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UNITED STATES COURT OF APPEALSUNITED STATES COURT OF APPEALS FOR DISTRICT OF COW1A C1RCUfl

FOR OISTRL I OF COLUMBIA CIROIJ1T --

_________

rAUG 152014 L 5Z0

RECEIVED

___

CLERK

IN THE UMTED STATES CouRT OF APPEALS

FOR TIlE DISTRICT OF COLUMBIA CIRcuIT

MURRAY ENERGY CORPORATION,

Petitioner,

CaseNo. i1115t

UNITED STATES ENVIRONMENTALPROTECTION AGENCY and REGINAA. McCARTHY, Administrator, U.S.Environmental Protection Agency,

Respondents.

PETITION FOR JUDICIAL REVIEW

Pursuant to Rule 15 of the Federal Rules of Appellate Procedure and

Section 307(b)(1) of the Clean Air Act, 42 U.S.C. §7607(b)(1), Murray Energy

Corporation hereby petitions the Court for review of a final action of

Respondents—the United States Environmental Protection Agency, and Gina

A. McCarthy, Administrator, U.S. Environmental Protection Agency—

initiating a rulemaking without authority and in violation of the Clean Air Act

by publishing a notice of proposed rulemaking entitled “Carbon Pollution

Emission Guidelines for Existing Stationary Sources: Electric Utility

Generating Units” in the Federal Register on June 18, 2014. 79 Fed. Reg. 34,830

(June 18, 2014) (attached hereto).

USCA Case #14-1151 Document #1508071 Filed: 08/15/2014 of 139

EPA’s action is final for purposes of this limited challenge asserting the

absence of authority to initiate the rulemaking. See Dow Chemical USA v. EPA,

491 F. Supp. 428, 43 1—32 (M.D.L.A. 1980) (granting EPA’s motion to dismiss

a challenge to EPA’s authority to initiate a rulemaking because this Court had

exclusive jurisdiction to review EPA’s “final action” of issuing a proposed rule

“even though the proposed regulations may, after comment, be revised”).

Because the agency has illegally initiated a rulemaking in violation of an

express statutory prohibition barring EPA from doing so, this Court has

jurisdiction and is a proper venue for this action under 42 U.S.C. §7607(b)(1).

Under that provision, this Court has jurisdiction to review EPA “action” that

“mark[sJ the consummation of the agency’s decisionmaking process” when

“EPA has rendered its last word on the matter’ in question.” Whitman v.

American Trucking Ass ‘ns, Inc., 531 U.S. 457, 478 (2001).

The publication on June 18, 2014 of the proposed rule culminated EPA’s

decision-making process that commenced with the publication of an advance

notice of proposed rulemaking. 73 Fed. Reg. 44,354 (July 30, 2008).

In that advance notice, EPA considered its legal authority to regulate

emissions of greenhouse gases. EPA stated it would have authority to subject

sources to duplicative regulation under Section 111(d) even if EPA were to

have already have subjected the sources to regulation under Section 112.

Id. at 44,487—93. After EPA fmally subjected power plants to regulation under

Section 112 in 2012, 77 Fed. Reg. 9,304 (Feb. 15, 2012), and thus rendered

any future attempt to regulate power plants under Section 111(d) illegal, the

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President ordered EPA to do so anyway. President Barack Obama, “Power

Sector Carbon Pollution Standards,” Memorandum for the Administrator of

the Environmental Protection Agency (June 25, 2013). Several trade groups in

a separate rulemaking had already warned EPA that the agency could not

lawfully regulate power plants under both Section 112 and Section 111(d).

EPA-HQ-OAR-201 1-0660-9998, at 63 (June 25, 2012). Then on June 6, 2014,

the Attorney General of West Virginia informed EPA that the agency could

not lawfully initiate a Section 111(d) rulemaking for power plants because they

were regulated under Section 112. Letter from Patrick Morrissey to Gina

McCarthy (June 6, 2014), available at http://www.ago.wv.gov/public

resources/Documents/Letter%2Oto%2OEPA%200n%20section%20111 %28d%2

9%20authority.pdf. EPA nonetheless initiated this rulemaking on June 18, 2014.

In doing so, EPA has taken a final action to the extent that EPA has initiated a

rulemaking without the authority to do so and has stripped power plants of

their statutorily guaranteed regulatory immunity from the Section 111(d)

program as sources that are already regulated under the Section 112 program.

Petitioner notes that unlike the petitions for review resolved by this

Court in the per cuñam order issued in Las Brisas Energy Center, LLC v. EPA,

No. 12-1248, this petition for review does not challenge the substance of a

proposed rule. Rather, this petition for review challenges whether EPA had

any authority to initiate a rulemaking at all when doing so violates an express

prohibition and unlawfully strips power plants of their regulatory immunity.

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Respectfully submitted,

(UJ&JJCLJ%ZkGeoffrey K. BöesI. Van CarsonRobert D. CherenRebecca A. WorthingtonSQUIRE PATTON BOGGS (US) LLP4900 Key Tower127 Public SquareCleveland, Ohio 44114(216) 479-8559geoffrey.bamessquirepb.com

Counsellor PetitionerMurray Energy Corporation

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COPY OF FEDERAL REGISTER NOTICE


()RfCO,

SCRIPTA .9’(NET

FEDERAL REGISTERVol. 79 Wednesday,

No. 117 June 18, 2014

Part II

Environmental Protection Agency

40 CFR Part 60Carbon Pollution Emission Guidelines for Existing Stationary Sources:Electric Utility Generating Units; Proposed Rule


34830 Federal Register/Vol. 79, No. 117/Wednesday, June 18, 2014/Proposed Rules

ENVIRONMENTAL PROTECTIONAGENCY

40 CFR Part 60

[EPA—HQ—OAR—207 3—0602; FRL—991 1—86—OAR

RIN 2060—AR33

Carbon Pollution Emission Guidelinesfor Existing Stationary Sources:Electric Utility Generating Units

AGENCY: Environmental ProtectionAgency (EPA).ACTION: Proposed rule.

SUMMARY: In this action, theEnvironmental Protection Agency (EPA)is proposing emission guidelines forstates to follow in developing pians toaddress greenhouse gas emissions fromexisting fossil fuel-fired electricgenerating units. Specifically, the EPAis proposing state-specific rate-basedgoals for carbon dioxide emissions fromthe power sector, as well as guidelinesfor states to follow in developing plansto achieve the state-specific goals. Thisrule, as proposed, would continueprogress already underway to reducecarbon dioxide emissions from existingfossil fuel-fired power plants in theUnited States.DATES: Comments on the proposed rule.Comments must be received on orbefore October 16, 2014. Comments onthe information collection request.Under the Paperwork Reduction Act(PRA), since the Office of Managementand Budget (0MB) is required to makea decision concerning the informationcollection request between 30 and 60days after June 18, 2014, a comment tothe 0MB is best assured of having itsfull effect if the 0MB receives it by July18, 2014.

Public Hearing. Four public hearingswill be convened. On July 29, 2014, onepublic hearing will be held in Atianta,Georgia, at the Sam Nunn AtlantaFederal Center Main Tower BridgeConference Area, Conference Room B,61 Forsyth Street SW., Atianta, GA30303, and one will be held in Denver,Colorado, at the EPA’s Region 8Building, 1595 Wynkoop Street, Denver,Colorado 80202. On July 30, 2014, apublic hearing will be held inWashington, DC, at the WilliamJefferson Clinton East Building, Room1152, 1201 Constitution Avenue NW.,Washington, DC 20004. On July 31,2014, a public hearing will be held inPittsburgh, Pennsylvania at the WilliamS. Moorhead Federal Building, Room1310, 1000 Liberty Avenue, Pittsburgh,Pennsylvania 15222. The hearings inPittsburgh, Pennsylvania, Atianta,

Georgia, and Washington, DC, willconvene at 9:00 a.m. and end at 8:00p.m. (Eastern Standard Time). Thehearing in Denver, Colorado, willconvene at 9:00 a.m. and end at 8:00p.m. (Mountain Daylight Time). For allhearings there will be a lunch breakfrom 12:00 p.m. to 1:00 p.m. and adinner break from 5:00 p.m. to 6:00 p.m.Please contact Ms. Pamela Garrett at919—541—7966 or at [email protected] to register to speak at one of thehearings. The last day to pre-register inadvance to speak at the hearings will beFriday, July 25, 2014. Additionally,requests to speak will be taken the dayof the hearings at the hearingregistration desk, although preferenceson speaking times may not be able to befulfilled. If you require the service of atranslator or special accommodationssuch as audio description, please let usknow at the time of registration.

The hearings will provide interestedparties the opportunity to present data,views or arguments concerning theproposed action. The EPA will makeevery effort to accommodate all speakerswho arrive and register. Because thesehearings are being held at U.S.government facilities, individualsplanning to attend the hearing should beprepared to show valid pictureidentification to the security staff inorder to gain access to the meetingroom. Please note that the REAL ID Act,passed by Congress in 2005, establishednew requirements for entering federalfacilities. These requirements will takeeffect July 21, 2014. If your driver’slicense is issued by Alaska, AmericanSamoa, Arizona, Kentucky, Louisiana,Maine, Massachusetts, Minnesota,Montana, New York, Oklahoma, or thestate of Washington, you must presentan additional form of identification toenter the federal buildings where thepublic hearings will be held. Acceptablealternative forms of identificationinclude: Federal employee badges,passports, enhanced driver’s licensesand military identification cards. Wewill list any additional acceptable formsof identification at: http://www2.epa.gov/cleanpowerplan/. Inaddition, you will need to obtain aproperty pass for any personalbelongings you bring with you. Uponleaving the building, you will berequired to return this property pass tothe security desk. No large signs will beallowed in the building, cameras mayonly be used outside of the building anddemonstrations will not be allowed onfederal property for security reasons.

The EPA may ask clarifying questionsduring the oral presentations, but willnot respond to the presentations at thattime. Written statements and supporting

information submitted during thecomment period will be consideredwith the same weight as oral commentsand supporting information presented atthe public hearing. Commenters shouldnotify Ms. Garrett if they will needspecific equipment, or if there are otherspecial needs related to providingcomments at the hearings. Verbatimtranscripts of the hearings and writtenstatements will be included in thedocket for the rulemalcing. The EPA willmake every effort to follow the scheduleas closely as possible on the day of thehearing; however, please plan for thehearings to run either ahead of scheduleor behind schedule. Additionally, moreinformation regarding the hearings willbe available at: http://www2.epa.gov/cleanpowerplan/.ADDRESSES: Comments. Submit yourcomments, identified by Docket ID No.EPA—HQ—OAR—2013—0602, by one ofthe following methods:

Federal eRulemaking portal: http:!/www.regulations.gov. Follow the onlineinstructions for submitting comments.

Email: [email protected] docket ID No. EPA—HQ—OAR—2013—0602 in the subject line of themessage.

Facsimile: (202) 566—9744. Includedocket ID No. EPA—HQ—OAR—2013—0602 on the cover page.

Mail: Environmental ProtectionAgency, EPA Docket Center (EPA/DC),Mail code 28221T, Attn: Docket ID No.EPA—HQ—OAR—2013—0602, 1200Pennsylvania Ave. NW., Washington,DC 20460. In addition, please mail acopy of your comments on theinformation collection provisions to theOffice of Information and RegulatoryAffairs, 0MB, Atm: Desk Officer for theEPA, 725 17th St. NW., Washington, DC20503.

Hand/Courier Delivery: EPA DocketCenter, Room 3334, EPA WJC WestBuilding, 1301 Constitution Ave. NW.,Washington, DC 20004, Attu: Docket IDNo. EPA—HQ—OAR—2013—0602. Suchdeliveries are accepted only during theDocket Center’s normal hours ofoperation (8:30 a.m. to 4:30 p.m.,Monday through Friday, excludingfederal holidays), and specialarrangements should be made fordeliveries of boxed information.

Instructions: All submissions mustinclude the agency name and docket IDnumber (EPA—HQ—OAR—2013—0602).The EPA’s policy is to include allcomments received without change,including any personal informationprovided, in the public docket, availableonline at http://www.regulations.gov,unless the comment includesinformation claimed to be Confidential


Federal Register/Vol. 79, No. 117/Wednesday, June 18, 2014/Proposed Rules 34831

Business Information (CBI) or otherinformation whose disclosure isrestricted by statute. Do not submitinformation that you consider to be CBIor otherwise protected through http://www.regulations.gov or email. Send ordeliver information identified as CBIonly to the following address: Mr.Roberto Morales, OAQPS DocumentControl Officer (C404—02), Office of AirQuality Planning and Standards, U.S.EPA, Research Triangle Park, NorthCarolina 27711, Attention Docket ID No.EPA—HQ—OAR—2013—0602. Clearlymark the part or all of the informationthat you claim to be CBI. For CBIinformation on a disk or CD—ROM thatyou mail to the EPA, mark the outsideof the disk or CD-ROM as CBI and thenidentify electronically within the disk orCD—ROM the specific information youclaim as CBI. In addition to onecomplete version of the coimnent thatincludes information claimed as CBI,you must submit a copy of the commentthat does not contain the informationclaimed as CBI for inclusion in thepublic docket. Information so markedwill not be disclosed except inaccordance with procedures set forth in40 CFR Part 2.

The EPA requests that you alsosubmit a separate copy of yourcomments to the contact personidentified below (see FOR FURTHERINFORMATION CONTACT). If the commentincludes information you consider to beCBI or otherwise protected, you shouldsend a copy of the comment that doesnot contain the information claimed asCBI or otherwise protected.

The www.regulations.gov Web site isan “anonymous access” system, whichmeans the EPA will not know youridentity or contact information unlessyou provide it in the body of yourcomment. If you send an emailcomment directly to the EPA withoutgoing through http://www.regulations.gov, your emailaddress will be automatically capturedand included as part of the commentthat is placed in the public docket andmade available on the Internet. If yousubmit an electronic comment, the EPArecommends that you include yourname and other contact information inthe body of your comment and with anydisk or CD-ROM you submit. if the EPAcannot read your comment due totechnical difficulties and cannot contactyou for clarification, the EPA may notbe able to consider your comment.Electronic files should avoid the use ofspecial characters, any form ofencryption and be free of any defects orviruses.

Docket: All documents in the docketare listed in the http://

www.regulations.gov index. Althoughlisted in the index, some information isnot publicly available (e.g., CBI or otherinformation whose disclosure isrestricted by statute). Certain othermaterial, such as copyrighted material,will be publicly available only in hardcopy. Publicly available docketmaterials are available eitherelectronically in http://www.regulations.gov or in hard copy atthe EPA Docket Center, WilliamJefferson Clinton Building West, Room3334, 1301 Constitution Ave. NW.,Washington, DC. The Public ReadingRoom is open from 8:30 a.m. to 4:30p.m., Monday through Friday, excludingfederal holidays. The telephone numberfor the Public Reading Room is (202)566—1744, and the telephone number forthe Air Docket is (202) 566—1742. Visitthe EPA Docket Center homepage athttp://www.epa.gov/epahome/dockets.htm for additional informationabout the EPA’s public docket.

In addition to being available in thedocket, an electronic copy of thisproposed rule will be available on theWorldwide Web (WAR,V). Followingsignature, a copy of this proposed rulewill be posted at the following address:http://www2.epa.gov/cleanpowerplan/.FOR FURTHER INFORMATION CONTACT: Ms.Amy Vasu, Sector Policies and ProgramsDivision (D205—01), U.S. EPA, ResearchTriangle Park, NC 27711; telephonenumber (919) 541—0107, facsimilenumber (919) 541—4991; email address:[email protected] or Ms. MargueriteMcLamb, Sector Policies and ProgramsDivision (D205—01), U.S. EPA, ResearchTriangle Park, NC 27711; telephonenumber (919) 541—7858, facsimilenumber (919) 541—4991; email address:[email protected] INFORMATION:

Acronyms. A number of acronymsand chemical symbols are used in thispreamble. While this may not be anexhaustive list, to ease the reading ofthis preamble and for referencepurposes, the following terms andacronyms are defined as follows:ACEEE American Council for an Energy

Efficient EconomyAEO Annual Energy OutlookAFL—CIO American Federation of Labor

and Congress of Industrial OrganizationsASTM American Society for Testing of

MaterialsBSER Best System of Emission ReductionBtu/kWh British Thermal Units per

Kilowatt-hourCAA Clean Air ActCBI Confidential Business InformationCCS Carbon Capture and Storage (or

Sequestration)CEMS Continuous Emissions Monitoring

System

CHP Combined Heat and PowerCO2 Carbon DioxideDOE Department of EnergyECMPS Emissions Collection and

Monitoring Plan SystemEERS Energy Efficiency Resource StandardECU Electric Generating UnitEIA Energy Information AdministrationEM&V Evaluation, Measurement and

VerificationEQ Executive OrderEPA Environmental Protection AgencyFR Federal RegisterGHG Greenhouse GasGW GigawattHAP Hazardous Air PollutantHRSG Heat Recovery Steam GeneratorIGCC Integrated Gasification Combined

CycleWCC Intergovernmental Panel on Climate

Change1PM Integrated Planning ModelIRP Integrated Resource PlanISO Independent System OperatorkW KilowattkWh Kilowatt-hourlb C02/Mwh Pounds of CO2 per Megawatt-

hourLBNL Lawrence Berkeley National

LaboratoryMMBtu Million British Thermal UnitsMW MegawattMWh Megawatt-hourNAAQS National Ambient Mr Quality

StandardsNMCS North American Industry

Classification System CommissionersNAS National Academy of SciencesNGCC Natural Gas Combined CycleNOx Nitrogen OxidesNRC National Research CouncilNSPS New Source Performance StandardNSR New Source ReviewNTTAA National Technology Transfer and

Advancement ActNYSERDA New York State Energy Research

and Development Authority0MB Office of Management and BudgetPM Particulate MatterPM2.5 Fine Particulate MatterPEA Paperwork Reduction ActPSB Public Service BoardPUC Public Utilities CommissionEEC Renewable Energy CreditRES Renewable Energy StandardEPA Regulatory Flexibility ActRGGI Regional Greenhouse Gas InitiativeETA Regulatory Impact AnalysisRPS Renewable Portfolio StandardRTO Regional Transmission OperatorSBA Small Business AdministrationSBC System Benefits ChargeSCC Social Cost of CarbonSW State Implementation PlanSO2 Sulfur DioxideTg Teragram (one trillion (10 12) grams)TSD Technical Support DocumentTTN Technology Transfer NetworkUlvifiA Unfunded Mandates Reform Act of

1995UNFCCC United Nations Framework

Convention on Climate ChangeUSGCRP U.S. Global Change Research

ProgramVCS Voluntary Consensus Standard



Organization of This Document. Theinformation presented in this preambleis organized as follows:I. General information

A. Executive Summary3. Organization and Approach for This

Proposed RuleII. Background

A. Climate Change Impacts From GHGEmissions

B. GHG Emissions From Fossil Fuel-FiredEGUs

C. The Utility Power SectorD. Statutory and Regulatory Requirements

ifi. Stakeholder Outreach and ConclusionsA. Stakeholder OutreachB. Key Messages From StakeholdersC. Key Stakeholder Proposals1). Consideration of the Existing Range of

Policies and ProgramsE. Conclusions

IV. Rule Requirements and Legal BasisA. Summary of Rule RequirementsB. Summary of Legal Basis

V. Authority To Regulate Carbon Dioxide andEGUs, Affected Sources, and Treatmentof Categories

A. Authority To Regulate Carbon DioxideB. Authority To Regulate EGUsC. Affected SourcesD. Implications for Tribes and U.S.

TerritoriesE. Combined Categories and Codification

in the Code of Federal RegulationsVI. Building Blocks for Setting State Goals

and the Best System of EmissionReduction

A. IntroductionB. Building Blocks for Setting State GoalsC. Detailed Discussion of Building Blocks

and Other Options ConsideredD. Potential Combinations of the Building

Blocks as Components of the BestSystem of Emission Reduction

E. Determination of the Best System ofEmission Reduction

VII. State GoalsA. OverviewB. Form of GoalsC. Proposed Goals and Computation

ProcedureD. State FlexibiifiesE. Alternate Goals and Other Approaches

ConsideredF. Reliable Affordable Electricity

VIII. State PlansA. OverviewB. ApproachC. Criteria for Approving State PlansD. State Plan ComponentsE. Process for State Plan Submittal and

ReviewF. State Plan ConsiderationsG. Additional Factors That Can Help States

Meet Their CO2 Emission PerformanceGoals

H. Resources for States To Consider inDeveloping Plans

DC. Implications for Other EPA Programs andRules

A. Implications for NSR ProgramB. Implications for Title V ProgramC. Interactions With Other EPA Rules

X. Impacts of the Proposed ActionA. What are the air impacts?

B. Comparison of Building BlockApproaches

C. Endangered Species ActD. What are the energy impacts?E. What are the compliance costs?F. What are the economic and employment

impacts?G. What are the benefits of the proposed

action?XI. Statutory and Executive Order Reviews

A. Executive Order 12866, RegulatoryPlanning and Review, and ExecutiveOrder 13563, Improving Regulation andRegulatory Review

B. Paperwork Reduction ActC. Regulatory Flexibility ActU. Unfunded Mandates Reform Act of 1995E. Executive Order 13132, FederalismF. Executive Order 13175, Consultation

and Coordination With Indian TribalGovernments

G. Executive Order 13045, Protection ofChildren From Environmental HealthRisks and Safety Risks

H. Executive Order 13211, ActionsConcerning Regulations ThatSignificantly Affect Energy Supply,Distribution, or Use

I. National Technology Transfer andAdvancement Act

J. Executive Order 12896, Federal ActionsTo Address Environmental Justice inMinority Populations and Low-incomePopulations

XII. Statutory Authority

I. General Information

A. Executive Summary

1. Purpose of the Regulatory ActionUnder the authority of Clean Air Act

(CAA) section 111(d), the EPA isproposing emission guidelines for statesto follow in developing plans to addressgreenhouse gas (GHG) emissions fromexisting fossil fuel-fired electricgenerating units (EGUs). In thissummary, we outline the proposal;discuss its purpose; sununarize its majorprovisions, including the EPA’sapproach to determining goals; describethe broad range of options available tostates, including flexibility in timingrequirements both for plan submissionand compliance deadlines under thoseplans; and briefly describe the estimatedCO2 emission reductions, costs andbenefits expected to result from fullimplementation of the proposal.

This rule, as proposed, wouldcontinue progress already underway tolower the carbon intensity of powergeneration in the United States (U.S.).Lower carbon intensity means feweremissions of C02, a potent greenhousegas that contributes to climate change.This proposal is a significant stepforward in the EPA and statespartnering to reduce GHG emissions inthe U.S. The proposal incorporatescritical elements that reflect theinformation and views shared during

the unprecedented effort that the EPAhas undertaken, beginning in thesummer of 2013, to interact directlywith, and solicit input from, a widerange of states and stakeholders. Thiseffort encompassed several hundredmeetings across the country with stateenvironmental and energy officials,public utility commissioners, systemoperators, utilities and public interestadvocates, as well as members of thepublic. Many participants submittedwritten material and data to the EPA aswell.

Nationwide, by 2030, this rule wouldachieve CO2 emission reductions fromthe power sector of approximately 30percent from CO2 emission levels in2005. This goal is achievable becauseinnovations in the production,distribution and use of electricity arealready making the power sector moreefficient and sustainable whilemaintaining an affordable, reliable anddiverse energy mix. This proposed rulewould reinforce and continue thisprogress. The EPA projects that, in 2030,the significant reductions in the harmfulcarbon pollution and in other airpollution, to which this rule wouldlead, would result in net climate andhealth benefits of $48 billion to $82billion. At the same time, coal andnatural gas would remain the twoleading sources of electricity generationin the U.S., with each providing morethan 30 percent of the projectedgeneration.

Based on evidence from programsalready being implemented by manystates as well as input received fromstakeholders, the agency recognizes thatthe most cost-effective system ofemission reduction for GHG emissionsfrom the power sector under CAAsection 111(d) entails not onlyimproving the efficiency of fossil fuel-fired EGUs, but also addressing theirutilization by taking advantage ofopportunities for lower-emittinggeneration and reduced electricitydemand across the electricity system’sinterconnecting network or grid.

The proposed guidelines are based onand would reinforce the actions alreadybeing taken by states and utilities toupgrade aging electricity infrastructurewith 21st century technologies. Theguidelines would ensure that thesetrends continue in ways that areconsistent with the long-term planningand investment processes already usedin this sector, to meet both region- andstate-specific needs. The proposalprovides flexibility for states to buildupon their progress, and the progress ofcities and towns, in addressing GHGs. Italso allows states to pursue policies toreduce carbon pollution that: (I)



Continue to rely on a diverse set ofenergy resources, (2) ensure electricsystem reliability, (3) provide affordableelectricity, (4) recognize investmentsthat states and power companies arealready making, and (5) can be tailoredto meet the specific energy,environmental and economic needs andgoals of each state. Thus, the proposedguidelines would achieve meaningfulCO2 emission reduction whilemaintaining the reliability andaffordability of electricity in the U.S.

a. Proposal Elements

The proposal has two main elements:(1) State-specific emission rate-basedCO2 goals and (2) guidelines for thedevelopment, submission andimplementation of state plans. To setthe state-specific CO2 goals, the EPAanalyzed the practical and affordablestrategies that states and utilities arealready using to lower carbon pollutionfrom the power sector. These strategiesinclude improvements in efficiency atcarbon-intensive power plants,programs that enhance the dispatchpriority of, and spur private investmentsin, low emitting and renewable powersources, as well as programs that helphomes and businesses use electricitymore efficiently. In addition, incalculating each state’s CO2 goal, theEPA took into consideration the state’sfuel mix, its electricity market andnumerous other factors. Thus, eachstate’s goal reflects its uniqueconditions.

While this proposal lays out state-specific CO2 goals that each state isrequired to meet, it does not prescribehow a state should meet its goal. CAAsection 111(d) creates a partnershipbetween the EPA and the states underwhich the EPA sets these goals and thestates take the lead on meeting them bycreating plans that are consistent withthe EPA guidelines. Each state will havethe flexibility to design a program tomeet its goal in a manner that reflectsits particular circumstances and energyand environmental policy objectives.Each state can do so alone or cancollaborate with other states on multistate plans that may provide additionalopportunities for cost savings andflexibility.

To facilitate the state planningprocess, this proposal lays outguidelines for the development andimplementation of state plans. Theproposal describes the components of astate plan, the latitude states have indeveloping compliance strategies, theflexibility they have in the timing forsubmittal of their plans and theflexibility they have in determining theschedule by which their sources must

achieve the required CO2 reductions.The EPA recognizes that each state hasdiffering policy considerations—including varying emission reductionopportunities and existing stateprograms and measures—and that thecharacteristics of the electricity systemin each state (e.g., utility regulatorystructure, generation mix and electricitydemand) also differ. Therefore, theproposed guidelines provide states withoptions for meeting the state-specificgoals established by the EPA in amanner that accommodates a diverserange of state approaches. This proposalalso gives states considerable flexibilitywith respect to the timeftames for plandevelopment and implementation,providing up to two or three years forsubmission of final plans and providingup to fifteen years for fullimplementation of all emissionreduction measures, after the proposal isfinalized.

Addressing a concern raised by bothutilities and states, the EPA is proposingthat states could choose approaches intheir compliance plans under which fullresponsibility for actions achievingreductions is not placed entirely uponemitting EGUs; instead, state planscould include measures and policies(e.g., demand-side energy efficiencyprograms and renewable portfoliostandards) for which the state itself isresponsible. Of course, individual stateswould also have the option ofstructuring programs (e.g., allowance-trading programs) under which fullresponsibility rests on the affectedEGUs.

The EPA believes that, using theflexibilities inherent in CAA section111(d), this proposal would result insignificant reductions of GHG emissionsthat cause harmful climate change,while providing states with ampleopportunity to design plans that useinnovative, cost-effective strategies thattake advantage of investments alreadybeing made in programs and measuresthat lower the carbon intensity of thepower sector and reduce GHGemissions.

b. Policy Context and IndustryConditions

This proposal is an important steptoward achieving the GHG emissionreductions needed to address theserious threat of climate change. GHGpollution threatens the American publicby leading to potentially rapid,damaging and long-lasting changes inour climate that can have a range ofsevere negative effects on human healthand the environment. CO2 is theprimary GHG pollutant, accounting fornearly three-quarters of global GHG

emissions1 and 82 percent of U.S. GHGemissions.2 The May 2014 report of theNational Climate Assessment3concluded that climate change impactsare already manifesting themselves andimposing losses and costs. The reportdocuments increases in extreme weatherand climate events in recent decades,damage and disruption to infrastructureand agriculture, and projects continuedincreases in impacts across a wide rangeof communities, sectors, andecosystems.

The President’s Climate Action Plan,4issued in June 2013, recognizes thatclimate change has far-reaching harmfulconsequences and real economic costs.The Climate Action Plan details a broadarray of actions to reduce GHGemissions that contribute to climatechange and affect public health and theenvironment. One of the plan’s goals isto reduce CO2 emissions from powerplants. This is because fossil fuel-firedEGUs are, by far, the largest emitters ofGHGs, primarily in the form of CO2,among stationary sources in the U.S. Toaccomplish this goal, President Obamaissued a Presidential Memorandum5that recognized the importance ofsignificant and prompt action. TheMemorandum directed the EPA tocomplete carbon pollution standards,regulations or guidelines, asappropriate, for modified, reconstructedand existing power plants by June 1,2015, and in doing so to build on stateleadership in moving toward a cleanerpower sector.

The way that power is produced,distributed and used is already changingdue to advancements in innovativepower sector technologies and in theavailability and cost of low carbon fuel,renewable energy and energy efficientdemand-side technologies, as well aseconomic conditions. In addition, theaverage age of the coal-fired generatingfleet is increasing. In 2025, the averageage of the coal-fired generating fleet is

‘Intergovernmental Panel on climate Change(IPCC) report, “Contribution of Working GToup Itothe Fourth Assessment Report of theIntergovernmental Panel on Climate Change,” 2007.Available at hftp://epa.gov/clirnatechange/ghgemissions/global.html.

2Table ES—2 “Inventory of U.S. Greenhouse GasEmissions and Sinks: 1990—2012”, Report EPA 430—R—14—003, United States Environmental ProtectionAgency, April 15, 2014.

3U.S. Global Change Research Program, ClimateChange Impacts in the United States: The ThirdNational Climate Assessment, May 2014. Availableat hftp://nca2Ol4.globalchange.gov/.

4The President’s Climate Action Plan, June 2013.http://www.whitehouse.gov/sites/default/files/image/president27sdlimateacdonplan.pdf.

5Presidential Memorandum—Power SectorCarbon Pollution Standards, June 25, 2013. http://www.whitehouse.gov/the-press-office/20;3/06/25/presidential-rnemorandum-power-sector-carbonpollution-standards.



projected to be 49 years old, and 20percent of units would be more than 60years old if they remained iji operationat that time. Therefore, even in theabsence of additional environmentalregulation, states and utilities can beexpected to be, and already are, makingplans to address the changesnecessitated by the aging of currentassets and infrastructure. With changeinevitably underway between now and2030, a CAA section 111(d) rulemakingfor CO2 emissions is timely and caninform current and ongoing decisionmaking by states and utilities, as well asprivate sector business and technologyinvestments. As states develop theirplans, they will make key decisions thatwill stimulate private sector investmentand innovation associated withreducing GHG emissions. We expectthat many states will consider theopportunities offered for their respectiveeconomies as a result of this investment.

The proposed guidelines are designedto build on and reinforce progress bystates, cities and towns, and companieson a growing variety of sustainablestrategies to reduce power sector CO2emissions. At the same time, the EPAbelieves that this proposal providesflexibility for states to develop plansthat align with their uniquecircumstances, as well as their otherenvironmental policy, energy andeconomic goals. All states will have theopportunity to shape their plans as theybelieve appropriate for meeting theproposed CO2 goals. This includes stateswith long-established reliance on coal-fired generation, as well as states witha commitment to promoting renewableenergy (including through sustainableforestry initiatives). It also includesstates that are already participating in orimplementing CO2 reduction programs,such as the Regional Greenhouse GasInitiative (RGGI), California’s “GlobalWarming Solutions Act” and Colorado’s“Clean Air, Clean Jobs Act”.

States would be able to rely on andextend programs they may already havecreated to address the power sector.Those states committed to IntegratedResource Planning (IRP) would be ableto establish their CO2 reduction planswithin that framework, while stateswith a more deregulated power sectorsystem could develop CO2 reductionplans within that specific framework.Each state, including states without anexisting program, would have theopportunity to take advantage of a widevariety of strategies for reducing CO2emissions from affected EGUs. The EPAand other federal entities, including theU.S. Department of Energy (DOE), theFederal Energy Regulatory Commission(FERC) and the U.S. Department of

Agriculture, among others, arecommitted to sharing expertise withinterested states as they develop andimplement their plans.

States would be able to address theeconomic interests of their utilities andratepayers by using the flexibilities inthis proposed action to: (1) Reduce coststo consumers, minimize stranded assets,and spur private investments inrenewable energy and energy efficiencytechnologies and businesses; and (2) ifthey choose, work with other states onmulti-state approaches that reflect theregional structure of electricityoperating systems that exists in mostparts of the country and is critical toensuring a reliable supply of affordableenergy. The proposed rule gives statesthe flexibility to provide a broad rangeof compliance options that recognizethat the power sector is made up of adiverse range of companies that ownand operate fossil fuel-fired EGUs,including vertically integratedcompanies in regulated markets,independent power producers, ruralcooperatives and municipally-ownedutilities, all of which are likely to havedifferent ranges of opportunities toreduce GHG emissions while facingdifferent challenges in meeting thesereductions.

Both existing state programs (such asRGGI, the California Global WarmingSolutions Act program and the ColoradoClean Air, Clean Jobs Act program) andideas suggested by stakeholders showthat there are a number of different waysthat states can design programs thatachieve required reductions whileworking within existing marketmechanisms used to dispatch powereffectively in the short term and toensure adequate capacity in the longterm. These programs and programs forconventional pollutants, such as theAcid Rain Program under Title IV of theCAA, have demonstrated thatcompliance with environmentalprograms can be monetized such that itis factored into power sector economicdecision making in ways that reduce thecost of controlling pollution, maintainelectricity system reliability and workwithin the least cost dispatchingprinciples that are key to operation ofour electric power grid. The proposalwould also allow states to work togetherwith individual companies on potentialspecific challenges. These and otherflexibilities are discussed further inSection Vifi of the preamble.

a. CAA Section 111(d) Requirements

Under CAA section 111(d),6 stateplans must establish standards of

6See also 40 CFR 6o.22(b)(5).

performance that reflect the degree ofemission limitation achievable throughthe application of the “best system ofemission reduction” that, taking intoaccount the cost of achieving suchreduction and any non-air quality healthand environmental impacts and energyrequirements, the Administratordetermines has been adequatelydemonstrated (BSER).7 Consistent withCAA section 111(d), the EPA isproposing state-specific goals thatreflect the EPA’s calculation of theemission limitation that each state canachieve through the application of theBSER. This calculation reflects thedegree of emission limitation that thestate plan must achieve in order toimplement the BSER that the EPA hasdetermined has been adequatelydemonstrated and that, in turn, wouldbe required to be, and via thecalculation, has been, applied for theaffected EGUs in each state. A CAAsection 111(d) state plan will differ froma state implementation plan (SIP) for acriteria aft pollutant national ambientair quality standard (NAAQS) in severalrespects, reflecting the significantdifferences between CAA sections 110and 111. A CAA section 110 SIP mustbe designed to meet the NAAQS for acriteria air pollutant for a particulararea—not for a source category—withina timeframe specified in the CAA. TheNAAQS itself is based on the currentbody of scientific evidence and, by law,does not reflect consideration of cost. Bycontrast, a CAA section 111(d) stateplan must be designed to achieve aspecific level of emission performancethat has been established for a particularsource category within a timeframedetermined by the Administrator and, tosome extent, by each state. Moreover,the emission levels for the sourcecategory reflect a determination of theBSER, which incorporates considerationof cost, technical feasibility and otherfactors.

To determine the BSER for reducingCO2 emissions at affected EGUs, theEPA considered numerous measuresthat are already being implemented andcan be implemented more broadly to

7Under CAA section i11(a)(1) and (d), the EPAis authorized to determine the BSER and tocalculate the amount of emission reductionachievable through applying the BSER. The state isauthorized to identify the standard or standards ofperformance that reflects that amount of emissionreduction. In addition, the state is required toinclude in its state plan the standards ofperformance and measures to implement andenforce those standards. The state must submit theplan to the EPA, and the EPA must approve theplan if the standards of performance andimplementing and enforcing measures aresatisfactory. This is discussed in more detail inSections IV, VI, Vfl and VIII of this preamble, aswell as in the Legal Memorandum.



improve emission rates and to reduceoverall CO2 emissions from fossil fuel-fired EGUs. Overall, the BSER proposedhere is based on a range of measuresthat fall into four main categories, or“building blocks,” which compriseimproved operations at EGUs,dispatching lower-emitting EGUs andzero-emitting energy sources, and end-use energy efficiency. All of thesemeasures have been amplydemonstrated via their currentwidespread use by utilities and states.

The proposed guidelines arestructured so that states would not berequired to use each and every one ofthe measures that the EPA determinesconstitute the BSER or to apply any oneof those measures to the same extentthat the EPA determines is achievable atreasonable cost. Instead, in developingits plan, each state will have theflexibility to select the measure orcombination of measures it prefers inorder to achieve its CO2 emissionreduction goal. Thus, a state couldchoose to achieve more reductions fromone measure encompassed by the BSERand less from another, or it couldchoose to include measures that werenot part of the EPA’s BSERdetermination, as long as the stateachieves the CO2 reductions at affectedEGUs necessary to meet the goal that theEPA has defined as representing theBSER.

As explained in further detail inSections VI, VII and Vifi of thispreamble regarding the agency’sdetermination of the BSER, the EPA isoffering the opportunity via thisproposal to comment on the proposedBSER, the proposed methodology forcomputing state goals based onapplication of the BSER, and the state-specific data used in the computations.Once the final goals have beenpromulgated, a state would no longerhave an opportunity to request that theEPA adjust its CO2 goal. The final state-specific CO2 goals would reflect anyadjustments as appropriate based oncomments provided to the EPA toaddress any data errors in the analysisfor the proposed goals. We expect thatstates will be able to meet the CO2 goalsbecause they will represent theapplication of the BSER for the states’affected sources.

This proposed rule sets forth the stategoals that reflect the BSER andguidelines for states to use indeveloping their plans to reduce CO2from fossil fuel-fired EGUs. Thepreamble describes the proposedexpectations for state plans anddiscusses options that the EPA hasconsidered. It also explains the EPA’sauthority to define the BSER, as well as

state goals, and each state’sresponsibility to develop andimplement standards of performancethat will achieve its CO2 goal.Additional detail on various aspects ofthe proposal is included in severaltechnical support documents (TSDs)and memoranda, which are available inthe rulemaking docket.

The proposal was substantiallyinformed by the extensive input fromstates and a wide range of stakeholdersthat the EPA sought and has receivedsince the summer of 2013. The EPAinvites further input through publiccomment on all aspects of this proposal.

2. Summary of the Proposal’s MajorProvisions

a. Approach

In developing this proposedrulemaking, the EPA is implementingstatutory provisions that have been inplace since Congress first enacted theCAA in 1970 and that have beenimplemented pursuant to regulationspromulgated in 1975 and followed insubsequent CAA section 111(d)rulemakings. These provisions ensurethat, in concert with the provisions ofCAA sections 110 and 112, new andexisting major stationary sourcesoperate in ways that address theiremissions of significant air pollutantsthat are harmful to public health and theenvironment. These requirements callon the EPA to develop emissionguidelines, which reflect the EPA’sdetermination of the BSER, for states tofollow in formulating compliance plansto implement standards of performanceto achieve emission reductionsconsistent with the BSER. In followingthese provisions, the EPA is proposinga BSER based on strategies currentiybeing used by states and companies toreduce CO2 emissions from EGUs.

The CAA, as interpreted by the courts,identifies several factors for the EPA toconsider in a BSER determination.These include technical feasibility,costs, size of emission reductions andtechnology (e.g., whether the systempromotes the implementation andfurther development of technology). Indetermining the BSER, the EPAconsidered the reductions achievablethrough measures that reduce CO2emissions from existing fossil fuel-firedEGUs either by (1) reducing the CO2emission rate at those units or (2)reducing the units’ CO2 emission total tothe extent that generation can be shiftedfrom higher-emitting fossil fuel-firedEGUs to lower- or zero-emitting options.

As the EPA has done in making BSERdeterminations in previous CAA section111(d) rulemaidngs, the agency

considered the types of strategies thatstates and owners and operators ofEGUs are already employing to reducethe covered pollutant (in this case, CC2)from affected sources (in this case, fossilfuel-fired EGUs).8 Across the nation,many states, cities and towns, andowners and operators of EGUs haveshown leadership in creating andimplementing policies and programsthat reduce CO2 emissions from thepower sector while achieving othereconomic, environmental and energybenefits. Some of these activities, suchas market-based programs and GHGperformance standards, directly requireCC2 emission reductions from EGUs.Others reduce CO2 emissions byreducing utilization of fossil fuel-firedEGUs through, for example, renewableportfolio standards (RPS) and energyefficiency resource standards (EERS).For example, currently 10 states havemarket-based GHG emission programs,38 states have renewable portfoliostandards or goals, and utilities in 47states run demand-side energyefficiency programs. Many individualcompanies also have significantvoluntary CO2 emission reductionprograms.

Such strategies—and the proposedBSER determination—reflect the factthat, in almost all states, the production,distribution and use of electricity canbe, and is, undertaken in ways thatacconunodate reductions in bothpollution emission rates and totalemissions. Specifically, electricityproduction, at least to some extent,takes place interchangeably betweenand among multiple generation facilitiesand different types of generation, a factthat Congress, the EPA and the stateshave long relied on in enacting orpromulgating pollution reductionprograms, such as Title IV of the CAA,the NO SIP Call, the Cross State AirPollution Rule (CSAPR) and RGGI.

As a result, the agency, in quantifyingstate goals, assessed what combinationof electricity production or energydemand reduction across generationfacilities can offer a reasonable-cost,technically feasible approach toachieving CO2 emission reductions.States, in turn, will be able to lookbroadly at opportunities across their

8The final emission guidelines for landfill gasemissions from municipal solid waste landfills,published on March 12, 1996 and amended on June16, 1998 (61 FR 9905 and 63 FR 32743,respectively) are one example, as they allow eitherof two approaches for controlling landfill gas—byrecovering the gas as a fuel, for sale, and removingfrom the premises, or by destroying the organiccontent of the gas on the premises using a controldevice. Recovering the gas as a fuel source was apractice already being used by some affectedsources prior to promulgation of the rulemaldng.



electricity system in devising plans tomeet their goals. Importantly, states mayrely on measures that they already havein place, including renewable energystandards and demand-side energyefficiency programs, and the proposaldetails how such existing state programscan be incorporated into state plans.States will also be able to participate inmulti-state programs that already existor may create new ones.

Thus, to determine the BSER forreducing CO2 emissions at affectedEGUs and to establish the numericalgoals that reflect the BSER, the EPAconsidered numerous measures that canand are being implemented to improveemission rates and to reduce or limitmass CO2 emissions from fossil fuel-fired EGUs. These measures encompasstwo basic approaches: (1) Reducing thecarbon intensity of certain affectedEGUs by improving the efficiency oftheir operations, and (2) addressingaffected EGUs’ mass emissions byvarying their utilization levels. Forpurposes of expressing the BSER as anemission limitation, in this case in theform of state-level goals, we propose tobase these two approaches on measuresgrouped into four main categories, or“building blocks.” These buildingblocks can also be used as a guide tostates for constructing broad-based, cost-effective, long-term strategies to reduceCO2 emissions. The EPA believes thatthe application of measures from each ofthe building blocks can achieve CO2emission reductions at fossil fuel-firedEGUs such that, when combined withmeasures from other building blocks,the measures represent the “best systemof emission reduction. . . adequatelydemonstrated” for fossil fuel-firedEGUs. The building blocks are:

1. Reducing the carbon intensity ofgeneration at individual affected EGUsthrough heat rate improvements.

2. Reducing emissions from the mostcarbon-intensive affected EGUs in theamount that results from substitutinggeneration at those EGUs withgeneration from less carbon-intensiveaffected EGUs (including NGCC unitsunder construction).

3. Reducing emissions from affectedEGUs in the amount that results fromsubstituting generation at those EGUswith expanded low- or zero-carbongeneration.

4. Reducing emissions from affectedEGUs in the amount that results fromthe use of demand-side energyefficiency that reduces the amount ofgeneration required.

The four building blocks aredescribed in detail in Sections VI of thispreamble. As explained in that section,the EPA evaluated each of the building

blocks individually against the BSERcriteria and found that each of thebuilding blocks independently meritsconsideration as part of the BSER. TheEPA also evaluated combinations of thebuilding blocks against the BSERcriteria—in particular, a combination ofall four building blocks and acombination of building blocks 1 and 2.

Based on that evaluation, the EPAproposes that the combination of allfour building blocks is the BSER. Thecombination of all four blocks bestrepresents the BSER because it achievesgreater emission reductions at a lowercost, takes better advantage of the widerange of measures that states, cities,towns and utilities are already using toreduce CO2 from EGUs and reflects theintegrated nature of the electricitysystem and the diversity of electricitygeneration technology. Section VI of thispreamble also explains how the EPAconsidered more aggressive applicationof measures in each block. This includesconsideration of more extensiveapplication of measures that the EPAdetermined do represent a component ofthe BSER (such as more extensive oraccelerated application of demand-sidemeasures), as well as consideration ofoptions in some blocks that the EPAdetermined would not represent theBSER for existing sources (such as theinclusion of retrofit carbon capture andstorage or sequestration (CCS) onexisting EGUs).

As part of the BSER determination,the EPA considered the impacts thatimplementation of the emissionreductions based on the combination ofthe blocks would have on the cost ofelectricity and electricity systemreliability. As the preamble details, theEPA believes that, both with respect tothe overall proposed BSER and withrespect to the individual buildingblocks, the associated costs arereasonable. Importantly, the proposedBSER, expressed as a numeric goal foreach state, provides states with theflexibility to determine how to achievethe reductions (i.e., greater reductionsfrom one building block and less fromanother) and to adjust the timing inwhich reductions are achieved, in orderto address key issues such as cost toconsumers, electricity system reliabilityand the remaining useful life of existinggeneration assets.

In sum, the EPA proposes that theBSER for purposes of CAA section111(d), as applied to existing fossil fuel-fired EGUs, is based on a combinationof measures that reduce CO2 emissionsand CO2 emission rates and encompass

all four building blocks.9 We are alsosoliciting comment on application ofonly the first two building blocks as thebasis for the BSER, while noting thatapplication of only the first twobuilding blocks achieves fewer CO2reductions at a higher cost.

In determining the BSER, we haveconsidered the ranges of reductions thatcan be achieved by application of eachbuilding block, and we have identifiedgoals that we believe reflect a reasonabledegree of application of each buildingblock consistent with the BSER criteria.Relying on all four building blocks tocharacterize the combination ofmeasures that reduce CO2 emissions andCO2 emission rates at affected EGUs asthe basis for the BSER is consistent withstrategies, actions and measures thatcompanies and states are alreadyundertaking to reduce GHG emissionsand with current trends in the electricpower sector, driven by efforts to reduceGHGs as well as by other factors, suchas advancements in technology.Reliance on all four building blocks inthis way also supports the goals ofachieving significant and technicallyfeasible reductions of CO2 at areasonable cost, while also promotingtechnology and approaches that areimportant for achieving furtherreductions. Finally, the EPA believesthat the diverse range of measuresencompassed in the four building blocksallows states and sources to take fulladvantage of the inherent flexibility ofthe current regionally interconnectedand integrated electricity system so as toachieve the CO2 goals while continuingto meet the demand for electricityservices in a reliable and affordablemanner.

The EPA recognizes that states differin important ways, including in theirmix of existing EGUs and in their policypriorities. Consequently, opportunitiesand preferences for reducing emissions,as reflected in each of the buildingblocks, vary across states. While thestate-specific goals that the EPA isproposing in this rule are based onconsistent application of a single goal-setting methodology across all states,the goals account for these keydifferences. The state-specific CO2 goalsderived from application of themethodology vary because, in settingthe goals for a state, the EPA used dataspecific to each state’s EGUs and certain

9The EPA notes that under the proposed BSER,some building blocks would apply to some, but notall, affected sources. Specifically, building block 1would apply to affected coal-fired steam EGUs,building block 2 would apply to all affected steamEGUs (both coal-fired and oil/gas-fired), andbuilding blocks 3 and 4 would apply to all affectedEGUs.



other attributes of its electricity system(e.g., current mix of generationresources).

The proposed BSER and goal-settingmethodology reflect informationprovided and priorities expressedduring the EPA’s recent, extensivepublic outreach process. The input wereceived ranged from the states’ desiresfor flexibility and recognition of varyingstate circumstances to the success thatstates and companies have had inadopting a range of pollution—anddemand-reduction strategies. The state-specific approach embodied in bothCAA section 111(d) and this proposalrecognizes that ultimately states are themost knowledgeable about their specificcircumstances and are best positioned toevaluate and leverage existing and newgeneration capacity and programs toreduce CO2 emissions.

To meet its goal, each state will beable to design programs that use themeasures it selects, and these mayinclude the combination of buildingblocks most relevant to its specificcircumstances and policy preferences.States may also identify technologies orstrategies that are not explicitlymentioned in any of the four buildingblocks and may use those technologiesor strategies as part of their overall plans(e.g., market-based trading programs orconstruction of new natural combinedcycle units or nuclear plants). Further,the EPA’s approach allows multi-statecompliance strategies.

The agency also recognizes theimportant functional relationshipbetween the period of time over whichmeasures are deployed and thestringency of emission limitations thosemeasures can achieve in a practical andreasonable cost way. Because, for thisproposal, the EPA is proposing a 10-yearperiod over which to achieve the fullrequired CO2 reductions, a period thatbegins more than five years from thedate of this proposal, a state could takeadvantage of this relationship in thedesign of its program by using relevantcombinations of building blocks toachieve its state goal in a manner thatprovides for electricity systemreliability, avoids the creation ofstranded assets and has a reasonablecost.

b. State Goals and FlexibilitiesIn this action, the EPA is proposing

state-specific rate-based goals that stateplans must be designed to meet. Thesestate-specific goals are based on anassessment of the amount of emissionsthat can be reduced at existing fossilfuel-fired EGUs through application ofthe BSER, as required under CAAsection 111(d). The agency is proposing

state-specific final goals that must beachieved by no later than the year 2030.The proposed final goals reflect theEPA’s quantification of adjusted state-average emission rates from affectedEGUs that could be achieved atreasonable cost by 2030 throughimplementation of the four buildingblocks described above.

The EPA recognizes that, with manymeasures, states can achieve emissionreductions in the short-term, though thefull effects of implementation of othermeasures, such as demand-side energyefficiency tEE) programs and theaddition of renewable energy (RE)generating capacity, can take longer.Thus, the EPA is proposing interimgoals that states must meet beginning in2020. The proposed interim goals wouldapply over a 2020—2029 phase-inperiod. They reflect the level ofreductions in CO2 emissions andemission rates and the extent of theapplication of the building blocks thatwould be presumptively approvable ina state plan during the Tamp-up toachieving the final goal.

The EPA is proposing to allow eachstate flexibility with regard to the formof the goal. A state could adopt the rate-based form of the goal established by theEPA or an equivalent mass-based formof the goal. A multi-state approachincorporating either a rate- or mass-based goal would also be approvablebased upon a demonstration that thestate’s plan would achieve theequivalent in stringency, includingcompliance timing, to the state-specificrate-based goal set by the EPA.

We believe that this approach toestablishing requirements for states indeveloping their plans responds both tothe needs of an effectively implementedprogram and to the range of viewpointsexpressed by stakeholders regarding thesimultaneous need for both flexibilityand clear guidance on what wouldconstitute an approvable state plan. Welikewise believe that this approachrepresents a reasonable balance betweentwo competing objectives grounded inCAA section 111(d)—a need for rigorand consistency in calculating emissionreductions reflecting the BSER and aneed to provide the states withflexibility in establishing andimplementing the standards ofperformance that reflect those emissionreductions. The importance of thisbalance is heightened by the fact thatthe operations of the electricity systemitself rely on the flexibility madeavailable and achieved throughdispatching between and amongmultiple interconnected EGUs, demandmanagement and end-use energyefficiency. We view the proposed goals

as providing rigor where required by thestatute with respect to the amount ofemission reductions, while providingstates with flexibility where permittedby the statute, particularly with respectto the range of measures that a statecould include in its plan. This approachrecognizes that state plans for emissionreductions can, and must, be consistentwith a vibrant and growing economyand supply of reliable, affordableelectricity to support that economy. Itfurther reflects the growing trend, asexemplified by many state and localclean energy policies and programs, toshift energy production away fromcarbon-intensive fuels to a modern,more sustainable system that putsgreater reliance on renewable energy,energy efficiency and other low-carbonenergy options.

c. State Plans

1. Plan ApproachEach state will determine, and

include in its plan, emissionperformance levels for its affected EGUsthat are equivalent to the state-specificCO2 goal in the emission guidelines, aswell as the measures needed to achievethose levels and the overall goal. As partof determining these levels, the statewill decide whether it will adopt therate-based form of the goal establishedby the EPA or translate the rate-basedgoal to a mass-based goal. The statemust then establish a standard, or set ofstandards, of performance, as well asimplementing and enforcing measures,to achieve the emission performancelevel specified in the state plan. Thestate may choose the measures it willinclude in its plan to achieve its goal.The state may use the same set ofmeasures as in the EPA’s approach tosetting the goals, or the state may useother or additional measures to achievethe required CO2 reductions.

A state plan must include enforceableCO2 emission limits that apply toaffected EGUs. In doing so, a state planmay take a portfolio approach, whichcould include enforceable CO2 emissionlimits that apply to affected EGUs aswell as other enforceable measures,such as RE and demand-side EEmeasures, that avoid EGU CO2emissions and are implemented by thestate or by another entity. The plan mustalso include a process for reporting onplan implementation, progress towardachieving CO2 goals, andimplementation of corrective actions, ifnecessary. No less frequently than everytwo rolling calendar years, beginningJanuary 1, 2022, the state will berequired to compare emissionperformance achieved by affected EGUs


34838 Federal Register/Vol. 79, No._117/Wednesday, June 18, 2014/Proposed Rules

in the state with the emissionsperformance projected in the state plan,and report that to the EPA.

In this action, the EPA is alsoproposing guidelines for states to followin developing their plans. Theseguidelines include approvabilitycriteria, requirements for state plancomponents, the process and timing forstate plan submittal and the process andtiming for demonstrating achievementof the CO2 emission performance levelin the state plan. The proposedguidelines provide states with optionsfor meeting the state-specific goalsestablished by the EPA in a flexiblemanner that accommodates a diverserange of state approaches. The planguidelines provide the states with theability to achieve the full reductionsover a multi-year period, through avariety of reduction strategies, usingstate-specific or multi-state approachesthat can be achieved on either a rate ormass basis. They also address severalkey policy considerations that states canbe expected to contemplate indeveloping their plans.

With respect to the structure of thestate plans, the EPA, in its extensiveoutreach efforts, heard from a widerange of stakeholders that the EPAshould authorize state plans to includea portfolio of actions that encompass adiverse set of programs and measuresthat achieve either a rate-based or mass-based emission performance level foraffected EGUs but that do not place legalresponsibility for achieving the entireamount of the emission performancelevel on the affected EGUs. In view ofthis strong sentiment from stakeholders,the EPA is proposing that state plansthat take this portfolio approach wouldbe approvable, provided that they meetother key requirements such asachieving the required emissionreductions over the appropriatetimeframes. Plans that do directly assurethat affected EGUs achieve all of therequired emission reductions (such asthe mass-based programs beingimplemented in California and the RGGIstates) would also be approvableprovided that they meet other keyrequirements, such as achieving therequired emission reductions over theappropriate timeframes.

ii. State Plan ComponentsThe EPA is proposing to evaluate and

approve state plans based on fourgeneral criteria: (1) Enforceablemeasures that reduce EGU CO2emissions; (2) projected achievement ofemission performance equivalent to thegoals established by the EPA, on atimeline equivalent to that in theemission guidelines; (3) quantifiable

and verifiable emission reductions; and(4) a process for reporting on planimplementation, progress towardachieving CO2 goals, andimplementation of corrective actions, ifnecessary. In addition, each state planmust follow the EPA frameworkregulations at 40 CFR 60.23. Theproposed components of states plansare:• Identification of affected entities• Description of plan approach and

geographic scope• Identification of state emission

performance level• Demonstration that plan is projected

to achieve emission performance level• Identification of emission standards• Demonstration that each emission

standard is quantifiable, non-duplicative, permanent, verifiable,and enforceable

• Identification of monitoring,reporting, and recordkeepingrequirements

• Description of state reporting• Identification of milestones• Identification of backstop measures• Certification of hearing on state plan• Supporting material

iii. Process for State Plan Submittal andReview

Recognizing the urgent need foractions to reduce GHG emissions, and inaccordance with the PresidentialMemorandum,10 the EPA expects tofinalize this rulemaking by June 1, 2015.The Presidential Memorandum alsocalls for a deadline of June 30, 2016, forstates to submit their state plans. TheEPA is proposing that each state mustsubmit a plan to the EPA by June 30,2016. However, the EPA recognizes thatsome states may need more than oneyear to complete all of the actionsneeded for their final state plans,including technical work, statelegislative and rulemaking activities,coordination with third parties, andcoordination among states involved inmulti-state plans. Therefore, the EPA isproposing an optional two-phasedsubmittal process for state plans. Eachstate would be required to submit a planby June 30, 2016, that contains certainrequired components. If a state needsadditional time to submit a completeplan, then the state must submit aninitial plan byJune 30, 2016 thatdocuments the reasons the state needsmore time and includes commitments toconcrete steps that will ensure that the

10 Presidential Memorandum—Power SectorCarbon Pollution Standards, June 25, 2013. hftp://www. whitehouse.gov/the-press-office/201 3/06/25/presidenticl-memorandum-power-sector-carbonpollution-stondards.

state will submit a complete plan byJune 30, 2017 or 2018, as appropriate.To be approvable, the initial plan mustinclude specific components, includinga description of the plan approach,initial quantification of the level ofemission performance that will beachieved in the plan, a commitment tomaintain existing measures that limitCO2 emissions, an explanation of thepath to completion, and a summary ofthe state’s response to any significantpublic comment on the approvabiity ofthe initial plan, as described in SectionVffl.E of this preamble.

If the initial plan includes thosecomponents and if the EPA does notnotify the state that the initial plan doesnot contain the required components,the extension of time to submit acomplete plan will be deemed grantedand a state would have until June 30,2017, to submit a complete plan if thegeographic scope of the plan is limitedto that state. if the state develops a planthat includes a multi-state approach, itwould have until June 30, 2018 tosubmit a complete plan. Further, theEPA is proposing that statesparticipating in a multi-state plan maysubmit a single joint plan on behalf ofall of the participating states.

Following submission of final plans,the EPA will review plan submittals forapprovability. Given the diverseapproaches states may take to meet theemission performance goals in theemission guidelines, the EPA isproposing to extend the period for EPAreview and approval or disapproval ofplans from the four-month periodprovided in the EPA frameworkregulations to a twelve-month period.

iv. Timing of ComplianceAs states, industry groups and other

stakeholders have made clear, the EPArecognizes that the measures states havebeen and will be taking to reduce CO2emissions from existing EGUs can taketime to implement. Thus, we areproposing that, while states must beginto make reductions by 2020, fullcompliance with the CO2 emissionperformance level in the state plan mustbe achieved by no later than 2030.Under this proposed option, a statewould need to meet an interim CO2emission performance level on averageover the 10-year period from 2020—202 9,as well as achieve its final CO2 emissionperformance level by 2030 and maintainthat level subsequently. This proposedoption is based on the application of arange of measures from all four buildingblocks, and the agency believes that thisapproach for compliance timing isreasonable and appropriate and wouldbest support the optimization of overall



CO2 reductions. The agency is alsorequesting comment on an alternativeoption, a 5-year period for compliance,in combination with a less stringent setof CO2 emission performance levels.These options are fully described inSection Vifi of this preamble, and thestate goals associated with thealternative option are described inSection VII.E of this preamble. The EPAis also seeking comment on differentcombinations of building blocks anddifferent levels of stringency for eachbuilding block.

The EPA is also proposing thatmeasures that a state takes after the dateof this proposal, or programs already inplace, which result in CO2 emissionreductions during the 2020—2030period, would apply towardachievement of the state’s 2030 CO2emission goal. Thus, states withcurrently existing programs andpolicies, and states that put in placenew programs and policies early, will bebetter positioned to achieve the goals.

v. Resources for StatesTo respond to requests from states for

methodologies, tools and information toassist them in designing andimplementing their plans, the EPA, inconsultation with the U.S. Departmentof Energy and other federal agencies, aswell as states, is collecting anddeveloping available resources and ismaking those resources available to thestates via a dedicated Web site.11 As weand others continue to develop tools,templates and other resources, we willupdate the Web site. We intend, duringthe public comment period, to workactively with the states on resources thatwill be helpful to them in bothdeveloping and implementing theirplans.

3. Projected National-Level EmissionReductions

Under the proposed guidelines, theEPA projects annual CO2 reductions of26 to 30 percent below 2005 levelsdepending upon the compliance year.These guidelines will also result inimportant reductions in emissions ofcriteria air pollutants, including sulfurdioxide (SO2), nitrogen oxides (NOx)and directly emitted fine particulatematter (PM2.5). A thorough discussion ofthe EPA’s analysis is presented in

llwww2.epa.gov/cleanpowerplantoolbox.

Section X.A of this preamble and inChapter 3 of the Regulatory ImpactAnalysis (RIA) included in the docketfor this rulemaking.

4. Costs and BenefitsActions taken to comply with the

proposed guidelines will reduceemissions of CO2 and other airpollutants, including SO, NO anddirectly emitted PM2.5, from the electricpower industry. States will make theultimate determination as to how theemission guidelines are implemented.Thus, all costs and benefits reported forthis action are illustrative estimates. TheEPA has calculated illustrative costs andbenefits in two ways: One based on anassumption of individual state plansand another based on an assumptionthat states will opt for multi-state plans.The illustrative costs and benefits arebased upon compliance approaches thatreflect a range of measures consisting ofimproved operations at EGUs,dispatching lower-emitting EGUs andzero-emitting energy sources, andincreasing levels of end-use energyefficiency.

Assuming that states comply with theguidelines collaboratively (referred to asthe regional compliance approach), theEPA estimates that, in 2020, thisproposal will yield monetized climatebenefits of approximately $17 billion(2011$) using a 3 percent discount rate(model average) relative to the 2020 basecase, as shown in Table 1.12 The airpollution health co-benefits associatedwith reducing exposure to ambientPM2.5 and ozone through emissionreductions of precursor pollutants in2020 are estimated to be $16 billion to$37 billion using a 3 percent discountrate and $15 billion to $34 billion(2011$) using a 7 percent discount raterelative to the 2020 base case. Theannual compliance costs are estimatedusing the Integrated Planning Model(1PM) and include demand-side energyefficiency program and participant costs

as well as monitoring, reporting andrecordkeeping costs. In 2020, totalcompliance costs of this proposal areapproximately $5.5 billion (2011$). Thequantified net benefits (the differencebetween monetized benefits andcompliance costs) in 2020 are estimatedto be $28 billion to $49 billion (2011$)using a 3 percent discount rate (modelaverage). As reflected in Table 2, climatebenefits are approximately $30 billionin 2030 using a 3 percent discount rate(model average, 2011$) relative to the2030 base case assuming a regionalcompliance approach for the proposal.Health co-benefits are estimated to beapproximately $25 to $59 billion (3percent discount rate) and $23 to $54billion (7 percent discount rate) relativeto the 2030 base case (2011$). In 2030,total compliance costs for the proposedoption regional approach areapproximately $7.3 billion (2011$). Thenet benefits for this proposal increase toapproximately $48 billion to $82 billion(3 percent discount rate model average,2011$) in 2030 for the proposed optionregional compliance approach.

In comparison, if states choose tocomply with the guidelines on a state-specific basis (referred to as statecompliance approach), the climatebenefits in 2020 are expected to beapproximately $18 billion (3 percentdiscount rate, model average, 2011$), asTable 1 shows. Health co-benefits areestimated to be $17 to $40 billion (3percent discount rate) and $15 to $36billion (7 percent discount rate). Totalcompliance costs are approximately$7.5 billion annually in 2020. Netbenefits in 2020 are estimated to be $27to $50 billion (3 percent model averagediscount rate, 2011$). In 2030, as shownon Table 2, climate benefits areapproximately $31 billion using a 3percent discount rate (model average,2011$) relative to the 2030 base caseassuming a state compliance approach.Health co-benefits are estimated to beapproximately $27 to $62 billion (3percent discount rate) and $24 to $56billion (7 percent discount rate) relativeto the 2030 base case (2011$). In 2030,total compliance costs for the stateapproach are approximately $8.8 billion(2011$). In 2030, these net benefits areestimated to be approximately $49 to$84 billion (3 percent discount rate,2011$) assuming a state complianceapproach.

12 EPA has used social cost of carbon (SCC)estimates—i.e., the monetary value of impactsassociated with a marginal change in CO2 emissionsin a given year—to analyze CO2 climate impacts ofthis rulemaking. The four scc estimates areassociated with different discount rates (modelaverage at 2.5 percent discount rate, 3 percent, and5 percent; 95th percentile at 3 percent), and eachincreases over time. In this summary, the EPAprovides the estimate of climate benefits associatedwith the SCC value deemed to be central: Themodel average at 3 percent discount rate.



TABLE 1—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR THE PROPOSEDGUIDELINES IN 2020 a

[Billions of 2011$]

3% Discount rate 7% Discount rate

Proposed Guidelines Regional Compliance Approach

Climate benefitsb$17.

Air pollution health cobenefitsc $16 to $37 $15 to $34.Total Compliance Costs

U $5.5 $5.5.Net Monetized Benefits e $28 to $49 $26 to $45.

Non-monetized Benefits Direct exposure to SO2 and NO2.1.3 tons of Hg.Ecosystem Effects.Visibility impairment.

Proposed Guidelines State Compliance Approach

Climate benefitsb $18

Air pollution health cobenefitsC $17 to $40 $15 to $36.Total Compliance Costsd $7.5 $7.5.Net Monetized Benefits a $27 to $50 $26 to $46.

Non-monetized Benefits Direct exposure to SO2 and NO2.1.5 tons.Ecosystem effects.Visibility impairment.

aAIl estimates are for 2020, and are rounded to two significant figures, so figures may not sum.bThe climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does not account for changes in

non-CO2 GHG emissions. Also, different discount rates are applied to SCC than to the other estimates because CO2 emissions are long-livedand subsequent damages occur over many years. The benefit estimates in this table are based on the average SCC estimated for a 3% discount rate, however we emphasize the importance and value of considering the full range of SCC values. As shown in the RIA, climate benefitsare also estimated using the other three SCC estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at3 percent). The SCC estimates are year-specific and increase over time.

cThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emittedPM2.5, SO2 and NON. The range reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 90 percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fineparticles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yetsufficient to allow differentiation of effect estimates by particle type.

dTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the proposed guidelinesand a discount rate of approximately 5%. This estimate includes monitoring, recordkeeping, and reporting costs and demand side energy efficiency program and participant costs.

eThe estimates of net benefits in this summary table are calculated using the global social cost of carbon at a 3 percent discount rate (modelaverage). The RIA includes combined climate and health estimates based on these additional discount rates.

TABLE 2—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR THE PROPOSEDGUIDELINES IN 2030 a

[Billions of 2011$]


Proposed Guidelines Regional Compliance Approach

Climate benefits b $30.

Air pollution health C $25 to $59 $23 to $54.Total Compliance Costs d $7.3 $7.3.Net Monetized 0 $48 to $82 $46 to $77.

Non-monetized Benefits Direct exposure to SO2 and NO2.1.7 tons of Hg and 580 tons of HCI.Ecosystem Effects.Visibility impairment.

Proposed Guidelines State Compliance Approach

Climate benefitsb $31.

Air pollution health co-benefits c $27 to $62 $24 to $56.Total Compliance Costsd $8.8 $8.8.Net Monetized Benefits e $49 to $84 $46 to $79.


federal Register/ Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34841

TABLE 2—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR THE PROPOSEDGUIDELINES IN 2030 a__Continued

[Billions of 2011$]


Non-monetized Benefits Direct exposure to SO2 and NO2.2.1 tons of Hg and 590 tons of HCI.Ecosystem effects.Visibility impairment.

aAll estimates are for 2030, and are rounded to two significant figures, so figures may not sum.bThe climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does not account for changes in non-CO2 GHG emis

sions. Also, different discount rates are applied to SCC than to the other estimates because CO2 emissions are long-lived and subsequent damages occur over manyyears. The benefit estimates in this table are based on the average SCC estimated for a 3% discount rate, however we emphasize the importance and value of considertng the full range of SCC values. As shown in the RIA, climate benefits are also estimated using the other three SCC estimates (model average at 2.5 percentdiscount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SCC estimates are year-specific and increase over time.cIhe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emitted PM2.5, SO2 and NON. Therange reflects the use of concentration-response functions from different epidemiology studies. The reduction In premature fatalities each year accounts for over 90percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potentin causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type.dTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the proposed guidelines and a discount rate ofapproximately 5%. This estimate includes monitoring, recordkeeping, and reporting costs and demand side energy efficiency program and participant costs.eThe estimates of net benefits in this summary table are calculated usin9 the global social cost of carbon at a 3 percent discount rate (model average). The RIA Includes combined climate and health estimates based on these additional discount rates.

There are additional importantbenefits that the EPA could notmonetize. These unquantified benefitsinclude climate benefits from reducingemissions of non-CO2 greenhouse gases(e.g., nitrous oxide and methane) 13 andco-benefits from reducing directexposure to 502, NOx and hazardous airpollutants (e.g., mercury and hydrogenchloride), as well as from reducingecosystem effects and visibilityimpairment.

In addition to the cost and benefits ofthe nile, the EPA projects theemployment impacts of the guidelines.We project job gains and losses relativeto base case for the electric generation,coal and natural gas production, anddemand side energy efficiency sectors.In 2020, we project job growth of 25,900to 28,000 job-years’4 in the powerproduction and fuel extraction sectors,and we project an increase of 78,800jobs in the demand-side energyefficiency sector.

Based upon the foregoing, it is clearthat the monetized benefits of thisproposal are substantial and faroutweigh the costs.

B. Organization and Approach for ThisProposed Rule

This action presents the EPA’sproposed emission guidelines for statesto consider in developing plans toreduce GHG emissions from the electric

‘Although CO2 is the predominant greenhousegas released by the power sector, electricitygenerating units also emit small amounts of nitrousoxide and methane. See RIA Chapter 2 for moredetail about power sector emissions and the U.S.Greenhouse Gas Reporting Program’s power sectorsummary, http://www.epa.gov/ghgreporting/ghgdata/reported/powerplants.html.

‘A job-year is not an individual job; rather, ajob-year is the amount of work performed by theequivalent of one full-time individual for one year.For example, 20 job-years in 2020 may represent 20full-time jobs or 40 half-time jobs.

power sector. Section II providesbackground on climate change impactsfrom GHG emissions, GHG emissionsfrom fossil fuel-fired EGUs and theutility power sector and CAA section111(d) requirements. Section ifi presentsa summary of the EPA’s stakeholderoutreach efforts, key messages providedby stakeholders, state policies andprograms that reduce GHG emissions,and conclusions. In Section IV of thepreamble, we present a summary of therule requirements and the regal basis forthese. Section V explains the EPAauthority to regulate CO2 and EGUs,identifies affected sources, anddescribes the proposed treatment ofsource categories. Section VI describesthe use of building blocks for settingstate goals and key considerations indoing so. Sections VII and Vifi provideexplanations of the proposed state-specific goals and the proposedrequirements for state plans,respectively. hnplications for the newsource review and Title V programs andpotential interactions with other EPArules are described in Section IX.Impacts of the proposed action are thendescribed in Section X, followed by adiscussion of statutory and executiveorder reviews in Section XI and thestatutory authority for this action inSection XII.

We note that this rulemaking overlapsin certain respects with two otherrelated rulemakings: The January 2014proposed rulemaking that the EPApublished on January 8, 2014 for CO2emissions from newly constructedaffected sources,’5 and the rulemakingfor modified and reconstructed sourcesthat the EPA is proposing at the sametime as this rulemaking. Each of thesethree rulemakings is independent of the

15 79 FR 1430.

other two, and each has its ownrulemaking docket. Accordingly,commenters who wish to comment onany aspect of this rulemaking, includinga topic that overlaps an aspect of one orboth of the other two relatedrulemaldngs, should make thosecomments on this rulemaking.

II. BackgroundIn this section, we discuss climate

change impacts from GHG emissions,both on public health and publicwelfare, present information about GHGemissions from fossil fuel fired EGUs,and summarize the statutory andregulatory requirements relevant to thisrulemaking.

A. Climate Change Impacts From GHGEmissions

In 2009, the EPA Administratorissued the document known as theEndangerment Finding under CAAsection 202(a)(1).16 In the EndangermentFinding, which focused on publichealth and public welfare impactswithin the United States, theAdministrator found that elevatedconcentrations of GHGs in theatmosphere may reasonably beanticipated to endanger public healthand welfare of current and futuregenerations. We summarize theseadverse effects on public health andwelfare briefly here.

1. Public Health Impacts Detailed in the2009 Endangerment Finding

Climate change caused by humanemissions of GHGs threatens publichealth in multiple ways. By raisingaverage temperatures, climate change

16”Endangerment and Cause or ContributeFindings for Greenhouse Gases Under Section202(a) of the Clean Air Act,” 74 FR 66,496 (Dec. 15,2009) (“Endangerment Finding”).



increases the likelihood of heat waves,which are associated with increaseddeaths and illnesses. While climatechange also increases the likelihood ofreductions in cold-related mortality,evidence indicates that the increases inheat mortality will be larger than thedecreases in cold mortality in theUnited States. Compared to a futurewithout climate change, climate changeis expected to increase ozone pollutionover broad areas of the U.S., includingin the largest metropolitan areas withthe worst ozone problems, and therebyincrease the risk of morbidity andmortality. Other public health threatsalso stem from projected increases inintensity or frequency of extremeweather associated with climate change,such as increased hurricane intensity,increased frequency of intense storms,and heavy precipitation. Increasedcoastal storms and storm surges due torising sea levels are expected to causeincreased drownings and other healthimpacts. Children, the elderly, and thepoor are among the most vulnerable tothese climate-related health effects.

2. Public Welfare Impacts Detailed inthe 2009 Endangerment Finding

Climate change caused by humanemissions of GHGs also threatens publicwelfare in multiple ways. Climatechanges are expected to place largeareas of the country at serious risk ofreduced water supplies, increased waterpollution, and increased occurrence ofextreme events such as floods anddroughts. Coastal areas are expected toface increased risks from storm andflooding damage to property, as well asadverse impacts from rising sea level,such as land loss due to inundation,erosion, wetland submergence andhabitat loss. Climate change is expectedto result in an increase in peakelectricity demand, and extremeweather from climate change threatensenergy, transportation, and waterresource infrastructure. Climate changemay exacerbate ongoing environmentalpressures in certain settlements,particularly in Alaskan indigenouscommunities. Climate change also isvery likely to fundamentally rearrangeU.S. ecosystems over the 21st century.Though some benefits may balanceadverse effects on agriculture andforestry in the next few decades, thebody of evidence points towardsincreasing risks of net adverse impactson U.S. food production, agriculture andforest productivity as temperaturecontinues to rise. These impacts areglobal and may exacerbate problemsoutside the U.S. that raise humanitarian,trade, and national security issues forthe U.S.

3. New Scientific Assessments

As outlined in Section Vffl.A. of the2009 Endangerment Finding, the EPA’sapproach to providing the technical andscientific information to inform theAdministrator’s judgment regarding thequestion of whether GHGs endangerpublic health and welfare was to relyprimarily upon the recent, majorassessments by the U.S. Global ChangeResearch Program (USGCRP), theIntergovernmental Panel on ClimateChange (WCC), and the NationalResearch Council (NRC) of the NationalAcademies. These assessmentsaddressed the scientific issues that theEPA was required to examine, werecomprehensive in their coverage of theGHG and climate change issues, andunderwent rigorous and exacting peerreview by the expert community, aswell as rigorous levels of U.S.government review. Since theadministrative record concerning theEndangerment Finding closed followingthe EPA’s 2010 Reconsideration Denial,a number of such assessments have beenreleased. These assessments include thePCC’s 2012 “Special Report onManaging the Risks of Extreme Eventsand Disasters to Advance ClimateChange Adaptation” (SREX) and the2013—2014 Fifth Assessment Report(AR5), the USGCRP’s 2014 “ClimateChange Impacts in the United States”(Climate Change Impacts), and theNRC’s 2010 “Ocean Acidification: ANational Strategy to Meet the Challengesof a Changing Ocean” (OceanAcidification), 2011 “Report on ClimateStabilization Targets: Emissions,Concentrations, and Impacts overDecades to Millennia” (ClimateStabilization Targets), 2011 “NationalSecurity Implications for U.S. NavalForces” (National Securitylinplications), 2011 “UnderstandingEarth’s Deep Past: Lessons for OurClimate Future” (Understanding Earth’sDeep Past), 2012 “Sea Level Rise for theCoasts of California, Oregon, andWashington: Past, Present, and Future”,2012 “Climate and Social Stress:Implications for Security Analysis”(Climate and Social Stress), and 2013“Abrupt Impacts of Climate Change”(Abrupt Impacts) assessments.

The EPA has reviewed these newassessments and finds that the improvedunderstanding of the climate systemthey present strengthens the case thatGHGs endanger public health andwelfare.

In addition, these assessmentshighlight the urgency of the situation asthe concentration of CO2 in theatmosphere continues to rise. Absent areduction in emissions, a recent

National Research Council of theNational Academies assessmentprojected that concentrations by the endof the century would increase to levelsthat the Earth has not experienced formillions of years.’7 In fact, thatassessment stated that “the magnitudeand rate of the present greenhouse gasincrease place the climate system inwhat could be one of the most severeincreases in radiative forcing of theglobal climate system in Earthhistory.” 18

What this means, as stated in anotherNRC assessment, is that:

Emissions of carbon dioxide from theburning of fossil fuels have ushered in a newepoch where human activities will largelydetermine the evolution of Earth’s climate.Because carbon dioxide in the atmosphere islong lived, it can effectively lock Earth andfuture generations into a range of impacts,some of which could become very severe.Therefore, emission reductions choices madetoday matter in determining impactsexperienced not just over the next fewdecades, but in the coming centuries andmillennia.1

Moreover, due to the time-lagsinherent in the Earth’s climate, theClimate Stabilization Targets assessmentnotes that the full warming from anygiven concentration of CO2 reached willnot be realized for several centuries.

The recently released USGCRP“Climate Change Impacts” 20

emphasizes that climate change isalready happening now and it ishappening in the United States. Theassessment documents the increases insome extreme weather and climateevents in recent decades, the damageand disruption to infrastructure andagriculture, and projects continuedincreases in impacts across a wide rangeof peoples, sectors, and ecosystems.

These assessments underscore theurgency of reducing emissions now:Today’s emissions will otherwise leadto raised atmospheric concentrations forthousands of years, and raised Earthsystem temperatures for even longer.Emission reductions today will benefitthe public health and public welfare ofcurrent and future generations.

Finally, it should be noted that theconcentration of carbon dioxide in theatmosphere continues to risedramatically. In 2009, the year of theEndangerment Finding, the averageconcentration of carbon dioxide as

‘National Research council, UnderstandingEarth’s Deep Past, p. 1.

laId., p.138.

19Nationai Research Council, ClimateStabilization Targets, p. 3.

20 U.S. Global Change Research Program, climatechange Impacts in the United States: The ThirdNational Climate Assessment, May 2014 Availableat hftp://nca2Ol 4.globalchange.gov/.



measured on top of Mauna Loa was 387parts per million.21 The averageconcentration in 2013 was 396 parts permillion. And the monthly concentrationin April of 2014 was 401 parts permillion, the first time a monthly averagehas exceeded 400 parts per millionsince record keeping began at MaunaLoa in 1958, and for at least the past800,000 years according to ice corerecords.ZZ

B. GHG Emissions From Fossil FuelFired EGUs

Fossil fuel-fired electric utilitygenerating units (EGUs) are by far thelargest emitters of GHGs, primarily inthe form of C02, among stationarysources in the U.S., and among fossilfuel-fired units, coal-fired units are byfar the largest emitters. This sectiondescribes the amounts of thoseemissions and places those amounts inthe context of the national inventory ofGHGs.

The EPA prepares the official U.S.Inventory of Greenhouse Gas Emissionsand Sinks 23 (the U.S. GHG Inventory) tocomply with commitments under theUnited Nations Framework Conventionon Climate Change (UNFCCC). Thisinventory, which includes recent trends,is organized by industrial sectors. Itprovides the information in Table 3below, which presents total U.S.anthropogenic emissions and sinks ofGHGs, including CO2 emissions, for theyears 1990, 2005 and 2012.

TABLE 3—U.S. GHG EMISSIONS AND SINKS BY SECTOR[Teragram carbon dioxide equivalent (Tg CO2 Eq.)]25

Sector 1990 2005 2012

Energy 5,260.1 6,243.5 5,498.9Industrial Processes 316.1 334.9 334.4Solvent and Other Product Use 4.4 4.4 4.4Agriculture 473.9 512.2 526.3Land Use, Land-Use Change and Forestry 13.7 25.5 37.8Waste 165.0 133.2 124.0

Total Emissions 6,233.2 7,253.8 6,525.6Land Use, Land-Use Change and Forestry (Sinks) (831.3) (1,030.7) (979.3)

Net Emissions (Sources and Sinks) 5,402.1 6,223.1 5,546.3

GHG emissions.26 In 2012, fossil fuel 38.7 percent of all energy-related CO2Total fossil energy-related CO2 combustion by the electric power emissions.27 Table 4 below presents

emissions (including both stationary sector—entities that burn fossil fuel and total CO2 emissions from fossil fuel-and mobile sources) are the largest whose primary business is the fired EGUs, for years 1990, 2005 andcontributor to total U.S. GHG emissions, generation of electricity—accounted for 2012.representing 77.7 percent of total 2012

TABLE 4—U.S. GHG EMISSIONS FROM GENERATION OF ELECTRICITY FROM COMBUSTION OF FOSSIL FUELS[Tg CO2]28

GHG emissions 1990 2005 2012

Total CO2 from fossil fuel combustion EGUs 1,820.8 2,402.1 2,022.7—from coal 1,547.6 1,983.8 1,511.2—from natural gas 175.3 318.8 492.2—from petroleum 97.5 99.2 18.8

C. The Utility Power Sector

Electricity in the United States isgenerated by a range of sources—frompower plants that use fossil fuels likecoal, oil, and natural gas, to non-fossil

2lftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_unnmean_mlo.txt.

22http://www.esrl.noaa.gov/gmd/ccgg/trends/.23’Inventory of U.S. Greenhouse Gas Emissions

and Sinks: 1990—2012”, Report EPA 430—R—14—003,United States Environmental Protection Agency,April 15, 2014.

24nks are a physical unit or process that storesGHGs, such as forests or underground or deep seareservoirs of carbon dioxide.

25 Table ES—4 of “Inventory of U.S.Greenhouse Gas Emissions and Sinks: 1990—2012,

sources, such as nuclear, solar, windand hydroelectric power. In 2013, over67 percent of power in the U.S. wasgenerated from the combustion of coal,natural gas, and other fossil fuels, over40 percent from coal and over 26percent from natural gas.29 In recent

Report EPA 430—R—14—003, United StatesEnvironmental Protection Agency, April 15, 2014.

26From Table ES—2 “Inventory of U.S.Greenhouse Gas Emissions and Sinks: 1990—2012”,Report EPA 430—R—14—003, United StatesEnvironmental Protection Agency, April 15, 2014.

27 Table 3—1 “Inventory of U.S. GreenhouseGas Emissions and Sinks: 1990—2012”, Report EPA430—R—14—003, United States EnvironmentalProtection Agency, April 15, 2014.

20 Table 3—5 “Inventory of U.S. GreenhouseGas Emissions and Sinks: 1990—2012”, Report EPA430—R—14—003, United States EnvironmentalProtection Agency, April 15, 2014.

years, though, the proportion of newrenewable generation coming on linehas increased dramatically. Forinstance, over 38 percent of newgenerating capacity (over 5 GW out of13.5 GW) built in 2013 used renewablepower generation technologies.30

29US Energy Information Administration (EIA),“Table 7.2b Electricity Net Generation: ElectricPower Sector Electric Power Sector,” data fromApril 2014 Monthly Energy Review, release dateApril 25, 2014. Available at: hftp://www.eia.gov/totalenergy/data/browserlxls.cfm?tbl—_To7.02B&fteq=m.

30Based on Table 6.3 (New Utility ScaleGenerating Units by Operating Company, Plant,Month, and Year) of the U.S. Energy InformationAdministration (EIA) Electric Power Monthly, datafor December 2013, for the following renewable

Continued



This range of different power plantsgenerates electricity that is transmittedand distributed through a complexsystem of interconnected components toindustrial, business, and residentialconsumers.

The utility power sector is unique inthat, unlike other sectors where thesources operate independently and on alocal scale, power sources operate in acomplex, interconnected grid systemthat typically is regional in scale. Inaddition, the U.S. economy depends onthis sector for a reliable supply of powerat a reasonable cost.

In the U.S., much of the existingpower generation fleet in theinfrastructure is aging. There has been,and continues to be, technologicaladvancement in many areas, includingenergy efficiency, solar powergeneration, and wind power generation.Advancements and innovation in powersector technologies provide theopportunity to address CO2 emissionlevels at affected power plants while atthe same time improving the overallpower system in the U.S. by loweringthe carbon intensity of powergeneration, and ensuring a continuedreliable supply of power at a reasonablecost.

D. Statutory and RegulatoryRequirements

Clean Air Act section 111, whichCongress enacted as part of the 1970Clean Air Act Amendments, establishesmechanisms for controlling emissions ofair pollutants from stationary sources.This provision requires the EPA topromulgate a list of categories ofstationary sources that theAdministrator, in his or her judgment,finds “causes, or contributessignificantly to, air pollution which mayreasonably be anticipated to endangerpublic health or welfare.”3’ The EPAhas listed more than 60 stationarysource categories under this provision.32Once the EPA lists a source category,the EPA must, under CAA section111(b)(i)(B), establish “standards ofperformance” for emissions of airpollutants from new sources in thesource categories.33 These standards areknown as new source performancestandards (NSPS), and they are nationalrequirements that apply directly to thesources subject to them.

When the EPA establishes NSPS fornew sources in a particular source

energy sources: solar, wind, hydro, geothermal,landfill gas, and biomass. Available at: http://www.eia.gov/electhcity/monthly/epm_table_grapher.cfm?t=epmt_6_03.

3’ CAA § 111(b)(1)(A).40 CFR 60 subparts Cb—0000.

33CAA §1ii(b](1)(B), 111(a)(1).

category, the EPA is also required,under CAA section iii(d)(1), toprescribe regulations for states to submitplans regulating existing sources in thatsource category for any air pollutantthat, in general, is not regulated underthe CAA section 109 requirements forthe NAAQS or regulated under the CAAsection 112 requirements for hazardousair pollutants (HAP). CAA section111(d)’s mechanism for regulatingexisting sources differs from the onethat CAA section 111(b) provides fornew sources because CAA section111(d) contemplates states submittingplans that establish “standards ofperformance” for the affected sourcesand that contain other measures toimplement and enforce those standards.

“Standards of performance” aredefined under CAA section 111(a)(1) asstandards for emissions that reflect theemission limitation achievable from the“best system of emission reduction,”considering costs and other factors, that“the Administrator determines has beenadequately demonstrated.” CAA sectionlii(d)(i) grants states the authority, inapplying a standard of performance toparticular sources, to take into accountthe source’s remaining useful life orother factors.

Under CAA section 111(d), a statemust submit its plan to the EPA forapproval, and the EPA must approve thestate plan if it is “satisfactory.” If astate does not submit a plan, or if theEPA does not approve a state’s plan,then the EPA must establish a plan forthat state.35 Once a state receives theEPA’s approval for its plan, theprovisions in the plan become federallyenforceable against the entityresponsible for noncompliance, in thesame manner as the provisions of anapproved SIP under CAA section 110.Although affected EGUs located inIndian country operate as part of theinterconnected system of electricityproduction and distribution, those EGUswould not be encompassed within astate’s CAA section 111(d) plan. Instead,a tribe that has one or more affectedEGUs located in its area of Indiancountry36 would have the opportunity,but not the obligation, to establish aplan that establishes standards of

‘4CAA section 111(d)(2)(A).“CAA section 111(d)(2)(A].35 EPA is aware of at least four affected

sources located in Indian Country: Two on Navajolands—the Navajo Generating Station and the FourCorners Generating Station; one on Ute lands—theBonanza Generating Station; and one on FortMojave lands, the South Point Energy Center. Theaffected EGUs at the first three plants are coal-firedEGUs. The fourth affected EGU is an NGCC facility.

performance for CO2 emissions fromaffected EGUs for its tribal lands.

The EPA issued regulationsimplementing CAA section 111(d) in1975, and has revised them in theyears since.38 (We refer to theregulations generally as theimplementing regulations, and we referto the 1975 rulemaking as theframework regulations.) Theseregulations provide that, inpromulgating requirements for sourcesunder CAA section 111(d), the EPA firstdevelops regulations known as“emission guidelines,” which establishbinding requirements that states mustaddress when they develop theirplans.39 The implementing regulationsalso establish timetables for state andEPA action: States must submit stateplans within 9 months of the EPA’sissuance of the guidelines,40 and theEPA must take final action on the stateplans within 4 months of the due datefor those plans,4’ although the EPA hasauthority to extend those deadlines.42 Inthe present rulemaking, the EPA isfollowing the requirements of theimplementing regulations, and is not reopening them, except that the EPA isextending the timetables, as describedbelow.

Over the last forty years, under CAAsection 111(d), the agency has regulatedfour pollutants from five sourcecategories (i.e., sulfuric acid plants (acidmist), phosphate fertilizer plants(fluorides), primary aluminum plants(fluorides), Kraft pulp plants (totalreduced sulfur), and municipal solidwaste landfills (landfill gases)).43 Inaddition, the agency has regulatedadditional pollutants under CAAsection 111(d) in conjunction with CAA

‘7”State Plans for the Control of CertainPollutants From Existing Facilities,” 40 FR 53,340(Nov. 17, 1975).

38 most recent amendment was in 77 FR 9304(Feb. 16, 2012).

3940 CFR 60.22. In the 1975 rulemaldng, the EPAexplained that it used the term “emissionsguidelines”—instead of emissions limitations—tomake clear that guidelines would not be bindingrequirements applicable to the sources, but insteadare ‘criteria for judging the adequacy of Stateplans.” 40 FR at 53,343.

°40 CFR 60.23(a)(1).4140 CFR 60.27(b).425ee 40 CFR 60.27(a).

See “Phosphate Fertilizer Plants; FinalGuideline Document Availability,” 42 Fed. Reg.12,022 (Mar. 1, 1977); “Standards of Performancefor New Stationary Sources; Emission Guideline forSulfuric Acid Mist,” 42 FR 55,796 (Oct. 18, 1977);“Kraft Pulp Mills, Notice of Availability of FinalGuideline Document,” 44 FR 29,828 (May 22,1979); “Primary Aluminum Plants; Availability ofFinal Guideline Document,” 45 FR 26,294 (Apr. 17,1980); “Standards of Performance for NewStationary Sources and Guidelines for Control ofExisting Sources: Municipal Solid Waste Landfills,Final Rule,” 61 FR 9905 (Mar. 12, 1996).



section 129. The agency has notpreviously regulated CO2 or any othergreenhouse gas under CAA section111(d).

The EPA’s previous CAA section111(d) actions were necessarily gearedtoward the pollutants and industriesregulated. Similarly, in this proposedrulemaking, in defining CAA section111(d) emission guidelines for the statesand determining the BSER, the EPAbelieves that taking into account theparticular characteristics of carbonpollution, the interconnected nature ofthe power sector and the manner inwhich EGUs are currently operated iswarranted. Specifically, the operatorsthemselves treat increments ofgeneration as interchangeable betweenand among sources in a way that createsoptions for relying on varyingutilization levels, lowering carbongeneration, and reducing demand ascomponents of the overall method forreducing CO2 emissions. Doing soresults in a broader, forward-thinldngapproach to the design of programs toyield critical CO2 reductions thatimprove the overall power system bylowering the carbon intensity of powergeneration, while offering continuedreliability and cost-effectiveness. Theseopportunities exist in the power sectorin ways that were not relevant oravailable for other industries for whichthe EPA has established CAA section111(d) emission guidelines.45

In this action, the EPA is proposingemission guidelines for states to followin developing their plans to reduceemissions of CO2 from the electricpower sector.

ff1. Stakeholder Outreach andConclusions

A. Stakehoider Outreach

1. The President’s Call for Engagement

Following the direction of thePresidential Memorandum to theAdministrator (June 25, 2013),46 this

44See, e.g., “Standards of Performance for NewStationary Sources and Emission Guidelines forExisting Sources: Sewage Sludge Incineration Units,Final Rule,” 76 FR 15,372 (Mar. 21, 2011).

45See “Phosphate Fertilizer Plants; FinalGuideline Document Availability,” 42 FR 12,022(Mar. 1, 1977); “Standards of Performance for NewStationary Sources; Emission Guideline for SulfuricAcid Mist,” 42 FR 55,796 (Oct. 18, 1977); “KraftPulp Mills, Notice of Availability of Final GuidelineDocument,” 44 FR 29,828 (May 22, 1979); ‘PrimaryAluminum Plants; Availability of Final GuidelineDocument,” 45 FR 26,294 (Apr. 17, 1980);“Standards of Performance for New StationarySources and Guidelines for Control of ExistingSources: Municipal Solid Waste Landfills, FinalRule,” 61 F R 9905 (Mar. 12, 1996).

46 Memorandum—Power SectorCarbon Pollution Standards, June 25, 2013. http://www.whitehouse.gov/the-press-offlce/201 3/06/25/

proposed rule was developed afterextensive and vigorous outreach tostakeholders and the general public. ThePresidential Memorandum instructedthe Administrator to inaugurate theprocess for developing standardsthrough direct engagement with thestates and a fall range of stakeholders:

Launch this effort through directengagement with States, as they will play acentral role in establishing and implementingstandards for existing power plants, and, atthe same time, with leaders in the powersector, labor leaders, non-governmentalorganizations, other experts, tribal officials,other stakeholders, and members of thepublic, on issues informing the design of theprogram.

2. Educating the Public and StakeholderOutreach

To carry out this stakeholderoutreach, the EPA embarked on anunprecedented pre-proposal outreacheffort. From consumer groups to statesto power plant owner/operators totechnology innovators, the EPA soughtinput from all perspectives.

The EPA began the outreach effortswith a webinar and associatedteleconferences to establish a commonunderstanding of the basic requirementsand process of CAA section 111(d). TheAugust 27, 2013 overview presentationwas offered as a webinar for state andtribal officials, “Building a CommonUnderstanding: Clean Air Act andUpcoming Carbon Pollution Guidelinesfor Existing Power Plants.”

The EPA followed up on thepresentation by offering four nationalteleconference calls with representativesfrom states, tribes, industry,environmental justice organizations,community organizations andenvironmental representatives. Theteleconferences offered a venue forstakeholders to ask questions of the EPAabout the overview presentation and forthe EPA to gather initial reactions fromstakeholders. Stakeholders andmembers of the public continued toview and refer to the overviewpresentation throughout the outreachprocess. By May 2014, the presentationhad been viewed more than 5,600 times.

The agency also providedmechanisms for anyone from the publicto provide input during the pre-proposaldevelopment of this action. The EPA setup two user-friendly options to acceptinput during the pre-proposal period—email and a web-based form. The EPAhas received more than 2,000 emailsoffering input into the development ofthese guidelines.

presidential-rnemorandurn-power-sector-carbonpollution-standards.

These emails and other materialsprovided to the EPA are posted on lineas part of a non-regulatory docket, EPADocket ID No. EPA—HQ—OAR—2014—0020, at www.regulations.gov. All of thedocuments on which this proposal isbased are available at Docket ID No.EPA—HQ—OAR—2013—0602, atwww.regulations.gov. However, whilethe information collected throughextensive outreach helped the agencyformulate this proposal, we are notrelying on all of the documents, emails,and other information included in theinformational docket that wasestablished as a part of that outreacheffort, nor will the EPA be respondingto specific comments or issues raisedduring the outreach effort. Rather, wehave included in the docket for thisproposal all of the information we reliedon for this action.

The agency has encouraged,organized, and participated in hundredsof meetings about CAA section 111(d)and reducing carbon pollution fromexisting power plants. Attendees atthese various meetings have includedstates and tribes, members of the public,and representatives from multipleindustries, labor leaders, environmentalgroups and other non-governmentalorganizations. The direct engagementhas brought together a variety of statesand stakeholders to discuss a widerange of issues related to the electricitysector and the development of emissionguidelines under CAA section 111(d).The meetings occurred in Washington,DC, and at locations across the country.The meetings were attended by the EPARegional Administrators, managers andstaff and who are playing or will playkey roles in developing andimplementing the rule.

Part of this effort included theagency’s holding of 11 public listeningsessions; one national listening sessionin Washington, DC and 10 listeningsessions in locations in the EPA regionaloffices across the country. All of theoutreach meetings were designed tosolicit policy ideas, concerns andtechnical information from stakeholdersabout using CAA section 111(d).

This outreach process has produced awealth of information which hasinformed this proposal significantly.The pre-proposal outreach efforts farexceeded what is required of the agencyin the normal course of a rulemakingprocess, and the EPA expects that thedialog with states and stakeholders willcontinue throughout the process andeven after the rule is finalized. The EPArecognizes the importance of workingwith all stakeholders, and in particularwith the states, to ensure a clear andcommon understanding of the role the



states will play in addressing carbonpollution from power plants.

3. Public Listening SessionsMore than 3,300 people attended the

public listening sessions held in 11cities across the country. Holding thelistening sessions at the EPA’s regionaloffices offered thousands of people fromdifferent parts of the country theopportunity to provide input to EPAofficials in accessible venues. Inaddition to being well located, holdingthe sessions in regional offices alsoallowed the agency to use resourcesprudently and enabled a variety of theEPA staff involved in the developmentand ultimate implementation of thisupcoming rule to attend and learn fromthe views expressed.

More than 1,600 people spoke at the11 listening sessions. Speakers includedMembers of Congress, other publicofficials, industry representatives, faith-based organizations, unions,environmental groups, communitygroups, students, public health groups,energy groups, academia and concernedcitizens. Participants shared a range ofperspectives. Many were concerned bythe impacts of climate change on theirhealth and on future generations, othersworried about the impact of regulationson the economy. Their support for theagency’s efforts varied.

Summaries of these 11 publiclistening sessions are available atwww.regulations.gov at EPA Docket IDNo. EPA—HQ-OAR—2014—0020.

4. State OfficialsSince fall 2013, the agency provided

multiple opportunities for the states toinform this proposal. In addition, theEPA organized, encouraged andattended meetings to discuss multi-stateplanning efforts. Because of theinterconnectedness of the power sector,and the fact that electricity generated atpower plants crosses state lines, states,utilities and ratepayers may benefit fromstates working together to address therequirements of this rulemakingimplementation. The meetings providedstate leaders, including governors,environmental commissioners, energyofficers, public utility commissioners,and air directors, opportunities toengage with the EPA officials.

Agency officials listened to ideas,concerns and details from states,including from states with a wide rangeof experience in reducing carbonpollution from power plants. Theagency has collected policy papers fromstates with overarching energy goals andtechnical details on the states’electricity sector. The agency hasengaged, and will continue to engage

with, all of the 50 states throughout therulemaking process.

5. Tribal OfficialsThe EPA conducted significant

outreach to tribes, who are not requiredto—but may—develop or adopt CleanAir Act programs. The EPA is aware ofthree coal-fired power plants and onenatural gas-fired EGU located in Indiancountry but is not aware of any EGUsthat are owned or operated by tribalentities.

The EPA conducted outreach to tribalenvironmental staff and offeredconsultation with tribal officials indeveloping this action. Because the EPAis aware of tribal interest in thisproposed rule, the EPA offeredconsultation with tribal officials early inthe process of developing the proposedregulation to permit tribes to havemeaningful and timely input into itsdevelopment.

The EPA sent consultation letters to584 tribal leaders. The letters providedinformation regarding the EPA’sdevelopment of emission guidelines forexisting power plants and offeredconsultation. None have requestedconsultation. Tribes were invited toparticipate in the national informationalwebinar held August 27, 2013. Inaddition, a consultation/outreachmeeting was held on September 9, 2013,with tribal representatives from some ofthe 584 tribes. The EPA representativesalso met with tribal environmental staffwith the National Tribal AirAssociation, by teleconference, onDecember 19, 2013. Tn thoseteleconferences, the EPA providedbackground information on the GHGemission guidelines to be developedand a summary of issues being exploredby the agency.

In addition, the EPA held a series oflistening sessions prior to developmentof this proposed action. Tribesparticipated in a session on September9, 2013 with the state agencies, as wellas in a separate session with tribes onSeptember 26, 2013.

6. Industry RepresentativesAgency officials have engaged with

industry leaders and representativesfrom trade associations in scores of one-on-one and national meetings. Manymeetings occurred at the EPAheadquarters and in the EPA’s RegionalOffices and some were sponsored bystalceholder groups. Because the focus ofthe standard is on the electricity sector,many of the meetings with industryhave been with utilities and industryrepresentatives directly related to theelectricity sector. The agency has alsomet with energy industries such as coal

and natural gas interests, as well ascompanies that offer new technology toprevent or reduce carbon pollution,including companies that have expertisein renewable energy and energyefficiency. Other meetings have beenheld with representatives of energyintensive industries, such as the ironand steel and aluminum industries tohelp understand the issues related tolarge industrial users of electricity.

7. Electric Utility RepresentativesAgency officials participated in many

meetings with utilities and theirassociations. The meetings focused onthe importance of the utility industry inreducing carbon emissions from powerplants. Power plant emissions arecentral to this rulemaking. The EPAencouraged industry representatives towork with state environmental andenergy officers.

The electric utility representativesincluded private utilities or investorowned utilities. Public utilities andcooperative utilities were also part of in-depth conversations about CAA section111(d) with EPA officials.

The conversations included meetingswith the EPA headquarters and Regionaloffices. State officials were included inmany of the meetings. Meetings withutility associations and groups ofutilities were held with key EPAofficials. The meetings coveredtechnical, policy, and legal topics ofinterest and utilities expressed a widevariety of support and concerns aboutCAA section 111(d).

8. Electricity Grid OperatorsThe EPA had a number of

conversations with the IndependentSystem Operators and RegionalTransmission Organizations (ISOs andRTOs) to discuss the rule and issuesrelated to grid operations and reliability.EPA staff met with the ISO/RTOCouncil on several occasions to collecttheir ideas. The EPA Regional Officesalso met with the ISOs and RTOs intheir regions. System operators haveoffered suggestions in using regionalapproaches to implement CAA section111(d) while maintaining reliable,affordable electricity.

9. Representatives From NonGovernmental Organizations

Agency officials engaged withrepresentatives of environmental justiceorganizations during the outreach effort,for example, we engaged with theNational Environmental JusticeAdvisory Council members inSeptember 2013. The NEJAC iscomposed of stakeholders, includingenvironmental justice leaders and other



leaders from state and local governmentand the private sector.

The EPA has also met with a numberof environmental groups to providetheir ideas on how to reduce carbonpollution from existing power plantsusing section 111(d) of the CAA.

Many environmental organizationsdiscussed the need for reducing carbonpollution. Meetings were technical,policy and legal in nature and manygroups discussed specific state policiesthat are already in place to reducecarbon pollution in the states.

A number of organizationsrepresenting religious groups havereached out to the EPA on severaloccasions to discuss their concerns andideas regarding this rule.

Public health groups discussed theneed for protection of children’s healthfrom harmful air pollution. Doctors andhealth care providers discussed the linkbetween reducing carbon pollution andair pollution and public health.Consumer groups representingadvocates for low income electricitycustomers discussed the need foraffordable electricity. They talked aboutreducing electricity prices forconsumers through energy efficiencyand low cost carbon reductions.

10. LaborEPA senior officials and staff met with

a number of labor union representativesabout reducing carbon pollution usingCAA section 111(d). Those unionsincluded: The United Mine Workers ofAmerica; the Sheet Metal, Air, Rail andTransportation Union (SMART); theInternational Brotherhood ofBoilermakers, lion Ship Builders,Blacksmiths, Forgers and Helpers (133);United Association of Journeymen andApprentices of the Plumbing and PipeFitting Industry of the United States andCanada; the international Brotherhoodof Electrical Workers (mEW): And theUtility Workers Union of America. inaddition, agency leaders met with thePresidents of several unions and thePresident of the American Federation ofLabor-Congress of industrialOrganizations (AFL-CIO) at the AFL—CIO headquarters.

EPA officials, when invited, attendedmeetings sponsored by labor unions togive presentations and engage indiscussions about reducing carbonpollution using CAA section 111(d).These included meetings sponsored bythe JEB and the IBEW.

B. Key Messages From StakeholdersMany stakeholders stated that

opportunities exist to reduce the carbonemissions from existing powergeneration through a wide range of

measures, from measures that areimplementable via physical changes atthe source to those that also areimplementable across the broader powergeneration system. Opinions variedabout how broader system measurescould factor into programs to reducecarbon pollution. Some stakeholdersrecommended that system-widemeasures be allowed for compliance,but not factored into the carbonimprovement goals the EPA establishes,while others recommended that system-wide measures be factored into thegoals. Among the arguments andinformation offered by stakeholders whosuggested that states be encouraged toincorporate system-wide measures intotheir state plans and that EGU operatorsbe encouraged to rely on such measureswere examples and discussions of thesignificant extent to which dispatch,end use energy efficiency and renewableenergy had already proven to besuccessful strategies for reducing EGUCO2 emissions. Some state and industryrepresentatives favored goals that theydescribed as based on measuresimplementable only within the facility“fence line” (i.e., measuresimplementable only at the source).Many stakeholders stated that the EPAshould not require the state plans toimpose on the affected EGUs legalresponsibility for the full amount ofrequired CO2 emissions reductions, andinstead, the EPA should authorize thestate plans to include requirements onentities other than the affected EGUsthat would have the effect of reducingutilization and, therefore, emissionsfrom the affected EGUs.

Views on the form and stringency ofthe goal or guidelines varied. Somestakeholders preferred a rate-based formof the goal, while others preferred amass-based form. in addition, somestakeholders recommended that the EPAlet the states have the flexibility toeither choose among multiple forms ofthe goals or to set their own goals. Withregard to the stringency of the goal,some stakeholders recommended thatthe stringency of the goals vary by state,to account for differences in statecircumstances.

Many stakeholders recognized thevalue of allowing states flexibility inimplementing the goals the EPAestablishes. For example, stateshighlighted the importance of the EPArecognizing existing state and regionalprograms that address carbon pollution,including market-based programs, andallowing credit for prioraccomplishments in reducing CO2emissions. Many states and otherstakeholders noted the importance ofthe EPA allowing flexibility in

compliance options such that statescould use approaches such as demand-side management to attain the goals.

Many stakeholders recommended thatstates be allowed to develop multi-stateprograms. It was frequently noted thatsuch regional approaches could offercost-effective carbon pollutionsolutions.

There was broad agreement that moststates would need more than one yearto develop and submit their completeplans to the EPA. For some states, moretime is necessary because of the statelegislative schedule and/or regulatoryprocess. in some cases, approval of aplan through a state’s legislative orregulatory process could take one yearor more after the plan has already beendeveloped. Additional time would alsoallow and encourage multi-state andregional partnerships and programs.

Many stakeholders also supportedflexibility in the timing ofimplementation of the state plans andpower sector compliance with the goalsin the state plans. Such flexibility, somestalceholders asserted, wouldaccommodate the diverse GHGmitigation potential of states andsupport more cost-effective approachesto achieving CO2 reductions.

During the outreach process, somestalceholders raised general concernsthat the rulemaking could have anegative impact on jobs and ratepayers.Some stakeholders also expressedconcerns about potential adverse effectson electric system reliability. Somestakeholders were concerned thatmeeting the goals could potentiallyresult in stranded generation assets. Toprevent this from occurring, somestalceholders suggested varying thestringency of standards to account forindividual state circumstances andvariation.

The EPA has given stakeholder inputcareful consideration during thedevelopment of this proposal and, as aresult, this proposal includes featuresthat are intended to be responsive tomany stalceholder concerns.

C. Key Stakeholder ProposalsDuring the EPA’s public outreach in

advance of this proposal, a number ofideas were put forward that are not fullyreflected in this proposal. We invitepublic comment on these ideas, some ofwhich are outlined below.

1. Model Rule on interstate EmissionsCredit Trading and Price Ceiling

Some groups thought that the EPAshould put forward a model rule for aninterstate emissions credit tradingprogram that could be easily adopted bystates who wanted to use such a


34848 Federal Register/Vol. 79, No. 117/ Wednesday, June 18, 2014 / Proposed Rules

program for its plan. One groupsuggested the model rule should includea provision to allow the state tocompensate merchant generators as wellas retail rate payers. Another groupspecified that the model rule would alsoinclude a ceiling-price called analternative compliance payment thatwould fund state directed cleantechnology investment. facilities thatface costs that exceed the ceiling pricecould opt to pay into the fund as a wayof complying.

2. Equivalency TestsOne group recommended that state

programs be allowed to demonstrateequivalency using one of three tests:Rate-based equivalency via ademonstration that the state programachieves equivalent or better carbonintensity for the regulated sector; mass-based equivalency via a demonstrationthat the program achieves equal orgreater emission reductions relative towhat would be achieved by the federalapproach; or a market price-basedequivalency via a demonstration thatthe program reflects a carbon pricecomparable to or greater than the cost-effectiveness benchmark used by theEPA in designing the program. The EPAis proposing a way to demonstrateequivalency and that is discussed inSection VIII of this preamble.

3. Power Plant-Specific AssessmentOther stakeholders suggested that an

“inside the fence” plant- or unit-specificassessment linked to the availability ofcontrol at the source such as heat rateimprovements should be considered.They indicated that once plant-specificgoals are established based on on-siteCO2 reduction opportunities, the sourceshould have the flexibility to look“outside the fence” for the means toachieve the goals, including the use ofemissions trading, and averaging.

The EPA invites comment on thesesuggestions.

D. Consideration of the Range ofExisting State Policies and Programs

Across the nation, many states andregions have shown strong leadership increating and implementing policies andprograms that reduce GHG emissionsfrom the power sector while achievingother economic, enviromnental, andenergy benefits. Some of these activities,such as market-based programs andGHG performance standards, directlyrequire GHG emission reductions fromEGUs. Others reduce GHG emissions byreducing utilization of fossil fuel-firedEGUs through, for example, renewableportfolio standards (RPS) and energyefficiency resource standards (EERS),

which alter the mix of energy supplyand reduce energy demand. States havedeveloped their policies and programswith stakeholder input and tailoredthem to their own circumstances andpriorities. Their leadership andexperiences provided the EPA withimportant information about bestpractices to build upon in this proposedrule. As directed by the PresidentialMemorandum, the EPA is, with thisproposal to reduce power plant carbonpollution, building on actions alreadyunderway in states and the powersector.

1. Market-Based Emission LimitsNine states actively participate in the

Regional Greenhouse Gas Initiative(RGGI), a market-based CO2 emissionreduction program addressing EGUs thatwas established in 2009. ThroughRGGI, the participating states areimplementing coordinated CO2emission budget trading programs. Inaggregate, these programs establish anoverall limit on allowable CO2emissions from affected EGUs in theparticipating states. Participating statesissue CO2 allowances in an amount upto the number of allowances in eachstate’s annual emission budget. At theend of each three-year complianceperiod, affected EGUs must submit CO2allowances equal to their reported CO2emissions. CO2 allowances may betraded among both regulated and non-regulated parties, creating a market foremission allowances. This marketcreates a price signal for CO2 emissions,which factors into the dispatch ofaffected EGUs. A price signal for CO2emissions also allows sources flexibilityto make emission reductions wherereduction costs are lowest, andencourages innovation in developingemission control strategies.

Approximately 90 percent of CO2allowances are distributed by the RGGIparticipating states through auction.48From 2009 through 2012, the nine RGGIstates invested auction proceeds of morethan $700 million in programs thatlower costs for energy consumers andreduce CO2 emissions.49 Through 2012,for example, the RGGI states investedapproximately $460 million of proceedsinto energy efficiency programs.5° The

4 nine states include Connecticut, Delaware,Maine, Maryland, Massachusetts, New Hampshire,New York, Rhode Island, and Vermont.

48Regional Greenhouse Gas Initiative 2013Allowance Allocation http://rggi.org/design/ovewiew/allowance-allocation/201 3-allocation.

49Regioual Investments of RGGI co2 AllowanceProceeds, 2012 (2014), available at http://www.rggL org/docs/Documents/2012-In vestment-Report .pdf.

5° of the $707 million in auction proceedsinvested by RGGI participating states through 2012,

participating RGGI states estimate thatthose investments are providing benefitsto energy consumers in the region ofmore than $1.8 billion in lifetime energysavings.5’

Between 2005, when an agreement toimplement RGGI was announced, and2012, power sector CO2 emissions in theRGGI participating states fell by morethan 40 percent.52 RGGI was not theprimary driver for these reductions butthe reductions led RGGI-participatingstates to later adjust the CO2 emissionlimits downward. In January 2014, theparticipating states lowered the overallallowable CO2 emission level in 2014 by45 percent, setting a multi-state CO2emission limit for affected EGUs of 91million short tons of CO2 in 2014 and78 million short tons of CO2 in 2020,more than 50 percent below 2008levels.

Similarly, California established aneconomy-wide market-based GHGemissions trading program under theauthority of its 2006 Global WarmingSolutions Act, which requires the stateto reduce its 2020 GHG emissions to1990 levels. While California’semission trading program, like its stateemission limit, is multi-sector in scope,the state projects that the emissionstrading program and relatedcomplementary measures will reducepower sector GHG emissions to lessthan 80 million metric tons of CO2equivalent by 2025, a 25 percentreduction from 2005 power sectoremission levels.56 Prior to theimplementation of the emission tradingprogram, California reports that itreduced CO2 power sector emissions by16 percent from 2005 to a 2010—2012

65 percent supported end-use energy efficiencyprograms. See Regional Greenhouse Gas Initiative,“Regional Investments of RGGI CO2 AllowanceProceeds, 2012” (2014). Available at http://www.rggi.org/docs/Documents/2012-Investment-Report.pdf.

SlId52 Regional Greenhouse Gas Initiative, Report on

Emission Reduction Efforts of the StatesParticipating in the Regional Greenhouse GasInitiative and Recommendations for Guidelinesunder Section 111(d) of the Clean Air Act (2013).

53 first three-year control period under RGGI,establishing CO2 emission limits for EGUs, began onJanuary 1, 2009.

54RGGI Press Release, January 13, 2014, http://www.rggi.org/docs/PressReleases/PRO11314_AuctfonNotice23.pdf.

55State of California Global Warming SolutionsAct of 2006, Assembly Bill 32, Chapter http://wwwdeginfo.ca .gov/pub/05-06/bffl/asm/ab_0001-0050/ob_32_bil_20060927_chaptered.pdf.

56Preliminary California Air Resources Boardanalyses, based in part on CARE 2008 to 2012Emissions for Mandatory GHG reporting Summary(2013), cited in Letter to the EPA Administrator,“States’ Roadmap on Reducing Carbon Pollution,”December 16, 2013. Available at hftp://www.georgetownclimate.org/sites/default/filesIEPA_SubmissionJrom_Stotes-FinolCompl.pdf.



averaging period, a reduction of 16million metric tons of CO2 equivalent.57

2. GHG Performance StandardsFour states, California, New York,

Oregon and Washington, have enactedGHG emission standards that imposeenforceable emission limits on new and!or expanded electric generating units.For example, since 2012, New Yorkrequires new or expanded baseloadplants that are greater than 25Megawatts (MW) to meet an emissionrate of either 925 pounds CO2/Megawatthour (MWh) (based on output) or 120pounds of CO2JMillion British ThermalUnits (MMBtu) (based on input).Similarly, non-baseload plants in NewYork of at least 25 MW or larger mustmeet an emission rate of either 1450pounds C02/MWh (based on output) or160 pounds of C02!MMBtu (based oninput).58

Three states, California, Oregon andWashington, have enacted GHGemission performance standards that setan emission rate for electricitypurchased by electric utilities. In bothOregon and Washington, for example,electric utilities may enter into longterm power purchase agreements forbaseload power only if the electricgenerator supplying the power has aCO2 emission rate of 1,100 pounds ofCO2 per MWh or less.59

3. Utility Planning ApproachesTwo states, Minnesota and Colorado,

have worked collaboratively with theirinvestor-owned utilities to developmulti-pollutant emission reductionplans on a utility-wide basis. Thismulti-pollutant, collaborative approachenables utilities to determine the leastcost way to meet long term andcomprehensive energy andenvironmental goals.

Colorado’s Clean Air, Clean Jobs Actof 2010, for example, required Coloradoinvestor-owned utilities with coal plantsto develop a multi-pollutant plan tomeet existing and reasonablyforeseeable federal CAA requirements.6°The utilities were not required to adopta specific plan set by the state but were,instead, required to work collaborativelywith the Colorado Department of PublicHealth and Environmental and ColoradoPublic Utility Commission to developan acceptable plan. Xcel Energy,Colorado’s largest investor-ownedutility, submitted a plan that wasapproved in 2010. With this plan, Xcel

585 New York Codes, Rules & Regulations. Part251 (Adopted June 28, 2012).

SB 101 (2000); Washington Revised Codech.80.80 (2013); Wash SB 6001 (2007).

50Colorado Clean Air, Clean Jobs Act, HE1365.

Energy is projected to reduce its CO2emissions from generation in Coloradoby 28 percent by 2020.61

4. Renewable Portfolio Standards

More than 25 states have mandatoryrenewable portfolio standards thatrequire retail electricity suppliers tosupply a minimum percentage oramount of their retail electricity loadwith electricity generated from eligiblesources of renewable energy.62 Thesestandards have been established viautility regulatory commissions,legislatures and citizen ballots andrequirements vary from state to state.State RPS typically specify the types ofrenewable energy, or other energysources, that qualify for use towardachievement of the standard, and oftenallow for the use of qualifyingrenewable energy resources locatedoutside of the state. They reduceutilization of fossil fuel-fired EGUs and,thereby, lead to reductions in GHGemissions by meeting a portion of thedemand for electricity throughrenewable or other energy sources.

Tn 2007, the Minnesota legislatureamended the state’s 2001 renewableenergy objective and established arenewable energy standard (RES)requiring at least 25 percent of allelectricity generated or purchased inMinnesota to come from renewableenergy by 2025. The standard setsrequirements and timetables, beginningin 2010, that vary based on the provider.For example, in 2011, Xcel Energy hada requirement to generate or purchase15 percent of its total retail sales fromrenewable energy while all otherutilities had a target of 7 percent of totalretail sales. According to the latestMinnesota Department of Commercereport to the legislature on progress, allutilities subject to the standard met itfor 2011 and were on track to meet their2012 goals.63 The 2012 requirementincreased to 18 percent of total retailsales for Xcel Energy and 12 percent forall other utilities.64 In 2013, theMinnesota legislature expanded the RESwith solar incentives and a specificsolar energy standard requiringMinnesota utilities to ensure that at

‘Xcel Energy, Colorado Clean Air-Clean JobsPlan, available at http://www.xcelenergy.com/Environment/Doing_Our_Part/Clean_Afr_Projects/Colorado_Cleun_Air_CleanJobs_PIan.

6Zhftp://www.dsireusa.org/.53Report to the Minnesota Legislature: Progress

on Compliance By Electric Utilities With TheMinnesota Renewable Energy Objective and theRenewable Energy Standard, Prepared by: TheMinnesota Department of Commerce, Division ofEnergy Resources January 14, 2013; hup://mn.gov/commewe/energy/images/2Ol3RESLegReport.pdf.

641d

least 1.5 percent of their retail electricitysales in 2020 come from solar energy.65

The Oregon Renewable PortfolioStandard (RPS) is another example of astate requirement for renewables.Originally enacted in 2007, it requiresthat all utilities serving Oregon meet apercentage of their retail electricityneeds with qualified renewableresources. Like in Minnesota, thepercentage varies across utilities withthe three largest utilities required toreach five percent from renewableenergy sources starting in 2011, 15percent in 2015, 20 percent in 2020, and25 percent in 2025. Other electricutilities in the state are required to reachlevels of five percent or ten percent by2025, depending on their size.According to the latest RPS compliancereports submitted by the largest utilitiesfor the state, each had achieved the fivepercent target as of the end of 2012.66

5. Demand-Side Energy EfficiencyPrograms

Many electric utilities, third-partyadministrators, and states implementdemand-side energy efficiency programsto reduce generation from EGUs byreducing electricity use, including peakdemand. When these programs reducefossil fuel electricity generation, theyalso reduce CO2 emissions. Demand-side energy efficiency programs use avariety of energy efficiency measures totarget a variety of end uses and are oftendriven by existing state standards andprograms, such as policies requiringutilities to obtain “all cost-effectiveenergy efficiency” through long-termintegrated resource planning (WP),renewable portfolio standards (BPS) thatinclude efficiency as a qualifyingresource, energy efficiency resourcestandards (EERS), public benefit funds,and other demand-side planningrequirements.

The purposes of demand-side energyefficiency programs vary; goals includeto reduce GHG emissions by reducingfossil-fired generation, help statesachieve energy savings goals, saveenergy and money for consumers andimprove electricity reliability. They aretypically funded through a small fee orsurcharge on customer electricity bills,but can also be funded by other sources,such as from RGGI CO2 allowanceauction proceeds mentioned above.

55Minnesota Statutes 2013, Section 2163.1691,Subdivision 2f. Solar Energy Standard hftps://wwwrevisor.mn.gov/statutes/?id=216b.l 691.

86Eugene Water Electric Board OregonRenewable Portfolio Standard 2012 ComplianceReport and 2013—2030 Implementation Plan, June 1,2013. PacifiCorp’s Renewable Portfolio StandardOregon Compliance Report for 2012, May 31, 2013.PGE 2012 Renewable Portfolio StandardCompliance Report, June 1, 2013.



Nationally, total spending on electricratepayer-fimded energy efficiencyprograms was about $5 billion in2012. Based on Lawrence BerkeleyNational Laboratory (LBNL) projections,spending is projected to reach $8.1billion in 2025.68

Electricity savings from energyefficiency programs are also growing. In2011, electricity savings from theseprograms totaled approximately 22.9million MWh, a 22 percent increasefrom the previous year.69

California has been advancing energyefficiency through utility-run demand-side energy efficiency programs fordecades and considers energy efficiency“the bedrock upon which climatepolicies are built.” 70 It requires itsinvestor-owned utilities to meetelectricity load “through all availableenergy efficiency and demand reductionresources that are cost-effective, reliableand feasible.”7’ The California PublicUtility Commission works with theCalifornia Energy Commission todetermine the amount of cost-effectivereduction potential and establishesefficiency targets. A recent energyefficiency potential study found that,even after years of running programs,California can still tap “tens ofthousands of GWh in potential savings

over the next decade.”’ Investor-owned utilities use demand-side energyefficiency programs to achieve theirtargets and currently “save about 3,000GW per year, enough savings to powerabout 600,000 households.”73 Between2010 and 2011, these programs areestimated to have reduced CO2 by 3.8million tons.74

In Vermont, for example, the VermontLegislature and the Vermont PublicService Board (PSB) established the firststatewide “energy efficiency utility” in1999 to provide energy efficiencyservices to residences and businesses

87Consortium foT Energy Efficiency AnnualIndustry Report: 2013 State of the EfficiencyProgram Industry—Budgets, Expenditures andImpacts, 2014.

Lawrence Berkeley National Laboratory (LBNL)The Future of Utility Customer-Funded EnergyEfficiency Programs in the United States: ProjectedSpending and Savings to 2025 (hup:/Iemp.lbI.gov/sites/all/files/lbnI-5803e.pdJ).

69American Council for an Energy EfficientEconomy (ACEEE) 2013 State Scorecard http://www.aceee.org/sites/defau1t/fl1es/pub1ications/researchreports/el 3k.pdf

70December27, 2013 Letter from MaryD.Nichols, Chairman of California Air ResourcesBoard, to EPA Administrator Gina McCarthy.

71 Cal Pub. Utility Code § 454.5 (a)(9)(C).in December 27 2013 Letter from Mary

B. Nichols, Chairman of California Air ResourcesBoard, to EPA Administrator Gina McCarthy.

741d.

throughout the state.75 Vermont lawrequires that the energy efficiencyutility budgets be set at a level toachieve “all reasonably available, cost-effective energy efficiency” and thenspecific energy (kWh) and peak demand(kW) savings levels are negotiated everythree years.76 In 2013, EfficiencyVermont, the PSB-appointed energyefficiency utility, achieved annualsavings of 1.66 percent of the state’selectricity sales, at a cost of 4.1 cents perkilowatt-hour, lower than the cost ofcomparable electric supply in the sameyear, which was 8.4 cents per kWh.Efficiency Vermont projects a netlifetime economic value to Vermont ofmore than $60 million from the 2013energy efficiency investments.78

6. Energy Efficiency Resource Standards

More than 20 states have energyefficiency resource standards (EERS)that require utilities to save a certainamount of energy each year orcumuiatively.79 They are typicallymulti-year requirements expressed as apercentage of annual retail electricitysales or as specific electricity savingsamounts over a long term period relativeto a baseline of retail sales. Over thecompliance period, an EERS reducesfossil fuel-fired EGU generation throughreductions in electricity demand,thereby reducing CO2 emissions fromthe power sector.

In Arizona, for example, the ArizonaCorporation Commission (ACC) adoptedrules in 2010 requiring all investor-owned utilities to achieve 22 percentcumulative electricity savings by 2020,making it one of the highest standardsin the nation.80 The rule requiredutilities to achieve 1.25 percentelectricity savings in 2011 compared toelectricity sales in the previous year,ramping up the savings each year until2020 according to a designated

75State of Vermont Public Service Board, EnergyEfficiency Utility Creation and Structure. hftp://psb.vermont.gov/utiityindustrfes/eeu/generalinfo/creationandsfructure.

76Vermont Statute, Title 30: Public Service, 30V.S.A. § 209 (d)3(B). hftp://www.leg.state.vt.us/statutes/fullsection.cfm?Title=30&Chapter=005&Section=00209.

Y7Efficiency Vermont Savings Claim Summary2013, Reported to the Vermont Public Service Boardand to the Vermont Public Service Department,2014, hftps://www.efflciencyvermont.com/docs/about_efflciency_vermont/annual_summaries/201 3_savingsclafm_summary.pdf.

79State Energy Efficiency Resource Standards:Policy Design, Status, and Impacts, DC Steinberg, 0.Zinaman, NREL Technical Report NREL/TP—6A20-61023, April 2014.

50Arizona Corporation Commission, Docket RE—00000C—09—0427, August 2010. Available athup://images.edocket.azcc.gov/docketpdf/000011 6125.pdf.

timetable.8’ In 2012, for example,investor-owned utilities were requiredto achieve energy savings equivalent to1.75 percent of the 2011 sales, leadingto a cumulative savings requirement of3 percent by the end of 2012 (an averageof 1.5% annually over the 2 yearperiod).82 Utilities can meet the energysavings requirements through a varietyof means, including cost-effectiveenergy efficiency programs, as well asload management and demand responseprograms.83 Arizona Public ServiceCompany (APS), the largest utility inArizona, achieved cumulative energysavings equivalent to 3.2 percent ofretail sales from 2011 to 2012, exceedingthe 3 percent savings target, andreported a net benefit to consumers ofmore than $200 million for the year2012 alone.84

E. ConclusionsStates have taken a leadership role in

mitigating GHG emissions and havedemonstrated the potential for nationalapplication of a number of approaches.Throughout the development of thisproposed rule, the EPA considered thestates’ experiences and lessons learnedregarding the design andimplementation of successful GHGmitigation programs. The agency alsofully considered input fromstakeholders during the development ofthis proposed rulemaking.

Considering all input fromstakeholders, the agency recognizes thatthe most cost-effective approach toreducing GHG emissions from thepower sector under CAA section 111(d)is to follow the lead of numerous statesand not only to identify improvementsin the efficiency of fossil fuel-firedEGUs as a component of the BSER, butalso include in the BSER determinationthe EGU-emissions-reductionopportunities that states have alreadydemonstrated to be successful in relyingon lower- and zero-emitting generationand reduced electricity demand.

CAA section 111(d) sets up apartnership between the EPA and thestates. In the context of that partnership,the EPA recognizes the importance ofeach state having the flexibility todesign a cost-effective program tailoredto its own specific circumstances. Theagency also recognizes, as many states

Slid

82izona Corporation Commission, Docket RE—00000C-09—0427, August 2010. Available athftp://images.edocket.azcc.gov/docketpdf/0000116125.pdf.

84Arizona Public Service Company 2012 DemandSide Management Annual Progress Report, March 1,2013 Web site, http://www.aps.com/en/ourcompany/aboutus/energyefficiency/Pages/home.aspx.



have, the value of regional planning indesigning approaches to achieve cost-effective GHG reductions. To supportstate flexibility and encourage multistate coordination in the development ofmulti-state and regional programs andpolicies, the EPA recognizes thatflexibility in both the timing of plansubmittal and the timing of CO2emission reductions will be necessary.

IV. Rule Requirements and Legal Basis

A. Summary ofRule RequirementsThe EPA is proposing emission

guidelines for each state to use indeveloping plans to address greenhousegas emissions from existing fossil fuel-fired electric generating units. Theemission guidelines are based on theEPA’s determination of the “best systemof emission reduction. . . adequatelydemonstrated” (3SER) and includestate-specific goals, generalapprovability criteria for state plans,requirements for state plan components,and requirements for the process andtiming for state plan submittal andcompliance.

Under CAA section 111(d), the statesmust establish standards of performancethat reflect the degree of emissionlimitation achievable through theapplication of the “best system ofemission reduction” that, taking intoaccount the cost of achieving suchreduction and any non-air quality healthand enviromnental impact and energyrequirements, the Administratordetermines has been adequatelydemonstrated. Consistent with CAAsection 111(d), the EPA is proposingstate-specific goals that reflect the EPA’scalculation of the BSER.

Under CAA section 111(d), each statemust develop, adopt, and then submitits plan to the EPA. To do so, the statewould determine, and include in itsplan, an emission performance levelthat is equivalent to the state-specificCO2 goal in the emission guidelines. Aspart of determining this level, the statewould decide whether to adopt the rate-based form of the goal established by theEPA or translate the rate-based goal toa mass-based goal. The state would thenestablish a standard of performance orset of standards of performance (knownas emission standards under the existingCAA section 111(d) frameworkregulations), along with implementingand enforcing measures, that willachieve a level of emission performancethat equals or exceeds the levelspecified in the state plan.

The EPA is proposing to determinethe BSER as the combination ofemission rate improvements andlimitations on overall emissions at

affected EGUs that can be accomplishedthrough any combination of one or moremeasures from the following four sets ofmeasures or building blocks:


2. Reducing emissions from the mostcarbon-intensive affected EGUs in theamount that results from substitutinggeneration at those EGUs withgeneration from less carbon-intensiveaffected EGUs (including natural gascombined cycle (NGCC) units that areunder construction).



The EPA has reviewed informationabout the current and recentperformance of affected EGUs andstates’ implementation of programs thatreduce CO2 emissions from thesesources. Based on our analysis of thatinformation, the proposed state goalsreflect the following stringency ofapplication of the measures in each ofthe building blocks: Block 1, improvingaverage heat rate of coal-fired steamEGUs by six percent; block 2, displacingcoal-fired steam and oil/gas-fired steamgeneration in each state by increasinggeneration from existing NGCC capacityin that state toward a 70 percent targetutilization rate; block 3, including theprojected amounts of generationachievable by completing all nuclearunits currently under construction,avoiding retirement of about six percentof existing nuclear capacity, andincreasing renewable electric generatingcapacity over time through the use ofstate-level renewable generation targetsconsistent with renewable generationportfolio standards that have beenestablished by states in the same region;and block 4, increasing state demand-side energy efficiency efforts to reach1.5 percent annual electricity savings inthe 2020—2029 period.

Based on the EPA’s application of theBSER to each state, the EPA isproposing to establish, as part of theemission guidelines, state-specific goals,expressed as average emission rates forfossil fuel-fired EGUs. Each state’s goalscomprise the EPA’s determination of theemission limitation achievable throughapplication of the BSER in that state.for each state, the EPA is proposing aninterim goal for the phase-in periodfrom 2020 to 2029 and the final goal that

applies beginning in 2030. Theproposed goals for each state are listedin Section VU, below. The EPA isproposing that measures that a statetakes after the date of this proposal, andthat result in CO2 emission reductionsduring the plan period, would applytoward achievement of the state’s CO2goal.

The EPA is further proposing, as partof the plan guidelines, timetables forstates to submit their plans. The agencyexpects to finalize this rulemaking byJune 2015, and we are proposing torequire that each state submit its plan tothe EPA by June 30, 2016. However, ifa state needs additional time to submita complete plan, the state must submitan initial plan by June 30, 2016, thatdocuments the reasons why more timeis needed to submit a complete plan andincludes commitments to take concretesteps that will ensure that the state willsubmit a complete plan by June 30,2017, or June 30, 2018, as appropriate.If such a state is developing a planlimited in geographical scope to theindividual state, then the state wouldhave until June 30, 2017, to submit acomplete plan. A state that isdeveloping a plan that includes a multistate approach would have until June30, 2018, to submit a complete plan.

The EPA is further proposing, as partof the emission guidelines, to allowstates the option of translating the EPA-determined goal, which will be rate-based, to a mass-based goal. For statesparticipating in a multi-state approach,the individual state performance goalsin the emission guidelines would bereplaced with an equivalent multi-stateperformance goal. The EPA is alsoproposing that in their plans, whethersingle state or multi-state, states may notadjust the stringency of the goals set bythe EPA.

Under CAA section 111(d)(1) and theimplementing regulations, with the stateemission performance level in place, thestate must adopt a state plan thatestablishes a standard of performance orset of standards of performance, alongwith implementing and enforcingmeasures, that will achieve thatemission performance level. The EPA isfurther proposing, as part of theguidelines, to authorize the state tosubmit either of two types of measuresto achieve the performance level: (1) Aset of measures that we refer to as“portfolio” measures, which include acombination of emission limitations thatapply directly to the affected sourcesand other measures that have the effectof limiting generation by, and thereforeemissions from, the affected sources; or(2) solely emission limitations thatapply directly to the affected sources.



The EPA is also proposing, as part ofthe plan guidelines, that a completestate plan include the following twelvecomponents:• Identification of affected entities• Description of plan approach and

geographic scope• Identification of state emission

performance level• Demonstration that plan is projected

to achieve emission performance level• Identification of emissions standards• Demonstration that each emissions

standard is quantifiable, non-duplicative, permanent, verifiable,and enforceable

• Identification of monitoring,reporting, and recordiceepingrequirements

• Description of state reporting• Identification of milestones• Identification of backstop measures• Certification of hearing on state plan• Supporting material

The EPA is also proposing, as part ofits emission guidelines, that planapprovability be based on four generalcriteria: (1) Enforceable measures thatreduce EGU CO2 emissions; (2)projected achievement of emissionperformance equivalent to the goalsestablished by the EPA, on a timelineequivalent to that in the emissionguidelines; (3) quantifiable andverifiable emission reductions; and (4) aprocess for reporting on planimplementation, progress towardachieving CO2 goals, andimplementation of corrective actions, ifnecessary.

The EPA is also proposing, as part ofits plan guidelines, requirements for theprocess and timing for demonstratingachievement of the required emissionperformance level, includingperformance and emission milestones.The proposed option would requireeach state to achieve its ultimate CO2emission performance level by 2030and, in addition, provide an initial,phase-in compliance period of up to 10years, from 2020 up to 2029, for a stateand/or other responsible parties tocomply with the emission performancelevel in the state plan. A state wouldneed to meet its interim 2020—2029 CO2emission performance level on averageover the 10-year phase-in complianceperiod, achieve its final CO2 emissionperformance level by 2030, andmaintain it thereafter.

If a state with affected EGUs does notsubmit a plan or if the EPA does notapprove a state’s plan, then under CAAsection 111(d)(2)(A), the EPA mustestablish a plan for that state. A statethat has no affected EGUs mustdocument this in a formal letter

submitted to the EPA by June 30, 2016.hi the case of a tribe that has one ormore affected EGUs in its area of Indiancountry,85 the tribe would have theopportunity, but not the obligation, toestablish a CO2 emission performancestandard and a CAA section 111(d) planfor its area of Indian country. If itdetermines that such a plan is necessaryor appropriate, the EPA has theresponsibility to establish CAA section111(d) plans for areas of Indian countrywhere affected sources are locatedunless a tribe on whose lands anaffected source (or sources) is locatedseeks and obtains authority from theEPA to establish a plan itself, pursuantto the Tribal Authority Rule.

B. Summary ofLegal BasisThis proposed action is consistent

with the requirements of CAA section111(d) and the implementingregulations. As an initial matter, theEPA reasonably interprets theprovisions identifying which airpollutants are covered under CAAsection 111(d) to authorize the EPA toregulate CO2 from fossil fuel-fired EGUs.In addition, the EPA recognizes thatCAA section 111(d) applies to sourcesthat, if they were new sources, would becovered under a CAA section 111(b)rule. The EPA intends to complete twoCAA section 111(b) rulemaldngsregulating CO2 from new fossil fuel-firedEGUs and from modified andreconstructed fossil fuel-fired EGUsbefore it finalizes this rulemaking, andeither of those section 111(b)rulemakings will provide the requisitepredicate for this rulemaking.

A key step in promulgatingrequirements under CAA section 111(d)is determining the “best system ofemission reduction. . . adequatelydemonstrated” (BSER). In promulgatingthe implementing regulations, the EPAexplicitly stated that it is authorized todetermine the BSER; 86 accordingly, inthis rulemaking, the EPA is determiningthe BSER.

The EPA is proposing two alternativeBSER for fossil fuel-fired EGUs, each ofwhich is based on methods that havealready been employed for reducingemissions of air pollutants, including, insome cases, CO2, from these sources.The first identifies the combination ofthe four building blocks as the BSER.

85The EPA is aware of at least four affected EGUslocated hi Indian country: Two on Navajo lands, theNavajo Generating Station and the Four CoTnersGenerating Station; one on Ute lands, the BonanzaGenerating Station; and one on Fort Mojave lands,the South Point Energy Center. The affected EGUsat the first three plants are coal-fired EGUs. Thefourth affected EGU is an NGCC facility.

86 EPA is not re-opening that interpretationin this rulemaldug.

These include operationalimprovements and equipment upgradesthat the coal-fired steam-generatingEGUs in the state may undertake toimprove their heat rate (building block1) and increases in, or retention of, zero-or low-emitting generation, as well asmeasures to reduce demand forgeneration, all of which, taken together,displace, or avoid the need for,generation from the affected EGUs(building blocks 2, 3, and 4). All of thesemeasures are components of a “systemof emission reduction” for the affectedEGUs because they either improve thecarbon intensity of the affected EGUs ingenerating electricity or, because of theintegrated nature of the electricitysystem and the fungibility of electricity,they displace or avoid the need forgeneration from those sources andthereby reduce the emissions from thosesources. Moreover, those measures maybe undertaken by the affected EGUsthemselves and, in the case of buildingblocks 2, 3, and 4, they may be requiredby the states.

Further, these measures meet thecriteria in CAA section 111(a)(1) and thecaselaw as the “best” system ofemission reduction because, amongother things, they achieve theappropriate level of reductions, they areof reasonable cost, and they encouragetechnological development that isimportant to achieving further emissionreductions. Moreover, the measures ineach of the building blocks are“adequately demonstrated” becausethey are each well-established innumerous states, and many of themhave already been relied on to reduceGHGs and other air pollutants fromfossil fuel-fired EGUs. It should beemphasized that these measures areconsistent with current trends in theelectricity sector.

For the alternative approach for theBSER, the EPA is identifying the“system of emission reduction” asincluding, in addition to building block1, the reduction of affected fossil fuel-fired EGUs’ mass emissions achievablethrough reductions in generation ofspecified amounts from those EGUs.Under this approach, the measures inbuilding blocks 2, 3, and 4 would notbe components of the system ofemission reduction, but instead wouldserve as bases for quantifying thereduction in emissions resulting fromthe reduction in generation at affectedEGUs. In light of the available sourcesof replacement generation through themeasures in the building blocks, thisapproach would also meet the criteriafor being the “best” system that is“adequately demonstrated” because ofthe emission reductions it would



achieve, its reasonable cost, and itspromotion of technologicaldevelopment, as well as the fact that thereliability of the electricity systemwould be maintained.

After determining the BSER, the EPAis authorized under the implementingregulations, as an integral component tosetting emission guidelines, to apply theBSER and determine the resultingemission limitation. The EPA isproposing to apply the BSER to theaffected EGUs on a statewide basis. Tnthis rulemaking, the EPA terms theresulting emission limitation the stategoal.

With the promulgation of theemission guidelines, each state mustdevelop a plan to achieve an emissionperformance level that corresponds tothe state goal. The state plans mustestablish standards of performance forthe affected EGUs and include measuresthat implement and enforce thosestandards. Based on requests fromstakeholders, the EPA is proposing thatstates be authorized to submit stateplans that do not impose legalresponsibility on the affected EGUs forthe entirety of the emission performancelevel, but instead, by adopting what thispreamble refers to as a “portfolioapproach,” impose requirements onother affected entities (e.g., renewableenergy and demand-side energyefficiency measures) that would reduceCO2 emissions from the affected EGUs.

It should be noted that an importantaspect of the BSER for affected EGUs isthat the EPA is proposing to apply it ona statewide basis. The statewideapproach also underlies the requiredemission performance level, which, asnoted, is based on the application of theBSER to a state’s affected EGUs, andwhich the suite of measures in the stateplan, including the emission standardsfor the affected EGUs, must achieveoverall. The state has flexibility inassigning the emission performanceobligations to its affected EGUs, in theform of standards of performance—and,for the portfolio approach, in imposingrequirements on other entities—as longas, again, the required emissionperformance level is met.

This state-wide approach bothharnesses the efficiencies of emissionreduction opportunities in theinterconnected electricity system and isfully consistent with the principles offederalism that underlie the Clean AirAct generally and CAA section 111(d)particularly. That is, this provisionachieves the emission performancerequirements through the vehicle of astate plan, and provides each statesignificant flexibility to take localcircumstances and state policy goals

into account in determining how toreduce emissions from its affectedsources, as long as the plan meetsminimum federal requirements. Thisstate-wide approach, and the standardsof performance for the affected EGUsthat the states will establish through thestate-plan process, are consistent withthe applicable CAA section 111provisions.

A state has discretion in determiningthe measures in its plans. The state mayadopt measures that assure theachievement of the required emissionperformance level, and is not limited tothe measures that the EPA identifies aspart of the BSER. By the same token, theaffected EGUs, to comply with theapplicable standards of performance inthe state plan, may rely on anyefficacious means of emissionreduction, regardless of whether theEPA identifies those measures as part ofthe BSER.

In this rulemaking, the EPA proposesreasonable deadlines for state plansubmission and the EPA’s action. Theproposed deadline for the EPA’s actionon state plan submittals varies from thatin the implementing regulations, andthe EPA is proposing to revise thatprovision in the regulations accordingly.Under CAA section 111(d)(2), the stateplans must be “satisfactory” for the EPAto approve them, and in thisrulemaking, the EPA is proposing thecriteria that the state plans must meetunder that requirement.

The EPA discusses its legalinterpretation in more detail in otherparts of this preamble and discussescertain issues in more detail in the LegalMemorandum included in the docketfor this rulemaking. The EPA solicitscomment on all aspects of its legalinterpretations, including the discussionin the Legal Memorandum.

V. Authority To Regulate CarbonDioxide and EGUs, Affected Sources,Treatment of Categories

A. Authority To Regulate CarbonDioxide

The EPA has the authority to regulate,under CAA section 111(d), CO2emissions from EGUs, under theAgency’s construction of the ambiguousprovisions in CAA section111(d)(1)(A)(i) that identify the airpollutants subject to CAA section111(d). The ambiguities stem fromapparent drafting errors that occurredduring enactment of the 1990 CAAAmendments, which revised section111(d).

During the 1990 CAA Amendments,the House of Representatives and theSenate each passed an amendment to

CAA section 111(d)(1)(A)(i). The twoamendments differed from each other,and were not reconciled during theConference Committee and, as a result,both were enacted into law. Asamended by the Senate, the pertinentlanguage of CAA section 1i1(d)(i)would exclude the regulation of anypollutant which is “included on a listpublished under [CAA sectionl112(b).” 87 As amended by the House,the pertinent language in CAA sectioniil(d)(i) would exclude the regulationof any pollutant which is “emitted froma source category which is regulatedunder section 112.” 88 The two versionsconflict with each other and thus areambiguous. Under these circumstances,the EPA may reasonably construe theprovision to authorize the regulation ofGHGs under CAA section 111(d).

It should be noted that the U.S.Supreme Court’s holding in AmericanElectric Power Co. v. Connecticut, 131 5.Ct. 2527, 2537—38 (2011), that “theClean Air Act and the EPA actions itauthorizes displace any federal commonlaw right to seek abatement of carbon-dioxide emissions from fossil fuel-firedpower plants” was premised on theCourt’s understanding that CAA section111, including CAA section 111(d),applies to carbon dioxide emissionsfrom those sources.

We discuss this issue in more detailin the Legal Memorandum.

B. Authority To Regulate EGUs

Before the EPA finalizes this CAAsection 111(d) rule, the EPA willfinalize a CAA section 111(b)rulemaking regulating CO2 emissionsfrom new EGUs, which will provide therequisite predicate for applicability ofCAA section 111(d).

CAA section 111(d)(1) requires theEPA to promulgate regulations underwhich states must submit state plansregulating “any existing source” ofcertain pollutants “to which a standardof performance would apply if suchexisting source were a new source.” A“new source” is “any stationary source,the construction or modification ofwhich is commenced after thepublication of regulations (or, if earlier,proposed regulations) prescribing astandard of performance under [CAAsection 1111 which will be applicable tosuch source.” It should be noted thatthese provisions make clear that a “newsource” includes one that undertakeseither new construction or amodification. It should also be noted

87Public Law 101—549, § 302(a), 104 Stat, at 2574(Nov. 15, 1990).88i Law 101—549, § 108(g), 104 Stat, at 2467

(Nov. 15, 1990).



that the EPA’s implementing regulationsdefine “construction” to include“reconstruction,” which theimplementing regulations go on todefine as the replacement ofcomponents of an existing facility to anextent that (i) the fixed capital cost ofthe new components exceeds 50 percentof the fixed capital cost that would berequired to construct a comparableentirely new facility, and (ii) it istechnologically and economicallyfeasible to meet the applicablestandards.

Under CAA section 111(d](1), in orderfor existing sources to become subject tothat provision, the EPA mustpromulgate standards of performanceunder CAA section 111(b) to which, ifthe existing sources were new sources,they would be subject. Those standardsof performance may include ones forsources that undertake newconstruction, modifications, orreconstructions.

The EPA is in the process ofpromulgating two rulemakings underCAA section 111(b) for CO2 emissionsfrom affected sources. The EPAproposed the first, which applies toaffected sources undertaking newconstructions, by notice dated January8, 2014, which we refer to as the January2014 Proposal. The EPA is proposingthe second, which applies to affectedsources undertaldng modifications orreconstructions, concurrently with thisCAA section 111(d) proposal. The EPAwill complete one or both of these CAAsection 111(b) rulemakings before orconcurrently with this CAA section111(d) rulemaking, which will providethe requisite predicate for applicabilityof CAA section 111(d).89

C. Affected SourcesThe EPA is proposing that, for the

emission guidelines, an affected EGU isany fossil fuel-fired EGU that was inoperation or had commencedconstruction as of January 8, 2014, andis therefore an “existing source” forpurposes of CAA section 111, and thatin all other respects would meet theapplicability criteria for coverage underthe proposed GHG standards for newfossil fuel-fired EGUs (79 FR 1430;January 8, 2014).

The January 8, 2014 proposed GHGstandards for new EGUs generallydefine an affected EGU as any boiler,integrated gasification combined cycle

891n the past, the EPA has issued standards ofperformance under section 111(b) and emissionguidelines under section 111(d) simultaneously.See “Standards of Performance for new StationarySources and Guidelines for Control of ExistingSources: Municipal Solid Waste Landfills—FinalRule,” 61 FR 9905 (March 12, 1996).

(IGCC), or combustion turbine (in eithersimple cycle or combined cycleconfiguration) that (1) is capable ofcombusting at least 250 million Btu perhour; (2) combusts fossil fuel for morethan 10 percent of its total annual heatinput (stationary combustion turbineshave an additional criteria that theycombust over 90 percent natural gas); (3)sells the greater of 219,000 M’Wh peryear and one-third of its potentialelectrical output to a utility distributionsystem; and (4) was not in operation orunder construction as of January 8, 2014(the date the proposed GHG standards ofperformance for new EGUs werepublished in the Federal Register). Theminimum fossil fuel consumptioncondition applies over any consecutivethree-year period (or as long as the unithas been in operation, if less). Theminimum electricity sales conditionapplies on an annual basis for boilersand IGCC facilities and over rollingthree-year periods for combustionturbines (or as long as the unit has beenin operation, if less).

The rationale for this proposalconcerning applicability is the same asthat for the January 8, 2014 proposal,sections V.A—B. See 79 FR at 1,459/1—1,461/2. We incorporate that discussionby reference here.

D. Implications for Tribes and U.S.Territories

As noted in Section II]) of thispreamble, although affected EGUslocated in Indian country operate as partof the interconnected system ofelectricity production and distribution,affected EGUs located in Indian countrywithin a state’s borders would not beencompassed within the state’s CAAsection 111(d) plan. The EPA is awareof four potentially affected power plantslocated in Indian country: The SouthPoint Energy Center, on Fort Mojavetribal lands within Arizona; the NavajoGenerating Station, on Navajo triballands within Arizona; the Four CornersPower Plant, on Navajo tribal landswithin New Mexico; and the BonanzaPower Plant, on Ute tribal lands withinUtah. The South Point facility is anNGCC power plant, and the Navajo,Four Corners, and Bonanza facilities arecoal-fired power plants. The operatorsand co-owners of these four facilitiesinclude investor-owned utilities,cooperative utilities, public poweragencies, and independent powerproducers, most of which also co-ownpotentially affected EGUs within statejurisdictions. We are not aware of anypotentially affected EGUs that areowned or operated by tribal entities. ifit determines that such a plan isnecessary or appropriate, the EPA has

the responsibility to establish CAAsection 111(d) plans for areas of Indiancountry where affected sources arelocated unless a tribe on whose lands anaffected source (or sources) is locatedseeks and obtains authority from theEPA to establish a plan itself, pursuantto the Tribal Authority Rule.°° The EPAintends to publish a supplementalproposal to establish emissionperformance goals (if it determines thatsuch action is necessary or appropriate)covering the four potentially affectedpower plants identified above, as wellas any subsequently identified similarlysituated power plants, and also toproposed goals for U.S. territories withaffected EGUs. The EPA intends to takefinal action on that proposal by June2015. If a tribe does seek and obtain thenecessary authority to establish a planitself, it is the EPA’s intention that thetribe would have flexibility to developa plan tailored to its circumstances, inthe same manner as a state, to meet CO2emission performance goals that wouldbe established by the EPA based onapplication of the BSER to that area ofIndian country. The EPA is aware ofactions that have been taken or are beingtaken by some sources in tribal areas orterritories and will be mindful of theseactions in considering establishment ofa plan.

The EPA invites comment on whethera tribe wishing to develop andimplement a CAA section 111(d) planshould have the option of including theEGUs located in its area of Indiancountry in a multi-jurisdictional planwith one or more states (i.e., treating thetribal lands as an additional state).

If the EPA develops one or more CAAsection 111(d) federal plans for areas ofIndian country with affected EGUs, weare likewise currently considering doingso on a multi-jurisdictional basis incoordination with nearby statesdeveloping section 111(d) state plans.The EPA solicits comment on such anapproach for a federal plan.

At this time, the EPA is not proposingCO2 emission performance goals forareas of Indian country containingpotentially affected EGUs. We do planto establish such goals in the future, tobe addressed through either tribal orfederal plans, as discussed above. TheEPA notes that some present andplanned actions being taken to reducecriteria pollutants from EGUs in Indiancountry will result in significant CO2emission reductions relative toemissions in the 2012 baseline periodused in computing the state CO2

0 40 CFR 49.1 to 49.11.



performance goals in this proposal.9’We invite comment on how the BSERshould be applied to potentially affectedEGUs in Indian country. We particularlyinvite comment on data sources forsetting renewable energy and demand-side energy efficiency targets.

The state-specific goals that the EPAis proposing are based on the collectionof affected EGUs located within thatstate. In setting goals specific to an areaof Indian country, the EPA proposes tobase the goals on the collection ofaffected EGUs located within that areaof Indian country. We request commenton this approach.

F. Combined Categories andCodification in the Code ofFederalRegulations

In this rulemaking, the EPA issoliciting comment on combining thetwo existing categories for the affectedEGUs into a single category for purposesof facilitating emission trading amongsources in both categories. The EPA isalso proposing codifying all of theproposed requirements for the affectedEGUs in a new subpart UUUU of 40 CFRpart 60.

As discussed in the January 8, 2014proposal for the CAA section 111(b)standards for GHG emissions fromEGUs, in 1971 the EPA listed fossil fuel-fired steam generating boilers as a newcategory subject to section 111rulemaking, and in 1979 the EPA listedfossil fuel-fired combustion turbines asa new category subject to the CAAsection 111 rulemaking. In the ensuingyears, the EPA has promulgatedstandards of performance for the twocategories, and codified those standards,at various times, in 40 CFR part 60subparts D, Da, GG, and KKKK. In the2014 proposal, the EPA proposedseparate standards of performance forsources in the two categories andproposed codifying the standards in thesame Da and KKKK subparts thatcurrently contain the standards ofperformance for conventional pollutantsfrom those sources. In addition, the EPAco-proposed combining the twocategories into a single category solelyfor purposes of the CO2 emissions fromnew construction of affected EGUs, andcodifying the proposed requirements ina new 40 CFR part 60 subpart TTTT.The EPA solicited comment on whethercombining the categories for new

91For example, a plan currently beingimplemented at the Four Corners plant to satisfyregional haze requirements calls for reduction ofNOx emissions to be achieved in part by shuttingdown a portion of the plants generating capacity,and a similar plan has been proposed for the Navajoplant. See 78 FR 62509 (October 22, 2013).

sources is necessary in order to combinethe categories for existing sources.

In the present rulemaking, the EPA isproposing emission guidelines for thetwo categories and is solicitingcomment on combining the twocategories into a single category forpurposes of the CO2 emissions fromexisting affected EGUs. The EPA solicitscomment on whether combining the twocategories would offer additionalflexibility, for example, by facilitatingimplementation of CO2 mitigationmeasures, such as shifting generationfrom higher to lower-carbon intensitygeneration among existing sources (e.g.,shifting from boilers to NGCC units) orfacilitating emissions trading amongsources. Because the two categories arepre-existing and the EPA would not besubjecting any additional sources toregulation, the combined categorywould not be considered a new categorythat the EPA must list under CAAsection 111(b)(1)(A). As a result, thisproposal does not list a new categoryunder section 111(a)(1)(A), nor does thisproposal revise either of the two sourcecategories—steam-generating boilersand combustion turbines—that the EPAhas already listed under that provision.Thus, the EPA would not be required tomake a finding that the combinedcategory causes or contributessignificantly to air pollution which mayreasonably be anticipated to endangerpublic health or welfare.

In addition, the EPA is proposing tocreate a new subpart UUUU and toinclude all GHG emission guidelines forthe affected sources—utility boilers andIGCC units as well as natural gas-firedstationary combustion turbines—in thatnewly created subpart. We believe thatcombining the emission guidelines foraffected sources into a new subpartUUUU is appropriate because theemission guidelines the EPA isestablishing do not vary by type ofsource. Accordingly, the EPA is notproposing to codify any of therequirements of this rulemaking insubparts Da or KKKK.

VI. Building Blocks for Selling StateGoals and the Best System of EmissionReduction

A. IntroductionBased on the experiences of states and

the industry and the EPA’s outreachwith stakeholders as described above,the EPA has identified multiplemeasures currently in use for achievingCO2 emission reductions from existingfossil fuel-fired EGUs. For purposes ofdetermining the “best system ofemission reduction. . . adequatelydemonstrated” (BSER) and developing

state emission performance goals, wehave screened the measures and havefound that they support two alternativeformulations for the BSER. We aregrouping the measures that we areproposing to consider further at thistime into four categories, which we call“building blocks.” We provide anoverview of these building blocks inSection VLB and more detaileddiscussion of each block in SectionW.C. In Section Vl.D we discusspossible combinations of the buildingblocks, and in Section VI.E, we explainwhy as a legal matter all four buildingblocks, taken together, support theBSER, which in turn serves as the basisfor the standards of performance thatthe states must include in their stateplans, as CAA section 111(d) requires.

As discussed in Section ifi of thispreamble, we are mindful of numerousand varied stakeholder concerns,including the need to achievemeaningful CO2 emission reductions atthe affected facilities and to recognizeand take advantage of the progressalready made by existing programs. Likestakeholders, we are attentive to theneed to maintain electricity systemreliability and to minimize adverseimpacts on electricity and fuel pricesand on assets that have already beenimproved by installation of controls forother kinds of pollution. Many of theseconsiderations align with our approachto determining the BSER, as discussedmore in Section VII, and we considerseveral of these to be key principles inthis application. As discussed inSections VII and VIII, we acknowledgeand appreciate the advantages ofallowing and promoting flexibility forstates in crafting their programs. Werecognize the knowledge that stateshave about their specific situations andtheir ability to evaluate and leverageexisting and new capacity and programsto ultimately reduce EGU CO2emissions.

Similarly, we recognize andappreciate that states operate withdiffering circumstances and policypreferences. For example, states havediffering access to specific fuel types,and the variety of types of EGUsoperating in different states is broad andsignificant. States are part of assortedEGU dispatch systems and vary in theamounts of electricity that they importand export. For these reasons, we alsorecognize and appreciate the value inallowing and promoting multi-statereduction strategies. Some states alreadyparticipate in a multi-state program thatreduces CO2 emissions, the RGGI, andwe have noted the success of thatprogram for those states.


34856 Federal Register/Vol. 79, No. 117/Wednesday, June 18,2014/Proposed Rules

Another key consideration indetermining the BSER, as discussedmore in the following sections, is therelationship between the timing ofmeasures and their effectiveness inlimiting emissions. For example, actionsthat can occur in the near term, such asimprovements to individual EGU heatrates, may fail to achieve the cumulativeemission reductions that sustainedimplementation of other actions, such asdemand-side energy efficiencyprograms, may achieve over time.

B. Building Blocks for the Best SystemofEmission Reduction

This subsection summarizes theEPA’s analytic approach to determiningthe best system of emission reduction(BSER) for CO2 emissions from existingEGUs. Later subsections discussparticular measures and how they formthe basis of the BSER.92

1. Overview of ApproachIn considering the appropriate scope

of the proposed BSER, the EPAevaluated three basic groupings ofstrategies for reducing CO2 emissionfrom EGUs: (i) Reductions achievablethrough improvements in individualEGUs’ emission rates (referred tothroughout this preamble as “buildingblock 1”); (ii) EGU CO2 emissionsreductions achievable through redispatch from affected steam EGUs toaffected NGCC units (“building block2”); and (iii) EGU CO2 emissionsreductions achievable by meetingdemand for electricity or electricityservices through expanded use of low-or zero-carbon generating capacity(“building block 3”) and through

92The EPA is aware of the potential that one ormore facilities involved in programs mentioned orrelied on in this proposal may have received someform of assistance under the Energy Policy Act of2005 (EPAct). Section 402 (i) of the EPAct (codifiedat 42 U.S.C. section 15962(1)) states:

“No technology, or level of emission reduction,solely by reason of the use of the technology, or theachievement of the emission reduction, by 1 ormore facilities receiving assistance under this Act,shall be considered to be—(1) adequatelydemonstrated for purposes of section 111 of theClean Mr Act (42 U.S.C. 7411)[.J”

In a February 26, 2014 Notice of DataAvailability, the EPA proposed to give thisprovision its natural meaning: the term “solely”modifies all of the provisions, so that any“adequately demonstrated” finding by the EPAcould not be based solely upon technology, level ofemission reduction, or achievement of the emissionreduction by a facility (or facilities) receivingassistance. The EPA proposes the sameinterpretation here. The EPA further believes thatits proposed determination of the “best system ofemission reduction. . . adequately demonstrated”does not depend exclusively on technology, level ofemission reduction, or achievement of emissionreduction from facilities receiving EPAct assistance,given the myriad number of technologies andemission performance on which that proposeddetermination is based.

expanded use of demand-side energyefficiency (“building block 4”). Whilethe first grouping plays the same role ineach of our two formulations of theBSER, the second and third groupingsplay different roles: In the firstformulation they constitute componentsof the BSER, and in the secondformulation they serve as the basis forwhy a component of that formulation ofthe BSER—reduced utilization of thehigher-emitting affected EGUs—isadequately demonstrated.

As described in the remainder of thissection, the EPA concluded that whilecertain strategies within the firstgrouping clearly should be part of theBSER, it was not appropriate to limitconsideration of the BSER to this firstgrouping, for several reasons. First, wedetermined that some strategiesavailable in the other two groupings cansupport reduced CO2 emissions from thefossil fuel-fired EGUs by significantamounts and at lower costs than someof the strategies in the first grouping.Second, we observed that strategies inall three groupings were already beingpursued by states and sources takingadvantage of the integrated nature of theelectricity system, at least in part for thepurpose of reducing CO2 emissions.Third, we were concerned that ifmeasures from the first grouping thatimprove heat rates at coal-fired steamEGUs were implemented in isolation,without additional measures thatencourage substitution of less carbonintensive ways of providing electricityservices for more carbon-intensivegeneration, the resulting increasedefficiency of coal-fired steam unitswould provide incentives to operatethose EGUs more, leading to smalleroverall reductions in CO2 emissions.93These factors reinforced theappropriateness of our consideringstrategies from all three groupings forpurposes of determining the BSER.

2. CO2 Reductions Achievable ThroughImprovements in Individual EGUs’Emission Rates

The first grouping of CO2 emissionreduction options that the EPAevaluated as potential options for theBSER consists of measures that canreduce individual EGUs’ CO2 emissionrates (i.e., the amount of CO2 emittedper unit of electricity94 output). These

Elsewhere in the preamble we refer to thepotential for efficiency improvements to lead toincreased competitiveness and therefore increasedutilization as a “rebound effect.”

94 simplicity, throughout this preamble wegenerally refer to the energy output produced byEGUs as electricity, recognizing that some EGUsproduce a portion of their energy output in otherforms, such as steam for heating or process uses.

measures included improving theefficiency with which EGUs convert fuelheat input to electricity output (i.e., heatrate improvements), applying carboncapture and storage (CCS) technology,and substituting lower-carbon fuelssuch as natural gas for higher-carbonfuels such as coal (i.e., natural gas cofiring or conversion].

Our assessment of heat rateimprovements showed that thesemeasures would achieve CO2 emissionreductions at low costs, althoughcompared to other measures, theavailable reductions were relativelylimited in quantity.95 Specifically, ouranalysis indicated that average CO2emission reductions of 1.3 to 6.7 percentcould be achieved by coal-fired steamEGUs through adoption of bestpractices, and that additional averagereductions of up to four percent couldbe achieved through equipmentupgrades.96 Heat rate improvements payfor themselves at least in part throughreductions in fuel costs, generallymaking this a relatively inexpensiveapproach for reducing CO2 emissions.We estimated that CO2 reductions ofbetween four and six percent fromoverall heat rate improvements could beachieved on average across the nation’sfleet of coal-fired steam EGUs for netcosts in a range of $6 to $12 per metricton.97

The EPA also examined application ofCCS technology at existing EGUs. CCSoffers the technical potential for CO2emission reductions of over 90 percent,or smaller percentages in partialapplications. In the recently proposedCarbon Pollution Standards for newfossil fuel-fired EGUs (79 FR 1430), wefound that partial CCS was adequatelydemonstrated for new fossil fuel-firedsteam EGUs and integrated gasification

The discussion here applies to both EGUs thatproduce only electricity and EGUs that produce acombination of electricity and other energy output.

95 EPA assessed opportunities to achieve CO2reductions through heat rate improvements at bothcoal-fired steam EGUs and non-coal-fired fossilfuel-fired EGUs, such as oil/gas-fired steam EGUsand NGCC units. At this time we are proposing thatthe basis for supporting the BSER should includeheat rate improvements only at coal-fired steamEGUs, but we are inviting comment on includingheat rate improvements at other EGU types. SeeSection W.C.5 for further discussion of ourassessment of heat rate opportunities for non-coal-fired EGUs.

96These estimated ranges are averages applicableto the fleet of coal-fired steam EGUs as a whole.Potential improvements at individual EGUs couldbe higher or lower.

97 noted above, in the absence of other kindsof CO2 emission reduction measures, the emissionreductions achievable through heat rateimprovements could be offset to some extent byincreased utilization of EGUs making theimprovements (a “rebound effect”). See SectionW,C.i below for further discussion.



combined cycle (IGCC) units. We alsofound that for these new units the costswere not unreasonable, either forindividual units or on a national basis,and we proposed to find thatapplication of partial CCS is the BSER.However, application of CCS at existingunits would entail additionalconsiderations beyond those at issue fornew units. Specifically, the cost ofintegrating a retrofit CCS system into anexisting facility would be expected to besubstantial, and some existing ECUsmight have space limitations and thusmight not be able to accommodate theexpansion needed to install CCS.Further, the aggregated costs of applyingCCS as a component of the BSER for thelarge number of existing fossil fuel-firedsteam ECUs would be substantial andwould be expected to affect the cost andpotentially the supply of electricity ona national basis. For these reasons,although some individual facilities mayfind implementation of CCS to be aviable CO2 mitigation option in theirparticular circumstances,98 the EPA isnot proposing and does not expect tofinalize CCS as a component of theBSER for existing EGUs in thisrulemaldng.99 Nevertheless, CCS wouldbe available to states and sources as acompliance option.

Natural gas co-firing or conversion atcoal-flied steam EGUs offers greaterpotential CO2 emission reductions thanheat rate improvements, but at a highercost (although less than the cost ofapplying CCS technology). Becausenatural gas contains less carbon than anenergy-equivalent quantity of coal,converting a coal-fired steam EGU toburn only natural gas would reduce theunit’s CO2 emissions by approximately40 percent. The CO2 reductions aregenerally proportional to the amount ofgas substituted for coal, so if an ECUcontinued to bum mostly coal while cofiring natural gas as, for example, 10percent of the ECU’s total heat input,the CO2 emission reductions would beapproximately four percent. The EPAdetermined that the most significantcost associated with natural gasconversion or co-firing is likely to be theincremental cost of natural gas relativeto the cost of coal. Using EnergyInformation Administration (EIA) fuelprice projections, we estimated that theCO2 reductions achieved throughnatural gas conversion or co-firing at anaverage coal-fired steam ECU would

CCS already has been or is being implementedat some existing EGUs, as noted in the discussionof CCS later in the preamble.

asAs noted later in this preamble, we arenevertheless seeking comment on the extent towhich existing EGUs could implement CCS in orderto improve our understanding.

have costs ranging from approximately$83 to $150 per metric ton.’°° Thus,although there have been past instanceswhere coal-fired steam EGUs have beenconverted to natural gas, and we expectsome additional future conversionswhere circumstances at individualECUs make the option particularlyattractive, for the industry as a wholewe would expect that other approachescould reduce CO2 emissions fromexisting EGUs at lower cost. However,gas conversion or co-firing would beavailable to states and sources as acompliance option, and, as noted laterin the preamble, we are seekingcomment on whether this option shouldbe considered part of the BSER.

3. CO2 Emission Reductions AchievableThrough Re-Dispatch From Steam EGUsto NGCC Units

The second grouping of CO2 emissionreduction options evaluated by the EPAin the BSER analysis involves reducingemissions by shifting generation amongaffected EGUs. An obvious alternative tosubstituting natural gas for coal atindividual steam ECUs throughconversion or co-firing is instead to usenatural gas to generate electricity at adifferent affected ECU with a better heatrate—notably a natural gas combinedcycle (NCCC) unit—and to substitutethat electricity for electricity from thecoal-fired steam ECU, thus resulting inlower emissions from the coal-firedsteam ECU and lower emissions fromthe set of affected ECUs overall.101 Theelectricity system is physicallyinterconnected or networked andoperated on an integrated basis acrosslarge regions. System operatorsroutinely increase or decrease theelectricity output of individual ECUs torespond to changes in electricitydemand, equipment availability, andrelative operating costs (or bid prices) ofindividual ECUs while observingreliability-related constraints. It has longbeen common industry practice forsystem operators to choose from amongmultiple ECUs when deciding whichECU to “dispatch” to generate the nextincrement of electricity needed to meetdemand. Thus, the well-establishedpractices of the industry support ourevaluation of “re-dispatch” ofgeneration from steam ECUs to NGCCunits as a potential component of the

100 lower end of the range is for conversionto 100 percent natural gas, which would allowEGUs to eliminate certain fixed operating andmaintenance costs associated with coal use but notnatural gas use. See Section W.C.5.a below forfurther discussion.

101 Strategies in this grouping also includeshifting generation from steam EGUs burning oil ornatural gas to more efficient NGCC units.

basis for the BSER to reduce CO2emissions from existing EGUs.

NCCC units can produce as much as46 percent more electricity from a givenquantity of natural gas than steamECUs,102 making the re-dispatchapproach a significantly less expensiveway to reduce CO2 emissions thanconversion or co-firing of coal-firedsteam ECUs to burn natural gas. Forexample, using the same ETA fuel costprojections as were used above toestimate the costs of natural gasconversion or co-firing, we estimatedthat the cost of CO2 reductionsachievable by substituting electricityfrom an existing NCCC unit forelectricity from an average coal-firedsteam ECU would be approximately $30per metric ton.’°3

Our analysis indicated that thepotential CO2 reductions availablethrough re-dispatch from steam ECUs toNGCC units are substantial. As of 2012,there was approximately 245 GW ofNCCC capacity in the United States, 196GW of which was placed in servicebetween 2000 and 2012.’° In 2012, theaverage utilization rate of U.S. NCCCcapacity was 46 percent, well below theutilization rates the units are capable ofachieving. In 2012 approximately 10percent of NGCC plants operated atannual utilization rates of 70 percent orhigher, and 19 percent of NGCC unitsoperated at utilization rates of at least 70percent over the summer season.Average reported availability generallyexceeds 85 percent. We recognize thatthe ability to increase NCCC utilizationrates may also be affected byinfrastructure and systemconsiderations, such as limits on theability of the natural gas industry toproduce and deliver the increasedquantities of natural gas, the ability ofsteam ECUs to reduce generation whileremaining ready to supply electricitywhen needed in peak demand hours,and the ability of the electrictransmission system to accommodatethe changed geographic pattern ofgeneration. However, theseconsiderations have not limited pastrapid increases in NGCC generationlevels, as indicated by a 20 percentincrease in natural gas consumption for

estimate assumes an average heat rate of10,434 BtuJkWh for coal fossil fuel-fired steamunits between 400 and 600 MW and 7,130 Btu/kWhfor NGCC units between 400 and 600 MW. SeeNEEDSv.5.13 at http://wwwepa.gov/powersectormodeling/BaseCasev5l3.html.

103 Section VI.C.2 below for furtherdiscussion.

‘°EIA Form 860, available at hftp://www.eia.gov/electricity/data/eiaB6O. In comparison, in 2012there was 336 GW of coal steam capacity, of which22 GW was placed in service between 2000 and2012. Id.



electricity generation from 2011 to2012.105 Further, we have taken theseconsiderations into account, and theproposal’s compliance scheduleprovides flexibility and time forinvestment in additional natural gas andelectric industry infrastructure ifneeded.

As discussed below in Section VLC.2,the data and considerations cited abovesupport our assessment that an averageNGCC utilization rate in a range of 65to 75 percent is a reasonable target forthe amount of additional NGCCgeneration that could be substituted forhigher carbon generation from steamEGUs as part of the BSER. 106 If redispatch consistent with a target averageNGCC utilization rate of 70 percent hadbeen achieved in 2012, the combinedCO2 emissions of steam EGUs andNGCCs would have been reduced byapproximately 13 percent.

Finally, we also note that mechanismsfor encouraging re-dispatch as a CO2reduction measure have already beendeveloped and applied in the industry.Under both RGGI and California’sGlobal Warming Solutions Act, shiftinggeneration from more carbon-intensiveEGUs to less carbon-intensive EGUs is away to facilitate compliance withregulatory requirements. In both cases,the industry has demonstrated theability to respond to the regulatoryrequirements of these state programs.

4. CO2 Emission Reductions AchievableThrough Other Actions Underway in theIndustry

The third grouping of CO2 emissionreduction options the EPA evaluated inthe BSER analysis encompasses othermeasures already used in the industryand not included in the first twogroupings. From our evaluation of redispatch as an option for reducing CO2emissions, it was apparent that relevantfactors for consideration include theintegrated nature of the electricitysystem and the fact that particularmeasures capable of reducing CO2emissions at EGUs were already beingused and would continue to be usedthroughout the industry, either for thepurpose of compliance with CO2emission reduction requirements or toserve other purposes and policy goals.That observation led us to considerwhat other potential actions and optionsthe industry was already using that hadresulted in or could result in, orsupport, the reduction of CO2 emissions

‘°5EIA Form 923, available at http://www.eia.gov/electricity/data/e1a923/.

106 Substitution would only occur to the extentthat there is both NGCC capacity whose generationcould be increased and steam EGUs whosegeneration could be decreased.

at EGUs. Again, we observed many suchinstances, some taking place incidentalto the routine operation of the electricitysystem and others taking place inresponse to specific state initiatives toreduce CO2 emissions from the powersector. We concluded that there are twoprincipal types of such potential optionsfor measures that support CO2 emissionreductions at EGUs affected under thisproposal: Ongoing development and useof low- and zero-carbon generatingcapacity, and ongoing development andapplication of demand-side energyefficiency measures.

Low-and zero-carbon generatingcapacity provides electricity that can besubstituted for generation from morecarbon-intensive EGUs. More than halfthe states already have established someform of state-level renewable energyrequirements, with targets calling onaverage for almost 20 percent of 2020generation to be supplied fromrenewable sources. The EPA is unawareof analogous state policies to supportdevelopment of new nuclear units, but30 states already have nuclear EGUs(with five units under construction) andthe generation from these units iscurrently helping to avoid CO2emissions from fossil fuel-fired EGUs.Policies that encourage development ofrenewable energy capacity anddiscourage premature retirement ofnuclear capacity could be usefulelements of CO2 reduction strategies andare consistent with current industrybehavior. Costs of CO2 reductionsachievable through these policies havebeen estimated in a range from $10 to$40 per metric ton.’°7

Demand-side energy efficiencyprograms produce electricity-dependentservices with less electricity, andthereby support reduced generationfrom existing fossil fuel-fired EGUs byreducing the demand for thatgeneration. Reduced generation resultsin lower CO2 emissions. More than 40states already have established someform of demand-side energy efficiencypolices, and individual states haveavoided up to 13 percent of theirelectricity demand. Again, policies thatencourage demand-side energyefficiency could be useful elements ofCO2 reduction strategies and areconsistent with current industrybehavior. Using conservatively highestimates of the costs of demand-sideenergy efficiency, the EPA estimatesthat the costs of CO2 emissionreductions achievable consistent with

107 See Section VLC.3 below for furtherdiscussion.

such policies would be in a range of $16to $24 per metric ton. 108

5. Summary of Building Blocks for theBest System of Emission Reduction

Based on the analytic approachsummarized above, the EPA hasidentified the following four principalcategories—”building blocks”—ofmeasures that provide the foundation ofour BSER determination for CO2emissions from existing EGUs:


2. Reducing emissions from the mostcarbon-intensive affected EGUs in theamount that results from substitutinggeneration at those EGUs withgeneration from less carbon-intensiveaffected EGUs (including NGCC unitsunder construction).



Since they either result in improvedoperating efficiency or supportreductions in mass emissions at existingEGUs, each of the four building blocksrepresents a demonstrated basis forreducing CO2 emissions from affectedEGUs that is already being pursued inthe power sector. In the next subsection,we discuss each of the building blocksat length. Our approach for applying thebuilding blocks to each state’scircumstances in order to develop stategoals is described in Section VII of thispreamble.

C. Detailed Discussion ofBuildingBlocks and Other Options Considered

In this subsection we discuss each ofthe building blocks in turn. For eachbuilding block, we provide ourproposed assessment of the technicalpotential of the building block and thereasonableness of its costs within thecontext of the BSER determination, andwe describe how we developed the datainputs used in the computations of theproposed state goals described inSection Vfl.C and the alternate goalsoffered for comment in Section VII.E.We also discuss certain measures thatwe are not proposing to consider as partof the best system of emissionreduction. Additional detail is provided

rea See Section VI.C.4 below for furtherdiscussion.



in the Greenhouse Gas AbatementMeasures TSD.

It is worth noting that although thediscussion below necessarily addressesthe building blocks individually, statesare not required to pursue plansinvolving any given building block or todo so at any particular level ofstringency. Rather, states have flexibilityto establish plans to meet their stateemission limitations using their ownpreferred combinations of efficaciousmeasures applied to the extentdetermined appropriate by the states.The EPA expects that states and affectedEGUs are unlikely to limit themselves tothe measures in any single buildingblock, but instead are likely to pursueportfolios of measures from acombination of the actions encompassedin the building blocks. In developing thedata inputs to be used in computingstate goals, the EPA has estimatedreasonable rather than maximumpossible implementation levels for eachbuilding block in order to establishoverall state goals that are achievablewhile allowing states to take advantageof the flexibility to pursue somebuilding blocks more extensively, andothers less extensively, than is reflectedin the goal computations, according toeach state’s needs and preferences.

1. Building Block 1—Heat RateImprovements

The first category of approaches toreducing CO2 emissions at affectedfossil fuel-fired EGUs consists ofmeasures that reduce the carbonintensity of generation at individualcoal-fired steam EGUs’°9 by improvingheat rate. Heat rate improvements arechanges that increase the efficiency withwhich an EGU converts fuel energy toelectric energy (and useful thermalenergy in the case of units thatcogenerate steam for process use as wellas electricity), thereby reducing theamount of fuel needed to produce thesame amount of electricity and loweringthe amount of CO2 produced as a

1°9A “steam EGU” is an EGU that combusts fuelin a boiler and uses the combustion heat to createsteam which is then used to drive a steam turbinethat drives a generator to create electricity. Incontrast, a “combined cycle EGU” combusts fuel ina combustion turbine that directly drives agenerator, and the waste heat is then used to createsteam which is used to drive a steam turbine thatdrives a generator to create more electricity. SteamEGUs can combust a wide variety of fuels includingcoal and natural gas. combined cycle EGUs aremore efficient at converting fuel energy to electricenergy but are limited to gaseous or liquid fuels,most commonly natural gas or distillate oil. Almostall existing coal-fired EGUs are steam EGUs (theexceptions are integrated gasification combinedcycle (IGCC) units where coal is processed to createa gaseous fuel that is then combusted in a combinedcycle unit).

byproduct of fuel combustion. Heat rateimprovements yield important benefitsto affected sources by reducing theirfuel costs.

The EPA is aware of the potential for“rebound effects” from improvementsin heat rates at individual EGUs. In thiscontext, a rebound effect would occurwhere, because of an improvement in itsheat rate, an EGU experiences areduction in variable operating coststhat makes the EGU more competitiverelative to other EGUs and consequentlyraises the EGU’s generation output. Theincrease in the EGU’s CO2 emissionsassociated with the increase ingeneration output would offset thereduction in the EGU’s CO2 emissionscaused by the decrease in its heat rateand rate of CO2 emissions per unit ofgeneration output. The extent of theoffset would depend on the extent towhich the EGU’s generation outputincreased (as well as the CO2 emissionrates of the EGUs whose generation wasdisplaced). The EPA considers therebound effect to be a potential concernif heat rate improvements were the onlyapproaches being considered for theBSER, but believes that the effect can beaddressed by establishing the BSER as acombination of approaches thatincludes not only heat rateimprovements but also approaches thatwill encourage reductions in electricitydemand or increases in generation fromlower- or zero-emitting EGUs. The topicof potential rebound effects is discussedfurther in Sections VI.D and VI.E below.For purposes of the remainder of thissubsection, no rebound effect isassumed.

Although heat rate improvementshave the potential to reduce CO2emissions from all types of affectedEGUs, the EPA’s analysis indicates thepotential is significantly greater for coal-fired steam EGUs than for other EGUs,and for purposes of determining the bestsystem of emission reduction at thistime, the EPA is conservativelyproposing to base its estimate of CO2emission reductions from heat rateimprovements on coal-fired steam EGUsonly.’° The remainder of thissubsection focuses on the EPA’sanalysis of potential heat rateimprovements from coal-fired steamEGUs. Our analysis of potential heat rateimprovements from other types of

ire As noted in Section VI.C.5.d below, we aretaking comment on including heat rateimprovement opportunities at other EGU types inthe basis for supporting the BSER. Also, forcompliance purposes states and EGUs would beable to rely on CO2 emission reductions achievedthrough heat rate improvements at other types ofEGUs.

affected EGUs is addressed in SectionW.C.5 below.

a. Ability of Heat Rate Improvements ToReduce CO2 Emissions

The heat rate of an EGU is the amountof fuel energy input needed (Btu, higherheating value basis) to produce 1 kWhof net electrical energy output (anduseful thermal energy in the case ofcogeneration units).” The currentweighted-average annual heat rate ofU.S. coal-fired EGUs in the range of 400to 600 MW is approximately 10,434 Btuper net kWh.”2 Because an EGU’s CO2emissions are driven primarily by theamount of fuel consumed, at any fossilfuel-fired EGU there is a strongcorrelation between potential heat rateimprovements and potential reductionsin carbon-intensity.”3

Several studies have examined theopportunities to employ heat rateimprovements as a means of reducingCO2 emissions from coal-fired powerplants.114 Among these, a 2009 study bythe engineering firm Sargent & Lundyused bottom-up engineering approachesevaluating potential heat rateimprovements from specific bestpractices and equipment upgrades,including upgrades to boilers, steamturbines, and control systems. Based onthis study, the EPA believes thatimplementation of all identified bestpractices and equipment upgrades at afacility could provide total heat rateimprovements in a range ofapproximately 4 to 12 percent. (Werecognize that individual EGUs wouldonly be able to implement the bestpractices or upgrades that wereapplicable to their specific designs orfuel types and that had not already beenimplemented.)

In addition to the Sargent & Lundystudy, which looked generically at thetypes of improvements that can be madeat specific types of EGUs, historical heatrate data also provides a basis for

“ Heat rate can also be expressed on a grossbasis—i.e., fuel input per kWh of gross electricitygenerated—instead of a net basis—i.e., fuel inputper kWh of net electricity sent to the grid. Thedifference between gross and net electricity is theamount of electricity used at the plant to operatecomponents such as pumps, fans, motors, andpollution control devices.

1i2 See NEEDSv.5.13 at hftp://www.epa.gov/powersectormodeling/BaseCasev5l3.html.

113A small portion of some fossil fuel-fired EGU’sCO2 emissions may come from sources other thanfuel, such as limestone or other carbonates used tocapture sulfur dioxide (SO2) and/or hydrogenchloride (HC1) in a scrubber or dry injection system.However, CO2 emissions from these reagents willalso tend to be reduced by heat rate improvements,because reagent usage, and the associated CO2emissions, will decrease when the amount of fuelused decreases.

114 chapter 2 of the GHG Abatement MeasuresTSD for details.



discerning the existence and possiblemagnitude of potential heat rateimprovements. Many EGUs regularlyreport to both the EPA and the U.S.Department of Energy’s EnergyInformation Administration (ETA) CO2emissions and generation data, fromwhich heat input and heat rate data canbe computed. We have reviewed thesedata and have identified several “dataapparent” instances where an EGU’sheat rate experienced a substantialimprovement in a short time—presumably because of equipmentupgrades installed at that point intime—that was then sustained. Theseheat rate improvements ranged from 3 to8 percent. In combination with bottom-up engineering analysis and the further,more detailed EPA analysis of hourlydata summarized below, the individualEGU heat rate histories provide a strongbasis for considering heat rateimprovement as a meaningful potentialapproach to reducing the carbonintensity of generation at individualaffected fossil fuel-fired EGUs.

b. Amounts of Heat Rate ImprovementsIn order to estimate the technical

potential of heat rate improvementopportunities at existing fossil fuel-firedEGUs suggested by the discussionabove, the EPA pursued two principalareas of analysis. The first areaconcerned the heat rate improvementsthat could be achieved by reducing heatrate variability at individual coal-firedEGUs through adoption of best practicesfor operation and maintenance. Thesecond area concerned heat rateimprovement opportunities that couldbe achieved through further equipmentupgrades. Both analyses are summarizedbelow along with our conclusions, andare discussed in greater detail in theGHG Abatement Measures TSD.

For the best practices analysis, theEPA worked with the hourly datareported to the EPA by affected EGUssubject to the monitoring and reportingrequirements of 40 CFR Part 75. Thereported data include hourly heat inputand, for most reporting EGUs, hourlygross generation, making it possible tocompute hourly gross heat rates. Weused the hourly data to assess variabilityin the hourly gross heat rates ofapproximately 900 individual coal-firedsteam EGUs over the period from 2002to 2012. Specifically, the EPA evaluatedthe consistency with which individualEGUs maintained their hourly heat ratesover time. We expected that a certaindegree of short-term heat rate variabilitywas caused by factors beyond operators’control, notably variation in hourlyambient temperature and hourly load,and preliminary analysis confirmed our

expectation. We therefore controlled forvariation in those factors by groupingthe observed hourly heat rate data foreach EGU into subsets corresponding toranges of hourly ambient temperaturesand hourly load levels.115 We believethat the amount of residual variabilitywithin each data subset is an indicationof the degree of technical potential toimprove the consistency with whichoptimal heat rate performance isachieved by adopting operating andmaintenance best practices. Forexample, optimal heat rate performancecould be achieved with greaterconsistency through practices such asturning off unneeded pumps at reducedloads, installation of digital controlsystems, more frequent tuning ofexisting control systems, or earlier like-kind replacement of worn existingcomponents. (Upgrades to existingequipment are considered below.) Byapplying best practices to theiroperating and maintenance procedures,owners and operators of EGUs couldreduce heat rate variability relative toaverage heat rates and, because thedeviations generally result inperformance worse than the optimalheat rates, improve the EGUs’ averageheat rates. Assuming that between 10percent and 50 percent of the deviationfrom top decile performance in eachsubset of hourly heat rate observationswithin defined ranges of temperatureand load could be eliminated throughadoption of best practices, the result isa corresponding estimated range of 1.3percent to 6.7 percent technicalpotential for improvement in theaverage heat rate of the entire fleet ofcoal-fired EGUs.”6 Based on thisanalysis, we believe a reasonableestimate for purposes of developingstate-specific goals is that affected coal-fired steam EGUs on average couldachieve a four percent improvement inheat rate through adoption of bestpractices to reduce hourly heat ratevariability. This estimate corresponds tothe elimination, on average across thefleet of affected EGUs, of 30 percent ofthe deviation from top-decileperformance in the hourly heat rate foreach EGU not attributable to hourlytemperature and load variation. We alsosolicit comment on the use of estimatesup to six percent, reflecting elimination

115 Temperature data are from the NationalOceanic and Atmospheric Administration’sIntegrated Surface Data, hftp://www.ncdc.noaa.gov/data-access/iand-based-station-data/land-baseddatasets/integrated-surface-database-isd. Electricalgeneration data are from the EPA’s Mr MarketsProgram Data, http://ampd.epa.gov/ampd/.

116 examined whether the potential for heatrate improvement varied based on ECUcharacteristics such as capacity, boiler type, andlocation, and found no meaningful differences.

on average of 50 percent of the deviationfrom top-decile performance.

For the equipment upgrade analysis,we evaluated potential opportunities toimprove heat rates at affected EGUsthrough specific upgrades identified inthe 2009 Sargent & Lundy study. In thatstudy, Sargent & Lundy estimatedranges of potential heat rateimprovement achievable through avariety of equipment upgrades. Wescreened the upgrades from the study toidentify what we consider to be areasonable subset of equipmentupgrades that would generally bebeyond the scope of investments wewould expect to be made for purposesof achieving the best-practices heat rateimprovements discussed above. Basedon the average of the study’s ranges ofpotential heat rate improvements fromthe various upgrades in this subset,implementation of the full subset ofappropriate opportunities at a singleEGU could be expected to result in anaggregate heat rate improvement ofapproximately four percent (incrementalto the improvement achievable fromadoption of best practices). However, werecognize that this total may overstatethe average equipment upgradeopportunity across all EGUs becausesome EGUs may have alreadyimplemented some of these upgrades.We therefore propose to use as a datainput for purposes of developing stategoals an estimate that, on average acrossthe fleet of affected EGUs, only half ofthe full equipment upgrade opportunityjust described remains—i.e., that for thefleet of affected EGUs as a whole, thetechnical potential for heat rateimprovements from equipmentupgrades incremental to the best-practices opportunity is on average twopercent rather than four percent. Wesolicit comment on increasing thisfigure up to four percent.

Some of the measures available toEGUs for reducing their carbon intensityaffect net heat rates rather than grossheat rates. Various EGU componentssuch as pumps, fans, motors, andpollution control devices use electricity,a factor that is not accounted for in grossheat rates (that is, fuel used per unit ofgross energy output) but is accountedfor in net heat rates (that is, fuel usedper unit of net energy output sent to theelectric grid or used for thermalpurposes). The electricity used by thesecomponents, referred to as auxiliary orparasitic load, may represent from 4 to12 percent of gross generation at a coal-fired steam EGU.117 The analysis of

117 Electric Power Research Institute 2011Technical Report—Program on TechnologyInnovation: Electricity Use in the Electric Sector



technical potential to reduce heat ratevariability discussed above was basedon gross heat rate data. Like gross heatrate, parasitic load can be addressedboth through adoption of best practicesand through equipment upgrades, andsome measures undertaken at EGUs mayaffect parasitic load as well as gross heatrate. Because the hourly generation datareported to the EPA represent grossgeneration, we have less data availableto directly analyze potential net heatrate improvements than gross heat rateimprovements. We have therefore notincluded any separate estimate ofparasitic load reductions achievablethrough best practices in our goal-setting data inputs. However, theseopportunities would be available as amechanism for reducing carbon-intensity at affected EGUs and thusprovide more flexibility andopportunities for sources to improvetheir heat rates at reasonable costs.’18

The total of the estimated potentialheat rate improvements from adoptionof best practices to reduce heat ratevariability and implementation ofequipment upgrades as discussed aboveis six percent. This total is used as thedata input for heat rate improvements inthe computation of proposed state goalsdiscussed in Section Vll.C below.Because of the close relationshipbetween an EGU’s fuel consumptionand its CO2 emissions, a six percent heatrate improvement would be associatedwith a reduction in CO2 emissions ofapproximately six percent. We believethat this represents a reasonableestimate of the technical potential forCO2 emission reductions that would beachievable from affected coal-firedsteam EGUs, on average, through heatrate improvements as an element of thebest system of emission reduction.

For purposes of developing thealternate set of goals on which we aretaking comment, as described in SectionVll.E below, we have used a moreconservative estimate of a four percentheat rate improvement from affectedcoal-fired EGUs on average. This level ofimprovement would be consistent withthose EGUs on average implementingbest practices to reduce heat ratevariability without making further

(Opportunities to Enhance Electric EnergyEfficiency in the Production and Delivery ofElectricity).

118 proposed, the state-specific goals areexpressed in the form of CO2 emissions per netMWh, and reporting requirements for sourceswould be in the same form, allowing parasitic loadreductions to contribute to improved measured heatrates. If goals and reporting requirements werechanged to a gross MWh basis in the final rule,accounting for parasitic load reductions as a sourceof CO2 reductions would require additionalprocedures.

equipment upgrades, or would beconsistent with those EGUs on averageimplementing both best practices andequipment upgrades, but to a lesserdegree than we have projected as beingachievable for purposes of our proposal.We view the four percent estimate as areasonable minimum estimate of thetechnical potential for heat rateimprovement on average across affectedcoal-fired steam EGUs.

c. Costs of Heat Rate ImprovementsBy definition, any heat rate

improvement made for the purpose ofreducing CO2 emissions will also reducethe amount of fuel the EGU consumesto produce its electricity output. Thecost attributable to CO2 emissionreductions therefore would be the netcost to achieve the heat rateimprovement after any savings fromreduced fuel expense. As summarizedbelow, we estimate that, on average, thesavings in fuel cost associated with a sixpercent heat rate improvement would besufficient to cover much of theassociated costs, with the result that thenet costs of heat rate improvementsassociated with reducing CO2 emissionsfrom affected EGUs are relatively low.

The EPA’s most detailed estimates ofthe average costs required to achieve thefull range of heat rate improvementscome from the 2009 Sargent & Lundystudy discussed above. Based on thestudy, the EPA esthnated that for arange of heat rate improvements from415 to 1205 Btus per kwh,corresponding to percentage heat rateimprovements of 4 to 12 percent for atypical coal-fired EGU, the requiredcapital costs would range from $40 to$150 per kW. To correspond to theaverage heat rate improvement of sixpercent that we have estimated to beachievable through the combination ofbest practices and equipment upgrades,we have estimated an average cost of$100 per kW, slightly above themidpoint of the Sargent & Lundy study’srange. At an estimated annual capitalcharge rate of 14.3 percent, the carryingcost of an estimated $100 per kWinvestment would be $14.30 per kWyear. For a coal-fired EGU with a heatrate of 10,450 Btu per kWh, a utilizationrate of 78 percent, and a coal price of$2.62 per JvTh4Btu, a six percent heat rateimprovement would produce fuel costsavings of approximately $11.20 perkW-year,119 leaving approximately$3.10 per kW-year of carrying cost not

119 10,450 Btu/kWh * 8760 hours/year * 78%utilization * $2.62 per MMBtu * 6% improvement* 0.000001 MMBtu/Btu = $11.2 per kW-year. Datainputs for average coal-fired EGU heat rate, averagecoal-fired EGU utilization, and average coal priceare from the 1PM 5.13 base case for 2020.

recovered through fuel cost savings. Atan average CO2 emission rate of 0.976metric tons per MWh, the same sixpercent heat rate improvement wouldreduce CO2 emissions by 0.40 metrictons per kW-year.’2° Thus, the averagecost of CO2 reductions from heat rateimprovements would be approximately$7.75 per metric ton of CO2 ($3.10/0.40).If the average heat rate improvementachievable for the $100 per kWinvestment were only four percent,consistent with the heat rateimprovement estimate in the alternategoals on which we seek comment, theaverage cost of CO2 reductions would be$11.63 per metric ton.’21 On the otherhand, if an average heat rateimprovement of four percent could beachieved for an average investment of$50 per kw, reflecting an assumptionthat the first improvements pursuedwould be the least expensive ones, theaverage cost of CO2 reductions wouldfall to $5.81 per metric ton.122

The EPA recognizes that thesimplified cost analysis just describedwill represent the costs for some EGUsbetter than others because of differencesin EGUs’ individual circumstances. Wefurther recognize that reductions in theutilization rates of coal-fired EGUsanticipated from other componentsproposed for inclusion in the bestsystem of emission reduction wouldtend to reduce the fuel savingsassociated with heat rate improvements,thereby raising the effective cost ofachieving the CO2 emission reductionsfrom the heat rate improvements.Nevertheless, we still expect that themajority of the investment required tocapture the technical potential for CO2emission reductions from heat rateimprovements would be offset by fuelsavings, and that the net costs of heatrate improvements as an approach toreducing CO2 emissions from existingfossil fuel-fired EGUs are reasonable.

Based on the analyses of technicalpotential and cost summarized above,we propose to find that a six percentreduction in the CO2 emission rate ofthe coal-fired EGUs in a state, onaverage, is a reasonable estimate of theamount of heat rate improvement thatcan be implemented at a reasonablecost.’23

1208760 hours/year * 78% utilization * 0.976metric tons/Mwh * 6% improvement * 0.001 MW/kW = 0.40 metric tons of CO2 per kW-year. Theestimated average coal-fired EGU CO2 emission rateper MWh is from the 1PM 5.13 base case for 2020.

121$7,75 per metric ton of CO2 * 6%/4% = $11.63per metric ton of CO2.

122 $11.63 per metric ton of CO2 * $50/$100 =

$5.81 per metric ton of CO2.123 note that although we expect that heat rate

improvements are also available from other fossilcontinued



We invite comment on all aspects ofour analyses and findings related to heatrate improvements, both as sammarizedhere and as further discussed in theGreenhouse Gas Abatement MeasuresTSD. As noted earlier, we specificallyrequest comment on increasing theestimates of the amounts of heat rateimprovement achievable throughadoption of best practices for operationand maintenance and throughequipment upgrades up to six percentand four percent, respectively,representing a total potentialimprovement of up to ten percent,particularly in light of the reasonablecost of heat rate improvements. We alsosolicit comment on the quantitativeimpacts on the net heat rates of coal-fired steam EGUs of operation at loadsless than the rated maximum unit loads.

2. Building Block 2—Dispatch ChangesAmong Affected EGUs

The second element of the foundationfor the EPA’s BSER determination forreducing CO2 emissions at affectedfossil fuel-fired EGUs goes to theachievement of reductions in massemissions at certain affected EGUs—inparticular, fossil fuel-fired steamEGUs—and entails an analysis of theextent to which generation at the mostcarbon-intensive affected EGUs—again,in particular, fossil fuel-fired steamEGUs—can be replaced with generationat less carbon-intensive affected fossilfuel-fired EGUs—in particular, NGCCunits that were in operation or hadcommenced construction as of January8, 2014, and are therefore affected unitsfor purposes of this rule.

a. Ability of Re-Dispatch To Reduce CO2Emissions

The nation’s EGUs are interconnectedby transmission grids extending overlarge regions. EGU owners and gridoperators, subject to various reliabilityand operational constraints, use theflexibility provided by theseinterconnections to prioritize amongavailable EGUs when deciding whichunits should be called upon (i.e.,“dispatched”) to increase or decreasegeneration in order to meet electricitydemand at any point in time.Recognizing that increments ofgeneration are to some extentinterchangeable, dispatch decisions arebased on electricity demand at a given

fuel-fired EGUs, we have conservatively notincluded CO2 emission rate reductions for thoseEGUs in the state goals. However, as discussed inSection VLC.5.d below, we are requesting commenton this aspect of the proposal. Further, states andsources would be free to use heat rateimprovements at those other units to help reach thestate goals.

point in time, the variable costs ofavailable generating resources, andsystem constraints. This system ofsecurity-constrained economic dispatchassures reliable and affordableelectricity. Electricity demand variesacross geography and time in responseto numerous conditions, such that EGUowners and grid operators areconstantly responding to changes indemand and “re-dispatching” to meetdemand in the most reliable and cost-effective manner possible. Since theenactment and implementation of TitleIV of the CAA Amendments of 1990, inregions where EGUs are subject tomarket-based programs to limitemissions of pollutants such as 502 andNOR, the costs of emission allowanceshave been factored directly into thoseEGUs’ variable costs, like the variablecosts of operating pollution controldevices, and have thereby beenaccounted for in least-cost economicdispatch decisions by grid operators.Similarly, operators of EGUs subject toCO2 emissions limits in RGGI nowinclude the cost of RGGI CO2allowances in those EGUs’ variablecosts,124 creating economic incentives toreplace generation at higher-emittingEGUs with generation from lower-emitting sources to reduce CO2emissions at the former through theprocess of least-cost economic dispatch.As an alternate mechanism, permittingauthorities can impose limits onutilization or CO2 emissions at higher-emitting EGUs, in which case gridoperators and other market participantswould use the integrated electricitysystem to find other ways to meet thedemand for electricity services, eitherthrough demand-side energy efficiencyor through increased generation fromlower-emitting EGUs. In either case,whether implemented througheconomic mechanisms or permitlimitations, reducing emissions at highcarbon-intensity EGUs is technicallyfeasible and can reduce overall powersector CO2 emissions because generationat such EGUs can be replaced bygeneration at less carbon-intensiveEGUs.

We have also analyzed potentialupstream net methane emissions impactfrom natural gas and coal for theimpacts analysis. This analysisindicated that any net impacts from

124 PJM market monitor publishesbreakdowns of wholesale energy prices, includinga CO2 emission allowance cost component, basedon analysis of the prices bid by the “marginal”EGUs. See Monitoring Analytics, 2013 State of theMarket Report for PJM at 103-05, this. 3—63 & 3—64 (2014), available at hftp://www.monitoringano1ytics.com/reports/pjm_state_of_the_market/2013.shtml.

methane emissions are likely to be smallcompared to the CO2 emissionsreduction impacts of shifting powergeneration from coal-fired steam EGUsto NGCC units. Further information onour analysis of upstream impacts can befound in Appendix 3A of the RIA.

b. Magnitude of Re-DispatchHaving identified replacing

generation at higher-emitting EGUs withgeneration at lower-emitting EGUs as atechnically feasible CO2 emissionsreduction strategy, we next address thequantity of replacement generation thatmay be relied upon at reasonable costs.The U.S. electric generating fleetincludes EGUs employing a variety ofgenerating technologies. EGUs usingtechnologies with relatively lowvariable costs, such as nuclear units, arefor economic reasons generally operatedat their maximum output whenever theyare available. Renewable EGUs such aswind and solar units also have lowvariable costs, but in any event aregenerally operated when wind and sunconditions permit rather than atoperators’ discretion. in contrast, fossilfuel-fired EGUs have higher variablecosts and are also relatively flexible.Fossil fuel-fired EGUs are thereforegenerally the units that operators use torespond to intra-day and intra-weekchanges in demand. Because of thesetypical characteristics of the variousEGU types, the primary re-dispatchopportunities among existing unitsavailable to EGU owners and gridoperators generally consist ofopportunities to shift generation amongvarious fossil fuel-fired units, inparticular between coal-fired EGUs (aswell as oil- and gas-fired steam EGUs)and NGCC units. in the shortterm—thatis, over time intervals shorter than thetime required to build a new EGU—fossil fuel-fired units consequently tendto compete more with one another thanwith nuclear and renewable EGUs. Theamount of re-dispatch from coal-firedEGUs to NGCC units that takes place asa result of this competition is highlyrelevant to overall power sector GHGemissions, because a typical NGCC unitproduces less than half as much CO2 perMWh of electricity generated as atypical coal-fired EGU.

in order to estimate the potentialmagnitude of the opportunity to reducepower sector CO2 emissions through redispatch among existing EGUs, the EPAfirst examined information on thedesign capabilities and availability ofNGCC units. This examination showedthat, although most NGCC units havehistorically been operated inintermediate-duty roles for economicreasons, they are technically capable of



operating in base-load roles at muchhigher annual utilization rates. Averageannual availability (that is, thepercentage of annual hours when anEGU is not in a forced or maintenanceoutage) for NGCC units in the U.S.generally exceeds 85 percent, and canexceed 90 percent for some groups.’25

We also researched historical data todetermine the utilization rates thatNGCC units have already beendemonstrated capable of sustaining.Over the last several years, EGU ownersand grid operators have engaged inconsiderable re-dispatch among varioustypes of fossil fuel-fired units relative tohistorical dispatch patterns, with NGCCunits increasing generation and manycoal-fired EGUs reducing generation. Infact, in April 2012, for the first time everthe total quantity of electricity generatednationwide from natural gas wasapproximately equal to the totalquantity of electricity generatednationwide from coal.’26 These changesin generation patterns have been drivenlargely by changes over time in therelative prices of natural gas and coal,in addition to lower overall demand forelectricity. Although the relative fuelprices vary by location, as do the recentpatterns of re-dispatch, this trend holdsacross broad regions of the U.S. hi theaggregate, the historical data provideample evidence indicating that, onaverage, existing NGCC units canachieve and sustain utilization rateshigher than their present utilizationrates.

The experience of relatively heavilyused NGCC units provides an additionalindication of the degree of increase inaverage NGCC unit utilization that istechnically feasible. According to thehistorical NGCC unit utilization ratedata reported to the EPA, in 2012roughly 10 percent of existing NGCCunits operated at annual utilization ratesof 70 percent or higher.’27 hi effect,these units were being dispatched toprovide base-load power. hi addition tothe 10 percent of NGCC units thatoperated at a 70 percent utilization rateon an annual basis, some NGCC unitsoperated at high utilization rates for

125 See, e.g., North American Electric ReliabilityCorp., 2008—2012 Generating Unit StatisticalBrochure—All Units Reporting, http:J/www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx;Higher Availability of Gas Turbine Combined Cycle,Power Engineering (Feb. 1, 2011), http://www.power-eng.com/articies/print/volume-i 15/issue-2/features/higher-avaiobiity-of-gas-turbine-cornbined-cycle.html.

lZB Today in Energy, EIA (June 6, 2012) (hftp:Uwww.eia.gov/todayinenergy/detaiLcfrn?id=6990).

127 The corresponding percentages of NGCC unitsthat in 2012 operated at annual utilization rates ofat least 65 percent and at least 75 percent were 16percent and 6 percent, respectively.

shorter, but still sustained, periods oftime in response to high cyclicaldemand. For example, on a seasonalbasis, a significant number of NGCCunits have achieved utilization ratesbetween 50 and 80 percent; over the2012 winter season (December 2011—February 2012) and summer season(June—August 2012), about 16 percentand 19 percent of NGCC units,respectively, operated at utilizationrates of 70 percent or more across theseentire seasons.’28 During the spring andfall periods when electricity demandlevels are typically lower, these unitswere sometimes idled or operated atmuch lower capacity factors.Nonetheless, the data clearlydemonstrate that a substantial numberof existing NGCC units have proven theability to sustain 70 percent utilizationrates for extended periods of time. Weview this as strong evidence thatincreasing the utilization rates ofexisting NGCC units to 70 percent, notin every individual instance but onaverage, as part of a comprehensiveapproach to reducing CO2 emissionsfrom existing high carbon-intensityEGUs, would be technically feasible.

For purposes of establishing stategoals, historical (2012) electricgeneration data are used to apply eachbuilding block and develop each state’sgoal (expressed as an adjusted CO2emission rate in lbs per MWh).129 In2012, total electric generation fromexisting NGCC units was 959 TWh.’3°After the application of NGCC redispatch toward a 70 percent targetutilization rate, the total generation fromthese existing sources is projected to be1,390 TWh per year. Adding in theNGCC units that had commencedconstruction before January 8, 2014 (andare therefore existing sources forpurposes of this proposal) but were notyet in operation in 2012 increases theprojected total generation from the fullset of existing NGCC units to 1,443 TWhper year.

Although producing over 1,400 TWhof generation in 2020 from existingNGCC units is not actually required,because states may choose otherabatement measures to reach the stategoals, the EPA nevertheless believes thatproducing this quantity of generationfrom this set of NGCC units is feasible.As a reference point, NGCC generationincreased by approximately 430 TWh(an 80 percent increase) between 2005and 2012. The EPA calculates that

128 Air Markets Program Data (at http://ampd.epo.gov/arnpd/).

‘29See Section VU for further explanation of howgoals were computed.

130 covered sources.

NGCC generation in 2020 could increaseby approximately 50 percent fromtoday’s levels. This reflects a smallerramp-up rate in NGCC generation thanhas been observed from 2005 to 2012.We also expect an increase in NGCCgeneration of this amount would notimpair power system reliability. As wenote in the TSD on Resource Adequacyand Reliability, the level of potential redispatch can be accommodated withinthe flexible compliance requirements ofthe rule. Similar conclusions have beenreached in recent studies of thepotential impact of emission reductionsfrom existing power plants.’3’

The EPA also examined the technicalcapability of the natural gas supply anddelivery system to provide increasedquantities of natural gas and thecapability of the electricity transmissionsystem to accommodate shiftinggeneration patterns. For several reasons,we conclude that these systems wouldbe capable of supporting the degree ofincreased NGCC utilization needed forstates to achieve the proposed goals.First, the natural gas pipeline system isalready supporting national averageNGCC utilization rates of 60 percent orhigher during peak hours, which are thehours when constraints on pipelines orelectricity transmission networks aremost likely to arise. NGCC unitutilization rates during the range of peakdaytime hours from 10 a.m. to 9 p.m. aretypically 15 to 20 percentage pointsabove their average utilization rates(which have recently been in the rangeof 40 to 50 percent).132 Fleet-widecombined-cycle average monthlyutilization rates have reached 65percent,’33 showing that the pipelinesystem can currently support these ratesfor an extended period. If the currentpipeline and transmission systemsallow these utilization rates to beachieved in peak hours and forextended periods, it is reasonable toexpect that similar utilization ratesshould also be possible in other hourswhen constraints are typically lesssevere, and be reliably sustained forother months of the year. The secondconsideration supporting our view thatnatural gas and electricity system

131 See Greenhouse Gas Emission ReductionsFrom Existing Power Plants: Options to EnsureElectric System Reliability (Analysis Group, Inc.,May 2014). Also see the Resource AdequacyTechnical Support Document.

132E1A, Average utilization of the nation’s naturalgas combined-cycle power plant fleet is rising,Today in Energy, July 9,2011, http://www.eia.gov/todayinenergy/detail.cfm?id=i 730#; ErA, Today inEnergy, Jan. 15, 2014, hftp:llwww.eia.gov/todayinenergy/detaiLcfrn?id=14611 (for recentdata).

133E1A, Electric Power Monthly, February, 2014.Table 6.7.A.



infrastructure would be capable ofsupporting increased NGCC unitutilization rates is the flexibility of theemission guidelines. The state goals donot require any particular NGCC unitutilization rate to be achieved in anyhour or year of the initial pian period.Thus, even if isolated natural gas orelectricity system constraints were tolimit NGCC unit utilization rates incertain locations in certain hours, thiswould not prevent an increase in NGCCgeneration overall across a state orbroader region and across all hours. Thethird consideration supporting aconclusion regarding the adequacy ofthe infrastructure is that pipeline andtransmission planners have repeatedlydemonstrated the ability tomethodically relieve bottlenecks andexpand capacity.’34 Natural gas pipelinecapacity has regularly been added inresponse to increased gas demand andsupply, such as the addition of largeamounts of new NGCC capacity from2001 to 2003, or the delivery to marketof unconventional gas supplies since2008. These pipeline capacity increaseshave added significant deliverability tothe natural gas pipeline network to meetthe potential demands from increaseduse of existing NGCC units. Over alonger time period, much moresignificant pipeline expansion ispossible. In previous studies, when thepipeline system was expected to facevery large demands for natural gas useby electric utilities about ten years ago,increases of up to 30 percent in totaldeliverability out of the pipeline systemwere judged to be possible by thepipeline industry.’35 There have beennotable pipeline capacity expansionsover the past five years, and substantialadditional pipeline expansions arecurrently under construction.136Similarly, the electric transmissionsystem is undergoing substantialexpansion.’37 Further, as discussed

‘34See, e.g., hA, Natural Gas Pipeline Additionsin 2011, Today in Energy; INGAA Foundation,Pipeline and Storage Infrastructure Requirementsfor a 30 Tcf Market (2004 update); INGAAFoundation, North American MidstreamInfrastructure Through 2035—A Secure EnergyFuture Report (2011).

135 Pipeline and Storage InfrastructureRequirements for a 30 Tcf Market, INGAAFoundation, 1999 (Updated July, 2004); U.S. gasgroups confident of 30-tcf market, Oil and GasJournal, 1999.

For example, between 2010 and April 2014,118 pipeline projects with 44,107 MMcf/day ofcapacity (4,699 miles of pipe) were placed inservice, and between April 2014 and 2016 anadditional 47 pipeline projects with 20,505 MMcf/day of capacity (1,567 miles of pipe) are scheduledfor completion. Energy Information Administration,http://www.eia.gov/naturalgas/data.cfm.

137 According to the Edison Electric Institute,member companies are planning over 170 projectsthrough 2024, with costs totaling approximately

below in Sections Vll.D and VIII of thispreamble (on state flexibilities and stateplans, respectively), we believe theflexible nature of the proposed goalsprovides time for infrastructureimprovements to occur should theyprove necessary in some locations.’38Combining these factors of currentlyobserved average monthly NCCCutilization rates of up to 65 percent, theflexibility of the emission guidelines,and the availability of thne to addressany existing infrastructure limitations, itis reasonable to conclude that thenatural gas pipeline system can reliablydeliver sufficient natural gas supplies,and the electric transmission system canreliably accommodate changedgeneration patterns, to allow NGCCutilization to increase up to an averageannual utilization rate of 70 percent.

We recognize that re-dispatch doescontemplate an associated increase innatural gas production, consistent withthe current trends in the natural gasindustry. The EPA expects the growth inNGCC generation assumed in goal-setting to be feasible and consistent withdomestic natural supplies. Increases inthe natural gas resource base have led tofundamental changes in the outlook fornatural gas. There is general agreementthat recoverable natural gas resourceswill be substantially higher for theforeseeable future than previouslyanticipated, exerting downwardpressure on natural gas prices.According to ETA, proven natural gasreserves have doubled between 2000and 2012. Domestic production hasincreased by 32 percent over that sametimeframe (from 19.2 TCF in 2000 to25.3 TCF in 2012). ETA’s Annual EnergyOutlook for 2014 projects thatproduction will further increase to 29.1TCF, as a result of increased suppliesand favorable market conditions. Forcomparison, NGCC generation growth of450 TWh (calculated in goal setting)would result in increased gasconsumption of roughly 3.5 TCF for theelectricity sector, which is less than theprojected increase in natural gasproduction.

The EPA notes that the assessmentsdescribed above regarding the ability ofthe electricity and natural gas industriesto achieve the levels of performanceindicated for building block 2 in thestate goal computations are supported

$60.6 billion (this is only a portion of the totaltransmission investment anticipated). Approximately 75 percent of the reported projects (over13,000 line miles) are high voltage (345 kV andhigher). http://www.eei.org/issuesandpolicy/transmission/Documents/Trans_Project_lowres_bookmurked.pdf.

138 See Section ‘JH.D and Section VIII below fordiscussion of timing flexibility.

by analysis that has been conductedusing the Integrated Planning Model(1PM). PM is a multi-regional, dynamic,deterministic linear programming modelof the U.S. electric power sector that theEPA has used for over two decades toevaluate the economic and emissionimpacts of prospective environmentalpolicies. To fulfill its purpose ofproducing projections related to theelectric power sector and its relatedmarkets—including least-cost capacityexpansion and electricity dispatchprojections—that reflect industryconditions in as realistic a manner aspossible, 1PM incorporatesrepresentations of constraints related tofuel supply, transmission, and unitdispatch. The model includes a detailedrepresentation of the natural gaspipeline network and the capability toproject economic expansion of thenetwork based on pipeline load factors.At the EGU level, PM includes detailedrepresentations of key operationallimitations such as turn-downconstraints, which are designed toaccount for the cycling capabilities ofEGUs to ensure that the model properlyreflects the distinct operatingcharacteristics of peaking, cycling, andbase load units.

As described in more detail below,the EPA used PM to assess the costs ofrequiring increasing levels of redispatch from higher- to lower-emittingEGUs, and to that end, the EPAdeveloped a series of modelingscenarios that explored shiftinggeneration from existing coal-fired EGUsto existing NGCC units on a 1:1 basiswithin defined areas.’39 By the nature ofPM’s design, those scenariosnecessarily also require compliancewith the constraints just described (asimplemented for any specific scenario).PM was able to arrive at a solution forscenarios reflecting average NGCCutilization rates of 65, 70, and 75percent, while observing the market,technical, and regulatory constraintsembedded in the model. Such a resultis consistent with the EPA’sdetermination that increasing theutilization rates of existing NGCC unitsto 70 percent, not in every individualinstance but on average, as part of acomprehensive approach to reducingCO2 emissions from existing highcarbon-intensity EGUs, would betechnically feasible.

c. Cost of Re-DispatchHaving established the technical

feasibility and quantification ofreplacing incremental generation at

139 See Chapter 3 of the Regulatory ImpactAnalysis for more detail.



higher-emitting EGUs with generation atNGCC facilities as a CO2 emissionsreduction strategy, we next turn to thequestion of cost. The cost of the powersector CO2 emission reductions that canbe achieved through re-dispatch amongexisting fossil fuel-fired EGUs dependson the relative variable costs ofelectricity production at EGUs withdifferent degrees of carbon intensity.These variable costs are driven by theEGUs’ respective fuel costs and by theefficiencies with which they can convertfuel to electricity (i.e., their heat rates).Historically, natural gas has had ahigher cost per unit of energy content(e.g., MMBtu) than coal in mostlocations, but for NGCC units thisdisadvantage in fuel cost per MMBturelative to coal-fired EGUs is typicallyoffset in significant part, and sometimescompletely, by a heat rate advantage.

The EPA has conducted two sets ofextensive analyses to help inform thedevelopment of the state-specificemission goals described in thisproposal, including analyses of theopportunity to reduce CO2 emissionsthrough re-dispatch. The first set was adispatch-only set that provided aframework for understanding thebroader economic and emissionsimplications of shifting generation toNGCC units from more carbon-intensiveEGUs without consideration of emissionreduction measures reflected in theother building blocks. The second setincluded additional refinements andmore closely reflected all thecharacteristics of the proposed goalsthat were used as the basis for assessingthe costs and benefits of the overallproposal. 140 Both sets of analyses wereconducted using PM.

The first set—the dispatch-onlyanalyses—explored the magnitude andcost of potential opportunities to shiftgeneration from existing coal-fired EGUsto existing NGCC units within definedareas. The purpose of analyzing thesescenarios was to understand anddemonstrate to what extent existingNGCC units could increase theirdispatch at reasonable costs and withoutsignificant impacts on other economicvariables such as the prices of naturalgas and electricity. To evaluate howEGU owners and grid operators couldrespond to a state plan’s possiblerequirements, signals, or incentives tore-dispatch from more carbon-intensiveto less carbon-intensive EGUs, the EPAanalyzed a series of scenarios in whichthe fleet of NGCC units nationwide wasrequired, on average, to achieve a

140 Regulatory Impact Analysis for moredetail.

specified annual utilization rate.’41Specifically, the scenarios requiredaverage NGCC unit utilization rates of atleast 65, 70, and 75 percent,respectively. For each scenario, weidentified the set of dispatch decisionsthat would meet electricity demand atthe lowest total cost, subject to all otherspecified operating and reliabilityconstraints for the scenario, includingthe specified average NGCC unitutilization rate. Further, we allowed redispatch to occur exclusively within aregion’s existing fleet.’42

The costs and economic impacts ofthe various scenarios were evaluated bycomparing the total costs and emissionsfrom each scenario to the costs andemissions from a business-as-usualscenario. For the scenario reflecting a 70percent NGCC utilization rate,comparison to the business-as-usualcase indicates that the average cost ofthe CO2 reductions achieved over the2020—2029 period was $30 per metricton of CO2.’ We view these estimatedcosts as reasonable and therefore assupporting the use of a 70 percentutilization rate target for purposes ofquantifying the emission reductionsachievable at a reasonable cost throughthe application of the BSER.

However, we also note that the costsjust described are higher than we wouldexpect to actually occur in real-worldcompliance with this proposal’s goals.One reason for this is that the 70 percentutilization rate in the scenarioexaggerates the stringency with whichbuilding block 2 is actually reflected ineach of the state goals: While the goalcomputation procedure uses 70 percentas a target NGCC utilization rate for allstates, for only 29 states do the goalsactually reflect reaching that targetNGCC utilization, with the result thatthe average NGCC utilization ratereflected in the computed state goals isonly 64 percent.’44 Also, at least somestates may be able to achieve additionalemission reductions through other

141 The utilization rate constraint applied onaverage to all NGCC units nationwide and did notapply to individual NGCC units or to the fleets ofNGCC units within individual states.

142 best reflect the integrated nature of theelectric power sector, the EPA defined six regionsfor this analysis, the borders of which are informedby North American Electric Reliability (NERC)regions and Regional Transmission Organizations(RTOs). See chapter 3 of the Regulatory ImpactAnalysis for more detail.

43 analogous costs for the scenarios with 65and 75 percent NGCC utilization rates were $21 and$40 per metric ton of C02, respectively. For furtherdetail on cost methodology, data inputs, andresults, refer to chapter 3 of the GHG AbatementMeasures TSD.

144 For further explanation of the state goalcomputation methodology, see Section VII of thepreamble and the Goal Computation TSD.

components of the BSER, and thoseother components may be relativelyinexpensive. The dispatch-only analyseswere focused on evaluating the potentialimpacts of re-dispatch in particular, andas a result, they reflect an assumptionthat even in a state where re-dispatchmight be relatively expensive comparedto other available CO2 emissionreduction measures that are part of theBSER, the state plan would rely on redispatch to the same extent as the plansof other states. In practice, under thesecircumstances, states would haveflexibility to choose among alternativeCO2 reduction strategies that were partof the BSER, instead of relying on redispatch to the maximum extent.

The EPA also analyzed dispatch-onlyscenarios where shifting of generationamong EGUs was limited by stateboundaries. In these scenarios with lessre-dispatch flexibility, the cost ofachieving the quantity of CO2reductions corresponding to anationwide average NGCC unitutilization of 70 percent was $33 permetric ton. Combining the results of themodeling with the factors likely to bepresent in the real world reinforces thesupport we expressed above for the 70percent utilization rate. We remainconcerned, however, that higher NGCCutilization rates could be harder tosustain and could exert further upwardpressure on prices.

We invite comment on whether theregional or state scenarios should begiven greater weight in establishing theappropriate degree of re-dispatch toincorporate into the state goals for CO2emission reductions, and in assessingcosts.

We also conclude from our analysesthat the extent of re-dispatch estimatedin this building block can be achievedwithout causing significant economicimpacts. For example, in both of the 70percent NGCC unit utilization ratescenarios—with re-dispatch limited toregional and state boundaries,respectively—delivered natural gasprices were projected to increase by anaverage of no more than ten percentover the 2020—2029 period, which iswell within the range of historicalnatural gas price variability.’45Projected wholesale electricity priceincreases over the same period were lessthan seven percent in both cases, whichsimilarly is well within the range ofhistorical electric price variability.’46

‘45According to EIA data, year-to-year changes innatural gas prices at Henry Hub averaged Z9.9percent over the period from 2000 to 2013.http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm.

146 example, year-on-year changes in PJMwholesale electricity prices averaged 19.5 percent

Continued



We view these projected impacts as notunreasonable and as supporting use ofa 70 percent NGCC utilization rate targetfor purposes of quantifying the emissionreductions achievable throughapplication of the BSER.

However, for the same reasonsdiscussed above with respect toestimated costs per ton of C02, in actualimplementation we again expect thatthe economic impacts shown in thesescenarios, including natural gas priceimpacts, are likely overstated comparedto the impacts that would actually occurin real-world compliance with thisrule’s proposed goals. Consistent withthis expectation, the comprehensiveanalyses used to assess the compliancecosts and benefits of this proposal,which reflect a more completerepresentation of the additionalflexibility available to states, showsignificantly smaller economic impacts.These analyses are discussed in SectionX below.

Based on the analyses summarizedabove, the EPA proposes that forpurposes of establishing state goals, areasonable estimate regarding the degreeof mass emission reductions achievableat fossil fuel-fired steam EGUs can bedetermined based on the degree towhich electricity generation could beshifted from more carbon-intensiveEGUs to less carbon-intensive EGUswithin the state at reasonable costthrough re-dispatch. The increment ofemission reductions incorporated in thiscomponent of our proposed BSERdetermination is commensurate with anannual utilization rate for the state’sNGCC units of up to 70 percent, onaverage across all the NGCC units in thestate.

For purposes of the alternative set ofgoals on which we are seekingcomment, we have used the lessstringent target of a 65 percent averageutilization rate for NGCC units. In 2012,approximately 16 percent of existingNGCC plants larger than 25 megawattshad utilization rates equal to or higherthan this level. Also, as noted earlier,average NGCC utilization nationwide isalready over 60 percent in some peakhours. We therefore view 65 percent asa reasonable lower-bound estimate of anachievable average NGCC utilizationrate, and we would expect the costs andeconomic impacts from re-dispatchassociated with a 65 percent NGCCutilization target to be lower than thecosts and impacts associated with the 70percent utilization target. Our cost

over the period from 2000 to 2013. Ventyx VelocitySuite, ISO real-time data for all hours. Pricevariability for other eastern ISO regions (NYISO,ISO—NE., and Midcontinent ISO) was similar. Id.

analysis indicated that CO2 emissionreductions consistent with a 65 percentaverage NGCC utilization rate could beachieved at a cost of $21 per metric ton.

As discussed above, in addition toanalyzing the impacts of using theproposed 70 percent target utilizationrate for existing NGCC units, the EPAhas also performed preliminary analysisof the impacts of using a targetutilization rate for existing NGCC unitsof 75 percent. That analysis showed thatCO2 emission reductions consistentwith a 75 percent target utilization ratecould be achieved at a cost of $40 permetric ton.’47 We invite comment onwhether we should consider options fora target utilization rate for existingNGCC units greater than the proposed70 percent target utilization rate.

We invite comment on these proposedfindings and on all other issues raisedby the discussion above and the relatedportions of the Greenhouse GasAbatement Measures TSD.

3. Building Block 3—Using anExpanded Amount of Less CarbonIntensive Generating Capacity

The third element of the foundationfor the EPA’s BSER determination forreducing CO2 emissions at affectedfossil fuel-fired EGUs also goes to theachievement of reductions in massemissions, but in this case thereductions would occur at all affectedEGUs, and entails an analysis of theextent to which generation at theaffected EGUs can be replaced by usingan expanded amount of lower-carbongenerating capacity to producereplacement generation. Below wediscuss two types of generating capacitythat can play this role: Renewablegenerating capacity and new andpreserved nuclear capacity.

a. Renewable Generating CapacityRenewable electricity (RE) generating

technologies are a well-established partof the U.S. power sector. In 2012,electricity generated from renewabletechnologies, including conventionalhydropower, represented 12 percent oftotal U.S. electricity generation, up from9 percent in 2005. More than half thestates have established renewableportfolio standards (RPS) that requireminimum proportions of electricitysales to be supplied with generationfrom renewable generating resources.’48Production of this renewable generationreplaces predominantly fossil fuel-fired

‘47For further analysis related to the use of a 75percent target utilization rate for NGCC units, seechapter 3 of the GHG Abatement Measures TSD.

148 Database of State Incentives for Renewables &Efficiency (DSIRE), http://www.dsfreusa.org/summarymaps/index.cfm?ee=O&RE=O.

generation and thereby avoids the CO2emissions from that replaced generation.The EPA believes that renewableelectricity generation is a proven way toassure reductions of CO2 emissions ataffected EGUs at a reasonable cost. 149

1. Proposed Quantification ofRenewable Energy Generation

To estimate the CO2 emissionreductions from affected EGUsachievable based on increases inrenewable generation, the EPA hasdeveloped a “best practices” scenariofor renewable energy generation basedon the RPS requirements alreadyestablished by a majority of states. TheEPA views the existing RPSrequirements as a reasonable foundationupon which to develop such a scenariofor two principal reasons. First, inestablishing the requirements, stateshave already had the opportunity toassess those requirements against arange of policy objectives includingboth feasibility and costs. These priorstate assessments therefore support thefeasibility and cost of the best practicesscenario as well. Second, renewableresource development potential variesby region, and the RPS requirementsdeveloped by the states necessarilyreflect consideration of the states’ ownrespective regional contexts.’5°

The EPA has not assumed anyspecific type of renewable generatingtechnology for the best practicesscenario. Also, the scenario is not anEPA forecast of renewable capacitydevelopment and neither establishesRPS requirements that any state mustmeet nor makes any determinationsregarding allowable RE compliancemeasures. Rather, it represents a level ofrenewable resource development forindividual states—with recognition ofregional differences—that we view asreasonable and consistent with policiesthat a majority of states have alreadyadopted based on their own policyobjectives and assessments of feasibilityand cost.

As noted above, renewable resourcepotential varies regionally. Thisgeographic pattern is reflected in theexisting RPS requirements of the variousstates. Recognizing this pattern, the EPAhas grouped the states into six regionsfor purposes of developing the best

149 For discussion of how states and sourcesmight use RE in state plans, see Section VIII below.

15e The EPA recognizes that individual RFSpolicies vary in their specification of wherequalifying RE generation must occur. However, theEPA believes the regional structure of thisestimation exercise supports a broad interpretationof RPS requirements across states within a regionas a proxy for reasonable-cost RE generationpotential within the same region.


Federal Register/Vol. 79, No. 117/Wethiesday, June 18, 2014/Proposed Rules 34867

practices scenario.’51 By comparing American Electric Reliability accounts for similar power systemeach state to a set of neighbors rather Corporation (NERC) regions and characteristics as well as geographicthan to a single national standard, we Regional Transmission Organizations similarities in RE potential. Theare able to take regional variation into (RTOs), with adjustments to align grouping of states into the six regions isaccount while still maintaining a level regional borders with state borders and shown in Table 5 below.of rigor for the scenario’s targets. The to group Florida and Texas withregional structure is informed by North neighboring states.’52 This structure

TABLE 5—REGIONS FOR DEVELOPMENT OF BEST PRACTICES RPS SCENARIO

Region States

East Central Delaware, District of Columbia*, Maryland, New Jersey, Ohio, Pennsylvania, Virginia, West Virginia.North Central Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri, North Dakota, South Dakota, Wisconsin.Northeast Connecticut, Maine, Massachusetts, New Hampshire, New York, Rhode Island, Vermont*.South Central Arkansas, Kansas, Louisiana, Nebraska, Oklahoma, Texas.Southeast Alabama, Florida, Georgia, Kentucky, Mississippi, North Carolina, South Carolina, Tennessee.West Arizona, California, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington, Wyoming.

* Because Vermont and the District of Columbia lack affected sources, no goals are being proposed for these jurisdictions.

The best practices scenario for eachstate consists of increasing annual levelsof RE generation estimated based onapplication of an annual RE growthfactor to the state’s historical REgeneration, subject to a maximum REgeneration target. The annual RE growthfactors and maximum RE generationtargets were developed separately foreach of the six regions. Our procedurefor determining these elements isdescribed in the Greenhouse GasAbatement Measures TSD andsummarized below.

The EPA first quantified the amountof renewable generation in 2012 in eachstate. The EPA then summed theseamounts for all states in each region todetermine a regional starting level ofrenewable generation prior toimplementation of the best practicesscenario. Hydropower geneTation isexcluded from this existing 2012generation for purposes of quantifyingBSER-related RE generation potentialbecause building the methodology froma baseline that includes large amountsof existing hydropower generation coulddistort regional targets that are laterapplied to states lacking that existinghydropower capacity. The exclusion ofpre-existing hydropower generationfrom the baseline of this target-settingframework does not prevent states fromconsidering incremental hydropowergeneration from existing facilities (or

later-built facilities) as an option forcompliance with state goals.

Next, the EPA estimated the aggregatetarget level of RE generation in each ofthe six regions assuming that all stateswithin each region can achieve the REperformance represented by an averageof RPS requirements in states withinthat region that have adopted suchrequirements. For this purpose, the EPAaveraged the existing RPS percentagerequirements that will be applicable in2020 and multiplied that averagepercentage by the total 2012 generationfor the region. We also computed eachstate’s maximum RE generation target inthe best practices scenario as its own2012 generation multiplied by thataverage percentage. (For some states thatalready have RPS requirements in place,these amounts are less than their RPStargets for 2030.)

For each region we then computed theregional growth factor necessary toincrease regional RE generation from theregional starting level to the regionaltarget through investment in new REcapacity, assuming that the newinvestment begins in 2017, the yearfollowing the initial state plansubmission deadline,’53 and continuesthrough 2029. This regional growthfactor is the growth factor used for eachstate in that region to develop the bestpractices scenario.

Finally, we developed the annual REgeneration levels for each state. To dothis, we applied the appropriateregional growth factor to that state’sinitial RE generation level, starting in2017, but stopping at the point whenadditional growth would cause total REgeneration for the state to exceed thestate’s maximum RE generation target.For computation of the proposed stategoals discussed in Section Vll.C below,we used the annual amounts for theyears 2020 through 2029. Forcomputation of the alternate state goalsdiscussed in Section Vll.E below, onwhich we are seeking comment, weused the annual amounts for the years2020 through 2024.

Alaska and Hawaii are treated asseparate regions. Their RE targets arebased on the lowest regional RE targetamong the continental U.S. regions andtheir growth factors are based uponhistorical growth rates in their own REgeneration. We invite commentregarding the treatment of Alaska andHawaii as part of this method.

For details on the regional targets andgrowth factors applied, please refer toChapter 4 of the GHG AbatementMeasures TSD.

The cumulative RE amounts for eachstate, represented as percentages of totalgeneration, are shown in Table 6.

151i their unique locations, Alaska andHawaii are not grouped with other states into theseregions. As a conservative approach to estimatingRE generation potential in Alaska and Hawaii, theEPA has developed RE generation targets for each

of those states based on the lowest values for thesix regions evaluated here.

152 regions are the same as those used inregional modeling of this rule; see the Regulatory

Impact Analysis for more information on theregional modeling.

‘53See Section VIII below for further discussionof timing requirements for state plan submittals.



TABLE 6—STATE RE GENERATION LEVELS FOR STATE GOAL DEVELOPMENT[Percentage of annual generation]1

The EPA notes that for some states,the RE generation targets developedusing the proposed approach are lessthan those states’ reported REgeneration amounts for 2012. We invitecomment on whether the approach forquantifying the RE generationcomponent of each state’s goal shouldbe modified to include a floor based on

reported 2012 RE generation in thatstate.

This approach to quantification of astate’s RE generation target does notexplicitly account for the amount offossil fuel-fired generation in that state.Without such an accounting, theapplication of this approach couldyield, for a given state, an increase in REgeneration that exceeds the state’s

‘54Vermont and the District of Columbia areexcluded from this table because we are notproposing goals for those jurisdictions.

reported 2012 fossil fuel-firedgeneration.’55 The EPA invites commenton whether this approach should bemodified so that the difference betweena state’s RE generation target and its2012 level of corresponding REgeneration does not exceed the state’s

1551n this proposed RE approach, this situationonly occurs with the RE targets quantified for thestate of Washington.

Proposed goals Alternate goals

State I2 Interim Final Interim FinalJ cen level * level level * level(percent) (percent) (percent) (percent)

AlabamaAlaskaArizonaArkansasCaliforniaColoradoConnecticutDelawareFloridaGeorgiaHawaiiIdahoIllinoisIndianaIowaKansasKentuckyLouisianaMaineMarylandMassachusettsMichiganMinnesotaMississippiMissouriMontanaNebraskaNevadaNew HampshireNew JerseyNew MexicoNew YorkNorth CarolinaNorth DakotaOhioOklahomaOregonPennsylvaniaRhode IslandSouth CarolinaSouth DakotaTennesseeTexasUtahVirginiaWashingtonWest VirginiaWisconsinWyoming

23

1512

22239

1643

2512

02

28253

18

54872

1142

15

1112

224

8337259

6235

2019

5768

1021

75

1519

5251015

6158288

1419

818117

156

1919

947

153

165

1212

88

15

9247

2121

91210101021

97

1520

27

251624

715103

10111825162118101511202116

61015

620

71615141119

34

20174446

1021

64

1519

425

611

515

6266

1215

516

85

154

1817

535

152

1349

1057

13

5

35

2119

5567

1021

75

1520

425

8136

158277

14197

1810

615

52019

736

153

155

1211

68

14



reported 2012 fossil fuel-firedgeneration.’56

We note that with the exception ofhydropower, the RE generation levelsrepresent total amounts of REgeneration, rather than incrementalamounts above a particular baselinelevel. As a result, this RE generation canbe supplied by any RE capacityregardless of its date of installation. Thisapproach is therefore focused onquantifying the fulfillment of eachstate’s potential for the deployment ofRE as part of BSER using a methodologythat does not require discriminatingbetween RE capacity that was installedbefore or after any given date. Underthis approach, states in a given regionwhere a higher proportion of totalgeneration has already been achievedfrom renewable resources are assumedto have less opportunity for deploymentof additional renewable generation aspart of the BSER framework informingstate goals, in comparison to states inthat region where the proportion of totalgeneration achieved from renewableresources to date has been lower. Thatbeing said, the assumptions of REgeneration used to develop the stategoals do not impose any specific REgeneration requirements on any state;they are only used to inform thequantification of state goals to whichstates may respond with whateveremission reduction measures arepreferred.

With regard to hydropower, we seekcomment regarding whether to include2012 hydropower generation from eachstate in that state’s “best practices” REquantified under this approach, andwhether and how the EPA shouldconsider year-to-year variability inhydropower generation if suchgeneration is included in the RE targetsquantified as part of BSER. Chapter 4 ofthe GHG Abatement Measures TSDpresents state RE targets both with andwithout the inclusion of each state’s2012 hydropower generation.

2. Cost of CO2 Emission Reductionsfrom RE Generation

The EPA believes that RE generationat the levels represented in the best

practices scenario can be achieved atreasonable costs. According to an EPAanalysis based on ETA levelized costs,the cost to reduce emissions through REranges from $10 to $40 per metric tonof CO2.’57 Analysis of RE developmentin response to state RPS policies alsofinds historical and projected costs ofRPS-driven RE deployment to bemodest. One comparative analysis that“synthesize[d] and analyze[d] theresults and methodologies of 28 distinctstate or utility-level RPS cost impactanalyses” projected the median changein retail electricity price to be $0.0004per kilowatt-hour (a 0.7 percentincrease), the median monthly billimpact to be between $0.13 and $0.82,and the median CO2 reduction cost to be$3 per metric ton.’58 This finding hasbeen confirmed with more recent RPScost data, including a report thatdetermined 2010—2012 retail electricityprice impacts due to state RPS policiesto be less than two percent, with onlytwo states experiencing price impacts ofgreater than three percent.’59Additionally, the National RenewableEnergy Laboratory has projected lowincremental costs for a range ofscenarios reflecting significant increasesin RE penetration, including scenariosthat increase RE penetration to a rangeof 30 to 40 percent of nationalgeneration, levels higher than thoseprojected in our best practicesscenario. 16C1

While RPS requirements willcontinue to grow over time, the EPAdoes not expect this anticipatedexpansion to fall outside the historicalnorms of deployment or to createunusual pressure for cost increases. Fullcompliance with current RPS goalsthrough 2035 would requireapproximately 4 to 4.5 GW of new

renewable capacity per year. Averagedeployment of RPS-supportedrenewable capacity from 2007 to 2012exceeded 6 GW per year.’6’ In addition,recent improvements in RPScompliance rates indicate to the EPA thereasonableness of current RPS growthtrajectories. Weighted averagecompliance rates among all states haveimproved in each of the past threereported years (2008—2011) from 92.1percent to 95.2 percent despite a 40percent increase in RPS obligationsduring this period.’62

We invite comment on this approachto treatment of renewable generatingcapacity as a basis for the best systemof emission reduction adequatelydemonstrated and for quantification ofstate goals.

3. Alternative Approach toQuantification of RE Generation

Additionally, the EPA is solicitingcomment on an alternative approach toquantification of renewable generationto support the BSER. Unlike theproposed RE scenario described abovethat relies on a regional application ofstate RPS conunitments, the alternativemethodology relies on a state-by-stateassessment of RE technical and marketpotential. The alternative approach isbased on two sources of information: Ametric representing the degree to whichthe technical potential of states todevelop RE generation has already beenrealized, and 1PM modeling of REdeployment at the state level under ascenario that reflects a reduced cost ofbuilding new renewable generatingcapacity.

The metric measuring realization ofRE technical potential in a statecompares each state’s existingrenewable generation by technologytype with the technical potential for thattechnology in that state as assessed bythe National Renewable EnergyLaboratory (NREL).163 This comparisonyields, for each state and for each REtechnology, a proportion of renewablegeneration technical potential that hasbeen achieved and can be represented asan RE development rate. For example, if

157 This analysis is based upon ETA’s AEO 2014Estimated Levelized Costs of Electricity for NewGeneration Sources, available at http://www.eia.gov/forecasts/oeo/electricity_generotion.cfm.

158 Chen at al., “Weighing the Costs and Benefitsof State Renewable Portfolio Standards: AComparative Analysis of State-Level Policy ImpactProjections,” Lawrence Berkeley NationalLaboratory, March 2007, available at http://emp.lbLgov/publications/weighing-costs-ondbeneftts-state-renewobles-portfolio-standardscomporative-anolysis-s.

159Galen Barbose, “Renewables PortfolioStandards in the United States: A Status Update,”Lawrence Berkeley National Lab, November 2013.Also to be published in Heeter at al., “Estimatingthe Costs and Benefits of Complying withRenewable Portfolio Standards: ReviewingExperience to Date” [review draft title].UNPIIBUSI{ED. National Renewable EnergyLaboratory and Lawrence Berkeley NationalLaboratory.

160NREL, “Renewable Electricity Futures Study”,NREL/TP—6A20—52409, 2012, http://www.nrel.gav/analysis/rejutures/.

‘56For example, for the state of Washington theproposed approach yields a final RE generationtarget of 17.7 TWh, representing an increase of 9.5TWh over Washington’s reported 2012 REgeneration (excluding hydropower) of 8.2 TWh. Bycomparison, Washington’s 2012 reported fossil fuel-fired generation was 9.4 ‘flArb. (The 2012 reportedRE and fossil fuel-fired generation amounts for allstates are included in the Goal Computation TSD.)If the limitation described in the text were appliedto Washington, the state’s incremental quantifiedRE generation would be limited to 9.4 TWh, withthe result that the state’s final RE generation targetwould be 17.6 TWh instead of 17.7 TWh.

161Galen Barbose, “Renewables PortfolioStandards in the United States: A Status Update,”Lawrence Berkeley National Laboratory, November2013.

l62http://emp.lbLgov/rps, retrieved March 2014.The RPS compliance measure cited is inclusive ofcredit multipliers and banked RECs utilized forcompliance, but excludes alternative compliancepayments, borrowed RECs, deferred obligations,and excess compliance. This estimate does notrepresent official compliance statistics, which varyin methodology by state.

183 Lopez et al., NREL, “U.S. Renewable EnergyTechnical Potentials: A GIS-Based Analysis,” (July2012).



a given state has 500 MWh of solargeneration in 2012 while NREL assessesthat state’s solar generation technicalpotential at 5,000 MWh/year, then thatstate’s solar RE development rate wouldbe ten percent. The EPA then considersthe range of RE development ratesacross states in order to define abenchmark RE development rate foreach technology.

While a benchmark RE developmentrate offers a useful metric to quantify theproportion of RE generation that wouldbring all states up to a designatedproportion of RE generation that hasbeen achieved in practice by certainstates to date, such a metric does notexplicitly take into account the cost thatwould be faced to reach the benchmarkRE development rate in each state. Inorder to take this cost into account, forthis alternative approach the EPA haspaired the benchmark RE developmentrates described above with 1PMmodeling of RE deployment at the statelevel, based on a scenario reflecting areduced cost of building new renewablegenerating capacity. The cost reductionfor new RE generating capacity isintended to represent the avoided costof other actions that could be takeninstead to reduce CO2 emissions fromthe power sector. In the Alternative REApproach TSD, available in the docket,we show the RE deployment levelsmodeled using a cost reduction of up to$30 per MWh, a level that is consistentwith the cost range of $10 to $40 permetric ton of avoided CO2 emissionsestimated for the proposed RE scenariodescribed above.’64

Under this alternative RE approach,the EPA would quantify RE generationfor each technology in each state as thelesser of (1) that technology’sbenchmark rate multiplied by thetechnology’s in-state technical potential,or (2) the PM-modeled market potentialfor that specific technology. Forexample, if the benchmark REdevelopment rate for solar generation isdetermined to be 12 percent, and thehypothetical state described above has asolar generation technical potential of5,000 MWh/year, then the benchmarkRE development level of generation forthat state would be 600 MWh/year. ifthe PM-modeled market potential forsolar generation in that state is 750MWh/year, then this approach wouldquantify solar generation for that state asthe benchmark RE development level(600 MWh/year) because it is the lesseramount of those two measures.

164 Additional detail regarding this modeling andapproach is provided in the Alternative REApproach TSD.

Having quantified an amount of REgeneration from each RE technology ineach state, the EPA would thendetermine for each state a total level ofRE generation that equals the sum of thegeneration quantified for each of theassessed RE technologies in that state. Ifthe EPA were to adopt this alternativeapproach for quantifying RE in BSER,these total levels of RE generation foreach state would be incorporated instate goals in place of the RE generationlevels quantified using the proposedapproach described above. Furthermethodological detail and state-level REtargets for this alternative approach areprovided in the Alternative REApproach TSD in the docket.

We invite comment on this alternativeapproach to quantification of REgeneration to support the BSER. Wenote that the three specific requests forcomment made above with respect tothe proposed quantification approach—addressing, first, the possibility of afloor based on 2012 RE generation,second, the possibility of a limitationbased on 2012 fossil fuel-firedgeneration and, third, the treatment ofhydropower generation—apply to thisalternative approach as well.’6

Finally, the EPA notes that thealternative RE approach described aboveis one of a number of possiblemethodologies for using technical andeconomic renewable energy potential toquantify RE generation for purposes ofstate goals. The EPA invites commenton other possible techno-economicapproaches. For example, a conceptualframework for another techno-economicapproach is provided in the AlternativeRE Approach TSD.

b. New and Preserved Nuclear Capacity

Nuclear generating capacity facilitatesCO2 emission reductions at fossil fuel-fired EGUs by providing carbon-freegeneration that can replace generation atthose EGUs. Because of their relativelylow variable operating costs, nuclearEGUs that are available to operatetypically are dispatched before fossilfuel-fired EGUs. Increasing the amountof nuclear capacity relative to theamount that would otherwise beavailable to operate is therefore atechnically viable approach to supportreducing CO2 emissions from affectedfossil fuel-fired EGUs.

165 The Alternative RE Approach TSD presentsthe quantification of hydropower generation underthe alternative approach, as well as the resultingstate RE targets both with and without hydropowergeneration included.

1. Proposed Quantification of NuclearGeneration

One way to increase the amount ofavailable nuclear capacity is to buildnew nuclear EGUs. However, inaddition to having low variableoperating costs, nuclear generatingcapacity is also relatively expensive tobuild compared to other types ofgenerating capacity, and little newnuclear capacity has been constructedin the U.S. in recent years; instead, mostrecent generating capacity additionshave consisted of NGCC or renewablecapacity. Nevertheless, five nuclearEGUs at three plants are currently underconstruction: Watts Bar 2 in Tennessee,Vogtle 3—4 in Georgia, and Summer 2—

in South Carolina. The EPA believesthat since the decisions to constructthese units were made prior to thisproposal, it is reasonable to view theincremental cost associated with theCO2 emission reductions available fromcompletion of these units as zero forpurposes of setting states’ CO2 reductiongoals (although the EPA acknowledgesthat the planning for those units likelyincluded consideration of the possibilityof future regulation of CO2 emissionsfrom EGUs). Completion of these unitstherefore represents an opportunity toreduce CO2 emissions from affectedfossil fuel-fired EGUs at a veryreasonable cost. For this reason, we areproposing that the emission reductionsachievable at affected sources based onthe generation provided at the identifiednuclear units currently underconstruction should be factored into thestate goals for the respective stateswhere these new units are located.However, the EPA also realizes thatreflecting completion of these units inthe goals has a significant impact on thecalculated goals for the states in whichthese units are located. If one or moreof the units were not completed asprojected, that could have a significantimpact on the state’s ability to meet thegoal. We therefore take comment onwhether it is appropriate to reflectcompletion of these units in the stategoals and on alternative ways ofconsidering these units when settingstate goals.

Another way to increase the amountof available nuclear capacity is topreserve existing nuclear EGUs thatmight otherwise be retired. The EPA isaware of six nuclear EGUs at five plantsthat have retired or whose retirementshave been announced since 2012: SanOnofre Units 2—3 in California, CrystalRiver 3 in Florida, Kewaunee inWisconsin, Vermont Yankee inVermont, and Oyster Creek in NewJersey. While each retirement decision



is based on the unique circumstances ofthat individual unit, the EPA recognizesthat a host of factors—increasing fixedoperation and maintenance costs,relatively low wholesale electricityprices, and additional capitalinvestment associated with ensuringplant security and emergencypreparedness—have altered the outlookfor the U.S. nuclear fleet in recent years.Reflecting similar concern for thesechallenges, ETA in its most recentAnnual Energy Outlook has projected anadditional 5.7 GW of capacityreductions to the nuclear fleet. ETAdescribes the projected capacityreductions—which are not tied to theprojected retirement of any specificunit—as necessary to recognize the“continued economic challenges” facedby the higher-cost nuclear units.’66

Likewise, without making any judgmentabout the lllcelthood that any individualEGU will retire, we view this 5.7 GW,which comprises an approximately sixpercent share of nuclear capacity, as areasonable proxy for the amount ofnuclear capacity at risk of retirement.

2. Cost of CO2 Emission ReductionsFrom Nuclear Generation

We have determined that, based onavailable information regarding the costand performance of the nuclear fleet,preserving the operation of at-risknuclear capacity would likely becapable of achieving CO2 reductionsfrom affected EGUs at a reasonable cost.For example, retaining the estimated sixpercent of nuclear capacity that is at riskfor retirement could support avoiding200 to 300 million metric tons of CO2over an initial compliance phase-inperiod of ten years.’67 According to arecent report, nuclear units may beexperiencing up to a $6IMWh shortfallin covering their operating costs withelectricity sales.168 Assuming that sucha revenue shortfall is representative ofthe incentive to retire at-risk nuclearcapacity, one can estimate the value ofoffsetting the revenue loss at these at-risk nuclear units to be approximately$12 to $17 per metric ton of CO2. TheEPA views this cost as reasonable. Wetherefore propose that the emissionreductions supported by retaining inoperation six percent of each state’shistorical nuclear capacity should be

‘66Jeffrey Jones and Michael Leff, EIA,“Implications of accelerated power plantretirements,” (April 2014).

167 Assuming replacement power for at-risknuclear capacity is sourced from new NGCCcapacity at 800 lbs/MWh or the power system at1127 lbs C02/MWh (average 2020 power sectoremissions intensity as projected in the EPA’s 1PMBase Case).

‘68”Nuclear * * * The Middle Age Dilemma?”Eggers, et al., Credit Suisse, February 2013.

factored into the state goals for therespective states.’69

For purposes of goal computation,generation from under-construction andpreserved nuclear capacity is based onan estimated 90 percent averageutilization rate for U.S. nuclear units,consistent with long-term averageannual utilization rates observed acrossthe nuclear fleet. The methodology fortaking this generation into account forpurposes of setting state emission rategoals is described below in Section VIIon state goals and in the GoalComputation TSD.

We invite comment on all aspects ofthe approach discussed above. Inaddition, we specifically requestcomment on whether we should includein the state goals an estimated amountof additional nuclear capacity whoseconstruction is sufficiently likely tomerit evaluation for potential inclusionin the goal-setting computation. if so,how should we do so—for example,according to EGU owners’announcements, the issuance ofpermits, projections of new constructionby the EPA or another governmentagency, or commercial projections?What specific data sources should weconsider for those permits orprojections?

4. Building Block 4—Demand-SideEnergy Efficiency

The fourth element of the foundationfor the EPA’s BSER determination forreducing CO2 emissions at affectedfossil fuel-fired EGUs also supportsreduced mass emissions at all affectedEGUs, and entails an analysis of theextent to which generation reductions atthe affected EGUs can be supported byreducing the demand for generation atthose EGUs through measures thatreduce the overall quantity of generationdemanded by end-users.’7°

a. Benefits of Demand-Side EnergyEfficiency

Reducing demand for generation ataffected EGUs through policies toimprove demand-side energy efficiencyis a proven basis for reducing CO2emissions at those EGUs. Every state hasestablished demand-side energyefficiency policies, and manystakeholders emphasized the success ofthese policies in reducing electricityconsumption by large amounts. Forexample, data reported to the U.S.Energy Information Administration

169A state’s historical nuclear fleet is defined asall units in commercial operation as of May 2014with no current plans to retire.

170Electricity end-users and electricity end-usereferred to throughout this subsection include theresidential, commercial and industrial sectors.

(ETA) show that in 2012 California andMinnesota avoided 12.5 percent and13.1 percent of their electricity demand,respectively, through their demand-sideefficiency programs.’71 Additionally,multiple studies have found thatsignificant improvements in end-useenergy efficiency can be realized at lesscost than the savings from avoidedpower system costs.’72 increasedinvestment in demand-side energyefficiency is being supported by effortsat the federal, state, and local levels ofgovernment as well as corporate efforts.Many stalceholders urged the inclusionof demand-side energy efficiencypolicies as compliance options underthe CAA section 111(d) guidelines.

By reducing electricity consumption,energy efficiency avoids greenhouse gasemissions associated with electricitygeneration. Because fossil fuel-firedEGUs typically have higher variablecosts than other EGUs (such as nuclearand renewable EGUs), their generationis typically the first to be replaced whendemand is reduced. Consequently,reductions in the utilization of fossilfuel-fired EGUs can be supported byreducing electricity consumption and,by the same token, reductions inelectricity consumption avoid the CO2emissions associated with the avoidedgeneration. In this manner, in 2011,state demand-side energy efficiencyprograms are estimated to have reducedCO2 emissions by 75 million metrictons.’73 And when integrated into acomprehensive approach for addressingCO2 emissions, demand-side energyefficiency improvements offer evenmore potential to improve the carbonprofile of the electricity supply system.For example, if incentives exist to shiftgeneration to lower carbon-intensityEGUs, and those EGUs are fully utilized,reducing demand can support furtherreductions in carbon intensity. Thispotential effect reinforces theappropriateness of incorporatingdemand-side efficiency improvementsinto a comprehensive approach toaddress power sector CO2 emissions, inaddition, by supporting reductions infossil fuel usage at EGUs, demand-side

171 Energy Information Administration Form 861,2012, available at http://www.eia.gav/electricity!data/eiaB6l/.

172 See, e.g., Electric Power Research Institute,U.S. Energy Efficiency Potential Through 2035(Final Report, April 2014); Wang, Yu and MarilynA. Brown, Policy Drivers for Improving ElectricityEnd-Use Efficiency in the U.S.: An Economic-Engineering Analysis (Energy Efficiency, 2014).

‘73lnnovation, Electricity, Efficiency (an Instituteof the Edison Foundation), Summary of Customer-Funded Electric Efficiency Savings, Expenditures,and Budgets (2011—2012) (March 2013), available athttp://www.edisonfoundation.net/iei/ourworkJPoges/issuebriefs.aspx.



energy efficiency supports not onlyreduced CO2 emissions and carbonintensity of the power sector, but alsoreduced criteria pollutant emissions,cooling water intake and discharge, andsolid waste production associated withfossil fuel combustion. By reducingelectricity usage significantly, energyefficiency also commonly reduces thebills of electricity customers.

b. “Best Practices” for Demand-SideEnergy Efficiency

To estimate the potential CO2reductions at affected EGUs that couldhe supported by implementation ofdemand-side energy efficiency policiesas a part of state goals, the EPAdeveloped a “best practices” demand-side energy efficiency scenario. Thisscenario provides an estimate of thepotential for sources and states toimplement policies that increaseinvestment in demand-side energyefficiency technologies and practices atreasonable costs. It does not representan EPA forecast of business-as-usualimpacts of state energy efficiencypolicies or an EPA estimate of the fullpotential of end-use energy efficiencyavailable to the power system, but ratherrepresents a feasible policy scenarioshowing the reductions in fossil fuel-fired electricity generation resultingfrom accelerated use of energyefficiency policies in all statesconsistent with a level of performancethat has already been achieved orrequired by policies (e.g., energyefficiency resource standards) of theleading states. The data andmethodology used to develop the bestpractices scenario are summarizedbelow.

We have not assumed any particulartype of demand-side energy efficiencypolicy. States with leading energyefficiency performance have employed avariety of strategies that areimplemented by a range of entitiesincluding investor-owned, municipaland cooperative electric utilities as wellas state agencies and third-partyadministrators. These include energyefficiency programs,’74 building energy

174 Energy efficiency programs are driven by avariety of state policies including energy efficiencyresource standards, requirements to acquire all cost-effective energy efficiency, integrated resourceplanning requirements, and demand-sidemanagement plans and budgets. Funding for energyefficiency programs is provided through a variety ofmechanisms as well, including per kilowatt-hoursurcharges and proceeds from forward capacitymarket and emission allowance auctions. Theprograms are implemented by a range of entitiesincluding investor-owned, municipal, andcooperative electric utilities, state agencies, anddesignated third-party administrators. All end-usesectors (residential, commercial, and industrial) are

targeted by energy efficiency programs and

codes, state appliance standards (forappliances without federal standards),tax credits, and benchmarkingrequirements for building energy use.’75Energy efficiency policies are designedto accelerate the deployment ofdemand-side energy efficiencytechnologies, practices, and measures byaddressing market barriers and marketfailures that limit their adoption. Somestates have adopted energy efficiencyresource standards’76 (EERS) to driveinvestment in energy efficiencyprograms; some have relied on otherstrategies; most states are using multiplepolicy approaches. Based on historicaldata on energy efficiency programsavings and analysis of the requirementsof existing state energy efficiencypolicies, twelve leading states haveeither achieved—or have establishedrequirements that will lead them toachieve—annual incremental savingsrates of at least 1.5 percent of theelectricity demand that would otherwisehave occurred.177 The 1.5 percentsavings rate is inclusive of, notadditional to, existing state energyefficiency requirements. These savingslevels are realized exclusively throughthe adoption and implementation ofenergy efficiency programs. The energysavings data underpinning theseanalyses are derived from energyefficiency program reports required bystate public utility commissions andother entities with a similar oversightrole.178 These state commissions defineand oversee the analysis and reportingrequirements for energy efficiencyprograms as part of their role ofoverseeing rates for utility customers intheir states. One typical requirement isthe application of recognizedevaluation, measurement, and

numerous strategies are employed, includingtargeted rebates for high-efficiency appliances;energy audits with recommendations for cost-effective, energy-saving upgrades; and processes tocertify energy efficiency service providers.

175 See the appendix to the State Planconsiderations TSD for descriptions of the fullarray of demand-side energy efficiency policiescurrently employed by states.

‘76EERS establish specific, long-term targets forenergy savings that utilities or non-utility programadministrators must meet through customer energyefficiency programs. EERS, as well as requirementsthat utilities acquire all cost-effective energyefficiency, have been the most impactful stateenergy efficiency strategies in recent years.

177 historical data used are reported to theEnergy Information Administration through FormEIA—861. The analysis and summary of state energyefficiency policies is from the American council foran Energy-Efficient Economy (ACEEE), State EERSActivity Policy Brief (February 24, 2014). See theGreenhouse Gas Abatement Measures TSD for moreinformation.

178E.g., energy efficiency programs operated bymunicipal and cooperative utilities may report theirprogram results to their Boards of Directors ratherthan to a state utility commission.

validation (EM&V) protocols thatspecify industry-preferred approachesand methodologies for estimatingsavings from efficiency programs.179

While EM&V data reflect documentedelectricity savings from energyefficiency programs, they typically donot account for potential electricitysavings available from additional state-implemented policies for which EM&Vprotocols are less consistently requiredor applied, such as building energycodes. Thus, we consider the 1.5percent annual incremental savings’80rate to be a reasonable estimate of theenergy efficiency policy performancethat is already achieved or required byleading states and that can be achievedat reasonable costs by all states givenadequate time. if we were to capture thepotential for additional policies, such asthe adoption and enforcement of state orlocal building energy codes, tocontribute additional reductions inelectricity demand beyond thoseresulting from energy efficiencyprograms, we could reasonably increasethe targeted annual incremental savingsrate beyond 1.5 percent.

For states where EE programexperience is more limited, reaching abest-practices level of performancerequires undertaking a set of activitiesthat takes some time to plan,implement, and evaluate. For the bestpractices scenario, we have thereforeestimated that each state’s annualincremental savings rate increases fromits 2012 annual saving rate 181 to a rateof 1.5 percent over a period of yearsstarting in 2017. (Thus, the goal for eachstate differs to reflect the assumptionthat in a state already close to a 1.5percent annual incremental savings rate,energy efficiency programs can beexpanded to reach that rate sooner thanin a state that is further from that rate.)The pace at which states are estimatedto increase their savings rate level is 0.2percent per year. This rate is consistentwith past performance and futurerequirements of leading states.’82 Forstates already at or above the 1.5 percent

‘79See the EM&V section of the State Plan TSDfor more information on EE program evaluation.

18O This incremental savings rate and all othersdiscussed in this subsection represent net, ratherthan gross, energy savings. Gross savings are thechanges in energy use (MWh) that result directlyfrom program-related actions taken by programparticipants, regardless of why they participated ina program. Net savings refer to the changes inenergy use that are directly attributable to aparticular energy efficiency program afteraccounting for free-ridership, spillover, and otherfactors.

181 2012 is the most recent year for energyefficiency program incremental savings datareported using EIA Form 861.

18Z the Greenhouse Gas Abatement MeasuresTSD for more information.



‘83For example, a state with a reported savingsrate of 0.5% in 2012 is assumed to realize a 2017savings rate of 0.5% and their savings rates for2018, 2019, 2020, 2021 and 2022 are calculated to

be 0.7%, 0.9%, 1.1%, 1.3%, and 1.5%, respectively.By this method, all states have reached the 1.5%target rate by 2017 at the earliest and by 2025 atthe latest.

184 See the Greenhouse Gas Abatement MeasuresTSD for more information.

annual incremental savings rate (basedon 2012 reported data), we estimate thatthey would realize a 1.5 percent rate in2017 and maintain that rate thiough2029. For all states we assume the initialsavings rate (the lower of their 2012value or 1.5 percent) is realized in 2017and increases each year by 0.2 percentuntil the target rate of 1.5 percent isachieved183 and is then maintained atthat level through 2029. The savingsfrom energy efficiency programs arecumulative, meaning that, in simplifiedterms, a state in which a sustainedprogram is implemented with a 1.5percent annual incremental savings ratecould expect cumulative annual savingsof approximately 1.5 percent after thefirst year, 3.0 percent after the secondyear, 4.5 percent after the third year,and so on. Savings from the first yearwould drop off at the end of the average

life of the energy efficiency programportfolio (typically about ten years).Accordingly, we have projected thecumulative annual savings for each statethat would be achieved for the period2020 to 2029 based on the state’sreaching and then sustaining the bestpractices annual incremental savingsrate through 2029. These values, foreach state and for each year (2020—2029), are used in the procedure forcomputing the state goals described inSection Vll.C below.

As discussed in Section Vll.E below,the EPA is also taking comment on aless stringent alternative for setting stategoals. Under this alternative, thedemand-side energy efficiencyrequirement uses 1.0 percent (ratherthan 1.5 percent) annual incrementalsavings as representative of the best-practices level of performance. Inaddition, the pace at which incremental

savings levels are increased from theirhistorical levels is relaxed slightly to0.15 percent per year (rather than 0.2percent). The 1.0 percent rate of savingsis a level of performance that has beenachieved—or that established staterequirements will cause to beachieved—by 20 states.’84 As is donewith the more stringent goal-settingapproach for energy efficiency, thecumulative percentages for each stateare derived and multiplied by the state’s2012 historical electricity sales asreflected in the ETA detailed state data,in this case for the period from 2020 to2024.

The state-specific cumulative annualelectricity saving data inputs for boththe proposed approach and the lessstringent alternative are discussed in theGreenhouse Gas Abatement MeasuresTSD and summarized in Table 7.

TABLE 7—DEMAND-SIDE ENERGY EFFICIENCY STATE GOAL DEVELOPMENT: CUMULATIVE ANNUAL ELECTRICITY SAVINGS(PERCENTAGE OF ANNUAL SALES) RESULTING FROM BEST PRACTICES SCENARIO785

1.5% Savings target scenario 1.0% Savings target scenarioState

2020 2029 2020 2024

AlabamaAlaskaArizonaArkansasCaliforniaColoradoConnecticutDelawareFloridaGeorgiaHawaiiIdahoIllinoisIndianaIowaKansasKentuckyLouisianaMaineMarylandMassachusettsMichiganMinnesotaMississippiMissouriMontanaNebraskaNevadaNew HampshireNew JerseyNew MexicoNew YorkNorth CarolinaNorth DakotaOhioOklahomaOregonPennsylvania

1.41.25.21.55.03.94.71.72.01.81.33.84.43.24.71.21.91.15.44.24.44.64.81.41.63.42.23.02.81.33.14.42.41.44.21.94.74.7

9.59.5

11.49.7

11.611.017.99.5

10.09.89.5

11.111.611.111.79.5

10.09.3

12.111.511.811.811.79.69.9

10.910.410.711.09.6

10.611.810.39.7

11.610.017.411.7

1.10.93.51.23.63.33.60.91.81.51.03.53.52.93.60.91.60.93.63.53.63.63.61.11.33.01.92.72.61.02.83.52.11.73.51.63.63.6

3.93.76.04.16.15.96.33.64.74.43.85.96.25.76.03.74.63.66.36.16.26.26.23.94.25.74.95.55.53.75.56.25.04.06.14.56.16.2


34874 Federal Register/Vol._79, No. 117/Wednesday, June 18, 2014/Proposed Rules

TABLE 7—DEMAND-SIDE ENERGY EFFICIENCY STATE GOAL DEVELOPMENT: CUMULATIVE ANNUAL ELECTRICITY SAVINGS(PERCENTAGE OF ANNUAL SALES) RESULTING FROM BEST PRACTICES SCENARIO 185—Continued

1.5% Savings target scenario 1.0% Savings target scenarioState

2020 2029 2020 2024

Rhode Island 3.9 11.6 3.4 6.1South Carolina 2.3 10.2 2.0 4.9South Dakota 1.6 9.9 1.3 4.2Tennessee 2.2 10.3 1.9 4.9Texas 1.8 9.9 1.5 4.4Utah 3.6 11.0 3.2 5.8Virginia 1.2 9.3 1.0 3.7Washington 4.2 11.3 3.5 6.0West Virginia 1.8 10.1 1.5 4.4Wisconsin 4.7 11.8 3.6 6.2Wyoming 1.6 9.7 1.3 4.2

c. Costs of Demand-Side EnergyEfficiency

The EPA expects implementation ofdemand-side energy efficiency policiesas reflected in the best practicesscenario to be achievable at reasonablecosts. The EPA finds support for thereasonableness of the costs of thisbuilding block from two perspectives.First, the specific savings levelsrepresented by this building block weredeveloped based upon the experienceand success of states in developing andimplementing energy efficiency policiesthat they undertake primarily for thepurpose of providing economic benefitsto electricity consumers in their state.Secondly, even with notablyconservative assumptions about thecosts of achieving the levels ofelectricity savings associated with thisbuilding block, the EPA’s analysis of thepower sector indicates that the costs arereasonable.

The processes by which statesdevelop funding for energy efficiencyprograms typically require theapplication of cost-effectiveness tests toensure that adopted program portfolioslead to lower costs than the use ofgeneration sources that would otherwisebe required to meet the associatedelectricity service demands. Indeed, amajor reason for the widespreadpresence and rapid growth of demand-side energy efficiency programs is thestrong evidence of the reasonableness oftheir costs even before the additionalbenefit of CO2 reductions isconsidered.’86 Independent studieshave found that end-users’ needs forenergy-dependent services (e.g., heating,cooling, lighting, motor output, and

‘85Vermont and the District of Columbia areexcluded from this table because we are notproposing goals for those jurisdictions.

Some states do include a valuation of CO2benefits as part of their evaluations of costeffectiveness.

information and entertainment services)frequently can be satisfied at lower costby improving the efficiency ofelectricity consumption rather than byincreasing the supply of electricity.87These factors indicate that the cost ofCO2 reductions achieved throughimplementation of demand-side energyefficiency at the levels reflected in thebest practices scenario are likely to bevery reasonable, typically resulting inreductions in average electricity billsacross all end-use sectors.188 Becausedemand-side energy efficiency costs areincurred at the time of investment,while the cost savings (from lowerelectricity usage) are realized over thelife of these investments (typically about10 years), bill reductions are greater inlater years, but provide substantialpayback over the investment period.

Another approach to evaluating thereasonableness of the costs associatedwith this building block is to comparethe demand-side energy efficiency coststo the avoided power system costs asrepresented within the EPA’s modelingof the power sector. The costs associatedwith the best practices scenario wereestimated based upon a synthesis ofdata and analysis of the factors that

‘87E.g., Electric Power Research Institute, U.S.Energy Efficiency Potential Through 2035 (FinalReport, April 2014); Northwest Power andConservation Council, Sixth NorthwestConservation and Electric Power Plan (Feb. 2010),available at http://www.nwcouncil.org/energypowerp1an/6/p1an/.

188 described below and in the GoalComputation TSD, in the case of a state that is anet importer of electricity, the proposed goalcomputation procedure includes an adjustment toaccount for the possibility that some of thegeneration and emissions avoided due to the state’sdemand-side energy efficiency programs may occurat EGUs in other states. Given the extremely lowcost of CO2 emission reductions achievable throughdemand-side energy efficiency programs,implementation of such programs is likely to reduceCO2 emissions at reasonable cost even for a statewhose own affected EGUs achieve only part of theCO, emission reduction benefit from the state’sdemand-side energy efficiency efforts.

impact energy efficiency program costsas calculated using an engineering-based, bottom-up approach that isstandard for state and utility analysis ofthese policies. These factors include theaverage energy efficiency program costsper unit of first-year energy savings($IMWh), the ratio of program toparticipant costs, and the lifetimes ofenergy efficiency measures across thefull portfolio of programs. In addition,the EPA has included a cost escalationfactor to represent the possibility ofincreased costs associated with higherlevels of incremental energy savingsrates and the national scope of the bestpractices scenario. The EPA has taken aconservative approach to each of thesefactors, selecting values that are at thehigher-cost end of reasonable ranges ofestimated values. The combination ofthese factors is reflected in the value theEPA has derived for the levelized costper MWh of saved energy. This valueincludes both the program costs paid byutilities for implementing energyefficiency programs and the amountsthat program participants pay for theirown energy efficiency improvementsbeyond the program costs. These costsare levelized across the measurelifetimes of a full portfolio of energyefficiency programs. This analysisprovides a levelized cost of savedenergy (LCOSE) range of $85/MWh to$90/MWh ($2011) over the 2020 to 2030period. This range of LCOSE is notablyconservative (leading to higher costs) incomparison with most utility and stateanalysis. For example, a 2014 analysisby the American Council for an Energy-Efficient Economy (ACEEE) surveyedprogram and participant cost resultsacross seven states and found acomparable LCOSE value of $54/MWh(2011$).189

American Council for an Energy-EfficientEconomy (AcEEE), The Best Value for America’sEnergy Dollar: A National Review of the Cost of



To estimate the reductions in powersystem costs and CO2 emissionsassociated with the best-practices levelof demand-side energy efficiencydescribed above, the EPA analyzed ascenario incorporating the resultingreduction in electricity demand andcompared the results with the business-as-usual scenario. Both analyses wereconducted using the Integrated PlanningModel (1PM) described previously.Combining the resulting power systemcost reductions with the energyefficiency cost estimates associated withthe best practices scenario, the EPAderived net cost impacts for 2020, 2025,and 2030. Dividing these net costimpacts by the associated CO2reductions for each year, the EPA foundthat the average cost of the CO2reductions achieved ranged from $16 to$24 per metric ton of CO2. The EPAviews these estimated costs asreasonable. Together with the history ofdemonstrated successful stateimplementation of demand-side energyefficiency programs at reasonable costsdiscussed above, this analysis supportsthe reasonableness of the level ofdemand-side energy efficiencyrepresented by the best practicesscenario and, by extension, thereasonableness of the emissionreductions at affected ECUs that can beachieved consistent with achievementof that level of demand-side energyefficiency.

Further details regarding the data andmethodology used to evaluate thepotential for demand-side energyefficiency programs to substitute forgeneration at affected EGUs and therebyfacilitate reductions of power sector CO2emissions at reasonable costs areprovided in the Greenhouse GasAbatement Measures TSD. We invitecomment on all aspects of our data andmethodology as discussed above and inthe TSD, as well as on the level ofreductions we propose to define as bestpractices suitable for representationconsistent with the best system ofemission reduction and the levelreflected in the less stringent scenario.We also specifically invite comment onseveral issues: (1) Increasing the annualincremental savings rate to 2.0 percentand the pace of improvement to 0.25percent per year to reflect an estimate ofthe additional electricity savingsachievable from state policies notreflected in the 1.5 percent rate and the0.20 percent per year pace ofimprovement, such as building energycodes and state appliance standards, (2)alternative approaches and/or data

Utility Energy Efficiency Programs (Report No.U1402, March 2014).

sources (i.e., other than ETA Form 861)for determining each state’s currentlevel of annual incremental electricitysavings, and (3) alternative approachesand/or data sources for evaluating costsassociated with implementation of statedemand-side energy efficiency policies.

5. Potential Emission ReductionMeasures Not Used To Set ProposedGoals

There are four additional potentialmeasures for reducing, or supportingreduced, GHG emissions from EGUs thatthe EPA does not propose to considerpart of the best system of emissionreduction adequately demonstrated forexisting EGUs at this time and thereforehas not used for goal-setting purposes,but that merit discussion here: Fuelswitching at individual EGUs, carboncapture and storage (CCS), usingexpanded amounts of less carbonintensive new NGCC capacity to providereplacement generation, and heat rateimprovements at affected EGUs otherthan coal-fired steam EGUs.

a. Fuel Switching at Individual UnitsOne technically feasible approach for

reducing CO2 emissions per MWh ofgeneration from an EGU designed forcoal-fired generation is to substitutenatural gas for some or all of the coal.Most existing coal-fired steam EGUboilers can be modified to switch to 100percent gas input or to co-fire gas withcoal in any desired proportion. Forcertain individual EGUs, switching to orco-firing with gas may be an attractiveoption for reducing CO2 emissions.

Changing the type of fuel burned at asteam ECU typically requires certainplant modifications (e.g., new burners)and may have some negative impact onthe net efficiencies of the boiler and theoverall generation process. If the plantlacks existing gas pipeline infrastructurecapable of delivering the necessaryquantities of natural gas to the boiler,installation of a new pipeline lateralwould also be required.

The capital costs of plantmodifications required to switch a coal-fired ECU completely to natural gas areroughly $100—300/kW, excludingpipeline costs. For plants that requireadditional pipeline capacity, the capitalcost of constructing new pipelinelaterals is approximately $1 million permile of pipeline built. Offsetting thesecapital costs, conversion to 100 percentgas input would typically reduce theECU’s fixed operating and maintenancecosts by about 33 percent due mainly tocertain equipment retirements and areduction in staffing, while non-fuelvariable costs would be reduced byabout 25 percent due to reduced

maintenance and waste disposal costs.However, in most cases, the mostsignificant cost change associated withswitching from coal to gas in a coal-firedboiler is likely to be the difference infuel cost. Using EIA’s projections offuture coal and natural gas prices,switching a steam ECU’s fuel from coalto gas typically would more than doublethe ECU’s fuel cost per MWh ofgeneration.

The CO2 reduction potential ofnatural gas co-firing or conversion isdue largely to the different carbonintensities of coal and natural gas andis directly related to the proportion ofgas burned. Greater reductions in theCO2 emission rate are achieved at higherproportions of gas usage. For example,at ten percent gas co-firing, the netemission rate (e.g., pounds of CO2 pernet MiVh of generation) of a typicalsteam ECU previously burning only coalwould decrease by approximately fourpercent. At 100 percent gas burn, the netemission rate of a typical steam ECUpreviously burning only coal woulddecrease by approximately 40 percent.

For a typical base-load coal-firedECU, and reflecting ETA’s projectedfuture natural gas and coal prices, theaverage cost of CO2 reductions achievedthrough gas conversion or co-firingranges from $83 per metric ton to $150per metric ton. The low end of the rangeof CO2 reduction costs represents a 100percent switch to gas, because ininstances where a combination of coaland gas is burned, the ECU wouldcontinue to bear the fixed costsassociated with equipment needed forcoal combustion, raising the cost per tonof CO2 reduced.

The EPA’s economic analysis suggeststhat there are more cost effectiveopportunities for coal-fired utilityboilers to reduce their CO2 emissionsthan through natural gas conversion orco-firing. As a result, the EPA has notproposed at this time to include thisoption in the BSER and has notincorporated implementation of theoption into the proposed state goals.However, the EPA believes that thereare a number of factors that warrantfurther consideration in determiningwhether the option should be included.First, the EPA is aware that a number ofutilities have reworked some of theircoal-fired units to allow for some levelof natural gas co-firing (and in somecases have converted the units to fireentirely on natural gas). Second, theEPA is aware of several possible reasonsbeyond reduction of CO2 emissions thatmay make natural gas co-firingeconomically attractive in somecircumstances. One example is thatnatural gas reburn strategies that involve



co-firing with 10 to 20 percent naturalgas can be an effective control strategyfor NOx emissions and, thus, can offsetoperational (and in some cases, capital)costs associated with other NOcontrols such as selective catalyticreduction (5CR) or selective non-catalytic reduction (SNCR). A secondexample suggested by some vendors isthat the capability to burn natural gas ina coal-fired boiler can improveeconomics because it allows the boilerto operate more effectively at lowerloads. A third example, applicable tounits that run infrequently but may beneeded for reliability purposes, is thatconverting to or co-firing with naturalgas may be more economically attractivethan either installing non-CO2 emissioncontrols or taking other measures, suchas transmission upgrades, that couldbecome necessary if the unit wereretired. Finally, beyond the reasons justdescribed explaining why EGU ownersmay find natural gas co-firing to be cost-effective, there are also potentiallysignificant health co-benefits associatedwith burning natural gas instead of coal.

We solicit comment on whethernatural gas co-firing or conversionshould be part of the BSER. We alsorequest comment regarding whether,and, if so, how, we should consider theco-benefits of natural gas co-firing inmaking that determination.

b. Carbon Capture and Storage

Another possible approach forreducing CO2 emissions from existingfossil fuel-fired EGUs is through theapplication of carbon capture and

190 technology (CCS). In therecently proposed standards ofperformance for new fossil fuel-firedEGUs (79 FR 1430), the EPA proposedto find that the best system of emissionreduction for new fossil fuel-firedboilers and IGCC units is partialapplication of CCS. In that proposal, theEPA found that, for new units, partialCCS has been adequately demonstrated,it is technically feasible, it can beimplemented at costs that are notunreasonable, it provides meaningfulemission reductions, and itsimplementation will serve to promotefurther development and deployment ofthe technology. The EPA also noted inthe proposal that most of the relativelyfew new boiler and IGCC EGU projectscurrently under development arealready planning to implement CCS,and, as a result, the proposed standardwould not have a significant impact onnationwide energy prices.

190 This is also sometimes referred to as “carboncapture and sequestration.”

In contrast, the EPA did not identifyfull or partial CCS as the BSER for newnatural gas-fired stationary combustionturbines, noting technical challenges toimplementation of CCS at NGCC unitsas compared to implementation at newsolid fossil fuel-fired sources. The EPAalso noted that, because virtually allnew fossil fuel-fired power projects areprojected to use NGCC technology,requiring full or partial CCS would havea greater impact on the price ofelectricity than requiring CCS at the fewprojected coal plants, and the largernumber of NGCC projects would makea CCS requirement difficult toimplement in the short term.

Partial CCS has been demonstrated atexisting EGUs. It has been demonstratedat a pilot-scale at Southern Company’sPlant Barry, it is being installed forlarge-scale demonstration at NRG’s W.A.Parish facility, and it is expected soonto be applied at a commercial scale asa retrofit at SaskPower’s Boundary Damplant in Canada. However, the EPAexpects that the costs of integrating aretrofit CCS system into an existingfacility would be substantial. Forexample, some existing sources have alimited footprint and may not have theland available to add a CCS system.Moreover, there are a large number ofexisting fossil-fired EGUs. Accordingly,the overall costs of requiring CCS wouldbe substantial and would affect thenationwide cost and supply ofelectricity on a national basis.

For the reasons just described, basedon the information available at thistime, the EPA does not propose to findthat CCS is a component of the bestsystem of emission reduction for CO2emissions from existing fossil fuel-firedEGUs. The EPA does solicit comment onall aspects of applying CCS to existingfossil fuel-fired EGUs (in either full orpartial configurations), but does notexpect to finalize CCS as a componentof the BSER in this rulemaldng. Itshould be noted, however, that in lightof the fact that several existing fossil-fired EGUs are currently beingretrofitted with CCS, theimplementation of partial CCS may be aviable GHG mitigation option at somefacilities, and as a result, emissionreductions achieved through use of thetechnology could be used to help meetthe emission performance level requiredunder a state plan.

Additional discussion can be found inthe Greenhouse Gas AbatementMeasures TSD.

c. New NGCC CapacityIn Section W.C.2 above, we discussed

the opportunity to reduce CO2emissions by replacing generation at

high carbon-intensity affected EGUswith lower-carbon generation fromexisting NGCC units.r°’ from atechnical perspective, the samepotential would exist to replace high-emitting generation with generationfrom additional NGCC capacity that maybe built in the future; the analysis aboveregarding the feasibility of policies toincrease utilization rates of existingNGCC units on average to 70 percentapplies equally to new NGCC units.’92We view the opportunity to reduce CO2emissions at affected EGUs by means ofaddition and operation of new NGCCcapacity as clearly feasible.

In addition, we note that ourcompliance modeling for this proposalsuggests that the construction andoperation of new NGCC capacity will beundertaken as method of responding tothe proposal’s requirements.

However, compared to theopportunity to reduce CO2 emissions ataffected EGUs by means of re-dispatchto existing NGCC capacity, the parallelopportunity involving new NGCCcapacity would be more costly forseveral reasons. The first reason is theadditional cost associated withadditional usage of natural gas. As notedin the discussion of building block 2above, the EPA analyzed costsassociated with several different targetutilization rates for existing NGCC unitsand that analysis showed higher costs ofCO2 reductions at higher target NGCCutilization rates.

The second reason that emissionreductions from the use of new NGCCcapacity would be more costly is thatthere would be capital investment costs.Some amount of new NGCC capacity(beyond the units that were alreadyunder construction as of January 8, 2014and are “existing” units for purposes ofthis proposal) would likely be built tomeet perceived electricity marketdemand or to replace less economiccapacity regardless of this proposal. Thecosts of achieving CO2 emissionreductions through re-dispatch to thesenew NGCC units and through redispatch to existing NGCC units wouldbe comparable (ignoring consideration

191 purposes of this proposal, NGCC units thathave commenced construction as of January 8, 2014are “existing” units.

192 Whether and to what extent adding new NGCCcapacity is likely to lead to CO2 reductions dependson what incentives would exist to operate that newcapacity in preference to operation of more carbonintensive existing EGUs. Because the proposed stategoals also reflect the opportunity to reduceutilization of high carbon-intensity EGUs byshifting generation to less carbon-intensive EGUs,we believe that in the context of a comprehensivestate plan, the necessary incentives would likelyexist, in which case adding new NGCC capacitywould tend to reduce CO2 emissions.



of the cost impacts just discussedrelated to increases in overall gas usage).However, in the case of any new NGCCunits that would not have been built ifnot for this proposal, and that were builtin pail for the purpose of achieving CO2reductions at affected EGUs, someportion of their construction or fixedoperating costs would also beattributable to the CO2 reductionopportunity, increasing to some extentthe cost of the CO2 reductions ataffected EGUs achieved through redispatch to those new NGCC units.

The third reason relates to the costs ofpipeline infrastructure expansion, andin particular the unevenly distributednature of those costs. While expandeduse of existing NGCC capacity toachieve CO2 emission reductions can beexpected to rely largely on existingpipeline infrastructure with incrementalcapacity expansions, use of new NGCCcapacity—if required in all states—could require substantially greaterpipeline infrastructure investments toserve some states than others.

Taken together, the EPA believes thecost considerations just describedindicate a higher cost for CO2 reductionsachievable from re-dispatch to newNGCC capacity than from other options,at least for states with limited naturalgas pipeline infrastructure, and wetherefore do not propose to include thisoption in state goals.

While the EPA is not proposing thatnew NGCC capacity is part of the basissupporting the BSER, we recognize thatthere are a number of new NGCC unitsbeing proposed and that many modelingefforts suggest that development of newNGCC capacity would likely be used asa CO2 emission mitigation strategy.Therefore, we invite comment onwhether we should considerconstruction and use of new NGCCcapacity as part of the basis supportingthe BSER. Further, we take comment onways to define appropriate state-levelgoals based on consideration of newNGCC capacity.

d. Assessment of Heat RateImprovement Opportunities at Oil-FiredSteam EGUs, Gas-Fired Steam EGUs,NGCC Units, and Simple-CycleCombustion Turbine Units

The EPA assessed opportunities toimprove heat rates at affected EGUsother than coal-fired steam units. Thisassessment, which is documented in aTechnical Memorandum included as anappendix to the GHG AbatementMeasures TSD, considers the potentialextent of heat rate improvements andCO2 reductions that could be reasonablyavailable from oil-fired steam EGUs, gas-fired steam EGUs, NGCC units, and

simple-cycle combustion turbine units.For these non-coal technologies, thetotal additional potential CO2reductions achievable through heat rateimprovements appear relatively smallcompared to the potential CO2reductions achievable through heat rateimprovements at coal-fired steam EGUs.For this reason, the EPA does notpropose to include heat rateimprovement opportunities at theseother fossil fuel-fired units as anelement of the BSER for CO2 emissionsfrom affected EGUs at this time.However, we are aware that theproportion of total generation providedfrom EGUs such as oil-fired steam EGUsor gas-fired steam EGUs varies bylocation, and may be relatively large ingeographically isolated areas such asislands. We therefore invite comment onwhether heat rate improvements forsome of the EGU types discussed aboveshould be identified as a basis forsupporting the BSER, with particularreference to U.S. territories.

Finally, the EPA expects that for someindividual oil/gas-fired steam EGUs andNGCC units attractive heat rateimprovement opportunities will exist.We note that under the proposedflexible approach to state plansdescribed later in this preamble, CO2reductions achieved through suchopportunities could be used to helpmeet state goals, regardless of whetherthese measures are used as a basis tosupport the BSER.

D. Potential Combinations of theBuilding Blocks as Components of theBest System ofEmission Reduction

This subsection summarizes theEPA’s examination of combinations ofthe building blocks as components ofthe BSER, comparing the merits of apotential BSER that comprises onlybuilding blocks 1 and 2 with the meritsof a BSER that comprises all fourbuilding blocks—the preferred option inthis proposal. (A more detaileddiscussion of how we evaluated eachoption against the criteria to beconsidered for the BSER follows inSection VLE.) 193

1. Reasons for ConsideringCombinations of Building Blocks

As previously described, the buildingblocks can be sununarized as follows:

convenience, the discussion in thisSection W.D is based on our proposal to identifythe BSER as consisting of the building blocksthemselves. The points made in this discussion arealso relevant for our alternative proposal to identifythe BSER as consisting of building block 1 coupledwith reduced utilization of the affected EGUs inspecified amounts.

Building block 1: Reducing the carbonintensity of generation at individualaffected EGUs through heat rateimprovements.

Building block 2: Reducing emissionsfrom the most carbon-intensive affectedEGUs in the amount that results fromsubstituting generation at those EGUswith generation from less carbon-intensive affected EGUs (includingNGCC units under construction).

Building block 3: Reducing emissionsfrom affected EGUs in the amount thatresults from substituting generation atthose EGUs with expanded low- or zero-carbon generation.

Building block 4: Reducing emissionsfrom affected EGUs in the amount thatresults from the use of demand-sideenergy efficiency that reduces theamount of generation required.

The EPA initially considered a BSERcomprising only strategies withinbuilding block 1. As described earlier inSection VLB, the EPA concluded thatcertain strategies within building block1—specifically heat rate improvementsat individual coal-fired steam EGUs—should be a component of the BSERdetermination, as they are technicallyfeasible and can be implemented at areasonable cost. However, the EPAfurther concluded that, while heat rateimprovements qualify as a system ofemission reduction, they are not inthemselves the BSER as there areadditional strategies that can be utilizedin combination with building block 1that are technically feasible, can beimplemented at reasonable cost, andresult in greater emission reductionsthan would be achieved throughbuilding block 1 strategies alone. TheEPA is also concerned that if themeasures that improve heat rates atcoal-fired steam EGUs in building block1 are implemented in isolation, withoutadditional measures that reduce overallelectricity demand or encouragesubstitution of less carbon-intensivegeneration for more carbon-intensivegeneration, the resulting increasedefficiency of coal-fired steam unitswould provide incentives to operatethose EGUs more, leading to smalleroverall reductions in CO2 emissions.Further, in listening sessions and otheroutreach meetings, the EPA learned thatstates and other sources were alreadyimplementing and pursuing strategies inthe other building blocks for thepurpose, at least in part, of reducingCO2 emissions.

2. A Combination of Building Blocks 1and 2 as the Best System of EmissionReduction

We considered a BSER that comprisesstrategies from building blocks I and 2.



In this system, emission reductions atthe most carbon-intensive individualaffected EGUs would occur through acombination of heat rate improvements(resulting in a decrease in emissionrates) and substitution of generation atless carbon-intensive affected EGUs,notably existing NGCC units. Onereason for considering a BSERcomprising these two building blocks isthat it involves only affected EGUs andgeneration from affected EGUs.

The EPA believes that thecombination of building blocks 1 and 2would be a “system of emissionreduction” capable of achievingsignificant reductions in CO2 emissionsfrom affected EGUs at a reasonable cost.As discussed in Section W.C above,each of the two building blocksindependently would be capable ofachieving meaningful CO2 emissionreductions at reasonable costs. Incombination, the need to achieve thelevel of emission reductions achievablethrough use of building block 2 canmitigate the concern that building block1, implemented alone, would makecoal-fired EGUs more economicallycompetitive and lead to increasedgeneration that would offset theemission reduction benefits of thecarbon-intensity improvements. Whilecombining the building blocks may alsoraise the cost per ton of emissionreductions achieved through heat rateimprovements (by reducing the quantityof MWh generated from the EGUs withimproved heat rates and therefore alsoreducing the aggregate emissionreductions achieved at those EGUs bythe heat rate improvements), the costs ofheat rate improvements are low enoughthat we believe their cost per ton ofemission reduction would remainreasonable.

Nevertheless, the EPA is notproposing that a combination ofbuilding blocks 1 and 2 is the BSER,because the proposed combination of allfour building blocks discussed below—in other words, adding to the measuresin building blocks 1 and 2 the measuresin building blocks 3 and 4, which weand stakeholders have identified asalready in use—is capable of achievingeven greater CO2 emission reductionsfrom affected EGUs at reasonable costs.The state-specific goals that would becomputed consistent with a BSER basedon the combination of only buildingblocks 1 and 2 (i.e., goals computedusing the goal computationmethodology discussed in Section VIIbelow, except for the omission ofbuilding blocks 3 and 4) are presentedin the Goal Computation TSD availablein the docket. Further information onthe EPA’s evaluation of this

combination is available in the“Analysis of Emission Reductions,Costs, Benefits and Economic ImpactsAssociated with Building Blocks 1 and2” available in the docket. We invitecomment on a potential BSERcomprising a combination of buildingblocks 1 and 2.

3. A Combination of all Four BuildingBlocks as the Best System of EmissionReduction

Our proposal for the BSER is acombination of all four building blocks.As discussed in Section VI.C above,each of the four building blocks is aproven way to support eitherimprovements in emissions rates ataffected EGUs or reductions in EGUmass emissions; each is in widespreaduse and is independently capable ofsupporting significant CO2 reductionsfrom affected EGUs, either on anemission rate or mass-emissions basis,at a reasonable cost consistent withensuring system reliability. Asdiscussed in Section VI.E below, thecombination of all four building blocksprovides the basis for satisfying the legalcriteria to be considered the BSER.Further, as discussed in Section Xbelow, the combination of all fourbuilding blocks can achieve greateroverall CO2 emission reductions fromaffected EGUs, at a lower cost per unitof CO2 eliminated, than the combinationof building blocks 1 and 2.

In the large and highly integratedelectricity system, where electricity isfungible and the demand for electricityservices can be met in many ways(including through demand-side energyefficiency), states and the industry havelong pursued a wide variety of strategiesfor ensuring that the demand forelectricity services is met reliably, atreasonable costs, and in a mannerconsistent with evolving constraints,including environmental objectives.These strategies have long extended tothe measures in all four building blocks.We believe the combination of all fourbuilding blocks fairly represents therange of measures that states and theindustry will consider when developingstate plans and strategies for reducingCO2 emissions from affected EGUswhile continuing to meet demand forelectricity services reliably andaffordably. Therefore, we believe it isappropriate to consider that samecombination as the BSER upon whichthe required CO2 standards ofperformance for affected EGUs shouldbe based.

E. Determination of the Best System ofEmission Reduction

1. Overview

In this section, the EPA explains the“best system of emission reduction.adequately demonstrated.” Thisexplanation includes what the EPAproposes to determine as the BSER andwhy. In addition the EPA explains howthe BSER forms the basis for each state’soverall emission limitation requirement,which the EPA determines as the stategoal and the state adopts into itsplanning process as the emissionsperformance level. The emissionperformance level, in turn, constitutesthe minimum degree of stringency forthe standards of performance that, takenas a whole, the state must establish forits affected EGUs (or, if the state adoptsthe portfolio approach, for therequirements imposed on the affectedEGUs and other entities). Through thisprocess, the BSER informs the minimumstringency of the standards ofperformance, although the state retainsflexibility in its allocation of emissionlimitations among its sources. As theEPA explains, central to this overallapproach is the fact that the EPA appliesthe BSER on a state-wide basis, whichis consistent with the interconnectednature of the electricity system.

The EPA is proposing two alternativeformulations for the BSER, each ofwhich is based on, although in differentways, the four building blocks. Underthe first approach, emission rateimprovements and mass emissionreductions at affected EGUs facilitatedthrough the adoption of the fourbuilding blocks themselves meet thecriteria for the BSER because they willamount to substantial reductions in CO2emissions achieved while maintainingfuel diversity and a reliable, affordableelectricity supply for the United States.Under the second approach, the BSERconsists of building block 1 coupledwith reduced utilization in specifiedamounts from, in general, higher-emitting affected EGUs. Under this latterapproach, the measures in buildingblocks 2, 3, and 4 serve to justify thoseamounts and the “adequate[]demonstrat[ion]” because they areproven measures that are already beingpursued by states and the industry, atleast in part for the purpose of reducingCO2 emissions from affected EGUs.

The remainder of this discussion isorganized into the followingsubsections. Subsection 2 contains asummary of relevant considerations forthe BSER as defined in the statute andfurther interpreted in court decisions.Subsection 3 discusses characteristics ofthe electricity industry relevant to



interpretation of the BSER for purposesof this proposal, most notably theindustry’s highly interconnected andintegrated nature. Subsection 4 providesa discussion of how the building blockswould satisfy the BSER criteria inisolation or support the alternativeformulation of the BSER as includingreduced utilization in specifiedamounts. Subsection 5 evaluates twocombinations of building blocks—acombination of building blocks 1 and 2,and the proposed combination of allfour building blocks—against the BSERcriteria, and explains why we proposethat the combination of all four is theBSER. Subsection 6 addressesadditional considerations related to theinclusion of building blocks 2, 3, and 4as parts of the basis supporting theBSER. In subsection 7, we describe andseek comment on the alternateinterpretation that the BSER includes, inaddition to building block 1, acomponent consisting of reducedgeneration from higher-emitting affectedEGUs, with the measures in the otherbuilding blocks serving as the basis forquantifying the amounts of generationreductions and consequent CO2emission reductions that can beachieved while continuing to meet thedemand for electricity services in areliable and affordable manner. Insubsection 8, we discuss the discretionthat the case law gives us in weighingthe various criteria to determine theBSER. In subsection 9, we discuss howthe BSER and the state-wide manner inwhich the EPA applies it form the basisfor the emission standards that the stateincludes in the plan, and we explainwhy that approach is consistent withthe applicable section 111 requirements.The final three subsections address thetopics of combining source categories,severability, and certain other specificissues on which we are seekingcomment. Additional discussion isprovided in the Legal Memorandumavailable in the docket.

2. Statutory and Regulatory ProvisionsRelated to Determination andApplication of the BSER

The EPA’s explanation for this BSERproposal begins with the statutorydefinition of a “standard ofperformance”:

The term “standard of performance” meansa standard for emissions of air pollutantswhich reflects the degree of emissionlimitation achievable through the applicationof the best system of emission reductionwhich (taking into account the cost ofachieving such reduction and any nonairquality health and environmental impact andenergy requirements) the Administrator

determines has been adequatelydemonstrated.42 U.S.C. 7411(a)(1).

The U.S. Court of Appeals for the D.C.Circuit (D.C. Circuit or Court) hashanded down case law over a 40-yearperiod that interprets this CAAprovision, including its componentelements.’94 Under this case law, theEPA determines the BSER based on thefollowing key considerations, amongothers:

• The system of emission reductionmust be technically feasible.

• The EPA must consider the amountof emission reductions that the systemwould generate.

• The costs of the system must bereasonable. The EPA may consider costsat the source level, the industry level,and, at least in the case of the powersector, the national level in terms of theoverall costs of electricity and theimpact on the national economy overtime.195

• The EPA must also consider thatCAA section 111 is designed to promotethe development and implementation oftechnology, including the diffusion ofexisting technology as the BSER,’°6 thedevelopment of new technology thatmay be treated as the BSER,’97 and thedevelopment of other emergingtechnology.198

1Portland Cement Ass’n v. Ruckelshaus, 486F.2d 375 tu.c. Cir. 1973), cert. denied, 416 U.S. 969(1974); Essex Chemical Corp. v. Ruckelshaus, 486F.2d 427 (D.C. Cir. 1973), cert. denied, AppalachianPower Co. v. EPA, 416 U.S. 969 (1974); Sierra Clubv. Costle, 657 F.2d 298 (D.C. Cfr. 1981); PortlandCement Ass’n v. EPA, 665 F.3d 177 (D.C. Cfr. 2011).Although this case law concerns the meaning of thedefinition of “standard of performance” forpurposes of rulemakings that the EPA promulgatedunder CAA section 111(b), the same term is usedfor section 111(d), and as a result, this case law isrelevant for the present rulemaldng under section111(d).

195 discussed in the January 2014 Proposal, theD.C. Circuit’s case law formulates the costconsideration in various ways: The costs must notbe “exorbitant[ ]“, Essex Chemical Corp. v.Ruckelshaus, 486 F.2d at 433, see Lignite EnergyCouncil v. EPA, 198 F.3d 930, 933 (D.C. Ck. 1999);“greater than the industry could bear and survive,”Portland Cement Ass’n v. EPA, 513 F.2d 506, 508(D.C. Cir. 1975); or “excessive” or “unreasonable,”Sierra Club v. Costle, 657 F.2d at 343. In the January2014 Proposal, the EPA stated that “these variousformulations of the cost standard. . . aresynonymous,” and, for convenience, we used“reasonableness” as the formulation. We take thesame approach in this rulemaking.

See 1970 Senate Committee Report No. 91—1196 at 15 (“The maximum use of available meansof preventing and controlling air pollution isessential to the elimination of new pollutionproblems”).

‘975ee Portland Cement Ass’n v. Ruckelshaus,486 F.2d at 391 (the best system of emissionreduction must “look[ I toward what may fairlybe projected for the regulated future, rather than thestate of the art at present”).

198 See Sierra Club v. Costle, 657 F.2d at 351(upholding a standard of performance designed topromote the use of an emerging technology).

Another consideration particularlyrelevant to this rulemaking is energyimpacts, which, as with costs, the EPAmay consider at the source level, theindustry level, and the national levelover time. In the context of theelectricity industry and this proposal,the EPA believes that the scope ofenergy impacts that may be consideredencompasses assurance of the continuedability of the industry to meet theevolving demand for electricity servicesin a reliable manner, while providingsufficient flexibility to enable affectedsources to follow state energy plans.

Importantly, the EPA has discretion toweigh these various considerations, maydetermine that some merit greaterweight than others, and may vary theweighting depending on the sourcecategory.

It is a well-established principle thatstates have discretion regarding themeasures adopted in their stateimplementation plans under CAAsection 110 to attain the NAAQS.’°9 TheEPA believes that the same principleapplies in the context of state plansunder section 111(d) as well, such thateach state has the discretion to adoptemission reduction measures other thanthe measures found by the EPA tocomprise the BSER, or to place greateror lesser emphasis than the EPA oncertain measures, provided that thestate’s plan achieves the required levelof emission performance for affectedsources.

The EPA discussed the CAArequirements and Court interpretationsof the BSER at length in the January2014 Proposal, 79 FR at 1,462/1—1,467/3, and incorporates by reference thatdiscussion into this rulemaking.

Over the last forty years, under CAAsection 111(d), the agency has regulatedfour pollutants from five sourcecategories (i.e., phosphate fertilizerplants (fluorides), sulfuric acid plants(acid mist), primary aluminum plants(fluorides), Kraft pulp plants (totalreduced sulfur), and municipal solidwaste landfills (landfill gases)).20° Inaddition, the agency has regulatedadditional pollutants under CAA

See Train v. Natural Res. Def Council, 421U.S. 60 (1975).

ZO See “Phosphate Fertilizer Plants; FinalGuideline Document Availability,” 42 FR 12022(Mar. 1, 1977); “Standards of Performance for NewStationary Sources; Emission Guideline for SulfuricAcid Mist,” 42 FR 55796 (Oct. 18, 1977); “KraftPulp Mills, Notice of Availability of Final GuidelineDocument,” 44 FR 29828 (May 22, 1979); “PrimaryAluminum Plants; Availability of Final GuidelineDocument,” 45 FR 26294 (Apr. 17, 1980);“Standards of Performance for New StationarySources and Guidelines for Control of ExistingSources: Municipal Solid Waste Landfills, FinalRule,” 61 FR 9905 (Mar. 12, 1996).



section 111(d) in conjunction with CAAsection 129.201 However, the agency hasnot previously regulated CO2 or anyother greenhouse gas under CAA section111(d) (although because landfill gasesinclude methane, the agency’sregulation of landfill gases reducedemissions of that greenhouse gas).Further, the electricity industry differsin important ways from the sourcecategories previously regulated undersection 111(d) in terms of its large scale,its central importance to the economy,and, as discussed below, its highlyinterconnected and integrated nature.

3. The Interconnected Nature of the U.S.Electricity Sector

The U.S. electricity system is a highlyinterconnected, integrated system inwhich large numbers of EGUs usingdiverse fuels and generatingtechnologies are operated in acoordinated manner to produce fungibleelectricity services for customers.Because electricity storage is costly andhas not been widely deployed, theamounts of electricity demanded andsupplied must be continuouslymatched, and system operators typicallyhave flexibility to choose amongmultiple EGUs when selecting where toobtain the next MliVh of generationneeded. Coordination over short- andlong-term time scales is accomplishedthough a variety of institutionsincluding vertically integrated utilities,state regulatory agencies, independentsystem operators and regionaltransmission organizations (ISOsIRTOs),and market mechanisms. The electricitysector is both critical to the nation’seconomy and the source of more than 30percent of U.S. greenhouse gasemissions, predominantly in the form ofCo2.

The integrated electricity systemallows increased generation from lesscarbon-intensive NGCC units tosubstitute for generation from morecarbon-intensive steam EGUs (buildingblock 2), thereby lowering CO2emissions from the group of affectedEGUs as a whole. The electricity systemsimilarly allows increased generationresulting from expansion of the amountof available low- or zero-carbongenerating capacity connected to theelectric grid (building block 3), as wellas avoided generation resulting fromreductions in electricity demand(building block 4), to substitute for fossilfuel-fired generation, thereby reducingCO2 emissions from affected EGUs. Each

201 See, e.g., ‘Standards of Performance for NewStationary Sources and Emission Guidelines forExisting Sources: Sewage Sludge Incineration Units,Final Rule,” 76 FR 15372 (Mar. 21, 2011).

of these measures already routinelyoccurs within this integrated system forproviding electricity and electricityservices.

The integrated nature of the electricitysystem has long played a central role inthe industry’s continuing efforts toassure reliability and to manage costsgenerally. Specifically in the area ofpollution control, state governments andthe federal government have repeatedlytaken advantage of the integrated natureof the electricity system when designingprograms to allow the industry to meetthe pollution control objectives in aleast-cost manner. Examples includeseveral cap-and-trade programs toreduce national or regional emissions ofSO2 and NOx: The S02-related portionof the CAA Title W Acid Rain Program,the Ozone Transport Commission (OTC)NO Budget Program, the NO SIP CallNO Budget Trading Program, and theClean Air Interstate Rule (CAW) annualSO2, annual NOx, and ozone-seasonNO trading programs. While the AcidRain Program was created by federallegislation, the OTC NOx BudgetProgram was developed primarilythrough the joint efforts of a group ofnortheastern states. In the NO SIP Calland CAIR programs, the federalgovernment set emission budgets anddeveloped trading programs that statescould use as a compliance option.202Each of these programs was designed totake advantage of the fact that in anintegrated electricity system, someEGUs can reduce emissions at lowercosts than others, and that by allowingthe industry to determine throughmarket mechanisms which EGUs tocontrol and which to leaveuncontrolled, and which EGUs topotentially operate more and which topotentially operate less, overallcompliance costs can be reduced. Theintegrated electricity system plays theimportant function of allowing someEGUs to reduce their generation whileensuring that overall demand forelectricity services can be reliably met.It is worth noting that adoption byaffected EGUs of any of the measures inthe building blocks could be (or couldhave been) used to facilitate compliancewith each of the programs justdescribed.203

202 In the Regional Greenhouse Gas Initiative,described in more detail below, participating statesuse emission budgets and a trading program toaddress CO2 emissions from the electricity sector.

203 addition to the already-implementedprograms mentioned above—the S02-relatedportion of the Acid Rain Program, the OTC NOBudget Program, the NO SIP Call NO BudgetTrading Program, and the Clean Air Interstate Ruletrading programs—use of measures in the buildingblocks would also facilitate compliance with thecap-and-trade programs established by the Cross-

Some states are already relying on theintegrated nature of the electricitysystem to establish the policy contextswithin which affected EGUs will reducetheir CO2 emissions.204 California andColorado provide two examples of howstatewide targets (or company-widetargets within a state) can be designedwith consideration of the wide range ofCO2 mitigation options and affectedEGUs’ flexibility to use those options.

California enacted its Global WarmingSolutions Act (also known as AB32) in2006, requiring the state to reduce itsGHG emissions to 1990 levels by 2020and 80 percent below 1990 levels by2050.205 According to California, “theintegrated nature of the power gridmeans that policies which displace theneed for fossil generation can often cutemissions from covered sources moredeeply, and more cost-effectively thancan engineering changes at the plantsalone, though these source-level controlefforts are a vital starting point.”206California therefore relied on a suite ofmechanisms to provide fossil fuel-firedgeneration substitutes and incentives forEGUs to reduce their emissions,including demand-side energyefficiency programs, renewable energyprograms, and an economy-wide cap-and-trade program, along with otherprograms.207 The California plan hasput in place mechanisms that thoughmarket dynamics affect both companies’longer-term planning decisions andtheir short-term dispatch decisions. Theneed to hold emissions allowances andthe reduced demand from demand-sideenergy efficiency programs impactlonger-term decisions companies makeabout investment in both existing andnew EGUs. The price of emissionallowances also impacts hourly dispatchdecisions; where emission allowancerequirements are in effect, EGU owners

State Air Pollution Rule (76 FR 48208, Aug. 8,2011).

204A number of utilities also have climatemitigation plans. Examples include National Grid,http://www2.nationa1grid.com/responsibility/how-were-doing/grid-data-cenfre/climate-change/;Exelon, http://www.exe1oncorp.com/newsroom/pr_201 40423_EKC_Exelon2O2O.aspx; PG&E, http://www.pge.com/about/environment/pge/climate/;and Austin Energy, http://austinenergy.com/wpslporta1/ae/abo ut/enWronment/austin-climateprotection-plan/!ut/p/a0/04_Sj9CPykssyOxPLMnMzOvMAfGjzOINjCyMPJwNjDzdz Y0sDBzdnZ28TcP8DAMMDPQLshOVA U4fG7s!/.

State of California Global Warming SolutionsAct of 2006, Assembly Bill 32, http://www.Ieginfo.ca.gov/pub/05-06/bih/asm/ab_0001 -0050/ab_32_bill_20060927_chaptered.pdf.

206 December 27, 2013 Letter from Mary D.Nichols, Chairman of California Air ResourcesBoard, to EPA Administrator Gina McCarthy.

207 Cal. Air Res. 3d., Climate Change ScopingPlan 31—32, 41—46 (2008), available athftp://www.arb.ca.gov/cc/scopingplan/document/udopted_scopingplan.pdf



routinely recognize the costs ofemission allowances as components ofthe variable operating costs that arerelied on for these decisions.208 in thismanner, allowance prices constitutemarket signals encouraging reduced useof higher-emitting EGUs and increaseduse of lower-emitting EGUs.

The Colorado Clean Air, Clean JobsAct (CACJA), signed into law on April19, 2010, required each investor-ownedutility with coal-fired EGUs to submit tothe state a multi-pollutant plan formeeting current and foreseeable EPAstandards for emissions of NON, 502,particulates, mercury, and CO2. Ratherthan fully prescribing specific controltechnologies, the law providedflexibility for each utility to select thebest set of measures to achieve theemission reductions.209 For example, autility could choose to retrofit orrepower EGUs, or it could choose toretire higher-emitting EGUs and replacethem with NGCC units and other low-or non-emitting energy plants or withend-use efficiency measures.21° TheColorado plan generally focused moreon impacting companies’ longer-termplanning decisions than on affectingshort-term dispatch decisions. inresponse, Colorado utilities haveadopted a mix of measures includingretrofits, natural gas conversions andretirements of coal-fired EGUs, as wellas construction of new NGCC units.

Multi-state mechanisms withanalogous impacts on both longer-termplanning decisions and short-termdispatch decisions have also been put inplace. For example, nine northeasternand Mid-Atlantic States21’ participatein the Regional Greenhouse Gasinitiative (RGGI), a market-basedemissions budget trading program thatsets an aggregate limit on CO2 emissionsfrom fossil fuel-fired EGUs in theparticipating states. To comply with theprogram, each EGU must acquireallowances equal to its emissions ineach compliance period—throughpurchases or by allocation from thestate—and must surrender theallowances at the end of the period. TheRGGI program offers flexibility toregulated parties through provisions for

208 The requirement to hold allowances coveringtheir CO2 emissions went into effect for EGUs inCalifornia on January 1, 2013.

209 law also set some explicit requirements,such as requirements for development of newrenewable generating capacity and requirements tophase out older coal-fired EGUs.

210 State of Colorado House Bill 10—1365,available at http://www.1eg.state.co.us/c1icsIc1ics2O1 Oa/csl.nsf/fsbillcont/0CA296732C8CEF4D872576E400641B74?Open&fiIe—1 365_Ten .pdf

211 Participating states include Connecticut,Delaware, Maine, Maryland, Massachusetts, NewHampshire, New York, Rhode Island, and Vermont.

multi-year compliance periods,allowance banking, offsets, an auctionreserve price, and a cost-containmentreserve of allowances, and furtherencourages emission allowance marketdevelopment by authorizing tradingbetween regulated and non-regulatedparties.212 Operating in this regime,EGUs could take a variety of complianceactions, including replacing generationat higher-emitting EGUs with generationat lower-emitting EGUs or achievingemissions reductions at EGUs by meansof end-use energy efficiency programs.

An approach to determination of theBSER that recognizes the integratednature of the electricity system is alsoconsistent with the way in which theelectricity industry already addressesresource planning issues. For example,in states where the price of EGUs’generation remains subject to regulation,utilities generally prepare integratedresource plans setting forth theirstrategies for meeting future demand forelectricity services in a cost-effectivemanner. These plans may includemeasures from building blocks 2, 3, and4. in most states where generation is nolonger subject to price regulation,regional transmission organizations(RTOs) or independent system operators(ISOs) ensure the adequacy of futuregeneration supplies by administeringauctions for forward capacity. In theseauctions, owners of existing EGUs (withconsideration of building blocks 1 and2),213 developers of new EGUs includingrenewable generating capacity (buildingblock 3), and developers of demand-sideresources (building block 4) all competeto provide potential resources formeeting the projected demand forelectricity services.

As indicated by the foregoingdiscussion, in the U.S. electricity systemthe demand for electricity services ismet, on both a short-term and longer-term basis and in both regulated andderegulated contexts, through integratedconsideration of a wide variety ofpossible options, coordinated by somecombination of utilities, regulators,system operators, and marketmechanisms. The EPA believes that theBSER for CO2 emissions from existingEGUs should reflect this integratedcharacter.

A final, important point regarding theintegrated electricity system is that thesets of actions that enable the demand

212 RGGI Web site at http://www.rggi.org/rggi.213 Potential heat rate improvements create

opportunities for EGU owners to reduce theirvariable costs, which increase potential operatingprofits from generation and thereby createopportunities to lower the prices at which theowners would bid the capacity of their EGUs intothe auctions.

for electricity services to becontinuously met can be undertaken indifferent orders, with changes in someinterconnected elements elicitingcompensating responses from otherinterconnected elements. Thus, the CO2emissions reductions associated withbuilding blocks 2, 3, and 4 can beachieved in either of two ways: (1) Firstinstituting measures in building blocks2, 3, and 4, which, due to theinterconnected and integrated nature ofthe grid, would elicit the response ofreducing generation at some or allaffected EGUs, thereby lowering thoseEGUs’ emissions; or (ii) first reducinggeneration and therefore emissions fromsome or all affected EGUs (or planningto make those reductions), which due tothe interconnected and integratednature of the grid, would elicit theresponses identified in building blocks2, 3, and 4 of increasing generation atlower-emitting EGUs or reducing thedemand for electricity services. (in somecases, the change and response could beplanned simultaneously.) Each of thesesets of actions, with the building blocksas the initial change or the reducedgeneration at affected EGUs as the initialchange, may be considered to be part ofa “system of emission reduction,” asdiscussed below.

Further discussion of the ways inwhich the “system of emissionreduction” for affected EGUs isinfluenced by the interconnected andintegrated nature of the electricitysystem is provided below in the contextof the EPA’s rationale for proposing tobase the BSER on the combination of allfour building blocks. This topic is alsodiscussed in the Legal Memorandumavailable in the docket.

4. Evaluation of individual BuildingBlocks Against the BSER Criteria

In this subsection we explain why (i)the individual building blocks meet thecriteria to qualify as components of the“best system of emission reduction.adequately demonstrated” and (ii) why,under the alternative formulation of theBSER as including reduced utilizationof higher-emitting affected EGUs inspecified amounts, building blocks 2, 3,and 4 serve as the basis for thoseamounts and why the reducedutilization is “adequatelydemonstrated.”

a. Building Block 1—Heat RateImprovements

Building block 1—reducing thecarbon intensity of generation atindividual affected coal-fired steamEGUs through heat rate improvements—is a component of the BSER because themeasures the affected sources may



undertake to achieve heat rateimprovements are technically feasibleand of reasonable cost, and meet theother requirements to qualify as acomponent of the “best system ofemission reduction. . . adequatelydemonstrated.”

The EPA’s analysis and conclusionsregarding the technical feasibility, costs,and magnitude of CO2 emissionreductions achievable through heat rateimprovements are discussed in SectionW.C.1 above. We consider heat rateimprovement to be a common and well-established practice within the industry.

Other BSER criteria also favorbuilding block 1 as a component of theBSER. For example, with respect to non-air health and environmental impacts,heat rate improvements cause fuel to beused more efficiently, reducing thevolumes of and therefore the adverseimpacts associated with disposal of coalcombustion solid waste products. Withrespect to technological innovation,building block 1 encourages the spreadof more advanced technology to EGUscurrently using components with olderdesigns. The EPA has not specificallyevaluated the extent to which enhancedmaintenance practices leading to heatrate improvements might also lead toelectricity reliability improvements, hutgenerally expects that enhancedmaintenance would be more likely toimprove than to degrade EGUavailability, which would tend toimprove electricity system reliability.

As noted above, the EPA is concernedabout the potential “rebound effect”associated with building block 1 ifapplied in isolation. More specifically,we noted that in the context of theintegrated electricity system, absentother incentives to reduce generationand CO2 emissions from coal-firedEGUs, heat rate improvements andconsequent variable cost reductions atthose EGUs would cause them tobecome more competitive compared toother EGUs and increase theirgeneration, leading to smaller overallreductions in CO2 emissions (dependingon the CO2 emission rates of thedisplaced generating capacity).However, we believe that this concerncan be readily addressed by ensuringthat the BSER also reflects other CO2reduction strategies that encourageincreases in generation from lower- orzero-carbon EGUs orin demand-sideenergy efficiency, thereby allowingbuilding block 1 to be considered partof the BSER for CO2 emissions ataffected EGUs.

b. Building Block 2—Re-DispatchBuilding block 2—reducing CO2

emissions at and substituting for

generation from the most carbon-intensive affected EGUs with generationfrom less carbon-intensive affectedEGUs (specifically NGCC units that arecurrently operating or underconstruction)—is a component of theBSER because the shifts in generationthat it involves demonstrate thatreducing mass CO2 emissions at higher-emitting EGUs is technically feasible,will not jeopardize system reliability, isof reasonable cost, and meets the otherrequirements for a component of the“best system of emission reduction.adequately demonstrated.”

The EPA’s analysis and conclusionsregarding the technical feasibility, costs,and magnitude of CO2 emissionreductions achievable at high-emittingEGUs through re-dispatch amongaffected EGUs are discussed in SectionVI.C.2 above. We consider re-dispatchamong the large number of diverseEGUs that are linked to one another andto customers by extensive regionaltransmission grids to be a routine andwell-established operating practicewithin the industry that is used tofacilitate the achievement of a widevariety of objectives, includingenvironmental objectives, while meetingthe demand for electricity services. Asdiscussed above, in the interconnectedand integrated electricity industry, fossilfuel-fired steam EGUs are able to reducetheir generation and NGCC units areable to increase their generation in acoordinated manner throughmechanisms—in some cases centralizedand in others not—that regularly dealwith such changes on both a short-termand a longer-term basis.

Both the achievability of this buildingblock and the reasonableness of its costsare supported by the fact that there hasbeen a long-term trend in the industryaway from coal-fired generation andtoward NGCC generation for a variety ofreasons. As part of their CO2 reductionstrategies, states can encourage thistrend in a variety of ways. First, a statecould use its permitting authority toimpose limits on the hours of operation(or emissions) of individual steamgenerating units over a given timeperiod. Second, a state could change therelative costs of generation for morecarbon-intensive and less carbonintensive generating units by imposinga cost on carbon emissions. A statecould do so through any of severalmarket-based mechanisms. One wouldbe to adopt an allowance-based system.An example is the Regional GreenhouseGas Initiative, an allowance-basedsystem in which sources purchaseallowances in periodic auctions.Another way would be through atradable emission rate system, under

which the state would impose anemission rate limit on the steamgenerating unit that the unit could meetonly by purchasing the right to averageits emission rate with a unit with alower rate, such as an NGCC unit. Mostbroadly, an allowance system wouldprovide the greatest incentive for themost carbon-intensive affected sourcesto reduce emissions as much as possibleso as to reduce their need to purchaseallowances (or to allow them to sell unneeded allowances), and the samewould be true for a tradable emissionrate system.

The emission reductions achievableor supported by the application ofbuilding block 2 also perform wellagainst other BSER criteria. Forexample, we expect that building block2 would have positive non-air healthand environmental impacts. Coalcombustion for electricity generationproduces large volumes of solid wastesthat require disposal, with somepotential for adverse environmentalimpacts; these wastes are not producedby natural gas combustion. The intakeand discharge of water for cooling atmany EGUs also carries some potentialfor adverse environmental impacts;NGCC units generally require lesscooling water than steam EGU5.214 Asalready noted, with respect to energyimpacts, the EPA believes that buildingblock 2 (at least at the level ofstringency proposed for purposes ofestablishing state goals) would not poserisks to reliability. Building block 2 alsopromotes greater use of the advancedNGCC technology installed in theexisting fleet of NGCC units.

It should be observed that, bydefinition of the elements of thisbuilding block, the shifts in generationtaking place under building block 2occur entirely among existing EGUssubject to this rulemaldng.215 Throughapplication of this building blockconsidered in isolation, some affectedsources—mostly coal-fired steamEGUs—would reduce their generationand CO2 emissions, while other affectedsources—NGCC units—would increasetheir generation and CO2 emissions.216

214 According to a DOE/NETL study, the relativeamount of water consumption for a new pulverizedcoal plant is 2.5 times the consumption for a newNGCC unit of similar size. “cost and PerformanceBaseline for Fossil Energy Plants: Volume 1:Bituminous Coal and Natural Gas to Electricity,”Rev 2a, September 2013, National EnergyTechnology Laboratory Report DOE/NETL—2010/1397.

215 purposes of this rulemaking, “existing”EGUs include units under construction as ofJanuary 8, 2014, the date of publication in theFederal Register of the Carbon Pollution Standardsfor new fossil fuel-fired EGUs.

ziS Because building blocks 3 and 4 reducegeneration and CO2 emissions from all fossil fuel-


Federal Register/Vol. 79, No. 117/Wednesday, June_18, 2014/Proposed_Rules 34883

However, because for each MWh ofgeneration, NGCC units produce lessCO2 emissions than coal-fired steamEGUs, the total quantity of CO2emissions from all affected sources inaggregate would decrease. In the contextof the integrated electricity system,where the operation of affected EGUs ofmultiple types is routinely coordinatedto provide a fungible service, and in thecontext of CO2 emissions, wherelocation is a less important factor thanis the case for other pollutants, the EPAbelieves that a measure that takesadvantage of that integration to reduceCO2 emissions from the overall set ofaffected EGUs is readily encompassedwithin the meaning of a “system ofemission reduction” for CO2 emissionsat affected EGUs even if the measurewould increase CO2 emissions from asubset of those affected EGUs. Indeed,our review of the data and discussionswith states reveal that some states arealready moving in this direction for thispurpose (while others are moving in thesame direction for other purposes).Emission trading or averagingapproaches can facilitate theimplementation of such a “system” andhave already been used in the electricityindustry to address CO2 as well as otherpollutants, as discussed above.

Finally, the EPA notes that thealternative interpretation of the BSERdiscussed later is based in part on there-dispatch measures in building block2. In this alternative, as it relates tobuilding block 2, reduced generationfrom the subset of affected EGUsconsisting of fossil fuel-fired steamEGUs—i.e., the most carbon-intensivesubset of affected EGUs—is acomponent of the BSER. The potentialto use increased generation from lesscarbon-intensive affected NGCC unitswould serve as a basis for quantifyingthe amounts of generation reductionsand CO2 emission reductions at morecarbon-intensive affected EGUs thatcould be achieved while continuing tomeet the demand for electricity servicesin a reliable and affordable manner.This alternative is discussed further inSection VI.E.7 below.

c. Building Block 3—Use of ExpandedLow- and Zero-Carbon GeneratingCapacity

Building block 3—reducing CO2emissions at and substituting forgeneration from affected EGUs by usingexpanded amounts of low- and zero-

fired affected EGUs as a group, including NGCCunits, the increase in generation and CO2 emissionsfrom NGCC units under building block 2 ismitigated to some extent by including thosebuilding blocks in the BSER along with buildingblock 2.

carbon generating capacity—is acomponent of the BSER because theexpansion and use of renewablegenerating capacity, completion and useof nuclear capacity currently underconstruction, and avoidance of nuclearcapacity retirements all establish thefoundation for a determination thatmass emission reductions from affectedEGUs are technically feasible, do notjeopardize system reliability, are ofreasonable cost, and meet the otherrequirements for a component of the“best system of emission reduction.adequately demonstrated.”

The EPA’s analysis and conclusionsregarding the technical feasibility, costs,and magnitude of the measures inbuilding block 3 are discussed inSection Vl.C.3 above. We consider all ofthese measures to be proven, well-established practices within theindustry, and development of renewablecapacity in particular is consistent withrecent industry trends. States arealready pursuing policies that encourageproduction of greater amounts ofrenewable energy, such as theestablishment of targets for procurementof renewable generating capacity.Moreover, markets for renewable energycertificates, which facilitate investmentin renewable energy, are already well-established. As noted above with redispatch, an allowance system ortradable emission rate system wouldprovide incentives for sources to reducetheir emissions as much as possible,including through substituting for theirgeneration with generation fromrenewable energy. In addition, ownersof existing nuclear units and nuclearunits currently under construction cantake action to complete or preserve thatcapacity, the generation from whichlikewise can be dispatched in acoordinated manner to substitute forfossil fuel-fired generation. As discussedabove, coordination of these decisionsin the integrated electricity system canoccur through a variety of mechanisms,some centralized and some not.

The renewable capacity measures inbuilding block 3 generally perform wellagainst other BSER criteria. Forexample, incentives for expansion ofrenewable capacity encouragetechnological innovation in improvedrenewable technologies as well as moreextensive deployment of currentadvanced technologies. Generation fromwind turbines (the most commonrenewable technology) does not producesolid waste or require cooling water, abetter environmental outcome than ifthat amount of generation had insteadbeen produced at a typical range offossil fuel-fired EGUs. Although theintermittent nature of generation from

renewable resources such as wind andsolar units requires specialconsideration from grid operators,renewable generation has grown quicklyin recent years, as discussed above, andthe EPA has seen no evidence thatoperators will be less able to cope withfuture growth than they have with rapidpast growth.

The EPA believes that theperformance of the nuclear measures inbuilding block 3 against the other BSERmeasures is also positive on balance.With respect to encouragement oftechnological innovation, incentives forcompletion of nuclear capacitycurrently under construction encouragedeployment of nuclear unit designs thatreflect advances over earlier designs.The nation’s nuclear fleet todayroutinely operates at high averageutilization rates, suggesting no reason toexpect adverse reliability consequencesfrom completion or preservation ofadditional nuclear capacity. The fivenuclear units currently underconstruction are all designed to useclosed-cycle cooling systems with lowercooling water usage than some existingfossil fuel-fired EGU5;Z17 existingnuclear units may use amounts ofcooling water comparable to theamounts used by those fossil fuel-firedsteam EGUs. The EPA recognizes thatnuclear generation poses unique wastedisposal issues (although it avoids thesolid waste issues specific to coal-firedgeneration). However, we do notconsider that potential disadvantage ofnuclear generation relative to fossil fuel-fired generation as outweighing nucleargeneration’s other advantages as anelement of building block 3. For allthese reasons, we consider buildingblock 3 to be a component of the “bestsystem of emission reduction.adequately demonstrated.”

Finally, the EPA notes that thealternative BSER discussed later wouldinclude a component consisting ofreduced generation from affected EGUs,

217 U.S. NRC, Watts Bar Unit 2 FInalEnvironmental Statement, Final Report at 3—3,available at http://pbadupws.nrc.gov/docs/ML1314/ML13144A092.pdf; U.S. NRC, Summer Units 2—3Final Environmental Impact Statement, FinalReport at 3—14, available at hftp://pbodupws.nrc.gov/docs/ML1 109/ML11098A044.pdf; U.S. NRC, Vogtle Units 3—4Final Environmental Impact Statement, FinalReport at 3—5, available at http://pbodupws.nrc.gov/docs/ML0822/ML082240145.pdf Relative to theonce-through systems at many existing powerplants, closed-cycle cooling systems withdraw fromand discharge to external water bodies substantiallyless overall cooling water, although they alsoconsume larger amounts of water throughevaporation. See Department of Energy/Office ofFossil Energy’s Power Plant Water ManagementR&D Program, available at hftp://www.netLdoe.gov/File%2oLibrary/Besearch/Energy%2OAnalysis/Publicotions/PowerPlontWaterMgtfl-D-Final-1 .pdf.



with the measures in building block 3serving as a basis for quantifying theamount of reduced generation andconsequent CO2 emission reductions.Because of the availability of thosemeasures, the amount of reducedgeneration can be achieved whilecontinuing to meet the demand forelectricity services in a reliable andaffordable manner. This alternativeBSER is discussed in Section VLE.7below.

d. Building Block 4—IncreasedDemand-Side Energy Efficiency

Building block 4—reducing CO2emissions at and reducing generationfrom affected EGUs by promotingdemand-side energy efficiency thatreduces the amount of generationrequired from affected EGUs—is acomponent of the BSER because thedemand-side energy efficiency istechnically feasible and of reasonablecost, and meets the other requirementsfor a component of the “best system ofemission reduction. . . adequatelydemonstrated.”

The EPA’s analysis and conclusionsregarding the technical feasibility, costs,and magnitude of building block 4 arediscussed in Section VI.C.4 above. Weconsider demand-side energy efficiencyprograms to be proven, well-establishedpractices within the industry that areconsistent with industry trends. Greaterdemand-side energy efficiency isalready a common policy goal amongstates, and most states already authorizeor require implementation of demand-side energy efficiency programs. Fossilfuel-fired EGUs can reduce theirgeneration. Owners of affected EGUs aswell as other parties can contract fordemand-side energy efficiency. Asdiscussed above, coordination of thesedecisions in the integrated electricitysystem can occur through a variety ofmechanisms, some centralized andsome not. For example, an allowancesystem or tradable emission rate systemwould provide incentives that promotethe measures in building block 4 in thesame manner as discussed above forother building blocks.

Building block 4 is also very attractiveunder other BSER criteria. Demand-sideenergy efficiency avoids the non-airhealth and environmental effects of thefossil fuel-fired generation for which itsubstitutes. Further, by reducing theoverall amount of electricity that needsto be transmitted between EGUs andcustomers, demand-side energyefficiency tends to relieve stress on thegrid, thereby increasing systemreliability. Creating incentives foradditional demand-side energyefficiency is also consistent with the

goals of encouraging technologicalinnovation in energy efficiency andencouraging deployment of currentadvanced technologies. For all thesereasons, the measures in building block4 qualify as a component of the “bestsystem of emission reduction.adequately demonstrated.”

The EPA notes that the alternativeBSER discussed later would include acomponent consisting of reducedgeneration from affected EGUs, withdemand-side energy efficiency servingas a basis for quantifying the amounts ofgeneration reductions and consequentCO2 emission reductions that can beachieved while continuing to meet thedemand for electricity services in areliable and affordable manner. Thisalternate interpretation of the BSER isdiscussed in Section W.E.7 below.

5. Evaluation of Building BlockCombinations Against the BSER Criteria

a. Combination of Building Blocks 1and 2

The EPA has considered whether acombination of building blocks 1 and 2would be the BSER. As described inSection VI.D above, we believe that sucha combination is technically feasibleand would be a “system of emissionreduction” capable of achievingmeaningful reductions in CO2 emissionsfrom affected EGUs at a reasonable cost.The combination would also satisfyother BSER criteria. Nevertheless, we donot propose that this combinationshould be the BSER because theproposed combination of all fourbuilding blocks is capable of achievinggreater reductions in CO2 emissionsfrom affected EGUs at a lower cost.

The EPA believes that both buildingblocks 1 and 2 individually satisfy theBSER criteria identified by the statuteand the D.C. Circuit, with one possibleconcern, related to a “rebound effect,”noted earlier. That concern is thepotential for the heat rate improvementsin building block 1, if implemented inisolation, to make coal-fired steam EGUsmore competitive compared to otherEGUs and cause them to increase theirgeneration, creating a “rebound effect”that would make building block 1 lesseffective at reducing CO2 emissions. Asdiscussed above, building blocks 1 and2 each appear attractive or neutral withrespect to each of the other BSERcriteria.

With respect to most of the BSERcriteria, there is no reason to expect thatthe combination of building blocks 1and 2 would be evaluated differentlyfrom the individual building blocks.However, as noted earlier, thecombination addresses the concern

about building block 1 regarding apotential rebound effect, and in thatimportant respect it performs better thanbuilding block 1 considered in isolation.The substitution of NGCC generation forgeneration from coal-fired and othersteam EGUs ensures that generationfrom coal-fired EGUs, as a group, wouldnot increase as a result of theirimproved variable costs, with the resultthat the reduction in CO2 emission ratesof coal-fired EGUs brought about by heatrate improvements would not be offsetby an increase in CO2 emissions due toincreased generation from those EGUs.The combination of building blockswould therefore be capable of achievinggreater reductions in CO2 emissionsfrom affected sources than eitherbuilding block in isolation.

While achieving substantially greateremission reductions than building block1 alone, by reducing overall generationfrom coal-fired EGUs the combination ofbuilding blocks 1 and 2 also has thepotential to raise the cost of the portionof the overall emission reductionsachievable through heat rateimprovements relative to the cost ofthose reductions if building block 1were implemented in isolation.218However, the EPA believes that the costof emission reductions achievedthrough heat rate improvements wouldremain reasonable for two reasons. First,as discussed in Section W.C.1 above,the cost of CO2 emission reductionsachievable through heat rateimprovements is quite low, and thatcost would remain reasonable even if itwas substantially increased. Second,although under the combination ofbuilding blocks 1 and 2 the volume ofcoal-fired generation would decrease,that decrease is unlikely to be spreaduniformly among all coal-fired EGUs. Itis more likely that some coal-fired EGUswould decrease their generation slightlywhile others would decrease theirgeneration by larger percentages orcease operations altogether. We wouldexpect EGU owners to take thesechanges in EGU operating patterns intoaccount when considering where toinvest in heat rate improvements, withthe result that there would be atendency for such investments to beconcentrated in EGUs whose generationoutput was expected to decrease the

2181f an EGU produces less generation output,then an improvement in that EGU’s heat rate endrate of co2 emissions per unit of generationproduces a smaller reduction in co2 emissions. Ifthe investment required to achieve theimprovement in heat rate and emission rate is thesame regardless of the EGU’s generation output,then the cost per unit of co2 emission reductionwill be higher when the EGU’s generation outputis lower.



least. This enlightened bias in spendingon heat rate improvements—that is,focusing investments on EGUs wheresuch improvements would have thelargest impacts and produce the highestreturns, given consideration of projectedchanges in dispatch patterns—wouldtend to mitigate any deterioration in thecost of CO2 emission reductionsachievable through heat rateimprovements.

As noted above, the EPA invitescomment on a potential BSERcomprising building blocks 1 and 2, inlight of the considerations that couldsupport this approach.

b. Combination of All Four BuildingBlocks

The EPA’s proposed BSER is acombination of all four building blocks.For the reasons described below, andsimilar to each of the building blocks,the combination must be considered a“system of emission reduction.”Moreover, as also discussed below, thecombination qualifies as the “best”system that is “adequatelydemonstrated.” The combination istechnically feasible; it is capable ofachieving meaningful reductions in CO2emissions from affected EGUs at areasonable cost; it satisfies the otherBSER criteria as well; and itscomponents are well-established. Thecombination of all four building blockswould achieve greater CO2 emissionreductions at a lower cost than thecombination of building blocks 1 and 2described above, and would alsoperform better against other BSERcriteria. We therefore propose to findthe combination of all four buildingblocks to be the “best system ofemission reduction. . . adequatelydemonstrated” for reducing COemissions at affected EGU5.219

The assessments of the individualbuilding blocks against the BSERcriteria would generally apply in thesame way to those building blocks whenimplemented as the combination of allfour building blocks, with the sameexceptions as discussed above withrespect to the combination of buildingblocks 1 and 2 as well. However, thecombination of all four building blocks

219 analysis of the interactions amongbuilding blocks provided above for the combinationof building blocks 1 and 2, indicating that theaddition of building block 2 would mitigate thepotential concern about a “rebound effect” ifbuilding block 1 were implemented in isolation,applies to the combination of all four buildingblocks as well; in fact, the addition of buildingblocks 3 and 4 would further mitigate that concern.The EPA believes that if implemented incombination, each of the four building blockswould achieve substantial reductions in CO2emissions from affected EGUs at a reasonable cost.

would improve upon the combination ofbuilding blocks 1 and 2 in severalrespects. First, because of the potentialof building blocks 3 and 4 to achieveadditional CO2 reductions at reasonablecosts, the broader combination wouldachieve greater CO2 emission reductionsat a lower average cost. Second, byencompassing the increased low-andzero-carbon generation in building block3, the broader combination wouldreduce reliance on fossil fuels andimprove fuel diversity. Third, byencompassing the increased demand-side energy efficiency in building block4, the broader combination wouldreduce the amount of electricity thatwould need to be delivered over theelectric grid, generally reducingpressure on the grid and therebyimproving electricity system reliability.These considerations all support basingthe BSER on the combination of all fourbuilding blocks. They also supportbasing the BSER, in the alternative, onthe combination of building block 1 andreduced generation in the amountsfacilitated by the remaining buildingblocks.

As has been discussed in earlierportions of the preamble, the costs andenergy impacts of each of the fourbuilding blocks individually arereasonable when viewed either at theindividual source level or through thelens of the electricity system as a whole,a conclusion that holds for thecombination of the building blocks aswell. Moreover, the flexibility availableto states and regulated entities to relymore extensively in their plans andstrategies on whichever measures bestsuit their particular circumstances willfurther improve cost effectiveness. Theanalysis the EPA performed to assessthe costs, benefits, and other impacts ofthe proposed goals reflects thiscompliance flexibility, along withtransmission and pipeline capabilitiesand constraints, fuel market andelectricity dispatch dynamics, andseasonal electricity load requirements.As described below in Section X, theresults indicate that the proposed stategoals (discussed in Section VII) arereadily achievable with no adverseimpacts on electricity system reliability,and that impacts on retail electricityprices are modest and fall within therange of price variability seenhistorically in response to changes infactors such as weather and fuel supply.Further, the costs tend to decline overtime as states and regulated entities takeadvantage of the available flexibility andexpand deployment of more cost-effective measures (notably demand-side energy efficiency). The EPA

considers this analysis strongconfirmation of the reasonableness ofthe costs of the measures in the fourbuilding blocks in combination as thebest system of emission reduction.

6. Additional Considerations Related toInclusion of Building Blocks 2, 3, and 4as Part of the Basis Supporting the BSER

In this section, we discuss additionalreasons why the measures in buildingblocks 2, 3, and 4, individually and incombination, meet the requirements tobe components of the BSER. inparticular, we discuss why they meetthe definition of a “system of emissionreduction,” and we provide additionalreasons why they are the “best” that is“adequately demonstrated.” Theinterconnected nature of the electricsystem is an important part of ourreasoning.

a. “System of Emission Reduction”

For the convenience of the reader, itis useful to reiterate the key CAAsection 111 requirements: Section111(d)(1) requires that each state’s plan“establisb[] standards of performancefor any existing source” for certain typesof air pollutants; and section 111(a)(1)defines a “standard of performance” as“a standard for emissions. . . whichreflects the degree of emissionlimitation achievable through theapplication of the best system ofemission reduction. . . adequatelydemonstrated.” These provisionsrequire that, in this rulemaking, theaffected sources must be subject toemissions standards, but the basis forthose standards—the “system ofemission reduction’ ‘—may be anymethod that reduces the affectedsources’ emissions, as long as thatmethod is a “system” that meets thecriteria for being the “best” that is“adequately demonstrated.”

As discussed in the LegalMemorandum, the EPA is justified inadopting this interpretation under thefirst step of the framework foradministrative agencies to construestatutes that the U.S. Supreme Courtestablished in Chevron U.S.A. Inc. v.NRDC, 467 U.S. 837, 842—844 (1984)(Chevron), which we refer to as Chevronstep 1.

Specifically, the term “system,”which is not defined in the CAA, isbroad: “A set of things working togetheras parts of a mechanism orinterconnecting network.” 220 The

22004ord Dictionary of English (3rd ed.)(published 2010, online version 2013), http://www.o4ordreference.com.mutex.gmu.edu/view/10.1093/acref/97801 99571123.001 .0001/acre!-9780199571123.



remaining provisions of the definition ofstandard of performance” do not

include any constraints on the “set ofthings” that may constitute a “system ofemission reduction.” Nor does thecontext in which “standard ofperformance” is found—the provisionsof section 111(d)(i)—add constraints onthe things that may constitute such asystem. Rather, it is clear from theseCAA provisions that anything thatreduces the emissions of affectedsources may be considered a “system ofemission reduction” for those sources.For this reason, the measures inbuilding blocks 2, 3, and 4 must beconsidered components of such asystem.

Even if these CAA provisions leaveroom for interpretation as to whetherthose measures must be consideredcomponents of such a system, the EPA’sinterpretation that they do is reasonable.As discussed in the LegalMemorandum, the EPA is justified inadopting this interpretation under thesecond step of the Chevron framework,which we refer to as Chevron step 2.There are several reasons. In enactingthe CAA, Congress established“pollution prevention” as a “primarygoal” of the Act, and described it as “thereduction or elimination, through anymeasures, of the amount of pollutantsproduced or created at the source.”221Building blocks 2, 3, and 4 are pollutionprevention measures, and, in light of theimportance of pollution prevention inthe CAA, it is reasonable to interpret“system of emission reduction” insection 111 to incorporate thosemeasures. In addition, the breadth of“system of emission reduction” isconfirmed by contrasting it with otherprovisions in the CAA that prescribespecific types of controls as the basis foremission limfts.222 Further support isfound in Title IV of the CAA, in whichCongress established the program thatregulates fossil fuel-fired power plantsto reduce their emissions of 502 andNOR, the precursors to acid deposition.In designing Title IV, Congressrecognized the integrated nature of theelectricity sector and how thatintegration could be harnessed to reduceair pollutant emissions. In fact, Congressincluded provisions to encourage re

221 CAA § 101(a)(3), (c).222 example, as discussed in the Legal

Memorandum c § 407(b)(2) requires the EPA tobase the nitrogen oxides (NOX] emission limits forcertain types of boilers “on the degree of reductionachievable through the retrofit application of thebest system of continuous emission reduction.;“ and further requires the EPA to revise previouslypromulgated emission limits for certain types ofboilers “to be more stringent if the [EPA]determines that more effective low NO burnertechnology is available.” (Emphasis added.)

dispatch to lower-emitting sources,renewable energy, and demand-sideenergy efficiency, all of which aremeasures in those building blocks.223All this supports the reasonableness ofinterpreting “system of emissionreduction” in CAA section 111 toincorporate those measures. It shouldalso be noted that a number ofcommentators in the private sector andacademia have indicated support forinterpreting the term, “system ofemission reduction” to base the CAAsection 111(d) standards of performanceon measures such as re-dispatch,renewable energy, and demand-sideenergy efficiency.224 Some stakeholdershave as well.225

b. “Best” System That Is “AdequatelyDemonstrated

As described earlier with respect tothe individual building blocks, themeasures in each of building blocks 2,

223 CPLA §401(b), 404(f)—(g).See Nordhaus R., Gutherz I., “Regulation of

CO2 Emissions from Existing Power Plants Under§ 111(d) of the clean Air Act: Program Design andStatutory Authority,” Environmental Law Reporter,44: 10366, 10384 (May 2014) (“strong argumentsfor” interpreting “system” to include measuressuch as the addition of new zero-carbon generatingcapacity and increases in end-user energyefficiency); Sussman R., “Power Plant RegulationUnder the clean Mr Act: A Breakthrough Momentfor u.s. climate Policy?” Virginia Environment LawJournal, 32:97, 119 (2014) (“EPA would seem tohave discretion to define ‘system’ to include anymix of strategies effective in reducing emissions.”);Konschnik K., Peskoe A., “Efficiency Rules: TheCase for End-Use Energy Efficiency Programs in theSection 111(d) Rule for Existing Power Plants,”Howard Law School Environmental Law Program—Policy Initiative 4 (March 3, 2014) (EPA isauthorized to “consider[ ]. . . the entire[electricity grid] system when setting performancestandards.”); Monast J., Profeta T., Pearson B.,Doyle J., “Regulating Greenhouse Gas EmissionsFrom Existing Sources: Section 111(d) and StateEquivalency,” Environmental Law Reporter, 42:10206, 10209 (March 2012) (“Demand-side energy-efficiency programs and renewable energygeneration may fit within the § 111 framework,however, because both reduce the utilization ofpower plant.. . . According to this reasoning,emission reductions are occuning within the sourcecategory, because of changes in generation at thepower plant.”).

225Ceronsky M., Carbonell T., “Section 111(d) ofthe Clean Air Act: The Legal Foundation for Strong,Flexible & Cost-Effective Carbon PollutionStandards for Existing Power Plants,”Environmental Defense Fund, at 9 (Oct. 2013),available at http://www.edforg/sites/default/files!111 -clean_air_act-strongfiexible_cost-effective_carbonpollution_standardsJor_existingfiower_plants.pdfi Doniger D., “Questions and Answers onthe EPA’s Legal Authority to Set ‘System Based’Carbon Pollution Standards for Existing PowerPlants under Clean Air Act Section 111(d),” NRDC[Natural Resources Defense Council] Issue Brief(Oct. 2013); “Comments of the Attorneys General ofNew York, California, Massachusetts, Connecticut,Delaware, Maine, Maryland, New Mexico, Oregon,Rhode Island, Vermont, Washington, and theDistrict of Columbia on the Design of a Program toReduce Carbon Pollution from Existing PowerPlants” (Dec. 16, 2013).

3, and 4 meet the criteria for the “best”system of emission reduction, and,generally for the same reasons, the threein combination do as well.

In addition, the measures in buildingblocks 2, 3, and 4, individually and incombination, are “adequatelydemonstrated.” As discussed earlier,thanks to the integrated nature of theelectricity system, they have long beenrelied on to reduce costs in general,assure reliability, and implement preexisting pollution control requirementsin the least-cost manner. As also notedelsewhere in the preamble, anddiscussed in more detail in thefollowing subsections, some utilities,states and regions are already relying onthese measures for the specific purposeof reducing CO2 emissions from EGUs.

(i) Actions by Affected EGUs

Measures in building blocks 2, 3, and4 may be undertaken or invested in bythe affected EGUs themselves, whichsupports that these measures are“adequately demonstrated.” Morespecifically, the EPA believes thatowners of units operating across a widerange of corporate, institutional andmarket structures (e.g., verticallyintegrated utilities in regulated markets,independent power producers,municipal utilities, and ruralcooperatives) can take advantage of abroad range of reduction opportunitiesincluded in the building blocks.Because of the proposed lengthyplanning period, owners can considerlonger-term options such asimplementing energy efficiencyprograms or replacement of oldergenerating resources with more moderntypes of generation, as well as shorter-term options such as heat rateimprovements and re-dispatch. Manycompanies, for example, already factor acarbon cost adder into their long-termplanning decisions.

Large vertically integrated utilitiesgenerally have options within all fourbuilding blocks. They tend to have largeand, as a general matter, at leastsomewhat diverse generation fleets. Fortheir higher-emitting units, they haveopportunities to use measures thatreduce the units’ CO2 emission rates,such as heat rate improvements, cofiring, or fuel switching. While thisproposal preserves fuel diversity, withover 30 percent of projected 2030generation coming from coal and over30 percent from natural gas, evencompanies that have traditionallydepended upon coal to supply themajority of their generation arediversifying their fleets, increasing their



opportunities for re-dispatch.22° Withinthe 5-to-15-year planning horizonestablished in this proposal to begin inJune 2015, most of these companies arelikely to be investing in new generationand can consider options such asincreased reliance on new renewablegenerating capacity. They also rimenergy efficiency programs for theircustomers.

Municipal utilities and ruralcooperatives that own generating assetportfolios also have multiple options forreducing CO2 emissions, particularlygeneration and transmissioncooperatives and larger municipalutilities. They can implement unit-specific improvements, re-dispatch tolower emitting resources, employ energyefficiency and renewable energystrategies, and explore longer-termcapacity planning strategies. Forcooperatives and municipal utilitieswith smaller fleets, re-dispatchingamong their own units may not provideas many opportunities, particularly inthe short term. But because of the timingflexibility in the guidelines, theseowners can use both short-term dispatchstrategies and longer-term capacityplanning strategies to reduce GHGemissions, and in many cases financingis available at tax-advantaged orsubsidized rates. At the same time, informulating their plans, states will be ina position to recognize the distinctiveattributes of smaller utilities—and, ofcourse, may consider participating inintegrated multi-state compliancestrategies to increase the flexibility andcost-saving opportunities that would beavailable to the covered EGUs.

Some stakeholders have expressedconcerns that municipal utilities andrural cooperatives can face otherchallenges as well. According to thesestakeholders, in deregulated areas, eventhough these utilities may be fullyvertically integrated entities, they maynot have as much flexibility to controldispatch because they are operating ina competitive market, where they can bein a position in which they need tooperate if called upon. Even in this case,the timing flexibility of the rule allowsthem to consider longer-term capacityplanning strategies. These can includebuilding or contracting for electricsupply from lower-emitting sources, useof distributed renewable technologies,and use of demand-side energyefficiency measures. There are a numberof municipal utilities and ruralcooperatives that are already

226http://online. wsj.com/article/PR-;CO20140508-;915605.html.

aggressively pursuing such strategies.227Nevertheless, in recognition ofstakeholders’ expressed concerns, weinvite comment on whether there arespecial considerations affecting smallrural cooperative or municipal utilitiesthat might merit adjustments to thisproposal, and if so, possible adjustmentsthat should be considered.

Independent power producers (PPs)may also face unique challenges butnevertheless have options. Companieswith coal-fired EGUs can implementefficiency improvements as well asother unit-level compliance optionssuch as co-firing or fuel switching.While these types of companies do notuse the integrated resource planningprocess that many vertically integratedutilities use, they still undertake long-term business planning and as a resultare in a position to consider differentlong-term strategies related to theirgenerating assets. Many IPPs areactively developing renewablegenerating capacity and natural gas-firedgenerating capacity. 1FF owners couldalso fund demand-side energy efficiencyprograms and document the resultingelectricity savings.

(ii) Actions by StatesAnother reason why the measures in

building blocks 2, 3, and 4 are“adequately demonstrated” is that statesmay adopt them and, in fact, manystates have already adopted many ofthem.

For example, several states havealready adopted renewable energy (RE)and demand-side energy efficiency (EE)measures in their CAA section 110 stateimplementation plans (SIPs) forattaining and maintaining the nationalambient air quality standards (NAAQS).The EPA has provided initial guidancefor states to do so.228 Some state airagencies did so for their 1997 8-hourozone NAAQS SIPs that were due in2007; for example, Washington, DC,included the purchase of wind powerand the installation of LED trafficlights 229; Dallas, Texas includedefficiency measures from the TexasEmissions Reduction Program

(TERP) 230; and Connecticut includedprojects such as high efficiency airconditioners, compact fluorescentlighting, combined heat and power(CHP), and solar photovoltaicinstallations.23’ Since that time, manystates have adopted legislative mandatesfor energy efficiency or renewableenergy, and states have expressedinterest in including EE/RE policies andprograms in upcoming NAAQS SIPs.The EPA has provided additionalguidance232 and has partnered with theNortheast States for Coordinated AirUse Management (NESCAUM) and threestates (Maryland, Massachusetts, andNew York) to identify opportunities forincluding EE/RE in a NAAQS SW andto provide real-world examples andlessons learned through those states’case studies.233

It should be recognized that eachstate’s electric utility sector operatesunder distinctive conditions andcircumstances. The EPA’s proposalensures that states retain flexibility tocraft standards of performance that canaccommodate characteristics includingfuel sources, types of EGU ownerswithin a state (e.g., investor-owned,municipal, and cooperative utilities,and independent power producers), andregulatory structure (e.g., regulated orrestructured). States can tailor theirregulatory mechanisms to recognizedifferences, for example by creatingbudgets on a company-wide basis orusing market-based mechanisms such asmass-based trading systems, to ensurethat requirements are achievable.

The proposal also recognizes thatstates have different resource bases andenergy policies in place, and thesedifferences are taken into account in thestate goal-setting and computationprocess. For instance, while the EPA’sBSER assumptions consider re-dispatchto NGCC units, they do not consider redispatch beyond the NGCC capacityalready existing in a state. In that way,the proposal does not presume that

230 Dallas/Ft. Worth, Texas 8-hour ozone SIP,http://www.gpo.gov/fdsys/pkg/FR-2008-08-1 5/pdf/E8-1 8835.pdf.

231 CT 1997 8-hour ozone SIP Web site, http://www.ct.gov/deep/cwp/view.asp?a=2684&q—_385886&depNav_GIL)= 1619(see Attainment Demonstration TSD, Chapter 6 at31, http://www.ct.gov/deep/lib/deep/air/regulations/proposed_and_reports/section_8.pdf).

232Roadmap for Incorporating EEIRE Policies andPrograms into SIPs/TIPs (July 2012), http://epa.gov/airquality/eere/manual.html.

233 States’ Perspectives on EPA’s Roadmap toIncorporate Energy Efficiency/Renewable Energy inNAAQS State Implementation Plans: Three CaseStudies, Final Report to the U.S. EnvironmentalProtection Agency (Dec. 2013), http://www.nescaum.org/documents/nescaum-final-reptto-epa-ee-in-naaqs-sip-roadmap-case-studies201 40522.pdf

227 For examples, see Large Public Power Council,Energy Efficiency Working Group, Second AnnualEnergy Efficiency Benchmarking Report (2013);https://www.nreca.coop/nreca-on-the-issues/energy-operations/energy-efficfency/.

228 See, e.g., Guidance on SIP Credits for EmissionReductions from Electric-Sector Energy Efficiencyand Renewable Energy Measures (Aug. 2004),hup://www.epa.govlftn/oarpg/tl/memoranda/ereseeremgd.pdfi Incorporating Emerging andVoluntary Measures in a State Implementation Plan(SIP) (Sept 2004), hftp:llwww.epa.gov/ttn/oazpg/tl/memoranda/evm_ievmg.pdf

229 DC Region 8-hour ozone SIP at 126, hftp://www.mwcog.org/uploads/pub-documents/9FhcXg20070525084306.pdf.


34888 Federal Register/Vol. 79, No. 117/Wednesday, June_18,2014/Proposed Rules

states with limited natural gasgeneration or infrastructure will have todevelop those resources.

Furthermore, while the BSER reflectsbest practices for both renewables andenergy efficiency, it also recognizes thatsome states have made more progressthan others in these areas. The BSERallows time for states to ramp up togreater levels of energy efficiency anduse and development of renewableenergy resources, should they choosethose approaches. With respect torenewable energy, the proposal alsorecognizes that different areas of thecountry have different resource basesand does not presume that a uniformlevel of penetration of renewablegeneration is appropriate for every state.

The features provided in this proposalto ensure policy flexibility can be usedby all states to address their uniquecircumstances. In a regulated state, if acompany’s compliance strategiesincluded reducing generation at higher-emitting EGUs, it would work throughits state’s integrated planning process toensure that adequate generation wasavailable through a combination of allfour building blocks. Cost recovery, andcost oversight, can be achieved throughrate cases before state regulators. In arestructured state, even if affectedcompanies responded to the guidelinesby reducing generation withoutthemselves replacing that generation,the electricity markets that havedeveloped would react to ensure theavailability of replacement generation.Other companies would seeopportunities to build or ramp upexisting lower-emitting generation, andin some markets that treat demand-sideresources on par with supply sideresources, energy service companieswould likely see opportunities. Further,state regulators can continue to play animportant role in restructured states aswell, authorizing or reviewing bothrenewable energy procurement anddemand-side energy efficiencyprograms. In all types of marketstructures, large energy users mightindependently see additional energyefficiency opportunities oropportunities for self-generation usingoptions such as combined heat andpower, solar, or power purchaseagreements, and states can structuretheir plans to allow the CO2 reductionsachieved at affected EGUs through suchactions to assist in reaching compliance.As discussed in earlier portions of thissection and elsewhere in the preamble,each of the building blocks is alreadybeing widely implemented, is consistentwith industry trends, and consists ofCO2 reduction methods already widelyaccepted in the eyes of various

stakeholders, as was clear from viewsexpressed in our outreach process.

Moreover, there are mechanismsthrough which states could requiremeasures from any of the buildingblocks in state plans. In fact, the stateplan formulation process through whichCAA section 111(d) is implementedreinforces the determination that thesemeasures are components of the BSER.For example, states would haveauthority to impose measures such asbest practices for operation andmaintenance of EGUs, dispatch limits,renewable energy resourcerequirements, and demand-side energyefficiency requirements. States alsowould have authority to establishrequirements that change the relativecosts of generation from more carbon-intensive and less carbon-intensiveEGUs, for example by creating emissionallowance systems that cause marketparticipants and system operators totake account of CO2 emission rates as anelement of variable operating costs.Such an approach can encouragemeasures from all of the building blockssimultaneously. As noted elsewhere inthe preamble, many states have alreadypursued one or more of theseapproaches.234

It also should be noted that during thepublic outreach sessions, stakeholdersgenerally recommended that state plansbe authorized to rely on, and thataffected sources be authorized toimplement, re-dispatch, renewableenergy measures, and demand-sideenergy efficiency measures in order tomeet states’ and sources’ emissionreduction obligations. The EPA agreesthat state plans may include thesemeasures, at least under certaincircumstances, as discussed in SectionVifi, and that sources may rely on themto achieve required reductions. It isclear that these types of measures arewell-accepted by the stakeholders asmeans to reduce emissions from affectedsources. The fact that state plans andsources would be expected to use thesetypes of measures to reduce emissionssupports the view that these measuresare part of a “system of emissionreduction” for those sources that theEPA may evaluate against theappropriate criteria to determinewhether they comprise the “best systemof emission reduction. . . adequatelydemonstrated.”

(iii) Regional Organizations

Another reason why the measures inbuilding blocks 2, 3, and 4 are

234 the discussions of California CaliforniaGlobal Warming Solutions Act and RGGI above inthis section and elsewhere in the preamble.

“adequately demonstrated” is that theycan be accommodated through theexisting regional components of theelectricity system.

On the regional level, ISO!RTOscontrol dispatch and are responsible forreliable operation of the bulk powersystem.235 They can seek solutions,such as capacity markets andtransmission upgrades, to preserveresource adequacy and ensure thecontinued reliable operation of the grid.For this proposal, the ISO/RTO Councilhas already submitted a set ofrecommendations they believe can helpbalance the needs of lower emissions,economic dispatch, and reliability,which is discussed in greater detail inSection Vffl.F.7 of this proposal236 Forareas of the country that are not coveredby an ISO/RTO, there are regionalgroups, such as ColumbiaGrid, NorthernTier Transmission Group andWestConnect in the west, and systemoperators such as Southern Company inthe southeast, that can provide thesefunctions. In shiffing to lower-emittingunits, grid operators across the countryfactor environmental costs into theireconomic dispatch through a variety ofmechanisms, including allowance costs,variable costs associated with operatingenvironmental controls, and operatinglimits for high-emitting units.

(iv) Concerns From Stakeholders;Solicitation of Comment

We note that some stakeholders haveargued that CAA section 111(a) (1) doesnot authorize the EPA to identify redispatch, low- or zero-emittinggeneration, or demand-side energyefficiency measures (building blocks 2,3, and 4) as components of the “bestsystem of emission reduction.adequately demonstrated.” According tothese stakeholders, as a legal matter, theBSER is limited to measures that may beundertaken at the affected units, and notmeasures that are beyond the affectedunits; the measures in building blocks 2,3, and 4 are “beyond-the-unit” or“beyond-the-fenceline” measuresbecause they are implemented outsideof the affected units and outside theircontrol; and as a result, those measurescannot be considered components of theBSER.

We welcome comment on this issue.As discussed above, we propose that the

235 Across all markets, at the federal level, FERCand NERC create and oversee standards forreliability. NERC works with electric reliabilitycouncils and control areas that comprise all typesof utilities and system operators to ensure thatadequate generation is available.

23e http://www.isorto.org/Documents/Report/20140128 IRCProposal-ReliabilitySafetyValveRegionalCompliancelieasurement_EPAC02Rule.pdf.



provisions of CAA section 111 do not bytheft terms preclude the BSER fromincluding those types of measures. Inaddition, as noted above, under ourproposed approach, affected sourcesmay themselves implement themeasures included in building blocks 2,3, and 4, so that those measures arewithin theft control with the result oftheft application being emissionsreductions at affected EGUs. Moreover,under our alternative approach, the“system of emission reduction”includes reductions in utilization at theaffected sources themselves.237 It shouldalso be noted that, as discussed above,the re-dispatch measures in buildingblock 2 are limited to affected sources.Thus, the proposed approach andalternative described above respond tothese stakeholder concerns.

7. Alternate Approach to the BestSystem of Emission Reduction

As an alternative to the approachdescribed above for determining the“best system of emission reduction.adequately demonstrated,” the “systemof emission reduction” may beidentified as including, in addition tobuilding block 1, the reduction ofaffected fossil fuel-fired EGUs’ massemissions achievable throughreductions in generation of specifiedamounts from those EGUs. Under thisapproach, the measures in building

237Commenters have critiqued this “at-the-unit”and “beyond-the-unit” distinction as follows:

There is an argument that the at-the-unit/beyond-the-unit distinction is not a meaningful one.Specifically, it could be argued that the distinctionbetween at-the-unit and beyond-the-unit measuresis largely artificial, because all of the emissionreductions under consideration—whether from at-the-unit measures (e.g., fuel-switching or efficiencyupgrades) or from beyond-the-unit measures—are,in fact, emission reductions at or from electricgenerating units on the interconnected electric grid.For example, neither the addition of renewablegeneration nor the reduction of end-user demanddirectly reduces atmospheric emission of C02;rather these measures permit fossil EGUs to reducetheir own output and emissions. It can be arguedthat all of the systems of emission reduction herecontemplated—whether they involve end-useenergy efficiency, displacing high-emissiongeneration with lower emission generation, fuel-switching, heat-rate improvements, etc.—areeffectively at-the-unit measures that ultimatelyreduce emissions solely from regulated EGUs. Ifenergy-efficiency programs, added renewableenergy, and redispatch from higher emittingfacilities to lower emitting facilities are viewed asat-the-unit systems of emission reduction, the at-the-unit/beyond-the-unit distinction arguablybecomes irrelevant—at least from a legalperspective. Rather, the real issue may come downto whether § 111(d) authorizes the EPA to requireEGUs to curtail their output of electricity as ameans of complying with the rule.

Nordhaus R., Gutherz 1., “Regulation of CO2Emissions from Existing Power Plants Under§ 111(d) of the Clean Air Act: Program Design andStatutory Authority,” Environmental Law Reporter,

44: 10366, 10383 n. 133 (May 2014).

blocks 2, 3, and 4 would not becomponents of the system of emissionreduction but instead would serve asbases for quantifying the reducedgeneration (and therefore emissions) ataffected EGUs, and assuring that theamount of reduced generation meets thecriteria for the “best” system that is“adequately demonstrated” because,among other things, the reducedgeneration can be achieved while thedemand for electricity services cancontinue to be met in a reliable andaffordable manner. Specifically, theamount of generation from the increasedutilization of NGCC units woulddetermine a portion of the amount of thegeneration reduction component of theBSER for affected fossil fuel-fired steamEGUs, and the amount of generationfrom the use of expanded low- and zero-carbon generating capacity that could beprovided, along with the amount ofgeneration from fossil fuel-fired EGUsthat could be avoided through thepromotion of demand-side energyefficiency, would determine a portion ofthe amount of the generation reductioncomponent of the BSER for all affectedEGUs.

Reduced generation is encompassedby the terms of the phrase “system ofemission reduction” in CAA section111(a)(1), as a matter of Chevron step 1,because, in accordance with the above-discussed definition of “system,”reduced generation is a “set of things’which include reduced use ofgenerating equipment and thereforereduced fuel input—that the affectedsource may take to reduce its CO2emissions.238 If that phrase is notconsidered clear by its terms, then,under Chevron step 2, it may reasonablybe interpreted to include reducedgeneration.239 As discussed in the LegalMemorandum, the legislative history ofthe 1970 CAA Amendments indicatesthat Congress recognized that emittingsources could comply with pollutioncontrol requirements by reducingproduction, including retiring.240 As

238 For this reason, under a Chevron step 1interpretation, “system of emission reduction”includes reduced generation.

239 these reasons, under a Chevron step 2interpretation, “system of emission reduction”includes reduced generation.

240 See CAA section 110(g) (authorizingtemporary emergency suspensions of SIP revisionsif needed to prevent the closing of a source of airpollution), enacted as CAA section 110(f) in the1970 CAA Amendments; 116 Cong. Rec. 42384(Dec. 18, 1970), reprinted in Congressional ResearchService, A Legislative History of the Clean Air ActAmendments of 1970, vol. 1, at 132—33 (1974)(statement of Sen. Muskie) (discussing criteria forsources to receive compliance date extensions).Sen. Muskie added that the emission standards setby the EPA for hazardous air pollutants “couldinclude emission standards which allowed for no

also noted in the Legal Memorandum,examples of reduced utilization as ameans of reducing emissions are foundin settlement agreements between theEPA and fossil fuel-fired EGUs toresolve alleged violations of the CAAnew source review (NSR)requirements.241

Reduction of, or limitation on, theamount of generation is already a well-established means of reducingemissions of pollutants in the electricsector, notwithstanding the fact that asa practical matter, some facilities mayhave to operate, or remain available, toensure system reliability. For example,reduced generation by higher-emittingsources is one of the compliance optionsavailable to, and used by, EGUs tocomply with the Clean Aft Act acid rainprogram in CAA title IV, as well as thetransport rules that we refer to as theNOx SIP Call242 and the Clean MrInterstate Rule (CAIR).243 Reduction ingeneration is also a possible means bywhich an EGU can achieve compliancewith its requirements under RGGI.

Reduced generation in specifiedamounts is part of the “best” system ofemission reduction that is “adequatelydemonstrated.” Reduced generation istechnically feasible because of asource’s ability to limit its ownoperations. In addition, the amounts ofgeneration and emission reductions maybe determined with precision throughthe application of building block 2, 3,and 4 measures for increased generationfrom low- or zero-emitting sources andincreased demand-side energyefficiency, which, in turn, ensure thereliability of the electricity grid and theaffordability of electricity to businessesand consumers.

Because of the availability of themeasures in building blocks 2, 3, and 4,the proposed levels of reducedgeneration axe of reasonable cost for theaffected source category and thenationwide electricity system, do notjeopardize reliability, result in animportant amount of emissionreductions, are consistent with currenttrends in the electricity sector, andpromote the development andimplementation of technology that isimportant for continued emissionsreductions. All these results come aboutbecause the operation of the electrical

measureable emissions,” id.. which further suggeststhat, as a practical mailer, the standards couldresult in reduced production.

241 See, e.g., Consent Decree at 18, United Statesv. Wis. Power & Light Co., No. 13—cv—266 (W.D.Wis. filed Apr. 22, 2013), available at http://wTNw2.epa.gov/sites/production/filesldocuments/wisconsinpower-cd.pdf.

24263 FR 57356 (Oct. 27, 1998).243 70 FR 25162 (May 12, 2005).



grid through integrated generation,transmission, and distribution networkscreates fimgibility for electricity andelectricity services, which allowsdecreases in generation at affected fossilfuel-fired steam EGUs to be replaced byincreases in generation at affected NGCCunits (building block 2) and allowsdecreases in generation at all affectedEGUs to be replaced by increasedgeneration at low- or zero-carbon EGUs(building block 3) or by decreaseddemand (building block 4). Further, thisfungibility increases over longertimeframes with the opportunity toinvest in infrastructure improvements,and as noted elsewhere, this proposalprovides an extended state plan andsource compliance horizon. Thesecharacteristics of the integratedelectricity system assure that reducedgeneration in specified amounts meetsthe criteria to qualify as part of the“best” system of emission reduction.

Reduced generation in those amountsis also “adequately demonstrated.” Asnoted above, the measures in buildingblocks 2, 3, and 4 are already inwidespread use in the industry. At thelevels proposed, they have the technicalcapability to substitute for reducedgeneration at some or all affected EGUsat reasonable cost. The NGCC capacitynecessary to accomplish the levels ofgeneration reduction proposed forbuilding block 2 is already in operationor under construction. Moreover, it isreasonable to expect that theincremental resources reflected inbuilding blocks 3 and 4 will develop atthe levels requisite to ensure anadequate and reliable supply ofelectricity at the same time that affectedEGUs may choose or be required toreduce their CO2 emissions by means ofreducing their utilization. There areseveral reasons for this. First, theaffected sources themselves could investin new renewable energy resources anddemand-side energy efficiency, asdiscussed above.2 Second, the states,as part of their plans, have mechanismsavailable to put these substitutes inplace: They could establishrequirements or incentives that wouldresult in new renewable energy anddemand-side energy efficiency

244ft should be noted that in light of the lowcurrent and projected near tern; prices for naturalgas, market forces may lead investors to choose tobuild new NGCC units, rather than new renewableresources. This result would not call into questionthe technical feasibility of a BSER that includedreductions in fossil fuel-fired generation by theamount of a specified amount of new renewableresources. This is because under thesecircumstances, the fossil fuel-fired generators couldstill reduce their generation without causingreliability or other problems in the electric powersystem.

programs, as also discussed above.245Third, as also discussed above, regionalentities in the electricity system canacconunodate these substitutes.

Most broadly, with respect to themeasures in building blocks 2, 3, and 4,provided there is sufficient lead time forplanning, mechanisms are in place inboth regulated and deregulatedelectricity markets to assure thatsubstitute generation will becomeavailable and/or steps to reduce demandwill be taken to compensate for reducedgeneration by affected EGUs. Thesemechanisms are based on, among otherthings, the integrated nature of theelectricity system coupled with theavailability of capacity in existing NGCCunits, the growing institutional capacityof entities that develop renewableenergy and demand-side energyefficiency resources, and the ability ofsystem operators and state regulators toincentivize further development ofthose resources.

The EPA solicits comment on whethermeasures in addition to those inbuilding blocks 2, 3, and 4 couldsupport the showing that reducedutilization is “adequatelydemonstrated,” including additionalNGCC capacity that may be built in thefuture, as discussed in Section VI.C.5.cabove.

8. The EPA’s Discretion in Applying theCriteria for the Best System of EmissionReduction

As discussed above, each of theapproaches to determining the “bestsystem of emission reduction.adequately demonstrated” entailsapplying the criteria described in theD.C. Circuit case law for evaluating theBSER. It should be emphasized thatunder the case law, the EPA hassignificant discretion in weighing thedifferent criteria, and may weigh themdifferently in different rulemaldngs.

For the present proposal, the EPA isheavily weighting three criteria inparticular: The amount of emissionreductions, the cost of achieving thosereductions, and the promotion oftechnology implementation—while alsonoting that the proposed BSERdetermination readily meets the othercriteria as well. The EPA considers itespecially important in this rulemaking,while ensuring that electricity systemreliability is preserved and that costs arenot unreasonable, to achieve asignificant amount of emissionsreductions in response to the urgencyand the magnitude of the need to

245 The nuclear generating capacity reflected inbuilding block 3 is already in operation or underconstruction.

mitigate climate change. The EPAdiscusses this above in the sectionsconcerning the scientific background forthis rulemaking. The EPA also considersit especially important for the presentproposal that the overall costs ofachieving the emission reductionsshould be reasonable. Costs can beminimized through the flexibility tochoose from a broad range of CO2emission reduction measures, as isprovided in the portion of this proposaladdressing state plans, and a similarlybroad range of emission reductionmeasures, represented by the fourbuilding blocks discussed above, shouldserve as the basis supporting the BSER.Finally, the EPA also considers itespecially important for the presentproposal to promote technologicalinnovation and development of, inparticular, the measures in buildingblocks 3 and 4 (to reiterate, low- or zero-carbon electricity generation anddemand-side energy efficiency,respectively). Promoting innovation in,and market penetration of, thesetechnologies and practices is critical tomaking the substantial reductions inemissions that will be required duringthe next few decades to reduce the risksto public health and welfare and oureconomic well-being of dangerousclimate change.

In addition, in this rulemaking, theEPA is determining the BSER in amanner that is consistent with, and thatprovides further impetus for, currenttrends in the nation’s electricity systemthat offer promise to reduce the carbonintensity of the system over the near-and long-term, while maintainingreliability and affordability. Thisapproach is consistent with the caselaw, which authorizes the EPA todetermine BSER by “balanc[ing] long-term national and regional impacts,”and by “using a long-term lens with abroad focus on future costs,environmental and energy effects ofdifferent technologicalsystems 246

9. State-Wide Application of the BSER;Appropriateness of Standards ofPerformance

An important aspect of the BSER foraffected EGUs is that the EPA isproposing to apply ft on a statewidebasis. The statewide approach alsounderlies the required emissionperformance level, which is based onthe application of the BSER to a state’saffected EGUs, and which the suite ofmeasures in the state plan, including theemission standards for the affected

246Sjerm Club v. Costle, 657 F.2d 298, 331 (D.C.Cfr. 1981).


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EGUs, must achieve overall. The statehas flexibility in assigning the emissionperformance obligations to its affectedEGUs, in the form of standards ofperformance—and, for the portfolioapproach, in imposing requirements onother entities—as long as, again, therequired emission performance level ismet.

This state-wide approach bothharnesses the efficiencies of emissionreduction opportunities in theinterconnected electricity system and isfully consistent with the principles offederalism that underlie the Clean AirAct generally and CAA section 111(d)particularly. That is, this provisionachieves the emission performancerequirements through the vehicle of astate plan, and provides each statesignificant flexibility to take localcircumstances and state policy goalsinto account in determining how toreduce emissions from its affectedsources, as long as the plan meetsminimum federal requirements.

In this subsection, we describe howthis approach, and the standards ofperformance for the affected EGUs thatthe states will establish through theprocess we describe, are consistent withthe CAA section 111(d)(1) and (a)(1)provisions.

For convenience, we set out therequirements of CAA section 111(d)(1)and (a)(1) here: Under CAA sectioniii(d)(1), the state must adopt a planthat “establishes standards ofperformance for any existing source.”Under CAA section 111(a)(1), a“standard of performance” is a“standard for emissions. . . whichreflects the degree of emissionlimitation achievable through theapplication of the best system ofemission reduction. . . adequatelydemonstrated.” The EPA proposes tointerpret these provisions as set forth inthis sub-section.

The first step is for the EPA todetermine the “best system of emissionreduction. . . adequatelydemonstrated.” As discussed at lengthelsewhere, the EPA is proposing twoalternative BSER. The first is themeasures in building blocks 1 through4 combined. This includes operationalimprovements and equipment upgradesthat the coal-fired steam EGUs in thestate may undertake to improve theirheat rate by, on average, six percent andincreases in, or retention of, zero- orlow-emitting generation, as well asmeasures to reduce demand forgeneration, all of which, taken together,displace, or avoid the need for,generation from the affected EGUs. ThisBSER is a set of measures that impactsaffected EGUs as a group. The

alternative approach to BSER is buildingblock 1 combined with reducedutilization from the affected EGUs in thestate as a group, in the amounts that canbe replaced by an increase in, orretention of, zero- or low-emittinggeneration, as well as reduced demandfor generation.

After determining the BSER, the EPAthen applies the BSER to each state’saffected EGUs, on a state-wide basis.Building block 1 is applied to the coal-fired steam EGUs on a statewide basis;building block 2 is applied to increasethe generation of the NGCC units in thestate up to certain amounts, anddecrease the amount of generation fromsteam EGUs accordingly; and themeasures in building blocks 3 and 4 areapplied to reduce, or avoid, generationfrom all affected EGUs on a state-widebasis. Under the alternative formulationof the BSER, the total amount ofreduced generation from the affectedEGUs in the state, associated with themeasures in building blocks 2, 3, and 4,is determined on the basis of eachstate’s affected EGUs as a group.

This statewide approach to applyingthe BSER is consistent with the CAAsection 111(a)(1) definition of “standardof performance,” which, as quotedabove, refers to “the application of the[BSER],” for the purpose of determining“the degree of emission limitationachievable,” but does not otherwiseconstrain how the BSER is to beapplied.

As a result, the EPA may apply theBSER to all of the affected EGUs in thestate as a group. Similarly, theimplementing regulations give the EPAbroad discretion to identify the group ofsources to which the BSER is applied.The regulations provide that the EPA“will specify different emissionguidelines or compliance times or bothfor different sizes, types, and classes ofdesignated facilities when costs ofcontrol, physical limitations,geographical location, or similar factorsmake subcategorization appropriate.”Applying the BSER to the affected EGUsin each state as a group is appropriate,and therefore is consistent with theseregulations.

As part of applying the BSER, theEPA, to return to provisions of CAAsection 111(a)(1), calculates the“emission limitation achievable throughthe application of the [BSERJ.” in thisrulemaking, we refer to this amount asthe state goal. As noted, the EPAexpresses the state goal in the emissionguidelines as an emission rate.

The state must develop a state planthat achieves the state goal, either in theform of an emission rate, as specified forthe state in the emission guidelines, or

a translated mass-based version of therate-based goal. We refer to the stategoal, in the form used by the state as thefoundation of its plan, as the requiredemission performance level.

As part of its state plan, the state mustestablish “standards of performance” forits affected EGUs. To do so, the statemay consider the measures the EPAidentified as part of the BSER or othermeasures that reduce emissions fromthe affected EGUs. Moreover, the statehas the flexibility to establish emissionstandards in the degree of stringencythat the state considers appropriate. Theprimary limitation on the state’sflexibility is that the emission standardsapplied to all of the state’s affectedEGUs—and, in the case of states thatadopt the portfolio approach, therequirements imposed on other affectedentities—taken as a whole, must bedemonstrated to achieve the requiredemission performance level, In addition,the state may make the emissionstandards for any of its affected EGUssufficiently stringent, so that thestandards and any requirementsimposed on other affected entities (ifrelevant), taken as a whole, achieve alevel of emission performance that isbetter than the required emissionperformance level. See CAA section116, 40 CFR 60.24(g).

Under these circumstances—that theemission standards that the stateestablishes for its affected EGUs and anyother requirements for the other affectedentities, as relevant, taken together, areat least as stringent as necessary toachieve the required emissionperformance level for the state’s affectedEGUs—each emission standard that thestate adopts for each of its affected EGUswill meet the definition of a “standardof performance” under CAA section111(a)(1). Specifically, the “standard ofperformance” for each source willconstitute, to return to the provisions ofCAA section 111(a)(1), “a standard foremissions which reflects [that is,embodies, or represents] 247 the degree[that is, the portion] of emissionlimitation achievable through theapplication of the [BSERI” [that is, asnoted above, the required emissionperformance level for all affectedsources in a state]. That “degree” orportion of the required emissionperformance level is, in effect, theportion of the state’s obligation to limitits affected sources’ emissions that thestate has assigned to each particularaffected source. An emission standard

247 See Oxford Dictionary of English (3rd ed. 2010(online version 2013)) (defining “reflect” as, amongother things, ‘embody or represent (something) ina faithful or appropriate way”).


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meets this definition of the term“standard of performance” regardless ofwhether it is part of a plan that adoptsthe portfoiio approach (in which case,the standard will reflect a relativelysmaller part of the emissionperformance level) or one that imposesthe plan’s emission limitationobligations entirely on the affectedEGUs (in which case, the standard willreflect a relatively larger part of theemission performance level).

These proposed interpretations of theprovisions of CAA sections 111(d)(1)and (a](1) are fully consistent with theEPA’s overall approach in thisrulemaking to determining and applyingthe BSER and identifying theappropriate level of emissionperformance for the affected EGUs. Asnoted, this approach entails applyingthe BSER on a state-wide basis and,based on the BSER, identifying theemission performance level for eachstate’s affected EGUs that each statemust achieve, so that each state maythen assign the emission limitationobligations among its sources. As noted,this approach is fully consistent withthe interconnected nature of theelectricity system and with theprinciples of federalism that underlieCAA section 111(d).

It should be emphasized that eachstate has many options for assigning theemission limitation obligations amongits affected sources. For example, thestate could impose emission standardsthat are consistent with the BSER.Under these circumstances, the statemay assign to different affected sourcesemission standards with different levelsof stringency because the state will havedetermined that those standards areconsistent with the nature of eachsource’s participation in the state’selectricity system. In addition, the statecould authorize emission trading as partof the emission standards for affectedsources. Under these circumstances, ifan affected source’s emission level washigher than the standard the stateestablished for it, the source couldachieve the standard by purchasingadditional emission rights through thetrading program.

Finally, it should be noted that statesretain authority under CAA section 116and 40 CFR 60.24(g) to imposestandards of performance that,cumulatively, are more stringent thanthe emission performance level.248

The EPA’s approach may also be characterizedas (i) determining the BSER for the affected EGUs,(II) establishing as the emission guideline thestandard for emissions that the affected EGUs in thestate can achieve on average through theapplication of the BSER, and (iii) as part of theemission guideline, authorizing each state to

10. Combined Categories

As discussed above, the EPA issoliciting comment on combining thecategory of steam EGUs and the categoryof combustion turbines (which includeNGCC units) into a single category forfossil fuel-fired EGUs, for purposes ofpromulgating emission guidelines forCO2 emissions. The EPA solicitscomment on whether combining thecategories is, as a legal matter, aprerequisite for (1) identifying as acomponent of the BSER re-dispatchbetween sources in the two categories(i.e., re-dispatch between steam EGUsand NGCC units), or (ii) facilitatingaveraging or trading systems thatinclude sources in both categories,which states may wish to adopt.

11. SeverabilityWe consider our proposed findings of

the BSER with respect to the variousbuilding blocks to be severable, suchthat in the event a court were toinvalidate our finding with respect toany particular building block, we wouldfind that the BSER consists of theremaining building blocks. The stategoals that would result from anycombination of the building blocks canbe computed from data included in theGoal Computation TSD and itsappendices using the methodologydescribed in the preamble and that TSD.

12. Solicitation of CommentWe invite comment on all aspects of

our proposed interpretation andalternate interpretation of the BSER forCO2 emissions from existing fossil fuel-fired EGUs, both as identified above andas further discussed in the LegalMemorandum in the docket.24 Inparticular, we invite comment on ouranalysis of the four building blocks ascomponents of the BSER, whether anyother potential measures should beconsidered, our analysis of thecombinations of building blocks 1 and2 and of all four building blocks, andthe legal, technical, and economic basesof our conclusions. With regard tocomments received during thestakeholder meetings, some commenters

establish as the applicable standard for eachaffected EGU, the standard that the state considersappropriate and that when totaled with thestandards established for the other EGUs tand asmay be adjusted to account for the portfolioapproach, if that approach is adopted by the state)is at least as stringent as the average standard in theemission guideline. As noted in the accompanyingtext, a state has many ways to establish standardsthat meet the CAA requirements, including, forexample, following the BSER or authorizingemission rate averaging or trading.

249 However, as noted, we are not solicitingcomment on issues that were resolved by theimplementing regulations.

noted that trading programs like RGGIhave been successful at reducing GHGs,and other commenters provided specificBSER proposals based on trading and/oremissions averaging approaches. Wespecifically request comment onwhether any of these approaches shouldbe considered as the BSER. We alsospecifically invite comment on thequestion, raised by some stakeholders,as to whether if measures may be reliedon in the state plan to achieve emissionsreductions, they cannot be excludedfrom the scope of the BSER solelybecause they involve actions by entitiesor at locations other than affectedsources.

VII. State Goals

A. Overview

In this section, the EPA sets outproposed state-specific CO2 emissionperformance goals to guide states indevelopment of their state plans. Theproposed goals reflect the EPA’squantification of each state’s averageemission rate from affected EGUs thatcould be achieved by 2030 andsustained thereafter, with interim goalsthat would apply over a 2020—202 9phase-in period, through reasonableimplementation, considering the uniquecircumstances of each individual state,of the best system of emission reductionadequately demonstrated (based on allfour building blocks) described above.In addition, we are taking comment ona second set of state-specific goals thatwould reflect less stringent applicationof the same BSER, in this case by 2025,with interim goals that would applyover a 2020—2024 phase-in period. Aspromulgated in the final rule followingconsideration of comments received, theinterim and final goals will be bindingemission guidelines for state plans.

The proposed goals are expressed inthe form of state-specific, 250

output-weighted-average CO2 emissionrates for affected EGUs. However, statesare authorized to translate the form ofthe goal to a mass-based form, as longas the translated goal achieves the samedegree of emission limitation.251

The EPA is also proposing thatmeasures taken by a state or its sources

250 described below, the emission rate goalsinclude adjustments to incorporate the potentialeffects of emission reduction measures that addresspower sector CO2 emissions primarily by reducingthe amount of electricity produced at a state’saffected EGUs (associated with, for example,increasing the amount of new low- or zero-carbongenerating capacity or increasing demand-sideenergy efficiency) rather than by reducing their CO2emission rates per unit of energy output produced.

251A method for translating from a rate-basedgoal to a mass-based goal is discussed in theProjecting CO2 Emission Performance in State PlansTSD.



after the date of this proposal, orprograms already in place, and whichresult in CO2 emission reductions ataffected EGUs during the 2020—203 0period, would apply towardachievement of the state’s CO2 goal.Thus, states with currently existingprograms and policies, and states thatput in place new programs and policiesearly, will be better positioned toachieve the goals.

The EPA is proposing to finalize thegoal for each state as proposed, andadjusted as may be appropriate based oncomments. A state may demonstrateduring the comment period thatapplication of one of the building blocksto that state would not be expected toproduce the level of emission reductionquantified by the EPA becauseimplementation of the building block atthe levels envisioned by the EPA wastechnically infeasible, or because thecosts of doing so were significantlyhigher than projected by the EPA. Whilethe EPA would consider this in settingfinal state goals, the EPA would alsoconsider (and would expect commentersto address) whether a similar overallstate goal could still be achievedthrough more aggressiveimplementation of one or more of themeasures encompassed in the otherbuilding blocks or through other,comparable measures. For example, if astate demonstrates during the publiccomment period that the state’s coal-fired steam EGUs could only achieve anaverage four percent heat rateimprovement, instead of the six percentthat the EPA is proposing to determineis achievable from application ofbuilding block 1, the EPA would notadjust the state’s goal to reflect thatchange unless the state alsodemonstrates that it could not getadditional reductions from applicationof building blocks 2, 3 or 4, or inrelated, comparable measures.

Each of the building blocksestablishes a reasonable level ofreductions, but not necessarily themaximum amount that could beachieved if that building block, and noother, were the basis supporting theBSER. Together the building blocksestablish a reasonable overall level ofreductions and effort that the EPAconsiders appropriate at this time. Thisamount of emission reductions issignificant and will require effort andadjustments throughout the electricitysector. In light of the overall effort toachieve the state goals based on acombination of all four building blocksat the levels specified, the EPA is notproposing a higher level of reductions atthis time, even though the measures inthe building blocks could be

implemented more stringently toachieve greater emission reductions.

Because the building blocks eachestablish a reasonable level of emissionreduction rather than the maximumpossible level of reduction, the EPAexpects that, for any particular state,even if the application of the measuresin one building block to that state wouldnot produce the level of emissionreductions reflected in the EPA’squantification for that state, the statewill be able to reasonably implementmeasures in other of the building blocksmore stringently, so that the state wouldstill be able to achieve the proposedgoal. Accordingly, the EPA proposesthat even if a state demonstrates duringthe comment period that application ofa building block to that state would notresult in the level of emissionreductions reflected in the EPA’squantification for that state, then thestate should also explain why theapplication of the other building blockswould not result in greater emissionreductions than are reflected in theEPA’s quantification for that state. Inlight of the fact that the building blocksare based on a reasonable level ofstringency and not the most stringentpossible level, the EPA expects thatsuch offsetting emission reductions atthe state’s affected EGUs from theapplication of other building blocks willbe available, so that the EPA will be ableto finalize the state goals as proposed.For example, a state’s inability to meetthe level of emission reductionsanticipated through use of one buildingblock may free up resources that thestate could then devote to morestringent implementation of anotherbuilding block. This approach wouldmean that overall, the same nationwidelevel of emission reductions asproposed would be achieved. The EPAinvites comment on this aspect of theproposal.

At this time, the EPA is not proposingCO2 emission performance goals foreither Indian country or U.S. territories.The EPA does plan to establish CO2emission goals for both Indian countryand territories in the future. The EPAplans to conduct additional outreachbefore seffing these goals.

Issues related to the establishment ofCO2 goals and CAA section 111(d) plansfor Indian country are discussed inSection V.D of this preamble. As notedin that discussion, the EPA is aware offour potentially affected power plantslocated in Indian country: The SouthPoint Energy Center, on Fort Mojavetribal lands within Arizona; the NavajoGenerating Station, on Navajo triballands within Arizona; the Four CornersPower Plant, on Navajo tribal lands

within New Mexico; and the BonanzaPower Plant, on Ute tribal lands withinUtah.252 Data for these four powerplants have been excluded from the dataused to compute the proposed stategoals for Arizona, New Mexico, andUtah discussed below.

With respect to territories, the EPA iscurrently aware of potentially affectedEGUs in Puerto Rico, the U.S. VirginIslands, and Guam. The EPA requestscomment on how the BSER would applyto these territories, as well as toAmerican Samoa or the NorthernMariana Islands if potentially affectedEGUs are subsequently identified inthose territories. In particular, the EPAsolicits comment on appropriatealternatives for territories that do nothave access to natural gas.253 Becausethe data sources we have used forpurposes of establishing renewableenergy and demand-side energyefficiency targets for states do not coverall the territories, we also solicitcomment on ways to determineappropriate renewable energy anddemand-side energy efficiency targetsusing other data sources.

The remainder of this sectionaddresses five sets of topics. First, wediscuss several issues related to theform of the goals. Second, we describethe proposed state goals and thecomputation procedure. Third, wediscuss several types of state flexibilitywith respect to the goals. Fourth, wedescribe the alternate set of goals offeredfor comment and certain otherapproaches we considered. Finally, wediscuss the proposal’s compatibilitywith the need to ensure a reliable,affordable supply of electricity.

Some of the topics addressed in thissection are addressed in greater detail insupplemental documents available inthe docket for this rulemaking,including the Goal Computation TSDand the Greenhouse Gas AbatementMeasures TSD. Specific topicsaddressed in the various TSDs are notedthroughout the discussion below.

B. Form of Goals

The proposed goals are presented inthe form of adjusted output-weighted-average CO2 emission rates that theaffected fossil fuel-fired EGUs located ineach state could achieve, on average,through application of the measures

252 The South Point facility is an NGCC powerplant, and the Navajo, Four Corners, and Bonanzafacilities are coal-fired power plants.

253 noted in Section VLC.5.d above, we arerequesting comment on whether heat rateimprovements for non-coal fossil fuel-fired EGUsshould be part of the basis supporting the BSER,with particular reference to the situation ofgeographically isolated jurisdictions such as theU.S. territories.



comprising the BSER (or alternativecontrol methods). Several aspects of thisproposed form of goal are worth notingat the outset: The use of an emissionrate-based form (e.g., the quantity of CO2per MWh of electricity generated), withthe opportunity for the state to adopt amass-based form (e.g., a cap on thetonnage of CO2 emissions); the use ofoutput-weighted-average emission ratesfor all affected EGUs in a state ratherthan nationally uniform emission ratesfor all affected EGUs of particular types;the use of adjustments to accommodatemeasures that reduce CO2 emissions byreducing the quantity of fossil fuel-firedgeneration rather than by reducing theCO2 emission rate per MWh generatedby affected sources; the use of emissionrates expressed in terms of net ratherthan gross energy output; and theadjustability of the goals based on theseverability of the underlying buildingblocks.

First, the EPA proposes to use anemission rate-based form for the state-specific goals included in theguidelines, and to give each state theopportunity to translate its rate-basedgoal to an equivalent mass-based formfor state plan purposes. Each of the twoforms of goals presents advantages, andstates have expressed support for havingthe flexibility to use either form.Defining emission performance levels ina rate-based form provides flexibility toaccommodate changes in the overallquantities of electricity generated inresponse to increases in electricitydemand. Defining emission performancelevels in a mass-based form providesrelative certainty as to the absoluteemission levels that would be achievedas well as relative simplicity inaccommodating and accounting for theemission impacts of a wide variety ofemission reduction strategies. In light ofthese respective advantages, we proposeto set an emission rate-based form ofgoal, and to allow any state to translatethe rate-based goal to an equivalentmass-based emission performance levelfor state plan purposes. This approachallows each state to maximize theadvantages it considers optimal and isconsistent with the state flexibilityprinciple that is central to the EPA’sdevelopment of this program.

The second aspect noted aboveconcerns the proposed choice of state-specific output-weighted-averageemission rates for all affected EGUs ineach state rather than nationallyuniform emission rates for particulartypes of affected EGUs. Here, the EPA’smain consideration has been to ensurethat the proposed goals reflectopportunities to manage CO2 emissionsby shifting generation among different

types of affected EGUs. Specifically,because CO2 emission rates differwidely across the fleet of affected EGUs,and because transmissioninterconnections typically providesystem operators with choices as towhich EGU should be called upon toproduce the next MWh of generationneeded to meet demand, opportunitiesexist to manage utilization of highcarbon-intensity EGUs based on theavailability of less carbon-intensivegenerating capacity. For states andgenerators, this means that CO2emission reductions can be achieved byshifting generation from EGUs withhigher CO2 emission rates, such as coal-fired EGUs, to EGUs with lower CO2emission rates, such as NGCC units. Ouranalysis indicates that shiftinggeneration among EGUs offersopportunities to achieve large amountsof CO2 emission reductions atreasonable costs. These opportunitiescan be reflected in a goal established inthe form of an output-weighted-averageemission rate for multiple affected EGUtypes. Our approach is also consistentwith the fact that the proportions ofdifferent EGU types and hence themagnitudes of the generation-shiftingopportunities vary across states, andthat CAA section 111(d) calls forstandards of performance to beestablished in state plans rather than ona nationwide basis.

The third aspect noted aboveregarding the proposed form of the goalsconcerns the adjustments made to theoutput-weighted-average emission ratesin order to accommodate reducedutilization of affected EGUs associatedwith measures such as increases in low-and zero-carbon generating capacity anddemand-side energy efficiency. Werecognize that these measures supportreduced overall CO2 mass emissionsfrom affected EGUs through reductionsin the quantity of generation fromaffected EGUs, and not necessarilythrough reductions in the weighted-average CO2 emission rates of affectedEGUs. Accordingly, we haveconstructed the emission rate goals in amanner that is intended to account forthese generation quantity-reducingmeasures by making adjustments to thevalues used in the emission ratecomputations. The specific adjustmentsare summarized below in the context ofthe goal computation methodology andare described in greater detail in theGoal Computation TSD. As describedbelow in Section VIII on state plans, weare proposing that a state choosing arate-based form of goal would be able tomake analogous adjustments whenassessing monitored emission

performance so that measures thatsupport avoided generation at affectedEGUs could be used to help the statemeet the rate-based emissionperformance level reflected in its plan.We note that adjustments of this natureare not necessary when a plan’semission performance level is based onthe mass of CO2 emissions 254 ratherthan on CO2 emission rates, because theemission-reducing effects of reducedgeneration at affected EGUs are evidentin the EGUs’ reported CO2 massemissions.

The fourth aspect noted aboveconcerns the proposed expression of thegoals in terms of net energy output 255_

that is, energy output encompassing netMWh of generation measured at thepoint of delivery to the transmissiongrid rather than gross MWh ofgeneration measured at the EGU’sgenerator.256 The difference between netand gross generation is the electricityused at a plant to operate auxiliaryequipment such as fans, pumps, motors,and pollution control devices. Becauseimprovements in the efficiency of thesedevices represent opportunities toreduce carbon intensity at existingaffected EGUs that would not becaptured in measurements of emissionsper gross MWh, we are proposing goalsexpressed in terms of net generation.Nearly all EGUs already have in placethe equipment necessary to determineand report hourly net generation, andwe believe that the proposed reportingrequirement would therefore not beburdensome. However, we alsorecognize that at present EGUs reportgross rather than net load257 to us under40 CFR Part 75, and that the proposedGHG standards of performance for newEGUs are expressed in terms of grossgeneration (although we soughtcomment on the use of net generationinstead). We therefore specifically seekcomment on whether the goals andreporting requirements for existingEGUs should be expressed in terms of

254We also recognize that even under a mass-based approach, adjustments may be appropriate insome circumstances to address interstate effects,such as when measures undertaken pursuant to onestate’s plan are expected to be associated withdecreases in fossil fuel-fired generation and co2emissions in another state. These issues arediscussed below in Section VIII on state pians.

255 discussed below in Section VIII on stateplans, we are similarly proposing that stateschoosing a rate-based form of emission performancelevel for their plans should establish a requirementfor affected EGUs to report hourly net energyoutput.

256 some EGUs, total net or gross energyoutput also includes useful thermal output, inaddition to either net or gross electric energyoutput.

Some EGUs report gross steam output insteadof gross electrical load.


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gross generation instead of netgeneration for consistency with existingreporting requirements and with theproposed requirements under the GHGstandards of performance for new EGUs.

The final aspect noted above has to dowith the severability of the four buildingblocks, discussed in Section VI above,upon which the goals are based.Because the building blocks can beimplemented independently of oneanother and the goals are the sum of theemission reductions from all of thebuilding blocks, if any of the buildingblocks is found to be an invalid basis forthe “best system of emission reduction

adequately demonstrated,” thegoals would be adjusted to reflect theemissions reductions from theremaining building blocks. As notedabove, the state goals that would resultfrom any combination of the buildingblocks can be computed from dataincluded in the Goal Computation TSDand its appendices using themethodology described below and inthat TSD.

We invite comment on all aspects ofthe proposed form of the goals.

C. Proposed Goals and ComputationProcedure

The EPA has developed proposedgoals for state plans reflectingapplication of the BSER, based on allfour building blocks described earlier, topertinent data for each state. The goalsare intended to represent CO2 emissionrates achievable by 2030 after a 2020—2029 phase-in period on an output-weighted-average basis collectively byall of a state’s affected EGUs, withcertain computation adjustmentsdescribed below to reflect the potentialto achieve mass emission reductions byavoiding fossil fuel-fired generation. Foreach state, in addition to the final goal,the EPA has developed an interim goalthat would apply during the 2020—202 9period on a cumulative or average basisas the state progresses toward the finalgoal. The proposed goals are set forth in

Table 8 below, followed by adescription of the computationmethodology. (The issue of how statescould demonstrate emissionperformance consistent with the interimand final goals is addressed in SectionVifi on state plans.)

TABLE 8—PROPOSED STATE258GOALS

[Adjusted output-weighted-average pounds ofCO2 per net MWh from all affected fossilfuel-fired EGUs]

State Interim Finalgoal goal

The proposed goals are expressed asadjusted output-weighted-averageemission rates for all affected EGUs ina state. As discussed earlier in thissection, a goal expressed as anunadjusted output-weighted-average

258 EPA has not developed goals for Vermontand the District of Columbia because currentinformation indicates those jurisdictions have noaffected EGUs. Also, as noted above, the EPA is notproposing goals for Indian country or U.S.territories at this time.

emission rate would fail to account formass emission reductions fromreductions in the total quantity of fossilfuel-fired generation associated withstate plan measures that increase low- orzero-carbon generating capacity ordemand-side energy efficiency.Accordingly, under the proposed goals,the emission rate computation includesan adjustment designed to reflect thosemass emission reductions. Theadjustment is made by estimating theannual net generation associated withan achievable amount of qualifying newlow-carbon and zero-carbon generatingcapacity, as well as the annual avoidedgeneration associated with anachievable portfolio of demand-sideenergy efficiency measures, and addingthose MWh amounts to the energyoutput from affected units that wouldhave been used in an unadjustedoutput-weighted-average emission ratecomputation.ZS Mathematically, thisadjustment has the effect of spreadingthe measured CO2 emissions from thestate’s affected EGUs over a largerquantity of energy output, thus resultingin an adjusted emission rate lower thanthe unadjusted emission rate. (Asdiscussed below in Section VIII on stateplans, we are proposing that a statecould make analogous adjustments tocompliance measurement approachesunder its state plan, thereby enablingthe state to adopt an emission rate-basedform of emission performance levelwhile still being able to rely on low- orzero-carbon capacity deploymentprograms and demand-side energyefficiency as components of its plan.)

The methodology used to computeeach state’s proposed goal issummarized on a step-by-step basisbelow. The methodology is described inmore detail in the Goal ComputationTSD, which includes a numericalexample illustrating the full procedure.The development of the data inputsused in the computation procedure isdiscussed in Section VI above and in theGreenhouse Gas Abatement MeasuresTSD.

Step 1 (compilation of baseline data).On a state-by-state basis, we obtainedtotal annual quantities of CO2emissions, net generation (MWh), andcapacity (MW) from reported 2012 datafor all affected EGUs.z60 For each state,

2591n the case of new capacity that is not zero-carbon, an adjustment would also be required to theemissions value used in computing the weighted-average emission rate. This procedure is discussedfurther in the Goal Computation TSD.

260EGUs whose capacity, fossil fuel combustion,or electricity sales were insufficient to qualify themas affected EGUs were not included in the goalcomputations. Most simple cycle combustion

Continued

AlabamaAlaskaArizona *

ArkansasCaliforniaColoradoConnecticutDelawareFloridaGeorgiaHawaiiIdahoIllinoisIndianaIowaKansasKentuckyLouisianaMaineMarylandMassachusettsMichiganMinnesotaMississippiMissouriMontanaNebraskaNevadaNew HampshireNew JerseyNew Mexico *

New YorkNorth CarolinaNorth DakotaOhioOklahomaOregonPennsylvaniaRhode IslandSouth CarolinaSouth DakotaTennesseeTexasUtah*VirginiaWashingtonWest VirginiaWisconsinWyoming

1,1471,097

735968556

1,159597913794891

1,378244

1,3661,6071,3411,5781,844

948393

1,347655

1,227911732

1,6211,8821,596

697546647

1,107635

1,0771,8171,452

931407

1,179822840800

1,254853

1,378884264

1,7481,2811,808

1,0591,003

702910537

1,108540841740834

1,306228

1,2711,5311,3011,4991,763

883378

1,187576

1,161873692

1,5441,7711,479

647486531

1,048549992

1,7831,338

895372

1,052782772741

1,163791

1,322810215

1,6201,2031,714

* Excludes EGUs located in Indian countrywithin the state.



we aggregated the 2012 data for all coal-fired steam EGUs as one group, all oil-and gas-fired steam EGUs as a secondgroup, and all NGCC units as a thirdgroup. We aggregated the 2012 data forall remaining affected EGUs (i.e.,integrated gasification combined-cycle(IGCC) units and any simple-cyclecombustion turbines satisfying relevantthresholds for qualification as affectedEGUs) as a fourth, “other” group.26’ Tothese totals for affected EGUs operatingin 2012, we added estimates for otherEGUs not yet in operation in 2012 thatare affected EGUs for purposes of thisemission guideline.262 Capacity andemission rate data inputs for the post-2012 affected EGUs were obtained fromthe NEEDS database maintained by theEPA for use with the IntegratedPlanning Model (PM). Generation datainputs for the post-2012 affected EGUswere estimated based on the average2012 utilization rates for recentlyconstructed EGUs of the same types; forexample, we estimated in this step thatthe post-2012 NGCC units wouldoperate at a 55 percent utilization rateon average.

Step 2 (application of building block1). The total CO2 emissions amount forthe coal-fired steam EGU group in eachstate from Step 1 was reduced by sixpercent, reflecting our assessment of theaverage opportunity to reduce CO2emission rates across the existing fleetof coal-fired steam EGUs through heatrate improvements that is technicallyachievable at a reasonable cost.

Step 3 (application of building block2). If the generation data for the NGCCgroup in a state developed in Step 1showed average annual utilizationbelow 70 percent of those units’maximum possible output, and thegeneration data developed in Step 1 alsoincluded generation from the coal-firedsteam or oil/gas-fired steam EGU groupsin that state, the generation andemissions figures for the NGCC groupwere increased, and the generation andemissions figures for the coal-fired andoil/gas-fired steam EGU groups fromStep 2 were proportionately263

turbines were excluded on this basis. See theapplicability criteria described in Section V.3.above.

261 emission and generation totals for the‘other” group also reflect the portion of affected

cogeneration units’ total CO2 emissions and totalenergy output corresponding to those units’ usefulthermal output.

262 Assuming it meets other applicability criteria,an EGU would be affected if it had commencedconstruction by January 8, 2014 (the data of federalRegister publication of the proposed GHG NSPS fornew EGUs).

263 example, if the data developed in Step Ishowed equal quantities of MWh generated by thecoal-fired steam EGU group and the oil/gas-fired

decreased, to reflect an estimatedpotential increase in utilization of theNGCC group to a maximum of 70percent. In this step, the total (across allfour groups) of the state’s fossil fuel-fired generation was maintained at theamount computed in Step 1, but to theextent that in the analysis a portion ofthe total fossil generation was shiftedfrom the coal-fired and oil/gas-firedsteam ECU groups, which have higherCO2 emission rates, to the NGCC group,which has a lower CO2 emission rate,the total (across all four groups) of thestate’s CO2 emissions was reduced.26

Step 4 (application of building block3). We estimated the total quantities ofgeneration from renewable generatingcapacity and from under-construction orpreserved nuclear capacity for each stateusing the approaches described inSection VI.C.3 above. Separate estimatesof renewable generation were computedfor each year of the plan period for eachstate based on the state’s 2012renewable generation and a regionalgrowth factor. Nuclear generation wasestimated as the amount of under-construction and preserved nuclearcapacity for each state operated at autilization rate of 90 percent, consistentwith recent industry-wide averageutilization rates for nuclear units.

Step 5 (application of building block4). We estimated the total MWh amountby which generation from each state’saffected EGUs would be cumulativelyreduced in each year of the plan periodassociated with implementation in thatstate of demand-side energy efficiencyprograms resulting in annualincremental reductions in the state’selectricity usage (relative to usageabsent those programs) of 1.5 percenteach year, as described in Section VI.C.4above. Separate estimates weredeveloped for each year to reflect thefact that energy efficiency programs thatare implemented on an ongoing basiswould be expected to produce largercumulative impacts on total annualelectricity usage over time. For statesthat are net importers of electricity, theestimated reduction in the generation bythe state’s affected EGUs was scaleddown to reflect an expectation that aportion of the generation avoided by thedemand-side energy efficiency wouldoccur at EGUs in other states.

steam EGU group, then any overall reduction in theMWh generated by these two groups due to acommensurate increase in the MWh generated bythe less carbon-intensive NGCC group would besplit equally between the coal-fired steam groupand the oil/gas-fired steam group.

264We did not estimate any change in utilization,generation, or emissions for the state’s “other”group of IGCC units and simple-cycle combustionturbines in Step 3.

Step 6 (computation of annuai rates).We computed adjusted output-weighted-average CO2 emission rates foreach state by dividing (1) the total CO2emissions for the coal-fired steam EGU,oil- and gas-fired steam EGU, NGCCunit, and “other” affected fossil EGUgroups from Step 3 above by (2) the totalof (a) the total net energy output(expressed in MWh) for the four groupsfrom Step 1 above plus (b) the estimatedannual net generation from renewableand nuclear generating capacity fromStep 4 above plus (c) the estimatedcumulative annual MWh amount savedthrough demand-side energy efficiencyfrom Step 5 above.265 We performedthese computations separately for eachyear from 2020 to 2029, using therespective cumulative annual MWhsavings figures developed in Steps 4 and5.

Step 7 (computation of interim andfinal goals). The final 2030 goal for eachstate is the annual rate computed for2029 for the state from Step 6 above. Wecomputed the 2020—2029 interim goalfor each state as the simple average ofthe annual rates computed for each ofthe years from 2020 to 2029 for the statefrom Step 6 above.

It bears emphasis that the proceduredescribed above is proposed to be usedonly to determine state goals, and theparticular data inputs used in theprocedure are not intended to representspecific requirements that would applyto any individual ECU or to thecollection of EGUs in any state. Thespecific requirements applicable toindividual EGUs, to the EGUs in a givenstate collectively, or to other affectedentities in the. state, would be based onthe standards of performanceestablished through that state’s plan.The details of how states could attainemission performance levels consistentwith the goals through different stateplan approaches that recognize emissionreductions achieved through all thebuilding blocks are discussed further inSection Vifi on state plans.

We invite comment on all aspects ofthe goal computation procedure. (Notethat we also invite comment on certainspecific alternate data inputs to theprocedure in Section VI.C above.) Wealso specifically invite comment on thestate-specific historical data to which

265 Expressed as a formula, the equation for theannual rate computation is:

[(Coal gen. x Coal emission rate) + tOG gen. x OGemission rate) ÷ (NGCC gen. x NGCC emission rate)÷ “Other” emissionsl/[Coal gen. + OG gen. + NGCCgen. ÷ “Other” gen. + Nuclear gen. + RE gen. + EEgen.1

This formula and its elements are furtherexplained in the Goal Computation TSD, as well asin the text above.



the building blocks are applied in orderto compute the state goals, as well as thestate-specific data used to develop thestate-specific data inputs for buildingblocks 3 and 4. These data are containedin the Goal Computation TSD and theGreenhouse Gas Abatement MeasuresTSD.

With respect to building block 2, wespecifically request comment on thefollowing alternate procedure: In Step 3,to the extent that generation from astate’s NGCC group was increasedconsistent with the NGCC utilizationrate target, in order to maximize theresulting emission reductions, wewould decrease generation from thestate’s coal-fired steam group first, andthen decrease generation from the state’soil/gas-fired steam group (instead ofdecreasing generation from the coal-fired steam and oil/gas-fired steamgroups proportionately).

With respect to building block 4, wespecifically invite comment on thealternative in Step 5 of scaling up theestimated reduction in the generation byaffected EGUs in net electricity-exporting states to reflect an expectationthat a portion of the generation avoidedin conjunction with the demand-sideenergy efficiency efforts of other, netelectricity-importing states would occurat those EGUs, analogous to theproposed adjustment for net electricityimporting states described in Step 5. Wealso request comment on the alternativeof maldng no adjustment in Step 5 foreither net electricity-importing or netelectricity-exporting states. Thesealternatives are discussed in the GoalComputation TSD.

We also request comment on whetherCO2 emission reductions associatedwith other measures not currentlyincluded in any of the four proposedbuilding blocks should be included inthe state goals.

D. State FlexibiitiesAs promulgated in the final rule

following consideration of comment, thestate-specific goals will be bindingemission guidelines. States’ ability toachieve emission performance levelsconsistent with the binding goals isenhanced by several distinct types offlexibility: (i) Choices as to the measuresemployed, including the timing of theirimplementation; (ii) the ability totranslate from a rate-based form of goalto a mass-based form of goal; and (iii)the opportunity to pursue multi-stateplan approaches.

First, a core flexibility provided underCAA section 111(d) is that while statesare required to establish standards ofperformance that reflect the degree ofemission limitation from application of

the control measures that the EPAidentifies as the BSER, they need notmandate the particular control measuresthe EPA identifies as the basis for itsBSER determination. In developing thebuilding block data inputs applied toeach state’s historical data to developthe goals, the EPA targeted reasonablyachievable rather than maximumperformance levels. The overall goalstherefore represent reasonablyachievable emission performance levelsthat provide states with flexibility topursue some building blocks moreextensively and others less extensivelythan the degree reflected in the EPA’sdata inputs while meeting the overallgoals. States can also choose to includein their plans other measures thatreduce CO2 emissions at affected EGUsbut that are not included in the buildingblocks.

Further, by allowing states todemonstrate emission performance byaffected EGUs on an average basis overa multi-year interim plan period of aslong as ten years, the EPA’s proposedapproach increases states’ flexibility tochoose among alternative potential planmeasures. for example, by takingadvantage of the multi-year flexibility, astate could choose to rely more heavilyin its plan on measures whoseeffectiveness tends to grow over time,such as demand-side energy efficiencyprograms. This flexibility could alsohelp states address concerns aboutstranded assets, for example, byenabling states to defer imposition ofrequirements on EGUs that may bescheduled to retire after 2020 but before2029.

The second type of flexibility notedabove is that while the EPA is proposingto establish goals in an emission rate-based form, we are also proposing toprovide states with the flexibility totranslate the rate-based goals to mass-based goals in order to accommodatestates’ potential interest in havingemission performance requirementsmeasured in absolute tons. For example,the northeastern and Mid-Atlantic statesthat currently participate in the mass-based Regional Greenhouse GasInitiative (RGGI) may choose to developstate plans (or a multi-state plan, asnoted below) establishing mass-basedemission performance levels designed tobe met at least in part through standardsof performance based on RGGI’s existingmarket-based CO2 emission budgettrading program. Because the use ofmass-based plans can simplify theprocess of accounting for the CO2reduction impacts of a variety ofmeasures, the EPA believes theflexibility to adopt mass-based emissionperformance levels can facilitate plan

development and could be attractive tostates that do not already participate inmass-based emission reductionprograms as well.

Third, the EPA’s approach allowsstates to submit multi-state plans. TheEPA expects this flexibility to reducethe cost of achieving the state goals andtherefore expects it to be attractive tostates. For example, the RGGIparticipating states could choose tosubmit a multi-state mass-based planthat demonstrates emission performanceby affected EGUs on a multi-state basis.Additional states may also choose tojoin a multi-state plan. The mechanicsof translating rate-based goals into mass-based goals and considerations relatedto multi-state plans are discussed belowin Section Vffi on state plans.

Some stalceholders have suggestedthat states themselves should beallowed to quantify the level ofemission reduction resulting from theapplication of BSER or, lithe EPAestablishes goals, the states should beallowed to adjust the goals or to treat thegoals established by the EPA as advisoryrather than binding. Consistent with theexisting implementing regulations forCAA section 111(d) at 40 CFR part 60,this quantification is the EPA’s role.266

As discussed in the LegalMemorandum, CAA section 111(d)directs the EPA to “prescriberegulations which shall establish aprocedure similar to that provided by[CAA section 1101 under which eachState shall submit” a section 111(d)state plan. As noted in Section ll.D ofthis preamble, the EPA promulgatedimplementing regulations in 1975, andhas revised parts of them since. Theregulations set out a multi-step processfor the development and approval ofstate plans, and assign responsibility forthe various steps in the process to theEPA or the states. The regulationsprovide that the EPA is to promulgatean “emission guideline that reflects theapplication of the best system ofemission reduction (considering the costof such reduction) that has beenadequately demonstrated for” affectedsources.267 In this manner, theregulations make clear that the EPAdetermines the BSER. In thisrulemaking, as discussed above, theEPA identifies the BSER. In addition, inthis rulemaking, the EPA applies theBSER to each state, and then, for eachstate, calculates the average emissionrate that, in the words of the regulationsjust quoted, “reflects the application of

26640 CFR 60.22(b)f5). We do not propose to reopen that portion of the implementing regulationsin this rulemaking.

267 Id



the [BSER].” That average emission rateis the state goal.

By the same token, because the stategoals are an integral part of the emissionguidelines that the frameworkregulations authorize the EPA toestablish, the goals are binding, and thestates, in their CAA section 111(d)plans, must meet those goals and maynot make them less stringent. Thismatter, too, is resolved by theimplementing regulations.268 Toreiterate, the proposed state goalsrepresent the level of performance thatis achievable through application of theBSER to the pertinent data for eachindividual state. States have theopportunity to comment on theproposed BSER, the proposedmethodology for computing state goalsbased on application of the BSER, andthe state-specific data that is proposedfor use in the computations. We expectthat the states will have an adequateopportunity to comment on the stategoals during the comment period. Oncethe final goals have been promulgated,and adjusted as may be appropriatebased on comments to address anyfactual errors in the analysis, the stateswill be able to meet them because theywill represent the application of BSERto the states’ affected sources. Inaddition, states have several types offlexibilities in developing their stateplans: They have flexibility regardingthe selection of the measures uponwhich they choose to rely and a 10-yeartime period over which to reach fullimplementation of these measures, andthey can use rate-based or mass-basedapproaches. In addition, as we havenoted, multi-state coordination offersstates an opportunity to achieveadditional emission reductions andreduce implementation costs. Theseflexibilities, discussed further in SectionVifi of this preamble, ensure that stateswill be able to achieve their final CO2emission performance goals and that nospecial provision for state adjustment ofgoals outside the normal notice-and-comment rulemaking process iswarranted.269

F. Alternate Goals Offered for Commentand Other Approaches Considered

in addition to the proposed state-specific emission rate-based goalsdescribed above, the EPA has developedfor public comment an alternate set of

268Id. We do not propose to re-open that portion

of the implementing regulations in this rulemaking.269In the event that a state becomes concerned

about its ability to meet the goal that the EPApromulgates for it, the state may submit to the EPAa petition for reconsideration, if that petition isbased on relevant information not available duringthe comment period. See CAA section 307(d)(7)(B).

goals reflecting less stringentapplication of the building blocks and ashorter implementation period. Thealternate final goals represent emissionperformance that would be achievableby 2025, after a 2020—2024 phase-inperiod, with interim goals that wouldapply during the 2020—2024 period ona cumulative or average basis as statesprogress toward the final goals.

Because the time period forimplementation relates directly to theemission reductions that are achievableand therefore what measures, and atwhat level of stringency, constitute theBSER, the alternate goals reflect severaldifferences in data inputs from theproposed goals. Specifically, a value offour percent (instead of six percent) wasused for the potential improvement incarbon intensity of coal-fired EGUs inStep 2; a value of 65 percent (instead of70 percent) was used for the potentialannual utilization rate of NGCC units inStep 3; and a value of one percent(instead of 1.5 percent) was used for theannual incremental electricity savingsachievable through a portfolio ofdemand-side energy efficiency programsin Step 5. (No change was made to thedata inputs regarding less carbon-intensive generating capacity in Step 4.)As noted above, the alternate goals alsoreflect a shortening of the proposedphase-in period from ten years (2020—2029) to five years (2020—2024) to reflectan expectation that less stringent goalscould be achieved in less time. Steps 5,6, and 7 of the goal computationprocedure therefore were performed forthe span of years from 2020 to 2024rather than for the span from 2020 to2029. The alternate goals are set forth inTable 9 below.

TABLE 9—ALTERNATE 270

GOALS


State Interim Finalgoal goal

TABLE 9—ALTERNATE 270

GOALS—Continued


s Interim Finaltate goal goal

Louisiana 1,052 1,025Maine 418 410Maryland 1,518 1,440Massachusetts 715 683Michigan 1,349 1,319Minnesota 1,018 999Mississippi 765 743Missouri 1,726 1,694Montana 2,007 1,960Nebraska 1,721 1,671Nevada 734 713New Hampshire 598 557New Jersey 722 676New Mexico* 1,214 1,176New York 736 697North Carolina 1,199 1,156North Dakota 1,882 1,870Ohio 1,588 1,545Oklahoma 1,019 986Oregon 450 420Pennsylvania 1,316 1,270Rhode Island 855 840South Carolina 930 897South Dakota 888 861Tennessee 1,363 1,326Texas 957 924Utah* 1,478 1,453Virginia 1,016 962Washington 312 284West Virginia 1,858 1,817Wisconsin 1,417 1,380Wyoming 1,907 1,869

The EPA recognizes that its approachto the alternate goals, comprising lessstringent requirements in each of thebuilding blocks to be achieved over ashorter compliance horizon, follows thelogic of including time as one of thefunctions of the BSER determination. Atthe same time, we also recognize thatthe components of the alternate goalsmay reflect an overly conservativeapproach. Specifically, the alternategoals as set forth above mayunderestimate the extent to which thekey elements of the four buildingblocks—achieving heat rateimprovements at EGUs, switchinggeneration to NGCC facilities, fosteringthe penetration of renewable resourcesor improving year-to-year end-useenergy efficiency—can be achievedrapidly while preserving reliability andremaining reasonable in cost.Accordingly, we request comment onthe alternate goals, particularly withrespect to whether any one or all of thebuilding blocks in the alternate goals

270 See footnote accompanying Table a above.

* Excludes EGUs located in Indian countryin the state.

AlabamaAlaskaArizona *

ArkansasCaliforniaColoradoConnecticutDelawareFloridaGeorgiaHawaiiIdahoIllinoisIndianaIowaKansasKentucky

1,2701,170

7791,083

5821,265

6511,007

907997

1,446261

1,5011,7151,4361,6781,951

1,2371,131

7631,058

5711,227

627983884964

1,417254

1,4571,6831,4171,6251,918



can be applied at a greater level ofstringency: Can the heat rateimprovement value be set at a levelabove four percent, even six percent?Can NGCC capacity be dispatched at autilization rate above 65 percent? Canannual incremental electricity savingsbe achieved at a rate higher than onepercent?

It is worth noting that the EPAprojects that the alternate goals willachieve emission reductions equal to 23percent below 2005 level in 2025. TheEPA’s analysis shows that under theproposed goals described in SectionVfl.C above, power sector emissions willbe 29 percent below 2005 levels in 2025,suggesting that the kinds of changescontemplated in the four buildingblocks, even as early as 2025, will beyielding reductions far greater than the23 percent projected for the alternategoals as set forth above in thissubsection.

The EPA has considered otherapproaches to setting goals. Inparticular, given the interconnectednature of the power sector and theimportance of opportunities for shiftinggeneration among EGUs, we consideredwhether goals should be set on a multistate basis reflecting the scope ofexisting regional transmission controlareas. We also considered whether goalsshould be set on a state-specific basis,but regional rather than state-specificevaluations should be used to assess theestimated opportunities to reduceutilization of the most carbon-intensiveEGUs by shifting generation to lesscarbon-intensive EGUs. A potentialadvantage of using regional evaluationsis the ability to recognize additionalemission reduction opportunities thatwould be available at reasonable costsbased on a more completerepresentation of the capabilities ofexisting infrastructure to accommodateshifts in generation among EGUs inmultiple states. We request comment onwhether, and if so how, the EPA shouldincorporate greater consideration ofmulti-state approaches into the goal-setting process, and on the issue ofwhether, and if so how, the potentialcost savings associated with multi-stateapproaches should be considered inassessing the reasonableness of the costsof state-specific goals.

F. Reliable Affordable ElectricityMany stakeholders raised concerns

that this regulation could affect thereliability of the electric power system.The EPA agrees that reliability must bemaintained and in designing thisproposed rulemaking has paid carefulattention to this issue. The EPA has meton several occasions with staff and

managers from the Department ofEnergy and the federal EnergyRegulatory Commission to discuss ourapproach to the rule and its potentialimpact on the power system. EPA staffand managers have also had numerousdiscussions with state public utilitycommissioners and their staffs to gettheir suggestions and advice concerningthis rule, including how to addressreliability concerns.

In addition, the EPA met withindependent system operators severaltimes to discuss any potential impact ofthis rule on grid reliability. The ISO!RTO Council, a national organization ofelectric grid operators, offered analyticsupport to help states design programsthat do not compromise the regionalbulk power system. They also offered tohelp states develop regional approacheswhich may reduce costs and strengthenthe reliability of the electricity grid.Specifically, the ISO/RTO Council hassuggested that ISOs and RTOs couldprovide analytic support to help statesdevelop and implement their plans. TheISOs and RTOs have the capability tomodel the system-wide effects ofindividual state plans. Providingassistance in this way, they felt, wouldallow states with borders that fall withinan ISO or RTO footprint to assess thesystem-wide impacts of potential stateplan approaches. In addition, as thestate implements its plan, ISO/RTOanalytic support would allow the stateto monitor the effects of its plan on theregional electricity system. ISO/RTOanalytic capability could help statesassure that their plans are consistentwith region-wide system reliability. TheISO/RTO Council suggested that theEPA ask states to consult with theapplicable ISO/RTO in developing theirstate plans. The EPA agrees with thissuggestion and encourages states withborders that fall within one or more ISOor RTO footprints to consult with therelevant ISOs/RTOs.

The EPA has met with the U.S.Department of Agriculture as well todiscuss how we can address theconcerns of small, relatively isolatedpower generators in rural America andespecially the electric cooperatives.Many of these entities have specialchallenges, as they may have small,older carbon-intensive assets and mighthave particular challenges meetingcarbon requirements.

With all of this in mind, the EPA indetermining the BSER lookedspecifically at the reasonableness of thecosts of control options in part to ensurethat the options would not have anegative effect on system reliability. TheBSER, including each of the buildingblocks, was determined to be feasible at

reasonable costs over the timeftameproposed here. Further, under the CleanAir Act the states are given theflexibility to design state plans thatinclude any measure or combination ofmeasures to achieve the requiredemission limitations. States are notrequired to use each of the measuresthat the EPA determines constitute theBSER or use those measures to the samedegree or extent that the EPAdetermines is feasible at a reasonablecost. Thus, each state has the flexibilityto choose the most cost-effectivemeasures given that state’s energyprofile and economy, as long as the stateachieves the reductions necessary tomeet its goal. Many market-basedapproaches which states may choosereduce the costs of compliance. Theycan allow certain units that are seldomused to remain in operation if they areneeded for reliability purposes. Multistate approaches also reduce costs andstress on the grid and so can help toreduce any concern about electricityreliability.

States may choose measures thatwould ease pressures on systemreliability. This is true for manydemand-side management approaches,including programs to encourage end-use energy efficiency, distributedgeneration, and combined heat andpower, which actually reduce demandfor centrally generated power and thusrelieve pressure on the grid.

The EPA is proposing a 10-yearperiod over which to achieve the fullrequired CO2 reductions, and we wouldexpect this to further relieve anypressure on grid reliability. Thisrelatively long planning andimplementation period provides stateswith substantial flexibility regardingmethods and timing of achievingemission reductions.

The EPA’s supporting analysis for thisrule includes an examination of theeffects of the rule on regional resourceadequacy.27’ The EPA’s analysis lookedat the types of changes in the generationfleet that were projected to occurthrough retirements, additionalgeneration and energy efficiency. Theanalysis did not raise concerns overregional resource adequacy. The EPAfurther examined how the policyoptions impacted the flows andtransfers of electricity that occur to meetreserve margins. None of theinterregional changes in the policy casessuggested that there would be increasesin flows that would raise significantconcerns about grid congestion or gridmanagement. Moreover, the thne

271 See the Resource Adequacy and ReliabilityAnalysis TSD, available in the docket.



horizon for compliance with this rulewill permit environmental andreliability planners to coordinate thesechanges and address potential concernsbefore they arise.

The EPA concludes that the proposedrule will not raise significant concernsover regional resource adequacy or raisethe potential for interregional gridproblems. The EPA believes that anyremaining local issues can be managedthrough standard reliability planningprocesses. The flexibility inherent in therule is responsive to the CAA’srecognition that state plans for emissionreduction can, and must, be consistentwith a vibrant and growing economyand reliable, affordable electricity tosupport that economy. The EPAwelcomes comments and suggestions onthis issue.

Vffl. State Plans

A. Overview

After the EPA establishes the state-specific rate-based CO2 goals in theemission guidelines, as described inSection VII above, each state must thendevelop, adopt, and submit its state planunder CAA section 111(d). To do so, thestate must first determine the emissionperformance level it will include in itsplan, which entails deciding whether itwill adopt the rate-based CO2 goal set bythe EPA or translate the rate-based goalto a mass-based goal.

The state must then establish anemission standard or set of emissionstandards, and, perhaps other measures,along with implementing and enforcingmeasures, that will achieve a level ofemission performance that is equal to orbetter than the level specified in thestate plan.

The state must then adopt the stateplan through certain procedures, whichinclude a state hearing. Within the timeperiod specified in the emissionguidelines (from as early as June 30,2016 to as late as June 30, 2018,depending on the state’s circumstances),the state must submit its complete stateplan to the EPA. The EPA then mustdetermine whether to approve ordisapprove the plan. If a state does notsubmit a plan, or if the EPA does notapprove a state’s plan, then the EPAmust establish a plan for the state.

As discussed in Section V.D of thispreamble, in the case of a tribe that hasone or more affected EGUs located in itsarea of Indian country, if the EPAdetermines that a CAA section 111(d)plan is necessary or appropriate, theEPA has the responsibility to establisha CAA section 111(d) plan for that areaof Indian country where affectedsources are located unless the tribe on

whose lands an affected source (orsources) is located seeks and obtainsauthority from the EPA to establish aplan itself, pursuant to the TribalAuthority Rule.22 The agency issoliciting comment on aspects of suchCAA section 111(d) plans, as describedin Section VI) of this preamble.

This section is organized into sixparts. First, we discuss the types ofplans that we propose states couldsubmit. Second, we address timing forplan implementation and achievementof state emission performance goals foraffected EGUs. Third, we discuss theproposed state plan approvabilitycriteria. Fourth, we summarize theproposed components of an approvablestate plan. Fifth, we address theproposed process and timing forsubmittal of state plans. Sixth, weidentify several key considerations forstates in developing and implementingplans, including: Affected entities withobligations under a plan; treatment ofexisting state programs; incorporation ofrenewable energy (RE) and demand-sideenergy efficiency (EE) programs incertain plans; quantification,monitoring, and verification of RE anddemand-side EE measures; reportingand record]ceeping for affected entities;treatment of interstate effects; andprojection of emission performance.Finally, we discuss a number ofadditional factors that could help statesmeet their CO2 emission performancegoals, and we note certain resources thatare available to facilitate plandevelopment and implementation.Additional discussion of some of thetopics covered in this section can befound in the State Plan ConsiderationsTSD and Projecting EGU CO2 EmissionPerformance in State Plans TSD, both ofwhich are in the rulemaking docket.

B. Approach

In this action, the EPA is proposingemission guidelines in the form of state-specific CO2 emission performancegoals. In addition, the EPA is proposingguidelines for states to follow indeveloping plans to establish andimplement CO2 emission standards foraffected EGUs. The proposed planguidelines include four general planapprovability criteria, twelve requiredcomponents for a state plan to beapprovable, the process and timing forstate plan submittal and review, and theprocess and timing for demonstratingachievement of the CO2 goals. These aredescribed below.

The EPA recognizes that each statehas different state policyconsiderations—including varying

272 40 CFR 49.1 to 49.11.

emission reduction opportunities andexisting state programs and measures—and that the characteristics of theelectricity system in each state (e.g.,utility regulatory structure, generationmix, electricity demand) also differ. Theagency also anticipates—and supports—states’ commitments to a wide range ofpolicy preferences that couldencompass those of states likeKentucky, West Virginia and Wyomingseeking to continue to feature significantreliance on coal-based generation; stateslike Minnesota, Colorado, California andthe nine RGGI states seeking to build onactions and policies they have alreadyundertaken; and states like Washingtonand Oregon seeking to integratesustainable forestry and renewableenergy strategies. The proposed planguidelines provide states with optionsfor establishing emission standards in amanner that accommodates a diverserange of state approaches. Each statewill have significant flexibility todetermine how to best achieve its CO2goals in light of its specificcircumstances, including addressingconcerns particular to the state, such asemployment transition issues, as ftdesigns and implements its plan overmultiple years. As an example, the RGGIstates’ implementation of their mass-based emission budget trading programraises proceeds through allowanceauctions and uses those proceeds toadvance programs promoting andexpanding end-use energy efficiency.States could address analogouspriorities, such as employmenttransition, through a similarmechanism.

The proposed plan guidelines wouldalso allow states to collaborate and todevelop plans that provide fordemonstration of emission performanceon a multi-state basis, in recognition ofthe fact that electricity is transmittedacross state lines, and that statemeasures may impact, and may beexplicitly designed to reduce, regionalEGU CO2 emissions. The EPA alsorecognizes that multi-state collaborationwould likely offer lower-costapproaches to achieving CO2 emissionreductions. With this in mind, we areproposing to provide states withadditional time to submit completeplans if they do so as part of a multistate plan, and we solicit comment onother potential mechanisms for fosteringmulti-state collaboration.

1. State Plan Approaches

a. Overview

Although state CAA section 111(d)plans must assure that the emissionperformance level is achieved through



reductions at the affected sources, webelieve that different types of state planscould be constructed that make use ofthe diversity of measures available toachieve CO2 emission reductions. Basedon the EPA’s outreach efforts, it is clearthat states are considering differenttypes of plans.

Three important issues in the designof state plans include: (1) Whether theplan should require the affected EGUs tobe subject to emission limits that assurethat the emission performance level isachieved, or instead, whether the plancould rely on measures, such asrenewable energy (RE) or demand-sideenergy-efficiency (EE), to assure theachievement of part of the emissionperformance level; (2) whether theresponsibility for all of the measuresother than emission limits should fallon the affected EGUs, or, instead, couldfall on entities other than affected EGUs;and (3) whether the fact that requiringall measures relied on to achieve theemission performance level to beincluded in the state plan renders thosemeasures federally enforceable. Theseissues and the EPA’s proposed approachare addressed in detail in the sectionsthat follow.

The EPA is proposing that allmeasures relied on to achieve theemission performance level be includedin the state plan, and that inclusion inthe state plan renders those measuresfederally enforceable.

In light of current state programs, andof stakeholder expressions of concernsover the above-noted issues, includinglegal enforcement considerations, withrespect to those programs, the EPA isproposing to authorize states either tosubmit plans that hold the affectedEGUs fully and solely responsible forachieving the emission performancelevel, or to submit plans that rely in parton measures imposed on entities otherthan affected EGUs to achieve at leastpart of that level, as well as on measuresimposed on affected EGUs to achievethe balance of that level. The EPArequests comment on this proposedapproach, as opposed to the approachunder which state plans simply wouldbe required to hold the affected EGUsfully and solely responsible forachieving the emission performancelevel.

In addition, the EPA is solicitingcomment on several other types of stateplans that may assure the requisite levelof emission performance withoutrendering certain types of measuresfederally enforceable and that limit theobligations of the affected EGUs.

b. Portfolio ApproachIn assessing the types of state plans to

authorize, the EPA reviewed existingstate programs that reduce CO2emissions from fossil fuel-fired powerplants. Existing state programs areparticularly informative for this purposein light of the fact that CAA section111(d) gives states the primaryresponsibility for designing their ownstate plans for submission to the EPA.Many of these existing state programs,as summarized above, include measuressuch as renewable energy (RE) anddemand-side energy efficiency (EE)programs, which impose responsibilitieson a range of entities, including stateagencies, for assuring implementation ofactions that result in reduced utilizationof, and therefore reduced emissionsfrom, fossil fuel-fired EGUs, and do notimpose legal responsibilities for thoseemission reductions on the EGUsthemselves.

In addition, during the EPA’sextensive outreach efforts, manystakeholders expressed concern over theextent of responsibility that fossil fuel-fired EGUs would be required to bear forthe required emission reductions, inparticular, those associated with RE anddemand-side EF measures. Thesestakeholders recommended that the EPAauthorize states to achieve emissionreductions from RE and demand-side FEmeasures by imposing requirements onentities other than fossil fuel-firedEGUs, and without imposing legalresponsibility for these emissionreductions on those EGUs.

Accordingly, the EPA is proposing toauthorize a state plan to adopt what werefer to as a “portfolio approach,” inwhich the plan would include emissionlimits for affected EGUs along withother enforceable measures, such as REand demand-side EE measures, thatreduce CO2 emissions from affectedEGUs. Under this approach, it would beall of the measures combined thatwould be designed to achieve therequired emission performance level foraffected EGUs as expressed in the stategoal. Under this approach, the emissionlimits enforceable against the affectedEGUs would not, on their own, assure,or be required to assure, achievement ofthe emission performance level. Rather,the state plan would include measuresenforceable against other entities thatsupport reduced generation by, andtherefore CO2 emission reductions from,the affected EGUs. As noted, these othermeasures would be federallyenforceable because they would beincluded in the state plan. A portfolioapproach could be used for state plansthat establish the emission performance

level on either an emission rate basis ora mass emissions basis.

In addition, a portfolio approachcould either be what we refer to as“utility-driven” or “state-driven,”depending on the utility regulatorystructure in a state. Under a utility-driven approach, a state plan mayinclude, for example, measuresimplemented consistent with a utilityintegrated resource plan, including bothmeasures that directly apply to affectedEGUs (e.g., repowering or retirement ofone or more EGUs) as well as RE anddemand-side EE measures that avoidEGU CO2 emissions.273 Under a state-driven approach, the measures in a stateplan would include emission standardsfor affected EGUs, as well asrequirements that apply to entities otherthan affected EGUs, for example,renewable portfolio standards (RPS) orend-use energy efficiency resourcestandards (EERS), both of which oftenapply to electric distribution utilities.2

c. Obligations on Affected EGUsThe EPA is proposing to authorize

state plans to adopt the portfolioapproach and is proposing to interpretthe CAA as allowing that approach, asdescribed in more detail below. CAAsection lii(d)(i) would certainly allowstate plans to require the affected EGUsto be the sole entities legally responsiblefor achieving the emission perfonnancelevel. The EPA is also solicitingcomment on whether it can reasonablyinterpret CAA section 111(d)(1) to allowstates to adopt plans that require EGUsand other entities to be legallyresponsible for actions required underthe plan that will, in aggregate, achievethe emission performance level.

We note that some existing stateprograms, such as RGGI in thenortheastern states, do impose theultimate responsibility on fossil fuel-fired EGUs to achieve the requiredemission reductions, but are alsodesigned to work either concurrently, orin an integrated fashion, with RE anddemand-side EE programs that reducethe cost of meeting those emissionlimitations. These existing programsoffer a possible precedent for anothertype of CAA section 111(d) state plan.Such a plan approach could rely on CO2emission standards enforceable againstaffected EGUs—whether in the form of

2731n the case of a utility-driven portfolioapproach, the vertically integrated electric utilityimplementing portfolio measures is also the ownerand operator of affected EGUs.

274A state-driven portfolio approach is morelikely in states that have instituted electricity sectorrestructuring, where electric utilities have typicallybeen required by states to divest electric generatingassets.



emission rate or mass limits—to ensureachievement of the required emissionperformance level, but also includeenforceable or complementary RE anddemand-side EE measures that lowercost and otherwise facilitate ECUemission reductions. Depending on thetype of plan, these RE and demand-sideEE measures could either be enforceablecomponents of the plan (that is, thestates could require affected EGUs orother affected entities to invest in RE orin demand-side EE programs) or becomplementary to the plan. In thismanner, RE and demand-side EEmeasures could be a major componentof a state’s overall strategy for reducingECU CO2 emissions at a reasonable cost.

It should be noted that state planapproaches that impose legalresponsibility on the affected EGUs toachieve the full level of requiredemission performance could incorporateRE and demand-side EE measuresregardless of whether the emissionstandards that those plans apply to theaffected ECUs take the form of anemission rate or a mass limit. Plans withrate-based emission limits couldincorporate enforceable RE anddemand-side FE measures by adjustingan ECU’s CO2 emission rate whendemonstrating compliance througheither an administrative adjustment bythe state or use of a tradable creditapproach. (These actions would need tobe enforceable components of a stateplan to facilitate ECU compliance withemission rate limits and ensure thatactions are properly quantified,monitored, and verified.) A state planthat imposes a mass limit on affectedEGUs that is sufficiently stringent toachieve the emission performance levelwould not need to include RE ordemand-side EE measures as anenforceable component of the plan toassure the achievement of thatperformance eve1. The mass limit itselfwould suffice. However, the state maywish to implement RE and demand-sideEE measures as a complement to theplan to support achievement of the masslimit at lesser cost.

d. Federal EnforceabilityAnother concern expressed by some

stakeholders is that including RE anddemand-side FE measures in state planswould render those measures federallyenforceable and thereby extend federalpresence into areas that, to date, largelyhave been the exclusive preserve of thestate and, in particular, state publicutility conunissions and the electricutility companies they regulate. Thesestakeholders suggest that states couldrely on RE and demand-side EEprograms as complementary measures to

reduce costs for, and otherwisefacilitate, ECU emission limits withoutincluding those measures in the CAAsection 111(d) state plan. Under thissuggested approach, the ECU emissionlimits would be federally enforceable,but RE and demand-side EF measureswould serve as complementarymeasures and would not be enforceableunder federal law; instead, they wouldremain enforceable under state law.According to stakeholders, those typesof state programs, particularly becausethey are well-established, can beexpected to achieve their intendedresults. Thus, they suggest that thestates could conclude that those RE anddemand-side FE measures would bebeneficial in assuring the achievementof the required emission performancelevel by the affected ECUs specified inthe CAA section 111(d) state plan, evenwithout including those measures in theplan.

e. Plans With State CommitmentsAs another vehicle for approving CAA

section 111(d) plans for states that wishto rely on state RE and demand-side EFprograms but do not wish to includethose programs in their state plans, theEPA requests comment on what we referto as a “state commitment approach.”This approach differs from the proposedportfolio approach, described above, inone major way: Under the statecommitment approach, the staterequirements for entities other thanaffected EGUs would not be componentsof the state plan and therefore wouldnot be federally enforceable. Instead, thestate plan would include an enforceablecommitment by the state itself toimplement state-enforceable (but notfederally enforceable) measures thatwould achieve a specified portion of therequired emission performance level onbehalf of affected ECUs. The agencyrequests comment on theappropriateness of this approach. Theagency also requests comment on thepolicy ramifications of the following:Under this approach, the state programsupon which the state bases itscommitment may, in turn, rely oncompliance by third parties, and if thosestate programs fail to achieve theexpected emission reductions, the statecould be subject to challenges—including by citizen groups—forviolating CAA requirements and, as aresult, could be held liable for CAApenalties.

We also solicit comment on avariation of this state commitment planapproach that is also designed toaddress stakeholder concerns, notedabove, about imposing sole legalresponsibility on affected ECUs for

achieving the emission performancelevel. With this variation, the state planwould in effect shift a portion of thatresponsibility to the state, in thefollowing manner: The state plan wouldimpose the full responsibility forachieving the emission performancelevel on the affected EGUs, but the statewould credit the ECUs with the amountof emission reductions expected to beachieved from, for example, RE ordemand-side EE measures. The statewould then assume responsibility forthat credited amount of emissionreductions in the same manner as thestate commitment plan approachdiscussed above. We solicit comment onwhether, if the EPA were to concludethat CAA section 111(d) requires stateplans to include standards ofperformance applicable to affectedECUs that achieve the emissionperformance level, this type of stateplan would meet that requirement whilealso assuring those ECUs an importantmeasure of support.

f. Legal Issues

The EPA is proposing to interpret therelevant provisions in CAA section 111to authorize state plans that achieveemissions reductions from affectedECUs by means of the portfolioapproach. CAA section 111(d)(1)requires each state to submit a plan that“(A) establishes standards ofperformance for any existing source [forcertain air pollutants]. . . and (B)provides for the implementation andenforcement of such standards ofperformance.” CAA section 111(a)(1)defines a “standard of performance” as“a standard for emissions of airpollutants which reflects the degree ofemission limitation achievable throughthe application of the best system ofemission reduction. . . adequatelydemonstrated.”

These provisions make clear thatemission limits that are enforceableagainst affected EGUs appropriatelybelong in state plans because theyclearly are “standards of performance.”However, the terms of CAA sectionill(d)(1) do not explicitly addresswhether, in addition to emission limitson affected ECUs, state plans mayinclude other measures for achievingthe emission performance leveL Nor dothey address whether entities other thanaffected ECUs may be subject torequirements that contribute to reducingECU emissions. Under the U.S.Supreme Court’s 1984 decision inChevron U.S.A. Inc. v. NRDC, where thestatute leaves a gap, the agency hasdiscretion to fashion an interpretation



that is a reasonable construction of thestatute.275

The EPA is proposing to rnterpret thephrases “standards of performance forany existing source” and “theimplementation and enforcement ofsuch standards of performance” toencompass and allow the variouscomponents of the portfolio approach.To the extent that a portfolio approachcontains measures that are not standardsof performance or do not implement orenforce such standards, the EPA isproposing to interpret CAA section 111as allowing state CAA section 111(d)plans to include measures that areneither standards of performance normeasures that implement or enforcethose standards, provided that themeasures reduce CO2 emissions fromaffected sources. These measures wouldalso be federally enforceable if includedin an approved plan.

The EPA’s proposed interpretation isbased, in part, on CAA section 111(d)’srequirement that states set performancestandards “for” affected sources.Although “for” could be read asmeaning that the standards must applyto affected sources, “for” is alsoreasonably interpreted to have a morecapacious meaning: Standards (such asEE and RE standards) are reasonablyconsidered to be “for” affected sourcesif they would have an effect on affectedsources by, for example, causingreductions in affected EGUs’ CO2emissions by decreasing the amount ofgeneration needed from affected EGUs.Under this interpretation, anddepending on the specific provisions inthe state plan, renewable energy anddemand-side energy efficiencyrequirements would be “for” fossil fuel-fired EGUs where such standards resultin reduced CO2 emissions from fossilfuel-fired EGUs, even if the standards donot apply directly to fossil fuel-firedEGUs.

The EPA also requests comment onanother approach: Whether “standardsof performance for [affected sourcesi” isreasonably read to include the emissionperformance level (i.e., the state goal) ongrounds that the level is “a standard foremissions” because it is in the nature ofa requirement that concerns emissionsand it is “for” the affected sourcesbecause it helps determine theirobligations under the plan.

Moreover, where the specificmeasures in the portfolio approach arenot themselves a “standard ofperformance,” state plans may includemeasures that implement or enforce astandard of performance. For example,

2Chewon U.S.A., Inc. v. NRDC, 467 U.s. 837,842—44 (1984).

if the state’s plan achieves the emissionperformance level through rate-basedemission limits applicable to theaffected sources, coupled with acrediting mechanism for RE anddemand-side EE measures, we proposethat RE and demand-side EE measuresmay be included in the plan as“implement[ing]” measures becausethey facilitate the sources’ compliancewith their standards of performance. Wesolicit comment on the extent to whichmeasures such as RE and demand-sideEE may be considered “implement[ing]”measures in state plans if they are notdirectly tied to emission reductions thataffected sources are required to makethrough emission limits, and if they arerequirements on entities other than theaffected sources. In addition, the EPAproposes to interpret CAA sectionili(d)(i) to allow state plans to includecomponents of the portfolio approachthat are measures that would reduceemissions from affected sources, even ifthose measures are neither “standards ofperformance for existing sources” normeasures “for the implementation andenforcement of such standards ofperformance.” There is no specificlanguage in CAA section 111(d) orelsewhere in the Act that prohibitsstates from including measures otherthan performance standards andimplementation and enforcementmeasures, provided that they reduceemissions from affected EGUs.

This interpretation is consistent withthe principle of cooperative federalism,which is one of the foundationalprinciples of the Clean Air Act andwhich supports providing flexibility tostates to meet environmental goals(provided minimum CAA statutoryrequirements are met). This generalprinciple, especially when combinedwith the statutory directive that CAAsection 111(d) regulations shallestablish procedures “similar to thatprovided by section 110,” supports aninterpretation of CAA section 111(d)that allows states sufficient flexibility inmeeting the state goal set under CAAsection 111(d) to include in their CAAsection 111(d) plans other measures(i.e., measures that are neitherperformance standards nor measuresthat enforce or implement performancestandards). The EPA solicits commenton all aspects of its proposedinterpretation that states have thisflexibility in selecting measures for theirstate plans under CAA section 111(d).

An alternative interpretation of CAAsection 111(d) (1) would suggest that theresponsibility to achieve the state’srequired emission performance levelmust be assigned solely to affectedEGUs. As described elsewhere in this

preamble, there are a number of state-level CO2 programs that take thisapproach while still taking advantage oflow-cost reductions from RE anddemand-side EE through the use ofcomplementary measures. Thisalternative interpretation would bebased on, for example: A determinationthat CAA section 111(d)(1) must be readas precluding a state plan fromincluding measures that are neitherstandards of performance nor measuresfor the implementation or enforcementof such standards; an interpretation thatthe state’s obligation to set performancestandards “for” existing sources meansthat the standards must apply toaffected EGUs and not to other entities;and an interpretation that measures “forthe implementation and enforcement ofsuch performance standards” do notinclude measures that are not intendedor designed to assist affected EGUs inmeeting the performance standards. TheEPA requests comment on whether itmust adopt this alternativeinterpretation, if so, the EPA also takescomment on whether there is a way,nonetheless, to allow states to rely onthe portfolio approach to some extentand/or for some period of time.

We request comment on all of theinterpretations discussed in this sectiongenerally, and on all legal issues underCAA section lil(d)(1) with respect towhat measures can be included in astate plan and what entities must belegally responsible for meeting thosemeasures.

g. Ongoing Applicability of CAASection 111(d) State Plan

The EPA is proposing that an existingsource that becomes subject torequirements under CAA section 111(d)will continue to be subject to thoserequirements even after it undertakes amodification or reconstruction. Underthis interpretation, a modified orreconstructed source would be subjectto both (1) the CAA section 111(d)requirements that it had previously beensubject to and (2) the modified source orreconstructed source standard beingpromulgated under CAA section 111(b)simultaneously with this rulemaking. Itshould be noted that this proposalapplies to any existing source subject toany CAA section 111(d) plan, and notonly existing sources subject to the CAAsection 111(d) plans promulgated underthis rulemaking.

As noted above, a “new source” isdefined under CAA section 111(a)(2) as“any stationary source, the constructionor modification of which is commencedafter,” in general, a proposed or finalCAA section 111(b) rule becomesapplicable to that source; and under



section 111(a)(6), an “existing source” isdefined as “any stationary source otherthan a new source.” Under thesedefinitions, an “existing source” thatcommences construction of amodification or reconstruction after theEPA has proposed or finalized a CAAsection 111(b) standard of performanceapplicable to it, becomes a “newsource.” However, CAA section 111(d)is silent on whether requirementsimposed under a CAA section 111(d)plan continue for a source that ceases tobe an existing source because itmodifies or reconstructs. Specifically,CAA section iii(d)(i) provides that“each State shall submit to theAdministrator a state plan which (A)“establishes standards of performancefor any existing source” but does not saywhether, once the EPA has approved astate plan that establishes a standard ofperformance for a given source, thatstandard is lifted if the source ceases tobe an existing source. Similarly, noother provisions of CAA section 111address whether the imposition of aCAA section 111(b) standard on amodified or reconstructed source endsthe source’s obligation to meet anyapplicable CAA section 111(d)requirements.

Because CAA section 111(d) does notaddress whether an existing source thatis subject to a CAA section 111(d)program remains subject to that programeven after it modifies or reconstructs,the EPA has authority to provide areasonable interpretation, under theSupreme Court’s decision in ChevronU.S.A. Inc. v. NRDC, 467 U.S. 837, 842—844 (1984). The EPA’s interpretation isthat under these circumstances, thesource remains subject to the CAAsection 111(d) plan, for two reasons.The first is to assure the integrity of theCAA section 111(d) plan. The EPAbelieves that many states will developintegrated plans that include all of theirEGUs, such as rate- or mass-basedtrading programs. Uncertainty aboutwhether units would remain in theprogram could be very disruptive to theoperation of the program. The secondreason is to avoid creating incentives forsources to seek to avoid their obligationsunder a CAA section 111(d) plan byundertaking modifications. The EPA isconcerned that owners or operators ofunits might have incentives to modifypurely because of potentialdiscrepancies in the stringency of thetwo programs, which would underminethe emission reduction goals of CAAsection 111(d).

The EPA invites comments on thisinterpretation of CAA section 111(d)(1),including whether this interpretation issupported by the statutory text and

whether this interpretation is sensiblepolicy and will further the goals of thestatute. It should be noted that thisinterpretation is severable from the restof this rulemaking, so that if the EPArevises this interpretation in the finalrule or if the EPA adopts thisinterpretation in the final rule but it isinvalidated by a Court, there would beno effect on the rest of this rulemaking.

2. Timing for Implementation andAchievement of Goals

This section describes proposed stateplan requirements related to the timingof achieving emission performancegoals, including performancedemonstrations, performance periods,and interim progress milestones.

As previously discussed, the goals arederived from application of four“building blocks.” The EPA has basedthe application of some of thesemeasures to reduce CO2 emissions,particularly blocks 3 (expansion ofcleaner generating capacity) and 4(increasing demand-side energyefficiency), on forward-looking, longer-term assumptions. For example, theEPA expects technologies to reducecarbon emissions to more fully developover time and acknowledges thecumulative effects of implementation ofEE programs and addition of REgenerating capacity over time.Therefore, the EPA is not proposing torequire each state to meet its full, finalgoal immediately, but rather to meet itby 2030. The EPA realizes, however,that states can achieve emissionreductions from those and othermeasures in the short-term. Therefore,the EPA is proposing that states beginmeeting interim goals, beginning in2020. The EPA also believes that timingflexibility in implementing measuresprovides significant benefits that allowstates to develop plans that will helpstates achieve a number of goals,including: Reducing cost, addressingreliability concerns, and addressingconcerns about stranded assets.Therefore, the EPA is also proposing toallow states flexibility to define thetrajectory of emission performancebetween 2020 and 2029, as long as theinterim emission performance level ismet on a 10-year average or cumulativebasis and the 2030 emissionperformance level is achieved.

Section Vffl.B.1.a of this preambleprovides an overview of the proposalsfor state plan performancedemonstrations and timing of emissionreductions. Subsequent subsectionsinclude proposals for the start date forthe interim goal performance period, theduration of the performance periods forthe final and interim goals, interim

progress milestone requirements,consequences if actual emissionperformance does not meet the stategoal, and out-year requirements forstates to maintain CO2 emissionperformance levels over time consistentwith the final goal. in Section Vlfl.B.2.fof this preamble, the agency alsorequests comment on alternativerequirements aimed at continuedemission performance improvementafter 2029. In Section VflI.B.2.g of thispreamble, the EPA proposes flexibilityfor states to change from mass-based torate-based goals in differentperformance periods and, in SectionVffl.B.2.h, we solicit comment onplanning requirements that match theoption of alternative, less stringent stategoals.

a. Performance Demonstrations andTiming of Emission Reductions

As described previously, the agency isproposing final state-specific goals(specified in Table 8) that representemission rates to be achieved by 2030,as well as interim goals, to be achievedon average over the 10-year period from2020—2029. The agency is alsoproposing that emission performancelevels consistent with the final state-specific goals be maintained after 2030.

This relatively long planning andimplementation period provides stateswith substantial flexibility regardingmethods and timing of achievingemission reductions. States may wish tomake adjustments to theirimplementation approaches along theway, or as conditions change may needto make adjustments to ensure that theirplans achieve the goals as intended. Asa result, the agency envisions that theEPA, states, and affected entities willhave an ongoing relationship in thecourse of implementing this program.

The EPA proposes that a state planmust demonstrate projectedachievement of the emissionperformance levels in the plan, andthese emission performance levels mustbe equivalent to or better than theinterim and final goals established bythe EPA. Specifically, the state planmust demonstrate that the projectedemission performance of affected EGUsin the state will be equivalent to orbetter than the applicable interim goalduring the 2020—202 9 period, andequivalent to or better than theapplicable final goal during the year2030. The state plan must identifyrequirements that continue to applyafter 2030 and are likely to maintaincontinued emission performance byaffected EGUs that meets the final goal;however, quantitative projections ofemission performance by affected EGUs



beyond 2030 would not be required bythis rule under the proposed approach.Jnstead, the EPA proposes that the stateplan would he considered to provide formaintenance of emission performanceconsistent with the final goal if the planmeasures used to demonstrateachievement of the final goal by 2030will continue in force and not sunset.

In addition to demonstrating thatprojected plan performance will meetthe interim and final state goals, theEPA proposes that state plans mustcontain requirements for tracking actualplan performance duringimplementation. For plans that do notinclude enforceable requirements foraffected EGUs that ensure achievementof the full level of required emissionperformance and interim progress, thestate plans would be required to includeperiodic program implementationmilestones and emission performancechecks, and include corrective measuresto be implemented if mid-coursecorrections are necessary. The state planwould provide for continued tracking ofemission performance after 2030, andfor corrective measures if the emissionperformance of affected EGUs in thestate did not continue to meet the 2030final goal during any three-yearperformance period.

The rationale for this approach is thatit would ensure that states design theirplans in a way that considers both theinterim and final goals. If only theinterim goal were considered, a stateplan might not be sufficient to achievethe final goal.276

The agency requests comment on asecond option in which, in addition tosubmitting a plan demonstratingemission performance through 2030,states would be required to make asecond submittal in 2025 showingwhether their plan measures wouldmaintain the final-goal level of emissionperformance over time (as furtherdescribed below), if not, the statesubmittal would be required tostrengthen or add to measures in thestate plan to the extent necessary tomaintain that level of performance overtime.

The EPA also requests comment onwhether 2025, or an earlier or later year,

276 2020—2029 interim goal is expressed as a10-year average emission rate to provide states withflexibility in designing their plans. Due to thepotential for continued end-use energy efficiencyimprovements, the 2029 four-building-block BSERbased level is a more stringent level than the 2020—2029 average four-building-block BSER-based level.The purpose of the final goal is to ensure that eachstate ultimately achieves the emission performancelevel for affected EGUs that is achievable by 2029.Without the final goal, it is possible that a statecould achieve the 2020—2029 interim goal but notachieve the 2030 final goal.

would be the optimal year for a secondplan submittal under the second option.

b. Start Date for Performance Period forInterim Goal

A performance period is a period forwhich the state plan must demonstratethat the required emission performancelevel will be met. The EPA proposes astart date of January 1,2020, for theinterim goal plan performanceperiod.277 This date would be thebeginning of the 10-year period forwhich a state must demonstrate that theprojected emission performance level ofaffected EGUs in the state, on average,will be equivalent to or better than theapplicable interim goal. The agencygenerally requests comment on theappropriate start date and rationale.

In considering the start date, it isrelevant to consider the due dates forstate plan submittals and the amount oftime available for programimplementation by the start date.January 2020 is 3.5 years from theproposed June 2016 deadline for initialplan submiltals, 2.5 years from theproposed June 2017 extended deadlinefor complete plans from states notparticipating in a multi-state plan, and1.5 years from the proposed June 2018extended deadline for complete plansfrom states participating in a multi-stateplan. The EPA suggests that affectedentities may have greater lead time forcompliance than might be implied bythe plan submittal dates referencedabove. Affected entities will haveknowledge of state requirements as theyare adopted, and the state must adoptrules and requirements in advance ofsubmitting its complete plan to the EPA.Also, as explained in detail insubsection c, states may choose adifferent emission performanceimprovement trajectory from that whichthe EPA assumes for purposes ofcalculating state goals, achieving lesserlevels of performance in early years andmore in later years, provided, of course,that the interim 10-year averagerequirement is met.

The EPA proposes that a 2020 startdate for the interim goal planperformance period is achievable inlight of the following additionalconsiderations. First, existing stateprograms will play a role in helping toachieve this rule’s proposed emissionperformance levels. Second, in advanceof this proposal, many states alreadywere contemplating design of strategies

277 The start date for a pian performance periodmust match the start date of the corresponding stateemission performance goal. If a start date other thanJanuary 2020 were selected, the EPA wouldrecompute the state goals consistent with theselected start date.

that would achieve CO2 emissionreductions equivalent to those thatcould be required by CAA section111(d) emission guidelines. Third, forinclusion in the building blocks, theEPA considered only those emissionabatement measures that are technicallyfeasible and broadly applicable, and canprovide reductions in CO2 emissionsfrom affected EGUs at reasonable cost.

For example, the EPA expects thatmany EGUs will meet theirrequirements in part by implementingheat rate improvements, and thoseactions may be undertaken promptly.The plant operations and maintenance(O&M) and engineering solutions usedto improve heat rates at existing EGUshave long been commercially availableand have been implemented at EGUs formany years. Further, the relativelymodest capital costs (average $100/kW)and significant fuel savings associatedwith a suite of heat rate improvement(HEI) methods result in this measurebeing a low-cost approach to reducingCO2 emissions from existing EGUs. HRI“best practices” (e.g., installation ofmodern control systems, operatortraining, smart soot blowing) are theleast-cost TIRE methods and can beapplied quickly, without lengthy EGUoutages. The somewhat more costly HRI“upgrades” (e.g., steam turbine upgrade,boiler draft fan/driver upgrade) mayrequire modest EGU outages toimplement, but have also been appliedon numerous EGUs to improve ormaintain performance. Drawing on thepower sector’s extensive experiencewith ITRI methods, and the manyexisting supply chains alreadysupporting these methods, the EPAexpects that it would be feasible toimplement HRI projects (i.e., buildingblock 1) by 2020.

Dispatch changes, which are largelydriven by the variable cost of operatinga given EGU, occur on an hourly basisin the power sector. The averageavailability factor for NGCCs in the U.S.generally exceeds 85 percent, and canexceed 90 percent for selectedgroups.278 In addition, the existingnatural gas pipeline and electricitytransmission networks are alreadyconnected to every existing NGCCfacility, and can support aggregateoperation of the NGCC fleet at 70percent (or above) at the state level, orcan be reasonably expected to do so inthe time frame for compliance with thisrule. Therefore, building block 2, whichrepresents shifting of generation fromsteam fossil EGUs to existing NGCCs, isa viable method for providing CO2

278 Source: NERC, 2008—2012 Generating UnitStatistical Brochure.


34906 Federal_Register/Vol. 79, No. 117/Wednesday, June 18, 2014/Proposed Rules

emission reductions at existing EGUs bythe 2020 compliance start date.

Building Block 3 is based on shiftinggeneration from affected fossil units tonew renewable energy generatingcapacity, which is added over time, andnew or preserved nuclear capacity, all ofwhich is expected to be in place by 2020(see the GHG Abatement Measures TSDfor more information).

Finally, there is considerableexperience with the states and thepower sector in designing andimplementing demand-side energyefficiency improvement strategies andprograms. It is also well accepted thatsuch improvements can achievereductions in CO2 emissions fromexisting EGUs at a reasonable cost.Building block 4 represents a feasiblepathway for reducing utilization ofcarbon-emitting EGUs by implementingimprovements in demand-side energyefficiency. This building block is basedon a “best practices” scenario where allstates achieve a level of performance—matching a level achieved or committedto by twelve leading states—of 1.5percent annual incremental electricitysavings as a percentage of retail sales.For the best practices scenario, all statesachieve this level of performance nolater than 2025, with leading statesreaching this level sooner. Each state’scurrent level of performance is takeninto account, with states achievinglower levels of performance beingallowed more time to reach the bestpractice level.

c. Duration of Performance Periods forFinal and Interim Goals

The EPA recognizes that a state’scircumstances and choice of emissionreduction strategies may affect thetiming of CO2 emission performanceimprovement within a multi-yearplanning period. States can be expectedto select various combinations ofmeasures and those measures may varyin the time needed to reach fullimplementation. The agency recognizesthat certain emission reductionmeasures and programs (e.g., heat rateimprovements) are generally easier toimplement in the near term, whileothers (e.g., renewable portfoliostandards, demand-side energyefficiency programs) may require severalyears to implement because of the timenecessary to establish the properinfrastructure if a state does not alreadyhave such programs in place. Thoughsome states have already implementedsuch programs that are achievingresults, other states may have toestablish them for the first time. Newsingle and multi-state programs, as wellas existing single and multi-state

programs that are adding or revisingmeasures, may need time forimplementation to achieve the requiredlevel of emission performance.

As described in Section VII of thepreamble, the EPA is proposing state-specific CO2 emission performancegoals in a multi-year format to providestates with flexibility for the timing ofprograms and measures that improveEGU emission performance, whileensuring an overall level of performanceconsistent with application of the BSER.Specifically, the agency is proposing thestate-specific goals (shown in Table 8)which represent emission rates to beachieved by 2030 (final goal) andemission rates to be achieved on averageover the 2020—202 9 period (the interimgoal).

The EPA proposes the following asthe preferred option for the final andinterim goal performance periods. Asfurther explained below, this optionreflects three main objectives: (1)Provide states with timing flexibilityduring the interim goal period toaccommodate differences in stateadoption processes and types of stateprograms, (2) ensure that state plans aredesigned to achieve the final goal nolater than 2030, and (3) provideflexibility for year-to-year variation inactual emission performance that mayoccur as the electricity system respondsto economic fluctuations.

Interim goal—Projected planperformance demonstration: To beapprovable, a state plan mustdemonstrate that the emissionperformance of affected EGUs will meetthe interim emission performance levelon average over the 2020—2029 period.

Interim goal—Actual planperformance check: In 2030, theemission performance of affected EGUsduring the period 2020—2029 must becompared against the interim goal. (Inaddition, as described separately below,interim emission performance checkswill occur during this 10-year period.)

Final goal—Projected planperformance demonstration: To beapprovable, a state plan mustdemonstrate that the emissionperformance of affected EGUs will meetthe final emission performance level nolater than 2030, on a single-year basis.

Final goal—Actual plan performancecheck: Starting at the end of 2032,emission performance of affected EGUsmust be compared against the final goalon a three-year rolling average basis(i.e., 2030—32, 2031—33, 2032—2034,etc.).

This proposed approach provides a10-year performance period for theinterim performance level. The 10-yearperiod allows states flexibility for

timing of program implementation asthe state ramps up its programs toachieve the final performance level.Using the single year 2030 as theprojected year for achievement of thefinal goal ensures that state plans aredesigned to achieve the final goal nolater than 2030; providing a multi-yeartime frame for projected planperformance would inappropriatelydelay the requirement for a final-goallevel of performance that the EPA’sanalysis shows is achievable at the endof the 10-year interim ramp-up period.Using 2030 also avoids overlap with theinterim goal performance period. Therolling three-year performance periodsfor measuring actual plan performanceagainst the final goal performance levelare proposed in light of year-to-yearvariability in economic and otherfactors, such as weather, that influencepower system operation and affect EGUCO2 emissions. The choice of 2030—2032 avoids overlap with the 2020—2029interim goal performance period.

For a rate-based plan, 2020—2 029emission performance is an average CO2emission rate for affected EGUsrepresenting cumulative CO2 emissionsfor affected EGUs over the course of the10-year performance period divided bycumulative MWh energy output279 fromaffected EGUs over the 10-yearperformance period, with rateadjustments for qualifying measures,such as end-use energy efficiency andrenewable energy measures, asdescribed in Section Vffl.F.3. For amass-based plan, 2020—202 9 emissionperformance is total tons of CO2 emittedby affected EGUs over the 10-yearperformance period.

The agency invites comment on thisand other approaches to specifyingperformance periods for state plans.

d. Program Implementation Milestonesand Tracking of Emission Performance

The EPA recognizes the importance ofensuring that, during the proposed 10-year performance period (2020—202 9)for the interim goal, a state is makingsteady progress toward achieving therequired level of emission performance.The EPA is proposing that certain typesof state plans be required to haveprogram implementation milestones toensure interim progress, as well asperiodic checks on overall emissionperformance leading to correctivemeasures if necessary.

Some types of plans are “self-correcting” in that they inherently

279 For EGUs that produce both electric energyoutput and other useful energy output, there wouldalso be a credit for non-electric output, expressedinMWh.



would assure interim performance andfull achievement of the state plan’srequired level of emission performancethrough requirements that areenforceable against affected EGUs. Oneexample is a state plan with a rate-basedemission performance level thatrequires affected EGUs collectively tomeet an emission rate consistent withthe state’s required emissionperformance level, and allows EGUs tocomply through an emission rateaveraging system. Another example is aplan that includes measures or actions(e.g., emission limits that apply toaffected EGUs and ensure full planperformance) that take effectautomatically if the plan’s requiredemission performance level is not met,in accordance with a specifiedmilestone. The EPA requests commenton whether there are other types of stateplans that should be considered “selfcorrecting.”

The EPA proposes that self-correctingplans need not contain interimmilestones consisting of programimplementation steps, because thesestate plans inherently require bothinterim progress and achievement of thefull level of required emissionperformance in a manner that isfederally enforceable against affectedECUs. Annual reporting of emissionperformance by the state, however, isrequired for all types of plans.

For plans that are not self-correcting,the EPA proposes that the state planmust identify periodic programimplementation milestones (e.g., start ofan end-use energy efficiency program,retirement of an affected ECU, orincrease in portfolio requirements undera renewable portfolio standard) that areappropriate to the programs andmeasures included in the plan. if,during plan implementation, a statewere to miss program implementationmilestones in its plan, it would need toreport the delay to the EPA, explain thecause, and describe the steps the statewill take to accelerate subsequentimplementation to achieve the plannedimprovements in emission performance.Depending on the severity of delay andthe explanation, the EPA couldultimately evaluate actions under CAAauthorities to ensure timely programimplementation.

In addition, we propose that the stateand the EPA would track state planemission performance on an ongoingbasis, with states reporting performancedata to the EPA annually by July 1.During the interim performance period,beginning in 2022, the state would berequired each year to include acomparison of emission performanceachieved to performance projected in

the state plan. Each comparison wouldcover the preceding two-year period.The EPA may also approve regular,periodic emission comparison checkswith a different frequency orcomparison period to reflect the designof a state’s programs (e.g., complianceperiods for EGUs under an emissionlimit).

A report and corrective measureswould be required if an interimemission check showed that actualemission performance of affectedentities was not within 10 percent of theperformance projected in the state plan(i.e., for a rate-based plan, if the averageemission rate of affected ECUs were 10percent higher than plan projections, orfor a mass-based plan, if collectiveemissions of affected ECUs were 10percent higher than plan projections). Inthat event, the state would be requiredin its submission to explain reasons forthe deviation (e.g., energy efficiencyprogram not working as effectively asexpected, prolonged extreme weatherthat had been unanticipated inelectricity demand projections) andspecify the corrective measures that willbe taken to ensure that the requiredlevel of emission performance in theplan will be met. The state also wouldbe required to implement thosecorrective measures as expeditiously aspractical.

The agency proposes that states begiven a choice regarding when to adoptinto regulation the corrective measuresthat the state plan identifies forimplementation in the event that stateplan performance is deficient. First, thestate could adopt corrective measuresinto regulation prior to plan submittal ina manner that enables the state toimplement the measuresadministratively, without furtherlegislation or rulemaking, if aperformance deficiency occurs duringplan implementation. This wouldexpedite implementation of correctivemeasures once a deficiency isdiscovered. Second, the state could electto wait to adopt into regulation thecorrective measures identified in theplan until after a plan performancedeficiency is discovered. The EPAproposes this choice in recognition ofthe fact that it may be challenging forstates to fuily adopt corrective measuresin advance to address the possibilitythat their plan will not perform asprojected. However, if a state makes thelatter choice, the EPA proposes that thestate must report the reasons fordeficient performance and mustimplement corrective measures if actualemission performance was inferior toprojected performance by eight percentor more (rather than 10 percent or

more). The reason for the lowerpercentage trigger is to identify agradually developing deficiency in planperformance earlier in time. Legislativeand/or regulatory action to adoptcorrective measures after a deficiency isdiscovered will take significant time.State processes to activate correctivemeasures should be triggered earlier ifcorrective measures are not adopted inregulation and ready to implement.

The EPA alternatively requestscomment on whether states should berequired to create legal authority and/oradopt regulations providing forcorrective measures in developing thestate plan. The agency requestscomment generally on the conditionsthat should trigger corrective measurerequirements. The agency also solicitscomment on whether actual emissionperformance inferior to projectedperformance by ten percent (for planswith corrective measures adopted intoregulation prior to complete plansubmittal) is the appropriate trigger forrequiring a state to report the reasons fordeficient performance and to implementcorrective measures. We are alsosoliciting comment on the range of fivepercent to fifteen percent. For planswithout corrective measures adoptedinto regulation prior to complete plansubmittal, the agency solicits commenton whether the proposed eight percentemission performance deviation triggeris appropriate. We also solicit commenton the range of five percent to tenpercent.

The EPA proposes that the state willbe required to compare actual emissionperformance achieved during the entire10-year interim performance period (i.e.,2020—2029) against the interim goal. Asnoted above, beginning after 2032, theEPA proposes that the state be requiredto compare actual emission performanceachieved against the final goal on arolling three-year average basis (e.g.,2030—32, 2031—33, etc.). The EPA alsorequests comment on the milestoneapproach and emission performancechecks outlined above in the context ofthe alternative 5-year performanceperiod and the planning approach foralternative state goals, which isdescribed below.

e. Consequences if Actual EmissionPerformance Does Not Meet State Coal

There are scenarios under which anapproved state plan might fail toachieve a level of emission performanceby affected EGUs that meets the stategoal. Under some types of plans, apossible scenario is that despitesuccessful plan implementation,emissions under the plan turn out to behigher than projected at the time of plan



approval because actual economicconditions vary from economicassumptions used when projectingemission performance. State officialshave raised the possibility that achievedemission performance might not meetprojected performance if, for example,planned retirements of EGUs werepostponed because severe weatherproduced greater-than-expectedelectricity generation needs. In addition,emissions could theoretically exceedprojections because affected entitiesunder a state plan did not flilifil theirresponsibilities, or because the state didnot fulfill its responsibilities.

The EPA believes that the emissionguidelines should specify theconsequences in the event that actualemission performance under a state plandoes not meet the applicable interimgoal in 2020—2029, or does not meet theapplicable final goal in 2030—2032 orlater, because CAA section 111(d) is notspecific on this point. The agencyrequests comment on how theconsequences should vary depending onthe reasons for a deficiency inperformance.

Specifically, the agency requestscomment on whether consequencesshould include the triggering ofcorrective measures in the state plan, orplan revisions to adjust requirements oradd new measures. The agency alsorequests comment on whether correctivemeasures, in addition to ensuring futureachievement of the state goal, should berequired to achieve additional emissionreductions to offset any emissionperformance deficiency that occurredduring a performance period for theinterim or final goal. This concept hasbeen applied, for example, in the AcidRain Program under Title W of the CAA;a source that has sulfur dioxideemissions exceeding the emissionallowances that it holds at the end of theperiod for demonstrating compliance isrequired subsequently to obtainadditional emission reductions to offsetits excess emissions.280 The agency alsorequests comment on the process forinvoking requirements forimplementation of corrective measuresin response to a state plan performancedeficiency.

The EPA further requests comment onwhether the agency should promulgatea mechanism under CAA section 111(d)similar to the SIP call mechanism inCAA section 110. Under this approach,after the agency makes a finding of theplan’s failure to achieve the state goalduring a performance period, the EPAwould require the state to cure thedeficiency with a new plan within a

280 CAA section 411(b).

specified period of time (e.g., 18months). if the state still lacked anapproved plan by the end of that timeperiod, the EPA would have theauthority to promulgate a federal planunder CAA section 111(d)(2)(A).

f. Out-Year Requirements: Maintainingor Improving the Level of EmissionPerformance Required by the Final Goal

The agency is determining state goalsfor affected EGU emission performancebased on application of the BSER duringspecified time periods. This raises thequestion of whether affected EGUemission performance should only bemaintained—or instead should befurther improved—once the final goal ismet in 2030. This involves questions ofgoal-setting as well as questions aboutstate planning. In this section, the EPAproposes that a state must maintain therequired level of performance, andrequests comment on the alternative ofrequiring continued improvement.

The EPA believes that Congress eitherintended the emission performanceimprovements required under CAAsection 111(d) to be permanent or,through silence, authorized the EPA toreasonably require permanence. OtherCAA section 111(d) emission guidelinesset emission limits to be metpermanently. Therefore, the EPA isproposing that the level of emissionperformance for affected EGUsrepresented by the final goal shouldcontinue to be maintained in the yearsafter 2030. The EPA is proposing amechanism for implementing thisobjective, and is taking comment on analternative option.

As noted above, the EPA proposesthat the state plan must demonstratethat plan measures are projected toachieve the final emission performancelevel by 2030. In addition, the state planmust identify requirements thatcontinue to apply after 2030 and arelikely to maintain affected EGUemission performance meeting the finalgoal; however, quantitative projectionsof emission performance beyond 2030would not be required under theproposed option. Instead, the EPAproposes that the state plan would beconsidered to provide for maintenanceof emission performance consistent withthe final goal if the plan measures usedto demonstrate projected achievement ofthe final goal by 2030 will continue inforce and not sunset.28’ After

281 This is straightforward for plans with EGUemission limits that ensure the full level ofperformance required. For renewable energyprograms, the agency suggests that the state couldcontinue to require the renewable portfoliopercentage level that was relied upon todemonstrate projected achievement of the final goal

implementation, the state would berequired to compare actual planperformance against the final goal on arolling three-year average basis startingin 2030, and to implement correctivemeasures if necessary.

The EPA also requests comment on analternative approach to a state’s preimplementation demonstration that thefinal-goal level of performance will bemaintained after 2030. Under thisalternative, the state plan would berequired to include projectionsdemonstrating that emissionperformance would continue to meetthe final goal for up to 10 years beyond2030. This approach could beimplemented through a second round ofstate plan analysis and submittals in2025 to make the demonstration andstrengthen or add measures if necessary.The EPA generally requests comment onappropriate requirements to maintainthe emission performance of affectedEGUs in years after 2030.

The EPA also requests comment onwhether we should establish BSERbased state emission performance goalsfor affected EGUs that extend furtherinto the future (e.g., beyond theproposed planning period), and if so,what those levels of improvedperformance should be. Under thisalternative, the EPA would apply itsgoal-setting methodology based onapplication of the BSER in 2030 andbeyond to a specified time period andfinal date. The agency requestscomment on the appropriate timeperiod(s) and final year for the EPA’scalculation of state goals that reflectapplication of the BSER under thisapproach.

The EPA notes that CAA section111(b)(1)(B) calls for the EPA, at leastevery eight years, to review and, ifappropriate, revise federal standards ofperformance for new sources. Thisrequirement provides for regularupdating of performance standards astechnical advances provide technologiesthat are cleaner or less costly. Theagency requests comment on theimplications of this concept, if any, forCAA section 111(d).

g. State Flexibility To Choose Mass-Based and Rate-Based Goals After 2029

The EPA proposes that states haveflexibility to choose between a rate-

performance level in 2030. For plans that rely inpart on end-use energy efficiency programs andmeasures, the EPA requests comment on what astate would need to require in its plan to show thatperformance will be maintained after 2030. End-useenergy efficiency programs and measures ofteninvolve an annual energy savings requirement orgoal, and some types require additional monetaryexpenditures each year to meet those savingsrequirements or goals.



based and mass-based performance levelfor each performance period. Forexample, if a state plan used a mass-based performance level for the 2020—2029 period, the state plan may still usea rate-based performance level for finalgoal performance periods, or vice versa.

A state that adopted a mass-basedperformance level for 2020—2029 wouldhave two options for addressing anyperceived need for emissions flexibilityin light of anticipated electricitydemand growth after 2029. The stateeither could adopt a rate-basedperformance level consistent with thefinal goal, or could adopt a mass-basedperformance level based on a translationof the rate-based final goal to a mass-based goal.

h. Planning Approach for AlternativeState Goals

In Section VII, the EPA requestscomment on alternative, five-year stateemission performance goals for affectedEGUs shown in Table 9. The alternativegoals represent emission ratesachievable on average during the 2020—2024 period, as well as emission rates tobe achieved and maintained after 2024.These alternative goals are less stringentthan the proposed goals in Table 8.

To accompany the alternative goals,the EPA requests comment on anotherapproach for state plan performanceperiods. This approach would requirestate plans to demonstrate that therequired interim emission performancelevel will be met on average by affectedEGUs during the five-year 2020—2024interim period, and that the alternativefinal goal be met no later than 2025.After plan implementation, actualemission performance would becompared with the alternative final goalon a three-year rolling average basis,starting with 2025—2027, in light ofyear-to-year variability in economic andother factors, such as weather, thatinfluence power system operation andaffect EGU CO2 emissions.

In connection with the alternativestate goals, for the years after 2027, theEPA requests comment on the same“out-year” issues and concepts formaintaining or improving emissionperformance over time that aredescribed above in Section Vffl.B.2.f.The EPA requests comment on whethera state plan should provide for emissionperformance after 2025 solely throughpost-implementation emission checksthat do not require a second plansubmittal, or whether a state should alsobe required to make a second submittalprior to 2025 to demonstrate that itsprograms and measures are sufficient tomaintain performance meeting the finalgoal for at least 10 years. In addition, the

agency requests comment on theappropriate date for any second stateplan submittal designed to maintainemission performance after the 2025performance level is achieved.

C. Criteria for Approving State PlansThe EPA is proposing to require the

twelve plan components discussed inSection Vffl.D of this preamble. We willevaluate the sufficiency of each planbased on the plan addressing thosecomponents and on four general criteriafor a state plan to be approvable. TheEPA proposes to use the combination ofthese twelve plan components and fourgeneral criteria to determine whether astate’s plan is “satisfactory” under CAAsection 111(d)(2)(A). First, a state planmust contain enforceable measures thatreduce EGU CO2 emissions. Second,these enforceable measures must beprojected to achieve emissionperformance equivalent to or better thanthe applicable state-specific CO2 goal ona timeline equivalent to that in theemission guidelines.282 Third, EGU CO2emission performance under the stateplan must be quantifiable and verifiable.Fourth, the state plan must include aprocess for state reporting of planimplementation (at the level of theaffected entity), CO2 emissionperformance outcomes, andimplementation of corrective measures,if necessary. The EPA requestscomments on all aspects of these generalcriteria and the twelve specific plancomponents described below.

The agency also notes that a CAAsection 111(d) state plan is not a CAAsection 110 state implementation plan(SIP). Although there are similarities inthe two programs, approvability criteriafor CAA section 111(d) plans need notbe identical to approvability criteria forSips.

1. Enforceable MeasuresIn developing its plan, a state must

ensure that the plan is enforceable andin conformance with the CAA. We areseeking comment on theappropriateness of existing EPAguidance on enforceability in thecontext of state plans under CAAsection 111(d), considering the types ofaffected entities that might be includedin a state plan. 2B3 This guidance serves

262Flexibilitfes provided to states in meeting thisgeneral approvability criterion are discussed belowin Section Vffl.C.2., emission performance.

Enforceability guidance includes:(1)September 23, 1987 memorandum andaccompanying implementing guidance, “Review ofState Implementation Plans and Revisions forEnforceability and Legal Sufficiency,” (2) August 5,2004 “Guidance on SIP Credits for EmissionReductions from Electric-Sector Energy Efficiencyand Renewable Energy Measures,” and (3) July 2012

as the foundation for the types ofemission limits that the EPA has foundcan be enforced as a practical matterand sets forth the general principle thata requirement that is enforceable as apractical matter is one that isquantifiable, verifiable, straightforward,and calculated over as short a term asreasonable.

As discussed in section Vffl.F.1, theEPA is seeking comment on whether theagency should provide guidance onenforceability considerations related torequirements in a state plan for entitiesother than affected EGUs (and if so,which types of entities). Also, asdiscussed in section Vffl.F.4, the EPAintends to develop guidance forevaluation, monitoring, and verification(EM&V) of renewable energy anddemand-side energy efficiency programsand measures incorporated in stateplans.

A state plan must include enforceableCO2 emission limits (either rate-based ormass-based) that apply to affected EGUs.As noted above, the EPA is proposingthat a state plan may take a portfolioapproach, which would includeenforceable CO2 emission limits thatapply to affected EGUs as well as otherenforceable measures, such as RE anddemand-side EE measures, that avoidEGU CO2 emissions and areimplemented by the state or by anotherentity assigned responsibility by thestate. As noted above, we are proposingthat state plans are not required toimpose emission limits on affectedEGUs that in themselves fully achievethe emission performance level.However, we are seeking comment onwhether, for state plans where emissionlimits applicable to affected EGUs alonewould not assure full achievement ofthe required level of emissionperformance, the state plan mustinclude additional measures that wouldapply if any of the other portfolio ofmeasures in the plan are not fullyimplemented, or if they are, but the planfails to achieve the required level ofemission performance.284

The EPA recognizes that a portfoiioapproach may result in enforceable stateplan obligations accruing to a diverserange of affected entities beyondaffected EGUs, and that there may bechallenges to practically enforcingagainst some such entities in the eventof noncompliance. We request comment

“Roadmap for incorporating Energy Efficiency!Renewable Energy Policies and Programs into Stateand Tribal Implementation Plans, Appendix F.”

28 This could include, for example, an expansionof the scope or an increase in stringency of thecurrent measures in the plan, a second set ofmeasures that avoid EGU COz emissions, oremissions limits that apply to affected EGUs.



on all aspects associated withenforceability of a state plan and how toensure compliance. We are also seekingcomment on enforceabilityconsiderations under different state planapproaches, which is addressed belowin Vffl.F.1.

2. Emission PerformanceThe second criterion for approvability

is that the projected CO2 emissionperformance by affected EGUs (takinginto account the impacts of planmeasures that are associated withreducing utilization from affected EGUs)must be equivalent to, or better than, therequired CO2 emission performancelevel in the state plan. State plans thatare projected to achieve an average CO2emission rate (expressed in lb C02/MWh) or tonnage CO2 emissionoutcome by all affected EGUs equal to,or lower than, the required level of CO2emission performance in the plan wouldmeet this approvability criterion.

We are proposing that states maydemonstrate such emission performanceby affected EGUs either on anindividual state basis or jointly on amulti-state basis.

All of the emission reductionmeasures included in the agency’sdetermination of the BSER reduce CO2emissions from affected EGUs. As aresult, the EPA is not proposing thatout-of-sector GHG offsets could beapplied to demonstrate CO2 emissionperformance by affected EGUs in a stateplan.

However, emission limits for affectedEGUs that are included in state planscould still include provisions thatprovide the ability to use GHC offsetsfor compliance with the emission limits,provided those emission limits wouldachieve the required level of emissionperformance for affected EGUs. We notethat inclusion of such provisions wouldcreate a degree of uncertainty about thelevel of emission performance thatwould be achieved by affected EGUswhen complying with the emissionlimit (as potentially would otherflexibility mechanisms included in anemission limit). As a result, suchemission limits would not beconsidered “self-correcting” asdiscussed above at Section Vffl.B.2.d.

All existing state emission budgettrading programs addressing GHGemissions include out-of-sector, project-based emission offsets, which may beused to cover a portion of thecompliance obligation of affectedsources. Other states may want to takea similar approach, for example, toincentivize GHG emission reductionsfrom land use and agricultural wastemanagement. How to address GHC

offsets included in ECU emission limitswhen projecting emission performanceunder a state plan is addressed in theProjecting ECU CO2 EmissionPerformance in State Plans TSD.

The ISO/RTO Council, anorganization of electric grid operators,has suggested that ISOs and RTOs couldplay a facilitative role in developing andimplementing region-wide, multi-stateplans, or coordinated individual stateplans. Existing ISOs and RTOs couldprovide a structure for achievingefficiencies by coordinating the stateplan approaches applied throughout agrid region. Just as the ISO/RTO regionstoday share the benefits and costs ofefficient ECU dispatch across stateboundaries, there are significantefficiencies that could be captured bycoordinating individual state plans orimplementing multi-state plans within agrid region. Under one variant of thisapproach, states would implement amulti-state plan and jointly demonstrateCO2 emission performance by affectedECUs across the entire ISO/RTOfootprint. States with borders that crossthe boundary of one or more ISO or RTOfootprints would need to includemultiple plan components that addressaffected ECUs in each respective ISO orRTO. The EPA is seeking comment onthis idea. States that are outside thefootprint of an ISO or RTO may benefitfrom consulting with other relevantplanning authorities when preparingstate plans. We are also requestingcomment on this idea.

3. Quantifiable and Verifiable EmissionPerformance

The third criterion for approvability isthat a state plan specify how the effectsof each state plan measure will bequantified and verified. The EPAproposes that all plans must specifyhow CO2 emissions from affected ECUsare monitored and reported. The EPA isproposing that both mass-based andrate-based plans must include CO2emission monitoring, reporting, andrecordkeeping requirements for affectedECUs, as specified in the emissionguidelines. A rate-based plan must alsoinclude monitoring, reporting, andrecordkeeping requirements for usefulenergy output from affected EGUs(electricity and useful thermal output),as specified in the emission guidelines.With one exception, these proposedrequirements are consistent with thosein the proposed ECU Carbon PollutionStandards for New Power Plants. See 79FR 1430—15 19 (January 8, 2014). Theexception is that we are proposing thatuseful energy output be measured interms of net output rather than grossoutput, as discussed below.

For state plans that include othermeasures that avoid ECU CO2emissions, such as RE and demand-sideEE measures, the state will also need toinclude quantification, monitoring, andverification provisions in its plan forthese measures, which may varydepending on the types of requirementsincluded in the specific plan, asspecified in the emission guidelines.This may include, for example,quantification, monitoring, andverification of RE generation anddemand-side FE energy savings under arate-based approach.285

4. Reporting and Corrective ActionsThe fourth criterion for approval is

that a state plan must (i) specify aprocess for annual reporting to the EPAof overall plan performance andimplementation (including complianceof affected entities with applicableemission standards) during the planperformance periods, and (ii) include aprocess and schedule for implementingcorrective measures if reporting showsthat the plan is not achieving theprojected level of emission performance.We solicit comment on whether thelatter process should include theadoption of new plan measures andsubsequent resubmission of the plan tothe EPA for review and approval, orwhether the process should specify theimplementation of measures that arealready included in the approved planin the event that the projected level ofperformance is not being achieved. Wealso solicit comment on the point atwhich such a process and schedulewould be triggered, such as at the endof a multi-year plan performance periodif emission performance is not met, orat specified interim stages within amulti-year plan performance period. Forplans with self-correcting mechanisms,the agency is not proposing thatrequirements for corrective measures beincluded in the plan. All of theseconsiderations are addressed in moredetail above in Section Vffl.B.2.

The agency is also proposing that astate plan specify appropriate periodicreporting requirements for each affectedentity in a state plan that will bereported at least annually,electronically, and disclosed on a statedatabase accessible by the public andthe EPA. The EPA is requestingcomment on the appropriate scope ofthese reporting requirements andwhether the reports should also bedirectly submitted by the affected

286 considerations for quantification, monitoring,and verification of RE and demand-side REmeasures are addressed in Section VU.F.4 of thispreamble and in the State Plan Considerations TSD.



entities to the EPA, as well as to thestate.

D. State Plan ComponentsThe EPA is proposing that an

approvable plan must meet theapprovability criteria described aboveand include the twelve state plancomponents summarized below,consistent with additional specificrequirements explained elsewhere inthis notice. Plans must comply with theEPA framework regulations at 40 CFR60.23—60.29, except as specifiedotherwise by these emission guidelines.These requirements apply both toindividual state plans and multi-stateplans.

For states wishing to participate in amulti-state plan, the EPA is proposingthat only one multi-state plan would besubmitted on behalf of all participatingstates. The joint submittal would besigned by authorized officials for each ofthe states participating in the multi-stateplan and would have the same legaleffect as an individual submittal foreach participating state. The jointsubmittal would adequately addressplan components that apply jointly forall participating states and for eachindividual state in the multi-state plan,including necessary state legal authorityto implement the plan, such as stateregulations and statutes. Because themulti-state plan functions as a singleplan, each of the required plancomponents described below (e.g., planperformance levels, programimplementation milestones, emissionperformance checks, and reporting)would be designed and implemented bythe participating states on a multi-statebasis.

We are also seeking comment on twoadditional options for multi-state plansubmittals. These options couldpotentially provide states withflexibility in addressing contingencieswhere one or more states submit plancomponents that are not approvable. insuch instances, these options wouldsimplify EPA approval of remainingcommon or individual portions of amulti-state plan. These options mightalso address contingencies during plandevelopment where a state fails tofinalize its participation in a multi-stateplan, with minimal disruption to thesubmittals of the remainingparticipating states.

First, the EPA is seeking comment onwhether states participating in a multistate plan should also be given theoption of providing a single submittal—signed by authorized officials from eachparticipating state — that addressescommon plan elements. individualparticipating states would also be

required to provide individualsubmiltals that provide state-specificelements of the multi-state plan. Boththe common multi-state submittal andeach individual participating statesubmittal would be required to addressall twelve plan components describedbelow (even if only through crossreference to either the commonsubmittal or individual submittals, asappropriate). Under this approach, thecombined common submittal and eachof the individual participating statesubmittals would constitute the multistate plan submitted for EPA review.

Second, the EPA is seeking commenton an approach where all statesparticipating in a multi-state planseparately make individual submittalsthat address all elements of the multistate plan. These submittals would needto be materially consistent for allcommon plan elements that apply to allparticipating states, and would alsoaddress individual state-specific aspectsof the multi-state plan. Each individualstate plan submittal would need toaddress all twelve plan components.

The EPA proposes that each planmust have the following twelvecomponents, except as indicatedotherwise for self-correcting plans:

1. Identification of Affected Entities(Affected EGUs and Other ResponsibleParties)

A state plan must list the individualaffected EGUs in the state that aresubject to the plan and provide aninventory of CO2 emissions from thoseunits (for the most recent calendar yearprior to plan submission for which dataare available), and identify any otheraffected entities in a state plan withresponsibilities for implementation andenforceable obligations under the plan.2. Description of Plan Approach andGeographic Scope

The state plan must describe itsapproach and geographic scope,including whether the state will achieveits required level of CO2 emissionperformance on an individual state basisor jointly through a multi-statedemonstration.

3. Identification of State EmissionPerformance Level

The state plan must identify thestate’s proposed emission performancelevel, which will either be the rate-based CO2 emission goal identified forthe state in the emission guidelines ora translation of the rate-based goal to amass-based goal.

A state plan must identify the rate-based or mass-based level of emissionperformance that must be met through

the plan, (expressed in numeric values,including the units of measurement forthe level of performance, such aspounds of CO2 per net MWh of usefulenergy output or tons of CO2). As noted,in the emission guidelines, the EPA willestablish the state goal in the form of aCO2 emission rate, and the state may, forits emission performance level, eitheradopt that rate or translate it into amass-based goal. If the plan adopts amass-based goal, the plan must includea description of the analytic process,tools, methods, and assumptions used totranslate from the rate-based goal to themass-based goal.

The EPA is proposing that multiplestates could jointly demonstrateemission performance by affected EGUs.For these multi-state approaches, stateswould demonstrate emissionperformance by affected EGUs inaggregate with partner states. For statesparticipating in a multi-state approach,the individual state performance goalsin the emission guidelines would bereplaced with an equivalent multi-stateperformance goal. For example, statestaking a rate-based approach woulddemonstrate that all affected EGUssubject to the multi-state plan achieve aweighted average CO2 emission rate thatis consistent, in aggregate, with anaggregation of the state-specific rate-based CO2 emission performance goalsestablished in the emission guidelinesthat apply to each of the participatingstates. If states were taking a mass-basedapproach, participating states woulddemonstrate that all affected EGUssubject to the multi-state plan emit atotal tonnage of CO2 emissionsconsistent with a translated multi-statemass-based goal. This multi-state mass-based goal would be based ontranslation of an aggregation of the state-specific rate-based CO2 emissionperformance goals established in theemission guidelines that apply to eachof the participating states.

The EPA is seeking comment on twooptions for calculating a weightedaverage, rate-based CO2 emissionperformance goal for multiple states.Under the first option, the weightedaverage emission rate goal for a group ofparticipating states is computed usingeach state’s emission rate goal from theemission guidelines and the quantity ofelectricity generation by affected EGUsin each of those states during the 2012base year that the EPA used incalculating the state-specific goals.Different levels would be computed forthe interim and final goals. Thisapproach is consistent with the methodused to calculate the state-specific, ratebased emission performance goals.However, it does not address the fact



that the weighted average emission rateperformance goal for multiple statesmay be influenced significantly by theweighting of electricity generation fromaffected EGUs in different states. Thismix of generation among affected EGUsin different states could differsignificantly during the planperformance periods from that duringthe 2012 base year.

Under the second option, theweighted average emission rate goal fora group of participating states iscomputed using each state-specificemission rate goal and the quantity ofprojected electricity generation byaffected EGUs in each state. Thecalculation would be performed for the2020 through 2029 period to produce amulti-state interim goal, and for 2030 toproduce a multi-state final goal. Thisprojection of electricity generation byaffected EGUs would be for a referencecase that does not include application ofeither the state-specific rate-basedemission performance goals for theparticipating states or the requirements,programs, and measures included in themulti-state plan. This approachaddresses the fact that the mix ofgeneration among affected EGUs indifferent states could differ significantlyduring the plan performance periodsfrom that during the 2012 base year. Asa result, it would base the weightedaverage goal in part on the anticipatedbusiness-as-usual mix of generation byaffected EGUs across the multiple statesduring the plan performance period.However, this approach could alsosignificantly alter the weighted averageperformance goal based on projectedretirements of affected EGUs in one ormore states.

Under both options, the rate-basedmulti-state goal could be translated to amass-based goal. These options, and theprocedure for translation to a mass-based goal, are discussed in more detailin the Projecting EGU COz EmissionPerformance in State Plans TSD.

We are requesting comment onwhether, to assist states that seek totranslate the rate-based goal into a mass-based goal, the EPA should provide apresumptive translation of rate-basedgoals to mass-based goals for all states,for those who request it, and/or formulti-state regions. As anotheralternative, the EPA could provideguidance for states to use in translatinga rate-based goal to a mass-based goalfor individual states and for multi-stateregions. This could include informationabout acceptable analytical methods andtools, as well as default inputassumptions for key parameters thatwill likely influence projections, such aselectricity load forecasts and projected

fossil fuel prices. Under this approach,the EPA might also provide acoordinating function in addressing theassumptions applied by multiple stateswithin a grid region, acknowledging thatassumptions about state programs acrossa broader grid region that are includedin an analysis scenario may influenceprojections of CO2 emissions by affectedEGUs in one or more particular states inthe grid region. The agency is seekingcomment on the process for establishingmass-based emission goals, includingthe options summarized above for theEPA’s and states’ roles in the translationprocess.

Technical considerations involved intranslating from rate-based goals tomass-based goals are discussed in detailin the Projecting EGU CO2 EmissionPerformance in State Plans TSD. TheTSD includes a discussion of possibleacceptable analytical methods, tools,and key assumption inputs that willinfluence projections. The agencyinvites comment on these technicalconsiderations.

4. Demonstration That the Plan IsProjected To Achieve the State’sEmission Performance Level

A state plan must demonstrate thatthe actions taken pursuant to the planare, when taken together, projected toachieve emission performance byaffected entities that, on average, willmeet the state’s required emissionperformance level for affected EGUsduring the initial 2020—2029 planperformance period, and will meet therequired final emission performancelevel in 2030. This demonstration willinclude a detailed description of theanalytic process, tools, and assumptionsused to project future CO2 emissionperformance by affected EGUs under theplan and the results of the analysis.Considerations related to projecting theemission performance of affected EGUsunder a state plan are discussed insection Vffl.F.7 and in the ProjectingEGU CO2 Emission Performance in StatePlans TSD.

5. MilestonesAs described in greater detail in

Section Vffl.B.2.d., state plans mustinclude periodic progranunaticmilestones to show progress in programimplementation if the plan is not self-correcting (i.e., does not inherentlyrequire both interim progress and thefull level of required emissionperformance in a manner that isfederally enforceable against affectedEGUs). These programmatic milestoneswith specific dates for achievementshould be appropriate to the programsand measures included in the plan.

In addition, the state plandemonstration will indicate the plan’sintended trajectory of emissionperformance improvement. Asdescribed in Section Vffl.B.2.d., eachyear during the interim performanceperiod, beginning in 2022 the state mustcompare the collective emissionperformance achieved by affectedentities in the state during the previoustwo-year period with performanceprojected in the state plan. If actualemission performance is not within 10percent of original projections, the statemust submit a report by the July 1following the end of the two-year period(submitted as part of the state’s annualreport on plan performance describedbelow in section Vffl.D.10) to explainreasons for the deviation and specify thecorrective actions that will be taken toensure that the required level ofemission performance in the plan willbe met.

6. Corrective MeasuresFor a plan that does not include self-

correcting mechanisms, the plan mustalso specify corrective measures thatwill be implemented if the state’sprogress in achieving its level ofperformance for affected EGUs fallsshort of what is projected under theplan, as well as a process and schedulefor implementing any such measures.The agency requests comment on theamount of emission rate improvementor emission reduction that the correctivemeasures included in the plan must bedesigned to achieve (e.g., measuressufficient to address a 10 percentperformance deficiency). The agencyalso seeks comment on whether theemission guidelines should establish adeadline for implementation ofcorrective measures (e.g., two years fromthe July 1 deadline described above forreporting the deficiency as part of thestate’s annual report on planperformance). Corrective measureprovisions are discussed in more detailabove in section Vffl.3.2.d and insection Vffl.B.2.f.

7. Identification of Emission Standardsand Any Other Measures

A state plan must identify the affectedentities to which each emissionstandard applies (e.g., individualaffected EGUs, groups of affected EGUs,all the state’s affected EGUs inaggregate, other affected entities that arenot EGUs), as well as any implementingand enforcing measures for suchstandards, and describe each emissionstandard and the process fordemonstrating compliance with itpursuant to state regulations or anotherlegal instrument, including the schedule



for compliance for each affected entity.In its proposed Carbon PollutionStandards (79 FR 1430—1519, January 8,2014), the EPA proposed that theappropriate averaging time for anemission standard for new EGUs be nolonger than 12 months. Similarly, theEPA proposes here that an appropriateaveraging time for any rate-basedemission standard for affected EGUsand/or other affected entities subject toa state plan is no longer than 12 monthswithin a plan performance period andno longer than three years for a mass-based standard. We also solicitcomment on longer and shorteraveraging times for emission standardsincluded in a state plan.

8. Demonstration That Each EmissionStandard Is Quantifiable, Non-Duplicative, Permanent, Verifiable, andEnforceable

In developing its CAA section 111(d)plan, a state must ensure that its plan isenforceable and in conformance withthe CAA. As discussed in sectionVffl.C.1, we are seeking comment on theappropriateness of existing EPAguidance on enforceability in thecontext of state plans under CAAsection 111(d), considering the types ofaffected entities that might be includedin a state plan.286 This guidance servesas the foundation for the types ofmonitoring, reporting, and limits thatthe EPA has found can be, as a practicalmatter, enforced, and set forth thegeneral principle that a requirement thatis enforceable as a practical matter isone that is quantifiable, verifiable,straightforward and is calculated over asshort a term as reasonable.

As discussed in section Vffl.F.1, theEPA is seeking comment on whether theagency should provide guidance onenforceability considerations related torequirements in a state plan for entitiesother than affected EGUs (and if so,which types of entities). Also, asdiscussed in section Vffl.F.4, the EPAintends to develop guidance forevaluation, monitoring, and verification(EM&V) of renewable energy anddemand-side energy efficiency programsand measures incorporated in stateplans.

For each emission standard, a planmust describe how it is quantifiable,

286 EPA guidance on enforceability includes: (1)September 23, 1987 memorandum andaccompanying implementing guidance, “Review ofState Implementation Plans and Revisions forEnforceability and Legal Sufficiency,” (2] August 5,2004 “Guidance on SW Credits for EmissionReductions from Electric-Sector Energy Efficiencyand Renewable Energy Measures,” and (3) July 2012“Roadmap for Incorporating Energy Efficiency!Renewable Energy Policies and Programs into Stateand Tribal Implementation Plans, Appendix F.”

non-duplicative, permanent, verifiable,and enforceable with respect to anaffected entity. An emission standard isquantifiable if it can be reliablymeasured, using technically soundmethods, in a manner that can bereplicated. These issues are discussedfurther in Section Vffl.F.4 and in theState Plan Considerations TSD.

An emission standard is non-duplicative with respect to an affectedentity if it is not already incorporated inanother state plan, except in instanceswhere incorporated in another state aspart of a multi-state plan. An exampleof a duplicative emission standardwould occur where recognition ofavoided CO2 emissions from, forexample, a wind farm, could be appliedin more than one state’s CAA section111(d) plan, except in the case of amulti-state plan where recognition isassigned among states or emissionperformance is demonstrated jointly forall affected EGUs subject to the multistate plan. This does not mean thatmeasures in an emission standardcannot also be used for other purposes.For example, if a state wished to takecredit for CO2 emissions avoided due toelectric generation from a new windfarm, those avoided emissions could beconsidered non-duplicative andincluded for purposes of CAA section111(d), even if electric generation fromthat wind farm was also being used togenerate renewable energy certificates(RECs) to comply with the state’s RPSrequirements. It also does not mean thata single affected entity could not besubject to similar emission standards indifferent state plans. For example, anaffected entity might be an electricdistribution utility that has a serviceterritory that crosses state lines. Thisentity might be subject to a separatestate demand-side FE requirement forelectricity supplied in each of the stateswhere it serves electricity customers. Inthis instance, the same company couldbe an affected entity subject to adifferent state demand-side FErequirement in each state plan, withoutthese emission standards in each planbeing considered duplicative. The EPAsolicits comment on whether anemission reduction becomes duplicative(and therefore cannot be used fordemonstrating performance in a plan) ifit is used as part of another state’sdemonstration of emission performanceunder its CAA section 111(d) plan.

An emission standard is permanent ifthe standard must be met for eachapplicable compliance year or period, orreplaced by another emission standardin a plan revision, or the statedemonstrates in a plan revision that theemission standard is no longer

necessary for the state to meet itsrequired emission performance level foraffected EGUs.

An emission standard is verifiable ifadequate monitoring, recordkeeping andreporting requirements are in place toenable the state and the Administratorto independently evaluate, measure, andverify compliance with it. This isdiscussed further in Section Vffl.F.4 andin the State Plan Considerations TSD.An emission standard is enforceable if:(1) It represents a technically accuratelimitation or requirement and the timeperiod for the limitation or requirementis specified, (2) compliancerequirements are clearly defined, (3) theaffected entities responsible forcompliance and liable for violations canbe identified, (4) each complianceactivity or measure is practicallyenforceable in accordance with EPAguidance on practical enforceability (asdiscussed in Section Vffl.F.1 of thispreamble), and the Administrator andthe state maintain the ability to enforceagainst violations and secureappropriate corrective actions pursuantto CAA sections 113(a)—(h).

9. Identification of Monitoring,Reporting, and RecordkeepingRequirements

The state plan must describe the CO2emission monitoring, reporting, andrecordkeeping requirements for affectedEGUs, including requirements formonitoring and reporting of usefulenergy output if a state plan is taking arate-based approach. The EPA isproposing that each plan includemonitoring, reporting, andrecordkeeping requirements for CO2emissions and useful energy output (ifapplicable) that are materiallyconsistent with the requirementsspecified in the emission guidelines.State plans with a rate-based form of theemission performance level mustrequire affected EGUs to report hourlynet energy output (including net MWhgeneration, and where applicable, usefulthermal output) to the EPA on an annualbasis.

Most affected EGUs already monitorCO2 emissions under 40 CFR Part 75and report the data using the EPA’sEmission Collection and MonitoringPlan System (ECMPS), which wouldgenerally satisfy CO2 emission reportingrequirements under the proposedguidelines. However, we are seekingcomment on two possible adjustmentsto the Part 75 Relative Accuracy TestAudit (RATA) requirements for steamEGU stack gas flow monitors that canaffect reported CO2 emissions. The firstpossible adjustment would be to requireuse of the most accurate RATA



reference method for specific stackconfigurations, while the secondpossible adjustment would be to requirea computation adjustment when an EGUchanges RATA reference methods. Therationale for these possible adjustmentsis described fu.rther in the Part 75Monitoring and ReportingConsiderations TSD available in thedocket.

We are also proposing monitoring andreporting protocols for net energyoutput under 40 CFR Part 75 that wouldallow the ECMPS to be used forpurposes of meeting the net energyoutput reporting requirement. Affectedfacilities with multiple generators (e.g.,combined cycle facilities) would berequired to report the electric outputfrom all generators. The proposedprotocols include a defaultapportionment procedure for multi-ECUfacilities under which the net generationof each EGU at the facility would bedetermined as the net generation of thefacility multiplied by the ratio of theECU’s gross generation to the sum of thegross generation for all EGUs at thefacility. (In the case of EGUs producingboth electric energy output and usefulthermal output, the apportionmentprocedure would include a thermal-to-electric energy conversion calculation asprovided in the proposed EGU GHGNSPS regulations.287) We solicitcomment on whether EGUs producingboth electric energy output and usefulthermal output should be required toreport both electric and useful thermaloutput. In addition, the proposedprotocols would allow facilities to usealternative apportionment procedureswith EPA approval. We invite commenton the proposal for reporting of netrather than gross energy output and onthe proposed protocols. Specifically, weare seeking comment on: Any existingprotocols for reporting net output(FERC, NERC, etc.); electricity meterspecifications; electricity meter qualityassurance testing and reportingprocedures; apportionment proceduresfor parasitic load at multi-unit facilities;treatment of externally providedelectricity; and monitoring and qualityassurance testing and reportingprocedures for non-electric energyoutput at CHP units. (Options regardingthese topics are discussed in the TSDmentioned above.) Also, consistent withthe requests for comment in theproposed CAA section 111(b) GHGNSPS regulations for modified andreconstructed sources, we invitecomment here on a range of two-thirdsto 100 percent credit for useful thermaloutput in the final rule, or other

28770 FR 1429—1519; Jarniary 8, 2014.

alternatives to better align incentiveswith avoided emissions.

A state plan that contains otheremission standards, in addition toemission limits applicable to affectedEGUs, must include additional reportingand recordkeeping requirements relatedto these other measures. These reportingand recordkeeping requirements willconsist of the data necessary for eachaffected entity to demonstratecompliance with its obligations. Thiscould include, for example, reporting ofMWh electricity savings achieved by anelectric distribution utility under anend-use energy efficiency resourcestandard and utility compliance withrequirements of the standard. Theserequirements might also includecomparable reporting by an electricdistribution utility of renewable energycertificates (RECs) held, or renewableenergy purchased or generated, under arenewable energy portfolio standard,and compliance with the standard. Thisis discussed further in Section VllI.F.5and the State Plan Considerations TSD.

The EPA is proposing that state plansmust include a record retentionrequirement of ten years, and we requestcomment on this proposed timeframe.

10. Description of State ReportingA state plan must provide that the

state will submit reports to the EPAdetailing plan implementation andprogress, including the actions taken bythe state, affected EGUs, and any otheraffected entities under the plan; thestatus of compliance by affected EGUsand any other affected entities withtheir obligations under the plan; currentaggregate and individual CO2 emissionperformance by affected EGUs duringthe reporting year and prior reportingyears; and any additional measuresapplied under the plan during thereporting period. The state plan mustdescribe the process, timing, andcontent for these reports. The EPA isproposing that an annual report is dueno later than the July 1 following theend of the reporting year.

While some of the proposed reportingrequirements such as reporting of EGUemissions (which can be done throughexisting reporting mechanisms) wouldnot place additional burdens on states,others may require assemblinginformation that is being reported understate programs into a single report. Forexample, in the case of a rate-based stateplan that calls for adjusting the actualemission rate of the state’s affectedEGUs based on emissions avoidedthrough renewable energy or end-useenergy efficiency programs, therequirement for comparing actual planperformance against projected plan

performance requires the state toincorporate information on resultsachieved by those programs each year.This emission performance comparisonserves as the basis for showing eitherthat a state plan is on track or thatcorrective measures are needed.Another reporting element is a list offacilities and their compliance status.The EPA is requesting comment on theappropriate frequency of reporting ofthe different proposed reportingelements, considering both the goals ofminimizing unnecessary burdens onstates and ensuring programeffectiveness. In particular, the agencyrequests comment on whether fullreports containing all of the reportelements should only be required everytwo years.

In addition, the EPA is solicitingcomment on whether these reportsshould be submitted electronically, tostreamline transmission.

11. Certification of State Plan Hearing

A state plan must providecertification that a hearing on the stateplan was held, a list of witnesses andtheir organizational affiliations, if any,appearing at the hearing, and a briefwritten summary of each presentation orwritten submission pursuant to therequirements of the EPA frameworkregulations at 40 CFR 60.23—60.29.

12. Supporting Material

The state must provide supportingmaterial and technical documentationrelated to applicable components of theplan. In its plan, a state must adequatelydemonstrate that it has the legalauthority for each implementation andenforcement component that it hasincluded in its plan as part of a federallyenforceable emission standard. A statecan make such a demonstration byproviding supporting material related tothe state’s legal authority used toimplement and enforce each componentof the plan, such as statutes, regulations,public utility commission orders, andany other applicable legal instruments.

A state plan must also provideanalytical materials used in translatinga rate-based goal to a mass-based goal (ifa translation is included), analyticalmaterials used in projecting emissionperformance that will be achievedthrough the plan, relevantimplementation materials, and anyadditional technical requirements andguidance the state proposes to use toimplement elements of the plan.



F. Process for State Plan Submittal andReview

1. Overview

Under the framework regulations,state pians would be due nine monthsafter finalization of the emissionguidelines. 40 CFR 60.23(a)(1). ThePresident in his June 25, 2013Memorandum specified that statesshould submit plans by June 30, 2016,which would provide states thirteenmonths. During the outreach process,many states expressed concern that thiswas not sufficient time to prepare andsubmit a state plan to the EPA. Statescommented that additional time wasneeded to accommodate, among otherthings, state legislative and rulemakingschedules, coordination among statesinvolved in multi-state plans,coordination with third parties, and thecomplex technical work needed todevelop a state plan. The EPArecognizes that state administrativeprocedures can be lengthy, some statesmay need new legislative authority, andstates planning to join in a multi-stateplan will likely need more than thirteenmonths to get necessary elements inplace. Balanced against that concern,however, is the urgency of addressingcarbon emissions and the fact that thereare certain steps we believe states cantake within thirteen months to setthemselves on a clear path to adoptionof a complete plan. Therefore, the EPAis proposing a plan submittal processwith a submittal date of June 30, 2016(thirteen months after the expectedfinalization date of the emissionguidelines), which provides additionaltime to submit a complete plan to theEPA after June 30, 2016, when justified.Part of that justification would includethe state’s demonstration of havingtaken meaningful steps during the firstthirteen months toward submitting acomplete plan. This approach involvesthe option that we refer to as an initialsubmittal, followed by submittal of acomplete state plan no later than eitherJune 30, 2017 for single-state plans orJune 30, 2018 for multi-state plans.

In addition, for states wishing toparticipate in a multi-state plan, theEPA is proposing that only one multistate plan would be submitted on behalfof all participating states, provided it issigned by authorized officials for each ofthe states participating in the multi-stateplan and contains the necessaryregulations, laws, etc. for each state inthe multi-state plan. In this instance, thejoint submittal would have the samelegal effect as an individual submittalfor each participating state.

2. State Plan Submittal and TimingThe EPA framework regulations (40

CFR 60.23) require that state plans besubmitted to the EPA within ninemonths of promulgation of the emissionguidelines, unless the EPA specifiesotherwise.288 In view of the potentialthat these plans may require states todevelop new regulatory or statutoryauthority, we are proposing that eachstate must submit a plan to the EPA byJune 30, 2016, which is more than oneyear after the expected finalization dateof the emission guidelines. The statemay submit a complete plan, or ifjustified, an initial plan that documentsthe state’s progress in preparing acomplete plan. To qualify for anextension of the June 30, 2016 deadlinefor submitting a complete plan, the statemust submit an initial plan thatdemonstrates the state is on track todevelop a complete plan and thatincludes meaningful steps that clearlycommit the state to complete anapprovable plan.

The EPA proposes that approvablejustifications for seeking an extensionbeyond 2016 for submitting a completeplan include: A state’s requiredschedule for legislative approval andadministrative rulemaking, the need formulti-state coordination in thedevelopment of an individual state plan,or the process and coordinationnecessary to develop a multi-state plan.The EPA is requesting comment onother circumstances for which anextension of time would be appropriate.We are also seeking comment onwhether some justifications forextension should not be permissible.

if a state submits an initial state planby June 30, 2016, and it meets theminimum requirements for an initialstate plan, as specified in the planguidelines, then the deadline extensionfor submitting a complete plan that thestate requested will be deemed granted.If the EPA determines that the initialplan does not meet the guidelines, theEPA will notify the state by letter,within 60 days, that the agency cannotapprove the state’s initial plan assubmitted. The EPA believes thisapproach is authorized by, andconsistent with, section 60.27(a) of theimplementing regulations.

If the EPA approves a two-yearextension to June 30, 2018, for a statedeveloping a multi-state plan, the statewould be required to provide oneupdate, on June 30, 2017, on its progresstoward milestones and schedules in theinitial plan for developing andsubmitting a complete plan. We are

28640 CFR 60.23(a](1).

requesting comment on this approachand the timing and frequency of updatesthat the state must provide.

3. Components of an Initial State PlanSubmittal and Approvability Criteria

As noted, if a state is unable toprepare and submit a complete plan byJune 30, 2016, the state must make aninitial submittal by that date. To beapproved, the EPA proposes that theinitial plan must address allcomponents of a complete plan,including identifying whichcomponents are not complete. Forincomplete components, an approvableinitial submittal must contain acomprehensive roadmap outlining thepath to completion, includingmilestones and dates. We recognize thatcertain options that states may chooseinvolve more analytic effort to preciselydemonstrate sources of emissionreductions than other options.

The EPA is proposing that the statemust provide an opportunity for publiccomment on a substantial draft of itsinitial submittal. The EPA proposes thatthis public comment opportunity willnot be governed by the proceduralrequirements of the frameworkregulations that apply to the state’sadoption of a complete plan, such as therequirement that the state hold a publichearing. 40 CFR 60.2 3(c)—(f). An initialplan might not include any legallyenforceable provisions that the statewould have adopted through itsadministrative or legislative processes,which generally provide for publicinput. Therefore, to ensure that thepublic has an opportunity to understandand inform the initial plan, the EPA isproposing that prior to submittal onJune 30, 2016 the state must haveprovided a reasonable opportunity forpublic comment on a substantial draft ofthe initial submittal, with notice to theEPA of that comment period. The EPAcan use this comment opportunity toadvise the state whether it is on track tosubmit an approvable initial plan. Whenthe state submits its initial plan, it mustprovide the EPA with a response to anysignificant comments it received onissues relating to the approvability ofthe initial plan so that the EPA can fullyassess whether it is approvable.

To be approvable, the initial planmust include the following information:

• A description of the plan approachand progress to date in developing acomplete plan.

• Initial quantification of the level ofemission performance that will beachieved through the plan.

• A commitment to maintain existingmeasures that limit or avoid CO2emissions (e.g., renewable energy



standards, unit-specific limits onoperation or fuel utilization), at leastuntil the complete pianis approved.

A comprehensive roadmap forcompleting the plan, including process,analytical methods, and schedule (withmilestones) specifying when allnecessary plan components will becomplete (e.g., demonstration ofprojected plan performance;implementing legislation, regulationsand agreements; any necessaryapprovals).

• Identification of existing programs,if any, the state intends to rely on tomeet its emission performance level.

• Identification of executedagreements with other states (e.g.,memorandum of understanding (MOU)),if a multi-state approach is beingpursued.

• A commitment to submit acomplete plan by no later than theapplicable required date andexplanation of actions the state will taketo show progress in addressingincomplete plan components.

• A description of all steps the statehas already taken in furtherance ofactions needed to finalize a completeplan (e.g., copies of draft or proposedregulations, draft or introducedlegislation, or draft implementationmaterials).

• Evidence of an opportunity forpublic comment and a response to anysignificant comments received on issuesrelating to the approvability of theinitial plan.

The EPA is soliciting comment onwhether there are other elements that astate must include in its initialsubmittal to qualify for a date extension.Specifically, the EPA requests commenton whether the guidelines shouldrequire a state to have taken significant,concrete steps toward adopting acomplete plan for the initial plan to beapprovable. For example, while it maybe difficult for a state to complete itsadministrative or legislative processwithin thirteen months, it may bereasonable to require that a state mustdocument that it has at least proposedany necessary regulations andintroduced any necessary legislationwithin the first thirteen months toqualify for additional time to submit acomplete plan.

For states participating in a multistate program, the initial submittalshould include executed agreementsamong the participating states and aroad map for both design of the multistate program and its implementation atthe state level. The RGGI provides anexample of such an approach. The RGGIparticipating states signed aMemorandum of Understanding (MOU)

in December 20, 2005, in which thestates “express[ed] their mutualunderstandings and commitments” •289

The MOU included a detailed outline ofthe multi-state emission budget tradingprogram, which served as a guide fordrafting a model rule. The MOU alsoincluded commitments by theparticipating states to draft and finalizethe model rule by specified dates, anda commitment to seek to establish instatute and/or regulation a programmaterially consistent with the modelrule in each state by a specified date.29°The MOU also included a commitmentto launch the program by January 1,2009 in all states and specified a processfor establishing a non-profitorganization to assist the states inadministering the regional aspects of theprogram. In addition, prior to executionof the MOU, the RGGI states committed,through letters from the Governors ofparticipating states, to engage in thedevelopment of a market-based programto reduce CO2 emissions from powerplants. This was followed bypublication of an action plan for tasksleading up to agreement on the basicstructure of the program, which wasultimately formalized in the MOU.4. Process for EPA Review of State Plans

Following the June 30, 2016, deadlinefor state plan submittals, the EPA willreview plan submittals forapprovability. For a state that submitsan initial state plan by June 30, 2016,and requests an extension of thedeadline for the submission of acomplete state plan, the EPA willdetermine if the initial plan submittalmeets the minimum requirements for aninitial state plan. If it meets theminimum requirements for an initialstate plan, as specified in the emissionguidelines, the state’s request for adeadline extension to submit a completeplan will be deemed granted, and thecomplete plan must be submitted to theEPA by no later than June 30, 2017 orJune 30, 2018 as appropriate.

After receipt of a complete plansubmittal, the EPA proposes that theagency will review the plan and, within

289 Regional Greenhouse Gas InitiativeMemorandum of Understanding, available athttp://rggi.org/design/history/mou. Two statessubsequently signed the original MOU in early 2007and a third joined the program later that yearthrough an amendment of the MOU; one of theoriginal states withdrew from the MOU in late 2011.

290 The model rule specified elements that neededto be consistent across states for the program tofunction, as well as areas where state rules coulddiffer (e.g., the method used for allocating co2allowances). For more information, see RegionalGreenhouse Gas Initiative Model Rule, available athftpil/rggi.org/docs/ProgramReWew/_FinalProgramfleviewMaterials/Model RuleFThML.pdf.

twelve months, approve or disapprovethe plan through a notice-and-commentrulemaking process, similar to that usedfor approving state implementation plansubmittals under section 110 of theCAA. The framework regulationscurrently provide for the EPA to act ona complete plan within four months. 40CFR 60.27(b). The EPA proposes that forplans under these guidelines, the agencywill act on a complete plan withintwelve months to provide adequate timefor rulemaking procedures.

Currently, the EPA’s frameworkregulations do not explicitly provide forthe EPA to use the different forms ofapproval actions Congress introducedinto the S1P program in the 1990 CleanMr Act Amendments. The EPA is takingcomment on whether, for complete stateplans under these guidelines, the agencymay use two approval mechanismsprovided for in CAA sections 110(k)(3)and (4), 42 U.S.C. 7410(k)(3) and (4).CAA section iii(d)(i) provides that theEPA shall establish “a procedure similarto that provided by section 7410 of thistitle [section 110 of the Act].” The EPAis considering whether to update theprocedures for acting on complete stateplans under the guideline to reflect theenhancements Congress included inCAA section 110 for agency actions onstate implementation plans.

The first mechanism is a partialapproval/partial disapproval. Where aCAA section 111(d) plan includesseverable provisions, some of which areapprovable and some of which are not,the EPA is taking comment on whetherthe agency should interpret the CAA asproviding the flexibility to approvethose elements that meet therequirements of this guideline, whiledisapproving those elements that donot. Any plan that is partially approvedand partially disapproved would notfully discharge the state’s obligation tosubmit a fully approvable plan, but thepartial approval would make federallyenforceable those elements of the state’splan that comply with these guidelines.

The second mechanism is aconditional approval. Where a CAAsection 111(d) plan is substantiallyapprovable and requires only minoramendments to fully meet therequirements of these guidelines, theEPA is taking comment on whether theagency should interpret the CAA asproviding the flexibility to approve thatplan on the condition that the statecommits to curing the minordeficiencies within one year. Any suchconditional approval would be treatedas a disapproval if the state fails tocomply with its commitment. Duringthe year following the conditionalapproval while the state works to cure



the deficiency identified in thecondition, the state’s plan would befederally enforceable.

The EPA has seen that thesemechanisms have proven useful whenreviewing and acting on stateimplementation plan submittals underCAA section 110. They allow the state,the EPA, and citizens to enforce goodelements of plans or plans that aresubstantially complete while the stateand the EPA work together to put inplace a fully approvable plan. Theagency notes that complete plansubmittals under these guidelines, likeSIPs that implement air qualitystandards, also may contain multipleprogram elements.

5. Failure To Submit a Complete PlanIf a state falls to submit a complete

plan by the applicable deadline, theEPA will notify the state by letter of itsfailure to submit. The EPA will publisha federal Register notice informing thepublic of any such notifications. Whenappropriate, the agency may batch thepublication of such notices periodicallyto simplify publication.

6. Modification of an Approved StatePlan

During the course of implementationof an approved state plan, a state maywish to update or alter one or more ofthe enforceable measures in the stateplan, or replace certain existingmeasures with new measures. The EPAproposes that the state may revise itsstate plan provided that the revisiondoes not result in reducing the requiredemission performance for affected EGUsspecified in the original approved plan.In other words, no “backsliding” onoverall plan emission performancethrough a plan modification would beallowed.

If the state wishes to reviseenforceable measures in its approvedstate plan, the EPA proposes that thestate must submit the revisedenforceable measures to the EPA anddemonstrate that the revised set ofenforceable measures in the modifiedplan will result in emissionperformance at affected EGUs that isequivalent to or better than the level ofemission performance required by theoriginal state plan. In the case of minorchanges to enforceable measures, thisshowing may be a simple explanation ofwhy the changes will not alter theemission performance of affected EGUsunder the state plan, or will clearlyimprove the emission performance ofaffected EGUs under the state plan. Inthe case of more substantive changes toenforceable measures, or substitution ofa new measure for an old measure, new

projections of emission performanceunder the modified plan would beneeded to demonstrate that the modifiedplan will meet the required level ofemission performance for affected EGUsspecified in the original approved plan.The EPA requests comment on whether,for such new projections of emissionperformance, the projection methods,tools, and assumptions used shouldmatch those used for the projection inthe original demonstration of planperformance, or should be updated toreflect the latest data and assumptions,such as assumptions for current andfuture economic conditions andtechnology cost and performance.

7. Plan Templates and ElectronicSubmittal

The EPA is seeking comment on thecreation of a template for initial andcomplete state plan submittals. A plantemplate would provide a frameworkthat includes all of the necessarycomponents for an initial and completesubmittal that could be populated bystates. This could assist states incompiling their plan submittals andstreamline EPA review by assuringgreater consistency in the format andorganization of submittals. This wouldprovide greater certainty for states aboutwhat they need to include in a submittaland allow the EPA to provide a quickerresponse to states about thecompleteness and approvability ofsubmittals. We are further seekingcomment on whether a template may bemore appropriate for initial plansubmittals than complete plans. Initialplan submittals are likely to be moresimilar across states, compared tocomplete plans, which may include adiverse range of components, dependingon the state plan approach.

The EPA is also seeking comment onwhether it should provide for, orrequire, electronic submittal of initialand complete plans. It is the EPA’sexperience that the electronic submittalof information increases the ease andefficiency of data submittal and dataaccessibility. We note that a number ofstates have requested an electronicsubmittal process for stateimplementation plans (SIPs) under CAAsection 110, and the EPA hasimplemented a pilot program with anumber of states for electronic submittalof such plans. The Electronic StateImplementation Plan Submission Pilot(eSIPS) includes an EPA-stateworkgroup that has developed and willevaluate an electronic submissionprocess. This pilot will use the EPA’sCentral Data Exchange (CDX) electronicsubmission system. We are seekingcomment on the suitability of such an

approach for submittal of state plansunder CAA section 111(d).

F. State Plan ConsiderationsThe EPA is proposing to give states

broad discretion to develop plans thatbest suit their circumstances and policyobjectives. In developing its plan, a statewill need to make a number of decisionsthat will require careful consideration,in order to ensure that its plan bothmeets the state’s policy objectives and isapprovable by the EPA. In this section,we identify several key decision pointsand factors that states should considerwhen developing their plans.

The EPA has also prepared a TSD,titled “State Plan Considerations,” thatprovides further information on thesetopics. The agency is seeking commenton the contents of this TSD and allaspects of the state plan decision pointsand factors below.

1. Affected Entities Other Than AffectedEGUs

A state will need to identify eachaffected entity responsible for meetingcompliance obligations under its planand the means by which compliancewith each plan requirement will be met,as well as demonstrate that it has thelegal authority to subject such entities tothe federally enforceable requirementsspecified in its state plan. We areproposing that affected entities in anapprovable state plan may include: Anowner or operator of an affected EGU,other affected entifies withresponsibilities assigned by a state (e.g.,an entity that is regulated by the state,such as an electric distribution utility,or a private or public third-party entity),and a state agency, authority or entity.We are seeking comment on otherappropriate examples of affected entitiesbeyond the affected EGUs.

While the EPA seeks to provide stateswith broad discretion to develop plansthat best suit their circumstances andpolicy objectives, a plan that assignsresponsibility to affected entities otherthan affected EGUs may be morechallenging to implement and enforcethan a plan with requirements assignedonly to affected EGUs.

Furthermore, it may be morechallenging for a state to demonstratethat it has sufficient legal authority tosubject such affected entities other thanaffected EGUs to the federallyenforceable requirements specified in itsstate plan. We seek comment onwhether the EPA should provideguidance on enforceabilityconsiderations related to requirementsin a state plan for affected entities otherthan EGUs (and if so, which suchentities). The State Plan Considerations



TSD provides illustrative examples ofpossible entities and legal mechanisms.

2. Treatment of Existing State Programsa. Framing Considerations

Many state officials and stakeholdershave said that the EPA should avoidstructuring the CAA section 111(d)emission guidelines in a way that woulddisadvantage states that already haveadopted programs that reduce CO2emissions from EGUs. The EPA agreeswith that policy principle.

There is much less agreement amongstates and stakeholders on the specificsof how existing state programs shouldbe treated in a demonstration that aproposed state plan will achieve therequired level of emission performance.

The EPA, starting from recenthistorical data, has identified theaffected EGU emission performanceimprovements and resulting averageemission performance levels for affectedEGUs that are achievable, consideringcost, in each state over the 2020—202 9period, with achievement of the finalCO2 emission performance level by2030.

As explained in Section VII above, theEPA’s proposed state-specific goalsreflect actions that many states havealready taken to reduce or avoid EGUCO2 emissions. CO2 emission reductionsdue to shifts to lower C02-emifflngpower generation are also represented inthe 2012 base period that was used toassess certain building blocks that areapplied in calculating a state emissionperformance goal.291

The agency recognizes that states thathave already shifted toward lowercarbon-intensity generation or rampedup demand-side EE programs are betterpositioned to meet state-specific goals.For example, states where significantshifts in generation to NGCC units havealready occurred would be closer to thegeneration mix reflected in the stategoals than states where NGCC capacityis not yet being operated to the samedegree. Likewise, states with relativelywell-established demand-side EEprograms would be able to build onthose programs more quickly than stateswith less established programs, andwould be closer to, or in some casesalready achieving, the level of demand-side energy efficiency reflected in thestate goals.

For example, in such instances a significantshift to NGCC generation prior to 2012 may resultin a lower potential for further re-dispatch to theseunits, as witnessed in the 2012 base period data.This would influence the calculated rate-basedemission goal for the state, reducing the percentageimprovement required relative to the base periodCO2 emission rate.

b. Proposed Approach for Treatment ofExisting State Programs and Measures inan Approvable State Plan

The EPA is proposing that existingstate programs, requirements, andmeasures,292 may qualify for use indemonstrating that a state plan willachieve the required level of emissionperformance, provided they meet theapprovability requirements in theemission guidelines (summarized abovein Section VIII.C) and relevantrequirements for plan components inthe emission guidelines (describedabove in Section Vffl.D). Several optionsfor treatment of existing state programsand measures are described below.

Specifically, the EPA is proposingthat, for an existing state requirement,program, or measure, a state may applytoward its required emissionperformance level the emissionreductions that existing state programsand measures achieve during a planperformance period as a result of actionstaken after the date of this proposal.293This proposed approach wouldrecognize beneficial emission impactsfrom existing state programs andmeasures during a plan performanceperiod. It would do so in a way that maybe generally compatible with theforward-looking methodology that theEPA used to propose state emissionperformance goals based on the BSER.By making actions taken after proposaleligible to help meet a state’s requiredemission performance level, thisapproach would support early beneficialemission-reducing actions. This optionwould ensure that actions taken afterproposal of the emission guidelines andprior to 2020 as a result of requirementsin a state plan, could be recognized ascontributing toward meeting a state’srequired emission performance level foraffected EGUs.

In general, the agency has identifiedtwo broad options for treatment ofexisting state programs and measures.As noted above, the EPA proposes thatemission reductions that existing staterequirements, programs and measures

292 An “existing measure” refers to a state orutility requirement, program, or measure that iscurrently “on the books.” For the purposes of thisdiscussion, this may include a legal requirementthat includes current and future obligations orcurrent programs and measures that are in placeand are anticipated to be continued or expanded inthe future in accordance with established plans.Existing measures may have past, current, andfuture impacts on EGU CO2 emissions.

293We are also proposing that this proposedlimitation would not apply to existing renewableenergy requirements, programs and measuresbecause existing renewable energy generation priorto the date of proposal of the emission guidelineswas factored into the state-specific CO2 goals as partof building block 3.

achieve during a plan performanceperiod as a result of actions taken aftera specified date may be recognized indetermining emission performanceunder a state plan. While proposing thatthe “specified date” would be the dateof proposal of these emissionguidelines, the EPA also requestscomment on the following alternatives:The start date of the initial planperformance period, the date ofpromulgation of the emissionguidelines, the end date of the baseperiod for the EPA’s BSER-based goalsanalysis (e.g., the beginning of 2013 forblocks 1—3 and beginning of 2017 forblock 4, end-use energy efficiency), theend of 2005, or another date.

For this option, we are seekingcomment on the point in time afterwhich such actions should be able toqualify for use during a planperformance period, considering themethod used to set state goals. Whetherthis option is consistent in practice withthe EPA’s application of the BSER maydepend on the date or dates that areapplied for qualifying actions underexisting state programs, requirements,and measures. For example,implementation of measures subsequentto the proposal or promulgation of theemission guidelines may be consistentwith a forward-looking goal-settingapproach, as these actions may benecessary to meet a required level ofemission performance during the planperformance period or will put a statein a better position to meet the requiredlevel of performance. An example is theEPA’s treatment of end-use energyefficiency potential in state goal-setting,where the energy savings achievableduring the initial plan performanceperiod are premised in part on aramping up of end-use energy efficiencyprograms and cumulative energysavings prior to the beginning of theplan performance period. Earlier datesmay also be consistent with a forward-looking goal-setting approach, if thegoal-setting approach is premised inpart on actions that could be taken priorto the initial plan performance period.However, inconsistency issues mayarise if the selected date is notadequately synchronized with the goal-setting method. The EPA requestscomment on whether there is a rationalbasis for choosing a date that predatesthe base period from which the EPAused historical data to derive state goals.The agency generally requests commenton the appropriate date to select underthis option.

The EPA also solicits comment on asecond broad option. This option wouldrecognize emission reductions thatexisting state requirements, programs



and measures achieved starting from aspecified date prior to the initial planperformance period, as well as emissionreductions achieved during a planperformance period. The specified datecould be, for example: The date ofpromulgation of the emissionguidelines; the date of proposal of theemission guidelines; the end date of thebase period for the EPA’s BSER-basedgoals analysis (e.g., the beginning of2013 for blocks 1—3 and the beginningof 2017 for block 4, end-use energyefficiency); the end of 2005; or anotherdate.

The EPA requests comment on thisoption—that emission reduction effectsthat occur prior to the beginning of theinitial plan performance period could beapplied toward meeting the requiredlevel of emission performance in a stateplan. This approach would enable astate to count emission improvementsachieved by state programs prior to 2020toward its interim goal, allowing thestate to begin demonstrating emissionperformance earlier and follow a moregradual emission improvementtrajectory during the interimperformance period of 2020—2 029. Thisapproach would in effect allow higheremissions during the 2020—2029 periodthan would occur under the proposedapproach (i.e., requiring less emissionperformance improvement during thatperiod). The rationale for this approachwould be that higher emissions in 2020—2029 would be offset by pre-2020emission reductions not required by theCAA section 111(d) program. However,total emissions to the atmosphere wouldlikely be greater under this approach,unless the pre-2020 emission reductionsthat can be counted toward the stategoal are limited to reductions thatwould not have occurred in the absenceof the CAA section 111(d) program. Tothe extent that states are able to bothadopt and implement new requirementsearlier than 2020 (e.g., by 2018 or 2019),this approach could provide anincentive for earlier emissionreductions. The agency requestscomment on whether pre-2020implementation of new requirementswould be practical for states. Theagency generally requests comment onthis approach, including the conditionsthat should apply to pre-2020 emissionreductions that would count toward thestate goal.

The agency also requests comment onthe alternative dates listed above inconnection with this option. We alsorequest comment on whether this optionis inconsistent with the forward-lookingmethod that the EPA has proposed forestablishing state goals based on theapplication of the BSER.

The agency is seeking comment onwhether some variation of this approachcould be justified as consistent with theEPA’s proposed goal-setting approach,as well as the general concept of theBSER and its application in establishingstate goals. In particular, we are seekingcomment on whether the emissioneffects of actions that are taken afterproposal or promulgation of theemission guidelines or the approval ofa state plan, but which occur prior tothe beginning of the initial state planperformance period, could be appliedtoward meeting the required level ofemission performance in a state plan.

c. Application of Options Under Rate-Based and Mass-Based Plan Approaches

Under a rate-based approach, theoptions described above would addressthe eligibility date for qualifyingdemand-side FE measures that, throughMWh savings, avoid CO2 emissionsfrom affected EGUs. Measures installedafter the eligibility date could generateIvfl’Vh savings during a planperformance period, and relatedavoided CO2 emissions, that could beapplied toward meeting a required rate-based emission performance level.Under the proposed option, theeligibility date would be the date ofthese proposed emission guidelines. Forexample, under this approach, newdemand-side EE measures installed in2015 or later to meet an existing, on-the-books energy efficiency resourcestandard (FERS) would be a qualifyingmeasure. However, only MWh savingsbeginning in 2020 and related avoidedCO2 emissions could be applied towardmeeting a required rate-based emissionperformance level.

Under a mass-based approach, theoptions described above would beapplied when establishing a referencecase scenario projection that is used totranslate a rate-based goal to a mass-based goal. For example, demand-sideEE measures after a respective eligibilitydate would not be included in thescenario that is used to project CO2emissions from affected EGUs whenestablishing a translated mass-basedemission goal. This could be achievedby not including the incrementalrequirements of an end-use EERSrequirement in a reference caseprojection, beginning at a specified date.These considerations are addressed inmore detail in Section Vffl.F.7. belowand in the Projecting CO2 EmissionPerformance in State Plans TSD.

3. Incorporating RE and Demand-SideEE Measures Under a Rate-BasedApproach

We are proposing that RE anddemand-side FE measures may beincorporated into a rate-based approachthrough an adjustment or tradable creditsystem applied to an EGU’s reportedCO2 emission rate.294 Under such aprocess, measures that avoid EGU CO2emissions from affected EGUs, such asquantified and verified end-use energysavings and renewable energygeneration, could be credited toward ademonstrated CO2 emission rate forEGU compliance purposes or used bythe state to administratively adjust theaverage CO2 emission rate of affectedEGUs when demonstrating achievementof the required rate-based emissionperformance level in a state plan.

Under this approach, affectedEGUs295 could comply with a CO2emission rate limit in part through theuse of credits for actions that avoid CO2emissions from affected EGUs. If a stateis implementing a portfolio approach,then the state could administrativelyadjust the average CO2 emission rate ofaffected EGUs through a similar process,provided that the CO2-avoithngmeasures are enforceable elements ofthe state plan.

We are seeking comment on differentapproaches for providing such creditingor administrative adjustment of EGUCO2 emission rates, which areelaborated further in the State PlanConsiderations TSD.

Credits or adjustment might representavoided MWh of electric generation oravoided tons of CO2 emissions. Theapproach chosen could have significantimplications for the amount ofadjustment or credit provided for REand demand-side FE measures. Ifadjustment or credits represent avoidedMWh, they would be added to thedenominator when determining anadjusted lb C02/MWh emission rate. Ifadjustment or credits represent avoidedCO2 emissions, they would besubtracted from the numerator whendetermining an adjusted lb CO2/MWhemission rate.

A MWh crediting or adjustmentapproach implicitly assumes that theavoided CO2 emissions come directlyfrom the particular affected EGU (orgroup of EGUs) to which the credits are

294We axe also proposing that RE arid demand-side EE measures could be used under a mass-basedportfolio approach in an approvable state plan.However, the focus of this section is limited toapplication of such measures under a rate-basedapproach.

295 This could include an individual affected ECUor group of affected EGUs if a rate-based averagingor trading approach is used.


34920 FederaiRegister/Vol. 79, No. 117/Wednesday, June 18, 2014/Proposed Rules

applied. It assumes, in effect, that anadditional emission-free MWh is beinggenerated by that respective ECU, andthat the RE or demand-side EE measurereduces CO2 emissions from thatindividual ECU or group of EGUs.296 Inpractice, the average or marginal CO2emission rate in the power pooi oridentified region—representing theavoided CO2 emissions from thegenerating sources being displaced by aMWh of energy savings or a MWh ofrenewable energy generation—coulddiffer significantly from the calculatedavoided CO2 emissions derived byadjusting the MWh output of an affectedEGU.

An alternative approach is to providean adjustment based on the estimatedCO2 emissions that are avoided from thepower pool or identified region as aresult of RE and demand-side EEmeasures. This approach implicitlyassumes that the avoided CO2 emissionscome from the electric power pool orother identified region as a whole,rather than an individual ECU. Theavoided CO2 emissions are determinedbased on the MWh saved or generated,multiplied by a CO2 emission rate forthe power pool or region. This CO2emission rate could be based on theaverage or marginal emission rate in thepower pool or region, or could be basedon the emission rate that represents therequired rate-based emissionperformance level in the plan. We invitecomment on each of these possibleapproaches.

In addition, because some of the CO2emissions avoided through RE anddemand-side EE measures may be fromnon-affected EGUs, we are seekingcomment on how this might beaddressed in a state plan, whether whenadjusting or crediting CO2 emissionrates of affected EGUs based on theeffects of RE and demand-side EEmeasures or otherwise. How thesedynamics might be addressed, both inprojections of plan performance and inactual demonstration of performanceachieved under a plan, is furtherdiscussed in the State PlanConsiderations TSD.

4. Quantification, Monitoring, andVerification of RE and Demand-Side EEMeasures

A key consideration for state plans isthe process and requirements under astate plan for quantifying, monitoring,

296As a result, the assumed avoided CO2emissions from an individual MWh of energysavings or MWh of generation from renewableenergy will differ based on the reported CO2emission rate of the individual EGU to which theMWh is applied as an adjustment to its MWhoutput.

and verifying the effect of RE anddemand-side EE measures that result inelectricity generation or electricitysavings.

The EPA is proposing that a state planthat includes enforceable RE anddemand-side FE measures must includean evaluation, measurement, andverification (EM&V) plan that explainshow the effect of these measures will bedetermined in the course of planimplementation. An EM&V plan willspecify the analytic methods,assumptions, and data sources that thestate will employ during the state planperformance periods to determine theenergy savings and energy generationrelated to RE and demand-side EEmeasures. An EM&V plan would besubject to EPA approval as part of a stateplan. As discussed below, the EPAintends to develop guidance onacceptable EM&V methods that could beincorporated in an approvable EM&Vplan that is included as part of anapprovable state plan.

Utilities and states have conductedongoing EM&V of demand-side EE andRE measures and programs for severaldecades. Current practice with EM&Vfor RE and demand-side EE programs inthe U.S. is primarily defined by statepublic utility commission (PUC)requirements for customer-fundedenergy efficiency and renewable energyprograms, as well as related complianceand reporting requirements for EERSand renewable portfolio standards(RPS).

The level of PUC oversight ofdemand-side EE programs varies fromstate to state, but this oversight processhas generated the majority of theindustry guidance and protocols fordocumenting energy savings from EEprograms. Typically, impact evaluationreports are responsive to requirementsestablished by PUCs and submitted(usually annually) for PUC review,approval, and use in resource planningand performance assessment. ThesePUC requirements generally rely upon awell-defined set of industry-standardpractices and procedures. In states withthe most experience implementing andoverseeing demand-side EE programs,this typically includes: Use of one ormore industry-standard EM&V protocolsor guidelines; use of “deemed savingsvalues,” 297 where appropriate, for well-understood demand-side EE measures;consideration of local factors, such as

297 Deemed savings are measure-specificstipulated values based on historical and verifieddata. Unlike other EM&V approaches, deemedsavings approaches involve limited or nomeasurement activities, and are therefore a commonand relatively low-cost strategy for documentingenergy savings.

climate, building type, and occupancy;involvement of stakeholders andsolicitation of expert advice regardingEM&V processes and resulting energysavings impacts; conduct of EM&Vactivities (e.g., direct equipmentmeasurements, application of deemedsavings, and reporting of impacts) on aregular basis; and provision of interimand annual reporting of achieved energysavings.

Despite this well-defined andgenerally accepted set of industrypractices, many states with energyefficiency programs use different inputvalues and assumptions in applyingthese practices (e.g., net versus grosssavings,298 run-time of equipment,measure lifetime). This can result insignificant differences in claimed energysavings values for similar energyefficiency measures between states andutilities, even when the same measuretype is installed under otherwiseidentical circumstances. In response toa growing awareness of this lack ofcross-state comparability, policymakers, regulatory agencies, and otherstakeholders are increasingly advocatingfor the use of common evaluationapproaches across jurisdictions. Anumber of states and utilities indifferent regions of the country arealready working to develop suchcommon approaches.

For RE measures and programs,EM&V employed by states and utilitiescommonly relies upon a set of standardpractices and procedures, such as theuse of revenue-quality meters forquantifying RE generation. As a result,existing state and utility requirementsand processes for quantification,monitoring, and verification of REprograms and measures generallyprovide a solid foundation for minimumrequirements or guidance established bythe EPA for state plans.

For both RE and demand-side FEmeasures included in state plans,additional information and reportingmay be necessary to accurately quantifythe avoided CO2 emissions associatedwith these measures, such asinformation on the location and thehourly, daily, or seasonal basis ofrenewable energy generation or energysavings.

Current state and utility EM&Vapproaches for RE and demand-side FEprograms and mandates are discussed inmore detail in the State Plan

298 Gross savings are the change in energy use(MWh) and demand (MW) that results directly fromprogram-related actions taken by programparticipants, regardless of why they participated ina program. Net savings refer to the change in energyuse and demand that is directly attributable to aparticular energy efficiency program.



Considerations TSD. We are seekingcomment on the suitability of theseapproaches in the context of anapprovable state plan, and on whetherharmonization of state approaches, orsupplemental actions and procedures,should be required in an approvablestate plan. In particular, we intend toestablish guidance for acceptablequantification, monitoring, andverification of RE and demand-side EEmeasures for an approvable EM&V plan,and are seeking comment on criticalfeatures of such guidance, includingscope, applicability, and minimumcriteria.299 We are also seeking commenton the appropriate basis for andtechnical resources used to establishsuch guidance, including considerationof existing state and utility protocols, aswell as existing international, national,and regional consensus standards orprotocols.30° The EPA’s goal indeveloping such guidance is to assurethat it is consistent with industry-standard EM&V approaches for both REand demand-side EE measures andprograms, leverages the EM&V resourcesand infrastructure already in place inmany states, and strikes a reasonablebalance between EM&V costs, rigor, andthe value of resulting information, whileconsidering the specific use of suchinformation in assessing avoided CO2emissions from affected EGUs.

In developing guidance, the agencydoes not intend to limit the types of REand demand-side EE measures andprograms that can be included in a stateplan, provided that supporting EM&V isrigorous, complete, and consistent withthe EPA’s guidance. This approachrecognizes differences among RE anddemand-side EE programs and measureswith respect to implementation historyand experience, existence of applicableEM&V protocols and methods, and thenature and type of program oversight(e.g., whether or not a program is subjectto PUC oversight). The EPA isrequesting comment on the merits ofthis approach, including whether suchguidance should identify types of REand demand-side EE measures andprograms for which evaluation of resultsis relatively straightforward and whichare appropriate for inclusion in a stateplan. Such approaches might be subjectto streamlined review of EM&Vprotocols included in an approvablestate plan, provided that such protocolsare applied in accordance with industrybest practices. For example, many

299 Section V.A.4 of the State Plan ConsiderationsTSD includes a detailed description of these EM&Vparameters

300A list of these protocols is provided in SectionV.A.3.1 of the State Plan Considerations TSD.

utilities have implemented a similarcore set of RE and demand-side EEmeasures and programs for utilitycustomers. For these types of measuresand programs, a substantial base ofexperience has been establishednationally for the evaluation of measureand program outcomes. Other types ofmeasures and programs, such as thosethat seek to alter consumer and buildingoccupant behavior might posequantification and verificationchallenges. Still other types ofmeasures, such as state energy-efficientappliance standards and building codes,have not typically been subject tosimilar evaluation of energy savingsresults. These types of approaches mighthave substantial impacts, and the EPAdoes not want to discourage theirimplementation in state plans, but theymight require development ofappropriate quantification, monitoring,and verification protocols. The EPA andits federal partners intend to discuss thedevelopment of appropriate EM&Vprotocols for such measures with statesin the coming years.

As an alternative to the EPA’sproposed approach of allowing a broadrange of RE and demand-side EEmeasures and programs to be includedin state plans, provided that supportingEM&V documentation meets applicableminimum requirements, the EPA isrequesting comment on whetherguidance should limit consideration tocertain well-established programs, suchas those characterized in SectionV.A.4.2.1 of the State PlanConsiderations TSD.

5. Reporting and Recordkeeping forAffected Entities Implementing RE andDemand-Side EE Measures

If a state plan incorporates RE anddemand-side EE measures under a rate-based approach or implements a mass-based portfolio approach with suchmeasures, reporting and recordkeepingrequirements for an approvable planwould differ from those applicable to anaffected EGU. For example, theserequirements may include compliancereporting by an electric distributionutility subject to an EERS or RPS. Theymay also include reporting by avertically integrated utilityimplementing an approved integratedresource plan. In the latter instance, theutility might also be the owner andoperator of affected EGUs, butadditional reporting of quantified effectsof RE and demand-side EE measuresunder the utility plan would benecessary to demonstrate emissionperformance under the state plan. Inother instances, a state agency or entityor a private or public third-party entity

might be implementing programs andmeasures that support the deploymentof end-use energy efficiency and cleanenergy technologies that areincorporated into a state plan. In eachof these instances, reporting of programcompliance or program outcomes is anecessary part of an approvable plan todemonstrate emission performanceunder the plan.

Examples of potential reportingobligations for affected entitiesimplementing RE and demand-side EEmeasures in an approvable state plan areprovided in the State PlanConsiderations TSD. We are seekingcomment on the examples andsuitability of potential approachesdescribed in the TSD and any otherappropriate reporting and recordkeepingrequirements for affected entitiesbeyond affected EGUs.

6. Treatment of Interstate EffectsThe electricity system and wholesale

electricity markets are interstate innature. EGUs in one state provideelectricity to customers in neighboringstates. Power companies often ownEGUs in more than one state andmanage them as a system. EGUs aredispatched both within and across stateborders.

Similarly, programs and measures ina state plan, such as RE and demand-side FE measures, may affect theperfonnance of the interconnectedelectricity system beyond a state border.In addition, many state programs allowfor actions in neighboring states to meetthe in-state requirement or explicitlyaddress CO2 emissions in neighboringstates. For example, many staterenewable portfolio standards allow forgeneration by qualifying renewableenergy sources in other states to counttoward meeting the state portfoliorequirement. Some states also apply CO2emission requirements related to thegeneration of power purchased byregulated utilities, including powerimported from out of state.

The EPA recognizes the complexity ofaccounting for interstate effectsassociated with measures in a state planin a consistent manner, to allow statesto take into account the CO2 emissionreductions resulting from theseprograms while minimizing thelikelihood of double counting. We alsorealize that interstate effects on CO2emissions from affected EGUs could beattributed in different manners in thecontext of an approvable state plan. TheEPA is seeking comment on the optionssummarized below, as well asalternatives. These options andalternatives, and how they might applyto both projections of plan performance



and reporting of achieved planperformance, are addressed in the StatePlan Considerations TSD.

The EPA is proposing that, fordemand-side EE measures, consistentwith the approach that the EPA used indetermining the 3SER, a state could takeinto account in its plan only those CO2emission reductions occurring (orprojected to occur) in the state thatresult from demand-side EE measuresimplemented in the state. The agency isalso proposing that, for states thatparticipate in multi-state plans, theparticipating states would have theflexibility to distribute the CO2 emissionreductions among states in the multistate area, as long as the total CO2emission reductions claimed are equalto the total of each state’s in-stateemissions reductions that result fromdemand-side EE measures implementedin those states. We are also proposingthat states could jointly demonstrateCO2 emission performance by affectedEGUs through a multi-state plan in acontiguous electric grid region, in whichcase attribution of emission reductionsfrom demand-side EE measures wouldnot be necessary. We also requestcomment on whether a state should beable to take credit for emissionreductions out of state due to in-state EEmeasures if the state can demonstratethat the reductions will not be double-counted when the relevant states reporton their achieved plan performance, andwhat such a demonstration shouldentail. We request comment on theseand other approaches for taking intoaccount CO2 emission reductions fromdemand-side EE measures in state plans.

The EPA is proposing that, forrenewable energy measures, consistentwith existing state RPS policies, a statecould take into account all of the CO2emission reductions from renewableenergy measures implemented by thestate, whether they occur in the state orin other states. This proposed approachfor RE acknowledges the existence ofrenewable energy certificates (REC) thatallow for interstate trading of REattributes and the fact that a givenstate’s RPS requirements often allow forthe use of qualifying RE located inanother state to be used to comply withthat state’s RPS.

The EPA is also seeking comment onhow to avoid double counting emissionreductions using this proposedapproach. The agency is also proposingthat states participating in multi-stateplans could distribute the CO2 emissionreductions among states in the multistate area, as long as the total CO2emission reductions claimed are equalto the total of each state’s in-stateemission reductions from RE measures.

We also request comment on the optionof allowing a state to take into accountonly those CO2 emission reductionsoccurring in its state. We are alsoproposing that states could jointlydemonstrate CO2 emission performanceby affected EGUs through a multi-stateplan in a contiguous electric grid region,in which case attribution among statesof emission reductions from renewableenergy measures would not benecessary. We also request comment onwhether a state should be able to takecredit for emission reductions out ofstate due to renewable energy measuresif the state can demonstrate that thereductions will not be double-countedwhen the relevant states report on theirachieved plan performance, and onwhat such a demonstration shouldentail. We request comment on theseand other approaches for taking intoaccount CO2 emission reductions fromrenewable energy measures.

7. Projecting Emission PerformanceAs proposed, an approvable state plan

will include a projection of CO2emission performance by affected EGUsunder the plan. in addition, a state planthat is using a mass-based goal indetermining the required level ofemission performance under the planwill include a translation of the rate-based emission goal in the emissionguidelines to a mass-based goal. Thistranslation will involve a projection ofCO2 emissions from affected EGUsduring the initial 2020—2029 planperformance period and in 2030, undera scenario that assumes the rate-basedgoal in the emission guidelines is met.

The EPA is striving to find a balancebetween providing state implementationflexibility and ensuring that theemission performance required by CAAsection 111(d) is properly defined instate plans and that plan performanceprojections have technical integrity.Each state plan must include aprojection of CO2 emission performancefrom affected EGUs during the multi-year plan period that will result fromimplementation of the plan. Dependingon the type of plan approach, this willinclude either a projection of theaverage CO2 emission rate achieved byaffected EGUs or total CO2 emissionsfrom affected EGUs.

The credibility of state plans underCAA section 111(d) will depend in largepart on ensuring credible and consistentemission performance projections instate plans. Therefore, the use ofappropriate methods, tools andassumptions for such projections iscritical.

Considerations for projectingemission performance under a state plan

will differ depending on the type ofplan. This includes differences in howinputs to projections are derived; howprojections are conducted, includingtools, methods and assumptions; andhow aspects of a plan are represented inthese projections.

in general, any material component ofa state requirement or program includedin a state plan that could affect emissionperformance by affected EGUs should beaccurately represented in emissionprojections included in the state plan.

For example, mass-based emissionbudget trading programs include anumber of compliance flexibilitymechanisms that might impact emissionperformance achieved by affected EGUssubject to these programs. These includemulti-year compliance periods; theability to bank allowances issued in aprevious compliance period for use in asubsequent compliance period; the useof out-of-sector project-based emissionoffsets; and cost-containment allowancereserves that make additionalallowances available to the market ifpre-established allowance pricethresholds are achieved. As a result,annual emissions from affected sourcessubject to an emission budget tradingprogram often differ from theestablished annual emission budget foraffected sources. In addition, theseprograms may be multi-sector in nature,regulating emissions for sourcecategories in addition to EGUs. As aresult, emission projections in stateplans will need to accurately accountfor and represent these complianceflexibilities, as well as the scope ofaffected sources if they are broader thanEGUs affected under CAA section111(d). Similarly, other types of stateprograms, such as RPS, may includeflexibility mechanisms or otherprovisions, such as alternativecompliance payment mechanisms,banking, and limits on total ratepayerimpact, that affect the ultimate amountof electricity generation required underthe portfolio standard. Theseconsiderations for different types ofstate programs are discussed in moredetail in the Projecting EGU CO2Emission Performance in State PlansTSD.

in general, as with projections used todetermine a mass-based goal,projections of emission performanceunder a state plan could be conductedusing historical data and parameters forestimating the future impact ofindividual state programs and measures.Alternatively, a projection couldinclude modeling, such as use of acapacity planning and dispatch



model.301 This latter approach would beable to capture dynamic interactionswithin the electricity sector, based onsystem operation and market forces,including interactions among stateprograms and measures and thedynamics of market-based measures.

These considerations, andconsiderations for projecting emissionperformance under different types ofstate plan approaches, are discussed indetail in the Projecting EGU CO2Emission Performance in State PlansTSD.

We are seeking comment on theconsiderations discussed in this TSD,including options presented for howprojections might be conducted in anapprovable state plan, and how differenttypes of state plan approaches arerepresented in these projections. We areseeking further comment on whether theEPA should develop guidance thatdescribes acceptable projectionapproaches, tools, and methods for usein an approvable plan, as well asproviding technical resources forconducting projections.

The ISO/RTO Council, anorganization of electric grid operators,has suggested that ISOs and RTOs couldprovide analytic support to help statesdevelop and implement their plans. TheISOs and RTOs have the capability tomodel the system-wide effects ofindividual state plans. Providingassistance in this way, they felt, wouldallow states with borders that fall withinan ISO or RTO footprint to assess thesystem-wide impacts of potential stateplan approaches. In addition, as thestate implements its plan, ISO/RTOanalytic support would allow the stateto monitor the effects of its plan on theregional electricity system. ISOIRTOanalytic capability could help statesassure that their plans are consistentwith region-wide system reliability. TheISO/RTO Council suggested that theEPA ask states to consult with theapplicable ISO/RTO in developing theirstate plans. The EPA agrees with thissuggestion and encourages states withborders that fall within one or more ISOor RTO footprints to consult with therelevant ISOs/RTOs.

8. Potential Emission ReductionMeasures Not Used To Set ProposedGoals

States may include measures in theirplans beyond those that the EPAincluded in its determination of theBSER. In general, any measures that

301 In many cases, this approach will also requirethe development of parameters for estimating thefuture effect of individual state programs andmeasures, for use as input assumptions formodeling.

meet the proposed criteria forapprovable state plans could beemployed in a state plan. Beyond that,under a mass-based approach, anymeasure that reduces affected EGUemissions—even if not included in thestate plan—will, if implemented duringa plan performance period, help toachieve actual emissions performancethat meets the required level.

Beyond the types of state planmeasures already discussed in thissection of the preamble, the agency hasidentified a number of other measuresthat could also lead to CO2 emissionreductions from EGUs. These include,for example, electricity transmissionand distribution efficiencyimprovements, retrofitting affectedEGUs with partial CCS, the use ofbiomass-derived fuels at affected EGUs,and use of new NGCC units. Althoughthe emission reduction methodsdiscussed in this section are notproposed to he part of the BSER, theagency anticipates that some states maybe interested in using these approachesin their state plans. The agency solicitscomment on whether these measures areappropriate to include in a state plan toachieve CO2 emission reductions fromaffected EGUs. In addition to thespecific requests for comment related tospecific technologies below, we alsorequest comment on other measures thatwould be appropriate. In addition, werequest comment on whether the EPAshould provide specific guidance oninclusion of these measures in a stateplan.

In addition, technological advancesand innovations in energy and pollutioncontrol technologies will continue overtime. The agency is aware that as newtechnologies become available or ascosts of a technology drop because oftechnical advances, states may wish toinclude measures in their state plansthat make use of those technologies.

To be more specific, there aremultiple potential measures that can betaken at an EGU beyond heat rateimprovements that will reduce CO2emissions. Some examples are:Including co-firing of less CO2 intensivefuels such as natural gas, retrofit ofpartial CCS and use of integratedrenewable technology (i.e. meeting someof the steam load in a steam turbinefrom a fossil unit and part of the steamload from a concentrating solarinstallation), and improving heat ratesof oil- and gas-fired generating units.Co-firing of natural gas and the use ofCCS could be incorporated into a stateplan demonstration of emissionperformance as a reduction in theemission rate at an affected ECU inexactly the same way that heat rate

reductions could be quantified. In thecase of an integrated renewable andfossil unit, reductions could either bequantified as a reduction in rate, or therenewable component could bequantified in the same way otherrenewable reductions are quantified inthe state plan.

In addition to the nuclear generationtaken into account in the state goalsanalysis, any additional new nucleargenerating units or uprating of existingnuclear units, relative to a baseline ofcapacity as of the date of proposal of theemission guidelines, could be acomponent of state plans. This baselinewould be consistent with the proposedapproach for treatment of existing stateprograms. The agency requests commenton alternative nuclear capacitybaselines, including whether the datefor recognizing additional non-BSERnuclear capacity should be the end ofthe base year used in the BSER analysisof potential nuclear capacity (i.e., 2012).In general, when considering nucleargeneration in a state plan, states maywish to consider the impacts thatdifferent types of policies may have ondifferent types of zero-emittinggeneration. Under a capped approachwhich does not provide any “crediting”for zero-emitting generation, the impacton all zero-emitting units should be thesame. In a rate based approach thatcredited zero or low-emittinggeneration, the crediting mechanismused could result in different economicimpacts on different types of zero- orlow-emitting generation.

Another way that a state plan couldreduce utilization and emissions fromaffected existing EGUs would bethrough construction of new NGCC—that is, NGCC on which constructioncommences after the date of proposal orfinalization of CAA section 111(b)standards applicable to that source. (Theagency’s CAA section 111(d) proposaldoes not include new NGCC as acomponent of the BSER, but requestscomment on that question in Section VIof this preamble.) Under a mass-basedplan where an emission limit onaffected EGUs would assureachievement of the required level ofemission performance in the state plan,any emission reductions at affectedEGUs resulting from substitution of newNGCC generation for higher-emittinggeneration by existing affected EGUswould automatically be reflected inmass emission reductions from affectedEGUs. A state would not need toinclude enforceable provisions for newNGCC in its plan, under such anapproach. However, under a mass-basedportfolio approach, enforceablemeasures in a state plan might include



construction of new NGCC to replaceone or more affected EGUs, perhaps aspart of a utility WP and related PUCorders. Again, the effects of new NGCCgeneration would be realized in reducedmass emissions from affected EGUs.

The agency requests comment on howemissions changes under a rate-basedplan resulting from substitution ofgeneration by new NGCC for generationby affected EGUs should be calculatedtoward a required emission performancelevel for affected EGUs. Specifically,considering the legal structure of CAAsection 111(d), should the calculationconsider only the emission reductions ataffected EGUs, or should the calculationalso consider the new emissions addedby the new NGCC unit, which is not anaffected unit under section 111(d)?Should the emissions from a new NGCCincluded as an enforceable measure ina mass-based state plan (e.g., in a planusing a portfolio approach) also beconsidered?

Similar to zero-emitting generation,states may also want to considerwhether the policy design they choosesends similar or different price signalsto new and existing NGCC. For instance,under a mass based program, if newNGCCs were not included, their costswould be less than the cost of anexisting NGCC unit.

In respect to new fossil fuel-firedEGUs, the agency also requestscomment on the concept of providingcredit toward a state’s required CAAsection 111(d) performance level foremission performance at new CAAsection 111(b) affected units that,through application of CCS, is superiorto the proposed standards ofperformance for new EGUs. Because theEPA proposed to find that the BSER fornew fossil fuel-fired boilers and IGCCunits is only a partial application ofCCS, we recognize that there is thepotential for such units, if constructed,to obtain additional emission reductionsby increasing the level of CCS andoutperforming the proposedperformance standards. In some casesthese incremental emission reductionsmay represent a cost effective abatementoption for states and would provide anincentive for the deployment andadvancement of CCS. We invitecomment on whether incrementalemission reductions from new fossilfuel-fired boilers and IGCC units withCCS, based on exceeding the CAAsection 111(b) performance standardsfor such units, should be allowed as acompliance option to help meet theemission performance level requiredunder a CAA section 111(d) state plan.

Similarly, while the EPA did notpropose to establish standards of

performance for new NGCC units basedon CCS under CAA section 111(b), werecognize that if a new NGCC unit wereto be constructed with a CCS system, itcould achieve a lower CO2 emission ratethan required by the proposed standardsof performance for new NGCC units. Weinvite comment on whether incrementalemission reductions from new NGCCunits that outperform the performancestandards for such units under CAAsection 111(b) based on the use of CCSshould be allowed as a complianceoption to help meet the emissionperformance level required under aCAA section 111(d) state plan.

Building block 4 focuses onimproving end-use energy efficiency.Another way to reduce the utilizationof, and CO2 emissions from, affectedEGUs is through electricity transmissionand distribution upgrades that reduceelectricity losses during the delivery ofelectricity to end users. Just as end-useenergy efficiency can reduce massemissions from affected EGUs, so cantransmission upgrades.

In addition, electricity storagetechnologies have the potential toenhance emission performance byreducing the need for fossil fuel-firedEGUs to provide generation duringperiods when intermittent wind andsolar generation are unavailable due tonatural conditions. States may wish toconsider this possibility as theyconsider options for design of theirplans.

The agency requests comment onwhether industrial combined heat andpower approaches warrantconsideration as a potential way toavoid affected ECU emissions, andwhether the answer depends oncircumstances that depend on the typeof CHP in question.

Many of the decisions that states willmake while developing complianceapproaches are fundamentally statedecisions that will have impacts onissues important to the state, includingcost to consumers and broader energypolicy goals, but will not impact overallemission performance. Some decisions,however, may impact emissionperformance and exemplify the kinds ofdecisions and approaches states may beinterested in pursuing. In light of thebroad latitude that the EPA is seeking toafford the states, including latitude toadopt measures such as those discussedin this subsection, the EPA intends tomake additional technical resourcesavailable and consider developingguidance for states, should they needsuch support in exploring and adoptingthese options. The EPA, in addition,requests comment on whether there arestill other areas beyond those discussed

above for which it would be useful forthe EPA to provide guidance.

Through President Obama’s ClimateAction Plan, the Administration isworking to identify new approaches toprotect and restore our forests, as wellas other critical landscapes includinggrasslands and wetlands, in the face ofa changing climate. Sustainable forestryand agriculture can improve resiliencyto climate change, be part of a nationalstrategy to reduce dependence on fossilfuels, and contribute to climate changemitigation by acting as a “sink” forcarbon. The plant growth associatedwith producing many of the biomassderived fuels can, to varying degrees fordifferent biomass feedstocks, sequestercarbon from the atmosphere. Forexample, America’s forests currentlyplay a critical role in addressing carbonpollution, removing nearly 12 percent oftotal U.S. greenhouse gas emissionseach year. As a result, broadly speaking,burning biomass-derived fuels forenergy recovery can yield climatebenefits as compared to burningconventional fossil fuels.

Many states have recognized theimportance of forests and other lands forclimate resilience and mitigation andhave developed a variety of differentsustainable forestry policies, renewableenergy incentives and standards andgreenhouse gas accounting procedures.Because of the positive attributes ofcertain biomass-derived fuels, the EPAalso recognizes that biomass-derivedfuels can play an important role in CO2emission reduction strategies. Weanticipate that states likely will considerbiomass-derived fuels in energyproduction as a way to mitigate the CO2emissions attributed to the energy sectorand include them as part of their plansto meet the emission reductionrequirements of this rule, and we thinkit is important to define a clear path forstates to do so.

To better understand the impacts ofusing different types of biomass-derivedfuels, the EPA is assessing the use ofbiomass feedstocks for energy recoveryby stationary sources and has developeda draft accounting framework that theEPA’s Science Advisory Board (SAB)has reviewed. The draft frameworkconcluded that while biomass and otherbiogenic feedstocks have the potential toreduce the overall level of CO2emissions resulting from electricitygeneration, the contribution of biomassderived fuels to atmospheric CO2 issensitive to the type of biomassfeedstock used, and the way in whichthe feedstock is grown, processed, andultimately combusted as a fuel forenergy production. The SAB in itsreview similarly found that there are



circumstances in which biomass isgrown, harvested and combusted in acarbon neutral fashion but commentedthat additional considerations arewarranted.

The EPA is in the process of revisingthe draft framework and consideringnext steps, taking into account both thecomments provided by the SAB andfeedback from stakeholders. The EPA’sbiogenic CO2 accounting framework isexpected to provide importantinformation regarding the scientificbasis for assessing these biomassderived fuels and their net atmosphericcontribution of CO2 related to thegrowth, harvest and use of these fuels.This information should assist bothstates and the EPA in assessing theimpact of the use of biomass fuels inreaching emission reduction goals in theenergy sector under state plans tocomply with the requirements in theemission guidelines.

9. Consideration of a Facility’s“Remaining Useful Life” in ApplyingStandards of Performance

In this section, the EPA discusses therelevance to this rule of the EPAregulations implementing the CAAsection 11i(d)(i) provision “permit[ing]the State in applying a standard ofperformance to any particular sourceunder a [111(d)] plan. . . to take intoconsideration, among other factors, theremaining useful life of the existingsource to which such standard applies.”

For the reasons discussed below, theEPA is proposing that, in this case, theflexibility provided in the state plandevelopment process adequately allowsfor consideration of the remaininguseful life of the affected facilities andother source-specific factors and,therefore, that separate application ofthe remaining useful life provision bystates in the course of developing andimplementing their CAA section 111(d)plans is unnecessary. The agency isrequesting comment on its analysisbelow of the implications of the EPA’sexisting regulations interpreting “usefullife” and “other factors” for purposes ofthis nflemaking.302 The agency alsorequests comment on whether it wouldbe desirable to include in regulatory textany aspects of this preamble discussionabout how the provisions in the existingimplementing regulations concerningsource-specific factors relate to thisemission guideline.

This section addresses the legalbackground concerning facility-specificconsiderations and the implications for

302 agency is not reopening or consideringchanges to this provision of the implementingregulations.

implementation of these emissionguidelines, including state emissionsperformance goals.

a. Legal BackgroundThe EPA’s 1975 implementing

303 address remaining usefullife and other facility-specific factorsthat might affect requirements for anexisting source under section 111(d).Those regulations provide that for apollutant such as GHGs, which havebeen found to endanger public health,standards of performance in state plansmust be as stringent as the EPA’semission guidelines. Deviation from thestandard might be appropriate wherethe state demonstrates with respect to aspecific facility (or class of facilities):

(1) Unreasonable cost of controlresulting from plant age, location, orbasic process design;

(2) Physical impossibility of installingnecessary control equipment; or

(3) Other factors specific to the facility(or class offacilities) that makeapplication of a less stringent standardor final compliance time significantlymore reasonable.

The reference to “[u]nreasonable costof control resulting from plant age”implements the statutory provision onremaining useful life. The languageconcerning plant location, basic processdesign, physical impossibility ofinstalling controls, and “other factors”addresses facility-specific issues otherthan remaining useful life that the EPAdetermined that in some circumstancescan affect the reasonableness of acontrol measure for a particular existingsource.

This regulatory provision provides theEPA’s default structure forimplementing the remaining useful lifeprovision of CAA section 111(d). Theopening clause, however, whichprovides that this provision isapplicable “unless otherwise specifiedin the applicable subpart” makes clearthat this structure may not beappropriate in each case and that theEPA has discretion to alter the extent towhich states may authorize relaxationsto standards of performance that wouldotherwise apply to a particular source orsource category, if appropriate under thecircumstances of the specific sourcecategory and proposed guidelines.

b. Implications for Implementation ofThese Emission Guidelines

In general, the EPA notes that theimplementing regulation provisions forremaining useful life and other facility-specific factors are relevant for emissionguidelines in which the EPA specifies a

30340 CFR 60.24(f).

presumptive standard of performancethat must be fully and directlyimplemented by each individualexisting source within a specifiedsource category. Such guidelines aremuch more like a CAA section 111(b)standard in their form. For example, theEPA emission guidelines for sulfuiicacid plants, phosphate fertilizer plants,primary aluminum plants, and Kraftpulp plants specify emission limits forsources.304 In the case of such emissionguidelines, some individual sources, byvirtue of their age or other uniquecircumstances, may warrant specialaccommodation.

In these proposed guidelines for stateplans to limit CO2 from affected EGUs,the agency does not take that approach.Instead, the EPA is proposing toestablish state emission performancegoals for the collective group of affectedEGUs in a state, leaving to each state thedesign of the specific requirements thatfall on each affected EGU. Due to theinherent flexibility in the EPA’sapproach to establishing the state-specific goals, and the flexibilityprovided to states in developingapprovable CAA section 111(d) plans toachieve those goals, the EPA’sguidelines contain no emissionstandards that the state must applydirectly to a specific EGU; therefore, norelief for individual facilities would beneeded.

Rather, because of the flexibility forstates to design their own standards, thestates have the ability to address theissues involved with “remaining usefullife” and “other factors” in the initialdesign of those standards, which wouldoccur within the framework of the CAAsection 111(d) plan developmentprocess. States are free to specifyrequirements for individual EGUs thatare appropriate considering remaininguseful life and other facility-specificfactors.

Therefore, to the extent that aperformance standard that a state maywish to adopt for affected EGUs raisesfacility-specific issues, the state is freeto make adjustments to a particularfacility’s requirements on facility-specific grounds, so long as any suchadjustments are reflected (along with

See “Phosphate Fertilizer Plants; FinalGuideline Document Availability,” 42 FR 12,022(Mar. 1, 1977); “Standards of Performance for NewStationary Sources; Emission Guideline for SulfuricAcid Mist,” 42 FR 55,796 (Oct. 18, 1977); “KraftPulp Mills, Notice of Availability of Final GuidelineDocument,” 44 FR 29,828 (May 22, 1979); “PrimaryAluminum Plants; Availability of Final GuidelineDocument,” 45 FR 26,294 (Apr. 17, 1980);“Standards of Performance for New StationarySources and Guidelines for Control of ExistingSources: Municipal Solid Waste Landfills, FinalRule,” 61 FR 9905 (Mar. 12, 1996).



any necessary compensating emissionreductions), as part of the state’s CAAsection 111(d) plan submission. Theagency requests comment on itsinterpretation.

c. Relationship to State EmissionPerformance Goals and Timing ofAchievement

The EPA also believes that, because ofthe way the state-specific goals havebeen developed in these proposedguidelines, remaining useful life andother facility-specific considerationsshould not affect the determination of astate’s rate-based or mass-basedemission performance goal or the state’sobligation to develop and submit anapprovable CAA section 111(d) planthat achieves that goal by the applicabledeadline.

Under the proposed guideline, stateswould have the flexibility to adopt astate plan that relies on emission-reducing requirements that do notrequire affected EGUs with a shortremaining useful life to make majorcapital expenditures 305 or incurunreasonable costs. Indeed, the EPA’sproposal would provide states withbroad flexibility regarding ways toimprove emission performance throughutilizing the emissions reductionmethods represented by the four“building blocks.”

We also note that a state is notrequired to achieve the same level ofemission reductions with respect to anyone building block as assumed in theEPA’s BSER analysis. If a state prefersnot to attempt to achieve the level ofperformance estimated by the EPA for aparticular building block, it cancompensate through over-achievementin another one, or employ othercompliance approaches not factoredinto the state-specific goal at all. TheEPA has estimated reasonable ratherthan maximum possible implementationlevels for each building block in orderto establish overall state goals that areachievable/while allowing states to takeadvantage of the flexibility to pursuesome building blocks more aggressively,and others less aggressively, than isreflected in the goal computations,according to each state’s needs andpreferences.

305 The agency requests comment on whetherthere are circumstances other than a major capitalinvestment that could lead to a prospective stateplan imposing unreasonable costs considering afacility’s remaining useful life. Where annual costspredominate and/or capital costs do not constitutea major expense, the EPA believes that theremaining useful life of an affected EGU will notsignificantly affect its annualized cost of controland therefore should not be a factor in determiningcontrol requirements for the EGU.

Of the four building blocksconsidered by the EPA in developingstate goals, only the first block, heat rateimprovements, involves capitalinvestments at the affected EGUs which,if mandated by a state rule, might giverise to remaining useful lifeconsiderations at a particular facility.The other building blocks—re-dispatchamong affected sources, addition of newgenerating capacity, and improvementin end-use energy efficiency—do notgenerally involve capital investments bythe owner/operator at an affected EGU.

In the case of heat rate improvementsat affected EGUs, states can choosewhether to require a greater or lesserdegree of heat rate improvement thanthe 6 percent improvement assumed inthe EPA’s proposed BSERdetermination, either because of theremaining useful life of one or moreEGUs, other source-specific factors thatthe state deemed appropriate toconsider, or any other relevant reasons.The agency also notes that any capitalexpenditures would be much smallerthan capital expenditures required forexample, for purchase and installationof scrubbers to remove sulfur dioxide; afleet-wide average cost for heat rateimprovements at coal-fired generatingunits is $100/kW, compared with atypical SO2 scrubber cost of $500/kw(costs vary with unit size).306 Inaddition, the proposed guideline allowsstates to regulate affected EGUs throughflexible regulatory approaches that donot require affected EGUs to incur largecapital costs (e.g., averaging and tradingprograms). Under the EPA’s proposedapproach—establishing state goals andproviding states with flexibility in plandesign—states have flexibility to makeexactly the kind of judgments necessaryto avoid requirements that would resultin stranded assets.

Remaining useful life and otherfactors, because of their facility-specificnature, are potentially relevant indetermining requirements that aredirectly applicable to affected EGUs. Forall of the reasons above, the agencybelieves that the issue of remaininguseful life will arise infrequently in thedevelopment of state plans to limit CO2emissions from affected existing EGUs.Even if relief is due a particular facility,the state has an available toolbox ofemission reduction methods that it canuse to develop a section 111(d) plan thatmeets its emissions performance goal on

Heat rate improvement methods and relatedcapital costs are discussed in the GHG AbatementMeasures TSD; SO2 scrubber capital costs are fromthe documentation for the EPA’s 1PM Base Casev5.13, Chapter 5, Table 5—3, available at hup://wwsv.epa.gov/powersectormodeling/BaseCasev5l3.html

time. The EPA therefore proposes thatthe remaining useful life of affectedEGUs, and the other facility-specificfactors identified in the existingimplementing regulations, should not beconsidered as a basis for adjusting astate emission performance goal or forrelieving a state of its obligation todevelop and submit an approvable planthat achieves that goal on time. Theagency solicits comment on thisposition.

10. Design, Equipment, Work Practice,or Operational standards

In this section, we discuss whetherstate plans may include design,equipment, work practice, oroperational standards.

CAA section 111(h)(1) authorizes theAdministrator to promulgate “a design,equipment, work practice, oroperational standard, or combinationthereof,” if in his or her judgment, “itis not feasible to prescribe or enforce astandard of performance.” CAA section111(h)(2) provides the circumstancesunder which prescribing or enforcing astandard of performance is “notfeasible”: generally, when the pollutantcannot be emitted through a conveyancedesigned to emit or capture thepollutant, or when there is nopracticable measurement methodologyfor the particular class of sources. Otherprovisions in section 111(h) furtherprovide that a design, equipment, workpractice, or operational standard (i)must “be promulgated in the form of astandard of performance whenever itbecomes feasible” to do so,307 and (ii)must “be treated as a standard ofperformance” for purposes of, ingeneral, the CAA.308

As noted above, CAA section 111(d)requires that state plans “establish[Jstandards of performance” as well as“provide[] for the implementation andenforcement of such standards ofperformance.” CAA section 111(d) issilent as to whether (1) states mayinclude design, equipment, workpractice, or operational standards, or (ii)they may include those types ofstandards, but only under the limitedcircumstances described in section111(h) (i.e., when it is “not feasible” toprescribe or enforce a standard ofperformance). Similarly, section 111(h)applies by its terms when theAdministrator is authorized to prescribestandards of performance (which wouldinclude rulemaking under CAA section111(b)), but is silent as to whether it

3e744,p section 111(h)(4).308 CAA section 111(h)(5).



applies to state plans under CAAsection i11(d).°

We invite consideration of the properinterpretation of CAA sections 111(d)and (h), under either Chevron step 1 orstep 2, specifically: (1) Do the provisionsof section 111(d) preclude state plansfrom including “design, equipment,work practice, or operationalstandard[sJ” unless those things can beconsidered “standards of performance”or as providing for the implementationand enforcement of such standards? Asa related matter, do the references to“standard[sJ of performance” in CAAsection 111(h) indicate that design,equipment, work practice, oroperational standards cannot beconsidered “standards of performance?”(ii) Alternatively, are state plansauthorized to include those design,equipment, work practice, oroperational standards, but only underthe limited circumstances described inCAA section 111(h) relating toinfeasibility? (iii) As another alternative,are state plans authorized to includedesign, equipment, work practice, oroperational standards under allcircumstances, so that the limits of CAAsection 111(h) do not apply? Finally, tothe extent there is legal uncertainty overwhether, and under whatcircumstances, state plans may includethose standards, should the EPAauthorize state plans to include them,on the understanding that if the Courtinvalidates the EPA’s interpretation,states would be required to revise theirplans accordingly without furtherrulemaking from the EPA?

11. Emissions Averaging and Trading

In this section, we discuss why CAAsection 111(d) plans may includestandards of performance that authorizeemissions averaging and trading.

CAA section 111(d) authorizes stateplans to include “standards ofperformance” and measures thatimplement and enforce those standardsof performance. CAA section 111(a)(1)defines a “standard of performance” as“a standard for emissions of airpollutants which reflects the degree ofemission limitation achievable throughthe application of the best system ofemission reduction. . . adequatelydemonstrated.” CAA section 302contains a set of definitions that apply“[wJhen used in [the Clean Air Act],”including subsection (1), which providesa separate definition of “standard of

30It should be noted that section iii(b)(5),which concerns controls promulgated by theAdministrator for new and modified sources, doesrefer to section 111(h).

performance” as “a requirement ofcontinuous emission reduction. .

The EPA proposes that the definitionof “standard of performance” is broadenough to incorporate emissionsaveraging and trading provisions,including both emission rate programs,in which sources may average or tradethose rates, and mass emission limitprograms, in which sources may buyand sell mass emission allowances (and,under certain circumstances, offsets).3’°The term “standard” in the phrase“standard for emissions of airpollutants” is not defined in the CAA.As the Supreme Court noted in a CAAcase, a “standard” is simply “that which‘is established by authority, custom, orgeneral consent, as a model or example;criterion; test.’ “311 A tradable emissionrate or a tradable mass limit is a“standard for emissions of airpollutants” because it establishes anemissions limit for a source’s airpollutants, and as a result, qualifies asa “criterion” or “test” for those airpollutants.

Moreover, although there may bedoubt that the definition of “standard ofperformance” in CAA section 302(1)applies to CAA section 111(d) in lightof the fact that the definition of the sameterm in CAA section 111(a)(1) is morespecific, even if the CAA section 302(1)definition does apply, an averaging ortrading requirement qualifies as a“continuous emission reduction”because, in the case of a tradableemission rate, the rate is applicable atall times, and, in the case of a tradablemass limit, the source is always underthe obligation that its emissions becovered by allowances.

It should be noted that the EPA haspromulgated two other CAA section111(d) rulemaldngs that authorized stateplans to include emissions averaging ortrading.312

310 Typically, in a mass emission limit tradingprogram, sources are required to obtain anallowance for each measure (e.g., ton) of airpollutant they emit. The acid rain program underTitle IV of the CAA is an example of this type oftrading program.

311Engine Mfrs. Ass’n v. South Coast Air QualityMgmt. Dist., 541 U.S. 246, 252—53 (2004) (quotingWebster’s Second International Dictional3r. at 2455(1945))

312 See “Standards of Performance for New andExisting Stationary Sources: Electric Utility SteamGenerating Units, Final Rule,” 70 FR 28,606 (May18, 2005) (also known as the Clean Air MercuryRule, or “CAIvIR”], vacated on other grounds byNew Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008),cert denied sub nom. Util. Air Reg. Grp. v. NewJersey, 555 U.S. 1169 (2009); “Standards ofPerformance for New Stationary Sources andEmission Guidelines for Existing Sources;Municipal Waste Combustors,” 60 FR 65,387 (Dec.19, 1995) (trading rules codified in 40 CFR60.33b(d)(1)—(2)).

G. Additional Factors That Can HelpState Meet Their CO2 EmissionPerformance Goals

A resource available from the EPA forstates pursuing market-basedapproaches is the EPA’s data andexperience in support of state tradingprograms and emissions data collection.For states needing technical assistancewith data or operation of market-basedprograms, existing EPA data systems area resource that have been used to collectemissions data, track allowances andtransfers, and determine compliance forstate programs. For example, NewHampshire was part of the OzoneTransport Commission (OTC) tradingprogram but was not included in theNOx SW Call. Because the state wantedits sources to continue to participate ina state trading program, the EPAoperated the emissions trading programfor New Hampshire sources, fromallocating allowances to compliancedetermination.

Additionally, as noted elsewhere inthis preamble, more than 25 states havemandatory renewable portfoliostandards, and other states havevoluntary renewable programs andgoals. There is considerable diversityamong the states in the scope andcoverage of these standards, inparticular in how renewable resourcesare defined. At the federal level, theEPA has considered the greenhouse gasimplications related to biomass use atstationary sources through severalactions, including a call for informationfrom stakeholders and the developmentand review of the “AccountingFramework for Biogenic CO2 Emissionsfrom Stationary Sources,” issued inSeptember 2011. That study wasreviewed by the EPA’s Science AdvisoryBoard in 2011 and 2012 and the agencycontinues to assess the framework andconsider the latest scientific analysesand technical input received fromstakeholders. The EPA expects that theframework, when finalized, will be aresource that could help inform states inthe development of their CAA section111(d) plans.

H. Resources for States To Consider inDeveloping Their Plans

As part of the stakeholder outreachprocess, the EPA asked states what theagency could do to facilitate state plandevelopment and implementation.Some states indicated that they wantedthe EPA to create resources to assistwith state plan development, especiallyresources related to accounting for end-use energy efficiency and renewableenergy (EE/RE) in state plans. Theyrequested clear methodologies for



measuring FE/RE policies and programs,so that these could be included as partof their compliance strategies.Stakeholders said that these tools andmetrics should build upon the EPA’s“Roadmap for incorporating EnergyEfficiency/Renewable Energy Policiesand Programs into State and TribalImplementation Plans,”313 as well as theState Energy Efficiency ActionNetwork’s “Energy Efficiency ProgramImpact Evaluation Guide.”314 The EPAalso heard that states would likeexamples of effective state policies andprograms.

As a result of this feedback, inconsultation with U.S. Department ofEnergy and other federal agencies, theEPA has developed a toolbox ofdecision support resources and ismaking that available at a dedicatedWeb site: http://www2.epa.gov/www2.epa.gov/cleanpowerplantoolbox.Current resources on the site focus onapproaches states and other entitieshave already taken that reduce CO2emissions from the electric utilitysector.

For the final rulemaking, the EPAplans to organize resources on the Website around the following two categories:State plan guidance and state plandecision support. The state planguidance section will serve as a centralrepository for the final emissionguidelines, regulatory impact analysis,technical support documents, and othersupporting materials. The state plandecision support section will includeinformation to help states evaluatedifferent approaches and measures theymight consider as they initiate plandevelopment. This section will include,for example, a summary of existing stateclimate and EE/RE policies andprograms,315 National Action Plan forEnergy Efficiency (Action Plan),316information on electric utility actionsthat reduce C02, and tools andinformation to assist with translatingenergy savings into emission reductions.

We note that our inclusion of ameasure in the toolbox does not meanthat a state plan must include thatmeasure. in fact, inclusion of measuresprovided at the Web site does notnecessarily imply the approvability ofan approach or method for use in a stateplan. States will need to demonstratethat any measure included in a stateplan meets all relevant approvabilitycriteria and adequately addresses

313 http ://epa.gov/afrquality/eere/.3l4http://wwwl .eere.energy.gov/seeaction/

index.html.315 Appendix, State Plan Considerations TSD.316http://www.epa.gov/cleanenergy/energy..

proçams/suca/resources.htmL

elements of the plan componentsdiscussed in Section VIII of thispreamble.

The EPA solicits comment on thisapproach and the information currentlyincluded, and planned for inclusion, inthe Decision Support Toolbox.

DC. Implications for Other EPAPrograms and Rules

A. Implications for New Source ReviewProgram

The new source review (NSR)program is a preconstruction permittingprogram that requires major stationarysources of aft pollution to obtainpermits prior to beginning construction.The requirements of the NSR programapply both to new construction and tomodifications of existing major sources.Generally, a source triggers thesepermitting requirements as a result of amodification when it undertakes aphysical or operational change thatresults in a significant emission increaseand a net emissions increase. NSRregulations define what constitutes asignificant net emissions increase, andthe concept is pollutant-specific. ForGHG emissions, the PSD applicabilityanalysis is described in the Preventionof Significant Deterioration and Title VGreenhouse Gas Tailoring Rule (FR 7531514, June 3, 2010). As a generalmatter, a modifying major stationarysource would trigger PSD permittingrequirements for GHGs if it emits GHGsin excess of 100,000 tons per year (tpy)of carbon dioxide equivalents (C02e),and it undergoes a change or change inthe method of operation (modification)resulting in an emissions increase of75,000 tpy C02e as well as an increaseon a mass basis. Once it has beendetermined that a change triggers therequirements of the NSR program, thesource must obtain a permit prior tomaking the change. The pollutant(s) atissue and the aft quality designation ofthe area where the facility is located orproposed to be built determine thespecific permitting requirements.

As part of its CAA section 111(d)plan, a state may impose requirementsthat require an affected EGU toundertake a physical or operationalchange to improve the unit’s efficiencythat results in an increase in the unit’sdispatch and an increase in the unit’sannual emissions. If the emissionsincrease associated with the unit’schanges exceeds the thresholds in theNSR regulations discussed above for oneor more regulated NSR pollutants,including the netting analysis, thechanges would trigger NSR.

While there may be instances inwhich an NSR permit would be

required, we expect those situations tobe few. As previously discussed in thispreamble, states have considerableflexibility in selecting varied measuresas they develop their plans to meet thegoals of the emissions guidelines. Oneof these flexibilities is the ability of thestate to establish the standards ofperformance in their CAA section111(d) plans in such a way so that theiraffected sources, in complying withthose standards, in fact would not haveemissions increases that trigger NSR. Toachieve this, the state would need toconduct an analysis consistent with theNSR regulatory requirements thatsupports its determination that as longas affected sources comply with thestandards of performance in their CAAsection 111(d) plan, the source’semissions would not increase in a waythat trigger NSR requirements.

For example, a state could decide toadjust its demand side measures orincrease reliance on renewable energyas a way of reducing the futureemissions of an affected source initiallypredicted (without such alterations) toincrease its emissions as a result of aCAA section 111(d) plan requirement.in other words, a state plan’sincorporation of expanded use ofcleaner generation or demand-sidemeasures could yield the result thatunits that would otherwise be projectedto trigger NSR through a physicalchange that might result in increaseddispatch would not, in fact, increasetheir emissions, due to reduced demandfor their operation. The state could also,as part of its CAA section 111(d) plan,develop conditions for a sourceexpected to trigger NSR that would limitthe unit’s ability to move up in thedispatch enough to result in asignificant net emissions increase thatwould trigger NSR (effectivelyestablishing a synthetic minor limit). 317

We request comment on whether,with adequate record support, the stateplan could include a provision, basedon underlying analysis, stating that anaffected source that complies with itsapplicable standard would be treated asnot increasing its emissions, and if so,whether such a provision would meanthat, as a matter of law, the source’sactions to comply with its standard

317 Certain stationary sources that emit or havethe potential to emit a pollutant at a level that isequal to or greater than specified thresholds aresubject to major source requirements. See, e.g., CAA§ 165(a)(1), 169(1), 501(2), 502(a). A syntheticminor limitation is a legally and practicablyenforceable restriction that has the effect of limitingemissions below the relevant level and that a sourcevoluntarily obtains to avoid major stationary sourcerequirements, such as the PSD or title V permittingprograms. See, e.g., 40 CFR 52.21(b)(4), 51.166(b)(4),70.2 (definition of “potential to emit”).


Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34929

would not subject the source to NSR.We also seek comment on the level ofanalysis that would be required tosupport a state’s determination thatsources will not trigger NSR whencomplying with the standards ofperformance included in the state’sCAA section 111(d) plan and the type ofplan requirements, if any, that wouldneed to be included in the state’s plan.

As a result of such flexibility andanticipated state involvement, weexpect that a limited number of affectedsources would trigger NSR when statesimplement their plans.

B. Implications for Title VProgramThe preamble to the re-proposed EGU

NSPS (70 FR 1429—1519; January 8,2014) explained that regulating GHGsfor the first time under section 111 ofthe CAA would make GHGs “regulatedair pollutants” for the first time underthe operating permit regulations of 40CFR parts 70 and 71. This would resultin GHGs becoming “fee pollutants” incertain state part 70 permit programsand in the EPA’s part 71 permitprogram, thus requiring the collection offees for GHG emissions in theseprograms. Where title V fees would berequired for GHGs, they would typicallybe charged at the same rate ($ per tonof pollutant) as all other fee pollutants.This would likely result in excessiveand unnecessary fees being charged tosubject sources. To avoid this situation,we proposed to exempt GHGs from thefee rates in effect for other feepollutants, while proposing analternative fee that would be muchlower than the fee charged to other feepollutants, yet sufficient to cover thecosts of addressing GHGs in operatingpermits.

This title V fee issue is a one-timeoccurrence resulting from thepromulgation of the first CAA section111 standard to regulate GHGs (the EGUNSPS for new sources) and is not anissue for any other subsequent CAAsection 111 regulations, so there is noneed to address any title V fee issues inthis proposal. Thus, we are not revisiting these title V fee issues in thisproposal, and we are not proposing anyadditional revisions to any title Vregulations as part of this action.

The title V regulations require eachpermit to include emission limitationsand standards, including operationalrequirements and limitations that assurecompliance with all applicablerequirements. Requirements resultingfrom this rule that are imposed onaffected EGUs or any other potentiallyaffected entities that have title Voperating permits are applicablerequirements under the title V

regulations and would need to beincorporated into the source’s title Vpermit in accordance with the scheduleestablished in the title V regulations.For example, if the permit has aremaining life of three years or more, apermit reopening to incorporate thenewly applicable requirement shall becompleted no later than 18 months afterpromulgation of the applicablerequirement. If the permit has aremaining life of less than three years,the newly applicable requirement mustbe incorporated at permit renewal.

C. Interactions With Other EPA RulesExisting fossil fuel-fired EGUs, such

as those covered in this proposal, are orwill be potentially impacted by severalother recently finalized or proposedEPA rules.’8 On February 16, 2012, theEPA issued the mercury and air toxicsstandards (MATS) rule (77 FR 9304) toreduce emissions of toxic air pollutantsfrom new and existing coal- and oil-fired EGUs. The MATS rule will reduceemissions of heavy metals, includingmercury (Hg), arsenic (As), chromium(Cr), and nickel (Ni); and acid gases,including hydrochloric acid (HC1) andhydrofluoric acid (Hf). These toxic airpollutants, also known as hazardous airpollutants or aft toxics, are known orsuspected of causing damage to thenervous system, cancer, and otherserious health effects. The MATS rulewill also reduce SO and fine particlepollution, which will reduce particleconcentrations in the air and preventthousands of premature deaths and tensof thousands of heart attacks, bronchitiscases and asthma episodes.

The EPA is closely monitoring MATScompliance and finds that the industryis making substantial progress. Plantowners are moving proactively to installcontrols that will achieve the MATSperformance standards. Certain units,especially those that operateinfrequently, may be considered notworth investing in given today’selectricity market, and those are closing.

Existing sources subject to the MATSrule are given until April 16, 2015 tocomply with the rule’s requirements.The final MATS rule provided afoundation on which states and otherpermitting authorities could rely ingranting an additional, fourth year forcompliance provided for by the CAA.States report that these fourth yearextensions are being granted. Inaddition, the EPA issued an

318 We discuss other rulemaltings solely forbackground purposes. The effort to coordinaterulemaldngs is not a defense to a violation of theCAA. Sources caDnot defer compliance withexisting requirements because of other upcomingregulations.

enforcement policy that provides a clearpathway for reliability-critical units toreceive an administrative order thatincludes a compliance schedule of up toan additional year, if it is needed toensure electricity reliability.

On May 19, 2014, the EPA issued afinal rule under section 316(b) of theClean Water Act (33 U.S.C. 1326(b))(referred to hereinafter as the 316(b)rule).319 This rule establishes newstandards to reduce injury and death offish and other aquatic life caused bycooling water intake structures atexisting power plants andmanufacturing facilities.320 The 3 16(b)rule subjects existing power plants andmanufacturing facilities that withdrawin excess of 2 million gallons per day(MGD) of cooling water, and use at least25 percent of that water for coolingpurposes, to a national standarddesigned to reduce the number of fishdestroyed through impingement and anational standard for establishingentrainment reduction requirements. Allfacilities subject to the rule must submitinformation on their operations for useby the permit authority in determining3 16(b) permit conditions. Certain plantsthat withdraw very large volumes ofwater will also be required to conductadditional studies for use by the permitauthority in determining the site-specific entrainment reductionmeasures for such facilities. The ruleprovides significant flexibility forcompliance with the impingementstandards and, as a result, is notprojected to impose a substantial costburden on affected facilities. Withrespect to entrainment, the rule callsupon the permitting authority to inestablishing appropriate entrainmentreduction measures, taking into account,among other factors, compliance costs,facility reliability and grid reliability.Existing sources subject to the 3 16(b)rule are required to comply with theimpingement requirements as soon aspracticable after the entrainmentrequirements are determined. Theymust comply with applicable site-specific entrainment reduction controlsbased on the schedule of requirementsestablished by the permitting authority.

The EPA is also reviewing publiccomments and working to finalize twoproposed rules which will also impact

319 pre-publication version of the final rule isavailable at: http://water.epa.gov/lawsregs/lowsguidance/cwa/31 6b/#final.

ISO CWA section 316(b) provides that standardsapplicable to point sources under sections 301 and306 of the Act must require that the location,design, construction and capacity of cooling waterintake structures reflect the best technologyavailable for minimizing adverse environmentalimpacts.



existing fossil fuel-fired EGUs: Thesteam electric effluent limitationguidelines (SE ELG) rule and the coalcombustion residuals (CCR) rule. Theseproposed rules are summarized below.

On June 7, 2013 (78 FR 34432), theEPA proposed the SE ELG rule tostrengthen the controls on dischargesfrom certain steam electric power plantsby revising technology-based effluentlimitations guidelines and standards forthe steam electric power generatingpoint source category. The currentregulations, which were last updated in1982, do not adequately address thetoxic pollutants discharged from theelectric power industry, nor have theykept pace with process changes thathave occurred over the last threedecades. Existing steam electric powerplants currently contribute 50—60percent of all toxic pollutantsdischarged to surface waters by allindustrial categories regulated in theUnited States under the CWA.Furthermore, power plant discharges tosurface waters are expected to increaseas pollutants are increasingly capturedby air pollution controls and transferredto wastewater discharges. This proposedregulation, which includes newrequirements for both existing and newgenerating units, would reduce theamount of toxic metals and otherpollutants discharged to surface watersfrom power plants.

On June 21, 2010 (75 FR 35128), theEPA proposed the CCR rule, which coproposed two approaches to regulatingthe disposal of coal combustionresiduals (CCRs) generated by electricutilities and independent powerproducers. CCRs are residues from thecombustion of coal in steam electricpower plants and include materialssuch as coal ash (fly ash and bottomash) and flue gas desulfurization (FGD)wastes. Under one proposed approach,the EPA would list these residuals as“special wastes,” when destined fordisposal in landfills or surfaceimpoundments, and would apply theexisting regulatory requirementsestablished under Subtitle C of RCRA tosuch wastes. Under the secondproposed approach, the EPA wouldestablish new regulations applicablespecifically to CCRs under subtitle D ofRCRA, the section of the statuteapplicable to solid (i.e., non-hazardous)wastes. Under both approaches, CCRsthat are beneficially used would remainexempt under the Bevill exclusion.32’

321 Beneficial use involves the reuse of ccRs ina product to replace virgin raw materials that wouldotherwise be obtained through extraction. The EPAencourages the beneficial use of cCRs in anappropriate and protective manner, because thispractice can produce environmental, economic, and

While the EPA still is evaluating all theavailable information and comments,and while a final risk assessment for theCCR rule has not yet been completed,reliance on data and analyses discussedin the preamble to the recent SE ELGproposal might have the potential tolower the CCR rule risk assessmentresults by as much as an order ofmagnitude. If this proves to be the case,the EPA’s current thinking is that therevised risks, coupled with the ELGrequirements that the agency mightpromulgate, and the increased federaloversight such requirements couldachieve, could provide strong supportfor a conclusion that regulation of CCRdisposal under RCRA Subtitle D wouldbe adequate.322 The EPA is under acourt-ordered deadline to complete theCCR rulemaking by December 19, 2014.

The EPA recognizes the importance ofassuring that each of the rules describedabove can achieve its intendedenvironmental objectives in acommonsense, cost-effective manner,consistent with underlying statutoryrequirements, and while assuring areliable power system. Executive Order(EO) 13563, “Improving Regulation andRegulatory Review,” issued on Ianuary18, 2011, states that “[un developingregulatory actions and identifyingappropriate approaches, each agencyshall attempt to promote.coordination, simplification, andharmonization. Each agency shall alsoseek to identify, as appropriate, meansto achieve regulatory goals that aredesigned to promote innovation.”Within the EPA, we are paying carefulattention to the interrelatedness andpotential impacts on the industry,reliability and cost that these variousrulemaldngs can have.

As discussed in Sections VII and Vifiof this preamble, the EPA is proposingto give states broad flexibility indeveloping approvable plans under

performance benefits. The Agency recentlyevaluated the environmental impacts associatedwith encapsulated beneficial uses of fly ash used asa direct substitute for Portland cement in concrete,and FGD gypsum used as a replacement for minedgypsum in wallboard. The EPA concluded that thebeneficial use of ccRs in concrete and wallboardis appropriate because the environmental releasesof constituents of potential concern (COPC) duringuse by the consumer are comparable to or lowerthan those from analogous non-cCR products, or areat or below relevant regulatory and health-basedbenchmarks for human and ecological receptors.See U.S. Environmental Protection Agency, CoalCombustion Residual Beneficial Use Evaluation: FlyAsh Concrete and FGD Gypsum Wallboard (2014).

322 U.S. EPA. September 2013. Regulatory ImpactAnalysis for the Proposed Standards of Performancefor Greenhouse Gas Emissions for New StationarySources: Electric Utility Generating Units. EPA—452/R—1 3—003. Available at http://www2.epa.gov/sites/production/files/201 3—09/documents!201 3o92oproposalria.pdf

CAA section 111(d), including theability to adopt rate-based or mass-basedemission performance goals, and to relyon a wide variety of CO2 emissionreduction measures. The EPA is alsoproposing to give states considerableflexibility with respect to thetimeframes for plan development andimplementation, with up to two or threeyears permitted for final plans to besubmitted after the proposed GHGemission guidelines are finalized, andup to fifteen years for all emissionreduction measures to be fullyimplemented. In light of theseflexibilities, we believe that states willhave ample opportunity, whendeveloping and implementing theirCAA section 111(d) plans, to coordinatetheir response to this requirement withsource and state responses to anyobligations that may be applicable toaffected EGUs as a result of the MATS,316(b), SE ELG and CCR rules—all ofwhich are or will be final rules beforethis rulemaking is finalized—and to doso in a manner that will help reducecost and ensure reliability, while alsoensuring that all applicableenvironmental requirements are met.323

The EPA is also endeavoring to enableEGUs to comply with applicableobligations under other power sectorrules as efficiently as possible (e.g., byfacilitating their ability to coordinateplanning and investment decisions withrespect to those rules) and, wherepossible, implement integratedcompliance strategies. For example, inthe proposed SE ELG rule, the EPAdescribes its current thinking on how itmight effectively harmonize thepotential requirements of that rule withthe requirements of the final CCR rule,to the extent that both rules mayregulate or affect the disposal of coalcombustion wastes to and from surfaceimpoundments at power plants.324 TheEPA’s goal in exploring how it mightharmonize the SE ELG and CCR rules isto minimize the overall complexity ofthe two regulatory structures and avoidcreating unnecessary burdens.325

should be noted that regulatory obligationsimposed upon states and sources operateindependently under different statutes and sectionsof statutes; the EPA expects that states and sourceswill take advantage of available fiexibilities asappropriate, but will comply with all relevant legalrequirements.

324 Federal Register Vol. 78, No. 110; June7, 2013. Page 34441.

325In considering how to coordinate the potentialrequirements between the SE ELG and CR rules,the EPA stated that it is guided by the followingpolicy considerations: First and foremost, the EPAintends to ensure that its statutory responsibilitiesto restore and maintain water quality under theCWA and to protect human health and theenvironment under RCRA are fulfilled. At the sametime, the EPA would seek to minimize the potential



In addition to the power sector riflesdiscussed above, the development ofSIPs for criteria pollutants (PM2.5, ozoneand 802) and regional haze may alsohave implications for existing fossil-fired EGUs.

On June 6, 2013, the EPA proposed animplementation rule for the 2008 ozoneNational Ambient Mr Quality Standards(NAAQS), to provide rules and guidanceto states on the development ofapprovable state implementation plans(SIPs), including SIPs under CAAsection 110 (infrastructure SIPs) andsection 182 (ozone nonattainment SIPs).This rule addresses the statutoryrequirements for areas that the EPA hasdesignated as nonattainment for the2008 ozone standard. The agency iscurrently working to finalize that rule.The EPA is also working on a proposedtransport rule that would identify theobligations of upwind states thatcontribute to those downwind stateozone nonattainment areas. This rule isscheduled for proposal in 2014 and tobe finalized by 2015.

The EPA is developing a proposedimplementation rule to provideguidance to states on the developmentof SIPs for the 2012 PM2.5 NAAQS.

The SO2 NAAQS was revised in June2010 to protect public health from theshort-term effects of 502 exposure. InJuly 2013, the EPA designated 29 areasin 16 states as nonattainment for the502 NAAQS. The EPA based thesenonattainrnent designations on the mostrecent set of certified air qualitymonitoring data as well as anassessment of nearby emission sourcesand weather patterns that contribute to

the monitored levels. The EPA intendsto address the designations for all otherareas in separate actions in thefuture 326 The EPA has proposed thedata requirements rule for the 1-hour502 NAAQS to require states tocharacterize air quality more extensivelyusing ambient monitoring or air qualitymodeling approaches.

The EPA requires SIP updates every10 years for regional haze, as requiredby the EPA’s Regional Haze Rule whichwas promulgated in 1999. The next 10-year SIP revision for regional haze,covering the time period through 2028,is due from each state by July 2018.Each SIP must provide for reasonableprogress towards visibility improvementin protected scenic areas.

The development of these SIPs may,where applicable, have significantimplications for existing fossil fuel-firedEGUs, as well as for the states that areresponsible for developing them. Thetimeframes for submittal of SIPs for thevarious programs and the timeftames weare proposing for submittal of the CAAsection 111(d) state plans will allowconsiderable time for coordination bystates in the development of theirrespective plans. The EPA is willing towork with states to assist them incoordinating their efforts across theseplanning processes. The EPA believesthat CAA section 111(d) efforts andactions will tend to contribute to overallair quality improvements and thusshould be complementary to criteriapollutant and regional haze SW efforts.

In light of the broad flexibilities weare proposing in this action, we believethat states will have ample opportunity

to design CAA section 111(d) plans thatuse innovative, cost-effective regulatorystrategies and that spark investment andinnovation across a wide variety ofclean energy technologies. We alsobelieve that the broad flexibilities weare proposing in this action will enablestates and affected EGUs to build ontheir longstanding, successful records ofcomplying with multiple CAA, CWA,and other environmental requirements,while assuring an adequate, affordable,and reliable supply of electricity.

X. Impacts of the Proposed Action327

A. What are the air impacts?

The EPA anticipates significantemission reductions under the proposedguidelines for the power sector. CO2emissions are projected to be reducedwhen compared to 2005 emissions, by26 percent to 27 percent in 2020 andabout 30 percent in 2030 under Option1. Option 2 reflects reductions of about23 percent in 2020 and 23 percent to 24percent in 2025 when compared to CO2emissions in 2005. The guidelines areprojected to result in substantial cobenefits through reductions of SO2,PM2.5 and NOx that will have directpublic health benefits by loweringambient levels of these pollutants andozone. Tables 10 and 11 show expectedCO2 and other air pollutant emissionreductions in the base case, with theproposed Option 1 for 2020, 2025, and2030 and regulatory alternative Option2, for 2020 and 2025.

TABLE 10—SUMMARY OF CO2 AND OTHER AIR POLLUTANT EMISSION REDUCTIONS WITH OPTION 1

for overlapping requirements to avoid imposing anyunnecessary burdens on regulated entities and tofacilitate implementation and minimize the overallcomplexity of the regulatory structure under whichfacilities must operate. Based on theseconsiderations, the EPA stated that it is exploringtwo primary means of integrating the two rules: (1)Through coordinating the design of any finalsubstantive cCR regulatory requirements, and (2)through coordination of the timing andimplementation of final rule requirements toprovide facilities with a reasonable timeline for

implementation that allows for coordinatedplanning and protects electricity reliability forconsumers.

326 EPA has developed a comprehensiveimplementation strategy for these future actionsthat focuses resources on identifying andaddressing unhealthy levels of SO2 in areas wherepeople are most likely to be exposed to violationsof the standard. The strategy is available at: http://wsvw.epa.gov/airqualfty/sulfurdioxide/implement.html.

327 impacts presented in this section of thepreamble represent an illustrative implementationof the guidelines. As states implement the proposedguidelines, they have sufficient flexibility to adoptdifferent state-level or regional approaches that mayyield different costs, benefits, and environmentalimpacts. For example, states may use theflexibilities described in these guidelines to findapproaches that are more cost effective for theirparticular state or choose approaches that shift thebalance of co-benefits and impacts to match broaderstate priorities.

CO2 SO2 NO PM2.5(thousands (thousands (thousands

tons) of tons) of tons) of tons)

2020 RegIonal Compliance Approach:

Base Case Proposed 2,161 1,476 } 1,559 212Guidelines: 1,790 1,184 1,213 156Emission Reductions 371 292 L 34j 56

2025 Regional Compliance Approach:

Base Case Proposed 2,231 1,515 1,587 209Guidelines: 1,730 1,120 1,166 150



TABLE 10—SUMMARY OF CO2 AND OTHER AIR POLLUTANT EMISSION REDUCTIONS WITH OPTION 1—Continued

CO2million

rIvI2.5

‘metric(thousands (thousands (thousands

tons)of tons) of tons) of tons)

Emission Reductions 501 395 421 59


Base Case Proposed 2,256 1,5301 1,537 198

Guidelines: 1,711 1,106 1,131 144


2020 State Compliance Approach:


Guidelines: 1,777 1,140 1,191 154




Guidelines: 1,724 1,090 1,151 145




Guidelines: 1,701 1,059 1,109 142


Source: Integrated Planning Model, 2014.

TABLE 1 1—SUMMARY OF CO2 AND AIR POLLUTANT EMISSION REDUCTIONS WITH OPTION 2

CO2(million SO2 NOx PM25

‘metric(thousands (thousands (thousands

tons) of tons) of tons) of tons)


Base Case 2,161 1,476 1,559 212

Option 2 1,878 1,231 1,290 166



Base Case 2,231 1,515 1,587 209

Option 2 1,862 1,218 1,279 165



Base Case 2,161 1,476 1,559 212

Option 2 1,866 1,208 1,277 163



Base Case [ 2,231 1,515 1,587 209

Option 2 I 1,855 1,188 1,271 161

Emission 376 327_L 317 48

Source: Integrated Planning Model, 2014.

The reductions in these tables do notaccount for reductions in hazardous airpollutants (HAPs) that may occur as aresult of this rule. For instance, the fineparticulate reductions presented abovedo not reflect all of the reductions inmany heavy metal particulates.

B. Comparison ofBuildingBlockApproaches

Though the EPA has determined thatthe 4-building block approach is theBSER, we did analyze the impacts ofboth a combination of building blocks 1and 2 and the combination of all four

building blocks. The analysis indicatesthat the combined strategies of heat rateimprovements (building block 1) and redispatch (building block 2) would resultin overall CO2 emission reductions ofapproximately 22 percent in 2020(compared to 2005 emissions and



assuming state-level compliance). Thiscompares to expected CO2 emissionreductions of approximately 27 percentfor the four-block BSER approachdiscussed below. The EPA analysis alsoestimates 24—3 2 GW of additional coal-fired EGU retirements in 2020(compared to 46—49 GW for the four-block approach) and an additional 3—5GW of oil/gas steam EGUs (compared to16 GW for the four-block approach). Forboth the two-block and the four-blockapproach, a decrease in coal productionand price is predicted in 2020. Thedecrease in production is predicted at20—23 percent for the two-blockapproach, compared to a decrease of 25—27 percent for the four-block approach.A 12 percent decrease in coal prices ispredicted for the two-block approach;while the four-block approach results ina 16 to 18 percent decrease. Under bothapproaches, the shifting in generationfrom higher-emitting steam EGUs tolower-emitting NGCC units results in anincrease in natural gas production andprice. The two-block approach results ina production increase of 19—22 percentand a price increase of 10—11 percent.The four-block approach results in aproduction increase of 12—14 percentand a price increase of 9—12 percent.Both the two-block and the four-blockapproaches result in construction ofadditional NGCC capacity by 2020, with11—18 GW of new NGCC for the two-block approach and 20—2 2 GW of newNGCC capacity for the four-blockapproach. However, while the two-blockapproach results in 5—17 GW of newNGCC capacity in 2030, the four-blockapproach results in 32—35 GW lessNGCC capacity in 2030 relative to thebase case (due to increased use ofrenewable energy sources and decreaseddemand from implementation ofdemand side energy efficiencymeasures). Also, significantly, the two-block approach results in less than 500MW of new renewable energy capacity;while the four-block option results inapproximately 12 GW of new renewablegenerating capacity.

The EPA projects that the annualincremental compliance cost for thebuilding block 1 and 2 approach isestimated to be $3.2 to $4.4 billion in2020 and $6.8 to $9.8 billion (2011$) in2030, excluding the costs associatedwith monitoring, reporting, andrecordkeeping (MRR). This compares tocosts excluding MRR of $5.4 to $7.4billion in 2020 and $7.3 to $8.8 billionin 2030 for the proposed Option 1(2011$) as discussed in Section X.E ofthis preamble.

The total combined climate benefitsand health co-benefits for the buildingblock 1 and 2 approach are estimated to

be $21 to $40 billion in 2020 and $32to $63 billion in 2030 (2011$ at a 3-percent discount rate [model average]).The net benefits are estimated to be $18to $36 billion in 2020 and $25 to $53billion in 2030 (2011$ at a 3-percentdiscount rate [model average]). For thepurposes of this summary, we list theclimate benefits associated with themarginal value of the model average at3% discount rate, however weemphasize the importance and value ofconsidering the full range of SCC values.These building block 1 and 2 benefitestimates compare to combined climatebenefits and health co-benefits of $33 to$57 billion in 2020 and $55 to $93billion in 2030 (2011$ at a 3-percentdiscount rate [model average]) for theproposed Option 1. Net benefits areestimated to be $27 to $50 billion in2020 and $48 to $84 billion in 2030(2011$ at a 3-percent discount rate[model average]) as discussed in SectionX.G. and XLA of this preamble.328

C. Endangered Species ActConsistent with the requirements of

section 7(a)(2) of the EndangeredSpecies Act (ESA), the EPA has alsoconsidered the effects of this proposedrule and has reviewed applicable ESAregulations, case law, and guidance todetermine what, if any, impact theremay be to listed endangered orthreatened species or designated criticalhabitat. Section 7(a)(2) of the ESArequires federal agencies, inconsultation with the U.S. Fish andWildlife Service (FWS) and/or theNational Marine Fisheries Service, toensure that actions they authorize, fund,or carry out are not likely to jeopardizethe continued existence of federallylisted endangered or threatened speciesor result in the destruction or adversemodification of designated criticalhabitat of such species. 16 U.S.C.1536(a)(2). Under relevantimplementing regulations, section7(a)(2) applies only to actions wherethere is discretionary federalinvolvement or control. 50 CFR 402.03.Further, under the regulationsconsultation is required only for actionsthat “may affect” listed species ordesignated critical habitat. 50 CFR§ 402.14. Consultation is not requiredwhere the action has no effect on suchspecies or habitat. Under this standard,it is the federal agency taking the actionthat evaluates the action and determineswhether consultation is required. See 51

325 Note that the health co-benefits and netbenefits for the proposed Option I include PM cobenefits associated with directly emitted PM25. Incontrast, the building block 1 and 2 analysis doesnot include co-benefits related to directly emittedPM25.

FR 19926, 19949 (June 3, 1986). Effectsof an action include both the direct andindirect effects that will be added to theenvironmental baseline. 50 CFR 402.02.Indirect effects are those that are causedby the action, later in time, and arereasonably certain to occur. Id. Totrigger a consultation requirement, theremust thus be a causal connectionbetween the federal action, the effect inquestion, and the listed species, and theeffect must be reasonably certain tooccur.

The EPA has considered the effects ofthis proposed rule and has reviewedapplicable ESA regulations, case law,and guidance to determine what, if any,impact there may be to listed species ordesignated critical habitat for purposesof section 7(a)(2) consultation. The EPAnotes that the projected environmentaleffects of this proposal are positive:reductions in overall GHG emissions,and reductions in PM and ozone-precursor emissions tSOx and NOx).With respect to the projected GHGemission reductions, the EPA does notbelieve that such reductions trigger ESAconsultation requirements under section7(a)(2). In reaching this conclusion, theEPA is mindful of significant legal andtechnical analysis undertaken by FWSand the U.S. Department of the Interiorin the context of listing the polar bearas a threatened species under the ESA.In that context, in 2008, FWS and DOIexpressed the view that the bestscientific data available wereinsufficient to draw a causal connectionbetween GHG emissions and effects onthe species in its habitat.329 The DOlSolicitor concluded that where theeffect at issue is climate change,proposed actions involving GHGemissions cannot pass the “may affect”test of the section 7 regulations and thusare not subject to ESA consultation. TheEPA has also previously consideredissues relating to GHG emissions inconnection with the requirements ofESA section 7(a)(2). Although the GHGemission reductions projected for thisproposal are large (the highest estimateis reductions of 555 MMT of CO2 in2030—see Table 10 above), the EPAevaluated larger reductions in assessingthis same issue in the context of thelight duty vehicle GHG emissionstandards for model years 2012—2016and 2017—2025. There the agencyprojected emission reductions roughlydouble and four times those projected

329 See, e.g., 73 FR 28212, 28300 (May 15, 2008);Memorandum from David Longly Bernhardt,Solicitor, U.S. Department of the Interior re:“Guidance on the Applicability of the EndangeredSpecies Act’s Consultation Requirements toProposed Actions Involving the Emission ofGreenhouse Gases” (Oct. 3, 2008).



here over the lifetimes of the modelyears in question33° and, based on airquality modeling of potentialenvironmental effects, concluded that“EPA knows of no modeling tool whichcan link these small, time-attenuatedchanges in global metrics to particulareffects on listed species in particularareas. Extrapolating from global metricto local effect with such small numbers,and accounting for further links in acausative chain, remain beyond currentmodeling capabilities.” EPA, Light DutyVehicle Greenhouse Gas Standards andCorporate Average Fuel EconomyStandards, Response to CommentDocument for Joint Rulemaking at 4—102(Docket EPA—OAR—HQ—2009—4 782).The EPA reached this conclusion afterevaluating issues relating to potentialimprovements relevant to bothtemperature and oceanographic pHoutputs. The EPA’s ultimate finding wasthat “any potential for a specific impacton listed species in their habitatsassociated with these very smallchanges in average global temperatureand ocean pH is too remote to trigger thethreshold for ESA section 7 (a)(2).” Id.The EPA believes that the sameconclusions apply to the presentproposal, given that the projected CO2emission reductions are less than thoseprojected for either of the light dutyvehicle rules. See, e.g., Ground ZeroCenter for Non-Violent Action v. U.S.Dept. of Navy, 383 F. 3d 1082, 1091—92(9th Cir. 2004) (where the likelihood ofjeopardy to a species from a federalaction is extremely remote, ESA doesnot require consultation).

With regard to non-GHG airemissions, the EPA is also projectingsubstantial reductions of SOX and NOas a collateral consequence of thisproposal. However, CAA sectioniii(d)(i) standards cannot directlycontrol emissions of criteria pollutants.Consequently, CAA section 111(d)provides no discretion to adjust thestandard based on potential impacts toendangered species of reduced criteriapollutant emissions. Section 7(a)(2)consultation thus is not required withrespect to the projected reductions ofcriteria pollutant emissions. See 50 CFR402.03; see also, National Lime Ass’n v.EPA, 233 F. 3d 625, 638—39 (D.C. Cir.2000) (although CAA section 112(b)(2)prohibits the EPA from listing criteriapollutants as hazardous air pollutants,the EPA may use PM as a surrogate formetal hazardous air pollutants andreductions in PM do not constituteimpermissible regulation of a criteriapollutant).

330 See 75 FR at 25438 Table I.C 2—4 (May 7,2010); 77 FR at 62894 Table ffl—68 (Oct. 15, 2012).

Moreover, there are substantialquestions as to whether any potentialfor relevant effects results from anyelement of the proposed rule or wouldresult instead from the separate actionsof States establishing standards ofperformance for existing sources andimplementing and enforcing thosestandards. Cf. American TruckingAssn’s v. EPA, 175 F. 3d 1027, 1043—45(D.C. Cir. 1999), rev’d on differentgrounds sub nom., Whitman v.American Trucking Assn’s, 531 U.S. 457(2000) (National Ambient Mr QualityStandards have no economic impact, forpurposes of Regulatory Flexibility Act,because impacts result from the actionsof States through their development,implementation and enforcement ofstate implementation plans). Thus, forexample, although questions may existwhether actions such as increasedutilization of solar or wind power couldhave effects on listed species, the EPAbelieves that such effects (if any) wouldresult from decisions and actions bystates in developing, implementing andenforcing their plans. The precise stepsStates choose to take in that regardcannot be determined or ordered by thisfederal action, and they are notsufficiently certain to be attributable tothis proposed rule for ESA purposes.Consequently, for this additional reason,the EPA does not believe that thisproposed rule (if enacted) would haveeffects on listed species that wouldtrigger the section 7 (a)(2) consultationrequirement.

D. What are the energy impacts?

The proposed guidelines haveimportant energy market implications.Under Option 1, average nationwideretail electricity prices are projected toincrease by roughly 6 to 7 percent in2020 relative to the base case, and byroughly 3 percent in 2030 (contiguousU.S.). Average monthly electricity billsare anticipated to increase by roughly 3percent in 2020, but decline byapproximately 9 percent by 2030. Thisis a result of the increasing penetrationof demand-side programs that more thanoffset increased prices to end users bytheir expected savings from reducedelectricity use.

The average delivered coal price tothe power sector is projected to decreaseby 16 to 17 percent in 2020 and roughly18 percent in 2030, relative to the basecase for Option 1. The EPA also projectsthat electric power sector-deliverednatural gas prices will increase by 9 to12 percent in 2020, with negligiblechanges in 2030. Natural gas use forelectricity generation will increase by asmuch as 1.2 trillion cubic feet (TCF) in

2020 relative to the base case, and thenbegin to decline over time.

These figures reflect the EPA’sillustrative modeling that presumespolicies that lead to dispatch changes in2020 and growing use of energyefficiency and renewable electricitygeneration out to 2029. if states makedifferent policy choices, impacts couldbe different. For instance, if statesimplement renewable and/or energyefficiency policies on a more aggressivetime-frame, impacts on natural gas andelectricity prices would likely be less.Implementation of other measures notincluded in the EPA’s BSER calculationor compliance modeling, such asnuclear uprates, transmission systemimprovements, use of energy storagetechnologies or retrofit CCS, could alsomitigate gas price and]or electricityprice impacts.

The EPA projects coal production foruse by the power sector, a largecomponent of total coal production, willdecline by roughly 25 to 27 percent in2020 from base case levels. The use ofcoal by the power sector will decreaseroughly 30 to 32 percent in 2030.Renewable energy capacity isanticipated to increase by roughly 12GWin2O2O andby9 GW in 2030 underOption 1. Energy market impacts fromthe guidelines are discussed moreextensively in the RIA found in thedocket for this rulemaking.

F. What are the compliance costs?The compliance costs of this proposed

action are represented in this analysis asthe change in electric power generationcosts between the base case and theproposed rule in which states pursue adistinct set of strategies beyond thestrategies taken in the base case to meetthe terms of the ECU GHG emissionguidelines, and include cost estimatesfor demand-side energy efficiency. Thecompliance assumptions—and,therefore, the projected compliancecosts—set forth in this analysis areillustrative in nature and do notrepresent the full suite of complianceflexibilities states may ultimatelypursue. These illustrative compliancescenarios are designed to reflect, to theextent possible, the scope and thenature of the proposed guidelines.However, there is considerableuncertainty with regards to the precisemeasures that states will adopt to meetthe proposed requirements, becausethere are considerable flexibilitiesafforded to the states in developing theirstate plans.

The EPA projects that the annualincremental compliance cost of Option1 is estimated to be between $5.5 and$7.5 billion in 2020 and between $7.3



and $8.8 billion (2011$) in 2030,including the costs associated withmonitoring, reporting, andrecordkeeping (MRR). The incrementalcompliance cost of Option 2 isestimated to be between $4.3 and $5.5billion in 2020, including MRR costs. In2025, the estimated compliance cost ofOption 2 is estimated to be between $4.5and $5.5 billion (with the assumedlevels of end-use energy efficiency).These important dynamics arediscussed in more detail in the RIA inthe rulemaking docket. The annualizedincremental cost is the projectedadditional cost of complying with theguidelines in the year analyzed, andincludes the amortized cost of capitalinvestment, needed new capacity, shiftsbetween or amongst various fuels,deployment of energy efficiencyprograms, and other actions associatedwith compliance. MRR costs areestimated to be $68.3 million (2011$) in2020 and $8.9 million in 2025 and 2030for Option 1 and $68.3 million in 2020and $8.9 million in 2025 for Option 2.More detailed cost estimates areavailable in the RIA included in therulemaking docket.

F. What are the economic andemployment impacts?

The proposed standards are projectedto result in certain changes to powersystem operation as a result of theapplication of state emission rate goals.Overall, we project dispatch changes,changes to fossil fuel and retailelectricity prices, and some additionalcoal retirements. Average electric powersector-delivered natural gas prices areprojected to increase by roughly 9 to 12percent in 2020 in Option 1, withnegligible changes by 2030. UnderOption 2, electric power sector naturalgas prices are projected to increase byroughly 8 percent in 2020, on an averagenationwide basis, and increase by 1percent or less in 2025. The averagedelivered coal price to the power sectoris projected to decrease by 16 to 17percent in 2020 under Option 1, anddecrease by roughly 14 percent underOption 2, on a nationwide average basis.Retail electricity prices are projected toincrease 6 to 7 percent under Option 1and increase by roughly 4 percent underOption 2, both in 2020 and on anaverage basis across the contiguous U.S.By 2030 under Option 1, electricityprices are projected to increase by about3 percent. Under Option 1, the EPAprojects 46 to 50 GW of additional coal-fired generation may be uneconomic tomaintain and may be removed fromoperation by 2030. The EPA projectsthat under Option 2, 30 to 33 GW ofadditional coal-fired generation may be

uneconomic to maintain and may beremoved from operation by 2025.

It is important to note that the EPA’smodeling does not necessarily accountfor all of the factors that may influencebusiness decisions regarding future coalfired capacity. By 2025, the average ageof the coal-fired fleet will be 49 yearsold and twenty percent of the fleet willbe more than 60 years old. Many powercompanies already factor a carbon priceinto their long term capacity planningthat would further influence businessdecisions to replace these aging assetswith modern, and significantly cleanergeneration.

The compliance modeling done tosupport the proposal assumes thatoverall electric demand will decreasesignificantly, as states ramp upprograms that result in lower overalldemand. End-use energy efficiencylevels increase such that they achieveabout an 11 percent reduction on overallelectricity demand levels in 2030 forOption 1, and a reduction in overallelectricity demand of approximately 6percent reduction in 2025 for Option 2.In response, there are anticipated to benotable changes to costs, prices, andelectricity generation in the powersector as more end-use efficiency isrealized.

Changes in price or demand forelectricity, natural gas, coal, can impactmarkets for goods and servicesproduced by sectors that use theseenergy inputs in the production processor supply those sectors. Changes in costof production may result in changes inprice, changes in quantity produced,and changes in profitability of firmsaffected. The EPA recognizes that theseguidelines provide significantflexibilities and states implementing theguidelines may choose to mitigateimpacts to some markets outside theEGU sector. Similarly, demand for newgeneration or energy efficiency canresult in shifts in production andprofitability for firms that supply thosegoods and services, and the guidelinesprovide flexibility for states that maywant to enhance demand for goods andservices from those sectors.

Executive Order 13563 directs federalagencies to consider the effect ofregulations on job creation andemployment. According to theExecutive Order, “our regulatory systemmust protect public health, welfare,safety, and our environment whilepromoting economic growth,innovation, competitiveness, and jobcreation. It must be based on the bestavailable science.” (Executive Order13563, 2011) Although standard benefit-cost analyses have not typicallyincluded a separate analysis of

regulation-induced employmentimpacts, we typically conductemployment analyses. During periods ofsustained high unemployment,employment impacts are of particularconcern and questions may arise abouttheir existence and magnitude.

States have the responsibility andflexibility to implement policies andpractices for compliance with ProposedElectric Generating Unit GreenhouseGas Existing Source Guidelines.Quantifying the associated employmentimpacts is complicated by the widerange of approaches that States may use.As such, the EPA’s employmentanalysis includes projected employmentimpacts associated with illustrativecompliance scenarios for theseguidelines for the electric powerindustry, coal and natural gasproduction, and demand-side energyefficiency activities. These projectionsare derived, in part, from a detailedmodel of the electricity productionsector used for this regulatory analysis,and U.S government data onemployment and labor productivity. Inthe electricity, coal, and natural gassectors, the EPA estimates that theseguidelines could have an employmentimpact of roughly 25,900 to 28,000 job-years increase in 2020 for Option 1,state to regional compliance approach,respectively. For Option 2, the state andregional compliance approach estimatesare 26,700 to 29,800 job-years increasein 2020. Demand-side energy efficiencyemployment impacts are approximatelyan increase of 78,800 jobs in 2020 forOption 1 and of 57,000 jobs for Option2. By its nature, energy efficiencyreduces overall demand for electricpower. The EPA recognizes as moreefficiency is built into the U.S. powersystem over time, lower fuelrequirements may lead to fewer jobs inthe coal and natural gas extractionsectors, as well as in EGU constructionand operation than would otherwisehave been expected. The EPA alsorecognizes the fact that, in many cases,employment gains and losses that mightbe attributable to this rule would beexpected to affect different sets ofpeople. Moreover, workers who losejobs in these sectors may findemployment elsewhere just as workersemployed in new jobs in these sectorsmay have been previously employedelsewhere. Therefore, the employmentestimates reported in these sectors mayinclude workers previously employedelsewhere. This analysis also does notcapture potential economy-wideimpacts due to changes in prices (offuel, electricity, labor, etc.). For thesereasons, the numbers reported here



should not be interpreted as a netnational employment impact.

G. What are the benefits of the proposedgoals?

Implementing the proposed standardswill generate benefits by reducingemissions of CO2 as well as criteriapollutants and their precursors,including 502, NOx and directlyemitted particles. SO2 and NOx areprecursors to PM2.5 (particles smallerthan 2.5 microns), and NOx is aprecursor to ozone. The estimatedbenefits associated with these emissionreductions are beyond those achievedby previous EPA rulemaldngs includingthe Mercury and Air Toxics Standardsrule. The health and welfare benefitsfrom reducing air pollution are

considered co-benefits for thesestandards. for this rulemaking, we wereonly able to quantify the climatebenefits from reduced emissions of CO2and the health co-benefits associatedwith reduced exposure to PM2.5 andozone. In summary, we estimate thetotal combined climate benefits andhealth co-benefits for Option 1 to be $33billion to $54 billion in 2020 and $55billion to $89 billion in 2030 assuminga regional compliance approach (2011dollars at a 3-percent discount rate[model average]), if states comply usinga state-specific compliance approach,these climate and health co-benefitsestimates are estimated to be $35 to $57billion in 2020 and $57 to $93 billionin 2030 (2011 dollars at a 3-percentdiscount rate [model averagel). We also

estimate the total combined climatebenefits and health co-benefits forOption 2 to be $26 billion to $44 billionin 2020 and $36 billion to $59 billionin 2025 (regional compliance approach,2011 dollars at a 3-percent discount rate[model average]). Assuming a statecompliance approach, the totalcombined climate benefits and healthco-benefits for Option 2 are estimated tobe $27 billion to $45 billion in 2020 and$36 billion to $60 billion in 2025 (2011dollars at a 3-percent discount rate[model average]). A summary of theemission reductions and monetizedbenefits estimated for this rule at alldiscount rates and additional analysisyears is provided in Tables 12 through17 of this preamble.

TABLE 12—SUMMARY OF THE MONETIZED GLOBAL CLIMATE BENEFITS FOR THE PROPOSED OPTION 1[Billions of 2011 dollars]a

Monetized climate benefits“02° Discount rate

(statistic) Regional Statecompliance compliance

CO2 Reductions (million metric tons) 371 3835 percent (average SCC) $4.7 $4.93 percent (average SCC) $17 $182.5 percent (average SCC) $25 $263 percent (95th percentile SCC) $51 $52

2025


2030


a Climate benefit estimates reflect impacts from CO2 emission changes in the analysis years presented in the table and do not account forchanges in non-CO2 GHG emissions. These estimates are based on the global social cost of carbon (SCC) estimates for the analysis years(2020, 2025, and 2030) and are rounded to two significant figures.

Monetized climate benefits2020 Discount rate



2025

TABLE 13—SUMMARY OF THE MONETIZED GLOBAL CLIMATE BENEFITS FOR[Billions of 2011 dollars] a

THE OPTION 2

CO2 Reductions (million metric tons)5 percent (average SCC)3 percent (average SCC)

368$5.5$18

376$5.6$19



TABLE 13—SUMMARY OF THE MONETIZED GLOBAL CLIMATE BENEFITS FOR THE OPTION 2—Continued[Billions of 2011 a

Monetized climate benefits2020 Discount rate


2.5 percent (average SCC) $27 $283 percent (95th percentile SCC) $56 $57

a Climate benefit estimates reflect impacts from CO2 emission changes in the analysis years presented in the table and do not account forchanges in non-CO2 GHG emissions. These estimates are based on the global SCC estimates for the analysis years (2020, 2025, and 2030)and are rounded to two significant figures.

TABLE 14—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS FOR THE PROPOSED STANDARDS OPTION 1 REGIONALCOMPLIANCE APPROACH IN THE U.S.

[Billions of 2011 dollars]a

National Monetized Monetizedemission health co- health coPollutant reductions benefits benefits

(thousands of (3 percent (7 percentshort tons) discount) discount)

Option 7 Regional Compliance Approach 2020

PM2.5 precursors: b

SO2 292 $l2to$26 $71 to$24Directly emitted PM25 (Elemental Carbon and Organic Carbon) 6 $0.75 to $1.7 $0.67 to $1.5Directly emitted PM2.5 (crustal) 44 $0.77 to $1.7 $0.69 to $1.6NO 345 $2.2 to $5.0 $2.0 to $4.5Ozone precursor:°NO (ozone season only) 746 $0.63 to $2.7 $0.63 to $2.7

Total Monetized Health Co-benefits $16 to $37 $15 to $34Total Monetized Health Co-benefits combined with Monetized Climate Benefits ci $33 to $54 $32 to $51


PM2.5 precursorsbSO2 395 $l7to $38 $75 to $35Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) 6 $0.85 to $1.9 $0.76 to $1.7Directly emitted PM2.5 (crustal) 46 $0.78 to $7.8 $0.70 to $1.6NO 421 $3.0 to $6.8 $2.7 to $6.1Ozone precursor: C

NO (ozone season only) 180 $1.0 to $4.3 $7.0 to $4.3

Total Monetized Health Co-benefits $23 to $53 $27 to $48

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d$48 to $78 $46 to $74


PM2.5 precursors: b

502 424 $20 to $44 $18 to $40Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) 5 $0.84 to $1.9 $0.76 to $1.7Directly emitted PM2.5 (crustal) 42 $0.77 to $1.7 $0.70 to $1.6NO 407 $3.0 to $6.7 $2.7 to $6.7Ozone precursor: C

NOx(ozone season only) 176 $7.1 to $4.5 $1.1 to $4.5

Total Monetized Health Co-benefits $25 to $59 $23 to $54Total Monetized Health Co-benefits combined with Monetized Climate Benefits d $55 to $89 $53 to $84aAlI estimates are for the analysis years (2020, 2025, 2030) and are rounded to two significant figures, so estimates may not sum. It Is important to note that themonetized co-benefits do not include reduced health effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S.bThe monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5 precursors, such asSO2, NO and directly emitted PM2.5. PM co-benefits are shown as a range reflecting the use of two concentration-response functions, with the lower end of therange based on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2072). 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 differentiationof effect estimates by particle type.CThe monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone through reductions of NOx during the ozone season. Ozone co-benefits are shown as a range reflecting the use of several different concentration-response functions, with the lower end of the range based on afunction from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits occur in the analysis year, so they are the samefor all discount rates.dWe estimate climate benefits associated with four different values of a one ton CO2 reduction (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase over time. For the purposes of this table, we show the benefits associated with the model average at 3% discount rate, however we emphasize the importance and value of considering the full range of SCC values. We provide combined climate and health estimates basedon additional discount rates in the RIA.



TABLE 15—SUMMARY OF THE MONETIZED HEALTH Co-BENEFITS IN THE U.S. FOR THE PROPOSED GUIDELINES OPTION 1STATE COMPLIANCE APPROACH

[Billions of 2011 dollars] a

National

Iemission Monetized health co-benefits Monetized health co-benefitso lutant

feUctIodflSf (3 percent discount) (7 percent discount)short tons)

Option 1 State Compliance Approach in 2020

PM2.5 precursors: b

502 335 $l3to$29 $11 to $26Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) 6 $0.76 to $1.7 $0.69 to $1.6Directly emitted PM2.5 (crustal) 45 $0.79 to $1.8 $0.77 to $1.6NO 367 $2.2 to $4.9 $2.0 to $4.4Ozone precursor: C



Total Monetized Health Co-benefits combined with Monetized Climate Benefits $35 to $57 $33 to $54

OptIon 1 State Compliance Approach in 2025

PM25 precursors: b

SO2 425 $18 to $40 $16 to $36Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) 6 $0.90 to $2.0 $0.81 to $1.8Directly emitted PM25 (crustal) 49 $0.83 to $1.9 $0.75 to $1.7NO 436 $2.9 to $6.5 $2.6 to $5.8Ozone precursor: C



Total Monetized Health Co-benefits combined with Monetized Climate Benefits d $49 to $80 $46 to $75


PM2.5 precursors: b

SO2 471 $21 to $47 $19 to $43Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) 6 $0.87 to $2.0 $0.78 to $1.8Directly emitted PM2.5 (crustal) 44 $0.80 to $1.8 $0.72 to $1.6NO 428 $2.9 to $6.6 $2.6 to $6.0Ozone precursor:CNO (ozone season only) 187 $1.1 to $4.6 $1.1 to $4.6


Total Monetized Health Co-benefits combined with Monetized Climate Benefits U $57 to $93 $55 to $87aAll estimates are for the analysis years (2020, 2025, 2030) and are rounded to two significant figures, so estimates may not sum. It is important to note that themonetized co-benefits do not include reduced health effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S.bThe monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2 precursors, such asSO2, NO, and directly emitted PM2.5. PM co-benefits are shown as a range reflecting the use of two concentration-response functions, with the lower end of therange based on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012). These models assume that all fine particles,regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiationof effect estimates by particle type.°The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone through reductions of NO during the ozone season. Ozone co-benefits are shown as a range reflecting the use of several different concentration-response functions, with the lower end of the range based on afunction from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits occur in the analysis year, so they are the samefor all discount rates.dWe estimate climate benefits associated with four different values of a one ton CO2 reduction (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase over time. For the purposes of this table, we show the benefits associated with the model average at 3% discount rate, however we emphasize the importance and value of considering the full range of SCC values. We provide combined climate and health estimates basedon additional discount rates in the RIA.

TABLE 16—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS IN THE U.s. FOR THE OPTION 2 REGIONAL COMPLIANCEAPPROACH


Nationalemission

Pollutant reductions Monetized health co-benefits Monetized health co-benefits(thousands of (3 percent discount) (7 percent discount)

short tons)


PM2.5 precursors: b

SO2Directly emitted PM2.5 (Elemental Carbon and Organic Carbon)Directly emitted PM2.5 (crustal)NOOzone precursor:°

2445

36268

$9.8 to $22$0.67 to $1.4$0.63 to $1.4$1.7 to $3.9

$8.9 to $20$0.55 to $1.2$0.57 to $1.3$1.6 to $3.5



TABLE 16—SUMMARY OF THE MONETIZED HEALTH Co-BENEFITS IN THE U.S. FOR THE OPTION 2 REGIONAL COMPLIANCEAPPROACH—Continued


Nationalemission Monetized health co-benefits Monetized health co-benefits0 utant

(thousands of (3 percent discount) (7 percent discount)short tons)



Total Monetized Health Co-benefits combined with Monetized Climate Benefits d $26 to $44 $25 to $41

Option 2 Regional Compliance Approach in 2025

PM2.5 precursors: b

502 297 $73to$29 $12 to $26Directly emitted PM25 (Elemental Carbon and Organic Carbon) 4 $0.64 to $1.4 $0.58 to $1.3Directly emitted PM25 (crustal) 34 $0.59 to $1.3 $0.53 to $1.2NO 309 $2.2 to $5.0 $2.0 to $4.5Ozone 0



Total Monetized Health Co-benefits combined with Monetized Climate Benefits d $36 to $59 $34 to $55GAll estimates are for the analysis years (2020, 2025) and are rounded to two significant figures, so estimates may not sum. It is important to note that the monetized co-benefits do not include reduced health effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air pollutionhealth co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S.bThe monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5 precursors, such as502, NO and directly emitted PM2.5. PM co-benefits are shown as a range reflecting the use of two concentration-response functions, with the lower end of therange based on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2072). 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 differentiationof effect estimates by particle type.clhe monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone through reductions of NOx during the ozone season. Ozone co-benefits are shown as a range reflecting the use of several different concentration-response functions, with the lower end of the range based on afunction from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits occur in the analysis year, so they are the samefor all discount rates.d We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase over time. For the purposes of this table, we show the benefits associated with the model average at 3% discount rate, however we emphasize the importance and value of considering the full range of SCC values. We provide combined climate and health estimates basedon additional discount rates in the RIA.

TABLE 17—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS IN THE U.S. FOR OPTIONAPPROACH


2 STATE COMPLIANCE

PM2.5 precursors: b

SO2Directly emitted PM2.5 (Elemental Carbon and Organic Car

bon).Directly emitted PM2.5 (crustal)NOxOzone precursor:°

327 $l4to$305 $0.69 to $1.6

38 $0.64 to $1.4317 $2.1 to $4.7

National

IIemission Monetized health co-benefits Monetized health co-benefitsu an

(thousands of (3 percent discount) (7 percent discount)short tons)


PM25 precursors:bSO2 267 $10 to $23 $9.1 to $21Directly emitted PM2.5 (Elemental Carbon and Organic Car- 5 $0.64 to $1.5 $0.58 to $1.3bon).Directly emitted PM2.5 (crustal) 38 $0.66 to $1.5 $0.60 to $1.4NO 281 $1.7 to $3.8 $1.5 to $3.4Ozone precursor:CNO (ozone season only) 119 $0.48 to $2.1 $0.48 to $2.1


Total Monetized Health Co-benefits combined with Monetized Climate $27 to $45 $26 to $42Benefits d


$12 to $27$0.63 to $1.4

$0.58 to $1.3$1.9 to $4.2



TABLE 17—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS IN THE U.S. FOR OPTION 2 STATE COMPLIANCEAPPROACH—Continued


National

Iemission Monetized health co-benefits Monetized health co-benefitsP0 lutant

(tldf (3 percent discount) (7 percent discount)short tons)



Total Monetized Health Co-benefits combined with Monetized Climate $36 to $60 $35 to $56Benefits d

a All estimates are for the analysis years (2020, 2025) and are rounded to two significant figures, so estimates may not sum. It is important tonote that the monetized co-benefits do not include reduced health effects from direct exposure to SO2, direct exposure to NO2, ecosystem effectsor visibility impairment. Air pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S.blhe monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5precursors, such as SO2, NO and directly emitted PM2.5. PM co-benefits are shown as a range reflecting the use of two concentration-responsefunctions, with the lower end of the range based on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule etal. (2012). These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type.cThe monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone through reductions of NOduring the ozone season. Ozone co-benefits are shown as a range reflecting the use of several different concentration-response functions, withthe lower end of the range based on a function from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozoneco-benefits occur in the analysis year, so they are the same for all discount rates.d We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average at 2.5 percent discount rate, 3percent, and 5 percent; 95th percentile at 3 percent), which each increase over time. For the purposes of this table, we show the benefits associated with the model average at 3% discount rate; however, we emphasize the importance and value of considering the full range of SCC values.We provide combined climate and health estimates based on additional discount rates in the RIA.

The EPA has used the social cost ofcarbon (SCC) estimates presented in the2013 Technical Support Document:Technical Update of the Social Cost ofCarbon for Regulatory Impact AnalysisUnder Executive Order 12866 (2013 5CCTSD) to analyze CO2 climate impacts ofthis rulemaking.331 We refer to theseestimates, which were developed by theU.S. government, as “8CC estimates.”The U.S. government first published theSCC estimates in 2010 following aninteragency process that included theEPA and other executive branchentities; the process used threeintegrated assessment models (JAM) todevelop 8CC estimates and selected fourglobal values for use in regulatoryanalyses. The U.S. government recentlyupdated these estimates using newversions of each integrated assessmentmodel and published them in 2013. The2013 update did not revisit the 2010

331 Docket ID EPA—HQ—OAR—2013—0495,Technical Support Document: Technical Update ofthe Social Cost of Carbon for Regulatory ImpactAnalysis Under Executive Order 12866, InteragencyWorking Group on Social Cost of Carbon, withparticipation by Council of Economic Advisers,Council on Environmental Quality, Department ofAgriculture, Department of Commerce, Departmentof Energy, Department of Transportation,Environmental Protection Agency, NationalEconomic Council, Office of Energy and ClimateChange, Office of Management and Budget, Officeof Science and Technology Policy, and Departmentof Treasury (May 2013, Revised November 2013).Available at: http://www.whitehouse.gov/sites!default/files/omb/assets/inforeg/technical-updatesocial-cost-of-carbon-for-regulator-impactan&ysis.pdf

modeling decisions (e.g., with regard tothe discount rate, reference casesocioeconomic and emission scenariosor equilibrium climate sensitivity).Rather, improvements in the waydamages are modeled are confined tothose that have been incorporated intothe latest versions of the models by thedevelopers themselves and published inthe peer-reviewed literature. The 2010SCC Technical Support Document (2010SCC TSD) provides a completediscussion of the methods used todevelop these estimates and the 20138CC TSD presents and discusses theupdated estimates.332

The EPA and other agencies havesought public comment on the 8CCestimates as part of various rulemakings.In addition, OMB’s Office ofInformation and Regulatory Affairsrecently sought public comment on theapproach used to develop the estimates.The comment period ended on February

332 Docket ID EPA—HQ—OAR—2009—0472—114577,Technical Support Document: Social Cost ofCarbon for Regulatory Impact Analysis UnderExecutive Order 12866, Interagency Working Groupon Social Cost of Carbon, with participation by theCouncil of Economic Advisers, Council onEnvironmental Quality, Department of Agriculture,Department of Commerce, Department of Energy,Department of Transportation, EnvironmentalProtection Agency, National Economic Council,Office of Energy and Climate Change, Office ofManagement and Budget, Office of Science andTechnology Policy, and Department of Treasury(February 2010). Also available at: hftp:!!www. whitehouse.gov!sites/default/files/omb!inforeg/for-agencies/Social-Cost-of-Corbon-forRJA.pdJ.

26, 2014, and 0MB is reviewing thecomments received.

The four 8CC estimates, updated in2013, are as follows: $13, $46, $68, and$137 per metric ton of CO2 emissions inthe year 2020 (2011 dollars).333 The firstthree values are based on the average8CC from the three JAMs, at discountrates of 5, 3, and 2.5 percent,respectively. SCCs at several discountrates are included because the literatureshows that the 8CC is quite sensitive toassumptions about the discount rate,and because no consensus exists on theappropriate rate to use in anintergenerational context (where costsand benefits are incurred by differentgenerations). The fourth value is the95th percentile of the 8CC from all threemodels at a 3 percent discount rate. Itis included to represent higher-than-expected impacts from temperaturechange further out in the tails of the8CC distribution (representing lesslikely, but potentially catastrophic,outcomes).

The 2010 8CC TSD noted a number oflimitations to the 8CC analysis,including the incomplete way in whichthe integrated assessment modelscapture catastrophic and non-catastrophic impacts, their incompletetreatment of adaptation and

33 The 2010 and 2013 TSDs present SCC in$2007. The estimates were adjusted to 2011$ usingthe GDP implicit Price Deflator. Also available at:hup:llwww.gpo.gov!fdsys!pkg!ECONI-2013-02!pdf/ECONI-201 3-02-Pg3.pdf.



technological change, uncertainty in theextrapolation of damages to hightemperatures, and assumptionsregarding risk aversion. Currentintegrated assessment models do notassign value to all of the importantphysical, ecological, and economicimpacts of climate change recognized inthe climate change literature for variousreasons, including the inherentdifficulties in valuing non-marketimpacts and the fact that the scienceincorporated into these modelsunderstandably lags behind the mostrecent research. Nonetheless, theseestimates and the discussion of theirlimitations represent the best availableinformation about the social benefits ofCO2 emission reductions to inform thebenefit-cost analysis. Model developerscontinually update the models toincorporate recent research. The newversions of the models used to estimatethe values presented in this rulemakingoffer some improvements in these areasidentified above, although further workis warranted. Accordingly, the EPA andother parties continue to conductresearch on modeling and valuation ofclimate impacts with the goal ofimproving these estimates. Additionaldetails are provided in the SCC TSDs.

The health co-benefits estimatesrepresent the total monetized humanhealth benefits for populations exposedto reduced PM2.5 and ozone resultingfrom emission reductions underillustrative compliance options for theproposed standards. Unlike the globalSCC estimates, the air pollution healthco-benefits are estimated for thecontiguous U.S. only. We used a“benefit-per-ton” approach to estimatethe benefits of this rulemaking. Tocreate the PM2.5 benefit-per-tonestimates, this approach uses a model toconvert emissions of PM2.5 precursorsinto changes in ambient PM2.5 levelsand another model to estimate thechanges in human health effectsassociated with that change in airquality, which are then divided by theemissions in specific sectors. Wederived national average benefit-per-tonestimates for the EGU sector using theapproach published in Fann et al.(2012), and updated those estimatesto reflect the studies and populationdata in the 2012 PM NAAQS RIA. Wefurther separated the national estimatesinto regional estimates to providegreater spatial resolution. In addition,

334Fann, N., KR. Baker and CM. Fuicher. 2012.“characterizing the PM25-related health benefits ofemission reductions for 17 industrial, area andmobile emission sectors across the U.S.”Environment International 4941—151.

U.s. Environmental Protection Agency (U.S.EPA). 2012. Regulatory Impact Analysis for the

we generated regional benefit-per-tonestimates for changes in ozoneexposure. The ozone estimates used theozone information from the sectormodeling for the EGU sector describedin Farm et al. (2012) and the healthimpact assumptions used in the OzoneNAAQS RIAs.336337 To calculate the cobenefits for the proposed standards, wemultiplied the regional benefit-per-tonestimates for the EGU sector by thecorresponding emission reductions.338All benefit-per-ton estimates reflect thegeographic distribution of the modeledemissions, which may not exactly matchthe emission reductions in thisrulemaking, and thus they may notreflect the local variability in populationdensity, meteorology, exposure, baselinehealth incidence rates, or other localfactors for any specific location. Moreinformation regarding the derivation ofthe benefit-per-ton estimates is availablein the RIA.

These models assume that all fineparticles, regardless of their chemicalcomposition, are equally potent incausing premature mortality because thescientific evidence is not yet sufficientto allow differentiation of effectestimates by particle type. Even thoughwe assume that all fine particles haveequivalent health effects, the benefit-per-ton estimates vary betweenprecursors depending on the locationand magnitude of their impact on PM2.5levels, which drive populationexposure.

It is important to note that themagnitude of the PM2.5 and ozone cobenefits is largely driven by theconcentration response functions for

Final Revisions to the Notional Ambient Air QualityStandards for Particulate Matter. Research TrianglePark, NC: Office of Air Quality Planning andStandards, Health and Environmental ImpactsDivision. (EPA document number EPA-452/R—12—003, December). Available at: <http://www.epa.gov/pm/2012/finalria.pdf>.

338 U.S. Environmental Protection Agency (U.S.EPA). 2008b. Final Ozone NAAQS RegulatoryImpact Analysis. Research Triangle Park, NC: Officeof Mr Quality Planning and Standards, Health andEnvironmental Impacts Division, Air Benefit andCost Group Research. (EPA document number EPA—452/R—08—003, March). Available at: <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfmi’deid=l 94645>.

337U.S. Environmental Protection Agency (U.S.EPA). 2010. Section 3: Re-analysis of the BenefitsofAttaining Alternative Ozone Standards toIncorporate Current Methods. Available at <hftp:I/www.epa.gav/ttnecasl/regdata/RLA5/s3-supplemental_analysis-updated_benefitsl 1-5.09.pdj>.

338 U.S. Environmental Protection Agency. 2013.Technical support document: Estimating the benefitper ton of reducing PM2.5 precursors from 17sectors. Research Triangle Park, NC: Office of Airand Radiation, Office of Mr Quality Planning andStandards, January. Available at: <hftp://www.epa.gov/airquality/benmap/models/Source_ApportionmentfiPT_TSD_1_31_1 3.pdf>.

premature mortality and the value of astatistical life used to value reductionsin premature mortality. For PM2.5, wecite two key empirical studies, onebased on the American Cancer Societycohort 339 and the extended SixCities cohort study.34° We present thePM2.5 co-benefits results as a rangebased on the concentration-responsefunctions from these two epidemiologystudies, but this range does not capturethe full range of uncertainty inherent inthe co-benefits estimates. In the RIA forthis rule, which is available in thedocket, we also include PM2.5 cabenefits estimates derived from expertjudgments (Roman et al., 2008) 341 as acharacterization of uncertaintyregarding the PM2.s-mortalityrelationship. For the ozone co-benefits,we present the results as a rangereflecting the use of several differentconcentration-response functions formortality, with the lower end of therange based on a function from Bell etal. (2004) 342 and the upper end basedon a function from Levy et al. (2005).34Similar to PM2.5, the range of ozone cobenefits does not capture the hill rangeof inherent uncertainty.

In this analysis, the EPA assumes thatthe health impact function for fineparticles is without a threshold. This isbased on the conclusions of EPA’sIntegrated Science Assessment forParticulate Matter,344 which evaluatedthe substantial body of publishedscientific literature, reflecting thousandsof epidemiology, toxicology, andclinical studies that documents theassociation between elevated PM2.5

339Krewski D.; M. Jerrett; R.T. Burnett; R. Ma; E.Hughes; Y. Shi, et al. 2009. Extended Follow-up andSpatial Analysis of the American Cancer SocietyStudy linking Particulate Air Pollution andMortality. Health Effects Institute. (HEI ResearchReport number 140). Boston, MA: Health EffectsInstitute.

340Lepeule, J.; F. Laden; D. Dockery; I. Schwartz.2012. “Chronic Exposure to Fine Particles andMortality: An Extended Follow-Up of the HarvardSix Cities Study from 1974 to 2009.” EnvironmentalHealth Perspective, 120(7), July, pp. 965—970.

341 Roman, H., et al. 2008. “Expert JudgmentAssessment of the Mortality Impact of Changes inAmbient Fine Particulate Mailer in the U.S.”Environmental Science & Technology, Vol. 42, No.7, February, pp. 2268—2274.

32 Bell, ML., at al. 2004. “Ozone and Short-TermMortality in 95 U.S. Urban Communities, 1987—2000.” Journal of the American MedicalAssociation, 292(19), pp. 2372—8.

34 Levy, J.I., SM. Chemerynski, and J.A. Samat.2005. “Ozone exposure and mortality: an empiricbayes metaregression analysis.” Epidemiology.16(4): p. 458—68.‘- U.S. Environmental Protection Agency. 2009.

Integrated Science Assessment for ParticulateMatter (Final Report). Research Triangle Park, NC:National Center for Environmental Assessment,RTP Division. (EPA document number EPA-600—R—08—139F, December). Available at: <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=21 6546>.


34942 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules

concentrations and adverse healtheffects, including increased prematuremortality. This assessment, which wastwice reviewed by the EPA’sindependent Science Advisory Board,concluded that the scientific literatureconsistently finds that a no-thresholdmodel most adequately portrays the PM-mortality concentration-responserelationship.

In general, we are more confident inthe magnitude of the risks we estimatefrom simulated PM2.5 concentrationsthat coincide with the bulk of theobserved PM concentrations in theepidemiological studies that are used toestimate the benefits. Likewise, we areless confident in the risk we estimatefrom simulated PM2.5 concentrationsthat fall below the bulk of the observeddata in these studies.

For this analysis, policy-specific airquality data are not available,3 andthus, we are unable to estimate thepercentage of premature mortalityassociated with this specific rule’semission reductions at each PM2.5 level.As a surrogate measure of mortalityimpacts, we provide the percentage ofthe population exposed above thelowest measured PM2.5 level (LML) ineach of the studies from which weobtained concentration-responsefunctions for PM2.5 mortality, using theestimates of PM2.5 from the sourceapportionment modeling used tocalculate the benefit-per-ton estimatesfor the EGU sector. Using the Krewskiet al. (2009) study, 93 percent of thepopulation is exposed to annual meanPM2.5 levels at or above the LML of 5.8micrograms per cubic meter Q.g/m3).Using the Lepeule et al. (2012) study, 67percent of the population is exposedabove the LML of 8 Lg/m3. It isimportant to note that baseline exposureis only one parameter in the healthimpact function, along with baselineincidence rates, population, and changein air quality. Therefore, caution iswarranted when interpreting the LMLassessment for this rule because theseresults are not consistent with resultsfrom rules that had air quality modeling.

Every benefit analysis examining thepotential effects of a change inenvironmental protection requirementsis limited, to some extent, by data gaps,model capabilities (such as geographiccoverage) and uncertainties in theunderlying scientific and economicstudies used to configure the benefit andcost models. Despite these uncertainties,we believe the air quality co-benefitanalysis for this rule provides a

345In addition, site-specific emission reductionswill depend upon how states implement theguidelines.

reasonable indication of the expectedhealth benefits of the air pollutionemission reductions for the illustrativecompliance options for the proposedstandards under a set of reasonableassumptions. This analysis does notinclude the type of detailed uncertaintyassessment found in the 2012 PM2.5National Ambient Air Quality Standard(NAAQS) RIA (U.S. EPA, 2012) becausewe lack the necessary air quality inputand monitoring data to conduct acomplete benefits assessment. Inaddition, using a benefit-per-tonapproach adds another important sourceof uncertainty to the benefits estimates.The 2012 PM2.5 NAAQS benefitsanalysis provides an indication of thesensitivity of our results to variousassumptions.

We note that the monetized cobenefits estimates shown here do notinclude several important benefitcategories, including exposure to SO2,NON, and hazardous air pollutants (e.g.,mercury and hydrogen chloride), as wellas ecosystem effects and visibilityimpairment. Although we do not havesufficient information or modelingavailable to provide monetizedestimates for this rule, we include aqualitative assessment of theseunquantified benefits in the RIA forthese proposed amendments.

For more information on the benefitsanalysis, please refer to the RIA for thisrule, which is available in therulemaking docket.

XI. Statutory and Executive OrderReviews

A. Executive Order 12866, RegulatoryPlanning and Review, and ExecutiveOrder 13563, Improving Regulation andRegulatory Review

Under Section 3(f)(1) of ExecutiveOrder 12866 (58 FR 51735, October 4,1993), this action is an “economicallysignificant regulatory action” because itis likely to have an annual effect on theeconomy of $100 million or more oradversely affect in a material way theeconomy, a sector of the economy,productivity, competition, jobs, theenvironment, public health or safety, orstate, local, or tribal governments orcommunities. The $100 millionthreshold can be triggered by eithercosts or benefits, or a combination ofthem. Accordingly, the EPA submittedthis action to 0MB for review underExecutive Orders 12866 and 13563 (76FR 3821, January 21, 2011), and anychanges made in response to 0MBrecommendations have beendocumented in the docket for thisaction.

The EPA also prepared an analysis ofthe potential costs and benefitsassociated with this action. Thisanalysis is contained in the RIA for thisproposed rule. A copy of the analysis isavailable in the docket for this action.

Consistent with EQ 12866 and EQ13563, the EPA estimated the costs andbenefits for illustrative complianceapproaches of implementing theproposed guidelines. This proposal setsgoals to reduce CO2 emissions from theelectric power industry. Actions takento comply with the proposed guidelineswill also reduce the emissions ofdirectly emitted PM2.5, sulfur dioxide(SO2) and nitrogen oxides (NOx). Thebenefits associated with these PM, SO2and NO reductions are referred to asco-benefits, as these reductions are notthe primary objective of this rule.

The EPA has used the social cost ofcarbon estimates presented in the 2013Technical Support Document:Technical Update of the Social Cost ofCarbon for Regulatory Impact AnalysisUnder Executive Order 12866 (2013 SCCTSD) to analyze CO2 climate impacts ofthis rulemaking. We refer to theseestimates, which were developed by theU.S. government, as “SCC estimates.”The SCC is an estimate of the monetaryvalue of impacts associated with amarginal change in CO2 emissions in agiven year. The four SCC estimates areassociated with different discount rates(model average at 2.5 percent discountrate, 3 percent, and 5 percent; 95thpercentile at 3 percent), and eachincreases over time. In this sununary,the EPA provides the esthnate of climatebenefits associated with the 8CC valuedeemed to be central in the 8CC TSD:The model average at 3% discount rate.For the regional compliance approach,the EPA estimates that in 2020 thisOption 1 proposal will yield monetizedclimate benefits (in 2011$) ofapproximately $17 billion (3 percentmodel average). The air pollution healthco-benefits in 2020 are estimated to be$16 billion to $37 billion (2011$) for a3 percent discount rate and $15 billionto $34 billion (2011$) for a 7 percentdiscount rate. The annual, illustrativecompliance costs estimated by 1PM andinclusive of demand side energyefficiency program and participant costsand MRR costs, are approximately $5.5billion (2011$) in 2020. The quantifiednet benefits (the difference betweenmonetized benefits and costs) in 2020are estimated to be $28 billion to $49billion assuming a regional complianceapproach (2011$) using a 3 percentdiscount rate (model average). Thisrange of net benefits is estimated to be$27 billion to $50 billion assuming astate compliance approach (2011$)



using a 3 percent discount rate (modelaverage). Table 18 shows the climatebenefits, health co-benefits, cost and netbenefits for Option 1 in 2020 for stateand regional compliance approaches.Table 19 shows similar estimates for2030.

For Option 1 in 2030 assuming aregional compliance approach, the EPAestimates this proposal will yieldmonetized climate benefits (in 2011$) ofapproximately $30 billion (3 percent,model average). The air pollution healthco-benefits in 2030 are estimated to be$25 billion to $59 billion (2011$) for a3 percent discount rate and $23 billionto $54 billion (2011$) for a 7 percentdiscount rate. The annual illustrative

compliance costs estimated using 1PM,inclusive of a demand-side energyefficiency program and participant costsand MRR costs, are approximately $7.3billion (2011$) in 2030. The quantifiednet benefits (the difference betweenmonetized benefits and costs) in 2030are estimated to be $48 billion to $82billion (2011$) using a 3 percentdiscount rate (model average). The EPAestimates that this proposal will yieldmonetized climate benefits (in 2011$) ofapproximately $31 billion (3 percent,model average) for Option 1 statecompliance approach in 2030. The airpollution health co-benefits in 2030 areestimated to be $27 billion to $62 billion(2011$) for a 3 percent discount rate and

$24 billion to $56 billion (2011$) for a7 percent discount rate. The annualillustrative compliance costs estimatedusing 1PM, inclusive of demand sideenergy efficiency program andparticipant costs and MRR costs, areapproximately $8.8 billion (2011$) in2030. The quantified net benefits (thedifference between monetized benefitsand costs) in 2030 are estimated to be$49 billion to $84 billion (2011$) usinga 3 percent discount rate (modelaverage) assuming a state complianceapproach. Based upon the foregoingdiscussion, it remains clear that thebenefits of the proposal Option 1 aresubstantial and far exceed the costs.

TABLE 19—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR PROPOSED OPTION 1IN 2030 a

[Billions of 2011$J


Option 1 Regional Compliance Approach


Air pollution health cobenefitsc $25 to $59 $23 to $54Total Compliance Costsd $7.3 $73Net Monetized Benefits e $48 to $82 $46 to $77

TABLE 18—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE CosTs AND NET BENEFITS FOR PROPOSED OPTION 1IN 2020a

[Billions of 2011$]


OptIon 1 Regional Compliance Approach

Climate benefits° $17.

Air pollution health co-benefits c $16 to $37 $15 to $34Total Compliance Costs d$5.5 $5.5Net Monetized Benetits $28 to $49 $26 to $45

Non-monetized Benefits Direct exposure to SO2 and NO2.1.3 tons of Hg.Ecosystem Effects.Visibility impairment

Option 1 State Compliance Approach


Air pollution health $17 to $40 $15 to $36Total Compliance Costs U $7.5 $7.5Net Monetized Benefits e $27 to $50 $26 to $46


aAll estimates are for 2020, and are rounded to two significant figures, so figures may not sum.bThe climate benefit estimate in this summary table reflects global impacts from CO2 emission chanes and does not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SCC than to the other estimates because CO2 emissions are long-lived and subsequent damages occur over manyyears. The benefit estimates in this table are based on the average SCC estimated for a 3 percent discount rate; however, we emphasize the importance and valueof considering the full range of SCC values. As shown in the RIA, climate benefits are also estimated using the other three SCC estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SCC estimates are year-specific and increase over time.CThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emitted PM2.5, SO2 and NOx. Therange reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 90percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potentin causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type.UTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the proposed option and a discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping, and reporting costs and demand side energy efficiency program and participant costs.eThe estimates of net benefits in this summary table are calculated usin9 the global social cost of carbon at a 3 percent discount rate (model average). The RIA includes combined climate and health estimates based on these additional discount rates.



TABLE 19—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR PROPOSED OPTION 1IN 2030 a_Continued

[Billions of 2011$]


Non-monetized Benefits Direct exposure to 502 and NO2.1.7 tons of Hg and 580 tons of HCI.Ecosystem Effects.Visibility impairment.



Air pollution health cobenefitsc $27 to $62 $24 to $56Total Compliance Costsd $8.8 $8.8Net Monetized $49 to $84 $46 to $79

Non-monetized Benefits Direct exposure to SO2 and NO2.2.1 tons of Hg and 590 tons of HCI.Ecosystem Effects.Visibility impairment.

aAll estimates are for 2030, and are rounded to two significant figures, so figures may not sum.bThe climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does not account for changes innon-CO2 GHG emissions. Also, different discount rates are applied to SCC than to the other estimates because CO2 emissions are long-livedand subsequent damages occur over many years. The benefit estimates in this table are based on the average SCC estimated for a 3 percentdiscount rate; however, we emphasize the importance and value of considering the full range of SCC values. As shown in the RIA, climate benefits are also estimated using the other three SCC estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SCC estimates are year-specific and increase over time.cThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emittedPM2.5, SO2 and NOR. The range reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 90 percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fineparticles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yetsufficient to allow differentiation of effect estimates by particle type.diotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the proposed option anda discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping, and reporting costs and demand side energy efficiency program and participant costs.elhe estimates of net benefits in this summary table are calculated using the global social cost of carbon at a 3 percent discount rate (modelaverage). The RIA includes combined climate and health estimates based on these additional discount rates.

The estimated costs and benefits forthe regulatory alternative—Option 2regional and state complia.nceapproaches are shown in Tables 20 and21. As these tables reflect, net benefitsin 2020 are estimated to be $22 to $40billion (3 percent discount rate) and $21to $37 billion (7 percent discount rate)for Option 2 assuming regionalcompliance. These Option 2 net benefitestimates become $22 to $40 billion (3percent discount rate) and $20 to $37

discount rate) assuming a regionalcompliance approach and $31 billion to$55 billion (3 percent discount rate) and$29 billion to $51 billion (7 percentdiscount rate) assuming a statecompliance approach.

non-CO2 greenhouse gases and cobenefits from reducing exposure to SO2,NOx, and hazardous air pollutants (e.g.,mercury and hydrogen chloride), as wellas ecosystem effects and visibility



Climate benefitsb

$73

Air pollution health cobenefitsc $13 to $37 $12 to $28Total Compliance Costs U $4.3 $4.3Net Monetized Benefits $22 to $40 $21 to $37Non-monetized Benefits Direct exposure to SO2 and NO2.

0.9 tons of Hg.Ecosystem Effects.Visibility impairment.

billion (7 percent discount rate) with the The EPA could not monetizestate compliance approach. In 2025, net important benefits of proposed Option 1benefits are estimated to be $31 billion and regulatory alternative Option 2.to $54 billion (3 percent discount rate) Unquantified benefits include climateand $29 billion to $50 billion (7 percent benefits from reducing emissions of

impairment.

TABLE 20—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR PROPOSED OPTION 2IN 2020a

[Billions of 2011$]


federal Register/Vol. 79, No. 117/Wednesday, June 18, 2014/Proposed Rules 34945

TABLE 20—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE CosTs, AND NET BENEFITS FOR PROPOSED OPTION 2IN 2020 a—Continued

[Billions of 2011$]



Climate benefits” $14.

Air pollution health co-benefits c $14 to $32 $12 to $29Total Compliance Costs d$5.5 $5.5Net Monetized Benefits e$22 to $40 $20 to $37

Non-monetized Benefits Direct exposure to SO and NO2.1.2 tons of Hg.Ecosystem Effects.Visibility impairment.

aAll estimates are for 2020, and are rounded to two significant figures, so figures may not sum.bThe climate benefit estimate in this summary table reflects global impacts from CO2 emission chan9es and does not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SCC than to the other estimates because CO2 emissions are long-lived and subsequent damages occur over manyyears. The benefit estimates in this table are based on the average SCC estimated for a 3 percent discount rate; however, we emphasize the importance and valueof considering the full range of SCC values. As shown In the RIA, climate benefits are also estimated using the other three SCC estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SCC estimates are year-specific and increase over time.CThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emitted PM2.5, SO2 and NOR. Therange reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 90percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potentin causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type.Total costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the proposed option and a discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping and reporting costs and demand side energy efficiency program and participant costs.•The estimates of net benefits in this summary table are calculated usin9 the global social cost of carbon at a 3 percent discount rate (model average). The RIA includes combined climate and health estimates based on these additional discount rates.

TABLE 21—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR PROPOSED OPTION 2IN 2025 a

[Billions of 2011$]




Air pollution health $17 to $40 $16 to $36Total Compliance Costsd $4.5 $4.5Net Monetized 0$31 to $54 $29 to $50




Air pollution health co.benefitsc $18 to $41 $16 to $37Total Compliance Costs d$5.5 $5.5Net Monetized Benefits $31 to $55 $29 to $51


aAll estimates are for 2025, and are rounded to two significant figures, so figures may not sum.bThe climate benefit estimate in this summary table reflects global impacts from CO2 emission chan9es and does not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SCC than to the other estimates because CO2 emissions are long-lived and subsequent damages occur over manyyears. The benefit estimates in this table are based on the average 5CC estimated for a 3 percent discount rate; however, we emphasize the importance and valueof considering the full range of SCC values. As shown in the RIA, climate benefits are also estimated using the other three SCC estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SCC estimates are year-specific and increase over time.The air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emitted PM2.5, SO2 and NOx. Therange reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 90percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potentin causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type.UTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the proposed option and a discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping and reporting costs and demand side energy efficiency program and participant costs.eThe estimates of net benefits in this summary table are calculated usin9 the global social cost of carbon at a 3 percent discount rate (model average). The RIA includes combined climate and health estimates based on these additional discount rates.

The analysis done in support of this the proposed Option 1 (and regulatory regional compliance approach. Theproposal shows that the emission alternative Option 2) are larger if states regional approach allows for morereductions, benefits, and costs for the choose to comply on an individual flexibility across states, which results inillustrative compliance approaches for basis, compared to the illustrative slightly fewer emission reductions and



lower overall costs. Net benefits (thedifference between benefits and costs]are roughly equivalent under theregional and state complianceapproaches.

In evaluating the impacts of theproposed guidelines, we analyzed anumber of uncertainties, for exampleevaluating different potential spatialapproaches to state compliance (i.e.,state and regional) and in the estimatedbenefits of reducing carbon dioxide andother air pollutants. For a furtherdiscussion of key evaluations ofuncertainty in the regulatory analysesfor this proposed rulemaking, see theRIA included in the docket.

B. Paperwork Reduction ActThe information collection

requirements in this proposed rule havebeen submitted for approval to theOffice of Management and Budget(0MB) under the Paperwork ReductionAct, 44 U.s.c. 3501 et seq. TheInformation collection Request (ICR)document prepared by the EPA has beenassigned the EPA ICR number 2503.01.

The information collectionrequirements are based on therecordkeeping and reporting burdenassociated with developing,implementing, and enforcing a stateplan to limit Co2 emissions fromexisting sources in the power sector.These recordkeeping and reportingrequirements are specifically authorizedby CAA section 114 (42 U.S.C. 7414).All information submitted to the EPApursuant to the recordiceeping andreporting requirements for which aclaim of confidentiality is made issafeguarded according to agencypolicies set forth in 40 CFR part 2,subpart B.

The annual burden for this collectionof information for the states (averagedover the first 3 years followingpromulgation of this proposed action) isestimated to be a range of 316,217 hoursat a total annual labor cost of$22,381,044, to 633,001 hours at a total

annual labor cost of $44,802,243. Thelower bound esthnate reflects theassumption that some states alreadyhave energy efficiency and renewableenergy programs in place. The higherbound estimate reflects the assumptionthat no states have energy efficiency andrenewable energy programs in place.The total annual burden for the federalgovernment (averaged over the first 3years following promulgation of thisproposed action) is estimated to be53,300 hours at a total annual labor costof $2,958,005. Burden means the totaltime, effort, or financial resourcesexpended by persons to generate,maintain, retain, or disclose or provideinformation to or for a federal agency.This includes the time needed to reviewinstructions; develop, acquire, install,and utilize technology and systems forthe purposes of collecting, validating,and verifying information, processingand maintaining information, anddisclosing and providing information;adjust the existing ways to comply withany previously applicable instructionsand requirements; train personnel to beable to respond to a collection ofinformation; search data sources;complete and review the collection ofinformation; and transmit or otherwisedisclose the information.

An agency may not conduct orsponsor, and a person is not required torespond to a collection of informationunless it displays a currently valid 0MBcontrol number. The 0MB controlnumbers for the EPA’s regulations arelisted in 40 CFR part 9 and 48 CFRchapter 15.

To comment on the agency’s need forthis information, the accuracy of theprovided burden estimates, and anysuggested methods for minimizingrespondent burden, the EPA hasestablished a public docket for this rule,which includes this ICR, under DocketID Number EPA-HQ-OAR-2013-0602.Submit any comments related to the ICRto the EPA and to 0MB. See theADDRESSES section at the beginning of

this notice for where to submitcomments to the EPA. Send commentsto 0MB at the Office of Information andRegulatory Affairs, Office ofManagement and Budget, 725 17thStreet, NW., Washington, DC 20503,Attention: Desk Office for the EPA.Since 0MB is required to make adecision concerning the ICR between 30and 60 days after June 18, 2014, acomment to 0MB is best assured ofhaving its full effect if 0MB receives itby July 18, 2014. The final rule willrespond to any 0MB or publiccomments on the information collectionrequirements contained in this proposal.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA)generally requires an agency to preparea regulatory flexibility analysis of anyrule subject to notice and commentrulemaking requirements under theAdministrative Procedure Act or anyother statute unless the agency certifiesthat the rule will not have a significanteconomic impact on a substantialnumber of small entities. Small entitiesinclude small businesses, smallorganizations, and small governmentaljurisdictions.

For purposes of assessing the impactsof this rule on small entities, smallentity is defined as:

(1) A small business that is defined bythe SBA’s regulations at 13 CFR 121.201(for the electric power generationindustry, the small business sizestandard is an ultimate parent entitywith less than 750 employees. TheNMCS codes for the affected industryare in Table 22 below);

(2) A small governmental jurisdictionthat is a government of a city, county,town, school district or special districtwith a population of less than 50,000;and

(3) A small organization that is anynot-for-profit enterprise which isindependently owned and operated andis not dominant in its field.

TABLE 22—POTENTIALLY REGULATED CATEGORIES AND ENTITIES a

Categorye5 Examples of potentially regulated entities a

Industry 221112 Fossil fuel electric power generating units.State/Local Government 221112 b Fossil fuel electric power generating units owned bymunicipalities.

a Include NAICS categories for source categories that own and operate electric power generating units (includes boilers and stationary combined cycle combustion turbines).b State or local government-owned and operated establishments are classified according to the activity in which they are engaged.

After considering the economicimpacts of this proposed rule on smallentities, I certify that this action will not

have a significant economic impact ona substantial number of small entities.

The proposed rule will not imposeany requirements on small entities.Specifically, emission guidelines



established under CAA section 111(d)do not impose any requirements onregulated entities and, thus, will nothave a significant economic impactupon a substantial number of smallentities. After emission guidelines arepromulgated, states establish standardson existing sources, and it is those staterequirements that could potentiallyimpact small entities. Our analysis hereis consistent with the analysis of theanalogous situation arising when theEPA establishes NAAQS, which do notimpose any requirements on regulatedentities. As here, any impact of aNAAQS on small entities would onlyarise when states take subsequent actionto maintain and/or achieve the NAAQSthrough their state implementationplans. See American Trucking Assoc. v.EPA, 175 F.3d 1029, 1043—45 (D.C. Cir.1999) (NAAQS do not have significantimpacts upon small entities becauseNAAQS themselves impose noregulations upon small entities).

Nevertheless, the EPA is aware thatthere is substantial interest in theproposed rule among small entities(municipal and rural electriccooperatives). As detailed in Sectionffl.A of this preamble, the EPA hasconducted an unprecedented amount ofstakeholder outreach on settingemission guidelines for existing EGUs.While formulating the provisions of theproposed rule, the EPA considered theinput provided over the course of thestakeholder outreach. Section llI.B ofthis preamble describes the keymessages from stakeholders. In addition,as described in the RFA section of thepreamble to the proposed standards ofperformance for GHG emissions fromnew EGUs (79 FR 1499—1500, January 8,2014), the EPA conducted outreach torepresentatives of small entities whileformulating the provisions of theproposed standards. Although only newEGUs would be affected by thoseproposed standards, the outreachregarded planned actions for new andexisting sources. We invite commentson all aspects of the proposal and itsimpacts, including potential impacts onsmall entities.

D. Unfunded Mandates Reform ActThis proposed action does not contain

a federal mandate that may result inexpenditures of $100 million or morefor state, local, and tribal governments,in the aggregate, or the private sector inany one year. Specifically, the emissionguidelines proposed under CAA section111(d) do not impose any directcompliance requirements on regulatedentities, apart from the requirement forstates to develop state plans. Theburden for states to develop state plans

in the 3-year period followingpromulgation of the rule was estimatedand is listed in Section IX B., above, butthis burden is estimated to be below$100 million in any one year. Thus, thisproposed rule is not subject to therequirements of section 202 or section205 of the Unfunded Mandates ReformAct (UMRA).

This proposed rule is also not subjectto the requirements of section 203 ofUMEA because ft contains no regulatoryrequirements that might significantly oruniquely affect small governments.

In light of the interest amonggovernmental entities, the EPA initiatedconsultations with governmentalentities while formulating theprovisions of the proposed standards fornew EGUs. Although only new EGUswould be affected by those proposedstandards, the outreach regardedplanned actions for new and existingsources. As described in the UMRAdiscussion in the preamble to theproposed standards of performance forGHG emissions from new EGUs (79 FR1500—1501, January 8, 2014), the EPAconsulted with the following 10national organizations representing stateand local elected officials: (1) NationalGovernors Association; (2) NationalConference of State Legislatures, (3)Council of State Governments, (4]National League of Cities, (5) U.S.Conference of Mayors, (6) NationalAssociation of Counties, (7)International City/County ManagementAssociation, 8) National Association ofTowns and Townships, (9) CountyExecutives of America, and 10)Environmental Council of States. OnFebruary 26, 2014, the EPA re-engagedwith those governmental entities toprovide a pre-proposal update on theemission guidelines for existing EGUsand emission standards for modifiedand reconstructed EGUs.

While formulating the provisions ofthese proposed emission guidelines, theEPA also considered the input providedover the course of the extensivestalceholder outreach conducted by theEPA (see Sections ffl.A. and ffl.B. of thispreamble).

E. Executive Order 13132, federalismUnder Executive Order 13132, the

EPA may not issue an action that hasfederalism implications, that imposessubstantial direct compliance costs, andthat is not required by statute, unlessthe federal government provides thefunds necessary to pay the directcompliance costs incurred by state andlocal governments, or the EPA consultswith state and local officials early in theprocess of developing the proposedaction.

The EPA has concluded that thisaction may have federalismimplications, because it may imposesubstantial direct compliance costs onstate or local governments, and thefederal government will not provide thefunds necessary to pay those costs. Asdiscussed in the Supporting Statementfound in the docket for this rulemaking,the development of state plans willentail many hours of staff time todevelop and coordinate programs forcompliance with the proposed rule, aswell as time to work with statelegislatures as appropriate, and developa plan submittal.

The EPA consulted with state andlocal officials early in the process ofdeveloping the proposed action topermit them to have meaningful andtimely input into its development. Asdescribed in the Federalism discussionin the preamble to the proposedstandards of performance for GHGemissions from new EGUs (79 FR 1501,January 8, 2014), the EPA consultedwith state and local officials in theprocess of developing the proposedstandards for newly constructed EGUs.This outreach regarded planned actionsfor new, reconstructed, modified andexisting sources. The EPA invited thefollowing 10 national organizationsrepresenting state and local electedofficials to a meeting on April 12, 2011,in Washington DC: (1) NationalGovernors Association; (2) NationalConference of State Legislatures, (3)Council of State Governments, (4)National League of Cities, (5) U.S.Conference of Mayors, (6) NationalAssociation of Counties, (7)International City/County ManagementAssociation, (8) National Association ofTowns and Townships, (9) CountyExecutives of America, and (10)Environmental Council of States. These10 organizations representing electedstate and local officials have beenidentified by the EPA as the “Big 10”organizations appropriate to contact forpurpose of consultation with electedofficials. On February 26, 2014, the EPAre-engaged with those governmentalentities to provide a pre-proposalupdate on the emission guidelines forexisting EGUs and emission standardsfor modified and reconstructed EGUs. Inaddition, extensive stakeholder outreachconducted by the EPA allowed stateleaders, including governors,environmental commissioners, energyofficers, public utility commissioners,and air directors, opportunities toengage with EPA officials and provideinput regarding reducing carbonpollution from power plants.

A detailed Federalism SummaryImpact Statement (FSIS) describing the


34948 Federal Register I Vol.79, No. 117 I Wednesday, June 18, 2014 / Proposed Rules

most pressing issues raised in preproposal and post-proposal commentswill be forthcoming with the final rule,as required by section 6(b) of ExecutiveOrder 13132. In the spirit of ExecutiveOrder 13132, and consistent with theEPA’s policy to promotecommunications between the EPA andstate and local governments, the EPAspecifically solicits comment on thisproposed action from State and localofficials.

F. Executive Order 13175, Consultationand Coordination With Indian TribalGovernments

This action does not have tribalimplications, as specified in ExecutiveOrder 13175 (65 FR 67249, November 9,2000). It would not impose substantialdirect compliance costs on tribalgovernments that have affected EGUslocated in their area of Indian country.Tribes are not required to, but may,develop or adopt CAA programs. Tribesare not required to develop plans toimplement the guidelines under CAAsection 111(d) for affected EGUs. To theextent that a tribal government seeksand attains treatment in a mannersimilar to a state (TAS) status for thatpurpose and is delegated authority forair quality planning purposes, theseproposed emission guidelines wouldrequire that planning requirements bemet and emission managementimplementation plans be executed bythe tribes. The EPA is aware of threecoal-fired EGUs and one natural gas-fired EGU located in Indian country butis not aware of any affected EGUs thatare owned or operated by tribal entities.The EPA notes that this proposal doesnot directly impose specificrequirements on ECU sources, includingthose located in Indian country, such asthe three coal-fired EGUs and onenatural gas-fired ECU, but providesguidance to any tribe with delegatedauthority to address CO2 emissions fromECU sources found subject to section111(d) of the CAA. Thus, ExecutiveOrder 13175 does not apply to thisaction.

The EPA conducted outreach to tribalenvironmental staff and offeredconsultation with tribal officials indeveloping this action. Because the EPAis aware of tribal interest in thisproposed nile, prior to the April 13,2012 proposal (77 FR 22 392—22441), theEPA offered consultation with tribalofficials early in the process ofdeveloping the proposed regulation topermit them to have meaningful andtimely input into its development. TheEPA’s consultation regarded plannedactions for new and existing sources. Inaddition, on April 15, 2014, prior to

proposal, the EPA met with NavajoEnergy Development Croup officials.For this proposed action for existingEGUs, a tribe that has one or moreaffected EGUs located in its area ofIndian 346 would have theopportunity, but not the obligation, toestablish a CO2 performance standardand a CAA section 111(d) plan for itsarea of Indian country.

Consultation letters were sent to 584tribal leaders. The letters providedinformation regarding the EPA’sdevelopment of both the NSPS andemission guidelines for fossil fuel-firedECUs and offered consultation. Notribes have requested consultation.Tribes were invited to participate in thenational informational webinar heldAugust 27, 2013. In addition, aconsultation/outreach meeting was heldon September 9, 2013, with tribalrepresentatives from some of the 584tribes. The EPA also met with tribalenvironmental staff via National TribalAir Association teleconferences on July25, 2013, and December 19, 2013. Tnthose teleconferences, the EPA providedbackground information on the GHGemission guidelines to be developedand a summary of issues being exploredby the agency. Tribes have expressedvaried points of view. Some tribesraised concerns about the impacts of theregulations on ECUs and the subsequentimpact on jobs and revenue for theirtribes. Other tribes expressed concernabout the impact the regulations wouldhave on the cost of water to theircommunities as a result of increasedcosts to the ECU that provide energy totransport the water to the tribes. Othertribes raised concerns about the impactsof climate change on their communities,resources, life ways and hunting andtreaty rights. The tribes were alsointerested in the scope of the guidelinesbeing considered by the agency (e.g.,over what time period, relationship tostate and multi-state plans) and howtribes will participate in these planningactivities. In addition, the EPA held aseries of listening sessions prior todevelopment of this proposed action. In2013, tribes participated in a sessionwith the state agencies, as well as aseparate session with tribes.

During the public comment period forthis proposal, the EPA will holdmeetings with tribal environmental staffto inform them of the content of this

346 The EPA is aware of at least four affectedEGUs located in Indian country: Two on Navajolands, the Navajo Generating Station and the FourCorners Generating Station; one on Ute lands, theBonanza Generating Station; and one on FortMojave lands, the South Point Energy Center. Theaffected EGUs at the first three plants are coal-firedEGUs. The fourth affected EGU is an NGCC facility.

proposal, as well as offer furtherconsultation with tribal elected officialswhere it is appropriate. We specificallysolicit comment from tribal officials onthis proposed rule.

G. Executive Order 13045, Protection ofChildren From Environmental HealthRisks and Safety Risks

The EPA interprets EO 13045 (62 FR19885, April 23, 1997) as applying tothose regulatory actions that concernhealth or safety risks, such that theanalysis required under section 5—501 ofthe Order has the potential to influencethe regulation. This action is not subjectto EO 13045 because it does not involvedecisions on environmental health orsafety risks that may disproportionatelyaffect children. The EPA believes thatthe CO2 emission reductions resultingfrom implementation of the proposedguidelines, as well as substantial ozoneand PM25 emission reductions as a cobenefit, would further improvechildren’s health.

H. Executive Order 13211, ActionsConcerning Regulations ThatSignificantly Affect Energy Supply,Distribution, or Use

Executive Order 13211 (66 FR 28355;May 22, 2001) requires the EPA toprepare and submit a Statement ofEnergy Effects to the Administrator ofthe Office of Information and RegulatoryAffairs, 0MB, for actions identified as“significant energy actions.” Thisaction, which is a significant regulatoryaction under EO 12866, is likely to havea significant effect on the supply,distribution, or use of energy. We haveprepared a Statement of Energy Effectsfor this action as follows. We estimatea 4 to 7 percent increase in retailelectricity prices, on average, across thecontiguous U.S. in 2020, and a 16 to 22percent reduction in coal-firedelectricity generation as a result of thisrule. The EPA projects that electricpower sector delivered natural gasprices will increase by about 8 to 12percent in 2020. For more informationon the estimated energy effects, pleaserefer to the economic impact analysisfor this proposal. The analysis isavailable in the RIA, which is in thepublic docket.

I. National Technology Transfer andAdvancement Act

Section 12(d) of the NationalTechnology Transfer and AdvancementAct (NTTAA) of 1995 (Pub. L. 104—113;15 U.S.C. 272 note) directs the EPA touse Voluntary Census Standards (VCS)in its regulatory and procurementactivities unless to do so would beinconsistent with applicable law or



otherwise impractical. Voluntaryconsensus standards are technicalstandards (e.g., materials specifications,test methods, sampling procedures,business practices) developed oradopted by one or more voluntaryconsensus bodies. The NTTAA directsthe EPA to provide Congress, throughannual reports to 0MB, withexplanations when an agency does notuse available and applicable VCS. Thisproposed rulemaking does not involvetechnical standards.

The EPA welcomes comments on thisaspect of the proposed rulemaldng andspecifically invites the public to identifypotentially-applicable VCS and toexplain why such standards should beused in this action.

J. Executive Order 12898: FederalActions to Address EnvironmentalJustice in Minority Populations andLow-Income Populations

Executive Order 12898 (59 FR 7629,February 16, 1994) establishes federalexecutive policy on environmentaljustice. Its main provision directsfederal agencies, to the greatest extentpracticable and permitted by law, tomake environmental justice part of theirmission by identifying and addressing,as appropriate, disproportionately highand adverse human health orenvironmental effects of their programs,policies and activities on minoritypopulations and low-incomepopulations in the U.S.

Section ll.A of this preamblesummarizes the public health andwelfare impacts from GHG emissionsthat were detailed in the 2009Endangerment Finding under CAAsection 202 (a)(1).347 As part of theEndangerment Finding, theAdministrator considered climatechange risks to minority or low-incomepopulations, finding that certain parts ofthe population may be especiallyvulnerable based on theircircumstances. These include the poor,the elderly, the very young, thosealready in poor health, the disabled,those living alone, and/or indigenouspopulations dependent on one or a fewresources. The Administrator placedweight on the fact that certain groups,including children, the elderly, and thepoor, are most vulnerable to climate-related health effects.

Strong scientific evidence that thepotential impacts of climate changeraise environmental justice issues isfound in the major assessment reports

‘Endangerment and cause or ContributeFindings for Greenhouse Gases Under Section202(a) of the Clean Air Act,” 74 FR 66,496 (Dec. 15,2009) (“Endangerment Finding”).

by the U.S. Global Change ResearchProgram (USGCRP), theIntergovernmental Panel on ClimateChange (IPCC), and the NationalResearch Council (NRC) of the NationalAcademies, summarized in the recordfor the Endangerment Finding. Theirconclusions include that poorcommunities can be especiallyvulnerable to climate change impactsbecause they tend to have more limitedadaptive capacities and are moredependent on climate-sensitiveresources such as local water and foodsupplies. In addition, Native Americantribal communities possess uniqueviilnerabiliUes to climate change,particularly those on establishedreservations that are restricted toreservation boundaries and thereforehave limited relocation options. Tribalcommunities whose health, economicwell-being, and cultural traditionsdepend upon the natural environmentwill likely be affected by thedegradation of ecosystem goods andservices associated with climate change.Southwest native cultures are especiallyvulnerable to water quality andavailability impacts. Native Alaskancommunities are likely to experiencedisruptive impacts, including shifts inthe range or abundance of wild speciescrucial to their livelihoods and wellbeing. The most recent assessmentscontinue to strengthen scientificunderstanding of climate change risks tominority and low-income populations.

This proposed rule would limit GHGemissions by establishing CO2 emissionguidelines for existing fossil fuel-firedEGUs. In addition to reducing CO2emissions, implementing the proposedrule would reduce other emissions fromEGUs that become dispatched lessfrequently due to their relatively lowenergy efficiency. These emissionreductions will include SO2 and NOx,which form ambient PM2.5 and ozone inthe atmosphere, and hazardous airpollutants (HAP), such as mercury andhydrochloric acid. In the final rulerevising the annual PM2.5 NAAQS,348the EPA identified persons with lowersocioeconomic status as an at-riskpopulation for experiencing adversehealth effects related to PM exposures.Persons with lower socioeconomicstatus have been generally found to havea higher prevalence of pre-existingdiseases, limited access to medicaltreatment, and increased nutritionaldeficiencies, which can increase thispopulation’s risk to PM-related and

349”National Ambient Air Quality Standards forParticulate Matter, Final Rule,” 78 FR 3086 (Jan. 15,2013).

ozone-related effects.34 Therefore, inareas where this rulemaking reducesexposure to PM25, ozone, andmethylmercury, persons with lowsocioeconomic status would alsobenefit. The RIA for this rulemaking,included in the docket for thisrulemaking, provides additionalinformation regarding the health andecosystem effects associated with theseemission reductions.

While there will be many locationswith improved air quality for PM2.5,ozone, and HAP, there may also beEGUs whose emissions of one or moreof these pollutants or their precursorsincrease as a result of the proposedemission guidelines for existing fossilfuel-fired EGUs. This may occur atEGUs that become dispatched moreintensively than in the past becausethey become more energy efficient. TheEPA has considered the potential forsuch increases and the environmentaljustice implications of such increases.

As we noted in the NSR discussion inthis preamble, as part of a state’s CAAsection 111(d) plan, the state mayrequire an affected ECU to undertake aphysical or operational changes toimprove the unit’s efficiency that resultin an increase in the unit’s dispatch andan increase in the unit’s annualemissions of GHGs and/or otherregulated pollutants. A state can takesteps to avoid increased utilization ofparticular EGUs and thus avoid anysignificant increases in emissionsincluding emissions of other regulatedpollutants whose environmental effectswould be more localized around theaffected EGU. To the extent that statestake this path, there would be no newenvironmental justice concerns in theareas near such EGUs. For any EGUsthat make modifications that do triggerNSR permitting, the applicable local,state, or federal permitting program willensure that there are no new NAAQSviolations and that no existing NAAQSviolations are made worse. For thoseEGUs in a permitting situation forwhich the EPA is the permit reviewingauthority, the EPA will considerenvironmental justice issues as requiredby Executive Order 12898.

In addition to some EGUs possiblybeing required by a state to makemodifications for increased energyefficiency, another effect of theproposed CO2 emission guidelines forexisting fossil fuel-fired EGUs would be

349 U.S. Environmental Protection Agency (U.S.EPA). 2009. Integrated Science Assessment forParticulate Matter (Final Report). EPA—600—R—08—139F. National Center for EnvironmentalAssessment—RTP Division. December. Available onthe Internet at <http://cfpub.epa.gov/ncea/cfm/recordfsplay.cfm?deid—21 6546>.



increased utilization of other,unmodified EGUs with relatively lowGHG emissions per unit of electricaloutput, in particular high efficiency gas-fired EGUs. Because such EGUs wouldnot have been modified physically norchanged their method of operation, theywould not be subject to review in theNSR permitting program. Such plantswould have more hours in the year inwhich they operate and emit pollutants,including pollutants whoseenvironmental effects if any would belocalized rather than global as is thecase with GHG emissions. Changes inutilization already occur now asdemands for and sources of electricalenergy evolve, but the proposed CO2emission guidelines for existing fossilfuel-fired EGUs can be expected tocause more such changes. Because gas-fired EGUs emit essentially no mercury,increased utilization would not increasemethylmercury concentrations in theirvicinities. Increased utilizationgenerally would not cause higher peakconcentrations of PM2.5, NOx, or ozonearound such EGUs than is alreadyoccurring because peak hourly or dailyemissions generally would not change,but increased utilization may makeperiods of relatively high concentrationsmore frequent. It should be noted thatthe gas-fired sources that are likely tobecome dispatched more frequentlythan at present have very low emissionsof primary particulate matter, SO2 andHAP per unit of electrical output, suchthat local (or regional) air quality forthese pollutants is likely to be affectedvery little. For natural gas-fired EGUS,the EPA found that regulation of HAPemissions “is not appropriate ornecessary because the impacts due toHAP emissions from such units arenegligible based on the results of thestudy documented in the utilityRTC.”35° In studies done by DOE/NETLcomparing cost and performance ofcoal- and NG-fired generation, theyassumed 802, PM (and Hg) emissions tobe “negligible.” Their studies predictNOx emissions from a NGCC unit to beapproximately 10 times lower than asubcritical or supercritical coal-firedboiler. Many are also very wellcontrolled for emission of NOx throughthe application of after combustioncontrols such as selective catalyticreduction, although not all gas-firedsources are so equipped. Depending onthe specificity of the state CAA section111(d) plan, the state may be able topredict which EGUs and communitiesmay be in this type of situation and toaddress any concerns about localizedNO2 concentrations in the design of the

°65 FR 79831.

CAA section 111(d) program, orseparately from the CAA section 111(d)program but before its implementation.In any case, existing tracking systemswill allow states and the EPA to beaware of the EGUs whose utilization hasincreased most significantly, and thus tobe able to prioritize our efforts to assesswhether air quality has changed in thecommunities in the vicinity of suchEGUs. There are multiple mechanismsin the CAA to address situations inwhich aft quality has degradedsignificantly. In conclusion, thisproposed rule would result in regionaland national pollutant reductions;however, there likely would also besome locations with more times duringthe year of relatively higherconcentrations of pollutants withpotential for effects on localizedcommunities than would beexperienced in the absence of theproposed rule. The EPA cannot exactlypredict how emissions from specificEGUs would change as an outcome ofthe proposed rule due to the state-ledimplementation. Therefore, the EPA hasconcluded that it is not practicable todetermine whether there would bedisproportionately high and adversehuman health or environmental effectson minority, low income, or indigenouspopulations from this proposed rule.

In order to provide opportunities formeaningful involvement early on in therule nmaldng process, the EPA has hostedwebinars and conference calls onAugust 27, 2013, and September 9,2013, on the proposed rule specificallyfor environmental justice communitiesand has taken all comments andsuggestions into consideration in thedesign of the emission guidelines.

The public is invited to submitcomments or identify peer-reviewedstudies and data that assess effects ofexposure to the pollutants addressed bythis proposal.

XII. Statutory Authority

The statutory authority for this actionis provided by sections 111, 301, 302,and 307(d)(1)(V) of the CAA, asamended (42 U.S.C. 7411, 7601, 7602,7607(d)(1)(V)). This action is alsosubject to section 307(d) of the CAA (42U.S.C. 7607(d)).

List of Subjects in 40 CFR Part 60

Environmental protection,Administrative practice and procedure,Air pollution control, Intergovernmentalrelations, Reporting and recordkeepingrequirements.

Dated: June 2, 2014.Gina McCarthy,Administrator.

For the reasons stated in thepreamble, title 40, chapter I, part 60 ofthe Code of the Federal Regulations isproposed to be amended as follows:

PART 60—STANDARDS OFPERFORMANCE FOR NEWSTATIONARY SOURCES

• 1. The authority citation for Part 60continues to read as follows:

Authority: 42 U.S.C. 7401 et seq.• 2. Section 60.27 is amended byrevising paragraph (b) to read as follows:

§ 60.27 ActIons by the Administrator.* * * * *

(b) After receipt of a plan or planrevision, the Administrator will proposethe plan or revision for approval ordisapproval. The Administrator will,within four months after the daterequired for submission of a plan orplan revision, approve or disapprovesuch plan or revision or each portionthereof, except as provided in § 60.5715.

• 3. Add subpart UUUUto read asfollows:

Subpart UUUU: Emission Guidelinesfor Greenhouse Gas Emissions andCompliance Times for Electric UtilityGenerating Units

Sec.

Iniroduction60.5700 What is the purpose of this

subpart?60.5705 What pollutants are regulated by

this subpart?60.5710 Am I affected by this subpart?60.5 715 What is the review and approval

process for my state plan?60.5 720 What if I do not submit a plan or

my plan is not approvable?60.5725 In lieu of a state plan submittal, are

there other acceptable option(s) for astate to meet its section 111(d)obligations?

60.5730 Is there an approval process for anegative declaration letter?

60.5735 What authorities will not bedelegated to state, local, or tribalagencies?

State Plan

60.5740 What must I include in my stateplan?

60.5745 Can I work with other states todevelop a multi-state plan?

60.5750 Can I include existingrequirements, programs, and measures inmy state plan?

60.5755 What are the timing requirementsfor submitting my state plan?

60.5760 What must I include in an initialsubmittal in lieu of a complete stateplan?



60.5765 What are the state rate-based CO2emission performance goals?

60.5770 What is the procedure forconverting my state rate-based CO2emission performance goal to a mass-based CO2 emissions performance goal?

60.5 775 What schedules, performanceperiods, and compliance periods must Iinclude in my state plan?

60.5780 What emission standards andenforcing measures must I include in myplan?

60.5785 What is the procedure for revisingmy state plan?

Applicability of State Plans to Affected EGUs60.5790 Does this subpart directly affect

EGU owners and operators in my state?60.5795 What affected EGUs must I address

in my state plan?60.5800 What affected EGUs are exempt

from my state plan?60.5805 What applicable monitoring,

recordkeeping, and reportingrequirements do I need to include in mystate plan for affected EGUs?

Recordkeeping and Reporting Requirements60.5810 What are my state recordkeeping

requirements?60.5815 What are my state reporting

requirements?

Definitions60.5820 What definitions apply to this

subpart?Table I to Subpart UUUU of Part 60—State

Rate-based CO2 Emission PerformanceGoals (Pounds of CO2 Per Net MWh)

Introduction

§ 60.5700 What is the purpose of thissubpart?

This subpart establishes emissionguidelines and approval criteria for stateplans that establish emission standardslimiting the control of greenhouse gasemissions from an affected steamgenerating unit, integrated gasificationcombined cycle (IGCC), or stationarycombustion turbine. An affected steamgenerating unit, IGCC, or stationarycombustion turbine shall, for thepurposes of this subpart, be referred toas an affected EGU. These emissionguidelines are developed in accordancewith sections 111(d) of the Clean AirAct and subpart B of this part. To theextent any requirement of this subpart isinconsistent with the requirements ofsubparts A or B of this part, therequirements of this subpart will apply.

§ 60.5705 What pollutants are regulated bythis subpart?

(a) The pollutants regulated by thissubpart are greenhouse gases.

(b) The greenhouse gas regulated bythis subpart is carbon dioxide (CC2).

§ 60.571 0 Am I affected by this subpart?If you are the Administrator of an air

quality program in a state with one or

more affected EGUs that commencedconstruction on or before January 8,2014, you must submit a state plan tothe U.S. Environmental ProtectionAgency (EPA) that implements theemission guidelines contained in thissubpart. You must submit a negativedeclaration letter in place of the stateplan if there are no affected EGUs forwhich construction commenced on orbefore January 8, 2014 in your state.

§ 60.5715 What is the review and approvalprocess for my state plan?

The EPA will review your state planaccording to § 60.27 except that under§ 60.27(b) the Administrator will havetwelve months after the date requiredfor submission of a plan or plan revisionto approve or disapprove such plan orrevision or each portion thereof. If yousubmit a request for extension under§ 60.5 760(a) in lieu of a complete stateplan the EPA will follow the procedurein § 60.5 760(b).

§ 60.5720 What it I do not submit a plan ormy plan is not approvable?

if you do not submit an approvablestate plan the EPA will develop aFederal plan for your state according to§ 60.27 to implement the emissionguidelines contained in this subpart.Owners and operators of affectedentities not covered by an approvedstate plan must comply with a Federalplan implemented by the EPA for thestate. The Federal plan is an interimaction and will be automaticallywithdrawn when your state plan isapproved.

§ 60.5725 In lieu of a state plan submittal,are there other acceptable option(s) for astate to meet its section 117(d) obligations?

A state may meet its CAA section111(d) obligations only by submitting acomplete state plan or a negativedeclaration letter (if applicable).

§ 60.5730 Is there an approval process fora negative declaration letter?

No. The EPA has no formal reviewprocess for negative declaration letters.Once your negative declaration letterhas been received, the EPA will place acopy in the public docket and publisha notice in the Federal Register. If, at alater date, an affected EGU for whichconstruction commenced on or beforeJanuary 8, 2014 is found in your state,a Federal plan implementing theemission guidelines contained in thissubpart would automatically apply tothat affected ECU until your state planis approved.

§ 60.5735 What authorities will not bedelegated to state, local, or tribal agencies?

The authorities that will not bedelegated to State, local, or tribalagencies are specified in paragraph (a)of this section.

(a) Approval of alternatives, notalready approved by this subpart, to theemissions performance goals in Table 1to this subpart established under§ 60.5755.

(b) [Reserved]

State Plan

§ 60.5740 What must I include in my stateplan?

(a) You must include the elementsdescribed in paragraphs (a)(1) through(11) of this section in your state plan.

(1) Identification of affected entities,including an inventory of CO2 emissionsfrom affected EGUs during the mostrecent calendar year prior to thesubmission of the plan for which datais available.

(2) A description of plan approachand the geographic scope of a plan (stateor multi-state), including, if relevant,identification of multi-state planparticipants and geographic boundariesrelated to plan elements.

(3) Identification of the state emissionperformance level for affected entitiesthat will be achieved throughimplementation of the plan.

(i) The plan must specify the averageemissions performance that the planwill achieve for the following periods:

(A) The 10 year interim planperformance period of 2O20 through2029.

(B) The single projection year of 2030.(ii) The identified emission

performance level for each planperformance period in paragraph(a)(3)(i) of this section must beequivalent to or better than the levels ofthe rate-based CO2 emissionperformance goals in Table 1 of thisSubpart for affected entities in yourstate. The emission performance levelsmay be in either a rate-based form or amass based form which is calculatedaccording to § 60.5770. The CO2emission performance level specifiedmust include either of the following asapplicable:

(A) For a rate-based CO2 emissionperformance level, the identified levelmust represent the CO2 emissions rate,in pounds of CO2 per MWh of netenergy output that will be achieved byaffected entities.

(B) For a mass-based CO2 emissionperformance level, the identified levelof performance must represent the totaltons of CO2 that will be emitted byaffected entities during each planperformance period.


34952 Federal Register / Vol. 79, No. 117 I Wednesday, June 18, 2014 / Proposed Rules

(ill) For the interim plan performanceperiod you must identify the emissionperformance levels anticipated underthe plan during each year 2020 through2029.

(4) A demonstration that the plan isprojected to achieve each of the state’semission performance levels for affectedentities according to paragraph (a)(3) ofthis section.

(5) Identification of emissionstandards for each affected entity,compliance periods for each emissionstandard, and demonstration that theemission standards are, when takentogether, sufficiently protective to meetthe state emissions performance level.

(6) A demonstration that eachemission standard is quantifiable, non-duplicative, permanent, verifiable, andenforceable with respect to an affectedentity.

(7) If your state plan does not requireachievement of the full level of requiredemission performance, and theidentified interim increments ofperformance in paragraph (a)(3)(iii) ofthis section, through emission limits onEGUs, the plan must specify thefollowing:

(1) Program implementationmilestones (e.g., start of an end-useenergy efficiency program, retirement ofan affected EGU, or increase in portfoliorequirements under a renewableportfolio standard) and milestone datesthat are appropriate to the requirements,programs, and measures included in theplan.

(ii) Corrective measures that will beimplemented in the event that thecomparison required by § 60.5815(b) ofprojected versus actual emissionsperformance of affected entities showsthat actual emissions performance isgreater than 10 percent in excess toprojected plan performance for theperiod described in § 60.5 775(c)(1), anda process and schedule forimplementing such corrective measures.

(8) Identification of applicablemonitoring, reporting, andrecordkeeping requirements for eachaffected entity. If applicable, theserequirements must be consistent withthe requirements specified in § 60.5 810.

(9) Description of the process,contents, and schedule for annual statereporting to the EPA about planimplementation and progress includinginformation required under § 60.5815.

(10) Certification that the hearing onthe state plan was held, a list ofwitnesses and their organizationalaffiliations, if any, appearing at thehearing, and a brief written summary ofeach presentation or writtensubmission.

(11) Supporting material including:

(i) Materials demonstrating the state’slegal authority to carry out eachcomponent of its plan, includingemissions standards;

(ii) Materials supporting the projectedemissions performance level that will beachieved by affected entities under theplan, according to paragraph (a)(4) ofthis section;

(iii) Materials supporting theprojected mass-based emissionperformance goal, calculated pursuantto § 60.5 770, if applicable; and

(iv) Materials necessary to supportevaluation of the plan by the EPA.

(b) You must follow the requirementsof subpart B of this part (Adoption andSubmittal of state plans for DesignatedFacilities) and demonstrate that theywere met in your state plan.

§ 60.5745 Can I work with other states todevelop a multi-state plan?

A multi-state plan may be submitted,provided it is signed by authorizedofficials for each of the statesparticipating in the multi-state plan. Inthis instance, the joint submittal willhave the same legal effect as anindividual submittal for eachparticipating state. A multi-state planwill include all the required elementsfor a single-state plan specified in§ 60.5 740(a). A multi-state plan, ifsubmitted by a state, must:

(a) Demonstrate CO2 emissionperformance jointly for all affectedentities in all states participating in themulti-state plan, as follows:

(1) For states demonstratingperformance based on the CO2 emissionrate, the level of performance identifiedin the multi-state plan pursuant to§ 60.5740(a)(3) will be a weighted (bynet energy output) average lb CO2/MWhemission rate to be achieved by allaffected EGUs in the multi-state areaduring the plan performance period; or

(2) For states demonstratingperformance based on mass CO2emissions, the level of performanceidentified in the multi-state planpursuant to 60.5740(a)(3) will be totalCO2 emissions by all affected EGUs inthe multi-state area during the planperformance period.

(b)Assign among states, according toa formula in the multi-state plan,avoided CO2 emissions resulting fromemission standards contained in theplan, from affected entities in statesparticipating in the multi-state plan.

§ 60.5750 Can I include existingrequirements, programs, and measures Inmy state plan?

(a) Yes, you may include existingrequirements, programs and measures inyour plan according to paragraphs (b)through (d) of this section.

(b)Existing state programs,requirements, and measures, mayqualify for use in demonstrating that astate plan achieves the required level ofemission performance specified in aplan, according to § 60.5740(a)(3).

(c) Existing state programs,requirements, and measures, mayqualify for use in projecting that a stateplan will achieve the required level ofemission performance specified in aplan, according to § 60.5 740(a)(4).

(d) Emission impacts of existingprograms, requirements, and measuresthat occur during a plan performanceperiod may be recognized in meeting orprojecting CO2 emission performance byaffected EGUs according to§ 60.5 740(a)(3) and (4), as long as theymeet the following requirements:

(1] Actions taken pursuant to anexisting state program, requirement, ormeasure, such as compliance with aregulatory obligation or initiation of anaction related to a program or measure,must occur after June 18, 2014; and

(2) The existing state program,requirement, or measure, and anyrelated actions taken pursuant to suchprogram, requirement, or measure, meetthe applicable requirements pursuant to§ 60.5740(a) and § 60.5780.

§ 60.5755 What are the timingrequirements for submitting my state plan?

(a) You must submit your state planwith the information in § 60.5740 byJune 30, 2016 unless you are submittinga request for extension according toparagraphs (b) or (c) of this section.

(b)For a state seeking a one yearextension for a complete plan submittalyou must include the information in§ 60.5 760(a) in a submittal by June 30,2016 to receive an extension to submityour complete state plan by June 30,2017.

(c) For states in a multi-state planseeking a two year extension for acomplete plan submittal you mustinclude the information in § 60.5 760(a)in a submittal by June 30, 2016 toreceive an extension to submit yourcomplete multi-state plan by June 30,2018.

§ 60.5760 What must I Include In an Initialsubmittal In lieu of a complete state plan?

(a) You must include the followingrequired elements in an initial submittalin lieu of a complete state plan:

(1) A description of the plan approachand progress made to date in developingeach of the plan elements in § 60.5740;

(2) An initial projection of the level ofemission performance that will beachieved under the complete plan;

(3) A commitment by the state tomaintain existing state programs and



measures that limit or avoid CO2emissions from affected entities (e.g.,renewable energy standards, unit-specific limits on operation or fuelutilization), which must at a minimumapply during the interim period prior tostate submission and EPA approval of acomplete plan, and must continue toapply in lieu of a complete plan if oneis ultimately not submitted andapproved;

(4) Justification of why additionaltime is needed to submit a completeplan;

(5) A comprehensive roadmap forcompleting the plan, including process,analytical methods and schedule(including milestones) specifying whenall necessary plan components will becomplete (e.g., projection of emissionperformance; implementing legislation,regulations and agreements; necessaryapprovals);

(6) Identification of existing andfuture programs, requirements, andmeasures the state intends to include inthe plan;

(7) If a multi-state plan is beingdeveloped, an executed agreement(s)with other states (e.g., MOU)participating in the development of themultistate plan; and

(8) A commitment to submit acomplete plan by June 30, 2017, for asingle-state plan, or June 30, 2018, for amulti-state plan, and actions the statewill take to show progress in addressingincomplete plan components prior tosubmittal of the complete plan.

(9) A description of all steps the statehas already taken in furtherance ofactions needed to finalize a completeplan.

(To) Evidence of an opportunity forpublic comment and a response to anysignificant comments received on issuesrelating to the approvability of theinitial plan.

(b) You must submit either a completestate plan or an initial submittal by June30, 2016. Where an initial submittal issubmitted in lieu of a complete stateplan the due date of a complete stateplan will be June 30, 2017, for a single-state plan, or June 30, 2018, for a multistate plan unless a state is notifiedwithin 60 days of the EPA receiving theinitial submittal in paragraph (a) of thissection that the EPA finds the initialsubmittal does not meet therequirements listed in paragraph (a) ofthis section.

§ 60.5765 What are the state rate-basedCO2 emissions performance goals?

(a) The annual average state rate-based CO2 emission performance goalsfor the interim performance periods of2020 through 2029, and the final 2030

and thereafter period are respectivelylisted in Table 1 of this Subpart. Thestate rate-based CO2 emissionperformance goal may be converted to amass-based emission performance goalaccording to § 60.5 770.

(b)[ReservedJ

§ 60.5770 What is the procedure forconverting my state rate-based CO2emission performance goal to a mass-based CO2 emissions performance goal?

(a) If the plan adopts a mass-basedgoal according to § 60.5740(a)(3), theplan must identify the mass-based goal,in tons of CO2 emitted by affected EGUsover the plan performance period, andinclude a description of the analyticprocess, tools, methods, andassumptions used to convert from therate-based goal for the state identified inTable 1 of this Subpart to an equivalentmass-based goal. The conversionprocess must include followingrequirements:

(1) The process, tools, methods, andassumptions used in the conversion ofthe rate-based goal must be included inyour state plan according to§ 60.5740(a) (ii).

(2) The material supporting theconversion of the rate-based goal,including results, data, anddescriptions, must be include in a stateplan according to § 60.5 740(a)(11).

(3) The conversion must represent thetons of CO2 emissions that are projectedto be emitted by affected EGUs, in theabsence of emission standardscontained in the plan, if the affectedEGUs were to perform at an average lbC02/MWh rate equal to the rate-basedgoal for the state identified in Table 1of this Subpart.

(b) [Reserved]

§ 60.5775 What schedules, performanceperiods, and compliance periods must IInclude in my state plan?

(a) Your state plan must include aschedule of compliance for eachaffected entity regulated under the plan.

(b) Your state plan must includecompliance periods, as defined insection § 60.5 820, for each affectedentity regulated under the plan.

(c) For the interim performanceperiod of 2020—202 9 your state mustmeet the requirements in paragraphs(c)(i) and (2) of this section.

(1) Your state plan must includeincrements of emissions performance(either rate based or mass based withrespect to the interim level ofperformance set in the state plan) withinthe interim performance period forevery 2-rolling calendar years startingJanuary 1, 2020 and ending in 2028 (i.e.2020—2021, 2021—2022, 2022—2023,etc.), unless other periods that ensure

regular progress in the interim periodare approved by the Administrator.

(2) At the end of 2029 your state mustmeet the interim emissions performancelevel specified in § 60.5 740(a)(3) asaveraged over the plan performanceperiod 2020—2029.

(d) During the final performanceperiod, 2030 and thereafter, your statemust meet the final emissionperformance level specified in§ 60.5740(a)(3) on a 3-calendar yearrolling average starting January 1, 2030(i.e., 2030—2032, 2031—2033, 2032—2034,etc.).

(e) You must include the provisions ofyour state plan which demonstrateprogress and compliance with therequirements in this § 60.5 775 and§ 60.5 740 in your state’s annual reportrequired in § 60.5815.

§ 60.5780 What emission standards andenforcing measures must I include In myplan?

(a) Your state plan shall includeemission standard(s) that arequantifiable, verifiable, non-duplicative,permanent, and enforceable withrespect to each affected entity. The planshall include the methods by whicheach emission standard meets each ofthe following requirements inparagraphs (b) through (f) of thissection.

(b) An emission standard isquantifiable with respect to an affectedentity if ft can be reliably measured, ina manner that can be replicated.

(c) An emission standard is verifiablewith respect to an affected entity ifadequate monitoring, recorcikeeping andreporting requirements are in place toenable the state and the Administratorto independently evaluate, measure, andverify compliance with the emissionstandard.

(d) An emission standard is non-duplicative with respect to an affectedentity if ft is not already incorporated asan emission standard in another stateplan unless incorporated in multi-stateplan.

(e) An emission standard ispermanent with respect to an affectedentity if the emission standard must bemet for each compliance period, orunless it is replaced by anotheremission standard in an approved planrevision, or the state demonstrates in anapproved plan revision that theemission reductions from the emissionstandard are no longer necessary for thestate to meet its state level ofperformance.

(f) An emission standard isenforceable against an affected entity if:

(1) A technically accurate limitationor requirement and the time period for



the limitation or requirement isspecified;

(2) Compliance requirements areclearly defined;

(3) The affected entities responsiblefor compliance and liable for violationscan be identified;

(4) Each compliance activity ormeasure is enforceable as a practicalmatter; and

(5) The Administrator and the statemaintain the ability to enforceviolations and secure appropriatecorrective actions pursuant to sections113(a) through (h) of the Act.

§ 60.5785 What is the procedure forrevising my state plan?

State plans can only be revised withapproval by the Administrator. If one (ormore) of the elements of the state planset in § 60.5 740 require revision withrespect to reaching the emissionperformance goal set in § 60.5765 arequest may be submitted to theAdministrator indicating the proposedcorrections to the state plan to ensurethe emission performance goal is met.

Applicability of State Plans to AffectedEGUs

§ 60.5790 Does this subpart directly affectEGU owners and operators in my state?

(a) This subpart does not directlyaffect EGU owners and operators in yourstate. However, EGU owners andoperators must comply with the stateplan that a state develops to implementthe emission guidelines contained inthis subpart.

(b) If a state does not submit anapprovable plan or initial submittal toimplement and enforce the emissionguidelines contained in this subpart byJune 30, 2016, the EPA wifi implementand enforce a Federal plan, as providedin § 60.5740, to ensure that each affectedEGU within the state that commencedconstruction on or before January 8,2014 reaches compliance with all theprovisions of this subpart.

§ 60.5795 What affected EGUs must Iaddress in my state plan?

(a) The EGUs that must be addressedby your state plan are any affected steamgenerating unit, IGCC, or stationarycombustion turbine that commencesconstruction on or before January 8,2014.

(b) An affected EGU is a steamgenerating unit, integrated gasificationcombined cycle (IGCC), or stationarycombustion turbine that meets therelevant applicability conditionsspecified in paragraph (bIl) or (2) ofthis section.

(1) A steam generating unit or IGCCthat has a base load rating greater than

73 MW (250 MMEtu/h) heat input offossil fuel (either alone or incombination with any other fuel) andwas constructed for the purpose ofsupplying one-third or more of itspotential electric output and more than219,000 MiVh net-electric output to autility distribution system on an annualbasis.

(2) A stationary combustion turbinethat has a base load rating greater than73 MW (250 MI’,IBtuIh), wasconstructed for the purpose ofsupplying, and supplies, one-third ormore of its potential electric output andmore than 219,000 M’VVh net-electricaloutput to a utility distribution systemon a 3-year rolling average basis,combusts fossil fuel for more than 10.0percent of the heat input during a 3-yearrolling average basis and combusts over90% natural gas on a heat input basis ona 3-year rolling average basis.

§ 60.5800 What affected EGUs are exemptfrom my state plan?

Affected EGUs that are exempt fromyour state plan include: those that aresubject to subpart TTTT as a result ofcommencing construction orreconstruction after the subpart TTTTapplicability date; and those subject tosubpart TTTT as a result of commencingmodification or reconstruction priorbecoming subject to an applicable stateplan.

§ 60.5805 What applicable monitoring,recordkeeping, and reporting requirementsdo I need to Include in my state plan foraffected EGUs?

(a) A state plan must includemonitoring that is no less stringent thatwhat is described in (a)(1) through (6) ofthis section.

(1) If an affected ECU is required tomeet a rate based emission standardthey must prepare a monitoring plan inaccordance with the applicableprovisions in § 75.53(g) and (h) of thischapter.

(2) An affected EGU must measure thehourly CO2 mass emissions from eachaffected unit using the procedures inparagraphs (a)(2)(i) through (v) of thissection, except as provided in paragraph(a)(3) of this section.

(i) An affected EGU must install,certify, operate, maintain, and calibratea CO2 continuous emissions monitoringsystem (CEMS) to directly measure andrecord CO2 concentrations in theaffected EGU exhaust gases emitted tothe atmosphere and an exhaust gas flowrate monitoring system according to§ 75.10(a)(3)(i) of this chapter. If anaffected ECU measures CO2concentration on a dry basis, they mustalso install, certify, operate, maintain,

and calibrate a continuous moisturemonitoring system, according to§ 75.11(b) of this chapter.

(ii) For each monitoring system anaffected ECU uses to determine the CO2mass emissions, they must meet theapplicable certification and qualityassurance procedures in § 75.20 of thischapter and Appendices B and D to part75 of this chapter.

(iii) An affected EGU must use a laserdevice to measure the dimensions ofeach exhaust gas stack or duct at theflow monitor and the reference methodsampling locations prior to the initialsetup (characterization) of the flowmonitor. For circular stacks, an affectedEGU must measure the diameter at threeor more distinct locations and averagethe results. For rectangular stacks orducts, an affected EGU must measureeach dimension (i.e., depth and width)at three or more distinct locations andaverage the results. If the flow ratemonitor or reference method samplingsite is relocated, an affected ECU mustrepeat these measurements at the newlocation.

(iv) An affected EGU must use onlyunadjusted exhaust gas volumetric flowrates to determine the hourly CO2 massemissions from the affected facility; anaffected ECU must not apply the biasadjustment factors described in section7.6.5 of Appendix A to part 75 of thischapter to the exhaust gas flow ratedata.

(v) If an affected EGU chooses to useMethod 2 in Appendix A—i to this partto perform the required relativeaccuracy test audits (RATAs) of the part75 flow rate monitoring system, theymust use a calibrated Type-S pitot tubeor pitot tube assembly. An affected ECUmust not use the default Type-S pitottube coefficient.

(3) If an affected EGU exclusivelycombusts liquid fuel and/or gaseous fuelas an alternative to complying withparagraph (b) of this section, they maydetermine the hourly CO2 massemissions by using Equation C—4 inAppendix C to part 75 of this chapteraccording to the requirements inparagraphs (a)(3)(i) and (ii) of thissection.

(i) An affected EGU must implementthe applicable procedures in appendix1) to part 75 of this chapter to determinehourly unit heat input rates (MMBtu/h),based on hourly measurements of fuelflow rate and periodic determinations ofthe gross calorific value (CCV) of eachfuel combusted.

(ii) An affected ECU may determinesite-specific carbon-based F-factors (Fe)using Equation F—7b in section 3.3.6 ofappendix F to part 75 of this chapter,and may use these F values in the



emissions calculations instead of usingthe default f values in the Equation C—4 nomenclature.

(4) An affected ECU must install,calibrate, maintain, and operate asufficient number of watt meters tocontinuously measure and record on anhourly basis net electric output.Measurements must be performed using0.2 accuracy class electricity meteringinstrumentation and calibrationprocedures as specified under ANSIStandards No. C12.20. Further, anaffected ECU that is a combined heatand power facility must install,calibrate, maintain and operateequipment to continuously measure andrecord on an hourly basis useful thermaloutput and, if applicable, mechanicaloutput, which are used with net electricoutput to determine net energy output.

(5) Tn accordance with § 60.13(g), iftwo or more affected ECUs thatimplement the continuous emissionsmonitoring provisions in paragraph(a)(2) of this section share a commonexhaust gas stack and are subject to thesame emissions standard, they maymonitor the hourly CO2 mass emissionsat the common stack in lieu ofmonitoring each ECU separately. If anaffected ECU chooses this option, thehourly net electric output for thecommon stack must be the sum of thehourly net electric output of theindividual affected facility and youmust express the operating time as“stack operating hours” (as defined in§ 72.2 of this chapter).

(6) Tn accordance with § 60.13(g), ifthe exhaust gases from an affected EGUthat implements the continuousemissions monitoring provisions inparagraph (a)(2) of this section areemitted to the atmosphere throughmultiple stacks (or if the exhaust gasesare routed to a common stack throughmultiple ducts and you elect to monitorin the ducts), they must monitor thehourly CO2 mass emissions and the“stack operating time” (as defined in§ 72.2 of this chapter) at each stack orduct separately. In this case, an affectedECU must determine compliance withan applicable emissions standard bysumming the CO2 mass emissionsmeasured at the individual stacks orducts and dividing by the net energyoutput for the affected ECU.

(b) An affected ECU must maintainrecords for at least 10 years followingthe date of each occurrence,measurement, maintenance, correctiveaction, report, or record.

(1) An affected ECU must maintaineach record on site for at least 2 yearsafter the date of each occurrence,measurement, maintenance, correctiveaction, report, or record, according to

§ 60.7. An affected ECU may maintainthe records off site and electronically forthe remaining year(s).

(c) An affected EGU must include ina report required by the state plancovering each compliance period allhourly CO2 emissions and all hourly netelectric output and all hourly net energyoutput measurements for a CHP facilitycalculated from data monitoredaccording to paragraph (a) of thissection.

Recordkeeping and ReportingRequirements

§ 60.5810 What are my staterecordkeeping requirements?

(a) States must keep records of allplan components, plan requirements,supporting documentation, and thestatus of meeting the plan requirementsdefined in the state plan on an annualbasis during the interim planperformance period from 2020—202 9.After 2029 states must keep records ofall information that is used to supportany continued effort to meet the finalemissions performance goal.

(b) States must keep records of alldata submitted by each affected entitythat is used to determine compliancewith each affected entity’s emissionsstandard.

(c) If a state has a requirement forhourly CO2 emissions and netgeneration information to be used tocalculate compliance with an annualemissions standard for affected ECUs,any information that is submitted to theEPA electronically pursuant torequirements in Part 75 would meet therecordkeeping requirement of thissection and a state would not need tokeep records of information that wouldbe in duplicate of paragraph (b) of thissection.

(d) A state must keep records atminimum for 20 years.

§ 60.5615 What are my state reportingrequirements?

(a) You must submit an annual reportcovering each calendar year no laterthan July 1 of the following year,starting July 1 2021. The annual reportmust include the following:

(1) The level of emissionsperformance achieved by all affectedentities and identification of whetheraffected entities are on schedule to meetthe applicable level of emissionsperformance for affected entities duringthe plan performance period andcompliance periods, as specified in theplan.

(2) The level of emissionsperformance achieved by all affectedEGUs during the reporting period, andprior reporting periods, expressed as

average CO2 emissions rate or total massCO2 emissions, consistent with the planapproach, and identification of whetheraffected EGUs are on schedule to meetthe applicable lel of emissionsperformance for affected ECUs duringthe plan performance period, asspecified in the plan.

(3) A list of affected entities and theircompliance status with the applicableemissions standards specified in thestate plan.

(4) A list of all affected ECUs andtheir reported CO2 emissionsperformance for each compliance periodduring the reporting period, and priorreporting periods.

(5) All other required information, asspecified in your state plan according to§ 60.5740(a)(9).

(6) All information required by§ 60.5 775(e).

(b) For each two-year period in§ 60.5775(c) (1), you must compare theaverage CO2 emission performanceachieved by affected entities in the stateversus the CO2 emission performanceprojected in the state plan. if actualemission performance is greater than 10percent in excess to projected planperformance for a two-year comparisonperiod, you must explain the reasons forthe deviation and specify the correctiveactions that will be taken to ensure thatthe required interim and final levels ofemission performance in the plan willbe met. The information required in thisparagraph must be included in theannual report required by paragraph (a)of this section.

(c) You must include in your 2029annual report (which is subsequentlydue by July 1, 2030) the calculation ofaverage emissions over the 2020—2029interim performance period used todetermine compliance with yourinterim emission performance level. Thecalculated value must be in unitsconsistent with your interim emissionperformance level.

(d) You must include in each report,starting with the 2032 annual report(which is subsequently due by July 1,2033), a 3-calendar year rolling averageused to determine compliance with thefinal emission performance level. Thecalculated value must be in unitsconsistent with your final emissionperformance level.

Definitions

§ 60.5820 What definitions apply to thissubpart?

As used in this subpart, all terms notdefined herein will have the meaninggiven them in the Clean Air Act and insubparts A (General Provisions) and B ofthis part.



Affected electric generating unit orAffected EGU means a steam generatingunit, an IGCC facility, or a stationarycombustion turbine that meets theapplicability conditions in section§ 60.5795.

Affected Entity shall mean any of thefollowing: An affected EGU, or anotherentity with obligations under thissubpart for the purpose of meeting theemissions performance goalrequirements in these emissionguidelines.

Base load rating means the maximumamount of heat input (fuel) that a steamgenerating unit can combust on a steadystate basis, as determined by thephysical design and characteristics ofthe steam generating unit at ISOconditions. For a stationary combustionturbine, base load rating means 100percent of the design heat inputcapacity of the simple cycle portion ofthe stationary combustion turbine at ISOconditions (heat input from ductburners is not included).

CO2 emissions performance goalmeans the rate-based CO2 emissionsperformance goal specified for a state inTable 1 of this subpart, or a translatedmass-based form of that goal.

Coal means all solid fuels classified asanthracite, bituminous, subbituminous,or lignite by the Mnerican Society ofTesting and Materials in ASTM D388(incorporated by reference, see § 60.17),coal refuse, and petroleum coke.Synthetic fuels derived from coal for thepurpose of creating useful heat,including but not limited to solvent-refined coal, gasified coal (not meetingthe definition of natural gas), coal-oilmixtures, and coal-water mixtures areincluded in this definition for thepurposes of this subpart.

Combined cycle facility means anelectric generating unit that uses astationary combustion turbine fromwhich the heat from the turbine exhaustgases is recovered by a heat recoverysteam generating unit to generateadditional electricity.

Combined heat and power facility orCHP facility, (also known as“cogeneration”) means an electricgenerating unit that that use a steam-generating unit or stationary combustionturbine to simultaneously produce bothelectric (or mechanical) and usefulthermal output from the same primaryenergy source.

Compliance period means the periodof time, set forth by a state in its stateplan, during which each affected entitymust demonstrate compliance with anapplicable emissions standard, and shallbe no greater than a three year period fora mass-based plan, and shall be no

greater than a one year period for a rate-based plan.

Emission performance level in a stateplan means the level of emissionsperformance for affected entitiesspecified in a state plan, according to§ 60.5 740.

Emission standard means in additionto the definition in § 60.21, anyrequirement applicable to any affectedentity other than an affected source thathas the effect of reducing utilization ofone or more affected sources, therebyavoiding emissions from such sources,including, for example, renewableenergy and demand-side energyefficiency measures requirements.

Excess emissions means a specifiedaveraging period over which the CO2emissions rate is higher than anapplicable emissions standard or anaveraging period during which anaffected EGU is not in compliance withany other emission limitation specifiedin an emission standard.

Existing state program, requirement,or measure means, in the context of astate plan, a regulation, requirement,program, or measure administered by astate, utility, or other entity that iscurrently established. This may includea regulation or other legal requirementthat includes past, current, and futureobligations, or current programs andmeasures that are in place and areanticipated to be continued or expandedin the future, in accordance withestablished plans. An existing stateprogram, requirement, or measure mayhave past, current, and future impactson EGU CO2 emissions.

Fossil fuel means natural gas,petroleum, coal, and any form of solid,liquid, or gaseous fuel derived fromsuch material for the purpose of creatinguseful heat.

Gaseous fuel means any fuel that ispresent as a gas at ISO conditions andincludes, but is not limited to, naturalgas, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and gasifiedcoal.

Heat recovery steam generating unit(HRSG) means a unit in which hotexhaust gases from the combustionturbine engine are routed in order toextract heat from the gases and generateuseful output. Heat recovery steamgenerating units can be used with orwithout duct burners.

Integrated gasification combinedcycle facility or 10CCfacility means acombined cycle facility that is designedto burn fuels containing 50 percent (byheat input) or more solid-derived fuelnot meeting the definition of natural gasplus any integrated equipment thatprovides electricity or useful thermaloutput to either the affected facility or

auxiliary equipment. The Administratormay waive the 50 percent solid-derivedfuel requirement during periods of thegasification system construction, startupand commissioning, shutdown, orrepair. No solid fuel is directly burnedin the unit during operation.

ISO conditions means 288 Kelvin (15°C), 60 percent relative humidity and101.3 kilopascals pressure.

Liquid fuel means any fuel that ispresent as a liquid at ISO conditionsand includes, but is not limited to,distillate oil and residual oil.

Mechanical output means the usefulmechanical energy that is not used tooperate the affected facility, generateelectricity and/or thermal output, or toenhance the performance of the affectedfacility. Mechanical energy measured inhorsepower hour should be convertedinto MWh by multiplying it by 745.7then dividing by 1,000,000.

Natural gas means a fluid mixture ofhydrocarbons (e.g., methane, ethane, orpropane), composed of at least 70percent methane by volume or that hasa gross calorific value between 35 and41 megajoules (MJ) per dry standardcubic meter (950 and 1,100 Btu per drystandard cubic foot), that maintains agaseous state under ISO conditions. Inaddition, natural gas contains 20.0grains or less of total sulfur per 100standard cubic feet. Finally, natural gasdoes not include the following gaseousfuels: Landfill gas, digester gas, refinerygas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke ovengas, or any gaseous fuel produced in aprocess which might result in highlyvariable sulfur content or heating value.

Net-electric output means the amountof gross generation the generator(s)produce (including, but not limited to,output from steam turbine(s),combustion turbine(s), and gasexpander(s)), as measured at thegenerator terminals, less the electricityused to operate the plant (i.e., auxiliaryloads); such uses include fuel handlingequipment, pumps, fans, pollutioncontrol equipment, other electricityneeds, and transformer losses asmeasured at the transmission side of thestep up transformer (e.g., the point ofsale).

Net energy output means:(1) The net electric or mechanical

output from the affected facility, plus 75percent of the useful thermal outputmeasured relative to SATP conditionsthat is not used to generate additionalelectric or mechanical output or toenhance the performance of the unit(e.g., steam delivered to an industrialprocess for a heating application).

(2) For combined heat and powerfacilities where at least 20.0 percent of


federal Register/Vol. 79, No. 117/Wednesday, June 18, 2014/Proposed Rules

the total gross energy output consists ofelectric or direct mechanical output and20.0 percent of the total gross energyoutput consists of useful thermal outputon a rolling 3 year basis, the net electricor mechanical output from the affectedfacility divided by 0.95, plus 75 percentof the useful thermal output measuredrelative to SATP conditions that is notused to generate additional electric ormechanical output or to enhance theperformance of the unit (e.g., steamdelivered to an industrial process for aheating application).

Petroleum means crude oil or a fuelderived from crude oil, including, butnot limited to, distillate and residual oil.

Solid fuel means any fuel that has adefinite shape and volume, has notendency to flow or disperse undermoderate stress, and is not liquid orgaseous at ISO conditions. Thisincludes, but is not limited to, coal,biomass, and pulverized solid fuels.

Standard ambient temperature andpressure (SATP) conditions means298.15 Kelvin (25° C, 77 °F)) and 100.0kilopascals (14.504 psi, 0.987 atm)pressure. The enthalpy of water at SATPconditions is 50 Btullb.

Stationary combustion turbine meansall equipment, including but not limited

to the turbine engine, the fuel, air,lubrication and exhaust gas systems,control systems (except emissionscontrol equipment), heat recoverysystem, fuel compressor, heater, and/orpump, post-combustion emissionscontrol technology, and any ancillarycomponents and sub-componentscomprising any simple cycle stationarycombustion turbine, any combinedcycle combustion turbine, and anycombined heat and power combustionturbine based system plus anyintegrated equipment that provideselectricity or useful thermal output tothe combustion turbine engine, heatrecovery system or auxiliary equipment.Stationary means that the combustionturbine is not self-propelled or intendedto be propelled while performing itsfunction. It may, however, be mountedon a vehicle for portability. If astationary combustion turbine burns anysolid fuel directly it is considered asteam generating unit.

Steam generating unit means anyfurnace, boiler, or other device used forcombusting fuel and producing steam(nuclear steam generators are notincluded) plus any integratedequipment that provides electricity or

34957

useful thermal output to the affectedfacility or auxiliary equipment.

Useful thermal output means thethermal energy made available for use inany industrial or commercial process, orused in any heating or coolingapplication, i.e., total thermal energymade available for processes andapplications other than electricgeneration, mechanical output at theaffected facility, or to directly enhancethe performance of the affected facility(e.g., economizer output is not usefulthermal output, but thermal energy usedto reduce fuel moisture is considereduseful thermal output). Useful thermaloutput for affected facilities with nocondensate return (or other thermalenergy input to the affected facility) orwhere measuring the energy in thecondensate (or other thermal energyinput to the affected facility) would notmeaningfully impact the emission ratecalculation is measured against theenergy in the thermal output at SATPconditions. Affected facilities withmeaningful energy in the condensatereturn (or other thermal energy input tothe affected facility) must measure theenergy in the condensate and subtractthat energy relative to SATP conditionsfrom the measured thermal output.

TABLE 1 TO SUBPART UUUU OF PART 60—STATE RATE-BASED CO2 EMISSION PERFORMANCE GOALS[Pounds of CO2 per net MWh]

State Interim goal Final goal

AlabamaAlaskaArizonaArkansasCaliforniaColoradoConnecticutDelawareFloridaGeorgiaHawaiiIdahoIllinoisIndianaIowaKansasKentuckyLouisianaMaineMarylandMassachusettsMichiganMinnesotaMississippiMissouriMontanaNebraskaNevadaNew HampshireNew JerseyNew MexicoNew YorkNorth CarolinaNorth Dakota

1,1471,097

735968556

1,159597913794891

1,378244

1,3661,6071,3411,5781,844

948393

1,347655

1,227911732

1,6211,8821,596

697546647

1,107635

1,0771,817

1,0591,003

702910537

1,108540841740834

1,306228

1,2711,5311,3011,4991,763

883378

1,187576

1,161873692

1,5441,7711,479

647486531

1,048549992

1,783



TABLE 1 TO SUBPART UUUU OF PART 60—STATE RATE-BASED CO2 EMISSION PERFORMANCE GOALS—Continued[Pounds of CO2 per net MWh]

State Interim goal Final goal

Ohio 1,452 1,338Oklahoma 931 895Oregon 407 372Pennsylvania 1,179 1,052Rhode Island 822 782South Carolina 840 772South Dakota 800 741Tennessee 1,254 1,163Texas 853 791Utah 1,378 1,322Virginia 884 810Washington 264 215West Virginia 1,748 1,620Wisconsin 1,281 1,203Wyoming 1,808 1,714

[FR Doc. 2014—13726 Filed 6—17—14; 8:45 am]BILLING CODE 6560—50-P


MITE STATES COURT OF APPEALSPOli DISTRICT OF COIUSIACIRCUff

AUG 152014 AUG 152014

RECEIVED

___

CLERK

__________________

J-rLrIJ_

IN TilE UNITED STATES COURT OF APPEALSFOR TilE DISTRICT OF COLUMBIA CIRCUIT


Petitioner,

v. Case No. 1 ‘ —1 1 t

UNITED STATES ENVIRONMENTALPROTECTION AGENCY and REGINAA. McCARTHY, Administrator, UnitedStates Environmental Protection Agency,

Respondents.

RULE 26.1 STATEMENT

Pursuant to Federal Rule of Appellate Procedure 26.1 and D.C. Circuit

Rule 26.1, Petitioner, Murray Energy Corporation, makes the following

disclosure: Murray Energy Corporation has no parent corporation and no

publicly held corporation owns ten percent (10%) or more of its stock.

Murray Energy Corporation is the largest privately-owned coal company

in the United States and the fifth largest coal producer in the country,

employing approximately 7,300 workers in the mining, processing,

transportation, distribution and sale of coal.


Res ctfully submitted,

Geoffrey K. BarnesI. Van CarsonRobert D. CherenRebecca A. WorthingtonSQUIRE PATTON BOGGS (US) LLP4900 Key Tower127 Public SquareCleveland, Ohio 44114(216) 479-8559geoffrey.bamessquirepb. corn

Counselfor PetitionerMurray Energy Corporation

-2-


IN THE UMTED STATES COURT OF APPEALSFOR THE DISTRICT OF COLUMBIA CmcuIT


Petitioner,

V.

UNITED STATES ENVIRONMENTALPROTECTION AGENCY and REGINAA. McCARTHY, Administrator, UnitedStates Environmental Protection Agency,

Respondents.

Case No..

CERTIFICATE OF SERVICE

I hereby certify that the foregoing PETITIoN FOR JuDIcIAL REVIEW and

RuLE 26.1 STATEMENT have been served by Petitioner, Murray Energy

Corporation, by United States first-class mail this 2nd day of August, 2014,

upon each of the following:

United States EnvironmentalProtection AgencyCorrespondence Control UnitOffice of General Counsel (2344-A)1200 Pennsylvania Ave., NWWashington, D.C. 20460

Eric H. Holder, Attorney GeneralU.S. Department of Justice950 Pennsylvania Ave., NWWashington, D.C. 20530

Regina A. McCarthy, AdministratorU.S. Environmental Protection AgencyArid Rios Building, 1 lOlA1200 Pennsylvania Ave., NWWashington, D.C. 20460


Respectfully submitted,

I. Van CarsonRobert D. CherenRebecca A. WorthingtonSQUIRE PATTON BOGGS (US) LLP

4900 Key Tower127 Public SquareCleveland, Ohio 44114(216) 479-8559geoffrey.bamessquirepb.com

Counselfor PetitionerMurray Energy Corporation

-2-
