of not replacing a federal plan for any compliance period for which allowances were 

already recorded.”

Comment: Reviewer agrees that switching between plan types should not be allowed for any 

compliance period for which allowances were already distributed/recorded. In any situation, 

reviewer recommends that switching should only be allowed at the beginning of a compliance 

period.

Trading Comments

1) Page 49/50. “The EPA also requests comment on expanding the scope of interstate trading to 

include linking states covered by the rate-based trading federal plan with any state that has an 

approved rate-based trading state plan meeting the proposed conditions for linkages and that 

uses an EPA-designated ERC tracking system that is interoperable with an EPA-administered ERC 

tracking system.” 

“The EPA also takes comment on allowing a state that has an approved rate-based trading state 

plan meeting the proposed conditions for linkages and that uses an EPA-designated ERC tracking 

system to register with the EPA, and after registration, to link with states covered by the ratebased trading federal plan.”

13
Comment: Reviewer strongly recommends not allowing states that select rate-based trading 

programs to link to other states unless all states within the linkage have select the same ratebased approach (i.e., either technology-specific rates or have the same blended rate). Reviewer 

notes that such a rule is important in states with rate-based goals to prevent unintended 

increases in emissions from otherwise identical EGUs that are operating under higher rates.

2) Page 50, 51. “In this proposed rule, the proposed approach to link from the mass-based trading 

federal plan to state plans could result in linking of the federal plan to state plans that include 

non-affected emission sources. The EPA requests comment on this proposed approach.”

Comment: Reviewer supports the intent to allow any approved mass-based plan to trade 

allowances with any other approved mass-based plan, even if one or more of those mass-based 

plans cover non-affected sources. Reviewer requests clarifications, on page 50, that state plans 

that include non-affected sources will have undergone a demonstration outlined in the EGs to 

ensure that the plan will result in affected sources meeting the mass-based target for covered 

sources. Also on page 50, reviewer requests clarification that the import and export adjustments 

required in the EGs will include allowances issued from approved state plans that cover affected 

and non-affected sources. 

3) Page 51. “The EPA requests comment on this expectation of a competitive ERC market and a 

competitive allowance market, and on potential program design choices that could address any 

identified market power concern.”

Comment: Reviewer recommends that a competitive and liquid ERC/allowance market is most 

likely to exist when there is 

a) Transparent release of information on regulatory changes. Reviewer recommends 

that EPA adopt communications strategies about ERC/Allowance issuance and other 

policy changes similar to communication strategies used by the Federal Reserve in 

discussing monetary policy, public companies in releasing financial information, or 

the EU Emissions Trading System in making policy announcements. In all cases, new 

information has the potential to affect billions of dollars of assets. Specifically, 

reviewer recommends that EPA should maintain a publicly available website and 

listserve that notifies the public in advance of announcements (e.g., 2-5 days) and is 

the first location announcements are released to the public. To the extent possible, 

reviewer encourages EPA to adopt a regular schedule in which updates or changes 

are announced (e.g., 10am on the first Wednesday of every month). Reviewer 

recommends that EPA establish highly confidential procedures for guarding the 

release of such information to avoid information leakage to traders who would 

benefit financially from the information. Beyond the website, the reviewer 

recommends that EPA publicly designate a limited number of people who can speak 

about changes to the program (such that market observers would discount 

comments from undesignated individuals). Reviewer notes that the ERC or 

Allowance market is anticipated to be a multi-billion dollar market and policies and 

procedures that ease the market’s ability to quickly and accurately absorb new 

information will greatly enhance liquidity in the market and remove costly and 

unnecessary volatility. 

b) Limited uncertainty about the total volume of ERCs available. Reviewer 

recommends issuing ERCs as frequently as possible (e.g. monthly for those ERC 

sources that can be issued monthly or quarterly for other sources) and at regular, 

14
pre-determined times to reduce uncertainty about how many ERCs are present in 

the market, which will reduce volatility in the price of ERCs. 

c) Strict monitoring of fraudulent ERCs/Allowances. Reviewer recommends strict 

oversight of allowance market to prevent the type of fraud experienced in the EU at 

the launch of their program. 

d) No limits on ERC/Allowance ownership. Reviewer believes that all types of entities 

can provide benefits to the market and encourages EPA to not limit the type or 

number of firms that can hold ERCs/allowances.

e) Market monitor enforcement against manipulation. Review recommends that EPA 

assign a market monitor to provide oversight of the various linked markets that 

form and report on potential market manipulation. 

Reviewer strongly recommends that EPA also require states to adopt similar practices as 

EPA with respect to the release of information about policy changes or ERC issuance 

because states will also play an important role in facilitating liquid and competitive 

markets.

4) Page 141-142, 156. “The EPA requests comment on whether there should be a quantitative limit 

or cap on the number of ERCs that can be banked. The EPA also requests comment on whether 

an ERC should be eligible to be banked between the interim and final compliance periods. The 

EPA is also proposing that ERCs will not expire after any duration of time. The EPA requests 

comment on the shelf-life of an ERC.”

Comment: Reviewer does not believe there should be a limit on the number of ERCs/Allowances 

that are banked. Reviewer recommends that ERCs/Allowances be allowed to be banked 

between the interim and final compliance periods. 

5) Page 146. “The EPA requests comment on a broader approach that would allow all affected 

EGUs that are located in states with approved rate-based state plans to participate in the federal 

plan trading program. In other words, this would extend federal-plan linkage to rate-based 

programs that are not set up to be “presumptively approvable,” or which use a set of emission 

rates for affected EGUs that are different from the national uniform subcategorized rates. We 

request comment specifically on what conditions or requirements would be needed in these 

cases in order to participate in the federal plan trading program in a way that is administratively 

feasible and maintains the integrity of all of the linked programs.”

Comment: Reviewer strongly recommends that EGUs should not be allowed to trade with other 

EGUs in other states unless EGUs of the same technology type operate under the same rate. 

Without that restriction, the policy would probably lead to unintended increases in emissions. 

Reviewer does not believe there is a mechanism that maintains emissions outcomes and at the 

same time allows linkages between state trading programs when “emission rates for affected 

EGUs...are different from the national uniform subcategorized rates.” 

6) Page 146. “Although the agency has serious concerns about the administrative complexity of 

this approach, we also request comment on the feasibility and potential mechanism of allowing 

EGUs in states with approved mass-based state plans to participate in a federal rate-based 

trading plan.”

Comment: Reviewer strongly recommends that EPA include in the Federal Plan that allowances 

should not be an acceptable compliance instrument in any rate-based program (regardless of 

15
the conversion from mass to rate) and that ERCs should not be an acceptable compliance 

instrument in any mass-based program (regardless of the conversion from rate to mass).

7) Page 156, 158. “The EPA is not proposing to allow allowance borrowing across compliance 

periods in the mass-based trading federal plans; however the agency is requesting comment on 

the use of borrowing across compliance periods.”

Comment: Reviewer notes that limited borrowing is implicitly allowed due to the 2 to 3 year 

compliance period. Reviewer does not recommend any borrowing beyond that implicit amount 

because it could encourage EGUs that anticipate shutting down to borrow significant quantities 

of ERCs/allowances and then declare bankruptcy at the same time they shut down. 

Compliance Comments

1) Page 56. “The EPA requests comment on whether there is any reason to use shorter compliance 

periods than the proposed periods, and how modifying these periods could be done in a manner 

that is consistent with the Emission Guidelines.”

Comment: Reviewer notes that a two to three year compliance period seems to be used 

successfully in other programs; however, reviewer encourages EPA not to further extend the 

compliance period beyond the currently proposed two to three years. A longer compliance 

period would likely have EGUs building up a larger ERC/Allowance liability prior to the 

conclusion of the compliance period, which might reduce their solvency if not sufficiently 

incorporated into planning.

2) Page 138, 159, 231. “The agency also requests comment on an earlier allowance transfer 

deadline [compared to November 1], such as June 1 or March 1, of the year after the last year in 

the compliance period.”

Comment: Reviewer recommends an earlier deadline for allowance compliance transfer, 

namely May 1, or the earliest that can be supported based on ERC issuance. The longer 

submission period (i.e., November 1) allows EGUs to build up a larger compliance liability. 

Reviewer is concerned about two specific situations. 1) An EGU that had planned to go out of 

business would have a longer period to emit before having to shut down or turn in compliance 

instruments. 2) An EGUs had not acquired or planned for acquiring sufficient compliance 

instruments, would build a larger compliance liability prior to being found to be out of 

compliance. That could contribute to an increased likelihood EGUs declare bankruptcy or 

otherwise exit the market. To somewhat address those situations, reviewer also recommends 

that 30 percent to 50 percent of an EGU’s expected annual compliance requirement be due in 

each of the interim years of the compliance period to prevent the buildup of large liabilities by 

EGUs. 

3) Page 140, 232. “The EPA solicits comment on sources owing two ERCs to make up for each 

insufficient ERC in previous compliance periods and whether two for one is the proper make-up 

rate or whether there should be a stricter or a more lenient ratio.”

Comment: Reviewer recommends clarifying on pages 140 (for ERCs) and 232 (for allowances) 

the timeframe within which an entity out of compliance would have to provide the two 

ERCs/allowances for every one that was needed but missing from its account, assuming that 

none are available to be automatically deducted. 

16
Reviewer notes that it appears that the EGs no longer include the requirement that sources owe 

two ERCs to make up for each insufficient ERC in the previous compliance period. Reviewer 

requests that EPA consider if the penalty for being out of compliance should be the same in the 

EGs and in the federal plan or if there is justification for the different treatment. 

Mass Allocation & Set-Asides Comment

1) Page 54, 178, 186-188. “The EPA takes comment on both the set-aside for output-based 

allocation and the set-aside of allowances for RE generation.”

Page 202. “We are also requesting comment on options for a percentage of allowances to be 

reserved [for the RE set-aside] ranging from 1-10 percent of total allowances in each state.”

Comment: Reviewer recommends that the RE set-aside be changed in the proposed federal plan 

such that allowances be set aside for low- and zero-emitting generation and be distributed to 

those low- and zero-emitting EGUs or projects in the first two interim compliance periods (i.e., 

2022-2024 and 2025-2027) in proportion to the incremental generation of those EGUs or 

projects during the 2020 and 2021 years (relative to historic generation between 2010 and 

2012). Reviewer suggests that the distribution of allowance vintages for both compliance 

periods occur at the same time. Such an allocation strategy would encourage early action, 

increase the likelihood that the United States achieves its international carbon reduction 

commitments, and provide information to the market about the future price of allowances. In 

subsequent interim compliance periods, reviewer suggests that allowances are allocated 

proportional to generation in the previous interim compliance period. That would simplify the 

allocation approach relative to the proposed Federal Plan and reduce uncertainty for developers 

of low- and zero-emitting EGUs. Reviewer suggests that this becomes the default and EPA take 

comment on it in the proposed federal plan.

Reviewer suggests that the proposed approach in the current version of the federal plan for 

allocation (i.e., projected future generation) is complicated, creates uncertainty, and is 

vulnerable to manipulation by firms over- or under-projecting their generation in an effort to 

affect ERC prices. 

Reviewer also suggests that EPA propose a larger set-aside or provide a rationale for limiting the 

set-aside to 2 percent of available allowances instead of a larger or smaller number. Specifically, 

on page 203 EPA states that 2 percent was chosen because “at a range of possible allowance 

prices...[it would] incent the development of additional RE projects.” Reviewer recommends 

clarifying the meaning of additionality in that statement.

2) Page 148. “The EPA is proposing that allowances be issued in metric tons for the federal plan, 

and also requesting comment on the issuance of allowances in short tons.”

Comment: Reviewer recommends that allowances be issued in metric tons, which is consistent 

with the units of an allowance adopted by California.

3) Page 162, 172. “the EPA is requesting comment on an alternative allocation approach that 

would first divide the total number of allowances from each state’s mass goal by source 

category and then allocate to affected EGUs within each category based on shares of historic 

generation.”

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Comment: Reviewer recommends that EPA clarify how the alternative allocation approach 

would be implemented. On page 172, “this alternative approach would divide the total number 

of allowances from a state’s mass goal... by affected EGU source categories. “ Reviewer 

recommends clarifying whether it is the affected EGU source categories generation or emissions

(and if it is the average from 2010-2012) that are placed in the denominator. 

Reviewer also recommends clarifying the following phrase located on the top of page 173, 

“...and multiply historic NGCC-unit generation by the NGCC-unit source category-specific CO2

emissions performance rate.” Is the intended emission performance rate the average eight year 

interim rate from the EGs, the yearly emission performance rates from the Goal Computation 

TSD, or the federal 2 or 3 year interim compliance period average emission performance rates?

4) Page 165, 247. “The agency requests comment on the proposed historic-generation based 

allocation approach and on other allocation approaches.”

Comment: Reviewer recommends that EPA take comment specifically on whether the historic 

generation allocation should reflect generation or emissions from affected EGUs. 

Reviewer recommends, in the discussion on Pg. 247 regarding calculation steps for the proposed 

historic-generation-based allocation approach, explaining whether/how historical operational 

data for plants during emergency/reliability events (i.e., unplanned outages, excess generation 

to offset outages) are considered in the averaging/allocation formula to avoid skewing the 

results.

5) Page 174. “The EPA requests comment on the use of other updating allocation approaches 

[instead of the historical allocation method].”

Comment: Reviewer recommends that EPA encourage states to reduce the size of the historicgeneration-based allocation over time because it does not contribute to market efficiency. 

6) Page 176-178. “The EPA requests comment on the design and utility of allocating allowances to 

LSEs to help mitigate electricity price impacts. In particular, the EPA requests comment on 

options to establish conditions requiring pass through of allowance value and verification of 

such pass-through, whether it would be appropriate to identify any conditions related to 

equitable distribution of allowance value among ratepayer categories, as well as EPA’s legal 

authority to apply any such conditions.”

“The EPA recognizes that allocation to LSEs, by reducing rate impacts, could reduce incentives 

for socially efficient demand response, including potential investment in energy efficiency. The 

EPA solicits comment on the magnitude of this effect, relative to alternative allocation options, 

and design options that could help mitigate this effect.”

Comment: Reviewer recommends that EPA note in the federal plan preamble and include in 

their approvability criteria that allowances allocated to LSEs may be used to help mitigate the 

effect of the policy on electricity consumers. Reviewer recommends that EPA also note that if 

the LSE passes through the value from selling the allocated allowances in a lump sum amount 

that is not associated with consumers’ electricity bills the incentives for economically efficient 

end-use energy efficiency are maintained. Finally reviewer suggests that EPA make clear that 

allowing LSEs to pass through the value of allocated allowances in a mechanism proportional to 

electricity usage will increase the cost of the program.

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7) Page 190, 192, 194, 196. “The EPA accordingly solicits comment on key parameters for the 

appropriate design of the output-based allocation approach used for this proposed set-aside [to 

fossil generators].”

Comment: Reviewer suggests also taking comment on having a higher limit on the size of the 

output based set aside for existing fossil NGCC EGUs because this set-aside improves the 

economic efficiency of the program (by reducing generation shifts to unaffected sources), 

whereas the historic generation allocation provides no safeguards against leakage to unaffected 

sources. 

8) Page 199. “The EPA also requests comment on extending output-based allocation from this set 

aside to affected utility boilers.”

Comment: Reviewer agrees with EPA’s reasoning for not extending output-based allocations to 

fossil steam EGUs.

9) Page 199-200. “The EPA solicits comment on the general merits of the proposed set-aside and 

the output-based allocation used under this set-aside. In addition, the agency solicits comment 

on how such an approach could be targeted to improve implementation of the proposed massbased trading federal plans and improve overall environmental and economic performance. In 

particular, the EPA solicits comment on which affected EGUs should receive any output-based 

allocation, the proper allocation rate(s), the total size of the set-aside, and from which 

compliance period’s total allowances the set-aside should be drawn.”

Comment: Reviewer recommends using an allocation rate that is similar to the emission rate of 

new NGCC units (i.e. ~800 – 900 lbs CO2/MWh) using a rate higher than this would not align the 

incentives between existing and new NGCC generation.

10) Page 204. “The agency is requesting comment on an additional condition that would limit 

eligibility to project providers that are also the owners or operators of affected EGUs.”

“Eligible projects must be located in the mass-based state for which the set-aside has been 

designated. The agency invites comment on whether capacity outside the state should be 

recognized, and how that could be implemented.”

Comment: Reviewer recommends against limiting the set-aside to owners and operating of 

affected EGUs; owners and operators of eligible set-aside projects who do not also own an 

affected EGU are equally important to reducing emissions and should not be disadvantaged in 

the set-aside policy. Such a limit would probably result in some type of market distortion such 

that eligible projects would be sold to owners of affected EGUs or owners of eligible projects 

would purchase affected EGUs. Reviewer recommends against issuing set-aside allowances to 

EGUs outside the state because BSER is calculated based on generation within the state and not 

generation outside of the state. EGUs outside the state would presumably be eligible to receive 

set-aside allowances within their own state. 

11) Page 210, 212. “The EPA is also seeking comment on whether a portion of this set-aside should 

be targeted to RE projects that benefit low-income communities.”

“The EPA seeks comment on how a low-income community should be defined under this setaside. We seek comment on how much of the set-aside should be designated as targeted at lowincome communities. We also request comment on whether the methods of approval and 

distribution of allowances to projects that benefit low-income communities should differ from 

the methods that are proposed to apply to other RE projects.”

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Comment: Reviewer recommends including a discussion of the importance of considering 

impacts on economically disadvantaged communities in the context of allowance allocation 

decisions described beginning on page 160. 

12) Page 214, 221-222. “We request comment below on the advantages and disadvantages of 

allowing a state to handle allocations via a delegation of federal plan authority.”

Comment: Reviewer recommends clarifying, on page 218, that if a state chooses to auction 

some or all of the allowances under a federal plan, that the state could choose to alter how the 

state spends the auction revenue, even though the allocation plan indicating what level of 

allowances will be auctioned “would be final and not subject to modification.” 

ERC Issuance Comments

1) Page 52. “This can be demonstrated through: 1) the provision of a power delivery contract or 

power purchase agreement in which an entity in the rate-based state contracts for the supply of 

the MWhs in question and 2) documentation that the electricity was treated as comparable to a 

generation resource used to serve regional load that included the rate-based state. This 

demonstration must be included as part of the project application for ERC issuance to the EPA 

from the RE provider in the mass-based state. Once the project is approved, subsequent 

applications for issuance of credit to the EPA will need to reference that the MWh submitted are 

achieved by an approved project located in a mass-based state. The EPA requests comment on 

this approach.”

Comment: Reviewer agrees that the first demonstration option ensures that ERCs are not 

double counted. However, reviewer recommends clarifying option 2 by including an example of 

how option 2 could be demonstrated and how it does not lead to double counting. 

2) Page 102. “The EPA broadly solicits comments on all aspects of the subcategorized rate 

approach.”

Comment: Reviewer notes that the subcategorized rate approach is the BSER from the EG. 

Recommend clarifying exactly what the EPA is inviting comment on, and that they are not reopening up BSER for comment.

Reviewer requests that EPA request comment on pages 101-102 on using the statewide blended 

rate target as the rate option for the model rate trading rule. Reviewer notes that 

subcategorized rates create a larger incentive for coal generation compared to a state blended 

rate, which may result in additional emission from coal under the subcategorized rate approach. 

Reviewer recommends EPA clarify how “subcategorized rates allow(s) for: (1) an equitable 

distribution of burden for emission reductions. Additionally, over what entities is the burden 

equally distributed? 

3) Page 99, 103, 111-112, 134-135. “This section describes how a rate-based federal plan would be 

designed and operated, and how measures consistent with the CPP EGs building blocks can 

generate ERCs. The EPA requests comment on these means of generating ERCs and whether 

other sources of low- or zero-emitting electricity not included in the building blocks should also 

be eligible to generate ERCs for compliance purposes.”

Comment: Reviewer recommends proposing (rather than taking comment on) that all non-BSER 

technologies that are acceptable to generate ERCs in the emission guidelines (EGs) be proposed 

20
as approved under a federal plan. That would include, but not be limited to, distributed RE 

generation, demand side energy efficiency, new and up-rated nuclear generation, offshore 

wind, and CCS retrofits. By not allowing certain abatement measures to be credited, the cost 

effectiveness of the policy is reduced both for the federal plan and for states that adopt a 

“presumptively approvable” plan modeled after the federal plan. EM&V requirements for state 

plans on non-BSER technologies are the same as for the federal plan, so comments should be 

requested on the best EM&V methodology, , and not which technologies and measures should 

be valid compliance mechanisms or not. Reviewer also notes that EPA takes comment on what 

the process should be for demonstrating the “appropriateness” of additional technologies, but 

never explains what the “appropriateness” standard requires. All technologies and measures 

could be held to a strict standard to be quantifiable, verifiable, and additional. Any technology 

or measure that can pass the requirements should be permitted to generate credits under a 

federal plan.

4) Page 108. “The EPA requests comment on this approach and requests comment and suggestions 

on other approaches for existing NGCCs to generate ERCs at all times. The EPA is considering this 

methodology that BB2 ERCs are generated for all NGCC generation because it ensures that all 

existing NGCCs are encouraged to run at a greater capacity. The EPA is requesting comment on 

alternative methods for NGCCs to generate BB2 ERCs. Specifically, the EPA solicits comment on 

NGCCs generating BB2 ERCs once a threshold of generation for the year is achieved.”

Comment: Reviewer found that the equation presented on page 106, using data from the Goal 

Computation TSD, does not compute to a 0.09 BB2 ERCs/MWh. Specifically, from the TSD, 

reviewer notes that NGCC Gen Post BB2 is 987TWh and NGCC Gen in 2012 is 734TWh, which 

leads to a BB2 ERC generating factor of 0.25 BB2 ERCs/MWh. Reviewer requests clarification on 

the correct formula and how “the collective sum of the BB2 ERCs generated realizes the amount 

of the emission reductions described in Building Block 2 when 75 percent capacity is achieved.” 

(p. 105).

Additionally, reviewer recommends that EPA clarify the purpose of the equation on the top of 

page 109. Reviewer first thought this equation only applied to either of the threshold 

approaches, but upon closer study it appears that this equation may be the key to reproducing 

the BB2 ERC generating factor of 0.09 ERCs/MWh.

Reviewer recommends clarifying the text on the top of page 105. The first full sentence, “To 

account for...Building Block 2.”, makes it sound like only incremental NGCC will generate BB2 

ERCs instead of all NGCC generation.

Reviewer recommends that EPA clarify over what time period the average NGCC generation is 

taken and after what building block in the following sentence from page 106. “...EPA has taken 

the average NGCC operation in the Eastern Interconnect and divided it by the 75% of Building 

Block 2...”

Reviewer recommends not proposing or asking for comment on the first threshold calculation 

option on page 108. Such an approach would appear to create a clear opportunity to game the 

BB2 ERC calculation without actually increasing generation from NGCC relative to 2012. For 

example, an owner of two NGCC EGUs could increase generation for one EGU relative to 2012 

21
and decrease generation from the other EGU relative to 2012, thus generating new ERCs but not 

increasing generation or reducing emissions. Alternatively, EPA could mention they considered 

this option, but decided against it for the reason above.

Reviewer also requests clarification on the second threshold calculation option presented for 

BB2 ERC generation, as it is not clear from the text how the percentage threshold is calculated 

or applied: “The other threshold option is to use a percentage threshold. This percentage is the 

2012 regional NGCC generation of total NGCC regional capacity in 2012. This percentage is 

applied at the unit level and all generation by the NGCC that exceeds that percent capacity at 

the NGCC is eligible to credited with BB2 ERCs.”

5) Page 110. “We invite comment on this approach [EGU based ERC generation] as a method of 

implementation of a federal plan and model trading rule.”

Comment: Reviewer recommends adding a short paragraph at the beginning of the section on 

“EGU Based ERC Generation” on page 103 to give an overview of the 2 ways that NGCC can 

generate ERCs, with a sentence describing each, and an explanation of the differences between 

ERCs and BB2 ERCs. It was not until the end of this section that it became clear how NGCCs and 

ERCs interact.

Reviewer also recommends against issuing two types of ERCs in the federal plan. Because BB2 

ERCs can be used for steam compliance and general ERCs can be used for both steam and NGCC 

compliance and because the vast majority of ERCs are expected to be used for steam 

compliance, one would expect there to be a single price for the two types of ERCs in a 

competitive market. Reviewer notes that maintaining two types of distinct ERCs makes the 

program more complicated and increases the transaction costs of compliance without providing 

any additional environmental benefits.

6) Page 111. “The EPA requests comment on the inclusion of various types of demand-side EE as 

eligible measures, such as state and utility EE programs, project-based demand-side EE, state 

building codes, state appliance standards, and conservation voltage reduction. The agency also 

requests comment on the inclusion of combined heat and power (CHP) as an eligible measure.”

Comment: Reviewer recommends that all EE measures and CHP projects with rigorous 

verification and that would be approvable under the EGs be included under the federal ratebased trading program. Reviewer recommends that EPA state these measures are approvable 

rather than taking comment on whether they should be approvable. 

7) Page 128, 129. “However, we solicit comment on the annual issuance of ERCs and whether 

issuance should occur at different intervals (e.g., quarterly, biannually, or other time frames). 

The EPA requests justification along with corresponding comments regarding issuance of ERC 

intervals.”

Comment: Reviewer recommends increasing the frequency of ERC issuance at intervals less 

than a year. Automatic issuance of ERCs based on monthly generation data after a facility has 

been approved for eligibility would decrease the administrative burden on generators and the 

ERC tracking system, reduce price volatility, encourage continual operation of efficient markets, 

and provide certainty for low- or zero-emission EGUs or projects. To the extent that EM&V 

requirements prevent the monthly issuance of ERCs from some types of projects, reviewer 

suggests that ERCs from those projects be issued as frequently as possible. Reviewer notes that 

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PJM currently generates certificates in PJM-GATS on a monthly basis (http://www.pjmeis.com/getting-started/faq.aspx#genentq1). This will allow more time for EGUs to acquire the 

necessary ERCs and provide more market certainty for ERC generators. 

8) Page 131. “The agency requests comment on whether a quarterly or semi-annual application 

process [for RE project and program eligibility applications and regulatory approval as well as 

information on ERC transfers] is appropriate. These applications will be accepted through the 

entirety of all compliance periods.”

Page 128 - 133: "As required in the final EGs, we are proposing a two-step application process to 

the federal plan tracking systems for RE ERCs... The EPA takes comment on all aspects of the 

proposed ERC issuance process. "

Comment: Reviewer recommends streamlining the proposed ERC issuance for RE, other 

generating measures, and demand side EE to reduce the reporting burden and allow ERCs to be 

issued more frequently than once per year. As proposed, RE measures must first submit a 

project application and then a separate application for credit issuance. Reviewer recommends 

having a single application process for RE or EE projects, which when approved allows automatic 

issuance of ERCs on a more than annual frequency based on recorded generation or estimated 

savings. An annual EM&V report could be created and reviewed by a third-party verifier; if 

discrepancies are identified, a NODA would be issued indicating the discrepancies and ERC 

adjustments taken for the relevant accounts.

Reviewer also recommends (on page 132) that EM&V methods for RE providers be approved 

during step one of the credit issuance process. Then in step two, only MWh would need to be 

submitted such that the process can be less onerous and time consuming.

Administration Comments

1) Page 48. “The state plan must use an EPA-administered tracking system (we are also requesting 

comment on expanding this to include a state plan that uses an EPA-designated tracking system 

that is interoperable with an EPA-administered system, as detailed below).”

Comment: Reviewer supports an EPA-designated tracking system that is interoperable with EPAdesignated/approved state tracking systems, as described on page 48, be included in the FIP. 

Reviewer recommends requesting comment on page 125 if additional information should be 

tracked in the ATCS to ensure compliance with trading rules laid out in the EGs and contribute to 

a more competitive market. Reviewer recommends EPA take comment on using a 3rd party to 

run the tracking system for a federally enforceable implementation plan. Reviewer recommends 

taking comment on needs for interoperability, using existing REC exchanges as a starting point.

Reviewer requests clarification on the integrity lost through linking state-approved and federally 

administered tracking systems. If each of the state-approved tracking systems meets the EPA 

requirements and exchange protocols that are determined, then integrity should be maintained 

(once emissions increases issues described above are addressed).

2) Page 83. “the agency believes it would be efficient and potentially avoid the need for recourse 

to litigation, to provide an administrative appeals process. Therefore we are proposing, and 

requesting comment on, the use of the regulations for appeals procedures set forth in 40 CFR 

Part 78, to provide for the adjudication of certain disputes that may arise during the course of 

implementation of a federal plan under section 111(d).”

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Comment: Reviewer recommends that any administrative appeals process be sufficiently 

transparent to facilitate ERC/Allowance price discovery by market participants. Reviewer notes 

the potential for such an administrative appeals process to be highly disruptive (and introduce 

significant price volatility) to the market for ERCs/Allowances if done in secrecy with sporadic 

releases of market-moving information.

Reliability

1) Page 64. “Therefore, a reliability safety valve for the federal plan is not needed. EPA invites 

comments on this aspect of the proposed federal plan.”

Comment: Reviewer recommends further explaining why emergency events (on Pg. 64) that 

would otherwise trigger the reliability safety valve would not do so under a federal plan, 

especially with respect to any short-term modifications to a federal plan that may be needed 

(noting that this depends on how the final CPP is clarified on this issue). Further, reviewer 

recommends considering (and explaining) why, given the limited circumstances under which a 

reliability safety valve would be exercised, the opportunity to do so is foreclosed with 

compliance under a federal plan, especially given that the federal plan structure (trading) cannot 

guarantee that a reliability safety valve-qualifying emergency event would not occur. 

2) Reviewer recommends that, in the event that the RSV is triggered, all excess emissions should 

be made up to maintain the stringency of the program on page 1163.

Biomass Feedstock Eligibility 

1) Page 114-115. “Provided for comment below are options for biomass treatment under the ratebased federal plan, which would also apply to eligible generation under the mass-based plan 

allowance set-aside and to the calculation of covered emissions for affected EGUs that are cofiring biomass, which include: 

a. A list of specific acceptable biomass fuels 

b. General principles and/or specific criteria regarding biomass fuel production, processing 

and use for energy 

c. A combination of the above options. “ 

Comment: Reviewer recommends EPA not take comment on options 2 and 3 as presented. 

Reviewer recommends to instead take comment on only two options: 1) EPA’s option 1 and 2) a 

modified version of EPA’s option 3.

For the modified version of EPA’s option 3, the reviewer recommends that EPA still create a list 

of acceptable biomass feedstocks that are updated over time (Option 1). The primary criteria for 

approving acceptable biomass feedstocks would consist of evaluating the carbon reduction 

benefits through a life-cycle emissions analysis of the biomass feedstock. 

A secondary method of evaluation for including biomass feedstocks onto a pre-approved list, is 

the sustainability and best forest management practices (with some caveats as commented on 

below ) outlined in Option 2 (pgs. 116-117). This method would provide clarity for common 

feedstocks, and emphasize carbon reduction as a metric for other feedstocks.

24
2) Page 114. “The revised Framework...finds that it is not scientifically valid to assume that all 

biogenic feedstocks are ‘carbon neutral’...”

Comment: The reviewer agrees with this comment, but notes that it is also not scientifically 

valid to assume that no biogenic feedstocks are carbon neutral, or that all emissions from 

biogenic feedstocks are additional to the emissions that would have occurred were they not 

used as a feedstock. Reviewer recommends inclusion of this clarification. 

3) Page 115: “The first option offered for comment is to specify a list of specific pre-approved 

acceptable biomass fuels.” 

Comment: Reviewer notes that the first option is similar to the feedstock/pathway approval 

process used for the RFS. Recommends noting this in text.

4) Page 115. “The second option offered for comment would be to establish general principles 

and/or specific criteria concerning the production, processing and use of biomass fuels.” 

Comment: Reviewer notes that the second option is presented under a discussion to develop 

principles and criteria for eligibility of feedstocks when the underlying issue with option two is 

implementation. The concern is that the third party verification/certification sets a potentially 

unwanted precedent of having Forest Service and BLM managers subject to a few selected 

individuals, and that the process would be redundant to current NEPA processes. Recommend 

clarifying how these interactions between agencies (EPA, USDA, DOI) would occur under the 

federal plan.

5) Page 116. “Under this option, the EPA could specify criteria for the production, processing and 

use of forest- and agriculture-derived biomass fuels that could also include the preservation of, 

and/or limiting or restricting the use of biomass fuels from, natural and old growth forests...”

Comment: Reviewer notes that nearly all federal forests are “natural forests.” Removal of 

biomass from these forests would offset the cost of needed treatments for these forests which 

are overstocked and prone to fire and pest epidemics. Reviewer recommends explicitly stating 

that this definition of “natural forests” would not exclude federal forests.

6) Page 116. “Limitations on deforestation and targeted land use change, especially of high carbon 

and/or otherwise ecologically sensitive areas for the production of bioenergy feedstocks “ 

Comment: Reviewer recommends defining “deforestation” as meaning land use changes and 

unrestricted logging in ecologically sensitive areas.

7) Page 117. “Use of the best scientific information and systems available to assess landscape 

health, carbon stock attributes and net carbon emissions attributable to production and use of 

biomass for combustion, and to continually refine and update inventories of these attributes” 

Comment: Reviewer suggests clarifying “continually refine and update inventories of these 

attributes” as it is a nebulous term that could have large economic and workload implications. 

8) Page 117. “Ensure forest and landscape productivity, and economic viability, including primary 

and secondary products. “ 

Comment: Reviewer recommends taking comment on “ensuring forest and landscape 

productivity” as it is a difficult task.

Biomass Compliance 

25
1) Page 118. “The EPA also requests comment on options for demonstrating compliance with the 

options listed above that include criteria that reflect sustainability and sustainable practices that 

are additional to the EM&V requirements discussed in section &&& above. These options for 

demonstration of compliance with criteria are described below.“

Comment: pg. 118-119, Reviewer recommends taking comment on Options 3 and 4 only, as 

they focus on existing certification and carbon accounting methodologies. 

2) Page 118. “The first option offered for comment would require provision of sufficient credible 

evidence, such as monitoring records and metrics showing that the forest/agricultural feedstock 

sources meet the criteria listed above and any others that might be adopted, and are at low risk 

of non-compliance.” 

Comment: Reviewer notes that the first option for demonstrating compliance requires evidence 

that defeats the purpose of having biomass fuels that are “pre-approved.” Recommend 

clarifying what the additional reporting for this would be beyond what would be required for 

just determining if a feedstock qualified or not.

3) Page 118. “The second option offered for comment would require the provision of approved 

third party verification and/or certification entities or programs to demonstrate compliance with 

established sustainability criteria.” 

Comment: Reviewer notes that NEPA compliance generally supersedes third party 

verification/certification programs, and that this option for compliance would be a redundant 

and costly requirement. Recommend addressing how NEPA compliance could be used under this 

option.

4) Page 119. “The third option offered for comment allows for the use of any other verification 

programs or entities to demonstrate compliance which are not pre-approved but can be proven 

to employ generally accepted sustainability metrics.” 

Comment: Reviewer supports the third option presented for compliance, as it would 

conceivably include NEPA compliance on federal forests and certifications for private lands. 

Recommend making this the preferred options and the other options as alternatives.

5) Page 119. “The fourth option offered for comment requires a determination of the biogenic 

emissions and sequestration related to the production, processing and use of the biomass fuel, 

with supporting records.” 

Comment: Reviewer notes that the fourth compliance option presented is also part of the 

proposed methodology for determining if a feedstock is eligible. Recommend clarifying whether 

carbon accounting if done for showing eligibility as a feedstock would not have to be repeated 

to show compliance under this option. 

6) Page 152. Reviewer recommends the following change: “This proposed requirement to hold and 

surrender allowances equal to emissions for each compliance period would apply to all reported 

emissions from a facility’s affected EGUs including any emissions from co-fired biomass as 

calculated according to the methodology discussed in the final Framework for Assessing 

Biogenic Carbon Dioxide for Stationary Sources.” 

Reliability Safety Valve

26
EPA indicates that a reliability safety valve is not needed for the federal plan (page 64). This is based on 

the assumption that affected EGUs can obtain allowances or credits as and when needed. However, the 

availability of allowances and credits would depend on the number of states that come under a federal 

plan or under a state plan that is “presumptively approvable.” Moreover, based on market fluctuations 

and operational anomalies, credits and allowances may not be available at a critical time when a system 

is faced with a serious reliability risk, or may be available but only at prohibitive prices. Accordingly, 

reviewers suggest that EPA set out certain limiting criteria for a safety valve in the federal plan instead 

of not including a safety valve at all. In addition, reviewer suggests that EPA allow the creation of ERCs 

and allowances before the compliance period begins in 2022. This would result in early emission 

reductions and environmental benefits and would also allow states and EGUs to create a bank of ERCs or 

allowances in advance of the compliance period to reduce the possible dependence on a safety valve in 

the early years of the initial compliance period. 

New Source Review 

The preamble states in several places (see e.g. pages 80-81) that the “situations will be very few” in 

which NSR applicability is triggered because of undertaking a physical change or change in the method 

of operation. EPA needs to substantiate this conclusion through an analysis to show why it believes that 

measure taken under BB 1 and BB2 would trigger NSR only in a “few situations.” This conclusion that 

NSR would be triggered in only a “few situations” appears inconsistent with EPA’s policies on 

implementation of NSR. While this is an NSR issue, it has bearing on this rulemaking because widespread 

triggering of NSR for the BSER measures under this rule may have an impact on the ability to meet the 

compliance schedule under this rule. The preamble cites UARG v. EPA for the proposition that 

greenhouse gas emissions alone cannot trigger NSR requirements. However, this case would not 

necessarily help sources avoid NSR with respect to the implementation of the Clean Power Plan because 

BSER measures under BB1 and BB2 could result in an increase in emissions of GHG and criteria 

pollutants (SO2, NOx, PM, etc.), resulting in those sources being considered “anyway” sources. 

Generation of ERCs Through Operation of non-BSER Sources 

The draft of the federal plan discusses (pages 110 to 120) the RE measures that would be eligible for ERC 

generation. To ensure consistency with the final Clean Power Plan, reviewers suggest that the federal 

plan allow the generation of ERCs from a broad range of zero-emitting non-BSER sources such as new 

nuclear and demand response EE, subject to EM&V requirements and verification/certification 

protocols. EPA is justifiably concerned about the impact of “leakage” from certain non-affected EGUs 

(e.g. new NGCC units) on the effectiveness of the BSER measures. However, zero-emitting sources such 

as nuclear and demand response EE would not cause leakages, and there is no principled basis to treat 

them differently from the RE measures that EPA has identified as being eligible for ERCs. By the same 

token, these other zero-emitting non-BSER measures should be eligible for receiving set-aside 

allowances in a mass-based program. 

Likewise, the draft federal plan sets out certain criteria under which ERCs generated from RE measures 

operated in mass-based states can be used to meet compliance obligations in rate-based states. 

Reviewers suggest that the use of ERCs generated from other zero-emitting sources located in mass27
based sources (such as nuclear and demand response EE) should likewise be allowed to meet 

compliance obligations in rate-based states.

Participation in Federal Plan Trading Program 

As to interstate trading (pages 144-147), reviewer recommends the use of the broader approach such 

that EGUs in states under a federal plan and in states with a “presumptively approvable” plan, could 

trade with EGUs in other states that are not under a federal plan or “presumptively approvable” plan. 

Creating such a mechanism that facilitates trading through a common federal trading rules (mass-based 

and rate-based) is critical as, otherwise, states would not have an incentive to develop state plans using 

a “state measures” approach. This is also a more equitable and economical approach to compliance. 

Moreover, the fact that state plans using a “state measures” approach would have the federal plan as a 

backstop minimizes the risk of harm in allowing trading between states under state and federal plans. 

Retired Units 

Many utilities own units that meet load and serve customers in multiple states. Therefore, utilities must 

make decisions for their generating fleet as a whole, not as isolated units in individual states. An owner 

of EGUs in two states with a mass-based plan may retire a unit in one state and need those allocations 

to help a unit in another state comply. In order to allow this flexibility, reviewer suggests the following 

approach that is not currently in the proposed rule. Reviewers suggest that the initial allocation of 

allowances for each unit be held constant and not removed from the unit regardless of the unit’s status 

throughout the compliance period. It would be inequitable to take allocations from EGU owners that 

retire units as a result of this rule. EPA could require EGU owners to demonstrate the need for excess 

allocations, due to unit retirement, to be used by its EGU in another state for compliance. Without this 

demonstration for need, the excess allowances could be distributed to other units in the state where the 

retired unit is located. 

Under the proposed federal plan, a unit that does not operate for two consecutive years would receive 

allocations for four years after it ceases operation (page 211). This scheme does not account for units 

that were placed in an extended outage to address major equipment maintenance, or were mothballed 

for use at a future date. Units that have maintained their Title V and other environmental permits with a 

view to restarting in the future, and have undertaken preventative maintenance while in extended 

outage or mothballed condition, should not be penalized merely because of non-operation for a two 

year period. Accordingly, reviewer suggests that the criteria for retired units be revised such that the 

two-year, non-operation clock would run only under certain conditions.

Other General Comments

With regards to the output-based allocation, commenters recommend giving the allocation to all clean 

new and existing generation in addition to all existing natural gas generation—in other words, to all 

generation that results in lower emissions rather than higher emissions. This will (1) ensure that the full 

incentive to build new renewables and preserve existing zero-carbon generation will be maintained and 

(2) eliminate market distortions associated with the threshold-based allowance allocation

Commenters recommend that EPA take comment on a BB2 ERC approach that generates some fraction 

of ERCs through the reduction in steam generation (in contrast to the central proposal that only focuses 

28
on increases in natural gas generation). In particular, this could be accomplished through a pro-rated 

additional demand for ERCs placed on steam generation.

Commenters recommend that new nuclear power and uprates, distributed PV and offshore wind be 

among the creditable technologies under a rate-based plan

Commenters recommend that ERCs be issued as often as possible to provide the most information and 

certainty to markets. If this cannot be done for all types of ERCs, it should be straightforward to do for 

RE.

Commenters recommend that States under a mass-based federal plan be allowed to take advantage of 

the full 8-year averaging across the interim compliance period, especially in light of the lack of an RSV. 

States could convert to a state plan provided that they either are at a zero or positive bank or that they 

account for any borrowed emissions in their state plan.

Commenters understand that the ERC crediting mechanism will be established in the emission 

guidelines, so is it correct to assume that the proposed options for ERC crediting in the FP will be 

removed?

It would be helpful to have a clarification of the current thinking on the process for finalizing a federal 

plan for a state in terms of the notice and comment requirements, if any, and what that timeline would 

be.

Would it be possible to provide for EPA payment of verifiers (through fees assessed to energy efficiency 

developers) to avoid having developers themselves paying verifiers, and the incentive structure that 

creates?

Could EPA discuss how it will be assured that states with a rate-based FP approach would have sufficient 

access to ERCs?

Would it be possible for a state to choose to opt-in its new sources under a mass-based FP, perhaps by 

making the anti-leakage design element one of the places where a state could choose to make a design 

decision for the FP?

Other Specific Comments

1) Page 144, 235. “The EPA also requests comment on requiring monitoring and reporting of CO2

mass and net generation for the year before the initial compliance period begins, i.e., to 

commence January 1, 2021.”

Comment: Reviewer recommends requiring monitoring and reporting of CO2 mass and net 

generation for the year before the initial compliance period so the effects of the first year of the 

policy may be measured and analyzed and so that any kinks in processes can be ironed out 

before compliance obligations begin.

2) Page 180, 220. “The EPA requests comment on the proposed approach of recording allowances 

seven months prior to the start of each compliance period, and on an alternative of recording 

allowances 13 months prior to the start of each compliance period.”

29
Comment: Reviewer requests clarification on whether EGUs can use allowances from the next 

compliance period to comply with a current compliance period since allowances will be issued 

for the preceding compliance period either 7 or 13 months before the current compliance 

period ends.

Technical Comments

1) Page 48-49. Reviewer request clarification on the passages on page 48-49. Is there a difference 

between “EGUs” and “sources”? Does EPA intend to make a distinction in the direction of 

trading? If not, consider using “between” instead of “from”. 

“The EPA proposes that interstate ERC trading could occur both i) from affected EGUs in states 

covered by the rate-based trading federal plan to affected EGUs in states with approved ratebased trading state plans meeting the proposed conditions for linkages, and ii) from sources in 

such state-plan-covered states to sources in federal-plan-covered states.” 

2) Page 63. Reviewer recommends expanding use of the ISO/RTO Council to reliability coordinators 

and planning authorities because the IRC does not encompass all areas of the country.

3) Page 103: Reviewer also recommends on page 103 changing the signs on “EGU limit” and “EGU 

operating rate” in the numerator of the equation, so that if “ERC MWh” is calculated to be 

positive it indicates how many ERC need to be surrendered and if it is calculated to be negative 

it indicates the number of ERCS that are being generated. This will then make the sign of “ERC 

MWh” that need to be surrendered consistent with other equations in the preamble (for 

example on page 107).

4) Page 104. Reviewer recommends deleting the following sentence on page 104. The sentence is 

correct, but it contains the same information as the equation and text on the previous page, but 

it is stated in a way that requires careful review to determine that fact.

“The needed quantity of ERCs for any given amount of generation can be easily calculated by 

dividing the total emissions of the affected EGU by the applicable emission rate limit, and then 

subtracting the generation of the affected EGU.”

5) Page 104: Reviewer requests clarification on the meaning of pro-rata in the sentence: “To 

incentivize and capture the emission reductions of Building Block 2 of the CPP EGs, the EPA 

proposes in the federal plan that NGCC generation has the capability to generate ERCs on a prorata basis reflecting incremental NGCC generation. “

6) Page 106. Reviewer recommends clarifying the following, as it is not clear what is meant by 

“when the region reaches 75 percent summer time capacity...” does this mean, “when the 

interconnect region generation reaches the level that would be generated if all NGCCs in the 

region operated at a 75% capacity factor” ?

7) Page 124 & 127. Reviewer suggests clarification that ERCs in a compliance account are retired 

and no longer available for trade when used for compliance purposes, which follows current 

terminology in REC tracking systems:

“A compliance account would be the account in which any ERCs used by the affected EGU for 

compliance with the emissions limitations would have to be held until retired for compliance.” 

30
“Accordingly and if necessary, the appropriate number of ERCs will be deducted from retired in

the EGU’s compliance account to adjust the emission rate of the EGU to be equal to the 

emission standard.

8) Page 127. Reviewer recommends clarifying the source of the data for the “total pounds of CO2 

emitted over the compliance period” and “the net MWh of energy the affected EGU produced.” 

Reviewer recommends that the source of data be sufficiently verified to ensure accurate data.

9) Page 128. Reviewer recommends clarifying the difference between ERC unique serial numbers 

and tracking numbers.

10) Page 130. Reviewer recommends clarification of how text on page 130/131 differs from 

previously described EPA-administered Allowance Tracking and Compliance System. Is this an 

alternative or additional tracking system for RE facilities or for EM&V?

“The EPA is proposing that the agency will establish a tracking system for administering the rule 

that provides for transparent access to RE project and program eligibility applications and 

regulatory approvals as well as information on ERC transfers and third party verifiers (third party 

verifiers are further discussed below as part of Evaluation, Measurement and Verification).”

11) Page 131. Reviewer supports EPA’s ability to designate an agent to coordinate project 

applications to prevent burdening the agency with these tasks which can be accomplished by 

other groups. “It is proposed that EPA may designate an agent to coordinate the project 

application process and assist with review of applications.”

12) Page 132. Reviewer seeks clarification on whether the text on page 132 indicates when facilities 

may apply for approval to generate ERCS versus actually issuing ERCs. 

“The agency is proposing that ERC issuance applications will be accepted after the beginning of 

the first compliance period, as soon as the agency is able to establish an application process, 

and that applications will be accepted on a periodic basis, either quarterly or semi-annually. 

These applications will be accepted through the entirety of all compliance periods.”

13) Page 133. There is a reference to the “clean energy investment pool” here, which is the only 

time that is mentioned. Reviewer suggests the discussion be extended to explain more about 

how it works. In addition, reviewer suggests including a discussion of this in the mass-based 

plan section, which would reduce confusion about why the rate-based plan discusses “massbased allowances.” 

14) Page 139. Reviewer recommends clarifying that when calculating the number of ERCs needed to 

be in compliance, the Adjusted Emission Rate must equal the Emission Standard in the first 

equation.

AAAAAAAAAAAAAAAA EEEEEE EEEEEE RRRR = MM oo CCCC2 (llll )

GG GG (MMMMh) + MMMMh EERRCC = EEEEEE EEEEEE SS

Reviewer also recommends the following edit to the second equation because the adjusted 

emission rate may not equal the emission standard for EGUs that are out of compliance. 

31
MMMMh EE = MM oo CCCC2 (llll )

EEEEEE EEEEEE SS ( llll

MMMMh)

− GG GG (MMMMh)

15) Page 160. Reviewer recommends the following edit on page 160 since the initial allowance 

allocation can affect the overall environmental results if emissions from non-covered sources 

are considered.

“The initial allowance allocation approach does not affect the environmental results of the 

program or generation patterns, except as it effects generation shifts between covered and uncovered sources.”

16) Page 167. Reviewer recommends clarifying (step 3) that EGUs that generated in 2010-2012, but 

that are no longer operating, have their generation be removed from the sum total of historical 

generation and not be awarded allowances. 

17) Page 181. Reviewer recommends the following text because there is some risk of leakage to 

new sources under a rate based standard depending on the level at which the rate is set.

“This risk is not as great or is not present, depending on the difference between the intensity of 

a new unaffected source and the performance emission rate, present for existing EGUs under a 

rate-based plan...”

18) Page 186. In the federal plan, reviewer recommends accounting for lost large zero carbon 

generation by subtracting the lost generation in the denominator of the rate-based compliance 

calculation for the state beginning in the year that the EGU goes offline.

19) Page 196-197. Reviewer recommends that EPA include an equation in addition to the text on 

these pages that explains how the number of allowances in the set-aside is calculated. 

Reviewer’s understanding from the section is that Allowances in Set-Aside = 98% of Total 

Allowances x Allocation Rate x 2014 NGCC Generation between 50% Capacity Factor and 70% 

Capacity Factor, but there are certain places in the text where this is not clear.

20) Page 235. Reviewer recommends updating the reference to MATS to reflect recent court 

decisions. 

21) Page 259. Reviewer recommends adding to the list of completeness criteria discussed on Pg. 259 

the 111(d) plan requirement regarding demonstrating that the state has consulted with the 

planning authority/reliability coordinator.

22) Reviewer recommends that the structure of the rate plan and mass plan, in terms of headers 

and content, should be roughly parallel. 

Typographical Comments

1) Page 52: Reviewer recommends revising the following sentence to infer that application of ERCs 

could be submitted to agent of EPA running a tracking system. (Page 52 and throughout text).

32
“This demonstration must be included as part of the project application for ERC issuance to the 

EPA or its agent from the RE provider in the mass-based state.”

2) Page 53: Reviewer recommends the following edit because there are cases where RE located in 

a mass state can be counted in a rate state.

“Under the proposed mass-based approach there is a restriction to counting RE that is located in 

a mass state in a rate-based system:, if RE providers that receive mass-based set-aside 

allowances for their generation. In this case RE generation is are barred from being issued having

ERCs issued for that generation in a rate-based state.”

3) Page 54: A sentence says “remain under the mass, thereby” which is missing a word after 

“mass” 

4) Page 71: Harmonize language to use either “step-down approach” or “glide path”– the latter 

was used exclusively in the preamble and it is suggested that this language be made consistent 

here and throughout the text: “At that point, the agency is using a step-down approach, or glide 

path...”

5) Page 101: Reviewer recommends revising the emissions standards in the table to match those in 

the redline preamble. 

6) Page 104: “Through Building Block 2 there is a call to shift represents shifting generation from 

fossil steam EGUs to NGCCs because NGCCs generate electricity at a lower carbon intensity and, 

thus, reduces CO2 emissions for the same level of generation”

7) Page 107: “The NGCC is subject to a final period emission rate limit of 780 lbs CO2/MWh. Since 

the NGCC is always subject to its NGCC emission rate limit of 780 lbs/MWh and it is operating at 

a rate above that limit it will owe non-BB2 ERCs for all generation”

8) Page 107: Reviewer recommends editing the variable name in the second equation to be 

consistent with elsewhere in the text. NGCC Generation * BB2 ERC Generating Factor on Rate = 

BB2 ERCs

9) Page 110: Reviewer recommends the following edit.

“This treatment for eligible measure types is also proposed for the set-aside for RE that is part of 

the proposed mas-based implementation approach in the federal plan,...”

10) Page 111: Reviewer recommends striking this comment because it should not be a relevant 

consideration for ERC generation eligibility purposes: “These technologies are also expected to 

be able to deploy on an economic basis during the compliance period, as discussed in the final 

EGs (see Sec. V.E.6).”

11) Page 142: “The EPA would require that ERC emissions generation data be reported to the EPA 

quarterly starting on April 30, 2022, and continuing every three months thereafter (i.e., the 30th 

of April, July, October, and January).”

33
12) Page 152 and Page 154: Reviewer suggests clarifying the terminology “interim compliance 

period” because the EG tends to use that phrase to denote the entire eight year period between 

2022 and 2029 whereas the federal plan states that the interim compliance represents the three 

and two year periods within that 8 year span. The EG refers to the periods of three and two 

years as interim steps. Reviewer recommends that this should be done throughout the text.

13) Page 159: Reviewer recommends including a discussion of designated representatives in both 

the rate-based and mass-based sections (currently it is just in the rate-based section). 

14) Page 175: It appears there is an unnecessary “The EPA requests” at the start of the first fill 

paragraph. 

15) Page 202: “The EPA is proposing that five percent of allowances will be reserved from the 

allocation for each state for the purpose of the set-aside.” Reviewer believes this should be 2 

percent, based on earlier language.

34
Attachment C.

35
From: Frey, Nathan J. <Nathan_J._Frey@omb.eop.gov>

Sent: Saturday, July 25, 2015 5:36 PM

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

Cc: Szabo, Aaron; Grossman, Andrea

Subject: Summary of Interagency Comments Under EO 12866 and 13563 ‐‐ Federal Plan Requirements

for GHG emissions from EGUs; Model Trading Rule

  

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

NPRM, Federal Plan Requirements for Greenhouse Gas Emissions from Electric Utility Generating Units

Constructed on or Before January 8, 2014; Model Trading Rule.

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

Nathan

36
Attachment C.1

37
a. Set-asides for Output-based Allocation 

The EPA is proposing a set-aside approach referred to as 

output-based allocation, which provides targeted allocations of a 

limited portion of allowances to existing NGCC and zero-emitting 

units as a means of mitigating emissions leakage to new units or 

existing units covered by a rate-based plan in a neighboring state. 

The EPA believes that this proposed set-aside would help ensure 

the environmental integrity of a mass-based plan, and could 

potentially reduce costs, and address incentives for generation to 

shift away from EGUs covered under mass-based plans to new 

unaffected EGUs or EGUs in rate-based states. We seek comment on 

all aspects of this proposal and its underlying rationale. 

Under the output-based allocation approach we are proposing, 

some of the total allowances within each mass-based state are 

allocated to existing NGCC and zero-emitting units based, in part, 

on their level of electricity generation in a recent period. The 

allocation to an eligible EGU is not fixed, but instead depends on 

its generation multiplied by a constant factor. Each eligible EGU 

may would get a larger allowance allocation if it generates more

such that owner/operators of eligible EGUs will have an incentive 

to generate more in order to receive more allowances, making them 

more competitive than they would be without the set-aside. Because 

38
the total number of allowances is limited, this allocation approach 

will not exceed the overall emission goal; instead, it merely 

modifies the distribution of allowances in a manner designed to 

mitigate emission leakage. 

Output-based allocation provides an incentive for eligible 

EGUs in mass-based states to increase their generation in order to 

increase their allocation of allowances. This incentive helps 

align the generation incentives for eligible EGUs in mass-based 

states with new EGUs within mass-based states that are not subject 

to the mass-based limits as well as analogous EGUs in other states 

covered by emission rate limits, mitigating emissions leakage. The 

EPA also solicits comment on another potential ancillary benefit 

of this set-aside: mitigating electricity price impacts associated 

with the proposed federal plan -- recognizing that this rate and 

bill impacts can also be achieved mitigated through other 

mechanisms. Output-based allocation lowers the marginal production 

cost of eligible EGUs. Therefore, if these EGUs influence 

electricity prices, the reduction in their production costs will 

place downward pressure on the electricity price. In the specific 

situation where eligible EGUs are in cost-of-service regions, the 

effect on electricity prices would depend on the relative cost of 

producing electricity from these EGUs relative to the cost of 

procuring power from EGUs subject to emission rate standards. 

39
It is important that the output-based allocation approach be 

designed to avoid unintended consequences. In particular, the 

design should reflect the fact that its application mayavoid, to 

the extent possible, any reduction ine the incentives to invest in 

maintainingmaintain or invest in existing orand adding new zeroor low-emitting generation as a result of the downward pressure it 

the allocation scheme may place on electricity prices. We take 

comment on whether and to what extent aAwarding allowances to new 

zero-emitting generation as well as existing zero-emitting 

generation and existing NGCC units wshould have this result, and 

whether additional allowance allocations to these resources are 

necessary.

Furthermore, providing too strong a generation incentive to

affected EGUs eligible for the set-aside could increase total 

electricity production costs. Specifically, if applied too 

strongly, output-based allocation can go beyond the alignment of 

incentives across similar EGUs and lead to undesirable differences 

in incentives in the other direction. For example, if eligible 

affected EGUs receive too a large number of allowances for each 

MWh of generation this could incentivize generation that is high 

cost, exclusive of the cost associated with obtaining the massbased emission limit, and disincentivize lower-cost generation 

subject to emission rate standards. This could raise the total 

40
cost of achieving overall emission levels with relatively little 

environmental benefit. The output-based allocation set-aside 

should be designed to address these economic concerns. 

The EPA accordingly solicits comment on key parameters for 

the appropriate design of the output-based allocation approach 

used for this proposed set-aside. Key parameters to be identified 

under the output-based allocation approach include which affected 

EGUs and other sources receive the allocation, the vintage for 

allowances, the allocation rate(s), and the size of the set-aside. 

EPA solicits comment on what other key parameters may be relevant 

for design of an appropriate output-based set-aside. 

The EPA first solicits comment on which EGUs should be

eligible to receive output-based allocation from the set-aside. 

The EPA proposes that only NGCC units subject to the final 

emissions guidelines and zero-emitting sourcesgeneration receive 

output-based allocation from the set-aside, subject to limitations 

described below. The EPA recognizes that performance of outputbased allocation may be improved by targeting which units receive 

this additional incentive. In particular, this approach can most 

effectively address emission leakage if targeted to those affected 

EGUs that face the greatest difference in their incentive to 

generate relative to otherwise similar EGUs subject to emission 

rate standards. As noted in the discussion of the allocation rate 

41
below, new combustion turbines would be expected to generate more 

absent this set-aside. Therefore, the difference in generation 

incentives between affected stationary combustion turbines under 

mass-based implementation and otherwise similar new stationary 

combustion turbines subject to the 111(b) standards is likely one 

of the most salient deviations in production incentives to address.

However, as noted above, it is important to retain incentives for 

zero-emittingclean generation even as the incentive difference 

between affected and new NGCC sources is decreased.

As discussed further below, under this proposal other 

affected EGUs , and EGUs not subject to the emissions guidelines, 

would not receive output-based allocations from this set-aside. 

Below we also take comment on whether sources other than combustion 

turbines sources subject to the emissions guidelinesthose 

mentioned here should be eligible for output-based allocations 

under this set-aside. 

Second, EPA requests comment on options for the allocation 

rate under this approach. The allocation rate is the emissionsequivalent number of allowances that an eligible EGU receives per 

one net MWh of generation eligible for the set-aside. In 

particular, we request comment on setting the allocation rate equal 

to the emissions rate of an advanced NGCC generator, in order to 

align the generation incentives across EGUs eligible for the set42
aside and the type of new emitting source that would generate more 

absent this set-aside [&&&REF]. We also specifically take comment 

on using a value such as 850 lbs/MWh-net or any other value. We 

additionally take comment on setting the allocation rate equal to 

the emission rate standard (on a net-basis) for new stationary 

combustion turbines under 111(b). With all these choices, any 

additional MWh of eligible generation would earn allowances equal 

to the emissions rate chosen here. In particular, all eligible 

sources would receive an equal allocation per MWh to ensure that 

the allocation does not introduce further distortions into the 

market.

In addition to an allocation to all eligible generation 

described above, The the EPA also proposesFor the portion of the 

updated generation-based allocation described above dedicated to 

existing NGCC generation, EPA takes comment on an alternatethat 

this approach be that is targeted towards marginal generation by 

only providing, in addition to allocations to zero-emitting 

generation , allocations to existing NGCC under this set-aside 

only to the portion of generation from eligible existing NGCC 

unitsEGUs that exceeds a certain average capacity factor over the 

compliance period. The allocation rate would only apply above a 

particular average capacity factor because it is intended to 

incentivize marginal generation and not generation that would have 

43
otherwise occurred absent the output-based allocation from the 

set-aside. Under this approach, eligible affected EGUs would 

receive no allowances from this set-aside for generation below 

this average capacity factor (although all affected EGUs will still 

receive allowances through the default allocation approach and any 

applicable set-aside). This approach avoids incentivizing 

production at lower levels of generation from an eligible source, 

and therefore avoids discouraging a relatively inefficient or 

infrequently used EGU from retiring.1 The EPA proposes takes 

comment on an approach under whichthe idea that each existing 

NGCCEGU eligible for the set-aside would receive output-based 

allocation at the allocation rate only if its average capacity 

factor in the compliance period is above 50 percent on a net-basis 

[&&& check net]. Furthermore, under such an approach, we propose 

take comment on, under such an approach, the idea that each 

eligible EGU existing NGCC receivinges allowances at the 

allocation rate for all generation above an average capacity factor 

of 50 percent. That is, there would be no “maximum” average 

capacity factor above which output-based allocations are not 

1 As discussed below, if a source would no longer receive allowance allocations 

after it retires it would be discouraged from retiring, which may increase total 

production costs. The logic for not providing output-based allocations to 

sources with low capacity-factors is the same, although the strength of the 

incentive to not retire is lower for output-based allocation than it is when 

the entire allocation to the source may be forfeit through retirement.

44
earned by an EGU eligible to receive them.2 This is to maintain 

the marginal incentive to generate from the affected EGU. (The 

total number of allowances available in the set-aside is limited, 

however, as described below.) EPA takes comments on the 

implications of this approachoption towardsfor the operation and 

efficiency of electricity markets. EPA also takes comment on 

whether to apply this approach to other eligible sources.

NextThird, the EPA solicits comment on selection of a source 

of allowances that is a specific vintage for allocation. This key 

parameter determines which compliance period’s allocation is 

distributed based, in part, on current period generation. 

Alternatives include the current compliance period’s allocation, 

which is the period in which the eligible generation occurs, and 

a future compliance period’s allocation. If allowances are 

allocated from a future period’s allocation, affected EGUseligible 

sources can receive additional allowances in a given future period, 

based on their additional generation in the current compliance 

period. 

Both approaches create an incentive to increase generation in 

the current compliance period to secure additional allowances; the 

difference is in when those allowances may be used. Allocating 

2 Effectively, the allocation rate of output-based allocation is zero up until 

this average capacity factor. 

45
current compliance period allowances based on current year 

generation may create uncertainty in that affected EGUs may not 

know if they will be allocated sufficient allowances to cover their 

emissions or will have to buy allowances, because their total 

allocation will not be fixed until the end of the period when their 

cumulative generation is known. Therefore, an advantage of 

allocating allowances from a future compliance period is that 

affected EGUs will know ex-ante how many allowances they will be 

allocated in a given period. However, if there is an expectation 

that the federal plan will be replaced by a state plan in the 

future compliance period, the incentive to respond to output-based 

allocations is potentially diminished. The longer the lag between 

the eligible generation and the output-based allocation, the 

greater the potential for uncertainty to lower the incentive 

associated with output-based allocation. At the same time, the 

ultimate effect of output-based allocation timing will also depend 

on expectations about future allowance prices relative to current 

prices and the degree to which the banking of allowances is 

permitted. 

Weighing these observations, the EPA specifically proposes 

allocating allowances based on generation from eligible EGUs in 

the preceding compliance period. In the first compliance period of 

the federal plan, allowances allocated to affected eligible EGUs 

46
would be distributed per the historic-generation-based approach 

described above (with no further adjustment). The EPA also requests 

comment on other approaches to selecting a vintage (or vintages) 

for allocating allowances for an output-based allocation setaside.

Further, we request comment on options for the allocation 

rate under this approach. The allocation rate is the emissionsequivalent number of allowances that the affected EGU receives per 

one net MWh of generation eligible for the set-aside. In 

particular, we request comment on setting the allocation rate equal 

to the emission rate standard (on a net-basis) for new stationary 

combustion turbines under 111(b). ), in order to align the 

generation incentives across EGUs eligible for the set-aside and 

the type of new emitting source that would generate more absent 

this set-aside [&&&REF]. Specifically, an additional MWh of 

eligible generation would earn the affected EGU allowances equal 

to the level of emissions permitted per MWh of net generation under 

the 111(b) new source standard, which is &&&___lb/MWh-net.

The EPA proposes to calculate allocations to NGCC units from 

the output-based set-aside using data from the preceding 

compliance period. For example, the EPA would calculate set-aside 

allowances for the second compliance period (2025 through 2027) 

based on data from 2022 through 2024. Each NGCC-unit affected EGU 

47
with an average capacity factor above 50 percent in the preceding 

compliance period would earn set-aside allowances. 

In the scenarioapproach based on a unit’s capacity factor, 

The the EPA proposes to calculatetakes comment on calculating an 

NGCC unit’sthe capacity factor based on the previous compliance 

period’s net generation and net summer capacity of the unit. The 

EPA is proposing to require affected EGUs to report net generation 

to the agency (see section V.H for proposed monitoring and 

reporting requirements).3 The EPA proposes takes comment onto

usinge net summer capacity as reported to EIA. In the alternative, 

the EPA proposes takes comment onto requiringe that NGCC units 

report net summer capacity directly to EPA; we would add EGU-level 

net summer capacity as a required data field in the certificate of 

registration that a unit’s owner/operator would submit to the 

agency per the procedure detailed in section V.G. The EPA requests 

comment on the relative efficiency of obtaining net summer capacity 

from data reported to EIA or of adding net summer capacity as a 

required data field on the certificate of registration. The EPA 

also requests comment on an alternative approach of basing the 

capacity-factor calculation on nameplate capacity instead of net 

summer capacity. 

3 The EPA proposes to make the reported generation data available to the public 

on the agency’s website.

48
After identifying NGCC units with average capacity factor 

above 50 percent the EPA would then calculate the amount of 

allowances these affected EGUs would receive from the output-based 

set-aside as the unit’s net generation in the preceding compliance 

period multiplied by the 111(b) rate standard for NGCC units of 

&&&__lb/MWh-netthe emissionsallocation rate of the NGCC unit. (The 

proposed approach to determine the size of the set-aside is 

detailed below.) 

The EPA proposes to provide notice of the capacity and 

generation data used, and the resulting allocations, by August 1 

of the first year in each compliance period, e.g., by August 1, 

2025 for the compliance period that commences in 2025. The agency 

proposes to provide 30 days for comment on the data and 

allocations, until August 31, and to provide notice of the final 

set-aside allocations by November 1 of the same year and record 

the allocations in the source accounts at that time. The EPA 

requests comment on other approaches to providing notice of the 

data and allocations. 

The EPA requests comment on all aspects of the proposed 

approach to calculate output-based set-aside allocations. Further 

details of the proposed approach are in the Allowance Allocation 

Proposed Rule TSD in the docket. 

The EPA proposes a particular size of the set-aside that is 

49
based on the total allocation, the allocation rate, the capacity 

factor above which eligible generation may receive the outputbased allocations, and an average capacity factor across all 

sources potentially eligible for allowances from the set-aside. In 

particular, EPA proposes that the share of the total used for the 

set-aside be equal to the allocation rate, multiplied by the amount 

of potential generation from all EGUs eligible for the set aside

in the state above an average capacity factor of 50 percent and 

below an average capacity factor of 70 percent, based on 2014 data 

as detailed below.4 The 50 percent average capacity factor is the 

capacity factor above which eligible generation may receive the 

output-based allocations. The 70 percent capacity factor limits 

the size of this set-aside, which increases the share of the 

allowances allocated based on historic-generation [&&& section 

V.D.1]. Maintaining a large share of allowances allocated based on 

historic generation provides all EGUs subject to the mass-based 

plan certainty in their allowance allocation. Furthermore, 

limiting the size of the set-aside avoids the risk of incentivizing 

too much generation from eligible sources.

The EPA proposes to determine the size of the output-based 

set-aside for each state using data reported to EIA for the year 

4 The capacity eligible for the set-aside would be determined from data provided 

at the end of the previous compliance period. 

50
2014. The EPA would calculate the size of the set-aside as based 

on the sum of net generation from NGCC-unit affected EGUs that 

operated above 50 percent and below 70 percent capacity factor 

eligible sources in 2014 multiplied by the the 111(b) rate 

standardemissionsallocation rate for of the NGCC units of &&&___ 

lb/MWh-net.5 The set-asides resulting from this proposed approach

using an allocation rate of 850 lbs/MWh-net are shown in Table 

&&&. The set-asides in the table would apply to every compliance 

period except for the first compliance period for which there would 

be no output-based set-aside. Although the size of the set-aside 

would remain the same for each compliance period, as the mass goals 

decrease with each step in the Interim Period and to the Final 

Period, the set-asides would constitute an increasing share of a 

state’s mass goal. The Allowance Allocation Proposed Rule TSD 

further details the proposed approach to determine the size of the 

set-aside. 

Table &&&. Proposed Size of Output-based Set-aside 

(Metric Tons) 

State Allowances in Output-based Setaside 

(Metric Tons)

5 Using net summer capacity and net generation data for 2014 as reported by 

facilities to EIA.

51
The EPA proposes to determine the size of the output-based 

set-aside once, before the start of the program, and not to change 

the size. The EPA also requests comment on updating the size of 

the set-aside once after the start of the Final Period using data 

from 2030 or another year, and also seeks comment on updating the 

size of the set-aside more than once after 2030, for example every 

six or eight years. If the EPA updated the size of the set-aside, 

we would provide notice of the data upon which we intended to rely 

and opportunity for comment; the EPA requests comment on this 

approach. 

Given the proposed limit on the total size of the set-aside, 

and the amount of potential generation eligible for the set aside, 

there may be fewer allowances available in the set aside than can 

be earned at the allocation rate. The EPA proposes that, if the 

amount of total generation eligible for the set aside multiplied 

by the allocation rate exceeds the size of this set-aside, then 

the allowances in this set-aside would be allocated to eligible 

generation on a pro-rata basis. 

We propose that if the number of allowances allocated from 

the set aside is less than the size of this set-aside, then the 

remaining allowances would be distributed to all EGUs using the

52
historic-generation based-approach described above. 

The EPA also requests comment on extending output-based 

allocation from this set aside to affected utility boilers. Outputbased allocation for steam generating units may increase 

generation subject to the mass limit, leading to reduced generation 

from new emitting sources. However, the EPA does not propose this 

approach because it is not as effective as output-based allocation. 

This is because output-based allocation to utility boilers would 

incentivize generation from relatively high-emitting EGUs, thereby 

leading to high allowance prices, which then counteracts the effect 

of lowering the cost of production of sources subject to the 

proposed mass-based plan.6 

The EPA solicits comment on the general merits of the proposed 

set-aside and the output-based allocation used under this setaside. In addition, the agency solicits comment on how such an 

approach could be targeted to improve implementation of the 

proposed mass-based trading federal plans and improve overall 

environmental and economic performance. In particular, the EPA 

solicits comment on which affected EGUs and other generation 

sources should receive any output-based allocation, the proper 

6 This effect on the allowance price is also present when output-based allocation 

is limited to NGCC units, but because NGCC units have a lower emissions rate 

the effect is not as strong.

53
allocation rate(s), the total size of the set-aside, and from which 

compliance period’s total allowances the set-aside should be 

drawn. 

54
Attachment D.

55
From: Jones, Toni <Jones.Toni@epa.gov>

Sent: Monday, July 27, 2015 4:55 PM

To: Frey, Nathan J.

Cc: Culligan, Kevin; Harvey, Reid; Tsirigotis, Peter; Eck, Janet; Cozzie, David

Subject: EO 12866 CPP Federal Plan ‐ response to comments

  

Hi Nathan,

I hope this email finds you well.  Attached, please find a redline version of the Federal Plan preamble for

the Clean Power Plan that reflects changes made to the package since the initial submittal to OMB.  Also

attached is the federal plan rule text and a document that details responses to OMB comments received

on the rule package.   File names for the attachments are:

  

‐ Redline version of the preamble: EO12866_CPP Federal

Plan_2060_AS47_NPRM>20150727_RLSO.docx

‐ Rule text: CPP Federal Plan Model Rule OMB 7_27_15 clean.docx

‐ Responses to OMB comments: EO12866 13563 Federal Plan NPRM Response to OMB

Comments 072715.docx

  

If you have any questions, please do not hesitate to contact me.

Kind regards,

Toni W. Jones

  

Toni Wyche Jones, EI, CFM | Fuels & Incineration Group | Sector Policies & Programs Division - Mail Code E143-

05 | Office of Air Quality Planning & Standards | U.S. Environmental Protection Agency | RTP, NC 27711 | Phone: 

(919) 541-0316 |

  

56
Attachment D.1

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment D.1.

57
Attachment D.2

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment D.2.

58
Attachment D.3

59
RIN 2060-AS47 

Federal Plan Requirements for Greenhouse Gas Emissions from Electric Utility Generating Units 

Constructed on or Before January 8, 2014; Model Trading Rules; Amendments to Framework 

Regulations

1) Mass. Reviewer recommends that EPA propose only a mass-based plan for the federal plan. To 

the extent that some states may select a state rate-based plan, reviewer recommends leaving in 

the requirements necessary to submit an approvable state rate-based plan as a model ratebased trading rule. If EPA does propose both, reviewer recommends putting the mass-based 

implementation approach before the rate approach, making their discussion and outline 

parallel, and highlighting the lower administrative burden for mass-based plans with respect to 

allowance tracking compared to rate-based plans with respect to ERC generation and tracking.

Reviewer notes that given EPA’s stated view that it would like to enable as much trading 

between states as possible (which would be enhanced by coordination on mass vs rate), there is 

value in proposing only a mass-based plan now rather than a year from now when the states 

have to submit initial plans.

Response: The EPA disagrees that only the mass based approach should be proposed. There are some 

benefits and drawbacks to either approach. In addition, the proposed FP serves as a model trading rule, 

and states are interested in seeing, and potentially using, models for both a rate and mass based 

approach. We have made changes in the preamble to more clearly indicate our intention to finalize a 

single approach for all states that receive a FP. We request comment on which approach should be 

selected. The agency is interested in the preferences that will be expressed by commenters as to which 

approach they prefer.

2) Technology Neutral. Reviewer recommends proposing (rather than taking comment on) that all 

non-BSER technologies and measures that are acceptable to generate ERCs in the emission 

guidelines (EGs) be proposed as approved under a federal plan. That would include, but not be 

limited to, distributed RE generation, demand side energy efficiency, new or up-rated nuclear 

generation, offshore wind, and CCS retrofits. Not allowing certain abatement measures to be 

credited reduces the cost effectiveness of the policy. EM&V requirements for state plans on 

non-BSER technologies are the same as the requirements for the federal plan, so comments 

should be requested on the EM&V methodologies, and not on which technologies and measures 

should be valid compliance mechanisms. Reviewer also notes that EPA takes comment on what 

the process should be for demonstrating the “appropriateness” of additional technologies, but 

never explains what the “appropriateness” standard requires. All technologies and measures 

could be held to a strict standard to be quantifiable, verifiable, and additional. Any technology 

or measure that can pass the requirements should be permitted to generate credits under a 

federal plan. 

Response: The feasibility of federal implementation is a key concern, and thus the EPA is proposing to 

only include non-distributed RE and new or up-rated generation due to requirements and rigor needed 

to ensure the quality of data and emission reductions achieved through the other described ERC 

generating resources.

60
Reviewer recommends that the allowances that are set-aside for low- or zero-emission activities 

be distributed using a technology-neutral methodology and not reserved exclusively for RE. 

(Reviewer notes that selecting only RE for a set aside, as suggested in the current version of the 

plan, is selecting particular technologies without sufficient justification.) Reviewer suggests that 

EPA take comment on a proposed federal plan that is technology neutral. Reviewer also 

recommends renaming this group of allowances as the Clean Energy Set-Aside to avoid 

confusion with the set-aside for existing NGCC. 

It should be explicitly stated on pages 99, 103 and 110-120 that incremental, new nuclear after 

2012 should be afforded equal treatment with renewable energy under this rulemaking 

consistent with the final Clean Power Plan. The nuclear units that are currently under 

construction represent a significant amount of zero-emitting baseload capacity that should be 

allowed to create ERCs in the federal plan and model trading rule. 

Response: The preamble text is being revised to recognize incremental nuclear power and nuclear uprates, as recognized under the final emission guidelines, as an eligible technology for ERC issuance under 

the rate-based federal plan approach. Aside from the recognition of qualifying nuclear, the EPA 

disagrees with the approach for recognizing all emission reductions measures eligible under the final 

emission guidelines for ERC issuance under a rate-based federal plan. In the context of the federal plan, 

the feasibility of federal implementation is a key concern, and thus we propose technologies that are 

widely demonstrated and provide the simplest path for EM&V implementation under a federal plan. We 

seek comment on how to implement the EM&V requirements for various technologies proposed in the 

federal plan, and how that could be implemented in the context of the final rule. We also seek comment 

on a process by which technologies can be determined to be eligible. The EPA notes that states that 

wish to have the ability to recognize all the eligible technologies under the final guidelines have the 

opportunity to submit an approvable state plan that does so. 

The same applies to set-asides under the mass plan approach. Incremental nuclear power and nuclear 

up-rates are not recognized under the set-aside because they do not face the same economic 

circumstances as RE capacity, and are not effectively addressed by the incentive provided by a set-aside. 

3) Set-aside. Reviewer recommends that the RE set-aside be changed in the proposed federal plan 

such that allowances be set aside for low- and zero-emitting generation and be distributed to 

those low- and zero-emitting EGUs or projects in the first two interim compliance periods (i.e., 

2022-2024 and 2025-2027) in proportion to the incremental generation of those EGUs or 

projects during the 2020 and 2021 years (relative to historic generation between 2010 and 

2012). This would have the added benefit of incentivize clean energy builds in 2020 and 2021.

Response: The preamble language is being revised to reflect in more detail the role that the Clean 

Energy Incentive Program would play in recognizing pre-compliance emission reductions in both the 

rate-based and mass-based approaches. This program includes the creation of mass-based set-asides 

that recognize RE and EE impacts on emission reductions in 2020 and 2021. 

4) ERC Issuance to NGCC. Reviewer recommends clarifying the formula for calculating ERC 

issuance from NGCC because the current formula and data available in previously released TSDs 

do not enable the reviewer to arrive at the same result of 0.09 ERCs/MWh NGCC. 

61
Response: There will be a separate TSD that describes how the gas shift ERC (GS-ERC) rate was 

calculated. 

General Comments

1) Page 12, 85, “The EPA is strongly considering taking a single approach (i.e., either the massbased or rate-based approach) for every state in which it promulgates a federal plan, and we are 

inviting comment on this. We also invite comment on which approach, mass-based or ratebased, should be selected if we opt to finalize a single approach.”

Comment: Reviewer recommends that EPA propose only a mass-based plan for the federal plan. 

To the extent that some states may select a state rate-based plan, reviewer recommends 

leaving in the requirements necessary to submit an approvable state rate-based plan as a model 

rate-based trading rule. Reviewer also recommends putting the mass-based implementation 

approach before the rate approach, making their discussion and outline parallel, and 

highlighting the lower administrative burden for mass-based plans with respect to allowance 

tracking compared to rate-based plans with respect to ERC generation and tracking. Reviewer 

notes that given EPA’s stated view that it would like to enable as much trading between states 

as possible (which would be enhanced by coordination on mass vs rate), there is value in 

proposing only a mass-based plan now rather than a year from now when the states have to 

submit initial plans. 

Response: We are proposing approaches to allow the public the opportunity to provide comments and 

information that will allow the EPA to make a more informed decision for finalizing the rule. 

2) Page 147, 224. “The EPA requests comment on whether there are reasons that a state should 

be allowed to transition from a federal plan to a state plan in the middle of a compliance period 

and if so what requirements should be put in place to do so while ensuring the integrity of both 

the federal plan and the state plan and while enabling the affected EGUs covered by the plans to 

understand and meet their compliance requirements.”

Comment: Reviewer recommends that states not be allowed to switch plans within a 

compliance period (either from a state plan to a federal plan or from a federal plan to a state 

plan) because, in rate-based plans, that would greatly complicate compliance given differences 

in ERC generation options between the Federal plan and possible state plans or, in mass-based 

plans, the federal plan allocates all allowances for the compliance period at the beginning of the 

period. 

Reviewer also recommends that any state that switches between a federal plan and a state plan 

or a rate plan and a mass plan needs to demonstrate a strategy for accounting for banked 

ERCs/Allowances that maintains the environmental integrity of the program. 

Response: The EPA generally agrees with this comment and will give further consideration after review 

of all public comments and information submitted post-proposal. 

3) Page 175. “The agency requests comment on the idea of auctioning all, or a portion of, each 

state’s allowances in the proposed federal plan, on how much of each state’s allowances to 

auction if not the entire amount, on the frequency (e.g., yearly or every few years), design of 

auctions (e.g., spot or advance) and who may participate in the auction.”

62
Comment: Reviewer recommends that the Federal mass-based plan encourage (but not require) 

states to auction at least a portion of their allowances instead of freely allocating all of them to 

affected EGUs and the set-aside. Periodic auctions are done in many other mass-based 

environmental compliance programs (California’s AB32, RGGI, the EU Emission Trading Program) 

because they facilitate allowance price discovery by market participants and allow for the 

efficient distribution of allowances. Reviewer acknowledges that EPA may not be able to run the 

auction on behalf of states, but reviewer recommends that EPA set up the auction infrastructure 

– for example, by establishing a turnkey auction platform with one of the many auction platform 

providers on the market – that can be used by states who choose to adopt the federal plan or a 

state plan. Reviewer recommends that the auctions should be online, multi-round, uniform 

price auctions. A standard auction platform would reduce transaction costs for EGUs that 

operate across multiple states as well as reduce the likelihood of technical glitches in some state 

auctions.

Response: The proposal provides that states may choose to determine their own allocation approach 

using a partial state plan, and may choose to conduct auctions. The proposal does not specify design of a 

state’s auction. In taking comment on the design of the auction for a federal plan as a general matter, 

the identification of the winning bid is now provided as an example of a specific relevant auction design 

feature. 

4) Page 215 – 216. “The EPA requests comment on this proposed approach for addressing leakage 

in a state allowance-distribution methodology and on any other approaches for doing so.... In 

this federal plan proposal, the EPA requests comment on an alternative option where a state 

that chooses to submit a state allowance-distribution methodology could provide a 

demonstration that leakage will not occur (without implementing the allocation strategies 

specified here) due to specific characteristics of the state.”

Comment: Reviewer recommends that the federal mass-based plan include an option whereby 

new NGCC is included under the mass goal as a mechanism for addressing leakage. Such an 

example would include the methodology for adjusting the state mass goal to reflect emissions 

from new NGCC.

Response: The agency has concerns about the legal viability of that approach. New sources will be 

subject to a separate NSPS under section 111(b). While the Emission guidelines recognize that states 

may cover new sources, so long as the 111(d) requirements for existing sources are met, the agency 

does not believe the same approach is available to EPA in a federal plan. On a related but different topic, 

EPA will re-propose in this rulemaking an interpretation of the effect of modifications or reconstructions 

by existing sources covered under section 111(d), and invite comment on the issue. This is to clarify an 

interpretive issue that was raised in the CPP proposal but not finalized. EPA may through this process be 

able to revisit the question of whether new sources can be covered in a federal 111(d) program, 

although, again, the agency does not believe at this stage that this is likely to be viable. 

 

5) Page 223. “The EPA requests comment on other approaches to provide a smooth transition 

from federal-plan implementation to implementation by state plans, and on its proposed 

approach of not replacing a federal plan for any compliance period for which allowances were 

already recorded.”

Comment: Reviewer agrees that switching between plan types should not be allowed for any 

compliance period for which allowances were already distributed/recorded. In any situation, 

63
reviewer recommends that switching should only be allowed at the beginning of a compliance 

period.

Response: The agency agrees with this comment and will give further consideration after review of all 

public comments and information submitted post-proposal. 

Trading Comments

1) Page 49/50. “The EPA also requests comment on expanding the scope of interstate trading to 

include linking states covered by the rate-based trading federal plan with any state that has an 

approved rate-based trading state plan meeting the proposed conditions for linkages and that 

uses an EPA-designated ERC tracking system that is interoperable with an EPA-administered ERC 

tracking system.” 

“The EPA also takes comment on allowing a state that has an approved rate-based trading state 

plan meeting the proposed conditions for linkages and that uses an EPA-designated ERC tracking 

system to register with the EPA, and after registration, to link with states covered by the ratebased trading federal plan.”

Comment: Reviewer strongly recommends not allowing states that select rate-based trading 

programs to link to other states unless all states within the linkage have select the same ratebased approach (i.e., either technology-specific rates or have the same blended rate). Reviewer 

notes that such a rule is important in states with rate-based goals to prevent unintended 

increases in emissions from otherwise identical EGUs that are operating under higher rates.

Response: We agree with the commenter and will revise the preamble to clarify the Agency’s intent. 

EGUs that wish to trade with EGUs subject to the federal plan will need to be under state plans 

approved as “Ready for interstate trading.” Nonetheless, the agency agrees that linkage between ratebased states requires use of the same emission rate limits for the respective affected EGUs.

2) Page 50, 51. “In this proposed rule, the proposed approach to link from the mass-based trading 

federal plan to state plans could result in linking of the federal plan to state plans that include 

non-affected emission sources. The EPA requests comment on this proposed approach.”

Comment: Reviewer supports the intent to allow any approved mass-based plan to trade 

allowances with any other approved mass-based plan, even if one or more of those mass-based 

plans cover non-affected sources. Reviewer requests clarifications, on page 50, that state plans 

that include non-affected sources will have undergone a demonstration outlined in the EGs to 

ensure that the plan will result in affected sources meeting the mass-based target for covered 

sources. Also on page 50, reviewer requests clarification that the import and export adjustments 

required in the EGs will include allowances issued from approved state plans that cover affected 

and non-affected sources. 

Response: This topic is fully addressed in the EG. The FP preamble cites to the EG section. 

3) Page 51. “The EPA requests comment on this expectation of a competitive ERC market and a 

competitive allowance market, and on potential program design choices that could address any 

identified market power concern.”

Comment: Reviewer recommends that a competitive and liquid ERC/allowance market is most 

likely to exist when there is 

64
a) Transparent release of information on regulatory changes. Reviewer recommends 

that EPA adopt communications strategies about ERC/Allowance issuance and other 

policy changes similar to communication strategies used by the Federal Reserve in 

discussing monetary policy, public companies in releasing financial information, or 

the EU Emissions Trading System in making policy announcements. In all cases, new 

information has the potential to affect billions of dollars of assets. Specifically, 

reviewer recommends that EPA should maintain a publicly available website and 

listserve that notifies the public in advance of announcements (e.g., 2-5 days) and is 

the first location announcements are released to the public. To the extent possible, 

reviewer encourages EPA to adopt a regular schedule in which updates or changes 

are announced (e.g., 10am on the first Wednesday of every month). Reviewer 

recommends that EPA establish highly confidential procedures for guarding the 

release of such information to avoid information leakage to traders who would 

benefit financially from the information. Beyond the website, the reviewer 

recommends that EPA publicly designate a limited number of people who can speak 

about changes to the program (such that market observers would discount 

comments from undesignated individuals). Reviewer notes that the ERC or 

Allowance market is anticipated to be a multi-billion dollar market and policies and 

procedures that ease the market’s ability to quickly and accurately absorb new 

information will greatly enhance liquidity in the market and remove costly and 

unnecessary volatility.

Response: The preamble details our intent to ensure that all information and data used for

issuing ERCs and allowances will be publicly available. 

b) Limited uncertainty about the total volume of ERCs available. Reviewer 

recommends issuing ERCs as frequently as possible (e.g. monthly for those ERC 

sources that can be issued monthly or quarterly for other sources) and at regular, 

pre-determined times to reduce uncertainty about how many ERCs are present in 

the market, which will reduce volatility in the price of ERCs. 

Response: Because of the rigor in the ERC issuance process, in addition to the review of data 

that is required, ERCs will be issued annually at the same time. We understand the benefits of 

issuing ERCs more frequently and will give consideration to any comments that present 

potential avenues to do so. 

c) Strict monitoring of fraudulent ERCs/Allowances. Reviewer recommends strict 

oversight of allowance market to prevent the type of fraud experienced in the EU at 

the launch of their program. 

Response: We agree with the comment. 

d) No limits on ERC/Allowance ownership. Reviewer believes that all types of entities 

can provide benefits to the market and encourages EPA to not limit the type or 

number of firms that can hold ERCs/allowances.

Response: Regarding allowances, the preamble states that any party could 

participate in the allowance market under the proposal. 

65
e) Market monitor enforcement against manipulation. Review recommends that EPA 

assign a market monitor to provide oversight of the various linked markets that 

form and report on potential market manipulation. 

Reviewer strongly recommends that EPA also require states to adopt similar practices as 

EPA with respect to the release of information about policy changes or ERC issuance 

because states will also play an important role in facilitating liquid and competitive 

markets. 

Response: This is a topic is being addressed under the CPP EGs.

4) Page 141-142, 156. “The EPA requests comment on whether there should be a quantitative limit 

or cap on the number of ERCs that can be banked. The EPA also requests comment on whether 

an ERC should be eligible to be banked between the interim and final compliance periods. The 

EPA is also proposing that ERCs will not expire after any duration of time. The EPA requests 

comment on the shelf-life of an ERC.”

Comment: Reviewer does not believe there should be a limit on the number of ERCs/Allowances 

that are banked. Reviewer recommends that ERCs/Allowances be allowed to be banked 

between the interim and final compliance periods. 

Response: We agree with this comment. However, to ensure there are not unforeseen drawbacks, we

are taking comment on the approach.

5) Page 146. “The EPA requests comment on a broader approach that would allow all affected 

EGUs that are located in states with approved rate-based state plans to participate in the federal 

plan trading program. In other words, this would extend federal-plan linkage to rate-based 

programs that are not set up to be “presumptively approvable,” or which use a set of emission 

rates for affected EGUs that are different from the national uniform subcategorized rates. We 

request comment specifically on what conditions or requirements would be needed in these 

cases in order to participate in the federal plan trading program in a way that is administratively 

feasible and maintains the integrity of all of the linked programs.”

Comment: Reviewer strongly recommends that EGUs should not be allowed to trade with other 

EGUs in other states unless EGUs of the same technology type operate under the same rate. 

Without that restriction, the policy would probably lead to unintended increases in emissions. 

Reviewer does not believe there is a mechanism that maintains emissions outcomes and at the 

same time allows linkages between state trading programs when “emission rates for affected 

EGUs...are different from the national uniform subcategorized rates.” 

 

Response: EPA agrees and the preamble language has been revised accordingly.

6) Page 146. “Although the agency has serious concerns about the administrative complexity of 

this approach, we also request comment on the feasibility and potential mechanism of allowing 

EGUs in states with approved mass-based state plans to participate in a federal rate-based 

trading plan.”

Comment: Reviewer strongly recommends that EPA include in the Federal Plan that allowances 

should not be an acceptable compliance instrument in any rate-based program (regardless of 

66
the conversion from mass to rate) and that ERCs should not be an acceptable compliance 

instrument in any mass-based program (regardless of the conversion from rate to mass).

Response: EPA agrees and the preamble language has been revised accordingly.

7) Page 156, 158. “The EPA is not proposing to allow allowance borrowing across compliance 

periods in the mass-based trading federal plans; however the agency is requesting comment on 

the use of borrowing across compliance periods.”

Comment: Reviewer notes that limited borrowing is implicitly allowed due to the 2 to 3 year 

compliance period. Reviewer does not recommend any borrowing beyond that implicit amount 

because it could encourage EGUs that anticipate shutting down to borrow significant quantities 

of ERCs/allowances and then declare bankruptcy at the same time they shut down. 

Response: We agree with this recommendation.

Compliance Comments

1) Page 56. “The EPA requests comment on whether there is any reason to use shorter compliance 

periods than the proposed periods, and how modifying these periods could be done in a manner 

that is consistent with the Emission Guidelines.”

Comment: Reviewer notes that a two to three year compliance period seems to be used 

successfully in other programs; however, reviewer encourages EPA not to further extend the 

compliance period beyond the currently proposed two to three years. A longer compliance 

period would likely have EGUs building up a larger ERC/Allowance liability prior to the 

conclusion of the compliance period, which might reduce their solvency if not sufficiently 

incorporated into planning. 

Response: EPA agrees and the preamble language has been revised accordingly.

2) Page 138, 159, 231. “The agency also requests comment on an earlier allowance transfer 

deadline [compared to November 1], such as June 1 or March 1, of the year after the last year in 

the compliance period.”

Comment: Reviewer recommends an earlier deadline for allowance compliance transfer, 

namely May 1, or the earliest that can be supported based on ERC issuance. The longer 

submission period (i.e., November 1) allows EGUs to build up a larger compliance liability. 

Reviewer is concerned about two specific situations. 1) An EGU that had planned to go out of 

business would have a longer period to emit before having to shut down or turn in compliance 

instruments. 2) An EGUs had not acquired or planned for acquiring sufficient compliance 

instruments, would build a larger compliance liability prior to being found to be out of 

compliance. That could contribute to an increased likelihood EGUs declare bankruptcy or 

otherwise exit the market. To somewhat address those situations, reviewer also recommends 

that 30 percent to 50 percent of an EGU’s expected annual compliance requirement be due in 

each of the interim years of the compliance period to prevent the buildup of large liabilities by 

EGUs. 

67
Response: In the mass-based approach we revised this to propose an allowance transfer deadline of 

May 1, and also request comment on earlier or later deadlines. Also in the mass-based approach, we 

revised this to request comment on requiring EGUs to demonstrate compliance for a portion of their 

emissions in each year of the multi-year compliance periods. In the rate-based approach we are 

maintaining November 1 to allow time for the EPA to QA/QC the data, allow time for EM&V, propose a 

NODA for ERC issuance, all a comment period, promulgate the NODA and issue the ERCs, and allow 

sufficient time for the newly issued ERCs to be traded. If the ERC issuance process can be expedited, 

there may be room for an earlier date, but this will happen through comments received.

3) Page 140, 232. “The EPA solicits comment on sources owing two ERCs to make up for each 

insufficient ERC in previous compliance periods and whether two for one is the proper make-up 

rate or whether there should be a stricter or a more lenient ratio.”

Comment: Reviewer recommends clarifying on pages 140 (for ERCs) and 232 (for allowances) 

the timeframe within which an entity out of compliance would have to provide the two 

ERCs/allowances for every one that was needed but missing from its account, assuming that 

none are available to be automatically deducted. 

Reviewer notes that it appears that the EGs no longer include the requirement that sources owe 

two ERCs to make up for each insufficient ERC in the previous compliance period. Reviewer 

requests that EPA consider if the penalty for being out of compliance should be the same in the 

EGs and in the federal plan or if there is justification for the different treatment. 

Response: Consistent with practice in the existing emissions budget trading programs that EPA 

administers, we would notify the facility as soon as we identify a shortage and give them the 

opportunity to respond. Regarding the two-for-one allowance surrender penalty in the fed plan 

proposal, we believe this provides a strong incentive for compliance with the allowance-holding 

requirement; states have flexibility in developing state plans and EPA intends to review and evaluate 

each plan to ensure they meet the requirements of the EGs. 

Mass Allocation & Set-Asides Comment

1) Page 54, 178, 186-188. “The EPA takes comment on both the set-aside for output-based 

allocation and the set-aside of allowances for RE generation.”

Page 202. “We are also requesting comment on options for a percentage of allowances to be 

reserved [for the RE set-aside] ranging from 1-10 percent of total allowances in each state.”

Comment: Reviewer recommends that the RE set-aside be changed in the proposed federal plan 

such that allowances be set aside for low- and zero-emitting generation and be distributed to 

those low- and zero-emitting EGUs or projects in the first two interim compliance periods (i.e., 

2022-2024 and 2025-2027) in proportion to the incremental generation of those EGUs or 

projects during the 2020 and 2021 years (relative to historic generation between 2010 and 

2012). Reviewer suggests that the distribution of allowance vintages for both compliance 

periods occur at the same time. Such an allocation strategy would encourage early action, 

increase the likelihood that the United States achieves its international carbon reduction 

commitments, and provide information to the market about the future price of allowances. In 

subsequent interim compliance periods, reviewer suggests that allowances are allocated 

proportional to generation in the previous interim compliance period. That would simplify the 

allocation approach relative to the proposed Federal Plan and reduce uncertainty for developers 

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of low- and zero-emitting EGUs. Reviewer suggests that this becomes the default and EPA take 

comment on it in the proposed federal plan. 

Reviewer suggests that the proposed approach in the current version of the federal plan for 

allocation (i.e., projected future generation) is complicated, creates uncertainty, and is 

vulnerable to manipulation by firms over- or under-projecting their generation in an effort to 

affect ERC prices. 

Reviewer also suggests that EPA propose a larger set-aside or provide a rationale for limiting the 

set-aside to 2 percent of available allowances instead of a larger or smaller number. Specifically, 

on page 203 EPA states that 2 percent was chosen because “at a range of possible allowance 

prices...[it would] incent the development of additional RE projects.” Reviewer recommends 

clarifying the meaning of additionality in that statement.

Response: The preamble language is being revised to reflect in more detail the role that the Clean 

Energy Incentive Program would play in recognizing pre-compliance emission reductions in both the 

rate-based and mass-based approaches. This program includes the creation of mass-based set-asides 

that recognize RE and EE impacts on emission reductions in 2020 and 2021. Preamble text has also been 

changed to reflect a larger RE five percent set-aside, and the EPA will provide in the docket an analysis 

that clarifies the quantification of the 5% set-aside. The EPA disagrees with the comment that the 

current proposed RE set-aside allocation method provides opportunity for manipulation, as providers 

will need to include an analytical justification for their projections that has been approved by a third 

party verifier, and will be accountable for any inaccuracies in their projections at the end of the 

performance year. It should also be acknowledged that this set-aside will only affect a subset of the 

available ERCs. We are also taking comment on whether set-asides should be based on actual 

megawatt-hours provided by the installation in a prior year or compliance period, or another form of 

historical generation data.

2) Page 148. “The EPA is proposing that allowances be issued in metric tons for the federal plan, 

and also requesting comment on the issuance of allowances in short tons.”

Comment: Reviewer recommends that allowances be issued in metric tons, which is consistent 

with the units of an allowance adopted by California.

Response: We have revised this to propose allowances in short tons, consistent with emissions reporting 

requirements.

3) Page 162, 172. “the EPA is requesting comment on an alternative allocation approach that 

would first divide the total number of allowances from each state’s mass goal by source 

category and then allocate to affected EGUs within each category based on shares of historic 

generation.”

Comment: Reviewer recommends that EPA clarify how the alternative allocation approach 

would be implemented. On page 172, “this alternative approach would divide the total number 

of allowances from a state’s mass goal... by affected EGU source categories. “ Reviewer 

recommends clarifying whether it is the affected EGU source categories generation or emissions

(and if it is the average from 2010-2012) that are placed in the denominator. 

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Reviewer also recommends clarifying the following phrase located on the top of page 173, 

“...and multiply historic NGCC-unit generation by the NGCC-unit source category-specific CO2

emissions performance rate.” Is the intended emission performance rate the average eight year 

interim rate from the EGs, the yearly emission performance rates from the Goal Computation 

TSD, or the federal 2 or 3 year interim compliance period average emission performance rates? 

Response: We have edited the preamble to clarify the alternative allocation approach.

4) Page 165, 247. “The agency requests comment on the proposed historic-generation based 

allocation approach and on other allocation approaches.”

Comment: Reviewer recommends that EPA take comment specifically on whether the historic 

generation allocation should reflect generation or emissions from affected EGUs. 

Reviewer recommends, in the discussion on Pg. 247 regarding calculation steps for the proposed 

historic-generation-based allocation approach, explaining whether/how historical operational 

data for plants during emergency/reliability events (i.e., unplanned outages, excess generation 

to offset outages) are considered in the averaging/allocation formula to avoid skewing the 

results.

Response: We added a specific request for comment on using historic emissions data. The proposed 

allocation approach would use the average of three years of generation data, and would only use nonzero values in calculating a unit’s average. For a unit that doesn’t have a full year of generation data, the 

proposed approach would use the same 2012 generation estimates as used in the CPP goal-setting 

calculations. The allocations TSD will provide more detailed information on the proposed allocation 

approach.

5) Page 174. “The EPA requests comment on the use of other updating allocation approaches 

[instead of the historical allocation method].”

Comment: Reviewer recommends that EPA encourage states to reduce the size of the historicgeneration-based allocation over time because it does not contribute to market efficiency. 

Response: As shown in the Regulatory Impact Analysis for the Emissions Guidelines, the presence of the 

EG contributes to economic efficiency as the benefits of the rule are larger than its costs, and that it 

would do so with historic-generation-based allocation (along with the set-asides described in the FP 

preamble). The commenter seems to suggest that there would be an alternative, but unidentified,

allocation or use of the allowance asset value, of which there are many options. The proposal takes 

comment on specific options for allocating allowance value that may improve economic efficiency. 

6) Page 176-178. “The EPA requests comment on the design and utility of allocating allowances to 

LSEs to help mitigate electricity price impacts. In particular, the EPA requests comment on 

options to establish conditions requiring pass through of allowance value and verification of 

such pass-through, whether it would be appropriate to identify any conditions related to 

equitable distribution of allowance value among ratepayer categories, as well as EPA’s legal 

authority to apply any such conditions.”

“The EPA recognizes that allocation to LSEs, by reducing rate impacts, could reduce incentives 

for socially efficient demand response, including potential investment in energy efficiency. The 

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EPA solicits comment on the magnitude of this effect, relative to alternative allocation options, 

and design options that could help mitigate this effect.”

Comment: Reviewer recommends that EPA note in the federal plan preamble and include in 

their approvability criteria that allowances allocated to LSEs may be used to help mitigate the 

effect of the policy on electricity consumers. Reviewer recommends that EPA also note that if 

the LSE passes through the value from selling the allocated allowances in a lump sum amount 

that is not associated with consumers’ electricity bills the incentives for economically efficient 

end-use energy efficiency are maintained. Finally reviewer suggests that EPA make clear that 

allowing LSEs to pass through the value of allocated allowances in a mechanism proportional to 

electricity usage will increase the cost of the program.

Response: The FP preamble already takes comment on the EPA’s ability to allocate to LSEs, and what 

criteria may be applied. The FP preamble also identifies that there may be economic efficiency 

consequences in the way that the allowance value is returned to consumers and takes comment on 

form of returning the asset value of allowances to electricity consumers. Some of the discussion 

regarding allocation to LSEs that was in the prior version of the preamble has been moved the

Allowance Allocation TSD for the FP (the TSD is described in the preamble). The discussion of the 

allocation to LSEs in the TSD will also refer to existing studies that describe and identify the potential 

efficiency consequences of various forms of returning allowance asset value to consumers (e.g., lump 

sum, in proportion to consumption, etc.).

7) Page 190, 192, 194, 196. “The EPA accordingly solicits comment on key parameters for the 

appropriate design of the output-based allocation approach used for this proposed set-aside [to 

fossil generators].”

Comment: Reviewer suggests also taking comment on having a higher limit on the size of the 

output based set aside for existing fossil NGCC EGUs because this set-aside improves the 

economic efficiency of the program (by reducing generation shifts to unaffected sources), 

whereas the historic generation allocation provides no safeguards against leakage to unaffected 

sources. 

Response: The preamble takes comment on all elements of the set-aside that determine the size of the 

set aside (e.g., the allocation rate, eligible sources, the capacity factor above which allowances are 

earned), and ultimately its marginal incentive for reducing leakage to new EGUs. 

8) Page 199. “The EPA also requests comment on extending output-based allocation from this set 

aside to affected utility boilers.”

Comment: Reviewer agrees with EPA’s reasoning for not extending output-based allocations to 

fossil steam EGUs. 

Response: No response needed.

9) Page 199-200. “The EPA solicits comment on the general merits of the proposed set-aside and 

the output-based allocation used under this set-aside. In addition, the agency solicits comment 

on how such an approach could be targeted to improve implementation of the proposed massbased trading federal plans and improve overall environmental and economic performance. In 

particular, the EPA solicits comment on which affected EGUs should receive any output-based 

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allocation, the proper allocation rate(s), the total size of the set-aside, and from which 

compliance period’s total allowances the set-aside should be drawn.”

Comment: Reviewer recommends using an allocation rate that is similar to the emission rate of 

new NGCC units (i.e. ~800 – 900 lbs CO2/MWh) using a rate higher than this would not align the 

incentives between existing and new NGCC generation.

Response: For the reasons that justify EPA’s choice of the 111(b) standard for new combustion turbines, 

and to maintain consistency with the incentives provided by that standard, we have kept the proposed 

allocation rate at the 111(b) NGCC standard. However, in response to this comment we have expanded 

the discussion of the allocation rate to request comment on a range of specific allocation rates that 

includes the expected emissions rate from new NGCC units.

10) Page 204. “The agency is requesting comment on an additional condition that would limit 

eligibility to project providers that are also the owners or operators of affected EGUs.”

“Eligible projects must be located in the mass-based state for which the set-aside has been 

designated. The agency invites comment on whether capacity outside the state should be 

recognized, and how that could be implemented.”

Comment: Reviewer recommends against limiting the set-aside to owners and operating of 

affected EGUs; owners and operators of eligible set-aside projects who do not also own an 

affected EGU are equally important to reducing emissions and should not be disadvantaged in 

the set-aside policy. Such a limit would probably result in some type of market distortion such 

that eligible projects would be sold to owners of affected EGUs or owners of eligible projects 

would purchase affected EGUs. Reviewer recommends against issuing set-aside allowances to 

EGUs outside the state because BSER is calculated based on generation within the state and not 

generation outside of the state. EGUs outside the state would presumably be eligible to receive 

set-aside allowances within their own state. 

Response: No response required.

11) Page 210, 212. “The EPA is also seeking comment on whether a portion of this set-aside should 

be targeted to RE projects that benefit low-income communities.”

“The EPA seeks comment on how a low-income community should be defined under this setaside. We seek comment on how much of the set-aside should be designated as targeted at lowincome communities. We also request comment on whether the methods of approval and 

distribution of allowances to projects that benefit low-income communities should differ from 

the methods that are proposed to apply to other RE projects.”

Comment: Reviewer recommends including a discussion of the importance of considering 

impacts on economically disadvantaged communities in the context of allowance allocation 

decisions described beginning on page 160. 

Response: The preamble already discusses that allowance allocations that do not change based on 

future activity (such as allocations under the proposed historic-generation based approach) do not 

affect the distribution of emissions under the program, and that the rule is expected to achieve 

significant emission reductions across the power sector. The preamble also requests comment on 

allocating a portion of allowances to LSEs as a way of mitigating electricity price impacts.

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12) Page 214, 221-222. “We request comment below on the advantages and disadvantages of 

allowing a state to handle allocations via a delegation of federal plan authority.”

Comment: Reviewer recommends clarifying, on page 218, that if a state chooses to auction 

some or all of the allowances under a federal plan, that the state could choose to alter how the 

state spends the auction revenue, even though the allocation plan indicating what level of 

allowances will be auctioned “would be final and not subject to modification.” 

 

Response: The text will be clarified to make clear that states that choose to auction allowances have the 

discretion to determine how to use the proceeds. However, EPA believes a state that wishes to handle 

allocations through an auction should submit a partial state plan rather than seek a delegation of the 

federal plan allocation program. 

ERC Issuance Comments

1) Page 52. “This can be demonstrated through: 1) the provision of a power delivery contract or 

power purchase agreement in which an entity in the rate-based state contracts for the supply of 

the MWhs in question and 2) documentation that the electricity was treated as comparable to a 

generation resource used to serve regional load that included the rate-based state. This 

demonstration must be included as part of the project application for ERC issuance to the EPA 

from the RE provider in the mass-based state. Once the project is approved, subsequent 

applications for issuance of credit to the EPA will need to reference that the MWh submitted are 

achieved by an approved project located in a mass-based state. The EPA requests comment on 

this approach.”

Comment: Reviewer agrees that the first demonstration option ensures that ERCs are not 

double counted. However, reviewer recommends clarifying option 2 by including an example of 

how option 2 could be demonstrated and how it does not lead to double counting. 

Response: This text is being revised in the proposal preamble. The EPA notes that number 1 and 

number 2 are both required for a sufficient demonstration, these are not two alternatives. 

2) Page 102. “The EPA broadly solicits comments on all aspects of the subcategorized rate 

approach.”

Comment: Reviewer notes that the subcategorized rate approach is the BSER from the EG. 

Recommend clarifying exactly what the EPA is inviting comment on, and that they are not reopening up BSER for comment.

Reviewer requests that EPA request comment on pages 101-102 on using the statewide blended 

rate target as the rate option for the model rate trading rule. Reviewer notes that 

subcategorized rates create a larger incentive for coal generation compared to a state blended 

rate, which may result in additional emission from coal under the subcategorized rate approach. 

Reviewer recommends EPA clarify how “subcategorized rates allow(s) for: (1) an equitable 

distribution of burden for emission reductions. Additionally, over what entities is the burden 

equally distributed? 

Response: EPA agrees and the preamble language has been revised accordingly.

3) Page 99, 103, 111-112, 134-135. “This section describes how a rate-based federal plan would be 

designed and operated, and how measures consistent with the CPP EGs building blocks can 

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generate ERCs. The EPA requests comment on these means of generating ERCs and whether 

other sources of low- or zero-emitting electricity not included in the building blocks should also 

be eligible to generate ERCs for compliance purposes.”

Comment: Reviewer recommends proposing (rather than taking comment on) that all non-BSER 

technologies that are acceptable to generate ERCs in the emission guidelines (EGs) be proposed 

as approved under a federal plan. That would include, but not be limited to, distributed RE 

generation, demand side energy efficiency, new and up-rated nuclear generation, offshore 

wind, and CCS retrofits. By not allowing certain abatement measures to be credited, the cost 

effectiveness of the policy is reduced both for the federal plan and for states that adopt a 

“presumptively approvable” plan modeled after the federal plan. EM&V requirements for state 

plans on non-BSER technologies are the same as for the federal plan, so comments should be 

requested on the best EM&V methodology, , and not which technologies and measures should 

be valid compliance mechanisms or not. Reviewer also notes that EPA takes comment on what 

the process should be for demonstrating the “appropriateness” of additional technologies, but 

never explains what the “appropriateness” standard requires. All technologies and measures 

could be held to a strict standard to be quantifiable, verifiable, and additional. Any technology 

or measure that can pass the requirements should be permitted to generate credits under a 

federal plan.

Response: The feasibility of federal implementation is a key concern, and thus the EPA is proposing to 

only include non-distributed RE and new or up-rated generation due to requirements and rigor needed 

to ensure the quality of data and emission reductions achieved through the other described ERC 

generating resources.

4) Page 108. “The EPA requests comment on this approach and requests comment and suggestions 

on other approaches for existing NGCCs to generate ERCs at all times. The EPA is considering this 

methodology that BB2 ERCs are generated for all NGCC generation because it ensures that all 

existing NGCCs are encouraged to run at a greater capacity. The EPA is requesting comment on 

alternative methods for NGCCs to generate BB2 ERCs. Specifically, the EPA solicits comment on 

NGCCs generating BB2 ERCs once a threshold of generation for the year is achieved.”

Comment: Reviewer found that the equation presented on page 106, using data from the Goal 

Computation TSD, does not compute to a 0.09 BB2 ERCs/MWh. Specifically, from the TSD, 

reviewer notes that NGCC Gen Post BB2 is 987TWh and NGCC Gen in 2012 is 734TWh, which 

leads to a BB2 ERC generating factor of 0.25 BB2 ERCs/MWh. Reviewer requests clarification on 

the correct formula and how “the collective sum of the BB2 ERCs generated realizes the amount 

of the emission reductions described in Building Block 2 when 75 percent capacity is achieved.” 

(p. 105).

Response: This section has been edited for clarity. There has been a slight change of course so that each 

unit will have its own BB2/GS-ERC rate depending on the difference between the emission rate and the 

steam generating unit’s standard. 

Additionally, reviewer recommends that EPA clarify the purpose of the equation on the top of 

page 109. Reviewer first thought this equation only applied to either of the threshold 

approaches, but upon closer study it appears that this equation may be the key to reproducing 

the BB2 ERC generating factor of 0.09 ERCs/MWh.

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Response: This section has been edited for clarity. 

Reviewer recommends clarifying the text on the top of page 105. The first full sentence, “To 

account for...Building Block 2.”, makes it sound like only incremental NGCC will generate BB2 

ERCs instead of all NGCC generation.

Response: This section has been edited for clarity. 

Reviewer recommends that EPA clarify over what time period the average NGCC generation is 

taken and after what building block in the following sentence from page 106. “...EPA has taken 

the average NGCC operation in the Eastern Interconnect and divided it by the 75% of Building 

Block 2...”

Response: This section has been edited for clarity. 

Reviewer recommends not proposing or asking for comment on the first threshold calculation 

option on page 108. Such an approach would appear to create a clear opportunity to game the 

BB2 ERC calculation without actually increasing generation from NGCC relative to 2012. For 

example, an owner of two NGCC EGUs could increase generation for one EGU relative to 2012 

and decrease generation from the other EGU relative to 2012, thus generating new ERCs but not 

increasing generation or reducing emissions. Alternatively, EPA could mention they considered 

this option, but decided against it for the reason above.

Response: We agree with this assessment. However we believe it is useful to solicit comment as it most 

closely follows the CPP EGs BSER. 

Reviewer also requests clarification on the second threshold calculation option presented for 

BB2 ERC generation, as it is not clear from the text how the percentage threshold is calculated 

or applied: “The other threshold option is to use a percentage threshold. This percentage is the 

2012 regional NGCC generation of total NGCC regional capacity in 2012. This percentage is 

applied at the unit level and all generation by the NGCC that exceeds that percent capacity at 

the NGCC is eligible to credited with BB2 ERCs.”

Response: The language has been modified to help with clarity, and a TSD is being developed to show 

the calculations that have been made.

5) Page 110. “We invite comment on this approach [EGU based ERC generation] as a method of 

implementation of a federal plan and model trading rule.”

Comment: Reviewer recommends adding a short paragraph at the beginning of the section on 

“EGU Based ERC Generation” on page 103 to give an overview of the 2 ways that NGCC can 

generate ERCs, with a sentence describing each, and an explanation of the differences between 

ERCs and BB2 ERCs. It was not until the end of this section that it became clear how NGCCs and 

ERCs interact.

Response: Language has been modified to provide clarity. 

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Reviewer also recommends against issuing two types of ERCs in the federal plan. Because BB2 

ERCs can be used for steam compliance and general ERCs can be used for both steam and NGCC 

compliance and because the vast majority of ERCs are expected to be used for steam 

compliance, one would expect there to be a single price for the two types of ERCs in a 

competitive market. Reviewer notes that maintaining two types of distinct ERCs makes the 

program more complicated and increases the transaction costs of compliance without providing 

any additional environmental benefits.

Response: The EPA understands the complexity concerns, but allowing two different types of ERCs 

conforms the market to the generation shifts that are desired as part of building block 2.

6) Page 111. “The EPA requests comment on the inclusion of various types of demand-side EE as 

eligible measures, such as state and utility EE programs, project-based demand-side EE, state 

building codes, state appliance standards, and conservation voltage reduction. The agency also 

requests comment on the inclusion of combined heat and power (CHP) as an eligible measure.”

Comment: Reviewer recommends that all EE measures and CHP projects with rigorous 

verification and that would be approvable under the EGs be included under the federal ratebased trading program. Reviewer recommends that EPA state these measures are approvable 

rather than taking comment on whether they should be approvable. 

Response: The EPA disagrees with this approach for recognizing eligible emission reductions measures 

under a rate-based federal plan. In the context of the federal plan, the feasibility of federal 

implementation is a key concern, and thus we seek comment on how to implement the EM&V 

requirements for various demand-side EE and CHP technologies on which we seek comment, and how 

that could be implemented in the context of the final rule. We also seek comment on a process by which 

technologies can be determined to be eligible. We also seek comment on a process by which 

technologies can be determined to be eligible. The EPA notes that states that wish to have the ability to 

recognize all the eligible demand-side EE and CHP technologies under the final guidelines have the 

opportunity to submit an approvable state plan that does so. 

7) Page 128, 129. “However, we solicit comment on the annual issuance of ERCs and whether 

issuance should occur at different intervals (e.g., quarterly, biannually, or other time frames). 

The EPA requests justification along with corresponding comments regarding issuance of ERC 

intervals.”

Comment: Reviewer recommends increasing the frequency of ERC issuance at intervals less 

than a year. Automatic issuance of ERCs based on monthly generation data after a facility has 

been approved for eligibility would decrease the administrative burden on generators and the 

ERC tracking system, reduce price volatility, encourage continual operation of efficient markets, 

and provide certainty for low- or zero-emission EGUs or projects. To the extent that EM&V 

requirements prevent the monthly issuance of ERCs from some types of projects, reviewer 

suggests that ERCs from those projects be issued as frequently as possible. Reviewer notes that 

PJM currently generates certificates in PJM-GATS on a monthly basis (http://www.pjmeis.com/getting-started/faq.aspx#genentq1). This will allow more time for EGUs to acquire the 

necessary ERCs and provide more market certainty for ERC generators. 

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Response: The EPA understands the benefits of issuing ERCs more frequently but because of the process 

needed to issue ERCs, it is a key federal implementation concern. We are requesting comment on means 

of expediting the process so that the EPA might be able to issue more frequently. 

8) Page 131. “The agency requests comment on whether a quarterly or semi-annual application 

process [for RE project and program eligibility applications and regulatory approval as well as 

information on ERC transfers] is appropriate. These applications will be accepted through the 

entirety of all compliance periods.”

Page 128 - 133: "As required in the final EGs, we are proposing a two-step application process to 

the federal plan tracking systems for RE ERCs... The EPA takes comment on all aspects of the 

proposed ERC issuance process. "

Comment: Reviewer recommends streamlining the proposed ERC issuance for RE, other 

generating measures, and demand side EE to reduce the reporting burden and allow ERCs to be 

issued more frequently than once per year. As proposed, RE measures must first submit a 

project application and then a separate application for credit issuance. Reviewer recommends 

having a single application process for RE or EE projects, which when approved allows automatic 

issuance of ERCs on a more than annual frequency based on recorded generation or estimated 

savings. An annual EM&V report could be created and reviewed by a third-party verifier; if 

discrepancies are identified, a NODA would be issued indicating the discrepancies and ERC 

adjustments taken for the relevant accounts.

Reviewer also recommends (on page 132) that EM&V methods for RE providers be approved 

during step one of the credit issuance process. Then in step two, only MWh would need to be 

submitted such that the process can be less onerous and time consuming.

Response: The EPA understands the benefits of issuing ERCs more frequently but because of the process 

needed to issue ERCs, it is a key federal implementation concern. We are requesting comment on means 

of expediting the process so that the EPA might be able to issue more frequently. The EPA will explore 

the options above between proposal and promulgation.

Administration Comments

1) Page 48. “The state plan must use an EPA-administered tracking system (we are also requesting 

comment on expanding this to include a state plan that uses an EPA-designated tracking system 

that is interoperable with an EPA-administered system, as detailed below).”

Comment: Reviewer supports an EPA-designated tracking system that is interoperable with EPAdesignated/approved state tracking systems, as described on page 48, be included in the FIP. 

Reviewer recommends requesting comment on page 125 if additional information should be 

tracked in the ATCS to ensure compliance with trading rules laid out in the EGs and contribute to 

a more competitive market. Reviewer recommends EPA take comment on using a 3rd party to 

run the tracking system for a federally enforceable implementation plan. Reviewer recommends 

taking comment on needs for interoperability, using existing REC exchanges as a starting point.

Reviewer requests clarification on the integrity lost through linking state-approved and federally 

administered tracking systems. If each of the state-approved tracking systems meets the EPA 

requirements and exchange protocols that are determined, then integrity should be maintained 

(once emissions increases issues described above are addressed).

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Response: An EPA administered system allows for ensured greater security and requirements. It will be 

difficult to assess all the capabilities for the state tracking system to fully coordinate with the EPA 

administered system. In the CPP EGs comment period, it was requested that EPA administer a tracking 

system. 

2) Page 83. “the agency believes it would be efficient and potentially avoid the need for recourse 

to litigation, to provide an administrative appeals process. Therefore we are proposing, and 

requesting comment on, the use of the regulations for appeals procedures set forth in 40 CFR 

Part 78, to provide for the adjudication of certain disputes that may arise during the course of 

implementation of a federal plan under section 111(d).”

Comment: Reviewer recommends that any administrative appeals process be sufficiently 

transparent to facilitate ERC/Allowance price discovery by market participants. Reviewer notes 

the potential for such an administrative appeals process to be highly disruptive (and introduce 

significant price volatility) to the market for ERCs/Allowances if done in secrecy with sporadic 

releases of market-moving information.

Response: The Part 78 process that the agency is proposing has been used for many years for similar 

disputes that may arise in the course of CAA trading programs. Actual need for administrative appeals 

and dispute resolution has been quite rare in these prior programs and has not been disruptive to the 

functioning of the programs. It is the agency’s expectation that the availability of party-specific dispute 

resolution will significantly reduce the possibility of disruption to the program via litigation. The process 

in Part 78 is ideal because it has already been designed to address transparency, participation, and due 

process needs.

Biomass Feedstock Eligibility 

1) Page 114-115. “Provided for comment below are options for biomass treatment under the ratebased federal plan, which would also apply to eligible generation under the mass-based plan 

allowance set-aside and to the calculation of covered emissions for affected EGUs that are cofiring biomass, which include: 

a. A list of specific acceptable biomass fuels 

b. General principles and/or specific criteria regarding biomass fuel production, processing 

and use for energy 

c. A combination of the above options. “ 

Comment: Reviewer recommends EPA not take comment on options 2 and 3 as presented. 

Reviewer recommends to instead take comment on only two options: 1) EPA’s option 1 and 2) a 

modified version of EPA’s option 3.

For the modified version of EPA’s option 3, the reviewer recommends that EPA still create a list 

of acceptable biomass feedstocks that are updated over time (Option 1). The primary criteria for 

approving acceptable biomass feedstocks would consist of evaluating the carbon reduction 

benefits through a life-cycle emissions analysis of the biomass feedstock. 

A secondary method of evaluation for including biomass feedstocks onto a pre-approved list, is 

the sustainability and best forest management practices (with some caveats as commented on 

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below ) outlined in Option 2 (pgs. 116-117). This method would provide clarity for common 

feedstocks, and emphasize carbon reduction as a metric for other feedstocks.

Response: We have removed options 2 and 3 and therefore are not taking comments on these options. 

We are taking comment on possible processes for adding biomass feedstocks to the pre-approved 

qualified biomass feedstock list. 

2) Page 114. “The revised Framework...finds that it is not scientifically valid to assume that all 

biogenic feedstocks are ‘carbon neutral’...”

Comment: The reviewer agrees with this comment, but notes that it is also not scientifically 

valid to assume that no biogenic feedstocks are carbon neutral, or that all emissions from 

biogenic feedstocks are additional to the emissions that would have occurred were they not 

used as a feedstock. Reviewer recommends inclusion of this clarification. 

Response: We disagree with this recommendation. The Science Advisory Board peer review report on

the 2011 draft Framework clearly stated that:

“Carbon neutrality cannot be assumed for all biomass energy a priori. There are circumstances in 

which biomass is grown, harvested and combusted in a carbon neutral fashion but carbon neutrality 

is not an appropriate a priori assumption; it is a conclusion that should be reached only after 

considering a particular feedstock’s production and consumption cycle. There is considerable 

heterogeneity in feedstock types, sources and production methods and thus net biogenic carbon 

emissions will vary considerably.”

This means that biomass should not be assumed carbon neutral prior to assessment, and through 

such an assessment, some feedstocks may be found to be carbon neutral. 

3) Page 115: “The first option offered for comment is to specify a list of specific pre-approved 

acceptable biomass fuels.” 

Comment: Reviewer notes that the first option is similar to the feedstock/pathway approval 

process used for the RFS. Recommends noting this in text.

Response: As this proposal and the request for comments on potential treatments of biomass therein

differ or may differ from those as mandated with the RFS program, adding this reference may confuse 

stakeholders and add connotations that are not intended by the proposed option. No change. 

4) Page 115. “The second option offered for comment would be to establish general principles 

and/or specific criteria concerning the production, processing and use of biomass fuels.” 

Comment: Reviewer notes that the second option is presented under a discussion to develop 

principles and criteria for eligibility of feedstocks when the underlying issue with option two is 

implementation. The concern is that the third party verification/certification sets a potentially 

unwanted precedent of having Forest Service and BLM managers subject to a few selected 

individuals, and that the process would be redundant to current NEPA processes. Recommend 

clarifying how these interactions between agencies (EPA, USDA, DOI) would occur under the 

federal plan.

Response: This option has been removed. 

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5) Page 116. “Under this option, the EPA could specify criteria for the production, processing and 

use of forest- and agriculture-derived biomass fuels that could also include the preservation of, 

and/or limiting or restricting the use of biomass fuels from, natural and old growth forests...”

Comment: Reviewer notes that nearly all federal forests are “natural forests.” Removal of 

biomass from these forests would offset the cost of needed treatments for these forests which 

are overstocked and prone to fire and pest epidemics. Reviewer recommends explicitly stating 

that this definition of “natural forests” would not exclude federal forests.

Response. This text has been removed. 

6) Page 116. “Limitations on deforestation and targeted land use change, especially of high carbon 

and/or otherwise ecologically sensitive areas for the production of bioenergy feedstocks “ 

Comment: Reviewer recommends defining “deforestation” as meaning land use changes and 

unrestricted logging in ecologically sensitive areas.

Response: This text has been removed. 

7) Page 117. “Use of the best scientific information and systems available to assess landscape 

health, carbon stock attributes and net carbon emissions attributable to production and use of 

biomass for combustion, and to continually refine and update inventories of these attributes” 

Comment: Reviewer suggests clarifying “continually refine and update inventories of these 

attributes” as it is a nebulous term that could have large economic and workload implications. 

Response: This text has been removed. 

8) Page 117. “Ensure forest and landscape productivity, and economic viability, including primary 

and secondary products. “ 

Comment: Reviewer recommends taking comment on “ensuring forest and landscape 

productivity” as it is a difficult task.

Response: This text has been removed. 

Biomass Compliance 

1) Page 118. “The EPA also requests comment on options for demonstrating compliance with the 

options listed above that include criteria that reflect sustainability and sustainable practices that 

are additional to the EM&V requirements discussed in section &&& above. These options for 

demonstration of compliance with criteria are described below.“

Comment: pg. 118-119, Reviewer recommends taking comment on Options 3 and 4 only, as 

they focus on existing certification and carbon accounting methodologies. 

Response: We are taking comments on all options related to biomass in this proposal. 

2) Page 118. “The first option offered for comment would require provision of sufficient credible 

evidence, such as monitoring records and metrics showing that the forest/agricultural feedstock 

sources meet the criteria listed above and any others that might be adopted, and are at low risk 

of non-compliance.” 

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Comment: Reviewer notes that the first option for demonstrating compliance requires evidence 

that defeats the purpose of having biomass fuels that are “pre-approved.” Recommend 

clarifying what the additional reporting for this would be beyond what would be required for 

just determining if a feedstock qualified or not. 

Response: This text has been removed. 

3) Page 118. “The second option offered for comment would require the provision of approved 

third party verification and/or certification entities or programs to demonstrate compliance with 

established sustainability criteria.” 

Comment: Reviewer notes that NEPA compliance generally supersedes third party 

verification/certification programs, and that this option for compliance would be a redundant 

and costly requirement. Recommend addressing how NEPA compliance could be used under this 

option.

Response: This text has been removed. 

4) Page 119. “The third option offered for comment allows for the use of any other verification 

programs or entities to demonstrate compliance which are not pre-approved but can be proven 

to employ generally accepted sustainability metrics.” 

Comment: Reviewer supports the third option presented for compliance, as it would 

conceivably include NEPA compliance on federal forests and certifications for private lands. 

Recommend making this the preferred options and the other options as alternatives.

Response: This text has been removed. 

5) Page 119. “The fourth option offered for comment requires a determination of the biogenic 

emissions and sequestration related to the production, processing and use of the biomass fuel, 

with supporting records.” 

Comment: Reviewer notes that the fourth compliance option presented is also part of the 

proposed methodology for determining if a feedstock is eligible. Recommend clarifying whether 

carbon accounting if done for showing eligibility as a feedstock would not have to be repeated 

to show compliance under this option.

 

Response: This text has been removed. 

6) Page 152. Reviewer recommends the following change: “This proposed requirement to hold and 

surrender allowances equal to emissions for each compliance period would apply to all reported 

emissions from a facility’s affected EGUs including any emissions from co-fired biomass as 

calculated according to the methodology discussed in the final Framework for Assessing 

Biogenic Carbon Dioxide for Stationary Sources.” 

Response: We do not agree with this comment. The draft 2014 Framework – a policy neutral 

technical document – is currently undergoing a second peer review with the Science Advisory Board. 

Generation of ERCs Through Operation of non-BSER Sources

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The draft of the federal plan discusses (pages 110 to 120) the RE measures that would be eligible for ERC 

generation. To ensure consistency with the final Clean Power Plan, reviewers suggest that the federal 

plan allow the generation of ERCs from a broad range of zero-emitting non-BSER sources such as new 

nuclear and demand response EE, subject to EM&V requirements and verification/certification 

protocols. EPA is justifiably concerned about the impact of “leakage” from certain non-affected EGUs 

(e.g. new NGCC units) on the effectiveness of the BSER measures. However, zero-emitting sources such 

as nuclear and demand response EE would not cause leakages, and there is no principled basis to treat 

them differently from the RE measures that EPA has identified as being eligible for ERCs. By the same 

token, these other zero-emitting non-BSER measures should be eligible for receiving set-aside 

allowances in a mass-based program. 

Response: The feasibility of federal implementation is a key concern, and thus the EPA is proposing to 

only include non-distributed RE and new or up-rated generation due to requirements and rigor needed 

to ensure the quality of data and emission reductions achieved through the other described ERC 

generating resources.

Likewise, the draft federal plan sets out certain criteria under which ERCs generated from RE measures 

operated in mass-based states can be used to meet compliance obligations in rate-based states. 

Reviewers suggest that the use of ERCs generated from other zero-emitting sources located in massbased sources (such as nuclear and demand response EE) should likewise be allowed to meet 

compliance obligations in rate-based states.

Response; Nuclear is now being included and is described in the same vein as RE, but as described 

above, EE is not being included in the federal plan and thus being discussed for rate and mass overlap.

Participation in Federal Plan Trading Program 

As to interstate trading (pages 144-147), reviewer recommends the use of the broader approach such 

that EGUs in states under a federal plan and in states with a “presumptively approvable” plan, could 

trade with EGUs in other states that are not under a federal plan or “presumptively approvable” plan. 

Creating such a mechanism that facilitates trading through a common federal trading rules (mass-based 

and rate-based) is critical as, otherwise, states would not have an incentive to develop state plans using 

a “state measures” approach. This is also a more equitable and economical approach to compliance. 

Moreover, the fact that state plans using a “state measures” approach would have the federal plan as a 

backstop minimizes the risk of harm in allowing trading between states under state and federal plans. 

Response: There is the restriction of trading that only affected EGUs in the federal plan may trade with 

states that are “ready-for interstate-trading” to ensure that there is no leakage and that all resources 

are being treated the same. The EPA wholly encourages trading, but understands that it must be done in 

a controlled way to ensure that everything is accurately accounted for. This does preclude not state plan 

to state plan interactions as described in the CPP EGs.

Retired Units

Many utilities own units that meet load and serve customers in multiple states. Therefore, utilities must 

make decisions for their generating fleet as a whole, not as isolated units in individual states. An owner 

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of EGUs in two states with a mass-based plan may retire a unit in one state and need those allocations 

to help a unit in another state comply. In order to allow this flexibility, reviewer suggests the following 

approach that is not currently in the proposed rule. Reviewers suggest that the initial allocation of 

allowances for each unit be held constant and not removed from the unit regardless of the unit’s status 

throughout the compliance period. It would be inequitable to take allocations from EGU owners that 

retire units as a result of this rule. EPA could require EGU owners to demonstrate the need for excess 

allocations, due to unit retirement, to be used by its EGU in another state for compliance. Without this 

demonstration for need, the excess allowances could be distributed to other units in the state where the 

retired unit is located. 

Under the proposed federal plan, a unit that does not operate for two consecutive years would receive 

allocations for four years after it ceases operation (page 211). This scheme does not account for units 

that were placed in an extended outage to address major equipment maintenance, or were mothballed 

for use at a future date. Units that have maintained their Title V and other environmental permits with a 

view to restarting in the future, and have undertaken preventative maintenance while in extended 

outage or mothballed condition, should not be penalized merely because of non-operation for a two 

year period. Accordingly, reviewer suggests that the criteria for retired units be revised such that the 

two-year, non-operation clock would run only under certain conditions.

Response: We have changed the proposed approach so that if an EGU doesn’t operate for two full 

calendar years, then starting with the next compliance period for which allowances have not yet been 

recorded, the retired unit would no longer receive allowances. We don’t intend to take back allowances 

that have already been recorded. If a retired unit began operating again after it didn’t operate for two 

full calendar years it would be a new unit and wouldn’t need to hold allowances for this program. We 

added a request for comment on treatment of allocations to units that are in long-term cold storage.

Other General Comments

With regards to the output-based allocation, commenters recommend giving the allocation to all clean 

new and existing generation in addition to all existing natural gas generation—in other words, to all 

generation that results in lower emissions rather than higher emissions. This will (1) ensure that the full 

incentive to build new renewables and preserve existing zero-carbon generation will be maintained and 

(2) eliminate market distortions associated with the threshold-based allowance allocation

Response: The preamble requests comment on which generating units should be eligible to receive 

output-based allocation from the set-aside, and it also proposes a set-aside for renewable energy 

projects. 

Commenters recommend that EPA take comment on a BB2 ERC approach that generates some fraction 

of ERCs through the reduction in steam generation (in contrast to the central proposal that only focuses 

on increases in natural gas generation). In particular, this could be accomplished through a pro-rated 

additional demand for ERCs placed on steam generation.

Response: This may add additional layers of complexity with diminishing returns, and the EPA wants to 

optimize clarity and simplicity. 

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Commenters recommend that new nuclear power and uprates, distributed PV and offshore wind be 

among the creditable technologies under a rate-based plan

Response: The preamble text is being revised to recognize incremental nuclear power and nuclear uprates, as recognized under the final emission guidelines, as an eligible technology for ERC issuance under 

the rate-based federal plan approach. Aside from the recognition of qualifying nuclear, the EPA 

disagrees with the approach for recognizing all emission reductions measures eligible under the final 

emission guidelines for ERC issuance under a rate-based federal plan. In the context of the federal plan, 

the feasibility of federal implementation is a key concern, and thus we propose technologies that are 

widely demonstrated and provide the simplest path for EM&V implementation under a federal plan. We 

seek comment on how to implement the EM&V requirements for various technologies on which we 

seek comment, and how that could be implemented in the context of the final rule. We also seek 

comment on a process by which technologies can be determined to be eligible. The EPA notes that 

states that wish to have the ability to recognize all the eligible technologies under the final guidelines 

have the opportunity to submit an approvable state plan that does so. 

Commenters recommend that ERCs be issued as often as possible to provide the most information and 

certainty to markets. If this cannot be done for all types of ERCs, it should be straightforward to do for 

RE.

Response: The EPA agrees that ERCs should be issued as often as possible. We will consider options to 

do this based on information received during the comment period for this action.

Commenters recommend that States under a mass-based federal plan be allowed to take advantage of 

the full 8-year averaging across the interim compliance period, especially in light of the lack of an RSV. 

States could convert to a state plan provided that they either are at a zero or positive bank or that they 

account for any borrowed emissions in their state plan.

Response: The proposal allows unlimited allowance banking. The multi-year compliance periods allow 

averaging across multiple years. The proposal requests comment on allowance borrowing across 

compliance periods but does not propose to allow cross-period borrowing for the reasons stated in the 

preamble.

Commenters understand that the ERC crediting mechanism will be established in the emission 

guidelines, so is it correct to assume that the proposed options for ERC crediting in the FP will be 

removed?

Response: No it will not be removed. The ERC issuance and crediting process is expands on the 

discussion from the EGs. 

It would be helpful to have a clarification of the current thinking on the process for finalizing a federal 

plan for a state in terms of the notice and comment requirements, if any, and what that timeline would 

be.

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Response: EPA has proposed the federal plan for all states with affected EGUs who do not submit 

approvable plans. EPA is taking comment on the federal plan now. Thus EPA will be in a position to 

finalize the federal plan, taking into account any comments, for each state, if necessary, as soon as 

predicate action has been taken on the state’s plan or failure to submit a plan. If states fail to submit 

anything by the deadline next year, EPA may ministerially determine that there has been a failure to 

submit. Where a state submits a plan that does not meet requirements, EPA would propose the plan for 

disapproval and go through a notice and comment process on the disapproval. The model trading rules 

may be finalized at any time after the notice and comment process, and EPA states its intention to 

finalize them by next summer. At that point, the expectation is that the agency would respond to 

comments that are relevant to the general design of the program. 

Would it be possible to provide for EPA payment of verifiers (through fees assessed to energy efficiency 

developers) to avoid having developers themselves paying verifiers, and the incentive structure that 

creates?

Could EPA discuss how it will be assured that states with a rate-based FP approach would have sufficient 

access to ERCs?

Response: Primarily, the amount of ERCs that are generated are based on the least stringent region’s 

ability to generate ERCs so it provides every opportunity for ERCs to be generated so that compliance 

can be achieved by the EGUs. Also, because there is a national trading platform, ERCs can be traded 

across the country and between states subject to the FP and states that are ready-for-interstate-trading. 

This should allow a large and diverse market for states that may not have as much ability to generate 

ERCs. 

Would it be possible for a state to choose to opt-in its new sources under a mass-based FP, perhaps by 

making the anti-leakage design element one of the places where a state could choose to make a design 

decision for the FP?

Response: A state can adopt the model rule, and if it chooses to follow the anti-leakage flexibility in the 

EG, it can incorporate those flexibilities to supersede those in the model rule.

Other Specific Comments

1) Page 144, 235. “The EPA also requests comment on requiring monitoring and reporting of CO2

mass and net generation for the year before the initial compliance period begins, i.e., to 

commence January 1, 2021.”

Comment: Reviewer recommends requiring monitoring and reporting of CO2 mass and net 

generation for the year before the initial compliance period so the effects of the first year of the 

policy may be measured and analyzed and so that any kinks in processes can be ironed out 

before compliance obligations begin.

Response: Agreed, the agency is taking comment to confirm. 

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2) Page 180, 220. “The EPA requests comment on the proposed approach of recording allowances 

seven months prior to the start of each compliance period, and on an alternative of recording 

allowances 13 months prior to the start of each compliance period.”

Comment: Reviewer requests clarification on whether EGUs can use allowances from the next 

compliance period to comply with a current compliance period since allowances will be issued 

for the preceding compliance period either 7 or 13 months before the current compliance 

period ends.

Response: Allowances cannot be used from a future compliance period.

Technical Comments

1) Page 48-49. Reviewer request clarification on the passages on page 48-49. Is there a difference 

between “EGUs” and “sources”? Does EPA intend to make a distinction in the direction of 

trading? If not, consider using “between” instead of “from”. 

“The EPA proposes that interstate ERC trading could occur both i) from affected EGUs in states 

covered by the rate-based trading federal plan to affected EGUs in states with approved ratebased trading state plans meeting the proposed conditions for linkages, and ii) from sources in 

such state-plan-covered states to sources in federal-plan-covered states.” 

Response: Preamble edits have been made accordingly. 

2) Page 63. Reviewer recommends expanding use of the ISO/RTO Council to reliability 

coordinators and planning authorities because the IRC does not encompass all areas of the 

country.

Response: The reference to “other planning authorities” addresses this comment.

3) Page 103: Reviewer also recommends on page 103 changing the signs on “EGU limit” and “EGU 

operating rate” in the numerator of the equation, so that if “ERC MWh” is calculated to be 

positive it indicates how many ERC need to be surrendered and if it is calculated to be negative 

it indicates the number of ERCS that are being generated. This will then make the sign of “ERC 

MWh” that need to be surrendered consistent with other equations in the preamble (for 

example on page 107).

Response: The EPA disagrees and thinks that the signs send the signal that is intended.

4) Page 104. Reviewer recommends deleting the following sentence on page 104. The sentence is 

correct, but it contains the same information as the equation and text on the previous page, but 

it is stated in a way that requires careful review to determine that fact.

“The needed quantity of ERCs for any given amount of generation can be easily calculated by 

dividing the total emissions of the affected EGU by the applicable emission rate limit, and then 

subtracting the generation of the affected EGU.”

Response: Preamble edits have been made accordingly.

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5) Page 104: Reviewer requests clarification on the meaning of pro-rata in the sentence: “To 

incentivize and capture the emission reductions of Building Block 2 of the CPP EGs, the EPA 

proposes in the federal plan that NGCC generation has the capability to generate ERCs on a prorata basis reflecting incremental NGCC generation. “

Response: Edits made to clarify the language

6) Page 106. Reviewer recommends clarifying the following, as it is not clear what is meant by 

“when the region reaches 75 percent summer time capacity...” does this mean, “when the 

interconnect region generation reaches the level that would be generated if all NGCCs in the 

region operated at a 75% capacity factor” ?

Response: Edits made to clarify the language

7) Page 124 & 127. Reviewer suggests clarification that ERCs in a compliance account are retired 

and no longer available for trade when used for compliance purposes, which follows current 

terminology in REC tracking systems:

“A compliance account would be the account in which any ERCs used by the affected EGU for 

compliance with the emissions limitations would have to be held until retired for compliance.” 

“Accordingly and if necessary, the appropriate number of ERCs will be deducted from retired in

the EGU’s compliance account to adjust the emission rate of the EGU to be equal to the 

emission standard.

Response: Preamble edits have been made accordingly. 

8) Page 127. Reviewer recommends clarifying the source of the data for the “total pounds of CO2 

emitted over the compliance period” and “the net MWh of energy the affected EGU produced.” 

Reviewer recommends that the source of data be sufficiently verified to ensure accurate data.

Response: Edits made to clarify the language

9) Page 128. Reviewer recommends clarifying the difference between ERC unique serial numbers 

and tracking numbers.

Response: Edits made to clarify the language

10) Page 130. Reviewer recommends clarification of how text on page 130/131 differs from 

previously described EPA-administered Allowance Tracking and Compliance System. Is this an 

alternative or additional tracking system for RE facilities or for EM&V?

“The EPA is proposing that the agency will establish a tracking system for administering the rule 

that provides for transparent access to RE project and program eligibility applications and 

regulatory approvals as well as information on ERC transfers and third party verifiers (third party 

verifiers are further discussed below as part of Evaluation, Measurement and Verification).”

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Response: The preamble language is being revised to reflect the following. The commenter is 

correct that the information on ERC transfers will be held in the Allowance Tracking and Compliance 

System. We are proposing that the information on RE project and program eligibility applications 

and regulatory approvals, as well as information on third party verifiers will be held in a 

complementary system that will also provide for transparent access to that information via the 

internet.

11) Page 131. Reviewer supports EPA’s ability to designate an agent to coordinate project 

applications to prevent burdening the agency with these tasks which can be accomplished by 

other groups. “It is proposed that EPA may designate an agent to coordinate the project 

application process and assist with review of applications.”

Response: No response needed

12) Page 132. Reviewer seeks clarification on whether the text on page 132 indicates when facilities 

may apply for approval to generate ERCS versus actually issuing ERCs. 

“The agency is proposing that ERC issuance applications will be accepted after the beginning of 

the first compliance period, as soon as the agency is able to establish an application process, 

and that applications will be accepted on a periodic basis, either quarterly or semi-annually. 

These applications will be accepted through the entirety of all compliance periods.”

Response: The EPA needs to establish the application process for approval to generate ERCs and once it 

is established providers may apply at any time to generate ERCs. ERCs will be issued annually after each 

year in a compliance period has concluded and the data has been verified. 

13) Page 133. There is a reference to the “clean energy investment pool” here, which is the only 

time that is mentioned. Reviewer suggests the discussion be extended to explain more about 

how it works. In addition, reviewer suggests including a discussion of this in the mass-based 

plan section, which would reduce confusion about why the rate-based plan discusses “massbased allowances.” 

Response: The preamble language is being revised to reflect in more detail the role that the Clean 

Energy Incentive Program would play in recognizing pre-compliance emission reductions in both the 

rate-based and mass-based approaches. This includes separate discussions in the rate-based and massbased sections.

14) Page 139. Reviewer recommends clarifying that when calculating the number of ERCs needed to 

be in compliance, the Adjusted Emission Rate must equal the Emission Standard in the first 

equation.

AAAAAAAAAAAAAAAA EEEEEE EEEEEE RRRR = MM oo CCCC2 (llll )

GG GG (MMMMh) + MMMMh EE = EE SS

Reviewer also recommends the following edit to the second equation because the adjusted 

emission rate may not equal the emission standard for EGUs that are out of compliance. 

MMMMh EE = MM oo CCCC2 (llll )

EEEEEE EEEEEE SS ( llll

MMMMh)

− GG GG (MMMMh)

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Response: Changes made accordingly

15) Page 160. Reviewer recommends the following edit on page 160 since the initial allowance 

allocation can affect the overall environmental results if emissions from non-covered sources 

are considered.

“The initial allowance allocation approach does not affect the environmental results of the 

program or generation patterns, except as it effects generation shifts between covered and uncovered sources.”

Response: An approach based on historic data doesn’t affect generation shifts between covered and 

uncovered sources; we’ve revised preamble to clarify this point.

16) Page 167. Reviewer recommends clarifying (step 3) that EGUs that generated in 2010-2012, but 

that are no longer operating, have their generation be removed from the sum total of historical 

generation and not be awarded allowances. 

Response: We edited the preamble to clarify that we included generation from units that operated in 

the historic data period and calculated allowances for such units, and added request for comment on 

treatment of generation from and allocations to units that retire before the start of the program.

17) Page 181. Reviewer recommends the following text because there is some risk of leakage to 

new sources under a rate based standard depending on the level at which the rate is set.

“This risk is not as great or is not present, depending on the difference between the intensity of 

a new unaffected source and the performance emission rate, present for existing EGUs under a 

rate-based plan...”

Response: Text has been edited accordingly.

18) Page 186. In the federal plan, reviewer recommends accounting for lost large zero carbon 

generation by subtracting the lost generation in the denominator of the rate-based compliance 

calculation for the state beginning in the year that the EGU goes offline.

Response: More clarification is needed from the reviewer on this comment

19) Page 196-197. Reviewer recommends that EPA include an equation in addition to the text on 

these pages that explains how the number of allowances in the set-aside is calculated. 

Reviewer’s understanding from the section is that Allowances in Set-Aside = 98% of Total 

Allowances x Allocation Rate x 2014 NGCC Generation between 50% Capacity Factor and 70% 

Capacity Factor, but there are certain places in the text where this is not clear.

Response: The proposed size of the set-aside is: 10% of total NGCC net summer capacity X number of 

hours in a year X allocation rate. This formula is included as an inline equation in the preamble text after 

each parameter is defined and discussed.

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20) Page 235. Reviewer recommends updating the reference to MATS to reflect recent court 

decisions. 

Response: See footnote 30 for an updated reference to the recent court decision on MATS.

21) Reviewer recommends that the structure of the rate plan and mass plan, in terms of headers 

and content, should be roughly parallel. 

Response: To the extent practicable, the structure of the rate and mass sections will mirror one 

another. However, in order to outline the details that are unique to each approach, differences in the 

structure are necessary.

Typographical Comments

1) Page 52: Reviewer recommends revising the following sentence to infer that application of ERCs 

could be submitted to agent of EPA running a tracking system. (Page 52 and throughout text).

“This demonstration must be included as part of the project application for ERC issuance to the 

EPA or its agent from the RE provider in the mass-based state.”

Response: Changes made

2) Page 53: Reviewer recommends the following edit because there are cases where RE located in 

a mass state can be counted in a rate state.

“Under the proposed mass-based approach there is a restriction to counting RE that is located in 

a mass state in a rate-based system:, if RE providers that receive mass-based set-aside 

allowances for their generation. In this case RE generation is are barred from being issued having

ERCs issued for that generation in a rate-based state.”

Response: The preamble text has been revised.

3) Page 54: A sentence says “remain under the mass, thereby” which is missing a word after 

“mass” 

Response: The preamble text has been revised.

4) Page 71: Harmonize language to use either “step-down approach” or “glide path”– the latter 

was used exclusively in the preamble and it is suggested that this language be made consistent 

here and throughout the text: “At that point, the agency is using a step-down approach, or glide 

path...”

5)

Response: “Glide path” is used consistently throughout the remainder of the preamble. Here, the use 

of the phrase “step-down approach” simply serves to further qualify the meaning of “glide path.”

6) Page 101: Reviewer recommends revising the emissions standards in the table to match those in 

the redline preamble. 

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Response: The emissions standards are up to date. 

7) Page 104: “Through Building Block 2 there is a call to shift represents shifting generation from 

fossil steam EGUs to NGCCs because NGCCs generate electricity at a lower carbon intensity and, 

thus, reduces CO2 emissions for the same level of generation”

Response: The preamble text has been revised. 

8) Page 107: “The NGCC is subject to a final period emission rate limit of 780 lbs CO2/MWh. Since 

the NGCC is always subject to its NGCC emission rate limit of 780 lbs/MWh and it is operating at 

a rate above that limit it will owe non-BB2 ERCs for all generation”

Response: The preamble text has been revised. 

9) Page 107: Reviewer recommends editing the variable name in the second equation to be 

consistent with elsewhere in the text. NGCC Generation * BB2 ERC Generating Factor on Rate = 

BB2 ERCs

Response: Terms have been redefined

10) Page 110: Reviewer recommends the following edit.

“This treatment for eligible measure types is also proposed for the set-aside for RE that is part of 

the proposed mas-based implementation approach in the federal plan,...”

Response: The preamble text has been revised.

11) Page 111: Reviewer recommends striking this comment because it should not be a relevant 

consideration for ERC generation eligibility purposes: “These technologies are also expected to 

be able to deploy on an economic basis during the compliance period, as discussed in the final 

EGs (see Sec. V.E.6).”

Response: EPA disagrees.

12) Page 142: “The EPA would require that ERC emissions generation data be reported to the EPA 

quarterly starting on April 30, 2022, and continuing every three months thereafter (i.e., the 30th 

of April, July, October, and January).”

Response: The preamble text has been revised

13) Page 152 and Page 154: Reviewer suggests clarifying the terminology “interim compliance 

period” because the EG tends to use that phrase to denote the entire eight year period between 

2022 and 2029 whereas the federal plan states that the interim compliance represents the three 

and two year periods within that 8 year span. The EG refers to the periods of three and two 

years as interim steps. Reviewer recommends that this should be done throughout the text.

Response: This model rule is written in the form to directly regulate EGUs, and thus the term 

compliance period is appropriate as the affected EGUs are complying with the emission standards 

91
set in this model rule during the interim compliance periods. In the context of the EG, the state is 

the intended reader. The EGs do not require the state to comply with the interim period, but 

require the states to regulate their affected EGUs to comply with those emission standards or 

measures set in the state plan. 

14) Page 159: Reviewer recommends including a discussion of designated representatives in both 

the rate-based and mass-based sections (currently it is just in the rate-based section). 

Response: Both the mass and the rate sections of the preamble discuss designated representatives. 

For mass, the discussion is in section V.G.1. and rate in IV.D.1

15) Page 175: It appears there is an unnecessary “The EPA requests” at the start of the first fill 

paragraph. 

Response: This text has been deleted.

16) Page 202: “The EPA is proposing that five percent of allowances will be reserved from the 

allocation for each state for the purpose of the set-aside.” Reviewer believes this should be 2 

percent, based on earlier language.

Response: The preamble text has been revised. All instances of this text have been edited to reflect 

a 5% set-aside.

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Attachment E.

93
From: Frey, Nathan J. <Nathan_J._Frey@omb.eop.gov>

Sent: Tuesday, July 28, 2015 1:19 PM

To: Jones, Toni; Szabo, Aaron

Cc: Owens, Nicole; Culligan, Kevin; Muellerleile, Caryn; Wiggins, Lanelle; Swanson, Nicholas; Boswell,

Colin; Schramm, Daniel

Subject: Summary of Interagency Comments under EO 12866 and 13563 ‐‐ Federal Plan for Regulating

Greenhouse Gas Emissions From Electric Generating Units

  

Attached please find an additional summary of interagency comments under EO 12866 and 13563 on

the EPA NPRM, Federal Plan for Regulating Greenhouse Gas Emissions From Electric Generating Units.

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

Nathan

94
Attachment E.1

95
• P.150 redline: “... This means that fractional GS-ERCs are generated for every NGCC 

MWh and when the interconnect region collectively reaches the level that would be 

generated if all NGCCs in the region operated at a 75 percent capacity factor there will 

be an amount of GS-ERCs that correlates to the emission reductions anticipated under 

BB2 of the BSER. NGCC units are expected to be incentivized to reach this level of 

generation in part due to market demand for GS-ERCs. Thus, GS-ERCs have the potential 

to play an important role in the sector meeting compliance obligations. Conversely, the 

extent to which cumulative NGCC generation will achieve the 75% capacity factor is 

ultimately related to relative market forces in future years (e.g., cost of natural gas, cost 

of RE), and the extent to which NGCC generation may fall short of the 75% level 

represents a potential discount on the benefit of a unit GS-ERC to actually achieve a zero 

CO2 emission MWh. For instance, if relative generation prices (with GS-ERCs and ERCs 

accounted for) in future years militate toward no or low increase in covered NGCC 

generation from the 2012 baseline, then a large fraction of the GS-ERCs will have been 

issued without any reduction in CO2 emissions, rising proportionally to fully reaching 

the unit zero emission MWh benefit as the NGCC generation more closely approaches 

75%. The additional ERCs required by fossil steam EGUs in situations below 75% NGCC 

generation would be made up by increased conventional ERC generation and purchase, 

but not the GS-ERCs already issued.”

• P.161-162 Redline: “While having a baseline threshold for EGU generation to credit GSERCs against closely resembles the EPA’s BSER determination, it enables a system in 

which GS-ERCs can be generated by replacing NGCC generation from one unit with 

NGCC generation from another. In this situation there is not necessarily any additional 

NGCC generation as a subcategory, but a shift in which NGCC units are generating 

electricity and to what degree. This allows for a situation in which GS-ERCs can be 

generated without achieving the anticipated reductions in CO2 emissions. An alternative 

under such an incremental GS-ERC system would be to require that system operators 

that manage more than one covered NGCC EGU to reach a cumulative average dispatch 

rate for all of their covered NGCC units that is greater than the baseline (2012 or 

state/regional average), prior to being able to generate GS-ERCs on any of their NGCC 

units.”

1. Endangered Species language. This section militates great care to not create adverse sound 

bites, and some of the current text could be adjusted to be more explicit, sentence by sentence, 

on what is being conveyed. Comments inserted (redline 423 onward) and below:

• P. 423-424 Redline: “The EPA reached this conclusion after evaluating issues relating to 

potential improvements from the fuel efficiency rule relevant to both temperature and 

oceanographic pH outputs. The EPA's ultimate finding was that “any potential for a 

specific impact [of the specific Federal action] 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 the 

same conclusion applies to the present rule. See, e.g., Ground Zero Center for Non96
Violent Action v. U.S. Dept. of Navy, 383 F. 3d 1082, 1091-92 (9th Cir. 2004). EPA 

similarly determines that the likelihood of jeopardy to a species from the CPP is 

extremely remote, and ESA does not require consultation). The EPA’s proposed 

conclusion is entirely consistent with DOI’s analysis regarding ESA requirements in the 

context of federal actions involving GHG emissions.”

97
Attachment F.

98
From: Frey, Nathan J. <Nathan_J._Frey@omb.eop.gov>

Sent: Tuesday, July 28, 2015 3:38 PM

To: Schramm, Daniel; Jones, Toni; Szabo, Aaron

Cc: Owens, Nicole

Subject: RE: Summary of Interagency Comments under EO 12866 and 13563 ‐‐ Federal Plan for

Regulating Greenhouse Gas Emissions From Electric Generating Units

  

Supposed to be Federal Plan.

From: Schramm, Daniel [mailto:Schramm.Daniel@epa.gov]  

Sent: Tuesday, July 28, 2015 3:29 PM

To: Frey, Nathan J.; Jones, Toni; Szabo, Aaron

Cc: Owens, Nicole

Subject: RE: Summary of Interagency Comments under EO 12866 and 13563 ‐‐ Federal Plan for

Regulating Greenhouse Gas Emissions From Electric Generating Units

  

Nathan, regarding the suggested edits on the ESA section, I think we are comfortable making these

changes, but I have a question. The edits refer to “the CPP” and not to the “federal plan.” Was this

intentional, and if so, what is the reasoning? Perhaps you can give me a call to discuss. Thank you,

Daniel Schramm

U.S. EPA Office of General Counsel

(202) 564‐3377

schramm.daniel@epa.gov

The contents of this message may be subject to the attorney‐client, work‐product, or deliberative

process privileges.

From: Frey, Nathan J. [mailto:Nathan_J._Frey@omb.eop.gov]  

Sent: Tuesday, July 28, 2015 1:20 PM

To: Jones, Toni; Szabo, Aaron

Cc: Owens, Nicole; Culligan, Kevin; Muellerleile, Caryn; Wiggins, Lanelle; Swanson, Nicholas; Boswell,

Colin; Schramm, Daniel

Subject: Summary of Interagency Comments under EO 12866 and 13563 ‐‐ Federal Plan for Regulating

Greenhouse Gas Emissions From Electric Generating Units

  

Attached please find an additional summary of interagency comments under EO 12866 and 13563 on

the EPA NPRM, Federal Plan for Regulating Greenhouse Gas Emissions From Electric Generating Units.

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

Nathan

99
Attachment G.

100
From: Frey, Nathan J. <Nathan_J._Frey@omb.eop.gov>

Sent: Tuesday, July 28, 2015 6:49 PM

To: Jones, Toni; Szabo, Aaron

Cc: Owens, Nicole; Culligan, Kevin; Muellerleile, Caryn; Wiggins, Lanelle; Swanson, Nicholas; Boswell,

Colin; Schramm, Daniel

Subject: Summary of Interagency Comments under EO 12866 and 13563 ‐‐ Federal Plan for Regulating

Greenhouse Gas Emissions From Electric Generating Units

  

Attached please find an additional summary of interagency comments under EO 12866 and 13563 on

the latest draft of the EPA NPRM, Federal Plan for Regulating Greenhouse Gas Emissions From Electric

Generating Units.

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

Nathan

101
Attachment G.1

102
(page numbers refer to the RLSO version)

General Comments

1. Reviewer recommends proposing (rather than taking comment on) that all non-BSER 

technologies and measures that are acceptable to generate ERCs in the emission guidelines 

(EGs) be proposed as approved to generate ERCs under a rate-based federal plan. Reviewer 

notes that renewable and nuclear are included as defaults but energy efficiency is missing. 

2. Reviewer recommends that the allowances that are set-aside in the mass-based approach for 

low- or zero-emission activities be distributed using a technology-neutral methodology and not 

reserved exclusively for RE. For example, on RLSO page 163, reviewer recommends that new 

nuclear units and capacity uprates at existing nuclear units should be eligible to receive set-aside 

allowances to provide equal treatment under the rate-based and mass-based plans. Reviewer 

also recommends renaming this group of allowances as the Clean Energy Set-Aside to avoid 

confusion with the set-aside for existing NGCC. 

Technical Comments

Page 43 RLSO. Reviewer requests clarifying the meaning and intent of this: “all of the language and 

provisions in the regulatory text relevant to these other ERC resources is relevant only to the proposed 

model trading rule and not to the federal plan as such. “

Page 69 RLSO. Reviewer supports language clarifying restriction on trading to only between other states 

with subcategory rates, and suggests referencing that this is consistent with the final EGs rules on ratebased trading, as described on pages 1526-27 (of 7/25 redlined version of the preamble).

Page 92 RLSO. Reviewer requests clarifying why a “similar mechanism [to an allowance set-aside] in a 

rate-based approach to address reliability issues in the federal plan” is not needed. 

Page 139 RLSO. Reviewer suggests clarifying changing “certain nuclear” to “new and uprated nuclear”. 

p.144 – “(3) new nuclear units and capacity uprates at existing nuclear units, and RE providers that 

develop metered projects and programs whose results, in MWh, are quantified and verified according to 

EM&V criteria as described below in section &&& IV.D.6 of this preamble.” Reviewer supports the 

revised language that includes reference to “metered” RE projects and programs. However, given that 

the requirement now exists for the projects to be metered, reviewer recommends allowing all 

renewable energy technologies – including offshore wind and distributed solar – to generate ERCs, 

provided they are metered and adhere to EM&V criteria. While all renewable energy technologies may 

not be “expected to be able to deploy on an economic basis during the compliance period” (p.164), if 

they aren’t economic, states are very unlikely to deploy them. This should result in no additional costs 

or administrative challenges.

 

103
Page 148 RLSO. Reviewer suggests rewording the following sentence: “This means that most NGCC units 

are being called to increase annual generation from 2012 baseline emissions.” Reviewer is concerned 

this could be seen as a requirement for the implementation of part of BSER, which language above 

reiterates is not the case. Suggested rewording: “This level of generation, for most NGCC units, would 

represent an increase in annual generation from a 2012 baseline.”

Page 149 RLSO. Reviewer recommends clarifying that (addition in red) “All affected NGCC generation 

will be credited, with ERCs, by a factor that represents the described emission reductions from 

incremental generation; ERCs credited in this way will be designated as Gas Shift ERCs (GS-ERCs) for 

clarity.” Reviewer also notes that this seems to conflict with the language describing only marginal 

generation beyond a certain average capacity factor will be credited, as described on pages 316-317.

Page 168 RLSO. Reviewer recommends the following language (as highlighted) to allow for the 

possibility that EPA may in the future find that some biogenic feedstock is carbon neutral: 

“The revised Framework, and the EPA’s Science Advisory Board (SAB) peer review of the 2011 Draft 

Framework, finds that it is not scientifically valid to assume that all biogenic feedstocks are “carbon 

neutral” and that the net biogenic CO2 atmospheric contribution of different biogenic feedstocks 

generally depends on various factors related to feedstock characteristics, production, processing and 

combustion practices, and, in some cases, what would happen to that feedstock and the related 

biogenic emissions if not used for energy production. A given feedstock may be found to be carbon 

neutral after appropriate EPA assessment.” 

Page 227-244 RLSO. Reviewer notes that pages 227-244 appear to be language from earlier versions of 

draft EM&V guidance documents, and suggests clarifying if the inclusion of the language in this 

document means that a separate guidance document on EM&V is no longer intended to be provided, or 

if this is meant to complement the separate guidance. 

p.229 – “These categories include project-based measurement and verification (M&V), deemed savings, 

and comparison group approaches such as randomized control trials (RCT). Regardless of the approach 

selected, the EPA is proposing that annual savings values must be quantified using these EM&V methods 

at specified time intervals (in years) on a recurring basis over the effective useful life of the EE project or 

measure in order to ensure accurate and reliable savings values. To be considered presumptively 

approvable, EE providers must conduct apply the above methods at a minimum of four year intervals for 

building energy codes and product standards; every one, two or three years for publicly or rate-payer 

funded EE programs, depending on the program type, magnitude of savings, and experience with the 

program; and annually for large individual commercial and industrial projects, unless the EE provider can 

credibly demonstrate why this is not possible and how the accuracy and reliability of savings values will 

be maintained.”

Reviewer finds the inclusion of deemed savings in this paragraph confusing. Reviewer believes that EPA 

means that states should update their deemed savings estimates every three years, per the language on 

subsequent pages, which makes sense. In this paragraph, however, it appears that EPA would require 

states to repeatedly calculate savings from the same project using deemed savings. 

104
Page 319-320 RLSO: Reviewer notes the references to 111(b) seems to be outdated and should updated: 

“ Specifically, an additional MWh of eligible generation would earn the affected EGU allowances equal 

to the level of emissions permitted per MWh of net generation under the 111(b) new source standard, 

which is 1,030 lb/MWh-net.” 

Typographical Comments

p. 18. Given EPA’s intent to finalize a single approach, commenter recommends the following change

should delete “if we opt to finalize a single approach” at the end of that paragraph. “We invite 

comment on which approach, i.e., either mass-based or rate-based trading, should be selected if when

we opt to finalize a single approach.”

Page 22. Reviewer requests clarification on how “vulnerable” communities are defined. 

Page 68. Reviewer notes that language is missing here: “The final guidelines specify the concern of 

leakage...”. 

Page 85. Reviewer requests clarification on how the federal plan can propose a two year compliance 

period after 2030 when this is finalized in the EG.

Page 90. "The EPA will work with the ISO/RTO Council to convene a face-to-face meeting for planning 

authorities with the EPA during the comment period to discuss any concerns or other feedback on the 

federal plan from those entities."

Comment: Reviewer still recommends expanding use of the ISO/RTO Council to reliability coordinators 

and planning authorities because the IRC does not encompass all areas of the country. The EPA 

response refers to text on Pg. 88 in a different context.

Page 144. Reviewer recommends clarifying that “RE providers that develop metered projects and 

programs...” become the fourth category and not be included in the third category to simplify 

composition.

Page 148-149. Reviewer recommends noting that NGCC will receive “a partial credit” or otherwise 

clarifying that NGCC will not receive an entire emission reduction credit for every hour of electricity it 

produces. 

Page 158. Reviewer believes that the steam generating unit emissions standard should be 1305 lbs 

CO2/MWh, as shown on page 142 (Table 4). That change would also change some of the equations on 

the page.

 

Page 163. Reviewer notes that the following sentence is incomplete and requests clarification about 

what is being proposed: “Further, the EPA is proposing that new nuclear units and capacity uprates at 

existing nuclear units that meet the requirements for eligible resources in the emission guidelines (as 

specified in the final emission guidelines Sec.VIII.K.) and all other requirements related to ERC issuance

in the emission guidelines and this proposal.”

105
p.221 –Reviewer notes a possible typo “The EPA requests comment on all metering, measurement, 

verification, and other requirements included in this subsection, including the appropriateness of their 

use for each type of renewable nuclear energy resource (including the relvant size and distribution of 

such resource) that qualifies for issuance of ERCs for use in Clean Power Plan compliance.”

p. 222 - "Prorated MWh = (1 - incremental CHP emission rate/applicable affected EGU emission limit

rate) * CHP MWh output, where the ratio is limited to values between 0 and 1." Reviewer believes the 

word “limit” is a mistake in the sentence above, and that it should be struck to be more consistent with 

the sentence later on that same page: "The incremental rate would be relative to the applicable CO2 

emission rate for affected EGUs in the state and would be limited to values between 0 and 1."

Page 398. Reviewer recommends considering whether the list of completeness criteria discussed on Pg. 

398 should include the 111(d) plan requirement regarding demonstrating that the state has consulted 

with the planning authority/reliability coordinator. (Also applies to the reg text, Pg.3.)

Page 90. Reviewer recommends further explaining why emergency events (on Pg. 90) that would 

otherwise trigger the reliability safety valve (emissions would not be counted against a state plan) would 

not do so under a federal plan, especially with respect to any short-term modifications to a federal plan 

that may be needed (noting that this depends on how the final CPP is clarified on this issue).

106
Attachment H.

107
From: Jones, Toni <Jones.Toni@epa.gov>

Sent: Tuesday, July 28, 2015 9:26 PM

To: Frey, Nathan J.

Cc: Culligan, Kevin; Harvey, Reid; Tsirigotis, Peter; Eck, Janet; Cozzie, David

Subject: EO 12866 CPP Federal Plan ‐ RIA

  

Hi Nathan,

I hope this email finds you well.  

Attached, please find for your review the draft CPP Federal Plan RIA and the draft RIA spreadsheet for

ROCIS.  During your review, please be reminded that the impacts from the 111(d) CPP EGs and the

federal plan are not additive.

  

If you have any questions, please do not hesitate to contact me.

Kind regards,

Toni W. Jones

  

Toni Wyche Jones, EI, CFM | Fuels & Incineration Group | Sector Policies & Programs Division - Mail Code E143-

05 | Office of Air Quality Planning & Standards | U.S. Environmental Protection Agency | RTP, NC 27711 | Phone: 

(919) 541-0316 |

  

108
Attachment H.1

109
EO12866_CPP Federal Plan 2060 AS47 RIA Final_20150728

Regulatory Impact Analysis 

for the 

 Proposed Federal Plan Requirements for 

Greenhouse Gas Emissions from Electric 

Utility Generating Units Constructed on or 

Before January 8, 2014; Model Trading Rule 

 

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ii

[This page intentionally left blank] 

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EPA-452/R-15-006 

July 2015 

Regulatory Impact Analysis for the for the 

 Proposed Federal Plan Requirements for Greenhouse Gas 

Emissions from Electric Utility Generating Units Constructed on or 

Before January 8, 2014; Model Trading Rule 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

Office of Air Quality Planning and Standards 

Research Triangle Park, NC 27711 

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iv

CONTACT INFORMATION 

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

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

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

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

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

macpherson.alex@epa.gov). 

ACKNOWLEDGEMENTS 

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

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

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

International. 

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v 

TABLE OF CONTENTS

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

ACRONYMS ................................................................................................................................ ix

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

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

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

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

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

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

1.3 Background for the Proposed Federal Plan and Model Trading Rules .................... 1-4

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

1.3.2 Trade in Compliance Instruments across States in the Federal Plan ............. 1-5

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

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

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

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

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

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

1.5.2 Costs ..........................................................................................................1-13

1.5.3 Monetized Climate Benefits and Health Co-benefits ..................................1-15

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

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

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

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

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

1.5.7 Uncertainty Analysis ..................................................................................1-34

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

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

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

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

2.2 Paperwork Reduction Act ...................................................................................... 2-1

2.3 Initial Regulatory Flexibility Analysis.................................................................... 2-1

2.3.1 Reasons why Action is Being Considered ................................................... 2-1

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

2.3.3 Description and Estimate of Affected Small Entities ................................... 2-3

2.3.4 Compliance Cost Impact Estimates ............................................................2-10

2.3.5 Projected Reporting, Recordkeeping and Other Compliance Requirements 2-18

2.3.6 Related Federal Rules ................................................................................2-18

2.3.7 Regulatory Flexibility Alternatives ............................................................2-19

2.4 Unfunded Mandates Reform Act (UMRA) ............................................................2-24

2.5 Executive Order 13132: Federalism ......................................................................2-24

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vi 

2.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments ...............................................................................................................2-24

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

and Safety Risks ..........................................................................................................2-24

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

Distribution, or Use .....................................................................................................2-24

2.9 National Technology Transfer and Advancement Act (NTTAA) ...........................2-24

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

Minority Populations and Low-Income Populations .....................................................2-25

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LIST OF TABLES

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

Plan Approach ............................................................................................................1-11

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

Plan Appproach ..........................................................................................................1-12

Table 1-3. Projected CO2 Emission Reductions, Relative to 2005 ...................................1-13

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

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

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

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

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

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

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

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

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

Table 2-1. SBA Size Standards by NAICS Code .............................................................. 2-8

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

under the Rate-Based Federal Plan Approach in 2030 .................................................2-14

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

Approach ....................................................................................................................2-14

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

under the Mass-Based Federal Plan Approach in 2030 ................................................2-15

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

Approach ....................................................................................................................2-15

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

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) .........2-16

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

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) .........2-17

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ACRONYMS

[Placeholder]

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1-1 

CHAPTER 1: SUMMARY OF POTENTIAL REGULATORY IMPACTS

1.1 Introduction 

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

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

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

Rule” (herein also referred to as “proposed federal plan and model trading rules”). In this action, 

the Environmental Protection Agency (EPA) is proposing a federal plan to implement the 

emission guidelines for existing fossil fuel-fired EGUs under the Clean Air Act (CAA). The 

emission guidelines were proposed in June 2014 and finalized on [&&&] as the Carbon Pollution 

Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units (also 

referred to as the Clean Power Plan Emission Guidelines). The EPA is taking comment on many 

of the elements of this proposal. 

This proposal presents two approaches to a federal plan for states and other jurisdictions 

that do not adopt and submit to the EPA in a timely manner an approvable plan: a rate-based 

emission trading program and a mass-based emission trading program. The federal plan is an 

important measure to ensure that congressionally mandated emission standards under the 

authority of the CAA are implemented. This proposal also constitutes two proposed model 

trading rules that states can adopt or tailor for implementation of the emission guidelines. 

The proposed federal plan is related to but separate from the Final Clean Power Plan 

Emission Guidelines. The final emission guidelines establish the best system of emission 

reduction (BSER) for applicable fossil fuel-fired EGUs in the form of a standard of &&& for 

steam-fired EGUs and a standard of &&& for natural gas-fired combined cycle EGUs and 

provide guidance and criteria for the development of approvable state plans. The purpose of the 

proposed federal plan is to establish requirements, directly applicable to a state’s affected EGUs 

that meet the BSER in order to achieve reductions in carbon dioxide (CO2) emissions in the case 

where a state or other jurisdiction does not submit an approvable plan. The stringency of the 

emission performance levels established in the final EGs will be the same whether implemented 

through a state plan or a federal plan.

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1-2 

1.2 Legal, Scientific and Economic Basis for this Rulemaking 

1.2.1 Statutory Requirement 

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

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

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

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

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

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

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

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

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

[August 31, 2016]. States are also allowed to seek a two year extension for a final plan submittal, 

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

final state plan or initial submittal, or if either a final state plan or an initial submittal does not 

meet the requirements of the final emission guidelines, the Agency will take the appropriate 

steps to finalize and implement a federal plan. 

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

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

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

state plan. 

1.2.2 Health and Welfare Impacts from Climate Change 

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

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

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

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

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

not just over the next few decades, but in the coming centuries and millennia.”1 

 

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

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1-3 

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

Administrator issued the Endangerment Finding under CAA section 202(a)(1).2 In the 

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

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

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

United States. 

Since the administrative record concerning the Endangerment Finding closed following 

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

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

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

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

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

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

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

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

Guidelines preamble3 and in Chapter 4 of the Clean Power Plan Final Rule Regulatory Impact 

Analysis (RIA).4

1.2.3 Market Failure 

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

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

 

2

 “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”). 

3

 [Placeholder] 

4

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

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

Division, Research Triangle Park, NC. December. Available at: <[Placeholder]>. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

internalize the negative externality associated with CO2 emissions. 

1.3 Background for the Proposed Federal Plan and Model Trading Rules 

1.3.1 Definition of Affected Sources 

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

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

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

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

 

5

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

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

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

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

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1.3.2 Trade in Compliance Instruments across States in the Federal Plan 

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

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

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

affected EGUs, or procure zero-emissions megawatt hours (MWhs) from eligible resources, in 

any other state covered by a federal plan that uses the same approach. In the proposed massbased federal-plan trading program, this would mean that affected EGUs in a state covered by 

the federal plan could use, as a compliance instrument, an allowance distributed in any other 

state covered by a federal plan. Similarly, in the proposed rate-based federal-plan trading 

program approach, this would mean that affected EGUs in a state covered by a federal plan could 

use, as a compliance instrument, an emission rate credit (ERC) issued in any other state covered 

by a federal plan. We propose that an affected EGU in a state covered by a mass-based trading 

federal plan must use allowances for compliance (not ERCs). Similarly, an affected EGU in a 

state covered by the rate-based trading federal plan must use ERCS for compliance (not 

allowances). 

1.3.3 Model Trading Rule 

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

proposal would be presumptively approvable. Additionally, there are stand-alone portions of the 

model trading rules, such as the evaluation, measurement and verification (EM&V) procedures, 

that would be approvable even if a state adopted an approach that differs from the federal plan. 

The model trading rules serves as a mechanism to create larger trading markets since consistency 

of state plans with the federal plan allows trading across both the state and federal programs. The 

EPA expects that a larger trading region would likely result in lower overall costs of compliance 

to affected EGUs due to the increase in abatement options. 

1.4 Summary of Regulatory Analysis 

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

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

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

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

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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. 

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

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

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

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

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

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

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

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

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

many states will require a federal plan. Because of this lack of information, for this RIA, the 

EPA has chosen to examine a scenario where all states of the contiguous U.S. will be regulated 

under a federal plan. Furthermore, because of the lack of information as to which states will 

adopt the model rule, the EPA has chosen to examine a scenario where all states of the 

contiguous U.S. adopt the model trading rule. Additionally, we examine two alternative federal 

plan approach scenarios, which will be described in more detail below, for implementation of 

federal plans. The first federal plan approach we examine in this RIA assumes all states in the 

contiguous U.S. are regulated under a rate-based federal plan. The second federal plan approach 

we examine assumes all contiguous states are regulated under a mass-based federal plan. 

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

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

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

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

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

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

As mentioned earlier, the EPA is taking comment on many of the elements of the federal 

plan and model trading rules proposal. The RIA also presents a discussion of limitations of the 

analysis and solicitations for public comments that may help improve the analysis supporting the 

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promulgation of the federal plan and model trading rules. In evaluating the impacts of the 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

analyses.6

1.4.1 Base Case and Years of Analysis 

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

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

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

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

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

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

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

 

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

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

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

21, 2015. 

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requirements. Additional legally binding and enforceable commitments for GHG reductions 

considered in the base case are discussed in the documentation for IPM.7 

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

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

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

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

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

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

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

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

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

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

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

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

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

1.4.2 Federal Plan Approaches Examined in RIA 

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

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

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

developing their plans.8 As noted above, like the RIA for the Final Clean Power Plan Emission 

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

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

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

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

 

7

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

8

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

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

all instances in all time periods in all places. 

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

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

the emission performance rates at affected EGUs. However, this proposed rule does not allow 

demand-side energy efficiency to directly count toward the compliance rate of affected EGUs in 

a rate-based compliance approach. Therefore, the EPA estimates that this RIA might understate 

the incremental compliance costs of the proposed federal plan and model trading rules.9

Compliance strategies under the federal plan that do not rely on demand-side energy efficiency 

will likely rely on different abatement measures than those modeled for this RIA. The climate 

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

presented here. The EPA is inviting comment on the inclusion of demand-side energy efficiency 

as a direct compliance measure under a rate-based approach in the federal plan and will seek to 

improve analysis supporting the final rule. 

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

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

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

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

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

Clean Power Plan Emission Guidelines RIA assumes that the plan applies a state’s rate-based 

goal as a requirement for affected EGUs in that state to achieve.10 The proposed federal plan 

 

9

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

to lower demand, which in turn reduces the compliance cost of achieving the performance rates. 

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

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

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

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

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

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

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specifically establishes an emissions rate performance standard that is applied to affected steamfired EGUs and an emission rate performance standard that is applied to affected natural gasfired combined cycle EGUs. 

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1.5 Summary of Regulatory Analysis 

1.5.1 Emissions Reductions 

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

plan approach. 

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

Approach1

 

CO2

(million short tons) 

SO2

(thousand short tons) 

Annual NOX 

(thousand short tons) 

2020 Rate-Based Approach 

Base Case 2,155 1,311 1,333 

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

Emissions Change -69 -14 -50 

2025 Rate-Based Approach 

Base Case 2,165 1,275 1,302 

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

Emissions Change -232 -178 -165 

2030 Rate-Based Approach 

Base Case 2,227 1,314 1,293 

Federal Plan Approach 1,812 996 1,011 

Emission Change -415 -318 -282 

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

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

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

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

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

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

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

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

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

air pollutants. 

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

plan approach. 

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

Appproach1

 

CO2

(million short tons) 

SO2

(thousand short tons) 

Annual NOX 

(thousand short tons) 

2020 Mass-Based Approach 

Base Case 2,155 1,311 1,333 

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

Emissions Change -81 -54 -60 

2025 Mass-Based Approach 

Base Case 2,165 1,275 1,302 

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

Emissions Change -265 -185 -203 

2030 Mass-Based Approach 

Base Case 2,227 1,314 1,293 

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

Emission Change -413 -280 -278 

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

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

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

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

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

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

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

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

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

air pollutants. 

 

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

approaches. 

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

 

CO2 Emissions 

(million short tons) 

CO2 Emissions: 

Change from 2005 

(million short tons) 

CO2 Emissions Reductions: 

Percent Change from 2005 

 2005 2020 2025 2030 2020 2025 2030 

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

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

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

Source: Integrated Planning Model, 2015. 

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

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

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

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

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

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

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

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

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

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

compared to 2005 levels. 

1.5.2 Costs 

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

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

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

recordkeeping requirements (MR&R).11 In the rate-based approach, energy efficiency activities 

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

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

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

 

11 See Chapter 3 of the Clean Power Plan Final Rule RIA for a detailed discussion of the compliance cost estimates. 

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

assumed to be the same in the two federal plan approaches.12 The compliance assumptions, and 

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

The annual incremental cost is the projected additional cost of complying with the 

proposed rule in the year analyzed and includes the net change in the annualized cost of capital 

investment in new generating sources and heat rate improvements at coal-fired steam generating 

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

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

compliance. The total compliance cost estimates presented here include the costs associated with 

monitoring, reporting, and recordkeeping.13 The costs for both federal plan approaches are 

reflected in Table 1-4 below. All dollar estimates are in 2011 dollars. 

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

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

2025 and $8.4 billion in 2030, including the costs associated with monitoring, reporting, and 

recordkeeping.14 The EPA estimates the annual incremental compliance cost for the mass-based 

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

2025 and $5.1 billion in 2030, including the costs associated with monitoring, reporting, and 

recordkeeping. 

 

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

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

Generating Units. Demand-Side Energy Efficiency. 

13 These costs are estimated outside of the IPM modelling framework as IPM only models the contiguous U.S. and 

does not incorporate monitoring, reporting, and recordkeeping requirements specific to the Clean Power Plan 

Final Rule. 

14 The MR&R costs of the proposed federal plan and model trading rules are assumed to be the same as those 

estimated for the Clean Power Plan Final Rule. These MR&R costs estimates are $65 million in 2020, $15 million 

in 2025 and $15 million in 2030 and are assumed to be the same for both rate-based and mass-based plan 

approaches. Note the MR&R costs in 2020 are related to facilities setting up net energy output monitoring and 

upgrading data acquisition systems. 

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

Incremental Cost from Base Case (billions of 2011$)

Rate-based Approach Mass-based Approach 

2020 $2.5 $1.4 

2025 $1.0 $3.0 

2030 $8.4 $5.1 

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

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

Final Rule RIA for a more complete explanation. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

presented later in this Chapter. 

1.5.3 Monetized Climate Benefits and Health Co-benefits 

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

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

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

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Revised July 2015), henceforth denoted as the current SC-CO2 TSD.15 Additionally, this analysis 

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

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

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

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

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

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

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

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

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

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

 

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

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

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

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

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

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

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

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Table 1-5 Quantified and Unquantified Benefits 

Benefits Category Specific Effect 

Effect Has 

Been 

Quantified

Effect Has 

Been 

Monetized

More Information 

Improved 

Environment 

Reduced climate 

effects 

Global climate impacts from CO2 —1  SC-CO2 TSD 

Climate impacts from ozone and black carbon (directly 

emitted PM) — — 

Ozone ISA, PM 

ISA2

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

aerosols, other impacts) — — IPCC2

Improved Human Health (co-benefits) 

Reduced incidence of 

premature mortality 

from exposure to 

PM2.5

Adult premature mortality based on cohort study estimates

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

Infant mortality (age <1)   PM ISA 

Reduced incidence of 

morbidity from 

exposure to PM2.5

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

Hospital admissions—respiratory (all ages)   PM ISA 

Hospital admissions—cardiovascular (age >20)   PM ISA 

Emergency room visits for asthma (all ages)   PM ISA 

Acute bronchitis (age 8-12)   PM ISA 

Lower respiratory symptoms (age 7-14)   PM ISA 

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

Asthma exacerbation (asthmatics age 6-18)   PM ISA 

Lost work days (age 18-65)   PM ISA 

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

Chronic Bronchitis (age >26) — — PM ISA2

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

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

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

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

ages and populations) 

— — PM ISA3

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

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

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

Reduced incidence of 

mortality from 

exposure to ozone 

Premature mortality based on short-term study estimates (all 

ages)   Ozone ISA 

Premature mortality based on long-term study estimates 

(age 30–99) — — Ozone ISA2

Reduced incidence of 

morbidity from 

exposure to ozone 

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

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

Emergency department visits for asthma (all ages)   Ozone ISA 

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

School absence days (age 5–17)   Ozone ISA 

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

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

Cardiovascular and nervous system effects — — Ozone ISA3

Reproductive and developmental effects — — Ozone ISA3,4

 

 

 

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Table 1-5. Continued 

Reduced incidence of 

morbidity from 

exposure to NO2

Asthma hospital admissions (all ages) — — NO2 ISA2

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

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

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

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

Premature mortality — — NO2 ISA2,3,4

Other respiratory effects (e.g., airway hyperresponsiveness 

and inflammation, lung function, other ages and 

populations) 

— — NO2 ISA3,4

Reduced incidence of 

morbidity from 

exposure to SO2

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

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

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

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

Premature mortality — — SO2 ISA2,3,4

Other respiratory effects (e.g., airway hyperresponsiveness 

and inflammation, lung function, other ages and 

populations) 

— — SO2 ISA2,3

Reduced incidence of 

morbidity from 

exposure to 

methylmercury 

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

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

memory, behavior) — — IRIS; NRC, 20003

Cardiovascular effects — — IRIS; NRC, 20003,4

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

Improved Environment (co-benefits) 

Reduced visibility 

impairment 

Visibility in Class 1 areas — — PM ISA2

Visibility in residential areas — — PM ISA2

Reduced effects on 

materials 

Household soiling — — PM ISA2,3

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

Reduced PM 

deposition (metals and 

organics) 

Effects on individual organisms and ecosystems — — PM ISA3

Reduced vegetation 

and ecosystem effects 

from exposure to 

ozone 

Visible foliar injury on vegetation — — Ozone ISA2

Reduced vegetation growth and reproduction — — Ozone ISA2

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

Damage to urban ornamental plants — — Ozone ISA3

Carbon sequestration in terrestrial ecosystems — — Ozone ISA2

Recreational demand associated with forest aesthetics — — Ozone ISA3

Other non-use effects Ozone ISA3

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

cycles, net primary productivity, leaf-gas exchange, 

community composition) 

— — Ozone ISA3

Reduced effects from 

acid deposition 

Recreational fishing — — NOx SOx ISA2

Tree mortality and decline — — NOx SOx ISA3

Commercial fishing and forestry effects — — NOx SOx ISA3

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

Other non-use effects NOx SOx ISA3

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

 

 

 

 

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Table 1-5. Continued 

Reduced effects from 

nutrient enrichment 

Species composition and biodiversity in terrestrial and 

estuarine ecosystems — — NOx SOx ISA3

Coastal eutrophication — — NOx SOx ISA3

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

Other non-use effects NOx SOx ISA3

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

regulation) — — NOx SOx ISA3

Reduced vegetation 

effects from exposure 

to SO2 and NOx

Injury to vegetation from SO2 exposure — — NOx SOx ISA3

Injury to vegetation from NOx exposure — — NOx SOx ISA3

Reduced ecosystem 

effects from exposure 

to methylmercury 

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

effects) — — 

Mercury Study 

RTC3

Commercial, subsistence and recreational fishing — —

Mercury Study 

RTC2

1

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

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

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

quantified changes in CO2 emissions. 

2

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

due to data and resource limitations for this analysis. 

3

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

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

4

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

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

the association. 

1.5.3.1 Estimating Global Climate Benefits 

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

rulemaking using the SC-CO2 estimates presented in the current SC-CO2 TSD.16 We refer to 

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

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

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

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

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

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

 

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

benefits. 

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

incremental reduction in cumulative global CO2 emissions). 

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

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

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

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

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

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

estimates.17

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

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

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

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

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

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

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

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

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

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

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

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

models (DICE, FUND, and PAGE)18, which the IWG harmonized across three key inputs: the 

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

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

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

 

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

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

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

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methodology and the current SC-CO2 TSD19 presents and discusses the updated estimates. The 

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

the year 2020 (2011$), and each estimate increases over time.20 These SC-CO2 estimates are 

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

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

percentile at 3 percent. 

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

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

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

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

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

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

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

models understandably lags behind the most recent research.21 In particular, the IPCC Fourth 

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

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

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

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

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

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

 

19 The IWG published the updated TSD in 2013, then issued two minor corrections to it in July 2015. 

20 The 2010 and 2013 TSDs present SC-CO2 in 2007$ per metric ton. The estimates were adjusted to (1) short tons 

using the conversion factor of 0.90718474 metric tons in a short ton and (2) 2011$ using GDP Implicit Price 

Deflator, http://www.gpo.gov/fdsys/pkg/ECONI-2013-02/pdf/ECONI-2013-02-Pg3.pdf. 

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

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

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

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

2014, www.epri.com. 

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

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

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

to reflect the best available scientific and economic information on climate change.22 The 

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

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

future updates. 

1.5.3.2 Estimating Air Quality Health Co-Benefits 

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

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

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

associated with the reduced exposure to these two pollutants.23 Unlike the global SC-CO2

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

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

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

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

endpoints ranging in severity from lower respiratory symptoms to heart attacks24 (U.S. EPA, 

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

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

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

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

2011). 

 

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

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

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

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

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

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

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

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

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

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

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

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

health impact and economic benefits assessments. 

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

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

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

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

estimates by aggregating the impacts in BenMAP25 to the region (i.e., East, West, and California) 

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

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

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

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

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

and 2030. 

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

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

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

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

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

rates, or other local factors for any specific location. 

 

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

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

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

impacts. 

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

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

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

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

health co-benefits. 

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

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

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

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

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

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

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

(U.S. EPA, 2009b). 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

1.5.3.3 Combined Benefits Estimates 

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

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

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

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

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

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

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

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

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

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

All dollar estimates are in 2011 dollars. 

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

Approach (billions of 2011$)* 

SC-CO2 Discount Rate and Statistic** 

Climate 

Benefits 

Only 

Climate Benefits plus Health Co-benefits 

(Discount Rate Applied to Health Co-benefits) 

3% 7% 

In 2020 69 million short tons CO2 

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

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

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

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

In 2025 232 million short tons CO2 

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

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

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

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

In 2030 415 million short tons CO2 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Approach (billions of 2011$)* 

SC-CO2 Discount Rate and Statistic** 

Climate 

Benefits 

Only 

Climate Benefits plus Health Co-benefits 

(Discount Rate Applied to Health Co-benefits) 

3% 7% 

In 2020 82 million short tons CO2 

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

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

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

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

In 2025 264 million short tons CO2 

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

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

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

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

In 2030 413 million short tons CO2 

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

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

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

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

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

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

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

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

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

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

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

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

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

1.5.4 Net Benefits 

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

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

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

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

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

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

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

ecosystem effects and visibility impairment. Upon considering these limitations and 

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

outweigh the costs. 

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

Federal Plan Approach (billions of 2011$) a 

 Rate-Based Approach 

2020 2025 2030

Climate Benefits b

5% discount rate $0.80 $3.1 $6.4 

3% discount rate $2.8 $10 $20 

2.5% discount rate $4.1 $15 $29 

95th percentile at 3% 

discount rate $8.2 $31 $61 

Air Quality Co-benefits Discount Rate 

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

Air Quality Health 

Co-benefits c $0.70 to $1.8 $0.64 to $1.7 $7.4 to $18 $6.7 to $16 $14 to $34 $13 to $31 

Compliance Costs d

$2.5 $1.0 $8.4 

Net Benefits e

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

Non-Monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition 

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

Visibility impairment 

a

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

b

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

efficiency program and participant costs. 

e

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

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

on additional discount rates. 

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

Federal Plan Approach (billions of 2011$) a 

 Mass-Based Approach 

2020 2025 2030

Climate Benefits b

5% discount rate $0.94 $3.6 $6.4 

3% discount rate $3.3 $12 $20 

2.5% discount rate $4.9 $17 $29 

95th percentile at 3% 

discount rate $9.7 $35 $60 

Air Quality Co-benefits Discount Rate 

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

Air Quality Health 

Co-benefits c $2.0 to $4.8 $1.8 to $4.4 $7.1 to $17 $6.5 to $16 $12 to $28 $11 to $26 

Compliance Costs d

$1.4 $3.0 $5.1 

Net Benefits e

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

Non-Monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition 

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

mercury 

Visibility improvement 

a

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

b

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

efficiency program and participant costs. 

e

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

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

on additional discount rates. 

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1.5.5 Economic Impacts 

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

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

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

mass-based federal plan approaches. 

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

Base Case) 

 Rate-Based Mass-Based 

 2020 2025 2030 2020 2025 2030 

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

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

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

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

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

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

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

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

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

and capacity changes by fuel type. 

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

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

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

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

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

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

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

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

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

1.5.6 Employment Impacts 

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

job creation and employment. According to the Executive Order, “our regulatory system must 

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protect public health, welfare, safety, and our environment while promoting economic growth, 

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

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

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

employment analyses.26 While the economy continues moving toward full-employment, 

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

magnitude. 

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

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

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

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

of the utility power sector used for this regulatory analysis, and U.S government data on 

employment and labor productivity. 

In the electricity, coal, and natural gas sectors, the EPA uses the IPM estimates of the 

changes in generation and fuel use of the proposed rule to estimate there could be a net decrease 

of approximately 25,000 job-years27 in 2025 for the proposed rule under the rate-based federal 

plan approach and approximately 26,000 job-years in 2025 under the mass-based approach. For 

2030 the estimates of the net decrease in job-years is 30,900 under the rate-based plan, and 

33,700 under the mass-based plan. The Agency is also offering an illustrative calculation of 

potential employment effects due to demand-side energy efficiency programs. Employment 

impacts from demand-side energy efficiency programs in 2030 could range from approximately 

52,000 to 83,000 jobs under proposed federal plan and model trading rules. The IPM-derived 

job-year numbers for the electricity, coal and natural gas sectors should not be added to the 

 

26 The employment analysis in this RIA is part of EPA’s ongoing effort to “conduct continuing evaluations of 

potential loss or shifts of employment which may result from the administration or enforcement of [the Act]” 

pursuant to CAA section 321(a). 

27 Job-years are not individual jobs, but rather the amount of work performed by the equivalent of one full-time 

individual for one year. For example, 20 job-years in 2020 may represent 20 full-time jobs or 40 half-time jobs in 

that year. 

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demand-side efficiency job impacts, since the former are reported in full-time equivalent jobyears, whereas the latter do not distinguish between full- and part-time employment. More detail 

about these analyses can be found in Chapter 6 of the final Clean Power Plan Emission 

Guidelines RIA. 

1.5.6 Additional Analysis of Output-Based Allocation as a Means of Mitigating Leakage 

The EPA is proposing a set-aside approach referred to as output-based allocation (OBA), 

which provides targeted allocations of a limited portion of allowances to existing NGCC units as 

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

the environmental integrity of a mass-based plan by addressing incentives for generation to shift 

away from EGUs covered under mass-based plans to new unaffected EGUs. OBA provides an 

incentive for eligible EGUs in mass-based states to increase their generation in order to increase 

their allocation of allowances. This approach helps align the generation incentives for eligible 

EGUs in mass-based states with new EGUs within mass-based states that are not subject to the 

mass-based limits as well as analogous EGUs in other states covered by emission rate limits, 

mitigating the potential for emissions leakage. 

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

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

proposed in this rulemaking. Therefore, the EPA conducted additional analysis to approximate 

the potential emissions reductions if the OBA set-aside were included in that mass-based 

scenario. The EPA is inviting comment on OBA. If appropriate, the EPA will further explore 

OBA as a means to mitigate leakage in the analysis supporting the final federal plan and model 

trading rules. 

The application of OBA will provide an incentive to increase generation at existing 

NGCC EGUs in place of generation at new NGCC EGUs and existing fossil steam EGUs. To 

approximate the effect of this incentive in the mass-based scenario, the EPA used IPM model 

plant results from the mass-based scenario to construct the dispatch order for model plants in 

each IPM region. Then, based on the allowance prices for the state in which each model plant 

resides, the EPA adjusted the dispatch order in the case where existing NGCC units were 

allocated allowances at a rate of 1,030 lbs/MWh for each MWh generated above a 50 percent 

capacity factor as proposed. In cases where an existing NGCC plant moved ahead of an existing 

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fossil steam plant in the dispatch order, the NGCC plant’s generation was increased while the 

existing fossil plant’s generation was reduced. The NGCC plant’s generation was increased to 

the maximum capacity factor assumed feasible within IPM while the amount of reduced 

generation at the fossil steam plant is determined by the amount that would keep the overall 

covered sources’ emissions in the region constant, so as to respect compliance with the massbased standards represented in the modeling scenario. Since the existing NGCC plant has a lower 

emissions rate than the existing fossil steam plant, the increase in generation at the NGCC plant 

is greater than the reduction in generation (because more generation is now possible from both 

plants together at the same given level of emissions). This net increase in generation from 

existing EGUs is then subtracted from new NGCC generation in the region, consistent with the 

total generation needed to meet the load assumed in the IPM modeling of the mass-based 

scenario. 

When applying this algorithm to the results from the mass-based scenario analyzed in this 

RIA, it forecasts nationally in 2030 a 10 percent increase in generation at existing NGCC EGUs, 

a 4 percent reduction in generation at existing fossil steam EGUs, and a 29 percent decrease in 

generation at new NGCC EGUs compared to the modeling scenario results presented above. The 

result of this reduction in new NGCC EGU generation is a reduction in CO2 emissions of 23 

million short tons (an amount equal to 1.3 percent of 2030 forecast emissions in mass-based 

scenario). We do not quantify the effect of these changes in generation on SO2 and NOx

emissions, although on net additional co-benefits would be expected. 

The incentives portrayed in this analysis are consistent with the incentives that would be 

realized under the OBA set-aside, and the general direction and magnitude of the results are 

likely consistent with those that would be observed had the mass-based scenario been modeled 

with the OBA set-aside. However, the results should be viewed as approximate given that 

analysis does not consider important aspects of power markets included in IPM. For example, the 

analysis does not consider any potential changes in relative fuel and allowance prices as a result 

of the OBA set-aside. The application of the OBA set-aside will place upward pressure on the 

allowance prices and therefore further incentivize a shift away from existing fossil steam 

generation. The OBA set-aside may also place upward pressure on the price of natural gas which 

would reduce the effectiveness of the set-aside at encouraging increased utilization of existing 

NGCC EGUs. Furthermore, the analysis does not consider the fact that electricity is traded 

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across many IPM regions. The application of OBA in one state may impact the generation at 

EGUs in another state. 

1.5.7 Uncertainty Analysis 

The Office of Management and Budget’s circular Regulatory Analysis (Circular A-4) 

provides guidance on the preparation of regulatory analyses required under E.O. 12866, and 

requires an uncertainty analysis for rules with annual benefits or costs of $1 billion or more.28

This proposed rulemaking potentially surpasses that threshold for both benefits and costs. 

Throughout this RIA and the referenced final Clean Power Plan Emission Guidelines RIA, we 

considered a number of sources of uncertainty, both quantitatively and qualitatively, on benefits 

and costs. We summarize three key elements of our analysis of uncertainty here: 

• Assess uncertainty in the methods used to calculate the health co-benefits associated with 

the reduction in PM2.5 and ozone and the use of a benefits-per-ton approach in estimating 

these co-benefits. 

• Characterizing uncertainty in monetizing climate-related benefits. 

Some of these elements are evaluated using probabilistic techniques, whereas for others 

the underlying likelihoods of certain outcomes are unknown and we use scenario analysis to 

evaluate their potential effect on the benefits and costs of this rulemaking. 

1.5.7.1 Uncertainty in Costs 

Our best estimates of the costs of these illustrative scenarios are reported within the cost analysis 

of the final Clean Power Plan Emission Guidelines and are included in the cost modeling in this 

RIA for both the proposed rate-based and mass-based approaches. A source of uncertainty under 

this regulation is the ultimate approach states will adopt in response to the guidelines, which will 

affect both the costs and benefits of this rule. For this reason we modeled two potential federal 

plan approaches: the rate-based plan approach and the mass-based plan approach. 

 

28 Office of Management and Budget (OMB), 2003, Circular A-4, 

http://www.whitehouse.gov/omb/circulars_a004_a-4 and OMB, 2011. Regulatory Impact Analysis: A Primer.

http://www.whitehouse.gov/sites/default/files/omb/inforeg/regpol/circular-a-4_regulatory-impact-analysis-aprimer.pdf 

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1.5.7.2 Uncertainty Associated with Estimating the Social Cost of Carbon 

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

the incomplete way in which the integrated assessment models (IAM) capture catastrophic and 

non-catastrophic impacts, their incomplete treatment of adaptation and technological change, 

uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk 

aversion.29 Currently integrated assessment models do not assign value to all of the important 

physical, ecological, and economic impacts of climate change recognized in the climate change 

literature due to a lack of precise information on the nature of damages and because the science 

incorporated into these models understandably lags behind the most recent research. These 

individual limitations do not all work in the same direction in terms of their influence on the SCCO2 estimates, though taken together they suggest that the SC-CO2 estimates are likely 

conservative. In particular, the IPCC Fourth Assessment Report (2007) concluded that “It is very 

likely that [SC-CO2 estimates] underestimate the damage costs because they cannot include 

many non-quantifiable impacts” and the IPCC Fifth Assessment report observed that SC-CO2

estimates continue to omit various impacts that would likely increase damages. The 95th

percentile estimate was included in the recommended range for regulatory impact analysis, in 

part, to address these concerns. 

The modeling underlying the development of the SC-CO2 estimates addressed 

uncertainty in several ways. An ensemble of three IAMs were used to generate the SC-CO2

estimates to capture differences in model structures that, in part, reflect uncertainty in the 

scientific literature about these relationships. Parametric uncertainty was explicitly addressed in 

each IAM, though to differing degrees, through Monte Carlo simulations in which explicit 

probability distributions for key parameters were specified, including the equilibrium climate 

 

29 Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866, Interagency Working Group on Social Cost of Carbon, with participation by the Council of Economic 

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

of Energy, Department of Transportation, Environmental Protection Agency, National Economic Council, Office 

of Energy and Climate Change, Office of Management and Budget, Office of Science and Technology Policy, and 

Department of Treasury (February 2010). Available at: 

<http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf>. 

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sensitivity, which represents the long-run responsiveness of the climate to increasing GHG 

concentrations. Furthermore, the analysis considered five different socioeconomic and emissions 

forecasts to capture the sensitivity of the SC-CO2 estimates to key exogenous projections used in 

the modeling. Finally, the results were calculated for three discount rates, which were selected, in 

part, to reflect uncertainty about how interest rates may change over time and the possibility that 

climate damages are positively correlated with uncertain future economic activity. This analysis 

produced 45 different distributions of the SC-CO2 estimates for each emissions year. To produce 

a range of plausible estimates that are manageable in regulatory analysis but still reflects the 

uncertainty in the results four point estimates were recommended. The use of this range of point 

estimates in this rulemaking helps to reflect the uncertainty in the SC-CO2 estimates. Chapter 4 

of the final Clean Power Plan Emission Guidelines RIA provides a comprehensive discussion 

about the methodology and application of the SC-CO2; see both the 2010 TSD and current SCCO2 TSD for a full description. 

In addition, OMB’s Office of Information and Regulatory Affairs received comments 

regarding uncertainty and the SC-CO2 estimates in response to a separate request for public 

comment on the approach used to develop the estimates. Commenters discussed the analyses and 

presentation of uncertainty in the TSD as well as the implications of uncertainty for use of the 

SC-CO2 estimates in regulatory impact analysis. In their response, the interagency working 

group (IWG) acknowledged uncertainty in the SC-CO2 estimates but disagreed with commenters 

that suggested the uncertainty undermines use of the SC-CO2 estimates in regulatory impact 

analysis. The IWG went on to note that the uncertainty in the SC-CO2 estimates is fully 

acknowledged and comprehensively discussed in the TSDs and supporting academic literature, 

and that while all regulatory impact analysis involves uncertainty, these analyses can provide 

useful information to decision makers and the public. See the IWG Response to Comments for 

the complete response.30 

1.5.7.3 Uncertainty Associated with PM2.5 and Ozone Health Co-Benefits Assessment 

EPA provides information on the relative uncertainty in the benefits estimates based on 

the 95th percentile confidence interval for avoided PM-related premature deaths and the 

 

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

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associated economic valuation estimated in the benefits analysis for the recent PM NAAQS RIA 

(U.S. EPA, 2012).. In general, the 95th percentile confidence interval for monetized PM2.5

benefits ranges from approximately -90 percent to +180 percent of the central estimates based on 

the two key PM mortality studies. To further explore uncertainty in the premature mortality 

benefits, EPA provides the PM-related results using concentration-response functions from two 

key epidemiology studies, as well as alternate concentration-response relationship provided by 

an expert elicitation and alternative ozone-related results using concentration-response 

relationships provided by alternative epidemiology studies. In addition, we include an 

assessment of the distribution of population exposure in the modeling underlying the benefit-perton estimates. 

In addition to the uncertainties in the underlying concentration-response and valuation 

functions, all benefit-per-ton approaches have inherent limitations, including that the estimates 

reflect the geographic distribution of the modeled sector emissions, which may not match the 

emission reductions anticipated by this proposed rule, and they may not reflect local variability 

in population density, meteorology, exposure, baseline health incidence rates, or other local 

factors for any specific location. In addition, these estimates reflect the regional average benefitper-ton for each ambient PM2.5 precursor emitted from EGUs, which assumes a linear 

atmospheric response to emission reductions. The regional benefit-per-ton estimates, although 

less subject to these types of uncertainties than national estimates, still should be interpreted with 

caution. Even though we assume that all fine particles have equivalent health effects, the benefitper-ton estimates vary between precursors depending on the location and magnitude of their 

impact on PM2.5 levels, which drive population exposure. 

1.6 References 

40 CFR Chapter I [EPA–HQ–OAR–2009–0171; FRL–9091–8] RIN 2060–ZA14, 

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

of the Clean Air Act,” Federal Register / Vol. 74, No. 239 / Tuesday, December 15, 2009 / 

Rules and Regulations. 

75 FR 49556. August 13, 2010. “EPA’s Denial of the Petitions to Reconsider the Endangerment 

and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean 

Air Act.”

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Bell, M.L., A. McDermott, S.L. Zeger, J.M. Sarnet, and F. Dominici. 2004. “Ozone and ShortTerm Mortality in 95 U.S. Urban Communities, 1987-2000.” Journal of the American 

Medical Association. 292(19):2372-8. 

Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support Document: Social Cost of 

Carbon for Regulatory Impact Analysis Under Executive Order 12866, Interagency Working 

Group on Social Cost of Carbon, with participation by the Council of Economic Advisers, 

Council on Environmental Quality, Department of Agriculture, Department of Commerce, 

Department of Energy, Department of Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and Climate Change, Office of Management 

and Budget, Office of Science and Technology Policy, and Department of Treasury (February 

2010). Available at: <http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf>. Accessed July 15, 2015. 

Docket ID EPA-HQ-OAR-2013-0602, Technical Support Document: Technical Update of the 

Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, 

Interagency Working Group on Social Cost of Carbon, with Participation by Council of 

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

Department of Commerce, Department of Energy, Department of Transportation, Domestic 

Policy Council, Environmental Protection Agency, National Economic Council, Office of 

Management and Budget, Office of Science and Technology Policy, and Department of 

Treasury (May 2013, Revised July 2015). Available at: 

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

Accessed July 15, 2015. 

Krewski D., M. Jerrett, R.T. Burnett, R. Ma, E. Hughes, Y. Shi, et al. 2009. Extended Follow-Up 

and Spatial Analysis of the American Cancer Society Study Linking Particulate Air Pollution 

and Mortality. HEI Research Report, 140, Health Effects Institute, Boston, MA. 

Interagency Working Group on Social Cost of Carbon, with participation by Council of 

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

Department of Commerce, Department of Energy, Department of Transportation, 

Environmental Protection Agency, National Economic Council, Office of Management and 

Budget, Office of Science and Technology Policy, and Department of Treasury. Response to 

to Comments: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866. July 2015. Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-commentsfinal-july-2015.pdf.> Accessed July 15, 2015. 

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Intergovernmental Panel on Climate Change (IPCC). 2007. Climate Change 2007: Synthesis 

Report Contribution of Working Groups I, II and III to the Fourth Assessment Report of the 

IPCC. Available at: 

<http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report_synt

hesis_report.htm>. Accessed June 6, 2015. 

Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. “Chronic Exposure to Fine Particles 

and Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environmental Health Perspectives. 120(7):965-70. 

Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. “Ozone Exposure and Mortality: An 

Empiric Bayes Metaregression Analysis.” Epidemiology. 16(4):458-68. 

Melillo, J.M., T.C. Richmond, and G.W. Yohe, Eds., 2014: Climate Change Impacts in the 

United States: The Third National Climate Assessment. U.S. Global Change Research 

Program. Available at <http://nca2014.globalchange.gov>. Accessed June 4, 2015. 

National Research Council (NRC). 2000. Toxicological Effects of Methylmercury: Committee on 

the Toxicological Effects of Methylmercury.” Board on Environmental Studies and 

Toxicology. National Academies Press. Washington, DC. 

National Research Council (NRC). 2002. Estimating the Public Health Benefits of Proposed Air 

Pollution Regulations. National Academies Press. Washington, DC. 

National Research Council. 2011. Climate Stabilization Targets: Emissions, Concentrations, and 

Impacts over Decades to Millennia. Washington, DC: The National Academies Press. 

U.S. Environmental Protection Agency (U.S. EPA). 2008a. Integrated Science Assessment for 

Sulfur Oxides—Health Criteria (Final Report). National Center for Environmental 

Assessment – RTP Division, Research Triangle Park, NC. September. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=198843>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2008b. Final Ozone NAAQS Regulatory 

Impact Analysis. EPA-452/R-08-003. Office of Air Quality Planning and Standards Health 

and Environmental Impacts Division, Air Benefit and Cost Group Research Triangle Park, 

NC. March. Available at: < http://www.epa.gov/ttnecas1/regdata/RIAs/6-

ozoneriachapter6.pdf>. Accessed June 4, 2015. 

U.S. EPA. 2008c. Integrated Science Assessment for Oxides of Nitrogen: Health Criteria (Final 

Report). Research Triangle Park, NC: National Center for Environmental Assessment. July. 

Available at < http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. 

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U.S. Environmental Protection Agency (U.S. EPA). 2008c. Integrated Science Assessment for 

Oxides of Nitrogen - Health Criteria (Final Report). National Center for Environmental 

Assessment, Research Triangle Park, NC. July. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2009b. Integrated Science Assessment for 

Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for Environmental 

Assessment – RTP Division, Research Triangle Park, NC. December. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2010d. Section 3: Re‐analysis of the Benefits 

of Attaining Alternative Ozone Standards to Incorporate Current Methods. Available at: 

<http://www.epa.gov/ttnecas1/regdata/RIAs/s3-supplemental_analysis-updated_benefits11-

5.09.pdf >. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2012a. Regulatory Impact Analysis for the 

Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. EPA452/R-12-003. Office of Air Quality Planning and Standards, Health and Environmental 

Impacts Division, Research Triangle Park, NC. December. Available at: < 

http://www.epa.gov/ttnecas1/regdata/RIAs/finalria.pdf>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2013b. Integrated Science Assessment of 

Ozone and Related Photochemical Oxidants (Final Report). EPA/600/R-10/076F. National 

Center for Environmental Assessment – RTP Division, Research Triangle Park. Available at: 

<http://cfpub.epa.gov/ncea/isa/recordisplay.cfm?deid=247492#Download>. Accessed June 4, 

2015. 

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

Clean Power Plan Final Rule. EPA-452/R-15-003. Office of Air Quality Planning and 

Standards, Health and Environmental Impacts Division, Research Triangle Park, NC. 

December. Available at: <[Placeholder] >. 

U.S. EPA. 2015b. Technical Support Document (TSD) the Final Carbon Pollution Emission 

Guidelines for Existing Stationary Sources: Electric Utility Generating Units. Demand-Side 

Energy Efficiency. 

Woodruff, T.J., J. Grillo, and K.C. Schoendorf. 1997. “The relationship between selected causes 

of postneonatal infant mortality and particulate air pollution in the United States.” 

Environmental Health Perspectives. 105(6): 608-612

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CHAPTER 2: STATUTORY AND EXECUTIVE ORDER REVIEWS

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

13563: Improving Regulation and Regulatory Review 

[Placeholder] 

2.2 Paperwork Reduction Act 

[Placeholder] 

2.3 Initial Regulatory Flexibility Analysis 

The Regulatory Flexibility Act (RFA; 5 U.S.C.§ 601 et seq.), as amended by the Small 

Business Regulatory Enforcement Fairness Act (Public Law No. 104-121), provides that 

whenever an agency is required to publish a general notice of proposed rulemaking, it must 

prepare and make available an initial regulatory flexibility analysis (IRFA), unless it certifies that 

the proposed rule, if promulgated, will not have a significant economic impact on a substantial 

number of small entities (5 U.S.C. § 605[b]). Small entities include small businesses, small 

organizations, and small governmental jurisdictions. An IRFA describes the economic impact of 

the proposed rule on small entities and any significant alternatives to the proposed rule that 

would accomplish the objectives of the rule while minimizing significant economic impacts on 

small entities. Pursuant to section 603 of the RFA, the EPA prepared an initial regulatory 

flexibility analysis (IRFA) that examines the impact of the proposed rule on small entities along 

with regulatory alternatives that could minimize that impact. 

2.3.1 Reasons why Action is Being Considered 

On &&&August 3, 2015, the EPA finalized the Clean Power Plan Emission Guidelines 

for existing fossil-fuel fired electricity generating units (EGUs) (40 CFR part 60, subpart UUUU) 

under authority of section 111 of the CAA (79 FR 34950). The Guidelines apply to existing 

fossil-fuel fired EGUs, i.e., those that were in operation or had commenced construction before 

January 8, 2014. States with existing EGUs subject to the guidelines are required to submit to the 

EPA by August 31, 2016, a state plan that implements the EGs. States may also make initial plan 

submittals in lieu of a complete state plan, in which case extensions can be granted (40 CFR 

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&&&).31 Once the EPA finds that a state has failed to submit a plan, or disapproves a state 

plan,32 section 111 of the CAA and 40 CFR 60.27 require the EPA to develop, implement, and 

enforce a federal plan for existing EGUs located in that state. 

The agency believes it is appropriate to propose the federal plan at this time for any states 

that may ultimately be found to have failed to submit a plan, or had their plan disapproved by the 

EPA. For some states in this situation, the federal plan may be no more than an interim measure 

to ensure that congressionally mandated emission standards under authority of section 111 of the 

CAA are implemented until they can get an approved plan in place. Other states may choose to 

rely on the federal plan and would not need to develop their own plan. This proposal also serves 

as two proposed model trading rules which states can adopt or tailor for adoption as their state 

plan. 

2.3.2 Statement of Objectives and Legal Basis for Proposed Rules 

The EPA is planning a notice of proposed rulemaking for a federal plan to implement 

greenhouse gas Emission Guidelines for existing fossil fuel-fired electric generating units 

(EGUs). The emission guidelines were proposed in June 2014 as the Carbon Pollution Emission 

Guidelines for Existing Stationary Sources: Electric Utility Generating Units (79 FR 34830; the 

Clean Power Plan). This plan is part of the President’s Climate Action Plan announced in June of 

2013 to reduce carbon emissions from the power sector by 30 percent below 2005 levels. This 

federal plan serves to: 1) provide a model rule that states can tailor for implementation, and 2) set 

in place a plan that EPA can implement for states that do not develop an approvable state plan. 

The EPA sees this federal plan as an interim measure to ensure that congressionally mandated 

emission standards under authority of section 111 of the CAA are implemented until states 

assume their role as the preferred implementers of the emission guidelines. 

 

31 See Section VII of this preamble for additional information on proposed changes to 40 CFR 60.27 to provide 

enhancements and flexibilities to the agency’s process for review and action on state plans and promulgation of 

federal plans. 

32 If a state has submitted a complete plan, then the EPA will go through a public notice and comment process to 

fully or partially approve or disapprove the state plan. 

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The final Clean Power Plan Emission Guidelines, due out this summer, are related to but 

separate from the proposed federal plan. The final Emission Guidelines s will detail the carbon 

dioxide (CO2) reduction goals for sources by state. The purpose of the proposed federal plan is to 

lay out mechanisms to achieve reductions in CO2 emissions from affected EGUs that are not 

covered by an EPA-approved state plan. The EPA is considering a range of options and 

approaches through which affected EGUs would meet a rate-based goal or a mass-based 

equivalent. The EPA intends to incorporate flexibility to the extent possible into the proposed 

federal plan so affected units can achieve these reductions in a cost-effective way. 

2.3.3 Description and Estimate of Affected Small Entities 

EPA conducted this regulatory flexibility analysis at the ultimate (i.e., highest) level of 

ownership, evaluating parent entities with the largest share of ownership in at least one 

potentially-affected EGU included in EPA’s Base Case using the Integrated Planning Model 

(IPM) v.5.15, used in the Regulatory Impact Analysis (RIA) for this proposed rule.33 This 

analysis draws on the “parsed” unit-level estimates using IPM results for 2030, as well as 

ownership, employment, and financial information for the potentially affected small entities 

drawn from other resources described in more detail below. EPA chose to examine potential 

impacts in 2030 because that is when the emission performance goals are required to be fully 

achieved. Also, as presented in the RIA for this proposed rule, 2030 is the year where the 

estimated annual compliance costs for the contiguous U.S. are at their highest.34 

It is important to briefly describe the cost analysis supporting this proposed rule. This 

action proposes a federal plan under section 111(d) of the CAA for the control of CO2, a 

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

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

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

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

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

 

33 See 1.4.1 of the RIA for this proposed rule for more detail on the IPM base case used for this analysis. Detailed 

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

34 See Section 1.5.2 of the RIA for this proposed rule. 

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

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

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

many states will require a federal plan. Because of this lack of information, for the RIA for this 

proposed rule, the EPA has chosen to examine a boundary scenario where all states of the 

contiguous U.S. will be regulated under a federal plan. Additionally, the proposal RIA examines 

two federal plan approach scenarios for implementation of federal plans. We use these scenarios 

to inform this IRFA. 

The first federal plan approach assumes all states in the contiguous U.S. are regulated 

under rate-based federal plans. The second federal plan approach assumes all contiguous states 

are regulated under mass-based federal plans. As with the RIA, the IRFA proceeds by examining 

potential costs to small entities under both the rate-based and mass-based approach, again under 

the strong assumption that all affected EGUs are regulated under a federal plan. The parsed unitlevel estimates used in this IRFA are consistent with the analysis presented elsewhere in the RIA. 

These 2030 year IPM files can also be found in the docket for the rulemaking. 

EPA identified the size of ultimate parent entities by using the Small Business 

Administration (SBA) size threshold guidelines.35 The criteria for size determination vary by the 

organization/operation category of the ultimate parent entity, as follows: 

• Privately-owned (non-government) entities (see Table 2-1) 

o Privately-owned entities include investor-owned utilities, non-utility entities, and 

entities with a primary business other than electric power generation. 

o For entities with electric power generation as a primary business, small entities 

are those with less than the threshold number of employees specified by SBA for 

each of the relevant North American Industry Classification System (NAICS) 

sectors (NAICS 2211). 

 

35 U.S. Small Business Administration (SBA). 2014. Small Business Size Standards. Effective as of July 14, 2014. 

See: http://www.sba.gov/sites/default/files/Size_Standards_Table.pdf. 

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o For entities with a primary business other than electric power generation, the 

relevant size criteria are based on revenue, assets, or number of employees by 

NAICS sector.36

• Publicly-owned entities 

o Publicly-owned entities include federal, state, municipal, and other political 

subdivision entities. 

o The federal and state governments were considered to be large. Municipalities and 

other political units with population fewer than 50,000 were considered to be 

small. 

• Rural Electric Cooperatives 

o Small entities are those with fewer than the threshold level of employees or 

revenue specified by SBA for each of the relevant NAICS sectors. 

EPA examined affected EGUs included in EPA’s 2030 projections and identified the 

associated power plants. Next, we determined power plant ownership information, including the 

name of associated owning entities, ownership shares, and each entity’s type of ownership. EPA 

primarily used data from SNL and Ventyx, supplemented by limited research using publicly 

available data.37 Majority owners of power plants with affected EGUs were categorized as one of 

the seven ownership types.38 These ownership types are: 

1. Investor-Owned Utility (IOU): Investor-owned assets (e.g., a marketer, independent 

power producer, financial entity) and electric companies owned by stockholders, etc.

 

36 Certain affected EGUs are owned by ultimate parent entities whose primary business is not electric power 

generation. 

37 SNL Financial data covers the energy market and other industries. For more information, see: www.snl.com. The 

Ventyx database consists of detailed ownership and corporate affiliation information at the EGU level. For more 

information, see: www.ventyx.com. 

38 Throughout this analysis, EPA refers to the owner with the largest ownership share as the “majority owner” even 

when the ownership share is less than 51 percent. 

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2. Cooperative (Co-Op): Non-profit, customer-owned electric companies that generate 

and/or distribute electric power.

3. Municipal: A municipal utility, responsible for power supply and distribution in a small 

region, such as a city.

4. Sub-division: Political subdivision utility is a county, municipality, school district, 

hospital district, or any other political subdivision that is not classified as a municipality 

under state law.

5. Private: Similar to an investor-owned utility, however, ownership shares are not openly 

traded on the stock markets.

6. State: Utility owned by the state.

7. Federal: Utility owned by the federal government.

Required ownership information could not be determined for two committed units that 

are represented in the IPM base case modeling for this proposed rule, preventing their inclusion 

in this analysis.39

Next, EPA used the Hoover’s online database to identify the ultimate owners of power 

plant owners identified in the SNL and Ventyx databases. This was necessary, as many majority 

owners of power plants (listed in SNL or Ventyx) are themselves owned by other ultimate parent 

entities (listed in Hoover’s).40 In these cases, the ultimate parent entity was identified via 

Hoover’s, whether domestically or internationally owned. 

EPA followed SBA size standards to determine which non-government ultimate parent 

entities should be considered small entities in this analysis. These SBA size standards are 

specific to each industry, each having a threshold level of either employees, revenue, or assets 

below which an entity is considered small. SBA guidelines list all industries, along with their 

associated NAICS code and SBA size standard. Therefore, it was necessary to identify the 

specific NAICS code associated with each ultimate parent entity in order to understand the 

 

39 The ORIS codes of these two units are 83609 and 83921. Without knowledge of entity type and size, it was not 

possible to accurately estimate revenue or costs impacts. An ORIS code is an identifying number assigned by the 

U.S. Energy Information Administration to power plants owned by utilities. 

40 The Hoover’s Inc. online platform includes company records that can contain NAICS codes, number of 

employees, revenues, and assets. For more information, see: http://www.hoovers.com. 

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appropriate size standard to apply. Data from Hoover’s was used to identify the NAICS codes for 

most of the ultimate parent entities.41 In many cases, an entity that is a majority owner of a power 

plant is itself owned by an ultimate parent entity with a primary business other than electric 

power generation. Therefore, it was necessary to consider SBA entity size guidelines for the 

range of NAICS codes listed in Table 2-1. This table represents the range of NAICS codes and 

areas of primary business of ultimate parent entities which are majority owners of potentially 

affected EGUs in EPA’s IPM base case. 

 

41 In the case of two entities, NAICS codes could not be located in Hoover’s, so publicly available information was 

used to determine the primary area of business for the ultimate parent entities. 

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Table 2-1. SBA Size Standards by NAICS Code 

Notes: 1) Based on size standards effective at the time EPA conducted this analysis (SBA size standards, effective 

July 14, 2014) 2) Small business size standards are not established for the Public Administration industry (NAICS 

code 921110). It is assumed that a comparable NAICS private sector industry is Fossil Fuel Electric Power 

Generation (NAICS code 221112). Therefore, for this analysis, the NAICS code 921110 is assumed to have a size 

standard of 750 employees. 

Source: SBA, 2014 

NAICS 

Code NAICS Description SBA Size Standard

211111 Crude Petroleum and Natural Gas Extraction 500 employees

211112 Natural Gas Liquid Extraction 500 employees

212111 Bituminous Coal and Lignite Surface Mining 500 employees

212221 Gold Ore Mining 500 employees

213112 Support Activities for Oil and Gas Operations $38.5 million in revenue

221111 Hydroelectric Power Generation 500 employees

221112 Fossil Fuel Electric Power Generation 750 employees

221113 Nuclear Electric Power Generation 750 employees

221118 Other Electric Power Generation 250 employees

221121 Electric Bulk Power Transmission and Control 500 employees

221122 Electric Power Distribution 1,000 employees

221210 Natural Gas Distribution 500 employees

238210 Electrical Contractors and Other Wiring Installation Contractors $15 million in revenue

238290 Other Building Equipment Contractors $15 million in revenue

324110 Petroleum Refineries 1,500 employees

325120 Industrial Gas Manufacturing 1,000 employees

325211 Plastics Material and Resin Manufacturing 750 employees

325320 Pesticide and Other Agricultural Chemical Manufacturing 500 employees

331110 Iron and Steel Mills and Ferroalloy Manufacturing 1,000 employees

331313 Alumina Refining and Primary Aluminum Production 1,000 employees

333613 Mechanical Power Transmission Equipment Manufacturing 500 employees

333999 All Other Miscellaneous General Purpose Machinery Manufacturing 500 employees

335312 Motor and Generator Manufacturing 1,000 employees

335999 All Other Miscellaneous Electrical Equipment and Component Manufacturing 500 employees

423610 Electrical Apparatus and Equipment, Wiring Supplies, and Related Equipment Merchant 

Wholesalers 100 employees

424720 Petroleum and Petroleum Products Merchant Wholesalers (except Bulk Stations and Terminals) 100 employees

454310 Fuel Dealers 50 employees

486210 Pipeline Transportation of Natural Gas $27.5 million in revenue

522110 Commercial Banking $550 million in assets

522220 Sales Financing $38.5 million in revenue

522320 Financial Transactions Processing, Reserve, and Clearinghouse Activities $38.5 million in revenue

523120 Securities Brokerage $38.5 million in revenue

523910 Miscellaneous Intermediation $38.5 million in revenue

523920 Portfolio Management $38.5 million in revenue

523930 Investment Advice $38.5 million in revenue

524113 Direct Life Insurance Carriers $38.5 million in revenue

524126 Direct Property and Casualty Insurance Carriers 1,500 employees

524210 Insurance Agencies and Brokerages $7.5 million in revenue

525110 Pension Funds $32.5 million in revenue

525120 Health and Welfare Funds $32.5 million in revenue

525990 Other Financial Vehicles $32.5 million in revenue

541611 Administrative Management and General Management Consulting Services $15 million in revenue

551112 Offices of Other Holding Companies $20.5 million in revenue

561110 Office Administrative Services $7.5 million in revenue

813910 Business Associations $7.5 million in revenue

921110 Public Administration 750 employees

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EPA compared the relevant entity size criterion for each ultimate parent entity to the SBA 

threshold value noted in Table 2-1. We used the following data sources and methodology to 

estimate the relevant size criterion values for each ultimate parent entity: 

1. Employment, Revenue, and Assets: EPA used the Hoover’s database as the primary 

source for information on ultimate parent entity employee numbers, revenue, and assets.42

In parallel, EPA also considered estimated revenues from affected EGUs based on 

analysis of parsed-file estimates for 2030.43 EPA assumed that the ultimate parent entity 

revenue was the larger of the two revenue estimates. In limited instances, supplemental 

research was also conducted to estimate an ultimate parent entity’s number of employees, 

revenue, or assets. 

2. Population: Municipal entities are defined as small if they serve populations of less than 

50,000. EPA primarily relied on data from the Ventyx database and the U.S. Census 

Bureau to inform this determination. Supplemental research of individual municipalities 

was also conducted in some instances. 

Ultimate parent entities for which the relevant measure is less than the SBA size criterion 

were identified as small entities and carried forward in this analysis. In the case of six entities, 

data limitations prevented the comparison of entities against their appropriate SBA size 

standards. For the purposes of this analysis, EPA assumed that these six entities are small 

entities.44

EPA identified 223 potentially affected EGUs owned by 74 small entities included in 

EPA’s 2030 projections. Fifty-nine of these potentially affected EGUs are projected to no longer 

 

42 Estimates of sales were used in lieu of revenue estimates when revenue data was unavailable. 

43 The methodology for the analysis of IPM results is detailed later in this IRFA. 

44 Generation from potentially affected EGUs owned by these six entities represents less than two percent of total 

generation from potentially affected EGUs owned by small entities under EPA’s base case projections. 

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be operating by 2030. Twenty-four small entities are projected to have all of their potentially 

affected EGUs cease operation in the base case by 2030. 

2.3.4 Compliance Cost Impact Estimates 

2.3.4.1 Methodology for Estimating Impacts on Small Entities 

This section presents the methodology for estimating the federal compliance costs of this 

proposed rule for small entities. EPA estimated net compliance costs for individual EGUs of the 

proposed rule using the following equation: 

Cnet compliance cost = ∆ Coperating + annualized capital + ∆ Cfuel + ∆ Cdemand-side energy efficiency + ∆ R 

where C represents the components of cost as labeled, R represents revenue, and ∆ indicates the 

calculation of difference between the base case and the federal plan approach under examination. 

The specific meaning of these variables is discussed below. 

This approach to estimate net compliance costs is consistent with previous proposed 

power sector regulations that required IRFAs, such as the proposed Mercury and Air Toxics 

Rule.45 However, there is an additional component in the net compliance cost equation: the 

change in the program costs of demand-side energy efficiency programs. Investment in demandside energy efficiency results in lower electricity demand, and consequently fewer emissions as 

production is reduced to meet the lower demand, an important emission-reduction strategy 

modelled in the rate-based and mass-based federal plan approaches. 

Because this analysis evaluates the net compliance costs as a sum of the costs changes 

associated with compliance choices as well as changes in electricity revenues, it captures 

potential net compliance cost increases or decreases. For example, if under the proposed rule 

entities increase revenue more than costs, the net compliance costs will be negative. As a result, 

 

45 U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis of the Proposed Toxics 

Rule: Final Report. Office of Air Quality Planning and Standards, Health and Environmental Impacts Division, 

Research Triangle Park, NC. Available at: http://www.epa.gov/ttnecas1/regdata/RIAs/ToxicsRuleRIA.pdf. 

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the approach used here to estimate net compliance costs is well-equipped to evaluate the 

potential distributional consequences of the proposed regulation. 

For this analysis, EPA used the parsed unit-level estimates mentioned before to estimate 

three of the four components of the net compliance cost equation above: the change in operating 

and annualized capital costs, the change in fuel costs, and the change in revenue, where all 

changes are estimated as the difference between the base case and federal plan scenario. These 

impacts were then summed for each small entity, adjusting for ownership share.46 As described 

momentarily, additional analysis was performed to estimate the change in costs of demand-side 

energy efficiency that factors in IPM-projected outputs but is not directly an output of the model. 

These individual components of compliance cost were estimated as follows: 

1. Operating and capital costs: Using the IPM parsed estimates for the base case and the 

rate-based and mass-based federal plan approaches, EPA evaluated changes in operating 

and capital costs at the EGU level. The equations for calculating operating and capital 

costs were adopted from technology assumptions used in EPA’s version of IPM version 

5.15. The model calculates the capital cost (in $/MW); the fixed operation and 

maintenance (O&M) cost (in $/MW-year); and the variable O&M cost (in $/MWh). 

2. Fuel costs: Using the IPM parsed estimates for the base case and the rate-based and 

mass-based federal plan approaches, EPA evaluated projected changes in fuel cost at the 

EGU level. These projected fuel costs are based on estimated EGU-level fuel input (in 

million British thermal units, MMBtu) and delivered fuel prices ($/MMBtu). 

3. Demand-side energy efficiency program costs: Demand-side energy efficiency 

program costs are estimated and allocated to affected EGUs outside of IPM in this 

analysis. For this analysis, we assumed that IOUs, Co-Ops, Municipals, and SubDivisions are utilities that receive revenues on the basis of retail electricity rates. Retail 

electricity in this and related EPA analyses contain an energy efficiency surcharge. The 

surcharge reflects the standard mechanism by which utilities collect revenue from their 

customers to pay for energy efficiency programs. Such surcharges are approved for 

 

46 Unit-level cost impacts are adjusted for ownership shares for individual small entities, so as not to overestimate 

burden on each entity. 

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inclusion in rates by state utility commission for IOUs or the equivalent authority (e.g., 

municipal or cooperative utility board of directors) for other utility types. To be 

consistent, EPA assumes that these utilities will incur an energy efficiency surcharge as a 

cost in this analysis. The demand-side energy efficiency surcharge is state specific, being 

the estimated state demand-side energy efficiency program costs47 divided by projected 

total state sales. The cost in this analysis is the surcharge multiplied by projected sales 

from affected EGUs.48 In contrast, entities of the type Private are not assessed demandside energy efficiency program costs in this analysis.49 This distinction is made because 

EPA assumes that Private entities own non-utility EGUs that will earn wholesale 

electricity rates. Wholesale electricity rates do not include a demand-side energy 

efficiency surcharge in this or related EPA analyses.

4. Revenues: EPA estimated the value of electricity generated by multiplying the projected 

electricity generation from EPA’s IPM modeling results with the regional retail 

electricity price estimates ($/MWh), for all entities except those categorized as Private in 

Ventyx. For private entities, EPA used projected wholesale electricity price instead of 

retail electricity price estimates because most of the private entities are independent 

power producers (IPP). Since IPPs sell their electricity to wholesale purchasers and do 

not own transmission facilities, their revenue was estimated with wholesale electricity 

prices. 

 

47 In practice, the costs of demand-side energy efficiency programs include the costs to the utilities that are funding 

the programs (known as the program costs) and the additional cost to the end-user purchasing a more energy 

efficient technology (known as the participant costs). Based upon a literature review, the analysis supporting this 

proposed rule and the Clean Power Plan Final Rule, total costs are assumed to be divided evenly, 50 percent each, 

between program costs and participant costs. This IRFA includes only to the program costs expected to be 

incurred by utilities. For more detail on how the demand-side energy efficiency costs are estimated, see U.S. EPA. 

2015. Technical Support Document (TSD) the Final Carbon Pollution Emission Guidelines for Existing 

Stationary Sources: Electric Utility Generating Units. Demand-Side Energy Efficiency. 

48 For these entity types (i.e., IOUs, Co-Ops, Municipals, and Sub-Divisions), projected sales is estimated to be 7.5 

percent less than generation. This 7.5 percent reduction is added to account for estimated transmission losses. 

49 Note that in this context, “Private” is one of seven distinct ownership types introduced earlier in this chapter. 

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2.3.4.2 Results 

This section presents the estimated net compliance cost impacts of the proposed rule on 

small entities in 2030 based on the following endpoints: 

• net compliance costs estimated for the proposed rule for potentially affected small 

entities, and 

• the ratio of small entity compliance cost impacts to revenues from electricity generation 

at affected EGUs 

It is worth noting again that the results in this section are based on the assumption made 

for this analysis that all affected EGUs owned by small entities are subject to this proposed rule. 

EPA chose to examine this boundary scenario because, at the time of this proposal, the EPA has 

no information on whether any or how many states will require a federal plan. 

The number of affected small entities by ownership type and the potential impact of the 

federal plan approaches are summarized in Tables 2-2 through 2-5. These tables are specific to 

either the rate-based federal plan approach (i.e., rate-based), or mass-based federal plan approach 

(i.e., mass-based). All costs are presented in 2011 dollars. 

EPA estimated the annualized net compliance cost to potentially affected small entities in 

2030 to be approximately $364 million under the rate-based approach, and $404 million under 

the mass-based approach. Results for small entities discussed here do not fully account for the 

reality that electricity markets are regulated in parts of the country. Entities operating in 

regulated or cost-of-service markets are likely able to recover compliance costs through rate 

adjustments; as a result these costs can be viewed as likely being over-estimates for this set of 

utilities. 

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

under the Rate-Based Federal Plan Approach in 2030 

EGU 

Ownership 

Type 

Number of 

Potentially 

Affected Entities 

Number of Entities 

Projected to Withdraw all 

Affected Units in Base Case 

Additional Entities Projected 

to Withdraw all Affected Units 

under Rate-Based Approach 

Co-Op 17 3 1 

IOU 8 3 1 

Municipal 24 13 1 

Private 19 5 2 

Sub-Division 6 0 2 

Grand Total 74 24 7 

Notes: 1) The number of potentially affected entities reflects those with affected EGUs that are modeled within IPM 

in 2030. 2) In this context, the term withdraw signifies that EGUs are represented in the 2030 IPM results but do not 

generate electricity. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

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

Approach 

EGU 

Ownership 

Type

Total Net 

Compliance Costs 

(2011$ millions) 

Number of Small Entities 

with Net Compliance Costs 

> 1% of Generation 

Revenues 

Number of Small Entities 

with Net Compliance Costs 

> 3% of Generation 

Revenues 

Co-Op 109 8 3 

IOU 186 4 4 

Municipal 17 7 5 

Private 34 11 9 

Sub-Division 18 6 2 

Grand Total 364 36 23 

Notes: 1) The total number of entities with costs greater than 1 or 3 percent of revenues includes only entities 

experiencing positive net compliance costs. 2) Costs are compared to generation revenues from affected EGUs, and 

do not consider additional revenues some entities may earn from other sources. 3) Nine small entities are estimated 

to have net compliance cost savings greater than 3 percent of generation revenues from affected sources. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

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

under the Mass-Based Federal Plan Approach in 2030 

EGU 

Ownership 

Type 

Number of 

Potentially 

Affected Entities 

Number of Entities 

Projected to Withdraw all 

Affected Units in Base Case 

Additional Entities Projected 

to Withdraw all Affected 

Units under Mass-Based 

Approach 

Co-Op 17 3 1 

IOU 8 3 1 

Municipal 24 13 1 

Private 19 5 2 

Sub-Division 6 0 0 

Grand Total 74 24 5 

Notes: 1) The number of potentially affected entities reflects those with affected EGUs that are modeled within IPM 

in 2030. 2) In this context, the term withdraw signifies that EGUs are represented in the 2030 IPM results but do not 

generate electricity. 

Source: U.S. EPA analysis, based on IPM modeling results. 

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

Approach 

EGU 

Ownership 

Type 

Total Net 

Compliance Costs 

(2011$ millions) 

Number of Small Entities 

with Net Compliance Costs 

> 1% of Generation 

Revenues 

Number of Small Entities 

with Net Compliance Costs 

> 3% of Generation 

Revenues 

Co-Op 133 10 4 

IOU 179 3 3 

Municipal 50 5 5 

Private 36 8 7 

Sub-Division 7 4 2 

Grand Total 404 30 21 

Notes: 1) The total number of entities with costs greater than 1 or 3 percent of revenues includes only entities 

experiencing positive net compliance costs. 2) Costs are compared to generation revenues from affected EGUs, and 

do not consider additional revenues some entities may earn from other sources. 3) Eleven small entities are 

estimated to have net compliance cost savings greater than 3 percent of generation revenues from affected sources. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

As noted earlier, there are 74 small entities with potentially affected EGUs that are 

modeled in the IPM base case in 2030. Of these, 24 small entities are projected to withdraw all of 

their potentially affected EGUs from operation under base case conditions. This leaves 50 small 

entities with potentially affected EGUs that are projected to be generating electricity in 2030. 

Under the rate-based federal plan approach, 7 of these 50 small entities are projected to withdraw 

all of their potentially affected EGUs from operation by 2030. Under the mass-based federal plan 

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approach, 5 of these 50 small entities are projected withdraw all of their potentially affected 

EGUs from operation by 2030. 

Under the rate-based federal plan approach, 23 small entities are projected to incur net 

compliance costs greater than 3 percent of generation revenues from their potentially affected 

EGUs. In contrast, 11 entities are estimated to have net compliance cost savings greater than 3 

percent of their generation revenues from affected EGUs. Under the mass-based federal plan 

approach, 21 small entities are projected to incur net compliance costs greater than 3 percent of 

generation revenues from their potentially affected EGUs. In contrast, 9 entities are estimated to 

have net compliance cost savings greater than 3 percent of generation revenues from their 

affected EGUs. 

The separate components of the net compliance costs for small entities under the 

proposed rule are summarized in Table 2-6 and Table 2-7. 

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

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) 

EGU 

Ownership 

Type 

Capital + 

Operating + Fuel 

Costs ($MM) 

Energy Efficiency 

Program Costs 

($MM) 

Change in 

Electricity 

Revenue ($MM) 

Total Net 

Compliance 

Costs 

 A B C =A+B-C 

Co-Op (79) 87 (102) 109 

IOU 78 93 (15) 186 

Municipal (26) 25 (19) 17 

Private (7) 0 (40) 34 

Sub-Division (68) 16 (70) 18 

Grand Total (102) 221 (246) 364 

Note: Totals may not add due to rounding. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

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

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) 

EGU 

Ownership 

Type 

Capital + 

Operating + Fuel 

Costs ($MM) 

Energy Efficiency 

Program Costs 

($MM) 

Change in 

Electricity 

Revenue ($MM) 

Total Net 

Compliance 

Costs 

 A B C =A+B-C 

Co-Op (178) 84 (228) 133 

IOU (17) 91 (104) 179 

Municipal (64) 23 (91) 50 

Private (2) 0 (38) 36 

Sub-Division (38) 18 (27) 7 

Grand Total (299) 215 (488) 404 

Note: Totals may not add due to rounding. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

The change in electricity revenue under the federal plan approaches take into account 

both the profit lost from units that do not operate and the difference in revenue for operating 

units. The cost of withdrawing a unit as uneconomic is estimated as the base case profit that is 

foregone by not operating under a federal plan approach. 

There are uncertainties and limitations in this analysis that may result in estimates that 

diverge from what we might see in reality. Some of these have already been noted. Below is a 

listing of important considerations when interpreting this analysis. 

• At the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan. The rate-based and mass-based federal 

plan approaches analyzed in this IRFA are based on a boundary scenario where 

all states of the contiguous U.S. will be regulated under a federal plan. 

• Results for small entities discussed here do not fully account for the reality that 

electricity markets are regulated in parts of the country. Entities operating in 

regulated or cost-of-service markets are likely able to recover compliance costs 

through rate adjustments; as a result these costs can be viewed as likely being 

over-estimates for this set of utilities. 

• Demand-side energy efficiency program costs are allocated proportionally in this 

analysis. To the extent that this differs in practice, associated costs incurred by 

small entities may be over- or under-estimated. 

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• To the extent that the EGU owner information used is not reflective of reality, the 

number of small entities may be over- or under-estimated. 

• To the extent that the entity-level ownership information (i.e., NAICS code, 

number of employees, revenues, and assets) are not reflective of reality, the 

number of small entities may be over- or under-estimated. 

2.3.5 Projected Reporting, Recordkeeping and Other Compliance Requirements 

[Placeholder] 

2.3.6 Related Federal Rules 

On September 20, 2013, EPA proposed carbon pollution standards for new fossil fuel 

fired EGUs. On June 2, 2014, the EPA, proposed carbon pollution standards for modified and 

reconstructed fossil fuel fired EGUs, in addition to the Clean Power Plan EGs, to cut carbon 

pollution from existing fossil fuel fired EGUs. These existing EGUs are, or will be, potentially 

impacted by several other recently finalized EPA rules. On February 16, 2012, the EPA issued 

the mercury and air toxics standards (MATS) rule (77 FR 9304) to reduce emissions of toxic air 

pollutants from new and existing coal- and oil-fired EGUs. On May 19, 2014, the EPA issued a 

final rule under section 316(b) of the Clean Water Act (33 U.S.C. 1326(b)). This rule establishes 

new standards to reduce injury and death of fish and other aquatic life caused by cooling water 

intake structures at existing power plants and manufacturing facilities. On June 18, 2014 (79 FR 

34830), the EPA promulgated the stream electric effluent limitation guidelines (SE ELG) rule to 

strengthen the controls on discharges from certain steam electric power plants. On April 17, 2015 

(80 FR 21302), the EPA promulgated the coal combustion residuals (CCR) rule, which 

establishes technical requirements for CCR landfills and surface impoundments under subtitle D 

of the Resource Conservation and Recovery Act (RCRA), the nation's primary law for regulating 

solid waste. 

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2.3.7 Regulatory Flexibility Alternatives 

2.3.7.1 Panel Process 

SERs commented on their perceptions of the adequacy of the SBREFA panel process for 

the section 111(d) federal plan. Under the statute, EPA provides “information on the potential 

impacts of the proposed rule on small entities and the type of small entities that might be 

affected.” § 609(b)(1). Then SERs are selected, and the Panel collects “advice and 

recommendations” from each SER. § 609(b)(4). The Panel reviews the SERs’ comments, and 

“any material the agency has prepared in connection with [the RFA],” and “report[s] on the 

comments of the [SERs] and its findings as to issues related to” preparation of an IRFA. § 

609(b)(5). EPA solicited SERs comments during the course of, and after holding three outreach 

meetings. The Agency provided information to the SERs on two primary regulatory alternatives 

for the federal plan – a rate-based trading program and a mass-based trading program. The 

Agency identified specific areas under both of these alternatives where it was still in the decision 

making process and open to recommendations. This information forms the basis for 

consideration of issues and additional regulatory options important to these small entities. 

Advocacy shares many of the concerns raised by the SERs (see attached letter from 

Acting Chief Counsel Claudia Rodgers to EPA Administrator Gina McCarthy). While Advocacy 

endorses the Panel recommendations, Advocacy agrees that the SERs did not have sufficient 

information to inform advice and recommendations about specific regulatory alternatives and 

flexibilities. In Advocacy’s view, this is reflected in Panel recommendations that advise EPA to 

consider issues raised by the SERs rather than to propose or consider regulatory alternatives. 

Advocacy regrets that the Panel is not able to make more specific recommendations for 

flexibilities to minimize the impacts on small entities. 

While not all members of the Panel agree with all of these concerns, the concerns of the 

SERs regarding the Panel process have been noted. Nonetheless, EPA is committed to ensuring 

that it meets the requirements of the RFA and will, to the maximum extent practicable, fully 

consider the advice and recommendations of representatives of small entities in the development 

of the proposed rule. The EPA intends to continue working on issues regarding small businesses, 

and consider appropriate flexibilities, throughout this rulemaking process. 

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2.3.7.2 Remaining Useful Life 

SERs commented that EPA needed to account for remaining useful life of EGUs. 

Multiple comments addressed challenges that EPA must face in satisfying the statutory mandate 

that “in applying a standard of performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other factors, the remaining useful life of 

the existing sources to which such standard applies.” SERs are concerned that EPA will develop 

EGs under section 111(d) in a manner that either prohibits plans from providing this 

consideration or only providing for plans to “make these adjustments at the expense of other 

sources.” AEPCO comments that it has obligations under the Rural Electrification Act to operate 

under an 80-year mandate. SBA recommends EPA propose allowing for guaranteed amount of 

run-time for small entities to allow them to recoup investment. EPA believes “remaining useful 

life” is a concern directed toward plants with short remaining lives, but recognizes that there are 

concerns about economic viability of some marginal plants. 

The Panel recommends that EPA clearly explain how it took into consideration remaining 

useful life and take comment on other ways of defining the remaining useful life consideration. 

The Panel also recommends proposing or considering economic incentives for compliance that 

could avoid early retirement or reduce the financial effects of early retirements. For instance, the 

EPA could propose continuing allocations for a set number of years to units that retire in order to 

alleviate the financial effects of the retirement. EPA should request comment on how long such 

allocations should continue. The EPA should also consider whether there are parallel 

mechanisms in a rate-based proposal that could provide similar regulatory relief or benefits for 

small entities, if appropriate. 

2.3.7.3 Design of the Compliance System 

The panel requested SER input on a number of aspects of the federal plan design, based 

on EPA’s presentation of federal plan options. SER comments ranged quite broadly. Comments 

included: 1) differing opinions within SERs on favor of rate- vs mass-based approaches, 2) 

emphasis on market liquidity in a program, 3) support for types of allocation methodologies (in a 

mass-based allowance system), 4) encouragement for early action crediting, 5) increased 

averaging and compliance times to help small entities, and 6) whether and how to consider the 

effects of credit/allowance banking, borrowing, and shelf-life on market liquidity. In some 

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instances, no general consensus emerged. The Panel notes the following specific areas where it is 

making a recommendation. 

Mass-based or rate-based trading 

Various SERs favored one system over the other, and some suggested that each 

individual small entity should be able to choose the system under which they would comply. 

However, it is unclear to what extent SERs would favor such choice at the expense of a broader 

trading pool. The panel, however, notes that the idea of individual companies within a state 

choosing which system to comply would significantly limit the opportunity for intra- or interstate trading and would therefore not be consistent with other recommendations. The Panel 

recommends that EPA take comment on which approach (mass or rate) is preferable. In the 

interests of maximizing liquidity across all federal plan states, the Panel recommends that EPA 

should propose to finalize a single approach for all federal plans. 

Allocations and credit issuance/early action 

SERs expressed a variety of views on the appropriate method of allocating allowances 

under a mass-based system or credits under a rate-based system. Some preferred allowing states 

to make these decisions. Some wanted allocations to account for early action and energy 

efficiency efforts. The Panel agrees that EPA should take comment on the use of allocations to 

minimize the impact of the federal plan on small entities. The Panel notes that the early incentive 

pool that is part of the EGs does provide credit for early action, but the SERs did not have an 

opportunity to respond to this flexibility. The panel recommends that in the federal plan the EPA 

allow credit for early action and energy efficiency efforts to the extent it is allowed under the 

guidelines. 

Non-generating party participation and market liquidity 

SERs generally supported developing a system that would ensure a sufficient supply of 

credits be available on the open market and available for free trade to ensure that they would not 

be disadvantaged by large utilities withholding excess credits generated by renewable energy in 

their portfolio. However, some SERs also expressed the need to be able to generate and use 

credits internally (particularly those with generation across multiple states) (i.e., a portfolio 

approach). Some SERs endorsed allowing non-generating parties to create and sell credits or 

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allowances. Other SERs warned that third parties should not be allowed to purchase credits or 

allowances for the purpose of retiring them without offsetting GHG emissions from electricity 

generation. The Panel recommends that the EPA ensure a liquid market in compliance 

instruments, through consideration, request or comment, or proposal of several of options, 

including: allocation methods or rules that could impact liquidity, mechanisms to place 

allowances or credits into the market relatively early, requirements for public transparency of 

information related to allowance or credit issuance, tracking, transfers, and holdings, and 

whether and to what extent oversight authority exists related to measures to ensure liquid 

markets Additionally, the Panel recommends that EPA solicit comment on other approaches to 

ensure liquidity, including but not limited to the concept of an early incentive pool which would 

serve to incentivize early reductions and create a market of additional allowances. 

2.3.7.4 Renewable Energy and Energy Efficiency 

Generally SERs encouraged EPA to incorporate existing EE efforts into the program in a 

way that gives credit for the investment and to rely on “deemed” energy savings to earn 

compliance credits. SERs raised concerns about the accounting of investments in RE and EE 

efforts in their compliance with GHG emission standards. 

SERs also expressed concern that they be able to generate and use credits across state 

lines. This is particularly important for the investment in renewables, for which the generating 

potential is highly dependent on geography and is unequally distributed among the states. Thus, 

the Panel recommends that EPA develop a credit or allowance compliance program that allows 

for interstate accounting and trading for states under the federal plan. Additionally, the Panel 

recommends that the program include opportunities for interstate trading between sources in 

states under the federal plan and states under compatible state plans. 

The Panel recommends that EPA consider the treatment of RE and EE in rate-based and 

mass-based federal plan contexts. EPA should further consider how to implement preferred 

policy options in a way that incentivizes investment and does not create unintended barriers for 

small entities. The Panel also recommends that EPA allow crediting of RE across states under 

the federal plan while soliciting comment for allowing crediting for EE across states under the 

federal plan. 

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2.3.7.5 Reliability 

Multiple SERs expressed concerns that implementation of the EGs, either by states or 

through a federal plan, could have a negative impact on reliability because individual units could 

have operational obligations that conflict with the emissions requirements. In their comments, 

both the American Public Power Association (APPA) and the National Rural Electric 

Cooperative Association (NRECA) recommend Dynamic Reliability Safety Valve. EPA noted 

that the use of a reliability mechanism in the EGs is provisioned on the concern that some forms 

of state plan may create inflexible requirements that could in some limited circumstances raise a 

reliability concern. However, EPA believes the design of the federal plan as a flexible trading 

program alleviates these concerns and therefore a reliability mechanism is not needed. 

The Panel recognizes the connection between meeting the GHG reduction goals of the 

federal plan and maintaining the reliability of the electric grid. The Panel recommends that EPA 

fully explain in the proposal and take comment on methods to address reliability and EPA should 

take comment on establishing a reliability safety valve, particularly if small entities can be 

shown to need regulatory flexibility for reliability critical units beyond the flexibilities already 

built into the design of the federal plan. 

2.3.7.6 Subcategorization/Applicability/Exemptions 

SER comments on applicability reflect concerns related to the combined series of 

rulemakings affecting GHG emissions from electricity generating units: the NSPS, the EGs and 

the federal plan. SERs endorse excluding RICE and NGSC units from the combined 

rulemakings. One SER requests a subcategory that addresses the particular characteristics of 

lignite coal. Some SERs suggest special provisions for small units or utilities, including a small 

system exemption. The SBA suggested taking comment on an economic hardship exemption for 

small entities and that EPA propose a mechanism for additional compliance time when 

generation and transmission investments necessary for compliance have been delayed by 

government reviews. However, EPA noted that regulatory exemptions must be grounded in 

statute and supported by analysis, and EPA believes the design of the federal plan itself should 

maximize compliance options that are both consistent with the EGs and also should adequately 

address these concerns. 

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The Panel notes that EPA must be consistent with the EGs on issues of applicability, 

which should address the SERs’ concerns with regard to inclusion of RICE or NGSC units. The 

Panel also notes that EPA is proposing a design to the federal plan that utilizes emission trading 

and thus maximizes compliance options such that individual units can take into account their 

particular characteristics in designing a compliance strategy. This should further address 

concerns and make unnecessary the need for further sub-categorization or the use of unit-specific 

exemptions. Additionally, the Panel recommends that EPA solicit comment on an alternative 

allocation methodology under the mass-based proposed federal plan that may increase 

allocations for small businesses, and consider whether there are parallel mechanisms in a ratebased proposal that could provide similar regulatory relief or benefits for small entities, if 

appropriate. 

2.4 Unfunded Mandates Reform Act (UMRA) 

[Placeholder] 

2.5 Executive Order 13132: Federalism 

[Placeholder] 

2.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments 

[Placeholder] 

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

and Safety Risks 

[Placeholder] 

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

Distribution, or Use 

[Placeholder] 

2.9 National Technology Transfer and Advancement Act (NTTAA) 

This proposed action does not involve technical standards. 

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

Minority Populations and Low-Income Populations 

[Placeholder] 

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United States 

Environmental 

Protection Agency 

Office of Air Quality Planning and Standards 

Health and Environmental Impacts Division 

Research Triangle Park, NC 

Publication No. 

EPA-452/R-15-006 

July 2015

184
Attachment H.2

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment H.2.

185
Attachment I.

186
From: Vasu, Amy <Vasu.Amy@epa.gov>

Sent: Wednesday, July 29, 2015 1:54 PM

To: nfrey@omb.eop.gov

Cc: Szabo, Aaron; Harvey, Reid; Tsirigotis, Peter; Culligan, Kevin; Jones, Toni

Subject: For Federal Plan ‐‐ revised CEIP text

  

Nathan,

I was asked to also send you the attached revised CEIP text for the Federal Plan proposal.

Sorry to create confusion. Toni Jones will continue to be the EPA contact on other Federal Plan

materials.

Thank you.

Amy

~~~~~~~~~~~~~~~~~~~~~~~

Amy B. Vasu

U.S. EPA / OAQPS

Sector Policies and Programs Division

email:  vasu.amy@epa.gov

phone:  919.541.0107

187
Attachment I.1

188
Clean Energy Incentive Program language for FP Preamble 

Overview – in section III in FP preamble 

The EPA outlined and initiated the Clean Energy Incentive 

Program (CEIP) in the final emission guidelines (Clean Power 

Plan EGs, section VIII.B.2). The program is designed to 

incentivize investment in certain types of RE projects, as well 

as demand-side EE projects that benefit low-income communities. 

These projects must commence construction after the date of 

submission of a complete state plan, or the effective date of a 

federal plan, and will receive incentives for the MWh they 

generate or the end-use energy demand reductions they achieve 

during 2020 and 2021. The CEIP also provides an additional 

incentive to drive investment in demand-side EE projects that 

benefit low-income communities. The EPA proposes to apply the 

CEIP in all states subject to either a rate-based or mass-based 

federal plan. The EPA’s proposed approaches to implementing the 

program in the rate-based and mass-based federal plans are 

detailed in sections IV and V of this preamble, respectively. 

189
Rate-based approach - in section IV in FP preamble 

For purposes of the proposed rate-based federal plan, the EPA 

proposes to implement the Clean Energy Incentive Program (CEIP) 

by issuing early action ERCs for eligible actions located in or 

benefitting a state that are implemented following the effective 

date of the federal plan for that state and that reduce or avoid 

CO2 emissions in 2020 and 2021. The EPA intends to implement the 

program in a way that maintains the stringency of the rate-based 

emission standards for affected EGUs in the compliance periods 

established in this rule. The EPA is proposing to award early 

action ERCs to two types of eligible projects located in or 

benefitting a state subject to the federal plan, as listed 

below. The rationale for including these projects is included in 

section VIII.B.2 of the final emission guidelines. 

• RE investments that generate metered MWh from wind or solar 

resources; and 

• Demand-side EE programs and measures that result in 

quantified and verified avoided generation, and demonstrate 

a direct benefit to low-income communities. 

 The EPA proposes the following framework to implement the 

CEIP in the rate-based federal plan. First, the EPA proposes to 

implement a mechanism for issuing early action ERCs for eligible 

actions that reduce or avoid CO2 emissions in 2020 and 2021. The 

EPA proposes to design this mechanism in a manner that would 

190
have no impact on the aggregate emission performance of sources 

required to meet rate-based emission standards during the 

compliance periods. The EPA requests comment on the structure of 

this mechanism, which could include adjusting the stringency of 

the emission standards during the compliance periods to account 

for the issuance of early action ERCs for MWh generated or 

avoided in 2020 or 2021. For example, during the interim 

performance period, a number of ERCs could be retired in an 

amount equivalent to the number of early action ERCs that were 

awarded for MWh generated or avoided in 2020 and 2021. As 

another option, the EPA, or a state under the model trading 

rule, could use modeling to project expected emissions and 

generation for covered sources. New targets could then be 

obtained by dividing the modeled level of emissions by the 

modeled level of generation adding in the number of borrowed 

ERCs. Alternatively, future targets could be adjusted by 

assuming reference case generation and emissions over the 2022-

2029 period and allocating those to fossil steam and NGCC using 

2012 shares, then adding in the number of early action ERCs. The 

EPA requests comments on these ideas, as well as alternatives 

for maintaining the stringency of a rate-based plan implementing 

the CEIP so as to have no impact on the aggregate emission 

performance of sources required to meet rate-based emission 

standards during the compliance periods. 

191
Second, the agency proposes to create an account of “matching” 

ERCs for each state participating in the CEIP – regardless of 

whether a state is implementing a state plan or the agency is 

implementing a federal plan on its behalf. This distribution 

would reflect each state’s pro rata share of a federal pool of 

additional ERCs, which would be limited to the equivalent of 300 

million short tons of CO2 emissions. The EPA proposes to 

distribute matching ERCs to all participating states based upon 

the amount of the reductions from 2012 levels each state must 

achieve relative to that of the other participating states. 

Thus, states under a federal plan whose EGUs face greater 

reduction obligations would be eligible to secure a larger 

proportion of the federal allocation upon demonstration of 

quantified and verified MWh of RE generation or demand side-EE 

savings realized in 2020 and 2021. The number of matching ERCs 

distributed to participating states will determine the total 

level of ERCs available for provision to eligible projects in 

each state participating in the CEIP. 

The EPA proposes to execute an initial distribution of 

matching ERCs following receipt of 2016 state submittals, and a 

final distribution following receipt of all complete state plans 

in 2018, and at which time the EPA may have issued federal plans 

for some states. Eligible projects may receive awards from these 

matching accounts upon demonstration of quantified and verified 

192
MWh of generation or savings achieved by eligible projects in 

2020 and 20201. The EPA requests comment on how the 300 million 

short ton CO2 emissions-equivalent pool may be converted into 

ERCs for the purpose of populating the CEIP accounts of states 

with rate-based plans. 

Third, the EPA is proposing to award early action ERCs and 

matching ERCs to eligible projects as follows, based upon the 

quantified and verified MWh of generation or savings achieved by 

the projects in 2020 and 2021: 

• For RE projects that generate metered MWh from wind or 

solar resources: for every two MWh generated, the project 

will receive one early action ERC and one matching ERC from 

the EPA. 

• For EE projects that benefit low-income communities: for 

every two MWh in end-use demand savings achieved, the 

project will receive two early action ERCs and two matching 

ERCs from the EPA. 

ERCs awarded by the EPA pursuant to the CEIP may be used for 

compliance by an affected EGU with its emission standards in any 

compliance period and are fully transferrable prior to such use. 

All matching ERCs that have not been issued by January 1, 2023 

would be retired by the EPA. 

The EPA requests comment on all aspects of implementing the 

CEIP under a rate-based federal plan approach, including (1) the 

193
method for maintaining the stringency of rate-based emission 

standards; (2) the criteria for eligible projects, including 

criteria for awards to EE projects that benefit low-income 

communities; (3) the mechanism for reviewing project submittals 

and issuing early action ERCs; (4) evaluation, measurement and 

verification (EM&V) requirements for eligible projects; (5) 

measurement and verification (M&V) reports; and (6) verification 

reports from an independent verifier. The EPA also requests 

comment on not providing matching ERCs in the rate-based trading 

federal plan. 

Mass-based approach – in section V in FP preamble 

For purposes of the proposed mass-based federal plan, the 

EPA proposes to implement the Clean Energy Incentive Program 

(CEIP) by issuing early action allowances for actions that 

reduce or avoid CO2 emissions in 2020 and 2021. These early 

action allowances would be drawn from a third set-aside of 

allowances from the general distribution methodology. The EPA 

believes it is reasonable to establish the total amount of the 

early action-set aside in an amount equal to the pool of 

matching allowances. Thus, the EPA proposes that the total early 

action set-aside would be of an amount equal to the pool of 

matching allowances: no more than 300 million CO2 allowances, 

depending on how many states are subject to a federal plan. 

194
The EPA proposes to distribute the 300 million early action 

set-aside allowances among the states based upon the amount of 

the reductions from 2012 levels each state must achieve relative 

to that of the other participating states. The EPA proposes to 

calculate these values as each state’s proportional share of the 

total difference between the 2012 baseline and the 2030 mass 

goals.1 See [Table &&& below] for the proposed set-asides for 

each state under the mass-based federal plan. The agency 

proposes to set aside 100 million early action allowances from 

each of the three years in the first compliance period (2022, 

2023, and 2024) for a total of 300 million allowances to be set 

aside. While the table shows set-asides for every state, the EPA 

proposes to implement this set aside, according to the amounts 

listed in [Table &&&], only for those states for whom EPA is 

implementing the mass-based federal plan. The EPA also requests 

comment on other approaches to determining the size of this setaside in the mass-based federal plan. 

In accordance with the final emission guidelines, the EPA 

is proposing to award early action allowances to two types of 

1 The 2012 baseline is from the CO2 Emission Performance Rate and 

Goal Computation TSD for the CPP Final Rule. Where a state’s 

relative share of the reductions from 2012 levels would yield a 

set-aside of zero, the EPA proposes to assign such a state a 

set-aside equal to one percent of the state’s 2030 mass goal and 

adjust the remaining state set-asides accordingly. 

195
eligible projects located in or benefitting the state for which 

the EPA is implementing a federal plan: 

• RE investments that generate metered MWh from wind or solar 

resources; and 

• Demand-side EE programs and measures that result in 

quantified and verified avoided generation, and demonstrate 

a direct benefit to low-income communities. 

 The EPA proposes the following framework to implement the 

CEIP in the mass-based federal plan. First, the EPA proposes to 

create a set-aside of early action allowances for all federalplan states, as described above. Second, the agency proposes to 

create an account of matching allowances for each state 

participating in the CEIP – regardless of whether a state is 

implementing a state plan or the agency is implementing a 

federal plan on its behalf. This distribution would reflect each 

state’s pro rata share of a federal pool of additional 

allowances, which will be limited to the equivalent of 300 

million short tons of CO2 emissions. The matching allowances 

would be distributed to all participating states based upon the 

amount of the reductions from 2012 levels each state must 

achieve relative to that of the other participating states. 

Thus, states whose EGUs face greater reduction obligations would 

be eligible to secure a larger proportion of the federal 

allocation upon demonstration of quantified and verified MWh of 

196
RE generation or demand side-EE savings realized in 2020 and 

2021. The EPA also seeks comment on whether the number of 

matching allowances available to a state under the federal plan 

should be limited to a number equal to the number of early 

action allowances included in each federal plan state’s early 

action allowance set-aside account. 

The EPA proposes to execute an initial distribution of 

matching allowances following receipt of 2016 state submittals, 

and a final distribution following receipt of all complete state 

plans in 2018, by which time the EPA may also have issued 

federal plans for some states. 

Third, for any state subject to a federal plan, the EPA 

proposes to award early action allowances and matching 

allowances to eligible projects as follows, based upon the 

quantified and verified MWh of generation or savings achieved by 

the projects in 2020 and 2021: 

• For RE projects that generate metered MWh from wind or 

solar resources: for every two MWh generated, the project 

will receive a number of allowances equivalent to one MWh 

from the state early action allowance set-aside, and a 

number of matching allowances equivalent to one MWh from 

the EPA. 

• For EE projects that benefit low-income communities: for 

every two MWh in end-use demand savings achieved, the 

197
project will receive a number of allowances equivalent to 

two MWh from the state early action allowance set-aside, 

and a number of matching allowances equivalent to two MWh 

from the EPA. 

The EPA will address implementation details, including the 

appropriate factor for determining equivalence between 

allowances and MWh, in a subsequent action. Allowances awarded 

by the EPA pursuant to the CEIP may be used for compliance by an 

affected EGU with its emission standards in any compliance 

period and are fully transferrable prior to such use. All 

matching allowances that have not been used by January 1, 2023 

would be retired by the EPA. The EPA proposes to distribute any 

remaining early action set-aside allowances in a state – after 

distribution to all eligible projects in the state – to the 

affected EGUs in the state on a pro-rata basis in proportion to 

the initial allocations made to those EGUs under the mass-based 

federal plan. 

As discussed in section V.E below, the EPA proposes to 

allow any state where a federal plan is being implemented to 

take responsibility for distributing allowances to affected 

sources. This will allow a state to tailor its allowancedistribution approach to the characteristics and preferences of 

the state. The EPA proposes that for approval of a delegation or 

a partial state plan to handle allocations, a state that chooses 

198
to replace the federal-plan allocations with a state-determined 

approach must include a CEIP set-aside, as authorized in section 

VIII.B.2 in the Clean Power Plan EGs. The EPA intends that such 

a state would have the same flexibilities as a state 

implementing a full state plan with respect to implementation of 

the CEIP. That is, the state would not be required to implement 

a set-aside of the same size as proposed in [Table &&&], but 

rather could choose how many of its allowances to set-aside for 

the CEIP. 

The EPA requests comment on all aspects of implementing the 

CEIP under a mass-based federal plan approach, including (1) the 

size of the early action allowance set aside; (2) the approach 

for distributing the early action allowance set-aside among 

states; (3) the timing of distribution of set-aside and matching 

allowances; (4) the amount of allowances awarded per eligible 

MWh generated or avoided; (5) the criteria for eligible 

projects, including criteria for awards to EE projects that 

benefit low-income communities; (6) the mechanism for reviewing 

project submittals and issuing early action allowances; and (7) 

the evaluation, measurement and verification (EM&V) requirements 

for eligible projects. 

The EPA also requests comment on the proposed approach of 

requiring states to implement this program as a condition of a 

state choosing to determine its own allocation approach via a 

199
partial state plan or a delegation of the federal plan. In 

addition, the EPA requests comment on not providing matching 

allowances in the mass-based trading federal plan, or on only 

providing matching allowances in federal plan states that choose 

to determine their own allocation approach. 

Table &&&. Proposed Clean Energy Incentive Program Early Action 

Set-Aside in Mass-Based Federal Plan for Projects in 2020 and 

2021 (Short Tons) 

State Set-Aside 2022 

through 2024 

Alabama 3,122,306

Arizona 1,719,618

Arkansas 2,187,230

California 218,846

Colorado 2,223,192

Connecticut 69,415

Delaware 138,392

Florida 3,230,248

Georgia 2,755,623

Idaho 14,929

Illinois 5,968,721

Indiana 5,754,076

Iowa 2,191,183

Kansas 2,115,630

Kentucky 4,952,862

Lands of the Fort Mojave Tribe 5,885

Lands of the Navajo Nation 1,623,066

Lands of the Uintah and Ouray Reservation 175,509

Louisiana 1,497,428

Maine 20,739

Maryland 972,775

Massachusetts 170,471

Michigan 3,727,861

Minnesota 2,002,903

Mississippi 357,307

200
Missouri 3,771,322

Montana 1,310,344

Nebraska 1,481,695

Nevada 336,288

New Hampshire 107,798

New Jersey 446,005

New Mexico 823,049

New York 557,771

North Carolina 2,674,590

North Dakota 2,150,635

Ohio 4,788,372

Oklahoma 2,067,006

Oregon 154,353

Pennsylvania 5,039,346

Rhode Island 35,674

South Carolina 1,652,802

South Dakota 264,207

Tennessee 2,178,084

Texas 10,400,192

Utah 1,401,189

Virginia 1,386,546

Washington 751,434

West Virginia 3,506,890

Wisconsin 2,393,870

Wyoming 3,104,324

201
Attachment J.

202
From: Frey, Nathan J. <Nathan_J._Frey@omb.eop.gov>

Sent: Wednesday, July 29, 2015 5:30 PM

To: Jones, Toni

Cc: Culligan, Kevin; Harvey, Reid; Tsirigotis, Peter; Eck, Janet; Cozzie, David; Szabo, Aaron; Grossman,

Andrea

Subject: Summary of Interagency Comments Under EO 12866 and 13563 ‐‐ CPP Federal Plan RIA

  

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

Federal Plan RIA.

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

Nathan

203
Attachment J.1

204
• In the Federal Plan for Regulating Greenhouse Gas Emissions From Electric Generating Units, 

EPA adopts the SBREFA panel report recommendations in lieu of preparing its own 

consideration of alternatives. Reviewer notes that EPA should have prepared its own 

alternatives sections, building on the panel recommendations, incorporating the information 

EPA did not share with the panel during its deliberations, including the analysis of net 

compliance costs. Reviewer is concerned that, given the additional analysis performed by EPA, 

how it could demonstrate which of the recommendations would “accomplish the stated 

objectives of applicable statutes and which minimize any significant economic impact of the 

proposed rule on small entities.“ 

• EPA projects that 1⁄2 of the small entities remaining in the market in 2030 will experience costs of 

over 3% of generation revenue. This would indicate significant hardship. Reviewer 

recommends including an explanation regarding what regulatory alternatives considered by EPA 

are included in this analysis, which were rejected, and how the alternatives affected these 

results.

• EPA projects that 1/3 of all small utilities will be closed without this rule by 2030. Reviewer 

recommends providing additional information to substantiate this result. 

• Reviewer recommends including a discussion of how the costs of credits are incorporated into 

the analysis and describing how the costs/revenues from credit trading are included in the cost 

impacts.

• Reviewer recommends that EPA provide a discussion of wow sensitive the analysis of the results 

are to the number of states that participate in a Federal plan. Reviewer notes that a sizeable 

portion of States implement their own plans without trading to FIPs and recommends that EPA 

include a discussion in the analysis of the impacts on these costs.

• EPA has discussed the role of regulated markets in cost-recovery in past rulemakings. Reviewer 

recommends that EPA include a discussion of how this concept has been discussed in prior 

rulemakings. 

205
Attachment K.

206
From: Frey, Nathan J. <Nathan_J._Frey@omb.eop.gov>

Sent: Wednesday, July 29, 2015 8:01 PM

To: Culligan, Kevin; Macpherson, Alex; Jones, Toni; Harvey, Reid

Subject: Summary of Interagency Comments Under EO 12866 and 13563 ‐‐ CPP Federal Plan RIA

  

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

Federal Plan NPRM RIA.

  

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

  

Nathan

207
Attachment K.1

208
General Comments

Reviewer notes that there are a number of features of the federal plan (FP) that are modeled 

incorrectly, or not modeled, in the IPM runs used for the FP RIA, since the FP RIA reuses the modeling 

from the CPP EG RIA. The reviewer recommends new IPM model runs to capture the unique 

characteristics of the FP for the final version of this RIA, but the reviewer recognizes that due to time 

constraints additional analysis cannot be done now. In particular, it is especially problematic that this 

RIA fails to model trading for a proposal which is expressly designed to enable broad trading. As an 

alternative, reviewer recommends EPA clarify how the approaches modeled in the FP RIA differ from 

what is allowed under the proposed FP and quantitatively explain how this would affect the results. 

Reviewer recommends that the FP RIA include explanations for the major differences between the FP 

and the model runs being used in the FP RIA: 

1. Trading

2. Output based set-aside 

3. Rate goal type

4. Energy Efficiency

Below are suggested line edits to address these points. Reviewer also recommends taking comment on 

what additional analysis besides these four points would strengthen the modeling representation of the 

federal plan in the final. 

1. Trading - The CPP EG RIA assumed “that sources within each state comply with the applicable 

state goals without exchanging a compliance instrument (ERC or allowance) with sources in any 

other state.” (Page 3-11 in the RLSO of the CPP EG RIA). The FP RIA states that trading is 

allowed, which should lower the compliance cost and the cost of allowances/ERCs. In the massbased scenario, this would be expected to affect the time profile of emissions of CO2 and other 

priority pollutants because lower-cost allowances create a lower incentive to bank compliance 

instruments for the future. In the rate-based scenario, trading would be expected to change the 

overall level of emissions. 

Suggested additional text: 

Page 3-11 RLSO: After, “Similarly, an affected EGU in a state covered by the rate-based federal 

plan must use ERCS for compliance (not allowances)”, add the following paragraph:

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

without exchanging a compliance instrument with EGUs in other states. However, under the 

proposed FP if all states had a federal plan and the same type of goal (as they do in this 

analysis), then trading among EGUs in different states would be allowed and would be expected

to lower compliance costs. The EPA is inviting comment on this approach to the modeling and 

will seek to improve analysis supporting the final rule.”

2. Output based set-aside – Reviewer recommends moving forward (or reiterating) the first two 

paragraphs of the discussion on output based allocation (OBA) (to p. 1-32), in order to present it 

before the results so readers have a clear picture of what was modeled. Reviewer also 

recommends the following edits to the second paragraph.

Suggested edit:

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

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

in this rulemaking. Therefore, in section X.X the EPA conducted additional analysis to 

209
approximate the potential emissions reductions if the OBA set-aside were included in that massbased scenario. The EPA is inviting comment on OBA. If appropriate, the EPA is inviting 

comment on its approach to modeling OBA and will further explore OBA as a means to mitigate 

leakage in the analysis supporting the final federal plan and model trading rules.” 

3. Rate goal type – On page 1-9 to 1-10 EPA states that the CPP EG RIA (and therefore the FP RIA) 

apply the state blended rate-based goal, but that the FP require the technology-specific rate 

goals. Reviewer recommends including a discussion of the implications of this difference.

Suggested edit: 

“Furthermore, the rate-based illustrative plan in the Final Clean Power Plan Emission Guidelines 

RIA assumes that the plan applies a state’s blended rate-based goal as a requirement for 

affected EGUs in that state to achieve. Alternatively, the proposed federal plan specifically 

establishes an emissions rate performance standard that is applied to affected steam-fired EGUs 

and an emission rate performance standard that is applied to affected natural gas-fired 

combined cycle EGUs. The technology-specific rate goal will alter the incentives among affected 

sources and could lead to different generation mixes and emissions. The EPA is inviting 

comment on its approach to modeling the FP and will further explore technology-specific 

standards to improve analysis supporting the final rule.”

4. Energy Efficiency –Reviewer recommends updating the text on 1-9 for clarity, as EE is currently

not included in the Federal Plan. Reviewer notes that in earlier comments, reviewer suggested 

that EE should be included in the Federal Plan. 

Suggested edit: 

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

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

the emission performance rates at affected EGUs. However, this proposed FP rule takes 

comment on whether or not EPA should does not allow demand-side energy efficiency to 

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

approach. However, This RIA assumes that states will use demand-side energy efficiency 

measures to reduce demand and thus reduce EGU compliance costs.9 Because energy efficiency 

may not create ERCs that could be used to cost-effectively comply, this RIA might understate the 

incremental compliance costs of the proposed federal plan and model trading rules. The EPA is 

inviting comment on this approach to the modeling, and EPA will seek to improve analysis 

supporting the final rule regarding demand-side energy efficiency and the associated benefits 

and costs.” 

210
Technical Comments

1) Page 1-1. Reviewer recommends the following change: “This proposal presents two approaches 

to a federal plan (or model rule) for states and other jurisdictions that either choose to adopt 

the model rule or do not adopt and submit to the EPA in a timely manner an approvable state

plan: a rate-based emission trading program and a mass-based emission trading program.” A 

version of this language is included on page 2-2.

2) Page 1-2. Reviewer recommends the following change to ensure consistency with the Federal 

Implementation Plan: “Upon approval of the state plan by EPA, the federal plan will no longer 

apply to the affected EGUs covered by the approved state plan, starting at the initiation of the 

next compliance period with the limitations noted in the federal plan.”

3) Page 1-5: Reviewer recommends clarifying whether using the EPA-administered tracking system 

enables trading among all participants or if trading would only occur between states with state 

plans or between states with the federal plan. If trading is allowed between all states using 

similar plan approaches, text should be edited to reflect this (Page 1-5) Suggested text: 

“The EPA proposes that affected EGUs in any state covered by a federal plan could trade 

compliance instruments with affected EGUs, or procure zero-emissions megawatt hours (MWhs) 

from eligible resources, in any other state covered by a federal plan or state plan that uses the 

same approach. In the proposed mass-based federal-plan trading program, this would mean 

that affected EGUs in a state covered by the federal plan could use, as a compliance instrument, 

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

same approach. Similarly, in the proposed rate-based federal-plan trading program approach, 

this would mean that affected EGUs in a state covered by a federal plan could use, as a 

compliance instrument, an emission rate credit (ERC) issued in any other state covered by a 

federal plan or state plan with the same approach.” 

4) Page 1-6: Reviewer recommends editing the second full paragraph for clarity. When reading for 

the first time, the reviewer thought that four scenarios had been modeled.

“Because of this lack of information, for this RIA, the EPA has chosen to examine a scenario 

where all states of the contiguous U.S. will be regulated under a federal plan. Furthermore, 

because of the lack of information as to which states will adopt the model rule, the EPA has 

chosen to examine a scenario where all states of the contiguous U.S. adopt the model trading 

rule. Additionally Furthermore, we examine two alternative federal plan approach scenarios, 

which will be described in more detail below, for implementation of federal plans. The first 

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

regulated under a rate-based federal plan. The second federal plan approach we examine 

assumes all contiguous states are regulated under a mass-based federal plan. The two 

approaches that are examined in this RIA are a re-presentation of the modeling done for the 

Clean Power Plan Emission Guidelines RIA.” 

5) Page 1-9. Reviewer requests that EPA provide a description of the mass-based assumptions 

parallel to those provided for the rate-based assumptions.

6) Page 1-32. Reviewer recommends the following change: “Then, based on the allowance prices 

for the state in which each model plant resides, the EPA adjusted...” Given that this RIA claims 

211
to be modeling trading across states, there would be a single allowance price, not different 

allowance prices for each state. 

7) Page 1-33. Reviewer recommends the following change: “The OBA set-aside may also place 

upward pressure on the price of natural gas which would reduce the effectiveness of the setaside at encouraging increased utilization of existing NGCC EGUs, but the OBA set-aside would 

be effective in increasing existing NGCC generation.” 

8) Reviewer notes that costs are also over-estimates for small business owners that operate 

affected EGUs in some competitive environments, particularly those where a steam EGU is on 

the margin and the affected EGUs of small businesses are NGCC EGUs inside the margin. Cost 

are really only increased for small business owners in the case of steam EGUs that are 

inframarginal when NGCC EGUs are on the margin. Reviewer recommends adding, for example, 

the following: "Similarly, entities owning NGCC EGUs operating in competitive markets are likely 

to be able to recover compliance costs if steam EGUs are setting the marginal price."

9) Page 2-23: "However, EPA believes the design of the federal plan as a flexible trading program 

alleviates these concerns and therefore a reliability mechanism is not needed."

Comment: Reviewer recommends further explaining why emergency events that would 

otherwise trigger the reliability safety valve would not do so under a federal plan (noting that 

this depends on how the final CPP is clarified on this issue). Further, reviewer recommends 

considering (and explaining) why, given the limited circumstances under which a reliability 

safety valve would be exercised, the opportunity to do so is foreclosed with compliance under a 

federal plan, especially given that the federal plan structure (trading) cannot guarantee that a 

reliability safety valve-qualifying emergency event would not occur. 

Typographical Comments

1) Reviewer recommends using the word “modeled” throughout text of this document and other 

related documents, not “modelled.”

2) Page 1-1. Reviewer recommends the following change: “The federal plan is an important 

measure to ensure that congressionally mandated emission standards under the authority of 

the congressionally mandated CAA are implemented.” This change could also be made on page 

2-2.

3) Page 1-5: “Similarly, an affected EGU in a state covered by the rate-based trading federal plan 

must use ERCSs for compliance (not allowances).”

4) Page 1-8, Footnote 7: “Detailed documentation for IPM v.5.1 IPM v.5.15 is available at: available 

at: http://www.epa.gov/powersectormodeling.”

5) Page 1-20. Reviewer recommends checking the math on the SC-CO2 presented. The 2020 costs 

on the EPA’s webpage (http://www.epa.gov/climatechange/EPAactivities/economics/scc.html ) 

212
are reported in 2014$ in metric tons: 13, 47, 69, and 140. Using 0.907 metric ton per short ton 

and 0.954 2011$/2014$, reviewer calculates the four prices: 11, 41, 60, and 121. Reviewer also 

recommends referencing NIPA Table 1.1.9 Implicit Price Deflators and Gross Domestic Product 

instead of the outdated table currently referenced in footnote 20.

6) Page 1-33: “We do not quantify the effect of these changes in generation on SO2 and NOx 

emissions, although on net additional co-benefits would be expected.”

7) Page 2-2. Reviewer notes that the CPP EG will be out by the time this is published: “The final 

Clean Power Plan Emission Guidelines, released this summer, are related to but separate from 

the proposed federal plan.”

8) Page 2-19. Reviewer believes this change should be made five times throughout the paragraph: 

“Advocacy The EPA shares many of the concerns raised...” In the previous paragraph, reviewer 

recommends changing “The Agency” to “The EPA”

9) Page 2-19. Reviewer recommends clarifying what the acronym “SERs” stands for when first used 

at the top of this page. 

213
Attachment L.

214
From: Jones, Toni <Jones.Toni@epa.gov>

Sent: Wednesday, July 29, 2015 8:05 PM

To: Frey, Nathan J.

Cc: Culligan, Kevin; Macpherson, Alex; Harvey, Reid

Subject: RE: Summary of Interagency Comments Under EO 12866 and 13563 ‐‐ CPP Federal Plan RIA

  

Thank you, Nathan.  I’ll consolidate the two sets of comments we’ve received this evening into one

document, and we’ll provide responses promptly.  In that regard, please let me know, if possible, if we

should expect additional comments tonight or tomorrow.

Kind regards,

Toni

Toni Wyche Jones, EI, CFM | Fuels & Incineration Group | Sector Policies & Programs Division - Mail Code E143-

05 | Office of Air Quality Planning & Standards | U.S. Environmental Protection Agency | RTP, NC 27711 | Phone: 

(919) 541-0316 |

From: Frey, Nathan J. [mailto:Nathan_J._Frey@omb.eop.gov]  

Sent: Wednesday, July 29, 2015 8:02 PM

To: Culligan, Kevin; Macpherson, Alex; Jones, Toni; Harvey, Reid

Subject: Summary of Interagency Comments Under EO 12866 and 13563 ‐‐ CPP Federal Plan RIA

  

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

Federal Plan NPRM RIA.

  

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

  

Nathan

215
Attachment M.

216
From: Jones, Toni <Jones.Toni@epa.gov>

Sent: Wednesday, July 29, 2015 10:36 PM

To: Frey, Nathan J.

Cc: Culligan, Kevin; Harvey, Reid; Tsirigotis, Peter; Eck, Janet; Cozzie, David

Subject: RE: EO 12866 CPP Federal Plan ‐ response to comments

  

Hi Nathan,

As promised, attached please find a redline version of the CPP Federal Plan preamble that reflects

changes made to the package since responding to OMB comments on July 27.  The revised rule text for

the federal plan will be sent along in a separate email tomorrow morning.  Please note, we will provide

responses to the comments received this evening in a separate email, along with conforming edits to

the RIA.

Please let know if you have any questions.

Kind regards,

Toni

Toni Wyche Jones, EI, CFM | Fuels & Incineration Group | Sector Policies & Programs Division - Mail Code E143-

05 | Office of Air Quality Planning & Standards | U.S. Environmental Protection Agency | RTP, NC 27711 | Phone: 

(919) 541-0316 |

  

217
Attachment M.1

218
RIN 2060-AS47

Federal Plan Requirements for Greenhouse Gas Emissions from Electric Utility Generating Units 

Constructed on or Before January 8, 2014; Model Trading Rules; Amendments to Framework 

Regulations

Reliability 

1) Page 64. “Therefore, a reliability safety valve for the federal plan is not needed. EPA invites 

comments on this aspect of the proposed federal plan.”

Comment: Reviewer recommends further explaining why emergency events (on Pg. 64) that 

would otherwise trigger the reliability safety valve would not do so under a federal plan, 

especially with respect to any short-term modifications to a federal plan that may be needed 

(noting that this depends on how the final CPP is clarified on this issue). Further, reviewer 

recommends considering (and explaining) why, given the limited circumstances under which a 

reliability safety valve would be exercised, the opportunity to do so is foreclosed with 

compliance under a federal plan, especially given that the federal plan structure (trading) cannot 

guarantee that a reliability safety valve-qualifying emergency event would not occur. 

Response: Emergency events can happen regardless of the plan. An inflexible plan that places 

requirements on individual EGUs may make it difficult to respond to some types of emergencies. The 

federal plan is not that type of plan. The kind of remedy that the reliability safety valve offers is not 

useful in the case of the federal plan. Rather in the federal plan, EGUs can make of use of ERC or 

allowances to make up any additional emissions reductions needed. Further we have proposed two 

more appropriate ways to address an emergency if in fact those ERCs or allowances are not available.

2) Reviewer recommends that, in the event that the RSV is triggered, all excess emissions should 

be made up to maintain the stringency of the program on page 1163.

Response: This comment refers to the Emissions Guidelines, not to the federal plan. 

EPA indicates that a reliability safety valve is not needed for the federal plan (page 64). This is 

based on the assumption that affected EGUs can obtain allowances or credits as and when 

needed. However, the availability of allowances and credits would depend on the number of 

states that come under a federal plan or under a state plan that is “presumptively approvable.” 

Moreover, based on market fluctuations and operational anomalies, credits and allowances may 

not be available at a critical time when a system is faced with a serious reliability risk, or may be 

available but only at prohibitive prices. Accordingly, reviewers suggest that EPA set out certain 

limiting criteria for a safety valve in the federal plan instead of not including a safety valve at all. 

In addition, reviewer suggests that EPA allow the creation of ERCs and allowances before the 

compliance period begins in 2022. This would result in early emission reductions and 

environmental benefits and would also allow states and EGUs to create a bank of ERCs or 

allowances in advance of the compliance period to reduce the possible dependence on a safety 

valve in the early years of the initial compliance period. 

Response: Although EPA believes it is unlikely that allowances or ERCs would not be available if needed 

to meet an emergency situation, EPA has requested comment on two options to deal with this problem. 

One of those options is a very similar option to what the reviewer is recommending in the federal plan. 

219
Page 259. Reviewer recommends adding to the list of completeness criteria discussed on Pg. 259 

the 111(d) plan requirement regarding demonstrating that the state has consulted with the 

planning authority/reliability coordinator.

Response: This comment refers to the Emissions Guidelines, not to the federal plan. 

New Source Review 

The preamble states in several places (see e.g. pages 80-81) that the “situations will be very 

few” in which NSR applicability is triggered because of undertaking a physical change or change 

in the method of operation. EPA needs to substantiate this conclusion through an analysis to 

show why it believes that measure taken under BB 1 and BB2 would trigger NSR only in a “few 

situations.” This conclusion that NSR would be triggered in only a “few situations” appears 

inconsistent with EPA’s policies on implementation of NSR. While this is an NSR issue, it has 

bearing on this rulemaking because widespread triggering of NSR for the BSER measures under 

this rule may have an impact on the ability to meet the compliance schedule under this rule. The 

preamble cites UARG v. EPA for the proposition that greenhouse gas emissions alone cannot 

trigger NSR requirements. However, this case would not necessarily help sources avoid NSR with 

respect to the implementation of the Clean Power Plan because BSER measures under BB1 and 

BB2 could result in an increase in emissions of GHG and criteria pollutants (SO2, NOx, PM, etc.), 

resulting in those sources being considered “anyway” sources. 

Response: The EPA will invite comment on potential scenarios in which affected EGUs, particularly small 

entities, could be subject to the requirements of the NSR program as a result of taking compliance 

measures under the federal plan, and any ideas for harmonizing or streamlining the permitting process 

for such sources that are consistent with judicial precedent. However, the EPA is not proposing any 

changes to the NSR program in this action, and the agency is not reopening or reconsidering any prior 

actions or determinations related to NSR in this action. Any comments related solely to the NSR program 

will be considered out of scope of this proposed rule.

Additional comments received 28 July 2015 

• P.150 redline: “... This means that fractional GS-ERCs are generated for every NGCC

MWh and when the interconnect region collectively reaches the level that would be 

generated if all NGCCs in the region operated at a 75 percent capacity factor there will 

be an amount of GS-ERCs that correlates to the emission reductions anticipated under

BB2 of the BSER. NGCC units are expected to be incentivized to reach this level of 

generation in part due to market demand for GS-ERCs. Thus, GS-ERCs have the potential 

to play an important role in the sector meeting compliance obligations. Conversely, the 

extent to which cumulative NGCC generation will achieve the 75% capacity factor is 

ultimately related to relative market forces in future years (e.g., cost of natural gas, cost 

of RE), and the extent to which NGCC generation may fall short of the 75% level 

represents a potential discount on the benefit of a unit GS-ERC to actually achieve a zero 

CO2 emission MWh. For instance, if relative generation prices (with GS-ERCs and ERCs 

accounted for) in future years militate toward no or low increase in covered NGCC 

220
generation from the 2012 baseline, then a large fraction of the GS-ERCs will have been 

issued without any reduction in CO2 emissions, rising proportionally to fully reaching 

the unit zero emission MWh benefit as the NGCC generation more closely approaches 

75%. The additional ERCs required by fossil steam EGUs in situations below 75% NGCC 

generation would be made up by increased conventional ERC generation and purchase, 

but not the GS-ERCs already issued.”

Response: EPA suggests the following: “The EPA notes that in this situation that if NGCC generation is 

below the 2012 baseline that the GS-ERCs generated do not represent any reductions in emissions.” 

 

• P.161-162 Redline: “While having a baseline threshold for EGU generation to credit GSERCs against closely resembles the EPA’s BSER determination, it enables a system in 

which GS-ERCs can be generated by replacing NGCC generation from one unit with 

NGCC generation from another. In this situation there is not necessarily any additional 

NGCC generation as a subcategory, but a shift in which NGCC units are generating 

electricity and to what degree. This allows for a situation in which GS-ERCs can be 

generated without achieving the anticipated reductions in CO2 emissions. An alternative 

under such an incremental GS-ERC system would be to require that system operators 

that manage more than one covered NGCC EGU to reach a cumulative average dispatch 

rate for all of their covered NGCC units that is greater than the baseline (2012 or 

state/regional average), prior to being able to generate GS-ERCs on any of their NGCC 

units.”

Response: The language proposed by the reviewer may obligate the system operators and make them 

subject to the rule. EPA suggests the following replacement language, “The EPA solicits comment on an 

alternative that in order to generate GS-ERCs, a system of NGCC units managed by the same system 

operator must generate greater than the collective baseline prior to being able to generate GS-ERCs on 

any of the encompassed NGCC units.”

1. Endangered Species language. This section militates great care to not create adverse sound 

bites, and some of the current text could be adjusted to be more explicit, sentence by sentence, 

on what is being conveyed. Comments inserted (redline 423 onward) and below:

• P. 423-424 Redline: “The EPA reached this conclusion after evaluating issues relating to 

potential improvements from the fuel efficiency rule relevant to both temperature and 

oceanographic pH outputs. The EPA's ultimate finding was that “any potential for a 

specific impact [of the specific Federal action] 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 the 

same conclusion applies to the present rule. See, e.g., Ground Zero Center for NonViolent Action v. U.S. Dept. of Navy, 383 F. 3d 1082, 1091-92 (9th Cir. 2004). EPA 

similarly determines that the likelihood of jeopardy to a species from the CPP is 

extremely remote, and ESA does not require consultation). The EPA’s proposed 

conclusion is entirely consistent with DOI’s analysis regarding ESA requirements in the 

context of federal actions involving GHG emissions.”

221
Response: Edits have been made consistent with this suggestion, however, we refer to the “proposed 

action” which is the federal plan, rather than the CPP in this instance. 

General Comments received July 29 2015 (page numbers refer to the RLSO version)

1. Reviewer recommends proposing (rather than taking comment on) that all non-BSER 

technologies and measures that are acceptable to generate ERCs in the emission guidelines 

(EGs) be proposed as approved to generate ERCs under a rate-based federal plan. Reviewer 

notes that renewable and nuclear are included as defaults but energy efficiency is missing.

 

Response: The feasibility of federal implementation is a key concern, and thus the EPA is proposing to 

only include non-distributed RE and new or up-rated generation due to requirements and rigor needed 

to ensure the quality of data and emission reductions achieved through the other described ERC 

generating resources.

2. Reviewer recommends that the allowances that are set-aside in the mass-based approach for 

low- or zero-emission activities be distributed using a technology-neutral methodology and not 

reserved exclusively for RE. For example, on RLSO page 163, reviewer recommends that new 

nuclear units and capacity uprates at existing nuclear units should be eligible to receive set-aside 

allowances to provide equal treatment under the rate-based and mass-based plans. Reviewer 

also recommends renaming this group of allowances as the Clean Energy Set-Aside to avoid 

confusion with the set-aside for existing NGCC. 

Response: The EPA disagrees with the approach for recognizing all emission reductions measures eligible 

under the final emission guidelines for set-aside eligibility. In the context of the federal plan, the 

feasibility of federal implementation is a key concern, and thus we propose technologies that are widely 

demonstrated and provide the simplest path for EM&V implementation under a federal plan. We seek 

comment on how to implement the EM&V requirements for various technologies proposed in the 

federal plan, and how that could be implemented in the context of the final rule. We also seek comment 

on a process by which technologies can be determined to be eligible. 

Incremental nuclear power and nuclear up-rates are not recognized under the set-aside because they do 

not face the same economic circumstances as RE capacity, and are not effectively addressed by the 

incentive provided by a set-aside. The EPA notes that if states under a federal plan wish to have the 

ability to recognize other eligible technologies, including nuclear, as part of a set-aside, they have the 

opportunity to submit state allowance distribution methodology as part of a partial state plan, and they 

can determine the allocation method, including set-aside structure, under the federal plan. The states 

also have the opportunity to submit an approvable state plan that has its own set-aside structure.

Technical Comments

Page 43 RLSO. Reviewer requests clarifying the meaning and intent of this: “all of the language and 

provisions in the regulatory text relevant to these other ERC resources is relevant only to the proposed 

model trading rule and not to the federal plan as such. “

222
Response: This language is noting that all the options for ERC generation are available for states that 

adopt the model rule, but ERC generating resources are limited in states subject to the federal plan. The 

sentence has been given a qualifier for clarity: “Thus, all of the language and provisions in the regulatory 

text relevant to these other ERC resources is relevant only to the proposed model trading rule and not 

to the federal plan as such (i.e., those ERC resources discussed in section VI.C.3 of this preamble are 

applicable to the model rule and only metered RE and applicable nuclear are applicable to the federal 

plan).”

Page 139 RLSO. Reviewer suggests clarifying changing “certain nuclear” to “new and uprated nuclear”.

Response: The text has been edited to say “nuclear generation (from new capacity and incremental 

capacity uprates)”

p.144 – “(3) new nuclear units and capacity uprates at existing nuclear units, and RE providers that 

develop metered projects and programs whose results, in MWh, are quantified and verified according to 

EM&V criteria as described below in section &&& IV.D.6 of this preamble.” Reviewer supports the 

revised language that includes reference to “metered” RE projects and programs. However, given that 

the requirement now exists for the projects to be metered, reviewer recommends allowing all 

renewable energy technologies – including offshore wind and distributed solar – to generate ERCs, 

provided they are metered and adhere to EM&V criteria. While all renewable energy technologies may 

not be “expected to be able to deploy on an economic basis during the compliance period” (p.164), if 

they aren’t economic, states are very unlikely to deploy them. This should result in no additional costs 

or administrative challenges.

 

Response: The EPA disagrees with the comment. We are proposing the inclusion of certain types of 

technologies that can be metered, are widely demonstrated, and are expected to be able to deploy on 

an economic basis during the compliance period. We are requesting comment on the inclusion of other 

RE technologies and whether they meet these criteria. 

Page 148 RLSO. Reviewer suggests rewording the following sentence: “This means that most NGCC units 

are being called to increase annual generation from 2012 baseline emissions.” Reviewer is concerned 

this could be seen as a requirement for the implementation of part of BSER, which language above 

reiterates is not the case. Suggested rewording: “This level of generation, for most NGCC units, would 

represent an increase in annual generation from a 2012 baseline.”

Response: Suggested language has been incorporated

Page 149 RLSO. Reviewer recommends clarifying that (addition in red) “All affected NGCC generation 

will be credited, with ERCs, by a factor that represents the described emission reductions from 

incremental generation; ERCs credited in this way will be designated as Gas Shift ERCs (GS-ERCs) for 

clarity.” Reviewer also notes that this seems to conflict with the language describing only marginal 

generation beyond a certain average capacity factor will be credited, as described on pages 316-317.

Response: The term “affected” has been incorporated. The discussion of the average capacity factor 

pertains to the proposed mass based trading program while ERCs pertain to the proposed rate-based 

trading program.

223
Page 227-244 RLSO. Reviewer notes that pages 227-244 appear to be language from earlier versions of 

draft EM&V guidance documents, and suggests clarifying if the inclusion of the language in this 

document means that a separate guidance document on EM&V is no longer intended to be provided, or 

if this is meant to complement the separate guidance. 

Response: There will be a separate guidance document pertaining to EM&V released with the model 

rule and federal plan. 

p.229 – “These categories include project-based measurement and verification (M&V), deemed savings, 

and comparison group approaches such as randomized control trials (RCT). Regardless of the approach 

selected, the EPA is proposing that annual savings values must be quantified using these EM&V methods 

at specified time intervals (in years) on a recurring basis over the effective useful life of the EE project or 

measure in order to ensure accurate and reliable savings values. To be considered presumptively 

approvable, EE providers must conduct apply the above methods at a minimum of four year intervals for 

building energy codes and product standards; every one, two or three years for publicly or rate-payer 

funded EE programs, depending on the program type, magnitude of savings, and experience with the 

program; and annually for large individual commercial and industrial projects, unless the EE provider can 

credibly demonstrate why this is not possible and how the accuracy and reliability of savings values will 

be maintained.”

Reviewer finds the inclusion of deemed savings in this paragraph confusing. Reviewer believes that EPA 

means that states should update their deemed savings estimates every three years, per the language on 

subsequent pages, which makes sense. In this paragraph, however, it appears that EPA would require 

states to repeatedly calculate savings from the same project using deemed savings. 

Response: The EPA’s final emission guidelines require that all EE providers demonstrate that they will 

quantify and verify MWh savings using best-practice EM&V approaches. One way to make this 

demonstration is to use the presumptively approvable EM&V approaches in the proposed Federal Plan, 

which specify that deemed savings values must be updated at least every three years (in addition to 

other quality control provisions around the use of deemed values). A separate presumptively 

approvable EM&V provision is that all MWh savings values must be quantified using allowable EM&V 

methods, which may include updated deemed savings values, at specified time intervals based on the 

program or project under consideration. 

Page 319-320 RLSO: Reviewer notes the references to 111(b) seems to be outdated and should updated: 

“ Specifically, an additional MWh of eligible generation would earn the affected EGU allowances equal 

to the level of emissions permitted per MWh of net generation under the 111(b) new source standard, 

which is 1,030 lb/MWh-net.”

Response: The EPA updated the references.

Typographical Comments

p. 18. Given EPA’s intent to finalize a single approach, commenter recommends the following change 

should delete “if we opt to finalize a single approach” at the end of that paragraph. “We invite 

comment on which approach, i.e., either mass-based or rate-based trading, should be selected if when

we opt to finalize a single approach.”

224
Response: The edit has been made.

Page 22. Reviewer requests clarification on how “vulnerable” communities are defined. 

Response: The agency gave extensive consideration to impacts on vulnerable communities, particularly 

low-income communities, communities of color, and indigenous communities. The EPA defines 

vulnerable communities to include low-income communities, communities of color, and indigenous 

communities. At this time no additional edits will be made. 

Page 68. Reviewer notes that language is missing here: “The final guidelines specify the concern of 

leakage...”.

Response: The edit has been made.

Page 85. Reviewer requests clarification on how the federal plan can propose a two year compliance 

period after 2030 when this is finalized in the EG.

Response: The EPA is taking comment on the length of the affected EGU compliance periods for the 

emission standards. In the Final EG, the EPA allows states the flexibility to have compliance periods that 

are shorter than the interim step and final reporting periods.

Page 90. "The EPA will work with the ISO/RTO Council to convene a face-to-face meeting for planning 

authorities with the EPA during the comment period to discuss any concerns or other feedback on the 

federal plan from those entities."

Comment: Reviewer still recommends expanding use of the ISO/RTO Council to reliability coordinators 

and planning authorities because the IRC does not encompass all areas of the country. The EPA 

response refers to text on Pg. 88 in a different context.

Response: Language has been changed. The intention was to say that the IRC could help us organize 

such a meeting, not that it would be limited to their participation. 

Page 144. Reviewer recommends clarifying that “RE providers that develop metered projects and 

programs...” become the fourth category and not be included in the third category to simplify 

composition.

Response: Text has been edited.

Page 148-149. Reviewer recommends noting that NGCC will receive “a partial credit” or otherwise 

clarifying that NGCC will not receive an entire emission reduction credit for every hour of electricity it 

produces. 

Response: Text has been edited

Page 158. Reviewer believes that the steam generating unit emissions standard should be 1305 lbs 

CO2/MWh, as shown on page 142 (Table 4). That change would also change some of the equations on 

the page.

225
Response: The example in question states that this calculation is occurring in the second interim 

compliance period. The table of standards shows this to be 1,500 as used in the equation. 

 

Page 163. Reviewer notes that the following sentence is incomplete and requests clarification about 

what is being proposed: “Further, the EPA is proposing that new nuclear units and capacity uprates at 

existing nuclear units that meet the requirements for eligible resources in the emission guidelines (as 

specified in the final emission guidelines Sec.VIII.K.) and all other requirements related to ERC issuance 

in the emission guidelines and this proposal.”

Response: Sentence has been modified to end with “...proposal are eligible to generate ERCs.”

p.221 –Reviewer notes a possible typo “The EPA requests comment on all metering, measurement, 

verification, and other requirements included in this subsection, including the appropriateness of their 

use for each type of renewable nuclear energy resource (including the relvant size and distribution of 

such resource) that qualifies for issuance of ERCs for use in Clean Power Plan compliance.”

Response: Text has been changed.

p. 222 - "Prorated MWh = (1 - incremental CHP emission rate/applicable affected EGU emission limit

rate) * CHP MWh output, where the ratio is limited to values between 0 and 1." Reviewer believes the 

word “limit” is a mistake in the sentence above, and that it should be struck to be more consistent with 

the sentence later on that same page: "The incremental rate would be relative to the applicable CO2 

emission rate for affected EGUs in the state and would be limited to values between 0 and 1."

Response: The term “limit” was in the correct place (changed to “standard”), but the sentence below 

should have had the term as well. “...to the applicable CO2 emission rate standard for affected EGUs...”

Page 398. Reviewer recommends considering whether the list of completeness criteria discussed on Pg. 

398 should include the 111(d) plan requirement regarding demonstrating that the state has consulted 

with the planning authority/reliability coordinator. (Also applies to the reg text, Pg.3.)

Response: The requirement that the state demonstrate that it has consulted with planning authorities is 

one of the approvability criteria for a state plan. Here in section VII. A. of the Federal Plan. The EPA is 

also proposing a number of changes to the framework 111(d) regulations of Subpart B of 40 CFR Part 60. 

This updates completeness criteria for all regulations under section 111(2) of the Clean Air Act not just 

the CPP, and so the EPA is not making the change suggested above.

Page 90. Reviewer recommends further explaining why emergency events (on Pg. 90) that would 

otherwise trigger the reliability safety valve (emissions would not be counted against a state plan) would 

not do so under a federal plan, especially with respect to any short-term modifications to a federal plan 

that may be needed (noting that this depends on how the final CPP is clarified on this issue).

Response: This comment is responded to above.

226
Attachment M.2

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment M.2.

227
Attachment N.

228
From: Szabo, Aaron <Aaron_L_Szabo@omb.eop.gov>

Sent: Thursday, July 30, 2015 6:30 PM

To: Jones, Toni; Culligan, Kevin; Harvey, Reid

Cc: Frey, Nathan J.; Grossman, Andrea

Subject: TSDs for Federal Plan

  

Toni,

  

Based on interagency comments, reviewers have requested the TSDs listed below.  If EPA is no longer

planning to develop the TSD, the reference should be removed from the Federal Plan preamble.

1. Affected EGU TSD

2. GS‐ERC TSD

3. Allowance Allocation Proposed Rule TSD

4. EGs Baseline TSD

  

Thank you and let me know if you have any questions.

  

Aaron L. Szabo

Policy Analyst

Office of Management and Budget

202‐395‐3621

Aaron_L_Szabo@omb.eop.gov

  

229
Attachment O.

230
From: Jones, Toni <Jones.Toni@epa.gov>

Sent: Thursday, July 30, 2015 7:19 PM

To: Frey, Nathan J.

Cc: Culligan, Kevin; Harvey, Reid; Tsirigotis, Peter; Eck, Janet

Subject: RE: EO 12866 CPP Federal Plan and RIA ‐ response to comments

  

Hi Nathan,

Attached please find responses to the comments received yesterday regarding the RIA, along with

responses to several outstanding comments received earlier in the week.  Additionally, attached please

find a redline of the rule text that reflects edits made since the last version submitted to OMB for

review.  

  

Also note, Kevin is working to send a small section on the retirement approach for your review.

As always, let me know if there are any questions.

Kind regards,

Toni

Toni Wyche Jones, EI, CFM | Fuels & Incineration Group | Sector Policies & Programs Division - Mail Code E143-

05 | Office of Air Quality Planning & Standards | U.S. Environmental Protection Agency | RTP, NC 27711 | Phone: 

(919) 541-0316 |

  

231
Attachment O.1

232
Comments on Chapter 1 and 2, received 7/29/15

General Comments

Reviewer notes that RIA fails to model trading for a proposal which is expressly designed to 

enable broad trading. As an alternative, reviewer recommends EPA clarify how the approaches 

modeled in the FP RIA differ from what is allowed under the proposed FP and quantitatively 

explain how this would affect the results. Reviewer recommends that the FP RIA include 

explanations for the major differences between the FP and the model runs being used in the FP 

RIA: 

1. Trading

2. Output based set-aside 

3. Rate goal type

4. Energy Efficiency

Below are suggested line edits to address these points. Reviewer also recommends taking 

comment on what additional analysis besides these four points would strengthen the modeling 

representation of the federal plan in the final. 

1. Trading - The CPP EG RIA assumed “that sources within each state comply with the 

applicable state goals without exchanging a compliance instrument (ERC or allowance) 

with sources in any other state.” (Page 3-11 in the RLSO of the CPP EG RIA). The FP RIA 

states that trading is allowed, which should lower the compliance cost and the cost of 

allowances/ERCs. In the mass-based scenario, this would be expected to affect the time 

profile of emissions of CO2 and other priority pollutants because lower-cost allowances

create a lower incentive to bank compliance instruments for the future. In the ratebased scenario, trading would be expected to change the overall level of emissions. 

Suggested additional text: 

Page 3-11 RLSO: After, “Similarly, an affected EGU in a state covered by the rate-based 

federal plan must use ERCS for compliance (not allowances)”, add the following 

paragraph:

Response: EPA notes that in this analysis EGUs within each state comply with the applicable 

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

under the proposed FP if all states had a federal plan and the same type of goal (as they do in 

this analysis), then trading among EGUs in different states would be allowed and would be 

expected to lower compliance costs. The EPA is inviting comment on this approach to the 

modeling and will seek to improve analysis supporting the final rule.”

2. Output based set-aside – Reviewer recommends moving forward (or reiterating) the 

first two paragraphs of the discussion on output based allocation (OBA) (to p. 1-32), in 

order to present it before the results so readers have a clear picture of what was 

modeled. Reviewer also recommends the following edits to the second paragraph.

Suggested edit:

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

representation of the set-aside for new renewable generation, it did not quantify the 

Commented [A1]: EPA response: we adopted the suggested 

language

Commented [A2]: EPA response: we moved the suggested 

paragraphs and we revised the text to state we are taking comment 

on our approach to approximate the impact of OBA on the results 

of the analysis.

233
effects of the OBA as proposed in this rulemaking. Therefore, in section X.X the EPA 

conducted additional analysis to approximate the potential emissions reductions if the 

OBA set-aside were included in that mass-based scenario. The EPA is inviting comment 

on OBA. If appropriate, the EPA is inviting comment on its approach to modeling OBA 

and will further explore OBA as a means to mitigate leakage in the analysis supporting 

the final federal plan and model trading rules.”

3. Rate goal type – On page 1-9 to 1-10 EPA states that the CPP EG RIA (and therefore the 

FP RIA) apply the state blended rate-based goal, but that the FP require the technologyspecific rate goals. Reviewer recommends including a discussion of the implications of 

this difference.

Suggested edit: 

“Furthermore, the rate-based illustrative plan in the Final Clean Power Plan Emission 

Guidelines RIA assumes that the plan applies a state’s blended rate-based goal as a 

requirement for affected EGUs in that state to achieve. Alternatively, the proposed 

federal plan specifically establishes an emissions rate performance standard that is 

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

applied to affected natural gas-fired combined cycle EGUs. 

Response: The technology-specific rate goal will alter the incentives among affected sources 

and could lead to different generation mixes and emissions. The EPA is inviting comment on its

approach to modeling the FP and will further explore technology-specific standards to improve 

analysis supporting the final rule.”

4. Energy Efficiency –Reviewer recommends updating the text on 1-9 for clarity, as EE is

currently not included in the Federal Plan. Reviewer notes that in earlier comments, 

reviewer suggested that EE should be included in the Federal Plan. 

Suggested edit: 

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

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

meeting the emission performance rates at affected EGUs. However, this proposed FP 

rule takes comment on whether or not EPA should does not allow demand-side energy 

efficiency to directly count toward the compliance rate of affected EGUs in a rate-based 

compliance approach. However, This RIA assumes that states will use demand-side 

energy efficiency measures to reduce demand and thus reduce EGU compliance costs.9

Because energy efficiency may not create ERCs that could be used to cost-effectively 

comply, this RIA might understate the incremental compliance costs of the proposed 

federal plan and model trading rules. The EPA is inviting comment on this approach to 

the modeling, and EPA will seek to improve analysis supporting the final rule regarding 

demand-side energy efficiency and the associated benefits and costs.” 

Commented [A3]: EPA response: we added language along the 

lines of the reviewer’ suggestions.

Commented [A4]: EPA response: we adopted the majority of 

these suggestions. 

234
Technical Comments

1) Page 1-1. Reviewer recommends the following change: “This proposal presents two 

approaches to a federal plan (or model rule) for states and other jurisdictions that either 

choose to adopt the model rule or do not adopt and submit to the EPA in a timely 

manner an approvable state plan: a rate-based emission trading program and a massbased emission trading program.” A version of this language is included on page 2-2.

2) Page 1-2. Reviewer recommends the following change to ensure consistency with the 

Federal Implementation Plan: “Upon approval of the state plan by EPA, the federal plan 

will no longer apply to the affected EGUs covered by the approved state plan, starting at 

the initiation of the next compliance period with the limitations noted in the federal 

plan.”

3) Page 1-5: Reviewer recommends clarifying whether using the EPA-administered tracking 

system enables trading among all participants or if trading would only occur between 

states with state plans or between states with the federal plan. If trading is allowed 

between all states using similar plan approaches, text should be edited to reflect this 

(Page 1-5) Suggested text: 

“The EPA proposes that affected EGUs in any state covered by a federal plan could trade 

compliance instruments with affected EGUs, or procure zero-emissions megawatt hours 

(MWhs) from eligible resources, in any other state covered by a federal plan or state 

plan that uses the same approach. In the proposed mass-based federal-plan trading 

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

could use, as a compliance instrument, an allowance distributed in any other state 

covered by a federal plan or state plan with the same approach. Similarly, in the 

proposed rate-based federal-plan trading program approach, this would mean that 

affected EGUs in a state covered by a federal plan could use, as a compliance 

instrument, an emission rate credit (ERC) issued in any other state covered by a federal 

plan or state plan with the same approach.” 

4) Page 1-6: Reviewer recommends editing the second full paragraph for clarity. When 

reading for the first time, the reviewer thought that four scenarios had been modeled.

“Because of this lack of information, for this RIA, the EPA has chosen to examine a 

scenario where all states of the contiguous U.S. will be regulated under a federal plan. 

Furthermore, because of the lack of information as to which states will adopt the model 

rule, the EPA has chosen to examine a scenario where all states of the contiguous U.S. 

adopt the model trading rule. Additionally Furthermore, we examine two alternative 

federal plan approach scenarios, which will be described in more detail below, for 

implementation of federal plans. The first federal plan approach we examine in this RIA 

assumes all states in the contiguous U.S. are regulated under a rate-based federal plan. 

The second federal plan approach we examine assumes all contiguous states are 

regulated under a mass-based federal plan. The two approaches that are examined in 

Commented [A5]: EPA response: adopted edit

Commented [A6]: EPA response: adopted edit

Commented [A7]: EPA Response: The EPA has made edits to 

the preamble. Instead of the suggested terms of “or state plans” 

and “state plan with the same approach” the EPA has incorporated 

the term “...or state meeting the conditions for linkage to the 

federal plan.”

Commented [A8]: EPA response: we revised the paragraph 

along the lines of the reviewers suggestions to prevent 

misunderstanding.

235
this RIA are a re-presentation of the modeling done for the Clean Power Plan Emission 

Guidelines RIA.” 

5) Page 1-9. Reviewer requests that EPA provide a description of the mass-based 

assumptions parallel to those provided for the rate-based assumptions.

6) Page 1-32. Reviewer recommends the following change: “Then, based on the allowance 

prices for the state in which each model plant resides, the EPA adjusted...” Given that 

this RIA claims to be modeling trading across states, there would be a single allowance 

price, not different allowance prices for each state. 

7) Page 1-33. Reviewer recommends the following change: “The OBA set-aside may also 

place upward pressure on the price of natural gas which would reduce the effectiveness 

of the set-aside at encouraging increased utilization of existing NGCC EGUs, but the OBA 

set-aside would be effective in increasing existing NGCC generation.” 

8) Reviewer notes that costs are also over-estimates for small business owners that 

operate affected EGUs in some competitive environments, particularly those where a 

steam EGU is on the margin and the affected EGUs of small businesses are NGCC EGUs 

inside the margin. Cost are really only increased for small business owners in the case 

of steam EGUs that are inframarginal when NGCC EGUs are on the margin. Reviewer 

recommends adding, for example, the following: "Similarly, entities owning NGCC EGUs 

operating in competitive markets are likely to be able to recover compliance costs if 

steam EGUs are setting the marginal price."

9) Page 2-23: "However, EPA believes the design of the federal plan as a flexible trading 

program alleviates these concerns and therefore a reliability mechanism is not needed."

Comment: Reviewer recommends further explaining why emergency events that would 

otherwise trigger the reliability safety valve would not do so under a federal plan (noting 

that this depends on how the final CPP is clarified on this issue). Further, reviewer 

recommends considering (and explaining) why, given the limited circumstances under 

which a reliability safety valve would be exercised, the opportunity to do so is foreclosed 

with compliance under a federal plan, especially given that the federal plan structure 

(trading) cannot guarantee that a reliability safety valve-qualifying emergency event 

would not occur. 

Typographical Comments

1) Reviewer recommends using the word “modeled” throughout text of this document and 

other related documents, not “modelled.”

Commented [A9]: EPA response: we added a parallel paragraph 

for the mass scenario

Commented [A10]: EPA response: It is correct as it was written. 

As a previous comment in this document noted, we are not 

modeling trading of allowances across states. Therefore, the 

shadow values on the state emissions constraints are different.

Commented [A11]: EPA response: we adopted the suggestion

Commented [A12]: EPA response: We added the following to 

to p2-17: “Similarly, entities owning NGCC EGUs operating in 

competitive markets may be able to recover compliance costs if 

steam EGUs are setting the marginal price.”

Commented [A13]: EPA response: Emergency events can 

happen regardless of the plan. An inflexible plan that places 

requirements on individual EGUs may make it difficult to respond to 

some types of emergencies. The federal plan is not that type of 

plan and for that reason the kind of remedy that the reliability 

safety valve offers is not useful or appropriate in the case of the 

federal plan. Rather in the federal plan, EGUs can make of use of 

ERCs or allowances to make up any additional emissions reductions 

needed. Further we have proposed and asked for comment on two 

more appropriate ways to address an emergency if, unexpectedly, 

those ERCs or allowances are not available. Those include either 

use of a set aside of ERCs or allowances for emergencies or a 

limited period during which an affected EGU or EGUs could be 

relieved of the requirement to hold ERCs or allowances.

Commented [A14]: EPA response: changed to “modeled”

236
2) Page 1-1. Reviewer recommends the following change: “The federal plan is an important 

measure to ensure that congressionally mandated emission standards under the 

authority of the congressionally mandated CAA are implemented.” This change could 

also be made on page 2-2.

3) Page 1-5: “Similarly, an affected EGU in a state covered by the rate-based trading 

federal plan must use ERCSs for compliance (not allowances).”

4) Page 1-8, Footnote 7: “Detailed documentation for IPM v.5.1 IPM v.5.15 is available at:

available at: http://www.epa.gov/powersectormodeling.”

5) Page 1-20. Reviewer recommends checking the math on the SC-CO2 presented. The 

2020 costs on the EPA’s webpage 

(http://www.epa.gov/climatechange/EPAactivities/economics/scc.html ) are reported in 

2014$ in metric tons: 13, 47, 69, and 140. Using 0.907 metric ton per short ton and 

0.954 2011$/2014$, reviewer calculates the four prices: 11, 41, 60, and 121. Reviewer

also recommends referencing NIPA Table 1.1.9 Implicit Price Deflators and Gross 

Domestic Product instead of the outdated table currently referenced in footnote 20. 

6) Page 1-33: “We do not quantify the effect of these changes in generation on SO2 and 

NOx emissions, although on net additional co-benefits would be expected.”

7) Page 2-2. Reviewer notes that the CPP EG will be out by the time this is published: “The 

final Clean Power Plan Emission Guidelines, released this summer, are related to but 

separate from the proposed federal plan.”

8) Page 2-19. Reviewer believes this change should be made five times throughout the 

paragraph: “Advocacy The EPA shares many of the concerns raised...” In the previous 

paragraph, reviewer recommends changing “The Agency” to “The EPA”

9) Page 2-19. Reviewer recommends clarifying what the acronym “SERs” stands for when 

first used at the top of this page. 

Comments on RIA Chapter 2, received 7/29/15 

• In the Federal Plan for Regulating Greenhouse Gas Emissions From Electric Generating 

Units, EPA adopts the SBREFA panel report recommendations in lieu of preparing its 

own consideration of alternatives. Reviewer notes that EPA should have prepared its 

own alternatives sections, building on the panel recommendations, incorporating the 

information EPA did not share with the panel during its deliberations, including the 

analysis of net compliance costs. Reviewer is concerned that, given the additional 

Commented [A15]: EPA response: EPA thinks sentence correct 

as-is.

Commented [A16]: EPA response: thanks

Commented [A17]: EPA response: sorry but not sure what the 

suggested change is

Commented [A18]: EPA response: Thank you, EPA’s math is 

correct. Reviewer gets slightly different numbers because s/he is 

starting with the rounded numbers (2 sig digits) from the website. 

EPA starts with 2007$/metric ton from the TSD (all to nearest 

dollar, which is 2-3 sig digits, depending on the estimate), adjusts 

2011$/2007$ (1.061374), adjusts to short using 0.90718474, which 

gives 11.55435, 40.44023, 59.69748, and 118.4321. Round those to 

2 significant digits gives 12, 40, 60, 120. Added further clarification 

to the footnote and updated the link for the GDP deflator.

Commented [A19]: EPA response: thanks.

Commented [A20]: EPA response: thanks. We deleted the 

reference to the timing of the EGs as they are discussed earlier

Commented [A21]: EPA Response: The text is correct as 

written.

Commented [A22]: EPA response: the acronym will be defined

Commented [A23]: EPA response: the federal plan and model 

trading rule proposal includes two complete regulatory alternatives 

(both a rate based and mass-based alternative) as well as a number 

of variations on those alternatives. We also are taking comments on 

numerous issues in the proposal.

237
analysis performed by EPA, how it could demonstrate which of the recommendations 

would “accomplish the stated objectives of applicable statutes and which minimize any 

significant economic impact of the proposed rule on small entities.“ 

• EPA projects that 1⁄2 of the small entities remaining in the market in 2030 will experience 

costs of over 3% of generation revenue. This would indicate significant 

hardship. Reviewer recommends including an explanation regarding what regulatory 

alternatives considered by EPA are included in this analysis, which were rejected, and 

how the alternatives affected these results.

• EPA projects that 1/3 of all small utilities will be closed without this rule by 

2030. Reviewer recommends providing additional information to substantiate this 

result. 

• Reviewer recommends including a discussion of how the costs of credits are 

incorporated into the analysis and describing how the costs/revenues from credit 

trading are included in the cost impacts.

• Reviewer recommends that EPA provide a discussion of wow sensitive the analysis of 

the results are to the number of states that participate in a Federal plan. Reviewer 

notes that a sizeable portion of States implement their own plans without trading to 

FIPs and recommends that EPA include a discussion in the analysis of the impacts on 

these costs.

• EPA has discussed the role of regulated markets in cost-recovery in past 

rulemakings. Reviewer recommends that EPA include a discussion of how this concept 

has been discussed in prior rulemakings. 

Additional comments on the CPP Federal Plan, included responses to the RLSO comment 

bubbles received 7/30/15

Page 69 RLSO. Reviewer supports language clarifying restriction on trading to only between 

other states with subcategory rates, and suggests referencing that this is consistent with the 

final EGs rules on rate-based trading, as described on pages 1526-27 (of 7/25 redlined version 

of the preamble).

Page 92 RLSO. Reviewer requests clarifying why a “similar mechanism [to an allowance setaside] in a rate-based approach to address reliability issues in the federal plan” is not needed. 

 

Page 168 RLSO. Reviewer recommends the following language (as highlighted) to allow for the 

possibility that EPA may in the future find that some biogenic feedstock is carbon neutral: 

“The revised Framework, and the EPA’s Science Advisory Board (SAB) peer review of the 2011 

Draft Framework, finds that it is not scientifically valid to assume that all biogenic feedstocks 

are “carbon neutral” and that the net biogenic CO2 atmospheric contribution of different 

Commented [A24]: EPA response: EPA provided an analysis of 

both rate- and mass-based alternatives. We also added language in 

the RIA highlighting that one of the primary drivers of the cost 

impacts is the reduced revenue due to decreased electricity sales 

related to implementation of demand-side measures. EPA takes 

comment on: 1) whether it is likely that small entities would 

consider demand-side strategies as they responded to a federal 

plan, 2) the appropriateness of considering the demand-side 

strategies in the analysis, and 3) if demand-side energy efficiency 

measures are considered in the final analysis, whether it is 

appropriate to consider them as a cost for a municipality or cityowned utility, as this reduced revenue will translate to direct cost 

savings for members of the community served by the affected 

units.

Commented [A25]: EPA response: we provided clearer pointer 

to IPM documentation so readers can obtain more information

Commented [A26]: EPA response: we added language in the 

limitation/important concerns section of Chapter 2: EPA has not 

factored in consideration of allowances that would be distributed to 

affected entities nor revenue that could be generated from the sale 

of ERCs in its analysis. EPA takes comment on how these factors 

should be considered in the final analysis.

Commented [A27]: EPA Response: These results assume the 

participation of all states in a Federal Plan, which is estimated by 

this RIA. To the extent that any number of states develop state 

implementation plans, and thus do not adopt the Federal Plan, 

these results might differ. Without knowing the particular 

implementation plan for each state, the EPA believes the estimates 

provided in this RIA are a reasonable approximation.

Commented [A28]: EPA response: The discussion of this here is

similar to other recent RIAs. We added a footnote to the end of 

section 2.3.4 pointing to MATS.

Commented [A29]: EPA Response: Response: Language has 

been clarified.

Commented [A30]: EPA Response: Emergency events can 

happen regardless of the plan. An inflexible plan that places 

requirements on individual EGUs may make it difficult to respond to 

some types of emergencies. The federal plan is not that type of 

plan and for that reason the kind of remedy that the reliability 

safety valve offers is not useful or appropriate in the case of the 

federal plan. Rather in the federal plan, EGUs can make of use of 

ERCs or allowances to make up any additional emissions reductions 

needed. Further we have proposed and asked for comment on two 

more appropriate ways to address an emergency if, unexpectedly, 

those ERCs or allowances are not available. Those include either 

use of a set aside of ERCs or allowances for emergencies or a 

limited period during which an affected EGU or EGUs could be 

relieved of the requirement to hold ERCs or allowances. 

Commented [A31]: EPA Response: Response: This language is 

being revised.

238
biogenic feedstocks generally depends on various factors related to feedstock characteristics, 

production, processing and combustion practices, and, in some cases, what would happen to 

that feedstock and the related biogenic emissions if not used for energy production. A given 

feedstock may be found to be carbon neutral after appropriate EPA assessment.” 

Allocations to units that retire. They interagency reviewers asked a question but didn’t request 

an edit, this is on p. 315. The question is “We would like to understand better the value of an 

allocation structure that creates different retirement incentives based on the year of 

retirement.” 

Monitoring for environmental integrity. The interagency reviewers asked a question but didn’t 

request an edit, this is on p. 343. The question is “A section was deleted here on measures that 

could monitor the environmental integrity of a federal plan. Can EPA say why this was 

removed?” 

“The Incremental Generation Factor is calculated by taking the number of MWh beyond the 

2012 baseline needed for the corresponding region to reach 75 percent NGCC generation 

capacity and dividing it by the the MWh that is 75 percent NGCC generation capacity, giving a 

factor. This factor can be summarized by the following expression:” Shouldn’t this be the 

average CF reached by NGCC over the compliance period in the region where the steam rate 

comes from (since there is a ramp in NGCC CF)?

“The EPA also requests comment on whether a distinct type of ERC that comes with the 

proposed restrictions (i.e., GS-ERCs) is necessary to maintain the integrity of the rate-based 

trading proposal. “

Commented [A32]: EPA Response: The proposed approach 

reflects the multi-year compliance periods and that we believe it’s 

important not to “take back” allocations once they are recorded as 

that would increase complexity and uncertainty. The proposed 

approach results in some difference in the length of time during 

which a retired unit would still get allocations but in any case it’s 

only a few years. The preamble requests comment on other 

approaches.

Commented [A33]: EPA Response: It was removed because 

similar language was added to the final EGs, specifying an analysis 

that EPA will do for all states. Language on an emission 

performance analysis was included in the final EGs in response to 

an OMB comment. The language is in section VIII.J.2.b in the EGs. 

Commented [A34]: EPA Response: This is inconsistent with the 

calculation methodology proposed; note EPA is soliciting comments 

on the topic. 

Commented [A35]: EPA Response: clarification requested

239
Attachment O.2

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment O.2.

240
Attachment P.

241
From: Szabo, Aaron <Aaron_L_Szabo@omb.eop.gov>

Sent: Friday, July 31, 2015 8:48 AM

To: Jones, Toni; Culligan, Kevin; Harvey, Reid

Cc: Frey, Nathan J.; Grossman, Andrea

Subject: Summary Of Interagency Comments under EO12866 and 13563 ‐‐ Federal Plan

  

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

entitled, Federal Plan Requirements for Greenhouse Gas Emissions from Electric Utility Generating Units

Constructed on or Before January 8, 2014; Model Trading Rules; Amendments to Framework

Regulations.

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

  

Aaron L. Szabo

Policy Analyst

Office of Management and Budget

202‐395‐3621

Aaron_L_Szabo@omb.eop.gov

242
Attachment P.1

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment P.1.

243
Attachment Q.

244
From: Culligan, Kevin <Culligan.Kevin@epa.gov>

Sent: Friday, July 31, 2015 5:42 PM

To: Frey, Nathan J.; Szabo, Aaron

Cc: Jones, Toni; Boswell, Colin

Subject: Federal plan

  

Hi Nathan,

Attached please find the CPP federal plan preamble and rule text.  These versions should be considered

final and reflect edits made based on the comments received from OMB.  Note, redline strike out

versions of both the rule and preamble are also attached, indicated by “RLSO” in the file name.   

Additionally, please see below for responses to the comments received today:

Comment: Please clarify whether this would require emission neutrality

EPA Response:  The highlighted paragraph has been revised and is reflected below. Also to note the

commenter’s point regarding “net neutrality,” this should be addressed in the paragraph below by the

assurances that the overall state goal is met.

The EPA is also taking comment on an alternative compliance pathway that could be available to units

under a mass based approach. The ways that the approach could be implemented are further outlined in

the Alternative Compliance Pathway for Units that Agree to Retire Before a Certain Date TSD. Under this

approach, two basic requirements would need to be met. The first is that the unit would have to take a

commitment that it would retire on a date on or before December 31, 2029. The second is that the unit

would have to demonstrate that it will take an enforceable emission limitation that would assure that

the overall state emission goal is met. The TSD explores ways that this approach could be implemented,

including ways that the enforceable emission limitation could be calculated and implemented. The EPA

requests comment on whether this approach should be available for all units or limited  to small units

(e.g. less than 100 MW nameplate capacity). EPA is also taking comment on whether and how such an

approach could be included under a rate‐based approach.

Comment:  Tracked changes edit regarding “reduce net CO2 emissions”

EPA Response:  We do not agree with this recommended edit. While the EPA believes it is reasonable to

consider generation from these fuels and technologies to be forms of RE generation, the fact that they

can produce stack emissions containing CO2 means that a section 111(d) plan seeking to permit use of

such generation to serve as the basis for issuance of ERCs must include appropriate consideration of

feedstock characteristics and climate benefits. Specifically, the use of some kinds of biomass has the

potential to offer a wide range of environmental benefits, including carbon benefits. However these

benefits can only be realized if biomass feedstocks are sourced responsibly and attributes of the carbon

cycle related to the biomass feedstock are taken into account.

245
Attachment Q.1

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment Q.1.

246
Attachment Q.2

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment Q.2.

247
Attachment Q.3

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment Q.3.

248
Attachment Q.4

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment Q.4.

249
Attachment R.

250
From: Culligan, Kevin <Culligan.Kevin@epa.gov>

Sent: Friday, July 31, 2015 8:08 PM

To: Frey, Nathan J.; Szabo, Aaron

Cc: Jones, Toni

Subject: Federal PLan RIA material

  

251
Attachment R.1

252
EO12866_CPP Federal Plan 2060 AS47 RIA Final_20150731 

Regulatory Impact Analysis 

for the 

 Proposed Federal Plan Requirements for 

Greenhouse Gas Emissions from Electric 

Utility Generating Units Constructed on or 

Before January 8, 2014; Model Trading 

Rules; Amendments to Framework 

Regulations 

 

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EPA-452/R-15-006 

July 2015 

Regulatory Impact Analysis for the for the 

 Proposed Federal Plan Requirements for Greenhouse Gas 

Emissions from Electric Utility Generating Units Constructed on or 

Before January 8, 2014; Model Trading Rule 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

Office of Air Quality Planning and Standards 

Research Triangle Park, NC 27711 

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CONTACT INFORMATION 

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

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

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

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

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

macpherson.alex@epa.gov). 

ACKNOWLEDGEMENTS 

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

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

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

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Table of Contents 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

2.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

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

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

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

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

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

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

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

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

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LIST OF TABLES

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

Plan Approach1 ...........................................................................................................1-11

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

Plan Appproach1 .........................................................................................................1-13

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

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

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

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

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

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

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

 ......................................................1-28

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

 ......................................................1-29

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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CHAPTER 1: SUMMARY OF POTENTIAL REGULATORY IMPACTS

1.1 Introduction 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 

1

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

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

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

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

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

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1-2 

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

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

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

1.2 Legal, Scientific and Economic Basis for this Rulemaking 

1.2.1 Statutory Requirement 

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

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

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

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

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

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

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

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

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

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

submittal, upon submitting a satisfactory initial submittal by the same deadline. If a state fails to 

submit a final state plan or initial submittal, or if either a final state plan or an initial submittal 

does not meet the requirements of the final emission guidelines, the Agency will take the 

appropriate steps to finalize and implement a federal plan. 

States will remain free, and indeed are strongly encouraged, to submit an approvable state 

plan even after promulgation of the federal plan for their jurisdictions. Upon approval of the state 

plan by EPA, the federal plan will no longer apply to the affected EGUs covered by the approved 

state plan, starting at the initiation of the next compliance period with the limitations noted in the 

federal plan. 

1.2.2 Health and Welfare Impacts from Climate Change 

According to the National Research Council, “Emissions of CO2 from the burning of 

fossil fuels have ushered in a new epoch where human activities will largely determine the 

evolution of Earth’s climate. Because CO2 in the atmosphere is long lived, it can effectively lock 

Earth and future generations into a range of impacts, some of which could become very severe. 

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Therefore, emission reduction choices made today matter in determining impacts experienced 

not just over the next few decades, but in the coming centuries and millennia.”2 

In 2009, based on a large body of robust and compelling scientific evidence, the EPA 

Administrator issued the Endangerment Finding under CAA section 202(a)(1).3 In the 

Endangerment Finding, the Administrator found that the current, elevated concentrations of 

GHGs in the atmosphere—already at levels unprecedented in human history—may reasonably 

be anticipated to endanger public health and welfare of current and future generations in the 

United States. 

Since the administrative record concerning the Endangerment Finding closed following 

the EPA’s 2010 Reconsideration Denial, the climate has continued to change, with new records 

being set for a number of climate indicators such as global average surface temperatures, Arctic 

sea ice retreat, CO2 concentrations, and sea level rise. Additionally, a number of major scientific 

assessments have been released that improve understanding of the climate system and strengthen 

the case that GHGs endanger public health and welfare both for current and future generations. 

These assessments are from the Intergovernmental Panel on Climate Change (IPCC), the U.S. 

Global Change Research Program (USGCRP), and the National Research Council (NRC). These 

and other assessments are discussed in more detail in the Final Clean Power Plan Emission 

Guidelines preamble and in Chapter 4 of the Clean Power Plan Final Rule Regulatory Impact 

Analysis (RIA).4

1.2.3 Market Failure 

Many regulations are promulgated to correct market failures, which otherwise lead to a 

suboptimal allocation of resources within the free market. Air quality and pollution control 

regulations address “negative externalities” whereby the market does not internalize the full 

opportunity cost of production borne by society as public goods such as air quality are unpriced. 

 

2 National Research Council, Climate Stabilization Targets, p.3. 

3

 “Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air 

Act,” 74 Fed. Reg. 66,496 (Dec. 15, 2009) (“Endangerment Finding”). 

4

 U.S. Environmental Protection Agency (U.S. EPA). 2015a. Regulatory Impact Analysis for the Clean Power Plan 

Final Rule. EPA-452/R-15-003. Office of Air Quality Planning and Standards, Health and Environmental Impacts 

Division, Research Triangle Park, NC. 

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GHG emissions impose costs on society, such as negative health and welfare impacts, 

that are not reflected in the market price of the goods produced through the polluting process. 

For this regulatory action the good produced is electricity. If a fossil fuel-fired electricity 

producer pollutes the atmosphere when it generates electricity, this cost will be borne not by the 

polluting firm but by society as a whole, thus imposing a negative externality. The equilibrium 

market price of electricity may fail to incorporate the full opportunity cost to society of 

generating electricity. All else equal, given this externality, the composition of EGUs used to 

generate electricity in a free market will not be socially optimal, and the quantity of electricity 

generated may not be at the socially optimal level. Fossil fuel-fired EGUs may produce more 

electricity than would occur if they had to account for the cost associated with this negative 

externality. Consequently, absent a regulation on emissions, the composition of the fleet of 

EGUs used to generate electricity may not be socially optimal, and the marginal social cost of 

the last unit of electricity produced may exceed its marginal social benefit. In the instances where 

the agency finalizes and implements a federal plan for a state’s affected EGUs, this proposed 

regulation will work towards addressing this market failure by causing affected EGUs to begin to 

internalize the negative externality associated with CO2 emissions. 

1.3 Background for the Proposed Federal plan and model trading rules 

1.3.1 Definition of Affected Sources 

Existing fossil fuel-fired electric generating units subject to the final Clean Power Plan 

Emission Guidelines that are located in a state that does not have an EPA-approved state plan are 

potentially subject to this proposed action. Existing fossil fuel-fired EGUs are those that were in 

operation or had commenced construction on or before January 8, 2014.5

1.3.2 Trade in Compliance Instruments across States 

The EPA intends to set up and administer a program to track trading programs – both 

rate-based and mass-based – that will be available for all states that choose it. The EPA proposes 

that affected EGUs in any state covered by a federal plan could trade compliance instruments 

 

5

 An affected EGU is any fossil fuel-fired EGU that was in operation or had commenced construction as of January 

8, 2014, and is therefore an ‘‘existing source’’ for purposes of CAA section 111, and that in all other respects 

would meet the applicability criteria for coverage under the proposed GHG standards for new fossil fuel-fired 

EGUs (79 FR 1430; January 8, 2014). 

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with affected EGUs in any other state covered by a federal plan or a state plan meeting the 

conditions for linkage to the federal plan. In the proposed mass-based federal-plan trading 

program, this would mean that affected EGUs in a state covered by the federal plan or a state 

meeting the conditions for linkage to the federal plan could use, as a compliance instrument, an 

allowance distributed in any other state covered by the federal plan or a state meeting the 

conditions for linkage to the federal plan. Similarly, in the proposed rate-based federal-plan 

trading program approach, this would mean that affected EGUs in a state covered by the federal 

plan or a state meeting the conditions for linkage to the federal plan could use, as a compliance 

instrument, an ERC issued in any other state covered by the federal plan or a state meeting the 

conditions for linkage to the federal plan. EPA is proposing that an affected EGU in a state 

covered by the mass-based trading federal plan must use allowances for compliance (not ERCs). 

Similarly, an affected EGU in a state covered by the rate-based trading federal plan must use 

ERCS for compliance (not allowances). 

1.3.3 Model Trading Rule 

A state program that adheres to the model trading rule provisions specified in this 

rulemaking would be presumptively approvable. States may submit means of meeting the 

emission guidelines requirements that differ from the model trading rule provisions, so long as 

the state demonstrates to the EPA’s satisfaction in the state plan submittal that such alternative 

means of addressing requirements are at least as stringent as the presumptively approvable 

approach described here. Additionally, there are stand-alone portions of the model trading rules, 

such as the evaluation, measurement, and verification (EM&V) procedures that would be 

approvable even if a state adopted an approach that differs from the federal plan. The model 

trading rules serve as a mechanism to facilitate larger trading markets since consistency with the 

federal plan allows trading across both the state and federal programs. The EPA expects a larger 

trading region is likely to result in lower overall costs. 

1.4 Summary of Regulatory Analysis 

In accordance with Executive Order 12866, Executive Order 13563, OMB Circular A-4, 

and the EPA’s “Guidelines for Preparing Economic Analyses,” the EPA prepared this RIA for 

this “significant regulatory action.” This action is an economically significant regulatory action 

because it may have an annual effect on the economy of $100 million or more or adversely affect 

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in a material way the economy, a sector of the economy, productivity, competition, jobs, the 

environment, public health or safety, or state, local, or tribal governments or communities.6 

This action proposes a federal plan under section 111(d) of the CAA for the control of 

CO2, a greenhouse gas pollutant, from certain large emitting fossil-fuel fired power plants, in the 

event that some states do not adopt their own plans. Specifically, the EPA is proposing 

approaches in the form of mass- and rate-based trading options that provide flexibility in 

implementing emission standards for a state’s affected EGUs. Both proposed approaches to the 

federal plan would require affected EGUs to meet emission standards set using the CO2 emission 

performance rates in the emission guidelines. The federal plan will achieve the same levels of 

emissions performance as required of state plans under the emission guidelines. 

However, at the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan or adopt a model rule. Because of this lack of information, 

for this RIA, the EPA has chosen to examine two federal plan approach scenarios where all 

states of the contiguous U.S. will be regulated under a federal plan or a model rule. The first 

federal plan approach we examine in this RIA assumes all states in the contiguous U.S. are 

regulated under a rate-based federal plan or model rule. The second federal plan approach we 

examine assumes all contiguous states are regulated under a mass-based federal plan or model 

rule. These two approaches are a re-presentation of the modeling done for the Clean Power Plan 

Emission Guidelines RIA. 

This approach is consistent with the analysis presented in the RIA for the final Clean 

Power Plan Emission Guidelines (U.S. EPA 2015). As a result, this RIA for the proposed federal 

plan and model trading rules re-presents the key results from the final Clean Power Plan 

Emission Guidelines RIA. These key results encompass the potential costs, emission reductions, 

and benefits of the proposed federal plan and model trading rules, as well as the potential 

impacts on electricity markets, employment, and markets outside the electricity sector. 

The RIA also presents a discussion of limitations of the analysis and solicitations for 

public comments that will contribute to the analysis supporting the promulgation of final federal 

 

6

 The analysis in this proposal RIA constitutes the economic assessment required by CAA section 317. In the EPA’s 

judgment, the assessment is as extensive as practicable taking into account the EPA’s time, resources, and other 

duties and authorities. 

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plans (as needed) and model trading rules. In evaluating the impacts of the proposed federal plan 

and model trading rules, we address a number of uncertainties. 

It is important to note that the potential regulatory impacts presented in the Clean Power 

Plan Final Rule RIA and the RIA for this proposed rule are not additive. Both RIAs present 

estimates of the benefits and costs of achieving the emission performance rates of the Clean 

Power Plan emissions guidelines. In the case of the Clean Power Plan Final Rule RIA, the 

illustrative analysis assumes the performance rates are met under state plans. In the case of this 

RIA for the proposed federal plan and model trading rules, the same performance rates are 

accomplished but are assumed to be accomplished under the federal plan or model trading rules. 

This RIA also presents in Chapter 2 the statutory and executive order analyses that 

accompany the proposal for this action, including the Initial Flexibility Regulatory Analysis 

(IRFA). The IRFA describes the economic impact of the proposed rule on small entities and any 

significant alternatives to the proposed rule that would accomplish the objectives of the rule 

while minimizing significant economic impacts on small entities. This IRFA has been prepared 

following EPA’s guidance document for preparing initial and final regulatory flexibility 

analyses.7

1.4.1 Base Case and Years of Analysis 

The base case for this analysis, which uses the Integrated Planning Model (IPM), 

includes state rules that have been finalized and/or approved by a state’s legislature or 

environmental agencies, as well as final federal rules. The IPM Base Case v.5.15 includes the 

Cross-State Air Pollution Rule (CSAPR), the Mercury and Air Toxics Rule (MATS), the 

proposed Carbon Pollution Standards for New Power Plants, the Cooling Water Intakes (316(b)) 

Rule, the Combustion Residuals from Electric Utilities (CCR), and other state and Federal 

regulations to the extent that they contain measures, permits, or other air-related limitations or 

 

7 See “EPA’s Action Development Process: Final Guidance for EPA Rulewriters: Regulatory Flexibility Act as 

amended by the Small Business Regulatory Enforcement Fairness Act.” OPEI Regulatory Development Series. 

November 2006. Available at: <http://www.epa.gov/sbrefa/documents/Guidance-RegFlexAct.pdf>. Accessed July 

21, 2015. 

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requirements. Additional legally binding and enforceable commitments for GHG reductions 

considered in the base case are discussed in the documentation for IPM.8 

To present a complete picture of the potential costs and benefits of the proposed federal 

plan and model trading rules, this RIA presents results for the analysis years 2020, 2025, and 

2030. While 2020 is before the first year of the interim compliance period (2022), the EPA 

expects states and affected EGUs to perform voluntary activities that will facilitate compliance 

with interim and final goals. These pre-compliance period activities might include investments in 

renewable energy or demand-side energy efficiency projects, for example, that produce 

emissions reductions in the compliance period. Activities might also include preparatory 

investments in transmission capacity or monitoring, reporting, and recordkeeping systems. As a 

result, there are likely to be benefits and costs in 2020, so these are reported in this RIA. 

Meanwhile, cost and benefits are estimated in this RIA for 2025, which is intended to represent a 

central period of the interim compliance time-frame as states are on glide paths toward fully 

meeting the final CO2 emission performance goals. Lastly, the RIA presents costs and benefits 

for 2030, when the emission performance goals are fully achieved. 

1.4.2 Federal Plan Approaches Examined in RIA 

In the Final Clean Power Plan Emission Guidelines, the EPA translated the source 

category-specific CO2 emission performance rates into equivalent state-level rate-based and 

mass-based CO2 goals in order to maximize the range of choices that states will have in 

developing their plans.9 As noted above, like the RIA for the Final Clean Power Plan Emission 

Guidelines, this RIA presents two scenarios designed to achieve these goals, which we term the 

rate-based federal plan approach and the mass-based federal plan approach. 

It is very important to note that the differences between the analytical results for the ratebased and mass-based federal plan approaches presented in this RIA may not be indicative of 

likely differences between the approaches. In other words, if one approach performs differently 

 

8

 Detailed documentation for IPM v.5.15 is available at: http://www.epa.gov/powersectormodeling. 

9

 See the preamble of the final Clean Power Plan Emissions Guidelines for these state-level rate-based and massbased CO2 goals. 

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than the other on a given metric during a given time period, this does not imply this will apply in 

all instances in all time periods in all places. 

In the rate-based approach modeled in the RIA for the final Clean Power Plan Emission 

Guidelines, avoided generation from demand-side energy efficiency is counted towards meeting 

the emission performance rates at affected EGUs. However, this federal plan and model trading 

rule proposal takes comment on whether EPA should allow demand-side energy efficiency to 

directly count toward the compliance rate of affected EGUs in a rate-based compliance approach. 

Because energy efficiency is not proposed to be eligible to generate ERCs that could be used to 

comply in the proposed rate-based federal plan, this RIA might be forecasting a different a 

generation mix and emissions levels than might occur from the proposed federal plan.10

Compliance strategies under either approach to the federal plan (mass or rate) may be anticipated 

to rely on different abatement measures than those modeled for this RIA. The climate benefits 

and health co-benefits arising from these alternative strategies may be different those presented 

here. We will update this analysis as necessary to support the final rule. 

Even without explicit incentives for energy efficiency under a rate-based federal plan, we 

believe that the increased focus that the Clean Power Plan Emission Guidelines will bring to 

considerations of CO2 emissions from EGUs will encourage states to consider more aggressive 

demand-side energy policies. Furthermore, the EPA anticipates that many states will submit 

fully-approvable plans, and that demand side energy efficiency is likely to be either an explicit 

component of, or a complimentary policy to, many of those plans. The resulting lower electricity 

demand in states not subject to a federal plan surrounding a state that is subject to a federal plan 

will likely have an impact on fossil generation and thus the cost of reducing CO2 emissions. The 

EPA takes comment on the appropriate way to factor such costs into the analysis of the final 

federal plan and model trading rules. 

In the rate-based approach modeled in the RIA for the final Clean Power Plan Emission 

Guidelines, affected EGUs may not procure emission reductions from (e.g., by averaging their 

emissions with) affected EGUs located in other states (which may also have different emission 

 

10 However, as with states subject to the mass-based approach, energy efficiency activities may be adopted by states 

subject to the rate-based approach to lower demand, which in turn may reduce the compliance cost of achieving 

the performance rates. 

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standards) in order to demonstrate compliance. As described in Section 1.3.2, in the proposed 

rate-based federal plan affected EGUs may procure ERCs from affected EGUs in other ratebased states subject to the federal plan. Furthermore, the rate-based illustrative plan in the Final 

Clean Power Plan Emission Guidelines RIA assumes that the plan applies a state’s blended ratebased goal as a requirement for affected EGUs in that state to achieve.11 Alternatively, the 

proposed federal plan specifically establishes an emissions rate performance standard that is 

applied to affected steam-fired EGUs and an emission rate performance standard that is applied 

to affected natural gas-fired combined cycle EGUs. Applying the subcategory-specific rate goal 

may alter the incentives among affected EGUs and could lead to a different generation mix and 

emission levels. The EPA will further explore the impacts of subcategory-specific rate goals in 

the analysis supporting the final rule. 

The mass-based plan approach requires affected sources in each state to limit their 

aggregate emissions not to exceed the mass goal for that state. The mass-based scenario 

presented in this chapter includes a 5 percent set-aside of allowances that would be allocated to 

recognize deployment of new renewable capacity, which is represented by lowering the capital 

cost of new renewable capacity in a compliance period by the estimated value of the allowances 

in the set-aside in that period. 

The EPA is also proposing a set-aside approach referred to as output-based allocation 

(OBA), which provides targeted allocations of a limited portion of allowances to existing NGCC 

units as a means of mitigating leakage. The EPA believes that this proposed set-aside would 

address incentives for generation to shift away from EGUs covered under mass-based plans to 

new unaffected EGUs. OBA provides an incentive for eligible EGUs in mass-based states to 

increase their generation in order to increase their allocation of allowances. This approach helps 

align the generation incentives for eligible EGUs in mass-based states with new EGUs that are 

not subject to the mass-based limits, mitigating the potential for emissions leakage. 

 

11 In the rate-based scenario in the RIA for the final Clean Power Plan Emission Guidelines, the generation-weighted 

average emission rate from affected EGUs, in which generation is inclusive of their procurement of zero-emitting 

generation or demand-side EE savings, in a state must be less than or equal to the state goal. One way for a state 

to achieve this outcome would be to assign in its plan emission rate performance standards to affected EGUs that 

equal the state emission rate goal, the incentives of which would be consistent with the analysis and results 

reported in the RIA for the final Clean Power Plan Emission Guidelines. 

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While the mass-based scenario analyzed for this proposed rule included a representation 

of the set-aside for new renewable generation, it did not quantify the effects of the OBA as 

proposed in this rulemaking. Therefore, in Section 1.5.6, the EPA conducted additional analysis 

to approximate the potential emissions reductions if the OBA set-aside were included in that 

mass-based scenario. The EPA is inviting comment on its approach to approximating the impact 

of OBA. If appropriate, the EPA will further explore OBA as a means to mitigate leakage in the 

analysis supporting the final federal plan and model trading rules. 

The EPA notes that, in this analysis, EGUs within each state comply with the applicable 

state goals without exchanging a compliance instrument with EGUs in other states. However, 

under the proposed federal plan and model trading rules if all states had a federal plan and the 

same type of goal (as they do in this analysis), then trading among EGUs in different states 

would be allowed and would lead to differences in the generation mix and emissions. The EPA is 

inviting comment on this approach to the modeling that will contribute to analysis supporting the 

final rule. 

1.5 Summary of Regulatory Analysis 

1.5.1 Emissions Reductions 

Table 1-1 shows the emission reductions associated with the modeled rate-based federal 

plan approach. 

Table 1-1. Climate and Air Pollutant Emission Reductions for the Rate-Based Federal Plan 

Approach1

 

CO2

(million short tons) 

SO2

(thousand short tons) 

Annual NOX 

(thousand short tons) 

2020 Rate-Based Approach 

Base Case 2,155 1,311 1,333 

Federal Plan Approach 2,085 1,297 1,282 

Emissions Change -69 -14 -50 

2025 Rate-Based Approach 

Base Case 2,165 1,275 1,302 

Federal Plan Approach 1,933 1,097 1,138 

Emissions Change -232 -178 -165 

2030 Rate-Based Approach 

Base Case 2,227 1,314 1,293 

Federal Plan Approach 1,812 996 1,011 

Emission Change -415 -318 -282 

Source: Integrated Planning Model, 2015. Emissions change may not sum due to rounding. 

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1 CO2 emission reductions are used to estimate the climate benefits of the proposed rule. SO2, and NOX reductions 

are relevant for estimating air quality health co-benefits of the proposed rule. The proposed rule is also expected to 

achieve reductions in directly emitted PM2.5, which we were not able to estimate for this RIA. 

In 2020, the EPA estimates that CO2 emissions will be reduced by 69 million short tons 

under the rate-based approach compared to base case levels. In 2025, the EPA estimates that CO2

emissions will be reduced by 232 million short tons under the rate-based approach compared to 

base case levels. CO2 emission reductions increase to 415 million short tons annually in 2030 

when compared to the base case emissions. Table 1-1 also shows emission reductions for criteria 

air pollutants. 

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Table 1-2 shows the emission reductions associated with the modeled mass-based federal 

plan approach. 

Table 1-2. Climate and Air Pollutant Emission Reductions for the Mass-Based Federal Plan 

Appproach1

 

CO2

(million short tons) 

SO2

(thousand short tons) 

Annual NOX 

(thousand short tons) 

2020 Mass-Based Approach 

Base Case 2,155 1,311 1,333 

Federal Plan Approach 2,073 1,257 1,272 

Emissions Change -81 -54 -60 

2025 Mass-Based Approach 

Base Case 2,165 1,275 1,302 

Federal Plan Approach 1,901 1,090 1,100 

Emissions Change -265 -185 -203 

2030 Mass-Based Approach 

Base Case 2,227 1,314 1,293 

Federal Plan Approach 1,814 1,034 1,015 

Emission Change -413 -280 -278 

Source: Integrated Planning Model, 2015. Emissions change may not sum due to rounding. 

1 CO2 emission reductions are used to estimate the climate benefits of the proposed rule. SO2, and NOX reductions 

are relevant for estimating air quality health co-benefits of the proposed rule. The proposed rule is also expected to 

achieve reductions in directly emitted PM2.5, which we were not able to estimate for this RIA. 

In 2020, the EPA estimates that CO2 emissions will be reduced by 81 million short tons under 

the mass-based approach compared to base case levels. In 2025, the EPA estimates that CO2

emissions will be reduced by 265 million short tons under the mass-based approach compared to 

base case levels. CO2 emission reductions increase to 413 million short tons annually in 2030 

when compared to the base case emissions. Table 1-2 also shows emission reductions for criteria 

air pollutants. 

 

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Table 1-3 presents CO2 emission reductions relative to 2005 for the two federal plan 

approaches. 

Table 1-3. Projected CO2 Emission Reductions, Relative to 2005 

 

CO2 Emissions 

(million short tons) 

CO2 Emissions: 

Change from 2005 

(million short tons) 

CO2 Emissions Reductions: 

Percent Change from 2005 

 2005 2020 2025 2030 2020 2025 2030 

Base Case 2,683 -528 -518 -456 -20% -19% -17% 

Rate-based - -598 -750 -871 -22% -28% -32% 

Mass-based - -610 -782 -869 -23% -29% -32% 

Source: Integrated Planning Model, 2015. 

In 2020, the EPA estimates that CO2 emissions will be reduced by 598 million short tons (22 

percent) under the rate-based approach compared to 2005 levels. In 2025, the EPA estimates that 

CO2 emissions will be reduced by 750 million short tons (28 percent) under the rate-based 

approach compared to 2005 levels. Under the rate-based approach, CO2 emission reductions 

increase to 871 million short tons (32 percent) in 2030 when compared to 2005 levels. 

Under the mass-based approach in 2020, the EPA estimates that CO2 emissions will be 

reduced by 610 million short tons (23 percent) under the rate-based approach compared to 2005 

levels. In 2025, the EPA estimates that CO2 emissions will be reduced by 782 million short tons 

(29 percent) under the mass-based approach compared to 2005 levels. Under the mass-based 

approach, CO2 emission reductions increase to 869 million short tons (32 percent) in 2030 when 

compared to 2005 levels. 

1.5.2 Costs 

 The compliance cost estimates in this analysis are the change in electric power 

generation costs between the base case and federal plan approach policy cases, including the cost 

of demand-side energy efficiency measures and costs associated with monitoring, reporting, and 

recordkeeping requirements (MR&R).12 In the rate-based approach, energy efficiency activities 

are modeled as being used by EGUs as a low-cost method of demonstrating compliance with 

their rate-based emissions standards. In the mass-based approach, energy efficiency activities are 

assumed to be adopted by states to lower demand, which in turn reduces the cost of achieving the 

 

12 See Chapter 3 of the Clean Power Plan Final Rule RIA for a detailed discussion of the compliance cost estimates. 

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mass limitations. The level of energy efficiency measures is determined outside of IPM and is 

assumed to be the same in the two federal plan approaches.13 The compliance assumptions, and 

therefore the projected “compliance costs” set forth in this analysis, are illustrative in nature. 

The annual compliance cost is the projected additional cost of complying with the rule in 

the year analyzed and reflects the net difference in the sum of the annualized cost of capital 

investment in new generating sources and heat rate improvements at coal steam facilities, the 

change in the ongoing costs of operating pollution controls, shifts between or amongst various 

fuels, demand-side energy efficiency measures, and other actions associated with compliance. 

The costs for both federal plan approaches are reflected in Table 1-4 below. All dollar estimates 

are in 2011 dollars. 

The EPA estimates the annual incremental compliance cost for the rate-based approach 

for the proposed federal plan and model trading rules to be $2.5 billion in 2020, $1.0 billion in 

2025 and $8.4 billion in 2030. The EPA estimates the annual incremental compliance cost for the 

mass-based approach for the federal plan and model trading rules to be $1.4 billion in 2020, $3.0 

billion in 2025 and $5.1 billion in 2030. 

Table 1-4. Compliance Costs for the Federal Rate-Based and Mass-Based Plan Approaches 

Incremental Cost from Base Case (billions of 2011$)

Rate-based Approach Mass-based Approach 

2020 $2.5 $1.4 

2025 $1.0 $3.0 

2030 $8.4 $5.1 

Source: Integrated Planning Model, 2015, with post-processing to account for exogenous demand-side management 

energy efficiency costs and monitoring, reporting, and recordkeeping costs. See Chapter 3 of the Clean Power Plan 

Final Rule RIA for a more complete explanation. 

The costs reported in Table 1-4 represent the estimated incremental electric utility 

generating costs changes from the base case plus the estimates of demand-side energy efficiency 

program costs (which are paid by electric utilities), demand-side energy efficiency participant 

costs (which are paid by electricity consumers), and MR&R costs. For example, in 2030, under 

the rate-based approach, the incremental electric utility generating costs decline by about $18.0 

 

13 For more detailed information on demand-side energy efficiency, see U.S. EPA. 2015b. Technical Support 

Document (TSD) the Final Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility 

Generating Units. Demand-Side Energy Efficiency. 

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billion from the base case. MR&R requirements in 2030 are estimated at $16.0 million, and 

demand-side energy efficiency costs in 2030 are estimated to be $26.3 billion, split equally 

between program and participants using a 3 percent discount rate (see Chapter 3 of this RIA for 

more details on these estimates). These cost estimates sum to the $8.4 billion shown in Table 1-4 

and represent the total costs of the rate-based federal plan approach in 2030. The same approach 

applies in each year of analysis for the rate-based and the mass-based federal plan approaches. 

The compliance costs reported in Table 1-4 are not social costs. These costs represent the 

estimated expenditures incurred by EGUs, the costs to participants in demand-side energy 

efficiency programs, and states to comply with the BSER goals for the Final Clean Power Plan 

Emission Guidelines. These compliance cost estimates are compared to estimates of social 

benefits to derive net benefits of the proposed federal plan and model trading rules, which are 

presented later in this Chapter. 

1.5.3 Monetized Climate Benefits and Health Co-benefits 

The climate benefits estimates have been calculated using the estimated values of 

marginal climate impacts presented in the Technical Support Document: Technical Update of the 

Social Cost of Carbon for Regulatory Impact Analysis under Executive Order 12866 (May 2013, 

Revised July 2015), henceforth denoted as the current SC-CO2 TSD.14 Additionally, this analysis 

takes into account the social benefits of changes in emissions of non-CO2 pollutants from the 

electricity sector. The range of combined benefits reflects different concentration-response 

functions for the air quality health co-benefits, but it does not capture the full range of 

uncertainty inherent in the health co-benefits estimates. Furthermore, we were unable to quantify 

or monetize all of the climate benefits and health and environmental co-benefits associated with 

the proposed federal plan and model trading rules, including reductions in directly emitted PM2.5, 

reduced exposure to SO2, NOX, and hazardous air pollutants (e.g., mercury), as well as 

ecosystem effects and visibility improvement. The omission of these endpoints from the 

 

14 Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon, with participation by 

Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture, Department of 

Commerce, Department of Energy, Department of Transportation, Domestic Policy Council, Environmental 

Protection Agency, National Economic Council, Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (May 2013, Revised July 2015). Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf> Accessed 7/11/2015. 

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monetized results should not imply that the impacts are small or unimportant. Table 1-5 provides 

the list of the quantified and unquantified health and environmental benefits in this analysis. 

Table 1-5 Quantified and Unquantified Benefits 

Benefits Category Specific Effect 

Effect Has 

Been 

Quantified

Effect Has 

Been 

Monetized

More Information 

Improved 

Environment 

Reduced climate 

effects 

Global climate impacts from CO2 —1  SC-CO2 TSD 

Climate impacts from ozone and black carbon (directly 

emitted PM) — — 

Ozone ISA, PM 

ISA2

Other climate impacts (e.g., other GHGs such as methane, 

aerosols, other impacts) — — IPCC2

Improved Human Health (co-benefits) 

Reduced incidence of 

premature mortality 

from exposure to 

PM2.5

Adult premature mortality based on cohort study estimates

and expert elicitation estimates (age >25 or age >30)   PM ISA 

Infant mortality (age <1)   PM ISA 

Reduced incidence of 

morbidity from 

exposure to PM2.5

Non-fatal heart attacks (age > 18)   PM ISA 

Hospital admissions—respiratory (all ages)   PM ISA 

Hospital admissions—cardiovascular (age >20)   PM ISA 

Emergency room visits for asthma (all ages)   PM ISA 

Acute bronchitis (age 8-12)   PM ISA 

Lower respiratory symptoms (age 7-14)   PM ISA 

Upper respiratory symptoms (asthmatics age 9-11)   PM ISA 

Asthma exacerbation (asthmatics age 6-18)   PM ISA 

Lost work days (age 18-65)   PM ISA 

Minor restricted-activity days (age 18-65)   PM ISA 

Chronic Bronchitis (age >26) — — PM ISA2

Emergency room visits for cardiovascular effects (all ages) — — PM ISA2

Strokes and cerebrovascular disease (age 50-79) — — PM ISA2

Other cardiovascular effects (e.g., other ages) — — PM ISA3

Other respiratory effects (e.g., pulmonary function, nonasthma ER visits, non-bronchitis chronic diseases, other 

ages and populations) 

— — PM ISA3

Reproductive and developmental effects (e.g., low birth 

weight, pre-term births, etc) — — PM ISA3,4

Cancer, mutagenicity, and genotoxicity effects — — PM ISA3,4

Reduced incidence of 

mortality from 

exposure to ozone 

Premature mortality based on short-term study estimates (all 

ages)   Ozone ISA 

Premature mortality based on long-term study estimates 

(age 30–99) — — Ozone ISA2

Reduced incidence of 

morbidity from 

exposure to ozone 

Hospital admissions—respiratory causes (age > 65)   Ozone ISA 

Hospital admissions—respiratory causes (age <2)   Ozone ISA 

Emergency department visits for asthma (all ages)   Ozone ISA 

Minor restricted-activity days (age 18–65)   Ozone ISA 

School absence days (age 5–17)   Ozone ISA 

Decreased outdoor worker productivity (age 18–65) — — Ozone ISA2

Other respiratory effects (e.g., premature aging of lungs) — — Ozone ISA3

Cardiovascular and nervous system effects — — Ozone ISA3

Reproductive and developmental effects — — Ozone ISA3,4

 

 

 

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Table 1-5. Continued 

Reduced incidence of 

morbidity from 

exposure to NO2

Asthma hospital admissions (all ages) — — NO2 ISA2

Chronic lung disease hospital admissions (age > 65) — — NO2 ISA2

Respiratory emergency department visits (all ages) — — NO2 ISA2

Asthma exacerbation (asthmatics age 4–18) — — NO2 ISA2

Acute respiratory symptoms (age 7–14) — — NO2 ISA2

Premature mortality — — NO2 ISA2,3,4

Other respiratory effects (e.g., airway hyperresponsiveness 

and inflammation, lung function, other ages and 

populations) 

— — NO2 ISA3,4

Reduced incidence of 

morbidity from 

exposure to SO2

Respiratory hospital admissions (age > 65) — — SO2 ISA2

Asthma emergency department visits (all ages) — — SO2 ISA2

Asthma exacerbation (asthmatics age 4–12) — — SO2 ISA2

Acute respiratory symptoms (age 7–14) — — SO2 ISA2

Premature mortality — — SO2 ISA2,3,4

Other respiratory effects (e.g., airway hyperresponsiveness 

and inflammation, lung function, other ages and 

populations) 

— — SO2 ISA2,3

Reduced incidence of 

morbidity from 

exposure to 

methylmercury 

Neurologic effects—IQ loss — — IRIS; NRC, 20002

Other neurologic effects (e.g., developmental delays, 

memory, behavior) — — IRIS; NRC, 20003

Cardiovascular effects — — IRIS; NRC, 20003,4

Genotoxic, immunologic, and other toxic effects — — IRIS; NRC, 20003,4

Improved Environment (co-benefits) 

Reduced visibility 

impairment 

Visibility in Class 1 areas — — PM ISA2

Visibility in residential areas — — PM ISA2

Reduced effects on 

materials 

Household soiling — — PM ISA2,3

Materials damage (e.g., corrosion, increased wear) — — PM ISA3

Reduced PM 

deposition (metals and 

organics) 

Effects on individual organisms and ecosystems — — PM ISA3

Reduced vegetation 

and ecosystem effects 

from exposure to 

ozone 

Visible foliar injury on vegetation — — Ozone ISA2

Reduced vegetation growth and reproduction — — Ozone ISA2

Yield and quality of commercial forest products and crops — — Ozone ISA2

Damage to urban ornamental plants — — Ozone ISA3

Carbon sequestration in terrestrial ecosystems — — Ozone ISA2

Recreational demand associated with forest aesthetics — — Ozone ISA3

Other non-use effects Ozone ISA3

Ecosystem functions (e.g., water cycling, biogeochemical 

cycles, net primary productivity, leaf-gas exchange, 

community composition) 

— — Ozone ISA3

Reduced effects from 

acid deposition 

Recreational fishing — — NOx SOx ISA2

Tree mortality and decline — — NOx SOx ISA3

Commercial fishing and forestry effects — — NOx SOx ISA3

Recreational demand in terrestrial and aquatic ecosystems — — NOx SOx ISA3

Other non-use effects NOx SOx ISA3

Ecosystem functions (e.g., biogeochemical cycles) — — NOx SOx ISA3

 

 

 

 

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Table 1-5. Continued 

Reduced effects from 

nutrient enrichment 

Species composition and biodiversity in terrestrial and 

estuarine ecosystems — — NOx SOx ISA3

Coastal eutrophication — — NOx SOx ISA3

Recreational demand in terrestrial and estuarine ecosystems — — NOx SOx ISA3

Other non-use effects NOx SOx ISA3

Ecosystem functions (e.g., biogeochemical cycles, fire 

regulation) — — NOx SOx ISA3

Reduced vegetation 

effects from exposure 

to SO2 and NOx

Injury to vegetation from SO2 exposure — — NOx SOx ISA3

Injury to vegetation from NOx exposure — — NOx SOx ISA3

Reduced ecosystem 

effects from exposure 

to methylmercury 

Effects on fish, birds, and mammals (e.g., reproductive 

effects) — — 

Mercury Study 

RTC3

Commercial, subsistence and recreational fishing — —

Mercury Study 

RTC2

1

 The global climate and related impacts of CO2 emissions changes, such as sea level rise, are estimated within each 

integrated assessment model as part of the calculation of the SC-CO2. The resulting monetized damages, which 

are relevant for conducting the benefit-cost analysis, are used in this RIA to estimate the welfare effects of 

quantified changes in CO2 emissions. 

2

 We assess these co-benefits qualitatively, as reported in the Chapter 4 of the Clean Power Plan Final Rule RIA, 

due to data and resource limitations for this analysis. 

3

 We assess these co-benefits qualitatively, as reported in the Chapter 4 of the Clean Power Plan Final Rule RIA, 

because we do not have sufficient confidence in available data or methods. 

4

 We assess these co-benefits qualitatively, as reported in the Chapter 4 of the Clean Power Plan Final Rule RIA, 

because current evidence is only suggestive of causality or there are other significant concerns over the strength of 

the association. 

1.5.3.1 Estimating Global Climate Benefits 

We estimate the global social benefits of CO2 emission reductions expected from this 

rulemaking using the SC-CO2 estimates presented in the current SC-CO2 TSD.15 We refer to 

these estimates, which were developed by the U.S. government, as “SC-CO2 estimates” for the 

remainder of this document. The SC-CO2 is a metric that estimates the monetary value of 

impacts associated with marginal changes in CO2 emissions in a given year. It includes a wide 

range of anticipated climate impacts, such as net changes in agricultural productivity and human 

health, property damage from increased flood risk, and changes in energy system costs, such as 

reduced costs for heating and increased costs for air conditioning. It is typically used to assess 

 

15 Also see Chapter 4 of the Clean Power Plan Final Rule RIA for more details on this assessment of climate 

benefits. 

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the avoided damages as a result of regulatory actions (i.e., benefits of rulemakings that lead to an 

incremental reduction in cumulative global CO2 emissions). 

The SC-CO2 estimates used in this analysis have been developed over many years, using 

the best science available, and with input from the public. The EPA and other federal agencies 

have considered the extensive public comments on ways to improve SC-CO2 estimation received 

via the notice and comment period that was part of numerous rulemakings. In addition, OMB’s 

Office of Information and Regulatory Affairs recently issued a response to the public comments 

it sought through a separate comment period on the approach used to develop the SC-CO2

estimates.16

An interagency working group (IWG) that included the EPA and other executive branch 

entities used three integrated assessment models (IAMs) to develop SC-CO2 estimates and 

recommended four global values for use in regulatory analyses. The SC-CO2 estimates represent 

global measures because of the distinctive nature of the climate change problem. Emissions of 

greenhouse gases contribute to damages around the world, even when they are released in the 

United States, and the world’s economies are now highly interconnected. Therefore, the SC-CO2 

estimates incorporate the worldwide damages caused by carbon dioxide emissions in order to 

reflect the global nature of the problem, and we expect other governments to consider the global 

consequences of their greenhouse gas emissions when setting their own domestic policies. See 

Chapter 4 of the final Clean Power Plan Emission Guidelines RIA for more discussion. 

The IWG first released the estimates in February 2010 and updated them in 2013 using 

new versions of each IAM. The SC-CO2 values was estimated using three integrated assessment 

models (DICE, FUND, and PAGE)17, which the IWG harmonized across three key inputs: the 

probability distribution for equilibrium climate sensitivity; five scenarios for economic, 

population, and emissions growth; and three constant discount rates. The 2010 SC-CO2

Technical Support Document (2010 SC-CO2 TSD) provides a complete discussion of the 

methodology and the current SC-CO2 TSD18 presents and discusses the updated estimates. The 

 

16 See https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-comments-final-july-2015.pdf 

17 The full models names are as follows: Dynamic Integrated Climate and Economy (DICE); Climate Framework for 

Uncertainty, Negotiation, and Distribution (FUND); and Policy Analysis of the Greenhouse Gas Effect (PAGE). 

18 The IWG published the updated TSD in 2013, then issued two minor corrections to it in July 2015. 

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four SC-CO2 estimates are as follows: $12, $40, $60, and $120 per short ton of CO2 emissions in 

the year 2020 (2011$), and each estimate increases over time.19 These SC-CO2 estimates are 

associated with different discount rates. The first three estimates are the model average at 5 

percent discount rate, 3 percent, and 2.5 percent, respectively, and the fourth estimate is the 95th

percentile at 3 percent. 

 The 2010 SC-CO2 TSD noted a number of limitations to the SC-CO2 analysis, including 

the incomplete way in which the IAMs capture catastrophic and non-catastrophic impacts, their 

incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of 

damages to high temperatures, and assumptions regarding risk aversion. Currently integrated 

assessment models do not assign value to all of the important physical, ecological, and economic 

impacts of climate change recognized in the climate change literature because of a lack of 

precise information on the nature of damages and because the science incorporated into these 

models understandably lags behind the most recent research.20 In particular, the IPCC Fourth 

Assessment Report concluded that “It is very likely that [SC-CO2 estimates] underestimate the 

damage costs because they cannot include many non-quantifiable impacts.” Nonetheless, these 

estimates and the discussion of their limitations represent the best available information about 

the social benefits of CO2 emission reductions to inform the benefit-cost analysis. 

In addition, after careful evaluation of the full range of comments submitted to OMB’s 

Office of Information and Regulatory Affairs, the IWG continues to recommend the use of these 

SC-CO2 estimates in regulatory impact analysis. With the release of the response to comments, 

the IWG announced plans to obtain expert independent advice from the National Academies of 

Sciences, Engineering, and Medicine (Academies) to ensure that the SC-CO2 estimates continue 

to reflect the best available scientific and economic information on climate change.21 The 

 

19 The 2010 and 2013 TSDs present SC-CO2 in 2007$ per metric ton. The unrounded estimates from the current 

TSD were adjusted to (1) 2011$ using GDP Implicit Price Deflator (1.061374), 

http://www.bea.gov/iTable/index_nipa.cfm and (2) short tons using the conversion factor of 0.90718474 metric 

tons in a short ton. These estimates were rounded to two significant digits. 

20 Climate change impacts and SCC modeling is an area of active research. For example, see: (1) Howard, Peter, 

“Omitted Damages: What’s Missing from the Social Cost of Carbon.” March 13, 2014, 

http://costofcarbon.org/files/Omitted_Damages_Whats_Missing_From_the_Social_Cost_of_Carbon.pdf; and (2) 

Electric Power Research Institute, “Understanding the Social Cost of Carbon: A Technical Assessment,” October 

2014, www.epri.com. 

21 See <https://www.whitehouse.gov/blog/2015/07/02/estimating-benefits-carbon-dioxide-emissions-reductions>. 

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Academies’ process will be informed by the public comments received and focus on the 

technical merits and challenges of potential approaches to improving the SC-CO2 estimates in 

future updates. 

1.5.3.2 Estimating Air Quality Health Co-Benefits 

The proposed federal plan and model trading rules would reduce emissions of precursor 

pollutants (e.g., SO2, NOX, and directly emitted particles), which in turn would lower ambient 

concentrations of PM2.5 and ozone. This co-benefits analysis quantifies the monetized benefits 

associated with the reduced exposure to these two pollutants.22 Unlike the global SC-CO2

estimates, the air quality health co-benefits are only estimated for the contiguous U.S. The 

estimates of monetized PM2.5 co-benefits include avoided premature deaths (derived from effect 

coefficients in two cohort studies [Krewski et al. 2009 and Lepeule et al. 2012] for adults and 

one for infants [Woodruff et al. 1997]), as well as avoided morbidity effects for ten non-fatal 

endpoints ranging in severity from lower respiratory symptoms to heart attacks23 (U.S. EPA, 

2012). The estimates of monetized ozone co-benefits include avoided premature deaths (derived 

from the range of effect coefficients represented by two short-term epidemiology studies [Bell et 

al. (2004) and Levy et al. (2005)]), as well as avoided morbidity effects for five non-fatal 

endpoints ranging in severity from school absence days to hospital admissions (U.S. EPA, 2008, 

2011). 

We use a “benefit-per-ton” approach to estimate the PM2.5 and ozone co-benefits in this 

RIA. Benefit-per-ton approaches apply an average benefit per ton derived from modeling of 

benefits of specific air quality scenarios to estimates of emissions reductions for scenarios where 

no air quality modeling is available. The benefit-per-ton approach we use in this RIA relies on 

estimates of human health responses to exposure to PM and ozone obtained from the peerreviewed scientific literature. These estimates are used in conjunction with population data, 

 

22 We did not estimate the co-benefits associated with reducing direct exposure to SO2 and NOX. For this RIA, we 

did not estimate changes in emissions of directly emitted particles. As a result, quantified PM2.5 related benefits 

are underestimated by a relatively small amount. In the proposal RIA, the benefits from reductions in directly 

emitted PM2.5 were less than 10 percent of total monetized health co-benefits across all scenarios and years. 

23 See Chapter 4 and Appendix 4A of the Clean Power Plan Final Rule for details on this assessment of health cobenefits. 

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baseline health information, air quality data and economic valuation information to conduct 

health impact and economic benefits assessments. 

Specifically, in this analysis, we multiplied the benefit-per-ton estimates by the 

corresponding emission reductions that were generated from air quality modeling of the 

proposed Clean Power Plan Emission Guidelines. Similar to the co-benefits analysis conducted 

for the final Clean Power Plan Emission Guidelines RIA, we generated regional benefit-per-ton 

estimates by aggregating the impacts in BenMAP24 to the region (i.e., East, West, and California) 

rather than aggregating to the nation. The benefit-per-ton for SO2 and NOx emissions used in this 

proposed rule were calculated using air quality modeling of the base case and the proposed Clean 

Power Plan (Option 1 State) scenario for 2025 as described in Appendix 4A of the final Clean 

Power Plan Emission Guidelines RIA. The benefit-per-ton values for 2020 and 2030 are based 

on applying the air quality modeling from 2025 to population and health information from 2020 

and 2030. 

To calculate the co-benefits for this proposed rule, we then multiplied the regional 

benefit-per-ton estimates for the EGU sector by the corresponding emission reductions. All 

benefit-per-ton estimates reflect the geographic distribution of the modeled emissions, which 

may not exactly match the emission reductions in this rulemaking, and thus they may not reflect 

the local variability in population density, meteorology, exposure, baseline health incidence 

rates, or other local factors for any specific location. 

Our estimate of the monetized co-benefits is based on the EPA’s interpretation of the best 

available scientific literature (U.S. EPA, 2009) and methods and supported by the EPA’s Science 

Advisory Board and the NAS (NRC, 2002). Below are key assumptions underlying the estimates 

for PM2.5-related premature mortality, which accounts for 98 percent of the monetized PM2.5

health co-benefits. 

1. We assume that all fine particles, regardless of their chemical composition, are 

equally potent in causing premature mortality. This is an important assumption, 

 

24 BenMAP is a computer program developed by the EPA that calculates the number and economic value of air 

pollution-related deaths and illnesses. The software incorporates a database that includes many of the 

concentration-response relationships, population files, and health and economic data needed to quantify these 

impacts. 

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because PM2.5 varies considerably in composition across sources, but the scientific 

evidence is not yet sufficient to allow differentiation of effect estimates by particle 

type. The PM ISA concluded that “many constituents of PM2.5 can be linked with 

multiple health effects, and the evidence is not yet sufficient to allow differentiation 

of those constituents or sources that are more closely related to specific outcomes” 

(U.S. EPA, 2009b). 

2. We assume that the health impact function for fine particles is log-linear without a 

threshold in this analysis. Thus, the estimates include health co-benefits from 

reducing fine particles in areas with varied concentrations of PM2.5, including both 

areas that do not meet the National Ambient Air Quality Standard for fine particles 

and those areas that are in attainment, down to the lowest modeled concentrations. 

3. We assume that there is a “cessation” lag between the change in PM exposures and 

the total realization of changes in mortality effects. Specifically, we assume that some 

of the incidences of premature mortality related to PM2.5 exposures occur in a 

distributed fashion over the 20 years following exposure based on the advice of the 

SAB-H1 (U.S. EPA-SAB, 2004c), which affects the valuation of mortality cobenefits at different discount rates. 

Every benefits analysis examining the potential effects of a change in environmental 

protection requirements is limited, to some extent, by data gaps, model capabilities (such as 

geographic coverage) and uncertainties in the underlying scientific and economic studies used to 

configure the benefit and cost models. Despite these uncertainties, we believe this analysis 

provides a reasonable indication of the expected health co-benefits of the air quality emission 

reductions for the proposed rule under a set of reasonable assumptions. This analysis does not 

include the type of detailed uncertainty assessment found in the 2012 PM2.5 National Ambient 

Air Quality Standard (NAAQS) RIA (U.S. EPA, 2012) because we lack the necessary air quality 

input and monitoring data to conduct a complete benefits assessment. In addition, using a 

benefit-per-ton approach adds another important source of uncertainty to the benefits estimates. 

1.5.3.3 Combined Benefits Estimates 

The EPA has evaluated the range of potential impacts by combining all four SC-CO2

values with health co-benefits values at the 3 percent and 7 percent discount rates. Different 

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discount rates are applied to SC-CO2 than to the health co-benefit estimates because CO2

emissions are long-lived and subsequent damages occur over many years. Moreover, several 

discount rates are applied to SC-CO2 because the literature shows that the estimate of SC-CO2 is 

sensitive to assumptions about discount rate and because no consensus exists on the appropriate 

rate to use in an intergenerational context. The IWG centered its attention on the average SCCO2 at a 3 percent discount rate but emphasized the importance of considering all four SC-CO2

estimates. Table 1-6 (rate-based federal plan approach) and Table 1-7 (mass-based federal plan 

approach) provide the combined climate benefits and health co-benefits for the proposed federal 

plan model trading rules estimated for 2020, 2025, and 2030 for each discount rate combination. 

All dollar estimates are in 2011 dollars. 

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Table 1-6. Combined Estimates of Climate Benefits and Health Co-Benefits for Rate-Based 

Approach (billions of 2011$)* 

SC-CO2 Discount Rate and Statistic** 

Climate 

Benefits 

Only 

Climate Benefits plus Health Co-benefits 

(Discount Rate Applied to Health Co-benefits) 

3% 7% 

In 2020 69 million short tons CO2 

5% $0.80 $1.5 to $2.6 $1.4 to $2.5 

3% $2.8 $3.5 to $4.6 $3.5 to $4.5 

2.5% $4.1 $4.9 to $6.0 $4.8 to $5.9 

3% (95th percentile) $8.2 $8.9 to $10 $8.9 to $9.9 

In 2025 232 million short tons CO2 

5% $3.1 $11 to $21 $9.9 to $19 

3% $10 $18 to $28 $17 to $26 

2.5% $15 $23 to $33 $22 to $31 

3% (95th percentile) $31 $38 to $49 $38 to $47 

In 2030 415 million short tons CO2 

5% $6.4 $21 to $40 $19 to $37 

3% $20 $34 to $54 $33 to $51 

2.5% $29 $43 to $63 $42 to $60 

3% (95th percentile) $61 $75 to $95 $74 to $92 

*All benefit estimates are rounded to two significant figures. Climate benefits are based on reductions in CO2

emissions. Co-benefits are based on regional benefit-per-ton estimates. Ozone co-benefits occur in analysis year, so 

they are the same for all discount rates. The health co-benefits reflect the sum of the PM2.5 and ozone co-benefits 

and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Bell et al. (2004) to 

Lepeule et al. (2012) with Levy et al. (2005)). The monetized health co-benefits do not include reduced health 

effects from reductions in directly emitted PM2.5, direct exposure to NOX, SO2, and HAP; ecosystem effects; or 

visibility impairment. See Chapter 4 of the Clean Power Plan Final Rule RIA for more information about these 

estimates and for more information regarding the uncertainty in these estimates. 

**Unless otherwise specified, the row reflects the average SC-CO2 estimate for the specified discount rate. 

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Table 1-7. Combined Estimates of Climate Benefits and Health Co-benefits for Mass-Based 

Approach (billions of 2011$)* 

SC-CO2 Discount Rate and Statistic** 

Climate 

Benefits 

Only 

Climate Benefits plus Health Co-benefits 

(Discount Rate Applied to Health Co-benefits) 

3% 7% 

In 2020 82 million short tons CO2 

5% $0.94 $2.9 to $5.7 $2.8 to $5.3 

3% $3.3 $5.3 to $8.1 $5.1 to $7.7 

2.5% $4.9 $6.9 to $9.7 $6.7 to $9.3 

3% (95th percentile) $9.7 $12 to $14 $11 to $14 

In 2025 264 million short tons CO2 

5% $3.6 $11 to $21 $10 to $19 

3% $12 $19 to $29 $18 to $27 

2.5% $17 $24 to $35 $24 to $33 

3% (95th percentile) $35 $42 to $52 $42 to $51 

In 2030 413 million short tons CO2 

5% $6.4 $18 to $34 $17 to $32 

3% $20 $32 to $48 $31 to $46 

2.5% $29 $41 to $57 $40 to $55 

3% (95th percentile) $60 $72 to $89 $71 to $86 

*All benefit estimates are rounded to two significant figures. Climate benefits are based on reductions in CO2

emissions. Co-benefits are based on regional benefit-per-ton estimates. Ozone co-benefits occur in analysis year, so 

they are the same for all discount rates. The health co-benefits reflect the sum of the PM2.5 and ozone co-benefits 

and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Bell et al. (2004) to 

Lepeule et al. (2012) with Levy et al. (2005)). The monetized health co-benefits do not include reduced health 

effects from reductions in directly emitted PM2.5, direct exposure to NOX, SO2, and HAP; ecosystem effects; or 

visibility impairment. See Chapter 4 of the Clean Power Plan Final Rule RIA for more information about these 

estimates and for more information regarding the uncertainty in these estimates. 

**Unless otherwise specified, the row reflects the average SC-CO2 estimate for the specified discount rate. 

1.5.4 Net Benefits 

Table 1-8 and 1-9 provide the estimates of the climate benefits, health co-benefits, 

compliance costs and net benefits of the proposed federal plan and model trading rules for ratebased and mass-based approaches, respectively. There are additional important benefits that the 

EPA could not monetize. Due to current data and modeling limitations, our estimates of the 

benefits from reducing CO2 emissions do not include important impacts like ocean acidification 

or potential tipping points in natural or managed ecosystems. Unquantified benefits also include 

climate benefits from reducing emissions of non-CO2 greenhouse gases and co-benefits from 

reducing exposure to SO2, NOX, and hazardous air pollutants (e.g., mercury), as well as 

ecosystem effects and visibility impairment. Upon considering these limitations and 

uncertainties, it remains clear that the benefits of this proposed rule are substantial and far 

outweigh the costs. 

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Table 1-8. Monetized Benefits, Compliance Costs, and Net Benefits Under the Rate-based 

Federal Plan Approach (billions of 2011$) a 

 Rate-Based Approach 

2020 2025 2030

Climate Benefits b

5% discount rate $0.80 $3.1 $6.4 

3% discount rate $2.8 $10 $20 

2.5% discount rate $4.1 $15 $29 

95th percentile at 3% 

discount rate $8.2 $31 $61 

Air Quality Co-benefits Discount Rate 

3% 7% 3% 7% 3% 7%

Air Quality Health 

Co-benefits c $0.70 to $1.8 $0.64 to $1.7 $7.4 to $18 $6.7 to $16 $14 to $34 $13 to $31 

Compliance Costs d

$2.5 $1.0 $8.4 

Net Benefits e

$1.0 to $2.1 $1.0 to $2.0 $17 to $27 $16 to $25 $26 to $45 $25 to $43 

Non-Monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and mercury 

Visibility impairment 

a

 All are rounded to two significant figures, so figures may not sum. 

b

 The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does 

not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SC-CO2 than to the 

other estimates because CO2 emissions are long-lived and subsequent damages occur over many years. The net 

benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount rate, however we 

emphasize the importance and value of considering the full range of SC-CO2 values. As shown in this table, climate 

benefits are also estimated using the other three SC-CO2 estimates (model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2 estimates are year-specific and increase over time. 

c The air quality health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions 

of SO2 and NOX. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These 

additional benefits would increase overall benefits by a few percent based on the analyses conducted for the 

proposed rule. The range reflects the use of concentration-response functions from different epidemiology studies. 

The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. Estimates in the table are presented for three analytical years with air quality cobenefits calculated using two discount rates. The estimates of co-benefits are annual estimates in each of the 

analytical years, reflecting discounting of mortality benefits over the cessation lag between changes in PM2.5

concentrations and changes in risks of premature death (see Chapter 4 of the Clean Power Plan Final Rule RIA for 

more details), and discounting of morbidity benefits due to the multiple years of costs associated with some 

illnesses. The estimates are not the present value of the benefits of the rule over the full compliance period. 

d Compliance costs are the compliance costs estimated using the Integrated Planning Model and a discount rate of 

approximately 5 percent. It also includes monitoring, recordkeeping, and reporting costs and demand-side energy 

efficiency program and participant costs. 

e

 The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount 

rate (model average). The Clean Power Plan Final Rule RIA includes combined climate and health estimates based 

on additional discount rates. 

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Table 1-9. Monetized Benefits, Compliance Costs, and Net Benefits under the Mass-based 

Federal Plan Approach (billions of 2011$) a 

 Mass-Based Approach 

2020 2025 2030

Climate Benefits b

5% discount rate $0.94 $3.6 $6.4 

3% discount rate $3.3 $12 $20 

2.5% discount rate $4.9 $17 $29 

95th percentile at 3% 

discount rate $9.7 $35 $60 

Air Quality Co-benefits Discount Rate 

3% 7% 3% 7% 3% 7%

Air Quality Health 

Co-benefits c $2.0 to $4.8 $1.8 to $4.4 $7.1 to $17 $6.5 to $16 $12 to $28 $11 to $26 

Compliance Costs d

$1.4 $3.0 $5.1 

Net Benefits e

$3.9 to $6.7 $3.7 to $6.3 $16 to $26 $15 to $24 $26 to $43 $25 to $40 

Non-Monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and 

mercury 

Visibility improvement 

a

 All are rounded to two significant figures, so figures may not sum. 

b

 The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does 

not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SC-CO2 than to the 

other estimates because CO2 emissions are long-lived and subsequent damages occur over many years. The net 

benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount rate, however we 

emphasize the importance and value of considering the full range of SC-CO2 values. As shown in this table, climate 

benefits are also estimated using the other three SC-CO2 estimates (model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2 estimates are year-specific and increase over time. 

c The air quality health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions 

of SO2 and NOX. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These 

additional benefits would increase overall benefits by a few percent based on the analyses conducted for the 

proposed rule. The range reflects the use of concentration-response functions from different epidemiology studies. 

The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. Estimates in the table are presented for three analytical years with air quality cobenefits calculated using two discount rates. The estimates of co-benefits are annual estimates in each of the 

analytical years, reflecting discounting of mortality benefits over the cessation lag between changes in PM2.5

concentrations and changes in risks of premature death (see Chapter 4 of the Clean Power Plan Final Rule RIA for 

more details), and discounting of morbidity benefits due to the multiple years of costs associated with some 

illnesses. The estimates are not the present value of the benefits of the rule over the full compliance period. 

d Compliance costs are the compliance costs estimated using the Integrated Planning Model and a discount rate of 

approximately 5 percent. It also includes monitoring, recordkeeping, and reporting costs and demand-side energy 

efficiency program and participant costs. 

e

 The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount 

rate (model average). The Clean Power Plan Final Rule RIA includes combined climate and health estimates based 

on additional discount rates. 

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1.5.5 Economic Impacts 

The federal plan approaches analyzed in this RIA indicate that the proposed federal plan 

and model trading rules may have important energy market implications. Table 1-10 presents a 

variety of important energy market impacts for 2020, 2025, and 2030 for both the rate-based and 

mass-based federal plan approaches. 

Table 1-10. Summary Table of Important Energy Market Impacts (Percent Change from 

Base Case) 

 Rate-Based Mass-Based 

 2020 2025 2030 2020 2025 2030 

Retail electricity prices 3% 1% 1% 3% 2% 0% 

Average electricity bills 3% -4% -7% 2% -3% -8% 

Price of coal at minemouth -1% -5% -4% -1% -5% -3% 

Coal production for power sector use -5% -14% -25% -7% -17% -24% 

Price of natural gas delivered to power sector 5% -8% 2% 4% -3% -2% 

Natural gas use for electricity generation 3% -1% -1% 5% 0% -4% 

Energy market impacts are discussed more extensively in Chapter 3 of the final Clean Power 

Plan Emission Guidelines RIA. As well as the above energy market impacts, Chapter 3 of the 

final Clean Power Plan Emission Guidelines RIA presents projections of power sector generation 

and capacity changes by fuel type. 

Additionally, changes in supply or demand for electricity, natural gas, and coal can 

impact markets for goods and services produced by sectors that use these energy inputs in the 

production process or that supply those sectors. Changes in cost of production may result in 

changes in price and/or quantity produced by these sectors and these market changes may affect 

the profitability of firms and the economic welfare of their consumers. Similarly, demand for 

new generation or energy efficiency, for example, can result in changes in production and 

profitability for firms that supply those goods and services. The EPA recognizes that states 

subject to the federal plan may choose to mitigate impacts to some markets outside the EGU 

sector, perhaps by implementing the guidelines through a state plan. 

1.5.6 Employment Impacts 

Executive Order 13563 directs federal agencies to consider the effect of regulations on 

job creation and employment. According to the Executive Order, “our regulatory system must 

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protect public health, welfare, safety, and our environment while promoting economic growth, 

innovation, competitiveness, and job creation. It must be based on the best available science” 

(Executive Order 13563, 2011). Although standard benefit-cost analyses have not typically 

included a separate analysis of regulation-induced employment impacts, we typically conduct 

employment analyses.25 While the economy continues moving toward full-employment, 

employment impacts are of particular concern and questions may arise about their existence and 

magnitude. 

Given the wide range of approaches that may be used to meet the requirements of the 

proposed federal plan and model trading rules, quantifying the associated employment impacts is 

difficult. The EPA’s illustrative employment analysis includes an estimate of projected 

employment impacts for the utility power sector, coal and natural gas production, and demandside energy efficiency activities. These projections are derived, in part, from the detailed model 

of the utility power sector used for this regulatory analysis, and U.S government data on 

employment and labor productivity. 

In the electricity, coal, and natural gas sectors, the EPA uses the IPM estimates of the 

changes in generation and fuel use of the proposed rule to estimate there could be a net decrease 

of approximately 25,000 job-years26 in 2025 for the proposed rule under the rate-based federal 

plan approach and approximately 26,000 job-years in 2025 under the mass-based approach. For 

2030 the estimates of the net decrease in job-years is 30,900 under the rate-based plan, and 

33,700 under the mass-based plan. The Agency is also offering an illustrative calculation of 

potential employment effects due to demand-side energy efficiency programs. Employment 

impacts from demand-side energy efficiency programs in 2030 could range from approximately 

52,000 to 83,000 jobs created under proposed federal plan and model trading rules. The IPMderived job-year numbers for the electricity, coal and natural gas sectors should not be added to 

the demand-side efficiency job impacts, since the former are reported in full-time equivalent jobyears, whereas the latter do not distinguish between full- and part-time employment. More detail 

 

25 The employment analysis in this RIA is part of EPA’s ongoing effort to “conduct continuing evaluations of 

potential loss or shifts of employment which may result from the administration or enforcement of [the Act]” 

pursuant to CAA section 321(a). 

26 Job-years are not individual jobs, but rather the amount of work performed by the equivalent of one full-time 

individual for one year. For example, 20 job-years in 2020 may represent 20 full-time jobs or 40 half-time jobs in 

that year. 

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about these analyses can be found in Chapter 6 of the final Clean Power Plan Emission 

Guidelines RIA. 

1.5.7 Additional Analysis of Output-Based Allocation as a Means of Mitigating Leakage 

The application of OBA will provide an incentive to increase generation at existing 

NGCC EGUs in place of generation at new NGCC EGUs and existing fossil steam EGUs. To 

approximate the effect of this incentive in the mass-based scenario, the EPA used IPM model 

plant results from the mass-based scenario to construct the average dispatch order for model 

plants in each IPM region. Then, based on the allowance prices for the state in which each model 

plant resides, the EPA adjusted the dispatch order in the case where existing NGCC units were 

allocated allowances at a rate of 1,030 lbs/MWh for each MWh generated above a 50 percent 

capacity factor as proposed. In cases where an existing NGCC plant moved ahead of an existing 

fossil steam plant in the dispatch order, the NGCC plant’s generation was increased while the 

existing fossil plant’s generation was reduced. The NGCC plant’s generation was increased to 

the maximum capacity factor assumed feasible within IPM while the amount of reduced 

generation at the fossil steam plant is determined by the amount that would keep the overall 

covered sources’ emissions in the region constant, so as to respect compliance with the massbased standards represented in the modeling scenario. Since the existing NGCC plant has a lower 

emissions rate than the existing fossil steam plant, the increase in generation at the NGCC plant 

is greater than the reduction in generation (because more generation is now possible from both 

plants together at the same given level of emissions). This net increase in generation from 

existing EGUs is then subtracted from new NGCC generation in the region, consistent with the 

total generation needed to meet the load assumed in the IPM modeling of the mass-based 

scenario. 

When applying this algorithm to the results from the mass-based scenario analyzed in this 

RIA, it forecasts nationally in 2030 a 10 percent increase in generation at existing NGCC EGUs, 

a 4 percent reduction in generation at existing fossil steam EGUs, and a 29 percent decrease in 

generation at new NGCC EGUs compared to the modeling scenario results presented above. The 

result of this reduction in new NGCC EGU generation is a reduction in CO2 emissions of 23 

million short tons (an amount equal to 1.3 percent of 2030 forecast emissions in mass-based 

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scenario). We do not quantify the effect of these changes in generation on SO2 and NOx

emissions, although on net additional co-benefits are expected. 

The incentives portrayed in this analysis are consistent with the incentives that would be 

realized under the OBA set-aside, and the general direction and magnitude of the results are 

likely consistent with those that would be observed had the mass-based scenario been modeled 

with the OBA set-aside. However, the results should be viewed as approximate given that 

analysis does not consider important aspects of power markets included in IPM. For example, the 

analysis does not consider any potential changes in relative fuel and allowance prices as a result 

of the OBA set-aside. The application of the OBA set-aside will place upward pressure on the 

allowance prices and therefore further incentivize a shift away from existing fossil steam 

generation. The OBA set-aside may also place upward pressure on the price of natural gas which 

would reduce the effectiveness of the set-aside at encouraging increased utilization of existing 

NGCC EGUs, but the OBA set-aside would be effective in increasing existing NGCC 

generation, the analysis does not consider the fact that electricity is traded across many IPM 

regions. The application of OBA in one state may impact the generation at EGUs in another 

state. 

1.5.8 Uncertainty Analysis 

The Office of Management and Budget’s circular Regulatory Analysis (Circular A-4) 

provides guidance on the preparation of regulatory analyses required under E.O. 12866, and 

requires an uncertainty analysis for rules with annual benefits or costs of $1 billion or more.27

This proposed rulemaking potentially surpasses that threshold for both benefits and costs. 

Throughout this RIA and the referenced final Clean Power Plan Emission Guidelines RIA, we 

considered a number of sources of uncertainty, both quantitatively and qualitatively, on benefits 

and costs. We summarize three key elements of our analysis of uncertainty here: 

 

27 Office of Management and Budget (OMB), 2003, Circular A-4, 

http://www.whitehouse.gov/omb/circulars_a004_a-4 and OMB, 2011. Regulatory Impact Analysis: A Primer.

http://www.whitehouse.gov/sites/default/files/omb/inforeg/regpol/circular-a-4_regulatory-impact-analysis-aprimer.pdf 

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• Assess uncertainty in the methods used to calculate the health co-benefits associated with 

the reduction in PM2.5 and ozone and the use of a benefits-per-ton approach in estimating 

these co-benefits. 

• Characterizing uncertainty in monetizing climate-related benefits. 

Some of these elements are evaluated using probabilistic techniques, whereas for others 

the underlying likelihoods of certain outcomes are unknown and we use scenario analysis to 

evaluate their potential effect on the benefits and costs of this rulemaking. 

1.5.8.1 Uncertainty in Costs 

Our best estimates of the costs of these illustrative scenarios are reported within the cost 

analysis of the final Clean Power Plan Emission Guidelines and are included in the cost 

modeling in this RIA for both the proposed rate-based and mass-based approaches. A source of 

uncertainty under this regulation is the ultimate approach states that are not subject to the federal 

plan or adopt the model rule will adopt in response to the guidelines, which will affect both the 

costs and benefits of this rule. For this reason we modeled the two proposed federal plan 

approaches assuming they applied to all of the states. 

1.5.8.2 Uncertainty Associated with Estimating the Social Cost of Carbon 

The 2010 SC-CO2 TSD noted a number of limitations to the SC-CO2 analysis, including 

the incomplete way in which the integrated assessment models (IAM) capture catastrophic and 

non-catastrophic impacts, their incomplete treatment of adaptation and technological change, 

uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk 

aversion.28 Currently integrated assessment models do not assign value to all of the important 

physical, ecological, and economic impacts of climate change recognized in the climate change 

literature due to a lack of precise information on the nature of damages and because the science 

incorporated into these models understandably lags behind the most recent research. These 

individual limitations do not all work in the same direction in terms of their influence on the SC-

 

28 Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866, Interagency Working Group on Social Cost of Carbon, with participation by the Council of Economic 

Advisers, Council on Environmental Quality, Department of Agriculture, Department of Commerce, Department 

of Energy, Department of Transportation, Environmental Protection Agency, National Economic Council, Office 

of Energy and Climate Change, Office of Management and Budget, Office of Science and Technology Policy, and 

Department of Treasury (February 2010). Available at: 

<http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf>. 

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CO2 estimates, though taken together they suggest that the SC-CO2 estimates are likely 

conservative. In particular, the IPCC Fourth Assessment Report (2007) concluded that “It is very 

likely that [SC-CO2 estimates] underestimate the damage costs because they cannot include 

many non-quantifiable impacts” and the IPCC Fifth Assessment report observed that SC-CO2

estimates continue to omit various impacts that would likely increase damages. The 95th

percentile estimate was included in the recommended range for regulatory impact analysis, in 

part, to address these concerns. 

The modeling underlying the development of the SC-CO2 estimates addressed 

uncertainty in several ways. An ensemble of three IAMs were used to generate the SC-CO2

estimates to capture differences in model structures that, in part, reflect uncertainty in the 

scientific literature about these relationships. Parametric uncertainty was explicitly addressed in 

each IAM, though to differing degrees, through Monte Carlo simulations in which explicit 

probability distributions for key parameters were specified, including the equilibrium climate 

sensitivity, which represents the long-run responsiveness of the climate to increasing GHG 

concentrations. Furthermore, the analysis considered five different socioeconomic and emissions 

forecasts to capture the sensitivity of the SC-CO2 estimates to key exogenous projections used in 

the modeling. Finally, the results were calculated for three discount rates, which were selected, in 

part, to reflect uncertainty about how interest rates may change over time and the possibility that 

climate damages are positively correlated with uncertain future economic activity. This analysis 

produced 45 different distributions of the SC-CO2 estimates for each emissions year. To produce 

a range of plausible estimates that are manageable in regulatory analysis but still reflects the 

uncertainty in the results four point estimates were recommended. The use of this range of point 

estimates in this rulemaking helps to reflect the uncertainty in the SC-CO2 estimates. Chapter 4 

of the final Clean Power Plan Emission Guidelines RIA provides a comprehensive discussion 

about the methodology and application of the SC-CO2; see both the 2010 TSD and current SCCO2 TSD for a full description. 

In addition, OMB’s Office of Information and Regulatory Affairs received comments 

regarding uncertainty and the SC-CO2 estimates in response to a separate request for public 

comment on the approach used to develop the estimates. Commenters discussed the analyses and 

presentation of uncertainty in the TSD as well as the implications of uncertainty for use of the 

SC-CO2 estimates in regulatory impact analysis. In their response, the interagency working 

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group (IWG) acknowledged uncertainty in the SC-CO2 estimates but disagreed with commenters 

that suggested the uncertainty undermines use of the SC-CO2 estimates in regulatory impact 

analysis. The IWG went on to note that the uncertainty in the SC-CO2 estimates is fully 

acknowledged and comprehensively discussed in the TSDs and supporting academic literature, 

and that while all regulatory impact analysis involves uncertainty, these analyses can provide 

useful information to decision makers and the public. See the IWG Response to Comments for 

the complete response.29 

1.5.8.3 Uncertainty Associated with PM2.5 and Ozone Health Co-Benefits Assessment 

EPA provides information on the relative uncertainty in the benefits estimates based on 

the 95th percentile confidence interval for avoided PM-related premature deaths and the 

associated economic valuation estimated in the benefits analysis for the recent PM NAAQS RIA 

(U.S. EPA, 2012).. In general, the 95th percentile confidence interval for monetized PM2.5

benefits ranges from approximately -90 percent to +180 percent of the central estimates based on 

the two key PM mortality studies. To further explore uncertainty in the premature mortality 

benefits, EPA provides the PM-related results using concentration-response functions from two 

key epidemiology studies, as well as alternate concentration-response relationship provided by 

an expert elicitation and alternative ozone-related results using concentration-response 

relationships provided by alternative epidemiology studies. In addition, we include an 

assessment of the distribution of population exposure in the modeling underlying the benefit-perton estimates. 

In addition to the uncertainties in the underlying concentration-response and valuation 

functions, all benefit-per-ton approaches have inherent limitations, including that the estimates 

reflect the geographic distribution of the modeled sector emissions, which may not match the 

emission reductions anticipated by this proposed rule, and they may not reflect local variability 

in population density, meteorology, exposure, baseline health incidence rates, or other local 

factors for any specific location. In addition, these estimates reflect the regional average benefitper-ton for each ambient PM2.5 precursor emitted from EGUs, which assumes a linear 

atmospheric response to emission reductions. The regional benefit-per-ton estimates, although 

 

29 See https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-comments-final-july-2015.pdf 

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less subject to these types of uncertainties than national estimates, still should be interpreted with 

caution. Even though we assume that all fine particles have equivalent health effects, the benefitper-ton estimates vary between precursors depending on the location and magnitude of their 

impact on PM2.5 levels, which drive population exposure. 

1.6 References 

40 CFR Chapter I [EPA–HQ–OAR–2009–0171; FRL–9091–8] RIN 2060–ZA14, 

“Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) 

of the Clean Air Act,” Federal Register / Vol. 74, No. 239 / Tuesday, December 15, 2009 / 

Rules and Regulations. 

75 FR 49556. August 13, 2010. “EPA’s Denial of the Petitions to Reconsider the Endangerment 

and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean 

Air Act.”

Bell, M.L., A. McDermott, S.L. Zeger, J.M. Sarnet, and F. Dominici. 2004. “Ozone and ShortTerm Mortality in 95 U.S. Urban Communities, 1987-2000.” Journal of the American 

Medical Association. 292(19):2372-8. 

Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support Document: Social Cost of 

Carbon for Regulatory Impact Analysis Under Executive Order 12866, Interagency Working 

Group on Social Cost of Carbon, with participation by the Council of Economic Advisers, 

Council on Environmental Quality, Department of Agriculture, Department of Commerce, 

Department of Energy, Department of Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and Climate Change, Office of Management 

and Budget, Office of Science and Technology Policy, and Department of Treasury (February 

2010). Available at: <http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf>. Accessed July 15, 2015. 

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Docket ID EPA-HQ-OAR-2013-0602, Technical Support Document: Technical Update of the 

Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, 

Interagency Working Group on Social Cost of Carbon, with Participation by Council of 

Economic Advisers, Council on Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, Department of Transportation, Domestic 

Policy Council, Environmental Protection Agency, National Economic Council, Office of 

Management and Budget, Office of Science and Technology Policy, and Department of 

Treasury (May 2013, Revised July 2015). Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf>. 

Accessed July 15, 2015. 

Krewski D., M. Jerrett, R.T. Burnett, R. Ma, E. Hughes, Y. Shi, et al. 2009. Extended Follow-Up 

and Spatial Analysis of the American Cancer Society Study Linking Particulate Air Pollution 

and Mortality. HEI Research Report, 140, Health Effects Institute, Boston, MA. 

Interagency Working Group on Social Cost of Carbon, with participation by Council of 

Economic Advisers, Council on Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, Department of Transportation, 

Environmental Protection Agency, National Economic Council, Office of Management and 

Budget, Office of Science and Technology Policy, and Department of Treasury. Response to 

to Comments: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866. July 2015. Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-commentsfinal-july-2015.pdf.> Accessed July 15, 2015. 

Intergovernmental Panel on Climate Change (IPCC). 2007. Climate Change 2007: Synthesis 

Report Contribution of Working Groups I, II and III to the Fourth Assessment Report of the 

IPCC. Available at: 

<http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report_synt

hesis_report.htm>. Accessed June 6, 2015. 

Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. “Chronic Exposure to Fine Particles 

and Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environmental Health Perspectives. 120(7):965-70. 

Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. “Ozone Exposure and Mortality: An 

Empiric Bayes Metaregression Analysis.” Epidemiology. 16(4):458-68. 

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Melillo, J.M., T.C. Richmond, and G.W. Yohe, Eds., 2014: Climate Change Impacts in the 

United States: The Third National Climate Assessment. U.S. Global Change Research 

Program. Available at <http://nca2014.globalchange.gov>. Accessed June 4, 2015. 

National Research Council (NRC). 2000. Toxicological Effects of Methylmercury: Committee on 

the Toxicological Effects of Methylmercury.” Board on Environmental Studies and 

Toxicology. National Academies Press. Washington, DC. 

National Research Council (NRC). 2002. Estimating the Public Health Benefits of Proposed Air 

Pollution Regulations. National Academies Press. Washington, DC. 

National Research Council. 2011. Climate Stabilization Targets: Emissions, Concentrations, and 

Impacts over Decades to Millennia. Washington, DC: The National Academies Press. 

U.S. Environmental Protection Agency (U.S. EPA). 2008a. Integrated Science Assessment for 

Sulfur Oxides—Health Criteria (Final Report). National Center for Environmental 

Assessment – RTP Division, Research Triangle Park, NC. September. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=198843>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2008b. Final Ozone NAAQS Regulatory 

Impact Analysis. EPA-452/R-08-003. Office of Air Quality Planning and Standards Health 

and Environmental Impacts Division, Air Benefit and Cost Group Research Triangle Park, 

NC. March. Available at: < http://www.epa.gov/ttnecas1/regdata/RIAs/6-

ozoneriachapter6.pdf>. Accessed June 4, 2015. 

U.S. EPA. 2008c. Integrated Science Assessment for Oxides of Nitrogen: Health Criteria (Final 

Report). Research Triangle Park, NC: National Center for Environmental Assessment. July. 

Available at < http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. 

U.S. Environmental Protection Agency (U.S. EPA). 2008c. Integrated Science Assessment for 

Oxides of Nitrogen - Health Criteria (Final Report). National Center for Environmental 

Assessment, Research Triangle Park, NC. July. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2009b. Integrated Science Assessment for 

Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for Environmental 

Assessment – RTP Division, Research Triangle Park, NC. December. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>. Accessed June 4, 2015. 

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U.S. Environmental Protection Agency (U.S. EPA). 2010d. Section 3: Re‐analysis of the Benefits 

of Attaining Alternative Ozone Standards to Incorporate Current Methods. Available at: 

<http://www.epa.gov/ttnecas1/regdata/RIAs/s3-supplemental_analysis-updated_benefits11-

5.09.pdf >. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2012a. Regulatory Impact Analysis for the 

Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. EPA452/R-12-003. Office of Air Quality Planning and Standards, Health and Environmental 

Impacts Division, Research Triangle Park, NC. December. Available at: < 

http://www.epa.gov/ttnecas1/regdata/RIAs/finalria.pdf>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2013b. Integrated Science Assessment of 

Ozone and Related Photochemical Oxidants (Final Report). EPA/600/R-10/076F. National 

Center for Environmental Assessment – RTP Division, Research Triangle Park. Available at: 

<http://cfpub.epa.gov/ncea/isa/recordisplay.cfm?deid=247492#Download>. Accessed June 4, 

2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2015a. Regulatory Impact Analysis for the 

Clean Power Plan Final Rule. EPA-452/R-15-003. Office of Air Quality Planning and 

Standards, Health and Environmental Impacts Division, Research Triangle Park. 

U.S. EPA. 2015b. Technical Support Document (TSD) the Final Carbon Pollution Emission 

Guidelines for Existing Stationary Sources: Electric Utility Generating Units. Demand-Side 

Energy Efficiency. 

Woodruff, T.J., J. Grillo, and K.C. Schoendorf. 1997. “The relationship between selected causes 

of postneonatal infant mortality and particulate air pollution in the United States.” 

Environmental Health Perspectives. 105(6): 608-612. 

 

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CHAPTER 2: STATUTORY AND EXECUTIVE ORDER REVIEWS

2.1 Executive Order 12866: Regulatory Planning and Review and Executive Order 

13563: Improving Regulation and Regulatory Review 

This proposed action is an economically significant regulatory action that was submitted 

to the OMB for review. Any changes made in response to OMB recommendations have been 

documented in the docket. The EPA prepared an analysis of the potential costs and benefits 

associated with this action. This analysis, which is presented in this RIA, is also available in the 

docket and is briefly summarized in section VIII of the preamble. 

Consistent with Executive Order 12866 and Executive Order 13563, the EPA estimated 

the costs and benefits for two alternative federal plan approaches to implementing the proposed 

federal plan and model trading rules. The proposed action will achieve the same levels of 

emissions performance as required of state plans under the CAA section 111(d) EGs for the 

control of CO2. Actions taken to comply with the guidelines will also reduce the emissions of 

directly-emitted PM2.5, SO2 and NOX. The benefits associated with these PM2.5, SO2 and NOX

reductions are referred to as co-benefits, as these reductions are not the primary objective of this 

rule. 

The RIA for this proposal analyzed two implementation scenarios, which we term the 

“rate-based federal plan approach” and the “mass-based federal plan approach”. It is very 

important to note that the differences between the analytical results for the rate-based and massbased federal plan approaches presented in this RIA may not be indicative of likely differences 

between the approaches if implemented by states and affected EGUs in response to the proposed 

rule. In other words, if one approach performs differently than the other on a given metric during 

a given time period, this does not imply this will apply in all instances. 

It is important to note that the potential regulatory impacts presented in the Clean Power 

Plan Final Rule RIA and this RIA are not additive. Both RIAs present estimates of the benefits 

and costs of achieving the emission performance rates of the Clean Power Plan EGs. In the case 

of the Clean Power Plan Final Rule RIA, the illustrative analysis assumes the performance rates 

are met under state plans. In the case of this RIA for the proposed federal plan and model trading 

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rules, the same performance rates are accomplished but are assumed to be achieved under the 

federal plan or model trading rules. 

The EPA has used the social cost of carbon estimates presented in the Technical Support 

Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866 (May 2013, Revised July 2015) (“current TSD”) to analyze CO2

climate impacts of this rulemaking. We refer to these estimates, which were developed by the 

U.S. government, as “SC-CO2 estimates.” The SC-CO2 is an estimate of the monetary value of 

impacts associated with a marginal change in CO2 emissions in a given year. The four SC-CO2

estimates are associated with different discount rates (model average at 2.5 percent discount rate, 

3 percent, and 5 percent; 95th percentile at 3 percent), and each increases over time. In this 

summary, the EPA provides the estimate of climate benefits associated with the SC-CO2 value 

deemed to be central in the current TSD: the model average at 3 percent discount rate. 

The EPA estimates that, in 2020, the proposal will yield monetized climate benefits (in 

2011$) of approximately $2.8 billion for the rate-based approach and $3.3 billion for the massbased approach (3 percent model average). For the rate-based approach, the air pollution health 

co-benefits in 2020 are estimated to be $0.7 billion to $1.8 billion (2011$) for a 3 percent 

discount rate and $0.64 billion to $1.7 billion (2011$) for a 7 percent discount rate. For the massbased approach, the air pollution health co-benefits in 2020 are estimated to be $2.0 billion to 

$4.8 billion (2011$) for a 3 percent discount rate and $1.8 billion to $4.4 billion (2011$) for a 7 

percent discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE 

program and participant costs and MRR costs in 2020, are approximately $2.5 billion for the 

rate-based approach and $1.4 billion for the mass-based approach (2011$). The quantified net 

benefits (the difference between monetized benefits and compliance costs) in 2020 are estimated 

to range from $1.0 billion to $2.1 billion (2011$) for the rate-based approach and from $3.9 

billion to 6.7 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model 

average). 

The EPA estimates that, in 2025, the proposal will yield monetized climate benefits (in 

2011$) of approximately $10 billion for the rate-based approach and $12 billion for the massbased approach (3 percent model average). For the rate-based approach, the air pollution health 

co-benefits in 2025 are estimated to be $7.4 billion to $18 billion (2011$) for a 3 percent 

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discount rate and $6.7 billion to $16 billion (2011$) for a 7 percent discount rate. For the massbased approach, the air pollution health co-benefits in 2025 are estimated to be $7.1 billion to 

$17 billion (2011$) for a 3 percent discount rate and $6.5 billion to $16 billion (2011$) for a 7 

percent discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE 

program and participant costs and MRR costs in 2025, are approximately $1.0 billion for the 

rate-based approach and $3.0 billion for the mass-based approach (2011$). The quantified net 

benefits (the difference between monetized benefits and compliance costs) in 2025 are estimated 

to range from $17 billion to $27 billion (2011$) for the rate-based approach and $16 billion to 

$26 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model 

average). 

The EPA estimates that, in 2030, the proposal will yield monetized climate benefits (in 

2011$) of approximately $20 billion for the rate-based approach and $20 billion for the massbased approach (3 percent model average). For the rate-based approach, the air pollution health 

co-benefits in 2030 are estimated to be $14 billion to $34 billion (2011$) for a 3 percent discount 

rate and $13 billion to $31 billion (2011$) for a 7 percent discount rate. For the mass-based 

approach, the air pollution health co-benefits in 2030 are estimated to be $12 billion to $28 

billion (2011$) for a 3 percent discount rate and $11 billion to $26 billion (2011$) for a 7 percent 

discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE program 

and participant costs and MRR costs in 2030, are approximately $8.4 billion for the rate-based 

approach and $5.1 billion for the mass-based approach (2011$). The quantified net benefits (the 

difference between monetized benefits and compliance costs) in 2030 are estimated to range 

from $26 billion to $45 billion (2011$) for the rate-based approach and from $26 billion to $43 

billion (2011$) for the mass-based approach, using a 3 percent discount rate (model average). 

Table 1-8 and Table 1-9 of this RIA provides the estimates of the climate benefits, health cobenefits, compliance costs and net benefits of the proposal for rate-based and mass-based federal 

plan approaches, respectively. 

There are additional important benefits that the EPA could not monetize. Due to current 

data and modeling limitations, our estimates of the benefits from reducing CO2 emissions do not 

include important impacts like ocean acidification or potential tipping points in natural or 

managed ecosystems. Unquantified benefits also include climate benefits from reducing 

emissions of non-CO2 GHGs (e.g., nitrous oxide and methane) and co-benefits from reducing 

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direct exposure to SO2, NOX, and HAP (e.g., mercury), as well as from reducing ecosystem 

effects and visibility impairment. Based upon the foregoing discussion, it remains clear that the 

benefits of this proposed action are substantial, and far exceed the costs. Additional details on 

benefits, costs, and net benefits estimates are provided in this RIA. 

 2.2 Paperwork Reduction Act 

The information collection requirements in this rule have been submitted for approval to 

OMB under the PRA. The Information Collection Request (ICR) document prepared by the EPA 

has been assigned EPA ICR number 2526.01. You can find a copy of the ICR in the docket for 

this rule, and it is briefly summarized here. The information collection requirements are not 

enforceable until approved by OMB. 

This rule does not directly impose specific requirements on state and U.S. territory 

governments with affected EGUs. The rule also does not impose specific requirements on tribal 

governments that have affected EGUs located in their area of Indian country. This rule does 

impose specific requirements on EGUs located in states, U.S. territories or areas of Indian 

country. 

The information collection activities in this proposed rule are consistent with those 

activities defined under the Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units finalized on August 3, 2015. The information 

collection requirements in this proposed rule have been submitted for approval to the Office of 

Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. 

The ICR document prepared by the EPA has been assigned EPA ICR number 2526.01. You can 

find a copy of the ICR in the docket for this rule, and it is briefly summarized here. 

Aside from reading and understanding the rule, this proposed action would impose 

minimal new information collection burden on affected EGUs beyond what those affected EGUs 

would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously 

approved the information collection requirements contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR part 98) under the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060–0626 and 

2060– 0629, respectively. Apart from certain reporting costs based on requirements in the NSPS 

General Provisions (40 CFR part 60, subpart A), which are mandatory for all owners/operators 

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subject to CAA section 111 national emission standards, there are no new information collection 

costs, as the information required by this proposed rule is already collected and reported by other 

regulatory programs. The recordkeeping and reporting requirements are specifically authorized 

by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the 

recordkeeping and reporting requirements for which a claim of confidentiality is made is 

safeguarded according to agency policies set forth in 40 CFR part 2, subpart B. 

Although EPA cannot determine at this time how many affected EGU respondents will 

submit information under the federal plan, EPA has estimated an “upper bound” burden estimate 

for this ICR that estimates burden should every affected EGU read and understand the rule. This 

is the only potential respondent activity that would be required under the 3-year period following 

publication of the final federal plan, so there are no obligations to respond in this period. The 

results of this “upper bound” estimate of federal plan burden are presented below: 

Respondents/affected entities: 1,028 

Respondents’ obligation to respond: Not applicable, no responses are required during the 

period covered by the ICR. 

Estimated number of respondents: Unknown at this time, but have assumed all affected 

entities are respondents for an upper bound estimate. 

Frequency of response: None, no responses are required during the period covered by the 

ICR. 

Total estimated burden: 17,133 hours (per year). Burden is defined at 5 CFR 1320.3(b). 

Total estimated cost: $1,706,501 (per year) 

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. 

Submit your comments on the agency’s need for this information, the accuracy of the 

provided burden estimates and any suggested methods for minimizing respondent burden to the 

EPA using the docket identified at the beginning of this rule. You may also send your ICRrelated comments to OMB’s Office of Information and Regulatory Affairs via email to 

oria_submissions@omb.eop.gov, Attention: Desk Officer for the EPA. Since OMB is required to 

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make a decision concerning the ICR between 30 and 60 days after receipt, OMB must receive 

comments no later than 30 days after the date of publication in the Federal Register. The EPA 

will respond to any ICR-related comments in the final rule. 

2.3 Initial Regulatory Flexibility Analysis 

The Regulatory Flexibility Act (RFA; 5 U.S.C.§ 601 et seq.), as amended by the Small 

Business Regulatory Enforcement Fairness Act (Public Law No. 104-121), provides that 

whenever an agency is required to publish a general notice of proposed rulemaking, it must 

prepare and make available an initial regulatory flexibility analysis (IRFA), unless it certifies that 

the proposed rule, if promulgated, will not have a significant economic impact on a substantial 

number of small entities (5 U.S.C. § 605[b]). Small entities include small businesses, small 

organizations, and small governmental jurisdictions. An IRFA describes the economic impact of 

the proposed rule on small entities and any significant alternatives to the proposed rule that 

would accomplish the objectives of the rule while minimizing significant economic impacts on 

small entities. Pursuant to section 603 of the RFA, the EPA prepared an initial regulatory 

flexibility analysis (IRFA) that examines the impact of the proposed rule on small entities along 

with regulatory alternatives that could minimize that impact. 

2.3.1 Reasons why Action is Being Considered 

On August 3, 2015, the EPA finalized the Clean Power Plan EGs for existing fossil-fuel 

fired EGUs (40 CFR part 60, subpart UUUU) under authority of section 111 of the CAA. The 

Guidelines apply to existing fossil-fuel fired EGUs, i.e., those that were in operation or had 

commenced construction before January 8, 2014. States with existing EGUs subject to the 

guidelines are required to submit to the EPA by September 6, 2016, a state plan that implements 

the EGs. States may also make initial plan submittals in lieu of a complete state plan, in which 

case extensions will be granted until September 6, 2018 (40 CFR &&&).30 As discussed in 

section VI.D of the preamble, Indian Tribes may, but are not required to, submit tribal plans. 

Once the EPA finds that a state has failed to submit a plan, or disapproves a state plan,31 section 

 

30 See Section VII of the preamble for additional information on proposed changes to 40 CFR 60.27 to provide 

enhancements and flexibilities to the agency’s process for review and action on state plans and promulgation of 

federal plans. 

31 If a state has submitted a complete plan, then the EPA will go through a public notice and comment process to 

fully or partially approve or disapprove the state plan. 

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111 of the CAA and 40 CFR 60.27 require the EPA to develop, implement, and enforce a federal 

plan for existing EGUs located in that state. In addition, CAA section 301(d)(2) authorizes the 

Administrator to treat an Indian Tribe in the same manner as a state for this EGU requirement. 

See 40 CFR 49.3; see also “Indian Tribes: Air Quality Planning and Management,” hereafter 

“Tribal Authority Rule,” (63 FR 7254, February 12, 1998). As discussed in section VI.D of the 

preamble, the agency in this action is proposing a necessary or appropriate finding for the 

affected EGUs in several areas of Indian country and is proposing the federal plan for these 

affected EGUs. 

The agency believes it is appropriate to propose the federal plan at this time for any states 

that may ultimately be found to have failed to submit a plan, or had their plan disapproved by the 

EPA. For some states in this situation, the federal plan may be no more than an interim measure 

to ensure that congressionally mandated emission standards under authority of section 111 of the 

CAA are implemented until they can get an approved plan in place. Other states may choose to 

rely on the federal plan and would not need to develop their own plan. This proposal also serves 

as two proposed model trading rules which states can adopt or tailor for adoption as their state 

plan. 

2.3.2 Statement of Objectives and Legal Basis for Proposed Rules 

The EPA is proposing this rulemaking for a federal plan to implement greenhouse gas 

Emission Guidelines for existing fossil fuel-fired electric generating units (EGUs). The emission 

guidelines were proposed in June 2014 as the Carbon Pollution Emission Guidelines for Existing 

Stationary Sources: Electric Utility Generating Units (79 FR 34830; the Clean Power Plan). This 

plan is part of the President’s Climate Action Plan announced in June of 2013 to reduce carbon 

emissions from the power sector by 30 percent below 2005 levels. This federal plan serves to: 1) 

provide a model rule that states can tailor for implementation, and 2) set in place a plan that EPA 

can implement for states that do not develop an approvable state plan. The EPA sees this federal 

plan as an interim measure to ensure that congressionally mandated emission standards under 

authority of section 111 of the CAA are implemented until states assume their role as the 

preferred implementers of the emission guidelines. 

The final Clean Power Plan Emission Guidelines are related to but separate from the 

proposed federal plan. The final Emission Guidelines will detail the carbon dioxide (CO2) 

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reduction goals for sources by state. The purpose of the proposed federal plan is to lay out 

mechanisms to achieve reductions in CO2 emissions from affected EGUs that are not covered by 

an EPA-approved state plan. The EPA is considering a range of options and approaches through 

which affected EGUs would meet a rate-based goal or a mass-based equivalent. The EPA intends 

to incorporate flexibility to the extent possible into the proposed federal plan so affected units 

can achieve these reductions in a cost-effective way. 

2.3.3 Description and Estimate of Affected Small Entities 

EPA conducted this regulatory flexibility analysis at the ultimate (i.e., highest) level of 

ownership, evaluating parent entities with the largest share of ownership in at least one 

potentially-affected EGU included in EPA’s Base Case using the Integrated Planning Model 

(IPM) v.5.15, used in this RIA.32 This analysis draws on the “parsed” unit-level estimates using 

IPM results for 2030, as well as ownership, employment, and financial information for the 

potentially affected small entities drawn from other resources described in more detail below. 

EPA chose to examine potential impacts in 2030 because that is when the emission performance 

goals are required to be fully achieved. Also, as presented in this RIA, 2030 is the year where the 

estimated annual compliance costs for the contiguous U.S. are at their highest.33 

This action proposes a federal plan under section 111(d) of the CAA for the control of 

CO2, a greenhouse gas pollutant, from certain large emitting fossil-fuel fired power plants, in the 

event that some states do not adopt their own plans. Specifically, the EPA is proposing 

approaches in the form of mass- and rate-based trading options that provide flexibility in 

implementing emission standards for a state’s affected EGUs. Both proposed approaches to the 

federal plan would require affected EGUs to meet emission standards set using the CO2 emission 

performance rates in the emission guidelines. The federal plan will achieve the same levels of 

emissions performance as required of state plans under the emission guidelines. 

However, at the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan or adopt a model rule. Because of this lack of information, 

for this RIA, the EPA has chosen to examine two federal plan approach scenarios where all 

 

32 See 1.4.1 of this RIA for more detail on the IPM base case used for this analysis. Detailed documentation for IPM 

v.5.15 is available at: http://www.epa.gov/powersectormodeling. 

33 See Section 1.5.2 of this RIA. 

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states of the contiguous U.S. will be regulated under a federal plan or a model rule. The first 

federal plan approach we examine in this RIA assumes all states in the contiguous U.S. are 

regulated under a rate-based federal plan or model rule. The second federal plan approach we 

examine assumes all contiguous states are regulated under a mass-based federal plan or model 

rule. We use these scenarios to inform this IRFA. 

As with the analysis in this RIA, the IRFA proceeds by examining potential costs to small 

entities under both the rate-based and mass-based approach, again under the strong assumption 

that all affected EGUs are regulated under a federal plan. The parsed unit-level estimates used in 

this IRFA are consistent with the analysis presented elsewhere in this RIA. These 2030 year IPM 

files can also be found in the docket for the rulemaking. 

EPA identified the size of ultimate parent entities by using the Small Business 

Administration (SBA) size threshold guidelines.34 The criteria for size determination vary by the 

organization/operation category of the ultimate parent entity, as follows: 

• Privately-owned (non-government) entities (see Table 2-1) 

o Privately-owned entities include investor-owned utilities, non-utility entities, and 

entities with a primary business other than electric power generation. 

o For entities with electric power generation as a primary business, small entities 

are those with less than the threshold number of employees specified by SBA for 

each of the relevant North American Industry Classification System (NAICS) 

sectors (NAICS 2211). 

o For entities with a primary business other than electric power generation, the 

relevant size criteria are based on revenue, assets, or number of employees by 

NAICS sector.35

• Publicly-owned entities 

 

34 U.S. Small Business Administration (SBA). 2014. Small Business Size Standards. Effective as of July 14, 2014. 

See: http://www.sba.gov/sites/default/files/Size_Standards_Table.pdf. 

35 Certain affected EGUs are owned by ultimate parent entities whose primary business is not electric power 

generation. 

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o Publicly-owned entities include federal, state, municipal, and other political 

subdivision entities. 

o The federal and state governments were considered to be large. Municipalities and 

other political units with population fewer than 50,000 were considered to be 

small. 

• Rural Electric Cooperatives 

o Small entities are those with fewer than the threshold level of employees or 

revenue specified by SBA for each of the relevant NAICS sectors. 

EPA examined affected EGUs included in EPA’s 2030 projections and identified the 

associated power plants. Next, we determined power plant ownership information, including the 

name of associated owning entities, ownership shares, and each entity’s type of ownership. EPA 

primarily used data from SNL and Ventyx, supplemented by limited research using publicly 

available data.36 Majority owners of power plants with affected EGUs were categorized as one of 

the seven ownership types.37 These ownership types are: 

1. Investor-Owned Utility (IOU): Investor-owned assets (e.g., a marketer, independent 

power producer, financial entity) and electric companies owned by stockholders, etc.

2. Cooperative (Co-Op): Non-profit, customer-owned electric companies that generate 

and/or distribute electric power.

3. Municipal: A municipal utility, responsible for power supply and distribution in a small 

region, such as a city.

4. Sub-division: Political subdivision utility is a county, municipality, school district, 

hospital district, or any other political subdivision that is not classified as a municipality 

under state law.

5. Private: Similar to an investor-owned utility, however, ownership shares are not openly 

traded on the stock markets.

6. State: Utility owned by the state.

 

36 SNL Financial data covers the energy market and other industries. For more information, see: www.snl.com. The 

Ventyx database consists of detailed ownership and corporate affiliation information at the EGU level. For more 

information, see: www.ventyx.com. 

37 Throughout this analysis, EPA refers to the owner with the largest ownership share as the “majority owner” even 

when the ownership share is less than 51 percent. 

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7. Federal: Utility owned by the federal government.

Required ownership information could not be determined for two committed units that 

are represented in the IPM base case modeling for this proposed rule, preventing their inclusion 

in this analysis.38

Next, EPA used the Hoover’s online database to identify the ultimate owners of power 

plant owners identified in the SNL and Ventyx databases. This was necessary, as many majority 

owners of power plants (listed in SNL or Ventyx) are themselves owned by other ultimate parent 

entities (listed in Hoover’s).39 In these cases, the ultimate parent entity was identified via 

Hoover’s, whether domestically or internationally owned. 

EPA followed SBA size standards to determine which non-government ultimate parent 

entities should be considered small entities in this analysis. These SBA size standards are 

specific to each industry, each having a threshold level of either employees, revenue, or assets 

below which an entity is considered small. SBA guidelines list all industries, along with their 

associated NAICS code and SBA size standard. Therefore, it was necessary to identify the 

specific NAICS code associated with each ultimate parent entity in order to understand the 

appropriate size standard to apply. Data from Hoover’s was used to identify the NAICS codes for 

most of the ultimate parent entities.40 In many cases, an entity that is a majority owner of a power 

plant is itself owned by an ultimate parent entity with a primary business other than electric 

power generation. Therefore, it was necessary to consider SBA entity size guidelines for the 

range of NAICS codes listed in Table 2-1. This table represents the range of NAICS codes and 

areas of primary business of ultimate parent entities which are majority owners of potentially 

affected EGUs in EPA’s IPM base case. 

 

38 The ORIS codes of these two units are 83609 and 83921. Without knowledge of entity type and size, it was not 

possible to accurately estimate revenue or costs impacts. An ORIS code is an identifying number assigned by the 

U.S. Energy Information Administration to power plants owned by utilities. 

39 The Hoover’s Inc. online platform includes company records that can contain NAICS codes, number of 

employees, revenues, and assets. For more information, see: http://www.hoovers.com. 

40 In the case of two entities, NAICS codes could not be located in Hoover’s, so publicly available information was 

used to determine the primary area of business for the ultimate parent entities. 

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Table 2-1. SBA Size Standards by NAICS Code 

Notes: 1) Based on size standards effective at the time EPA conducted this analysis (SBA size standards, effective 

July 14, 2014) 2) Small business size standards are not established for the Public Administration industry (NAICS 

code 921110). It is assumed that a comparable NAICS private sector industry is Fossil Fuel Electric Power 

Generation (NAICS code 221112). Therefore, for this analysis, the NAICS code 921110 is assumed to have a size 

standard of 750 employees. 

Source: SBA, 2014 

NAICS 

Code NAICS Description SBA Size Standard

211111 Crude Petroleum and Natural Gas Extraction 500 employees

211112 Natural Gas Liquid Extraction 500 employees

212111 Bituminous Coal and Lignite Surface Mining 500 employees

212221 Gold Ore Mining 500 employees

213112 Support Activities for Oil and Gas Operations $38.5 million in revenue

221111 Hydroelectric Power Generation 500 employees

221112 Fossil Fuel Electric Power Generation 750 employees

221113 Nuclear Electric Power Generation 750 employees

221118 Other Electric Power Generation 250 employees

221121 Electric Bulk Power Transmission and Control 500 employees

221122 Electric Power Distribution 1,000 employees

221210 Natural Gas Distribution 500 employees

238210 Electrical Contractors and Other Wiring Installation Contractors $15 million in revenue

238290 Other Building Equipment Contractors $15 million in revenue

324110 Petroleum Refineries 1,500 employees

325120 Industrial Gas Manufacturing 1,000 employees

325211 Plastics Material and Resin Manufacturing 750 employees

325320 Pesticide and Other Agricultural Chemical Manufacturing 500 employees

331110 Iron and Steel Mills and Ferroalloy Manufacturing 1,000 employees

331313 Alumina Refining and Primary Aluminum Production 1,000 employees

333613 Mechanical Power Transmission Equipment Manufacturing 500 employees

333999 All Other Miscellaneous General Purpose Machinery Manufacturing 500 employees

335312 Motor and Generator Manufacturing 1,000 employees

335999 All Other Miscellaneous Electrical Equipment and Component Manufacturing 500 employees

423610 Electrical Apparatus and Equipment, Wiring Supplies, and Related Equipment Merchant 

Wholesalers 100 employees

424720 Petroleum and Petroleum Products Merchant Wholesalers (except Bulk Stations and Terminals) 100 employees

454310 Fuel Dealers 50 employees

486210 Pipeline Transportation of Natural Gas $27.5 million in revenue

522110 Commercial Banking $550 million in assets

522220 Sales Financing $38.5 million in revenue

522320 Financial Transactions Processing, Reserve, and Clearinghouse Activities $38.5 million in revenue

523120 Securities Brokerage $38.5 million in revenue

523910 Miscellaneous Intermediation $38.5 million in revenue

523920 Portfolio Management $38.5 million in revenue

523930 Investment Advice $38.5 million in revenue

524113 Direct Life Insurance Carriers $38.5 million in revenue

524126 Direct Property and Casualty Insurance Carriers 1,500 employees

524210 Insurance Agencies and Brokerages $7.5 million in revenue

525110 Pension Funds $32.5 million in revenue

525120 Health and Welfare Funds $32.5 million in revenue

525990 Other Financial Vehicles $32.5 million in revenue

541611 Administrative Management and General Management Consulting Services $15 million in revenue

551112 Offices of Other Holding Companies $20.5 million in revenue

561110 Office Administrative Services $7.5 million in revenue

813910 Business Associations $7.5 million in revenue

921110 Public Administration 750 employees

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EPA compared the relevant entity size criterion for each ultimate parent entity to the SBA 

threshold value noted in Table 2-1. We used the following data sources and methodology to 

estimate the relevant size criterion values for each ultimate parent entity: 

1. Employment, Revenue, and Assets: EPA used the Hoover’s database as the primary 

source for information on ultimate parent entity employee numbers, revenue, and assets.41

In parallel, EPA also considered estimated revenues from affected EGUs based on 

analysis of parsed-file estimates for 2030.42 EPA assumed that the ultimate parent entity 

revenue was the larger of the two revenue estimates. In limited instances, supplemental 

research was also conducted to estimate an ultimate parent entity’s number of employees, 

revenue, or assets. 

2. Population: Municipal entities are defined as small if they serve populations of less than 

50,000. EPA primarily relied on data from the Ventyx database and the U.S. Census 

Bureau to inform this determination. Supplemental research of individual municipalities 

was also conducted in some instances. 

Ultimate parent entities for which the relevant measure is less than the SBA size criterion 

were identified as small entities and carried forward in this analysis. In the case of six entities, 

data limitations prevented the comparison of entities against their appropriate SBA size 

standards. For the purposes of this analysis, EPA assumed that these six entities are small 

entities.43

EPA identified 223 potentially affected EGUs owned by 74 small entities included in 

EPA’s 2030 projections. Fifty-nine of these potentially affected EGUs are projected to no longer 

be operating by 2030 in the Base Case of EPA’s version of IPM v.5.15.44 Twenty-four small 

 

41 Estimates of sales were used in lieu of revenue estimates when revenue data was unavailable. 

42 The methodology for the analysis of IPM results is detailed later in this IRFA. 

43 Generation from potentially affected EGUs owned by these six entities represents less than two percent of total 

generation from potentially affected EGUs owned by small entities under EPA’s base case projections. 

44 Detailed documentation for IPM v.5.15 is available at: http://www.epa.gov/powersectormodeling. 

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entities are projected to have all of their potentially affected EGUs cease operation by 2030 in 

this Base Case. 

2.3.4 Compliance Cost Impact Estimates 

2.3.4.1 Methodology for Estimating Impacts on Small Entities 

This section presents the methodology used in this analysis for estimating the compliance 

costs of this proposed rule for small entities. For the purposes of this IRFA, EPA estimated net 

compliance costs for individual EGUs of the proposed rule using the following equation: 

Cnet compliance cost = ∆ Coperating + annualized capital + ∆ Cfuel + ∆ Cdemand-side energy efficiency + ∆ R 

where C represents the components of cost as labeled, R represents revenue, and ∆ indicates the 

calculation of difference between the base case and the federal plan approach under examination. 

The specific meaning of these variables is discussed below. 

This approach to estimate net compliance costs is consistent with previous proposed 

power sector regulations that required IRFAs, such as the proposed Mercury and Air Toxics 

Rule.45 However, there is an additional component in the net compliance cost equation: the 

change in the program costs of demand-side energy efficiency programs. Investment in demandside energy efficiency results in lower electricity demand, and consequently fewer emissions as 

production is reduced to meet the lower demand, an important emission-reduction strategy 

modelled in the rate-based and mass-based federal plan approaches. 

Because this analysis evaluates the net compliance costs as a sum of the costs changes 

associated with compliance choices as well as changes in electricity revenues, it captures 

potential net compliance cost increases or decreases. For example, if under the proposed rule 

entities increase revenue more than costs, the net compliance costs will be negative. As a result, 

the approach used here to estimate net compliance costs is well-equipped to evaluate the 

potential distributional consequences of the proposed regulation. 

For this analysis, EPA used the parsed unit-level estimates mentioned before to estimate 

three of the four components of the net compliance cost equation above: the change in operating 

 

45 U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis of the Proposed Toxics 

Rule: Final Report. Office of Air Quality Planning and Standards, Health and Environmental Impacts Division, 

Research Triangle Park, NC. Available at: http://www.epa.gov/ttnecas1/regdata/RIAs/ToxicsRuleRIA.pdf. 

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and annualized capital costs, the change in fuel costs, and the change in revenue, where all 

changes are estimated as the difference between the base case and federal plan scenario. These 

impacts were then summed for each small entity, adjusting for ownership share.46 As described 

momentarily, additional analysis was performed to estimate the change in costs of demand-side 

energy efficiency that factors in IPM-projected outputs but is not directly an output of the model. 

These individual components of compliance cost were estimated as follows: 

1. Operating and capital costs: Using the IPM parsed estimates for the base case and the 

rate-based and mass-based federal plan approaches, EPA evaluated changes in operating 

and capital costs at the EGU level. The equations for calculating operating and capital 

costs were adopted from technology assumptions used in EPA’s version of IPM version 

5.15. The model calculates the capital cost (in $/MW); the fixed operation and 

maintenance (O&M) cost (in $/MW-year); and the variable O&M cost (in $/MWh). 

2. Fuel costs: Using the IPM parsed estimates for the base case and the rate-based and 

mass-based federal plan approaches, EPA evaluated projected changes in fuel cost at the 

EGU level. These projected fuel costs are based on estimated EGU-level fuel input (in 

million British thermal units, MMBtu) and delivered fuel prices ($/MMBtu). 

3. Demand-side energy efficiency program costs: Demand-side energy efficiency 

program costs are estimated and allocated to affected EGUs outside of IPM in this 

analysis. For this analysis, we assumed that IOUs, Co-Ops, Municipals, and SubDivisions are utilities that receive revenues on the basis of retail electricity rates. Retail 

electricity in this and related EPA analyses contain an energy efficiency surcharge. The 

surcharge reflects the standard mechanism by which utilities collect revenue from their 

customers to pay for energy efficiency programs. Such surcharges are approved for 

inclusion in rates by state utility commission for IOUs or the equivalent authority (e.g., 

municipal or cooperative utility board of directors) for other utility types. To be 

consistent, EPA assumes that these utilities will incur an energy efficiency surcharge as a 

cost in this analysis. The demand-side energy efficiency surcharge is state specific, being 

 

46 Unit-level cost impacts are adjusted for ownership shares for individual small entities, so as not to overestimate 

burden on each entity. 

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the estimated state demand-side energy efficiency program costs47 divided by projected 

total state sales. The cost in this analysis is the surcharge multiplied by projected sales 

from affected EGUs.48 In contrast, entities of the type Private are not assessed demandside energy efficiency program costs in this analysis.49 This distinction is made because 

EPA assumes that Private entities own non-utility EGUs that will earn wholesale 

electricity rates. Wholesale electricity rates do not include a demand-side energy 

efficiency surcharge in this or related EPA analyses.

4. Revenues: EPA estimated the value of electricity generated by multiplying the projected 

electricity generation from EPA’s IPM modeling results with the regional retail 

electricity price estimates ($/MWh), for all entities except those categorized as Private in 

Ventyx. For private entities, EPA used projected wholesale electricity price instead of 

retail electricity price estimates because most of the private entities are independent 

power producers (IPP). Since IPPs sell their electricity to wholesale purchasers and do 

not own transmission facilities, their revenue was estimated with wholesale electricity 

prices. 

2.3.4.2 Results 

This section presents the estimated net compliance cost impacts of the proposed rule on 

small entities in 2030 based on the following endpoints: 

• net compliance costs estimated for the proposed rule for potentially affected small 

entities, and 

 

47 In practice, the costs of demand-side energy efficiency programs include the costs to the utilities that are funding 

the programs (known as the program costs) and the additional cost to the end-user purchasing a more energy 

efficient technology (known as the participant costs). Based upon a literature review, the analysis supporting this 

proposed rule and the Clean Power Plan Final Rule, total costs are assumed to be divided evenly, 50 percent each, 

between program costs and participant costs. This IRFA includes only the program costs expected to be incurred 

by utilities. For more detail on how the demand-side energy efficiency costs are estimated, see U.S. EPA. 2015. 

Technical Support Document (TSD) the Final Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units. Demand-Side Energy Efficiency. 

48 For these entity types (i.e., IOUs, Co-Ops, Municipals, and Sub-Divisions), projected sales is estimated to be 7.5 

percent less than generation. This 7.5 percent reduction is added to account for estimated transmission losses. 

49 Note that in this context, “Private” is one of seven distinct ownership types introduced earlier in this chapter. 

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• the ratio of small entity compliance cost impacts to revenues from electricity generation 

at affected EGUs 

It is worth noting again that the results in this section are based on the assumption made 

for this analysis that all affected EGUs owned by small entities are subject to this proposed rule. 

EPA chose to examine this scenario because, at the time of this proposal, the EPA has no 

information on whether any or how many states will require a federal plan. 

The number of affected small entities by ownership type and the potential impact of the 

federal plan approaches are summarized in Tables 2-2 through 2-5. These tables are specific to 

either the rate-based federal plan approach (i.e., rate-based), or mass-based federal plan approach 

(i.e., mass-based). All costs are presented in 2011 dollars. 

EPA estimated the annualized net compliance cost to potentially affected small entities in 

2030 to be approximately $364 million under the rate-based approach, and $404 million under 

the mass-based approach. Results for small entities discussed here do not fully account for the 

reality that electricity markets are regulated in parts of the country. Entities operating in 

regulated or cost-of-service markets are likely able to recover compliance costs through rate 

adjustments; as a result these costs can be viewed as likely being over-estimates for this set of 

utilities.50

 

50This is similarly discussed in previous EPA analyses. For example, see section 7.4.5.2 within the Regulatory 

Impact Analysis for the Final Mercury and Air Toxics Standards. Available at: 

http://www.epa.gov/ttnecas1/regdata/RIAs/matsriafinal.pdf. 

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Table 2-2. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Rate-Based Federal Plan Approach in 2030 

EGU 

Ownership 

Type 

Number of 

Potentially 

Affected Entities 

Number of Entities 

Projected to Withdraw all 

Affected Units in Base Case 

Additional Entities Projected 

to Withdraw all Affected Units 

under Rate-Based Approach 

Co-Op 17 3 1 

IOU 8 3 1 

Municipal 24 13 1 

Private 19 5 2 

Sub-Division 6 0 2 

Grand Total 74 24 7 

Notes: 1) The number of potentially affected entities reflects those with affected EGUs that are modeled within IPM 

in 2030. 2) In this context, the term withdraw signifies that EGUs are represented in the 2030 IPM results but do not 

generate electricity. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

Table 2-3. Projected Impact on Small Entities in 2030 under Rate-Based Federal Plan 

Approach 

EGU 

Ownership 

Type

Total Net 

Compliance Costs 

(2011$ millions) 

Number of Small Entities 

with Net Compliance Costs 

> 1% of Generation 

Revenues 

Number of Small Entities 

with Net Compliance Costs 

> 3% of Generation 

Revenues 

Co-Op 109 8 3 

IOU 186 4 4 

Municipal 17 7 5 

Private 34 11 9 

Sub-Division 18 6 2 

Grand Total 364 36 23 

Notes: 1) The total number of entities with costs greater than 1 or 3 percent of revenues includes only entities 

experiencing positive net compliance costs. 2) Costs are compared to generation revenues from affected EGUs, and 

do not consider additional revenues some entities may earn from other sources. 3) Nine small entities are estimated 

to have net compliance cost savings greater than 3 percent of generation revenues from affected sources. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

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Table 2-4. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Mass-Based Federal Plan Approach in 2030 

EGU 

Ownership 

Type 

Number of 

Potentially 

Affected Entities 

Number of Entities 

Projected to Withdraw all 

Affected Units in Base Case 

Additional Entities Projected 

to Withdraw all Affected 

Units under Mass-Based 

Approach 

Co-Op 17 3 1 

IOU 8 3 1 

Municipal 24 13 1 

Private 19 5 2 

Sub-Division 6 0 0 

Grand Total 74 24 5 

Notes: 1) The number of potentially affected entities reflects those with affected EGUs that are modeled within IPM 

in 2030. 2) In this context, the term withdraw signifies that EGUs are represented in the 2030 IPM results but do not 

generate electricity. 

Source: U.S. EPA analysis, based on IPM modeling results. 

Table 2-5. Projected Impact on Small Entities in 2030 under Mass-Based Federal Plan 

Approach 

EGU 

Ownership 

Type 

Total Net 

Compliance Costs 

(2011$ millions) 

Number of Small Entities 

with Net Compliance Costs 

> 1% of Generation 

Revenues 

Number of Small Entities 

with Net Compliance Costs 

> 3% of Generation 

Revenues 

Co-Op 133 10 4 

IOU 179 3 3 

Municipal 50 5 5 

Private 36 8 7 

Sub-Division 7 4 2 

Grand Total 404 30 21 

Notes: 1) The total number of entities with costs greater than 1 or 3 percent of revenues includes only entities 

experiencing positive net compliance costs. 2) Costs are compared to generation revenues from affected EGUs, and 

do not consider additional revenues some entities may earn from other sources. 3) Eleven small entities are 

estimated to have net compliance cost savings greater than 3 percent of generation revenues from affected sources. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

As noted earlier, there are 74 small entities with potentially affected EGUs that are 

modeled in the IPM base case in 2030. Of these, 24 small entities are projected to withdraw all of 

their potentially affected EGUs from operation under base case conditions. This leaves 50 small 

entities with potentially affected EGUs that are projected to be generating electricity in 2030. 

Under the rate-based federal plan approach, 7 of these 50 small entities are projected to withdraw 

all of their potentially affected EGUs from operation by 2030. Under the mass-based federal plan 

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approach, 5 of these 50 small entities are projected withdraw all of their potentially affected 

EGUs from operation by 2030. 

Under the rate-based federal plan approach, 23 small entities are projected to incur net 

compliance costs greater than 3 percent of generation revenues from their potentially affected 

EGUs. In contrast, 9 entities are estimated to have net compliance cost savings greater than 3 

percent of their generation revenues from affected EGUs. Under the mass-based federal plan 

approach, 21 small entities are projected to incur net compliance costs greater than 3 percent of 

generation revenues from their potentially affected EGUs. In contrast, 11 entities are estimated to 

have net compliance cost savings greater than 3 percent of generation revenues from their 

affected EGUs. 

The separate components of the net compliance costs for small entities under the 

proposed rule are summarized in Table 2-6 and Table 2-7. 

Table 2-6. Incremental Costs in 2030 under the Rate-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) 

EGU 

Ownership 

Type 

Capital + 

Operating + Fuel 

Costs ($MM) 

Energy Efficiency 

Program Costs 

($MM) 

Change in 

Electricity 

Revenue ($MM) 

Total Net 

Compliance 

Costs 

 A B C =A+B-C 

Co-Op (79) 87 (102) 109 

IOU 78 93 (15) 186 

Municipal (26) 25 (19) 17 

Private (7) 0 (40) 34 

Sub-Division (68) 16 (70) 18 

Grand Total (102) 221 (246) 364 

Note: Totals may not add due to rounding. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

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Table 2-7. Incremental Costs in 2030 under the Mass-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) 

EGU 

Ownership 

Type 

Capital + 

Operating + Fuel 

Costs ($MM) 

Energy Efficiency 

Program Costs 

($MM) 

Change in 

Electricity 

Revenue ($MM) 

Total Net 

Compliance 

Costs 

 A B C =A+B-C 

Co-Op (178) 84 (228) 133 

IOU (17) 91 (104) 179 

Municipal (64) 23 (91) 50 

Private (2) 0 (38) 36 

Sub-Division (38) 18 (27) 7 

Grand Total (299) 215 (488) 404 

Note: Totals may not add due to rounding. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

The change in electricity revenue under the federal plan approaches take into account 

both the profit lost from units that do not operate and the difference in revenue for operating 

units. The cost of withdrawing a unit as uneconomic is estimated as the base case profit that is 

foregone by not operating under a federal plan approach. One of the primary drivers of the cost 

impacts is the reduced revenue due to decreased electricity sales related to the modeled 

implementation of demand-side energy efficiency measures. The EPA solicits comment on: 1) 

whether it is likely that small entities would consider demand-side strategies as they responded to 

a federal plan, 2) the appropriateness of considering the demand-side strategies in the analysis, 

and 3) if demand-side energy efficiency measures are considered in the final analysis, whether it 

is appropriate to consider them as a cost for a municipality or city-owned utility, as this reduced 

revenue will translate to direct cost savings for members of the community served by the 

affected units. 

There are uncertainties and limitations in this analysis that may result in estimates that 

diverge from what we might see in reality. Some of these have already been noted. Below is a 

listing of important considerations when interpreting this analysis. 

• At the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan. The rate-based and mass-based federal 

plan approaches analyzed in this IRFA are based on a scenario where all states of 

the contiguous U.S. will be regulated under a federal plan. 

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• Results for small entities discussed here do not fully account for the reality that 

electricity markets are regulated in parts of the country. Entities operating in 

regulated or cost-of-service markets are likely able to recover compliance costs 

through rate adjustments; as a result these costs can be viewed as likely being 

over-estimates for this set of utilities. 

• Small entities owning NGCC EGUs operating in competitive markets may be able 

to recover compliance costs if steam EGUs are setting the marginal price. 

• EPA has not factored in consideration of allowances that would be distributed to 

affected entities nor revenue that could be generated from the sale of ERCs in its 

analysis. EPA takes comment on how these factors should be considered in the 

final analysis. 

• In this analysis, estimated state demand-side energy efficiency program costs are 

allocated to utility EGUs owned by IOUs, Co-Ops, Municipals, and SubDivisions based on the share of forecasted total state electricity sales that they are 

projected to provide. To the extent that this differs in practice, associated costs 

incurred by small entities may be over- or under-estimated. 

• To the extent that the EGU owner information used is not reflective of reality, the 

number of small entities may be over- or under-estimated. 

• To the extent that the entity-level ownership information (i.e., NAICS code, 

number of employees, revenues, and assets) are not reflective of reality, the 

number of small entities may be over- or under-estimated. 

2.3.5 Projected Reporting, Recordkeeping and Other Compliance Requirements 

The reporting, recordkeeping and other compliance requirements are most likely covered 

under Part 75 and Part 98 programs for affected EGUs. Therefore, only a marginal additional 

cost is expected for the monitoring, reporting and recordkeeping requirements of the proposed 

federal plan for affected EGUs. 

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2.3.6 Related Federal Rules 

On September 20, 2013, EPA proposed carbon pollution standards for new fossil fuel 

fired EGUs. On June 2, 2014, the EPA, proposed carbon pollution standards for modified and 

reconstructed fossil fuel fired EGUs, in addition to the Clean Power Plan EGs, to cut carbon 

pollution from existing fossil fuel fired EGUs. These existing EGUs are, or will be, potentially 

impacted by several other recently finalized EPA rules. On February 16, 2012, the EPA issued 

the mercury and air toxics standards (MATS) rule (77 FR 9304) to reduce emissions of toxic air 

pollutants from new and existing coal- and oil-fired EGUs. On May 19, 2014, the EPA issued a 

final rule under section 316(b) of the Clean Water Act (33 U.S.C. 1326(b)). This rule establishes 

new standards to reduce injury and death of fish and other aquatic life caused by cooling water 

intake structures at existing power plants and manufacturing facilities. On June 18, 2014 (79 FR 

34830), the EPA promulgated the stream electric effluent limitation guidelines (SE ELG) rule to 

strengthen the controls on discharges from certain steam electric power plants. On April 17, 2015 

(80 FR 21302), the EPA promulgated the coal combustion residuals (CCR) rule, which 

establishes technical requirements for CCR landfills and surface impoundments under subtitle D 

of the Resource Conservation and Recovery Act (RCRA), the nation's primary law for regulating 

solid waste. 

2.3.7 Regulatory Flexibility Alternatives 

2.3.7.1 Panel Process 

Small Entity Representatives (SERs) commented on their perceptions of the adequacy of 

the SBREFA panel process for the section 111(d) federal plan. Under the statute, EPA provides 

“information on the potential impacts of the proposed rule on small entities and the type of small 

entities that might be affected.” § 609(b)(1). Then SERs are selected, and the Panel collects 

“advice and recommendations” from each SER. § 609(b)(4). The Panel reviews the SERs’ 

comments, and “any material the agency has prepared in connection with [the RFA],” and 

“report[s] on the comments of the [SERs] and its findings as to issues related to” preparation of 

an IRFA. § 609(b)(5). EPA solicited SERs comments during the course of, and after holding 

three outreach meetings. The Agency provided information to the SERs on two primary 

regulatory alternatives for the federal plan – a rate-based trading program and a mass-based 

trading program. The Agency identified specific areas under both of these alternatives where it 

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was still in the decision making process and open to recommendations. This information forms 

the basis for consideration of issues and additional regulatory options important to these small 

entities. 

Advocacy shares many of the concerns raised by the SERs (see attached letter from 

Acting Chief Counsel Claudia Rodgers to EPA Administrator Gina McCarthy). While Advocacy 

endorses the Panel recommendations, Advocacy agrees that the SERs did not have sufficient 

information to inform advice and recommendations about specific regulatory alternatives and 

flexibilities. In Advocacy’s view, this is reflected in Panel recommendations that advise EPA to 

consider issues raised by the SERs rather than to propose or consider regulatory alternatives. 

Advocacy regrets that the Panel is not able to make more specific recommendations for 

flexibilities to minimize the impacts on small entities. 

While not all members of the Panel agree with all of these concerns, the concerns of the 

SERs regarding the Panel process have been noted. Nonetheless, EPA is committed to ensuring 

that it meets the requirements of the RFA and will, to the maximum extent practicable, fully 

consider the advice and recommendations of representatives of small entities in the development 

of the proposed rule. The EPA intends to continue working on issues regarding small businesses, 

and consider appropriate flexibilities, throughout this rulemaking process. 

2.3.7.2 Remaining Useful Life 

SERs commented that EPA needed to account for remaining useful life of EGUs. 

Multiple comments addressed challenges that EPA must face in satisfying the statutory mandate 

that “in applying a standard of performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other factors, the remaining useful life of 

the existing sources to which such standard applies.” SERs are concerned that EPA will develop 

EGs under section 111(d) in a manner that either prohibits plans from providing this 

consideration or only providing for plans to “make these adjustments at the expense of other 

sources.” AEPCO comments that it has obligations under the Rural Electrification Act to operate 

under an 80-year mandate. SBA recommends EPA propose allowing for guaranteed amount of 

run-time for small entities to allow them to recoup investment. EPA believes “remaining useful 

life” is a concern directed toward plants with short remaining lives, but recognizes that there are 

concerns about economic viability of some marginal plants. 

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The Panel recommends that EPA clearly explain how it took into consideration remaining 

useful life and take comment on other ways of defining the remaining useful life consideration. 

The Panel also recommends proposing or considering economic incentives for compliance that 

could avoid early retirement or reduce the financial effects of early retirements. For instance, the 

EPA could propose continuing allocations for a set number of years to units that retire in order to 

alleviate the financial effects of the retirement. EPA should request comment on how long such 

allocations should continue. The EPA should also consider whether there are parallel 

mechanisms in a rate-based proposal that could provide similar regulatory relief or benefits for 

small entities, if appropriate. 

2.3.7.3 Design of the Compliance System 

The panel requested SER input on a number of aspects of the federal plan design, based 

on EPA’s presentation of federal plan options. SER comments ranged quite broadly. Comments 

included: 1) differing opinions within SERs on favor of rate- vs mass-based approaches, 2) 

emphasis on market liquidity in a program, 3) support for types of allocation methodologies (in a 

mass-based allowance system), 4) encouragement for early action crediting, 5) increased 

averaging and compliance times to help small entities, and 6) whether and how to consider the 

effects of credit/allowance banking, borrowing, and shelf-life on market liquidity. In some 

instances, no general consensus emerged. The Panel notes the following specific areas where it is 

making a recommendation. 

Mass-based or rate-based trading 

Various SERs favored one system over the other, and some suggested that each 

individual small entity should be able to choose the system under which they would comply. 

However, it is unclear to what extent SERs would favor such choice at the expense of a broader 

trading pool. The panel, however, notes that the idea of individual companies within a state 

choosing which system to comply would significantly limit the opportunity for intra- or interstate trading and would therefore not be consistent with other recommendations. The Panel 

recommends that EPA take comment on which approach (mass or rate) is preferable. In the 

interests of maximizing liquidity across all federal plan states, the Panel recommends that EPA 

should propose to finalize a single approach for all federal plans. 

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Allocations and credit issuance/early action 

SERs expressed a variety of views on the appropriate method of allocating allowances 

under a mass-based system or credits under a rate-based system. Some preferred allowing states 

to make these decisions. Some wanted allocations to account for early action and energy 

efficiency efforts. The Panel agrees that EPA should take comment on the use of allocations to 

minimize the impact of the federal plan on small entities. The Panel notes that the early incentive 

pool that is part of the EGs does provide credit for early action, but the SERs did not have an 

opportunity to respond to this flexibility. The panel recommends that in the federal plan the EPA 

allow credit for early action and energy efficiency efforts to the extent it is allowed under the 

guidelines. 

Non-generating party participation and market liquidity 

SERs generally supported developing a system that would ensure a sufficient supply of 

credits be available on the open market and available for free trade to ensure that they would not 

be disadvantaged by large utilities withholding excess credits generated by renewable energy in 

their portfolio. However, some SERs also expressed the need to be able to generate and use 

credits internally (particularly those with generation across multiple states) (i.e., a portfolio 

approach). Some SERs endorsed allowing non-generating parties to create and sell credits or 

allowances. Other SERs warned that third parties should not be allowed to purchase credits or 

allowances for the purpose of retiring them without offsetting GHG emissions from electricity 

generation. The Panel recommends that the EPA ensure a liquid market in compliance 

instruments, through consideration, request or comment, or proposal of several of options, 

including: allocation methods or rules that could impact liquidity, mechanisms to place 

allowances or credits into the market relatively early, requirements for public transparency of 

information related to allowance or credit issuance, tracking, transfers, and holdings, and 

whether and to what extent oversight authority exists related to measures to ensure liquid 

markets Additionally, the Panel recommends that EPA solicit comment on other approaches to 

ensure liquidity, including but not limited to the concept of an early incentive pool which would 

serve to incentivize early reductions and create a market of additional allowances. 

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2.3.7.4 Renewable Energy and Energy Efficiency 

Generally SERs encouraged EPA to incorporate existing EE efforts into the program in a 

way that gives credit for the investment and to rely on “deemed” energy savings to earn 

compliance credits. SERs raised concerns about the accounting of investments in RE and EE 

efforts in their compliance with GHG emission standards. 

SERs also expressed concern that they be able to generate and use credits across state 

lines. This is particularly important for the investment in renewables, for which the generating 

potential is highly dependent on geography and is unequally distributed among the states. Thus, 

the Panel recommends that EPA develop a credit or allowance compliance program that allows 

for interstate accounting and trading for states under the federal plan. Additionally, the Panel 

recommends that the program include opportunities for interstate trading between sources in 

states under the federal plan and states under compatible state plans. 

The Panel recommends that EPA consider the treatment of RE and EE in rate-based and 

mass-based federal plan contexts. EPA should further consider how to implement preferred 

policy options in a way that incentivizes investment and does not create unintended barriers for 

small entities. The Panel also recommends that EPA allow crediting of RE across states under 

the federal plan while soliciting comment for allowing crediting for EE across states under the 

federal plan. 

2.3.7.5 Reliability 

Multiple SERs expressed concerns that implementation of the EGs, either by states or 

through a federal plan, could have a negative impact on reliability because individual units could 

have operational obligations that conflict with the emissions requirements. In their comments, 

both the American Public Power Association (APPA) and the National Rural Electric 

Cooperative Association (NRECA) recommend Dynamic Reliability Safety Valve. EPA noted 

that the use of a reliability mechanism in the EGs is provisioned on the concern that some forms 

of state plan may create inflexible requirements that could in some limited circumstances raise a 

reliability concern. However, EPA believes the design of the federal plan as a flexible trading 

program alleviates these concerns and therefore a reliability mechanism is not needed. 

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The Panel recognizes the connection between meeting the GHG reduction goals of the 

federal plan and maintaining the reliability of the electric grid. The Panel recommends that EPA 

fully explain in the proposal and take comment on methods to address reliability and EPA should 

take comment on establishing a reliability safety valve, and whether there is a need for regulatory 

flexibility for reliability critical units beyond the flexibilities already built into the design of the 

federal plan. 

2.3.7.6 Subcategorization/Applicability/Exemptions 

SER comments on applicability reflect concerns related to the combined series of 

rulemakings affecting GHG emissions from electricity generating units: the NSPS, the EGs and 

the federal plan. SERs endorse excluding RICE and NGSC units from the combined 

rulemakings. One SER requests a subcategory that addresses the particular characteristics of 

lignite coal. Some SERs suggest special provisions for small units or utilities, including a small 

system exemption. The SBA suggested taking comment on an economic hardship exemption for 

small entities and that EPA propose a mechanism for additional compliance time when 

generation and transmission investments necessary for compliance have been delayed by 

government reviews. However, EPA noted that regulatory exemptions must be grounded in 

statute and supported by analysis, and EPA believes the design of the federal plan itself should 

maximize compliance options that are both consistent with the EGs and also should adequately 

address these concerns. 

The Panel notes that EPA must be consistent with the EGs on issues of applicability, 

which should address the SERs’ concerns with regard to inclusion of RICE or NGSC units. The 

Panel also notes that EPA is proposing a design to the federal plan that utilizes emission trading 

and thus maximizes compliance options such that individual units can take into account their 

particular characteristics in designing a compliance strategy. In EPA’s view, this makes it less 

likely that there is a need for further sub-categorization or the use of unit-specific exemptions. 

Additionally, the Panel recommends that EPA solicit comment on an alternative allocation 

methodology under the mass-based proposed federal plan that may increase allocations for small 

businesses, and consider whether there are parallel mechanisms in a rate-based proposal that 

could provide similar regulatory relief or benefits for small entities, if appropriate. 

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2.4 Unfunded Mandates Reform Act (UMRA) 

This action contains a federal mandate under UMRA, 2 U.S.C. 1531-1538, that could 

potentially result in expenditures of $100 million or more for state, local, and tribal governments, 

in the aggregate, or the private sector in any one year. This federal plan will apply only to those 

EGUs located in states that do not submit approvable state plans, which is a subset of the EGUs 

considered in the RIA for the final emission guidelines (EGs). Because it is impossible to 

determine at this time which states might be ultimately subject to a federal plan, EPA cannot 

determine whether this final rule will be subject to UMRA. However, as noted below, the 

Agency has done substantial outreach to government entities as part of both the federal plan and 

the related 111(d) rulemaking. Further, regardless of whether EPA does determine that this 

action ultimately meets the UMRA threshold, the agency intends to do additional outreach with 

government entities between now and the final rule. Additionally, the EPA has determined that 

this action is not subject to the requirements of section 203 of UMRA because it contains no 

regulatory requirements that might significantly or uniquely affect small governments. 

Nevertheless, the EPA is aware that there is substantial interest in this rule among small 

entities (e.g., municipal and rural electric cooperatives). In light of this interest, prior to this 

action, the EPA sought early input from representatives of small entities while formulating the 

provisions of the proposed regulation. Such outreach is also consistent with the President’s 

January 18, 2011 Memorandum on Regulatory Flexibility, Small Business, and Job Creation, 

which emphasizes the important role small businesses play in the American economy. This 

outreach process has enabled the EPA to hear directly from these representatives, as EPA 

developed the rule about how the EPA should approach the complex question of how to apply 

section 111 of the CAA to the regulation of GHGs from these source categories. We invite 

comments on all aspects of this proposal and its impacts, including potential adverse impacts, on 

small entities. 

2.5 Executive Order 13132: Federalism 

The EPA believes that this proposed rule may be of significant interest to state and local 

governments due to its relationship with the Clean Power Plan EGs. Therefore, the EPA has 

determined that consultations with state and local governments conducted during the Clean 

Power Plan EGs development process are also relevant to this proposed rule. Consistent with the 

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EPA’s policy to promote communications between the EPA and state and local governments, the 

EPA consulted with state and local officials early in the process of developing the Clean Power 

Plan EGs to permit them to have meaningful and timely input into its development. As described 

in the Federalism discussion in the preamble to the proposed standards of performance for GHG 

emissions from new EGUs (79 FR 1501; January 8, 2014), the EPA consulted with state and 

local officials in the process of developing the proposed standards for newly constructed EGUs. 

A detailed Federalism Summary Impact Statement (FSIS) describing the most pressing issues 

raised in pre-proposal and post-proposal comments will be forthcoming with the final Clean 

Power Plan EGs, as required by section 6(b) of Executive Order 13132. In the spirit of Executive 

Order 13132, and consistent with the EPA’s policy to promote communications between the 

EPA and state and local governments, the EPA specifically solicits comment on this proposed 

action from state and local officials. 

2.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments 

 This proposed action has tribal implications. However, it will neither impose substantial 

direct compliance costs on federally recognized tribal governments, nor preempt tribal law. The 

EGU potentially impacted by this proposed rulemaking located on Indian reservations are 

primarily owned by private entities, and in one case, partially owned by an agency of the U.S. 

government. As a result, the tribes on whose areas of Indian country those units are located will 

not be directly impacted by any costs of complying with this proposed rulemaking incurred by 

the owners/operators of those units. There would only be tribal implications in regards to 

compliance costs associated with this proposed rulemaking in the case where a tribal government 

has an ownership interest in a potentially affected EGU. A tribal government could also incur 

costs in the event that it seeks and is given delegated authority to enforce the federal plan 

proposed in this rulemaking. The EPA has, nevertheless, offered consultation to the tribes on 

whose areas of Indian country the units are located. As part of its general outreach to tribes 

regarding this proposed rulemaking, the EPA received feedback from a number of tribes 

regarding the potential overall economic impact that both the proposed Clean Power Plan and a 

proposed federal plan rulemaking may have on them. In these instances, the EPA has reached out 

to these tribes and as part of the consultation on the Clean Power Plan engaged with them on 

their concerns regarding a potential federal plan. 

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The EPA has conducted consultation with tribes on the Clean Power Plan and the 

Supplemental Proposal for the Clean Power Plan and will offer all tribes consultation on this 

proposed action. The EPA held consultations with tribes on the Clean Power Plan in the fall of 

2014 before the agency issued its Supplemental Proposal for Indian Country and U.S. Territories. 

Additionally, the EPA held consultations for tribes shortly following the release of the 

supplemental proposal. The agency also held a public hearing on the supplemental proposal on 

November 19, 2014, in Phoenix, Arizona. At the public hearing the agency received oral 

comments from community members representing a number of tribes and a number of tribal 

officials. The agency also conducted consultation with tribes in the spring and summer of 2015. 

An overview of the consultations provided as part of the Clean Power Plan is available in section 

XII.F of the final EGs. 

Additionally, the EPA engaged in meaningful dialogue with tribal stakeholders to obtain 

their feedback in the pre-proposal stages of this rulemaking. We provided an update on this 

proposed rulemaking on the May 28, 2015, National Tribal Air Association and the EPA Air 

Policy call. Additionally, staff attended the National Tribal Forum conference on May 20, 2015 

and provided an overview of the Clean Power Plan and explained that the agency would be 

proposing a federal plan. 

Consistent with previous rulemakings impacting the power sector, there is significant 

tribal interest in these rulemakings because of the potential indirect impacts that rules such as the 

Clean Power Plan and this proposed federal plan may have on tribes. The EPA specifically 

solicits additional feedback from tribal officials on all aspects of this proposed rulemaking, 

including whether tribes whose areas of Indian country contain affected EGU(s) are interested in 

developing their own plan implementing the final EGs. Additionally, tribal stakeholders will be 

included in the outreach that the agency will be conducting with those communities already 

overburdened by pollution, which are often low-income communities, communities of color, and 

indigenous communities. The actions that the agency will be taking are outlined in section IX of 

the preamble. 

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2.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks 

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those 

regulatory actions that concern health or safety risks, such that the analysis required under 

section 5–501 of the Order has the potential to influence the regulation. This action is not subject 

to EO 13045 because it does not involve decisions on environmental health or safety risks that 

may disproportionately affect children. The EPA believes that the CO2 emission reductions 

resulting from implementation of the proposed guidelines, as well as substantial ozone and 

PM2.5 emission reductions as a cobenefit, would further improve children’s health. 

2.8 Executive Order 13211: Actions That Significantly Affect Energy Supply, 

Distribution, or Use 

This action, which is a significant regulatory action under EO 12866, is likely to have a 

significant effect on the supply, distribution, or use of energy. The EPA has prepared a Statement 

of Energy Effects for this action as follows. We estimate a 1 to 2 percent change in retail 

electricity prices on average across the contiguous U.S. in 2025, and a 22 to 23 percent reduction 

in coal-fired electricity generation as a result of this rule. The EPA projects that utility power 

sector delivered natural gas prices will increase by up to 2.5 percent in 2030. For more 

information on the estimated energy effects, please refer to the economic impact analysis for this 

proposal in Chapter 1 of this RIA. 

2.9 National Technology Transfer and Advancement Act (NTTAA) 

This proposed action does not involve technical standards. 

2.10 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations 

Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive 

policy on EJ. Its main provision directs federal agencies, to the greatest extent practicable and 

permitted by law, to make EJ part of their mission by identifying and addressing, as appropriate, 

disproportionately high and adverse human health or environmental effects of their programs, 

policies, and activities on minority populations and low-income populations in the U.S. The EPA 

defines EJ as the fair treatment and meaningful involvement of all people regardless of race, 

color, national origin, or income with respect to the development, implementation, and 

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enforcement of environmental laws, regulations, and policies. The EPA has this goal for all 

communities and persons across this Nation. It will be achieved when everyone enjoys the same 

degree of protection from environmental and health hazards and equal access to the decisionmaking process to have a healthy environment in which to live, learn, and work. 

Leading up to this rulemaking the EPA summarized the public health and welfare effects 

of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment Finding, the 

Administrator considered climate change risks to minority populations and low-income 

populations, finding that certain parts of the population may be especially vulnerable based on 

their characteristics or circumstances. Populations that were found to be particularly vulnerable 

to climate change risks include the poor, the elderly, the very young, those already in poor 

health, the disabled, those living alone, and/or indigenous populations dependent on one or a few 

resources. See sections X.F and X.G of the preamble where the EPA discusses Consultation and 

Coordination with Tribal Governments and Protection of Children. The Administrator placed 

weight on the fact that certain groups, including children, the elderly, and the poor, are most 

vulnerable to climate-related health effects. 

The record for the 2009 Endangerment Finding summarizes the strong scientific evidence 

in the major assessment reports by the U.S. Global Change Research Program, the 

Intergovernmental Panel on Climate Change (IPCC), and the National Research Council of the 

National Academies that the potential impacts of climate change raise EJ issues. These reports 

concluded that poor communities can be especially vulnerable to climate change impacts because 

they tend to have more limited adaptive capacities and are more dependent on climate-sensitive 

resources such as local water and food supplies. In addition, Native American tribal communities 

possess unique vulnerabilities to climate change, particularly those impacted by degradation of 

natural and cultural resources within established reservation boundaries and threats to traditional 

subsistence lifestyles. Tribal communities whose health, economic well-being, and cultural 

traditions that depend upon the natural environment will likely be affected by the degradation of 

ecosystem goods and services associated with climate change. The 2009 Endangerment Finding 

record also specifically noted that Southwest native cultures are especially vulnerable to water 

quality and availability impacts. Native Alaskan communities are already experiencing 

disruptive impacts, including coastal erosion and shifts in the range or abundance of wild species 

crucial to their livelihoods and well-being. 

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The most recent assessments continue to strengthen scientific understanding of climate 

change risks to minority populations and low-income populations in the U.S.51 The new 

assessment literature provides more detailed findings regarding these populations’ vulnerabilities 

and projected impacts they may experience. In addition, the most recent assessment reports 

provide new information on how some communities of color may be uniquely vulnerable to 

climate change health impacts in the U.S. These reports find that certain climate change related 

impacts—including heat waves, degraded air quality, and extreme weather events—have 

disproportionate effects on low-income populations and some communities of color (in 

particular, populations defined jointly by ethnic/racial characteristics and geographic location), 

raising EJ concerns. Existing health disparities and other inequities in these communities 

increase their vulnerability to the health effects of climate change. In addition, assessment 

reports also find that climate change poses particular threats to health, well-being, and ways of 

life of indigenous peoples in the U.S. 

As the scientific literature presented above and as the 2009 Endangerment Finding 

illustrates, low income populations and some communities of color are especially vulnerable to 

the health and other adverse impacts of climate change. The EPA believes that communities will 

benefit from this proposed federal plan because this action directly addresses the impacts of 

climate change by limiting GHG emissions through the establishment of CO2 emission standards 

for existing affected fossil fuel-fired EGUs. 

In addition to reducing CO2 emissions, the guidelines finalized in this rulemaking would 

reduce other emissions from affected EGUs that reduce generation due to higher adoption of EE 

 

51 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United 

States: The Third National Climate Assessment. U.S. Global Change Research Program, 841 pp. 

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects.

Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate 

Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, 1132 pp. 

 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects. 

Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate 

Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, 688 pp.

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and RE. These emission reductions will include SO2 and NOx, which form ambient PM2.5 and 

ozone in the atmosphere, and HAP, such as mercury and hydrochloric acid. In the final rule 

revising the annual PM2.5 NAAQS,52 the EPA identified low-income populations as being a 

vulnerable population for experiencing adverse health effects related to PM exposures. Lowincome populations have been generally found to have a higher prevalence of pre-existing 

diseases, limited access to medical treatment, and increased nutritional deficiencies, which can 

increase this population’s susceptibility to PM-related effects.53 In areas where this rulemaking 

reduces exposure to PM2.5, ozone, and methylmercury, low-income populations will also benefit 

from such emissions reductions. Chapter 1 of this RIA provides additional information regarding 

the health and ecosystem effects associated with these emission reductions. 

Additionally, as outlined in the community and EJ considerations section IX of the 

preamble, the EPA has taken a number of actions to help ensure that this action will not have 

potential disproportionately high and adverse human health or environmental effects on 

vulnerable communities. The EPA consulted its May 2015, Guidance on Considering 

Environmental Justice During the Development of Regulatory Actions, when determining what 

actions to take.54 As described in the community and EJ considerations section of the preamble 

the EPA also conducted a proximity analysis, which is available in the docket of this rulemaking 

and is discussed in section IX of the preamble. Additionally, as outlined in sections I and IX of 

the preamble the EPA has engaged meaningfully with communities throughout the development 

of the CPP and has devised a robust outreach strategy for continual engagement throughout this 

rulemaking.

 

52 “National Ambient Air Quality Standards for Particulate Matter, Final Rule,” 78 FR 3086 (Jan. 15, 2013). 

53 U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for Particulate Matter 

(Final Report). EPA-600-R-08-139F. National Center for Environmental Assessment – RTP Division. December. 

Available on the Internet at http://www.cfpub.epa.gov/si/si_public_record_Report.cfm?dirEntryId=216546. 

54 Guidance on Considering Environmental Justice During the Development of Regulatory Actions. 

http://www.epa.gov/environmentaljustice/resources/policy/considering-ej-in-rulemaking-guide-final.pdf. May 

2015. 

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United States 

Environmental 

Protection Agency 

Office of Air Quality Planning and Standards 

Health and Environmental Impacts Division 

Research Triangle Park, NC 

Publication No. 

EPA-452/R-15-006 

July 2015

336
Attachment R.2

337
Regulatory Impact Analysis 

for the 

Proposed Federal Plan Requirements for 

Greenhouse Gas Emissions from Electric 

Utility Generating Units Constructed on or 

Before January 8, 2014; Model Trading 

Rules; Amendments to Framework 

Regulations 

338
[This page intentionally left blank] 

339
EPA-452/R-15-006 

July 2015 

Regulatory Impact Analysis for the for the 

Proposed Federal Plan Requirements for Greenhouse Gas 

Emissions from Electric Utility Generating Units Constructed on or 

Before January 8, 2014; Model Trading Rule 

U.S. Environmental Protection Agency

Office of Air and Radiation

Office of Air Quality Planning and Standards

Research Triangle Park, NC 27711

340
CONTACT INFORMATION

This document has been prepared by staff from the Office of Air Quality Planning and 

Standards, the Office of Atmospheric Programs, and the Office of Policy of the U.S. 

Environmental Protection Agency. Questions related to this document should be addressed to 

Alexander Macpherson, U.S. Environmental Protection Agency, Office of Air Quality Planning 

and Standards, Research Triangle Park, North Carolina 27711 (email: 

macpherson.alex@epa.gov). 

ACKNOWLEDGEMENTS

Thank you to the many staff who worked on this document from EPA Offices including 

the Office of Air Quality Planning and Standards, the Office of Atmospheric Programs, and the 

Office of Policy. Contributions to this report were also made by ICF International. and RTI 

International.

341
Contents

LIST OF TABLES ............................................................................................................................ vii

CHAPTER 1: SUMMARY OF POTENTIAL REGULATORY IMPACTS ..................................................1

1.1 Introduction ....................................................................................................................1

1.2 Legal, Scientific and Economic Basis for this Rulemaking ..........................................2

1.2.1 Statutory Requirement ........................................................................................2

1.2.2 Health and Welfare Impacts from Climate Change ............................................3

1.2.3 Market Failure ....................................................................................................4

1.3 Background for the Proposed Federal plan and model trading rules .............................5

1.3.1 Definition of Affected Sources ...........................................................................5

1.3.2 Trade in Compliance Instruments across States .................................................5

1.3.3 Model Trading Rule............................................................................................6

1.4 Summary of Regulatory Analysis ..................................................................................7

1.4.1 Base Case and Years of Analysis .......................................................................9

1.4.2 Federal Plan Approaches Examined in RIA .....................................................10

1.5 Summary of Regulatory Analysis ................................................................................14

1.5.1 Emissions Reductions .......................................................................................14

1.5.2 Costs .................................................................................................................16

1.5.3 Monetized Climate Benefits and Health Co-benefits .......................................18

1.5.4 Net Benefits ......................................................................................................30

1.5.5 Economic Impacts ............................................................................................33

1.5.6 Employment Impacts ........................................................................................33

1.5.6 Additional Analysis of Output-Based Allocation as a Means of Mitigating 

Leakage ........................................................................................................................35

1.5.7 Uncertainty Analysis ........................................................................................36

1.6 References ....................................................................................................................40

CHAPTER 2: STATUTORY AND EXECUTIVE ORDER REVIEWS .......................................................1

2.1 Executive Order 12866: Regulatory Planning and Review and Executive Order 

13563: Improving Regulation and Regulatory Review ........................................................1

2.2 Paperwork Reduction Act ..............................................................................................4

2.3 Initial Regulatory Flexibility Analysis...........................................................................6

2.3.1 Reasons why Action is Being Considered ..........................................................6

2.3.2 Statement of Objectives and Legal Basis for Proposed Rules ............................8

2.3.3 Description and Estimate of Affected Small Entities .........................................9

2.3.4 Compliance Cost Impact Estimates ..................................................................16

2.3.5 Projected Reporting, Recordkeeping and Other Compliance Requirements ...24

2.3.6 Related Federal Rules .......................................................................................25

2.3.7 Regulatory Flexibility Alternatives ..................................................................25

2.4 Unfunded Mandates Reform Act (UMRA) .................................................................32

2.5 Executive Order 13132: Federalism ............................................................................33

2.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments .......................................................................................................................33

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2.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks ..................................................................................................................35

2.8 Executive Order 13211: Actions That Significantly Affect Energy Supply, 

Distribution, or Use .............................................................................................................35

2.9 National Technology Transfer and Advancement Act (NTTAA) ...............................36

2.10 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations ..........................................................36

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LIST OF TABLES

Table 1-1. Climate and Air Pollutant Emission Reductions for the Rate-Based Federal 

Plan Approach1 ..................................................................................................................14

Table 1-2. Climate and Air Pollutant Emission Reductions for the Mass-Based Federal 

Plan Appproach1 ................................................................................................................15

Table 1-3. Projected CO2 Emission Reductions, Relative to 2005 ........................................16

Table 1-4. Compliance Costs for the Federal Rate-Based and Mass-Based Plan 

Approaches ........................................................................................................................18

Table 1-5 Quantified and Unquantified Benefits ..................................................................20

Table 1-6. Combined Estimates of Climate Benefits and Health Co-Benefits for RateBased Approach (billions of 2011$)* ................................................................................29

Table 1-7. Combined Estimates of Climate Benefits and Health Co-benefits for MassBased Approach (billions of 2011$)* ................................................................................30

Table 1-8. Monetized Benefits, Compliance Costs, and Net Benefits Under the Ratebased Federal Plan Approach (billions of 2011$) a

 ...........................................................31

Table 1-9. Monetized Benefits, Compliance Costs, and Net Benefits under the Massbased Federal Plan Approach (billions of 2011$) a

 ...........................................................32

Table 1-10. Summary Table of Important Energy Market Impacts (Percent Change from 

Base Case) ..........................................................................................................................33

Table 2-1. SBA Size Standards by NAICS Code ..................................................................13

Table 2-2. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Rate-Based Federal Plan Approach in 2030 ......................................................19

Table 2-3. Projected Impact on Small Entities in 2030 under Rate-Based Federal Plan 

Approach ............................................................................................................................19

Table 2-4. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Mass-Based Federal Plan Approach in 2030 .....................................................20

Table 2-5. Projected Impact on Small Entities in 2030 under Mass-Based Federal Plan 

Approach ............................................................................................................................20

Table 2-6. Incremental Costs in 2030 under the Rate-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) .............21

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Table 2-7. Incremental Costs in 2030 under the Mass-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) .............22

345
CHAPTER 1: SUMMARY OF POTENTIAL REGULATORY IMPACTS

1.1 Introduction

This Regulatory Impact Analysis (RIA) discusses potential benefits, costs, and economic 

impacts of for the “Proposed Federal Plan Requirements for Greenhouse Gas Emissions from 

Electric Utility Generating Units Constructed on or Before January 8, 2014; Model Trading 

Rules; Amendments to Framework Regulations” (herein also referred to as “proposed federal 

plan and model trading rules”1). In this action, the Environmental Protection Agency (EPA) is 

proposing a federal plan to implement the emission guidelines for existing fossil fuel-fired EGUs 

under the Clean Air Act (CAA). The emission guidelines were proposed in June 2014 and 

finalized on August 3, 2015[&&&] as the Carbon Pollution Emission Guidelines for Existing 

Stationary Sources: Electric Utility Generating Units (also referred to as the Clean Power Plan 

Clean Power Planor Emission Guidelines). The EPA is taking comment on many of the elements 

of this proposal. 

This proposal presents two approaches to a federal plan (or model rule) for states and 

other jurisdictions that either chose to adopt a model rule or do not adopt andand submit to the 

EPA in a timely manner an approvable state plan: a rate-based emission trading program and a 

mass-based emission trading program. The federal plan is an important measure to ensure that 

congressionally mandated emission standards under the authority of the CAA are implemented. 

The agency is also proposing a necessary or appropriate finding for the affected EGUs in several 

areas of Indian country and is proposing the federal plan for these affected EGUs.This proposal 

also constitutes two proposed model trading rules that states can adopt or tailor for 

implementation of the emission guidelines. 

The proposed federal plan is related to but separate from the final Final Clean Power Plan

Emission Guidelinesemission guidelines. The final emission guidelines establish the best system 

of emission reduction (BSER) for applicable fossil fuel-fired EGUs in the form of a standard of 

&&& forto subcategorizeda carbon dioxide (CO2) emission performance rates for steam-fired 

1 The proposed amendments to the framework regulations for section 111(d) are limited to enhancements in the 

procedure and timing of the EPA’s action on state plans. See Section VII of the preamble. They do not modify 

requirements or obligations in the CPP or other substantive rules, or directly regulate any third parties. Therefore, 

the EPA has not included these changes in its analysis in this RIA and proposes to certify that these changes will not 

have a significant impact on a significant number of small entities pursuant to the Regulatory Flexibility Act (RFA). 

346
EGUs and a CO2 emission performance rate a standard of &&& for natural gas-fired combined 

cycle unitsEGUs, and provide guidance and criteria for the development of approvable state 

plansand provide equivalent mass- and rate-based state goals as well as guidance and criteria for 

the development of approvable state plans. The purpose of the proposed federal plan is to 

establish requirements, directly applicable to a state’s affected EGUs that meet the emission 

performance levels in order to achieve reductions in carbon dioxide (CO2) emissions in the case 

where a state or other jurisdiction does not submit an approvable plandetermined by application 

of the BSER in order to achieve reductions in carbon dioxide (CO2) emissions in the case where 

a state or other jurisdiction does not submit an approvable plan. The stringency of the emission 

performance levels established in the final emission EGsguidelines will be the same whether 

implemented through a state plan or a federal plan.

1.2 Legal, Scientific and Economic Basis for this Rulemaking 

1.2.1 Statutory Requirement 

Section 111(d)(2) of the Clean Air Act (CAA), 42 U.S.C. 7411(d)(2) provides the EPA 

the same authority to prescribe a plan for a state in cases where the state fails to submit a 

satisfactory plan as the Agency would have under CAA section 110(c) in the case of failure to 

submit a National Ambient Air Quality Standard implementation plan. In addition, the EPA has 

authority under CAA section 111(d)(1) to prescribe regulations that establish procedures similar 

to CAA section 110 with respect to the submission of state plans, and the EPA also has general 

rulemaking authority as necessary to implement the CAA under section 301. A federal Plan 

under CAA section 111(d) applies, implements and enforces standards of performance for 

affected EGUs. Under the Clean Power Plan Emission Guidelines, state plans will be due on 

[August 31September 6, 2016]. States are also allowed to seek a two year extension for a final 

plan submittal, upon submitting a satisfactory initial submittal by the same deadline. If a state 

fails to submit a final state plan or initial submittal, or if either a final state plan or an initial 

submittal does not meet the requirements of the final emission guidelines, the Agency will take 

the appropriate steps to finalize and implement a federal plan. 

States will remain free, and indeed are strongly encouraged, to submit an approvable state 

plan even after promulgation of the federal plan for their jurisdictions. Upon approval of the state 

347
plan by EPA, the federal plan will no longer apply to the affected EGUs covered by the approved 

state plan, starting at the initiation of the next compliance period with the limitations noted in the 

federal plan. 

1.2.2 Health and Welfare Impacts from Climate Change 

According to the National Research Council, “Emissions of CO2 from the burning of 

fossil fuels have ushered in a new epoch where human activities will largely determine the 

evolution of Earth’s climate. Because CO2 in the atmosphere is long lived, it can effectively lock 

Earth and future generations into a range of impacts, some of which could become very severe. 

Therefore, emission reduction choices made today matter in determining impacts experienced 

not just over the next few decades, but in the coming centuries and millennia.”2

 

In 2009, based on a large body of robust and compelling scientific evidence, the EPA 

Administrator issued the Endangerment Finding under CAA section 202(a)(1).3 In the 

Endangerment Finding, the Administrator found that the current, elevated concentrations of 

GHGs in the atmosphere—already at levels unprecedented in human history—may reasonably 

be anticipated to endanger public health and welfare of current and future generations in the 

United States. 

Since the administrative record concerning the Endangerment Finding closed following 

the EPA’s 2010 Reconsideration Denial, the climate has continued to change, with new records 

being set for a number of climate indicators such as global average surface temperatures, Arctic 

sea ice retreat, CO2 concentrations, and sea level rise. Additionally, a number of major scientific 

assessments have been released that improve understanding of the climate system and strengthen 

the case that GHGs endanger public health and welfare both for current and future generations. 

These assessments are from the Intergovernmental Panel on Climate Change (IPCC), the U.S. 

Global Change Research Program (USGCRP), and the National Research Council (NRC). These 

and other assessments are discussed in more detail in the Final Clean Power Plan Emission 

2 National Research Council, Climate Stabilization Targets, p.3. 

3 “Endangerment and Cause or Contribute Findings for Greenhouse Gases Underunder Section 202(a) of the Clean 

Air Act,” 74 Fed. Reg. 66,496 (Dec. 15, 2009) (“Endangerment Finding”).

348
Guidelines preamble and in Chapter 4 of the Clean Power Plan Final Rule Regulatory Impact

Analysis (RIA).4

1.2.3 Market Failure 

Many regulations are promulgated to correct market failures, which otherwise lead to a 

suboptimal allocation of resources within the free market. Air quality and pollution control 

regulations address “negative externalities” whereby the market does not internalize the full 

opportunity cost of production borne by society as public goods such as air quality are unpriced. 

GHG emissions impose costs on society, such as negative health and welfare impacts, 

that are not reflected in the market price of the goods produced through the polluting process. 

For this regulatory action the good produced is electricity. If a fossil fuel-fired electricity 

producer pollutes the atmosphere when it generates electricity, this cost will be borne not by the 

polluting firm but by society as a whole, thus imposing a negative externality. The equilibrium 

market price of electricity may fail to incorporate the full opportunity cost to society of 

generating electricity. All else equal, given this externality, the composition of EGUs used to 

generate electricity in a free market will not be socially optimal, and the quantity of electricity 

generated may not be at the socially optimal level. Fossil fuel-fired EGUs may produce more 

electricity than would occur if they had to account for the cost associated with this negative 

externality. Consequently, absent a regulation on emissions, the composition of the fleet of 

EGUs used to generate electricity may not be socially optimal, and the marginal social cost of 

the last unit of electricity produced may exceed its marginal social benefit. In the instances where 

the agency finalizes and implements a federal plan for a state’s affected EGUs, this proposed 

regulation will work towards addressing this market failure by causing affected EGUs to begin to 

internalize the negative externality associated with CO2 emissions. 

4 U.S. Environmental Protection Agency (U.S. EPA). 2015a. Regulatory Impact Analysis for the Clean Power Plan 

Final Rule. EPA-452/R-15-003. Office of Air Quality Planning and Standards, Health and Environmental Impacts 

Division, Research Triangle Park, NC.

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1.3 Background for the Proposed Federal plan and model trading rules

1.3.1 Definition of Affected Sources

Existing fossil fuel-fired electric generating units subject to the final Clean Power Plan 

Emission Guidelines that are located in a state that does not have an EPA-approved state plan are 

potentially subject to this proposed action. Existing fossil fuel-fired EGUs are those that were in 

operation or had commenced construction on or before January 8, 2014.5

1.3.2 Trade in Compliance Instruments across States in the Federal Plan

The EPA intends to set up and administer a program to track trading programs – both 

rate-based and mass-based – that will be available for all states that choose it. The EPA proposes 

that affected EGUs in any state covered by a federal plan could trade compliance instruments 

with affected EGUs in any other state covered by a federal plan or a state plan meeting the 

conditions for linkage to the federal plan. In the proposed mass-based federal-plan trading 

program, this would mean that affected EGUs in a state covered by the federal plan or a state 

meeting the conditions for linkage to the federal plan could use, as a compliance instrument, an 

allowance distributed in any other state covered by the federal plan or a state meeting the 

conditions for linkage to the federal plan. Similarly, in the proposed rate-based federal-plan 

trading program approach, this would mean that affected EGUs in a state covered by the federal 

plan or a state meeting the conditions for linkage to the federal plan could use, as a compliance 

instrument, an ERC issued in any other state covered by the federal plan or a state meeting the 

conditions for linkage to the federal plan. EPA is proposing that an affected EGU in a state 

covered by the mass-based trading federal plan must use allowances for compliance (not ERCs). 

Similarly, an affected EGU in a state covered by the rate-based trading federal plan must use 

ERCS for compliance (not allowances).The EPA intends to set up and administer a program to 

track trading programs – both rate- and mass-based – that will be available for all states that 

choose it. The EPA proposes that affected EGUs in any state covered by a federal plan could 

trade compliance instruments with affected EGUs, or procure zero-emissions megawatt hours 

(MWhs) from eligible resources, in any other state covered by a federal plan that uses the same 

5

 An affected EGU is any fossil fuel-fired EGU that was in operation or had commenced construction as of January 

8, 2014, and is therefore an ‘‘existing source’’ for purposes of CAA section 111, and that in all other respects 

would meet the applicability criteria for coverage under the proposed GHG standards for new fossil fuel-fired 

EGUs (79 FR 1430; January 8, 2014). 

350
approach. In the proposed mass-based federal-plan trading program, this would mean that 

affected EGUs in a state covered by the federal plan could use, as a compliance instrument, an 

allowance distributed in any other state covered by a federal plan. Similarly, in the proposed 

rate-based federal-plan trading program approach, this would mean that affected EGUs in a state 

covered by a federal plan could use, as a compliance instrument, an emission rate credit (ERC) 

issued in any other state covered by a federal plan. We propose that an affected EGU in a state 

covered by a mass-based trading federal plan must use allowances for compliance (not ERCs). 

Similarly, an affected EGU in a state covered by the rate-based trading federal plan must use 

ERCS for compliance (not allowances). 

1.3.3 Model Trading Rule 

A state program that adheres to the model trading rule provisions specified in this

rulemaking would be presumptively approvable. States may submit means of meeting the 

emission guidelines requirements that differ from the model trading rule provisions, so long as 

the state demonstrates to the EPA’s satisfaction in the state plan submittal that such alternative 

means of addressing requirements are at least as stringent as the presumptively approvable 

approach described here. Additionally, there are stand-alone portions of the model trading rules, 

such as the evaluation, measurement, and verification (EM&V) procedures that would be 

approvable even if a state adopted an approach that differs from the federal plan. The model 

trading rules serve as a mechanism to facilitate larger trading markets since consistency with the 

federal plan allows trading across both the state and federal programs. The EPA expects a larger 

trading region is likely to result in lower overall costs. A state program that adheres to the model 

trading rule provisions specified in this proposal would be presumptively approvable. 

Additionally, there are stand-alone portions of the model trading rules, such as the evaluation, 

measurement and verification (EM&V) procedures, that would be approvable even if a state 

adopted an approach that differs from the federal plan. The model trading rules serves as a 

mechanism to create larger trading markets since consistency of state plans with the federal plan 

allows trading across both the state and federal programs. The EPA expects that a larger trading 

region would likely result in lower overall costs of compliance to affected EGUs due to the 

increase in abatement options.

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1.4 Summary of Regulatory Analysis 

In accordance with Executive Order 12866, Executive Order 13563, OMB Circular A-4, 

and the EPA’s “Guidelines for Preparing Economic Analyses,” the EPA prepared this RIA for 

this “significant regulatory action.” This action is an economically significant regulatory action 

because it may have an annual effect on the economy of $100 million or more or adversely affect 

in a material way the economy, a sector of the economy, productivity, competition, jobs, the 

environment, public health or safety, or state, local, or tribal governments or communities.6 

This action proposes a federal plan under section 111(d) of the CAA for the control of 

CO2, a greenhouse gas pollutant, from certain large emitting fossil-fuel fired power plants, in the 

event that some states do not adopt their own plans. Specifically, the EPA is proposing 

approaches in the form of mass- and rate-based trading options that provide flexibility in 

implementing emission standards for a state’s affected EGUs. Both proposed approaches to the 

federal plan would require affected EGUs to meet emission standards set using the CO2 emission 

performance rates in the emission guidelines. The federal plan will achieve the same levels of 

emissions performance as required of state plans under the emission guidelines. 

However, at the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan or adopt a model rule. Because of this lack of information, 

for this RIA, the EPA has chosen to examine two federal plan approach a scenarios where all 

states of the contiguous U.S. will be regulated under a federal plan or a model rule. Furthermore, 

because of the lack of information as to which states will adopt the model rule, the EPA has 

chosen to examine a scenario where all states of the contiguous U.S. adopt the model trading rule 

. Additionally, we examine two alternative federal plan approach scenarios, which will be 

described in more detail below, for implementation of federal plans. The first federal plan 

approach we examine in this RIA assumes all states in the contiguous U.S. are regulated under a 

rate-based federal plan or model rule. The second federal plan approach we examine assumes all 

contiguous states are regulated under a mass-based federal plan or model rule. These two 

6 The analysis in this proposal RIA constitutes the economic assessment required by CAA section 317. In the EPA’s 

judgment, the assessment is as extensive as practicable taking into account the EPA’s time, resources, and other 

duties and authorities.

352
approaches are a re-presentation of the modeling done for the Clean Power Plan Emission 

Guidelines RIA.

This approach is consistent with the analysis presented in the RIA for the final Clean 

Power Plan Emission Guidelines (U.S. EPA 2015). As a result, this RIA for the proposed federal 

plan and model trading rules re-presents the key results from the final Clean Power Plan 

Emission Guidelines RIA. These key results encompass the potential costs, emission reductions, 

and benefits of the proposed federal plan and model trading rules, as well as the potential 

impacts on electricity markets, employment, and markets outside the electricity sector. 

As mentioned earlier, the EPA is taking comment on many of the elements of the federal 

plan and model trading rules proposal. The RIA also presents a discussion of limitations of the 

analysis and solicitations for public comments that may help improvewill contribute to the 

analysis supporting the promulgation of final the federal plans (as needed) and model trading 

rules. In evaluating the impacts of the proposed federal plan and model trading rules, we address 

a number of uncertainties. 

It is important to note that the potential regulatory impacts presented in the Clean Power 

Plan Final Rule RIA and the RIA for this proposed rule are not additive. Both RIAs present 

estimates of the benefits and costs of achieving the emission performance rates of the Clean 

Power Plan emissions guidelines. In the case of the Clean Power Plan Final Rule RIA, the 

illustrative analysis assumes the performance rates are met under state plans. In the case of this 

RIA for the proposed federal plan and model trading rules, the same performance rates are 

accomplished but are assumed to be accomplished under the federal plan or model trading rules. 

This RIA also presents in Chapter 2 the statutory and executive order analyses that 

accompany the proposal for this action, including the Initial Flexibility Regulatory Analysis 

(IRFA). The IRFA describes the economic impact of the proposed rule on small entities and any 

significant alternatives to the proposed rule that would accomplish the objectives of the rule 

while minimizing significant economic impacts on small entities. This IRFA has been prepared 

353
following EPA’s guidance document for preparing initial and final regulatory flexibility 

analyses.7

1.4.1 Base Case and Years of Analysis 

The base case for this analysis, which uses the Integrated Planning Model (IPM), 

includes state rules that have been finalized and/or approved by a state’s legislature or 

environmental agencies, as well as final federal rules. The IPM Base Case v.5.15 includes the 

Cross-State Air Pollution Rule (CSAPR), the Mercury and Air Toxics Rule (MATS), the 

proposed Carbon Pollution Standards for New Power Plants, the Cooling Water Intakes (316(b)) 

Rule, the Combustion Residuals from Electric Utilities (CCR), and other state and Federal 

regulations to the extent that they contain measures, permits, or other air-related limitations or 

requirements. Additional legally binding and enforceable commitments for GHG reductions 

considered in the base case are discussed in the documentation for IPM.8 

To present a complete picture of the potential costs and benefits of the proposed federal 

plan and model trading rules, this RIA presents results for the analysis years 2020, 2025, and 

2030. While 2020 is before the first year of the interim compliance period (2022), the EPA 

expects states and affected EGUs to perform voluntary activities that will facilitate compliance 

with interim and final goals. These pre-compliance period activities might include investments in 

renewable energy or demand-side energy efficiency projects, for example, that produce 

emissions reductions in the compliance period. Activities might also include preparatory 

investments in transmission capacity or monitoring, reporting, and recordkeeping systems. As a 

result, there are likely to be benefits and costs in 2020, so these are reported in this RIA. 

Meanwhile, cost and benefits are estimated in this RIA for 2025, which is intended to represent a 

central period of the interim compliance time-frame as states are on glide paths toward fully 

meeting the final CO2 emission performance goals. Lastly, the RIA presents costs and benefits 

for 2030, when the emission performance goals are fully achieved. 

7 See “EPA’s Action Development Process: Final Guidance for EPA Rulewriters: Regulatory Flexibility Act as 

amended by the Small Business Regulatory Enforcement Fairness Act.” OPEI Regulatory Development Series. 

November 2006. Available at: <http://www.epa.gov/sbrefa/documents/Guidance-RegFlexAct.pdf>. Accessed July 

21, 2015.

8 Detailed documentation for IPM v.5.15 is available at: http://www.epa.gov/powersectormodeling. 

354
1.4.2 Federal Plan Approaches Examined in RIA 

In the Final Clean Power Plan Emission Guidelines, the EPA translated the source 

category-specific CO2 emission performance rates into equivalent state-level rate-based and 

mass-based CO2 goals in order to maximize the range of choices that states will have in 

developing their plans.9 As noted above, like the RIA for the Final Clean Power Plan Emission 

Guidelines, this RIA presents two scenarios designed to achieve these goals, which we term the 

rate-based federal plan approach and the mass-based federal plan approach. 

It is very important to note that the differences between the analytical results for the ratebased and mass-based federal plan approaches presented in this RIA may not be indicative of 

likely differences between the approaches. In other words, if one approach performs differently 

than the other on a given metric during a given time period, this does not imply this will apply in 

all instances in all time periods in all places.

In the rate-based approach modeled in the RIA for the final Clean Power Plan Emission 

Guidelines, avoided generation from demand-side energy efficiency is counted towards meeting 

the emission performance rates at affected EGUs. However, this proposed FPfederal plan and 

model trading rule proposal rule takes comment on whether or not EPA should does not allow 

demand-side energy efficiency to directly count toward the compliance rate of affected EGUs in 

a rate-based compliance approach. Because energy efficiency is not proposed to be eligible to 

generate ERCs that could be used to cost-effectively comply in the proposed rate-based federal 

plan, Therefore, the EPA estimates that this RIA might be forecasting a different a generatione 

mix and emissions levels understate the incremental compliance costs than of might occur from 

the proposed federal planan and model trading rules.

10 Compliance strategies under the federal 

planeither approach to the federal plan (mass or rate) may be anticipated to that do not rely on 

demand-side energy efficiency will likely rely on different abatement measures than those 

modeled for this RIA. The climate benefits and health co-benefits arising from these 

altenativealternative strategies may be different those presented here. The EPA is inviting 

9 See the preamble of the final Clean Power Plan Emissions Guidelines for these state-level rate-based and massbased CO2 goals. 

10 However,, as with in as with states subject to the mass-based approach, energy efficiency activities may be 

adopted by states subject to the rate-based approach to lower demand, which in turn may reduces the compliance 

cost of achieving the performance rates. 

355
comment on the inclusion of demand-side energy efficiency as a direct compliance measure 

under a rate-based approach in the federal plan.We will update this analysis as necessary to 

support the final rule. 

Even without explicit incentives for energy efficiency under a rate-based federal plan, we 

believe that the increased focus that the Clean Power Plan Emission Guidelines will bring to 

considerations of CO2 emissions from EGUs will encourage states to consider more aggressive 

demand-side energy policies. Furthermore, the EPA anticipates that many states will submit 

fully-approvable plans, and that demand side energy efficiency is likely to be either an explicit 

component of, or a complimentary policy to, many of those plans. The resulting lower electricity

demand in states not subject to a federal plan surrounding a state that is subject to a federal plan 

will likely have an impact on fossil generation and thus the cost of reducing CO2 emissions. The 

EPA takes comment on the appropriate way to factor such costs into the analysis of the final 

federal plan and model trading rules.

In the rate-based approach modeled in the RIA for the final Clean Power Plan Emission 

Guidelines, affected EGUs may not procure emission reductions from (e.g., by averaging their 

emissions with) affected EGUs located in other states (which may also have different emission 

standards) in order to demonstrate compliance. As described in Section 1.3.2, in the proposed 

rate-based federal plan affected EGUs may procure ERCs from affected EGUs in other ratebased states subject to the federal plan. Furthermore, the rate-based illustrative plan in the Final 

Clean Power Plan Emission Guidelines RIA assumes that the plan applies a state’s blended ratebased goal as a requirement for affected EGUs in that state to achieve.

11 Alternatively, tThe

proposed federal plan specifically establishes an emissions rate performance standard that is

applied to affected steam-fired EGUs and an emission rate performance standard that is applied 

to affected natural gas-fired combined cycle EGUs. Applying the subcategory-specific rate goal 

may alter the incentives among affected sourcesEGUs and could lead to a different generation 

11 In the rate-based scenario in the RIA for the final Clean Power Plan Emission Guidelines, the generation-weighted 

average emission rate from affected EGUs, in which generation is inclusive of their procurement of zero-emitting 

generation or demand-side EE savings, in a state must be less than or equal to the state goal. One way for a state 

to achieve this outcome would be to assign in its plan emission rate performance standards to affected EGUs that 

equal the state emission rate goal, the incentives of which would be consistent with the analysis and results 

reported in the RIA for the final Clean Power Plan Emission Guidelines. 

356
mixes and emissions levels. The EPA will further explore the impacts of subcategory-specific 

rate goals in the analysis supporting the final rule. 

The mass-based plan approach requires affected sources in each state to limit their 

aggregate emissions not to exceed the mass goal for that state. The mass-based scenario 

presented in this chapter includes a 5 percent set-aside of allowances that would be allocated to 

recognize deployment of new renewable capacity, which is represented by lowering the capital 

cost of new renewable capacity in a compliance period by the estimated value of the allowances 

in the set-aside in that period.

The EPA is also proposing a set-aside approach referred to as output-based allocation

(OBA), which provides targeted allocations of a limited portion of allowances to existing NGCC 

units as a means of mitigating leakage. The EPA believes that this proposed set-aside would help 

ensure the environmental integrity of a mass-based plan by addressing incentives for generation 

to shift away from EGUs covered under mass-based plans to new unaffected EGUs. OBA

provides an incentive for eligible EGUs in mass-based states to increase their generation in order 

to increase their allocation of allowances. This approach helps align the generation incentives for 

eligible EGUs in mass-based states with new EGUs within mass-based states that are not subject 

to the mass-based limits as well as analogous EGUs in other states covered by emission rate 

limits, mitigating the potential for emissions leakage.

While the mass-based scenario analyzed for this proposed rule included a representation 

of the set-aside for new renewable generation, it did not quantify the effects of the OBA as 

proposed in this rulemaking. Therefore, in Section 1.5.6, the EPA conducted additional analysis 

to approximate the potential emissions reductions if the OBA set-aside were included in that 

mass-based scenario. The EPA is inviting comment on OBA. If appropriate, Tthe EPA is inviting 

comment on its approach to approximating the impact of OBA. If appropriate, the EPA will 

further explore OBA as a means to mitigate leakage in the analysis supporting the final federal 

plan and model trading rules.

The EPA notes that, in this analysis, EGUs within each state comply with the applicable 

state goals without exchanging a compliance instrument with EGUs in other states. However, 

under the proposed federal plan and model trading rules if all states had a federal plan and the 

same type of goal (as they do in this analysis), then trading among EGUs in different states 

357
would be allowed and would lead to differences in the generation mix and emissions. The EPA is 

inviting comment on this approach to the modeling and will seek to improvethat will contribute 

to analysis supporting the final rule. 

358
1.5 Summary of Regulatory Analysis 

1.5.1 Emissions Reductions 

Table 1-1 shows the emission reductions associated with the modelledmodeled rate-based 

federal plan approach. 

Table 1-1. Climate and Air Pollutant Emission Reductions for the Rate-Based Federal Plan 

Approach1

 CO2

(million short tons)

SO2

(thousand short tons)

Annual NOX 

(thousand short tons)

2020 Rate-Based Approach

Base Case 2,155 1,311 1,333

Federal Plan Approach 2,085 1,297 1,282

Emissions Change -69 -14 -50

2025 Rate-Based Approach

Base Case 2,165 1,275 1,302

Federal Plan Approach 1,933 1,097 1,138

Emissions Change -232 -178 -165

2030 Rate-Based Approach

Base Case 2,227 1,314 1,293

Federal Plan Approach 1,812 996 1,011

Emission Change -415 -318 -282

Source: Integrated Planning Model, 2015. Emissions change may not sum due to rounding. 1 CO2 emission reductions are used to estimate the climate benefits of the proposed rule. SO2, and NOX reductions 

are relevant for estimating air quality health co-benefits of the proposed rule. The proposed rule is also expected to 

achieve reductions in directly emitted PM2.5, which we were not able to estimate for this RIA.

In 2020, the EPA estimates that CO2 emissions will be reduced by 69 million short tons 

under the rate-based approach compared to base case levels. In 2025, the EPA estimates that CO2

emissions will be reduced by 232 million short tons under the rate-based approach compared to 

base case levels. CO2 emission reductions increase to 415 million short tons annually in 2030 

when compared to the base case emissions. Table 1-1 also shows emission reductions for criteria 

air pollutants.

359
Table 1-2 shows the emission reductions associated with the modeled mass-based federal 

plan approach. 

Table 1-2. Climate and Air Pollutant Emission Reductions for the Mass-Based Federal Plan 

Appproach1

 CO2

(million short tons)

SO2

(thousand short tons)

Annual NOX 

(thousand short tons)

2020 Mass-Based Approach

Base Case 2,155 1,311 1,333

Federal Plan Approach 2,073 1,257 1,272

Emissions Change -81 -54 -60

2025 Mass-Based Approach

Base Case 2,165 1,275 1,302

Federal Plan Approach 1,901 1,090 1,100

Emissions Change -265 -185 -203

2030 Mass-Based Approach

Base Case 2,227 1,314 1,293

Federal Plan Approach 1,814 1,034 1,015

Emission Change -413 -280 -278

Source: Integrated Planning Model, 2015. Emissions change may not sum due to rounding. 1 CO2 emission reductions are used to estimate the climate benefits of the proposed rule. SO2, and NOX reductions 

are relevant for estimating air quality health co-benefits of the proposed rule. The proposed rule is also expected to 

achieve reductions in directly emitted PM2.5, which we were not able to estimate for this RIA.

In 2020, the EPA estimates that CO2 emissions will be reduced by 81 million short tons under 

the mass-based approach compared to base case levels. In 2025, the EPA estimates that CO2

emissions will be reduced by 265 million short tons under the mass-based approach compared to 

base case levels. CO2 emission reductions increase to 413 million short tons annually in 2030 

when compared to the base case emissions. Table 1-2 also shows emission reductions for criteria 

air pollutants. 

360
Table 1-3 presents CO2 emission reductions relative to 2005 for the two federal plan 

appoachesapproaches. 

Table 1-3. Projected CO2 Emission Reductions, Relative to 2005 

 CO2 Emissions 

(million short tons)

CO2 Emissions: 

Change from 2005 

(million short tons)

CO2 Emissions Reductions: 

Percent Change from 2005

 2005 2020 2025 2030 2020 2025 2030

Base Case 2,683 -528 -518 -456 -20% -19% -17%

Rate-based - -598 -750 -871 -22% -28% -32%

Mass-based - -610 -782 -869 -23% -29% -32%

Source: Integrated Planning Model, 2015. 

In 2020, the EPA estimates that CO2 emissions will be reduced by 598 million short tons (22 

percent) under the rate-based approach compared to 2005 levels. In 2025, the EPA estimates that 

CO2 emissions will be reduced by 750 million short tons (28 percent) under the rate-based 

approach compared to 2005 levels. Under the rate-based approach, CO2 emission reductions 

increase to 871 million short tons (32 percent) in 2030 when compared to 2005 levels. 

Under the mass-based approach in 2020, the EPA estimates that CO2 emissions will be 

reduced by 610 million short tons (23 percent) under the rate-based approach compared to 2005 

levels. In 2025, the EPA estimates that CO2 emissions will be reduced by 782 million short tons 

(29 percent) under the mass-based approach compared to 2005 levels. Under the mass-based 

approach, CO2 emission reductions increase to 869 million short tons (32 percent) in 2030 when 

compared to 2005 levels. 

1.5.2 Costs 

The compliance cost estimates in this analysis are the change in electric power 

generation costs between the base case and federal plan approach policy cases, including the cost 

of demand-side energy efficiency measures and costs associated with monitoring, reporting, and 

recordkeeping requirements (MR&R).

12 In the rate-based approach, energy efficiency activities 

are modeled as being used by EGUs as a low-cost method of demonstrating compliance with 

their rate-based emissions standards. In the mass-based approach, energy efficiency activities are 

assumed to be adopted by states to lower demand, which in turn reduces the cost of achieving the 

12 See Chapter 3 of the Clean Power Plan Final Rule RIA for a detailed discussion of the compliance cost estimates.

361
mass limitations. The level of energy efficiency measures is determined outside of IPM and is 

assumed to be the same in the two federal plan approaches.13 The compliance assumptions, and 

therefore the projected “compliance costs” set forth in this analysis, are illustrative in nature. 

The annual compliance cost is the projected additional cost of complying with the rule in 

the year analyzed and reflects the net difference in the sum of the annualized cost of capital 

investment in new generating sources and heat rate improvements at coal steam facilities,The 

annual incremental cost is the projected additional cost of complying with the proposed rule in 

the year analyzed and includes the net change in the annualized cost of capital investment in new 

generating sources and heat rate improvements at coal-fired steam generating units, the change in 

the ongoing costs of operating pollution controls, shifts between or amongst various fuels, 

demand-side energy efficiency measures, and other actions associated with compliance. The total 

compliance cost estimates presented here include the costs associated with monitoring, reporting, 

and recordkeeping.14 The costs for both federal plan approaches are reflected in Table 1-4 below. 

All dollar estimates are in 2011 dollars.

The EPA estimates the annual incremental compliance cost for the rate-based approach 

for the proposed federal plan and model trading rules to be $2.5 billion in 2020, $1.0 billion in 

2025 and $8.4 billion in 2030, including the costs associated with monitoring, reporting, and 

recordkeeping.

15 The EPA estimates the annual incremental compliance cost for the mass-based 

approach for the federal plan and model trading rules to be $1.4 billion in 2020, $3.0 billion in 

2025 and $5.1 billion in 2030, including the costs associated with monitoring, reporting, and 

recordkeeping. 

13 For more detailed information on demand-side energy efficiency, see U.S. EPA. 2015b. Technical Support 

Document (TSD) the Final Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility 

Generating Units. Demand-Side Energy Efficiency.

14 These costs are estimated outside of the IPM modellingmodeling framework as IPM only models the contiguous 

U.S. and does not incorporate monitoring, reporting, and recordkeeping requirements specific to the Clean Power 

Plan Final Rule.

15 The MR&R costs of the proposed federal plan and model trading rules are assumed to be the same as those 

estimated for the Clean Power Plan Final Rule. These MR&R costs estimates are $65 million in 2020, $15 million 

in 2025 and $15 million in 2030 and are assumed to be the same for both rate-based and mass-based plan 

approaches. Note the MR&R costs in 2020 are related to facilities setting up net energy output monitoring and 

upgrading data acquisition systems.

362
Table 1-4. Compliance Costs for the Federal Rate-Based and Mass-Based Plan Approaches

Incremental Cost from Base Case (billions of 2011$)

Rate-based Approach Mass-based Approach 

2020 $2.5 $1.4

2025 $1.0 $3.0

2030 $8.4 $5.1

Source: Integrated Planning Model, 2015, with post-processing to account for exogenous demand-side management 

energy efficiency costs and monitoring, reporting, and recordkeeping costs. See Chapter 3 of the Clean Power Plan 

Final Rule RIA for a more complete explanation.

The costs reported in Table 1-4 represent the estimated incremental electric utility 

generating costs changes from the base case plus the estimates of demand-side energy efficiency 

program costs (which are paid by electric utilities), demand-side energy efficiency participant 

costs (which are paid by electricity consumers), and MR&R costs. For example, in 2030, under 

the rate-based approach, the incremental electric utility generating costs decline by about $18.0 

billion from the base case. MR&R requirements in 2030 are estimated at $16.0 million, and 

demand-side energy efficiency costs in 2030 are estimated to be $26.3 billion, split equally 

between program and participants using a 3 percent discount rate (see Chapter 3 of this RIA for 

more details on these estimates). These cost estimates sum to the $8.4 billion shown in Table 1-4 

and represent the total costs of the rate-based federal plan approach in 2030. The same approach 

applies in each year of analysis for the rate-based and the mass-based federal plan approaches.

The compliance costs reported in Table 1-4 are not social costs. These costs represent the 

estimated expenditures incurred by EGUs, the costs to participants in demand-side energy 

efficiency programs, and states to comply with the BSER goals for the Final Clean Power Plan 

Emission Guidelines. These compliance cost estimates are compared to estimates of social 

benefits to derive net benefits of the proposed federal plan and model trading rules, which are 

presented later in this Chapter. 

1.5.3 Monetized Climate Benefits and Health Co-benefits

The climate benefits estimates have been calculated using the estimated values of 

marginal climate impacts presented in the Technical Support Document: Technical Update of the 

Social Cost of Carbon for Regulatory Impact Analysis under Executive Order 12866 (May 2013, 

363
Revised July 2015), henceforth denoted as the current SC-CO2 TSD.16 Additionally, this analysis 

takes into account the social benefits of changes in emissions of non-CO2 pollutants from the 

electricity sector. The range of combined benefits reflects different concentration-response 

functions for the air quality health co-benefits, but it does not capture the full range of 

uncertainty inherent in the health co-benefits estimates. Furthermore, we were unable to quantify 

or monetize all of the climate benefits and health and environmental co-benefits associated with 

the proposed federal plan and model trading rules, including reductions in directly emitted PM2.5, 

reduced exposure to SO2, NOX, and hazardous air pollutants (e.g., mercury), as well as 

ecosystem effects and visibility improvement. The omission of these endpoints from the 

monetized results should not imply that the impacts are small or unimportant. Table 1-5 provides 

the list of the quantified and unquantified health and environmental benefits in this analysis. 

16 Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon, with participation by 

Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture, Department of 

Commerce, Department of Energy, Department of Transportation, Domestic Policy Council, Environmental 

Protection Agency, National Economic Council, Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (May 2013, Revised July 2015). Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf> Accessed 7/11/2015.

364
Table 1-5 Quantified and Unquantified Benefits

Benefits Category Specific Effect

Effect Has 

Been 

Quantified

Effect Has 

Been 

Monetized

More Information

Improved 

Environment

Reduced climate 

effects

Global climate impacts from CO2 —1  SC-CO2 TSD

Climate impacts from ozone and black carbon (directly 

emitted PM) — — Ozone ISA, PM ISA2

Other climate impacts (e.g., other GHGs such as methane, 

aerosols, other impacts) — — IPCC2

Improved Human Health (co-benefits)

Reduced incidence of 

premature mortality 

from exposure to 

PM2.5

Adult premature mortality based on cohort study estimates

and expert elicitation estimates (age >25 or age >30)   PM ISA

Infant mortality (age <1)   PM ISA

Reduced incidence of 

morbidity from 

exposure to PM2.5

Non-fatal heart attacks (age > 18)   PM ISA

Hospital admissions—respiratory (all ages)   PM ISA

Hospital admissions—cardiovascular (age >20)   PM ISA

Emergency room visits for asthma (all ages)   PM ISA

Acute bronchitis (age 8-12)   PM ISA

Lower respiratory symptoms (age 7-14)   PM ISA

Upper respiratory symptoms (asthmatics age 9-11)   PM ISA

Asthma exacerbation (asthmatics age 6-18)   PM ISA

Lost work days (age 18-65)   PM ISA

Minor restricted-activity days (age 18-65)   PM ISA

Chronic Bronchitis (age >26) — — PM ISA2

Emergency room visits for cardiovascular effects (all ages) — — PM ISA2

Strokes and cerebrovascular disease (age 50-79) — — PM ISA2

Other cardiovascular effects (e.g., other ages) — — PM ISA3

Other respiratory effects (e.g., pulmonary function, nonasthma ER visits, non-bronchitis chronic diseases, other 

ages and populations)

— — PM ISA3

Reproductive and developmental effects (e.g., low birth 

weight, pre-term births, etc) — — PM ISA3,4

Cancer, mutagenicity, and genotoxicity effects — — PM ISA3,4

Reduced incidence of 

mortality from 

exposure to ozone

Premature mortality based on short-term study estimates (all 

ages)   Ozone ISA

Premature mortality based on long-term study estimates 

(age 30–99) — — Ozone ISA2

Reduced incidence of 

morbidity from 

exposure to ozone

Hospital admissions—respiratory causes (age > 65)   Ozone ISA

Hospital admissions—respiratory causes (age <2)   Ozone ISA

Emergency department visits for asthma (all ages)   Ozone ISA

Minor restricted-activity days (age 18–65)   Ozone ISA

School absence days (age 5–17)   Ozone ISA

Decreased outdoor worker productivity (age 18–65) — — Ozone ISA2

Other respiratory effects (e.g., premature aging of lungs) — — Ozone ISA3

Cardiovascular and nervous system effects — — Ozone ISA3

Reproductive and developmental effects — — Ozone ISA3,4

365
Table 1-5. Continued

Reduced incidence of 

morbidity from 

exposure to NO2

Asthma hospital admissions (all ages) — — NO2 ISA2

Chronic lung disease hospital admissions (age > 65) — — NO2 ISA2

Respiratory emergency department visits (all ages) — — NO2 ISA2

Asthma exacerbation (asthmatics age 4–18) — — NO2 ISA2

Acute respiratory symptoms (age 7–14) — — NO2 ISA2

Premature mortality — — NO2 ISA2,3,4

Other respiratory effects (e.g., airway hyperresponsiveness 

and inflammation, lung function, other ages and 

populations)

— — NO2 ISA3,4

Reduced incidence of 

morbidity from 

exposure to SO2

Respiratory hospital admissions (age > 65) — — SO2 ISA2

Asthma emergency department visits (all ages) — — SO2 ISA2

Asthma exacerbation (asthmatics age 4–12) — — SO2 ISA2

Acute respiratory symptoms (age 7–14) — — SO2 ISA2

Premature mortality — — SO2 ISA2,3,4

Other respiratory effects (e.g., airway hyperresponsiveness 

and inflammation, lung function, other ages and 

populations)

— — SO2 ISA2,3

Reduced incidence of 

morbidity from 

exposure to 

methylmercury

Neurologic effects—IQ loss — — IRIS; NRC, 20002

Other neurologic effects (e.g., developmental delays, 

memory, behavior) — — IRIS; NRC, 20003

Cardiovascular effects — — IRIS; NRC, 20003,4

Genotoxic, immunologic, and other toxic effects — — IRIS; NRC, 20003,4

Improved Environment (co-benefits)

Reduced visibility 

impairment

Visibility in Class 1 areas — — PM ISA2

Visibility in residential areas — — PM ISA2

Reduced effects on 

materials

Household soiling — — PM ISA2,3

Materials damage (e.g., corrosion, increased wear) — — PM ISA3

Reduced PM 

deposition (metals and 

organics)

Effects on individual organisms and ecosystems — — PM ISA3

Reduced vegetation 

and ecosystem effects 

from exposure to 

ozone

Visible foliar injury on vegetation — — Ozone ISA2

Reduced vegetation growth and reproduction — — Ozone ISA2

Yield and quality of commercial forest products and crops — — Ozone ISA2

Damage to urban ornamental plants — — Ozone ISA3

Carbon sequestration in terrestrial ecosystems — — Ozone ISA2

Recreational demand associated with forest aesthetics — — Ozone ISA3

Other non-use effects Ozone ISA3

Ecosystem functions (e.g., water cycling, biogeochemical 

cycles, net primary productivity, leaf-gas exchange, 

community composition)

— — Ozone ISA3

Reduced effects from 

acid deposition

Recreational fishing — — NOx SOx ISA2

Tree mortality and decline — — NOx SOx ISA3

Commercial fishing and forestry effects — — NOx SOx ISA3

Recreational demand in terrestrial and aquatic ecosystems — — NOx SOx ISA3

Other non-use effects NOx SOx ISA3

Ecosystem functions (e.g., biogeochemical cycles) — — NOx SOx ISA3

366
Table 1-5. Continued

Reduced effects from 

nutrient enrichment

Species composition and biodiversity in terrestrial and 

estuarine ecosystems — — NOx SOx ISA3

Coastal eutrophication — — NOx SOx ISA3

Recreational demand in terrestrial and estuarine ecosystems — — NOx SOx ISA3

Other non-use effects NOx SOx ISA3

Ecosystem functions (e.g., biogeochemical cycles, fire 

regulation) — — NOx SOx ISA3

Reduced vegetation 

effects from exposure 

to SO2 and NOx

Injury to vegetation from SO2 exposure — — NOx SOx ISA3

Injury to vegetation from NOx exposure — — NOx SOx ISA3

Reduced ecosystem 

effects from exposure 

to methylmercury

Effects on fish, birds, and mammals (e.g., reproductive 

effects) — — Mercury Study RTC3

Commercial, subsistence and recreational fishing — — Mercury Study 

RTC2

1 The global climate and related impacts of CO2 emissions changes, such as sea level rise, are estimated within each 

integrated assessment model as part of the calculation of the SC-CO2. The resulting monetized damages, which 

are relevant for conducting the benefit-cost analysis, are used in this RIA to estimate the welfare effects of 

quantified changes in CO2 emissions.

2 We assess these co-benefits qualitatively, as reported in the Chapter 4 of the Clean Power Plan Final Rule RIA, 

due to data and resource limitations for this analysis.

3 We assess these co-benefits qualitatively, as reported in the Chapter 4 of the Clean Power Plan Final Rule RIA, 

because we do not have sufficient confidence in available data or methods.

4 We assess these co-benefits qualitatively, as reported in the Chapter 4 of the Clean Power Plan Final Rule RIA, 

because current evidence is only suggestive of causality or there are other significant concerns over the strength of 

the association.

1.5.3.1 Estimating Global Climate Benefits

We estimate the global social benefits of CO2 emission reductions expected from this 

rulemaking using the SC-CO2 estimates presented in the current SC-CO2 TSD.17 We refer to 

these estimates, which were developed by the U.S. government, as “SC-CO2 estimates” for the 

remainder of this document. The SC-CO2 is a metric that estimates the monetary value of 

impacts associated with marginal changes in CO2 emissions in a given year. It includes a wide 

range of anticipated climate impacts, such as net changes in agricultural productivity and human 

health, property damage from increased flood risk, and changes in energy system costs, such as 

reduced costs for heating and increased costs for air conditioning. It is typically used to assess 

17 Also see Chapter 4 of the Clean Power Plan Final Rule RIA for more details on this assessment of climate

benefits.

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the avoided damages as a result of regulatory actions (i.e., benefits of rulemakings that lead to an 

incremental reduction in cumulative global CO2 emissions). 

The SC-CO2 estimates used in this analysis have been developed over many years, using 

the best science available, and with input from the public. The EPA and other federal agencies 

have considered the extensive public comments on ways to improve SC-CO2 estimation received 

via the notice and comment period that was part of numerous rulemakings. In addition, OMB’s 

Office of Information and Regulatory Affairs recently issued a response to the public comments 

it sought through a separate comment period on the approach used to develop the SC-CO2

estimates.18

An interagency working group (IWG) that included the EPA and other executive branch 

entities used three integrated assessment models (IAMs) to develop SC-CO2 estimates and 

recommended four global values for use in regulatory analyses. The SC-CO2 estimates represent 

global measures because of the distinctive nature of the climate change problem. Emissions of 

greenhouse gases contribute to damages around the world, even when they are released in the 

United States, and the world’s economies are now highly interconnected. Therefore, the SC-CO2 

estimates incorporate the worldwide damages caused by carbon dioxide emissions in order to 

reflect the global nature of the problem, and we expect other governments to consider the global 

consequences of their greenhouse gas emissions when setting their own domestic policies. See 

Chapter 4 of the final Clean Power Plan Emission Guidelines RIA for more discussion. 

The IWG first released the estimates in February 2010 and updated them in 2013 using 

new versions of each IAM. The SC-CO2 values was estimated using three integrated assessment 

models (DICE, FUND, and PAGE)19, which the IWG harmonized across three key inputs: the 

probability distribution for equilibrium climate sensitivity; five scenarios for economic, 

population, and emissions growth; and three constant discount rates. The 2010 SC-CO2

Technical Support Document (2010 SC-CO2 TSD) provides a complete discussion of the 

methodology and the current SC-CO2 TSD20 presents and discusses the updated estimates. The 

18 See https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-comments-final-july-2015.pdf 

19 The full models names are as follows: Dynamic Integrated Climate and Economy (DICE); Climate Framework for 

Uncertainty, Negotiation, and Distribution (FUND); and Policy Analysis of the Greenhouse Gas Effect (PAGE).

20 The IWG published the updated TSD in 2013, then issued two minor corrections to it in July 2015. 

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four SC-CO2 estimates are as follows: $12, $40, $60, and $120 per short ton of CO2 emissions in 

the year 2020 (2011$), and each estimate increases over time.21 These SC-CO2 estimates are 

associated with different discount rates. The first three estimates are the model average at 5 

percent discount rate, 3 percent, and 2.5 percent, respectively, and the fourth estimate is the 95th

percentile at 3 percent. 

 The 2010 SC-CO2 TSD noted a number of limitations to the SC-CO2 analysis, including 

the incomplete way in which the IAMs capture catastrophic and non-catastrophic impacts, their 

incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of 

damages to high temperatures, and assumptions regarding risk aversion. Currently integrated 

assessment models do not assign value to all of the important physical, ecological, and economic 

impacts of climate change recognized in the climate change literature because of a lack of 

precise information on the nature of damages and because the science incorporated into these 

models understandably lags behind the most recent research.22 In particular, the IPCC Fourth 

Assessment Report concluded that “It is very likely that [SC-CO2 estimates] underestimate the 

damage costs because they cannot include many non-quantifiable impacts.” Nonetheless, these 

estimates and the discussion of their limitations represent the best available information about 

the social benefits of CO2 emission reductions to inform the benefit-cost analysis. 

In addition, after careful evaluation of the full range of comments submitted to OMB’s 

Office of Information and Regulatory Affairs, the IWG continues to recommend the use of these

SC-CO2 estimates in regulatory impact analysis. With the release of the response to comments, 

the IWG announced plans to obtain expert independent advice from the National Academies of 

Sciences, Engineering, and Medicine (Academies) to ensure that the SC-CO2 estimates continue 

to reflect the best available scientific and economic information on climate change.23 The 

21 The 2010 and 2013 TSDs present SC-CO2 in 2007$ per metric ton. The unrounded estimates from the current 

TSD were adjusted to (1) short tons using the conversion factor of 0.90718474 metric tons in a short ton and (21) 

2011$ using GDP Implicit Price Deflator (1.061374), http://www.bea.gov/iTable/index_nipa.cfm, . and (2) short

tons using the conversion factor of 0.90718474 metric tons in a short ton. These estimates were rounded to two 

significant digits. 

22 Climate change impacts and SCC modeling is an area of active research. For example, see: (1) Howard, Peter, 

“Omitted Damages: What’s Missing from the Social Cost of Carbon.” March 13, 2014, 

http://costofcarbon.org/files/Omitted_Damages_Whats_Missing_From_the_Social_Cost_of_Carbon.pdf; and (2) 

Electric Power Research Institute, “Understanding the Social Cost of Carbon: A Technical Assessment,” October 

2014, www.epri.com.

23 See <https://www.whitehouse.gov/blog/2015/07/02/estimating-benefits-carbon-dioxide-emissions-reductions>.

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Academies’ process will be informed by the public comments received and focus on the 

technical merits and challenges of potential approaches to improving the SC-CO2 estimates in 

future updates. 

1.5.3.2 Estimating Air Quality Health Co-Benefits

The proposed federal plan and model trading rules would reduce emissions of precursor 

pollutants (e.g., SO2, NOX, and directly emitted particles), which in turn would lower ambient 

concentrations of PM2.5 and ozone. This co-benefits analysis quantifies the monetized benefits 

associated with the reduced exposure to these two pollutants.24 Unlike the global SC-CO2

estimates, the air quality health co-benefits are only estimated for the contiguous U.S. The 

estimates of monetized PM2.5 co-benefits include avoided premature deaths (derived from effect 

coefficients in two cohort studies [Krewski et al. 2009 and Lepeule et al. 2012] for adults and 

one for infants [Woodruff et al. 1997]), as well as avoided morbidity effects for ten non-fatal 

endpoints ranging in severity from lower respiratory symptoms to heart attacks25 (U.S. EPA, 

2012). The estimates of monetized ozone co-benefits include avoided premature deaths (derived 

from the range of effect coefficients represented by two short-term epidemiology studies [Bell et 

al. (2004) and Levy et al. (2005)]), as well as avoided morbidity effects for five non-fatal 

endpoints ranging in severity from school absence days to hospital admissions (U.S. EPA, 2008, 

2011). 

We use a “benefit-per-ton” approach to estimate the PM2.5 and ozone co-benefits in this 

RIA. Benefit-per-ton approaches apply an average benefit per ton derived from modeling of 

benefits of specific air quality scenarios to estimates of emissions reductions for scenarios where 

no air quality modeling is available. The benefit-per-ton approach we use in this RIA relies on 

estimates of human health responses to exposure to PM and ozone obtained from the peerreviewed scientific literature. These estimates are used in conjunction with population data, 

24 We did not estimate the co-benefits associated with reducing direct exposure to SO2 and NOX. For this RIA, we 

did not estimate changes in emissions of directly emitted particles. As a result, quantified PM2.5 related benefits 

are underestimated by a relatively small amount. In the proposal RIA, the benefits from reductions in directly 

emitted PM2.5 were less than 10 percent of total monetized health co-benefits across all scenarios and years.

25 See Chapter 4 and Appendix 4A of the Clean Power Plan Final Rule for details on this assessment of health cobenefits.

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baseline health information, air quality data and economic valuation information to conduct 

health impact and economic benefits assessments. 

Specifically, in this analysis, we multiplied the benefit-per-ton estimates by the 

corresponding emission reductions that were generated from air quality modeling of the 

proposed Clean Power Plan Emission Guidelines. Similar to the co-benefits analysis conducted 

for the final Clean Power Plan Emission Guidelines RIA, we generated regional benefit-per-ton 

estimates by aggregating the impacts in BenMAP26 to the region (i.e., East, West, and 

California) rather than aggregating to the nation. The benefit-per-ton for SO2 and NOx emissions 

used in this proposed rule were calculated using air quality modeling of the base case and the 

proposed Clean Power Plan (Option 1 State) scenario for 2025 as described in Appendix 4A of 

the final Clean Power Plan Emission Guidelines RIA. The benefit-per-ton values for 2020 and 

2030 are based on applying the air quality modeling from 2025 to population and health 

information from 2020 and 2030. 

To calculate the co-benefits for this proposed rule, we then multiplied the regional 

benefit-per-ton estimates for the EGU sector by the corresponding emission reductions. All 

benefit-per-ton estimates reflect the geographic distribution of the modeled emissions, which 

may not exactly match the emission reductions in this rulemaking, and thus they may not reflect 

the local variability in population density, meteorology, exposure, baseline health incidence 

rates, or other local factors for any specific location. 

Our estimate of the monetized co-benefits is based on the EPA’s interpretation of the best 

available scientific literature (U.S. EPA, 2009) and methods and supported by the EPA’s Science 

Advisory Board and the NAS (NRC, 2002). Below are key assumptions underlying the estimates 

for PM2.5-related premature mortality, which accounts for 98 percent of the monetized PM2.5

health co-benefits. 

1. We assume that all fine particles, regardless of their chemical composition, are 

equally potent in causing premature mortality. This is an important assumption, 

26 BenMAP is a computer program developed by the EPA that calculates the number and economic value of air 

pollution-related deaths and illnesses. The software incorporates a database that includes many of the 

concentration-response relationships, population files, and health and economic data needed to quantify these 

impacts.

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because PM2.5 varies considerably in composition across sources, but the scientific 

evidence is not yet sufficient to allow differentiation of effect estimates by particle 

type. The PM ISA concluded that “many constituents of PM2.5 can be linked with 

multiple health effects, and the evidence is not yet sufficient to allow differentiation 

of those constituents or sources that are more closely related to specific outcomes” 

(U.S. EPA, 2009b). 

2. We assume that the health impact function for fine particles is log-linear without a 

threshold in this analysis. Thus, the estimates include health co-benefits from 

reducing fine particles in areas with varied concentrations of PM2.5, including both 

areas that do not meet the National Ambient Air Quality Standard for fine particles 

and those areas that are in attainment, down to the lowest modeled concentrations. 

3. We assume that there is a “cessation” lag between the change in PM exposures and 

the total realization of changes in mortality effects. Specifically, we assume that some 

of the incidences of premature mortality related to PM2.5 exposures occur in a 

distributed fashion over the 20 years following exposure based on the advice of the 

SAB-H1 (U.S. EPA-SAB, 2004c), which affects the valuation of mortality cobenefits at different discount rates.

Every benefits analysis examining the potential effects of a change in environmental 

protection requirements is limited, to some extent, by data gaps, model capabilities (such as 

geographic coverage) and uncertainties in the underlying scientific and economic studies used to 

configure the benefit and cost models. Despite these uncertainties, we believe this analysis 

provides a reasonable indication of the expected health co-benefits of the air quality emission 

reductions for the proposed rule under a set of reasonable assumptions. This analysis does not 

include the type of detailed uncertainty assessment found in the 2012 PM2.5 National Ambient 

Air Quality Standard (NAAQS) RIA (U.S. EPA, 2012) because we lack the necessary air quality 

input and monitoring data to conduct a complete benefits assessment. In addition, using a 

benefit-per-ton approach adds another important source of uncertainty to the benefits estimates. 

1.5.3.3 Combined Benefits Estimates

The EPA has evaluated the range of potential impacts by combining all four SC-CO2

values with health co-benefits values at the 3 percent and 7 percent discount rates. Different 

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discount rates are applied to SC-CO2 than to the health co-benefit estimates because CO2

emissions are long-lived and subsequent damages occur over many years. Moreover, several 

discount rates are applied to SC-CO2 because the literature shows that the estimate of SC-CO2 is 

sensitive to assumptions about discount rate and because no consensus exists on the appropriate 

rate to use in an intergenerational context. The IWG centered its attention on the average SCCO2 at a 3 percent discount rate but emphasized the importance of considering all four SC-CO2

estimates. Table 1-6 (rate-based federal plan approach) and Table 1-7 (mass-based federal plan 

approach) provide the combined climate benefits and health co-benefits for the proposed federal 

plan model trading rules estimated for 2020, 2025, and 2030 for each discount rate combination. 

All dollar estimates are in 2011 dollars.

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Table 1-6. Combined Estimates of Climate Benefits and Health Co-Benefits for Rate-Based 

Approach (billions of 2011$)* 

SC-CO2 Discount Rate and Statistic**

Climate 

Benefits 

Only

Climate Benefits plus Health Co-benefits 

(Discount Rate Applied to Health Co-benefits)

3% 7%

In 2020 69 million short tons CO2

5% $0.80 $1.5 to $2.6 $1.4 to $2.5

3% $2.8 $3.5 to $4.6 $3.5 to $4.5

2.5% $4.1 $4.9 to $6.0 $4.8 to $5.9

3% (95th percentile) $8.2 $8.9 to $10 $8.9 to $9.9

In 2025 232 million short tons CO2

5% $3.1 $11 to $21 $9.9 to $19

3% $10 $18 to $28 $17 to $26

2.5% $15 $23 to $33 $22 to $31

3% (95th percentile) $31 $38 to $49 $38 to $47

In 2030 415 million short tons CO2

5% $6.4 $21 to $40 $19 to $37

3% $20 $34 to $54 $33 to $51

2.5% $29 $43 to $63 $42 to $60

3% (95th percentile) $61 $75 to $95 $74 to $92

*All benefit estimates are rounded to two significant figures. Climate benefits are based on reductions in CO2

emissions. Co-benefits are based on regional benefit-per-ton estimates. Ozone co-benefits occur in analysis year, so 

they are the same for all discount rates. The health co-benefits reflect the sum of the PM2.5 and ozone co-benefits 

and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Bell et al. (2004) to 

Lepeule et al. (2012) with Levy et al. (2005)). The monetized health co-benefits do not include reduced health 

effects from reductions in directly emitted PM2.5, direct exposure to NOX, SO2, and HAP; ecosystem effects; or 

visibility impairment. See Chapter 4 of the Clean Power Plan Final Rule RIA for more information about these 

estimates and for more information regarding the uncertainty in these estimates.

**Unless otherwise specified, the row reflects the average SC-CO2 estimate for the specified discount rate. 

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Table 1-7. Combined Estimates of Climate Benefits and Health Co-benefits for Mass-Based 

Approach (billions of 2011$)* 

SC-CO2 Discount Rate and Statistic**

Climate 

Benefits 

Only

Climate Benefits plus Health Co-benefits 

(Discount Rate Applied to Health Co-benefits)

3% 7%

In 2020 82 million short tons CO2

5% $0.94 $2.9 to $5.7 $2.8 to $5.3

3% $3.3 $5.3 to $8.1 $5.1 to $7.7

2.5% $4.9 $6.9 to $9.7 $6.7 to $9.3

3% (95th percentile) $9.7 $12 to $14 $11 to $14

In 2025 264 million short tons CO2

5% $3.6 $11 to $21 $10 to $19

3% $12 $19 to $29 $18 to $27

2.5% $17 $24 to $35 $24 to $33

3% (95th percentile) $35 $42 to $52 $42 to $51

In 2030 413 million short tons CO2

5% $6.4 $18 to $34 $17 to $32

3% $20 $32 to $48 $31 to $46

2.5% $29 $41 to $57 $40 to $55

3% (95th percentile) $60 $72 to $89 $71 to $86

*All benefit estimates are rounded to two significant figures. Climate benefits are based on reductions in CO2

emissions. Co-benefits are based on regional benefit-per-ton estimates. Ozone co-benefits occur in analysis year, so 

they are the same for all discount rates. The health co-benefits reflect the sum of the PM2.5 and ozone co-benefits 

and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Bell et al. (2004) to 

Lepeule et al. (2012) with Levy et al. (2005)). The monetized health co-benefits do not include reduced health 

effects from reductions in directly emitted PM2.5, direct exposure to NOX, SO2, and HAP; ecosystem effects; or 

visibility impairment. See Chapter 4 of the Clean Power Plan Final Rule RIA for more information about these 

estimates and for more information regarding the uncertainty in these estimates.

**Unless otherwise specified, the row reflects the average SC-CO2 estimate for the specified discount rate. 

1.5.4 Net Benefits

Table 1-8 and 1-9 provide the estimates of the climate benefits, health co-benefits, 

compliance costs and net benefits of the proposed federal plan and model trading rules for ratebased and mass-based approaches, respectively. There are additional important benefits that the 

EPA could not monetize. Due to current data and modeling limitations, our estimates of the 

benefits from reducing CO2 emissions do not include important impacts like ocean acidification 

or potential tipping points in natural or managed ecosystems. Unquantified benefits also include 

climate benefits from reducing emissions of non-CO2 greenhouse gases and co-benefits from 

reducing exposure to SO2, NOX, and hazardous air pollutants (e.g., mercury), as well as 

ecosystem effects and visibility impairment. Upon considering these limitations and 

uncertainties, it remains clear that the benefits of this proposed rule are substantial and far 

outweigh the costs. 

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Table 1-8. Monetized Benefits, Compliance Costs, and Net Benefits Under the Rate-based 

Federal Plan Approach (billions of 2011$) a 

Rate-Based Approach 

2020 2025 2030

Climate Benefits b

5% discount rate $0.80 $3.1 $6.4 

3% discount rate $2.8 $10 $20 

2.5% discount rate $4.1 $15 $29 

95th percentile at 3% 

discount rate $8.2 $31 $61 

Air Quality Co-benefits Discount Rate

3% 7% 3% 7% 3% 7%

Air Quality Health 

Co-benefits c $0.70 to $1.8 $0.64 to $1.7 $7.4 to $18 $6.7 to $16 $14 to $34 $13 to $31

Compliance Costs d $2.5 $1.0 $8.4

Net Benefits e $1.0 to $2.1 $1.0 to $2.0 $17 to $27 $16 to $25 $26 to $45 $25 to $43 

Non-Monetized 

Benefits

Non-monetized climate benefits

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and mercury

Visibility impairment

a All are rounded to two significant figures, so figures may not sum.

b The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does 

not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SC-CO2 than to the 

other estimates because CO2 emissions are long-lived and subsequent damages occur over many years. The net 

benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount rate, however we 

emphasize the importance and value of considering the full range of SC-CO2 values. As shown in this table, climate 

benefits are also estimated using the other three SC-CO2 estimates (model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2 estimates are year-specific and increase over time. c The air quality health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions

of SO2 and NOX. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These 

additional benefits would increase overall benefits by a few percent based on the analyses conducted for the 

proposed rule. The range reflects the use of concentration-response functions from different epidemiology studies. 

The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. Estimates in the table are presented for three analytical years with air quality cobenefits calculated using two discount rates. The estimates of co-benefits are annual estimates in each of the 

analytical years, reflecting discounting of mortality benefits over the cessation lag between changes in PM2.5

concentrations and changes in risks of premature death (see Chapter 4 of the Clean Power Plan Final Rule RIA for 

more details), and discounting of morbidity benefits due to the multiple years of costs associated with some 

illnesses. The estimates are not the present value of the benefits of the rule over the full compliance period.

d Compliance costs are the compliance costs estimated using the Integrated Planning Model and a discount rate of 

approximately 5 percent. It also includes monitoring, recordkeeping, and reporting costs and demand-side energy 

efficiency program and participant costs.

e The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount 

rate (model average). The Clean Power Plan Final Rule RIA includes combined climate and health estimates based 

on additional discount rates.

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Table 1-9. Monetized Benefits, Compliance Costs, and Net Benefits under the Mass-based 

Federal Plan Approach (billions of 2011$) a 

Mass-Based Approach 

2020 2025 2030

Climate Benefits b

5% discount rate $0.94 $3.6 $6.4 

3% discount rate $3.3 $12 $20

2.5% discount rate $4.9 $17 $29 

95th percentile at 3% 

discount rate $9.7 $35 $60 

Air Quality Co-benefits Discount Rate

3% 7% 3% 7% 3% 7%

Air Quality Health 

Co-benefits c $2.0 to $4.8 $1.8 to $4.4 $7.1 to $17 $6.5 to $16 $12 to $28 $11 to $26

Compliance Costs d $1.4 $3.0 $5.1

Net Benefits e $3.9 to $6.7 $3.7 to $6.3 $16 to $26 $15 to $24 $26 to $43 $25 to $40

Non-Monetized 

Benefits

Non-monetized climate benefits

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and 

mercury

Visibility improvement

a All are rounded to two significant figures, so figures may not sum.

b The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does 

not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SC-CO2 than to the 

other estimates because CO2 emissions are long-lived and subsequent damages occur over many years. The net 

benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount rate, however we 

emphasize the importance and value of considering the full range of SC-CO2 values. As shown in this table, climate 

benefits are also estimated using the other three SC-CO2 estimates (model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2 estimates are year-specific and increase over time. c The air quality health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions

of SO2 and NOX. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These 

additional benefits would increase overall benefits by a few percent based on the analyses conducted for the 

proposed rule. The range reflects the use of concentration-response functions from different epidemiology studies. 

The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. Estimates in the table are presented for three analytical years with air quality cobenefits calculated using two discount rates. The estimates of co-benefits are annual estimates in each of the 

analytical years, reflecting discounting of mortality benefits over the cessation lag between changes in PM2.5

concentrations and changes in risks of premature death (see Chapter 4 of the Clean Power Plan Final Rule RIA for 

more details), and discounting of morbidity benefits due to the multiple years of costs associated with some 

illnesses. The estimates are not the present value of the benefits of the rule over the full compliance period. d Compliance costs are the compliance costs estimated using the Integrated Planning Model and a discount rate of 

approximately 5 percent. It also includes monitoring, recordkeeping, and reporting costs and demand-side energy 

efficiency program and participant costs.

e The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount 

rate (model average). The Clean Power Plan Final Rule RIA includes combined climate and health estimates based 

on additional discount rates.

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1.5.5 Economic Impacts 

The federal plan approaches analyzed in this RIA indicate that the proposed federal plan 

and model trading rules may have important energy market implications. Table 1-10 presents a 

variety of important energy market impacts for 2020, 2025, and 2030 for both the rate-based and 

mass-based federal plan approaches.

Table 1-10. Summary Table of Important Energy Market Impacts (Percent Change from 

Base Case)

Rate-Based Mass-Based

2020 2025 2030 2020 2025 2030

Retail electricity prices 3% 1% 1% 3% 2% 0%

Average electricity bills 3% -4% -7% 2% -3% -8%

Price of coal at minemouth -1% -5% -4% -1% -5% -3%

Coal production for power sector use -5% -14% -25% -7% -17% -24%

Price of natural gas delivered to power sector 5% -8% 2% 4% -3% -2%

Natural gas use for electricity generation 3% -1% -1% 5% 0% -4%

Energy market impacts are discussed more extensively in Chapter 3 of the final Clean Power 

Plan Emission Guidelines RIA. As well as the above energy market impacts, Chapter 3 of the 

final Clean Power Plan Emission Guidelines RIA presents projections of power sector generation 

and capacity changes by fuel type.

Additionally, changes in supply or demand for electricity, natural gas, and coal can 

impact markets for goods and services produced by sectors that use these energy inputs in the 

production process or that supply those sectors. Changes in cost of production may result in 

changes in price and/or quantity produced by these sectors and these market changes may affect 

the profitability of firms and the economic welfare of their consumers. Similarly, demand for 

new generation or energy efficiency, for example, can result in changes in production and 

profitability for firms that supply those goods and services. The EPA recognizes that states 

subject to the federal plan may choose to mitigate impacts to some markets outside the EGU 

sector, perhaps by implementing the guidelines through a state plan. 

1.5.6 Employment Impacts 

Executive Order 13563 directs federal agencies to consider the effect of regulations on 

job creation and employment. According to the Executive Order, “our regulatory system must 

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protect public health, welfare, safety, and our environment while promoting economic growth, 

innovation, competitiveness, and job creation. It must be based on the best available science” 

(Executive Order 13563, 2011). Although standard benefit-cost analyses have not typically 

included a separate analysis of regulation-induced employment impacts, we typically conduct 

employment analyses.27 While the economy continues moving toward full-employment, 

employment impacts are of particular concern and questions may arise about their existence and 

magnitude. 

Given the wide range of approaches that may be used to meet the requirements of the 

proposed federal plan and model trading rules, quantifying the associated employment impacts is 

difficult. The EPA’s illustrative employment analysis includes an estimate of projected 

employment impacts for the utility power sector, coal and natural gas production, and demandside energy efficiency activities. These projections are derived, in part, from the detailed model 

of the utility power sector used for this regulatory analysis, and U.S government data on 

employment and labor productivity. 

In the electricity, coal, and natural gas sectors, the EPA uses the IPM estimates of the 

changes in generation and fuel use of the proposed rule to estimate there could be a net decrease 

of approximately 25,000 job-years28 in 2025 for the proposed rule under the rate-based federal 

plan approach and approximately 26,000 job-years in 2025 under the mass-based approach. For 

2030 the estimates of the net decrease in job-years is 30,900 under the rate-based plan, and 

33,700 under the mass-based plan. The Agency is also offering an illustrative calculation of 

potential employment effects due to demand-side energy efficiency programs. Employment 

impacts from demand-side energy efficiency programs in 2030 could range from approximately 

52,000 to 83,000 jobs created under proposed federal plan and model trading rules. The IPMderived job-year numbers for the electricity, coal and natural gas sectors should not be added to 

the demand-side efficiency job impacts, since the former are reported in full-time equivalent jobyears, whereas the latter do not distinguish between full- and part-time employment. More detail 

27 The employment analysis in this RIA is part of EPA’s ongoing effort to “conduct continuing evaluations of

potential loss or shifts of employment which may result from the administration or enforcement of [the Act]” 

pursuant to CAA section 321(a). 28 Job-years are not individual jobs, but rather the amount of work performed by the equivalent of one full-time 

individual for one year. For example, 20 job-years in 2020 may represent 20 full-time jobs or 40 half-time jobs in 

that year. 

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about these analyses can be found in Chapter 6 of the final Clean Power Plan Emission 

Guidelines RIA. 

1.5.6 Additional Analysis of Output-Based Allocation as a Means of Mitigating LeakageThe 

EPA is proposing a set-aside approach referred to as output-based allocation (OBA), which 

provides targeted allocations of a limited portion of allowances to existing NGCC units as a 

means of mitigating leakage. The EPA believes that this proposed set-aside would help ensure 

the environmental integrity of a mass-based plan by addressing incentives for generation to 

shift away from EGUs covered under mass-based plans to new unaffected EGUs. OBA

provides an incentive for eligible EGUs in mass-based states to increase their generation in 

order to increase their allocation of allowances. This approach helps align the generation 

incentives for eligible EGUs in mass-based states with new EGUs within mass-based states 

that are not subject to the mass-based limits as well as analogous EGUs in other states 

covered by emission rate limits, mitigating the potential for emissions leakage.

While the mass-based scenario analyzed for this proposed rule included a representation 

of the set-aside for new renewable generation, it did not quantify the effects of the OBA as 

proposed in this rulemaking. Therefore, the EPA conducted additional analysis to approximate 

the potential emissions reductions if the OBA set-aside were included in that mass-based 

scenario. The EPA is inviting comment on OBA. If appropriate, the EPA will further explore 

OBA as a means to mitigate leakage in the analysis supporting the final federal plan and model 

trading ruleThe application of OBA will provide an incentive to increase generation at existing 

NGCC EGUs in place of generation at new NGCC EGUs and existing fossil steam EGUs. To 

approximate the effect of this incentive in the mass-based scenario, the EPA used IPM model 

plant results from the mass-based scenario to construct the average dispatch order for model 

plants in each IPM region. Then, based on the allowance prices for the state in which each model 

plant resides, the EPA adjusted the dispatch order in the case where existing NGCC units were 

allocated allowances at a rate of 1,030 lbs/MWh for each MWh generated above a 50 percent 

capacity factor as proposed. In cases where an existing NGCC plant moved ahead of an existing 

fossil steam plant in the dispatch order, the NGCC plant’s generation was increased while the 

existing fossil plant’s generation was reduced. The NGCC plant’s generation was increased to 

the maximum capacity factor assumed feasible within IPM while the amount of reduced 

generation at the fossil steam plant is determined by the amount that would keep the overall 

covered sources’ emissions in the region constant, so as to respect compliance with the massbased standards represented in the modeling scenario. Since the existing NGCC plant has a lower 

emissions rate than the existing fossil steam plant, the increase in generation at the NGCC plant 

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is greater than the reduction in generation (because more generation is now possible from both 

plants together at the same given level of emissions). This net increase in generation from 

existing EGUs is then subtracted from new NGCC generation in the region, consistent with the 

total generation needed to meet the load assumed in the IPM modeling of the mass-based 

scenario. 

When applying this algorithm to the results from the mass-based scenario analyzed in this 

RIA, it forecasts nationally in 2030 a 10 percent increase in generation at existing NGCC EGUs, 

a 4 percent reduction in generation at existing fossil steam EGUs, and a 29 percent decrease in 

generation at new NGCC EGUs compared to the modeling scenario results presented above. The 

result of this reduction in new NGCC EGU generation is a reduction in CO2 emissions of 23 

million short tons (an amount equal to 1.3 percent of 2030 forecast emissions in mass-based 

scenario). We do not quantify the effect of these changes in generation on SO2 and NOx

emissions, although on net additional co-benefits are likelyexpected.

The incentives portrayed in this analysis are consistent with the incentives that would be 

realized under the OBA set-aside, and the general direction and magnitude of the results are 

likely consistent with those that would be observed had the mass-based scenario been modeled 

with the OBA set-aside. However, the results should be viewed as approximate given that 

analysis does not consider important aspects of power markets included in IPM. For example, the 

analysis does not consider any potential changes in relative fuel and allowance prices as a result 

of the OBA set-aside. The application of the OBA set-aside will place upward pressure on the 

allowance prices and therefore further incentivize a shift away from existing fossil steam 

generation. The OBA set-aside may also place upward pressure on the price of natural gas which 

would reduce the effectiveness of the set-aside at encouraging increased utilization of existing 

NGCC EGUs, but the OBA set-aside would be effective in increasing existing NGCC 

generation, the analysis does not consider the fact that electricity is traded across many IPM 

regions. The application of OBA in one state may impact the generation at EGUs in another 

state. 

1.5.7 Uncertainty Analysis 

The Office of Management and Budget’s circular Regulatory Analysis (Circular A-4) 

provides guidance on the preparation of regulatory analyses required under E.O. 12866, and 

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requires an uncertainty analysis for rules with annual benefits or costs of $1 billion or more.29

This proposed rulemaking potentially surpasses that threshold for both benefits and costs. 

Throughout this RIA and the referenced final Clean Power Plan Emission Guidelines RIA, we 

considered a number of sources of uncertainty, both quantitatively and qualitatively, on benefits 

and costs. We summarize three key elements of our analysis of uncertainty here: 

• Assess uncertainty in the methods used to calculate the health co-benefits associated with 

the reduction in PM2.5 and ozone and the use of a benefits-per-ton approach in estimating 

these co-benefits. 

• Characterizing uncertainty in monetizing climate-related benefits. 

Some of these elements are evaluated using probabilistic techniques, whereas for others 

the underlying likelihoods of certain outcomes are unknown and we use scenario analysis to 

evaluate their potential effect on the benefits and costs of this rulemaking. 

1.5.7.1 Uncertainty in Costs 

Our best estimates of the costs of these illustrative scenarios are reported within the cost 

analysis of the final Clean Power Plan Emission Guidelines and are included in the cost 

modeling in this RIA for both the proposed rate-based and mass-based approaches. A source of 

uncertainty under this regulation is the ultimate approach states that are not subject to the federal 

plan or adopt the model rule will adopt in response to the guidelines, which will affect both the 

costs and benefits of this rule. For this reason we modeled the two potential proposed federal 

plan approaches assuming they applied to all of the states: the rate-based plan approach and the 

mass-based plan approach.

.1.5.7.2 Uncertainty Associated with Estimating the Social Cost of Carbon 

The 2010 SC-CO2 TSD noted a number of limitations to the SC-CO2 analysis, including 

the incomplete way in which the integrated assessment models (IAM) capture catastrophic and 

non-catastrophic impacts, their incomplete treatment of adaptation and technological change, 

29 Office of Management and Budget (OMB), 2003, Circular A-4, 

http://www.whitehouse.gov/omb/circulars_a004_a-4 and OMB, 2011. Regulatory Impact Analysis: A Primer.

http://www.whitehouse.gov/sites/default/files/omb/inforeg/regpol/circular-a-4_regulatory-impact-analysis-aprimer.pdf

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uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk 

aversion.30 Currently integrated assessment models do not assign value to all of the important 

physical, ecological, and economic impacts of climate change recognized in the climate change 

literature due to a lack of precise information on the nature of damages and because the science 

incorporated into these models understandably lags behind the most recent research. These 

individual limitations do not all work in the same direction in terms of their influence on the SCCO2 estimates, though taken together they suggest that the SC-CO2 estimates are likely 

conservative. In particular, the IPCC Fourth Assessment Report (2007) concluded that “It is very 

likely that [SC-CO2 estimates] underestimate the damage costs because they cannot include 

many non-quantifiable impacts” and the IPCC Fifth Assessment report observed that SC-CO2

estimates continue to omit various impacts that would likely increase damages. The 95th

percentile estimate was included in the recommended range for regulatory impact analysis, in 

part, to address these concerns.

The modeling underlying the development of the SC-CO2 estimates addressed 

uncertainty in several ways. An ensemble of three IAMs were used to generate the SC-CO2

estimates to capture differences in model structures that, in part, reflect uncertainty in the 

scientific literature about these relationships. Parametric uncertainty was explicitly addressed in 

each IAM, though to differing degrees, through Monte Carlo simulations in which explicit 

probability distributions for key parameters were specified, including the equilibrium climate 

sensitivity, which represents the long-run responsiveness of the climate to increasing GHG 

concentrations. Furthermore, the analysis considered five different socioeconomic and emissions 

forecasts to capture the sensitivity of the SC-CO2 estimates to key exogenous projections used in 

the modeling. Finally, the results were calculated for three discount rates, which were selected, in 

part, to reflect uncertainty about how interest rates may change over time and the possibility that 

climate damages are positively correlated with uncertain future economic activity. This analysis 

produced 45 different distributions of the SC-CO2 estimates for each emissions year. To produce 

30 Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866, Interagency Working Group on Social Cost of Carbon, with participation by the Council of Economic 

Advisers, Council on Environmental Quality, Department of Agriculture, Department of Commerce, Department 

of Energy, Department of Transportation, Environmental Protection Agency, National Economic Council, Office 

of Energy and Climate Change, Office of Management and Budget, Office of Science and Technology Policy, and 

Department of Treasury (February 2010). Available at: 

<http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf>. 

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a range of plausible estimates that are manageable in regulatory analysis but still reflects the 

uncertainty in the results four point estimates were recommended. The use of this range of point 

estimates in this rulemaking helps to reflect the uncertainty in the SC-CO2 estimates. Chapter 4 

of the final Clean Power Plan Emission Guidelines RIA provides a comprehensive discussion 

about the methodology and application of the SC-CO2; see both the 2010 TSD and current SCCO2 TSD for a full description. 

In addition, OMB’s Office of Information and Regulatory Affairs received comments 

regarding uncertainty and the SC-CO2 estimates in response to a separate request for public 

comment on the approach used to develop the estimates. Commenters discussed the analyses and 

presentation of uncertainty in the TSD as well as the implications of uncertainty for use of the 

SC-CO2 estimates in regulatory impact analysis. In their response, the interagency working 

group (IWG) acknowledged uncertainty in the SC-CO2 estimates but disagreed with commenters 

that suggested the uncertainty undermines use of the SC-CO2 estimates in regulatory impact 

analysis. The IWG went on to note that the uncertainty in the SC-CO2 estimates is fully 

acknowledged and comprehensively discussed in the TSDs and supporting academic literature, 

and that while all regulatory impact analysis involves uncertainty, these analyses can provide 

useful information to decision makers and the public. See the IWG Response to Comments for 

the complete response.31 

1.5.7.3 Uncertainty Associated with PM2.5 and Ozone Health Co-Benefits Assessment 

EPA provides information on the relative uncertainty in the benefits estimates based on 

the 95th percentile confidence interval for avoided PM-related premature deaths and the 

associated economic valuation estimated in the benefits analysis for the recent PM NAAQS RIA 

(U.S. EPA, 2012).. In general, the 95th percentile confidence interval for monetized PM2.5

benefits ranges from approximately -90 percent to +180 percent of the central estimates based on 

the two key PM mortality studies. To further explore uncertainty in the premature mortality 

benefits, EPA provides the PM-related results using concentration-response functions from two 

key epidemiology studies, as well as alternate concentration-response relationship provided by 

an expert elicitation and alternative ozone-related results using concentration-response 

31 See https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-comments-final-july-2015.pdf

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relationships provided by alternative epidemiology studies. In addition, we include an 

assessment of the distribution of population exposure in the modeling underlying the benefit-perton estimates. 

In addition to the uncertainties in the underlying concentration-response and valuation 

functions, all benefit-per-ton approaches have inherent limitations, including that the estimates 

reflect the geographic distribution of the modeled sector emissions, which may not match the 

emission reductions anticipated by this proposed rule, and they may not reflect local variability 

in population density, meteorology, exposure, baseline health incidence rates, or other local 

factors for any specific location. In addition, these estimates reflect the regional average benefitper-ton for each ambient PM2.5 precursor emitted from EGUs, which assumes a linear 

atmospheric response to emission reductions. The regional benefit-per-ton estimates, although 

less subject to these types of uncertainties than national estimates, still should be interpreted with 

caution. Even though we assume that all fine particles have equivalent health effects, the benefitper-ton estimates vary between precursors depending on the location and magnitude of their 

impact on PM2.5 levels, which drive population exposure. 

1.6 References

40 CFR Chapter I [EPA–HQ–OAR–2009–0171; FRL–9091–8] RIN 2060–ZA14, 

“Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) 

of the Clean Air Act,” Federal Register / Vol. 74, No. 239 / Tuesday, December 15, 2009 / 

Rules and Regulations. 

75 FR 49556. August 13, 2010. “EPA’s Denial of the Petitions to Reconsider the Endangerment 

and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean 

Air Act.”

Bell, M.L., A. McDermott, S.L. Zeger, J.M. Sarnet, and F. Dominici. 2004. “Ozone and ShortTerm Mortality in 95 U.S. Urban Communities, 1987-2000.” Journal of the American 

Medical Association. 292(19):2372-8. 

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Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support Document: Social Cost of 

Carbon for Regulatory Impact Analysis Under Executive Order 12866, Interagency Working 

Group on Social Cost of Carbon, with participation by the Council of Economic Advisers, 

Council on Environmental Quality, Department of Agriculture, Department of Commerce, 

Department of Energy, Department of Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and Climate Change, Office of Management 

and Budget, Office of Science and Technology Policy, and Department of Treasury (February 

2010). Available at: <http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf>. Accessed July 15, 2015. 

Docket ID EPA-HQ-OAR-2013-0602, Technical Support Document: Technical Update of the 

Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, 

Interagency Working Group on Social Cost of Carbon, with Participation by Council of 

Economic Advisers, Council on Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, Department of Transportation, Domestic 

Policy Council, Environmental Protection Agency, National Economic Council, Office of 

Management and Budget, Office of Science and Technology Policy, and Department of 

Treasury (May 2013, Revised July 2015). Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf>.

Accessed July 15, 2015. 

Krewski D., M. Jerrett, R.T. Burnett, R. Ma, E. Hughes, Y. Shi, et al. 2009. Extended Follow-Up 

and Spatial Analysis of the American Cancer Society Study Linking Particulate Air Pollution 

and Mortality. HEI Research Report, 140, Health Effects Institute, Boston, MA. 

Interagency Working Group on Social Cost of Carbon, with participation by Council of 

Economic Advisers, Council on Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, Department of Transportation, 

Environmental Protection Agency, National Economic Council, Office of Management and 

Budget, Office of Science and Technology Policy, and Department of Treasury. Response to 

to Comments: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866. July 2015. Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-commentsfinal-july-2015.pdf.> Accessed July 15, 2015. 

386
Intergovernmental Panel on Climate Change (IPCC). 2007. Climate Change 2007: Synthesis 

Report Contribution of Working Groups I, II and III to the Fourth Assessment Report of the 

IPCC. Available at: 

<http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report_synt

hesis_report.htm>. Accessed June 6, 2015. 

Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. “Chronic Exposure to Fine Particles 

and Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environmental Health Perspectives. 120(7):965-70. 

Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. “Ozone Exposure and Mortality: An 

Empiric Bayes Metaregression Analysis.” Epidemiology. 16(4):458-68. 

Melillo, J.M., T.C. Richmond, and G.W. Yohe, Eds., 2014: Climate Change Impacts in the 

United States: The Third National Climate Assessment. U.S. Global Change Research 

Program. Available at <http://nca2014.globalchange.gov>. Accessed June 4, 2015. 

National Research Council (NRC). 2000. Toxicological Effects of Methylmercury: Committee on 

the Toxicological Effects of Methylmercury.” Board on Environmental Studies and 

Toxicology. National Academies Press. Washington, DC. 

National Research Council (NRC). 2002. Estimating the Public Health Benefits of Proposed Air 

Pollution Regulations. National Academies Press. Washington, DC.

National Research Council. 2011. Climate Stabilization Targets: Emissions, Concentrations, and 

Impacts over Decades to Millennia. Washington, DC: The National Academies Press. 

U.S. Environmental Protection Agency (U.S. EPA). 2008a. Integrated Science Assessment for 

Sulfur Oxides—Health Criteria (Final Report). National Center for Environmental 

Assessment – RTP Division, Research Triangle Park, NC. September. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=198843>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2008b. Final Ozone NAAQS Regulatory 

Impact Analysis. EPA-452/R-08-003. Office of Air Quality Planning and Standards Health 

and Environmental Impacts Division, Air Benefit and Cost Group Research Triangle Park, 

NC. March. Available at: < http://www.epa.gov/ttnecas1/regdata/RIAs/6-

ozoneriachapter6.pdf>. Accessed June 4, 2015. 

U.S. EPA. 2008c. Integrated Science Assessment for Oxides of Nitrogen: Health Criteria (Final 

Report). Research Triangle Park, NC: National Center for Environmental Assessment. July. 

Available at < http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. 

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U.S. Environmental Protection Agency (U.S. EPA). 2008c. Integrated Science Assessment for 

Oxides of Nitrogen - Health Criteria (Final Report). National Center for Environmental 

Assessment, Research Triangle Park, NC. July. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2009b. Integrated Science Assessment for 

Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for Environmental 

Assessment – RTP Division, Research Triangle Park, NC. December. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2010d. Section 3: Re‐analysis of the Benefits 

of Attaining Alternative Ozone Standards to Incorporate Current Methods. Available at: 

<http://www.epa.gov/ttnecas1/regdata/RIAs/s3-supplemental_analysis-updated_benefits11-

5.09.pdf >. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2012a. Regulatory Impact Analysis for the 

Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. EPA452/R-12-003. Office of Air Quality Planning and Standards, Health and Environmental 

Impacts Division, Research Triangle Park, NC. December. Available at: <

http://www.epa.gov/ttnecas1/regdata/RIAs/finalria.pdf>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2013b. Integrated Science Assessment of 

Ozone and Related Photochemical Oxidants (Final Report). EPA/600/R-10/076F. National 

Center for Environmental Assessment – RTP Division, Research Triangle Park. Available at: 

<http://cfpub.epa.gov/ncea/isa/recordisplay.cfm?deid=247492#Download>. Accessed June 4, 

2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2015a. Regulatory Impact Analysis for the 

Clean Power Plan Final Rule. EPA-452/R-15-003. Office of Air Quality Planning and 

Standards, Health and Environmental Impacts Division, Research Triangle Park. 

U.S. EPA. 2015b. Technical Support Document (TSD) the Final Carbon Pollution Emission 

Guidelines for Existing Stationary Sources: Electric Utility Generating Units. Demand-Side 

Energy Efficiency.

Woodruff, T.J., J. Grillo, and K.C. Schoendorf. 1997. “The relationship between selected causes 

of postneonatal infant mortality and particulate air pollution in the United States.” 

Environmental Health Perspectives. 105(6): 608-612. 

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CHAPTER 2: STATUTORY AND EXECUTIVE ORDER REVIEWS

2.1 Executive Order 12866: Regulatory Planning and Review and Executive Order 

13563: Improving Regulation and Regulatory Review 

This proposed action is an economically significant regulatory action that was submitted 

to the OMB for review. Any changes made in response to OMB recommendations have been 

documented in the docket. The EPA prepared an analysis of the potential costs and benefits 

associated with this action. This analysis, which is presented in this RIA, is also contained in the 

“Regulatory Impact Analysis for the Proposed Federal Plan Requirements for Greenhouse Gas 

Emissions from Electric Utility Generating Units Constructed on or Before January 8, 2014; 

Model Trading Rules; Amendments to Framework Regulations” (EPA-452/R-15-006, July 

2015), is available in the docket and is briefly summarized in section VIII of theis preamble. 

Consistent with Executive Order 12866 and Executive Order 13563, the EPA estimated 

the costs and benefits for two alternative federal plan approaches to implementing the proposed 

federal plan and model trading rules. The proposed action will achieve the same levels of 

emissions performance as required of state plans under the CAA section 111(d) EGs for the 

control of CO2. Actions taken to comply with the guidelines will also reduce the emissions of 

directly-emitted PM2.5, SO2 and NOX. The benefits associated with these PM2.5, SO2 and NOX

reductions are referred to as co-benefits, as these reductions are not the primary objective of this 

rule.

The Regulatory Impact Analysis (RIA) for this proposal analyzed two implementation 

scenarios, which we term the “rate-based federal plan approach” and the “mass-based federal

plan approach”. It is very important to note that the differences between the analytical results for 

the rate-based and mass-based federal plan approaches presented in thise RIA may not be 

indicative of likely differences between the approaches if implemented by states and affected 

EGUs in response to the proposed rule. In other words, if one approach performs differently than 

the other on a given metric during a given time period, this does not imply this will apply in all 

instances.

It is important to note that the potential regulatory impacts presented in the Clean Power 

Plan Final Rule RIA and thise RIA for this proposed rule are not additive. Both RIAs present 

390
estimates of the benefits and costs of achieving the emission performance rates of the Clean 

Power Plan EGs. In the case of the Clean Power Plan Final Rule RIA, the illustrative analysis 

assumes the performance rates are met under state plans. In the case of this RIA for the proposed 

federal plan and model trading rules, the same performance rates are accomplished but are 

assumed to be achieved under the federal plan or model trading rules. 

The EPA has used the social cost of carbon estimates presented in the Technical Support 

Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866 (May 2013, Revised July 2015) (“current TSD”) to analyze CO2

climate impacts of this rulemaking. We refer to these estimates, which were developed by the 

U.S. government, as “SC-CO2 estimates.” The SC-CO2 is an estimate of the monetary value of 

impacts associated with a marginal change in CO2 emissions in a given year. The four SC-CO2

estimates are associated with different discount rates (model average at 2.5 percent discount rate, 

3 percent, and 5 percent; 95th percentile at 3 percent), and each increases over time. In this 

summary, the EPA provides the estimate of climate benefits associated with the SC-CO2 value 

deemed to be central in the current TSD: the model average at 3 percent discount rate. 

The EPA estimates that, in 2020, the proposal will yield monetized climate benefits (in 

2011$) of approximately $2.8 billion for the rate-based approach and $3.3 billion for the massbased approach (3 percent model average). For the rate-based approach, the air pollution health 

co-benefits in 2020 are estimated to be $0.7 billion to $1.8 billion (2011$) for a 3 percent 

discount rate and $0.64 billion to $1.7 billion (2011$) for a 7 percent discount rate. For the massbased approach, the air pollution health co-benefits in 2020 are estimated to be $2.0 billion to 

$4.8 billion (2011$) for a 3 percent discount rate and $1.8 billion to $4.4 billion (2011$) for a 7 

percent discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE

program and participant costs and MRR costs in 2020, are approximately $2.5 billion for the 

rate-based approach and $1.4 billion for the mass-based approach (2011$). The quantified net 

benefits (the difference between monetized benefits and compliance costs) in 2020 are estimated 

to range from $1.0 billion to $2.1 billion (2011$) for the rate-based approach and from $3.9 

billion to 6.7 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model 

average).

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The EPA estimates that, in 2025, the proposal will yield monetized climate benefits (in 

2011$) of approximately $10 billion for the rate-based approach and $12 billion for the massbased approach (3 percent model average). For the rate-based approach, the air pollution health 

co-benefits in 2025 are estimated to be $7.4 billion to $18 billion (2011$) for a 3 percent 

discount rate and $6.7 billion to $16 billion (2011$) for a 7 percent discount rate. For the massbased approach, the air pollution health co-benefits in 2025 are estimated to be $7.1 billion to 

$17 billion (2011$) for a 3 percent discount rate and $6.5 billion to $16 billion (2011$) for a 7 

percent discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE

program and participant costs and MRR costs in 2025, are approximately $1.0 billion for the 

rate-based approach and $3.0 billion for the mass-based approach (2011$). The quantified net 

benefits (the difference between monetized benefits and compliance costs) in 2025 are estimated 

to range from $17 billion to $27 billion (2011$) for the rate-based approach and $16 billion to 

$26 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model 

average).

The EPA estimates that, in 2030, the proposal will yield monetized climate benefits (in 

2011$) of approximately $20 billion for the rate-based approach and $20 billion for the massbased approach (3 percent model average). For the rate-based approach, the air pollution health 

co-benefits in 2030 are estimated to be $14 billion to $34 billion (2011$) for a 3 percent discount 

rate and $13 billion to $31 billion (2011$) for a 7 percent discount rate. For the mass-based 

approach, the air pollution health co-benefits in 2030 are estimated to be $12 billion to $28 

billion (2011$) for a 3 percent discount rate and $11 billion to $26 billion (2011$) for a 7 percent 

discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE program 

and participant costs and MRR costs in 2030, are approximately $8.4 billion for the rate-based 

approach and $5.1 billion for the mass-based approach (2011$). The quantified net benefits (the 

difference between monetized benefits and compliance costs) in 2030 are estimated to range 

from $26 billion to $45 billion (2011$) for the rate-based approach and from $26 billion to $43 

billion (2011$) for the mass-based approach, using a 3 percent discount rate (model average). 

Table 1-8 and Table 1-9 of this RIA provides the estimates of the climate benefits, health cobenefits, compliance costs and net benefits of the proposal for rate-based and mass-based federal

plan approaches, respectively. 

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There are additional important benefits that the EPA could not monetize. Due to current 

data and modeling limitations, our estimates of the benefits from reducing CO2 emissions do not 

include important impacts like ocean acidification or potential tipping points in natural or 

managed ecosystems. Unquantified benefits also include climate benefits from reducing 

emissions of non-CO2 GHGs (e.g., nitrous oxide and methane) and co-benefits from reducing 

direct exposure to SO2, NOX, and HAP (e.g., mercury), as well as from reducing ecosystem 

effects and visibility impairment. Based upon the foregoing discussion, it remains clear that the 

benefits of this proposed action are substantial, and far exceed the costs. Additional details on 

benefits, costs, and net benefits estimates are provided in thethis RIA for this proposal. 

[Placeholder]

2.2 Paperwork Reduction Act

[Placeholder]The information collection requirements in this rule have been submitted for 

approval to OMB under the PRA. The Information Collection Request (ICR) document prepared 

by the EPA has been assigned EPA ICR number 2526.01. You can find a copy of the ICR in the 

docket for this rule, and it is briefly summarized here. The information collection requirements 

are not enforceable until approved by OMB. 

This rule does not directly impose specific requirements on state and U.S. territory 

governments with affected EGUs. The rule also does not impose specific requirements on tribal 

governments that have affected EGUs located in their area of Indian country. This rule does 

impose specific requirements on EGUs located in states, U.S. territories or areas of Indian 

country. 

The information collection activities in this proposed rule are consistent with those 

activities defined under the Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units finalized on August 3, 2015. The information 

collection requirements in this proposed rule have been submitted for approval to the Office of 

Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. 

The ICR document prepared by the EPA has been assigned EPA ICR number 2526.01. You can 

find a copy of the ICR in the docket for this rule, and it is briefly summarized here. 

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Aside from reading and understanding the rule, this proposed action would impose 

minimal new information collection burden on affected EGUs beyond what those affected EGUs 

would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously 

approved the information collection requirements contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR part 98) under the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060–0626 and 

2060– 0629, respectively. Apart from certain reporting costs based on requirements in the NSPS 

General Provisions (40 CFR part 60, subpart A), which are mandatory for all owners/operators 

subject to CAA section 111 national emission standards, there are no new information collection 

costs, as the information required by this proposed rule is already collected and reported by other 

regulatory programs. The recordkeeping and reporting requirements are specifically authorized 

by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the 

recordkeeping and reporting requirements for which a claim of confidentiality is made is 

safeguarded according to agency policies set forth in 40 CFR part 2, subpart B. 

Although EPA cannot determine at this time how many affected EGU respondents will 

submit information under the federal plan, EPA has estimated an “upper bound” burden estimate 

for this ICR that estimates burden should every affected EGU read and understand the rule. This 

is the only potential respondent activity that would be required under the 3-year period following 

publication of the final federal plan, so there are no obligations to respond in this period. The 

results of this “upper bound” estimate of federal plan burden are presented below: 

Respondents/affected entities: 1,028 

Respondents’ obligation to respond: Not applicable, no responses are required during the 

period covered by the ICR. 

Estimated number of respondents: Unknown at this time, but have assumed all affected 

entities are respondents for an upper bound estimate. 

Frequency of response: None, no responses are required during the period covered by the 

ICR.

Total estimated burden: 17,133 hours (per year). Burden is defined at 5 CFR 1320.3(b). 

Total estimated cost: $1,706,501 (per year) 

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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 in 40 CFR are listed in 40 CFR part 9. 

Submit your comments on the agency’s need for this information, the accuracy of the 

provided burden estimates and any suggested methods for minimizing respondent burden to the 

EPA using the docket identified at the beginning of this rule. You may also send your ICRrelated comments to OMB’s Office of Information and Regulatory Affairs via email to 

oria_submissions@omb.eop.gov, Attention: Desk Officer for the EPA. Since OMB is required to 

make a decision concerning the ICR between 30 and 60 days after receipt, OMB must receive 

comments no later than 30 days after the date of publication in the Federal Register. The EPA 

will respond to any ICR-related comments in the final rule.

2.3 Initial Regulatory Flexibility Analysis

The Regulatory Flexibility Act (RFA; 5 U.S.C.§ 601 et seq.), as amended by the Small 

Business Regulatory Enforcement Fairness Act (Public Law No. 104-121), provides that 

whenever an agency is required to publish a general notice of proposed rulemaking, it must 

prepare and make available an initial regulatory flexibility analysis (IRFA), unless it certifies that 

the proposed rule, if promulgated, will not have a significant economic impact on a substantial 

number of small entities (5 U.S.C. § 605[b]). Small entities include small businesses, small 

organizations, and small governmental jurisdictions. An IRFA describes the economic impact of 

the proposed rule on small entities and any significant alternatives to the proposed rule that 

would accomplish the objectives of the rule while minimizing significant economic impacts on 

small entities. Pursuant to section 603 of the RFA, the EPA prepared an initial regulatory 

flexibility analysis (IRFA) that examines the impact of the proposed rule on small entities along 

with regulatory alternatives that could minimize that impact. 

2.3.1 Reasons why Action is Being Considered 

On August 3, 2015, the EPA finalized the Clean Power Plan EGs for existing fossil-fuel 

fired EGUs (40 CFR part 60, subpart UUUU) under authority of section 111 of the CAA (79 FR 

34950). The Guidelines apply to existing fossil-fuel fired EGUs, i.e., those that were in operation 

or had commenced construction before January 8, 2014. States with existing EGUs subject to the 

guidelines are required to submit to the EPA by September 6, 2016, a state plan that implements 

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the EGs. States may also make initial plan submittals in lieu of a complete state plan, in which 

case extensions will be granted until September 6, 2018 (40 CFR &&&).32 As discussed in 

section VI.D of theis preamble, Indian Tribes may, but are not required to, submit tribal plans. 

Once the EPA finds that a state has failed to submit a plan, or disapproves a state plan,33 section 

111 of the CAA and 40 CFR 60.27 require the EPA to develop, implement, and enforce a federal 

plan for existing EGUs located in that state. In addition, CAA section 301(d)(2) authorizes the 

Administrator to treat an Indian Tribe in the same manner as a state for this EGU requirement. 

See 40 CFR 49.3; see also “Indian Tribes: Air Quality Planning and Management,” hereafter 

“Tribal Authority Rule,” (63 FR 7254, February 12, 1998). As discussed in section VI.D of theis

preamble, the agency in this action is proposing a necessary or appropriate finding for the 

affected EGUs in several areas of Indian country and is proposing the federal plan for these 

affected EGUs.

The agency believes it is appropriate to propose the federal plan at this time for any states 

that may ultimately be found to have failed to submit a plan, or had their plan disapproved by the 

EPA. For some states in this situation, the federal plan may be no more than an interim measure 

to ensure that congressionally mandated emission standards under authority of section 111 of the 

CAA are implemented until they can get an approved plan in place. Other states may choose to 

rely on the federal plan and would not need to develop their own plan. This proposal also serves 

as two proposed model trading rules which states can adopt or tailor for adoption as their state 

plan.On &&&August 3, 2015, the EPA finalized the Clean Power Plan Emission Guidelines for 

existing fossil-fuel fired electricity generating units (EGUs) (40 CFR part 60, subpart UUUU)

under authority of section 111 of the CAA (79 FR 34950). The Guidelines apply to existing 

fossil-fuel fired EGUs, i.e., those that were in operation or had commenced construction before 

January 8, 2014. States with existing EGUs subject to the guidelines are required to submit to the 

EPA by August 31, 2016, a state plan that implements the EGs. States may also make initial plan 

submittals in lieu of a complete state plan, in which case extensions can be granted (40 CFR 

32 See Section VII of theis preamble for additional information on proposed changes to 40 CFR 60.27 to provide 

enhancements and flexibilities to the agency’s process for review and action on state plans and promulgation of 

federal plans.

33 If a state has submitted a complete plan, then the EPA will go through a public notice and comment process to 

fully or partially approve or disapprove the state plan. 

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&&&).

34 Once the EPA finds that a state has failed to submit a plan, or disapproves a state 

plan,35 section 111 of the CAA and 40 CFR 60.27 require the EPA to develop, implement, and 

enforce a federal plan for existing EGUs located in that state. 

The agency believes it is appropriate to propose the federal plan at this time for any states 

that may ultimately be found to have failed to submit a plan, or had their plan disapproved by the 

EPA. For some states in this situation, the federal plan may be no more than an interim measure 

to ensure that congressionally mandated emission standards under authority of section 111 of the 

CAA are implemented until they can get an approved plan in place. Other states may choose to 

rely on the federal plan and would not need to develop their own plan. This proposal also serves 

as two proposed model trading rules which states can adopt or tailor for adoption as their state 

plan. 

2.3.2 Statement of Objectives and Legal Basis for Proposed Rules 

The EPA is planning a notice of propossinged this rulemaking for a federal plan to 

implement greenhouse gas Emission Guidelines for existing fossil fuel-fired electric generating 

units (EGUs). The emission guidelines were proposed in June 2014 as the Carbon Pollution 

Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units (79 FR 

34830; the Clean Power Plan). This plan is part of the President’s Climate Action Plan 

announced in June of 2013 to reduce carbon emissions from the power sector by 30 percent 

below 2005 levels. This federal plan serves to: 1) provide a model rule that states can tailor for 

implementation, and 2) set in place a plan that EPA can implement for states that do not develop 

an approvable state plan. The EPA sees this federal plan as an interim measure to ensure that 

congressionally mandated emission standards under authority of section 111 of the CAA are 

implemented until states assume their role as the preferred implementers of the emission 

guidelines. 

The final Clean Power Plan Emission Guidelines , due out this summer, are related to but 

separate from the proposed federal plan. The final Emission Guidelines s will detail the carbon 

34 See Section VII of this preamble for additional information on proposed changes to 40 CFR 60.27 to provide 

enhancements and flexibilities to the agency’s process for review and action on state plans and promulgation of 

federal plans.

35 If a state has submitted a complete plan, then the EPA will go through a public notice and comment process to 

fully or partially approve or disapprove the state plan. 

397
dioxide (CO2) reduction goals for sources by state. The purpose of the proposed federal plan is to 

lay out mechanisms to achieve reductions in CO2 emissions from affected EGUs that are not 

covered by an EPA-approved state plan. The EPA is considering a range of options and 

approaches through which affected EGUs would meet a rate-based goal or a mass-based 

equivalent. The EPA intends to incorporate flexibility to the extent possible into the proposed 

federal plan so affected units can achieve these reductions in a cost-effective way. 

2.3.3 Description and Estimate of Affected Small Entities

EPA conducted this regulatory flexibility analysis at the ultimate (i.e., highest) level of 

ownership, evaluating parent entities with the largest share of ownership in at least one 

potentially-affected EGU included in EPA’s Base Case using the Integrated Planning Model 

(IPM) v.5.15, used in this the Regulatory Impact Analysis (RIA) for this proposed rule.

36 This 

analysis draws on the “parsed” unit-level estimates using IPM results for 2030, as well as 

ownership, employment, and financial information for the potentially affected small entities 

drawn from other resources described in more detail below. EPA chose to examine potential 

impacts in 2030 because that is when the emission performance goals are required to be fully 

achieved. Also, as presented in thisthe RIA for this proposed rule, 2030 is the year where the 

estimated annual compliance costs for the contiguous U.S. are at their highest.37 

It is important to briefly describe the cost analysis supporting this proposed rule. This 

action proposes a federal plan under section 111(d) of the CAA for the control of CO2, a 

greenhouse gas pollutant, from certain large emitting fossil-fuel fired power plants, in the event 

that some states do not adopt their own plans. Specifically, the EPA is proposing approaches in 

the form of mass- and rate-based trading options that provide flexibility in implementing 

emission standards for a state’s affected EGUs. Both proposed approaches to the federal plan 

would require affected EGUs to meet emission standards set using the CO2 emission 

performance rates in the emission guidelines. The federal plan will achieve the same levels of 

emissions performance as required of state plans under the emission guidelines. 

36 See 1.4.1 of thise RIA for this proposed rule for more detail on the IPM base case used for this analysis. Detailed 

documentation for IPM v.5.15 is available at: http://www.epa.gov/powersectormodeling. 

37 See Section 1.5.2 of thise RIA for this proposed rule. 

398
However, at the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan or adopt a model rule. Because of this lack of information, 

for this RIA, the EPA has chosen to examine two federal plan approach a scenarios where all 

states of the contiguous U.S. will be regulated under a federal plan or a model rule. Furthermore, 

because of the lack of information as to which states will adopt the model rule, the EPA has 

chosen to examine a scenario where all states of the contiguous U.S. adopt the model trading rule 

. Additionally, we examine two alternative federal plan approach scenarios, which will be 

described in more detail below, for implementation of federal plans. The first federal plan 

approach we examine in this RIA assumes all states in the contiguous U.S. are regulated under a 

rate-based federal plan or model rule. The second federal plan approach we examine assumes all 

contiguous states are regulated under a mass-based federal plan or model rule. However, at the 

time of this proposal, the EPA has no information on whether any or how many states will 

require a federal plan. Because of this lack of information, for the RIA for this proposed rule, the 

EPA has chosen to examine a boundary scenario where all states of the contiguous U.S. will be 

regulated under a federal plan. Additionally, the proposal RIA examines two federal plan 

approach scenarios for implementation of federal plans. We use these scenarios to inform this 

IRFA.

The first federal plan approach assumes all states in the contiguous U.S. are regulated 

under rate-based federal plans. The second federal plan approach assumes all contiguous states 

are regulated under mass-based federal plans. As with the analysis in this RIA, the IRFA 

proceeds by examining potential costs to small entities under both the rate-based and mass-based 

approach, again under the strong assumption that all affected EGUs are regulated under a federal 

plan. The parsed unit-level estimates used in this IRFA are consistent with the analysis presented 

elsewhere in thise RIA. These 2030 year IPM files can also be found in the docket for the 

rulemaking. 

EPA identified the size of ultimate parent entities by using the Small Business 

Administration (SBA) size threshold guidelines.

38 The criteria for size determination vary by the 

organization/operation category of the ultimate parent entity, as follows: 

38 U.S. Small Business Administration (SBA). 2014. Small Business Size Standards. Effective as of July 14, 2014. 

See: http://www.sba.gov/sites/default/files/Size_Standards_Table.pdf.

399
• Privately-owned (non-government) entities (see Table 2-1) 

o Privately-owned entities include investor-owned utilities, non-utility entities, and 

entities with a primary business other than electric power generation.

o For entities with electric power generation as a primary business, small entities 

are those with less than the threshold number of employees specified by SBA for 

each of the relevant North American Industry Classification System (NAICS) 

sectors (NAICS 2211). 

o For entities with a primary business other than electric power generation, the 

relevant size criteria are based on revenue, assets, or number of employees by 

NAICS sector.39

• Publicly-owned entities

o Publicly-owned entities include federal, state, municipal, and other political 

subdivision entities. 

o The federal and state governments were considered to be large. Municipalities and 

other political units with population fewer than 50,000 were considered to be 

small.

• Rural Electric Cooperatives

o Small entities are those with fewer than the threshold level of employees or 

revenue specified by SBA for each of the relevant NAICS sectors.

EPA examined affected EGUs included in EPA’s 2030 projections and identified the 

associated power plants. Next, we determined power plant ownership information, including the 

name of associated owning entities, ownership shares, and each entity’s type of ownership. EPA 

primarily used data from SNL and Ventyx, supplemented by limited research using publicly 

39 Certain affected EGUs are owned by ultimate parent entities whose primary business is not electric power 

generation.

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available data.40 Majority owners of power plants with affected EGUs were categorized as one of 

the seven ownership types.41 These ownership types are:

1. Investor-Owned Utility (IOU): Investor-owned assets (e.g., a marketer, independent 

power producer, financial entity) and electric companies owned by stockholders, etc.

2. Cooperative (Co-Op): Non-profit, customer-owned electric companies that generate 

and/or distribute electric power.

3. Municipal: A municipal utility, responsible for power supply and distribution in a small 

region, such as a city.

4. Sub-division: Political subdivision utility is a county, municipality, school district, 

hospital district, or any other political subdivision that is not classified as a municipality 

under state law.

5. Private: Similar to an investor-owned utility, however, ownership shares are not openly 

traded on the stock markets.

6. State: Utility owned by the state.

7. Federal: Utility owned by the federal government.

Required ownership information could not be determined for two committed units that 

are represented in the IPM base case modeling for this proposed rule, preventing their inclusion 

in this analysis.42

Next, EPA used the Hoover’s online database to identify the ultimate owners of power 

plant owners identified in the SNL and Ventyx databases. This was necessary, as many majority 

owners of power plants (listed in SNL or Ventyx) are themselves owned by other ultimate parent 

entities (listed in Hoover’s).43 In these cases, the ultimate parent entity was identified via 

Hoover’s, whether domestically or internationally owned. 

40 SNL Financial data covers the energy market and other industries. For more information, see: www.snl.com. The 

Ventyx database consists of detailed ownership and corporate affiliation information at the EGU level. For more 

information, see: www.ventyx.com.

41 Throughout this analysis, EPA refers to the owner with the largest ownership share as the “majority owner” even 

when the ownership share is less than 51 percent.

42 The ORIS codes of these two units are 83609 and 83921. Without knowledge of entity type and size, it was not 

possible to accurately estimate revenue or costs impacts. An ORIS code is an identifying number assigned by the 

U.S. Energy Information Administration to power plants owned by utilities. 

43 The Hoover’s Inc. online platform includes company records that can contain NAICS codes, number of 

employees, revenues, and assets. For more information, see: http://www.hoovers.com. 

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EPA followed SBA size standards to determine which non-government ultimate parent 

entities should be considered small entities in this analysis. These SBA size standards are 

specific to each industry, each having a threshold level of either employees, revenue, or assets 

below which an entity is considered small. SBA guidelines list all industries, along with their 

associated NAICS code and SBA size standard. Therefore, it was necessary to identify the 

specific NAICS code associated with each ultimate parent entity in order to understand the 

appropriate size standard to apply. Data from Hoover’s was used to identify the NAICS codes for 

most of the ultimate parent entities.44 In many cases, an entity that is a majority owner of a 

power plant is itself owned by an ultimate parent entity with a primary business other than 

electric power generation. Therefore, it was necessary to consider SBA entity size guidelines for 

the range of NAICS codes listed in Table 2-1. This table represents the range of NAICS codes 

and areas of primary business of ultimate parent entities which are majority owners of potentially 

affected EGUs in EPA’s IPM base case.

44 In the case of two entities, NAICS codes could not be located in Hoover’s, so publicly available information was 

used to determine the primary area of business for the ultimate parent entities.

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Table 2-1. SBA Size Standards by NAICS Code 

Notes: 1) Based on size standards effective at the time EPA conducted this analysis (SBA size standards, effective 

July 14, 2014) 2) Small business size standards are not established for the Public Administration industry (NAICS 

code 921110). It is assumed that a comparable NAICS private sector industry is Fossil Fuel Electric Power 

Generation (NAICS code 221112). Therefore, for this analysis, the NAICS code 921110 is assumed to have a size 

standard of 750 employees.

Source: SBA, 2014

NAICS 

Code NAICS Description SBA Size Standard

211111 Crude Petroleum and Natural Gas Extraction 500 employees

211112 Natural Gas Liquid Extraction 500 employees

212111 Bituminous Coal and Lignite Surface Mining 500 employees

212221 Gold Ore Mining 500 employees

213112 Support Activities for Oil and Gas Operations $38.5 million in revenue

221111 Hydroelectric Power Generation 500 employees

221112 Fossil Fuel Electric Power Generation 750 employees

221113 Nuclear Electric Power Generation 750 employees

221118 Other Electric Power Generation 250 employees

221121 Electric Bulk Power Transmission and Control 500 employees

221122 Electric Power Distribution 1,000 employees

221210 Natural Gas Distribution 500 employees

238210 Electrical Contractors and Other Wiring Installation Contractors $15 million in revenue

238290 Other Building Equipment Contractors $15 million in revenue

324110 Petroleum Refineries 1,500 employees

325120 Industrial Gas Manufacturing 1,000 employees

325211 Plastics Material and Resin Manufacturing 750 employees

325320 Pesticide and Other Agricultural Chemical Manufacturing 500 employees

331110 Iron and Steel Mills and Ferroalloy Manufacturing 1,000 employees

331313 Alumina Refining and Primary Aluminum Production 1,000 employees

333613 Mechanical Power Transmission Equipment Manufacturing 500 employees

333999 All Other Miscellaneous General Purpose Machinery Manufacturing 500 employees

335312 Motor and Generator Manufacturing 1,000 employees

335999 All Other Miscellaneous Electrical Equipment and Component Manufacturing 500 employees

423610 Electrical Apparatus and Equipment, Wiring Supplies, and Related Equipment Merchant 

Wholesalers 100 employees

424720 Petroleum and Petroleum Products Merchant Wholesalers (except Bulk Stations and Terminals) 100 employees

454310 Fuel Dealers 50 employees

486210 Pipeline Transportation of Natural Gas $27.5 million in revenue

522110 Commercial Banking $550 million in assets

522220 Sales Financing $38.5 million in revenue

522320 Financial Transactions Processing, Reserve, and Clearinghouse Activities $38.5 million in revenue

523120 Securities Brokerage $38.5 million in revenue

523910 Miscellaneous Intermediation $38.5 million in revenue

523920 Portfolio Management $38.5 million in revenue

523930 Investment Advice $38.5 million in revenue

524113 Direct Life Insurance Carriers $38.5 million in revenue

524126 Direct Property and Casualty Insurance Carriers 1,500 employees

524210 Insurance Agencies and Brokerages $7.5 million in revenue

525110 Pension Funds $32.5 million in revenue

525120 Health and Welfare Funds $32.5 million in revenue

525990 Other Financial Vehicles $32.5 million in revenue

541611 Administrative Management and General Management Consulting Services $15 million in revenue

551112 Offices of Other Holding Companies $20.5 million in revenue

561110 Office Administrative Services $7.5 million in revenue

813910 Business Associations $7.5 million in revenue

921110 Public Administration 750 employees

403
EPA compared the relevant entity size criterion for each ultimate parent entity to the SBA 

threshold value noted in Table 2-1. We used the following data sources and methodology to 

estimate the relevant size criterion values for each ultimate parent entity:

1. Employment, Revenue, and Assets: EPA used the Hoover’s database as the primary 

source for information on ultimate parent entity employee numbers, revenue, and 

assets.45 In parallel, EPA also considered estimated revenues from affected EGUs based 

on analysis of parsed-file estimates for 2030.46 EPA assumed that the ultimate parent 

entity revenue was the larger of the two revenue estimates. In limited instances, 

supplemental research was also conducted to estimate an ultimate parent entity’s number 

of employees, revenue, or assets.

2. Population: Municipal entities are defined as small if they serve populations of less than 

50,000. EPA primarily relied on data from the Ventyx database and the U.S. Census 

Bureau to inform this determination. Supplemental research of individual municipalities 

was also conducted in some instances. 

Ultimate parent entities for which the relevant measure is less than the SBA size criterion 

were identified as small entities and carried forward in this analysis. In the case of six entities, 

data limitations prevented the comparison of entities against their appropriate SBA size 

standards. For the purposes of this analysis, EPA assumed that these six entities are small 

entities.47

EPA identified 223 potentially affected EGUs owned by 74 small entities included in 

EPA’s 2030 projections. Fifty-nine of these potentially affected EGUs are projected to no longer 

be operating by 2030 in the Base Case of EPA’s version of IPM v.5.15.

48 Twenty-four small 

45 Estimates of sales were used in lieu of revenue estimates when revenue data was unavailable.

46 The methodology for the analysis of IPM results is detailed later in this IRFA.

47 Generation from potentially affected EGUs owned by these six entities represents less than two percent of total 

generation from potentially affected EGUs owned by small entities under EPA’s base case projections.

48 Detailed documentation for IPM v.5.15 is available at: http://www.epa.gov/powersectormodeling.

404
entities are projected to have all of their potentially affected EGUs cease operation by 2030 in

this Base Case the base case by 2030. 

2.3.4 Compliance Cost Impact Estimates 

2.3.4.1 Methodology for Estimating Impacts on Small Entities 

This section presents the methodology used in this analysis for estimating the federal 

compliance costs of this proposed rule for small entities. For the purposes of this IRFA, EPA 

estimated net compliance costs for individual EGUs of the proposed rule using the following 

equation: 

Cnet compliance cost = Δ Coperating + annualized capital + Δ Cfuel + Δ Cdemand-side energy efficiency + Δ R

where C represents the components of cost as labeled, R represents revenue, and Δ indicates the 

calculation of difference between the base case and the federal plan approach under examination. 

The specific meaning of these variables is discussed below. 

This approach to estimate net compliance costs is consistent with previous proposed 

power sector regulations that required IRFAs, such as the proposed Mercury and Air Toxics 

Rule.49 However, there is an additional component in the net compliance cost equation: the 

change in the program costs of demand-side energy efficiency programs. Investment in demandside energy efficiency results in lower electricity demand, and consequently fewer emissions as 

production is reduced to meet the lower demand, an important emission-reduction strategy 

modelled in the rate-based and mass-based federal plan approaches. 

Because this analysis evaluates the net compliance costs as a sum of the costs changes

associated with compliance choices as well as changes in electricity revenues, it captures 

potential net compliance cost increases or decreases. For example, if under the proposed rule 

entities increase revenue more than costs, the net compliance costs will be negative. As a result, 

49 U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis of the Proposed Toxics 

Rule: Final Report. Office of Air Quality Planning and Standards, Health and Environmental Impacts Division, 

Research Triangle Park, NC. Available at: http://www.epa.gov/ttnecas1/regdata/RIAs/ToxicsRuleRIA.pdf. 

405
the approach used here to estimate net compliance costs is well-equipped to evaluate the 

potential distributional consequences of the proposed regulation. 

For this analysis, EPA used the parsed unit-level estimates mentioned before to estimate 

three of the four components of the net compliance cost equation above: the change in operating 

and annualized capital costs, the change in fuel costs, and the change in revenue, where all 

changes are estimated as the difference between the base case and federal plan scenario. These 

impacts were then summed for each small entity, adjusting for ownership share.50 As described 

momentarily, additional analysis was performed to estimate the change in costs of demand-side 

energy efficiency that factors in IPM-projected outputs but is not directly an output of the model. 

These individual components of compliance cost were estimated as follows:

1. Operating and capital costs: Using the IPM parsed estimates for the base case and the

rate-based and mass-based federal plan approaches, EPA evaluated changes in operating 

and capital costs at the EGU level. The equations for calculating operating and capital 

costs were adopted from technology assumptions used in EPA’s version of IPM version 

5.15. The model calculates the capital cost (in $/MW); the fixed operation and 

maintenance (O&M) cost (in $/MW-year); and the variable O&M cost (in $/MWh). 

2. Fuel costs: Using the IPM parsed estimates for the base case and the rate-based and 

mass-based federal plan approaches, EPA evaluated projected changes in fuel cost at the 

EGU level. These projected fuel costs are based on estimated EGU-level fuel input (in 

million British thermal units, MMBtu) and delivered fuel prices ($/MMBtu). 

3. Demand-side energy efficiency program costs: Demand-side energy efficiency 

program costs are estimated and allocated to affected EGUs outside of IPM in this 

analysis. For this analysis, we assumed that IOUs, Co-Ops, Municipals, and SubDivisions are utilities that receive revenues on the basis of retail electricity rates. Retail 

electricity in this and related EPA analyses contain an energy efficiency surcharge. The 

surcharge reflects the standard mechanism by which utilities collect revenue from their 

customers to pay for energy efficiency programs. Such surcharges are approved for 

inclusion in rates by state utility commission for IOUs or the equivalent authority (e.g., 

50 Unit-level cost impacts are adjusted for ownership shares for individual small entities, so as not to overestimate 

burden on each entity.

406
municipal or cooperative utility board of directors) for other utility types. To be 

consistent, EPA assumes that these utilities will incur an energy efficiency surcharge as a 

cost in this analysis. The demand-side energy efficiency surcharge is state specific, being 

the estimated state demand-side energy efficiency program costs51 divided by projected 

total state sales. The cost in this analysis is the surcharge multiplied by projected sales 

from affected EGUs.52 In contrast, entities of the type Private are not assessed demandside energy efficiency program costs in this analysis.53 This distinction is made because 

EPA assumes that Private entities own non-utility EGUs that will earn wholesale 

electricity rates. Wholesale electricity rates do not include a demand-side energy 

efficiency surcharge in this or related EPA analyses.

4. Revenues: EPA estimated the value of electricity generated by multiplying the projected 

electricity generation from EPA’s IPM modeling results with the regional retail 

electricity price estimates ($/MWh), for all entities except those categorized as Private in 

Ventyx. For private entities, EPA used projected wholesale electricity price instead of 

retail electricity price estimates because most of the private entities are independent 

power producers (IPP). Since IPPs sell their electricity to wholesale purchasers and do 

not own transmission facilities, their revenue was estimated with wholesale electricity 

prices.

2.3.4.2 Results

This section presents the estimated net compliance cost impacts of the proposed rule on 

small entities in 2030 based on the following endpoints: 

51 In practice, the costs of demand-side energy efficiency programs include the costs to the utilities that are funding 

the programs (known as the program costs) and the additional cost to the end-user purchasing a more energy 

efficient technology (known as the participant costs). Based upon a literature review, the analysis supporting this 

proposed rule and the Clean Power Plan Final Rule, total costs are assumed to be divided evenly, 50 percent each, 

between program costs and participant costs. This IRFA includes only to the program costs expected to be 

incurred by utilities. For more detail on how the demand-side energy efficiency costs are estimated, see U.S. EPA. 

2015. Technical Support Document (TSD) the Final Carbon Pollution Emission Guidelines for Existing 

Stationary Sources: Electric Utility Generating Units. Demand-Side Energy Efficiency. 

52 For these entity types (i.e., IOUs, Co-Ops, Municipals, and Sub-Divisions), projected sales is estimated to be 7.5 

percent less than generation. This 7.5 percent reduction is added to account for estimated transmission losses. 

53 Note that in this context, “Private” is one of seven distinct ownership types introduced earlier in this chapter.

407
• net compliance costs estimated for the proposed rule for potentially affected small 

entities, and 

• the ratio of small entity compliance cost impacts to revenues from electricity generation

at affected EGUs

It is worth noting again that the results in this section are based on the assumption made 

for this analysis that all affected EGUs owned by small entities are subject to this proposed rule. 

EPA chose to examine this boundary scenario because, at the time of this proposal, the EPA has 

no information on whether any or how many states will require a federal plan. 

The number of affected small entities by ownership type and the potential impact of the 

federal plan approaches are summarized in Tables 2-2 through 2-5. These tables are specific to 

either the rate-based federal plan approach (i.e., rate-based), or mass-based federal plan approach 

(i.e., mass-based). All costs are presented in 2011 dollars. 

EPA estimated the annualized net compliance cost to potentially affected small entities in 

2030 to be approximately $364 million under the rate-based approach, and $404 million under 

the mass-based approach. Results for small entities discussed here do not fully account for the 

reality that electricity markets are regulated in parts of the country. Entities operating in 

regulated or cost-of-service markets are likely able to recover compliance costs through rate 

adjustments; as a result these costs can be viewed as likely being over-estimates for this set of 

utilities.54

54This is similarly discussed dynamic is also expressed in previous EPA analyses. For example, see section 7.4.5.2 

within the Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards. Available at: 

http://www.epa.gov/ttnecas1/regdata/RIAs/matsriafinal.pdf.

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Table 2-2. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Rate-Based Federal Plan Approach in 2030 

EGU 

Ownership 

Type

Number of 

Potentially 

Affected Entities

Number of Entities 

Projected to Withdraw all 

Affected Units in Base Case

Additional Entities Projected 

to Withdraw all Affected Units 

under Rate-Based Approach

Co-Op 17 3 1

IOU 8 3 1

Municipal 24 13 1

Private 19 5 2

Sub-Division 6 0 2

Grand Total 74 24 7

Notes: 1) The number of potentially affected entities reflects those with affected EGUs that are modeled within IPM 

in 2030. 2) In this context, the term withdraw signifies that EGUs are represented in the 2030 IPM results but do not 

generate electricity.

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results.

Table 2-3. Projected Impact on Small Entities in 2030 under Rate-Based Federal Plan 

Approach 

EGU 

Ownership 

Type

Total Net 

Compliance Costs 

(2011$ millions)

Number of Small Entities 

with Net Compliance Costs 

> 1% of Generation 

Revenues

Number of Small Entities 

with Net Compliance Costs 

> 3% of Generation 

Revenues

Co-Op 109 8 3 

IOU 186 4 4 

Municipal 17 7 5 

Private 34 11 9 

Sub-Division 18 6 2 

Grand Total 364 36 23

Notes: 1) The total number of entities with costs greater than 1 or 3 percent of revenues includes only entities 

experiencing positive net compliance costs. 2) Costs are compared to generation revenues from affected EGUs, and 

do not consider additional revenues some entities may earn from other sources. 3) Nine small entities are estimated 

to have net compliance cost savings greater than 3 percent of generation revenues from affected sources.

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results.

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Table 2-4. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Mass-Based Federal Plan Approach in 2030 

EGU 

Ownership 

Type

Number of 

Potentially 

Affected Entities

Number of Entities 

Projected to Withdraw all 

Affected Units in Base Case

Additional Entities Projected 

to Withdraw all Affected 

Units under Mass-Based 

Approach

Co-Op 17 3 1

IOU 8 3 1

Municipal 24 13 1

Private 19 5 2

Sub-Division 6 0 0

Grand Total 74 24 5

Notes: 1) The number of potentially affected entities reflects those with affected EGUs that are modeled within IPM 

in 2030. 2) In this context, the term withdraw signifies that EGUs are represented in the 2030 IPM results but do not 

generate electricity.

Source: U.S. EPA analysis, based on IPM modeling results.

Table 2-5. Projected Impact on Small Entities in 2030 under Mass-Based Federal Plan 

Approach

EGU 

Ownership 

Type

Total Net 

Compliance Costs 

(2011$ millions)

Number of Small Entities 

with Net Compliance Costs 

> 1% of Generation 

Revenues

Number of Small Entities 

with Net Compliance Costs 

> 3% of Generation 

Revenues

Co-Op 133 10 4 

IOU 179 3 3 

Municipal 50 5 5 

Private 36 8 7 

Sub-Division 7 4 2 

Grand Total 404 30 21

Notes: 1) The total number of entities with costs greater than 1 or 3 percent of revenues includes only entities 

experiencing positive net compliance costs. 2) Costs are compared to generation revenues from affected EGUs, and 

do not consider additional revenues some entities may earn from other sources. 3) Eleven small entities are 

estimated to have net compliance cost savings greater than 3 percent of generation revenues from affected sources.

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results.

As noted earlier, there are 74 small entities with potentially affected EGUs that are 

modeled in the IPM base case in 2030. Of these, 24 small entities are projected to withdraw all of 

their potentially affected EGUs from operation under base case conditions. This leaves 50 small 

entities with potentially affected EGUs that are projected to be generating electricity in 2030. 

Under the rate-based federal plan approach, 7 of these 50 small entities are projected to withdraw 

all of their potentially affected EGUs from operation by 2030. Under the mass-based federal plan 

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approach, 5 of these 50 small entities are projected withdraw all of their potentially affected 

EGUs from operation by 2030. 

Under the rate-based federal plan approach, 23 small entities are projected to incur net 

compliance costs greater than 3 percent of generation revenues from their potentially affected 

EGUs. In contrast, 911 entities are estimated to have net compliance cost savings greater than 3 

percent of their generation revenues from affected EGUs. Under the mass-based federal plan 

approach, 21 small entities are projected to incur net compliance costs greater than 3 percent of 

generation revenues from their potentially affected EGUs. In contrast, 119 entities are estimated 

to have net compliance cost savings greater than 3 percent of generation revenues from their 

affected EGUs. 

The separate components of the net compliance costs for small entities under the 

proposed rule are summarized in Table 2-6 and Table 2-7. 

Table 2-6. Incremental Costs in 2030 under the Rate-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) 

EGU 

Ownership 

Type

Capital + 

Operating + Fuel 

Costs ($MM)

Energy Efficiency 

Program Costs 

($MM)

Change in 

Electricity 

Revenue ($MM)

Total Net 

Compliance 

Costs

A B C =A+B-C

Co-Op (79) 87 (102) 109 

IOU 78 93 (15) 186 

Municipal (26) 25 (19) 17 

Private (7) 0 (40) 34 

Sub-Division (68) 16 (70) 18 

Grand Total (102) 221 (246) 364 

Note: Totals may not add due to rounding. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results.

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Table 2-7. Incremental Costs in 2030 under the Mass-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) 

EGU 

Ownership 

Type

Capital + 

Operating + Fuel 

Costs ($MM)

Energy Efficiency 

Program Costs 

($MM)

Change in 

Electricity 

Revenue ($MM)

Total Net 

Compliance 

Costs

A B C =A+B-C

Co-Op (178) 84 (228) 133 

IOU (17) 91 (104) 179 

Municipal (64) 23 (91) 50 

Private (2) 0 (38) 36 

Sub-Division (38) 18 (27) 7 

Grand Total (299) 215 (488) 404 

Note: Totals may not add due to rounding. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results.

The change in electricity revenue under the federal plan approaches take into account 

both the profit lost from units that do not operate and the difference in revenue for operating 

units. The cost of withdrawing a unit as uneconomic is estimated as the base case profit that is 

foregone by not operating under a federal plan approach. One of the primary drivers of the cost 

impacts is the reduced revenue due to decreased electricity sales related to the modeled

implementation of demand-side energy efficiency measures. The EPA solicits comment on: 1) 

whether it is likely that small entities would consider demand-side strategies as they responded to 

a federal plan, 2) the appropriateness of considering the demand-side strategies in the analysis, 

and 3) if demand-side energy efficiency measures are considered in the final analysis, whether it 

is appropriate to consider them as a cost for a municipality or city-owned utility, as this reduced

revenue will translate to direct cost savings for members of the community served by the 

affected units.

There are uncertainties and limitations in this analysis that may result in estimates that 

diverge from what we might see in reality. Some of these have already been noted. Below is a 

listing of important considerations when interpreting this analysis.

• At the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan. The rate-based and mass-based federal 

plan approaches analyzed in this IRFA are based on a boundary scenario where 

all states of the contiguous U.S. will be regulated under a federal plan.

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• Results for small entities discussed here do not fully account for the reality that 

electricity markets are regulated in parts of the country. Entities operating in 

regulated or cost-of-service markets are likely able to recover compliance costs 

through rate adjustments; as a result these costs can be viewed as likely being 

over-estimates for this set of utilities.

• Small entities owning NGCC EGUs operating in competitive markets may be able 

to recover compliance costs if steam EGUs are setting the marginal price. 

• EPA has not factored in consideration of allowances that would be distributed to 

affected entities nor revenue that could be generated from the sale of ERCs in its 

analysis. EPA takes comment on how these factors should be considered in the 

final analysis.

• In this analysis, estimated state dDemand-side energy efficiency program costs 

are allocated to utility EGUs owned by IOUs, Co-Ops, Municipals, and SubDivisions basbased on the share of forecasted total state electricity sales that they 

are projected to provide. proportional to electricity salesly in this analysis. To the 

extent that this differs in practice, associated costs incurred by small entities may 

be over- or under-estimated.

• To the extent that the EGU owner information used is not reflective of reality, the 

number of small entities may be over- or under-estimated.

• To the extent that the entity-level ownership information (i.e., NAICS code, 

number of employees, revenues, and assets) are not reflective of reality, the 

number of small entities may be over- or under-estimated.

2.3.5 Projected Reporting, Recordkeeping and Other Compliance Requirements 

The reporting, recordkeeping and other compliance requirements are most likely covered 

under Part 75 and Part 98 programs for affected EGUs. Therefore, only a marginal additional 

cost is expected for the monitoring, reporting and recordkeeping requirements of the proposed 

federal plan for affected EGUs. [Placeholder]

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2.3.6 Related Federal Rules

On September 20, 2013, EPA proposed carbon pollution standards for new fossil fuel 

fired EGUs. On June 2, 2014, the EPA, proposed carbon pollution standards for modified and 

reconstructed fossil fuel fired EGUs, in addition to the Clean Power Plan EGs, to cut carbon 

pollution from existing fossil fuel fired EGUs. These existing EGUs are, or will be, potentially 

impacted by several other recently finalized EPA rules. On February 16, 2012, the EPA issued 

the mercury and air toxics standards (MATS) rule (77 FR 9304) to reduce emissions of toxic air 

pollutants from new and existing coal- and oil-fired EGUs. On May 19, 2014, the EPA issued a 

final rule under section 316(b) of the Clean Water Act (33 U.S.C. 1326(b)). This rule establishes 

new standards to reduce injury and death of fish and other aquatic life caused by cooling water 

intake structures at existing power plants and manufacturing facilities. On June 18, 2014 (79 FR 

34830), the EPA promulgated the stream electric effluent limitation guidelines (SE ELG) rule to 

strengthen the controls on discharges from certain steam electric power plants. On April 17, 2015 

(80 FR 21302), the EPA promulgated the coal combustion residuals (CCR) rule, which 

establishes technical requirements for CCR landfills and surface impoundments under subtitle D 

of the Resource Conservation and Recovery Act (RCRA), the nation's primary law for regulating 

solid waste. 

2.3.7 Regulatory Flexibility Alternatives

2.3.7.1 Panel Process

Small Entity Representatives (SERs) commented on their perceptions of the adequacy of 

the SBREFA panel process for the section 111(d) federal plan. Under the statute, EPA provides 

“information on the potential impacts of the proposed rule on small entities and the type of small 

entities that might be affected.” § 609(b)(1). Then SERs are selected, and the Panel collects 

“advice and recommendations” from each SER. § 609(b)(4). The Panel reviews the SERs’ 

comments, and “any material the agency has prepared in connection with [the RFA],” and 

“report[s] on the comments of the [SERs] and its findings as to issues related to” preparation of 

an IRFA. § 609(b)(5). EPA solicited SERs comments during the course of, and after holding 

three outreach meetings. The Agency provided information to the SERs on two primary 

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regulatory alternatives for the federal plan – a rate-based trading program and a mass-based 

trading program. The Agency identified specific areas under both of these alternatives where it 

was still in the decision making process and open to recommendations. This information forms 

the basis for consideration of issues and additional regulatory options important to these small 

entities. 

Advocacy shares many of the concerns raised by the SERs (see attached letter from 

Acting Chief Counsel Claudia Rodgers to EPA Administrator Gina McCarthy). While Advocacy 

endorses the Panel recommendations, Advocacy agrees that the SERs did not have sufficient 

information to inform advice and recommendations about specific regulatory alternatives and 

flexibilities. In Advocacy’s view, this is reflected in Panel recommendations that advise EPA to 

consider issues raised by the SERs rather than to propose or consider regulatory alternatives. 

Advocacy regrets that the Panel is not able to make more specific recommendations for 

flexibilities to minimize the impacts on small entities. 

While not all members of the Panel agree with all of these concerns, the concerns of the 

SERs regarding the Panel process have been noted. Nonetheless, EPA is committed to ensuring 

that it meets the requirements of the RFA and will, to the maximum extent practicable, fully 

consider the advice and recommendations of representatives of small entities in the development 

of the proposed rule. The EPA intends to continue working on issues regarding small businesses, 

and consider appropriate flexibilities, throughout this rulemaking process. 

2.3.7.2 Remaining Useful Life

SERs commented that EPA needed to account for remaining useful life of EGUs. 

Multiple comments addressed challenges that EPA must face in satisfying the statutory mandate 

that “in applying a standard of performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other factors, the remaining useful life of 

the existing sources to which such standard applies.” SERs are concerned that EPA will develop 

EGs under section 111(d) in a manner that either prohibits plans from providing this 

consideration or only providing for plans to “make these adjustments at the expense of other 

sources.” AEPCO comments that it has obligations under the Rural Electrification Act to operate 

under an 80-year mandate. SBA recommends EPA propose allowing for guaranteed amount of 

run-time for small entities to allow them to recoup investment. EPA believes “remaining useful 

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life” is a concern directed toward plants with short remaining lives, but recognizes that there are 

concerns about economic viability of some marginal plants. 

The Panel recommends that EPA clearly explain how it took into consideration remaining 

useful life and take comment on other ways of defining the remaining useful life consideration. 

The Panel also recommends proposing or considering economic incentives for compliance that 

could avoid early retirement or reduce the financial effects of early retirements. For instance, the 

EPA could propose continuing allocations for a set number of years to units that retire in order to 

alleviate the financial effects of the retirement. EPA should request comment on how long such 

allocations should continue. The EPA should also consider whether there are parallel 

mechanisms in a rate-based proposal that could provide similar regulatory relief or benefits for 

small entities, if appropriate.

2.3.7.3 Design of the Compliance System 

The panel requested SER input on a number of aspects of the federal plan design, based 

on EPA’s presentation of federal plan options. SER comments ranged quite broadly. Comments 

included: 1) differing opinions within SERs on favor of rate- vs mass-based approaches, 2) 

emphasis on market liquidity in a program, 3) support for types of allocation methodologies (in a 

mass-based allowance system), 4) encouragement for early action crediting, 5) increased 

averaging and compliance times to help small entities, and 6) whether and how to consider the 

effects of credit/allowance banking, borrowing, and shelf-life on market liquidity. In some 

instances, no general consensus emerged. The Panel notes the following specific areas where it is 

making a recommendation.

Mass-based or rate-based trading 

Various SERs favored one system over the other, and some suggested that each 

individual small entity should be able to choose the system under which they would comply. 

However, it is unclear to what extent SERs would favor such choice at the expense of a broader 

trading pool. The panel, however, notes that the idea of individual companies within a state 

choosing which system to comply would significantly limit the opportunity for intra- or interstate trading and would therefore not be consistent with other recommendations. The Panel 

recommends that EPA take comment on which approach (mass or rate) is preferable. In the 

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interests of maximizing liquidity across all federal plan states, the Panel recommends that EPA 

should propose to finalize a single approach for all federal plans.

Allocations and credit issuance/early action

SERs expressed a variety of views on the appropriate method of allocating allowances 

under a mass-based system or credits under a rate-based system. Some preferred allowing states 

to make these decisions. Some wanted allocations to account for early action and energy 

efficiency efforts. The Panel agrees that EPA should take comment on the use of allocations to 

minimize the impact of the federal plan on small entities. The Panel notes that the early incentive 

pool that is part of the EGs does provide credit for early action, but the SERs did not have an 

opportunity to respond to this flexibility. The panel recommends that in the federal plan the EPA 

allow credit for early action and energy efficiency efforts to the extent it is allowed under the 

guidelines. 

Non-generating party participation and market liquidity

SERs generally supported developing a system that would ensure a sufficient supply of 

credits be available on the open market and available for free trade to ensure that they would not 

be disadvantaged by large utilities withholding excess credits generated by renewable energy in 

their portfolio. However, some SERs also expressed the need to be able to generate and use 

credits internally (particularly those with generation across multiple states) (i.e., a portfolio 

approach). Some SERs endorsed allowing non-generating parties to create and sell credits or 

allowances. Other SERs warned that third parties should not be allowed to purchase credits or 

allowances for the purpose of retiring them without offsetting GHG emissions from electricity 

generation. The Panel recommends that the EPA ensure a liquid market in compliance 

instruments, through consideration, request or comment, or proposal of several of options, 

including: allocation methods or rules that could impact liquidity, mechanisms to place 

allowances or credits into the market relatively early, requirements for public transparency of 

information related to allowance or credit issuance, tracking, transfers, and holdings, and 

whether and to what extent oversight authority exists related to measures to ensure liquid 

markets Additionally, the Panel recommends that EPA solicit comment on other approaches to 

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ensure liquidity, including but not limited to the concept of an early incentive pool which would 

serve to incentivize early reductions and create a market of additional allowances. 

2.3.7.4 Renewable Energy and Energy Efficiency

Generally SERs encouraged EPA to incorporate existing EE efforts into the program in a 

way that gives credit for the investment and to rely on “deemed” energy savings to earn 

compliance credits. SERs raised concerns about the accounting of investments in RE and EE

efforts in their compliance with GHG emission standards. 

SERs also expressed concern that they be able to generate and use credits across state 

lines. This is particularly important for the investment in renewables, for which the generating 

potential is highly dependent on geography and is unequally distributed among the states. Thus, 

the Panel recommends that EPA develop a credit or allowance compliance program that allows 

for interstate accounting and trading for states under the federal plan. Additionally, the Panel 

recommends that the program include opportunities for interstate trading between sources in 

states under the federal plan and states under compatible state plans. 

The Panel recommends that EPA consider the treatment of RE and EE in rate-based and 

mass-based federal plan contexts. EPA should further consider how to implement preferred 

policy options in a way that incentivizes investment and does not create unintended barriers for 

small entities. The Panel also recommends that EPA allow crediting of RE across states under 

the federal plan while soliciting comment for allowing crediting for EE across states under the 

federal plan. 

2.3.7.5 Reliability

Multiple SERs expressed concerns that implementation of the EGs, either by states or

through a federal plan, could have a negative impact on reliability because individual units could 

have operational obligations that conflict with the emissions requirements. In their comments, 

both the American Public Power Association (APPA) and the National Rural Electric 

Cooperative Association (NRECA) recommend Dynamic Reliability Safety Valve. EPA noted 

that the use of a reliability mechanism in the EGs is provisioned on the concern that some forms 

of state plan may create inflexible requirements that could in some limited circumstances raise a 

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reliability concern. However, EPA believes the design of the federal plan as a flexible trading 

program alleviates these concerns and therefore a reliability mechanism is not needed.

The Panel recognizes the connection between meeting the GHG reduction goals of the 

federal plan and maintaining the reliability of the electric grid. The Panel recommends that EPA 

fully explain in the proposal and take comment on methods to address reliability and EPA should 

take comment on establishing a reliability safety valve, particularly if small entities can be 

shown to need regulatory flexibility for reliability critical units beyond the flexibilities already 

built into the design of the federal plan. Multiple SERs expressed concerns that implementation 

of the EGs, either by states or through a federal plan, could have a negative impact on reliability 

because individual units could have operational obligations that conflict with the emissions 

requirements. In their comments, both the American Public Power Association (APPA) and the 

National Rural Electric Cooperative Association (NRECA) recommend Dynamic Reliability 

Safety Valve. EPA noted that the use of a reliability mechanism in the EGs is provisioned on the 

concern that some forms of state plan may create inflexible requirements that could in some 

limited circumstances raise a reliability concern. However, EPA believes the design of the 

federal plan as a flexible trading program alleviates these concerns and therefore a reliability 

mechanism is not needed.

The Panel recognizes the connection between meeting the GHG reduction goals of the 

federal plan and maintaining the reliability of the electric grid. The Panel recommends that EPA 

fully explain in the proposal and take comment on methods to address reliability and EPA should 

take comment on establishing a reliability safety valve, and whether there is a need for regulatory 

flexibility for reliability critical units beyond the flexibilities already built into the design of the 

federal plan.

2.3.7.6 Subcategorization/Applicability/Exemptions 

SER comments on applicability reflect concerns related to the combined series of 

rulemakings affecting GHG emissions from electricity generating units: the NSPS, the EGs and 

the federal plan. SERs endorse excluding RICE and NGSC units from the combined 

rulemakings. One SER requests a subcategory that addresses the particular characteristics of 

lignite coal. Some SERs suggest special provisions for small units or utilities, including a small 

system exemption. The SBA suggested taking comment on an economic hardship exemption for 

419
small entities and that EPA propose a mechanism for additional compliance time when 

generation and transmission investments necessary for compliance have been delayed by 

government reviews. However, EPA noted that regulatory exemptions must be grounded in 

statute and supported by analysis, and EPA believes the design of the federal plan itself should 

maximize compliance options that are both consistent with the EGs and also should adequately 

address these concerns.

The Panel notes that EPA must be consistent with the EGs on issues of applicability, 

which should address the SERs’ concerns with regard to inclusion of RICE or NGSC units. The 

Panel also notes that EPA is proposing a design to the federal plan that utilizes emission trading 

and thus maximizes compliance options such that individual units can take into account their 

particular characteristics in designing a compliance strategy. This should further address 

concerns and make unnecessary the need for further sub-categorization or the use of unit-specific 

exemptions. Additionally, the Panel recommends that EPA solicit comment on an alternative 

allocation methodology under the mass-based proposed federal plan that may increase 

allocations for small businesses, and consider whether there are parallel mechanisms in a ratebased proposal that could provide similar regulatory relief or benefits for small entities, if 

appropriate.SER comments on applicability reflect concerns related to the combined series of 

rulemakings affecting GHG emissions from electricity generating units: the NSPS, the EGs and 

the federal plan. SERs endorse excluding RICE and NGSC units from the combined 

rulemakings. One SER requests a subcategory that addresses the particular characteristics of 

lignite coal. Some SERs suggest special provisions for small units or utilities, including a small 

system exemption. The SBA suggested taking comment on an economic hardship exemption for 

small entities and that EPA propose a mechanism for additional compliance time when 

generation and transmission investments necessary for compliance have been delayed by 

government reviews. However, EPA noted that regulatory exemptions must be grounded in 

statute and supported by analysis, and EPA believes the design of the federal plan itself should 

maximize compliance options that are both consistent with the EGs and also should adequately 

address these concerns.

The Panel notes that EPA must be consistent with the EGs on issues of applicability, 

which should address the SERs’ concerns with regard to inclusion of RICE or NGSC units. The 

Panel also notes that EPA is proposing a design to the federal plan that utilizes emission trading 

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and thus maximizes compliance options such that individual units can take into account their 

particular characteristics in designing a compliance strategy. In EPA’s view, this makes it less 

likely that there is a need for further sub-categorization or the use of unit-specific exemptions. 

Additionally, the Panel recommends that EPA solicit comment on an alternative allocation 

methodology under the mass-based proposed federal plan that may increase allocations for small 

businesses, and consider whether there are parallel mechanisms in a rate-based proposal that 

could provide similar regulatory relief or benefits for small entities, if appropriate.

2.4 Unfunded Mandates Reform Act (UMRA)

This action contains a federal mandate under UMRA, 2 U.S.C. 1531-1538, that could 

potentially result in expenditures of $100 million or more for state, local, and tribal governments, 

in the aggregate, or the private sector in any one year. This federal plan will apply only to those 

EGUs located in states that do not submit approvable state plans, which is a subset of the EGUs 

considered in the RIA for the final emission guidelines (EGs) (see RIA for further discussion of 

impacts). Because it is impossible to determine at this time which states might be ultimately 

subject to a federal plan, EPA cannot determine whether this final rule will be subject to UMRA. 

However, as noted below, the Agency has done substantial outreach to government entities as 

part of both the federal plan and the related 111(d) rulemaking. Further, regardless of whether 

EPA does determine that this action ultimately meets the UMRA threshold, the agency intends to 

do additional outreach with government entities between now and the final rule. Additionally, 

the EPA has determined that this action is not subject to the requirements of section 203 of 

UMRA because it contains no regulatory requirements that might significantly or uniquely affect 

small governments. 

Nevertheless, the EPA is aware that there is substantial interest in this rule among small 

entities (e.g., municipal and rural electric cooperatives). In light of this interest, prior to this 

action, the EPA sought early input from representatives of small entities while formulating the 

provisions of the proposed regulation. Such outreach is also consistent with the President’s 

January 18, 2011 Memorandum on Regulatory Flexibility, Small Business, and Job Creation, 

which emphasizes the important role small businesses play in the American economy. This 

outreach process has enabled the EPA to hear directly from these representatives, as EPA 

developed the rule about how the EPA should approach the complex question of how to apply 

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section 111 of the CAA to the regulation of GHGs from these source categories. We invite 

comments on all aspects of this proposal and its impacts, including potential adverse impacts, on 

small entities. [Placeholder]

2.5 Executive Order 13132: Federalism

The EPA believes that this proposed rule may be of significant interest to state and local 

governments due to its relationship with the Clean Power Plan EGs. Therefore, the EPA has 

determined that consultations with state and local governments conducted during the Clean 

Power Plan EGs development process are also relevant to this proposed rule. Consistent with the 

EPA’s policy to promote communications between the EPA and state and local governments, the 

EPA consulted with state and local officials early in the process of developing the Clean Power 

Plan EGs to permit them to have meaningful and timely input into its development. As described 

in the Federalism discussion in the preamble to the proposed standards of performance for GHG 

emissions from new EGUs (79 FR 1501; January 8, 2014), the EPA consulted with state and 

local officials in the process of developing the proposed standards for newly constructed EGUs. 

A detailed Federalism Summary Impact Statement (FSIS) describing the most pressing issues 

raised in pre-proposal and post-proposal comments will be forthcoming with the final Clean 

Power Plan EGs, as required by section 6(b) of Executive Order 13132. In the spirit of Executive 

Order 13132, and consistent with the EPA’s policy to promote communications between the 

EPA and state and local governments, the EPA specifically solicits comment on this proposed 

action from state and local officials.[Placeholder]

2.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments

This proposed action has tribal implications. However, it will neither impose substantial 

direct compliance costs on federally recognized tribal governments, nor preempt tribal law. The 

EGU potentially impacted by this proposed rulemaking located on Indian reservations are 

primarily owned by private entities, and in one case, partially owned by an agency of the U.S. 

government. As a result, the tribes on whose areas of Indian country those units are located will 

not be directly impacted by any costs of complying with this proposed rulemaking incurred by 

the owners/operators of those units. There would only be tribal implications in regards to 

compliance costs associated with this proposed rulemaking in the case where a tribal government 

422
has an ownership interest in a potentially affected EGU. A tribal government could also incur 

costs in the event that it seeks and is given delegated authority to enforce the federal plan 

proposed in this rulemaking. The EPA has, nevertheless, offered consultation to the tribes on 

whose areas of Indian country the units are located. As part of its general outreach to tribes 

regarding this proposed rulemaking, the EPA received feedback from a number of tribes 

regarding the potential overall economic impact that both the proposed Clean Power Plan and a 

proposed federal plan rulemaking may have on them. In these instances, the EPA has reached out 

to these tribes and as part of the consultation on the Clean Power Plan engaged with them on 

their concerns regarding a potential federal plan. 

The EPA has conducted consultation with tribes on the Clean Power Plan and the 

Supplemental Proposal for the Clean Power Plan and will offer all tribes consultation on this 

proposed action. The EPA held consultations with tribes on the Clean Power Plan in the fall of 

2014 before the agency issued its Supplemental Proposal for Indian Country and U.S. Territories. 

Additionally, the EPA held consultations for tribes shortly following the release of the 

supplemental proposal. The agency also held a public hearing on the supplemental proposal on 

November 19, 2014, in Phoenix, Arizona. At the public hearing the agency received oral 

comments from community members representing a number of tribes and a number of tribal 

officials. The agency also conducted consultation with tribes in the spring and summer of 2015. 

An overview of the consultations provided as part of the Clean Power Plan is available in section 

XII.F of the final EGs. 

Additionally, the EPA engaged in meaningful dialogue with tribal stakeholders to obtain 

their feedback in the pre-proposal stages of this rulemaking. We provided an update on this 

proposed rulemaking on the May 28, 2015, National Tribal Air Association and the EPA Air 

Policy call. Additionally, staff attended the National Tribal Forum conference on May 20, 2015 

and provided an overview of the Clean Power Plan and explained that the agency would be 

proposing a federal plan. 

Consistent with previous rulemakings impacting the power sector, there is significant 

tribal interest in these rulemakings because of the potential indirect impacts that rules such as the 

Clean Power Plan and this proposed federal plan may have on tribes. The EPA specifically 

solicits additional feedback from tribal officials on all aspects of this proposed rulemaking, 

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including whether tribes whose areas of Indian country contain affected EGU(s) are interested in 

developing their own plan implementing the final EGs. Additionally, tribal stakeholders will be 

included in the outreach that the agency will be conducting with those communities already 

overburdened by pollution, which are often low-income communities, communities of color, and 

indigenous communities. The actions that the agency will be taking are outlined in section IX of 

thethis preamble. [Placeholder]

2.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those 

regulatory actions that concern health or safety risks, such that the analysis required under 

section 5–501 of the Order has the potential to influence the regulation. This action is not subject 

to EO 13045 because it does not involve decisions on environmental health or safety risks that 

may disproportionately affect children. The EPA believes that the CO2 emission reductions 

resulting from implementation of the proposed guidelines, as well as substantial ozone and 

PM2.5 emission reductions as a cobenefit, would further improve children’s health.[Placeholder]

2.8 Executive Order 13211: Actions That Significantly Affect Energy Supply, 

Distribution, or Use 

This action, which is a significant regulatory action under EO 12866, is likely to have a 

significant effect on the supply, distribution, or use of energy. The EPA has prepared a Statement 

of Energy Effects for this action as follows. We estimate a 1 to 2 percent change in retail 

electricity prices on average across the contiguous U.S. in 2025, and a 22 to 23 percent reduction 

in coal-fired electricity generation as a result of this rule. The EPA projects that utility power 

sector delivered natural gas prices will increase by up to 2.5 percent in 2030. For more 

information on the estimated energy effects, please refer to the economic impact analysis for this 

proposal in Chapter 1 of this RIA. The analysis is available in the RIA, which is in the public 

docket.

This action, which is a significant regulatory action under EO 12866, is likely to have a 

significant effect on the supply, distribution, or use of energy. The EPA has prepared a Statement 

of Energy Effects for this action as follows. We estimate a 1 to 2 percent change in retail 

electricity prices on average across the contiguous U.S. in 2025, and a 22 to 23 percent reduction 

424
in coal-fired electricity generation as a result of this rule. The EPA projects that utility power 

sector delivered natural gas prices will increase by up to 2.5 percent in 2030. For more 

information on the estimated energy effects, please refer to the economic impact analysis for this 

proposal. The analysis is available in the RIA, which is in the public docket. 

[Placeholder]

2.9 National Technology Transfer and Advancement Act (NTTAA) 

This proposed action does not involve technical standards. 

2.10 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations

[Placeholder]Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal 

executive policy on EJ. Its main provision directs federal agencies, to the greatest extent 

practicable and permitted by law, to make EJ part of their mission by identifying and addressing, 

as appropriate, disproportionately high and adverse human health or environmental effects of 

their programs, policies, and activities on minority populations and low-income populations in 

the U.S. The EPA defines EJ as the fair treatment and meaningful involvement of all people 

regardless of race, color, national origin, or income with respect to the development, 

implementation, and enforcement of environmental laws, regulations, and policies. The EPA has 

this goal for all communities and persons across this Nation. It will be achieved when everyone 

enjoys the same degree of protection from environmental and health hazards and equal access to 

the decision-making process to have a healthy environment in which to live, learn, and work. 

Leading up to this rulemaking the EPA summarized the public health and welfare effects 

of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment Finding, the 

Administrator considered climate change risks to minority populations and low-income 

populations, finding that certain parts of the population may be especially vulnerable based on 

their characteristics or circumstances. Populations that were found to be particularly vulnerable 

to climate change risks include the poor, the elderly, the very young, those already in poor 

health, the disabled, those living alone, and/or indigenous populations dependent on one or a few 

resources. See sections X.F and X.G of thethis preamble, above, where the EPA discusses 

Consultation and Coordination with Tribal Governments and Protection of Children. The 

425
Administrator placed weight on the fact that certain groups, including children, the elderly, and 

the poor, are most vulnerable to climate-related health effects.

The record for the 2009 Endangerment Finding summarizes the strong scientific evidence 

in the major assessment reports by the U.S. Global Change Research Program, the 

Intergovernmental Panel on Climate Change (IPCC), and the National Research Council of the 

National Academies that the potential impacts of climate change raise EJ issues. These reports 

concluded that poor communities can be especially vulnerable to climate change impacts because 

they tend to have more limited adaptive capacities and are more dependent on climate-sensitive 

resources such as local water and food supplies. In addition, Native American tribal communities 

possess unique vulnerabilities to climate change, particularly those impacted by degradation of 

natural and cultural resources within established reservation boundaries and threats to traditional 

subsistence lifestyles. Tribal communities whose health, economic well-being, and cultural 

traditions that depend upon the natural environment will likely be affected by the degradation of 

ecosystem goods and services associated with climate change. The 2009 Endangerment Finding 

record also specifically noted that Southwest native cultures are especially vulnerable to water 

quality and availability impacts. Native Alaskan communities are already experiencing 

disruptive impacts, including coastal erosion and shifts in the range or abundance of wild species 

crucial to their livelihoods and well-being. 

The most recent assessments continue to strengthen scientific understanding of climate 

change risks to minority populations and low-income populations in the U.S.55 The new 

55 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United 

States: The Third National Climate Assessment. U.S. Global Change Research Program, 841 pp. 

 

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects.

Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate 

Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, 1132 pp.

 

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects. Contribution 

of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Barros, 

V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, 

R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, 688 pp.

426
assessment literature provides more detailed findings regarding these populations’ vulnerabilities 

and projected impacts they may experience. In addition, the most recent assessment reports 

provide new information on how some communities of color may be uniquely vulnerable to 

climate change health impacts in the U.S. These reports find that certain climate change related 

impacts—including heat waves, degraded air quality, and extreme weather events—have 

disproportionate effects on low-income populations and some communities of color (in 

particular, populations defined jointly by ethnic/racial characteristics and geographic location), 

raising EJ concerns. Existing health disparities and other inequities in these communities 

increase their vulnerability to the health effects of climate change. In addition, assessment 

reports also find that climate change poses particular threats to health, well-being, and ways of 

life of indigenous peoples in the U.S. 

As the scientific literature presented above and as the 2009 Endangerment Finding 

illustrates, low income populations and some communities of color are especially vulnerable to 

the health and other adverse impacts of climate change. The EPA believes that communities will 

benefit from this proposed federal plan because this action directly addresses the impacts of 

climate change by limiting GHG emissions through the establishment of CO2 emission standards 

for existing affected fossil fuel-fired EGUs. 

In addition to reducing CO2 emissions, the guidelines finalized in this rulemaking would 

reduce other emissions from affected EGUs that reduce generation due to higher adoption of EE 

and RE. These emission reductions will include SO2 and NOx, which form ambient PM2.5 and 

ozone in the atmosphere, and HAP, such as mercury and hydrochloric acid. In the final rule 

revising the annual PM2.5 NAAQS,56 the EPA identified low-income populations as being a 

vulnerable population for experiencing adverse health effects related to PM exposures. Lowincome populations have been generally found to have a higher prevalence of pre-existing 

diseases, limited access to medical treatment, and increased nutritional deficiencies, which can 

increase this population’s susceptibility to PM-related effects.57 In areas where this rulemaking 

reduces exposure to PM2.5, ozone, and methylmercury, low-income populations will also benefit 

56 “National Ambient Air Quality Standards for Particulate Matter, Final Rule,” 78 FR 3086 (Jan. 15, 2013).

57 U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for Particulate Matter 

(Final Report). EPA-600-R-08-139F. National Center for Environmental Assessment – RTP Division. December. 

Available on the Internet at http://www.cfpub.epa.gov/si/si_public_record_Report.cfm?dirEntryId=216546. 

427
from such emissions reductions. TheChpaterChapter 1 of this 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. 

Additionally, as outlined in the community and EJ considerations section IX of thisthe 

preamble, the EPA has taken a number of actions to help ensure that this action will not have 

potential disproportionately high and adverse human health or environmental effects on 

vulnerable communities. The EPA consulted its May 2015, Guidance on Considering 

Environmental Justice During the Development of Regulatory Actions, when determining what 

actions to take.58 As described in the community and EJ considerations section of theis preamble 

the EPA also conducted a proximity analysis, which is available in the docket of this rulemaking 

and is discussed in section IX of theis preamble. Additionally, as outlined in sections I and IX of 

theis preamble the EPA has engaged meaningfully with communities throughout the 

development of the CPP and has devised a robust outreach strategy for continual engagement 

throughout this rulemaking. 

58 Guidance on Considering Environmental Justice During the Development of Regulatory Actions. 

http://www.epa.gov/environmentaljustice/resources/policy/considering-ej-in-rulemaking-guide-final.pdf. May 

2015.

428
United States

Environmental 

Protection Agency 

Office of Air Quality Planning and Standards 

Health and Environmental Impacts Division 

Research Triangle Park, NC

Publication No. 

EPA-452/R-15-006 

July 2015 

429
Attachment R.3

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment R.3.

430
Attachment S.

431
From: Jones, Toni <Jones.Toni@epa.gov>

Sent: Saturday, August 1, 2015 4:43 PM

To: Frey, Nathan J.; Szabo, Aaron

Cc: Harvey, Reid; Tsirigotis, Peter; Eck, Janet; Cozzie, David; Culligan, Kevin

Subject: EO 12866 CPP Federal Plan

  

Hi Nathan and Aaron,

Attached please find the final, clean versions of the CPP Federal Plan preamble and rule.  Additionally,

attached is a redline version of both files (indicated by “RLSO” in the file name) that reflect changes

made to the package since the initial submittal to OMB.  Also attached is the final RIA.

Please let know if you have any questions.

It’s been a pleasure working with both of you!

Kind regards,

Toni

Toni Wyche Jones, EI, CFM | Fuels & Incineration Group | Sector Policies & Programs Division - Mail Code E143-

05 | Office of Air Quality Planning & Standards | U.S. Environmental Protection Agency | RTP, NC 27711 | Phone: 

(919) 541-0316 |

432
Attachment S.1

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment S.1.

433
Attachment S.2

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment S.2.

434
Attachment S.3

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment S.3.

435
Attachment S.4

This file is available in the docket with title Clean Power Plan (CPP) Federal Plan – Summary of

EPA Interagency Communications – Attachment S.4.

436
Attachment S.5

437
Regulatory Impact Analysis 

for the 

 Proposed Federal Plan Requirements for 

Greenhouse Gas Emissions from Electric 

Utility Generating Units Constructed on or 

Before January 8, 2014; Model Trading 

Rules; Amendments to Framework 

Regulations 

438
ii 

[This page intentionally left blank] 

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iii 

EPA-452/R-15-006 

August 2015 

Regulatory Impact Analysis for the for the 

 Proposed Federal Plan Requirements for Greenhouse Gas 

Emissions from Electric Utility Generating Units Constructed on or 

Before January 8, 2014; Model Trading Rule 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

Office of Air Quality Planning and Standards 

Research Triangle Park, NC 27711 

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iv 

CONTACT INFORMATION 

This document has been prepared by staff from the Office of Air Quality Planning and 

Standards, the Office of Atmospheric Programs, and the Office of Policy of the U.S. 

Environmental Protection Agency. Questions related to this document should be addressed to 

Alexander Macpherson, U.S. Environmental Protection Agency, Office of Air Quality Planning 

and Standards, Research Triangle Park, North Carolina 27711 (email: 

macpherson.alex@epa.gov). 

ACKNOWLEDGEMENTS 

Thank you to the many staff who worked on this document from EPA Offices including 

the Office of Air Quality Planning and Standards, the Office of Atmospheric Programs, and the 

Office of Policy. Contributions to this report were also made by ICF International. 

441
v 

Table of Contents 

LIST OF TABLES ........................................................................................................................vii

CHAPTER 1: SUMMARY OF POTENTIAL REGULATORY IMPACTS ............................................ 1-1

1.1 Introduction ........................................................................................................... 1-1

1.2 Legal, Scientific and Economic Basis for this Rulemaking ..................................... 1-2

1.2.1 Statutory Requirement ................................................................................ 1-2

1.2.2 Health and Welfare Impacts from Climate Change ...................................... 1-2

1.2.3 Market Failure ............................................................................................ 1-3

1.3 Background for the Proposed Federal plan and model trading rules........................ 1-4

1.3.1 Definition of Affected Sources .................................................................... 1-4

1.3.2 Trade in Compliance Instruments across States ........................................... 1-4

1.3.3 Model Trading Rule .................................................................................... 1-5

1.4 Summary of Regulatory Analysis........................................................................... 1-5

1.4.1 Base Case and Years of Analysis ................................................................ 1-7

1.4.2 Federal Plan Approaches Examined in RIA ................................................ 1-8

1.5 Summary of Regulatory Analysis..........................................................................1-11

1.5.1 Emissions Reductions ................................................................................1-11

1.5.2 Costs ..........................................................................................................1-14

1.5.3 Monetized Climate Benefits and Health Co-benefits ..................................1-16

1.5.4 Net Benefits ...............................................................................................1-27

1.5.5 Economic Impacts......................................................................................1-30

1.5.6 Employment Impacts .................................................................................1-30 

1.5.7 Additional Analysis of Output-Based Allocation as a Means of Mitigating 

Leakage ................................................................................................................1-32 

1.5.8 Uncertainty Analysis ..................................................................................1-33

1.6 References ............................................................................................................1-37

CHAPTER 2: STATUTORY AND EXECUTIVE ORDER REVIEWS ................................................. 2-1

2.1 Executive Order 12866: Regulatory Planning and Review and Executive Order 

13563: Improving Regulation and Regulatory Review .................................................. 2-1

2.2 Paperwork Reduction Act ...................................................................................... 2-4

2.3 Initial Regulatory Flexibility Analysis.................................................................... 2-6

2.3.1 Reasons why Action is Being Considered ................................................... 2-6

2.3.2 Statement of Objectives and Legal Basis for Proposed Rules ...................... 2-7

2.3.3 Description and Estimate of Affected Small Entities ................................... 2-8

2.3.4 Compliance Cost Impact Estimates ............................................................2-14

2.3.5 Projected Reporting, Recordkeeping and Other Compliance Requirements 2-22

2.3.6 Related Federal Rules ................................................................................2-23

2.3.7 Regulatory Flexibility Alternatives ............................................................2-23

2.4 Unfunded Mandates Reform Act (UMRA) ............................................................2-29

2.5 Executive Order 13132: Federalism ......................................................................2-29

2.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments ...............................................................................................................2-30

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vi 

2.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks ..........................................................................................................2-32

2.8 Executive Order 13211: Actions That Significantly Affect Energy Supply, 

Distribution, or Use .....................................................................................................2-32

2.9 National Technology Transfer and Advancement Act (NTTAA) ...........................2-32

2.10 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations .....................................................2-32

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vii 

LIST OF TABLES

Table 1-1. Climate and Air Pollutant Emission Reductions for the Rate-Based Federal 

Plan Approach ............................................................................................................1-12

Table 1-2. Climate and Air Pollutant Emission Reductions for the Mass-Based Federal 

Plan Appproach ..........................................................................................................1-13

Table 1-3. Projected CO2 Emission Reductions, Relative to 2005 ...................................1-14

Table 1-4. Compliance Costs for the Federal Rate-Based and Mass-Based Plan 

Approaches.................................................................................................................1-15

Table 1-5. Quantified and Unquantified Benefits ............................................................1-17

Table 1-6. Combined Estimates of Climate Benefits and Health Co-Benefits for RateBased Approach (billions of 2011$) ............................................................................1-26

Table 1-7. Combined Estimates of Climate Benefits and Health Co-benefits for MassBased Approach (billions of 2011$) ............................................................................1-27

Table 1-8. Monetized Benefits, Compliance Costs, and Net Benefits Under the Ratebased Federal Plan Approach (billions of 2011$) ........................................................1-28

Table 1-9. Monetized Benefits, Compliance Costs, and Net Benefits under the Massbased Federal Plan Approach (billions of 2011$) ........................................................1-29

Table 1-10. Summary Table of Important Energy Market Impacts (Percent Change from 

Base Case) ..................................................................................................................1-30

Table 2-1. SBA Size Standards by NAICS Code .............................................................2-12

Table 2-2. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Rate-Based Federal Plan Approach in 2030 .................................................2-18

Table 2-3. Projected Impact on Small Entities in 2030 under Rate-Based Federal Plan 

Approach ....................................................................................................................2-18

Table 2-4. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Mass-Based Federal Plan Approach in 2030 ................................................2-19

Table 2-5. Projected Impact on Small Entities in 2030 under Mass-Based Federal Plan 

Approach ....................................................................................................................2-19

Table 2-6. Incremental Costs in 2030 under the Rate-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) .........2-20

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viii 

Table 2-7. Incremental Costs in 2030 under the Mass-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) .........2-21

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1-1 

CHAPTER 1: SUMMARY OF POTENTIAL REGULATORY IMPACTS

1.1 Introduction 

This Regulatory Impact Analysis (RIA) discusses potential benefits, costs, and economic 

impacts of for the “Proposed Federal Plan Requirements for Greenhouse Gas Emissions from 

Electric Utility Generating Units Constructed on or Before January 8, 2014; Model Trading 

Rules; Amendments to Framework Regulations” (herein also referred to as “proposed federal 

plan and model trading rules”1). In this action, the Environmental Protection Agency (EPA) is 

proposing a federal plan to implement the emission guidelines for existing fossil fuel-fired EGUs 

under the Clean Air Act (CAA). The emission guidelines were proposed in June 2014 and 

finalized on August 3, 2015 as the Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units (also referred to as the Clean Power Plan or Emission 

Guidelines). The EPA is taking comment on many of the elements of this proposal. 

This proposal presents two approaches to a federal plan (or model rule) for states and 

other jurisdictions that either chose to adopt a model rule or do not adopt and submit to the EPA 

in a timely manner an approvable state plan: a rate-based emission trading program and a massbased emission trading program. The federal plan is an important measure to ensure that 

congressionally mandated emission standards under the authority of the CAA are implemented. 

The agency is also proposing a necessary or appropriate finding for the affected EGUs in several 

areas of Indian country and is proposing the federal plan for these affected EGUs. 

The proposed federal plan is related to but separate from the final emission guidelines. 

The final emission guidelines establish the best system of emission reduction (BSER) for 

applicable fossil fuel-fired EGUs in the form of a carbon dioxide (CO2) emission performance 

rate for steam-fired EGUs and a CO2 emission performance rate for natural gas-fired combined 

cycle units, and provide guidance and criteria for the development of approvable state plans. The 

purpose of the proposed federal plan is to establish requirements directly applicable to a state’s 

affected EGUs that meet the emission performance levels in order to achieve reductions in 

 

1

 The proposed amendments to the framework regulations for section 111(d) are limited to enhancements in the 

procedure and timing of the EPA’s action on state plans. See Section VII of the preamble. They do not modify 

requirements or obligations in the CPP or other substantive rules, or directly regulate any third parties. Therefore, 

the EPA has not included these changes in its analysis in this RIA and proposes to certify that these changes will not 

have a significant impact on a significant number of small entities pursuant to the Regulatory Flexibility Act (RFA). 

446
1-2 

carbon dioxide (CO2) emissions in the case where a state or other jurisdiction does not submit an 

approvable plan. The stringency of the emission performance levels established in the final 

emission guidelines will be the same whether implemented through a state plan or a federal plan. 

1.2 Legal, Scientific and Economic Basis for this Rulemaking 

1.2.1 Statutory Requirement 

Section 111(d)(2) of the Clean Air Act (CAA), 42 U.S.C. 7411(d)(2) provides the EPA 

the same authority to prescribe a plan for a state in cases where the state fails to submit a 

satisfactory plan as the Agency would have under CAA section 110(c) in the case of failure to 

submit a National Ambient Air Quality Standard implementation plan. In addition, the EPA has 

authority under CAA section 111(d)(1) to prescribe regulations that establish procedures similar 

to CAA section 110 with respect to the submission of state plans, and the EPA also has general 

rulemaking authority as necessary to implement the CAA under section 301. A federal Plan 

under CAA section 111(d) applies, implements and enforces standards of performance for 

affected EGUs. Under the Clean Power Plan Emission Guidelines, state plans will be due on 

September 6, 2016. States are also allowed to seek a two year extension for a final plan 

submittal, upon submitting a satisfactory initial submittal by the same deadline. If a state fails to 

submit a final state plan or initial submittal, or if either a final state plan or an initial submittal 

does not meet the requirements of the final emission guidelines, the Agency will take the 

appropriate steps to finalize and implement a federal plan. 

States will remain free, and indeed are strongly encouraged, to submit an approvable state 

plan even after promulgation of the federal plan for their jurisdictions. Upon approval of the state 

plan by EPA, the federal plan will no longer apply to the affected EGUs covered by the approved 

state plan, starting at the initiation of the next compliance period with the limitations noted in the 

federal plan. 

1.2.2 Health and Welfare Impacts from Climate Change 

According to the National Research Council, “Emissions of CO2 from the burning of 

fossil fuels have ushered in a new epoch where human activities will largely determine the 

evolution of Earth’s climate. Because CO2 in the atmosphere is long lived, it can effectively lock 

Earth and future generations into a range of impacts, some of which could become very severe. 

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1-3 

Therefore, emission reduction choices made today matter in determining impacts experienced 

not just over the next few decades, but in the coming centuries and millennia.”2 

In 2009, based on a large body of robust and compelling scientific evidence, the EPA 

Administrator issued the Endangerment Finding under CAA section 202(a)(1).3 In the 

Endangerment Finding, the Administrator found that the current, elevated concentrations of 

GHGs in the atmosphere—already at levels unprecedented in human history—may reasonably 

be anticipated to endanger public health and welfare of current and future generations in the 

United States. 

Since the administrative record concerning the Endangerment Finding closed following 

the EPA’s 2010 Reconsideration Denial, the climate has continued to change, with new records 

being set for a number of climate indicators such as global average surface temperatures, Arctic 

sea ice retreat, CO2 concentrations, and sea level rise. Additionally, a number of major scientific 

assessments have been released that improve understanding of the climate system and strengthen 

the case that GHGs endanger public health and welfare both for current and future generations. 

These assessments are from the Intergovernmental Panel on Climate Change (IPCC), the U.S. 

Global Change Research Program (USGCRP), and the National Research Council (NRC). These 

and other assessments are discussed in more detail in the Final Clean Power Plan Emission 

Guidelines preamble and in Chapter 4 of the Clean Power Plan Final Rule Regulatory Impact 

Analysis (RIA).4

1.2.3 Market Failure 

Many regulations are promulgated to correct market failures, which otherwise lead to a 

suboptimal allocation of resources within the free market. Air quality and pollution control 

regulations address “negative externalities” whereby the market does not internalize the full 

opportunity cost of production borne by society as public goods such as air quality are unpriced. 

 

2 National Research Council, Climate Stabilization Targets, p.3. 

3

 “Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air 

Act,” 74 Fed. Reg. 66,496 (Dec. 15, 2009) (“Endangerment Finding”). 

4

 U.S. Environmental Protection Agency (U.S. EPA). 2015a. Regulatory Impact Analysis for the Clean Power Plan 

Final Rule. EPA-452/R-15-003. Office of Air Quality Planning and Standards, Health and Environmental Impacts 

Division, Research Triangle Park, NC. 

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1-4 

GHG emissions impose costs on society, such as negative health and welfare impacts, 

that are not reflected in the market price of the goods produced through the polluting process. 

For this regulatory action the good produced is electricity. If a fossil fuel-fired electricity 

producer pollutes the atmosphere when it generates electricity, this cost will be borne not by the 

polluting firm but by society as a whole, thus imposing a negative externality. The equilibrium 

market price of electricity may fail to incorporate the full opportunity cost to society of 

generating electricity. All else equal, given this externality, the composition of EGUs used to 

generate electricity in a free market will not be socially optimal, and the quantity of electricity 

generated may not be at the socially optimal level. Fossil fuel-fired EGUs may produce more 

electricity than would occur if they had to account for the cost associated with this negative 

externality. Consequently, absent a regulation on emissions, the composition of the fleet of 

EGUs used to generate electricity may not be socially optimal, and the marginal social cost of 

the last unit of electricity produced may exceed its marginal social benefit. In the instances where 

the agency finalizes and implements a federal plan for a state’s affected EGUs, this proposed 

regulation will work towards addressing this market failure by causing affected EGUs to begin to 

internalize the negative externality associated with CO2 emissions. 

1.3 Background for the Proposed Federal plan and model trading rules 

1.3.1 Definition of Affected Sources 

Existing fossil fuel-fired electric generating units subject to the final Clean Power Plan 

Emission Guidelines that are located in a state that does not have an EPA-approved state plan are 

potentially subject to this proposed action. Existing fossil fuel-fired EGUs are those that were in 

operation or had commenced construction on or before January 8, 2014.5

1.3.2 Trade in Compliance Instruments across States 

The EPA intends to set up and administer a program to track trading programs – both 

rate-based and mass-based – that will be available for all states that choose it. The EPA proposes 

that affected EGUs in any state covered by a federal plan could trade compliance instruments 

 

5

 An affected EGU is any fossil fuel-fired EGU that was in operation or had commenced construction as of January 

8, 2014, and is therefore an ‘‘existing source’’ for purposes of CAA section 111, and that in all other respects 

would meet the applicability criteria for coverage under the proposed GHG standards for new fossil fuel-fired 

EGUs (79 FR 1430; January 8, 2014). 

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1-5 

with affected EGUs in any other state covered by a federal plan or a state plan meeting the 

conditions for linkage to the federal plan. In the proposed mass-based federal-plan trading 

program, this would mean that affected EGUs in a state covered by the federal plan or a state 

meeting the conditions for linkage to the federal plan could use, as a compliance instrument, an 

allowance distributed in any other state covered by the federal plan or a state meeting the 

conditions for linkage to the federal plan. Similarly, in the proposed rate-based federal-plan 

trading program approach, this would mean that affected EGUs in a state covered by the federal 

plan or a state meeting the conditions for linkage to the federal plan could use, as a compliance 

instrument, an ERC issued in any other state covered by the federal plan or a state meeting the 

conditions for linkage to the federal plan. EPA is proposing that an affected EGU in a state 

covered by the mass-based trading federal plan must use allowances for compliance (not ERCs). 

Similarly, an affected EGU in a state covered by the rate-based trading federal plan must use 

ERCS for compliance (not allowances). 

1.3.3 Model Trading Rule 

A state program that adheres to the model trading rule provisions specified in this 

rulemaking would be presumptively approvable. States may submit means of meeting the 

emission guidelines requirements that differ from the model trading rule provisions, so long as 

the state demonstrates to the EPA’s satisfaction in the state plan submittal that such alternative 

means of addressing requirements are at least as stringent as the presumptively approvable 

approach described here. Additionally, there are stand-alone portions of the model trading rules, 

such as the evaluation, measurement, and verification (EM&V) procedures that would be 

approvable even if a state adopted an approach that differs from the federal plan. The model 

trading rules serve as a mechanism to facilitate larger trading markets since consistency with the 

federal plan allows trading across both the state and federal programs. The EPA expects a larger 

trading region is likely to result in lower overall costs. 

1.4 Summary of Regulatory Analysis 

In accordance with Executive Order 12866, Executive Order 13563, OMB Circular A-4, 

and the EPA’s “Guidelines for Preparing Economic Analyses,” the EPA prepared this RIA for 

this “significant regulatory action.” This action is an economically significant regulatory action 

because it may have an annual effect on the economy of $100 million or more or adversely affect 

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in a material way the economy, a sector of the economy, productivity, competition, jobs, the 

environment, public health or safety, or state, local, or tribal governments or communities.6 

This action proposes a federal plan under section 111(d) of the CAA for the control of 

CO2, a greenhouse gas pollutant, from certain large emitting fossil-fuel fired power plants, in the 

event that some states do not adopt their own plans. Specifically, the EPA is proposing 

approaches in the form of mass- and rate-based trading options that provide flexibility in 

implementing emission standards for a state’s affected EGUs. Both proposed approaches to the 

federal plan would require affected EGUs to meet emission standards set using the CO2 emission 

performance rates in the emission guidelines. The federal plan will achieve the same levels of 

emissions performance as required of state plans under the emission guidelines. 

However, at the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan or adopt a model rule. Because of this lack of information, 

for this RIA, the EPA has chosen to examine two federal plan approach scenarios where all 

states of the contiguous U.S. will be regulated under a federal plan or a model rule. The first 

federal plan approach we examine in this RIA assumes all states in the contiguous U.S. are 

regulated under a rate-based federal plan or model rule. The second federal plan approach we 

examine assumes all contiguous states are regulated under a mass-based federal plan or model 

rule. These two approaches are a re-presentation of the modeling done for the Clean Power Plan 

Emission Guidelines RIA. 

This approach is consistent with the analysis presented in the RIA for the final Clean 

Power Plan Emission Guidelines (U.S. EPA 2015). As a result, this RIA for the proposed federal 

plan and model trading rules re-presents the key results from the final Clean Power Plan 

Emission Guidelines RIA. These key results encompass the potential costs, emission reductions, 

and benefits of the proposed federal plan and model trading rules, as well as the potential 

impacts on electricity markets, employment, and markets outside the electricity sector. 

The RIA also presents a discussion of limitations of the analysis and solicitations for 

public comments that will contribute to the analysis supporting the promulgation of final federal 

 

6

 The analysis in this proposal RIA constitutes the economic assessment required by CAA section 317. In the EPA’s 

judgment, the assessment is as extensive as practicable taking into account the EPA’s time, resources, and other 

duties and authorities. 

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plans (as needed) and model trading rules. In evaluating the impacts of the proposed federal plan 

and model trading rules, we address a number of uncertainties. 

It is important to note that the potential regulatory impacts presented in the Clean Power 

Plan Final Rule RIA and the RIA for this proposed rule are not additive. Both RIAs present 

estimates of the benefits and costs of achieving the emission performance rates of the Clean 

Power Plan emissions guidelines. In the case of the Clean Power Plan Final Rule RIA, the 

illustrative analysis assumes the performance rates are met under state plans. In the case of this 

RIA for the proposed federal plan and model trading rules, the same performance rates are 

accomplished but are assumed to be accomplished under the federal plan or model trading rules. 

This RIA also presents in Chapter 2 the statutory and executive order analyses that 

accompany the proposal for this action, including the Initial Flexibility Regulatory Analysis 

(IRFA). The IRFA describes the economic impact of the proposed rule on small entities and any 

significant alternatives to the proposed rule that would accomplish the objectives of the rule 

while minimizing significant economic impacts on small entities. This IRFA has been prepared 

following EPA’s guidance document for preparing initial and final regulatory flexibility 

analyses.7

1.4.1 Base Case and Years of Analysis 

The base case for this analysis, which uses the Integrated Planning Model (IPM), 

includes state rules that have been finalized and/or approved by a state’s legislature or 

environmental agencies, as well as final federal rules. The IPM Base Case v.5.15 includes the 

Cross-State Air Pollution Rule (CSAPR), the Mercury and Air Toxics Rule (MATS), the 

proposed Carbon Pollution Standards for New Power Plants, the Cooling Water Intakes (316(b)) 

Rule, the Combustion Residuals from Electric Utilities (CCR), and other state and Federal 

regulations to the extent that they contain measures, permits, or other air-related limitations or 

 

7 See “EPA’s Action Development Process: Final Guidance for EPA Rulewriters: Regulatory Flexibility Act as 

amended by the Small Business Regulatory Enforcement Fairness Act.” OPEI Regulatory Development Series. 

November 2006. Available at: <http://www.epa.gov/sbrefa/documents/Guidance-RegFlexAct.pdf>. Accessed July 

21, 2015. 

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requirements. Additional legally binding and enforceable commitments for GHG reductions 

considered in the base case are discussed in the documentation for IPM.8 

To present a complete picture of the potential costs and benefits of the proposed federal 

plan and model trading rules, this RIA presents results for the analysis years 2020, 2025, and 

2030. While 2020 is before the first year of the interim compliance period (2022), the EPA 

expects states and affected EGUs to perform voluntary activities that will facilitate compliance 

with interim and final goals. These pre-compliance period activities might include investments in 

renewable energy or demand-side energy efficiency projects, for example, that produce 

emissions reductions in the compliance period. Activities might also include preparatory 

investments in transmission capacity or monitoring, reporting, and recordkeeping systems. As a 

result, there are likely to be benefits and costs in 2020, so these are reported in this RIA. 

Meanwhile, cost and benefits are estimated in this RIA for 2025, which is intended to represent a 

central period of the interim compliance time-frame as states are on glide paths toward fully 

meeting the final CO2 emission performance goals. Lastly, the RIA presents costs and benefits 

for 2030, when the emission performance goals are fully achieved. 

1.4.2 Federal Plan Approaches Examined in RIA 

In the Final Clean Power Plan Emission Guidelines, the EPA translated the source 

category-specific CO2 emission performance rates into equivalent state-level rate-based and 

mass-based CO2 goals in order to maximize the range of choices that states will have in 

developing their plans.9 As noted above, like the RIA for the Final Clean Power Plan Emission 

Guidelines, this RIA presents two scenarios designed to achieve these goals, which we term the 

rate-based federal plan approach and the mass-based federal plan approach. 

It is very important to note that the differences between the analytical results for the ratebased and mass-based federal plan approaches presented in this RIA may not be indicative of 

likely differences between the approaches. In other words, if one approach performs differently 

 

8

 Detailed documentation for IPM v.5.15 is available at: http://www.epa.gov/powersectormodeling. 

9

 See the preamble of the final Clean Power Plan Emissions Guidelines for these state-level rate-based and massbased CO2 goals. 

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than the other on a given metric during a given time period, this does not imply this will apply in 

all instances in all time periods in all places. 

In the rate-based approach modeled in the RIA for the final Clean Power Plan Emission 

Guidelines, avoided generation from demand-side energy efficiency is counted towards meeting 

the emission performance rates at affected EGUs. However, this federal plan and model trading 

rule proposal takes comment on whether EPA should allow demand-side energy efficiency to 

directly count toward the compliance rate of affected EGUs in a rate-based compliance approach. 

Because energy efficiency is not proposed to be eligible to generate ERCs that could be used to 

comply in the proposed rate-based federal plan, this RIA might be forecasting a different a 

generation mix and emissions levels than might occur from the proposed federal plan.10

Compliance strategies under either approach to the federal plan (mass or rate) may be anticipated 

to rely on different abatement measures than those modeled for this RIA. The climate benefits 

and health co-benefits arising from these alternative strategies may be different those presented 

here. We will update this analysis as necessary to support the final rule. 

Even without explicit incentives for energy efficiency under a rate-based federal plan, we 

believe that the increased focus that the Clean Power Plan Emission Guidelines will bring to 

considerations of CO2 emissions from EGUs will encourage states to consider more aggressive 

demand-side energy policies. Furthermore, the EPA anticipates that many states will submit 

fully-approvable plans, and that demand side energy efficiency is likely to be either an explicit 

component of, or a complimentary policy to, many of those plans. The resulting lower electricity 

demand in states not subject to a federal plan surrounding a state that is subject to a federal plan 

will likely have an impact on fossil generation and thus the cost of reducing CO2 emissions. The 

EPA takes comment on the appropriate way to factor such costs into the analysis of the final 

federal plan and model trading rules. 

In the rate-based approach modeled in the RIA for the final Clean Power Plan Emission 

Guidelines, affected EGUs may not procure emission reductions from (e.g., by averaging their 

emissions with) affected EGUs located in other states (which may also have different emission 

 

10 However, as with states subject to the mass-based approach, energy efficiency activities may be adopted by states 

subject to the rate-based approach to lower demand, which in turn may reduce the compliance cost of achieving 

the performance rates. 

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standards) in order to demonstrate compliance. As described in Section 1.3.2, in the proposed 

rate-based federal plan affected EGUs may procure ERCs from affected EGUs in other ratebased states subject to the federal plan. Furthermore, the rate-based illustrative plan in the Final 

Clean Power Plan Emission Guidelines RIA assumes that the plan applies a state’s blended ratebased goal as a requirement for affected EGUs in that state to achieve.11 Alternatively, the 

proposed federal plan specifically establishes an emissions rate performance standard that is 

applied to affected steam-fired EGUs and an emission rate performance standard that is applied 

to affected natural gas-fired combined cycle EGUs. Applying the subcategory-specific rate goal 

may alter the incentives among affected EGUs and could lead to a different generation mix and 

emission levels. The EPA will further explore the impacts of subcategory-specific rate goals in 

the analysis supporting the final rule. 

The mass-based plan approach requires affected sources in each state to limit their 

aggregate emissions not to exceed the mass goal for that state. The mass-based scenario 

presented in this chapter includes a 5 percent set-aside of allowances that would be allocated to 

recognize deployment of new renewable capacity, which is represented by lowering the capital 

cost of new renewable capacity in a compliance period by the estimated value of the allowances 

in the set-aside in that period. 

The EPA is also proposing a set-aside approach referred to as output-based allocation 

(OBA), which provides targeted allocations of a limited portion of allowances to existing NGCC 

units as a means of mitigating leakage. The EPA believes that this proposed set-aside would 

address incentives for generation to shift away from EGUs covered under mass-based plans to 

new unaffected EGUs. OBA provides an incentive for eligible EGUs in mass-based states to 

increase their generation in order to increase their allocation of allowances. This approach helps 

align the generation incentives for eligible EGUs in mass-based states with new EGUs that are 

not subject to the mass-based limits, mitigating the potential for emissions leakage. 

 

11 In the rate-based scenario in the RIA for the final Clean Power Plan Emission Guidelines, the generation-weighted 

average emission rate from affected EGUs, in which generation is inclusive of their procurement of zero-emitting 

generation or demand-side EE savings, in a state must be less than or equal to the state goal. One way for a state 

to achieve this outcome would be to assign in its plan emission rate performance standards to affected EGUs that 

equal the state emission rate goal, the incentives of which would be consistent with the analysis and results 

reported in the RIA for the final Clean Power Plan Emission Guidelines. 

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While the mass-based scenario analyzed for this proposed rule included a representation 

of the set-aside for new renewable generation, it did not quantify the effects of the OBA as 

proposed in this rulemaking. Therefore, in Section 1.5.6, the EPA conducted additional analysis 

to approximate the potential emissions reductions if the OBA set-aside were included in that 

mass-based scenario. The EPA is inviting comment on its approach to approximating the impact 

of OBA. If appropriate, the EPA will further explore OBA as a means to mitigate leakage in the 

analysis supporting the final federal plan and model trading rules. 

The EPA notes that, in this analysis, EGUs within each state comply with the applicable 

state goals without exchanging a compliance instrument with EGUs in other states. However, 

under the proposed federal plan and model trading rules if all states had a federal plan and the 

same type of goal (as they do in this analysis), then trading among EGUs in different states 

would be allowed and would lead to differences in the generation mix and emissions. The EPA is 

inviting comment on this approach to the modeling that will contribute to analysis supporting the 

final rule. 

1.5 Summary of Regulatory Analysis 

1.5.1 Emissions Reductions 

Table 1-1 shows the emission reductions associated with the modeled rate-based federal 

plan approach. 

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Table 1-1. Climate and Air Pollutant Emission Reductions for the Rate-Based Federal Plan 

Approach1

 

CO2

(million short tons) 

SO2

(thousand short tons) 

Annual NOX 

(thousand short tons) 

2020 Rate-Based Approach 

Base Case 2,155 1,311 1,333 

Federal Plan Approach 2,085 1,297 1,282 

Emissions Change -69 -14 -50 

2025 Rate-Based Approach 

Base Case 2,165 1,275 1,302 

Federal Plan Approach 1,933 1,097 1,138 

Emissions Change -232 -178 -165 

2030 Rate-Based Approach 

Base Case 2,227 1,314 1,293 

Federal Plan Approach 1,812 996 1,011 

Emission Change -415 -318 -282 

Source: Integrated Planning Model, 2015. Emissions change may not sum due to rounding. 

1 CO2 emission reductions are used to estimate the climate benefits of the proposed rule. SO2, and NOX reductions 

are relevant for estimating air quality health co-benefits of the proposed rule. The proposed rule is also expected to 

achieve reductions in directly emitted PM2.5, which we were not able to estimate for this RIA. 

In 2020, the EPA estimates that CO2 emissions will be reduced by 69 million short tons 

under the rate-based approach compared to base case levels. In 2025, the EPA estimates that CO2

emissions will be reduced by 232 million short tons under the rate-based approach compared to 

base case levels. CO2 emission reductions increase to 415 million short tons annually in 2030 

when compared to the base case emissions. Table 1-1 also shows emission reductions for criteria 

air pollutants. 

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Table 1-2 shows the emission reductions associated with the modeled mass-based federal 

plan approach. 

Table 1-2. Climate and Air Pollutant Emission Reductions for the Mass-Based Federal Plan 

Appproach1

 

CO2

(million short tons) 

SO2

(thousand short tons) 

Annual NOX 

(thousand short tons) 

2020 Mass-Based Approach 

Base Case 2,155 1,311 1,333 

Federal Plan Approach 2,073 1,257 1,272 

Emissions Change -81 -54 -60 

2025 Mass-Based Approach 

Base Case 2,165 1,275 1,302 

Federal Plan Approach 1,901 1,090 1,100 

Emissions Change -265 -185 -203 

2030 Mass-Based Approach 

Base Case 2,227 1,314 1,293 

Federal Plan Approach 1,814 1,034 1,015 

Emission Change -413 -280 -278 

Source: Integrated Planning Model, 2015. Emissions change may not sum due to rounding. 

1 CO2 emission reductions are used to estimate the climate benefits of the proposed rule. SO2, and NOX reductions 

are relevant for estimating air quality health co-benefits of the proposed rule. The proposed rule is also expected to 

achieve reductions in directly emitted PM2.5, which we were not able to estimate for this RIA. 

In 2020, the EPA estimates that CO2 emissions will be reduced by 81 million short tons under 

the mass-based approach compared to base case levels. In 2025, the EPA estimates that CO2

emissions will be reduced by 265 million short tons under the mass-based approach compared to 

base case levels. CO2 emission reductions increase to 413 million short tons annually in 2030 

when compared to the base case emissions. Table 1-2 also shows emission reductions for criteria 

air pollutants. 

 

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Table 1-3 presents CO2 emission reductions relative to 2005 for the two federal plan 

approaches. 

Table 1-3. Projected CO2 Emission Reductions, Relative to 2005 

 

CO2 Emissions 

(million short tons) 

CO2 Emissions: 

Change from 2005 

(million short tons) 

CO2 Emissions Reductions: 

Percent Change from 2005 

 2005 2020 2025 2030 2020 2025 2030 

Base Case 2,683 -528 -518 -456 -20% -19% -17% 

Rate-based - -598 -750 -871 -22% -28% -32% 

Mass-based - -610 -782 -869 -23% -29% -32% 

Source: Integrated Planning Model, 2015. 

In 2020, the EPA estimates that CO2 emissions will be reduced by 598 million short tons (22 

percent) under the rate-based approach compared to 2005 levels. In 2025, the EPA estimates that 

CO2 emissions will be reduced by 750 million short tons (28 percent) under the rate-based 

approach compared to 2005 levels. Under the rate-based approach, CO2 emission reductions 

increase to 871 million short tons (32 percent) in 2030 when compared to 2005 levels. 

Under the mass-based approach in 2020, the EPA estimates that CO2 emissions will be 

reduced by 610 million short tons (23 percent) under the rate-based approach compared to 2005 

levels. In 2025, the EPA estimates that CO2 emissions will be reduced by 782 million short tons 

(29 percent) under the mass-based approach compared to 2005 levels. Under the mass-based 

approach, CO2 emission reductions increase to 869 million short tons (32 percent) in 2030 when 

compared to 2005 levels. 

1.5.2 Costs 

 The compliance cost estimates in this analysis are the change in electric power 

generation costs between the base case and federal plan approach policy cases, including the cost 

of demand-side energy efficiency measures and costs associated with monitoring, reporting, and 

recordkeeping requirements (MR&R).12 In the rate-based approach, energy efficiency activities 

are modeled as being used by EGUs as a low-cost method of demonstrating compliance with 

their rate-based emissions standards. In the mass-based approach, energy efficiency activities are 

assumed to be adopted by states to lower demand, which in turn reduces the cost of achieving the 

 

12 See Chapter 3 of the Clean Power Plan Final Rule RIA for a detailed discussion of the compliance cost estimates. 

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mass limitations. The level of energy efficiency measures is determined outside of IPM and is 

assumed to be the same in the two federal plan approaches.13 The compliance assumptions, and 

therefore the projected “compliance costs” set forth in this analysis, are illustrative in nature. 

The annual compliance cost is the projected additional cost of complying with the rule in 

the year analyzed and reflects the net difference in the sum of the annualized cost of capital 

investment in new generating sources and heat rate improvements at coal steam facilities, the 

change in the ongoing costs of operating pollution controls, shifts between or amongst various 

fuels, demand-side energy efficiency measures, and other actions associated with compliance. 

The costs for both federal plan approaches are reflected in Table 1-4 below. All dollar estimates 

are in 2011 dollars. 

The EPA estimates the annual incremental compliance cost for the rate-based approach 

for the proposed federal plan and model trading rules to be $2.5 billion in 2020, $1.0 billion in 

2025 and $8.4 billion in 2030. The EPA estimates the annual incremental compliance cost for the 

mass-based approach for the federal plan and model trading rules to be $1.4 billion in 2020, $3.0 

billion in 2025 and $5.1 billion in 2030. 

Table 1-4. Compliance Costs for the Federal Rate-Based and Mass-Based Plan Approaches 

Incremental Cost from Base Case (billions of 2011$)

Rate-based Approach Mass-based Approach 

2020 $2.5 $1.4 

2025 $1.0 $3.0 

2030 $8.4 $5.1 

Source: Integrated Planning Model, 2015, with post-processing to account for exogenous demand-side management 

energy efficiency costs and monitoring, reporting, and recordkeeping costs. See Chapter 3 of the Clean Power Plan 

Final Rule RIA for a more complete explanation. 

The costs reported in Table 1-4 represent the estimated incremental electric utility 

generating costs changes from the base case plus the estimates of demand-side energy efficiency 

program costs (which are paid by electric utilities), demand-side energy efficiency participant 

costs (which are paid by electricity consumers), and MR&R costs. For example, in 2030, under 

the rate-based approach, the incremental electric utility generating costs decline by about $18.0 

 

13 For more detailed information on demand-side energy efficiency, see U.S. EPA. 2015b. Technical Support 

Document (TSD) the Final Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility 

Generating Units. Demand-Side Energy Efficiency. 

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billion from the base case. MR&R requirements in 2030 are estimated at $16.0 million, and 

demand-side energy efficiency costs in 2030 are estimated to be $26.3 billion, split equally 

between program and participants using a 3 percent discount rate (see Chapter 3 of this RIA for 

more details on these estimates). These cost estimates sum to the $8.4 billion shown in Table 1-4 

and represent the total costs of the rate-based federal plan approach in 2030. The same approach 

applies in each year of analysis for the rate-based and the mass-based federal plan approaches. 

The compliance costs reported in Table 1-4 are not social costs. These costs represent the 

estimated expenditures incurred by EGUs, the costs to participants in demand-side energy 

efficiency programs, and states to comply with the BSER goals for the Final Clean Power Plan 

Emission Guidelines. These compliance cost estimates are compared to estimates of social 

benefits to derive net benefits of the proposed federal plan and model trading rules, which are 

presented later in this Chapter. 

1.5.3 Monetized Climate Benefits and Health Co-benefits 

The climate benefits estimates have been calculated using the estimated values of 

marginal climate impacts presented in the Technical Support Document: Technical Update of the 

Social Cost of Carbon for Regulatory Impact Analysis under Executive Order 12866 (May 2013, 

Revised July 2015), henceforth denoted as the current SC-CO2 TSD.14 Additionally, this analysis 

takes into account the social benefits of changes in emissions of non-CO2 pollutants from the 

electricity sector. The range of combined benefits reflects different concentration-response 

functions for the air quality health co-benefits, but it does not capture the full range of 

uncertainty inherent in the health co-benefits estimates. Furthermore, we were unable to quantify 

or monetize all of the climate benefits and health and environmental co-benefits associated with 

the proposed federal plan and model trading rules, including reductions in directly emitted PM2.5, 

reduced exposure to SO2, NOX, and hazardous air pollutants (e.g., mercury), as well as 

ecosystem effects and visibility improvement. The omission of these endpoints from the 

 

14 Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon, with participation by 

Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture, Department of 

Commerce, Department of Energy, Department of Transportation, Domestic Policy Council, Environmental 

Protection Agency, National Economic Council, Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (May 2013, Revised July 2015). Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf> Accessed 7/11/2015. 

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monetized results should not imply that the impacts are small or unimportant. Table 1-5 provides 

the list of the quantified and unquantified health and environmental benefits in this analysis. 

Table 1-5. Quantified and Unquantified Benefits 

Benefits Category Specific Effect 

Effect Has 

Been 

Quantified

Effect Has 

Been 

Monetized

More Information 

Improved 

Environment 

Reduced climate 

effects 

Global climate impacts from CO2 —1  SC-CO2 TSD 

Climate impacts from ozone and black carbon (directly 

emitted PM) — — 

Ozone ISA, PM 

ISA2

Other climate impacts (e.g., other GHGs such as methane, 

aerosols, other impacts) — — IPCC2

Improved Human Health (co-benefits) 

Reduced incidence of 

premature mortality 

from exposure to 

PM2.5

Adult premature mortality based on cohort study estimates

and expert elicitation estimates (age >25 or age >30)   PM ISA 

Infant mortality (age <1)   PM ISA 

Reduced incidence of 

morbidity from 

exposure to PM2.5

Non-fatal heart attacks (age > 18)   PM ISA 

Hospital admissions—respiratory (all ages)   PM ISA 

Hospital admissions—cardiovascular (age >20)   PM ISA 

Emergency room visits for asthma (all ages)   PM ISA 

Acute bronchitis (age 8-12)   PM ISA 

Lower respiratory symptoms (age 7-14)   PM ISA 

Upper respiratory symptoms (asthmatics age 9-11)   PM ISA 

Asthma exacerbation (asthmatics age 6-18)   PM ISA 

Lost work days (age 18-65)   PM ISA 

Minor restricted-activity days (age 18-65)   PM ISA 

Chronic Bronchitis (age >26) — — PM ISA2

Emergency room visits for cardiovascular effects (all ages) — — PM ISA2

Strokes and cerebrovascular disease (age 50-79) — — PM ISA2

Other cardiovascular effects (e.g., other ages) — — PM ISA3

Other respiratory effects (e.g., pulmonary function, nonasthma ER visits, non-bronchitis chronic diseases, other 

ages and populations) 

— — PM ISA3

Reproductive and developmental effects (e.g., low birth 

weight, pre-term births, etc) — — PM ISA3,4

Cancer, mutagenicity, and genotoxicity effects — — PM ISA3,4

Reduced incidence of 

mortality from 

exposure to ozone 

Premature mortality based on short-term study estimates (all 

ages)   Ozone ISA 

Premature mortality based on long-term study estimates 

(age 30–99) — — Ozone ISA2

Reduced incidence of 

morbidity from 

exposure to ozone 

Hospital admissions—respiratory causes (age > 65)   Ozone ISA 

Hospital admissions—respiratory causes (age <2)   Ozone ISA 

Emergency department visits for asthma (all ages)   Ozone ISA 

Minor restricted-activity days (age 18–65)   Ozone ISA 

School absence days (age 5–17)   Ozone ISA 

Decreased outdoor worker productivity (age 18–65) — — Ozone ISA2

Other respiratory effects (e.g., premature aging of lungs) — — Ozone ISA3

Cardiovascular and nervous system effects — — Ozone ISA3

Reproductive and developmental effects — — Ozone ISA3,4

 

 

 

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Table 1-5. Continued 

Reduced incidence of 

morbidity from 

exposure to NO2

Asthma hospital admissions (all ages) — — NO2 ISA2

Chronic lung disease hospital admissions (age > 65) — — NO2 ISA2

Respiratory emergency department visits (all ages) — — NO2 ISA2

Asthma exacerbation (asthmatics age 4–18) — — NO2 ISA2

Acute respiratory symptoms (age 7–14) — — NO2 ISA2

Premature mortality — — NO2 ISA2,3,4

Other respiratory effects (e.g., airway hyperresponsiveness 

and inflammation, lung function, other ages and 

populations) 

— — NO2 ISA3,4

Reduced incidence of 

morbidity from 

exposure to SO2

Respiratory hospital admissions (age > 65) — — SO2 ISA2

Asthma emergency department visits (all ages) — — SO2 ISA2

Asthma exacerbation (asthmatics age 4–12) — — SO2 ISA2

Acute respiratory symptoms (age 7–14) — — SO2 ISA2

Premature mortality — — SO2 ISA2,3,4

Other respiratory effects (e.g., airway hyperresponsiveness 

and inflammation, lung function, other ages and 

populations) 

— — SO2 ISA2,3

Reduced incidence of 

morbidity from 

exposure to 

methylmercury 

Neurologic effects—IQ loss — — IRIS; NRC, 20002

Other neurologic effects (e.g., developmental delays, 

memory, behavior) — — IRIS; NRC, 20003

Cardiovascular effects — — IRIS; NRC, 20003,4

Genotoxic, immunologic, and other toxic effects — — IRIS; NRC, 20003,4

Improved Environment (co-benefits) 

Reduced visibility 

impairment 

Visibility in Class 1 areas — — PM ISA2

Visibility in residential areas — — PM ISA2

Reduced effects on 

materials 

Household soiling — — PM ISA2,3

Materials damage (e.g., corrosion, increased wear) — — PM ISA3

Reduced PM 

deposition (metals and 

organics) 

Effects on individual organisms and ecosystems — — PM ISA3

Reduced vegetation 

and ecosystem effects 

from exposure to 

ozone 

Visible foliar injury on vegetation — — Ozone ISA2

Reduced vegetation growth and reproduction — — Ozone ISA2

Yield and quality of commercial forest products and crops — — Ozone ISA2

Damage to urban ornamental plants — — Ozone ISA3

Carbon sequestration in terrestrial ecosystems — — Ozone ISA2

Recreational demand associated with forest aesthetics — — Ozone ISA3

Other non-use effects Ozone ISA3

Ecosystem functions (e.g., water cycling, biogeochemical 

cycles, net primary productivity, leaf-gas exchange, 

community composition) 

— — Ozone ISA3

Reduced effects from 

acid deposition 

Recreational fishing — — NOx SOx ISA2

Tree mortality and decline — — NOx SOx ISA3

Commercial fishing and forestry effects — — NOx SOx ISA3

Recreational demand in terrestrial and aquatic ecosystems — — NOx SOx ISA3

Other non-use effects NOx SOx ISA3

Ecosystem functions (e.g., biogeochemical cycles) — — NOx SOx ISA3

 

 

 

 

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Table 1-5. Continued 

Reduced effects from 

nutrient enrichment 

Species composition and biodiversity in terrestrial and 

estuarine ecosystems — — NOx SOx ISA3

Coastal eutrophication — — NOx SOx ISA3

Recreational demand in terrestrial and estuarine ecosystems — — NOx SOx ISA3

Other non-use effects NOx SOx ISA3

Ecosystem functions (e.g., biogeochemical cycles, fire 

regulation) — — NOx SOx ISA3

Reduced vegetation 

effects from exposure 

to SO2 and NOx

Injury to vegetation from SO2 exposure — — NOx SOx ISA3

Injury to vegetation from NOx exposure — — NOx SOx ISA3

Reduced ecosystem 

effects from exposure 

to methylmercury 

Effects on fish, birds, and mammals (e.g., reproductive 

effects) — — 

Mercury Study 

RTC3

Commercial, subsistence and recreational fishing — —

Mercury Study 

RTC2

1

 The global climate and related impacts of CO2 emissions changes, such as sea level rise, are estimated within each 

integrated assessment model as part of the calculation of the SC-CO2. The resulting monetized damages, which 

are relevant for conducting the benefit-cost analysis, are used in this RIA to estimate the welfare effects of 

quantified changes in CO2 emissions. 

2

 We assess these co-benefits qualitatively, as reported in the Chapter 4 of the Clean Power Plan Final Rule RIA, 

due to data and resource limitations for this analysis. 

3

 We assess these co-benefits qualitatively, as reported in the Chapter 4 of the Clean Power Plan Final Rule RIA, 

because we do not have sufficient confidence in available data or methods. 

4

 We assess these co-benefits qualitatively, as reported in the Chapter 4 of the Clean Power Plan Final Rule RIA, 

because current evidence is only suggestive of causality or there are other significant concerns over the strength of 

the association. 

1.5.3.1 Estimating Global Climate Benefits 

We estimate the global social benefits of CO2 emission reductions expected from this 

rulemaking using the SC-CO2 estimates presented in the current SC-CO2 TSD.15 We refer to 

these estimates, which were developed by the U.S. government, as “SC-CO2 estimates” for the 

remainder of this document. The SC-CO2 is a metric that estimates the monetary value of 

impacts associated with marginal changes in CO2 emissions in a given year. It includes a wide 

range of anticipated climate impacts, such as net changes in agricultural productivity and human 

health, property damage from increased flood risk, and changes in energy system costs, such as 

reduced costs for heating and increased costs for air conditioning. It is typically used to assess 

 

15 Also see Chapter 4 of the Clean Power Plan Final Rule RIA for more details on this assessment of climate 

benefits. 

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the avoided damages as a result of regulatory actions (i.e., benefits of rulemakings that lead to an 

incremental reduction in cumulative global CO2 emissions). 

The SC-CO2 estimates used in this analysis have been developed over many years, using 

the best science available, and with input from the public. The EPA and other federal agencies 

have considered the extensive public comments on ways to improve SC-CO2 estimation received 

via the notice and comment period that was part of numerous rulemakings. In addition, OMB’s 

Office of Information and Regulatory Affairs recently issued a response to the public comments 

it sought through a separate comment period on the approach used to develop the SC-CO2

estimates.16

An interagency working group (IWG) that included the EPA and other executive branch 

entities used three integrated assessment models (IAMs) to develop SC-CO2 estimates and 

recommended four global values for use in regulatory analyses. The SC-CO2 estimates represent 

global measures because of the distinctive nature of the climate change problem. Emissions of 

greenhouse gases contribute to damages around the world, even when they are released in the 

United States, and the world’s economies are now highly interconnected. Therefore, the SC-CO2 

estimates incorporate the worldwide damages caused by carbon dioxide emissions in order to 

reflect the global nature of the problem, and we expect other governments to consider the global 

consequences of their greenhouse gas emissions when setting their own domestic policies. See 

Chapter 4 of the final Clean Power Plan Emission Guidelines RIA for more discussion. 

The IWG first released the estimates in February 2010 and updated them in 2013 using 

new versions of each IAM. The SC-CO2 values was estimated using three integrated assessment 

models (DICE, FUND, and PAGE)17, which the IWG harmonized across three key inputs: the 

probability distribution for equilibrium climate sensitivity; five scenarios for economic, 

population, and emissions growth; and three constant discount rates. The 2010 SC-CO2

Technical Support Document (2010 SC-CO2 TSD) provides a complete discussion of the 

methodology and the current SC-CO2 TSD18 presents and discusses the updated estimates. The 

 

16 See https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-comments-final-july-2015.pdf 

17 The full models names are as follows: Dynamic Integrated Climate and Economy (DICE); Climate Framework for 

Uncertainty, Negotiation, and Distribution (FUND); and Policy Analysis of the Greenhouse Gas Effect (PAGE). 

18 The IWG published the updated TSD in 2013, then issued two minor corrections to it in July 2015. 

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four SC-CO2 estimates are as follows: $12, $40, $60, and $120 per short ton of CO2 emissions in 

the year 2020 (2011$), and each estimate increases over time.19 These SC-CO2 estimates are 

associated with different discount rates. The first three estimates are the model average at 5 

percent discount rate, 3 percent, and 2.5 percent, respectively, and the fourth estimate is the 95th

percentile at 3 percent. 

 The 2010 SC-CO2 TSD noted a number of limitations to the SC-CO2 analysis, including 

the incomplete way in which the IAMs capture catastrophic and non-catastrophic impacts, their 

incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of 

damages to high temperatures, and assumptions regarding risk aversion. Currently integrated 

assessment models do not assign value to all of the important physical, ecological, and economic 

impacts of climate change recognized in the climate change literature because of a lack of 

precise information on the nature of damages and because the science incorporated into these 

models understandably lags behind the most recent research.20 In particular, the IPCC Fourth 

Assessment Report concluded that “It is very likely that [SC-CO2 estimates] underestimate the 

damage costs because they cannot include many non-quantifiable impacts.” Nonetheless, these 

estimates and the discussion of their limitations represent the best available information about 

the social benefits of CO2 emission reductions to inform the benefit-cost analysis. 

In addition, after careful evaluation of the full range of comments submitted to OMB’s 

Office of Information and Regulatory Affairs, the IWG continues to recommend the use of these 

SC-CO2 estimates in regulatory impact analysis. With the release of the response to comments, 

the IWG announced plans to obtain expert independent advice from the National Academies of 

Sciences, Engineering, and Medicine (Academies) to ensure that the SC-CO2 estimates continue 

to reflect the best available scientific and economic information on climate change.21 The 

 

19 The 2010 and 2013 TSDs present SC-CO2 in 2007$ per metric ton. The unrounded estimates from the current 

TSD were adjusted to (1) 2011$ using GDP Implicit Price Deflator (1.061374), 

http://www.bea.gov/iTable/index_nipa.cfm and (2) short tons using the conversion factor of 0.90718474 metric 

tons in a short ton. These estimates were rounded to two significant digits. 

20 Climate change impacts and SCC modeling is an area of active research. For example, see: (1) Howard, Peter, 

“Omitted Damages: What’s Missing from the Social Cost of Carbon.” March 13, 2014, 

http://costofcarbon.org/files/Omitted_Damages_Whats_Missing_From_the_Social_Cost_of_Carbon.pdf; and (2) 

Electric Power Research Institute, “Understanding the Social Cost of Carbon: A Technical Assessment,” October 

2014, www.epri.com. 

21 See <https://www.whitehouse.gov/blog/2015/07/02/estimating-benefits-carbon-dioxide-emissions-reductions>. 

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Academies’ process will be informed by the public comments received and focus on the 

technical merits and challenges of potential approaches to improving the SC-CO2 estimates in 

future updates. 

1.5.3.2 Estimating Air Quality Health Co-Benefits 

The proposed federal plan and model trading rules would reduce emissions of precursor 

pollutants (e.g., SO2, NOX, and directly emitted particles), which in turn would lower ambient 

concentrations of PM2.5 and ozone. This co-benefits analysis quantifies the monetized benefits 

associated with the reduced exposure to these two pollutants.22 Unlike the global SC-CO2

estimates, the air quality health co-benefits are only estimated for the contiguous U.S. The 

estimates of monetized PM2.5 co-benefits include avoided premature deaths (derived from effect 

coefficients in two cohort studies [Krewski et al. 2009 and Lepeule et al. 2012] for adults and 

one for infants [Woodruff et al. 1997]), as well as avoided morbidity effects for ten non-fatal 

endpoints ranging in severity from lower respiratory symptoms to heart attacks23 (U.S. EPA, 

2012). The estimates of monetized ozone co-benefits include avoided premature deaths (derived 

from the range of effect coefficients represented by two short-term epidemiology studies [Bell et 

al. (2004) and Levy et al. (2005)]), as well as avoided morbidity effects for five non-fatal 

endpoints ranging in severity from school absence days to hospital admissions (U.S. EPA, 2008, 

2011). 

We use a “benefit-per-ton” approach to estimate the PM2.5 and ozone co-benefits in this 

RIA. Benefit-per-ton approaches apply an average benefit per ton derived from modeling of 

benefits of specific air quality scenarios to estimates of emissions reductions for scenarios where 

no air quality modeling is available. The benefit-per-ton approach we use in this RIA relies on 

estimates of human health responses to exposure to PM and ozone obtained from the peerreviewed scientific literature. These estimates are used in conjunction with population data, 

 

22 We did not estimate the co-benefits associated with reducing direct exposure to SO2 and NOX. For this RIA, we 

did not estimate changes in emissions of directly emitted particles. As a result, quantified PM2.5 related benefits 

are underestimated by a relatively small amount. In the proposal RIA, the benefits from reductions in directly 

emitted PM2.5 were less than 10 percent of total monetized health co-benefits across all scenarios and years. 

23 See Chapter 4 and Appendix 4A of the Clean Power Plan Final Rule for details on this assessment of health cobenefits. 

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baseline health information, air quality data and economic valuation information to conduct 

health impact and economic benefits assessments. 

Specifically, in this analysis, we multiplied the benefit-per-ton estimates by the 

corresponding emission reductions that were generated from air quality modeling of the 

proposed Clean Power Plan Emission Guidelines. Similar to the co-benefits analysis conducted 

for the final Clean Power Plan Emission Guidelines RIA, we generated regional benefit-per-ton 

estimates by aggregating the impacts in BenMAP24 to the region (i.e., East, West, and California) 

rather than aggregating to the nation. The benefit-per-ton for SO2 and NOx emissions used in this 

proposed rule were calculated using air quality modeling of the base case and the proposed Clean 

Power Plan (Option 1 State) scenario for 2025 as described in Appendix 4A of the final Clean 

Power Plan Emission Guidelines RIA. The benefit-per-ton values for 2020 and 2030 are based 

on applying the air quality modeling from 2025 to population and health information from 2020 

and 2030. 

To calculate the co-benefits for this proposed rule, we then multiplied the regional 

benefit-per-ton estimates for the EGU sector by the corresponding emission reductions. All 

benefit-per-ton estimates reflect the geographic distribution of the modeled emissions, which 

may not exactly match the emission reductions in this rulemaking, and thus they may not reflect 

the local variability in population density, meteorology, exposure, baseline health incidence 

rates, or other local factors for any specific location. 

Our estimate of the monetized co-benefits is based on the EPA’s interpretation of the best 

available scientific literature (U.S. EPA, 2009) and methods and supported by the EPA’s Science 

Advisory Board and the NAS (NRC, 2002). Below are key assumptions underlying the estimates 

for PM2.5-related premature mortality, which accounts for 98 percent of the monetized PM2.5

health co-benefits. 

1. We assume that all fine particles, regardless of their chemical composition, are 

equally potent in causing premature mortality. This is an important assumption, 

 

24 BenMAP is a computer program developed by the EPA that calculates the number and economic value of air 

pollution-related deaths and illnesses. The software incorporates a database that includes many of the 

concentration-response relationships, population files, and health and economic data needed to quantify these 

impacts. 

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because PM2.5 varies considerably in composition across sources, but the scientific 

evidence is not yet sufficient to allow differentiation of effect estimates by particle 

type. The PM ISA concluded that “many constituents of PM2.5 can be linked with 

multiple health effects, and the evidence is not yet sufficient to allow differentiation 

of those constituents or sources that are more closely related to specific outcomes” 

(U.S. EPA, 2009b). 

2. We assume that the health impact function for fine particles is log-linear without a 

threshold in this analysis. Thus, the estimates include health co-benefits from 

reducing fine particles in areas with varied concentrations of PM2.5, including both 

areas that do not meet the National Ambient Air Quality Standard for fine particles 

and those areas that are in attainment, down to the lowest modeled concentrations. 

3. We assume that there is a “cessation” lag between the change in PM exposures and 

the total realization of changes in mortality effects. Specifically, we assume that some 

of the incidences of premature mortality related to PM2.5 exposures occur in a 

distributed fashion over the 20 years following exposure based on the advice of the 

SAB-H1 (U.S. EPA-SAB, 2004c), which affects the valuation of mortality cobenefits at different discount rates. 

Every benefits analysis examining the potential effects of a change in environmental 

protection requirements is limited, to some extent, by data gaps, model capabilities (such as 

geographic coverage) and uncertainties in the underlying scientific and economic studies used to 

configure the benefit and cost models. Despite these uncertainties, we believe this analysis 

provides a reasonable indication of the expected health co-benefits of the air quality emission 

reductions for the proposed rule under a set of reasonable assumptions. This analysis does not 

include the type of detailed uncertainty assessment found in the 2012 PM2.5 National Ambient 

Air Quality Standard (NAAQS) RIA (U.S. EPA, 2012) because we lack the necessary air quality 

input and monitoring data to conduct a complete benefits assessment. In addition, using a 

benefit-per-ton approach adds another important source of uncertainty to the benefits estimates. 

1.5.3.3 Combined Benefits Estimates 

The EPA has evaluated the range of potential impacts by combining all four SC-CO2

values with health co-benefits values at the 3 percent and 7 percent discount rates. Different 

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discount rates are applied to SC-CO2 than to the health co-benefit estimates because CO2

emissions are long-lived and subsequent damages occur over many years. Moreover, several 

discount rates are applied to SC-CO2 because the literature shows that the estimate of SC-CO2 is 

sensitive to assumptions about discount rate and because no consensus exists on the appropriate 

rate to use in an intergenerational context. The IWG centered its attention on the average SCCO2 at a 3 percent discount rate but emphasized the importance of considering all four SC-CO2

estimates. Table 1-6 (rate-based federal plan approach) and Table 1-7 (mass-based federal plan 

approach) provide the combined climate benefits and health co-benefits for the proposed federal 

plan model trading rules estimated for 2020, 2025, and 2030 for each discount rate combination. 

All dollar estimates are in 2011 dollars. 

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Table 1-6. Combined Estimates of Climate Benefits and Health Co-Benefits for Rate-Based 

Approach (billions of 2011$)* 

SC-CO2 Discount Rate and Statistic** 

Climate 

Benefits 

Only 

Climate Benefits plus Health Co-benefits 

(Discount Rate Applied to Health Co-benefits) 

3% 7% 

In 2020 69 million short tons CO2 

5% $0.80 $1.5 to $2.6 $1.4 to $2.5 

3% $2.8 $3.5 to $4.6 $3.5 to $4.5 

2.5% $4.1 $4.9 to $6.0 $4.8 to $5.9 

3% (95th percentile) $8.2 $8.9 to $10 $8.9 to $9.9 

In 2025 232 million short tons CO2 

5% $3.1 $11 to $21 $9.9 to $19 

3% $10 $18 to $28 $17 to $26 

2.5% $15 $23 to $33 $22 to $31 

3% (95th percentile) $31 $38 to $49 $38 to $47 

In 2030 415 million short tons CO2 

5% $6.4 $21 to $40 $19 to $37 

3% $20 $34 to $54 $33 to $51 

2.5% $29 $43 to $63 $42 to $60 

3% (95th percentile) $61 $75 to $95 $74 to $92 

*All benefit estimates are rounded to two significant figures. Climate benefits are based on reductions in CO2

emissions. Co-benefits are based on regional benefit-per-ton estimates. Ozone co-benefits occur in analysis year, so 

they are the same for all discount rates. The health co-benefits reflect the sum of the PM2.5 and ozone co-benefits 

and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Bell et al. (2004) to 

Lepeule et al. (2012) with Levy et al. (2005)). The monetized health co-benefits do not include reduced health 

effects from reductions in directly emitted PM2.5, direct exposure to NOX, SO2, and HAP; ecosystem effects; or 

visibility impairment. See Chapter 4 of the Clean Power Plan Final Rule RIA for more information about these 

estimates and for more information regarding the uncertainty in these estimates. 

**Unless otherwise specified, the row reflects the average SC-CO2 estimate for the specified discount rate. 

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Table 1-7. Combined Estimates of Climate Benefits and Health Co-benefits for Mass-Based 

Approach (billions of 2011$)* 

SC-CO2 Discount Rate and Statistic** 

Climate 

Benefits 

Only 

Climate Benefits plus Health Co-benefits 

(Discount Rate Applied to Health Co-benefits) 

3% 7% 

In 2020 82 million short tons CO2 

5% $0.94 $2.9 to $5.7 $2.8 to $5.3 

3% $3.3 $5.3 to $8.1 $5.1 to $7.7 

2.5% $4.9 $6.9 to $9.7 $6.7 to $9.3 

3% (95th percentile) $9.7 $12 to $14 $11 to $14 

In 2025 264 million short tons CO2 

5% $3.6 $11 to $21 $10 to $19 

3% $12 $19 to $29 $18 to $27 

2.5% $17 $24 to $35 $24 to $33 

3% (95th percentile) $35 $42 to $52 $42 to $51 

In 2030 413 million short tons CO2 

5% $6.4 $18 to $34 $17 to $32 

3% $20 $32 to $48 $31 to $46 

2.5% $29 $41 to $57 $40 to $55 

3% (95th percentile) $60 $72 to $89 $71 to $86 

*All benefit estimates are rounded to two significant figures. Climate benefits are based on reductions in CO2

emissions. Co-benefits are based on regional benefit-per-ton estimates. Ozone co-benefits occur in analysis year, so 

they are the same for all discount rates. The health co-benefits reflect the sum of the PM2.5 and ozone co-benefits 

and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Bell et al. (2004) to 

Lepeule et al. (2012) with Levy et al. (2005)). The monetized health co-benefits do not include reduced health 

effects from reductions in directly emitted PM2.5, direct exposure to NOX, SO2, and HAP; ecosystem effects; or 

visibility impairment. See Chapter 4 of the Clean Power Plan Final Rule RIA for more information about these 

estimates and for more information regarding the uncertainty in these estimates. 

**Unless otherwise specified, the row reflects the average SC-CO2 estimate for the specified discount rate. 

1.5.4 Net Benefits 

Table 1-8 and 1-9 provide the estimates of the climate benefits, health co-benefits, 

compliance costs and net benefits of the proposed federal plan and model trading rules for ratebased and mass-based approaches, respectively. There are additional important benefits that the 

EPA could not monetize. Due to current data and modeling limitations, our estimates of the 

benefits from reducing CO2 emissions do not include important impacts like ocean acidification 

or potential tipping points in natural or managed ecosystems. Unquantified benefits also include 

climate benefits from reducing emissions of non-CO2 greenhouse gases and co-benefits from 

reducing exposure to SO2, NOX, and hazardous air pollutants (e.g., mercury), as well as 

ecosystem effects and visibility impairment. Upon considering these limitations and 

uncertainties, it remains clear that the benefits of this proposed rule are substantial and far 

outweigh the costs. 

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Table 1-8. Monetized Benefits, Compliance Costs, and Net Benefits Under the Rate-based 

Federal Plan Approach (billions of 2011$) a 

 Rate-Based Approach 

2020 2025 2030

Climate Benefits b

5% discount rate $0.80 $3.1 $6.4 

3% discount rate $2.8 $10 $20 

2.5% discount rate $4.1 $15 $29 

95th percentile at 3% 

discount rate $8.2 $31 $61 

Air Quality Co-benefits Discount Rate 

3% 7% 3% 7% 3% 7%

Air Quality Health 

Co-benefits c $0.70 to $1.8 $0.64 to $1.7 $7.4 to $18 $6.7 to $16 $14 to $34 $13 to $31 

Compliance Costs d

$2.5 $1.0 $8.4 

Net Benefits e

$1.0 to $2.1 $1.0 to $2.0 $17 to $27 $16 to $25 $26 to $45 $25 to $43 

Non-Monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and mercury 

Visibility impairment 

a

 All are rounded to two significant figures, so figures may not sum. 

b

 The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does 

not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SC-CO2 than to the 

other estimates because CO2 emissions are long-lived and subsequent damages occur over many years. The net 

benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount rate, however we 

emphasize the importance and value of considering the full range of SC-CO2 values. As shown in this table, climate 

benefits are also estimated using the other three SC-CO2 estimates (model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2 estimates are year-specific and increase over time. 

c The air quality health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions 

of SO2 and NOX. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These 

additional benefits would increase overall benefits by a few percent based on the analyses conducted for the 

proposed rule. The range reflects the use of concentration-response functions from different epidemiology studies. 

The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. Estimates in the table are presented for three analytical years with air quality cobenefits calculated using two discount rates. The estimates of co-benefits are annual estimates in each of the 

analytical years, reflecting discounting of mortality benefits over the cessation lag between changes in PM2.5

concentrations and changes in risks of premature death (see Chapter 4 of the Clean Power Plan Final Rule RIA for 

more details), and discounting of morbidity benefits due to the multiple years of costs associated with some 

illnesses. The estimates are not the present value of the benefits of the rule over the full compliance period. 

d Compliance costs are the compliance costs estimated using the Integrated Planning Model and a discount rate of 

approximately 5 percent. It also includes monitoring, recordkeeping, and reporting costs and demand-side energy 

efficiency program and participant costs. 

e

 The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount 

rate (model average). The Clean Power Plan Final Rule RIA includes combined climate and health estimates based 

on additional discount rates. 

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Table 1-9. Monetized Benefits, Compliance Costs, and Net Benefits under the Mass-based 

Federal Plan Approach (billions of 2011$) a 

 Mass-Based Approach 

2020 2025 2030

Climate Benefits b

5% discount rate $0.94 $3.6 $6.4 

3% discount rate $3.3 $12 $20 

2.5% discount rate $4.9 $17 $29 

95th percentile at 3% 

discount rate $9.7 $35 $60 

Air Quality Co-benefits Discount Rate 

3% 7% 3% 7% 3% 7%

Air Quality Health 

Co-benefits c $2.0 to $4.8 $1.8 to $4.4 $7.1 to $17 $6.5 to $16 $12 to $28 $11 to $26 

Compliance Costs d

$1.4 $3.0 $5.1 

Net Benefits e

$3.9 to $6.7 $3.7 to $6.3 $16 to $26 $15 to $24 $26 to $43 $25 to $40 

Non-Monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and 

mercury 

Visibility improvement 

a

 All are rounded to two significant figures, so figures may not sum. 

b

 The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does 

not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SC-CO2 than to the 

other estimates because CO2 emissions are long-lived and subsequent damages occur over many years. The net 

benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount rate, however we 

emphasize the importance and value of considering the full range of SC-CO2 values. As shown in this table, climate 

benefits are also estimated using the other three SC-CO2 estimates (model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2 estimates are year-specific and increase over time. 

c The air quality health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions 

of SO2 and NOX. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These 

additional benefits would increase overall benefits by a few percent based on the analyses conducted for the 

proposed rule. The range reflects the use of concentration-response functions from different epidemiology studies. 

The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. Estimates in the table are presented for three analytical years with air quality cobenefits calculated using two discount rates. The estimates of co-benefits are annual estimates in each of the 

analytical years, reflecting discounting of mortality benefits over the cessation lag between changes in PM2.5

concentrations and changes in risks of premature death (see Chapter 4 of the Clean Power Plan Final Rule RIA for 

more details), and discounting of morbidity benefits due to the multiple years of costs associated with some 

illnesses. The estimates are not the present value of the benefits of the rule over the full compliance period. 

d Compliance costs are the compliance costs estimated using the Integrated Planning Model and a discount rate of 

approximately 5 percent. It also includes monitoring, recordkeeping, and reporting costs and demand-side energy 

efficiency program and participant costs. 

e

 The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount 

rate (model average). The Clean Power Plan Final Rule RIA includes combined climate and health estimates based 

on additional discount rates. 

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1.5.5 Economic Impacts 

The federal plan approaches analyzed in this RIA indicate that the proposed federal plan 

and model trading rules may have important energy market implications. Table 1-10 presents a 

variety of important energy market impacts for 2020, 2025, and 2030 for both the rate-based and 

mass-based federal plan approaches. 

Table 1-10. Summary Table of Important Energy Market Impacts (Percent Change from 

Base Case) 

 Rate-Based Mass-Based 

 2020 2025 2030 2020 2025 2030 

Retail electricity prices 3% 1% 1% 3% 2% 0% 

Average electricity bills 3% -4% -7% 2% -3% -8% 

Price of coal at minemouth -1% -5% -4% -1% -5% -3% 

Coal production for power sector use -5% -14% -25% -7% -17% -24% 

Price of natural gas delivered to power sector 5% -8% 2% 4% -3% -2% 

Natural gas use for electricity generation 3% -1% -1% 5% 0% -4% 

Energy market impacts are discussed more extensively in Chapter 3 of the final Clean Power 

Plan Emission Guidelines RIA. As well as the above energy market impacts, Chapter 3 of the 

final Clean Power Plan Emission Guidelines RIA presents projections of power sector generation 

and capacity changes by fuel type. 

Additionally, changes in supply or demand for electricity, natural gas, and coal can 

impact markets for goods and services produced by sectors that use these energy inputs in the 

production process or that supply those sectors. Changes in cost of production may result in 

changes in price and/or quantity produced by these sectors and these market changes may affect 

the profitability of firms and the economic welfare of their consumers. Similarly, demand for 

new generation or energy efficiency, for example, can result in changes in production and 

profitability for firms that supply those goods and services. The EPA recognizes that states 

subject to the federal plan may choose to mitigate impacts to some markets outside the EGU 

sector, perhaps by implementing the guidelines through a state plan. 

1.5.6 Employment Impacts 

Executive Order 13563 directs federal agencies to consider the effect of regulations on 

job creation and employment. According to the Executive Order, “our regulatory system must 

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protect public health, welfare, safety, and our environment while promoting economic growth, 

innovation, competitiveness, and job creation. It must be based on the best available science” 

(Executive Order 13563, 2011). Although standard benefit-cost analyses have not typically 

included a separate analysis of regulation-induced employment impacts, we typically conduct 

employment analyses.25 While the economy continues moving toward full-employment, 

employment impacts are of particular concern and questions may arise about their existence and 

magnitude. 

Given the wide range of approaches that may be used to meet the requirements of the 

proposed federal plan and model trading rules, quantifying the associated employment impacts is 

difficult. The EPA’s illustrative employment analysis includes an estimate of projected 

employment impacts for the utility power sector, coal and natural gas production, and demandside energy efficiency activities. These projections are derived, in part, from the detailed model 

of the utility power sector used for this regulatory analysis, and U.S government data on 

employment and labor productivity. 

In the electricity, coal, and natural gas sectors, the EPA uses the IPM estimates of the 

changes in generation and fuel use of the proposed rule to estimate there could be a net decrease 

of approximately 25,000 job-years26 in 2025 for the proposed rule under the rate-based federal 

plan approach and approximately 26,000 job-years in 2025 under the mass-based approach. For 

2030 the estimates of the net decrease in job-years is 30,900 under the rate-based plan, and 

33,700 under the mass-based plan. The Agency is also offering an illustrative calculation of 

potential employment effects due to demand-side energy efficiency programs. Employment 

impacts from demand-side energy efficiency programs in 2030 could range from approximately 

52,000 to 83,000 jobs created under proposed federal plan and model trading rules. The IPMderived job-year numbers for the electricity, coal and natural gas sectors should not be added to 

the demand-side efficiency job impacts, since the former are reported in full-time equivalent jobyears, whereas the latter do not distinguish between full- and part-time employment. More detail 

 

25 The employment analysis in this RIA is part of EPA’s ongoing effort to “conduct continuing evaluations of 

potential loss or shifts of employment which may result from the administration or enforcement of [the Act]” 

pursuant to CAA section 321(a). 

26 Job-years are not individual jobs, but rather the amount of work performed by the equivalent of one full-time 

individual for one year. For example, 20 job-years in 2020 may represent 20 full-time jobs or 40 half-time jobs in 

that year. 

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about these analyses can be found in Chapter 6 of the final Clean Power Plan Emission 

Guidelines RIA. 

1.5.7 Additional Analysis of Output-Based Allocation as a Means of Mitigating Leakage 

The application of OBA will provide an incentive to increase generation at existing 

NGCC EGUs in place of generation at new NGCC EGUs and existing fossil steam EGUs. To 

approximate the effect of this incentive in the mass-based scenario, the EPA used IPM model 

plant results from the mass-based scenario to construct the average dispatch order for model 

plants in each IPM region. Then, based on the allowance prices for the state in which each model 

plant resides, the EPA adjusted the dispatch order in the case where existing NGCC units were 

allocated allowances at a rate of 1,030 lbs/MWh for each MWh generated above a 50 percent 

capacity factor as proposed. In cases where an existing NGCC plant moved ahead of an existing 

fossil steam plant in the dispatch order, the NGCC plant’s generation was increased while the 

existing fossil plant’s generation was reduced. The NGCC plant’s generation was increased to 

the maximum capacity factor assumed feasible within IPM while the amount of reduced 

generation at the fossil steam plant is determined by the amount that would keep the overall 

covered sources’ emissions in the region constant, so as to respect compliance with the massbased standards represented in the modeling scenario. Since the existing NGCC plant has a lower 

emissions rate than the existing fossil steam plant, the increase in generation at the NGCC plant 

is greater than the reduction in generation (because more generation is now possible from both 

plants together at the same given level of emissions). This net increase in generation from 

existing EGUs is then subtracted from new NGCC generation in the region, consistent with the 

total generation needed to meet the load assumed in the IPM modeling of the mass-based 

scenario. 

When applying this algorithm to the results from the mass-based scenario analyzed in this 

RIA, it forecasts nationally in 2030 a 10 percent increase in generation at existing NGCC EGUs, 

a 4 percent reduction in generation at existing fossil steam EGUs, and a 29 percent decrease in 

generation at new NGCC EGUs compared to the modeling scenario results presented above. The 

result of this reduction in new NGCC EGU generation is a reduction in CO2 emissions of 23 

million short tons (an amount equal to 1.3 percent of 2030 forecast emissions in mass-based 

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scenario). We do not quantify the effect of these changes in generation on SO2 and NOx

emissions, although on net additional co-benefits are expected. 

The incentives portrayed in this analysis are consistent with the incentives that would be 

realized under the OBA set-aside, and the general direction and magnitude of the results are 

likely consistent with those that would be observed had the mass-based scenario been modeled 

with the OBA set-aside. However, the results should be viewed as approximate given that 

analysis does not consider important aspects of power markets included in IPM. For example, the 

analysis does not consider any potential changes in relative fuel and allowance prices as a result 

of the OBA set-aside. The application of the OBA set-aside will place upward pressure on the 

allowance prices and therefore further incentivize a shift away from existing fossil steam 

generation. The OBA set-aside may also place upward pressure on the price of natural gas which 

would reduce the effectiveness of the set-aside at encouraging increased utilization of existing 

NGCC EGUs, but the OBA set-aside would be effective in increasing existing NGCC 

generation, the analysis does not consider the fact that electricity is traded across many IPM 

regions. The application of OBA in one state may impact the generation at EGUs in another 

state. 

1.5.8 Uncertainty Analysis 

The Office of Management and Budget’s circular Regulatory Analysis (Circular A-4) 

provides guidance on the preparation of regulatory analyses required under E.O. 12866, and 

requires an uncertainty analysis for rules with annual benefits or costs of $1 billion or more.27

This proposed rulemaking potentially surpasses that threshold for both benefits and costs. 

Throughout this RIA and the referenced final Clean Power Plan Emission Guidelines RIA, we 

considered a number of sources of uncertainty, both quantitatively and qualitatively, on benefits 

and costs. We summarize three key elements of our analysis of uncertainty here: 

 

27 Office of Management and Budget (OMB), 2003, Circular A-4, 

http://www.whitehouse.gov/omb/circulars_a004_a-4 and OMB, 2011. Regulatory Impact Analysis: A Primer.

http://www.whitehouse.gov/sites/default/files/omb/inforeg/regpol/circular-a-4_regulatory-impact-analysis-aprimer.pdf 

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• Assess uncertainty in the methods used to calculate the health co-benefits associated with 

the reduction in PM2.5 and ozone and the use of a benefits-per-ton approach in estimating 

these co-benefits. 

• Characterizing uncertainty in monetizing climate-related benefits. 

Some of these elements are evaluated using probabilistic techniques, whereas for others 

the underlying likelihoods of certain outcomes are unknown and we use scenario analysis to 

evaluate their potential effect on the benefits and costs of this rulemaking. 

1.5.8.1 Uncertainty in Costs 

Our best estimates of the costs of these illustrative scenarios are reported within the cost 

analysis of the final Clean Power Plan Emission Guidelines and are included in the cost 

modeling in this RIA for both the proposed rate-based and mass-based approaches. A source of 

uncertainty under this regulation is the ultimate approach states that are not subject to the federal 

plan or adopt the model rule will adopt in response to the guidelines, which will affect both the 

costs and benefits of this rule. For this reason we modeled the two proposed federal plan 

approaches assuming they applied to all of the states. 

1.5.8.2 Uncertainty Associated with Estimating the Social Cost of Carbon 

The 2010 SC-CO2 TSD noted a number of limitations to the SC-CO2 analysis, including 

the incomplete way in which the integrated assessment models (IAM) capture catastrophic and 

non-catastrophic impacts, their incomplete treatment of adaptation and technological change, 

uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk 

aversion.28 Currently integrated assessment models do not assign value to all of the important 

physical, ecological, and economic impacts of climate change recognized in the climate change 

literature due to a lack of precise information on the nature of damages and because the science 

incorporated into these models understandably lags behind the most recent research. These 

individual limitations do not all work in the same direction in terms of their influence on the SC-

 

28 Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866, Interagency Working Group on Social Cost of Carbon, with participation by the Council of Economic 

Advisers, Council on Environmental Quality, Department of Agriculture, Department of Commerce, Department 

of Energy, Department of Transportation, Environmental Protection Agency, National Economic Council, Office 

of Energy and Climate Change, Office of Management and Budget, Office of Science and Technology Policy, and 

Department of Treasury (February 2010). Available at: 

<http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf>. 

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CO2 estimates, though taken together they suggest that the SC-CO2 estimates are likely 

conservative. In particular, the IPCC Fourth Assessment Report (2007) concluded that “It is very 

likely that [SC-CO2 estimates] underestimate the damage costs because they cannot include 

many non-quantifiable impacts” and the IPCC Fifth Assessment report observed that SC-CO2

estimates continue to omit various impacts that would likely increase damages. The 95th

percentile estimate was included in the recommended range for regulatory impact analysis, in 

part, to address these concerns. 

The modeling underlying the development of the SC-CO2 estimates addressed 

uncertainty in several ways. An ensemble of three IAMs were used to generate the SC-CO2

estimates to capture differences in model structures that, in part, reflect uncertainty in the 

scientific literature about these relationships. Parametric uncertainty was explicitly addressed in 

each IAM, though to differing degrees, through Monte Carlo simulations in which explicit 

probability distributions for key parameters were specified, including the equilibrium climate 

sensitivity, which represents the long-run responsiveness of the climate to increasing GHG 

concentrations. Furthermore, the analysis considered five different socioeconomic and emissions 

forecasts to capture the sensitivity of the SC-CO2 estimates to key exogenous projections used in 

the modeling. Finally, the results were calculated for three discount rates, which were selected, in 

part, to reflect uncertainty about how interest rates may change over time and the possibility that 

climate damages are positively correlated with uncertain future economic activity. This analysis 

produced 45 different distributions of the SC-CO2 estimates for each emissions year. To produce 

a range of plausible estimates that are manageable in regulatory analysis but still reflects the 

uncertainty in the results four point estimates were recommended. The use of this range of point 

estimates in this rulemaking helps to reflect the uncertainty in the SC-CO2 estimates. Chapter 4 

of the final Clean Power Plan Emission Guidelines RIA provides a comprehensive discussion 

about the methodology and application of the SC-CO2; see both the 2010 TSD and current SCCO2 TSD for a full description. 

In addition, OMB’s Office of Information and Regulatory Affairs received comments 

regarding uncertainty and the SC-CO2 estimates in response to a separate request for public 

comment on the approach used to develop the estimates. Commenters discussed the analyses and 

presentation of uncertainty in the TSD as well as the implications of uncertainty for use of the 

SC-CO2 estimates in regulatory impact analysis. In their response, the interagency working 

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group (IWG) acknowledged uncertainty in the SC-CO2 estimates but disagreed with commenters 

that suggested the uncertainty undermines use of the SC-CO2 estimates in regulatory impact 

analysis. The IWG went on to note that the uncertainty in the SC-CO2 estimates is fully 

acknowledged and comprehensively discussed in the TSDs and supporting academic literature, 

and that while all regulatory impact analysis involves uncertainty, these analyses can provide 

useful information to decision makers and the public. See the IWG Response to Comments for 

the complete response.29 

1.5.8.3 Uncertainty Associated with PM2.5 and Ozone Health Co-Benefits Assessment 

EPA provides information on the relative uncertainty in the benefits estimates based on 

the 95th percentile confidence interval for avoided PM-related premature deaths and the 

associated economic valuation estimated in the benefits analysis for the recent PM NAAQS RIA 

(U.S. EPA, 2012).. In general, the 95th percentile confidence interval for monetized PM2.5

benefits ranges from approximately -90 percent to +180 percent of the central estimates based on 

the two key PM mortality studies. To further explore uncertainty in the premature mortality 

benefits, EPA provides the PM-related results using concentration-response functions from two 

key epidemiology studies, as well as alternate concentration-response relationship provided by 

an expert elicitation and alternative ozone-related results using concentration-response 

relationships provided by alternative epidemiology studies. In addition, we include an 

assessment of the distribution of population exposure in the modeling underlying the benefit-perton estimates. 

In addition to the uncertainties in the underlying concentration-response and valuation 

functions, all benefit-per-ton approaches have inherent limitations, including that the estimates 

reflect the geographic distribution of the modeled sector emissions, which may not match the 

emission reductions anticipated by this proposed rule, and they may not reflect local variability 

in population density, meteorology, exposure, baseline health incidence rates, or other local 

factors for any specific location. In addition, these estimates reflect the regional average benefitper-ton for each ambient PM2.5 precursor emitted from EGUs, which assumes a linear 

atmospheric response to emission reductions. The regional benefit-per-ton estimates, although 

 

29 See https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-comments-final-july-2015.pdf 

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less subject to these types of uncertainties than national estimates, still should be interpreted with 

caution. Even though we assume that all fine particles have equivalent health effects, the benefitper-ton estimates vary between precursors depending on the location and magnitude of their 

impact on PM2.5 levels, which drive population exposure. 

1.6 References 

40 CFR Chapter I [EPA–HQ–OAR–2009–0171; FRL–9091–8] RIN 2060–ZA14, 

“Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) 

of the Clean Air Act,” Federal Register / Vol. 74, No. 239 / Tuesday, December 15, 2009 / 

Rules and Regulations. 

75 FR 49556. August 13, 2010. “EPA’s Denial of the Petitions to Reconsider the Endangerment 

and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean 

Air Act.”

Bell, M.L., A. McDermott, S.L. Zeger, J.M. Sarnet, and F. Dominici. 2004. “Ozone and ShortTerm Mortality in 95 U.S. Urban Communities, 1987-2000.” Journal of the American 

Medical Association. 292(19):2372-8. 

Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support Document: Social Cost of 

Carbon for Regulatory Impact Analysis Under Executive Order 12866, Interagency Working 

Group on Social Cost of Carbon, with participation by the Council of Economic Advisers, 

Council on Environmental Quality, Department of Agriculture, Department of Commerce, 

Department of Energy, Department of Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and Climate Change, Office of Management 

and Budget, Office of Science and Technology Policy, and Department of Treasury (February 

2010). Available at: <http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf>. Accessed July 15, 2015. 

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Docket ID EPA-HQ-OAR-2013-0602, Technical Support Document: Technical Update of the 

Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, 

Interagency Working Group on Social Cost of Carbon, with Participation by Council of 

Economic Advisers, Council on Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, Department of Transportation, Domestic 

Policy Council, Environmental Protection Agency, National Economic Council, Office of 

Management and Budget, Office of Science and Technology Policy, and Department of 

Treasury (May 2013, Revised July 2015). Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf>. 

Accessed July 15, 2015. 

Krewski D., M. Jerrett, R.T. Burnett, R. Ma, E. Hughes, Y. Shi, et al. 2009. Extended Follow-Up 

and Spatial Analysis of the American Cancer Society Study Linking Particulate Air Pollution 

and Mortality. HEI Research Report, 140, Health Effects Institute, Boston, MA. 

Interagency Working Group on Social Cost of Carbon, with participation by Council of 

Economic Advisers, Council on Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, Department of Transportation, 

Environmental Protection Agency, National Economic Council, Office of Management and 

Budget, Office of Science and Technology Policy, and Department of Treasury. Response to 

to Comments: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866. July 2015. Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-commentsfinal-july-2015.pdf.> Accessed July 15, 2015. 

Intergovernmental Panel on Climate Change (IPCC). 2007. Climate Change 2007: Synthesis 

Report Contribution of Working Groups I, II and III to the Fourth Assessment Report of the 

IPCC. Available at: 

<http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report_synt

hesis_report.htm>. Accessed June 6, 2015. 

Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. “Chronic Exposure to Fine Particles 

and Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environmental Health Perspectives. 120(7):965-70. 

Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. “Ozone Exposure and Mortality: An 

Empiric Bayes Metaregression Analysis.” Epidemiology. 16(4):458-68. 

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Melillo, J.M., T.C. Richmond, and G.W. Yohe, Eds., 2014: Climate Change Impacts in the 

United States: The Third National Climate Assessment. U.S. Global Change Research 

Program. Available at <http://nca2014.globalchange.gov>. Accessed June 4, 2015. 

National Research Council (NRC). 2000. Toxicological Effects of Methylmercury: Committee on 

the Toxicological Effects of Methylmercury.” Board on Environmental Studies and 

Toxicology. National Academies Press. Washington, DC. 

National Research Council (NRC). 2002. Estimating the Public Health Benefits of Proposed Air 

Pollution Regulations. National Academies Press. Washington, DC. 

National Research Council. 2011. Climate Stabilization Targets: Emissions, Concentrations, and 

Impacts over Decades to Millennia. Washington, DC: The National Academies Press. 

U.S. Environmental Protection Agency (U.S. EPA). 2008a. Integrated Science Assessment for 

Sulfur Oxides—Health Criteria (Final Report). National Center for Environmental 

Assessment – RTP Division, Research Triangle Park, NC. September. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=198843>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2008b. Final Ozone NAAQS Regulatory 

Impact Analysis. EPA-452/R-08-003. Office of Air Quality Planning and Standards Health 

and Environmental Impacts Division, Air Benefit and Cost Group Research Triangle Park, 

NC. March. Available at: < http://www.epa.gov/ttnecas1/regdata/RIAs/6-

ozoneriachapter6.pdf>. Accessed June 4, 2015. 

U.S. EPA. 2008c. Integrated Science Assessment for Oxides of Nitrogen: Health Criteria (Final 

Report). Research Triangle Park, NC: National Center for Environmental Assessment. July. 

Available at < http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. 

U.S. Environmental Protection Agency (U.S. EPA). 2008c. Integrated Science Assessment for 

Oxides of Nitrogen - Health Criteria (Final Report). National Center for Environmental 

Assessment, Research Triangle Park, NC. July. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2009b. Integrated Science Assessment for 

Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for Environmental 

Assessment – RTP Division, Research Triangle Park, NC. December. Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>. Accessed June 4, 2015. 

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U.S. Environmental Protection Agency (U.S. EPA). 2010d. Section 3: Re‐analysis of the Benefits 

of Attaining Alternative Ozone Standards to Incorporate Current Methods. Available at: 

<http://www.epa.gov/ttnecas1/regdata/RIAs/s3-supplemental_analysis-updated_benefits11-

5.09.pdf >. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2012a. Regulatory Impact Analysis for the 

Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. EPA452/R-12-003. Office of Air Quality Planning and Standards, Health and Environmental 

Impacts Division, Research Triangle Park, NC. December. Available at: < 

http://www.epa.gov/ttnecas1/regdata/RIAs/finalria.pdf>. Accessed June 4, 2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2013b. Integrated Science Assessment of 

Ozone and Related Photochemical Oxidants (Final Report). EPA/600/R-10/076F. National 

Center for Environmental Assessment – RTP Division, Research Triangle Park. Available at: 

<http://cfpub.epa.gov/ncea/isa/recordisplay.cfm?deid=247492#Download>. Accessed June 4, 

2015. 

U.S. Environmental Protection Agency (U.S. EPA). 2015a. Regulatory Impact Analysis for the 

Clean Power Plan Final Rule. EPA-452/R-15-003. Office of Air Quality Planning and 

Standards, Health and Environmental Impacts Division, Research Triangle Park. 

U.S. EPA. 2015b. Technical Support Document (TSD) the Final Carbon Pollution Emission 

Guidelines for Existing Stationary Sources: Electric Utility Generating Units. Demand-Side 

Energy Efficiency. 

Woodruff, T.J., J. Grillo, and K.C. Schoendorf. 1997. “The relationship between selected causes 

of postneonatal infant mortality and particulate air pollution in the United States.” 

Environmental Health Perspectives. 105(6): 608-612. 

 

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CHAPTER 2: STATUTORY AND EXECUTIVE ORDER REVIEWS

2.1 Executive Order 12866: Regulatory Planning and Review and Executive Order 

13563: Improving Regulation and Regulatory Review 

This proposed action is an economically significant regulatory action that was submitted 

to the OMB for review. Any changes made in response to OMB recommendations have been 

documented in the docket. The EPA prepared an analysis of the potential costs and benefits 

associated with this action. This analysis, which is presented in this RIA, is also available in the 

docket and is briefly summarized in section VIII of the preamble. 

Consistent with Executive Order 12866 and Executive Order 13563, the EPA estimated 

the costs and benefits for two alternative federal plan approaches to implementing the proposed 

federal plan and model trading rules. The proposed action will achieve the same levels of 

emissions performance as required of state plans under the CAA section 111(d) EGs for the 

control of CO2. Actions taken to comply with the guidelines will also reduce the emissions of 

directly-emitted PM2.5, SO2 and NOX. The benefits associated with these PM2.5, SO2 and NOX

reductions are referred to as co-benefits, as these reductions are not the primary objective of this 

rule. 

The RIA for this proposal analyzed two implementation scenarios, which we term the 

“rate-based federal plan approach” and the “mass-based federal plan approach”. It is very 

important to note that the differences between the analytical results for the rate-based and massbased federal plan approaches presented in this RIA may not be indicative of likely differences 

between the approaches if implemented by states and affected EGUs in response to the proposed 

rule. In other words, if one approach performs differently than the other on a given metric during 

a given time period, this does not imply this will apply in all instances. 

It is important to note that the potential regulatory impacts presented in the Clean Power 

Plan Final Rule RIA and this RIA are not additive. Both RIAs present estimates of the benefits 

and costs of achieving the emission performance rates of the Clean Power Plan EGs. In the case 

of the Clean Power Plan Final Rule RIA, the illustrative analysis assumes the performance rates 

are met under state plans. In the case of this RIA for the proposed federal plan and model trading 

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rules, the same performance rates are accomplished but are assumed to be achieved under the 

federal plan or model trading rules. 

The EPA has used the social cost of carbon estimates presented in the Technical Support 

Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866 (May 2013, Revised July 2015) (“current TSD”) to analyze CO2

climate impacts of this rulemaking. We refer to these estimates, which were developed by the 

U.S. government, as “SC-CO2 estimates.” The SC-CO2 is an estimate of the monetary value of 

impacts associated with a marginal change in CO2 emissions in a given year. The four SC-CO2

estimates are associated with different discount rates (model average at 2.5 percent discount rate, 

3 percent, and 5 percent; 95th percentile at 3 percent), and each increases over time. In this 

summary, the EPA provides the estimate of climate benefits associated with the SC-CO2 value 

deemed to be central in the current TSD: the model average at 3 percent discount rate. 

The EPA estimates that, in 2020, the proposal will yield monetized climate benefits (in 

2011$) of approximately $2.8 billion for the rate-based approach and $3.3 billion for the massbased approach (3 percent model average). For the rate-based approach, the air pollution health 

co-benefits in 2020 are estimated to be $0.7 billion to $1.8 billion (2011$) for a 3 percent 

discount rate and $0.64 billion to $1.7 billion (2011$) for a 7 percent discount rate. For the massbased approach, the air pollution health co-benefits in 2020 are estimated to be $2.0 billion to 

$4.8 billion (2011$) for a 3 percent discount rate and $1.8 billion to $4.4 billion (2011$) for a 7 

percent discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE 

program and participant costs and MRR costs in 2020, are approximately $2.5 billion for the 

rate-based approach and $1.4 billion for the mass-based approach (2011$). The quantified net 

benefits (the difference between monetized benefits and compliance costs) in 2020 are estimated 

to range from $1.0 billion to $2.1 billion (2011$) for the rate-based approach and from $3.9 

billion to 6.7 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model 

average). 

The EPA estimates that, in 2025, the proposal will yield monetized climate benefits (in 

2011$) of approximately $10 billion for the rate-based approach and $12 billion for the massbased approach (3 percent model average). For the rate-based approach, the air pollution health 

co-benefits in 2025 are estimated to be $7.4 billion to $18 billion (2011$) for a 3 percent 

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discount rate and $6.7 billion to $16 billion (2011$) for a 7 percent discount rate. For the massbased approach, the air pollution health co-benefits in 2025 are estimated to be $7.1 billion to 

$17 billion (2011$) for a 3 percent discount rate and $6.5 billion to $16 billion (2011$) for a 7 

percent discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE 

program and participant costs and MRR costs in 2025, are approximately $1.0 billion for the 

rate-based approach and $3.0 billion for the mass-based approach (2011$). The quantified net 

benefits (the difference between monetized benefits and compliance costs) in 2025 are estimated 

to range from $17 billion to $27 billion (2011$) for the rate-based approach and $16 billion to 

$26 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model 

average). 

The EPA estimates that, in 2030, the proposal will yield monetized climate benefits (in 

2011$) of approximately $20 billion for the rate-based approach and $20 billion for the massbased approach (3 percent model average). For the rate-based approach, the air pollution health 

co-benefits in 2030 are estimated to be $14 billion to $34 billion (2011$) for a 3 percent discount 

rate and $13 billion to $31 billion (2011$) for a 7 percent discount rate. For the mass-based 

approach, the air pollution health co-benefits in 2030 are estimated to be $12 billion to $28 

billion (2011$) for a 3 percent discount rate and $11 billion to $26 billion (2011$) for a 7 percent 

discount rate. The annual compliance costs estimated by IPM and inclusive of DS-EE program 

and participant costs and MRR costs in 2030, are approximately $8.4 billion for the rate-based 

approach and $5.1 billion for the mass-based approach (2011$). The quantified net benefits (the 

difference between monetized benefits and compliance costs) in 2030 are estimated to range 

from $26 billion to $45 billion (2011$) for the rate-based approach and from $26 billion to $43 

billion (2011$) for the mass-based approach, using a 3 percent discount rate (model average). 

Table 1-8 and Table 1-9 of this RIA provides the estimates of the climate benefits, health cobenefits, compliance costs and net benefits of the proposal for rate-based and mass-based federal 

plan approaches, respectively. 

There are additional important benefits that the EPA could not monetize. Due to current 

data and modeling limitations, our estimates of the benefits from reducing CO2 emissions do not 

include important impacts like ocean acidification or potential tipping points in natural or 

managed ecosystems. Unquantified benefits also include climate benefits from reducing 

emissions of non-CO2 GHGs (e.g., nitrous oxide and methane) and co-benefits from reducing 

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direct exposure to SO2, NOX, and HAP (e.g., mercury), as well as from reducing ecosystem 

effects and visibility impairment. Based upon the foregoing discussion, it remains clear that the 

benefits of this proposed action are substantial, and far exceed the costs. Additional details on 

benefits, costs, and net benefits estimates are provided in this RIA. 

 2.2 Paperwork Reduction Act 

The information collection requirements in this rule have been submitted for approval to 

OMB under the PRA. The Information Collection Request (ICR) document prepared by the EPA 

has been assigned EPA ICR number 2526.01. You can find a copy of the ICR in the docket for 

this rule, and it is briefly summarized here. The information collection requirements are not 

enforceable until approved by OMB. 

This rule does not directly impose specific requirements on state and U.S. territory 

governments with affected EGUs. The rule also does not impose specific requirements on tribal 

governments that have affected EGUs located in their area of Indian country. This rule does 

impose specific requirements on EGUs located in states, U.S. territories or areas of Indian 

country. 

The information collection activities in this proposed rule are consistent with those 

activities defined under the Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units finalized on August 3, 2015. The information 

collection requirements in this proposed rule have been submitted for approval to the Office of 

Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. 

The ICR document prepared by the EPA has been assigned EPA ICR number 2526.01. You can 

find a copy of the ICR in the docket for this rule, and it is briefly summarized here. 

Aside from reading and understanding the rule, this proposed action would impose 

minimal new information collection burden on affected EGUs beyond what those affected EGUs 

would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously 

approved the information collection requirements contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR part 98) under the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060–0626 and 

2060– 0629, respectively. Apart from certain reporting costs based on requirements in the NSPS 

General Provisions (40 CFR part 60, subpart A), which are mandatory for all owners/operators 

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subject to CAA section 111 national emission standards, there are no new information collection 

costs, as the information required by this proposed rule is already collected and reported by other 

regulatory programs. The recordkeeping and reporting requirements are specifically authorized 

by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the 

recordkeeping and reporting requirements for which a claim of confidentiality is made is 

safeguarded according to agency policies set forth in 40 CFR part 2, subpart B. 

Although EPA cannot determine at this time how many affected EGU respondents will 

submit information under the federal plan, EPA has estimated an “upper bound” burden estimate 

for this ICR that estimates burden should every affected EGU read and understand the rule. This 

is the only potential respondent activity that would be required under the 3-year period following 

publication of the final federal plan, so there are no obligations to respond in this period. The 

results of this “upper bound” estimate of federal plan burden are presented below: 

Respondents/affected entities: 1,028 

Respondents’ obligation to respond: Not applicable, no responses are required during the 

period covered by the ICR. 

Estimated number of respondents: Unknown at this time, but have assumed all affected 

entities are respondents for an upper bound estimate. 

Frequency of response: None, no responses are required during the period covered by the 

ICR. 

Total estimated burden: 17,133 hours (per year). Burden is defined at 5 CFR 1320.3(b). 

Total estimated cost: $1,706,501 (per year) 

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. 

Submit your comments on the agency’s need for this information, the accuracy of the 

provided burden estimates and any suggested methods for minimizing respondent burden to the 

EPA using the docket identified at the beginning of this rule. You may also send your ICRrelated comments to OMB’s Office of Information and Regulatory Affairs via email to 

oria_submissions@omb.eop.gov, Attention: Desk Officer for the EPA. Since OMB is required to 

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make a decision concerning the ICR between 30 and 60 days after receipt, OMB must receive 

comments no later than 30 days after the date of publication in the Federal Register. The EPA 

will respond to any ICR-related comments in the final rule. 

2.3 Initial Regulatory Flexibility Analysis 

The Regulatory Flexibility Act (RFA; 5 U.S.C.§ 601 et seq.), as amended by the Small 

Business Regulatory Enforcement Fairness Act (Public Law No. 104-121), provides that 

whenever an agency is required to publish a general notice of proposed rulemaking, it must 

prepare and make available an initial regulatory flexibility analysis (IRFA), unless it certifies that 

the proposed rule, if promulgated, will not have a significant economic impact on a substantial 

number of small entities (5 U.S.C. § 605[b]). Small entities include small businesses, small 

organizations, and small governmental jurisdictions. An IRFA describes the economic impact of 

the proposed rule on small entities and any significant alternatives to the proposed rule that 

would accomplish the objectives of the rule while minimizing significant economic impacts on 

small entities. Pursuant to section 603 of the RFA, the EPA prepared an initial regulatory 

flexibility analysis (IRFA) that examines the impact of the proposed rule on small entities along 

with regulatory alternatives that could minimize that impact. 

2.3.1 Reasons why Action is Being Considered 

On August 3, 2015, the EPA finalized the Clean Power Plan EGs for existing fossil-fuel 

fired EGUs (40 CFR part 60, subpart UUUU) under authority of section 111 of the CAA. The 

Guidelines apply to existing fossil-fuel fired EGUs, i.e., those that were in operation or had 

commenced construction before January 8, 2014. States with existing EGUs subject to the 

guidelines are required to submit to the EPA by September 6, 2016, a state plan that implements 

the EGs. States may also make initial plan submittals in lieu of a complete state plan, in which 

case extensions will be granted until September 6, 2018 (40 CFR &&&).30 As discussed in 

section VI.D of the preamble, Indian Tribes may, but are not required to, submit tribal plans. 

Once the EPA finds that a state has failed to submit a plan, or disapproves a state plan,31 section 

 

30 See Section VII of the preamble for additional information on proposed changes to 40 CFR 60.27 to provide 

enhancements and flexibilities to the agency’s process for review and action on state plans and promulgation of 

federal plans. 

31 If a state has submitted a complete plan, then the EPA will go through a public notice and comment process to 

fully or partially approve or disapprove the state plan. 

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111 of the CAA and 40 CFR 60.27 require the EPA to develop, implement, and enforce a federal 

plan for existing EGUs located in that state. In addition, CAA section 301(d)(2) authorizes the 

Administrator to treat an Indian Tribe in the same manner as a state for this EGU requirement. 

See 40 CFR 49.3; see also “Indian Tribes: Air Quality Planning and Management,” hereafter 

“Tribal Authority Rule,” (63 FR 7254, February 12, 1998). As discussed in section VI.D of the 

preamble, the agency in this action is proposing a necessary or appropriate finding for the 

affected EGUs in several areas of Indian country and is proposing the federal plan for these 

affected EGUs. 

The agency believes it is appropriate to propose the federal plan at this time for any states 

that may ultimately be found to have failed to submit a plan, or had their plan disapproved by the 

EPA. For some states in this situation, the federal plan may be no more than an interim measure 

to ensure that congressionally mandated emission standards under authority of section 111 of the 

CAA are implemented until they can get an approved plan in place. Other states may choose to 

rely on the federal plan and would not need to develop their own plan. This proposal also serves 

as two proposed model trading rules which states can adopt or tailor for adoption as their state 

plan. 

2.3.2 Statement of Objectives and Legal Basis for Proposed Rules 

The EPA is proposing this rulemaking for a federal plan to implement greenhouse gas 

Emission Guidelines for existing fossil fuel-fired electric generating units (EGUs). The emission 

guidelines were proposed in June 2014 as the Carbon Pollution Emission Guidelines for Existing 

Stationary Sources: Electric Utility Generating Units (79 FR 34830; the Clean Power Plan). This 

plan is part of the President’s Climate Action Plan announced in June of 2013 to reduce carbon 

emissions from the power sector by 30 percent below 2005 levels. This federal plan serves to: 1) 

provide a model rule that states can tailor for implementation, and 2) set in place a plan that EPA 

can implement for states that do not develop an approvable state plan. The EPA sees this federal 

plan as an interim measure to ensure that congressionally mandated emission standards under 

authority of section 111 of the CAA are implemented until states assume their role as the 

preferred implementers of the emission guidelines. 

The final Clean Power Plan Emission Guidelines are related to but separate from the 

proposed federal plan. The final Emission Guidelines will detail the carbon dioxide (CO2) 

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reduction goals for sources by state. The purpose of the proposed federal plan is to lay out 

mechanisms to achieve reductions in CO2 emissions from affected EGUs that are not covered by 

an EPA-approved state plan. The EPA is considering a range of options and approaches through 

which affected EGUs would meet a rate-based goal or a mass-based equivalent. The EPA intends 

to incorporate flexibility to the extent possible into the proposed federal plan so affected units 

can achieve these reductions in a cost-effective way. 

2.3.3 Description and Estimate of Affected Small Entities 

EPA conducted this regulatory flexibility analysis at the ultimate (i.e., highest) level of 

ownership, evaluating parent entities with the largest share of ownership in at least one 

potentially-affected EGU included in EPA’s Base Case using the Integrated Planning Model 

(IPM) v.5.15, used in this RIA.32 This analysis draws on the “parsed” unit-level estimates using 

IPM results for 2030, as well as ownership, employment, and financial information for the 

potentially affected small entities drawn from other resources described in more detail below. 

EPA chose to examine potential impacts in 2030 because that is when the emission performance 

goals are required to be fully achieved. Also, as presented in this RIA, 2030 is the year where the 

estimated annual compliance costs for the contiguous U.S. are at their highest.33 

This action proposes a federal plan under section 111(d) of the CAA for the control of 

CO2, a greenhouse gas pollutant, from certain large emitting fossil-fuel fired power plants, in the 

event that some states do not adopt their own plans. Specifically, the EPA is proposing 

approaches in the form of mass- and rate-based trading options that provide flexibility in 

implementing emission standards for a state’s affected EGUs. Both proposed approaches to the 

federal plan would require affected EGUs to meet emission standards set using the CO2 emission 

performance rates in the emission guidelines. The federal plan will achieve the same levels of 

emissions performance as required of state plans under the emission guidelines. 

However, at the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan or adopt a model rule. Because of this lack of information, 

for this RIA, the EPA has chosen to examine two federal plan approach scenarios where all 

 

32 See 1.4.1 of this RIA for more detail on the IPM base case used for this analysis. Detailed documentation for IPM 

v.5.15 is available at: http://www.epa.gov/powersectormodeling. 

33 See Section 1.5.2 of this RIA. 

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states of the contiguous U.S. will be regulated under a federal plan or a model rule. The first 

federal plan approach we examine in this RIA assumes all states in the contiguous U.S. are 

regulated under a rate-based federal plan or model rule. The second federal plan approach we 

examine assumes all contiguous states are regulated under a mass-based federal plan or model 

rule. We use these scenarios to inform this IRFA. 

As with the analysis in this RIA, the IRFA proceeds by examining potential costs to small 

entities under both the rate-based and mass-based approach, again under the strong assumption 

that all affected EGUs are regulated under a federal plan. The parsed unit-level estimates used in 

this IRFA are consistent with the analysis presented elsewhere in this RIA. These 2030 year IPM 

files can also be found in the docket for the rulemaking. 

EPA identified the size of ultimate parent entities by using the Small Business 

Administration (SBA) size threshold guidelines.34 The criteria for size determination vary by the 

organization/operation category of the ultimate parent entity, as follows: 

• Privately-owned (non-government) entities (see Table 2-1) 

o Privately-owned entities include investor-owned utilities, non-utility entities, and 

entities with a primary business other than electric power generation. 

o For entities with electric power generation as a primary business, small entities 

are those with less than the threshold number of employees specified by SBA for 

each of the relevant North American Industry Classification System (NAICS) 

sectors (NAICS 2211). 

o For entities with a primary business other than electric power generation, the 

relevant size criteria are based on revenue, assets, or number of employees by 

NAICS sector.35

• Publicly-owned entities 

 

34 U.S. Small Business Administration (SBA). 2014. Small Business Size Standards. Effective as of July 14, 2014. 

See: http://www.sba.gov/sites/default/files/Size_Standards_Table.pdf. 

35 Certain affected EGUs are owned by ultimate parent entities whose primary business is not electric power 

generation. 

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o Publicly-owned entities include federal, state, municipal, and other political 

subdivision entities. 

o The federal and state governments were considered to be large. Municipalities and 

other political units with population fewer than 50,000 were considered to be 

small. 

• Rural Electric Cooperatives 

o Small entities are those with fewer than the threshold level of employees or 

revenue specified by SBA for each of the relevant NAICS sectors. 

EPA examined affected EGUs included in EPA’s 2030 projections and identified the 

associated power plants. Next, we determined power plant ownership information, including the 

name of associated owning entities, ownership shares, and each entity’s type of ownership. EPA 

primarily used data from SNL and Ventyx, supplemented by limited research using publicly 

available data.36 Majority owners of power plants with affected EGUs were categorized as one of 

the seven ownership types.37 These ownership types are: 

1. Investor-Owned Utility (IOU): Investor-owned assets (e.g., a marketer, independent 

power producer, financial entity) and electric companies owned by stockholders, etc.

2. Cooperative (Co-Op): Non-profit, customer-owned electric companies that generate 

and/or distribute electric power.

3. Municipal: A municipal utility, responsible for power supply and distribution in a small 

region, such as a city.

4. Sub-division: Political subdivision utility is a county, municipality, school district, 

hospital district, or any other political subdivision that is not classified as a municipality 

under state law.

5. Private: Similar to an investor-owned utility, however, ownership shares are not openly 

traded on the stock markets.

6. State: Utility owned by the state.

 

36 SNL Financial data covers the energy market and other industries. For more information, see: www.snl.com. The 

Ventyx database consists of detailed ownership and corporate affiliation information at the EGU level. For more 

information, see: www.ventyx.com. 

37 Throughout this analysis, EPA refers to the owner with the largest ownership share as the “majority owner” even 

when the ownership share is less than 51 percent. 

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7. Federal: Utility owned by the federal government.

Required ownership information could not be determined for two committed units that 

are represented in the IPM base case modeling for this proposed rule, preventing their inclusion 

in this analysis.38

Next, EPA used the Hoover’s online database to identify the ultimate owners of power 

plant owners identified in the SNL and Ventyx databases. This was necessary, as many majority 

owners of power plants (listed in SNL or Ventyx) are themselves owned by other ultimate parent 

entities (listed in Hoover’s).39 In these cases, the ultimate parent entity was identified via 

Hoover’s, whether domestically or internationally owned. 

EPA followed SBA size standards to determine which non-government ultimate parent 

entities should be considered small entities in this analysis. These SBA size standards are 

specific to each industry, each having a threshold level of either employees, revenue, or assets 

below which an entity is considered small. SBA guidelines list all industries, along with their 

associated NAICS code and SBA size standard. Therefore, it was necessary to identify the 

specific NAICS code associated with each ultimate parent entity in order to understand the 

appropriate size standard to apply. Data from Hoover’s was used to identify the NAICS codes for 

most of the ultimate parent entities.40 In many cases, an entity that is a majority owner of a power 

plant is itself owned by an ultimate parent entity with a primary business other than electric 

power generation. Therefore, it was necessary to consider SBA entity size guidelines for the 

range of NAICS codes listed in Table 2-1. This table represents the range of NAICS codes and 

areas of primary business of ultimate parent entities which are majority owners of potentially 

affected EGUs in EPA’s IPM base case. 

 

38 The ORIS codes of these two units are 83609 and 83921. Without knowledge of entity type and size, it was not 

possible to accurately estimate revenue or costs impacts. An ORIS code is an identifying number assigned by the 

U.S. Energy Information Administration to power plants owned by utilities. 

39 The Hoover’s Inc. online platform includes company records that can contain NAICS codes, number of 

employees, revenues, and assets. For more information, see: http://www.hoovers.com. 

40 In the case of two entities, NAICS codes could not be located in Hoover’s, so publicly available information was 

used to determine the primary area of business for the ultimate parent entities. 

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Table 2-1. SBA Size Standards by NAICS Code 

Notes: 1) Based on size standards effective at the time EPA conducted this analysis (SBA size standards, effective 

July 14, 2014) 2) Small business size standards are not established for the Public Administration industry (NAICS 

code 921110). It is assumed that a comparable NAICS private sector industry is Fossil Fuel Electric Power 

Generation (NAICS code 221112). Therefore, for this analysis, the NAICS code 921110 is assumed to have a size 

standard of 750 employees. 

Source: SBA, 2014 

NAICS 

Code NAICS Description SBA Size Standard

211111 Crude Petroleum and Natural Gas Extraction 500 employees

211112 Natural Gas Liquid Extraction 500 employees

212111 Bituminous Coal and Lignite Surface Mining 500 employees

212221 Gold Ore Mining 500 employees

213112 Support Activities for Oil and Gas Operations $38.5 million in revenue

221111 Hydroelectric Power Generation 500 employees

221112 Fossil Fuel Electric Power Generation 750 employees

221113 Nuclear Electric Power Generation 750 employees

221118 Other Electric Power Generation 250 employees

221121 Electric Bulk Power Transmission and Control 500 employees

221122 Electric Power Distribution 1,000 employees

221210 Natural Gas Distribution 500 employees

238210 Electrical Contractors and Other Wiring Installation Contractors $15 million in revenue

238290 Other Building Equipment Contractors $15 million in revenue

324110 Petroleum Refineries 1,500 employees

325120 Industrial Gas Manufacturing 1,000 employees

325211 Plastics Material and Resin Manufacturing 750 employees

325320 Pesticide and Other Agricultural Chemical Manufacturing 500 employees

331110 Iron and Steel Mills and Ferroalloy Manufacturing 1,000 employees

331313 Alumina Refining and Primary Aluminum Production 1,000 employees

333613 Mechanical Power Transmission Equipment Manufacturing 500 employees

333999 All Other Miscellaneous General Purpose Machinery Manufacturing 500 employees

335312 Motor and Generator Manufacturing 1,000 employees

335999 All Other Miscellaneous Electrical Equipment and Component Manufacturing 500 employees

423610 Electrical Apparatus and Equipment, Wiring Supplies, and Related Equipment Merchant 

Wholesalers 100 employees

424720 Petroleum and Petroleum Products Merchant Wholesalers (except Bulk Stations and Terminals) 100 employees

454310 Fuel Dealers 50 employees

486210 Pipeline Transportation of Natural Gas $27.5 million in revenue

522110 Commercial Banking $550 million in assets

522220 Sales Financing $38.5 million in revenue

522320 Financial Transactions Processing, Reserve, and Clearinghouse Activities $38.5 million in revenue

523120 Securities Brokerage $38.5 million in revenue

523910 Miscellaneous Intermediation $38.5 million in revenue

523920 Portfolio Management $38.5 million in revenue

523930 Investment Advice $38.5 million in revenue

524113 Direct Life Insurance Carriers $38.5 million in revenue

524126 Direct Property and Casualty Insurance Carriers 1,500 employees

524210 Insurance Agencies and Brokerages $7.5 million in revenue

525110 Pension Funds $32.5 million in revenue

525120 Health and Welfare Funds $32.5 million in revenue

525990 Other Financial Vehicles $32.5 million in revenue

541611 Administrative Management and General Management Consulting Services $15 million in revenue

551112 Offices of Other Holding Companies $20.5 million in revenue

561110 Office Administrative Services $7.5 million in revenue

813910 Business Associations $7.5 million in revenue

921110 Public Administration 750 employees

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EPA compared the relevant entity size criterion for each ultimate parent entity to the SBA 

threshold value noted in Table 2-1. We used the following data sources and methodology to 

estimate the relevant size criterion values for each ultimate parent entity: 

1. Employment, Revenue, and Assets: EPA used the Hoover’s database as the primary 

source for information on ultimate parent entity employee numbers, revenue, and assets.41

In parallel, EPA also considered estimated revenues from affected EGUs based on 

analysis of parsed-file estimates for 2030.42 EPA assumed that the ultimate parent entity 

revenue was the larger of the two revenue estimates. In limited instances, supplemental 

research was also conducted to estimate an ultimate parent entity’s number of employees, 

revenue, or assets. 

2. Population: Municipal entities are defined as small if they serve populations of less than 

50,000. EPA primarily relied on data from the Ventyx database and the U.S. Census 

Bureau to inform this determination. Supplemental research of individual municipalities 

was also conducted in some instances. 

Ultimate parent entities for which the relevant measure is less than the SBA size criterion 

were identified as small entities and carried forward in this analysis. In the case of six entities, 

data limitations prevented the comparison of entities against their appropriate SBA size 

standards. For the purposes of this analysis, EPA assumed that these six entities are small 

entities.43

EPA identified 223 potentially affected EGUs owned by 74 small entities included in 

EPA’s 2030 projections. Fifty-nine of these potentially affected EGUs are projected to no longer 

be operating by 2030 in the Base Case of EPA’s version of IPM v.5.15.44 Twenty-four small 

 

41 Estimates of sales were used in lieu of revenue estimates when revenue data was unavailable. 

42 The methodology for the analysis of IPM results is detailed later in this IRFA. 

43 Generation from potentially affected EGUs owned by these six entities represents less than two percent of total 

generation from potentially affected EGUs owned by small entities under EPA’s base case projections. 

44 Detailed documentation for IPM v.5.15 is available at: http://www.epa.gov/powersectormodeling. 

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entities are projected to have all of their potentially affected EGUs cease operation by 2030 in 

this Base Case. 

2.3.4 Compliance Cost Impact Estimates 

2.3.4.1 Methodology for Estimating Impacts on Small Entities 

This section presents the methodology used in this analysis for estimating the compliance 

costs of this proposed rule for small entities. For the purposes of this IRFA, EPA estimated net 

compliance costs for individual EGUs of the proposed rule using the following equation: 

Cnet compliance cost = ∆ Coperating + annualized capital + ∆ Cfuel + ∆ Cdemand-side energy efficiency + ∆ R 

where C represents the components of cost as labeled, R represents revenue, and ∆ indicates the 

calculation of difference between the base case and the federal plan approach under examination. 

The specific meaning of these variables is discussed below. 

This approach to estimate net compliance costs is consistent with previous proposed 

power sector regulations that required IRFAs, such as the proposed Mercury and Air Toxics 

Rule.45 However, there is an additional component in the net compliance cost equation: the 

change in the program costs of demand-side energy efficiency programs. Investment in demandside energy efficiency results in lower electricity demand, and consequently fewer emissions as 

production is reduced to meet the lower demand, an important emission-reduction strategy 

modelled in the rate-based and mass-based federal plan approaches. 

Because this analysis evaluates the net compliance costs as a sum of the costs changes 

associated with compliance choices as well as changes in electricity revenues, it captures 

potential net compliance cost increases or decreases. For example, if under the proposed rule 

entities increase revenue more than costs, the net compliance costs will be negative. As a result, 

the approach used here to estimate net compliance costs is well-equipped to evaluate the 

potential distributional consequences of the proposed regulation. 

For this analysis, EPA used the parsed unit-level estimates mentioned before to estimate 

three of the four components of the net compliance cost equation above: the change in operating 

 

45 U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis of the Proposed Toxics 

Rule: Final Report. Office of Air Quality Planning and Standards, Health and Environmental Impacts Division, 

Research Triangle Park, NC. Available at: http://www.epa.gov/ttnecas1/regdata/RIAs/ToxicsRuleRIA.pdf. 

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and annualized capital costs, the change in fuel costs, and the change in revenue, where all 

changes are estimated as the difference between the base case and federal plan scenario. These 

impacts were then summed for each small entity, adjusting for ownership share.46 As described 

momentarily, additional analysis was performed to estimate the change in costs of demand-side 

energy efficiency that factors in IPM-projected outputs but is not directly an output of the model. 

These individual components of compliance cost were estimated as follows: 

1. Operating and capital costs: Using the IPM parsed estimates for the base case and the 

rate-based and mass-based federal plan approaches, EPA evaluated changes in operating 

and capital costs at the EGU level. The equations for calculating operating and capital 

costs were adopted from technology assumptions used in EPA’s version of IPM version 

5.15. The model calculates the capital cost (in $/MW); the fixed operation and 

maintenance (O&M) cost (in $/MW-year); and the variable O&M cost (in $/MWh). 

2. Fuel costs: Using the IPM parsed estimates for the base case and the rate-based and 

mass-based federal plan approaches, EPA evaluated projected changes in fuel cost at the 

EGU level. These projected fuel costs are based on estimated EGU-level fuel input (in 

million British thermal units, MMBtu) and delivered fuel prices ($/MMBtu). 

3. Demand-side energy efficiency program costs: Demand-side energy efficiency 

program costs are estimated and allocated to affected EGUs outside of IPM in this 

analysis. For this analysis, we assumed that IOUs, Co-Ops, Municipals, and SubDivisions are utilities that receive revenues on the basis of retail electricity rates. Retail 

electricity in this and related EPA analyses contain an energy efficiency surcharge. The 

surcharge reflects the standard mechanism by which utilities collect revenue from their 

customers to pay for energy efficiency programs. Such surcharges are approved for 

inclusion in rates by state utility commission for IOUs or the equivalent authority (e.g., 

municipal or cooperative utility board of directors) for other utility types. To be 

consistent, EPA assumes that these utilities will incur an energy efficiency surcharge as a 

cost in this analysis. The demand-side energy efficiency surcharge is state specific, being 

 

46 Unit-level cost impacts are adjusted for ownership shares for individual small entities, so as not to overestimate 

burden on each entity. 

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the estimated state demand-side energy efficiency program costs47 divided by projected 

total state sales. The cost in this analysis is the surcharge multiplied by projected sales 

from affected EGUs.48 In contrast, entities of the type Private are not assessed demandside energy efficiency program costs in this analysis.49 This distinction is made because 

EPA assumes that Private entities own non-utility EGUs that will earn wholesale 

electricity rates. Wholesale electricity rates do not include a demand-side energy 

efficiency surcharge in this or related EPA analyses.

4. Revenues: EPA estimated the value of electricity generated by multiplying the projected 

electricity generation from EPA’s IPM modeling results with the regional retail 

electricity price estimates ($/MWh), for all entities except those categorized as Private in 

Ventyx. For private entities, EPA used projected wholesale electricity price instead of 

retail electricity price estimates because most of the private entities are independent 

power producers (IPP). Since IPPs sell their electricity to wholesale purchasers and do 

not own transmission facilities, their revenue was estimated with wholesale electricity 

prices. 

2.3.4.2 Results 

This section presents the estimated net compliance cost impacts of the proposed rule on 

small entities in 2030 based on the following endpoints: 

• net compliance costs estimated for the proposed rule for potentially affected small 

entities, and 

 

47 In practice, the costs of demand-side energy efficiency programs include the costs to the utilities that are funding 

the programs (known as the program costs) and the additional cost to the end-user purchasing a more energy 

efficient technology (known as the participant costs). Based upon a literature review, the analysis supporting this 

proposed rule and the Clean Power Plan Final Rule, total costs are assumed to be divided evenly, 50 percent each, 

between program costs and participant costs. This IRFA includes only the program costs expected to be incurred 

by utilities. For more detail on how the demand-side energy efficiency costs are estimated, see U.S. EPA. 2015. 

Technical Support Document (TSD) the Final Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units. Demand-Side Energy Efficiency. 

48 For these entity types (i.e., IOUs, Co-Ops, Municipals, and Sub-Divisions), projected sales is estimated to be 7.5 

percent less than generation. This 7.5 percent reduction is added to account for estimated transmission losses. 

49 Note that in this context, “Private” is one of seven distinct ownership types introduced earlier in this chapter. 

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• the ratio of small entity compliance cost impacts to revenues from electricity generation 

at affected EGUs 

It is worth noting again that the results in this section are based on the assumption made 

for this analysis that all affected EGUs owned by small entities are subject to this proposed rule. 

EPA chose to examine this scenario because, at the time of this proposal, the EPA has no 

information on whether any or how many states will require a federal plan. 

The number of affected small entities by ownership type and the potential impact of the 

federal plan approaches are summarized in Tables 2-2 through 2-5. These tables are specific to 

either the rate-based federal plan approach (i.e., rate-based), or mass-based federal plan approach 

(i.e., mass-based). All costs are presented in 2011 dollars. 

EPA estimated the annualized net compliance cost to potentially affected small entities in 

2030 to be approximately $364 million under the rate-based approach, and $404 million under 

the mass-based approach. Results for small entities discussed here do not fully account for the 

reality that electricity markets are regulated in parts of the country. Entities operating in 

regulated or cost-of-service markets are likely able to recover compliance costs through rate 

adjustments; as a result these costs can be viewed as likely being over-estimates for this set of 

utilities.50

 

50This is similarly discussed in previous EPA analyses. For example, see section 7.4.5.2 within the Regulatory 

Impact Analysis for the Final Mercury and Air Toxics Standards. Available at: 

http://www.epa.gov/ttnecas1/regdata/RIAs/matsriafinal.pdf. 

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Table 2-2. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Rate-Based Federal Plan Approach in 2030 

EGU 

Ownership 

Type 

Number of 

Potentially 

Affected Entities 

Number of Entities 

Projected to Withdraw all 

Affected Units in Base Case 

Additional Entities Projected 

to Withdraw all Affected Units 

under Rate-Based Approach 

Co-Op 17 3 1 

IOU 8 3 1 

Municipal 24 13 1 

Private 19 5 2 

Sub-Division 6 0 2 

Grand Total 74 24 7 

Notes: 1) The number of potentially affected entities reflects those with affected EGUs that are modeled within IPM 

in 2030. 2) In this context, the term withdraw signifies that EGUs are represented in the 2030 IPM results but do not 

generate electricity. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

Table 2-3. Projected Impact on Small Entities in 2030 under Rate-Based Federal Plan 

Approach 

EGU 

Ownership 

Type

Total Net 

Compliance Costs 

(2011$ millions) 

Number of Small Entities 

with Net Compliance Costs 

> 1% of Generation 

Revenues 

Number of Small Entities 

with Net Compliance Costs 

> 3% of Generation 

Revenues 

Co-Op 109 8 3 

IOU 186 4 4 

Municipal 17 7 5 

Private 34 11 9 

Sub-Division 18 6 2 

Grand Total 364 36 23 

Notes: 1) The total number of entities with costs greater than 1 or 3 percent of revenues includes only entities 

experiencing positive net compliance costs. 2) Costs are compared to generation revenues from affected EGUs, and 

do not consider additional revenues some entities may earn from other sources. 3) Nine small entities are estimated 

to have net compliance cost savings greater than 3 percent of generation revenues from affected sources. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

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Table 2-4. Number of Affected Small Entities in the Base Case, and Projected Impact 

under the Mass-Based Federal Plan Approach in 2030 

EGU 

Ownership 

Type 

Number of 

Potentially 

Affected Entities 

Number of Entities 

Projected to Withdraw all 

Affected Units in Base Case 

Additional Entities Projected 

to Withdraw all Affected 

Units under Mass-Based 

Approach 

Co-Op 17 3 1 

IOU 8 3 1 

Municipal 24 13 1 

Private 19 5 2 

Sub-Division 6 0 0 

Grand Total 74 24 5 

Notes: 1) The number of potentially affected entities reflects those with affected EGUs that are modeled within IPM 

in 2030. 2) In this context, the term withdraw signifies that EGUs are represented in the 2030 IPM results but do not 

generate electricity. 

Source: U.S. EPA analysis, based on IPM modeling results. 

Table 2-5. Projected Impact on Small Entities in 2030 under Mass-Based Federal Plan 

Approach 

EGU 

Ownership 

Type 

Total Net 

Compliance Costs 

(2011$ millions) 

Number of Small Entities 

with Net Compliance Costs 

> 1% of Generation 

Revenues 

Number of Small Entities 

with Net Compliance Costs 

> 3% of Generation 

Revenues 

Co-Op 133 10 4 

IOU 179 3 3 

Municipal 50 5 5 

Private 36 8 7 

Sub-Division 7 4 2 

Grand Total 404 30 21 

Notes: 1) The total number of entities with costs greater than 1 or 3 percent of revenues includes only entities 

experiencing positive net compliance costs. 2) Costs are compared to generation revenues from affected EGUs, and 

do not consider additional revenues some entities may earn from other sources. 3) Eleven small entities are 

estimated to have net compliance cost savings greater than 3 percent of generation revenues from affected sources. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

As noted earlier, there are 74 small entities with potentially affected EGUs that are 

modeled in the IPM base case in 2030. Of these, 24 small entities are projected to withdraw all of 

their potentially affected EGUs from operation under base case conditions. This leaves 50 small 

entities with potentially affected EGUs that are projected to be generating electricity in 2030. 

Under the rate-based federal plan approach, 7 of these 50 small entities are projected to withdraw 

all of their potentially affected EGUs from operation by 2030. Under the mass-based federal plan 

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approach, 5 of these 50 small entities are projected withdraw all of their potentially affected 

EGUs from operation by 2030. 

Under the rate-based federal plan approach, 23 small entities are projected to incur net 

compliance costs greater than 3 percent of generation revenues from their potentially affected 

EGUs. In contrast, 9 entities are estimated to have net compliance cost savings greater than 3 

percent of their generation revenues from affected EGUs. Under the mass-based federal plan 

approach, 21 small entities are projected to incur net compliance costs greater than 3 percent of 

generation revenues from their potentially affected EGUs. In contrast, 11 entities are estimated to 

have net compliance cost savings greater than 3 percent of generation revenues from their 

affected EGUs. 

The separate components of the net compliance costs for small entities under the 

proposed rule are summarized in Table 2-6 and Table 2-7. 

Table 2-6. Incremental Costs in 2030 under the Rate-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) 

EGU 

Ownership 

Type 

Capital + 

Operating + Fuel 

Costs ($MM) 

Energy Efficiency 

Program Costs 

($MM) 

Change in 

Electricity 

Revenue ($MM) 

Total Net 

Compliance 

Costs 

 A B C =A+B-C 

Co-Op (79) 87 (102) 109 

IOU 78 93 (15) 186 

Municipal (26) 25 (19) 17 

Private (7) 0 (40) 34 

Sub-Division (68) 16 (70) 18 

Grand Total (102) 221 (246) 364 

Note: Totals may not add due to rounding. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

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Table 2-7. Incremental Costs in 2030 under the Mass-based Federal Plan Approach 

Summarized by Ownership Group and Cost Category in 2030 (2011$ millions) 

EGU 

Ownership 

Type 

Capital + 

Operating + Fuel 

Costs ($MM) 

Energy Efficiency 

Program Costs 

($MM) 

Change in 

Electricity 

Revenue ($MM) 

Total Net 

Compliance 

Costs 

 A B C =A+B-C 

Co-Op (178) 84 (228) 133 

IOU (17) 91 (104) 179 

Municipal (64) 23 (91) 50 

Private (2) 0 (38) 36 

Sub-Division (38) 18 (27) 7 

Grand Total (299) 215 (488) 404 

Note: Totals may not add due to rounding. 

Source: U.S. EPA analysis, based on EPA’s IPM v.5.15 modeling results. 

The change in electricity revenue under the federal plan approaches take into account 

both the profit lost from units that do not operate and the difference in revenue for operating 

units. The cost of withdrawing a unit as uneconomic is estimated as the base case profit that is 

foregone by not operating under a federal plan approach. One of the primary drivers of the cost 

impacts is the reduced revenue due to decreased electricity sales related to the modeled 

implementation of demand-side energy efficiency measures. The EPA solicits comment on: 1) 

whether it is likely that small entities would consider demand-side strategies as they responded to 

a federal plan, 2) the appropriateness of considering the demand-side strategies in the analysis, 

and 3) if demand-side energy efficiency measures are considered in the final analysis, whether it 

is appropriate to consider them as a cost for a municipality or city-owned utility, as this reduced 

revenue will translate to direct cost savings for members of the community served by the 

affected units. 

There are uncertainties and limitations in this analysis that may result in estimates that 

diverge from what we might see in reality. Some of these have already been noted. Below is a 

listing of important considerations when interpreting this analysis. 

• At the time of this proposal, the EPA has no information on whether any or how 

many states will require a federal plan. The rate-based and mass-based federal 

plan approaches analyzed in this IRFA are based on a scenario where all states of 

the contiguous U.S. will be regulated under a federal plan. 

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• Results for small entities discussed here do not fully account for the reality that 

electricity markets are regulated in parts of the country. Entities operating in 

regulated or cost-of-service markets are likely able to recover compliance costs 

through rate adjustments; as a result these costs can be viewed as likely being 

over-estimates for this set of utilities. 

• Small entities owning NGCC EGUs operating in competitive markets may be able 

to recover compliance costs if steam EGUs are setting the marginal price. 

• EPA has not factored in consideration of allowances that would be distributed to 

affected entities nor revenue that could be generated from the sale of ERCs in its 

analysis. EPA takes comment on how these factors should be considered in the 

final analysis. 

• In this analysis, estimated state demand-side energy efficiency program costs are 

allocated to utility EGUs owned by IOUs, Co-Ops, Municipals, and SubDivisions based on the share of forecasted total state electricity sales that they are 

projected to provide. To the extent that this differs in practice, associated costs 

incurred by small entities may be over- or under-estimated. 

• To the extent that the EGU owner information used is not reflective of reality, the 

number of small entities may be over- or under-estimated. 

• To the extent that the entity-level ownership information (i.e., NAICS code, 

number of employees, revenues, and assets) are not reflective of reality, the 

number of small entities may be over- or under-estimated. 

2.3.5 Projected Reporting, Recordkeeping and Other Compliance Requirements 

The reporting, recordkeeping and other compliance requirements are most likely covered 

under Part 75 and Part 98 programs for affected EGUs. Therefore, only a marginal additional 

cost is expected for the monitoring, reporting and recordkeeping requirements of the proposed 

federal plan for affected EGUs. 

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2.3.6 Related Federal Rules 

On September 20, 2013, EPA proposed carbon pollution standards for new fossil fuel 

fired EGUs. On June 2, 2014, the EPA, proposed carbon pollution standards for modified and 

reconstructed fossil fuel fired EGUs, in addition to the Clean Power Plan EGs, to cut carbon 

pollution from existing fossil fuel fired EGUs. These existing EGUs are, or will be, potentially 

impacted by several other recently finalized EPA rules. On February 16, 2012, the EPA issued 

the mercury and air toxics standards (MATS) rule (77 FR 9304) to reduce emissions of toxic air 

pollutants from new and existing coal- and oil-fired EGUs. On May 19, 2014, the EPA issued a 

final rule under section 316(b) of the Clean Water Act (33 U.S.C. 1326(b)). This rule establishes 

new standards to reduce injury and death of fish and other aquatic life caused by cooling water 

intake structures at existing power plants and manufacturing facilities. On June 18, 2014 (79 FR 

34830), the EPA promulgated the stream electric effluent limitation guidelines (SE ELG) rule to 

strengthen the controls on discharges from certain steam electric power plants. On April 17, 2015 

(80 FR 21302), the EPA promulgated the coal combustion residuals (CCR) rule, which 

establishes technical requirements for CCR landfills and surface impoundments under subtitle D 

of the Resource Conservation and Recovery Act (RCRA), the nation's primary law for regulating 

solid waste. 

2.3.7 Regulatory Flexibility Alternatives 

2.3.7.1 Panel Process 

Small Entity Representatives (SERs) commented on their perceptions of the adequacy of 

the SBREFA panel process for the section 111(d) federal plan. Under the statute, EPA provides 

“information on the potential impacts of the proposed rule on small entities and the type of small 

entities that might be affected.” § 609(b)(1). Then SERs are selected, and the Panel collects 

“advice and recommendations” from each SER. § 609(b)(4). The Panel reviews the SERs’ 

comments, and “any material the agency has prepared in connection with [the RFA],” and 

“report[s] on the comments of the [SERs] and its findings as to issues related to” preparation of 

an IRFA. § 609(b)(5). EPA solicited SERs comments during the course of, and after holding 

three outreach meetings. The Agency provided information to the SERs on two primary 

regulatory alternatives for the federal plan – a rate-based trading program and a mass-based 

trading program. The Agency identified specific areas under both of these alternatives where it 

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was still in the decision making process and open to recommendations. This information forms 

the basis for consideration of issues and additional regulatory options important to these small 

entities. 

Advocacy shares many of the concerns raised by the SERs (see attached letter from 

Acting Chief Counsel Claudia Rodgers to EPA Administrator Gina McCarthy). While Advocacy 

endorses the Panel recommendations, Advocacy agrees that the SERs did not have sufficient 

information to inform advice and recommendations about specific regulatory alternatives and 

flexibilities. In Advocacy’s view, this is reflected in Panel recommendations that advise EPA to 

consider issues raised by the SERs rather than to propose or consider regulatory alternatives. 

Advocacy regrets that the Panel is not able to make more specific recommendations for 

flexibilities to minimize the impacts on small entities. 

While not all members of the Panel agree with all of these concerns, the concerns of the 

SERs regarding the Panel process have been noted. Nonetheless, EPA is committed to ensuring 

that it meets the requirements of the RFA and will, to the maximum extent practicable, fully 

consider the advice and recommendations of representatives of small entities in the development 

of the proposed rule. The EPA intends to continue working on issues regarding small businesses, 

and consider appropriate flexibilities, throughout this rulemaking process. 

2.3.7.2 Remaining Useful Life 

SERs commented that EPA needed to account for remaining useful life of EGUs. 

Multiple comments addressed challenges that EPA must face in satisfying the statutory mandate 

that “in applying a standard of performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other factors, the remaining useful life of 

the existing sources to which such standard applies.” SERs are concerned that EPA will develop 

EGs under section 111(d) in a manner that either prohibits plans from providing this 

consideration or only providing for plans to “make these adjustments at the expense of other 

sources.” AEPCO comments that it has obligations under the Rural Electrification Act to operate 

under an 80-year mandate. SBA recommends EPA propose allowing for guaranteed amount of 

run-time for small entities to allow them to recoup investment. EPA believes “remaining useful 

life” is a concern directed toward plants with short remaining lives, but recognizes that there are 

concerns about economic viability of some marginal plants. 

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The Panel recommends that EPA clearly explain how it took into consideration remaining 

useful life and take comment on other ways of defining the remaining useful life consideration. 

The Panel also recommends proposing or considering economic incentives for compliance that 

could avoid early retirement or reduce the financial effects of early retirements. For instance, the 

EPA could propose continuing allocations for a set number of years to units that retire in order to 

alleviate the financial effects of the retirement. EPA should request comment on how long such 

allocations should continue. The EPA should also consider whether there are parallel 

mechanisms in a rate-based proposal that could provide similar regulatory relief or benefits for 

small entities, if appropriate. 

2.3.7.3 Design of the Compliance System 

The panel requested SER input on a number of aspects of the federal plan design, based 

on EPA’s presentation of federal plan options. SER comments ranged quite broadly. Comments 

included: 1) differing opinions within SERs on favor of rate- vs mass-based approaches, 2) 

emphasis on market liquidity in a program, 3) support for types of allocation methodologies (in a 

mass-based allowance system), 4) encouragement for early action crediting, 5) increased 

averaging and compliance times to help small entities, and 6) whether and how to consider the 

effects of credit/allowance banking, borrowing, and shelf-life on market liquidity. In some 

instances, no general consensus emerged. The Panel notes the following specific areas where it is 

making a recommendation. 

Mass-based or rate-based trading 

Various SERs favored one system over the other, and some suggested that each 

individual small entity should be able to choose the system under which they would comply. 

However, it is unclear to what extent SERs would favor such choice at the expense of a broader 

trading pool. The panel, however, notes that the idea of individual companies within a state 

choosing which system to comply would significantly limit the opportunity for intra- or interstate trading and would therefore not be consistent with other recommendations. The Panel 

recommends that EPA take comment on which approach (mass or rate) is preferable. In the 

interests of maximizing liquidity across all federal plan states, the Panel recommends that EPA 

should propose to finalize a single approach for all federal plans. 

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Allocations and credit issuance/early action 

SERs expressed a variety of views on the appropriate method of allocating allowances 

under a mass-based system or credits under a rate-based system. Some preferred allowing states 

to make these decisions. Some wanted allocations to account for early action and energy 

efficiency efforts. The Panel agrees that EPA should take comment on the use of allocations to 

minimize the impact of the federal plan on small entities. The Panel notes that the early incentive 

pool that is part of the EGs does provide credit for early action, but the SERs did not have an 

opportunity to respond to this flexibility. The panel recommends that in the federal plan the EPA 

allow credit for early action and energy efficiency efforts to the extent it is allowed under the 

guidelines. 

Non-generating party participation and market liquidity 

SERs generally supported developing a system that would ensure a sufficient supply of 

credits be available on the open market and available for free trade to ensure that they would not 

be disadvantaged by large utilities withholding excess credits generated by renewable energy in 

their portfolio. However, some SERs also expressed the need to be able to generate and use 

credits internally (particularly those with generation across multiple states) (i.e., a portfolio 

approach). Some SERs endorsed allowing non-generating parties to create and sell credits or 

allowances. Other SERs warned that third parties should not be allowed to purchase credits or 

allowances for the purpose of retiring them without offsetting GHG emissions from electricity 

generation. The Panel recommends that the EPA ensure a liquid market in compliance 

instruments, through consideration, request or comment, or proposal of several of options, 

including: allocation methods or rules that could impact liquidity, mechanisms to place 

allowances or credits into the market relatively early, requirements for public transparency of 

information related to allowance or credit issuance, tracking, transfers, and holdings, and 

whether and to what extent oversight authority exists related to measures to ensure liquid 

markets Additionally, the Panel recommends that EPA solicit comment on other approaches to 

ensure liquidity, including but not limited to the concept of an early incentive pool which would 

serve to incentivize early reductions and create a market of additional allowances. 

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2.3.7.4 Renewable Energy and Energy Efficiency 

Generally SERs encouraged EPA to incorporate existing EE efforts into the program in a 

way that gives credit for the investment and to rely on “deemed” energy savings to earn 

compliance credits. SERs raised concerns about the accounting of investments in RE and EE 

efforts in their compliance with GHG emission standards. 

SERs also expressed concern that they be able to generate and use credits across state 

lines. This is particularly important for the investment in renewables, for which the generating 

potential is highly dependent on geography and is unequally distributed among the states. Thus, 

the Panel recommends that EPA develop a credit or allowance compliance program that allows 

for interstate accounting and trading for states under the federal plan. Additionally, the Panel 

recommends that the program include opportunities for interstate trading between sources in 

states under the federal plan and states under compatible state plans. 

The Panel recommends that EPA consider the treatment of RE and EE in rate-based and 

mass-based federal plan contexts. EPA should further consider how to implement preferred 

policy options in a way that incentivizes investment and does not create unintended barriers for 

small entities. The Panel also recommends that EPA allow crediting of RE across states under 

the federal plan while soliciting comment for allowing crediting for EE across states under the 

federal plan. 

2.3.7.5 Reliability 

Multiple SERs expressed concerns that implementation of the EGs, either by states or 

through a federal plan, could have a negative impact on reliability because individual units could 

have operational obligations that conflict with the emissions requirements. In their comments, 

both the American Public Power Association (APPA) and the National Rural Electric 

Cooperative Association (NRECA) recommend Dynamic Reliability Safety Valve. EPA noted 

that the use of a reliability mechanism in the EGs is provisioned on the concern that some forms 

of state plan may create inflexible requirements that could in some limited circumstances raise a 

reliability concern. However, EPA believes the design of the federal plan as a flexible trading 

program alleviates these concerns and therefore a reliability mechanism is not needed. 

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The Panel recognizes the connection between meeting the GHG reduction goals of the 

federal plan and maintaining the reliability of the electric grid. The Panel recommends that EPA 

fully explain in the proposal and take comment on methods to address reliability and EPA should 

take comment on establishing a reliability safety valve, and whether there is a need for regulatory 

flexibility for reliability critical units beyond the flexibilities already built into the design of the 

federal plan. 

2.3.7.6 Subcategorization/Applicability/Exemptions 

SER comments on applicability reflect concerns related to the combined series of 

rulemakings affecting GHG emissions from electricity generating units: the NSPS, the EGs and 

the federal plan. SERs endorse excluding RICE and NGSC units from the combined 

rulemakings. One SER requests a subcategory that addresses the particular characteristics of 

lignite coal. Some SERs suggest special provisions for small units or utilities, including a small 

system exemption. The SBA suggested taking comment on an economic hardship exemption for 

small entities and that EPA propose a mechanism for additional compliance time when 

generation and transmission investments necessary for compliance have been delayed by 

government reviews. However, EPA noted that regulatory exemptions must be grounded in 

statute and supported by analysis, and EPA believes the design of the federal plan itself should 

maximize compliance options that are both consistent with the EGs and also should adequately 

address these concerns. 

The Panel notes that EPA must be consistent with the EGs on issues of applicability, 

which should address the SERs’ concerns with regard to inclusion of RICE or NGSC units. The 

Panel also notes that EPA is proposing a design to the federal plan that utilizes emission trading 

and thus maximizes compliance options such that individual units can take into account their 

particular characteristics in designing a compliance strategy. In EPA’s view, this makes it less 

likely that there is a need for further sub-categorization or the use of unit-specific exemptions. 

Additionally, the Panel recommends that EPA solicit comment on an alternative allocation 

methodology under the mass-based proposed federal plan that may increase allocations for small 

businesses, and consider whether there are parallel mechanisms in a rate-based proposal that 

could provide similar regulatory relief or benefits for small entities, if appropriate. 

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2.4 Unfunded Mandates Reform Act (UMRA) 

This action contains a federal mandate under UMRA, 2 U.S.C. 1531-1538, that could 

potentially result in expenditures of $100 million or more for state, local, and tribal governments, 

in the aggregate, or the private sector in any one year. This federal plan will apply only to those 

EGUs located in states that do not submit approvable state plans, which is a subset of the EGUs 

considered in the RIA for the final emission guidelines (EGs). Because it is impossible to 

determine at this time which states might be ultimately subject to a federal plan, EPA cannot 

determine whether this final rule will be subject to UMRA. However, as noted below, the 

Agency has done substantial outreach to government entities as part of both the federal plan and 

the related 111(d) rulemaking. Further, regardless of whether EPA does determine that this 

action ultimately meets the UMRA threshold, the agency intends to do additional outreach with 

government entities between now and the final rule. Additionally, the EPA has determined that 

this action is not subject to the requirements of section 203 of UMRA because it contains no 

regulatory requirements that might significantly or uniquely affect small governments. 

Nevertheless, the EPA is aware that there is substantial interest in this rule among small 

entities (e.g., municipal and rural electric cooperatives). In light of this interest, prior to this 

action, the EPA sought early input from representatives of small entities while formulating the 

provisions of the proposed regulation. Such outreach is also consistent with the President’s 

January 18, 2011 Memorandum on Regulatory Flexibility, Small Business, and Job Creation, 

which emphasizes the important role small businesses play in the American economy. This 

outreach process has enabled the EPA to hear directly from these representatives, as EPA 

developed the rule about how the EPA should approach the complex question of how to apply 

section 111 of the CAA to the regulation of GHGs from these source categories. We invite 

comments on all aspects of this proposal and its impacts, including potential adverse impacts, on 

small entities. 

2.5 Executive Order 13132: Federalism 

The EPA believes that this proposed rule may be of significant interest to state and local 

governments due to its relationship with the Clean Power Plan EGs. Therefore, the EPA has 

determined that consultations with state and local governments conducted during the Clean 

Power Plan EGs development process are also relevant to this proposed rule. Consistent with the 

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EPA’s policy to promote communications between the EPA and state and local governments, the 

EPA consulted with state and local officials early in the process of developing the Clean Power 

Plan EGs to permit them to have meaningful and timely input into its development. As described 

in the Federalism discussion in the preamble to the proposed standards of performance for GHG 

emissions from new EGUs (79 FR 1501; January 8, 2014), the EPA consulted with state and 

local officials in the process of developing the proposed standards for newly constructed EGUs. 

A detailed Federalism Summary Impact Statement (FSIS) describing the most pressing issues 

raised in pre-proposal and post-proposal comments will be forthcoming with the final Clean 

Power Plan EGs, as required by section 6(b) of Executive Order 13132. In the spirit of Executive 

Order 13132, and consistent with the EPA’s policy to promote communications between the 

EPA and state and local governments, the EPA specifically solicits comment on this proposed 

action from state and local officials. 

2.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments 

 This proposed action has tribal implications. However, it will neither impose substantial 

direct compliance costs on federally recognized tribal governments, nor preempt tribal law. The 

EGU potentially impacted by this proposed rulemaking located on Indian reservations are 

primarily owned by private entities, and in one case, partially owned by an agency of the U.S. 

government. As a result, the tribes on whose areas of Indian country those units are located will 

not be directly impacted by any costs of complying with this proposed rulemaking incurred by 

the owners/operators of those units. There would only be tribal implications in regards to 

compliance costs associated with this proposed rulemaking in the case where a tribal government 

has an ownership interest in a potentially affected EGU. A tribal government could also incur 

costs in the event that it seeks and is given delegated authority to enforce the federal plan 

proposed in this rulemaking. The EPA has, nevertheless, offered consultation to the tribes on 

whose areas of Indian country the units are located. As part of its general outreach to tribes 

regarding this proposed rulemaking, the EPA received feedback from a number of tribes 

regarding the potential overall economic impact that both the proposed Clean Power Plan and a 

proposed federal plan rulemaking may have on them. In these instances, the EPA has reached out 

to these tribes and as part of the consultation on the Clean Power Plan engaged with them on 

their concerns regarding a potential federal plan. 

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The EPA has conducted consultation with tribes on the Clean Power Plan and the 

Supplemental Proposal for the Clean Power Plan and will offer all tribes consultation on this 

proposed action. The EPA held consultations with tribes on the Clean Power Plan in the fall of 

2014 before the agency issued its Supplemental Proposal for Indian Country and U.S. Territories. 

Additionally, the EPA held consultations for tribes shortly following the release of the 

supplemental proposal. The agency also held a public hearing on the supplemental proposal on 

November 19, 2014, in Phoenix, Arizona. At the public hearing the agency received oral 

comments from community members representing a number of tribes and a number of tribal 

officials. The agency also conducted consultation with tribes in the spring and summer of 2015. 

An overview of the consultations provided as part of the Clean Power Plan is available in section 

XII.F of the final EGs. 

Additionally, the EPA engaged in meaningful dialogue with tribal stakeholders to obtain 

their feedback in the pre-proposal stages of this rulemaking. We provided an update on this 

proposed rulemaking on the May 28, 2015, National Tribal Air Association and the EPA Air 

Policy call. Additionally, staff attended the National Tribal Forum conference on May 20, 2015 

and provided an overview of the Clean Power Plan and explained that the agency would be 

proposing a federal plan. 

Consistent with previous rulemakings impacting the power sector, there is significant 

tribal interest in these rulemakings because of the potential indirect impacts that rules such as the 

Clean Power Plan and this proposed federal plan may have on tribes. The EPA specifically 

solicits additional feedback from tribal officials on all aspects of this proposed rulemaking, 

including whether tribes whose areas of Indian country contain affected EGU(s) are interested in 

developing their own plan implementing the final EGs. Additionally, tribal stakeholders will be 

included in the outreach that the agency will be conducting with those communities already 

overburdened by pollution, which are often low-income communities, communities of color, and 

indigenous communities. The actions that the agency will be taking are outlined in section IX of 

the preamble. 

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2.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks 

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those 

regulatory actions that concern health or safety risks, such that the analysis required under 

section 5–501 of the Order has the potential to influence the regulation. This action is not subject 

to EO 13045 because it does not involve decisions on environmental health or safety risks that 

may disproportionately affect children. The EPA believes that the CO2 emission reductions 

resulting from implementation of the proposed guidelines, as well as substantial ozone and 

PM2.5 emission reductions as a cobenefit, would further improve children’s health. 

2.8 Executive Order 13211: Actions That Significantly Affect Energy Supply, 

Distribution, or Use 

This action, which is a significant regulatory action under EO 12866, is likely to have a 

significant effect on the supply, distribution, or use of energy. The EPA has prepared a Statement 

of Energy Effects for this action as follows. We estimate a 1 to 2 percent change in retail 

electricity prices on average across the contiguous U.S. in 2025, and a 22 to 23 percent reduction 

in coal-fired electricity generation as a result of this rule. The EPA projects that utility power 

sector delivered natural gas prices will increase by up to 2.5 percent in 2030. For more 

information on the estimated energy effects, please refer to the economic impact analysis for this 

proposal in Chapter 1 of this RIA. 

2.9 National Technology Transfer and Advancement Act (NTTAA) 

This proposed action does not involve technical standards. 

2.10 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations 

Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive 

policy on EJ. Its main provision directs federal agencies, to the greatest extent practicable and 

permitted by law, to make EJ part of their mission by identifying and addressing, as appropriate, 

disproportionately high and adverse human health or environmental effects of their programs, 

policies, and activities on minority populations and low-income populations in the U.S. The EPA 

defines EJ as the fair treatment and meaningful involvement of all people regardless of race, 

color, national origin, or income with respect to the development, implementation, and 

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enforcement of environmental laws, regulations, and policies. The EPA has this goal for all 

communities and persons across this Nation. It will be achieved when everyone enjoys the same 

degree of protection from environmental and health hazards and equal access to the decisionmaking process to have a healthy environment in which to live, learn, and work. 

Leading up to this rulemaking the EPA summarized the public health and welfare effects 

of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment Finding, the 

Administrator considered climate change risks to minority populations and low-income 

populations, finding that certain parts of the population may be especially vulnerable based on 

their characteristics or circumstances. Populations that were found to be particularly vulnerable 

to climate change risks include the poor, the elderly, the very young, those already in poor 

health, the disabled, those living alone, and/or indigenous populations dependent on one or a few 

resources. See sections X.F and X.G of the preamble where the EPA discusses Consultation and 

Coordination with Tribal Governments and Protection of Children. The Administrator placed 

weight on the fact that certain groups, including children, the elderly, and the poor, are most 

vulnerable to climate-related health effects. 

The record for the 2009 Endangerment Finding summarizes the strong scientific evidence 

in the major assessment reports by the U.S. Global Change Research Program, the 

Intergovernmental Panel on Climate Change (IPCC), and the National Research Council of the 

National Academies that the potential impacts of climate change raise EJ issues. These reports 

concluded that poor communities can be especially vulnerable to climate change impacts because 

they tend to have more limited adaptive capacities and are more dependent on climate-sensitive 

resources such as local water and food supplies. In addition, Native American tribal communities 

possess unique vulnerabilities to climate change, particularly those impacted by degradation of 

natural and cultural resources within established reservation boundaries and threats to traditional 

subsistence lifestyles. Tribal communities whose health, economic well-being, and cultural 

traditions that depend upon the natural environment will likely be affected by the degradation of 

ecosystem goods and services associated with climate change. The 2009 Endangerment Finding 

record also specifically noted that Southwest native cultures are especially vulnerable to water 

quality and availability impacts. Native Alaskan communities are already experiencing 

disruptive impacts, including coastal erosion and shifts in the range or abundance of wild species 

crucial to their livelihoods and well-being. 

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The most recent assessments continue to strengthen scientific understanding of climate 

change risks to minority populations and low-income populations in the U.S.51 The new 

assessment literature provides more detailed findings regarding these populations’ vulnerabilities 

and projected impacts they may experience. In addition, the most recent assessment reports 

provide new information on how some communities of color may be uniquely vulnerable to 

climate change health impacts in the U.S. These reports find that certain climate change related 

impacts—including heat waves, degraded air quality, and extreme weather events—have 

disproportionate effects on low-income populations and some communities of color (in 

particular, populations defined jointly by ethnic/racial characteristics and geographic location), 

raising EJ concerns. Existing health disparities and other inequities in these communities 

increase their vulnerability to the health effects of climate change. In addition, assessment 

reports also find that climate change poses particular threats to health, well-being, and ways of 

life of indigenous peoples in the U.S. 

As the scientific literature presented above and as the 2009 Endangerment Finding 

illustrates, low income populations and some communities of color are especially vulnerable to 

the health and other adverse impacts of climate change. The EPA believes that communities will 

benefit from this proposed federal plan because this action directly addresses the impacts of 

climate change by limiting GHG emissions through the establishment of CO2 emission standards 

for existing affected fossil fuel-fired EGUs. 

In addition to reducing CO2 emissions, the guidelines finalized in this rulemaking would 

reduce other emissions from affected EGUs that reduce generation due to higher adoption of EE 

 

51 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United 

States: The Third National Climate Assessment. U.S. Global Change Research Program, 841 pp. 

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects.

Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate 

Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, 1132 pp. 

 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects. 

Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate 

Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, 688 pp.

519
2-35 

and RE. These emission reductions will include SO2 and NOx, which form ambient PM2.5 and 

ozone in the atmosphere, and HAP, such as mercury and hydrochloric acid. In the final rule 

revising the annual PM2.5 NAAQS,52 the EPA identified low-income populations as being a 

vulnerable population for experiencing adverse health effects related to PM exposures. Lowincome populations have been generally found to have a higher prevalence of pre-existing 

diseases, limited access to medical treatment, and increased nutritional deficiencies, which can 

increase this population’s susceptibility to PM-related effects.53 In areas where this rulemaking 

reduces exposure to PM2.5, ozone, and methylmercury, low-income populations will also benefit 

from such emissions reductions. Chapter 1 of this RIA provides additional information regarding 

the health and ecosystem effects associated with these emission reductions. 

Additionally, as outlined in the community and EJ considerations section IX of the 

preamble, the EPA has taken a number of actions to help ensure that this action will not have 

potential disproportionately high and adverse human health or environmental effects on 

vulnerable communities. The EPA consulted its May 2015, Guidance on Considering 

Environmental Justice During the Development of Regulatory Actions, when determining what 

actions to take.54 As described in the community and EJ considerations section of the preamble 

the EPA also conducted a proximity analysis, which is available in the docket of this rulemaking 

and is discussed in section IX of the preamble. Additionally, as outlined in sections I and IX of 

the preamble the EPA has engaged meaningfully with communities throughout the development 

of the CPP and has devised a robust outreach strategy for continual engagement throughout this 

rulemaking.

 

52 “National Ambient Air Quality Standards for Particulate Matter, Final Rule,” 78 FR 3086 (Jan. 15, 2013). 

53 U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for Particulate Matter 

(Final Report). EPA-600-R-08-139F. National Center for Environmental Assessment – RTP Division. December. 

Available on the Internet at http://www.cfpub.epa.gov/si/si_public_record_Report.cfm?dirEntryId=216546. 

54 Guidance on Considering Environmental Justice During the Development of Regulatory Actions. 

http://www.epa.gov/environmentaljustice/resources/policy/considering-ej-in-rulemaking-guide-final.pdf. May 

2015. 

520
United States 

Environmental 

Protection Agency 

Office of Air Quality Planning and Standards 

Health and Environmental Impacts Division 

Research Triangle Park, NC 

Publication No. 

EPA-452/R-15-006 

August 2015

521
Attachment T.

522
From: Frey, Nathan J. <Nathan_J._Frey@omb.eop.gov>

Sent: Saturday, August 1, 2015 5:15 PM

To: Jones, Toni; Szabo, Aaron

Cc: Harvey, Reid; Tsirigotis, Peter; Eck, Janet; Cozzie, David; Culligan, Kevin

Subject: RE: EO 12866 CPP Federal Plan

  

Please have the final CLEAN versions of the rule document and RIA uploaded to ROCIS in the appropriate

places.

Please upload the rule under “primary documents” and RIA under “supplementary documents.”

Thanks very much.

Nathan

From: Jones, Toni [mailto:Jones.Toni@epa.gov]  

Sent: Saturday, August 01, 2015 4:45 PM

To: Frey, Nathan J. <Nathan_J._Frey@omb.eop.gov>; Szabo, Aaron <Aaron_L_Szabo@omb.eop.gov>

Cc: Harvey, Reid <Harvey.Reid@epa.gov>; Tsirigotis, Peter <Tsirigotis.Peter@epa.gov>; Eck, Janet

<Eck.Janet@epa.gov>; Cozzie, David <Cozzie.David@epa.gov>; Culligan, Kevin

<Culligan.Kevin@epa.gov>

Subject: EO 12866 CPP Federal Plan  

Importance: High

 

Hi Nathan and Aaron,

Attached please find the final, clean versions of the CPP Federal Plan preamble and rule.  Additionally,

attached is a redline version of both files (indicated by “RLSO” in the file name) that reflect changes

made to the package since the initial submittal to OMB.  Also attached is the final RIA.

Please let know if you have any questions.

It’s been a pleasure working with both of you!

Kind regards,

Toni

Toni Wyche Jones, EI, CFM | Fuels & Incineration Group | Sector Policies & Programs Division - Mail Code E143-

05 | Office of Air Quality Planning & Standards | U.S. Environmental Protection Agency | RTP, NC 27711 | Phone: 

(919) 541-0316 |

523
Attachment U.

524
From: Frey, Nathan J. <Nathan_J._Frey@omb.eop.gov>

Sent: Sunday, August 2, 2015 10:37 AM

To: Culligan, Kevin; McCabe, Janet; Tsirigotis, Peter; Harvey, Reid; Vasu, Amy; Hutson, Nick; Fruh, Steve;

Jones, Toni

Cc: Shelanski, Howard; Mancini, Dominic J.

Subject: Concluding Review Under EO 12866 and 13563 ‐‐ Clean Power Plan Rules

  

Hello everyone,

  

I am writing to inform you that OIRA has officially concluded its review under EO 12866 and 13563 of

the following three EPA rules:

  

2060‐AQ91          Standards of Performance for Greenhouse Gas Emissions From New, Modified, and

Reconstructed Stationary Sources: Electric Utility Generating Units

2060‐AR33           Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility

Generating Units    

2060‐AS47           Federal Plan for Regulating Greenhouse Gas Emissions From Electric Generating Units

Thank you to everyone and your teams for a tremendous job well done on these important rules.

  

All the best,

  

Nathan                                                 

525