From: Frey, Nathan J. To: Hutson, Nick Cc: Culligan, Kevin ; Wayland, Robertj ; Tsirigotis, Peter Subject: Re: Revised (RLSO) versions of preamble; EPA response Date: Saturday, August 31, 2013 11:28:43 AM


### Thanks Nick. Will send around and be in touch about follow up.

From : Hutson, Nick [mailto:Hutson.Nick@epa.gov] Sent : Friday, August 30, 2013 05:36 PM To : Frey, Nathan J. Cc : Culligan, Kevin <Culligan.Kevin@epa.gov>; Wayland, Robertj <Wayland.Robertj@epa.gov>; Tsirigotis, Peter <Tsirigotis.Peter@epa.gov> Subject : Revised (RLSO) versions of preamble; EPA response



### Nathan

Attached to this email are three files:
(1) A PDF version of the redline changes to the preamble (2) A MSWord version of the redline changes to the preamble (3) An updated ‘EPA Response’ to the Interagency Comments
In emails immediately following this one, I will send versions of the ...
(1) Revised regulatory language (2) Revised RIA chapters; and (3) A DRAFT version of a TSD entitled “ Fossil Fuel-Fired Boiler and IGCC EGU Projects Under Development: Status and Approach”

We have made many changes in response to comments from OMB and the Interagency Workgroup. We are still considering some comments. Those are noted in the text and in the EPA Response. We can continue to discuss specific comments and other aspects of the package once you have had the opportunity to see the edits in these revised versions. Have a nice holiday and a relaxing time off next week.
Regards, Nick

Nick Hutson, PhD Energy Strategies Group U.S. Environmental Protection Agency Research Triangle Park, NC 27711 (919) 541-2968 hutson.nick@epa.govEO 12866_EGU GHG NSPS 2060-AQ91 NPRM_20130628 6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60
[EPA-HQ-OAR-2013-0495; FRL- 9839-4 ]

RIN 2060-AQ91

Standards of Performance for Greenhouse Gas Emissio ns from New Stationary Sources: Electric Utility Generating Uni ts

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

SUMMARY: On April 13, 2012, the EPA proposed a new source performance standard for emissions of carbon dioxid e for new affected fossil fuel-fired electric utility generat ing units.

The EPA received more than 2.5 million comments on the proposed rule. After consideration of information provided i n those comments, as well as consideration of continuing ch anges in the electricity sector, the EPA determined that revisio ns in its proposed approach are warranted. Thus, in a separat e action, the EPA is rescinding the April 13, 2012 proposal, and in this action, the EPA is proposing new standards of perfo rmance for new affected fossil fuel-fired electric utility ste am generating units and stationary combustion turbines. This acti on proposes a separate standard of performance for fossil fuel-fi red electric utility steam generating units and integrated gasif ication Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 2 of 373 combined cycle units that burn coal, petroleum coke and other fossil fuels that is based on partial implementatio n of carbon capture and storage as the best system of emission reduction. This action also proposes standards for natural gas -fired stationary combustion turbines based on modern, eff icient natural gas combined cycle technology as the best s ystem of

emission reduction.

DATES: Comments . Comments must be received on or before [INSERT

THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN T HE FEDERAL REGISTER OF THIS PROPOSED RULE]. Under the Paperwor k Reduction Act (PRA), since the Office of Management and Budge t (OMB) is required to make a decision concerning the informat ion collection request between 30 and 60 days after [IN SERT THE DATE

OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROP OSED RULE], a comment to the OMB is best assured of having its fu ll effect if the OMB receives it by [INSERT THE DATE 30 DAYS AFT ER THE DATE

OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROP OSED RULE]. Public Hearing . The EPA will hold a public hearing (or hearings) on this proposal. The date, time, and loc ation of the public hearing (or hearings) will be announced sepa rately in a subsequent Federal Register notice. Oral testimony will be limited to five minutes per commenter. The EPA enco urages

commenters to submit written versions of their oral testimonies Moved down [2]: The EPA previously proposed a new source performance standard for emissions of carbon dioxide (CO 2 ) for new affected fossil fuel-fired electric utility generating units (EGUs) on April 13, 2012 (77 FR 22392). The EPA considered comments submitted in response to the original April 13, 2012 proposal in developing this new proposal. However, we are rescinding the original proposal. If you would like consideration of comments submitted on the April 13, 2012 rulemaking, you should submit new comments or re-submit previous comments. Commenters who submitted public comments concerning any aspect of the previous proposal will need to consider the applicability of those comments to this current proposal and submit them again, if applicable, even if the comments are exactly or substantively the same as those previously submitted, to ensure consideration in the development of the final rulemaking. Comment [SM1]: Do not include information other than dates in the DATES caption. Place any discussion of meeting agenda, content of material available for inspection, etc. in the SUPPLEMENTARY INFORMATION section.

MJ: Moved text.

Deleted: provide***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 3 of 373 either electronically or in paper copy. The rulemak ing docket will include verbatim transcripts and written state ments. If you would like to present oral testimony at one of the hearings, please notify Ms. Pamela Garrett, Sector Policies a nd Programs Division (C504–03), U.S. EPA, Research Triangle Par k, NC 27711, telephone number (919) 541–7966; email: garrett.pam ela@epa.gov. Persons wishing to provide testimony should notify Ms. Garrett at least two days in advance of the public hearings . The public hearings will provide interested parties the opport unity to present data, views, or arguments concerning the pr oposed rule. EPA officials may ask clarifying questions during t he oral presentations but will not respond to the presentat ions or comments at that time. Written statements and suppo rting information submitted during the comment period wil l be considered with the same weight as any oral comment s and supporting information presented at the public hear ing. For updates and additional information on the public he arings, please check the EPA’s website for this rulemaking, http://www.epa.gov/carbonpollutionstandards /

.
ADDRESSES: Comments . Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2013-0495, by one of the followin g methods: At the website http://www.regulations.gov : Follow the instructions for submitting comments. Deleted: airquality/***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 4 of 373 At the website http://www.epa.gov/oar/docket.html : Follow the instructions for submitting comments on the EPA Air and

Radiation Docket web site.

E-mail : Send your comments by electronic mail (e-mail) to a-and-r-docket@epa.gov , Attn: Docket ID No. EPA-HQ-OAR-2013-

0495.

Facsimile : Fax your comments to (202) 566-9744, Attn:
Docket ID No. EPA-HQ-OAR-2013-0495.

Mail : Send your comments to the EPA Docket Center, U.S. EPA, Mail Code 2822T, 1200 Pennsylvania Ave., NW, W ashington, DC
20460, Attn: Docket ID No. EPA-HQ-OAR-2013-0495. Pl ease include a total of two copies. In addition, please mail a c opy of your comments on the information collection provisions t o the Office of Information and Regulatory Affairs, OMB, Attn: D esk Officer
for EPA, 725 17 th St. NW, Washington, DC 20503. Hand Delivery or Courier : Deliver your comments to the EPA
Docket Center, EPA West, Room 3334, 1301 Constituti on Ave., NW, Room 3334, Washington, DC, 20460, Attn: Docket ID N o. EPA-HQOAR-2013-0495. Such deliveries are accepted only du ring the Docket Center’s normal hours of operation (8:30 a.m . to 4:30 p.m., Monday through Friday, excluding federal holi days), and special arrangements should be made for deliveries of boxed

information.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 5 of 373

Instructions : All submissions must include the agency name
and docket ID number (EPA-HQ-OAR-2013-0495). The EP A’s policy is to include all comments received without change, in cluding any personal information provided, in the public docket , available online at http://www.regulations.gov , unless the comment

includes information claimed to be Confidential Bus iness
Information (CBI) or other information whose disclo sure is restricted by statute. Do not submit information th at you consider to be CBI or otherwise protected through http://www.regulations.gov or e-mail. Send or deliver information identified as CBI only to the following address: Roberto Morales, OAQPS Document Control Officer (C4 04-02), Office of Air Quality Planning and Standards, U.S. EPA, Research Triangle Park, North Carolina 27711, Attention Dock et ID No. EPA-HQ-OAR-2013-0495. Clearly mark the part or all of the information that you claim to be CBI. For CBI infor mation on a disk or CD-ROM that you mail to the EPA, mark the o utside of the disk or CD-ROM as CBI and then identify electronica lly within the disk or CD-ROM the specific information you cla im as CBI. In addition to one complete version of the comment tha t includes information claimed as CBI, you must submit a copy of the

comment that does not contain the information claim ed as CBI for inclusion in the public docket. Information so mark ed will not***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 6 of 373 be disclosed except in accordance with procedures s et forth in
40 CFR part 2. The EPA requests that you also submit a separate c opy of your comments to the contact person identified belo w (see FOR
FURTHER INFORMATION CONTACT). If the comment includes information you consider to be CBI or otherwise pro tected, you should send a copy of the comment that does not con tain the information claimed as CBI or otherwise protected. The www.regulations.gov website is an “anonymous access” system, which means the EPA will not know your iden tity or contact information unless you provide it in the bo dy of your comment. If you send an email comment directly to t he EPA without going through http://www.regulations.gov , your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electro nic comment, the EPA recommends that you include your name and o ther contact information in the body of your comment and with an y disk or CDROM you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for c larification, the EPA may not be able to consider your comment. E lectronic files should avoid the use of special characters, a ny form of encryption, and be free of any defects or viruses.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 7 of 373

Docket : All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some information is not publicly available (e.g., C BI or other information whose disclosure is restricted by statu te). Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available doc ket materials are available either electronically in http://www.regulations.gov or in hard copy at the EPA Docket
Center, EPA West, Room 3334, 1301 Constitution Ave. , NW, Washington, DC. The Public Reading Room is open fro m 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding fede ral holidays. The telephone number for the Public Reading Room is (202) 566- 1744, and the telephone number for the Air Docket i s (202) 566- 1742. Visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm for additional information about the EPA’s public docket. In addition to being available in the docket, an e lectronic copy of this proposed rule will be available on the Worldwide Web (WWW) through the Technology Transfer Network ( TTN). Following signature, a copy of the proposed rule wi ll be posted on the TTN’s policy and guidance page for newly pro posed or promulgated rules at the following address: http://www.epa.gov/ttn/oarpg/

.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 8 of 373

FOR FURTHER INFORMATION CONTACT: Dr. Nick Hutson, Energy Strategies Group, Sector Policies and Programs Divi sion (D243- 01), U.S. EPA, Research Triangle Park, NC 27711; te lephone number (919) 541-2968, facsimile number (919) 541-5 450; email address: hutson.nick@epa.gov or Mr. Christian Felln er, Energy Strategies Group, Sector Policies and Programs Divi sion (D243- 01), U.S. EPA, Research Triangle Park, NC 27711; te lephone number (919) 541-4003, facsimile number (919) 541-5 450; email address: fellner.christian@epa.gov.

SUPPLEMENTARY INFORMATION: Comments on the April 13, 2012
proposal. The EPA previously proposed a new source performanc e standard for emissions of carbon dioxide (CO 2 ) for new affected fossil fuel-fired electric utility generating units (EGUs) on April 13, 2012 (77 FR 22392). The EPA considered co mments submitted in response to the original April 13, 201 2 proposal in developing this new proposal. However, we are resci nding the original proposal. If you would like consideration of comments submitted on the April 13, 2012 rulemaking, you sho uld submit new comments or re-submit previous comments. Commen ters who submitted public comments concerning any aspect of the previous proposal will need to consider the applicability of those comments to this current proposal and submit them a gain, if applicable, even if the comments are exactly or sub stantively Moved (insertion) [2]***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 9 of 373 the same as those previously submitted, to ensure c onsideration in the development of the final rulemaking.

Acronyms . A number of acronyms and chemical symbols are used in this preamble. While this may not be an exh austive list, to ease the reading of this preamble and for refere nce purposes, the following terms and acronyms are defined as fol lows: AB Assembly Bill AEP American Electric Power AEO Annual Energy Outlook ANSI American National Standards Institute ASME American Society of Mechanical Engineers ASTM American Society for Testing of Materials BACT Best Available Control Technology BDT Best Demonstrated Technology BSER Best System of Emission Reduction Btu/kWh British Thermal Units per Kilowatt-hour Btu/lb British Thermal Units per Pound CAA Clean Air Act CAIR Clean Air Interstate Rule CBI Confidential Business Information CCS Carbon Capture and Storage (or Sequestration) CDX Central Data Exchange CEDRI Compliance and Emissions Data Reporting Inter face CEMS Continuous Emissions Monitoring System CFB Circulating Fluidized Bed CH 4 Methane CHP Combined Heat and Power CO 2 Carbon Dioxide CSAPR Cross-State Air Pollution Rule DOE Department of Energy DOT Department of Transportation ECMPS Emissions Collection and Monitoring Plan Syst em EERS Energy Efficiency Resource Standards EGU Electric Generating Unit EIA Energy Information Administration EO Executive Order EOR Enhanced Oil Recovery EPA Environmental Protection Agency FB Fluidized Bed FGD Flue Gas Desulfurization***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 10 of 373 FR Federal Register GHG Greenhouse Gas GW Gigawatts H 2 Hydrogen Gas HAP Hazardous Air Pollutant HFC Hydrofluorocarbon HRSG Heat Recovery Steam Generator IGCC Integrated Gasification Combined Cycle IPCC Intergovernmental Panel on Climate Change IPM Integrated Planning Model IRPs Integrated Resource Plans kg/MWh Kilogram per Megawatt-hour kJ/kg Kilojoules per Kilogram kWh Kilowatt-hour lb CO 2 /MMBtu Pounds of CO 2 per Million British Thermal Unit lb CO 2 /MWh Pounds of CO 2 per Megawatt-hour lb CO 2 /yr Pounds of CO 2 per Year lb/lb-mole Pounds per Pound-Mole MATS Mercury and Air Toxic Standards MMBtu/hr Million British Thermal Units per Hour MW Megawatt MWe Megawatt Electric al MWh Megawatt-hour N 2 O Nitrous Oxide NAAQS National Ambient Air Quality Standards NAICS North American Industry Classification Syste m NAS National Academy of Sciences NETL National Energy Technology Laboratory NGCC Natural Gas Combined Cycle NRC National Research Council NSPS New Source Performance Standards NSR New Source Review NTTAA National Technology Transfer and Advancement Act O 2 Oxygen Gas OMB Office of Management and Budget PC Pulverized Coal PFC Perfluorocarbon PM Particulate Matter PM 2.5 Fine Particulate Matter PRA Paperwork Reduction Act PSD Prevention of Significant Deterioration PUC Public Utilities Commission RCRA Resource Conservation and Recovery Act RFA Regulatory Flexibility Act RGGI Regional Greenhouse Gas Initiative RIA Regulatory Impact Analysis Deleted: Metric***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 11 of 373

RPS Renewable Portfolio Standard RTC Response to Comments RTP Response to Petitions SBA Small Business Administration SCC Social Cost of Carbon SCR Selective Catalytic Reduction SF 6 Sulfur Hexafluoride SIP State Implementation Plan SNCR Selective Non-Catalytic Reduction SO 2 Sulfur Dioxide SSM Startup, Shutdown, and Malfunction Tg Teragram (one trillion (10 12 ) grams) Tpy Tons per Year TSD Technical Support Document TTN Technology Transfer Network UIC Underground Injection Control UMRA Unfunded Mandates Reform Act of 1995 U.S. United States USGCRP U.S. Global Change Research Program VCS Voluntary Consensus Standard WGS Water Gas Shift WWW Worldwide Web Organization of This Document . The information presented in this preamble is organized as follows:

I. General Information A. Executive summary B. Overview C. Does this action apply to me? II. Background A. Climate change impacts from GHG emissions B. GHG emissions from fossil fuel-fired EGUs C. The utility power sector and how its structure is c hanging D. Statutory background E. Regulatory and litigation background F. Coordination with other rulemakings G. Stakeholder input III. Proposed Requirements for New Sources A. Applicability requirements B. Emission standards C. Startup, shutdown, and malfunction requirements D. Continuous monitoring requirements E. Emissions performance testing requirements F. Continuous compliance requirements Deleted: Affected sources***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 12 of 373

G. Notification, recordkeeping, and reporting requirem ents IV. Rationale for Reliance on Rational Basis to Reg ulate GHGs from Fossil-fired EGUs A. Overview B. Climate Change Impacts from GHG Emissions; Amounts of GHGs from fossil fuel-fired EGUs C. CAA § 111 requirements D. Interpretation of CAA § 111 requirements E. Rational basis to promulgate standards for GHGs from fossilfired EGUs F. Alternative findings of endangerment and signifi cant contribution G. Comments on the state of the science of climate change V. Rationale for Applicability Requirements A. Applicability requirements - original proposal a nd comments B. Applicability requirements – today’s proposal VI. Legal Requirements for Establishing Emission St andards A. Overview B. CAA requirements and Court interpretation C. Technical feasibility D. Factors to consider in determining the “best system ” E. Nationwide component of factors in determining the “best system” F. Chevron framework G. Agency discretion H. Lack of requirement that standard be able to be met by all sources VII. Rationale for Emission Standards for New Fossi l Fuel-fired Boilers and IGCC s A. Overview B. Identification of the best system of emission re duction C. Determination of the level of the standard D. Extent of reductions in CO 2 emissions E. Technical feasibility F. Costs G. Promotion of technology H. Nationwide, longer-term perspective

I . Deference J . CCS and BSER in locations where costs are too hig h to implement CCS K . Compliance period L . Geologic sequestration VIII. Rationale for Emission Standards for Natural Gas-fired Stationary Combustion Turbines Deleted: C. Codification in the Code of Federal Regulations

Deleted: <#>Overall purposes¶

Deleted: Utility Deleted: Units

Deleted: I. Consistency with purposes of CAA section 111 Deleted: J Deleted: K Deleted: L Deleted: M***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 13 of 373 A. Best system of emission reduction B. Determination of the standards of performance IX. Rationale for Compliance R equirements X. Implications for PSD and Title V Programs A. Overview B. Applicability of tailoring rule thresholds under the PSD program C. Implications for BACT determinations under PSD D. Implications for title V program E. Implications for title V fee requirements for GH Gs XI. Impacts of the Proposed Action A. What are the air impacts? B. What are the energy impacts? C. What are the compliance costs? D. How will this proposal contribute to climate change protection? E. What are the economic and employment impacts? F. What are the benefits of the proposed standards? XII. Request for Comments XIII. Statutory and Executive Order Reviews A. Executive Order 12866, Regulatory Planning and Revi ew, and Executive Order 13563, Improving Regulation and Reg ulatory Review B. Paperwork Reduction Act C. Regulatory Flexibility Act as Amended by the Small Business Regulatory Enforcement Fairness Act of 1996, 5 U.S. C. 601 et seq . D. Unfunded Mandates Reform Act of 1995 E. Executive Order 13132, Federalism F. Executive Order 13175, Consultation and Coordinatio n With Indian Tribal Governments G. Executive Order 13045, Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211, Actions Concerning Regulatio ns That Significantly Affect Energy Supply, Distribution, o r Use I. National Technology Transfer and Advancement Act J. Executive Order 12898, Federal Actions to Address Environmental Justice in Minority Populations and L ow-Income Populations

I. General Information A. Executive summary 1. Purpose of the regulatory action Deleted: Other Requirements¶ A. Deleted: r***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 14 of 373 On April 13, 2012, under the authority of Clean Air Act (CAA) section 111, the EPA proposed a new source pe rformance

standard (NSPS) to limit emissions of carbon dioxide (CO 2 ) from new fossil fuel-fired electric utility generating u nits (EGUs) , including, primarily, coal- and natural gas-fired u nits (77 FR 22392). After consideration of the information prov ided in more than 2.5 million comments on the proposal, as well as consideration of continuing changes in the electric ity sector , the EPA is issuing a new proposal . Today’s action proposes to establish separate standards for fossil fuel-fired electric steam generating units (utility boilers and Integrated Gasification Combined Cycle ( IGCC ) units) and for natural gasfired stationary combustion turbines

. These proposed standards

reflect separate determination s of the best system of emission

reduction adequately demonstrated (BSER) for utility boilers and IGCC units and for natural gas-fired stationary com bustion turbines. Because, in contrast, the April 2012 prop osal relied on a single standard and a single BSER determination for all new fossil fuel-fired units, the EPA is issuing, as a f inal action, a notice (published separately in today’s Federal R egister ) that rescinds the original proposal, as well as issuing this new proposal. 2. Summary of the major provisions Deleted: 1
, Comment [A2]: This FN appears to be missing and/or is duplicative of the next FN, which is also labeled FN 1. EPA: The FN did not belong here and it has been removed.

Deleted: that use coal, petroleum coke and other fossil fuels Comment [A3]: What other fossil fuels are referred to? It would improve clarity to be more specific. EPA: This phrase has been removed.

Deleted: ing, respectively, Deleted: a Deleted: a BSER determination***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 15 of 373 This action proposes a standard of performance for utility boilers and IGCC units based on partial implementat ion of carbon capture and storage (CCS) as the BSER . The proposed emission
limit for those sources is 1,100 lb CO 2 /MWh. 1 This action also proposes standards of performance for natural gas-f ired stationary combustion turbines based on modern, eff icient natural gas combined cycle (NGCC) technology as the BSER . The proposed emission limits for th o se sources are 1,000 lb CO 2 /MWh for larger units and 1,100 lb CO 2 /MWh for smaller units. At this time, the EPA is not proposing standards of perform ance for

modified or reconstructed sources.

3. Costs and benefits As explained in the Regulatory Impact Analysis (RIA ) for this proposed rule, available data – including utility announcements and EIA modeling - indicate that, even in the
absence of this rule, (i) existing and anticipated economic

conditions mean that few, if any, solid fossil fuel-fired EGU s will be built in the foreseeable future; and (ii) electricity

generators are expected to choose new generation technologies that would meet the proposed standard s . Therefore, based on the analysis presented in Chapter 5 of the RIA, the EPA projects

1 In this rulemaking, all references to lb CO 2 /MWh are on a gross output basis, unless specifically noted otherwise. Deleted: separate

Deleted: best system of emission reduction

Deleted: best system of emission reduction Deleted: e

Deleted: will lead

Deleted: without installation of additional controls***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 16 of 373 that this proposed rule will result in negligible C O 2 emission changes, quantified benefits, and costs by 2022. 2 These projections are in line with utility announcements and Energy Information Administration ( EIA ) modeling that indicate that

coal units built between now and 2020 would have CC S, even in the absence of this rule. However, for a variety of reasons, some companies may consider coal units that the mod eling does not anticipate. Therefore, in Chapter 5 of the RIA, we also present an analysis of the project-level costs of a new coalfired unit with partial CCS alongside the project-l evel costs of

a new coal-fired unit without CCS.

B. Overview

1. Why is the EPA issuing this proposed rule? Greenhouse gas (GHG) pollution threatens the Americ an public's health and welfare by contributing to long -lasting changes in our climate that can have a range of neg ative effects on human health and the environment. The impacts co uld include: longer, more intense and more frequent heat waves; more intense precipitation events and storm surges; less precipi tation and more prolonged drought in the West and Southwest; m ore fires and insect pest outbreaks in American forests, especial ly in the

2 Conditions in the analysis year of 2022 are repres ented by a model year of 2020. Deleted: 2020.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 17 of 373 West; and increased ground level ozone pollution, o therwise known as smog, which has been linked to asthma and premature death. Health risks from climate change are especia lly serious for children, the elderly and those with heart and respiratory problems. The U.S. Supreme Court ruled that GHGs meet the def inition of “air pollutant” in the CAA, and this decision cl arified that

the CAA’s authorities and requirements apply to GHG emissions

. Unlike most other air pollutants, GHGs may persist in the atmosphere from decades to millennia, depending on the specific greenhouse gas. This special characteristic makes i t crucial to take initial steps now to limit GHG emissions from fossil fuelfired power plants, specifically emissions of CO 2 , since they are the nation’s largest sources of carbon pollution. T his rule will ensure that the next generation of fossil fuel-fire d power plants in this country will use modern technologies that limit harmful carbon pollution. On April 13, 2012, the EPA issued a proposed rule t o limit GHG emissions from fossil fuel-fired power plants b y establishing a single standard applicable to all new fossil fuel-fired EGUs serving intermediate and base load power demand

. After consideration of the information provided in more than 2.5 million comments on the proposal, as well as consid eration of Deleted: Clean Air Act ( Deleted: or Act) Deleted: Act’s

Deleted: carbon dioxide ( Deleted: )

Deleted: both natural gas- and coalfired Deleted: generating units Deleted: baseload***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 18 of 373 continuing changes in the electricity sector 3 , the EPA is issuing a new proposal to establish separate standards for fossil fuelfired electric steam generating units (utility boil ers and IGCC units) and for natural gas-fired stationary combust ion turbines

. These proposed standards reflect separate determination s of the

BSER adequately demonstrated for utility boilers and IGCC units

and for natural gas-fired stationary combustion turbin es. Because, in contrast, the April 2012 proposal relie d on a single
standard for all new fossil fuel-fired units, the E PA is issuing, as a final action, a notice (published sep arately in today’s Federal Register ) that rescinds the original proposal, as well as issuing this new proposal.

2. What authority is the EPA relying on to address pow er plant

CO 2 emissions? Congress established requirements under section 111 of the

1970 CAA to control air pollution from new stationary sourc es through NSPS. Specifically, section 111 requires th e EPA to set technology-based standards for new stationary sourc es to minimize emissions of air pollution to the environm ent. For more

3 For example, since April 2012, there has been sign ificant progress on two CCS projects (Kemper County and Bou ndary Dam), and they are now both over 75 percent complete. Two other projects have continued to make progress toward construction (Texas Clean Energy Project and Hydrogen Energy Cal ifornia Project). Deleted: ing, respectively, a

Deleted: best system of emission reduction ( Deleted: ) Deleted: that use coal, petroleum coke and other fossil fuels, and a BSER determination

Deleted: Clean Air Act

Deleted: new source performance standards ( Deleted: ) Deleted: ¶

Deleted: breaking ground***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 19 of 373 than four decades, the EPA has used its authority u nder section

111 to set cost-effective emission standards that e nsure newly constructed sources use the best performing technol ogies to limit emissions of harmful air pollutants. In this proposal, the EPA is following the same well-established, customa ry interpretation and application of the law under sec tion 111 to address GHG emissions from new fossil fuel-fired po wer plants.

3. What sources should the EPA include as it develo ps proposed standards for GHGs for power plants? Before determining the appropriate technologies and levels of control that represent BSER for GHG emissions, the EPA must first identify the appropriate sources to control. The starting point is to consider whether, given cu rrent trends concerning coal-fired and natural gas-fired power plants and the nature of GHGs, the EPA’s current NSPS regu latory structure is appropriate. The EPA’s NSPS regulation s already regulate conventional pollutants from these sources under two 40 CFR part 60 subparts: subpart Da, electric utility steam generating units, which includes both steam electri c utility boilers and IGCC units, and subpart KKKK, stationar y combustion turbines, which includes both simple cycle and comb ined cycle stationary combustion turbines. Deleted: greenhouse gas

Deleted: logical

Deleted: integrated gasified combined cycle ( Deleted: )***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 20 of 373 For sources covered under subpart Da, the original proposal

relied on analyses, primarily undertaken by EIA, indicating
that, while substantial reliance on coal-fired elec tricity generation would continue in the future, few, if an y, new coalfired power plants without CCS were likely to be built by 2025.

Based in part on these results, the EPA concluded that it was appropriate to propose in April 2012 a single fuel-neutral standard covering all intermediate and base load units based on the performance of recently constructed NGCC units. In light of developments in the electricity sector since the Ap ril 2012 proposal, and in response to numerous comments on t he proposal itself, the EPA is changing the approach in today's notice and proposing to set separate standards for sources cov ered by subpart Da

. 4
The EPA notes that, since the original April 2012 proposal,

a few coal-fired units have reached the advanced st ages of construction and development, which suggests that p roposing a separate standard for coal-fired units is appropria te. Since the original proposal, progress on Southern Company's Kemper Cou nty Energy Facility, an IGCC facility which will implement partial CCS, has continued, and the project is now over 75 percent

4 While the emphasis of EPA’s BSER determination is on coal- and petcoke-fired units, the subpart covers all fossil fuel-fired EGU boilers and IGCC units, including those burning oil and gas. Deleted: analysis,

Comment [A4]: Without CCS, right? Aren’t a few with CCS projected to be built? EPA: Yes, that is correct. Comment [A5]: This wasn’t the entire basis for the previous conclusion that a single standard was appropriate. EPA also considered that NGCC was available to meet the needs for base load power and , that, even if a coal plant were built, CCS would be an option. “Based on these results” here suggests that that justification was thinner than it actuall y was. EPA: Agreed Deleted: baseload Deleted: natural gas combined cycle ( Deleted: )

Deleted: this

Deleted: which will deploy Deleted: with***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 21 of 373
complete. Similarly, SaskPower’s Boundary Dam CCS Project in Estevan, Saskatchewan, a project that will fully in tegrate the
rebuilt 110 MW coal-fired Unit #3 with available CC S technology to capture 90 percent of its CO 2 emissions, is more than 75 percent complete. Performance testing is expected t o commence in late 2013 and the facility is expected to be fully operational

in 2014. Additionally, two other projects, Summit Power's Te xas Clean Energy Project (TCEP) and the Hydrogen Energy California Project (HECA) – both of which are IGCC units with CCS – continue to move forward. Continued progress on the se projects is consistent with the EIA modeling which projects that few, if any, new coal-fired EGUs would be built in this dec ade and that

those that are built would include CCS. 5 The existence and apparent ongoing viability of these projects which include CCS justify a separate BSER determination for new fossil fuel-fired utility boilers and IGCC power plants

. In addition to these projects, a number of commente rs (to the April 2012 proposal) noted that, if natural gas prices increase, there could be greater interest in the co nstruction of

5 Even in its sensitivity analysis, the EIA does not project any additional coal projects beyond its reference case until 2023, in a case where power companies assume no emission limitations for GHGs, and until 2024 in any sensitivity analysis in which there are emission limitations for GHGs. Deleted: will deploy

Deleted: have

Deleted: IGCC Deleted: with

Deleted: coal-fired and other solid fossil fuel-fired (e.g., petroleum coke)

Deleted: 2025***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 22 of 373 additional coal-fired generation capacity. This, to o, is consistent with the EIA analysis, which also sugges ts that, in a limited number of potential scenarios generally ass ociated with both significantly higher than anticipated electric demand and significantly higher than expected natural gas pric es, some additional new coal-fired generation capacity may b e built beyond 2020. It is also consistent with publicly av ailable electric utility Integrated Resource Plans (IRPs) 6

. Many of those IRPs indicated the utilities’ interes t in developing some amount of generating capacity using other

intermediate-load and base load technologies, in addition to new NGCC capacity, to meet future demand (albeit, almos t always at a higher cost than NGCC technology). Only a few utili ties’ IRPs indicated that new coal-fired generation without CC S was a technology option that was being considered to meet future demand. Finally, a number of commenters suggested t hat it was important to set standards that preserve options fo r fuel diversity, particularly if natural gas prices excee d projected
levels. Given this information, the EPA believes th at it is appropriate to set a separate standard for solid fo ssil fuel-

6 IRPs are planning documents that many Public Utili ty Commissions require utilities to file outlining the ir plans to meet future demand. Many of the IRPs that the EPA h as reviewed included planning horizons of ten years or more. Deleted: baseload

Deleted: they were seriously considering Deleted: that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 23 of 373
fired EGUs, both to address the small number of coa l plants that evidence suggests might get built and to set a stan dard that is robust across a full range of possible futures in t he energy and electricity sectors. Utility announcements (about the status of coal pro jects), IRPs, and EIA projections suggest that, by far, the largest sources of new fossil fuel-fired electricity genera tion are likely to be NGCC units. The EPA believes, therefor e, that it is also appropriate to set a standard for stationary c ombustion

turbines used as EGUs. These units are currently covered under subpart KKKK (stationary combustion turbines). The EPA also proposes to maintain the definition of EGUs under the NSPS that differentiates between EGUs (so urces used primarily for generating electricity for sale to th e grid) and non-EGUs (turbines primarily used to generate steam and/or electricity for on-site use). That definition defin es EGUs as

units that sell more than one-third of their potential electric output to the grid. Under this definition, most sim ple cycle “peaking” stationary combustion turbines, which typ ically sell significantly less than one-third of their potential electric output to the grid, would not be affected by today’ s proposal. Finally, the EPA is not proposing standards today f or one conventional coal-fired EGU project which, based on current Deleted: natural gas-fired combined cycle ( Deleted: )

Deleted: 1/3

Deleted: 1/3***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 24 of 373 information, appears to be the only such project un der development that has an active air permit and that has not already commenced construction for NSPS purposes. I f the EPA

observes that the project is truly proceeding, it may propose a
standard for that source at the time the EPA finali zes today’s proposed rule.

4. What is the EPA’s general approach to setting stand ards for new sources under Section 111(b)? Section 111(b) requires the EPA to identify the “be st system of emission reduction ... adequately demonstra ted” (BSER) available to limit pollution. The CAA and subsequen t court
decisions (detailed later in this notice) identify the factors

for the EPA to consider in a BSER determination. Fo r this rulemaking, the following factors are key: feasibil ity, costs,

size of emission reductions and technology. Feasibility: The EPA considers whether the system of emission reduction is technically feasible.

Costs: The EPA considers whether the costs of the system

are unreasonable

. Size of emission reductions: The EPA considers the amount of emissions reductions that the system would gener ate. Technology: The EPA considers whether the system promotes the implementation and further development of techn ology. Deleted: determines Deleted: will

Deleted: BSER

Comment [A6]: It would improve clarity by adding a footnote with references and a summary of the court decisions. EPA: A summary is provided later in the “legal” section.

Deleted: not***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 25 of 373 After considering these four factors, we propose that partial implementation of CCS technology is the BSER for new affected fossil fuel-fired boilers and IGCC units ( subpart Da sources) and modern, efficient NGCC units is the BSER for new affected combustion turbines (subpart KKKK sources) . The

foundations for these determinations are described in sections

VII and VIII.

5. What is BSER for new fossil fuel-fired utility boilers and

IGCC units? Power generated from the combustion or gasification of coal

emits more CO 2 than power generated from the combustion of natural gas or by other means, such as solar or win d. If any new coal-fired unit is built, its CO 2 emissions would be approximately double tha t of a new NGCC unit of comparable capacity . Thus, it is important to set a standard for any n ew coal plant that might be built.

The three alternatives the EPA considered in the BS ER analysis for new fossil fuel-fired utility boilers and IGCC units are: (1) highly efficient new generation that does not include CCS technology, (2) new generation with “fu ll capture” CCS and (3) new generation with “partial capture” C CS. Generation technologies representing enhancements i n operational efficiency (e.g., supercritical or ultr aDeleted: to find Comment [A7]: suggest to change “find” to “define,” or revise the sentence to “..., we propose that partial implementation of carbon capture and storage (CCS) technology to be the BSER...”

EPA: The text has been revised.

Deleted: carbon capture and storage ( Deleted: ) Deleted: to be Deleted: to be

Deleted: non-low emitting Comment [A8]: Is non-emitting completely accurate? Suggest rephrasing as low emitting. EPA: Agreed

Deleted: significantly greater Comment [A9]: It could be helpful to provide numeric magnitude of differences, such as adding “...significantly greater (e.g., X%-X%) than a comparable sized NGCC unit.” EPA: Agreed

Deleted: n Deleted: comparably sized***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 26 of 373 supercritical coal-fired boilers or IGCC units) are clearly technically feasible and present little or no incre mental cost compared to the types of technologies that some companies are considering for new coal-fired generation capacity . However, they do not provide meaningful reductions in CO 2 emissions from new sources. Efficiency-improvement technologies al one result in only very small reductions ( several percent ) in CO 2 emissions, especially in contrast to those achieved by the app lication of CCS. Determining that these high-efficiency generating technologies represent the BSER for CO 2 emissions from coal-fired generation would fail to promote the development an d deployment

of CO 2 pollution-reduction technology from power plants. In fact,

a determination that this efficiency-enhancing technology alone, as opposed to CCS, is the BSER for CO 2 emissions from new coalfired generation likely would inhibit the developme nt of technology that could reduce CO 2 emissions significantly, thus defeating one of the purposes of the CAA's NSPS pro visions. For example, during its pilot-scale CCS demonstration a t the Mountaineer Plant in New Haven, WV, American Electr ic Power
(AEP) announced in 201 1 that it was placing on hold its plans to scale-up the CCS system, citing the uncertain statu s of U.S. climate policy as a key contributing factor to its decision. Deleted: weighing

Deleted: without CCS are considering

Comment [A10]: Again, would be helpful to give numeric examples, such as the range of percentage reductions in CO2 emissions. EPA: Agreed Comment [A11]: Suggested edits to enhance clarity. EPA: Agreed

Deleted: finding Comment [A12]: Perhaps “determination” is more appropriate. EPA: Agreed

Deleted: placed Deleted: [insert year] Deleted: ed

Deleted: contributor Comment [A13]: Perhaps change to “a key contributing factor”? EPA: Agreed

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 27 of 373

An assessment of the t he technical feasibility and availability of CCS indicates that at least half of the coalfired power plants that are currently under develop ment are designed to use some type of CCS. In most cases, th e projects will sell or use the captured CO 2 to generate additional revenue. These projects include the following (each of which has obtained

some governmental financial assistanc e ) : Southern Company’s Kemper County Energy Facility , a 582 MW IGCC power plant that is currently under constructi on in Kemper County, Mississippi. The plant will include a CCS system designed to capture approximately 65 percent of the produced CO 2 . SaskPower’s Boundary Dam CCS Project , in Estevan, Saskatchewan is a commercial-scale CCS project that will fully integrate the rebuilt 110 MW coal-fired Unit #3 with available CCS technology to capture 90 percent of i ts CO 2 emissions. Texas Clean Energy Project (TCEP), an IGCC plant near Odessa, Texas, that is under development by the Sum mit Power Group, Inc. (Summit). TCEP is a 400 MW IGCC p lant that expects to capture approximately 90 percent of the produced CO 2 . Deleted: Reflecting Deleted: T Deleted: ,

Comment [A14]: Does EPA know if all of the planned projects intend to generate revenues from captured CO2, which seems to be what a company would want to do to improve the economics of a CCS project? Can EPA explain the difference between “sell” and “use”? EPA: We believe that all planned projects (that we are aware of) will generate additional revenues fro m capture CO2. Selling the CO2 to an offsite user for EOR is an example of “sell”, while on-site chemical productio n (e.g., urea) is an example of “use”. Deleted: as Comment [A15]: Add Boundary Dam? EPA: Yes, agreed Deleted: , with some financial assistance from DOE,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 28 of 373 Hydrogen Energy California, LLC (HECA), is proposing to build a plant similar to TCEP in western Kern Count y, California. The HECA plant is an IGCC plant fueled by coal and petroleum coke that will produce 300 MW of powe r and will capture CO 2 for use in enhanced oil recovery (EOR) operations. They expect to capture approximately 90 percent of the produced CO 2 . The above examples suggest that project developers who are incorporating CCS generally considered two variants : either a partial CCS system or a full CCS system (i.e., usually 90
percent capture or greater) . Therefore, the EPA considered both options. In assessing whether the cost of a certain option i s reasonable, the EPA first considered the appropriate frame of

reference . Power companies often choose the lowest cost form of generation when determining what type of new genera tion to

build. Based on both the EIA modeling and utility IRPs, there appears to be a general acceptance that the lowest cost form of

new power generation is NGCC. Many states find value in coal investments and have policies and incentives to encourage coal energy ge neration. Utility IRPs (as well as comments on the April 2012 proposal) suggest that many companies also find value in othe r factors, Deleted: ,

Deleted: “full capture” and “partial capture” CCS technologies.

Deleted: Coal plants implementing “full capture” CCS plan to achieve large reductions in CO 2 pollution - usually 90 percent or more, though it is not clear whether the units being developed today will be able to achieve full capture at the outset..¶ Comment [A16]: This statement should further clarify whether these facilities will, at a minimum , achieve “partial capture” at the outset.

EPA: This has been deleted to avoid confusion. Comment [A17]: Is EPA confident on this statement? Will this be read as EPA casting doubt on the viability of the project TCEP or HECA project?

EPA: This has been deleted to avoid confusion.

Deleted: referenc Deleted: both Comment [A18]: Suggested edit to enhance clarity. EPA: Agreed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 29 of 373 such as fuel diversity, and are often willing to pa y a premium for it. Utility IRPs suggest that a range of techno logies can

meet the preference for fuel diversity from a dispatchab le form of generation that can provide intermediate or base -load power , including coal without CCS, coal with CCS and nucle ar. Biomassfired power generation and geothermal power generat ion are other technologies that are dispatchable and that could p otentially meet this objective. These technologies all cost si gnificantly more than natural gas-fired generation, which range s from a levelized cost of electricity (LCOE) 7 of $ 59 /MWh to $86/MWh, depending upon assumptions about natural gas prices . In assessing whether the cost of coal with CCS would h ave an unreasonable impact on the cost of power generation , the EPA believes it is appropriate to compare coal with CCS to this range of non-natural gas-fired electricity generati on options.

Based on data from the EIA and the DOE National Ene rgy and Technology Laboratory (NETL), the EPA believes that the

levelized cost of technologies other than coal with CCS and N GCC range from $80/MWh to $130/MWh. These include nuclear from

7 The levelized cost of electricity is an economic as sessment of the cost of electricity from a new generating unit or plant, including all the costs over its lifetime: initial investment, operations and maintenance, cost of fuel, and cost of capital. The LCOE value presented here are in $2007. Deleted: this preference

Comment [A19]: It would be helpful to add some language to clarify whether these technologies are comparable, i.e., are these technologies used t o serve base-load and intermediate loads, and would they have comparable generation capacity? EPA: Agreed

Deleted: 52 Comment [A20]: Are these LCOE estimates? Should probably specify. EPA: Agreed.

Comment [A21]: Are these “levelized” costs? EPA: Yes, edited accordingly Comment [A22]: Are these LCOE estimates? Should probably specify. EPA: Yes, edited accordingly Deleted: at***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 30 of 373 $103/MWh to $114/MWh, biomass from $97/MWh to $130/ MWh, and geothermal from $80/MWh to $99/MWh.

The EPA believes t he cost of “full capture” CCS without EOR is outside the range of costs that companies are co nsidering for comparable generation and therefore should not be c onsidered

BSER for CO 2 emissions for coal-fired power plants. The EPA projects the LCOE of generation technologies with full capture

CCS to be in the range of $136/MWh to $147/MWh (without EOR
benefits)

. 8 Because these ”full capture” CCS costs without EOR are significantly above the price range of potentia l alternative generation options, the EPA believes that full capt ure CCS does

not meet the cost criterion of BSER. Finally, the EPA considered whether implementation of “partial capture” CCS should be proposed to be BSER for new fossil fuel-fired utility boilers and IGCC units.

8 The cost assumptions and technology configurations for these cost estimates are provided in the DOE/NETL “Cost a nd Performance Baseline” reports. For these cost estim ates, we used costs for new SCPC and IGCC units utilizing bitumin ous coal from the reports “Cost and Performance Baseline for Foss il Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity”, Revision 2, Report DOE/NETL-2010/1397 (November 2010) and “Cost and Performance of PC and IGCC Plan ts for a Range of Carbon Dioxide Capture”, DOE/NETL-2011/149 8, May 27, 2011. Additional cost and performance information c an be found in additional volumes that are available at http://www.netl.doe.gov/energy-analyses/baseline_st udies.html

. Deleted: at

Deleted: at

Deleted: T

Deleted: mitlitgates against determining that it is the Deleted: levelized cost of electricity ( Deleted: )

Comment [A23]: Without EOR, right? Should specify in this sentence. EPA: Agreed

Comment [A24]: Could EPA please provide estimated levelized costs for full capture project with EOR revenue and compare with other forms of generation? As stated above, CCS+EOR appears to be most likely scenario, an assessment of the economics of CCS+EOR scenario is more relevant.

EPA: Added later in more detailed cost discussion

. To make our BSER determination more robust, it is being made assuming no EOR.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 31 of 373 Partial capture CCS has been implemented successful ly in a number of facilities over many years. The Great Pla ins Synfuels Facility 9 is a coal gasification facility that has captured at least 50 percent of its produced CO 2 for use in EOR operations since 2000. Projects such as AEP Mountaineer have s uccessfully demonstrated the performance of partial capture CCS on a significant portion of their exhaust stream. The So uthern Company Kemper County Energy Facility will use part ial CCS to capture approximately 65 percent of the produced CO 2 for use in nearby EOR operations. The facility is now more tha n 75 percent complete and is expecting to begin operation in 201 4. The EPA analysis shows that the costs of partial CC S are comparable to costs of other non-NGCC generation. T he EPA projects LCOE generation ranging from $92/MWh to $110/MWh, depending upon assumptions about technology choices and the amount, if any, of revenue from sale of CO 2 for EOR. This range compares to levelized costs in a range of $80/MWh t o $130/MWh for various forms of other non-natural gas-fired el ectricity generation. When considered against the range of costs that would be incurred by projects deploying non-natural gas-fired

9 While this facility is not an EGU, it has signific ant similarities to a coal gasification combined cycle EGU, and the implementation of the partial CCS technology would be similar enough for comparison. Comment [A25]: Are there any international facilities that can be referenced here? EPA: We are still addressing this comment.

Deleted: enhanced oil recovery ( Deleted: )

Moved down [1]: When considered against the range of costs that would be incurred by projects deploying non-natural gas-fired electricity generation, the implementation costs of partial CCS are, clearly, not unreasonable. Comment [A26]: This conclusion would fit more appropriately at the end of the paragraph. Without reading the LCOE information, it is not “clearly, n ot unreasonable” EPA: Agreed

Deleted: levelized costs of electricity

Moved (insertion) [1]***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 32 of 373 electricity generation, the implementation costs of partial CCS are, clearly, not unreasonable. The projects in development for new coal-fired gene ration are few in number, and most would already meet an e mission limit based on implementation of partial CCS. As a result , a standard based on partial CCS would not have a significant i mpact on nationwide energy prices. Moreover, the fact that I GCC developers could meet the requirements of the stand ard through the use of a conventional turbine ( i.e., a syngas turbine, rather than a more advanced hydrogen turbine) reinf orces both the technical feasibility and cost basis of today’s proposal to determine that CCS with partial capture is the BSER

. Partial CCS designed to meet an emission standard o f 1,100

lb CO 2 /MWh would also achieve significant emission reduct ions, emitting on the order of 30 to 50 percent less CO 2 than a coalfired unit without CCS. Finally, a standard based on partial CCS clearly promotes implementation and further development of CCS technologies, and does so as much as , and perhaps even more
than, a standard based on a full capture CCS requirement would. After conducting a BSER analysis of the three optio ns described above, the EPA proposes that new fossil f uel-fired utility boilers and IGCC units implementing partial CCS best meets the requirements for BSER. It ensures that an y new fossil Deleted: These include nuclear at $103/MWh to $114/MWh, biomass at $97/MWh to $130/MWh, and geothermal at $80/MWh to $99/MWh. Comment [A27]: Suggest moving this information above (see insert) to improve clarity. EPA: Agreed

Deleted: more

Deleted: the EPA’s

Deleted: (

Deleted: )

Deleted: requirement***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 33 of 373 fuel-fired utility boiler or IGCC unit will achieve meaningful

emission reductions in CO 2, and it will also encourage greater use, development, and refinement of CCS technologie s. CCS technology has been adequately demonstrated, and it s implementation costs are reasonable. Therefore, the EPA is basing the standards for new fossil fuel-fired util ity boilers and IGCC units on partial CCS technology operating to a level of
1,100 lb CO 2 /MWh.

6 . What is BSER for natural gas -fired stationary combustion

turbines? We considered two alternatives in evaluating the BS ER for new fossil fuel-fired stationary combustion turbine s: (1) modern, efficient NGCC units and (2) modern, effici ent NGCC

units with CCS. NGCC units are the most common type of new fossil f uelfired units being planned and built today. The tech nology is in wide use. Nearly all new fossil fuel-fired EGUs bei ng constructed today are using this advanced, efficien t system for generating intermediate and base load power. Importantly, NGCC is an inherently lower CO 2 -emitting technology. Almost every natural gas-fired stationary combined cycle unit bu ilt in the U.S. in the last five years emits approximately 50 percent less

CO 2 per MWh than a typical new coal-fired plant of the same size. Deleted: carbon capture and storage ( Deleted: )

Deleted: fossil fuel

Deleted: baseload***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 34 of 373 The design is technically feasible, and evidence sh ows that NGCC units are currently the lowest-cost, most efficient option for new fossil fuel-fired power generation. By contrast, NGCC with CCS is not a configuration t hat is being planned and built today. The EPA considered w hether NGCC

with CCS could be identified as the BSER adequately demonstrated for new stationary combustion turbines, and we deci ded that it

could not be identified for several reasons. At thi s time, CCS has not been implemented for NGCC units, and we bel ieve there is

insufficient information to make a determination re garding the technical feasibility of implementing CCS at these types of units. The EPA is aware of only one NGCC unit that has implemented CCS on a very small portion of its exha ust stream.

This contrasts with coal units where , in addition to demonstration projects, there are several full scal e project s under construction and a coal gasification plant wh ich has been

demonstrat ing much of the technology needed for an IGCC to
captur e CO 2 for more than ten years. The EPA is not aware of any demonstrations of NGCC units implementing CCS techn ology that would justify setting a national standard. Further, the EPA does not have sufficient information on the prospects of transferring the coal-based experience with CCS to NGCC units. I n fact, CCS technology has primarily been applied to gas stream s that have a Deleted: widely

Deleted: best system of emission reductions

Comment [A28]: Is it a question of technical feasibility, as in, whether it is technically feasi ble to implement CCS with NGCC, or is it a question of overall likelihood that CCS would be implemented with NGCC. Are there are technical constraints to actually using CCS in the NGCC context? Or, are there financial and efficiency drivers involved? EPA: We have edited the text to hopefully further clarify these questions.

Deleted: e Deleted: s Deleted: has been Deleted: ing Deleted: over***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 35 of 373 relatively high to very high concentration of CO 2 (such as that from a coal combustion or coal gasification unit). The

concentration of CO 2 in the flue gas stream of a coal combustion unit is normally about four times higher than the c oncentration

of CO 2 in a natural gas-fired unit. Natural gas-fired sta tionary combustion turbines also operate differently from c oal-fired

boilers and IGCC units of similar size. The NGCC un its are more easily cycled (i.e., ramped up and down as power de mands increase and decrease). Adding CCS to a NGCC may limit the operating flexibility in particular during the freq uent startups/shut-downs and the rapid load change requiremen ts. 10 This cyclical operation, combined with the already low c oncentration

of CO 2 in the flue gas stream, mean that we can not assume that the technology can be easily transferred to NGCC without larger scale demonstration projects on units operating more like a typical NGCC. This would be true for both partial and full

capture. After considering both technology options, the EPA is proposing to find modern, efficient NGCC technology to be the BSER for stationary combustion turbines, and we are basing the
proposed standards on the performance of recently c onstructed

10 “Operating Flexibility of Power Plants with CCS”, International Energy Agency (IEAGHG) report 2012/6, June 2012. Deleted: ’t Deleted: just

Deleted: in Deleted: acting Deleted: Deleted: whether we were considering Deleted: or

Deleted: lead to uncertainty about how technically feasible CCS technology is for NGCC units absent further information. Comment [A29]: Are there references to support these statements?

EPA: A citation has been added.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 36 of 373 NGCC units. The EPA is proposing that larger units be required
to meet a standard of 1,000 lb CO 2 /MWh and that smaller units (typically slightly less efficient, as noted in com ments on the original proposal) be required to meet a standard o f 1,100 lb

CO 2 /MWh. 7. How is EPA proposing to codify the requirements?

The EPA is considering two options for codifying the requirements. Under the first option EPA is proposi ng to issue standards of performance for the respective sources within existing 40 CFR part 60 subparts. Applicable GHG st andards for electric utility steam generating units would be li sted under subpart Da and applicable GHG standards for standar ds for stationary combustion turbines would be listed unde r subpart

KKKK. In the second option, t he EPA is co-proposing to create a new subpart TTTT (as in the original proposal for t his rulemaking) and to list all GHG standards of performance for covered sources in that newly created subpart. Unlike the original proposal, the subpart would contain two di fferent categories, one for utility boilers and IGCC units and one for stationary combustion turbines.

8 . What is the organization and approach for the pro posal? This action presents the EPA’s proposed approach f or setting standards of performance for new affected f ossil fuelDeleted: Deleted: proposing to Deleted: the proposed

Deleted: T Deleted: is Deleted: also Deleted: Deleted: the option of creating Deleted: ing Deleted:

Deleted: ’s

Deleted: 7***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 37 of 373 fired electric utility steam generating units (util ity boilers) and stationary combustion turbines. The rationale f or regulating GHG emissions from the utility power sector, includ ing related regulatory and litigation background and relationsh ip to other rulemakings, is presented below in section II. The specific proposed requirements for new sources are described in detail in

section III. The rationale for reliance on a ration al basis to regulate GHG emissions from fossil fuel-fired EGUs is presented in section IV, followed by the rationale for applic ability requirements in section V. The legal requirements f or establishing emission standards are discussed in de tail in

section VI. Sections VII and VIII describe the rati onale for each of the proposed emission standards, including an explanation of the determination of BSER for new fo ssil fuelfired utility boilers and IGCC units and for natura l gas-fired stationary combustion turbines, respectively. Ratio nale for other proposed requirements is discussed in section IX. Implications for Prevention of Significant Deterioration ( PSD ) and title V programs are described in section X, an d impacts of the proposed action are described in section XI. In section XII, the agency specifically requests comments on the pr oposal. A discussion of statutory and executive order reviews is provided***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 38 of 373 in section XIII. Also published today in the Federa l Register is the notice rescinding the original April 13, 2012 p roposal. Today’s proposal outlines an approach for setting s tandards of performance for emissions of carbon dioxide for new affected fossil fuel-fired electric utility steam generating units (utility boilers) and stationary combustion turbine s. C. Does this action apply to me? The entities potentially affected by the proposed s tandards

are shown in Table 1 below.

Table 1. Potentially Affected Entities a

Category NAICS

Code Examples of Potentially Affected Entities

Industry 221112 Fossil fuel electric power generating units.

Federal Government 221112 b Fossil fuel electric power generating units owned by the federal government.

State/Local Government 221112 b Fossil fuel electric power generating units owned by municipalities.

Tribal Government 921150 Fossil fuel electric power generating units in Indian Country.

a Includes NAICS categories for source categories that own an d operate electric power generating units (including boilers and stationary combined cycle combustion turbines). b Federal, state, or local government-owned and oper ated establishments are classified according to the acti vity in which they are engaged. Deleted: Include***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 39 of 373

This table is not intended to be exhaustive, but ra ther to provide a guide for readers regarding entities like ly to be affected by this proposed action. To determine whet her your facility, company, business, organization, etc., wo uld be regulated by this proposed action, you should exami ne the applicability criteria in 40 CFR 60.1. If you have any questions regarding the applicability of this action to a par ticular entity, consult either the air permitting authority for the entity or your EPA regional representative as liste d in 40 CFR
60.4 or 40 CFR 63.13 (General Provisions). II. Background In this section we discuss climate change impacts f rom GHG emissions, both on public health and public welfare , and the science behind the agency’s conclusions. We present information
about GHG emissions from fossil-fuel fired EGUs, an d we describe the utility power sector and its changing structure . We then provide the statutory, regulatory, and litigation b ackground for this proposed rule. We close this section by discus sing how this proposed rule coordinates with other rulemakings an d describing actions to obtain stakeholder input on this topic a nd the original proposed rule. A. Climate change impacts from GHG emissions***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 40 of 373
In 2009, the EPA Administrator issued the document we refer to as the Endangerment Finding under CAA section 20 2(a)(1). 11 In the Endangerment Finding, which focused on public h ealth and public welfare impacts within the United States, th e
Administrator found that elevated concentrations of GHGs in the atmosphere may reasonably be anticipated to endange r public health and welfare of current and future generation s. We summarize these adverse effects on public health an d welfare briefly here and in more detail in the RIA. 1. Public health impacts detailed in the 2009 Endan germent Finding Anthropogenic emissions of GHGs and consequent clim ate change threaten public health in multiple aspects. By raising average temperatures, climate change increases the likelihood of
heat waves, which are associated with increased dea ths and illnesses. While climate change also leads to reduc tions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality. Climate change is expected to increase o zone pollution over broad areas of the country, includin g large population areas with already unhealthy surface ozo ne levels,

11 “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202 (a) of the Clean Air Act,” 74 Fed. Reg. 66,496 (Dec. 15, 2009) (“Endangerment Finding”). Deleted: 292***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 41 of 373 and thereby increase morbidity and mortality. Other public

health threats also stem from increases in intensit y or frequency of extreme weather associated with climat e change, such as increased hurricane intensity, increased fr equency of intense storms and heavy precipitation. Increased c oastal storms and storm surges due to rising sea levels are expec ted to cause increased drownings and other health impacts. Child ren, the elderly, and the poor are among the most vulnerable to these

climate-related health effects. 2. Public welfare impacts detailed in the 2009 Enda ngerment Finding Anthropogenic emissions of GHGs and consequent clim ate change also threaten public welfare in multiple asp ects. Climate
changes are expected to place large areas of the country at serious risk of reduced water supplies, increased w ater pollution, and increased occurrence of extreme even ts such as floods and droughts. Coastal areas are expected to face increased risks from storm and flooding damage to p roperty, as well as adverse impacts from rising sea level, such as land loss due to inundation, erosion, wetland submergence and habitat loss. Climate change is expected to result in an in crease in peak electricity demand, and extreme weather from c limate change threatens energy, transportation, and water resourc e Deleted: is

Deleted: rise***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 42 of 373 infrastructure. Climate change may exacerbate ongoi ng environmental pressures in certain settlements, par ticularly in Alaskan indigenous communities. Climate change also is very likely to fundamentally rearrange U.S. ecosystems o ver the 21 st
century. Though some benefits may balance adverse e ffects on agriculture and forestry in the next few decades, t he body of evidence points towards increasing risks of net adv erse impacts on U.S. food production, agriculture and forest pro ductivity as temperature continue s to rise. These impacts are global and may exacerbate problems outside the U.S. that raise hum anitarian, trade, and national security issues for the U.S. 3. The science upon which the Agency relies The EPA received comments in response to the April 2012 proposed NSPS rule (77 FR 22392) that addressed the scientific underpinnings of the EPA’s 2009 Endangerment Findin g and hence the proposed rule. The EPA carefully reviewed all o f those comments. It is important to place these comments i n the context of the history and associated voluminous record on this subject that has been compiled over the last few years, inc luding: 1) the process by which the Administrator reached the Endangerment Finding in 2009; 2) the EPA’s response in 2010 to t en administrative petitions for reconsideration of the Endangerment Deleted: s***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 43 of 373 Finding (the Reconsideration Denial) 12 ; and 3) the decision by the United States Court of Appeals for the District of Columbia
Circuit (the D.C. Circuit or the Court) in 2012 to uphold the Endangerment Finding and the Reconsideration Denial

. 13,14
As outlined in Section VIII.A. of the 2009 Endanger ment Finding, the EPA’s approach to providing the techni cal and

scientific information to inform the Administrator’ s judgment regarding the question of whether GHGs endanger pub lic health and welfare was to rely primarily upon the recent, major assessments by the U.S. Global Change Research Prog ram (USGCRP), the Intergovernmental Panel on Climate Change (IPCC ), and the National Research Council (NRC) of the National Aca demies. These

assessments addressed the scientific issues that th e EPA was required to examine, were comprehensive in their co verage of the GHG and climate change issues, and underwent rigoro us and exacting peer review by the expert community, as we ll as rigorous levels of U.S. government review. The EPA received

12 “EPA’s Denial of the Petitions to Reconsider the E ndangerment and Cause or Contribute Findings for Greenhouse Gas es Under Section 202(a) of the Clean Air Act, 75 Fed. Reg. 4 9,557 (Aug. 13, 2010) (“Reconsideration Denial”). 13 Coalition for Responsible Regulation, Inc. v. Envir onmental Protection Agency, 684 F.3d 102 (D.C. Cir.), reh’g en banc denied, 2012 U.S. App. LEXIS 25997, 26313 (D.C. Cir . 2012), petitions for cert. filed, No. 12-1253 (U.S. Apr. 2 013). 14 We discuss litigation history involving this rulem aking in more detail later in this section. Deleted: Coalition for Responsible Regulation, Inc. v. EPA , 684 F.3d 102 (D.C. Cir. 2012), rehearing and rehearing en banc den.

________ (“ CRR ”).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 44 of 373
thousands of comments on the proposed Endangerment Finding and responded to them in depth in an 11-volume Response to Comments
(RTC) document. 15 While the EPA gave careful consideration to all

of the scientific and technical information receive d, the agency placed less weight on the much smaller number of in dividual

studies that were not considered or reflected in th e major assessments; often these studies were published aft er the submission deadline for those larger assessments. P rimary reliance on the major scientific assessments provid ed the EPA greater assurance that it was basing its judgment o n the best available, well-vetted science that reflected the c onsensus of the climate science community. The EPA reviewed ind ividual studies not incorporated in the assessment literatu re largely to see if they would lead the EPA to change its interp retation of, or place less weight on, the major findings reflect ed in the assessment reports. From its review of individual s tudies submitted by commenters, the EPA concluded that the se studies did not change the various conclusions and judgment s the EPA drew from the more comprehensive assessment reports . The major

15 “Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air Act: EP A's Response to Public Comments,” http://www.epa.gov/climatechange/endangerment/#comm ents (“Response to Comments” or “RTC”).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 45 of 373 findings of the USGCRP, IPCC, and NRC assessments s upported the EPA’s determination that GHGs threaten the public h ealth and welfare of current and future generations. The EPA presented this scientific support at length in the Endangerme nt Finding, in its Technical Support Document (which summarized the findings
of USGCRP, IPCC and NRC) 16 and in the RTC. The EPA then reviewed ten administrative petitions for reconsideration of the Endangerment Finding in 2010 . In the Reconsideration Denial, the Administrator denied th ose petitions on the basis that the Petitioners failed to provide substantial support for the argument that the EPA should revise the Endangerment Finding and therefore their objections were not of “central relevance” to the Finding. The EPA prepare d an accompanying three-volume Response to Petitions (RT P) document to provide additional information, often more techn ical in nature, in response to the arguments, claims, and a ssertions by the petitioners to reconsider the Endangerment Find ing. 17
The 2009 Endangerment Finding and the 2010 Reconsid eration Denial were challenged in a lawsuit before the D.C. Circuit. On

16 “Technical Support Document for Endangerment and C ause or Contribute findings for Greenhouse Gases under Sect ion 202(s) of the Clean Air Act (Dec. 7, 2009), http://www.epa.gov/climatechange/Downloads/endanger ment/Endanger ment_TSD.pdf (TSD). 17 http://www.epa.gov/climatechange/endangerment/peti tions.html***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 46 of 373 June 26, 2012, the Court upheld the Endangerment Fi nding and the Reconsideration Denial, ruling that the Finding (in cluding the Reconsideration Denial) was not arbitrary or capric ious, was consistent with the U.S. Supreme Court’s decision i n Massachusetts v. EPA, which granted to the EPA the authority to regulate GHGs, 18 and was adequately supported by the

administrative record. 19 The Court found that the EPA had based

its decision on “substantial scientific evidence” a nd noted that

the EPA’s reliance on assessments was consistent wi th the

methods decision-makers often use to make a science -based judgment. 20 The Court also agreed with the EPA that the Petitioners had “not provided substantial support f or their argument that the Endangerment Finding should be re vised.” 21
Moreover, the Court supported the EPA’s reliance on the major scientific assessment reports conducted by USGCRP, IPCC, and NRC

and found that:

The EPA evaluated the processes used to develop the various assessment reports, reviewed their contents, and considered the depth of the scientifi c consensus the reports represented. Based on these evaluations, the EPA determined the assessments represented the best source material to use in

18 549 U.S. 497 (2007). 19 CRR , 684 F.3d at 117-27. 20 Id. at 121. 21 Id. at 125.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 47 of 373 deciding whether GHG emissions may be reasonably anticipated to endanger public health or welfare. 22

As the Court stated –

It makes no difference that much of the scientific evidence in large part consisted of ‘syntheses’ of individual studies and research. Eve n individual studies and research papers often synthesize past work in an area and then build upon it. This is how science works. The EPA is not requi red to re-prove the existence of the atom every time it approaches a scientific question. 23

In the context of this extensive record and the rec ent affirmation of the Endangerment Finding by the Cour t, the EPA considered all of the submitted comments and report s for the April 2012 proposed NSPS rule. As it did in the End angerment Finding, the EPA gave careful consideration to all of the

scientific and technical comments and information i n the record. The major peer-reviewed scientific assessments, how ever, continue to be the primary scientific and technical basis for the Administrator’s judgment regarding the threats to public health and welfare posed by GHGs. Commenters submitted two major peer-reviewed scient ific

assessments released after the administrative recor d concerning the Endangerment Finding closed following the EPA’s 2010

22 Id. at 120. 23 Id. at 120. Deleted: after***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 48 of 373 Reconsideration Denial: the IPCC’s 2012 “Special Re port on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation” (SREX) and the NRC’s 201 1 “Report on Climate Stabilization Targets: Emissions, Concentra tions, and Impacts over Decades to Millennia” (Climate Stabili zation
Targets). According to the IPCC in the SREX, “A changing clim ate leads to changes in the frequency, intensity, spati al extent, duration, and timing of extreme weather and climate events, and can result in unprecedented extreme weather and cli mate

events. 24 ” The SREX documents observational evidence of chan ges
in some weather and climate extremes that have occu rred globally since 1950. The assessment also provides evidence r egarding the
cause of some of these changes to elevated concentr ations of GHGs, including warming of extreme daily temperatur es, intensified extreme precipitation events, and incre ases in extreme coastal high water levels due to rising sea level. The SREX projects further increases in some extreme wea ther and climate events during the 21st century. Combined wi th increasing vulnerability and exposure of populations and asset s, changes in extreme weather and climate events have consequence s for

24 SREX, p. 7.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 49 of 373 disaster risk, with particular impacts on the water , agriculture and food security and health sectors. In the Climate Stabilization Targets assessment, th e NRC

states: Emissions of carbon dioxide from the burning of fossil fuels have ushered in a new epoch where huma n activities will largely determine the evolution of Earth’s climate. Because carbon dioxide in the atmosphere is long lived, it can effectively lock Earth and future generations into a range of impact s, some of which could become very severe. 25

The assessment concludes that carbon dioxide emissi ons will alter the atmosphere’s composition and therefore th e climate for thousands of years; and attempts to quantify the re sults of stabilizing GHG concentrations at different levels. The report also projects the occurrence of several specific cl imate change impacts, finding warming could lead to increases in heavy rainfall and decreases in crop yields and Arctic se a ice extent, along with other significant changes in precipitati on and stream flow. For an increase in global average temperature of 1 to 2 oC above pre-industrial levels, the assessment found t hat the area burnt by wildfires in western North America will li kely more than double and coral bleaching and erosion will in crease due both to warming and ocean acidification. An increas e of 3 oC

25 Climate Stabilization Targets, p. 3.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 50 of 373 will lead to a sea level rise of 0.5 to 1 meter by 2100. With an increase of 4 oC, the average summer in the United States would be as warm as the warmest summers of the past centu ry. The assessment notes that although many important aspec ts of climate change are difficult to quantify, the risk of adver se impacts is likely to increase with increasing temperature, and the risk of surprises can be expected to increase with the dura tion and magnitude of the warming. Several other National Academy assessments regardin g climate have also been released recently. The EPA h as reviewed these assessments and finds that in general, the im proved understanding of the climate system they and the tw o assessments described above present strengthens the case that G HGs are endangering public health and welfare. Three of the new NRC assessments provide estimates of projected global s ea level rise that are larger than, and in some cases more than t wice as large
as, the rise estimated in a 2007 IPCC assessment of between 0.18 and 0.59 meters by the end of the century, relative to 1990 (though the IPCC in 2007 had noted that including p oorly understood ice sheet processes could lead to an inc rease in their projections). 26 While these three NRC assessments continue

26 Climate Stabilization Targets; “National Security Implications for U.S. Naval Forces” (2011) (National Security Im plications); Deleted: Three of the new NRC assessments provide estimates of projected global sea level rise that at least are twice as large as or more than larger than, and in some cases more than twice as large as, the rise estimated in a 2007 IPCC assessment of between 0.18 and 0.59 meters by the end of the century, relative to 1990 (though the IPCC in 2007 had noted that including poorly understood ice sheet processes could lead to an increase in those projections).1990 (and noting that including poorly understood ice sheet processes would likely increase those projections).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 51 of 373 to recognize and characterize the uncertainty inher ent in accounting for ice sheet processes, these revised e stimates strongly support and strengthen the existing findin g that GHGs are reasonably anticipated to endanger public healt h and welfare. Other key findings of the recent assessmen ts are described briefly below:

One of these assessments projects a global sea level rise of 0.5 to 1.4 meters by 2100, which is sufficient t o lead to rising relative sea level even in the northern stat es. 27 Another assessment considers potential impacts of sea level rise and
suggests that “the Department of the Navy should ex pect roughly 0.4 to 2 meters global average sea-level rise by 21 00. 28 This assessment also recommends preparing for increased needs for

humanitarian aid ; responding to the effects of climate change in geopolitical hotspots , including possible mass migrations ; and addressing changing security needs in the Arctic as sea ice

retreats. A third NRC assessment found that it woul d be “prudent for security analysts to expect climate surprises i n the coming

“Sea Level Rise for the Coasts of California, Orego n, and Washington: Past, Present, and Future” (2012) (Sea Level Rise). 27 Sea Level Rise, p. 4

. 28 National Security Implications, p. 9. Deleted: , Deleted: responses***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 52 of 373 decade . . . and for them to become progressively m ore serious and more frequent thereafter[.]” 29
Another NRC assessment finds that “the magnitude an d rate of the present greenhouse gas increase place the cl imate system

in what could be one of the most severe increases i n radiative forcing of the global climate system in Earth histo ry.” 30 This

assessment finds that CO 2 concentrations by the end of the

century , without a reduction in emissions, is projected to

increase to levels that Earth has not experienced for more than 30 million years

. 31 The report draws potential parallels with

non-linear events such as the Paleo-Eocene Thermal Maximum, a rapid global warming event about 55 million years a go associated with mass extinctions and other disruptions. The as sessment notes that acidification and warming caused by GHG increases similar to the changes expected over the next hundr ed years likely caused up to four of the five major coral re ef crises of the past 500 million years. Similarly, another NRC assessment finds that “[t]he chemistry of the ocean is changing at an unpreceden ted rate and magnitude due to anthropogenic carbon dioxide emiss ions; the

29 “Climate and Social Stress: Implications for Secur ity Analysis” (2012), p.3. 30 “Understanding Earth’s Deep Past: Lessons for Our Climate Future” (2011), p.138. 31 Ibid, p. 1. Deleted: )

Deleted: will likely exceed

Deleted: not present Deleted: in the Deleted: since the formation of the Antarctic and Greenland Ice Sheets. Deleted: The assessment examines evidence from past climatic changes and concludes that the climate could be more sensitive to greenhouse gases, the tropical surface temperatures less well regulated, sea level rise higher, and the oceans more anoxic than current expectations.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 53 of 373
rate of change exceeds any known to have occurred f or at least the past hundreds of thousands of years.” 32 The assessment notes that the full range of consequences is still unknow n, but the risks “threaten coral reefs, fisheries, protected s pecies, and

other natural resources of value to society.” 33
Comments were submitted in support of the Endangerm ent Finding , which provid ed additional documentation showing that climate change is a threat to public health and wel fare. Commenters provided several individual studies and documentation of observed or projected climate changes of local i mportance or concern to commenters. The EPA appreciates these co mments, but as previously stated, we place lesser weight on ind ividual studies than on major scientific assessments. Local observed changes must be assessed in the context of the broa der scientific picture, as it is more difficult to draw robust conclusions regarding climate change over short tim e scales and in small geographic regions. The EPA plans to continue relying on the major asse ssments by the USGCRP, the IPCC, and the NRC. Studies from these bodies

address the scientific issues that the Administrato r must examine, represent the current state of knowledge o n the key

32 “Ocean Acidification: A National Strategy to Meet the Challenges of a Changing Ocean” (2010), p. 5. 33 Id. Deleted: and Deleted: ing

Deleted: they***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 54 of 373 elements for the endangerment analysis, comprehensi vely cover and synthesize thousands of individual studies to o btain the majority conclusions from the body of scientific li terature and undergo a rigorous and exacting standard of review by the peer expert community and U.S. government. Several commenters argued that the Endangerment Fin ding

should be reconsidered or overturned based on those commenters’ reviews of specific climate science literature, inc luding publications that have appeared since the EPA’s 201 0 Reconsideration Denial. Some commenters presented t heir own compilations of individual studies and other docume nts to support their assertions that climate change will h ave beneficial effects in many cases and that climate i mpacts will

not be as severe or adverse as the EPA , and the assessment

report s upon which the EPA relied, have stated. Some commenters also concluded that U.S. society will easily adapt to climate change and that it therefore does not threaten publ ic health and welfare, and some commenters questioned the Endange rment Finding based on a 2011 EPA Inspector General’s report.

The EPA reviewed the submitted information and foun d that overall, the commenters’ critiques of the rule’s sc ientific

basis were addressed in the EPA’s response to comments for the 2009 Endangerment Finding, the EPA’s responses in t he 2010 Deleted: a certain USGCRP 2009

Deleted: the EPA had addressed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 55 of 373
Reconsideration Denial, or the D.C. Circuit’s 2012 decision upholding the EPA’s 2009 Endangerment Finding. The EPA nonetheless carefully reviewed these comments and a ssociated documents and found that nothing in them would chan ge the conclusions reached in the Endangerment Finding. Th ese recent publications submitted by commenters, and any new i ssues they

may present , do not undermine either the significant body of scientific evidence that has accumulated over the y ears or the conclusions presented in the substantial peer-revie wed
assessments of the USGCRP, NRC, and IPCC.

One commenter submitted e-mails between climate cha nge researchers from the period 1999 to 2009 that were surreptitiously obtained from a University of East Anglia server in 2009 and publicly released in 2011. According to the commenter, these e-mails showed that the climatolog ists distorted their research results to prove that clim ate change

causes adverse effects. The EPA reviewed these emai ls and found that they raised no issues that Petitioners had not already raised concerning other emails from the same incide nt, released in 2009. The commenter’s unsubstantiated assumption s and subjective assertions regarding what the e-mails pu rport to show about the state of climate change science is not ad equate Deleted: Circuit Deleted: in its Deleted: to uphold

Deleted: and Deleted: that the EPA Deleted: that are extracted from them***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 56 of 373 evidence to challenge the voluminous and well-docum ented body of science that underpins the Administrator’s Endanger ment Finding. Some commenters argued for reconsideration based on uncertainty regarding climate science. However, the EPA made the decision to find endangerment with full and explici t recognition of the uncertainty involved, stating that “[t]he Ad ministrator acknowledges that some aspects of climate change sc ience and the projected impacts are more certain than others.” 34 The D.C. Circuit subsequently noted that “the existence of s ome uncertainty does not, without more, warrant invalid ation of an endangerment finding.” 35
Some commenters also argued that the U.S. will adap t to climate change impacts and that therefore climate c hange impacts pose no threat. However, the D.C. Circuit, in CRR , held that considerations of adaption are irrelevant to the En dangerment determination. The Court stated, “These contentions are foreclosed by the language of the statute and the S upreme
Court's decision in Massachusetts v. EPA ” because “predicting society’s adaptive response to the dangers or harms caused by

34 74 FR 66524. 35 CRR , 684 F.3d at 121. Deleted:

.

Comment [A30]: Please check citations to this case; although abbreviated here, it is fully spelle d out in later footnotes 89 and 97. EPA: We are still addressing this comment.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 57 of 373 climate change” does not inform the “scientific jud gment” that the EPA is required to make regarding an Endangerme nt Finding. 36
Some commenters raised issues regarding the EPA Ins pector General’s report, Procedural Review of EPA’s Greenhouse Gases Endangerment Finding Data Quality Processes

. 37 These commenters mischaracterized the report’s scope and conclusions and thus

overstate d the significance of the Inspector General’s procedural recommendations. Nothing in the Inspecto r General’s report questions the scientific validity of the End angerment Finding, because that report did not evaluate the s cientific basis of the Endangerment Finding. Rather, the Insp ector General offers recommendations for clarifying and standardi zing internal procedures for documenting data quality and peer re view processes when referencing existing peer reviewed s cience in the

EPA actions. 38

36 Id. at 117. The EPA took a similar position in the Endangerment Finding, in which we responded to simi lar comments regarding society’s ability to adapt to climate cha nge by stating: “Risk reduction through adaptation and GHG mitigation measures is of course a strong focal area of scient ists and policy makers, including the EPA; however, the EPA considers adaptation and mitigation to be potential responses to endangerment, and as such has determined that they are outside the scope of the endangerment analysis.” 74 FR 6651 2. 37 Report No. 11-P-0702 (September 26, 2011). 38 Unrelated to the Endangerment Finding and its vali dation by the Court, the EPA has made progress towards implem enting the recommendations from the Inspector General

. Deleted: OIG***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 58 of 373 In addition, some commenters argued that the Endang erment Finding should be overturned because of the carbon dioxide fertilization effect, that is, the proposition that increased amounts of carbon dioxide can spur growth of vegeta tion.
However, these commenters did not show how the scie nce they provide on the subject differs from the carbon diox ide fertilization science already considered by the Adm inistrator in the Endangerment Finding or how the existence of so me benefits

from the carbon dioxide fertilization effect could outweigh the numerous negative impacts of climate change. In sum, the EPA reviewed all of the comments purpor ting to refute the Endangerment Finding to determine whethe r they provide evidence that the Administrator’s judgment that climate change endangers public health and welfare was flaw ed, because the Administrator misinterpreted the underlying ass essments, because the science in new peer reviewed assessment s differs from that in previous assessments, or because new i ndividual studies provide compelling reasons for the EPA to c hange its interpretation of, or place less weight on, the maj or findings reflected in the assessment reports. In all cases, the

commenters failed to demonstrate that the science t hat the

Administrator relied on was inaccurate or that the additional

information from the commenter is of central relevance to the Deleted: either

Deleted: the science***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 59 of 373 Administrator’s judgment regarding endangerment. For these reasons, the commenters on the original proposal th at criticized the Endangerment Finding have not provided a suffic ient basis to cast doubt on the Finding.

B. GHG emissions from fossil fuel-fired EGUs Fossil fuel-fired electric utility generating units are by far the largest emitters of GHGs, primarily in the form of CO 2 , among stationary sources in the U.S., and among fos sil fuelfired units, coal-fired units are by far the larges t emitters.

This section describes the amounts of those emissio ns and places

those amounts in the context of the national invent ory of GHGs. The EPA prepares the official U.S. Inventory of Gre enhouse

Gas Emissions and Sinks 40 (the U.S. GHG Inventory) to comply with

commitments under the United Nations Framework Conv ention on Climate Change (UNFCCC). This inventory, which incl udes recent trends, is organized by industrial sectors. It prov ides the information in Table 2 below, which presents total U.S. anthropogenic emissions and sinks of GHGs, includin g CO 2 emissions, for the years 1990, 2005 and 2011. 41

40 “Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990 – 2011”, Report EPA 430-R-13-001, United States Envir onmental Protection Agency, April 15, 2013. 41 Sinks are a physical unit or process that stores G HGs, such as forests or underground or deep sea reservoirs of ca rbon dioxide. Deleted: 39***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 60 of 373 Table 2. U.S. GHG Emissions and Sinks by Sector (te ragram carbon dioxide equivalent (Tg CO 2 Eq.)) 42

SECTOR 1990 2005 2011

Energy 5,267.3 6,251.6 5,745.7

Industrial Processes 316.1 330.8 326.5

Solvent and Other Product Use 4.4 4.4 4.4 Agriculture 413.9 446.2 461.5
Land Use, Land-Use Change and Forestry 13.7 25.4 36.6

Waste 167.8 136.9 127.7

Total Emissions 6,183.3 7,195.3 6,702.3
Land Use, Land-Use Change and Forestry (Sinks) (794.5) (997.8) (905.0)
Net Emissions (Sources and Sinks) 5,388.7 6,197.4 5,797.3

Total fossil energy-related CO 2 emissions (including both stationary and mobile sources) are the largest cont ributor to total U.S. GHG emissions, representing 78.7 percent of total 2011 GHG emissions. In 2011, fossil fuel combustion by the electric power sector –-entities that burn fossil f uel and whose primary business is the generation of electricity – - accounted

42 From Table 2-3 of “Inventory of U.S. Greenhouse Ga s Emissions and Sinks: 1990 – 2011”, April 15, 2013, EPA 430-R- 13-001.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 61 of 373
for 39.6 percent of all energy-related CO 2 emissions. Table 3 below presents total CO 2 emissions from fossil fuel-fired EGUs, for years 1990, 2005 and 2011. 43

Table 3. U.S. GHG Emissions from Generation of Elec tricity from Combustion of Fossil Fuels (Tg CO 2 Eq.)

We are aware that nitrous oxide (N 2 O) and, to a lesser
extent, methane (CH 4 ) may be emitted from fossil fuel-fired EGUs,

43 Note that for the purposes of reporting national G HG emissions under the UNFCCC, the U.S. GHG Inventory is calcula ted using internationally accepted methodological guidance fr om the Intergovernmental Panel on Climate Change (IPCC). I n accordance with IPCC guidance, CO 2 emissions from combustion of biogenic feedstocks are not reported in the energy sector, b ut are instead reported separately as a "Memo item" in the U.S. GHG Inventory. Consistent with the IPCC guidance, any c arbon stock changes related to the use of biogenic feedstocks i n the energy sector, and the CO 2 emissions associated with those carbon stock changes, are accounted for under the forestry and/o r agricultural sectors of the U.S. GHG Inventory. Att ribution of CO 2 emissions from the combustion of biogenic feedstoc ks by stationary sources in the energy sector to the fore stry and/or agricultural sectors, in the context of U.S. GHG em issions reporting to the UNFCCC, should not be interpreted as an indication that such emissions are “carbon neutral. ” GHG EMISSIONS 1990 2005 2011

Total CO 2 from fossil fuel combustion EGUs 1,820.8 2,402.1 2,158.5

- from coal 1,547.6 1,983.8 1,722.7 - from natural gas 175.3 318.8 408.8 - from petroleum 97.5 99.2 26.6***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 62 of 373 especially from coal-fired circulating fluidized be d (CFB) combustors and from units with selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) systems

installed for NO X control. The estimated emissions for N 2 O and

CH 4 from fossil fuel-fired EGUs are about 17.9 and 0.4 Tg of CO 2 equivalent in 2011, respectively, which is about 0. 8 percent of

total CO 2 equivalent emissions from fossil fuel-fired electr ic power generating units. However, we are not proposi ng separate

N 2 O or CH 4 emission limits or an equivalent CO 2 emission limit in today’s notice because we lack more precise data on the quantity

of these emissions and information on cost-effectiv e controls. We request comment on this approach and we solicit information about the quantity of N 2 O and CH 4 emissions from these affected sources and possible controls. C. The utility power sector and how its structure i s changing 1. Utility power sector. The majority of power in the U.S. is generated from the combustion of coal, natural gas and other fossil fu els. Natural gas-fired EGUs typically use one of two tec hnologies. NGCC units first generate power from a combustion t urbine (the combustion cycle). The unused heat from the combust ion turbine is then routed to a Heat Recovery Steam Generator ( HRSG) which generates steam which is used to generate power usi ng a steam Deleted: Natural gas combined cycle ( Deleted: )***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 63 of 373 turbine (the steam cycle). The combining of these g eneration cycles increases the overall efficiency of the syst em. Simple cycle combustion turbines only use a single combustion turbine to produce electricity (i.e., th ere is no heat recovery). The power output from these simple cycle combustion turbines can be easily ramped up and dow n making them ideal for “peaking” operations. Coal-fired utility boilers are primarily either pul verized
coal (PC) boilers or fluidized bed (FB) boilers. At a PC boiler, the coal is crushed (pulverized) into a powder in o rder to increase its surface area. The coal powder is then blown into a boiler and burned. In a coal-fired boiler using flu idized bed combustion, the coal is burned in a layer of heated particles suspended in flowing air. Power can also be generated using gasification tech nology. An IGCC unit gasifies coal to form a syngas compose d of carbon monoxide (CO) and hydrogen (H 2 ), which can be combusted in a combined cycle system to generate power. 2. Changing structure of the power sector a. Technological developments and costs Since the April 2012 proposal, a few coal-fired uni ts have reached the advanced stages of construction and dev elopment, which suggests that setting a separate standard for new fossil Deleted: integrated gasification combined cycle ( Deleted: )***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 64 of 373 fuel-fired boilers and IGCC units is appropriate. P rogress on Southern Company's Kemper County Energy Facility, w hich will deploy IGCC with partial CCS, has continued, and th e project is now over 75% complete. Additionally, two other proj ects, Summit Power's Texas Clean Energy Project (TCEP) and the H ydrogen Energy California Project (HECA) – both of which wi ll deploy

IGCC with CCS – continue to move forward. The EIA m odeling projects that coal-fired power generation will rema in the single largest portion of the electricity sector beyond 20 30. The EIA modeling also projects that few, if any, new coal-f ired EGUs

would be built in this decade and that those that a re built

would have CCS. 44 Continued progress on these projects is consistent with the EIA modeling that suggests that a small number of coal-fired power plants may be constructe d. The primary reasons for this rate of current and projec ted future development of new coal projects include highly com petitive natural gas prices, lower electricity demand, and i ncreases in the supply of renewable energy.

44 Even in its sensitivity analysis that assumes higher natural gas prices and electricity demand , EIA does not project any additional coal beyond its reference case until 202 3, in a case where power companies assume no GHGs emission limit ations, and until 2025 in a case where power companies do assume GHGs emission limitations. Comment [A31]: EPA regulations, such as MATS, are not also a factor? EPA: MATS has almost no impact on the cost of a new coal

- fired unit.

Deleted: any sensitivity analysis in whichthat Deleted: s***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 65 of 373 Natural gas prices have decreased dramatically and generally stabilized in recent years, as new drilli ng techniques have brought additional supply to the marketplace a nd greatly increased the domestic resource base. As a result, natural gas prices are expected to be competitive for the fores eeable future and EIA modeling and utility announcements confirm that utilities are likely to rely heavily on natural gas to meet new demand for electricity generation. On average, as d iscussed below, the cost of generation from a new natural-ga s fired power plant (a NGCC unit) is expected to be significantly lower than the cost of generation from a new coal-fired power plant. 45
Other drivers that may influence decisions to build new power plants are increases in renewable energy supp lies, often due to state and federal energy policies. Many stat es have adopted renewable portfolio standards (RPS), which require a certain portion of electricity to come from renewab le energy sources such as solar or wind. The federal governme nt has also adopted incentives for electric generation from ren ewable energy sources and loan guarantees for new nuclear power p lants. Due to these factors, the EIA projections from the last several years show that natural gas is likely to be the most

45 Levelized Cost of New Generation Resources in the Annual Energy Outlook 2011 http://www.eia.gov/forecasts/aeo/electricity_genera tion.html

. Deleted: ,

Deleted: natural gas combined cycle ( Deleted: ) Comment [A32]: The weblink provided in the footnote does not appear to work. Please provide a publicly accessible link to the report.

EPA: Weblink has been revised.

Comment [A33]: Please provide references to the projections.

EPA: Added references.

Deleted: http://205.254.135.24/oiaf/a eo/electricity_generation.html***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 66 of 373 widely-used fossil fuel for new construction of ele ctric generating capacity through 2020, along with renewa ble energy, nuclear power, and a limited amount of coal with CC S. 46

b. Energy sector modeling Various energy sector modeling efforts, including projections from the EIA and the EPA, forecast tren ds in new power plant construction and utilization of existin g power plants that are consistent with the above-described technological developments and costs. The EIA forec asts the structure and developments in the power sector in i ts annual report, the Annual Energy Outlook (AEO). These repo rts are based on economic modeling that reflects existing policy and regulations, such as state RPS programs and federal tax credits

for renewables. 47 The current report, AEO 2013 48 , shows that although some coal-fired power plants are currently under construction and expected to begin operation in the next several years (referred to as “planned”), in the reference case, no new model-projected (“unplanned”) conventional coal-fired capacity

46 http://www.eia.gov/forecasts/aeo/pdf/0383(2013).pd f ; http://www.eia.gov/forecasts/aeo/pdf/0383(2012).pd f ;http://prod-http-80-800498448.us-east1.elb.amazonaws.com/w/images/6/6d/0383%282011%29.pd f

. 47 http://www.eia.gov/forecasts/aeo/chapter_legs_regs .cfm. 48 Energy Information Adminstration’s Annual Energy O utlook for 2013, Final Release available at http://www.eia.gov/forecasts/aeo/index.cfm. Deleted: Energy Information Agency ( Deleted: )

Deleted: and***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 67 of 373 will come online after 2012, and through 2035

. Instead, according to the AEO 2013, the vast majority of new generating capacity will be either natural gas-fired or renewa ble, with a very small amount of new coal with CCS that is incl uded in the AEO reference case in response to Federal and State incentives. The EIA projections from the last several years sho w that natural gas is likely to be the most widely-used fo ssil fuel for new construction of electric generating capacity th rough 2020. 49
However, coal will remain an important part of the fuel mix for power generation, particularly for existing sources . Modeling from both the EIA and the EPA predict that coal-fir ed generation will remain the largest single source of electricit y in the U.S. through 2040. In the EIA’s AEO 2013, coal will supp ly 39 percent of all electricity in both 2020 and 2025. The AEO 2013 projects the need for 25.9 GW of addit ional

base load or intermediate load generation capacity by 2020 ( this includes projects that are under development (i.e., being constructed or in advance planning) and model-proje cted nuclear, coal, and NGCC projects). The vast majority of this new electric capacity (22.5 GW) is already under development (un der construction or in advanced planning); it includes about 6.1 GW of new coal-fired capacity, 5.5 GW of new nuclear c apacity, and

49 Annual Energy Outlook 2010, 2011, 2012, and 2013. Deleted: no new model-projected (“unplanned”) coal-fired capacity will come online after 2012. Deleted:

Deleted: with a very small amount of new coal with CCS that is included in the AEO reference case in response to Federal and State incentives.

Deleted: Energy Information Administration ( Deleted: )

Deleted: 50

Deleted: baseload***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 68 of 373 10.9 GW of new NGCC capacity. The EPA believes that most current fossil fuel-fired projects are already designed to meet limits consistent with today’s proposal (or they have alre ady commenced construction and are thus not impacted by today’s n otice). The AEO 2013 also projects an additional 3.4 GW of new base load capacity additions, which are model-projected (unpl anned). This consists of 3.1 GW of new NGCC capacity, and 0.3 GW of new coal equipped with CCS (incentivized with some governmen t funding). Therefore, the AEO 2013 projection suggests that th is proposal would only impact small amounts of new power genera ting capacity through 2020, all of which is expected to already m eet the proposed emissions standards without incurring furt her control costs. In AEO 2013, this is also true through 2030, where new model-projected (unplanned) intermediate and base load capacity is expected to be compliant with the proposed stand ard without incurring further control costs (48.2 GW of NGCC an d 0.3 GW of coal with CCS, cumulative). The EPA modeling using the Integrated Planning Mode l (IPM), a detailed power sector model that the EPA uses to support power sector regulations, also shows limited future const ruction of Deleted: baseload

Deleted: s

Deleted: baseload***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 69 of 373 new coal-fired power plants under the base case. 51 The EPA’s projections from IPM can be found in the RIA. c. Integrated Resource Plans The trends in the power sector described above are also apparent in publicly available long-term resource p lans , termed

IRPs. The EPA has reviewed publicly available IRPs from a range of companies (e.g., varying in size, location, curr ent fuel mix), and these plans are generally consistent with both EIA and EPA modeling projections. Companies seem focused on demand-side management programs to lower future electricity dem and and mostly reliant on a mix of new natural gas-fired ge neration and renewable energy to meet increased load demand and to replace retired generation capacity. Notwithstanding this clear trend towards natural ga s-fired generation and renewables, many of the IRPs raise f uel diversity concerns and include options to diversify new gener ation capacity beyond natural gas and renewable energy. S everal IRPs indicate that companies are considering new nuclear generation, including either traditional nuclear power plants o r small modular reactors, and new coal-fired generation cap acity with

51 http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation. Deleted: many power companies’ Deleted: – Deleted: Integrated Resource Plans ( Deleted: ) Deleted: - of many power companies***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 70 of 373 and without CCS technology.Based on these IRPs, the EPA acknowledges that a small number of new coal -fired power plants may be built in the near future. While this is contrary to the economic modeling predictions, the Agency understan ds that economic modeling may not fully reflect the range o f factors that a particular company may consider when evaluat ing new generation options, such as fuel diversification. B y the same token, as discussed below, it is possible that some of this potential new coal-fired construction may occur bec ause developers are able to design projects that can pro vide competitively priced electricity for a specific geo graphic region. D. Statutory background

Section 111 of the Clean Air Act sets forth the standards

of performance for new sources ( NSPS ) program , and with this

program, establishes mechanisms for regulating emissions of air pollutants from stationary sources that are key in this rulemaking

. 52 As a preliminary step to regulation, the EPA must list categories of stationary sources that the Admi nistrator, in his or her judgment, finds “cause[], or contribute[ ]

52 CAA §111(b)(1)(A). The EPA has regulated more than 60 stationary source categories under CAA section 111. See generally 40 CFR subparts D-MMMM. Comment [A34]: Please add a reference for this block quote. EPA: This paragraph was mistakenly formatted as a block quote. It is not and it has been changed to the proper format. Has EPA considered referencing the Minnesota PUC’s recent decision on Great River Energy’s resource plan? EPA: We are still considering this comment. Deleted: ¶ Deleted: fossil fuel

Deleted: ( Deleted: Standards Deleted: Performance Deleted: New Deleted: Sources Deleted: or Deleted: ) Comment [A35]: EPA previously made endangerment findings for Subpart Da and KKKK sources when they were originally listed. citations to those should be added in this FN. EPA: We are still considering this comment. Deleted: to

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 71 of 373 significantly to, air pollution which may reasonabl y be anticipated to endanger public health or welfare.” Once the EPA has listed a source category, the EPA proposes and then promulgates “standards of performance” for “new sources” in the category. 53 A “ new source” is “any stationary
source, the construction or modification of which is commenced

after ,” in general, the date of the proposal. 54 A modification is “any physical change ... or change in the method of operation ... which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted .” 55 The EPA, through regulations, has determined that certain types of c hanges are exempt from consideration as a modification. 56 An existing facility is also considered a new source if it unde rtakes a “reconstruction,” which is the replacement of compo nents to such an extent that the capital costs of the new equipme nt or components exceed 50 percent of what is believed to be the cost of a completely new facility. 57 In establishing standards of

53 CAA §111(b)(1)(B). 54 CAA §111(a)(2). 55 CAA §111(a)(4). 56 40 CFR 60.2, 60.14(e). 57 40 CFR 60.15. Deleted: New Deleted: include sources that Deleted: “commence[]” either “ Deleted: ” Deleted: “ Deleted: ”

Deleted: ,” unless it is a specific type of change, Deleted: , such as installation of pollution control projects

Deleted: , Deleted: Deleted: , Deleted: CAA, §111(a)(4);***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 72 of 373 performance, the EPA has significant discretion to create subcategories based on source type, class or size. 58

Clean Air Act section 111(a)(1) defines a “standard of performance” as

a standard for emissions of air pollutants which reflects the degree of emission limitation achievab le through the application of the best system of emiss ion reduction which (taking into account the cost of achieving such reduction and any nonair quality hea lth and environmental impact and energy requirements) t he Administrator determines has been adequately demonstrated.

This definition makes clear that the standard of performance must be based on control s that constitute “ the best system of emission reduction

... adequately demonstrated ” (BSER).

59 The standard that the EPA develops, based on the B SER, is commonly a numerical emissions limit, expressed as a performance level (e.g., a rate-based standard). Generally, the EPA does not prescribe a particular technological system that mu st be used to comply with a standard of performance. Rather, sour ces generally can select any measure or combination of measures that will

achieve the emissions level of the standard

.

58 CAA, §111(b)(2). 59 As noted, we generally refer to this system of cont rol as the best system of emission reduction, or BSER, but w e may occasionally refer to it as the “best demonstrated system.” In the past, this level of control was frequently refe rred to as the “best demonstrated technology” (BDT). Deleted: We call this level of

Deleted: equivalent or greater control of Comment [A36]: Has EPA considered adding examples of other NSPS that do prescribe a particular technological system? EPA: We are still considering this comment.

Deleted: W Deleted: this level of control***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 73 of 373 Regarding other titles in the CAA, this rulemaking has implications for EGUs and other stationary sources in the CAA PSD program under Title I, part C, and the operatin g permits program under Title V. We discuss these implication s in section

X of this preamble

. E. Regulatory and litigation background The EPA initially included fossil fuel-fired EGUs ( which includes EGUs that burn fossil fuel including coal, gas, oil and petroleum coke and that use different technologies, including boilers and combustion turbines) in a category that it listed under section 111(b)(1)(A), and the EPA promulgated the first set of standards of performance for EGUs in 1971, c odified in subpart D. 60 As discussed in Section IV.D. of this preamble , the EPA has revised those regulations, and in some inst ances, revised the subparts, several times over the ensuin g decades. None of these rulemakings or codifications, however , have constituted a new listing under CAA § 111(b)(1)(A). In 1979, the EPA revised subpart D of 40 CFR part 60 ; as part of this revision, the EPA formed subpart Da an d promulgated

60 “Standards of Performance for Fossil-Fuel-Fired St eam Generators for Which Construction Is Commenced Afte r August 17, 1971,” 36 Fed. Reg. 24875 (Dec. 23, 1971) codified at 40 CFR 60.40-46; 36 Fed. Reg. 5931 (Mar. 31, 1971). Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 74 of 373 NSPS for electric utility steam generating units. 61 These NSPS on June 11, 1979 apply to units capable of firing more than 73 megawatts (MW) (250 MMBtu/h) heat input of fossil f uel that commenced construction, reconstruction, or modifica tion after September 18, 1978. The NSPS for EGUs also apply to industrialcommercial-institutional cogeneration units that se ll more than 25 MW and more than one-third of their potential ou tput capacity to any utility power distribution system. The EPA promulgated amendments to subpart Da in 200 6, resulting in new criteria pollutant limitations for EGUs (the
2006 Final Rule). 62 The 2006 Final Rule did not establish standards of performance for GHG emissions. Two gro ups of petitioners – 13 governmental entities and three en vironmental groups – filed petitions for judicial review of thi s rule by the

D.C. Circuit. 64 These petitioners contended, among other issues ,

61 “Standards of Performance for Electric Utility Ste am Generating Units for Which Construction is Commence d After September 18, 1978 ,” 44 Fed. Reg. 33580 (June 11, 1979) 62 ”Standards of Performance for Electric Utility Ste am Generating Units, Industrial-Commercial-Institution al Steam Generating Units, and Small Industrial-Commercial-I nstitutional Steam Generating Units, Final Rule. ” 71 Fed. Reg. 9866 (Feb. 27, 2006). 64 State of New York, et al. v. EPA, No. 06–1322 . The two groups of petitioners were (1) the States of New York, Cal ifornia, Connecticut, Delaware, Maine, New Mexico, Oregon, R hode Island, Vermont and Washington; the Commonwealth of Massach usetts; the District of Columbia and the City of New York (coll ectively ‘‘State Petitioners’’); and (2) Natural Resources D efense Deleted: the most recent significant

Deleted: ,63***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 75 of 373 that the rule was required to include standards of performance

for GHG emissions from EGUs. The Court severed portions of the petitions for rev iew of

the 2006 Final Rule that related to GHG emissions. Following the U.S. Supreme Court’s 2007 decision in Massachusetts v. EPA , which gave authority to the EPA to regulate GHGs, t he D.C. Circuit remanded the 2006 Final Rule to the EPA upo n its own

motion for further consideration of the issues rela ted to GHG emissions in light of Massachusetts. The EPA did not act on that
remand. Rather, these State and Environmental P etitioners and the EPA negotiated a proposed settlement agreement that set deadlines for the EPA to propose and take final act ion on (1) a
rule under CAA section 111(b) that includes standar ds of performance for GHGs for new and modified EGUs that are subject to 40 CFR part 60, subpart Da; and (2) a rule under CAA section 111(d) that includes emission guidelines for GHGs f rom existing EGUs that would have been subject to 40 CFR part 60 , subpart Da if they were new sources. Pursuant to CAA section 1 13(g), the EPA provided for a notice-and-comment opportunity o n the proposed settlement agreement and, after reviewing the comments received, finalized the agreement in late 2010

.

Council (NRDC), Sierra Club, and Environmental Defe nse Fund (EDF)(collectively ‘‘Environmental Petitioners’’). Deleted: certain p

Comment [A37]: Insert year of settlement agreement? EPA: The settlement agreement was signed in late 2010.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 76 of 373
In June 2012, the D.C. Circuit in Coalition for Responsible Regulation, upheld the EPA’s Endangerment Finding concerning GHGs and the EPA’s companion finding that GHGs from motor vehicles contribute to the air pollution that endan gers public

health and welfare. 65 The Court also upheld standards for motor

vehicles that limited GHG emissions. 66 In addition, the Court

affirmed the EPA’s view that the CAA PSD and title V permitting requirements became applicable to GHG-emitting stationary sources when the EPA regulated GHG emissions from m otor vehicles, because PSD and title V are automatically applicable to a pollutant when that pollutant is regulated und er any part of the Act. The Court also dismissed challenges to what we refer to as the Timing Decision , 67 which established the January 2, 2011 date when the PSD and title V permitting requi rements applied to GHG-emitting stationary sources; and the Tailoring
Rule, 68 which is the EPA’s common sense approach to phasing in

65 Coalition for Responsible Regulation, Inc. v. Envir onmental Protection Agency, 684 F.3d 102 (D.C. Cir.), reh’g en banc denied, 2012 U.S. App. LEXIS 25997, 26313 (D.C. Cir . 2012), petitions for cert. filed, No. 12-1253 (U.S. Apr. 2 013). 66 "Light-Duty Vehicle Greenhouse Gas Emission Standa rds and Corporate Average Fuel Economy Standards; Final Rul e." 75 FR 25324 (May 7, 2010). 67 "Interpretation of Regulations that Determine Poll utants Covered by Clean Air Act Permitting Programs." 75 FR 17004 (April 2, 2010). 68 Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule; Final Rule. 75 FR 31514 (June 3, 2010). Deleted: CRR

Deleted: stationary source

Deleted: of the Clean Air Act

Deleted: Coalition for Responsible Regulation v. EPA , 684 F.3d 102 (D.C. Cir.), rehearing en banc den. __ F.3d __ (2012) CRR , 684 F.3d 102; "Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, Final Rule." 74 FR 66496 (December 15, 2009).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 77 of 373 GHG permitting requirements to avoid an initial inc rease in the number of PSD and title V permit applications that would overwhelm the permitting authorities’ administrativ e capacities.
In June 2012, several companies filed petitions for review of the original proposal for this rulemaking action in the D.C.

Circuit. 69 In December 2012, the D.C. Circuit dismissed these petitions on grounds that the challenged proposed r ule is not final agency action subject to judicial review. 70

In April, 2013, EPA completed rulemaking to regulat e power plants in the Mercury and Air Toxics rule (“MATS”) 71 . In this same rulemaking, EPA promulgated revised standards of performance under CAA §111(b) for criteria pollutan t emissions

from EGUs.

F. Coordination with other rulemakings

69 Las Brisas Energy Center, LLC v. Environmental Prot ection Agency, No. 12-1248, 2012 U.S. App. LEXIS 25535 (D. C. Cir. Dec. 13, 2012). 70 Las Brisas Energy Center v. EPA, No. 12-1248, Order (D.C. Cir., Dec. 13, 2012). 71 “Reconsideration of Certain New Source Issues: Na tional Emission Standards for Hazardous Air Pollutants Fro m Coal- and Oil-Fired Electric Utility Steam Generating Units a nd Standards of Performance for Fossil-Fuel-Fired Electric Utili ty, Industrial-Commercial-Institutional, and Small Indu strialCommercial-Institutional Steam Generating Units, Fi nal Rulemaking, ” 78 Fed. Reg. 24073 (April 24, 2013). Deleted: industry entities

Deleted: Las Brisas Energy Center, LLC v. EPA, No. 12-1248 and consolidated cases.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 78 of 373 EGUs are the subject of several recent CAA rulemaki ngs. 72 In general, most EPA rulemakings affecting the power s ector focus on existing sources. Therefore, few interactions ar e likely between other power sector rules and this rule, whi ch focuses only on new sources. We note that the EPA recently finalized revisions to the

MATS rule as related to new sources. 73 The revised MATS new

source emission standards for air toxics and new source performance standards for criteria pollutants , coupled with GHG performance standards in this proposed rule, provid e a clear regulatory structure for new fossil fuel-fired generation. The EPA recognizes that it is important that each o f these regulatory efforts achieves its intended environmental objectives in a common-sense, cost-effective manner consistent with the underlying statutory requirements and assu re s a reliable power system. Executive Order (EO) 13563 s tates that ‘‘[i]n developing regulatory actions and identifyin g appropriate approaches, each agency shall attempt to promote ..

. coordination, simplification, and harmonization. Ea ch agency

72 We discuss other rulemakings solely for background purposes. The effort to coordinate rulemakings is not a defen se to a violation of the CAA. Sources cannot defer complian ce with existing requirements because of other upcoming reg ulations.

73 78 FR 24073. Comment [A38]: Don’t most also have requirements for new sources too? This seems to imply that they don’t. Maybe it should say “on existing sources as well as new sources”? EPA: We prefer the language since it says “focus on existing sources” – we do not see any implication that new sources aren’t subject to regulations.

Deleted: the updated criteria pollutant

Deleted: path Comment [A39]: It is odd to refer to this as a path. Suggest revising to say structure. EPA: Agreed

Deleted: that is

Deleted: and that minimize impacts on electricity rates

Deleted: “Reconsideration of Certain New Source Issues: National Emission Standards for HazardousAir Pollutants From Coal- and OilFired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-FiredElectric Utility, IndustrialCommercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units,” April 24, 2013 ( Deleted: )***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 79 of 373 shall also seek to identify, as appropriate, means to achieve regulatory goals that are designed to promote innov ation.’’ Recent guidance from the Office of Management and B udget’s Office of Information and Regulatory Affairs has em phasized the importance of, where appropriate and feasible, the consideration

of cumulative effects in regulated industries and seeks to harmonize rules in terms of both content and timing . We believe that these recent finalized and proposed rules will allow industry to comply with its obligations as efficien tly as possible, by making coordinated investment decision s and, to the greatest extent possible, adopting integrated compl iance strategies. G. Stakeholder input The EPA extensively interacted with many different stakeholders regarding climate change, source contr ibutions, and emission reduction opportunities. These stakeholder s included industry entities, environmental organizations and many regional, state, and local air quality management a gencies, as well as the general public. As part of developing t h e original proposed rule, the EPA held five listening sessions in February

and March 2011 to obtain additional information and input from key stakeholders and the public. Each of the five s essions had a particular target audience; these were the electric power Deleted: considering

Deleted: seeking

Deleted: under these rules

Deleted: is***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 80 of 373 industry, environmental and environmental justice o rganizations, states and Tribes, coalition groups and the petrole um refinery industry. Each session lasted two hours and feature d a facilitated roundtable discussion among stakeholder representatives. The EPA asked key stakeholder grou ps to identify these roundtable participants in advance o f the listening sessions. The EPA accepted comments from the public at

the end of each session and via the electronic dock et system. 74
On May 3, 2012, the EPA announced that it would hol d two public hearings on the original proposed rule. The hearings were both held on May 24, 2012, in Washington, D.C. and Chicago, IL. Also on May 3, 2012, the EPA announced an extension of the public comment period for the original proposed rul e, until June 25, 2012. The EPA received more than 2.5 million pu blic comments on the original proposed rule. 75 While the Agency is not preparing a RTC document responding to the comments it received as part of that process, the EPA has taken into con sideration
those comments, as well as information received in the listening sessions, in developing this new proposal. III. Proposed Requirements for New Sources

74 Comments related to the listening sessions submitt ed via the electronic docket system are available at www.regul ations.gov (docket number EPA-HQ-OAR-2011-0090). 75 Those comments are available at www.regulations.go v (docket number EPA-HQ-OAR-2011-0660). Deleted: approximately

Deleted: response-to-comments***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 81 of 373 This section describes the proposed requirements in this rulemaking for new sources. Our rationale for these proposed requirements is provided in Sections IV-X of this p reamble.

A. Applicability requirements We generally refer to sources that would be subject to the standards of performance in this rulemaking as “aff ected” or “covered” sources, units, facilities, or simply as EGUs. These

sources meet both the definition of “affected” and “covered” EGUs subject to an emission standard as provided by this rule, and the requirements for “new” sources as defined u nder the provisions of CAA section 111. 1. Covered EGUs, generally Subpart Da currently defines an EGU as a boiler tha t is: 1)

“ capable of combusting ” more than 250 MMBtu/h heat input of
fossil fuel, 76 2) “ constructed for the purpose of supplying more

than one-third of its potential net- electric output capacity

... to any utility power distribution system for sale ” 77 (that is, to the grid), and 3) “ constructed for the purpose of supplying

... more than 25 MW net-electric output ” to the grid.” 78 We are proposing to define an EGU slightly differently tha n it is

76 E.g., 40 CFR 60.40Da(a)(1). 77 40 CFR 60.41Da (definition of (“Electric utility s teamgenerating unit”). 78 Id. Deleted: Affected sources

Deleted: variously

Deleted: that is

Deleted: 1/3

Deleted: , Deleted: that is Deleted: any utility power distribution system for sale.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 82 of 373 currently defined in subpart Da or in the original proposal for this rulemaking . First, we are proposing to revise the second

criteria to be met if the EGU “supplies more than one-third of

its potential electric output” to the grid instead of of the EGU

is “constructed for the purpose of supplying more than one-third

of its potential electric output capacity” to the grid

. This approach to applicability with the CO 2 standard is similar to criteria pollutant emission standards included in b oth subparts Da and KKKK that vary depending on the fuels combus ted. In this case, when EGUs do not supply more than one-third o f their potential electric output to the grid, no CO 2 emissions standard would be applicable. Second, we are proposing to revise the third criteria to be met if the EGU supplies “more than 219,000 MWh,” as opposed to “25 MW,” net-electrical output to the grid. The proposed change of 25 MW net sales to 219,000 M Wh net sales is consistent with the EPA Acid Rain Program (ARP) definition, and we have concluded that it is functionally equiv alent to the 25 MW net sales language. The 25 MW sales value has been interpreted to be the continuous sale of 25 MW of e lectricity on an annual basis, which is equivalent to 219,000 MWh . We are also proposing to revise the averaging period for electric sales from an annual basis to a three-year rolling averag e for stationary combustion turbines. Lengthening this pe riod will Deleted: and Deleted: April 2012

Deleted: use Deleted: 1/3 Deleted: their Deleted: output Deleted: ” Deleted: 1/3 Deleted: their Deleted: ” when determining applicability of the CO 2 standard.

Deleted: use***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 83 of 373

ensure that the CO 2 standards only apply to the intended
facilities, which are intermediate and base load EG Us. In addition, we are proposing to add a new applicabili ty criterion that is not currently in subpart Da for the CO 2 standard. Similar to the applicability requirements in the Mercury an d Air Toxics Standard, we are proposing that EGUs, where 10 percent or less of the heat input over a three-year period is deriv ed from a fossil fuel, are not subject to any of the proposed CO 2
standards. For the purposes of this rule, we are proposing sev eral additional changes to the way applicability is curr ently determined under subpart Da. First, we are proposin g a different definition of potential electric output from the cu rrent definition in subpart Da. To assure that the applic ability does not discourage the installation of the most efficie nt simple cycle turbines, we are proposing a definition of po tential electric output that includes “or the design electr ic output efficiency on a net output basis” as an alternative to the

default one-third efficiency value. Next, we are proposing to add “of the thermal host facility or facilities” to the definition of net-electric output. This would make applicability consistent for both facility-owned CHP and qualifyi ng thirdparty-owned CHP, since the owner of the CHP does no t need to Deleted: or which,

Comment [A40]: Something is amiss with this sentence. Suggested edits for clarification.

EPA: Sentence has been revised.

Deleted: 33 percent Deleted: default***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 84 of 373 also own the thermal host facility. Finally, consis tent with our approach in the NSPS part of the MATS rule and the original proposal for this rulemaking , we are proposing to amend the definition of a steam generating unit to include “p lus any integrated equipment that provides electricity or u seful thermal output to either the boiler or to power auxiliary e quipment” and delete the existing language “plus any integrated c ombustion turbines and fuel cells.” We are also proposing to add the additional language to the definition of IGCC and s tationary

combustion turbine.

2. CO 2 emissions only This action proposes to regulate covered EGU emissi ons of

CO 2 , and not other constituent gases of the air pollut ant GHGs. We identify the pollutant we propose to regulate as GHGs, but, again, only CO 2 emissions are subject to the proposed standard of performance.

3. Sources not subject to this rulemaking

W e are not proposing standards for certain types of

sources. These include new steam generating units and stationary

combustion turbines that sell one-third or less of their potential output to the grid, new non-natural gas-f ired stationary combustion turbines, existing sources un dertaking modifications or reconstructions, or certain projec ts under Deleted: the intent expressed in the NSPS response to comments document Deleted: April 2012

Deleted: “New” sources Deleted: CAA section 111(a)(2) defines a “new source” as “any stationary source, the construction or modification of which is commenced after publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under [CAA section 111] which will be applicable to such source.” In contrast, CAA section 111(a)(6) defines an “existing source” as “any stationary source other than a new source.” The definition of a “new source” applies according to its terms for purposes of this rulemaking. Note that w Deleted: than 1/3 Comment [A41]: What is included in this category and what is EPA’s rationale for not including such sources? Do they not fall under the Subpart Da or KKKK categories?EPA: Our intention was to exclude new liquid oilfired CC units since we have insufficient informati on to set a standard for them, we expect they will onl y be built in areas (islands, territories, remote par ts of Alaska, Florida Keys, etc. where natural gas is not available. For criteria pollutants, they are covere d under KKKK.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 85 of 373 development as discussed below. As a result, under the CAA §111(a) definitions of “new source” and “existing s ource,” 79 if those types of sources commence construction or mod ification,
they would not be treated as “new source[s]” subject to the standards of performance proposed today , and instead, they would be treated as existing sources

. 4. Certain projects under development This proposal does not apply to the proposed Wolver ine EGU project in Rogers City, Michigan . Based on current information, the Wolverine project appears to be the only fossil fuel-fired boiler or IGCC EGU project presently under developm ent that may be capable of “commencing construction” for NSPS pu rposes in the very near future and, as currently designed, could not meet the
1,100 lb CO 2 /MWh standard proposed for other new fossil fuelfired boiler and IGCC EGUs. The EPA has not formul ated a view as to the project’s status in the development proce ss or as to whether the proposed 1,100 lb CO 2 /MWh standard or some other CO 2 standard of performance would be representative of BSER for this project and invites comment on these question s . 80 At the time of

79 CAA §111(a)(2), (6). 80 The EPA’s lack of view regarding the appropriate C O 2 standard is closely related to the existence of conflicting information on where the project stands in the development proc ess. The developer has claimed that the project was delayed by issues related to the standards of performance for hazardo us air Deleted: theseis***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 86 of 373 finalization of this proposal (but not sooner than one year following Federal Register publication of this proposal), if the Wolverine project remains under development and has not either commenced construction or been canceled, we anticip ate proposing that the project either be made subject to the 1,10 0 lb CO 2 /MWh standard or be assigned to a subcategory with an al ternate CO 2 standard. Further discussion is provided in the tec hnical support document in the docket entitled “Fossil Fue l-Fired Boiler and IGCC EGU Projects under Development: Sta tus and Approach.”

There are two other fossil fuel-fired boiler or IGC C EGU projects without CCS – the Washington County projec t in Georgia and the Holcomb project in Kansas – that appear to remain under
development but whose developers have recently repr esented that the projects have commenced construction for NSPS p urposes.
pollutants promulgated in December 2011, 77 FR 9304 (Feb. 16, 2012) (Mercury and Air Toxics Standards, or MATS). Specifically, the developer cited a perceived inability to obtain guarantees from pollution control equipment vendors that the p lant would achieve the MATS standards. See Jim Dulzo, As Coal Plant Teeters, Groups Mount Legal Attack , Michigan Land Use Institute blog, Feb. 13, 2012, http://www.mlui.org/energy/new s-views/newsviews-articles/as-coal-plant-teeters-groups-mount-l egalattack.html. While some of the MATS new-unit standa rds were revised upon reconsideration in March 2013, 78 FR 2 4073 (Apr. 24, 2013), the developer’s claims raise the possibi lity that the EPA’s own actions may have delayed the project and contributed to the present uncertainty as to the project’s deve lopment status. Deleted: “ Deleted: ”

Deleted: “ Deleted: ”***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 87 of 373 Based solely on the developers’ representations, th e projects would be existing sources, and thus not subject to this proposal. However, neither developer has sought a formal EPA determination of NSPS applicability; and if upon re view it was determined that the projects have not commenced con structions, the projects could be situated similarly to the Wol verine project. Accordingly, if either developer seeks a formal EPA determination of applicability 81 within 120 days following Federal Register publication of this proposal and the EPA finds that the project has not “commenced construction,” 82 as of the date of the Federal Register publication of this proposal, then that project automatically – without, for example, any supplemental proposal or re-proposal – would be add ressed in the

81 Under the NSPS regulations, the EPA will respond wi thin 30 days to any request by an owner or operator for “a deter mination of whether action taken or intended to be taken by suc h owner or operator constitutes construction . . . or the comm encement thereof within the meaning of this part.” 40 CFR 6 0.5. 82 The NSPS regulations include the following definiti ons of “commenced” and “construction”: Commenced means . . . that an owner or operator has undertaken a continuous program of construction . . . or that an owner or operator has entered into a contra ctual obligation to undertake and complete, within a reas onable time, a continuous program of construction . . . . Construction means fabrication, erection, or installation of an affected facility. 40 CFR 60.2. Deleted: an

Deleted: “ Deleted: ”

Deleted: we propose that Deleted: an***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 88 of 373 same manner as the Wolverine project. 83 Further discussion is provided in the technical support document in the d ocket

referenced above. 84
We invite comment on all aspects of this approach f or addressing the Wolverine project (and the Washingto n County and Holcomb projects, if applicable). 85

83 In this event, there will not be any proposed stan dard “which will be applicable to such source” within the meani ng of CAA section 111(a)(2), and to the extent that this prop osal did, until the time of the applicability determination, apply to that project, this proposal will be considered automatic ally to be withdrawn as it applies to that project as of the t ime of the applicability determination. The purpose of this au tomatic withdrawal is to ensure that the project is placed on the same footing as the Wolverine project as soon as possibl e. It is worth noting that, if the developers do not seek ap plicability determinations within the 120 day timeframe , nothing in this rulemaking binds the EPA to the position that the p rojects have “commenced construction” for NSPS purposes. 84 In the April 2012 GHG NSPS proposal, the Wolverine , Washington County, and Holcomb projects were among a group of 15 projects distinguished from other EGU projects as “potential transitional sources.” This proposal does not continue that dist inction. Except as described above for the Wolverine project , and possibly the Washington County and Holcomb projects , any former “potential transitional source” that commences cons truction after publication of this proposal (and meets any o ther applicability criteria) will be subject to the fina l CO 2 standards established in this rulemaking. Any forme r “potential transitional source” that commenced construction pr ior to publication of this proposal is an existing source not subject to the CO 2 standards established in this rulemaking, but inst ead subject to the CO 2 standards that are required to be established for existing sources pursuant to CAA section 111(d)

. 85 The EPA intends that its treatment of the Wolverin e project (and the Washington County and Holcomb projects, if applicable) be severable from its treatment of differently situ ated sources and considers that severability is logical because of the Deleted: will Deleted: be***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 89 of 373

B. Emission standards In this rulemaking, the EPA is proposing NSPS for C O 2 emissions from several subcategories of affected so urces, which

are new fossil fired EGUs described above in Sectio n III.A. 1. Standards of performance for affected sources The proposed standard of performance for each subca tegory is in the form of a gross output-based CO 2 emission limit expressed in units of emissions mass per unit of us eful recovered energy, specifically, in pounds per megaw att-hour (lb/MWh). This emission limit would apply to affect ed sources upon the effective date of the final action. The subcategories, for which the EPA is proposing s eparate standards of performance, are (1) natural gas-fired stationary combustion turbines with a heat input rating that i s greater
than 850 MMBtu/h; 86 (2) natural gas-fired stationary combustion turbines with a heat input rating that is less than or equal to 850 MMBtu/h; and (3) all fossil fuel-fired boilers and IGCC

record-based differences between these sources and differently situated sources and because there is no interdepen dency in the EPA’s treatment of the different types of sources. This statement concerning severability should not be con strued to have implications for whether other components in t his rulemaking are severable. 86 This subcategorization of stationary combustion tu rbines is consistent with the subcategories used in the combu stion turbine (subpart KKKK) criteria pollutant NSPS. The size li mit of 850 MMBtu/h corresponds to approximately 100 MWe. Deleted: standards of performance ( Deleted: )

Deleted: , which are also natural gas fired***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 90 of 373 units, which generally are solid-fuel fired. We are proposing that all affected new fossil fuel- fired EGUs are required to meet an output-based emission rate of a specific mass of CO 2 per MWh of useful output. Specifically, new combustion turbines with a heat input rating greate r than 850 MMBtu/h would be required to meet a standard of 1,0 00 lb CO 2 /MWh. New combustion turbines with a heat input rating le ss than or equal to 850 MMBtu/h would be required to meet a st andard of
1,100 lb CO 2 /MWh. As discussed below, these proposed standards are based on the demonstrated performance of recent ly constructed NGCC units, which are currently in wide use throughout the country, and are currently the predo minant fossil fuel-fired technology for new electric generating u nits in the

near future.

New fossil fuel-fired boilers and IGCC units would be required, based on the performance of currently ava ilable CCS technology, to meet a standard of 1,100 lb CO 2 /MWh on a 12- operating-month rolling average, or alternatively a lower standard, which we propose as between 950 lb CO 2 /MWh and 1,050 lb

CO 2 /MWh, on a 60-operating-month rolling average as an equivalently stringent standard. The EPA has previo usly offered sources optional, longer-term emission standards th at are discounted from the primary emissions standard in combination Deleted: natural gas combined cycle ( Deleted: )

Deleted: exchange for Comment [A42]: “in exchange for” sounds like it’s a negotiation.

EPA: Sentence has been revised.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 91 of 373

with a longer averaging period. We are requesting comment on the appropriate numerical standard such that the 60-ope rating-month standard would be as stringent as or more stringent than the 12- operating-month standard. We also request comment on whether an appropriate 12-operating-month standard that owners /operators electing to comply with the 60-operating-month stan dard should also be required to comply with a maximum 12-operat ing-month

standard. This standard would be between the otherw ise applicable proposed 1,100 lb CO 2 /MWh standard and an emissions rate of a coal-fired EGU without CCS (e.g., 1,800 l b CO 2 /MWh),

and we solicit comment on what the standard should be. This shorter term standard would be more easily enforced and assure adequate emission reductions. While the EPA is proposing specific standards of pe rformance for each subcategory, we are also taking comment on a range of potential emission limitations. We solicit comment on a range of
950 – 1,100 lb CO 2 /MWh for new stationary combustion turbines with a heat input rating greater than 850 MMBtu/h. We also solicit comment on an emission limitation range of 1,000 – 1,150

lb CO 2 /MWh for new stationary combustion turbines with a heat input rating less than or equal to 850 MMBtu/h. In addition, we

solicit comment on an emission limitation for new f ossil fuelfired boilers and IGCC units in the range of 1,000 – 1,200 lb Deleted: the

Deleted: We also request comment on an appropriate 12-operating-month standard that owners/operators electing to comply with the 60- operating-month standard would have to comply with. This standard would be numerically between the alternate 12-operating-month standard and an emissions rate of a coal-fired EGU without CCS (e.g., 1,800 lb CO 2 /MWh). Comment [A43]: This is unclear. Can EPA be more specific about what goal the shorter term standard would be trying to achieve? To ensure tha t sources are on track to meet the longer term target ? EPA: Additional language has been added. The shorter term standard would mainly be for enforcement.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 92 of 373

CO 2 /MWh. As discussed below, the proposed method to calculat e compliance is to sum the emissions for all operatin g hours and to divide that value by the sum of the useful energ y output over a rolling 12-operating-month period. In the alterna tive, we solicit comment on requiring calculation of complia nce on an annual (calendar year) period. To recognize the environmental benefit of reduced e lectric
transmission and distribution losses of CHP, we are proposing that CHP facilities where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and 20.0 percent of the total gro ss useful energy output consists of useful thermal output on a rolling three calendar year basis receive similar credit as currently in subpart Da and the proposed amendments to subpart K KKK (77 FR 52554). Specifically, the measured electric output would be divided by 0.95 to account for a five percent avoided energy loss in the transmission of electricity. The minima l electric and thermal output requirements are to avoid owners /operators from selling trivial amounts of thermal output and claiming a line loss benefit when in reality they are similar to a central power station. Comment [E44]: We are still considering the ccmment to revise this range to 900 to 1,200 lb/MWh.

Comment [A45]: Should this say avoided energy loss?

EPA: Sentence has been revised.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 93 of 373 Subpart Da currently defines gross electric output from new units as the “gross electrical or mechanical output from the affected facility minus any electricity used to pow er the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) plus 75 percent of the useful thermal o utput
measured relative to ISO conditions” (refer r ed to in today’s notice as “adjusted gross output”). The current criteria pollutant emission standards for new subpart Da uni ts were developed by analyzing the gross emission rates of PC facilities, and were finalized on February 16, 2013 (77 FR 9304). In that rulemaking, we did not have emission s data from modern IGCC designs. We therefore concluded that a technology neutral approach was appropriate and applied the sa me standards to traditional coal and IGCC EGUs. The adjusted gro ss output definition accounts for the largest gas compressors at an IGCC facility. Subsequently, IGCC facilities complying w ith the NSPS requirements would emit at approximately the same n et output based emissions rate as a comparable traditional co al-fired EGU. Using this definition, both IGCC and traditional co al-fired EGUs at the same gross output-based emissions rate would have similar net output-based efficiencies. If we did not includ e the parasitic load from the primary gas compressors whe n determining Deleted:

.

Deleted: pulverized coal

Deleted: “ Deleted: ”***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 94 of 373 the gross efficiency of an IGCC facility, it would emit more pollutants to the atmosphere than a traditional coa l-fired EGU when complying with the criteria pollutant NSPS.

In contrast, in the April 2012 proposal, we proposed a definition of gross output as “the gross electrical or mechanical output from the unit plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanica l output or to enhance the performance of the unit (i.e., steam delivered to an industrial process).” This definition was approp riate since

NGCC was the BSER for the combined subcategory and auxiliary

loads associated with feedwater pumps and associated compressors (air separation unit main compressor, oxygen compre ssor, and nitrogen compressor) are not relevant to the gross efficiency of

an NGCC . However, we requested comment on requiring the use of net output based standards. Part of the rationale b ehind the use of net output-based standards is that the use of a gross outputbased standard as defined could have potentially drive n the installation of electrically driven feed pumps inst ead of steam driven feed pumps at a steam generating unit, even though from an overall net efficiency basis it may be more effi cient to use steam-driven feed pumps. Deleted: s

Deleted: the

Deleted: associated with IGCC facilities

Deleted: that approach

Deleted: currently

Deleted: Subpart Da currently defines gross electric output from steam generating units as the “gross electrical or mechanical output from the affected facility minus any electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) plus 75 percent of the useful thermal output measured relative to ISO conditions.”***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 95 of 373

A fter further consideration and because many of the proposed IGCC facilities are actually co-production facilities (i.e., produce useful byproducts and chemicals alon g with electricity), we have concluded that measuring the electricity used by the primary gas compressors associated with electricity production at IGCC facilities could be more challenging to implement

. Therefore, we are proposing the gross electric outp ut for steam generating units be the electricity measured at the generator terminals minus electric power used to ru n the feedwater pumps and the associated gas compressors , and the gross electric output for IGCC and subpart KKKK aff ected facilities would be the electricity measured at the generator

terminals. We are considering and requesting comment on if the gross output definition in subpart Da should be con sistent for both criteria and GHG purposes, if we should adopt the proposed

definition or the current adjusted gross output definition in subpart Da, and if the definition should be the sam e for both

traditional and IGCC facilities. If we do finalize the adjusted gross output definition, we take comment on issues related to accounting for power consumption associated with products other than electricity and steam created at a poly-genera tion facility and the impact on the numerical emissions standard

. Deleted: We have concluded that the fFeedwater pump efficiency impacts are primarily relevant to steam generating units, as combustion turbine based combined cyclegenerators (and IGCC facilities) generators use relatively smaller feedwater pumps and are not typically do not use steam driven feedwater pumps. Therefore, measuringincluding the electric load of these pumps is unnecessaryily burdensome for subpart KKKK facilities since it would not drive the installation of electric feedwater pumps and could cause confusion for the regulated community. Therefore, we are proposing that the electric auxiliary load of feedwater pumps not be included in the definition of gross output for subpart KKKK. However, the use of steam or electric feedwater pumps is still relevant to subpart Da steam generating units and we are proposing to maintain the electric driven feedwater pumps auxiliary loads when determining the gross output for steam generating units.NGCC and IGCC facilities. ¶ Deleted: In addition, a Deleted: which can make determining net electricity output more complicated Deleted: difficult Deleted: and is also unnecessarily burdensome, as they are an inherent part of the currently available IGCC process

Deleted: Using the current subpart Da definition of gross output would reduce the gross efficiency of an IGCC facility. The corresponding emissions rate we are considering for the final rule using this definition for gross output is 1,100 to 1,400 lb CO 2 /MWh-gross. Deleted: related to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 96 of 373 We are proposing that with respect to CO 2 emissions, 75 percent credit is the appropriate discount factor f or useful thermal output. However, we are requesting comment on a range of

two-thirds to three-fourths credit for useful therm al output in

the final rule. 2. 60-operating-month rolling average compliance op tion We also propose a 60-operating-month rolling averag ing compliance option that would be available for affec ted subpart Da boilers and IGCC facilities. The EPA suggests th at this 60- operating-month rolling average compliance option w ill offer operational flexibility and will tend to dampen sho rt-term emission excursions, which may be warranted especia lly at the initial startup of the facility and the CCS system. We have concluded that this alternative compliance option is not necessary for new stationary combustion turb ine EGUs, as they should be able to meet the proposed performanc e standard with no need for add-on technology. We seek comment on all other aspects of this 60-operating-month rolling averagin g compliance option. C. Startup, shutdown, and malfunction requirements
1. Startups and shutdowns Consistent with Sierra Club v. EPA, the EPA is prop osing standards in this rule that apply at all times, inc luding during Comment [A46]: This case is referenced below, but this appears to be the first reference. Please add full cite. EPA: We are still addressing this comment.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 97 of 373 startups and shutdowns. In proposing the standards in this rule, the EPA has taken into account startup and shutdown periods and, for the reasons explained below has not proposed al ternate standards for those periods. In the compliance calc ulation, periods of startup and shutdown are included as per iods of partial load. To establish the proposed NSPS’s outp ut-based CO 2 standard, we accounted for periods of startup and s hutdown by incorporating them as periods of partial load opera tion. As noted above, the proposed method to calculate compl iance is to sum the emissions for all operating hours and to di vide that value by the sum of the electrical energy output an d useful thermal energy output, where applicable for CHP EGU s, over a rolling 12-operating-month period. This averaging a pproach gives more weight to high-load hours and more accurately reflects overall environmental performance. Periods of start up and shutdown will be short, relative to total operating time. Since we are primarily concerned with overall environment al performance over extended periods of time, incorpor ating relatively short periods of partial load has a negl igible effect on measuring performance of the source with respect to long-term efficiency. Thus we allowed that low-load hours do not factor as heavily into the calculated average performance of the source. We solicit comment on any alternative to our propos al that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 98 of 373 the periods of startup and shutdown be included as periods of partial load in the 12- and 60-operating-month roll ing averaging compliance option.

2. Malfunctions Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source’s opera tions. However, by contrast, malfunction is defined as a “ sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner. F ailures that are caused in part by poor maintenance or careless operations
are not malfunctions.’’(40 CFR 60.2). The EPA has d etermined that CAA section 111 does not require that emission s that occur during periods of malfunction be factored into deve lopment of CAA section 111 standards. Nothing in CAA section 1 11 or in case law requires that the EPA anticipate and account fo r the innumerable types of potential malfunction events i n setting emission standards. CAA section 111 provides that t he EPA set standards of performance which reflect the degree o f emission limitation achievable through ‘‘the application of the best system of emission reduction’’ that the EPA determi nes is adequately demonstrated. Applying the concept of ‘‘ the application of the best system of emission reductio n’’ to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 99 of 373 periods during which a source is malfunctioning pre sents difficulties. The ‘‘application of the best system of emission reduction’’ is more appropriately understood to inc lude operating units in such a way as to avoid malfuncti ons. Further, accounting for malfunctions would be diffi cult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the category a nd given the difficulties associated with predicting or accounti ng for the frequency, degree, and duration of various malfunct ions that might occur. As such, the performance of units that are malfunctioning is not “reasonably” foreseeable. See , e.g.,
Sierra Club v EPA , 167 F.3d 658, 662 (D.C. Cir. 1999) (The EPA typically has wide latitude in determining the exte nt of datagathering necessary to solve a problem. We generall y defer to an agency's decision to proceed on the basis of imperf ect scientific information, rather than to "invest the resources to conduct the perfect study."). See also, Weyerhaeuser v. Costle, 590 F.2d 1011, 1058 (DC Cir. 1978) (“In the nature of things, no general limit, individual permit, or even any upset provision can anticipate all upset situations. After a certai n point, the transgression of regulatory limits caused by ‘uncon trollable acts of third parties,’ such as strikes, sabotage, operator intoxication or insanity, and a variety of other ev entualities,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 100 of 373

must be a matter for the administrative exercise of case-by-case enforcement discretion, not for specification in ad vance by regulation”). In addition, the goal of a source tha t uses the best system of emission reduction is to operate in such a way as to avoid malfunctions of the source and accounting for malfunctions could lead to standards that are signi ficantly less stringent than levels that are achieved by a well-p erforming non-malfunctioning source. The EPA’s approach to ma lfunctions is

consistent with section 111 and is a reasonable int erpretation

of the statute. In the event that a source fails to comply with the applicable CAA section 111 standards as a result of a malfunction event, the EPA would determine an appro priate response based on, among other things, the good fai th efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as w ell as root cause analyses to ascertain and rectify excess emis sions. The

EPA would also consider whether the source's failur e to comply with the CAA section 111 standard was, in fact, “su dden, infrequent, not reasonably preventable” and was not instead “caused in part by poor maintenance or careless ope ration.” 40
CFR section 60.2 (definition of malfunction). Finally, the EPA recognizes that even equipment tha t is***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 101 of 373 properly designed and maintained can sometimes fail and that

such failure can sometimes cause a violation of the relevant emission standard. (See, e.g., State Implementation Plans: Response to Petition for Rulemaking; Finding of Exc ess Emissions During Periods of Startup, Shutdown, and Malfunctio n; Proposed Rule, 78 FR 12460 (Feb. 22, 2013): (State Implement ation Plans: Policy Regarding Excessive Emissions During Malfunc tions, Startup, and Shutdown (Sept. 20, 1999); Policy on E xcess Emissions During Startup, Shutdown, Maintenance, an d Malfunctions (Feb. 15, 1983)). The EPA is therefore proposing to add an affirmative defense to civil penalties for v iolations of emission standards that are caused by malfunctions. See 40 CFR 60.10042 (defining “affirmative defense” to mean, i n the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has t he burden of proof, and the merits of which are independently an d objectively evaluated in a judicial or administrative proceedin g). We also are proposing other regulatory provisions to specif y the elements that are necessary to establish this affir mative defense; the source must prove by a preponderance o f the

evidence that it has met all of the elements set fo rth in 60.5530. (See 40 CFR 22.24). The criteria are desig ned in part

to ensure that the affirmative defense is available only where***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 102 of 373

the event that causes a violation of the emission s tandard meets

the narrow definition of malfunction in 40 CFR 60.2 (sudden, infrequent, not reasonably preventable and not caus ed by poor maintenance and or careless operation). For example , to successfully assert the affirmative defense, the so urce must prove by a preponderance of the evidence that the v iolation “[w]as caused by a sudden, infrequent, and unavoida ble failure of air pollution control, process equipment, or a p rocess to operate in a normal or usual manner....” The criteria also are designed to ensure that steps are taken to correct the malfunction, to minimize emissions in accordance wi th section 60.10001 and to prevent future malfunctions. For ex ample, the source must prove by a preponderance of the evidenc e that “[r]epairs were made as expeditiously as possible w hen a violation occurred...” and that “[a]ll possible steps were taken to minimize the impact of the violation on ambient air quality, the environment and human health....” In any judicial or administrative proceeding, the Administrator may ch allenge the assertion of the affirmative defense and, if the re spondent has not met its burden of proving all of the requiremen ts in the affirmative defense, appropriate penalties may be a ssessed in
accordance with section 113 of the CAA (see also 40 CFR part
22.27).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 103 of 373 The EPA included an affirmative defense in the prop osed rule in an attempt to balance a tension, inherent i n many types of air regulation, to ensure adequate compliance wh ile simultaneously recognizing that despite the most di ligent of efforts, emission standards may be violated under c ircumstances beyond the control of the source. The EPA must esta blish emission standards that “limit the quantity, rate, or concentration of emissions of air pollutants on a c ontinuous
basis.” 42 U.S.C. § 7602(k)(defining “emission limitation” and
“emission standard”). See generally Sierra Club v. EPA , 551 F.3d 1019, 1021 (D.C. Cir. 2008) Thus, the EPA is requir ed to ensure

that section 111 emissions standards are continuous . The

affirmative defense for malfunction events meets th is requirement by ensuring that even where there is a malfunction, the emission standard is still enforceable through injunctive relief. The United States Court of Appeals for the Fifth Circuit recently upheld the EPA’s view that an affirmative defense provision is consistent with section 113(e) of the Clean Air

Act. Luminant Generation Co. LLC v. United States EPA , 2013 U.S. App. LEXIS 6397 (5th Cir. Mar. 25, 2013) 699 F3d. 4 27(5 th Cir. Oct. 12, 2012) (upholding the EPA’s approval of aff irmative defense provisions in a CAA State Implementation Pl an). While “continuous” standards, on the one hand, are requir ed, there is***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 104 of 373 also case law indicating that in many situations it is appropriate for the EPA to account for the practica l realities of technology. For example, in Essex Chemical v. Ruckelshaus , 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circui t acknowledged that in setting standards under CAA se ction 111 “variant provisions” such as provisions allowing fo r upsets during startup, shutdown and equipment malfunction “appear necessary to preserve the reasonableness of the sta ndards as a whole and that the record does not support the ‘nev er to be exceeded’ standard currently in force.” See also, Portland

Cement Association v. Ruckelshaus , 486 F.2d 375 (D.C. Cir.
1973). Though intervening case law , such as Sierra Club v. EPA

and the CAA 1977 amendments , call into question the relevance of these cases today, they support the EPA’s view that a system that incorporates some level of flexibility is reas onable. The affirmative defense simply provides for a defense t o civil penalties for violations that are proven to be beyo nd the control of the source. By incorporating an affirmat ive defense, the EPA has formalized its approach to malfunctions . In a Clean Water Act setting, the Ninth Circuit required this type of formalized approach when regulating “upsets beyond the control of the permit holder.” Marathon Oil Co. v. EPA , 564 F.2d 1253,
1272-73 (9 th Cir. 1977). See also , Mont. Sulphur & Chem. Co. v. Comment [A47]: The relevance is questioned with respect to other issues? Add clarifying statement. EPA: We are still considering this comment.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 105 of 373

United States EPA , 666 F.3d. 1174 (9 th Cir. 2012)(rejecting industry argument that reliance on the affirmative defense was not adequate). But see, Weyerhaeuser Co. v. Costle , 590 F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an inf ormal approach is adequate). The affirmative defense prov isions give the EPA the flexibility to both ensure that its emi ssion standards are “continuous” as required by 42 U.S.C. § 7602(k), and account for unplanned upsets and thus support t he

reasonableness of the standard as a whole. We propose that these same requirements, an affirma tive defense to civil penalties for violations of emissi on limits that are caused by malfunctions, would apply to bot h the 12- operating-month standard and the 60-operating-month rolling average compliance option; however, we will take co mment on whether it is appropriate to have an affirmative de fense for the 60-operating-month rolling average portion of that compliance option, given that we would expect malfunctions to only impact shorter averaging periods, and the longer the compl iance period, the less likely malfunction events are to impact a source’s ability to meet the standard. D. Continuous monitoring requirements Today’s proposed rule would require owners or opera tors of EGUs that combust solid fuel to install, certify, m aintain, and***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 106 of 373 operate continuous emission monitoring systems (CEM S) to measure

CO 2 concentration, stack gas flow rate, and (if needed ) stack gas moisture content in accordance with 40 CFR Part 75, in order to determine hourly CO 2 mass emissions rates (tons/hr). The proposed rule would allow owners or operators of EGUs that burn exclusively gaseous or liquid fuels to in stall fuel

flow meters as an alternative to CEMS and to calcul ate the hourly CO 2 mass emissions rates using Equation G-4 in Appendi x G of Part 75. To implement this option, hourly measur ements of fuel flow rate and periodic determinations of the g ross calorific value (GCV) of the fuel are also required , in accordance with Appendix D of Part 75.

In addition to requiring monitoring of the CO 2 mass emission rate, the proposed rule would require EGU owners or operators to monitor the hourly unit operating time and “gross o utput”, expressed in megawatt hours (MWh). The gross output includes electrical output plus any mechanical output, plus 75 percent of any useful thermal output. The proposed rule would require EGU owners or oper ators to prepare and submit a monitoring plan that includes both electronic and hard copy components, in accordance with §§ 75.53(g) and (h). The electronic portion of the mon itoring plan

would be submitted to the EPA’s Clean Air Markets D ivision***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 107 of 373 (CAMD) using the Emissions Collection and Monitorin g Plan System (ECMPS) Client Tool. The hard copy portion of the p lan would be sent to the applicable State and EPA Regional offic e. Further, all monitoring systems used to determine the CO 2 mass emission rates would have to be certified according to § 75.20 and section 6 of Part 75, Appendix A within the 180-day window of
time allotted under § 75.4(b), and would be required to meet the applicable on-going quality assurance procedures in Appendices B

and D of Part 75. The proposed rule would require all valid data collected

and recorded by the monitoring systems (including data recorded during startup, shutdown, and malfunction) to be us ed in assessing compliance. Failure to collect and record required data is a violation of the monitoring requirements, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required m onitoring system quality assurance or quality control activit ies that temporarily interrupt the measurement of stack emis sions (e.g., calibration error tests, linearity checks, and requ ired zero and span adjustments). An affirmative defense to civil penalties for

malfunctions is available to a source if it can dem onstrate that certain criteria and requirements are satisfied.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 108 of 373 The proposed rule would require only those operatin g hours

in which valid data are collected and recorded for all of the parameters in the CO 2 mass emission rate equation to be used for compliance purposes. Additionally for EGUs using CO 2 CEMS, only unadjusted stack gas flow rate values would be used in the emissions calculations. In this proposal, Part 75 b ias adjustment factors (BAFs) would not be applied to t he flow rate

data. These restrictions on the use of Part 75 data for Part 60 compliance are consistent with previous NSPS regula tions and

revisions. The following variations from and additions to the basic Part 75 monitoring would be required:

• If you determine compliance using CEMS, you would b e required to use a laser device to measure the stack

diameter at the flow monitor and the reference meth od sampling locations prior to the initial setup
(characterization) of the flow monitor. For circula r stacks, you would need to make measurements of the

diameter at 3 or more distinct locations and average the results. For rectangular stacks or ducts, you would need

to make measurements of each dimension (i.e., depth an d width) at 3 or more distinct locations and average the

results. If the flow rate monitor or reference meth od Deleted: three determinations

Deleted: three***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 109 of 373 sampling site is relocated, you would repeat these

measurements at the new location.

• If you elect to use Method 2 in Appendix A-1 of Par t 60 to perform the required relative accuracy test audits (RATAs) of the Part 75 flow rate monitoring system, you wou ld have to use a calibrated Type-S pitot tube or pitot tube assembly. Use of the default Type-S pitot tube coef ficient would not be permitted.

• If your EGU combusts natural gas and/or fuel oil an d you

elect to measure the CO 2 mass emissions rate using Equation G-4 in Appendix G of Part 75, you would be allowed to determine site-specific carbon-based F-factors usin g Equation F-7b in section 3.3.6 of Appendix F of Par t 75, and you could use these F c values in the emissions calculations instead of using the default F c values in the Equation G-4 nomenclature. Today’s proposed rule includes the following specia l compliance provisions for units with common stack o r multiple stack configurations; these provisions are consiste nt with §
60.13(g):

• If two or more of your EGUs share a common exhaust stack, are subject to the same emission limit, and you are required to (or elect to) determine compliance usin g CEMS,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 110 of 373 you would be allowed to monitor the hourly CO 2 mass
emission rate at the common stack instead of monito ring each EGU separately. If this option is chosen, the hourly gross electrical load (or steam load) would be the sum of the hourly loads for the individual EGUs and the op erating time would be expressed as “stack operating hours” (as defined in 40 CFR 72.2). Then, if compliance with t he applicable emission limit is attained at the common stack, each EGU sharing the stack would be in compliance with the

CO 2 emissions limit

.

• If you are required to (or elect to) determine comp liance using CEMS and the effluent from your EGU discharge s to the atmosphere through multiple stacks (or, if the effluent is fed to a stack through multiple ducts a nd you choose to monitor in the ducts), you would be requi red to monitor the hourly CO 2 mass emission rate and the “stack operating time” at each stack or duct separately. I n this case, compliance with the applicable emission limit would be determined by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross output for the unit. The proposed rule would require 95 percent of the o perating hours in each compliance period (including the comp liance Deleted: considered to be***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 111 of 373 periods for the intermediate emission limits ) to be valid hours, i.e., operating hours in which quality-assured data are
collected and recorded for all of the parameters used to

calculate CO 2 mass emissions. EGU owners or operators would have the option to use backup monitoring systems, as pro vided in §§ 75.10(e) and 75.20(d), to help meet this proposed d ata capture requirement. E. Emissions performance testing requirements
In accordance with § 75.64(a), the proposed rule would require an EGU owner or operator to begin reporting emissions data when monitoring system certification is comple ted or when the 180-day window in § 75.4(b) allotted for initial certification of the monitoring systems expires (wh ichever date is earlier). For EGUs subject to the 450 kg/MWh (1, 000 lb/MWh) standard or the 500 kg/MWh (1,100 lb/MWh) emission standard, the initial performance test would consist of the first 12- operating-months of data, starting with the month i n which emissions are first required to be reported. The in itial 12- operating-month compliance period would begin with the first month of the first calendar year of EGU operation i n which the facility exceeds the capacity factor applicability threshold. The traditional 3-run performance tests (i.e., stac k tests)
described in § 60.8 would not be required for this rule. Deleted: “ Deleted: ”

Deleted: obtained***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 112 of 373 Following the initial compliance determination, the emission standard would be met on a 12-operating-month rolli ng average basis. For EGUs that combust coal and/or petroleum coke and whose owners or operators elect to comply with the alternative 60-operating-month rolling average emissions standa rd, the first month in the compliance period would be the month i n which emissions reporting is required to begin under § 75.64(a). F. Continuous compliance requirements Today’s proposed rule specifies that compliance wit h the
1,000 lb/MWh (450 kg/MWh) and 1,100 lb/MWh ( 500 kg/MWh ) CO 2 mass
emissions rate limits would be determined on a 12-o peratingmonth rolling average basis, updated after each new operating month. For each 12-operating-month compliance perio d, qualityassured data from the certified Part 75 monitoring systems would be used together with the gross output over that pe riod of time to calculate the average CO 2 mass emissions rate. The proposed rule specifies that the first operatin g month included in either the initial 12- or 60-operating- month compliance period would be the month in which repor ting of emissions data is required to begin under § 75.64(a), i.e., either the month in which monitoring system certifi cation is completed or the month in which the 180-day window allotted to Deleted: 450 kg/MWh ( Deleted: ) Deleted: (1,100 lb/MWh) Comment [A48]: In most instances, the rule lists the lb/Mwh - suggest putting kg/MWh in parenthesis here for consistency. EPA: Agreed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 113 of 373 finish certification testing expires (whichever mon th is
earlier). We are proposing that initial compliance with the applicable emissions limit in kg/MWh be calculated by dividing the sum of the hourly CO 2 mass emissions values by the total gross output for the 12- or 60-operating-month peri od. Affected EGUs would continue to be subject to the standards and maintenance requirements in the section 111 regulat ory general provisions contained in 40 CFR part 60, subpart A. G. Notification, recordkeeping, and reporting requi rements Today’s proposed rule would require an EGU owner or operator to comply with the applicable notification requirements
in § 75.61, §§ 60.7(a)(1) and (a)(3) and § 60.19. The proposed rule would also require the applicable recordkeepin g requirements in subpart F of Part 75 to be met. For EGUs using
CEMS, the data elements that would be recorded incl ude, among others, hourly CO 2 concentration, stack gas flow rate, stack gas moisture content (if needed), unit operating time, and gross electric generation. For EGUs that exclusively comb ust liquid and/or gaseous fuel(s) and elect to determine CO 2 emissions using Equation G-4 in Appendix G of Part 75, the key data elements in subpart F that would be recorded include hourly fue l flow rates, fuel usage times, fuel GCV, gross electric generati on.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 114 of 373 The proposed rule would require EGU owners or opera tors to keep records of the calculations performed to deter mine the

total CO 2 mass emissions and gross output for each operating month. Records would be kept of the calculations pe rformed to determine the average CO 2 mass emission rate (kg/MWh) and the percentage of valid CO 2 mass emission rates in each compliance period. The proposed rule would also require record s to be kept of calculations performed to determine site-specifi c carbonbased F-factors for use in Equation G-4 of Part 75, Appendix G (if applicable).
For EGU owners or operators who would elect to comp ly with the 60-operating-month rolling average emissions st andard, records must be kept for 10 years. All other record s would be kept for a period of three years. All required reco rds would be kept on-site for a minimum of two years, after whic h the records

could be maintained off-site. The proposed rule would require all affected EGU owners/operators to submit quarterly electronic emi ssions reports in accordance with subpart G of Part 75. Th e proposed rule would require these reports to be submitted us ing the ECMPS Client Tool. Except for a few EGUs that may be exem pt from the Acid Rain Program (e.g., oil-fired units), this is not a new reporting requirement. Sources subject to the Acid Rain Program***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 115 of 373 are already required to report the hourly CO 2 mass emission rates that are needed to assess compliance with today’s r ule. Additionally, in the proposed rule and as part of a n Agency-wide effort to streamline and facilitate the reporting of environmental data, the rule would require selected data elements that pertain to compliance under this rule , and that serve the purpose of traditional excess emissions r eports, to be reported periodically using ECMPS. Specifically, for EGU owners/operators who would co mply with a 12-operating-month rolling average standard, quarterly electronic “excess emissions” reports must be submi tted, within 30 days after the end of each quarter. The first re port would be for the quarter that includes the final (12 th ) operating month of

the initial 12

- operating

- month compliance period. For that initial report and any subsequent report in which t he twelfth operating month of a compliance period (or periods) occurs during the calendar quarter, the average CO 2 mass emissions rate (kg/MWh) would be reported for each compliance peri od, along with the dates (year and month) of the first and tw elfth operating months in the compliance period and the p ercentage of

valid CO 2 mass emission rates obtained in the compliance per iod. The dates of the first and last operating months in the compliance period would clearly bracket the period used in the Deleted: Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 116 of 373 determination, which facilitates auditing of the da ta. Reporting the percentage of valid CO 2 mass emission rates is necessary to demonstrate compliance with the requirement to obta in valid data for 95 percent of the operating hours in each compl iance period. Any excess emissions that occur during the quarter would be identified. If there are no compliance periods that end in the quarter, a definitive statement to that effect woul d be included in the report. If one or more compliance periods en d in the quarter but there are no excess emissions, a statem ent to that effect would be included in the report. For EGU owners or operators that would comply with a 60- operating-month rolling average basis, quarterly el ectronic “excess emissions” reports would be submitted, with in 30 days after the end of each quarter. The first report wou ld be for the quarter that includes the final (60 th ) operating month of the initial 60-operating-month compliance period. For t hat initial report and any subsequent report in which the sixti eth operating month of a compliance period (or periods) occurs du ring the calendar quarter, the average CO 2 mass emissions rate (kg/MWh) must be reported for each compliance period, along with the dates (year and month) of the first and sixtieth op erating months in the compliance period and the percentage of valid CO 2 mass emission rates obtained in the compliance peri od. The dates***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 117 of 373 of the first and last operating months in the compl iance period would clearly bracket the period used in the determ ination, which facilitates auditing of the data. Reporting o f the percentage of valid CO 2 mass emission rates is necessary to demonstrate compliance with the requirement to obta in valid data for 95 percent of the operating hours in each compl iance period. Any excess emissions that occur during the quarter would be identified. If there are no compliance periods that end in the quarter, a definitive statement to that effect woul d be included in the report. If one or more compliance periods en d in the quarter but there are no excess emissions, a statem ent to that effect would be included in the report. Currently, ECMPS is not programmed to receive exces s emission report information from EGUs . However, we will make the necessary modifications to the system in order to f ully implement the reporting requirements of this rule u pon promulgation. IV. Rationale for Reliance on Rational Basis to Reg ulate GHGs

from Fossil-fired EGUs

A. Overview In our original proposal, we proposed and solicited comment on what basis we are required to have concerning th e health and welfare impacts of GHG emissions from fossil-fuel f ired power Comment [A49]: From any source category? Or, just from EGUs? Consider clarifying.

EPA: Text has been clarified.

Deleted: to Regulate***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 118 of 373 plants in order to regulate those emissions under C AA § 111. However, we took the position that we are not requi red to make findings that GHGs from fossil-fired power plants “ cause[], or contribute[] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare,”
under CAA § 111(b)(1)(A). We have reconsidered that proposal in light of the numerous comments we received. In today’s notice, we propose that under
§111, the EPA is required to ha ve a rational basis for promulgating standards for GHG emissions from elect ricity generating plants , and that the EPA has such a basis because the EPA has already determined that GHG emissions may r easonably be anticipated to endanger public health and welfare , and because electricity generating plants, as an industry, cons titute, by a significant margin, the largest emitters in the inv entory. In the April 2012 proposal, the EPA discussed whether CAA section 111 requires that the EPA issue, as a prerequisite for this rulemaking, another “endangerment” finding. After r eviewing the comments, recent scientific developments, the amoun t of emissions from the power plant sector, and the case law, the EPA

has concluded that even if § 111 requires an endangerment finding, the rational basis described in today’s ac tion would qualify as an endangerment finding as well. Deleted: s

Deleted: ;

Deleted: section Deleted: only that the EPA establish a rational basis for regulating GHG emissions from power plants, but that even if Deleted: were required***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 119 of 373 As related matters, in this notice, we are proposin g to establish regulatory requirements for CO 2 emissions of affected units, which are included in source categor ies (both steamgenerating units and turbines) that the EPA already listed under

CAA § 111(b)(1)(A) for regulation under CAA and we are no t proposing a listing of a new source category. We are, however, proposing to subcategorize different sets of source s, and

establish different CO 2 standards of performance for them, in
accordance with CAA § 111(b)(2). To avoid confusion, we are proposing to codify the CO 2 standards of performance in the same subparts – Da and KKKK, depending on the types of u nits – that currently include the standards of performance for conventional pollutants . We are also co-proposing, in the alternative , to codify the CO 2 standards in a new subpart , TTTT, as we proposed in the original proposal for this rulemaking in Apr il, 2012

. 87

87 It should be noted that CAA §111 clearly applies to GHGs. The U.S. Supreme Court has made this clear because (i) §111 applies to “any air pollutant,” CAA §111(a)(3), see §111(d) (1)(A) (exempting, for purposes of §111(d), certain air po llutants); and in Massachusetts v. EPA, 549 U.S. 497 (2007), t he Supreme Court held that the term “air pollutant,” as define d under CAA §302(g), includes GHGs; and (ii) in American Electr ic Power Company v. Connecticut, 131 S.Ct. 2527 (2011), the Supreme Court based its holding that “the Clean Air Act and the E PA actions it authorizes displace any federal common law right to seek abatement of carbon-dioxide emissions from fossil f uel-fired power plants” on the grounds that CAA §111 “provide s a means to seek limits on emissions of carbon dioxide from dom estic power plants....” Id. at 2538. Deleted: a Deleted: y

Deleted: new

Deleted: instead of

Deleted: ing***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 120 of 373

B. Climate c hange i mpacts from GHG e missions; Amounts of GHGs

from fossil fuel-fired EGUs In 2009, the EPA Administrator issued the Endangerm ent Finding under CAA section 202(a)(1). With the Endan germent Finding, the Administrator found that elevated conc entrations of GHGs in the atmosphere may reasonably be anticipate d to endanger public health and welfare of current and future gen erations, and focused on public health and public welfare impacts within the United States. Fossil fuel-fired EGUs are by far th e largest emitters of GHGs, primarily in the form of CO 2 , among stationary

sources in the U.S. These adverse effects of GHGs o n public
health and welfare, and the amounts of GHGs emitted by fossil fuel-fired EGUs are briefly summarized in the secti on II of this
preamble and described in more detail in the RIA, and need not

be recited here.

C. CAA § 111 requirements To review the key CAA § 111 requirements: CAA § 111(b)(1)(A), by its terms, requires that the Admin istrator -- shall publish (and from time to time thereafter sha ll revise) a list of categories of stationary sources. He shall include a category of sources in such list if in his judgment it causes, or contributes significantl y to air pollution which may reasonably be anticipate d to endanger public health or welfare.

CAA § 111(b)(1)(B) goes on to provide that after listing the source category, the EPA must promulgate regulation s Deleted: C Deleted: I Deleted: E

Deleted: background

Deleted: , Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 121 of 373 “establishing federal standards of performance for new sources within such category.” In turn, CAA § 111(a)(1) defines a “standard of performance” as a “standard for emissi ons of air pollutants which reflects the degree of emission re duction which (taking into account ... cost ... and any nonair qualit y health and environmental impact and energy requirements) ... h as been adequately demonstrated.” CAA § 111(b)(2) provides that “The Administrator may distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing

such standards.” D. Interpretation of CAA § 111 requirements

CAA § 111(b)(1)(A) requires the EPA to list a source category if it contributes significantly to air pol lution that endangers public health or welfare. The EPA must ne cessarily conduct this listing by making determinations as to the health or welfare impacts of the pollution to which the so urce
category ’s pollutants contribute , and as to the significance of the amount of such contribution. However, by the te rms of CAA § 111(b)(1)(A), the EPA may make these determinations on the basis of the impacts of the air pollution as a whole to which the source category’s pollutants , taken as a whole , contribute

. Nothing in CAA § 111(b)(1)(A) requires that the EPA make Deleted: one or more of the pollutants emitted by that source category, or Deleted: s

Deleted: all of

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 122 of 373 separate determinations for each type of pollution or each pollutant. After listing a source category, the EPA must proce ed to promulgate standards of performance for the source category’s pollutants under CAA § 111(b)(1)(B) and 111(a)(1). However, nothing in those provisions requires that, at the t ime when the EPA promulgates the standards of performance for th e individual pollutants, the EPA must make a determination as to the health or welfare effects of those particular pollutants o r as to the significance of the amount of the source category’s emissions of
those pollutants. Clearly, CAA § 111 does not by its terms require that as a prerequisite for the EPA to promu lgate a standard of performance for a particular pollutant, the EPA must first find that the pollutant causes or contributes significantly to air pollution that endangers publi c health or welfare. The lack of any such requirement contrasts with other CAA provisions that do require the EPA to make enda ngerment and cause-or-contribute findings for the particular pol lutant that the EPA regulates under those provisions. E.g., CAA sections
202(a)(1), 211(c)(1), 231(a)(2)(A). The lack of any express requirement in CAA section 111 addressing whether and how the EPA is to evaluate e missions of a particular pollutant from the listed source categor y as a***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 123 of 373 prerequisite for promulgation of a standard of perf ormance is properly viewed as a statutory gap that requires th e EPA to make

what we refer to as a Chevron step 2 interpretation. Under the U.S. Supreme Court’s 1984 decision in Chevron U.S.A. Inc. v.

NRDC , 88 to interpret how a statute applies to a particular question, an agency must, at Step 1, determine whet her Congress’s intent as to the specific question is cl ear, and, if so, the agency must give effect to that intent. If congressional intent is not clear, then the agency, at Step 2, ha s discretion to fashion an interpretation that is a reasonable c onstruction

of the statute. 89 In this case, the EPA is authorized to develop a reasonable interpretation. Our interpretation is that in order to promulgate a § 111 standard of performance for a particular pollutant, we do not need to make a pollutant-specific endangerment find ing, but

instead must demonstrate a rational basis for contr olling the emissions of the pollutant. That rational basis may be based on information concerning the health and welfare impac ts of the air pollution at issue, and the amount of contribution that the source category’s emissions make to that air pollut ion.

88 467 U.S. 837 (1984). 89 Id. at 842-43.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 124 of 373 Commenters on the April 2012 proposal stated that t he EPA is required to make an endangerment finding for CO 2 because when the EPA listed this source category, it was on the basis of
other pollutants, and not CO 2 . However, to reiterate, CAA § 111(b)(1)(A) by its terms requires that the EPA “sh all publish
(and from time to time thereafter, shall revise) a list of categories of stationary sources,” and that the EPA shall list “a category of sources” based on the EPA’s judgment that the category “causes, or contributes significantly to, air pollution” that endangers public health or welfare. Thus, this provision requires that the EPA make the listing de cision on a category basis, and not on a pollutant-by-pollutant basis. That is, this provision does not require that the EPA es tablish separate lists of source categories, with each list covering a different pollutant. Therefore, this provision does not require that the EPA make an endangerment finding on a poll utant by pollutant basis. Commenters on the April 2012 proposal stated that t he EPA was required to make an endangerment finding becaus e by creating the new subpart TTTT in 40 CFR part 60 , the EPA was listing a

new source category that included the affected units. However, in neither the original April 2012 proposal nor this new proposal has EPA proposed to list a new source cate gory. The EPA Deleted: the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 125 of 373 initially included fossil fuel-fired electric steam generating
units (which included boilers) in a category that it listed
under section 111(b)(1)(A) 90 and the EPA promulgated the first
set of standards of performance for this source category in
1971, which the EPA codified in subpart D. 91 Subsequently, the

EPA included fossil-fuel-fired combustion turbines in a category
that the EPA listed under section 111(b)(1)(A), 92 and the EPA promulgated standards of performance for this sourc e category in

1979 , which the EPA codified in subpart GG. 93
The EPA has revised those regulations, and in some
instances, revised the codifications (that is, the subparts ) , several times over the ensuing decades. In 1979, the EPA divided subpart D into 3 subparts – Da (“Standards of Perfo rmance for Electric Utility Steam Generating Units for Which C onstruction is Commenced After September 18, 1978”), Db (“Stand ards of

Performance for Industrial-Commercial-Institutional Steam Generating Units”) and Dc (“Standards of Performanc e for Small

90 “Air Pollution Prevention and Control: List of Cate gories of Stationary Sources,” 36 FR 5931 (March 31, 1971). 91 “Standards of Performance for Fossil-Fuel-Fired St eam Generators for Which Construction Is Commenced Afte r August 17, 1971,” 36 Fed. Reg. 24875 (Dec. 23, 1971) codified at 40 CFR 60.40-46; 36 Fed. Reg. 5931 (Mar. 31, 1971). 92 42 FR 53,657 (Oct. 3, 1977). 93 “Standards of Performance for Electric Utility Stea m Generating Units for Which Construction is Commence d After September 18, 1978 ,” 44 Fed. Reg. 33580 (June 11, 1979). Deleted: EGUs (which includes EGUs that burn fossil fuel including coal, gas, oil and petroleum coke and that use different technologies, including boilers and combustion turbines) Deleted: EGUs

Deleted: CITE

Deleted: CITE

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Industrial-Commercial-Institutional Steam Generatin g Units”) – in order to codify separate requirements that it es tablished for these subcategories. 94 In 2006, the EPA created subpart KKKK, ”Standards of Performance for Stationary Combustion Turbines,” which applied to certain sources previously regulated in subparts Da and GG

. 95 None of these rulemakings , including the

revised codifications, however, constituted a new listing under

CAA § 111(b)(1)(A). In today’s rulemaking, the EPA is promulgating new standards of performance for CO 2 emissions from certain sets of

sources, e.g., steam-generating boilers (except for liquid-fired
boilers) and turbines. Moreover, we are establishin g different requirements for different sets of sources, includi ng steamgenerating boilers as well as smaller and larger combustion
turbines, in accordance with CAA § 111(b)(2). That provision authorizes the EPA to “distinguish among classes, t ypes, and sizes within categories of new sources for the purp ose of establishing ... standards [of performance.]”

94 44 Fed. Reg. 33,580 (June 11, 1979) 95 71 Fed. Reg. 38497 (July 6, 2006), as amended at 7 4 Fed. Reg. 11861 (Mar. 20, 2009). Deleted: from multiple subparts

Deleted: or

Deleted: similarly to the original proposal, the EPA is not proposing to list a new category of sources. Rather, Deleted: simply

Deleted: , but not liquid-fired sourcesturbines

Deleted: , and boilers

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I n today’s rulemaking , we are including a proposal and, in the alternative, a co-proposal, which take two diff erent approaches to the source categories and their codif ication. 97 Our proposal is to codify the new CO 2 standards in the same subparts in which the standards of performance for conventio nal pollutants are codified. Thus, we propose to codify the GHG

standards for steam-generating boilers as a new section in subpart Da, and the GHG standards for combustion turbines as new sections in subpart KKKK. This proposal does not list a new category under section 111(a)(1)(A). Nor does this proposal revise either of the two source categories – steam- generating

boilers and combustion turbines – that EPA has alre ady listed, or revise the codification of the new source requir ements for those categories in subparts Da, GG, and KKKK. Unde r this proposal, the establishment of different requiremen ts for

97 In the original proposal for this rulemaking, the E PA proposed to create within 40 CFR part 60 a new subpart that would include GHG emission regulatory requirements for electric u tility steam generating units (i.e., boilers and IGCC units), wh ose conventional pollutant regulatory requirements are codified under subpart Da; as well as stationary combustion turbines that generate electricity for sale and meet certain size and operational criteria, conventional pollutant regula tory requirements are codified under subpart KKKK. The E PA proposed to number this newly created subpart as subpart TTT T. The EPA explained that combining the GHG regulatory require ments for those sources in TTTT was appropriate because the E PA was establishing the same limit for all those sources b ased on the same BSER, which was NGCC. 77 Fed. Reg. at 22,410/2 – 22,411/3. Deleted: We recognize that our original proposal, by codifying these new standards of performance in a separate subpart, TTTT, may have led to some confusion over whether the new subpart under the EPA’s regulations constituted a new listing under CAA § 111(b)(1)(A). That was not the case, for the reasons noted above, but to minimize confusion, we are taking a different approach i Deleted: this proposal Deleted: and are Deleted: ing Deleted: are Deleted: ing Deleted: solid-fuel fired EGUs***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 128 of 373 different sets of sources – for example, coal-fired power plants, larger NGCC plants, and smaller NGCC plants – constitute subcategorizations within the existing categories. In the alternative, we co-propose to combine the tw o source categories – again, steam-generating boilers and co mbustion turbines -- for purposes of regulating CO 2 emissions (but not for regulating emissions of conventional pollutants), a nd to codify all of the proposed regulatory requirements in a ne w subpart,

TTTT. 98 This combined category cannot be considered a new category that EPA is placing on the list of categor ies for regulation under CAA §111(b)(1)(A). Under this co-p roposal, the establishment of different requirements for differe nt sets of sources continues to constitute subcategorizations within the existing category.

We solicit comment on the relative merits of each a pproach. In particular we seek comment on whether the co-proposal to combine the categories and codify the GHG standards for all affected sources in subpart TTTT will offer any add itional flexibility for any future emission guidelines for existing

sources.

98 Under this co-proposal, these regulatory requireme nts are substantively the same as the requirements proposed for inclusion in subparts Da and KKKK, and are simply c ollected in a separate subpart, TTTT.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 129 of 373 E. Rational basis to promulgate standards for GHGs from fossilfired EGUs In this rulemaking, the EPA has a rational basis fo r concluding that emissions of CO 2 from fossil-fired power plants, which are the major U.S. source of greenhouse gas air pollution , merits taking action under CAA § 111. As noted, in 2009, the EPA made a finding that GHG air pollution may reasonabl y be anticipated to endanger public health or welfare, a nd in 2010, the EPA denied petitions to reconsider that finding . The EPA extensively reviewed the available science concerni ng GHG pollution and its impacts in taking those actions. In 2012, the U.S. Court of Appeals for the D.C. Circuit upheld t he finding and denial of petitions to reconsider. In addition, assessments from the NRC and the IPCC, published in 2010, 2011, and 2012 lend further credence to the validity of the Endang erment Finding. As discussed below, no information that co mmenters have presented or that the EPA has reviewed provides a b asis for rescinding that finding. In addition, as noted, the high level

of GHG emissions from the fossil-fired EGUs makes c lear that it is rational for the EPA to regulate GHG emissions f rom this sector. This information amply supports that the EP A has a rational basis for promulgating regulations under C AA § 111 designed to address GHG air pollution. Deleted: the air pollution in question is GHGs, and

Deleted: this***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 130 of 373

Our conclusion is consistent with the case law hand ed down by the D.C. Circuit. In its 1980 decision in Nation al Lime

Association v. EPA , 99 the Court upheld EPA’s determination that lime manufacturing plants emit particulates that co ntribute significantly to air pollution that endangers publi c health or welfare. The Court noted that (i) EPA’s basis was i ts prior determination that “the significant production of p articulate emissions ... cause[s] or contribute[s] to air poll ution (which may reasonably be anticipated to endanger public he alth or welfare);” and (ii) “[t]he Agency has made this det ermination for purposes of establishing national primary and s econdary ambient air quality standards under [CAA § 109].” The Court

held: We think the danger of particulate emissions' effec t on health has been sufficiently supported in the Agency's (and its predecessor's) previous determinations to provide a rational basis for the Administrator's finding in this case. 100
Similarly, in National Asphalt Pavement Ass’n v. Tr ain, 101 the D.C. Circuit upheld a determination by the EPA that asphalt cement plants contribute significantly to particula te matter air pollution that endangers public health and welfare. The Court indicated that the EPA’s determination that particu late matter

99 627 F.2d 416 (D.C. Cir. 1980). 100 Id. at 431-32 n.48. 101 539 F.2d 775 (D.C. Cir. 1976)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 131 of 373 endangers is valid simply on grounds that the EPA e stablished a NAAQS for that pollutant. 102
These cases support our relying primarily on the an alysis and conclusions in our previous Endangerment Findin g, and the subsequent assessments, as providing a rational bas is for our decision to impose standards of performance on GHG emissions

from fossil-fuel fired EGUs. In comments on the original proposal, c ommenters state that because the proposed rulemaking limits emissions of only CO 2 , and not other GHGs, the EPA cannot rely on the analysis and conclusions in the 2009 Endangerment Finding becaus e it

concerned a mix of six GHGs: carbon dioxide and fiv e others. These commenters assert that as a prerequisite for regulating CO 2 emissions alone , the EPA must make an endangerment finding for

CO 2 alone. Because the present proposal also limits emissions of only CO 2 , and not the other GHGs, we expect that the same i ssue may arise with respect to this proposal. Commenters’ assertion
is incorrect for two reasons. First, as discussed a bove, the EPA does not need to make a formal endangerment finding with respect to a particular pollutant to set standards for that pollutant under section 111(b)(1)(B). Second, the EPA may rea sonably rely on the analysis and conclusions in the 2009 Endange rment Finding

102 Id. at 784 Deleted: C

Deleted: the present rulemaking

Deleted: here***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 132 of 373

on GHGs even when regulating only CO 2. W ith respect to this proposed rulemaking, the air pollution at issue her e is the mix of six GHGs. It is that air pollution that has caus ed the various impacts on health and welfare that formed t he basis for the Endangerment Finding. T he CO 2 emissions from EGUs are a major component of that air pollution. As we noted in the 2009 Endangerment Finding, CO 2 is the “dominant anthropogenic greenhouse gas.” 103 The fact that we are not regulating the other five GHGs in this rulemaking does not mean th at we are required to identify the air pollution as CO 2 alone rather than

the mix of six GHGs. This is consistent with the EPA ’s past actions. In the 2010 Light Duty Vehicle Rule for wh ich the Endangerment Finding served as the predicate, the E PA regulated only four of the GHGs, not all six. 104
Further, the fact that affected EGUs emit almost 1/ 3 of all U.S. GHGs and comprise by far the largest stationar y source category of GHG emissions, along with the fact that the CO 2 emissions from even a single new coal-fired power p lant may amount to millions of tons each year, provide a rational basis for regulating CO 2 emissions from affected EGUs. 105 This is

103 74 Fed. Reg. 66,496, 66,519 (Dec. 15, 2009 ) 104 75 Fed. Reg. 25,324, 25,396-97 (May 7, 2010). 105 Commenters on the original proposal stated that ne w solidfuel fired power plants made no contribution to air pollution Deleted: because, Deleted: w

Deleted: Further, Comment [A50]: This sentence is quite bulky. Consider whether the highlighted text could be deleted in this sentence, and then redrafted as a n ew sentence that follows the final clause in this sentence. In some way, this “Second,” sentence should be drafted to be more concise and straightforward.

EPA: Text has been revised.

Deleted: t Deleted: cause or contribute significantly to

Deleted: as discussed above, Deleted: s Deleted: Deleted: Indeed, so great is the contribution of CO 2 air pollutants from EGUs to GHG air pollution, that it is simply not necessary in this rulemaking to determine the specific threshold for when a contribution may be considered to be a “significant[]” contribution. 106 There can be no question that whatever that threshold may be, GHG emissions from fossil-fuel fired EGUs exceed it. 107 Deleted: [placeholder: Cite Deleted: CITE TO LIGHT DUTY VEHICLE RULE***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 133 of 373 consistent with previous EPA actions that have been upheld by

the D.C. Circuit. In the National Lime Association v. EPA case, noted above, the Court upheld the EPA’s regulation of lime
plants on grounds that they were one of the largest -- although not within the largest 10 percent -- emitting indus tries of particulates. The Court stated, EPA ... focused ...on the sheer quantity of dust ge nerated by lime plants. 42 Fed. Reg. 22507 (“A study performed for EPA in 1975 by the Research Corporation of New Engl and ranked the lime industry twenty-fifth on a list of 112 stationary sources categories which are emitters of particulate matter”); SSEIS 8-2 (“In a study perfor med for EPA by Argonne National Laboratory in 1975, the lim e industry ranked seventh on a list of the 56 largest particulate source categories in the U.S.”). 108
In the National Asphalt Pavement Ass’n v. Train case, noted above, the Court upheld the EPA’s determination tha t the asphalt industry contributed significantly to the air pollu tion based on “the number of existing plants, the expected rate o f growth in the number of plants, the rate of uncontrolled emis sions, and the level of emissions currently tolerated.” 109

because EPA’s modeling projected no new constructio n of those types of plants. However, CAA §111(b)(1)(A) is cl ear by its terms that the source category listing that is the prerequisite to regulation is based on the contribution of the “ category” to air pollution, and therefore is not based on the co ntribution of only new sources in the category. The same reasonin g applies to the rational basis determination. 108 627 F.2d at 432, n.48. 109 539 F.2d at 784-85.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 134 of 373 F. Alternative findings of endangerment and signifi cant
contribution Even if CAA section 111 is interpreted to require t hat the EPA make endangerment and cause-or-contribute signi ficantly findings as prerequisites for today’s rulemaking, t hen our rational basis, as described, should be considered to constitute those findings. As noted above, the EPA’s rational basis for regula ting

under § 111 GHGs is based primarily on the analysis and conclusions in the EPA’s 2009 Endangerment Finding and 2010 denial of petitions to reconsider that Finding, cou pled with the
2010, 2011, and 2012 assessments from the IPCC and NRC that describe scientific developments since those EPA ac tions. In
addition, as noted above, we would review comments presenting

other scientific information to determine whether t hat information has any meaningful impact on our primar y basis. This rational basis approach is substantially simil ar to the approach the EPA took in the 2009 Endangerment Finding and the 2010 denial of petitions to reconsider. As note d, the D.C. Circuit upheld that approach in the CRR case. Accordingly, that approach would support an endangerment finding for this rulemaking.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 135 of 373 By the same token, if the EPA were required to make a cause-or-contribute-significantly finding for CO 2 emissions from the fossil fuel-fired EGUs, as a prerequisite to re gulating such
emissions under CAA § 111, the same facts that support our rational basis determination would support such a f inding. In particular, as noted, fossil fuel-fired EGUs emit almost 1/3 of all U.S. GHG emissions, and constitute by far the l argest single stationary source category of GHG emissions ; and the CO 2 emissions from even a single new coal-fired power p lant may amount to millions of tons each year. It should be noted that at

present, it is not necessary for the EPA to decide whether it

must identify a specific threshold for the amount of emi ssions from a source category that constitutes a significa nt contribution. Under any reasonable threshold or def inition, the emissions from EGUs are a significant contribution. 110

G. Comments on the state of the science of climate change The EPA received a number of comments in response t o the original proposed NSPS rule addressing the scientific underpinnings of the EPA’s 2009 Endangerment Findin g and, in essence, the scientific justification for this rule

. Because

110 Indeed, it is literally true that if fossil-fuel f ired EGUs cannot be found to contribute significantly to GHG air pollution, then there is no source category in the U.S. that does contribute significantly to GHG air pollution, a result that would defeat the purposes of CAA §111. Deleted:

.

Deleted: Thus, even

Deleted: if the EPA were required tomake a cause-or-contributesignificantly finding as part of setting standards under section 111(b)(1)(B), Deleted: would Deleted: be

Deleted: that addressed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 136 of 373 this action is not a final action, we are not requi red to respond to those comments. Even so, we ha ve carefully reviewed
all of those comments, and we do provide some responses in this action. It is important to place these comments in the context of the voluminous record on this subject that has b een compiled over the last few years. This includes: 1) the proc ess by which the Administrator reached the 2009 finding that GHG s are reasonably anticipated to endanger the public healt h and welfare of current and future generations; 2) the EPA’s res ponse in 2010 to ten administrative petitions for reconsideration of the Endangerment Finding, the “Reconsideration Denial”; and, 3) the decision by the United States Court of Appeals for the DC Circuit (DC Circuit Court) in 2012 to uphold the En dangerment Finding and the Reconsideration Denial. As outlined in Section VIII.A. of the 2009 Endanger ment Finding, the EPA’s approach to providing the techni cal and

scientific information to inform the Administrator’ s judgment regarding the question of whether GHGs endanger hum an health and welfare was to rely primarily upon the recent, majo r assessments by the U.S. Global Change Research Program (USGCRP) , the Intergovernmental Panel on Climate Change (IPCC), a nd the National Research Council (NRC) of the National Aca demies. In
brief, these assessments addressed the scientific i ssues that Deleted: The EPA Deleted: s Deleted: to those comments are provided in the Response to Comments document for***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 137 of 373 the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change problem, and underwent rigorous and exacting peer review by the expert com munity, as well as rigorous levels of U.S. government review a nd acceptance, in which the EPA took part. The EPA rec eived thousands of comments on the proposed Endangerment Finding and responded to them in depth in an 11-volume RTC docu ment. While the EPA gave careful consideration to all of the scientific and technical information received, it placed less weig ht on the

much smaller number of individual studies that were not considered or reflected in the major assessments—of ten these studies were published after the submission deadlin e for those larger assessments. Primary reliance on the major s cientific assessments provided the EPA greater assurance that it was basing its judgment on the best available, well-vet ted science

that reflected the consensus of the climate science community, rather than selecting the studies it would rely on.
Nonetheless, the EPA reviewed individual studies no t incorporated in the assessment literature to see if they would lead the EPA to change its interpretation of, or pl ace less weight on, the major findings reflected in the asse ssment reports. From its review of individual studies subm itted by
commenters, the EPA concluded that these studies di d not change Deleted: Response to Comments ( Deleted: )

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 138 of 373 the various conclusions or judgments the EPA would draw based on the more comprehensive assessment reports. The majo r findings of the USGCRP, IPCC, and NRC assessments supported the EPA’s determination that GHGs threaten the public health and welfare of current and future generations. The EPA demonstr ated this scientific support at length in the Endangerment Fi nding itself, in its Technical Support Document (which summarized the findings
of USGCRP, IPCC and NRC), and in its RTC document. The EPA then reviewed ten administrative petitions for reconsideration of the Endangerment Finding in 2010 . The Administrator denied those petitions in the “Recons ideration

Denial” on the basis that the Petitioners failed to provide substantial support for the argument that the Endan germent Finding should be revised and therefore their objec tions were not of “central relevance” to the Finding. 111 The EPA prepared an accompanying 3-volume RTP document to provide ad ditional
information, often more technical in nature, in res ponse to the arguments, claims, and assertions by the petitioner s to reconsider the Endangerment Finding.

111 EPA’s Denial of the Petitions To Reconsider the End angerment and Cause or Contribute Findings for Greenhouse Gas es Under Section 202(a) of the Clean Air Act (“Reconsideration Denial”), 75 Fed. Reg. 49,556, 58 (Aug. 13, 2010). Deleted: Response to Petitions ( Deleted: )***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 139 of 373 The 2009 Endangerment Finding and the 2010 Reconsid eration Denial were challenged in a lawsuit , and on June 26, 2012, the

D

. C

. Circuit upheld the m , ruling that the y were neither arbitrary nor capricious, were consistent with Massachusetts v.

EPA, 112 and were adequately supported by the administrative

record. 113 The Court found that the EPA had based its decisio n on “substantial scientific evidence,” 114 and noted that the EPA’s

reliance on assessments was consistent with the met hods decision-makers often use to make a science-based j udgment

. 115

The Court also found that the Petitioners had “not provided substantial support for their argument that the End angerment Finding should be revised.” 117 Moreover, the Court assessed the EPA’s reliance on the major scientific assessment r eports that

were conducted by USGCRP, IPCC, and NRC, and subjected t o rigorous expert and government review, and found th at -- EPA evaluated the processes used to develop the various assessment reports, reviewed their contents , and considered the depth of the scientific consensu s the reports represented. Based on these evaluations , the EPA determined the assessments represented the best source material to use in deciding whether GHG emissions may be reasonably anticipated to endanger public health or welfare. 118

112 Massachusetts v. EPA, 549 U.S. 497. 113 CRR , 684 F.3d at 102. 114 Id at 121. 115 Id at 120. 117 Id at 125. 118 Id at 120. Deleted: ;

Deleted: Court Deleted: Endangerment Finding and the Reconsideration Denial Deleted: Finding Deleted: was Deleted: was Deleted: was

Deleted: ,

Deleted: and stated that “EPA’s interpretation of the governing CAA provisions is unambiguously correct.” 116

Deleted:

Deleted: “

Deleted: ”

Deleted: Coalition for Responsible Regulation, Inc. v. EPA , Deleted: (D.C. Cir. 2012) Deleted: bi Deleted: bi Deleted: bi Deleted: bi***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 140 of 373

As the Court stated,

It makes no difference that much of the scientific evidence in large part consisted of ‘syntheses’ of individual studies and research. Eve n individual studies and research papers often synthesize past work in an area and then build upon it. This is how science works. The EPA is not requi red to re-prove the existence of the atom every time it approaches a scientific question. 119

It is within the context of this extensive record, and recent affirmation of the Endangerment Finding by t he Court,

that the EPA has considered all of the submitted sc ience-related comments and reports for the April 2012 proposed ru le, and will consider any further comments in response to today’ s proposed

rule. As we did in the original Endangerment Finding, the EPA is giving careful consideration to all of the scientif ic and
technical information in the record. However, the m ajor peerreviewed scientific assessments continue to provide the primary scientific and technical basis upon which the Admin istrator’s judgment relies regarding the threat to public heal th and welfare posed by GHGs. Commenters on the April 2012 proposed rule submitte d two major peer-reviewed scientific assessments that wer e released since the administrative record concerning the Enda ngerment

119 Id at 120. Deleted: “

Deleted: ”

Deleted: it

Deleted: bi***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 141 of 373 Finding was closed after the EPA’s 2010 Reconsidera tion Denial: the IPCC Special Report on Managing the Risks of Ex treme Events and Disasters to Advance Climate Change Adaptation (2012) (SREX) and the NRC Report on Climate Stabilization Targets : Emissions, Concentrations, and Impacts over Decades to Millenn ia (2011) (Climate Stabilization Targets) . The EPA has reviewed these assessments and they are briefly characterized here :

SREX. The IPCC SREX assessment states that, “A changing climate leads to changes in the frequency, intensit y, spatial extent, duration, and timing of extreme wea ther and climate events, and can result in unprecedented ext reme weather and climate events.” The SREX documents observational evidence of changes in some of the we ather and climate extremes that have occurred globally si nce 1950. The SREX assessment provides evidence regarding the attribution of some of these changes to elevated concentrations of GHGs, including warming of extrem e daily temperatures, intensification of extreme precipitat ion events, and rising extreme coastal high water due t o increases in sea level. The assessment notes that further increases in some extreme weather and climate event s are projected over the 21st century. The assessments also conclude that, combined with increasing vulnerability and exposure of populations and assets, changes in extr eme weather and climate events have consequences for di saster risk, with particular impacts on the water, agricul ture and food security, and health sectors. Climate Stabilization Targets. The NRC Climate Stabilization Targets assessment st ates that, “Emissions of carbon dioxide from the burning of fossil fuels have ushered in a new epoch where huma n activities will largely determine the evolution of Earth’s climate. Because carbon dioxide in the atmosphere i s long lived, it can effectively lock Earth and future gen erations into a range of impacts, some of which could become very severe.” The assessment addresses the fact that emi ssions of carbon dioxide will alter the composition of the atmosphere, and therefore the climate, for thousand s of Deleted: (2012)

Deleted: Special Report on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation (SREX), Intergovernmental Panel on Climate Change, 2012. Deleted: ¶

Deleted: also

Deleted: Further Deleted: F Deleted: Combined

Deleted: Report on Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia , National Research Council, 2011.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 142 of 373 years and attempts to quantify the implications of stabilizing GHG concentrations at different levels. The report also estimates a number of specific climate change impacts, finding warming could lead to increases in heavy rainfall and decreases in crop yields and Arctic se a ice extent, along with other important changes in preci pitation and stream flow. For an increase in global average temperature of 1 to 2 oC above pre-industrial level s, the assessment found that the area burnt by wildfires i n western North America will likely more than double and coral bleaching and erosion will increase due both to warming and ocean acidification; an increase of 3 o C will lead to a sea level rise of 0.5 to 1.0 meters by 2100; and with an increase of 4 oC, the average summer in the United States would be as warm as the warmest summers of t he past century. The assessment notes that although many im portant aspects of climate change are difficult to quantify , the risk of adverse impacts is likely to increase with increasing temperature, and the risk of dangerous s urprises can be expected to increase with the duration and m agnitude of the warming. A number of other National Academy assessments rega rding climate have also been released recently. The EPA h as reviewed these assessments, and finds that the improved unde rstanding of the climate system resulting from the two assessmen ts described

above and the National Academy assessments strengthens the case that GHGs are endangering public health and welfare . Perhaps the most dramatic change relative to the prior assessme nts concern
sea level rise. T he previous 2007 IPCC AR4 assessment projected a rise in global sea level of between 7 and 23 inch es by the end of the century relative to 1990 (with an acknowledg ment that inclusion of ice sheet processes that were poorly u nderstood would likely increase those projections)

. T hree new NRC Deleted: 1.6 to 3.3 feet

Comment [A51]: Add cites?

Deleted: other

Deleted: is that, where Deleted: t

Deleted: , Deleted: t***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 143 of 373 assessments have provided estimates of projected se a level rise

that are much larger, in some cases more than twice as large as the previous IPCC estimates

. Climate Stabilization Targets; National Security Implications for U.S. Naval Force s (2011); Sea Level Rise for the Coasts of California, Oregon, an d Washington:
Past, Present, and Future (2012). While the three NRC assessments continue to recognize and characterize the uncertainty inherent in accounting for ice sheet pr ocesses, these revised estimates strongly support and streng then the existing finding that GHGs are reasonably anticipat ed to endanger human health and welfare. Other key findin gs of the recent assessments are described briefly below:

The Sea Level Rise for the Coasts of California, Oregon , and Washington: Past, Present, and Future (2012) assessment notes that observations have shown that sea level r ise on the West Coast has risen south of Cape Mendocino ov er the past century but dropped north of that point during that time due to tectonic uplift and other factors in Or egon and Washington. However, the assessment projects a glob al sea level rise of 1.6 to 4.6 feet by 2100, which is suf ficient to lead to rising relative sea level even in the no rthern states. The National Security Implications of Climate Change for U.S. Naval Forces also considers potential impacts of sea level rise, using a range of 1.3 to 6.6 feet by 2100. This assessment also suggests preparing fo r increased needs for humanitarian aid, responses to climate change in geopolitical hotspots including possible mass migrations, and addressing changing security needs in the Arctic as sea ice retreats. The Climate and Social Stress: Implications for Security Analysis (2012) assessment found that it would be “prudent for security analysts to expect climate surprises in the coming decade . . . and fo r them to become progressively more serious and more frequ ent thereafter[.]” Understanding Earth’s Deep Past: Lessons for Deleted: (Climate Stabilization Targets, National Security Implications for U.S. Naval Forces in 2011, and Sea Level Rise for the Coasts of California, Oregon, and Washington: Past, Present, and Future in 2012) Deleted: twice as large or more***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 144 of 373

Our Climate Future (2011) examines the period of Earth’s history prior to the formation of the Antarctic and Greenland Ice Sheets because CO 2 concentrations by the end of the century will have exceeded levels seen in th e 30 million years since that time. The assessment discu sses the possibility that analogous paleoclimate states migh t suggest higher climate sensitivity, less well regul ated tropical surface temperatures, higher sea level ris e, more anoxic oceans, and more potential for non-linear ev ents such as the Paleo-Eocene Thermal Maximum than previ ously estimated. The assessment notes that three or four out of the five major coral reef crises of the past 500 mi llion years were probably driven by acidification and war ming caused by GHG increases similar to the changes expe cted over the next hundred years. The assessment states that “the magnitude and rate of the present greenhouse g as increase place the climate system in what could be one of the most severe increases in radiative forcing of t he global climate system in Earth history.” Similarly, the Ocean Acidification: A National Strategy to Meet th e Challenges of a Changing Ocean (2010) assessment found that “[t]he chemistry of the ocean is changing at an unprecedented rate and magnitude due to anthropogen ic carbon dioxide emissions; the rate of change exceed s any known to have occurred for at least the past hundre ds of thousands of years.” The assessment notes that the full range of consequences is still unknown, but the ris ks “threaten coral reefs, fisheries, protected species , and other natural resources of value to society.”

Several commenters on the April 2012 proposed rule argue that the Endangerment Finding should be reconsidere d or overturned based on those commenters’ reviews of sp ecific climate science literature, particularly newer publ ications that have appeared since the EPA’s 2010 Denial of Petiti ons. Some commenters have presented their own compilations of individual studies as support for their assertions that climat e change will have beneficial effects in many cases and that clim ate impacts***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 145 of 373

will not be as severe or adverse as the EPA and ass essments like the USGCRP (2009) report have stated. These comment ers conclude that U.S. society will continue to easily adapt to climate change and that climate change therefore does not p ose a threat

to human health and welfare.

The EPA has reviewed the information submitted and finds
that, the fundamental issues raised in the comments that critique the scientific justification for the rule have been addressed by the EPA’s 11-volume response to commen ts for the 2009 Endangerment Finding, the EPA’s responses to a ll issues raised by Petitioners in the R econsideration Denial , or the D.C. Circuit in its 2012 decision to uphold the EPA’s 20 09 Endangerment Finding. The se comments do not change the various conclusions or judgments that the EPA would draw ba sed on the assessment reports relied upon in the recent 2009 F inding. These comments often highlight uncertainty regardin g climate science as an argument for reconsideration. However, uncertainty was explicitly recognized in the 2009 E ndangerment Finding: “The Administrator acknowledges that some aspects of climate change science and the projected impacts ar e more certain than others”, 120 and the decision to find endangerment was made with full recognition of the uncertainty i nvolved. In

120 74 FR 66524. Deleted: either

Deleted: for Deleted: r Deleted: of the 2009 Endangerment Finding Deleted: Court Deleted: EPA has nonetheless carefully reviewed these comments and finds again that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 146 of 373
addition, the D.C. Circuit Court decision noted tha t, “the existence of some uncertainty does not, without mor e, warrant invalidation of an endangerment finding.” 121 In short, these recent publications submitted by commenters, and an y new issues
that are extracted from them, do not undermine eith er the significant body of scientific evidence that has ac cumulated over the years or the conclusions presented in the substantial peer-reviewed assessments of the USGCRP, NRC, and I PCC. Regarding the contentions that the U.S. will adapt to climate change impacts and that therefore climate c hange impacts pose no threat, the EPA stated in the 2009 Endanger ment Finding, Risk reduction through adaptation and GHG mitigatio n measures is of course a strong focal area of scientists and policy makers, including the EPA; however, the EPA considers adaptation and mitigatio n to be potential responses to endangerment, and as such has determined that they are outside the scope of t he endangerment analysis. 122

The D

. C

. Circuit upheld this position, ruling that “These contentions [that the U.S. can adapt] are foreclose d by the language of the statute and the Supreme Court's dec ision in Massachusetts v. EPA” because “predicting society’s adaptive response to the dangers or harms caused by climate change” does

121 CRR , 684 F.3d at 121. 122 74 FR 66512 (emphasis added). Deleted: “

Deleted: ” Deleted:

Deleted: Court

Deleted: Coalition for Responsible Regulation, Inc. v. EPA , Deleted: (D.C. Cir. 2012)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 147 of 373 not inform the “scientific judgment” that the EPA i s required to take regarding Endangerment. 123
Some commenters raise issues regarding the EPA Insp ector General’s report, Procedural Review of EPA’s Greenhouse Gases Endangerment Finding Data Quality Processes ([Date]) . These commenters mischaracterize the report’s scope and c onclusions and, thus, vastly overstate the significance of the Inspector General’s procedural recommendations. Ultimately, n othing in the Inspector General report questions the validity of the EPA’s Endangerment Finding because that report did not ev aluate the scientific basis of the Endangerment Finding. Rathe r, the Inspector General offers recommendations for clarif ying and standardizing internal procedures for documenting d ata quality and peer review processes when referencing existing peer
reviewed science in the EPA actions. Unrelated to t he

E ndangerment F inding and its validation by the Court, the EPA has made progress towards implementing the recommen dations by the Inspector General

. One commenter submitted a number of emails from the period 1999 to 2009 that were obtained from a University o f East Anglia server in 2009 and publicly released in 2011. After reviewing these emails, the EPA finds that they raise no issu es that were

123 984 F.3d at 117. Deleted: e Deleted: f Deleted: Circuit Deleted: OIG***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 148 of 373 not previously raised by Petitioners in regard to a n earlier group of emails from the same incident, released in 2009. The commenter makes unsubstantiated assumptions and sub jective assertions regarding what the e-mails purport to sh ow about the state of climate change science; this provides inad equate evidence to challenge the voluminous and well docum ented body of

science that is the technical foundation of the Adm inistrator’s Endangerment Finding. A number of comments were also submitted in support of the Endangerment Finding and/or providing further evide nce that climate change is a threat to human health and welf are. A number

of individual studies were submitted and a number o f observed or projected climate changes of local importance or co ncern to commenters were documented. Again, the EPA places l esser weight on individual studies than on the major scientific assessments. Local observed changes can be of great concern to i ndividuals

and communities but must be assessed in the context of the broader science, as it is more difficult to draw ro bust conclusions regarding climate change over short tim e scales and in small geographic regions. V. Rationale for Applicability Requirements A. Applicability requirements - original proposal a nd comments***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 149 of 373 The original proposal was designed to apply to new

intermediate and base load EGUs, specifically, 1) fossil fuelfired utility boiler s and IGCC EGUs subject to subpart Da for criteria pollutant emissions, and 2) natural gas combined cycle EGUs subject to subpart KKKK for criteria pollutan t emissions. The original proposal explicitly did not apply to s imple cycle turbines because we concluded that they were operat ed infrequently and therefore only contributed small a mounts to total GHG emissions. (For convenience, we occasiona lly refer to this explicit statement that the original proposed NSPS did not apply to a type of source as anexclusion

. ) We received comments that supported the simple cycl e exclusion and others that opposed it. Commenters in support stated that a new simple cycle power plant serves a different purpose than a new combined cycle plant and that ec onomics will drive the use of combined cycle facilities over sim ple cycle plants. They also stated that the original proposed standard is not achievable by, and therefore is not BSER for, s imple cycle turbines. Commenters opposing the exclusion stated that it creates an opportunity to evade the standard and co uld thereby increase GHG emissions. According to these commente rs, any applicability distinctions should be based on utili zation and function rather than purpose or technology. Deleted: baseload

Deleted: /steam turbines

Deleted: Deleted:

.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 150 of 373 After considering these comments, we are proposing a different approach to the applicability provisions. B. Applicability requirements – today’s proposal In today’s rulemaking, we propose that applicabilit y should be based on electric sales alone, so that the propo sed standards of performance apply to a facility if the facility supplies more than 1/3 of its potential electric output and more than 219,000 MWh net electric output to the grid per year . (We refer to a facility’s sale of more than one-third of its poten tial electric output as the one-third sales criterion, and we refer to the amount of potential electric output s upplied to a utility power distribution system, expressed in MWh, as the capacity factor.) This proposed definition does not explicitly exclud e simple cycle combustion turbines, but as a practical matte r, it would exclude most of them because the vast majority of s imple cycle

turbines sell less than one-third of their potential electric

output. T he few simple-cycle combustion turbines that sell more than 1/3 of their potential electric output to the grid would be subject to the proposed standards of performance. A s explained

below , we have concluded that at this level of output, there are less expensive and lower emitting technologies that could be constructed consistent with today’s proposed standa rds. Although, as noted, today’s proposal does not expli citly exclude Comment [A52]: We would suggest adding a more clear justification for why EPA thinks this exclusion is needed. The description here seems to focus on why the exclusion was structured the way that it is versus why it is appropriate or what it is trying to achieve. EPA: Discussion has been revised/expanded. Deleted: sells

Deleted: 33 percent

Deleted: old

Deleted: 1/3

Comment [A53]: Please add a description that indicates what, generally, the other 2/3 of electri c output goes towards. EPA: The vast majority of simple cycle CTs operate less than one-third of their potential output ... so the remaining 2/3 of capacity is never generated becaus e the units are not operational. Deleted: For Deleted: for t***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 151 of 373 simple cycle combustion turbines, we solicit commen t on whether to provide an explicit exclusion. We are proposing to apply the one-third sales criterion on a rolling three year basis instead of an annual bas is for stationary combustion turbines for multiple reasons . First, extending the period to three years would permit fa cilities intended to generally operate at low capacity facto rs (e.g. simple cycle turbines that sell less than 1/3 of th eir potential electric output) to provide system capacity and ope rate at high capacity factors during individual years with abnor mally high electric demand. Second, only 0.2 percent of existi ng simple cycle turbines had a three-year average capacity fa ctor of greater than one-third between 2000 and 2012. Therefore, as noted, from a practical standpoint, few new simple cycle

turbines will be subjected to the standards of performance in this rulemaking. The 2013 AEO cost and performance characteristics f or new generation technologies include costs for advanced and conventional combined cycle facilities and advanced simple cycle

turbines. A ccording to the AEO 2013 values , advanced combined cycle facilities have a lower cost of electricity t han advanced simple cycle turbine facilities above approximately a 20 percent capacity factor. Therefore, the use of a combined c ycle Deleted: 33 percent

Deleted: 33 percent

Deleted: In addition, a Deleted: cost and performance characteristics for new generation technologies***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 152 of 373 technology would be BSER for higher capacity factor stationary

combustion turbines. However, a dvanced combined cycle facilities do not have a lower cost of electricity than less capital

intensive conventional combined cycle facilities until above approximately a 40 percent capacity factor. Between approximately 20 to 40 percent capacity factors, co nventional combined cycle facilities offer the lowest cost of electricity, and below approximately 20 percent capacity factors advanced simple cycle turbines offer the lowest cost of elec tricity. A capacity factor exemption at 40 percent (i.e., sell less than 2/5 of potential electric output per year) would allow

conventional combined cycle facilities built with the intent to operate at relatively low capacity factors as an alternative
technology to simple cycle turbines because neither would be subject to the NSPS requirements. Based on these co st considerations, we are specifically requesting comm ent on a range of 20 to 40 percent of potential electric out put sales on a three-year basis for the capacity factor exemptio n. The 20 percent applicability limit is consistent with generating the lowest cost of electricity for advanced combined cy cle turbines compared to advanced simple cycle turbines , and based on historical capacity factors would impact the operat ion of only approximately two percent of simple cycle turbines. The 40 Deleted: In addition, the 2013 AEO cost and performance characteristics for new generation technologies include costs for a conventional combined cycle facility. Deleted: A

Deleted: for Deleted: to compete with

Deleted: lower range***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 153 of 373 percent applicability limit would be more consistent with the

annual run hour limitations currently contained in many simple cycle operating permits. We are also requesting comments on whether applicab ility for stationary combustion turbines should be define d on a single calendar year basis, similar to the subpart Da appl icability provisions, instead of a three-year basis. With a s ingle year basis, we are considering an applicability level of up to 40 (instead of one-third ) percent sales. Only 0.4 percent of existing simple cycle turbines had an annual capaci ty factor of greater than 40 percent between 2000 and 2012. Assu ming the average hourly output of a simple cycle turbine is 80 percent of the maximum rated output, a simple cycle turbine co uld operate up to 4,400 hours annually before exceeding the cap acity factor threshold. This is consistent with the operation ho ur limitation in many permits. Therefore, with this 40 percent sa les criterion on a single-year basis, as a practical matter, it is anticipated

that few new simple cycle turbines would be subject to t he proposed standards of performance. Thus, w e are specifically requesting comment on a range of 1/3 to 2/5 of pote ntial electric output annual sales. The lower range would be consistent with how an EGU is currently defined in the EPA rules, and would mean that the proposed standards o f performance Deleted: upper range

Deleted: operational

Deleted: and would provide significant operational flexibility

Deleted: 33 percent

Deleted: W***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 154 of 373 would impact approximately one percent of new simpl e cycle

turbines. We are also proposing a different definition of pot ential electric output from the current definition that determines the potential electric output (in MWh on an annual basi s) considering only the design heat input capacity of the facility and does not account for efficiency. It assumes a 33 percent net electric efficiency, regardless of the actual effic iency of the facility and could discourage the installation of more effi cient facilities. For example, a 33 percent efficient 100 MW facility would have a heat input of 1,034 MMBtu/h and a 40 p ercent efficient 100 MW facility would have a heat input o f 853
MMBtu/h

. 124 The 33 percent efficient facility would have become subject the NSPS requirements when it sells more th an one-third

of its potential electric output , 8 80 ,000 MWh . The 40 percent efficient facility would become subject the NSPS requirements

when it sells more than 73 0 ,000 MWh. 125 This could potentially encourage the construction of less efficient facili ties, since they could have a higher actual capacity factor tha n a more

124 (100 MW)*(3.412 MMBtu/h/ 1 MWh)*(1/0.33) = 1,034 M MBtu/h (100 MW)*(3.412 MMBtu/h/ 1 MWh)*(1/0.40) = 853 MMBt u/h 125 (1,034 MMBtu/h)*(1 MWh/3.412MMBtu/h)*(1/3)*(8,760h /yr) = 880,000 MWh (853 MMBtu/h)*(1 MWh/3.412MMBtu/h)*(1/3)*(8,760h/yr ) = 730,000 MWh Deleted: to

Deleted: in subpart Da. The existing definition is based on the design heat input capacity and

Deleted: This could potentially have a negative impact on more efficient facilities. For example, a Deleted: 100 MW Deleted: a Deleted: of Deleted: 76 Deleted: Deleted: and Deleted: a Deleted: 100 MW Deleted: have a potential electric output of only Deleted: 2

Deleted: ¶***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 155 of 373 efficient unit, while still not being an EGU subjec t to a CO 2 standard. Therefore, we are proposing a definition of potential electric output that allows the source the option o f calculating its potential electric output on the basis of its a ctual design electric output efficiency on a net output basis, a s an
alternative to the default one-third value. The proposed definition would permit the 40 percent efficient fa cility to use the actual efficiency of the facility so that the e lectric sales applicability criteria would be 880,000 MWh and app licability

would be determined the same as for the less effici ent facility. The April 2012 proposal would have applied to facil ities that primarily burn non-fossil fuels but also co-fi re a fossil fuel. We have concluded that it is not appropriate to subject these facilities to the standards in today’s propos al. The EPA believes this is appropriate because these types of units more closely resemble the non-fossil fuel-fired boilers and stationary combustion turbines that are not covered by today’s proposed rule, than they do the fossil fuel-fired boilers and stationary combustion turbines that are covered by this rule. This approach is similar to the approach used in th e Mercury and

Air Toxics Standards , another CAA regulatory effort focused on

fossil fuel-fired power plants. Therefore, we are proposing to limit the applicability of the standard to faciliti es where the Deleted: 33 percent

Deleted:

Deleted:

-

Deleted:

-

Deleted: rule

Deleted:

- Deleted: Comment [A54]: EPA should add more explanation of its rational for this determination. EPA: Discussion has been revised/expanded.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 156 of 373 heat input is comprised of more than 10.0 percent f ossil fuel on a three-year rolling average basis. To simplify det ermining applicability with the CO 2 standard, we also request comment on whether the applicability for facilities that co-fi re non-fossil fuels should be made on an annual average basis, in stead of a three-year rolling average basis. In the original proposal, we requested comment on t he applicability of the GHG NSPS to combined heat and power (CHP)

facilities and if applicability should be changed from how it is currently determined in subpart Da. We have conclud ed that if CHP facilities meet the general applicability crite ria they should be subject to the same requirements as elect ric-only generators. However, one potential issue that we ha ve identified is inequitable applicability to third-party CHP dev elopers compared to CHP facilities owned by the facility us ing the thermal output from the CHP facility. The current definition of net electric output (used in the 1/3 sales applicab ility criteria) is “the gross electric sales to the utili ty power distribution system minus purchased power on a cale ndar year basis. Owners/operators of a CHP facility located a t a facility
they own can subtract out power purchased at that f acility on an annual basis when determining applicability. Howeve r, t hirdparty CHP developers would not be able to benefit f rom the Deleted: This approach is similar to that of the Mercury and Air Toxics Standards.

Deleted: it

Deleted: T

Deleted: have Deleted: en***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 157 of 373 “minus purchased power on a calendar year basis” in the definition of net electric output when determining applicability since the thermal host(s) are not part of the same affected facility. We are therefore proposing to add “of the thermal host facility or facilities” (i.e., the gross electric sales to the utility power distribution system minus purchased p ower of the thermal host facility or facilities on a calendar y ear basis to the definition of net-electric output for qualifyin g CHP facilities. This would make applicability consisten t for both facility-owned CHP and third-party-owned CHP. This proposal includes within the definition of a steam electric generating unit, IGCC, and stationary comb ustion turbine that are subject to the proposed requiremen ts, any integrated device that provides electricity or usef ul thermal output to the boiler , the stationary combustion turbine or to power auxiliary equipment

. The rationale behind including integrated equipment recognizes that the integrated equipment may be a type of combustion unit that emits GHGs, a nd that it is important to assure that those GHG emissions are included as part of the overall GHG emissions from the affected source. Including integrated equipment avoid s circumvention of the requirements by having a boiler not subject to the standard supplying useful energy input (e.g., an industrial boiler Deleted: adding “

Deleted: either Deleted: / Deleted: ” in the definition of a steam electric generating unit, IGCC, and stationary combustion turbine in subparts Da and KKKK respectively. Deleted: is***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 158 of 373 supplying steam for amine regeneration in a CCS system) without accounting for the GHG emissions when determining compliance with the NSPS. In addition, the proposed definition would provide additional compliance flexibility similar to when the HRSG was included in the combustion turbine NSPS by recognizing the environmental benefit of integrated equipment t hat lowers the overall emissions rate of the affected facility . Even without this specific language, the original 1979 s team electric generating unit definition in subpart Da allows the use of solar

thermal equipment for feedwater heating as an approach to integrating non-emitting generation to reduce envir onmental impact and lower the overall emissions rate. The cu rrent definition expands the flexibility to include combu stion turbines, fuel cells, or other combustion technolog y for reheating or preheating boiler feedwater, preheatin g combustion air, producing steam for use in the steam turbine o r to power the boiler feedpumps, or using the exhaust directly in the boiler to generate steam. This in theory could lowe r generation

costs as well as lower the GHG emissions rate for a n EGU. VI. Legal Requirements for Establishing Emission St andards

A. Overview In this section, we describe the principal legal requirement for the standards of performance under CAA § 111 Deleted: , and Deleted: to Deleted: s Deleted: For example, using heat from integrated equipment to reheat boiler feedwater in a coal-fired EGU would minimize the steam otherwise extracted from the steam turbine used for the feedwater reheating process. This would decrease the size of the coal-fired boiler by approximately 1/4 for the same overall electric output, reducing the initial capitalrequired to construct the new coalfired portion of the EGU. Potential eEmission rate reductions could also occurare similar. . While IGCC and NGCC do not extract the same levels of steam for feedwater heating requirements, multiple projects exist where solar thermal is integrated into the facility to preheat the feedwater and increase the output from the steam turbine relative to an NGCC facility without integrated solar thermal. Our understanding is that one of the primary benefits of this approach is decreased incremental cost of the solar thermal generated electricity due to the ability to use equipment (e.g., HRSG, steam turbine, condenser, etc.) already included at the NGCC facility. Deleted: ¶ C. Codification in the Code of Federal Regulations ¶ In the original proposal, the EPA proposed to create within 40 CFR part 60 a new subpart that would include GHG emission regulatory requirements for electric utility steam generating units (i.e., boilers and IGCC units), whose conventional pollutant regulatory requirements are codified under subpart Da; as well as stationary combustion turbines that generate electricity for sale and meet certain size and operational criteria, conventional pollutant regulatory requirements are codified under subpart KKKK. The EPA proposed to number this newly created subpart as subpart TTTT. The EPA explained that combining the GHG regulatory requirements for those sources in TTTT was appropriate because the EPA was establishing the same limit for all those sources based on the same BSER, which was NGCC.¶ In today’s rulemaking, we propose different standards, based on different determinations of BSER, ... [1]***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 159 of 373 that we propose in this rulemaking, which is that t he standards

must consist of emission limits that are based on t he “best system of emission reduction ... adequately demons trated,” taking into account cost and other factors (BSER) . In this

manner, CAA § 111 provides that the EPA’s central task is to identify the BSER. The D.C. Circuit has handed down case law, which we review in detail, that interprets this CAA provision, including its component elements. The Court’s inter pretation indicates the technical, economic, and energy-relat ed factors that are relevant for determining the BSER, and pro vides the framework for analyzing those factors. According to the D.C. Circuit, EPA determines the b est demonstrated system based on the following key cons iderations,
among others:

• The system of emission reduction must be technicall y
feasible.

• EPA must consider the amount of emissions reduction s that the system would generate.

• The costs of the system must be reasonable. EPA may consider the costs on the source level, the industr y-wide level, and, at least in the case of the power secto r, on
the national level in terms of the overall costs of electricity and the impact on the national economy over***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 160 of 373

time.

• EPA must also consider that CAA § 111 is designed to promote the development and implementation of techn ology. Other considerations are also important, including that EPA must also consider energy impacts, and, as with cos ts, may
consider them on the source level and on the nation wide structure of the power sector over time. Importantl y, EPA has discretion to weigh these various considerations, m ay determine that some merit greater weight than others, and may vary the weighting depending on the source category. B. CAA requirements and Court interpretation 1. Clean Air Act Requirements The EPA’s basis for proposing that partial capture CCS is the BSER for new fossil fuel-fired utility boilers and IGCC units, and that NGCC is the BSER for natural gas-fi red stationary combustion turbines, is rooted in the pr ovisions of

CAA § 111 requirements, as interpreted by the United Stat es Court of Appeals for the D.C. Circuit (“D.C. Circui t” or “Court”), which is the federal Court of Appeals wit h jurisdiction over the EPA’s CAA rulemaking. As the first step towards establishing standards of performance, the EPA “shall publish ... a list of cat egories of stationary sources ... [that] cause[], or contribute[ ] Comment [A55]: This focuses on BSER instead of the standards of performance, but suggest that EPA consider referencing standards of performance here, especially since the next paragraph starts wi th that discussion. Or, consider stating that the bas is of both the standards of performance and BSER are rooted in CAA 111 and caselaw. EPA: BSER is the appropriate term as used in this paragraph.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 161 of 373 significantly to, air pollution which may reasonabl y be anticipated to endanger public health or welfare.” § 111(b)(1)(A). Following that listing, the EPA “shal l publish proposed regulations, establishing federal standard s of performance for new sources within such category” a nd then “promulgate ... such standards” within a year after p roposal. § 111(b)(1)(B). The EPA “may distinguish among classe s, types, and sizes within categories of new sources for the purp ose of establishing such standards.” § 111(b)(2). The term “standard of performance” is defined to “mean[] a standard for e missions of air pollutants which reflects the degree of emissio n limitation achievable through the application of the best syst em of emission reduction which (taking into account the c ost of achieving such reduction and any nonair quality hea lth and environmental impact and energy requirements) the A dministrator determines has been adequately demonstrated.” § 111(a)(1). 2. Court interpretation For present purposes, the key § 111 provisions are the definition of “standard of performance,” under CAA § 111(a)(1), and, in particular, the “best system of emission re duction which (taking into account ... cost ... nonair quality hea lth and environmental impact and energy requirements) ... has been adequately demonstrated.” The D.C. Circuit has revi ewed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 162 of 373 rulemakings under § 111 on numerous occasions during the past 40 years, handing down decisions dated from 1973 to 20 11, 126 through which the Court has developed a body of case law th at interprets the term “standard of performance.” These interpret ations are of central importance to the EPA’s justification for t he standards of performance in the present rulemaking. At the outset, it should be noted that Congress fir st included the definition of “standard of performance ” when enacting CAA § 111 in the 1970 Clean Air Act Amendments (CAAA),
and then amended it in the 1977 CAAA, and then amen ded it again in the 1990 CAAA, generally repealing the amendment s in the 1977 CAAA and, therefore, reverting to the version as it read after the 1970 CAAA. The legislative history for the 1970 and 1977 CAAAs explained various aspects of the definition a s it read at
those times. Moreover, the various decisions of the D.C. Circuit interpreted the definition that was applicable to t he rulemakings before the Court. Notwithstanding the a mendments to the definition, the D.C. Circuit’s interpretations discussed

126 Portland Cement Ass’n v. Ruckelshaus , 486 F.2d 375 (D.C. Cir. 1973); Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427, (D.C. Cir. 1973); Portland Cement Ass’n v. EPA , 665 F.3d 177 (D.C. Cir. 2011).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 163 of 373 below remain applicable to the current definition. 127
3. Overview of interpretation By its terms, the definition of “standard of perfor mance” under CAA § 111(a)(1) provides that the emission li mit that the EPA promulgates must be “achievable” and must be ba sed on a

127 In the 1970 CAAA, Congress defined “standard of pe rformance,” under §111(a)(1), as— a standard for emissions of air pollutants which reflects the degree of emission limitation achievab le through the application of the best system of emiss ion reduction which (taking into account the cost of achieving such reduction) the Administrator determi nes has been adequately demonstrated. In the 1977 CAAA, Congress revised the definition t o distinguish among different types of sources, and t o require that for fossil fuel-fired sources, the standard (i ) be based on, in lieu of the “best system of emission reducti on ... adequately demonstrated,” the “best technological s ystem of continuous emission reduction ... adequately demonstr ated;” and (ii) require a percentage reduction in emissions. I n addition, in the 1977 CAAA, Congress expanded the parenthetic al requirement that the Administrator consider the cos t of achieving the reduction to also require the Adminis trator to consider “any nonair quality health and environment impact and energy requirements.” In the 1990 CAAA, Congress again revised the defini tion, this time repealing the requirements that the stand ard of performance be based on the best technological syst em and achieve a percentage reduction in emissions, and re placing those provisions with the terms used in the 1970 CAAA ver sion of §111(a)(1) that the standard of performance be base d on the “best system of emission reduction ... adequately dem onstrated.” This 1990 CAAA version is the current definition, w hich is applicable at present. Even so, because parts of th e definition as it read under the 1977 CAAA were retained in the 1990 CAAA, the explanation in the 1977 CAAA legislative histor y, and the interpretation in the case law, of those parts of t he definition remain relevant to the definition as it reads today

.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 164 of 373 system of emission reduction – generally, but not r equired to be always, a technological control -- that the EPA det ermines to be the “best system” that is “adequately demonstrated, ” “taking into account ... cost ... nonair quality health and env ironmental impact and energy requirements.” The D.C. Circuit has stated that in determining the “best” system, the EPA must also take into account “the amount of air pollution” 128 and “technological

innovation.” 129
As discussed below, the D.C. Circuit has elaborate d on the criteria and process for determining whether a stan dard is “achievable,” based on an “adequately demonstrated” technology or system. In addition, the Court has identified li mits on the costs and other factors that are acceptable for the technology or system to qualify as the “best.” The Court has a lso held that the EPA may consider the costs and other factors on a regional or national level (e.g., the EPA may consider impac ts on the national economy and the affected industry as a who le) and over time, and not just on a plant-specific level at the time of the rulemaking. 130 In addition, the Court has emphasized that the EPA has a great deal of discretion in weighing the vari ous factors

128 See Sierra Club v. Costle , 657 F.2d 298, 326 (D.C. Cir. 1981). 129 See Sierra Club v. Costle , 657 F.2d at 347. 130 See Sierra Club v. Costle, 657 F.2d at 330. Deleted: may take into account***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 165 of 373 to determine the “best system.” 131 Moreover, the Court has stated that in considering the various factors and determining the “best system,” the EPA must be mindful of the p urposes of § 111, and the Court has identified those purposes as “not giv[ing] a competitive advantage to one State over another in attracting industry[,]... “reducing emissions as much as practicable[,]”... “forc[ing] the installation of all the control technology that will ever be necessary on new plant s at the time of construction[,]...” and “forc[ing] the development of improved technology.” 132 Finally, based on cases the D.C. Circuit has handed down under related provisions of the CAA and the EPA’s regulatory precedent under § 111, the EPA may promulgate a standard of performance for a particular category o f sources even if not every type of new source in the categor y would be

able to achieve that standard. 133
We next discuss in more detail each of these compon ents of the interpretation of “standard of performance.” C. Technical feasibility
The D.C. Circuit’s first decision under § 111, Portland

131 See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999). 132 Sierra Club v. Costle , 657 F.2d at 325 & n.83 (quoting 44 Fed.Reg. 33,580, 33,581/3-33,582/1). 133 See, e.g., International Harvester Co. v. EPA , 478 F.2d 615, 640 (D.C. Cir. 1973).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 166 of 373

Cement Ass’n v. Ruckelshaus , 486 F.2d 375, 391 (D.C. Cir. 1973), concerned whether EPA’s standard of performance for the cement industry met the requirement to be “achievable,” wh ich, in turn, depended on whether the technology on which EPA bas ed the standard was “adequately demonstrated.” 134 In this case, the Court interpreted these provisions to require that the technology must be technically feasible for the sou rce category, and established criteria for determining technical feasibility. The Court explained that a standard of performance is “achievable” if a technology can reasonably be proj ected to be available to new sources at the time they are const ructed that will allow them to meet the standard. Specifically, the D.C. Circuit explained:

Section 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at present, since it is addressed to standards for new plants....- It is the “achievability” of the proposed standard that is in issue.... The Senate Report made clear that it did not intend that the technology “must be in actual routi ne use somewhere.” The essential question was rather whether the technology would be available for installation in new plants.... The Administrator ma y make a projection based on existing technology, tho ugh that projection is subject to the restraints of reasonableness and cannot be based on “crystal ball ” inquiry. 135

134 486 F.2d at 390.
135 Portland Cement Ass’n v. Ruckelshaus , 486 F.2d 375, 391 (D.C. Cir. 1973) (citations omitted).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 167 of 373

In subsequent cases, the D.C. Circuit has consisten tly

reiterated this formulation of “achievable.” 136

It should be noted that in another of the early cases, Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427 (D.C. Cir. 1973), the D.C. Circuit upheld a standard of perfor mance as “achievable” on the basis of test data showing that the tested plant emitted less than or at the standard on three occasions
and emitted above the standard on 16 occasions, and that, on average, it emitted 15% above the standard on a tot al of 19

occasions. 137 The fact that the plant had achieved the standard on at least a few occasions, even though the plant had not done so on the great majority of occasions, “adequately demonstrated”

that the standard was “achievable.” D. Factors to consider in determining the “best sys tem”
1. Amount of emissions reductions Although the definition of “standard of performanc e” does not by its terms identify the amount of emissions f rom the category of sources and the amount of emission redu ctions

achieved as factors the EPA must consider in determ ining the “best system of emission reduction,” the D.C. Circu it has stated

136 See, e.g., National Asphalt Pavement Ass’n v. Trai n , 539 F.2d 775, 785 (D.C. Cir. 1976); Lignite Energy Council v . EPA, 109 F

. 3d 930, 934 (D.C. Cir. 1999).

137 Essex Chemical Corp. v. Ruckelshaus , 486 F.2d at 437 & n. 27.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 168 of 373
that the EPA must do so. See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) (“we can think of no sens ible interpretation of the statutory words “best ... syste m” which would not incorporate the amount of air pollution a s a relevant factor to be weighed when determining the optimal s tandard for controlling ... emissions”). 138 This is consistent with the Court’s statements in Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973) that it is necessary to “[k]eep[] in mind Congress' intent that new plants be controlled to t he ‘maximum practicable degree.’” 139

2. Costs In several cases, the D.C. Circuit has elaborated o n the cost factor that the EPA is required to consider un der CAA § 111(a)(1), and has identified limits to how costly a control technology may be before it no longer qualifies as the “best system of emission reduction ... adequately demonstra ted.” As a

138 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was governed by the 1977 CAAA version of the definition of “standard of performance,” which revised the phrase “best sys tem” to read, “best technological system.” The 1990 CAAA deleted “technological,” and thereby returned the phrase to how it read under the 1970 CAAA. The Sierra Club v. Costle ’s interpretation of this phrase to require consideration of the amou nt of air emissions remains valid for the phrase “best system .” 139 Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 4 37 & n. 27 (citing “Summary of the Provisions of Conference Ag reement on the Clean Air Amendments of 1970,” 116 Cong. Rec. 4 2384, 42385 (1970)).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 169 of 373 related matter, although no D.C. Circuit case addre sses how to account for revenue generated from the byproducts o f pollution control, it is logical and a reasonable interpretat ion of the

statute that any expected revenues from the sale of pollutants or pollution control byproducts associated with tho se controls may be considered when determining the overall cost s of implementation of the control technology . Clearly, such a sale would offset regulatory costs and so must be includ ed to accurately assess the costs of the standard.

a. Criteria for costs
(i) Formulation In Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit stated that to b e “adequately demonstrated,” the system must be “reasonably relia ble, reasonably efficient, and ... reasonably expected to serve the interests of pollution control without becoming exo rbitantly costly in an economic or environmental way.” The Co urt has reiterated this limit in subsequent case law, inclu ding Lignite Energy Council v. EPA , 198 F.3d 930, 933 (D.C. Cir. 1999), in

which it stated: “EPA's choice will be sustained un less the environmental or economic costs of using the techno logy are

exorbitant.” In Portland Cement Ass’n v. EPA , 513 F.2d 506, 508 (D.C. Cir. 1975), the Court elaborated by explainin g that the Deleted: the costs of the control technology should be offset by any revenues from the sale of pollutants or pollution control byproducts associated with those controls Comment [A56]: Has this been done in any other NSPS context that could be referenced here? EPA: We are still considering this; the language ha s been edited to make it more clear.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 170 of 373 inquiry is whether the costs of the standard are “greater than the industry could bear and survive.” 140
In Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981), the Court provided a substantially similar f ormulation of

the cost standard when it held: “EPA concluded that the Electric

Utilities' forecasted cost was not excessive and di d not make the cost of compliance with the standard unreasonab le. This is a judgment call with which we are not inclined to qua rrel.” We

believe that these various formulations of the cost standard – “exorbitant,” “greater than the industry could bear and survive,” “excessive,” and “unreasonable” – are syn onymous; the

140 The 1977 House Committee Report noted: In the [1970] Congress [sic: Congress’s] view, it w as only right that the costs of applying best practica ble control technology be considered by the owner of a large new source of pollution as a normal and prope r expense of doing business. 1977 House Committee Report at 184. Similarly, the 1970 Senate Committee Report stated:

The implicit consideration of economic factors in determining whether technology is “available” shoul d not affect the usefulness of this section. The overriding purpose of this section would be to prev ent new air pollution problems, and toward that end, maximum feasible control of new sources at the time of their construction is seen by the committee as the most effective and, in the long run, the least expensive approach.
S. Comm. Rep. No. 91-1196 at 16.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 171 of 373 D.C. Circuit has made no attempt to distinguish amo ng them. For convenience, in this rulemaking, we will use the “u nreasonable” formulation, so that a control technology cannot be considered the “best system of emission reduction ... adequately

demonstrated” if its costs are “unreasonable.” (ii) Examples

In the case law under CAA § 111, the D.C. Circuit has never invalidated a standard of performance on grounds th at it was too costly. In several cases, the Court upheld standard s that entailed high costs. In Portland Cement Association v.
Ruckelshaus , 486 F.2d 375 (D.C. Cir. 1973), the Court consider ed a standard of performance that the EPA promulgated for particulate matter emissions from new and modified Portland cement plants. According to the Court, the cost for the control technologies that a new facility would need to inst all to meet the standard was about 12 percent of the capital in vestment for the total facility, and annual operating costs for the control equipment would be 5-7 percent of the total plant o perating costs. The Court found that these costs “could be p assed on without substantially affecting competition” becaus e the demand for the product was not “highly elastic with regard to price and would not be very sensitive to small price changes. ” The Court held that the EPA gave appropriate consideration to the Comment [A57]: Is the case the same for EGUs? Add a FN to explain relevance. EPA: This section is just providing legal background, the relevance is explained later.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 172 of 373 “economic costs to the industry.” 141

In Sierra Club v. Costle , 657 F.2d 298 (D.C. Cir. 1981), the D.C. Circuit upheld a standard of performance i mposing
costly controls on SO 2 emissions from coal-fired power plants.

The Court noted:

The importance of the challenged standards arises not only from the magnitude of the environmental an d health interests involved, but also from the critic al implications the new pollution controls have for th e economy at the local and national levels.   Coal is the dominant fuel used for generating electricity in the United States .... In 1976 power plant emissions accounted for 64 percent of the tot al estimated sulfur dioxide emissions and 24 percent o f the total estimated particulate matter emissions in the entire country. EPA's revised NSPS are designed to curtail these emissions. EPA predicts that the new standards woul d reduce national sulfur dioxide emissions from new plants by 50 percent and national particulate matte r emissions by 70 percent by 1995. The cost of the ne w controls, however, is substantial. EPA estimates that utilities will have to spend tens of billions of dollars by 1995 on pollution control under the new NSPS. Consumers will ultimately bear these costs, b oth directly in the form of residential utility bills, and indirectly in the form of higher consumer prices du e to increased energy costs. 142

b. Revenue enhancements In determining the costs of pollution control techn ology, it is reasonable to take into account any revenues generated by

141 Portland Cement Association v. Ruckelshaus , 486 F.2d at 387- 88. 142 Sierra Club v. Costle , 657 F.2d at 313 (citations omitted) (emphasis added). Deleted: ,** *E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 173 of 373
the sale of any by-products of the control process. Many types of pollution control technology generate byproducts that must be disposed, and the costs of that disposal are consid ered part of the costs of the control technology. For example, C CS generates

a stream of CO 2 that must be disposed of through sequestration. In some instances, however, the by-products of poll ution
control have marketable value. In these cases, reve nues from selling the by-products would defray the costs of p ollution control. For example, in a recent rulemaking under the CAA regional haze program that entailed determining the “best available retrofit technology” (BART) for power pla nts, revenue from fly ash generated during boiler combustion and sold for use in concrete production factored into the State’s se lection of
BART). 144
3. Expanded use and development of technology

In Sierra Club v. Costle , the Court made clear that technological innovation was grounded in the terms of section
111 itself, and therefore should be considered one of the factors to be considered in determining the “best s ystem of

144 Similarly, the EPA has taken into account the valu e of fuel savings in determining the costs of rules that limi t emissions from motor vehicles, which limits manufacturers are expected to achieve by reducing the rates of fuel consumption b y the vehicles. See, e.g., 77 Fed. Reg. 62,624, 62,628-29; 62,923-27; 62,942-46 (October 15, 2012) (rulemaking setting GH G emissions standards for Light-Duty Vehicles for Model Years 2 017-2025). Deleted: 143

Comment [A58]: Add a citation to the State determination in the FN before sentence regarding EPA LDV rule.

EPA: Citation added.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 174 of 373

emission reduction:”

Our interpretation of section 111(a) is that the mandated balancing of cost, energy, and nonair qual ity health and environmental factors embraces consideration of technological innovation as part o f that balance. The statutory factors which EPA must weigh are broadly defined and include within their ambit subfactors such as technological innovation. 145
The Court’s interpretation finds firm grounding in the legislative history. For example, the 1970 Senate C ommittee Report stated:

Standards of performance should provide an incentive for industries to work toward constant improvement in techniques for preventing and controlling emissions from stationary sources, sinc e more effective emission control will provide greate r latitude in the selection of sites for new facilities. 146
Similarly, the 1977 Senate Committee Report stated: In passing the Clean Air Amendments of 1970, the Congress for the first time imposed a requirement f or

145 Sierra Club v. Costle , 657 F.2d at 347. 146 S.Rep. 91-1196 at 16 (1970). The technology-forcin g nature of §111 is consistent with the technology-forcing natu re of the 1970 CAAA as a whole. The principal Senate author o f the 1970 CAAA, Sen. Edmund Muskie (D-ME), during the Senate floor debate, described the overall requirements of the 1970 CAAA and then observed: These five sets of requirements will be difficult to meet. But the committee is convinced that indust ry can make compliance with them possible or impossibl e. It is completely within their control. Industry has been presented with challenges in the past that see med impossible to meet, but has been made possible. 116 Cong. Rec. 32902 (Sept. 21, 1970) (statement of Sen. Muskie).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 175 of 373 specified levels of control technology. The section 111 Standards of Performance for New Stationary Sources required the use of the “best system of emission reduction which (taking into account the c ost of achieving such reduction) the Administrator determines has been adequately demonstrated.” This requirement sought to assure the use of available technology and to stimulate the development of new technology. 147
The legislative history just quoted identifies thre e different ways that Congress designed section 111 t o authorize standards of performance that promote technological improvement: (i) the development of technology that may be treat ed as the “best system of emission reduction ... adequately dem onstrated;”
under section 111(a)(1) 148 ; (ii) the expanded use of the best demonstrated technology; 149 and (iii) the development of emerging

147 S. Rep. 95-127 at 17 (1977), cited in Sierra Club v. Costle, 657 F.2d at 346 n. 174. The 1977 CAAA legislative h istory is replete with other references to the technology for cing nature of §111 or the CAAA as a whole. See “1977 Clean Air Act Conference Report: Statement of Intent; Clarificati on of Select Provisions,” 123 Cong. Rec. 27071 (1977) (quoted in Sierra Club v. Costle, 657 F.2d at 346 n. 174) (one of the enum erated purposes of section 111 was to “create incentives f or new technology”); 123 Cong. Reg. 16195 (May 24, 1977) ( statement of Rep. Meads) (”The main purposes of the Clean Air Ac t Amendments of 1977 are as follows: ... tenth, to promote the uti lization of new technologies for pollution choice”). 148 See Portland Cement Ass’n v.Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (the best system of emission reduc tion must “look[] toward what may fairly be projected for the regulated future, rather than the state of the art at present ”). 149 See 1970 Senate Committee Report No. 91-1196 at 15 (“The maximum use of available means of preventing and controlling air pollution is essential to the elimi nation of new pollution problems”).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 176 of 373
technology. 150
E. Nationwide component of factors in determining t he “best
system” Another component of the D.C. Circuit’s interpretat ions of section 111 is that the EPA may consider the variou s factors it is required to balance on a national or regional le vel and over time, and not only on a plant-specific level at the time of the rulemaking. 151 As the D.C. Circuit stated in Sierra Club v.

Costle: The language of [the definition of ‘standard of performance’ in] section 111 ... gives EPA authority when determining the best ... system to weigh cost, energy, and environmental impacts in the broadest sense at the national and regional levels and over time as opposed to simply at the plant level in the immediate present. 152
In that case, in upholding the EPA’s variable stand ard for

SO 2 emissions, the D.C. Circuit justified and elaborat ed on that interpretation of the definition of “standard of pe rformance” and then went on to evaluate the EPA’s justificatio n for its rulemaking in light of that interpretation. It is u seful to set out these parts of the Court’s opinion at some leng th in order to make clear the scope of the factors and the natu re of the

150 See Sierra Club v. Costle, 657 F.2d at 351 (uphold ing a standard of performance designed to promote the use of an emerging technology). 151 Sierra Club v. Costle, 657 F.2d at 351. 152 Sierra Club v. Costle , 657 F.2d at 330. Deleted: ¶ As discussed below, CAA § 111 standards can promote technological innovation through: (i) the expanded use of the technology that is considered to be the best demonstrated technology; (ii) the further development of the best demonstrated technology; and (iii) the development of technology that is emerging, but that is not necessarily on a path to become the best demonstrated technology. Comment [A59]: This last part doesn’t seem to be explained later. Discussion later talks about “ the development of technology that is emerging.” Explanation of the “not necessarily on a path to become the best demonstrated technology” part would be helpful.

EPA: Discussion has been revised.

Deleted: ;***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 177 of 373 balancing exercise that the Court held section 111( a)(1)

authorizes the EPA to take.

The Court first recited the terms of the definition of “standard of performance,” as it read following the 1977 CAA

Amendments:

The pertinent portion of section 111 reads: A standard of performance shall reflect the degree of emission limitation ... achievable through application of the best ... system of ... emission reduction which (taking into consideration the cost of achieving such emission reduction, any nonair quali ty health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. 153

The Court then stated that these terms could reason ably be

read to authorize the EPA to establish the standard of performance based on environmental, economic, and e nergy considerations “on the grand scale:”

Parsed, section 111 most reasonably seems to require that EPA identify the emission levels that are “achievable” with “adequately demonstrated technology.” After EPA makes this determination, it must exercise its discretion to choose an achievabl e emission level which represents the best balance of economic, environmental, and energy considerations. It

153 Sierra Club v. Costle , 657 F.2d at 330. Note that the elipses in the quotation of the definition of “standard of performance” in the text indicate the omission of terms repealed by the 1990 CAAA

. T he Court’s analysis of the meaning of this definiti on did not turn on those repealed terms, and as a result, the Court’s analysis remains relevant for the current definitio n of “standard of performance.” Deleted: ; Deleted: t***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 178 of 373

follows that to exercise this discretion EPA must examine the effects of technology on the grand scal e in order to decide which level of control is best . For example, an efficient water intensive technology capable of 95 percent removal efficiency might be “best” in the East where water is plentiful, but environmentally disastrous in the water-scarce West where a different technology, capable of only 80 percent reduction efficiency might be “best.” ... The standard is, after all, a national standard with lo ngterm effects. 154

The Court then justified its “reading of ... section 111 as authorizing the EPA to balance long-term national a nd regional impacts of alternative standards” on the 1977 CAAA legislative history: The Conferees defined the best technology in terms of “long-term growth,” “long-term cost saving s,” effects on the “coal market,” including prices and utilization of coal reserves, and “incentives for improved technology.” Indeed, the Reports from both Houses on the Senate and House bills illustrate ver y clearly that Congress itself was using a long-term lens with a broad focus on future costs, environmen tal and energy effects of different technological syste ms when it discussed section 111. 155

The Court then examined the EPA’s justification for the

154 Sierra Club v. Costle , 657 F.2d at 330 (emphasis added). As noted, after the 1990 CAAA -- which changed the ter m “best technological system ... of emission reduction ... adequately demonstrated” to “best system ... of emission reducti on ... adequately demonstrated” -- the Court’s discussion of “adequately demonstrated technology” should be cons idered to hold true for adequately demonstrated system of emi ssion reduction.

155 Sierra Club v. Costle , 657 F.2d at 331 (citations omitted) (citing legislative history). Deleted:

Deleted: Deleted: (emphasis added)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 179 of 373 variable standard. The Court quoted at length the E PA’s discussion of how it “justified the variable standa rd in terms of the policies of the Act,” including, in part:

The standard reflects a balance in environmental, economic, and energy consideration by being sufficiently stringent to bring about substantial reductions in SO 2 emissions (3 million tons in 1995) yet does so at reasonable costs without significant energy penalties.... By achieving a balanced coal demand within the utility sector and by promoting t he development of less expensive SO 2 control technology, the final standard will expand environmentally acceptable energy supplies to existing power plants and industrial sources. By substantially reducing SO 2 emissions, the standard will enhance the potential for long term economic growth at both the national and regional levels. 156

The D.C. Circuit then held that it found this expla nation to be

reasonable. 157

F . Chevron framework Above, we discuss how in Sierra Club v. Costle the D.C. Circuit interpreted the definition of “standard of performance”
in CAA § 111(a)(1), among other things, to authorize the EPA to balance economic, environmental, or energy factors through a nationwide lens, and to encompass technology forcin g. The D.C. Circuit handed down this decision in 1981, and ther efore it did

156 Sierra Club v. Costle , 657 F.2d at 327-28 (quoting 44 Fed. Reg. at 33,583/3 - 33,584/1). 157 Sierra Club v. Costle , 657 F.2d at 337-39. Comment [A60]: Elaborate this sentence or add another sentence to summarize the point you are trying to make here, which seems to be about EPA balancing factors on a national or regional level a nd over time (as opposed to about the fact that EPA selected a variable standard). The conclusion need s to be more robust to keep the reader oriented. EPA: We are considering this suggestion further.

Deleted: F. Overall purposes ¶ The D.C. Circuit, during an extensive discussion of “standard of performance” in the 1981 decision in Sierra Club v. Costle , identified and explained the purposes of section 111 and upheld a standard in part on grounds that it was consistent with those purposes. 158 Specifically, the D.C. Circuit identified “the essential purposes” of CAA § 111 – insofar as relevant for present purposes -- as follows: 159 ¶ 1. The standards must not give a competitive advantage ... [2] Comment [A61]: EPA may want to consider reiterating this point and citation (copied below) from earlier about how section 111 looks towards what may be fairly projected, which is not clear fr om the case law cited in this section. EPA: We are considering this suggestion further. The Court explained that a standard of performance is “achievable” if a technology can reasonably be projected to be available to new sources at the time they are constructed that will allow them to meet the standard. Specifically, the D.C. Circuit explained: Section 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at present, since it is addressed to standards for new plants....- It is the “achievability” of the proposed standard that is in issue.... The Senate Report made clear that it did not intend that the technology “must be in actual routine use somewhere.” The ... [3] Comment [A62]: On its own, couldn’t this be read to mean that 111 incentivizes new technologies through a process where a vendor produces a new innovation and then the standard moves up to that level of performance (rewarding the vendor by then guaranteeing a market) vs. being “forcing” in the sense that it sets a forward looking standard that vendors must then meet? For this reason, it may be helpful to consider reiterating here the case law supporting a reading that 111 looks towards what may be fairly projected (see previous comment). EPA: We are considering this suggestion further.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 180 of 373
not employ the two-step framework for statutory con struction in federal rulemaking that the U.S. Supreme Court mand ated in 1984,

in Chevron U.S.A. Inc. v. NRDC , 467 U.S. 837 (1984). However, the D.C. Circuit’s interpretations are fully consis tent with the

Chevron framework.

In Chevron , the Supreme Court held that an agency must, at Step 1, determine whether Congress’s intent as to t he specific matter at issue is clear, and, if so, the agency mu st give effect to that intent. If congressional intent is n ot clear, then, at Step 2, the agency has discretion to fashi on an interpretation that is a reasonable construction of the

statute. 173
As noted, under CAA section 111(a)(1), a standard o f performance must be based on the “best system of em ission reduction which (taking into account the cost of ac hieving such reduction and any nonair quality health and environ mental impact and energy requirements) ... has been adequately demo nstrated.” The terms “best system of emission reduction,” “cos t,” and “energy requirements,” on their face, can be interp reted to apply on a regionwide or nationwide basis, and are not limited to the individual source. Thus, this interpretation is supportable under Chevron step 1, but even if not, then the EPA

173 Chevron U.S.A. Inc. v. NRDC , 467 U.S. 837, 842-43 (1984).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 181 of 373 considers the interpretation supportable under step 2 because it is reasonable and consistent with the purposes of t he CAA. Similarly, the technology-development interpretatio n is
supportable under Chevron step 1 because encouraging the utilization or development of improved technology i s a logical consideration in determining the “best system of em ission

reduction” and , as noted, was clearly a focus of the legislative history . E ven if that interpretation is not supportable under

Chevron step 1, however, then the EPA considers the interpretation supportable under step 2 because it is reasonable and consistent with the purposes of the CAA.

G . Agency discretion

The D.C. Circuit has made clear that the EPA has br oad discretion in determining the appropriate standard of performance under the definition in CAA § 111(a)(1), quoted above. Specifically, in Sierra Club v. Costle , 657 F.2d 298 (D.C. Cir. 1981), the Court explained that “section 111(a) explicitly instructs the EPA to balance multiple co ncerns when promulgating a NSPS,” 175 and emphasized that “[t]he text gives the EPA broad discretion to weigh different factors in setting

the standard.” 176 In Lignite Energy Council v. EPA , 198 F.3d 930

175 Sierra Club v. Costle , 657 F.2d at 319. 176 Sierra Club v. Costle , 657 F.2d at 321. Deleted: self-evidently a

Deleted: 174, but e

Deleted: H***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 182 of 373
(D.C. Cir. 1999), the Court reiterated:

Because section 111 does not set forth the weight that should be assigned to each of these factors, w e have granted the agency a great degree of discretio n in balancing them.... EPA's choice [of the ‘best system’] will be sustained unless the environmental or economic costs of using the technology are exorbitant.... EPA [has] considerable discretion unde r section 111. 177

The important point is that Courts acknowledge that there

are several factors to be considered and what is “b est” depends on how much weight to give the factors. In promulga ting certain standards of performance, EPA may give greater weig ht to particular factors than it may do so in promulgating other standards of performance. Thus, the determination o f what is “best” is complex and necessarily requires an exerc ise of judgment. By analogy, the question of who is the “b est” sprinter in the 100-meter dash primarily depends on only one criterion – speed – and therefore is relatively straightforward , while the question of who is the “best” baseball player depen ds on a more complex weighing of several criteria and therefore requires a greater exercise of judgment.

H . Lack of requirement that standard be able to be m et by all

sources

177 Lignite Energy Council v. EPA , 198 F.3d 930, 933 (D.C. Cir. 1999) (paragraphing revised for convenience). Deleted: e

Comment [A63]: Suggest this is not necessary. EPA: We are considering this suggestion further. Deleted: I***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 183 of 373

Under CAA § 111, an emissions standard may meet the requirements of a “standard of performance” even if it cannot be met by every new source in the source category that would have

constructed in the absence of that standard. As dis cussed below, this is clear in light of (i) the legislative histo ry of CAA § 111, read in conjunction with the legislative histo ry of the CAA as a whole; (ii) case law under analogous CAA provi sions; and (iii) long-standing precedent in the EPA rulemaking s under CAA §

111.1. 1. Legislative history As noted, Congress, in enacting section 111 in the 1970 CAAA, intended that the EPA promulgate uniform, nat ionwide controls. Congress was explicit that this meant tha t large industrial sources, including electric generating p ower plants, would be required to implement controls meeting the requirements regardless of their location. According to the 1970 Senate Committee Report:

Major new facilities such as electric generating plants, kraft pulp mills, petroleum refineries, ste el mills, primary smelting plants, and various other commercial and industrial operations must be controlled to the maximum practicable degree regardless of their location and industrial operations.... 178

178 S. Rep. 91-1116 at 16 (1970). See 116 Cong. Rec. 42 ,384 (statement of Sen. Muskie) (summarizing the House-S enate Conference agreement). ) Deleted: 1970 S. Comm. Rep. at 16, GLH at 416. See 1970 Senate Debate on Conference, 91 Cong. Rec. 42,384 (Muskie***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 184 of 373

Congress’s purposes in designing a standard that ca lled for uniform national controls were to prevent pollution havens – caused by some states seeking competitive advantage by limiting their pollution control requirements – and to assur e that areas that had good air quality would be able to maintain good air quality even after new industrial sources located t here, which,
in turn, would allow more sources to locate there a s well. 179
At the same time, Congress recognized that in ligh t of the attainment provisions of the CAAA of 1970, sources – particularly large industrial sources, again, inclu ding electric generating plants -- may not be able to construct n ew facilities anywhere in the country; that is, an area with air quality at or above the NAAQS limits might not have enough room i n its airshed

to accommodate these new facilities. The 1970 Senat e Committee Report stated, “[l]and use policies must be develop ed to prevent location of facilities which are not compatible wit h implementation of national standards.” 180 Senator Muskie added: Land use planning and control should be used by Sta te, local, and regional agencies as a method of minimiz ing air pollution. Large industries and power generatin g facilities should be located in places where their adverse effect on the air is minimal. There is a ne ed for State or regional agencies to revise proposed

179 See S. Rep. 91-1196 at 16 (1970). 180 1970 Senate Commitee Report at 2. Deleted: See S. Comm. Rep. at 16, GLH at 416. Deleted: 1970 Sen. Comm. Rep, 91- 1196 (91 st Cong., 2d Sess) p. 2:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 185 of 373 power plant sites to assure that a number of environmental values, including air pollution, are considered. 181
The 1970 CAAA legislative history includes other st atements that also recognize that under the newly required air po llution control requirements, new sources may not be able t o build anywhere in the country and, in fact, some existing sources might have to be shut down. 182
Thus, in 1970, Congress designed section 111 to re quire uniform national controls for large industrial faci lities, while recognizing that those facilities could not necessa rily construct in every place in the country. Although a t the time, Congress expected that the reason why some sources would not be able to locate in certain places was related to local air quality concerns, if the reason turns out to be rel ated to the emission limits that the EPA promulgates under sect ion 111, that

should not be viewed as inconsistent with congressional intent

for section 111. For example, if the EPA promulgates se ction 111 emission limits based on a particular type of techn ology, and for economic or technical reasons, sources are able to utilize that technology in only certain parts of the countr y and not

181 116 Cong. Rec. 32,917 (1970) (statement of Sen. Mus kie).

182 _See 116 Cong. Rec. 42,385 (Dec. 18, 1970) (stateme nt of Sen. Muskie) (sources of hazardous air pollutants could be required to close due to absence of control techniques). Deleted: would be the reason why some sources would not be able to locate in certain places

Deleted: 1970 Senate Debate, GLH at 37 (Sept. 21, 1970) (statement of Sen. ?? Muskie?/] maybe p. 32,917.

Deleted: [cites]***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 186 of 373 other parts, that result should not be viewed as in consistent with congressional intent for CAA section 111. Rather, that result is consistent with Congress’s recognition th at certain sources may be precluded from locating in certain a reas. 2. Case law under analogous CAA provisions Under analogous CAA provisions, the D.C. Circuit h as recognized that the EPA may promulgate uniform stan dards that apply to new sources in a group or category of sour ces, even though some types of those new sources that would o therwise construct would no longer be able to construct beca use they

could not meet the standard. One of these cases was

International Harvester Co. v. EPA , 478 F.2d 615 (D.C. Cir.
1973). There, the EPA declined to exercise its disc retion under the CAA mobile source provisions, as they read at t hat time (42 USC 1857f-1(b)(5)(D) (1970 CAAA)), to grant automak ers a oneyear extension to comply with exhaust standards. Th e EPA stated

that the automakers had failed to meet their burden of establishing that controls were not available. The EPA based its decision on grounds that certain technology was ava ilable for the motor vehicles in question. The EPA dismissed t he automakers’ objections that this technology could n ot feasibly be installed in all models or engine types, and the EPA explained that the public’s “basic demand” for auto mobiles could Deleted: under***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 187 of 373 be met by the models and engine types that could fe asibly install that technology. 478 F.2d at 626. Although the Court remanded the EPA’s decision not to grant the one-year extension, it agreed with the EPA on t his point, stating: We are inclined to agree with the Administrator that as long as feasible technology permits the dem and for new passenger automobiles to be generally met, the basic requirements of the Act would be satisfied, e ven though this might occasion fewer models and a more limited choice of engine types. The driving preferences of hot rodders are not to outweigh the goal of a clean environment. 183

Similarly, in a 2007 decision under CAA § 112, NRDC v. EPA , 489 F.3d 1364, 1376 (D.C. Cir. 2007) the D.C. Circu it upheld the EPA’s decision to apply the same hazardous air poll utant requirements to different types of plywood and comp osite wood products facilities – even though one of those type s of facilities faced greater difficulties meeting the r equirements than the other types of facilities – in part on the grounds that the facilities “compet[ed] in the same markets.” 184
3. Section 111 rulemaking precedent Through long-standing rulemaking precedent, the EP A has taken the position that section 111 authorizes a st andard of

183 International Harvester Co. v. EPA , 478 F.2d at 640. 184 NRDC v. EPA, 489 F.3d at 1376

. Comment [A64]: This is helpful – is there any further elaboration that could be made on this poin t, particularly to connect this with the electricity market? EPA: We are considering this suggestion further.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 188 of 373
performance for a source category that may not be f easible for all types of new sources in the category, as long a s there are other types of sources in the category that can serve the same function and meet the standard. Specifically, in a 1976 rulemaking under section 111 covering primary coppe r, zinc, and
lead smelters, the EPA established, as the standard of performance, a single standard for SO 2 emissions for new construction or modifications of reverberatory, fla sh, and electric smelting furnaces in primary copper smelte rs that process materials with low levels of volatile impur ities. The
EPA acknowledged that although for flash and electr ic smelting
furnaces, the cost of the controls was “reasonable, ” for reverberatory smelting furnaces, the cost of the st andard was “unreasonable in most cases.” Even so, the EPA dete rmined that this standard would not adversely affect new constr uction or modification of primary copper smelters processing materials containing low levels of volatile impurities becaus e new construction could use flash and electric smelting furnaces, and existing sources could expand without increasing em issions. 185
The EPA explained:

[T]he Agency believes that section 111 authorizes

185 Standards of Performance for New Stationary Source s, Primary Copper, Zinc, and Lead Smelters, 41 FR 2331 , 2333 (Jan. 15, 1976). Deleted:

____***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 189 of 373 the promulgation of one standard applicable to all processes used by a class of sources, in order that the standard may reflect the maximum feasible contr ol for that class. When the application of a standard to a given process would effectively ban the process, however, a separate standard must be prescribed for it unless some other process(es) is available to perfo rm the function at reasonable cost.... The Administrator has determined that the flash copper smelting process is available and will perfo rm the function of the reverberatory copper smelting process at reasonable cost.... 186

VII. Rationale for Emission Standards for New Fossi l Fuel-fired

Boilers and IGCCs

A. Overview In this section we explain our rationale for conclu ding that partial implementation of CCS is the BSER adequately

demonstrated for new fossil fuel-fired boiler and I GCC EGUs.
As noted, CAA § 111 and subsequent court decisions

establish a set of factors for the EPA to consider in a BSER determination, including criteria listed in CAA § 111 or identified in the court decisions and the underlyin g purposes of

§ 111. Key factors include: emission reductions, tech nical feasibility, costs, and encouragement of technology . Other factors, such as energy impacts, may also be import ant. As also noted, the EPA has discretion in balancing those fa ctors, and may balance them differently in promulgating standa rds for

186 41 FR at 2333. Deleted: best system of emission reduction

Deleted: (BSER) Comment [A65]: Should this reference standards of performance instead of BSER? Or, both?

Deleted: (emphasis added)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 190 of 373 different source categories.

The EPA considered three alternative control technology configurations as potentially representing the BSER for new

fossil fuel-fired boilers and IGCC units. Power com pany
announcements indicate that the few new coal-fired projects that may occur will likely consider one or more of these three configurations. The three alternatives are: (1) hig hly efficient new generation technology that does not include any level of CCS, (2) new generation technology with “full captu re” CCS (that is, CCS with capture of at least 90 percent CO 2 emissions) and (3) new generation technology with “partial capture ” CCS (that is, CCS with capture of a lower level of CO 2 emissions).
We discuss each of these alternatives below, and ex plain why we propose that partial capture CCS qualifies a s the BSER. We first discuss the technical systems that we cons idered for
the BSER, our evaluations of them, and our reasons for determining that only partial CCS meets the criteri a to qualify

as the BSER. We include in this discussion our rati onale for selecting 1,100 lb CO 2 /MWh as the emission limitation for these sources and why we are considering a range from 1,000 to 1,200

lb CO 2 /MWh for the final rule . We next discuss our rationale for allowing a 60-operating-month averaging period as a n alternative compliance method, with the requirement that source s choosing Deleted: different

Comment [A66]: Is it “few” or “none”. Suggest adding a sentence before power company sentence stating that EIA projects none,.

EPA: We believe this is correct. Deleted: the EPA considered in the BSER analysis

Deleted: seek comment on***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 191 of 373
that method meet a limit of between 1,000 lb CO 2 /MWh and 1,050 lb

CO 2 /MWh. 187 We then explain our rationale for the requirements for geologic sequestration. B. Identification of the best system of emission re duction

1. Highly efficient new generation without CCS technol ogy Some commenters on the April 2012 proposal suggeste d that

the emission limitation for new coal-fired EGUs sho uld be based on the performance of highly efficient generation t echnology that does not include CCS, such as (i) a supercriti cal 188
pulverized coal (SCPC) or CFB boiler, or (ii) a mod ern, wellperforming IGCC unit. These options are technically feasible. However, we do not consider them to qualify as the BSER for the follow ing reasons:

a. Lack of significant CO 2 reductions Because of the large amount of CO 2 emissions from solid-fuel fired power plants, it is important, in promulgatin g a standard of performance for these sources, to give effect to the purpose

187 This is on a gross output basis. All emission rate s in this section are on a gross output basis unless specifically noted otherwise. 188 Subcritical coal-fired boilers are designed and op erated with a steam cycle below the critical point of water. Su percritical coal-fired boilers are designed and operated with a steam cycle above the critical point of water. Increasing the s team pressure and temperature increases the amount of energy with in the steam, so that more energy can be extracted by the steam t urbine, which in turn leads to increased efficiency and lower emi ssions. Deleted: circulating fluidized bed ( Deleted: )

Deleted: clearly Comment [A67]: The NOPR uses “clearly” a fair amount, and the use does not add persuasiveness. Consider omitting.

Deleted: Deleted: other Deleted: listed as***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 192 of 373

of CAA § 111 of providing “as much [emission reduction] as practicable.” 189 Accordingly, we reviewed the emission rates of efficient PC and CFB units. According to the DOE/NE TL estimates, a new subcritical PC unit firing bituminous coal wo uld emit approximately 1, 800 lb CO 2 /MWh, 190 a new SCPC unit using

bituminous coal would emit nearly 1, 700 lb CO 2 /MWh, and a new

IGCC unit 191 would emit about 1, 450 lb CO 2 /MWh. 192
New power sector projects using coal as a primary f uel that have been proposed or are currently under construct ion are generally SCPC or IGCC projects. For example, since 2007, almost all coal-fueled EGUs that have broken ground have b een high performing versions of SCPC or IGCC projects. 193 Among those plants are: (1) AEP’s John W. Turk, Jr. Power Plant , a 600 MW

189 Sierra Club, F.2d at 327 & n. 83 (quoting 44 FR at 33,581/3 – 33,582/1). 190 Exhibit ES-2 from “Cost and Performance Baseline f or Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity”, Revision 2, Report DOE/NETL-2010/1397 (November 2010). 191 “Case 1” from Exhibit ES-2 from “Cost and Performa nce Baseline for Fossil Energy Plants Volume 1: Bitumin ous Coal and Natural Gas to Electricity”, Revision 2, Report DOE /NETL2010/1397 (November 2010). 192 The comparable emissions on a net basis are: subcr itical PC – 1,888 lb CO 2 /MWh; supercritical PC – 1,768 lb CO 2 /MWh; and IGCC – 1,723 lb CO 2 /MWh. 193 The only exception that we are aware of is the Vir ginia City subcritical CFB unit

. Deleted: pulverized coal ( Deleted: ) Deleted: 783

Deleted: 675

Deleted: 434

Comment [A68]: What are the CO2 emissions of the subcritical CFB? The FN contains only minimal discussion; should elaborate. EPA: We are considering this suggestion.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 193 of 373 ultra-supercritical 194 PC (USCPC) facility located in the
southwest corner of Arkansas; (2) Duke Power’s Edwa rdsport plant, a 618 MW coal IGCC unit located in Knox Coun ty, Indiana;
and (3) Southern Company’s Kemper County Energy Fac ility, a 582 MW lignite IGCC unit located in Kemper County, Miss issippi. These facilities all use advanced generation techno logy: Turk, as noted, is an ultra-supercritical boiler; Edwards port is an IGCC unit that is “CCS ready;” and Kemper is an IGC C unit that will implement partial CCS. Under these circumstances, in this rule, identifyin g a new supercritical unit as the BSER and requiring the as sociated emission limitation, would provide little meaningfu l CO 2 emission reductions for this source category. As noted, for the most part, new sources are already designed to achieve a t least that emission limitation. Identifying IGCC as the BSER a nd requiring the associated emission limitation, would provide s ome CO 2 emission reductions from the segment of the industr y that would otherwise construct new PC units, but not from the segment of the industry that would already construct new IGCC units.
As a result, emission reductions in the amount that would

194 Ultra-supercritical (USC) and advanced ultra-super critical (A-USC) are terms often used to designate a coal-fi red power plant design with steam conditions well above the c ritical point. Deleted: of approximately 1,675 lb CO 2 /MWh

Deleted: of approximately 1,434 lb CO 2 /MWh***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 194 of 373
result from an emission standard based on SCPC/USCP C or even IGCC as the BSER would not be consistent with the p urpose of CAA

§ 111 to achieve “as much [emission reduction] as practicable.” 195 As we discuss below, identifying CCS-partial capture as the BSER would provide for significantly greater
emissions reductions.

b. Lack of incentive for technological innovation Identifying highly efficient generation technology as the BSER would not achieve another purpose of CAA § 111, to encourage the development and implementation of con trol technology. At present, CCS technologies are the mo st promising options to achieve significant reductions in CO 2 emissions from

fossil-fuel fired utility boilers and IGCC units . A standard based on the performance of highly efficient coal-f ired generation does not advance the development and imp lementation

of control technologies that reduce CO 2 emissions. Further, highly efficient generation technology does not dev elop control technology that is transferrable to existing EGUs. On the contrary, such a standard could impede the advancement of CCS technology by creating regulator y disincentives for such technology. In 2011, AEP def erred

195 Sierra Club , F.2d at 327 & n. 83 (quoting 44 FR at 33,581/3 – 33,582/1). Comment [A69]: Promising or effective? EPA: We believe “promising”.

Deleted: solid Deleted: EGUs

Deleted: American Electric Power ( Deleted: )***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 195 of 373 construction of a large-scale CCS retrofit demonstr ation project on one of their coal-fired power plants because the state’s utility regulators would not approve cost recovery for CCS investments without a regulatory requirement to red uce CO 2 emissions. AEP’s chairman was explicit on this poin t, stating in a July 17, 2011 press release announcing the deferr al:

We are placing the project on hold until economic and policy conditions create a viable path forward

... We are clearly in a classic ‘which comes first?’ situation. The commercialization of this technology is vital if owners of coal-fueled generation are to comply with potential future climate regulations without prematurely retiring efficient, cost-effect ive generating capacity. But as a regulated utility, it is impossible to gain regulatory approval to recover o ur share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract partners to help fund the industry’s share. 196

As we discuss below, regulatory requirements for CO 2 reductions with some level of CCS as the BSER will promote further development of the technology.

2. Carbon capture and storage

We have also considered whether the emission limita tion for new coal-fired EGUs should be based on the performa nce of CCS, including either “full capture” CCS that treats the entire flue gas or syngas stream to achieve on the order of 90 percent

196 http://www.aep.com/newsroom/newsreleases/?id=1704***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 196 of 373

reduction in CO 2 emissions, or “partial capture” CCS that achieves some level less than 90 percent of capture

. We propose that implementation of partial capture C CS technology is the BSER for new fossil fuel-fired bo ilers and

IGCC units because it fulfills the criteria establi shed under

CAA § 111. In the sections that follow, we explain the te chnical configurations that facilitate full and partial cap ture, describe the operational flexibilities that partial capture offers, and then identify and justify the emission rate that we propose based on partial capture. After that, we di scuss the criteria for BSER, and describe why partial capture meets those criteria and why full capture does not. Among other things, partial capture provides meaningful emission reduct ions, it has been adequately demonstrated to be technically feas ible, it can be implemented at a reasonable cost, and it promote s deployment and further development of the technology.

3. Technical configurations for CCS The DOE’s National Energy Technology Laboratory (NE TL) performed a study to establish the cost and perform ance for a range of CO 2 capture levels for new SCPC and IGCC power plants. 197

197 “Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture”, DOE/NETL-2011/1498, May 27 , 2011. Deleted: not un***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 197 of 373 The study identified technical configurations that were tailored to achieve a specific level of carbon capture.

a. SCPC For the new SCPC case, the study assumed a new SCPC boiler
with a combination of low-NOx burners (LNB) with ov erfire air (OFA) and a selective catalytic reduction (SCR) sys tem for NOx control. The plant was assumed to have a fabric fil ter and a wet limestone flue gas desulfurization (FGD) scrubber f or particulate matter and sulfur dioxide (SO 2 ) control, respectively. The plant was also assumed to have a sodium hydroxide (NaOH) polishing scrubber to ensure that the flue gas entering the CO 2 capture system has a SO 2 concentration of 10 ppmv or less. The SCPC plant was equipped with Fluo r’s Econamine

FG Plus SM process for post-combustion CO 2 capture via temperature swing absorption with a monoethanolamine (MEA) solu tion as the

chemical solvent. The study’s authors identified two options for achi eving partial capture (i.e., less than 90 percent CO 2 capture) in the SCPC unit. The first option was to process the enti re flue gas stream through the MEA capture system at reduced so lvent circulation rates. The second option was to maintai n the same high solvent circulation rate and steam stripping r equirement as would be used for full capture but only treat a por tion of the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 198 of 373 total flue gas stream. The authors determined that the second approach – the “slip stream” approach - was the mos t economical.

The authors further noted that the cost of CO 2 capture with an amine scrubbing process is dependent on the volume of gas being treated, and a reduction in flue gas flow rate will : (1) decrease the quantity of energy consumed by flue ga s blowers, (2) reduce the size of the CO 2 absorption columns, and (3) trim the cooling water requirement of the direct contact cooling system. The slip stream approach leads to lower cap ital and operating costs. All of the partial capture cases i n the NETL study assumed this approach.

b. IGCC For a new IGCC unit, the product syngas would conta in primarily H 2 , CO and some lesser amount of CO 2 . 198 The amount of

CO 2 can be increased by “shifting” the composition via the catalytic water-gas shift (WGS) reaction. This proc ess involves the catalytic reaction of steam (“water”) with CO ( “gas”) to

form H 2 and CO 2 . An emission standard that requires partial capture of CO 2 from the syngas could be met by adjusting the

level of CO 2 in the syngas stream by controlling the level of

198 The amount of CO 2 in un-shifted syngas depends upon the specific gasifier technology used, the operating co nditions, and the fuel used; but is typically less than 20 volume percent (http://www.netl.doe.gov/technologies/coalpower/gas ification/gas ifipedia/4-gasifiers/4-3_syngas-table2.html). Deleted: hydrogen ( Deleted: ) Deleted: carbon monoxide ( Deleted: )***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 199 of 373 syngas “shift” prior to treatment in the pre-combus tion acid gas

treatment system. For a new IGCC EGU, the study’s authors assumed the use of the GE gasifier coupled with a variety of potential configurations (i.e., no WGS reactor, single-stage WGS, twostage WGS, varying WGS bypass ratios, and CO 2 scrubber removal efficiency). The study evaluated a number of IGCC p lant configurations. The first was an IGCC that used the SelexolTM process for acid gas control (i.e., hydrogen sulfid e (H 2 S) and

CO 2 ) but no WGS reactor. This unit was capable of CO 2 capture ranging from zero up to 25 percent. The no-CO 2 capture case employed a one-stage SelexolTM unit for H 2 S control and the 25
percent CO 2 capture case utilized a two-stage SelexolTM unit to

maximize CO 2 capture from the unshifted syngas (i.e., >90 perce nt

of the CO 2 from the unshifted syngas was captured in the seco nd stage SelexolTM scrubber). To achieve moderate levels of partial CO 2 capture – approximately 25 to 75 percent - the IGCC was confi gured with a single-stage WGS reactor with bypass and a two-stag e SelexolTM unit. Varying the extent of the WGS reaction by con trolling the
amount of syngas that was processed through the WGS reactor (by controlling the amount that bypassed the WGS reacto r) manipulated the level of CO 2 capture. As more syngas is processed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 200 of 373 through the WGS reactor, the steam demand increases . The SelexolTM removal efficiency was manipulated by vary ing the solvent circulation rate. Thus, a facility using th is configuration could select or “dial in” a level of control of between 25 – 75 percent. To achieve higher CO 2 capture levels – levels greater than 75 percent - the IGCC was configured with a two-sta ge WGS with bypass and the two-stage acid gas (SelexolTM) scrubb ing system. The facility could “dial in” a level of control of between 25 to greater than 90 percent by controlling the WGS bypa ss and the

SelexolTM scrubber recirculation rates. The water-gas shift involves the catalytic reaction of

carbon monoxide and steam . Since the syngas initially contains primarily CO and H 2 , this shift reaction diminishes the

concentration of CO and enriches the concentration of H 2 in the pre-combustion syngas stream via the following reac tion :

CO + H 2 O ∆

CO 2 + H 2 An unshifted or partially shifted syngas can be com busted using a typical combustion turbine. However, as the level of H 2 in the syngas increases, the more the syngas must b e diluted

with N 2 or air. Very high levels of H 2 in the syngas stream require use of a specialty hydrogen turbine.

4. Operational and design flexibility Deleted: following

Deleted: syngas

Deleted: Since the syngas initially contains primarily CO and H 2 , this shift reaction diminishes the concentration of CO and enriches the concentration of H 2 in the precombustion syngas stream.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 201 of 373 To this point, most of the studies involving resear ch, development and demonstration of carbon capture tec hnology, along with most of the studies that have modeled th e costs and implementation of such technology have assumed capt ure requirements of 90 percent for fossil fuel-fired po wer plants (“full capture”). However, the EPA believes that pa rtial capture provides significant benefits because an emission l imit based on partial capture offers operators considerable opera tional flexibility. With such emission limits, project dev elopers would have the option of designing and installing CO 2 capture technology at a size sufficient to treat the entire flue gas stream, with the capability to meet CO 2 emission limits that are much lower than required. The operator of the plant could then choose to achieve those deeper capture rates during non-peak electricity demand periods and to achieve lesser ca pture rates (and thus generate more electricity) during peak el ectricity demand periods. This type of operational flexibilit y provides owners and operators the opportunity to optimize th e operation

and minimize the cost of CCS in new fossil fuel-fir ed projects.
In addition, an emission standard that can be met w ith partial capture offers the opportunity for design f lexibility. A project developer of a new conventional coal-fired plant (i.e., a new supercritical PC or CFB) could install post-c ombustion CO 2***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 202 of 373 scrubbers that have been designed and sized to trea t only a portion of the flue gas stream.
For a new IGCC unit, as noted, an emission standard that requires partial capture of CO 2 offers operational flexibility because the standard could be met by adjusting the level of CO 2 in the syngas stream by controlling the level of sy ngas “shift” prior to treatment in the pre-combustion acid gas t reatment
system.

C. Determination of the level of the standard Once the EPA has determined that a technology has b een adequately demonstrated based on cost and other fac tors, including the impact a standard will have on furthe r technology development , and therefore represents BSER, the EPA must establish an emission standard. In this case, for n ew fossil
fuel-fired boiler and IGCC EGUs, the EPA proposes to find that the level of partial capture of CO 2 that qualifies as the BSER supports a standard of 1,100 lb CO 2 /MWh on a gross basis. The

level of the standard is based on the emission redu ctions that can be achieved by an IGCC with a single-stage WGS reactor and a two-stage acid gas removal system. According to the DOE/NETL partial capture study, an IGCC with this configurat ion would be expected to achieve a CO 2 emission reduction of 25 to 75 percent, which corresponds to emissions of approximately 1,0 60 and 380 lb Deleted: is Deleted: ing***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 203 of 373

CO 2 /MWh-gross, respectively. The EPA is proposing a st andard of performance of 1,100 lb CO 2 /MWh-gross, which is the high end of this range, for several reasons.
First, both a new IGCC and a conventional coal-fire d boiler
(PC or CFB), can achieve this emission standard at a reasonable cost and the standard is based on technology that h as been adequately demonstrated. The partial capture requirement and standard of per formance will allow new IGCC project developers to minimize the need for multi-stage water-gas shift reactors (and the assoc iated steam requirement) and will allow for the continued use o f conventional syngas combustion turbines (rather tha n requiring the use of advanced hydrogen turbines). Second, thi s partial capture configuration will provide operators with o perational flexibility. Third, this level of the standard best promotes further enhancement of the performance of existing technology and promotes continued development of new, better p erforming technology. Because the proposed emission standard would requir e only partial implementation of CCS, it will provide developers with the opportunity to investigate new emerging te chnologies that may achieve deeper reductions at lower or comp arable cost. For instance, developers could build plants with th e capacity to achieve deeper CO 2 reductions and choose to employ those greater Comment [A70]: Could EPA further explain why it believes the level of standard that can be m et by existing technologies would spur development of new, better performing technology? EPA: Explanation added.

Deleted: It will provide developers with the opportunity to investigatenew emerging and potentially lowercost technologies.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 204 of 373 capture rates during non-peak periods, and then emp loy lower capture rates (and thus generate more electricity) during peak periods. While the EPA is proposing an emission rate of 1,10 0 lb

CO 2 /MWh, we are also soliciting comment on whether the emission limit may be more appropriately set at a different level . Based on the rationale included in this proposal, we are considering a range of 1,000 to 1,200 lb CO 2 /MWh -gross for the final rule . An emission rate of 1,200 lb CO 2 /MWh -gross could potentially be met by an IGCC unit that does not include a WGS reactor (although an owner/operator might still use a WGS reactor or co- fire natural gas to maintain operational flexibility), thus further reducing the capital and operating costs. An emission limit of 1,000 lb

CO 2 /MWh -gross would provide greater emission reductions , could still be achieved with a single WGS reactor, and would also advance CCS technology but would offer less operati onal flexibility and increase costs

. We are not currently considering a standard below 1 ,000 lb

CO 2 /MWh. At an emissions rate of 1,000 lb CO 2 /MWh-gross or higher, an owner/operator of an IGCC facility could burn natural gas during periods when the gasifier is unavailable while still maintaining an annual emissions rate that is below the NSPS. In addition, an owner/operator could elect to co-fire natural gas Deleted: within the

Deleted:

–***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 205 of 373 as an option to reduce the amount of CCS required t o comply with the NSPS. We request that commenters who suggest em ission rates
below 1,000 lb CO 2 /MWh address potential concerns about operational flexibility. We are not currently considering a standard above 1 ,200 lb

CO 2 /MWh because the NSPS would not necessarily promote the development of CO 2 emissions control technology or provide significant CO 2 reductions. At an emissions rate of 1,300 lb

CO 2 /MWh-gross, IGCC facilities would only be required to capture approximately 10 percent of the CO 2 , and many designs would have sufficient compliance margin that they would not ne ed to use a WGS reactor. Further, an owner/operator of an IGCC could comply with this standard without the use of any CCS. A ne w IGCG designed to co-fire 20 percent natural gas or using fuel cells instead of combustion turbines could comply with an emissions
rate of 1,300 lb CO 2 /MWh-gross without the use of CCS. An
emissions rate of 1,400 lb CO 2 /MWh-gross would provide even less technology development and emissions reductions. At an emissions
rate of 1,400 lb CO 2 /MWh-gross, an IGCC could comply with no WGS reactor and capturing less than 5% of the CO2, co-f iring less ten percent natural gas with no CCS, or using integ rated solar thermal for supplemental steam production without C CS. In addition, at an emissions rate of 1,400 lb CO 2 /MWh-gross a PC or***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 206 of 373 CFB could use integrated combustion turbines or fue l cells for boiler feedwater heating, supplemental steam produc tion, or for preheated air for the boiler as an alternative to C CS. We request that commenters who suggest emission rates above 1,200

lb CO 2 /MWh-gross address potential concerns about prov id ing adequate reductions and technology development to b e considered

BSER.

The next several sections review the factors for determining BSER and explain why partial capture at the level we are proposing meets those requirements, as well as why full capture does not meet some of them.

D. Extent of reductions in CO 2 emissions The proposed standard of 1,100 lb CO 2 /MWh will provide meaningful reductions in emissions. As mentioned ea rlier, the
DOE/NETL has estimated that a new SC PC boiler using bituminous
coal would emit 1,675 lb CO 2 /MWh. The DOE/NETL has also estimated
that a new IGCC unit would emit 1,434 lb CO 2 /MWh. The emissions would be higher for units utilizing subbituminous c oal or lignite and will vary when utilizing other fossil f uels such as petroleum coke or mixtures of fuels. We estimate th at this

standard will result in reduction in emissions of a t least 40 percent when compared to the expected emissions of a new SC PC

boiler. Deleted: supercritical

Deleted: supercritical***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 207 of 373 E. Technical feasibility The EPA proposes to find that partial CCS is feasi ble because each step in the process has been demonstra ted to be feasible through an extensive literature record, fo ssil fuelfired industrial plants currently in commercial ope ration and pilot-scale fossil fuel-fired EGUs currently in ope ration, and the progress towards completion of construction of fossil fuelfired EGUs implementing CCS at commercial scale. Th is literature record and experience demonstrate that partial CCS is achievable for all types of new boiler and IGCC configurations . Although

much of this information also serves to demonstrate the technical feasibility of full capture, we note that several of the CCS projects that are the furthest along are pa rtial capture projects, which further supports our view that part ial capture

is BSER.

1. Literature The current status of CCS technology was described and analyzed by the 2010 Interagency Task Force on CCS, established by President Obama on February 3, 2010, co-chaired by the DOE and the EPA, and composed of 14 executive departmen ts and federal agencies. The Task Force was charged with p roposing a plan to overcome the barriers to the widespread, co st-effective deployment of CCS within 10 years, with a goal of b ringing five Deleted: the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 208 of 373 to ten commercial demonstration projects online by 2016. The Task Force found that, although early CCS projects face economic challenges related to climate policy uncertainty, f irst-of-akind technology risks, and the current cost of CCS relative to other technologies, there are no insurmountable tec hnological, legal, institutional, regulatory or other barriers that prevent CCS from playing a role in reducing GHG emissions. 199
The Pacific Northwest National Laboratory (PNNL) re cently prepared a study that evaluated the development sta tus of various CCS technologies for the DOE. 200 The study addressed the availability of capture processes, transportation o ptions (CO 2 pipelines), injection technologies, and measurement , verification and monitoring technologies. The study concluded that, in general, CCS is technically viable today a nd that key component technologies of complete CCS systems have been deployed at scales large enough to meaningfully inf orm discussions about CCS deployment on large commercia l fossilfired power plants. In addition, DOE/NETL has prepared other reports – in

199 Report of the Interagency Task Force on Carbon Cap ture and Storage (August 2010), page 7. Comment [A71]: Does the task force findings say anything about leakage from geological storage and ways to manage for leakage? Suggest that this information could be cited somewhere in the rulemaking, if it exisits. EPA: We are considering this comment

Deleted: additional***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 209 of 373 particular their “Cost and Performance Baseline” re ports , 201
including one on partial capture 202 -- that further support the technical feasibility of partial capture. 2. Capture, transportation and storage technologies Each of the core components of CCS -- CO 2 capture, compression, transportation and storage -- ha s already been implemented and, in fact, in some instances, implemented on a
commercial scale. The U.S. experience with large-scale CO 2 injection, including injection at enhanced oil and gas recovery projects, combined with ongoing CCS research, devel opment, and demonstration programs in the U.S. and throughout t he world, provide confidence that the capture, transport, com pression, and storage of large amounts of CO 2 can be achieved.

a. CO 2 capture technology Capture of CO 2 from industrial gas streams has occurred

since the 1930s , through us e of a variety of approaches to
separate CO 2 from other gases. These processes have been used i n the natural gas industry and to produce food and ch emical-grade

CO 2 .

201 The “Cost and Performance Baseline” reports are a series of reports by DOE/NETL that establish estimates for th e cost and performance of combustion- and gasification-based p ower plants - all with and without CO 2 capture and storage. Available at www.netl.doe.gov/energy-analyses/baseline_studies.h tml

. 202 “Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture”, DOE/NETL-2011/1498, May 27 , 2011. Comment [A72]: It would be helpful to summarize the reports to substantiate the statement that these reports support the technical feasibilit y determination by EPA. EPA: We are considering this suggestion further.

Deleted: ve

Comment [LRB73]: Addresses Interagency comment that this text did not fit in section c.i, so we moved it here.

Deleted: ing***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 210 of 373 Although current capture technologies are feasible, the

costs of CO 2 capture and compression represent the largest barriers to widespread commercialization of CCS. Cu rrently

available CO 2 capture and compression processes are estimated to represent 70 to 90 percent of the overall CCS costs

. 203
In general, CO 2 capture technologies applicable to coalfired power generation can be categorized into thre e approaches: 204

• Pre-combustion systems that are designed to separat e CO 2 and

H 2 in the high-pressure syngas produced at IGCC power plants.

• Post-combustion systems that are designed to separa te CO 2 from the flue gas produced by fossil-fuel combustio n in

air.

• Oxy-combustion that uses high-purity O 2 , rather than air, to combust coal and thereby produce a highly concentra ted CO 2

stream.Each of these three carbon capture approaches (precombustion, post-combustion, and oxy-combustion) is technologically feasible. However, each results in increased

203 Report of the Interagency Task Force on Carbon Cap ture and Storage (August 2010). 204 IPCC, 2005; DOE, 2007.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 211 of 373 capital and operating costs and decreased electrici ty output (that is, an energy penalty), with a resulting incr ease in the cost of electricity. The energy penalty occurs beca use the CO 2 capture process uses some of the energy (e.g., elec tricity, steam, heat) produced from the plant.

b. CO 2 transportation Carbon dioxide has been transported via pipelines i n the U.S. for nearly 40 years. Approximately 50 million metric tons

of CO 2 are transported each year through 3,600 miles of pipelines. Moreover, a review of the 500 largest CO 2 point sources in the U.S. shows that 95 percent are withi n 50 miles of a possible geologic sequestration site, 205 which would lower transportation costs. There are multiple factors that contribute

to the cost of CO 2 transportation via pipelines including but not limited to; availability and acquisition of rights- of-way for new pipelines, capital costs, operating costs, leng th and diameter of pipeline, terrain, flow rate of CO 2 , and the number of sources utilizing the pipeline. At the same time , studies and DOE quality guidelines have shown CO 2 pipeline transport costs in

205 JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gu pta, SH Kim, EL Malone (2006), Carbon Dioxide Capture and G eologic Storage: A Key Component of a Global Energy Technol ogy Strategy to Address Climate Change. Joint Global Change Rese arch Institute, Battelle Pacific Northwest Division. PNW D-3602. College Park, MD. Comment [A74]: Can EPA address the costs associated with any new pipelines that could be use d for transportation? Or the costs to get from a fac ility to a GS site?

EPA: Text added.

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 212 of 373 the $1 to $4 dollar per ton of CO 2 range. 206,207,208,209 For these reasons, the transportation component of CCS is well-established as technically feasible and is not a significant component of

the cost of CCS.

c. CO 2 storage (i) Current availability of geologic sequestration Existing project and regulatory experience (includi ng EOR), research, and analogs (e.g. naturally existing CO 2 sinks, natural gas storage, and acid gas injection), indicate that geologic sequestration is a viable long term CO 2 storage option. While EPA has confidence that geologic sequestration is techn ically feasible and available, EPA recognizes the need to continue to advance the understanding of various aspects of the technology, including, but not limited to, site selection and

206 Report of the Interagency Task Force on Carbon Capt ure and Storage (August 2010). 207 McCollum, D., Ogden, J., 2006. Techno-Economic Mode ls for Carbon Dioxide Comprssion, Transport, and Storage & Correlations for Estimating Carbon Dioxide Density and Viscosity . Institute of Transportation Studies, University of California , Davis, Davis, CA 208 McCoy, S., E.S. Rubin and M.B. Berkenpas, 2008. Technical Documentation: The Economics of CO2 Transport by Pi peline Storage in Saline Aquifers and Oil Reserves. Final Report , Prepared by Carnegie Mellon University, Pittsburgh, PA for U.S. Department of Energy, National Energy Technology Ce nter, Pittsburgh, PA 209 DOE/NETL. (2013). Carbon Dioxide Transport and Sto rage Costs in NETL Studies, Quality Guidelines for energy syst em studies. March 2013. DOE/NETL-2013/1614. Deleted: expected to be

Deleted: impediment to the commercial availability Deleted: in the future Comment [A75]: Can EPA provide a more direct explanation of how the permanence of storage has been demonstrated? The explanation that follows talks about how storage locations and opportunities are available for geologic sequestration and EOR, but does not discuss evidence that CO2 can actually be technically stored for long periods of time. I believe that evidence exists, but would be good to explain directly.

EPA: Text added.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 213 of 373
characterization, CO 2 plume tracking, and monitoring. On-going Federal government efforts such as DOE/NETL’s activ ities to enhance the commercial development of safe, afforda ble, and broadly deployable CCS technologies in the United S tates, including: Research, development, and demonstration of CCS technologies and the assessment of the country's ge ologic capacity to store carbon dioxide are particularly i mportant. 210

Furthermore, t his rule, including the information collected through the GHG Reporting Program, will facilitate further deployment of CCS and advancements in the technolog y. Information collected under the GHG Reporting Progr am will provide a transparent means for EPA and the public to continue to evaluate the effectiveness of CCS, including imp rovements needed in monitoring technologies.

The viability of geologic sequestration of CO 2 is based on a demonstrated understanding of the fate of CO 2 in the subsurface. Geologic sequestration occurs through a combination of structural and stratigraphic trapping (trapping bel ow a low permeability confining layer), residual CO 2 trapping (retention as an immobile phase trapped in the pore spaces of the storage formation), solubility trapping (dissolution in the in situ

210 Report of the Interagency Task Force on Carbon Capt ure and Storage (August 2010). Deleted: T***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 214 of 373 formation fluids), mineral trapping (reaction with the minerals in the storage formation and confining layer to pro duce carbonate minerals), and preferential adsorption tr apping (adsorption onto organic matter in coal and shale). 211,212 These mechanisms are functions of the physical and chemic al properties

of CO 2 and the geologic formations into which the CO 2 is injected.

Project and research experience continues to add t o the confidence in geologic sequestration as a viable CO 2 reduction technology. In addition to the four existing comme rcial CCS

facilities worldwide 213 , multiple studies have been completed that have demonstrated geologic sequestration of CO 2 as well as have improved technologies to monitor and verify th at the CO 2 remains sequestered. 214 For example, CO 2 has been injected in the

SACROC Unit in the Permian basin since 1972 for enh anced oil recovery purposes. A study of this site evaluated t his project,

and estimated that about 93 million metric tons of CO 2 were

211 Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide Capture and Storage. Retrieved from http://www.ipcc.ch/pdf/special-reports/srccs/srccs_ chapter5.pdf 212 Benson, Sally M. and David R. Cole. (2008). CO 2 Sequestration in Deep Sedimentary Formations . Elements , Vol. 4, pp. 325–331. 213 Sleipner in the North Sea, Snøhvit in the Barents S ea, In Salah in Algeria, and Weyburn in Canada. 214 Report of the Interagency Task Force on Carbon Capt ure and Storage (August 2010).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 215 of 373 injected and about 38 million metric tons were prod uced from 1972 to 2005, resulting in a geologic CO 2 accumulation of 55

million metric tons of CO 2 . 215 This study evaluated the ongoing and potential CO 2 trapping occurring through various mechanisms using modeling and simulations, and collection and analysis of seismic surveys and well logging data. The monitori ng at this

site demonstrated that CO 2 can indeed become trapped in geologic formations. Studies on the permanence of CO 2 storage in geologic sequestration have been conducted internationally a s well. For example, the Gorgon Carbon Dioxide Injection Projec t and CollieSouth West CO 2 Geosequestration Hub project in Australia have both demonstrated geologic CO 2 trapping mechanisms. 216
Numerous other field studies, for example those con ducted by the DOE/NETL Regional Carbon Sequestration Partn erships, have been completed that demonstrate CO 2 trapping mechanisms working in geologic formations in smaller scale projects (o ther similar

215 Han, Weon Shik et al. (2010). Evaluation of trapping mechanisms in geologic CO2 sequestration: Case study of SACROC northern platform, a 35-year CO 2 injection site . American Journal of Science Online April 2010 vol. 310 no. 4 282-324. R etrieved from: http://www.ajsonline.org/content/310/4/282.ab stract 216 Sewell, Margaret, Frank Smith and Dominique Van Ge nt. Western Australia Greenhouse Gas Capture and Storage: A tal e of two projects. (2012). Australian Department of Resource s, Energy and Tourism and Western Australia Government of Western Australia. Retrieved from http://cdn.globalccsinstitute.com/sites/default/fil es/publicatio ns/39961/ccsinwareport-opt.pdf***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 216 of 373 projects are underway). Examples of these DOE/NETL studies

include: 217

• Midwest Regional Carbon Sequestration Partnership M ichigan Basin Phase II Validation Test, which injected approximately 60,000 metric tons of CO 2 over two period from February to March 2008 (~10,000 metric tons) and fr om January to July 2009 (~50,000 metric tons).

• Midwest Geologic Sequestration Consortium Loudon, M umford Hills, and Sugar Creek Phase II Validation Test, wh ich consisted of injecting over 14,000 tons of CO 2 across three

EOR-scale field tests.

• Southwest Regional Partnership on Carbon Sequestrat ion
(SWP) San Juan Basin Phase II Validation Test, whic h injected 16,700 metric tons into the coal layers of the

Fruitland Formation.

Geologic storage potential for CO 2 is widespread and available throughout the U.S. and Canada. Estimates based on DOE studies indicate that areas of the U.S. with approp riate geology

217 DOE/NETL. (2012). Best Practices for: Monitoring, Verification, and Accounting of CO2 Stored in Deep Geologic Formations – 2012 Update . DOE/NETL-2012/1568. Retrieved from http://www.netl.doe.gov/technologies/carbon_seq/ref shelf/BPMMVA-2012.pdf. Comment [LRB76]: Added per interagency comment on ‘Geologic Sequestration’ (page 12-13 of comment response document.). Deleted: Existing project and regulatory experience (including EOR), research, and analogs (e.g. naturally existing CO 2 sinks, natural gas storage, and acid gas injection), indicate that geologic sequestration is a viable long term CO 2 storage option. While the EPA has confidence that geologic sequestration is technically feasible and available, the EPA recognizes the need to continue to advance the understanding of various aspects of the technology, including, but not limited to, site selection and characterization, CO 2 plume tracking, and monitoring. This rule, including the information collected through the GHG Reporting Program, will facilitate further deployment of CCS and advancements in the technology. Information collected under the GHG Reporting Program will provide a transparent means for the EPA and the public to continue to evaluate the effectiveness of CCS, including improvements needed in monitoring technologies.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 217 of 373 have a storage potential of 2,300 billion to more t han 20,000

billion metric tons of CO 2 in deep saline formations, oil and gas

reservoirs and un-mineable coal seams. 218 Other types of geologic formations such as organic rich shale and basalt ma y also have the ability to store CO 2 ; and the DOE is currently evaluating their potential storage capacity. While these are estimates, each p otential geologic sequestration site must undergo appropriate site characterization to ensure that th e site can safely and securely store CO 2 . Estimates of CO 2 storage resources by state/province are compiled by the DOE’s Nationa l Carbon Sequestration Database and Geographic Information S ystem
(NATCARB). Further evidence of the widespread availability CO 2 storage reserves in the U.S. comes from the Department of I nterior’s U.S. Geological Survey (USGS) which has recently co mpleted a comprehensive evaluation of the technically accessi ble storage resource for carbon storage for 36 sedimentary basi ns in the

onshore areas and State waters of the United States

. 219 The USGS assessment estimates a mean of 3,000 billion metric tons of

218 The United States 2012 Carbon Utilization and Stor age Atlas, Fourth Edition, U.S Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory (NETL ). 219 U.S. Geological Survey Geologic Carbon Dioxide Sto rage Resources Assessment Team, 2013, National assessmen t of geologic carbon dioxide storage resources – Results: U.S. Ge ological Survey Circular 1386, 41 p., http://pubs.usgs.gov/f s/2013/1386/. Deleted: ¶ P Deleted: s***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 218 of 373

subsurface CO 2 storage potential across the United States. For comparison, this amount is 500 times the 2011 annua l U.S. energy-related CO 2 emissions of 5.5 Gigatons (Gt). 220
Nearly every state in the U.S. has or is in close p roximity to formations with carbon storage potential includi ng vast areas

offshore. (ii) Current availability of enhanced oil and gas recove ry Geologic storage options also include use of CO 2 in EOR , which is the injection of fluids into a reservoir to increa se oil production efficiency. E O R is typically conducted at a reservoir after production yields have decreased fr om primary production. Fluids commonly used for E O R include brine, fresh water, steam, nitrogen, alkali solutions, surfactan t solutions, polymer solutions, and CO 2 . EOR using CO 2 , sometimes referred to

as ’CO 2 flooding’ or CO 2 -EOR, involves injecting CO 2 into an oil reservoir to help mobilize the remaining oil and ma ke it available for recovery. The crude oil and CO 2 mixture is produced, and sent to a separator where the crude o il is separated from the gaseous hydrocarbons and CO 2 . The gaseous CO 2 - rich stream then is typically dehydrated, purified to remove

220 U.S. Geological Survey Geologic Carbon Dioxide Sto rage Resources Assessment Team, 2013, National assessmen t of geologic carbon dioxide storage resources – Summary: U.S. Ge ological Survey Factsheet 2013-3020, 6p.http://pubs.usgs.gov/fs/2013/3020/. Deleted: At the end of 2012 three large-scale geologic sequestration projects were underway in the U.S., with a goal of injecting more than 1 million tonnes of CO 2 . The U.S. experience with large-scale CO 2 injection, such as at enhanced oil and gas recovery projects, combined with ongoing research, development, and demonstration programs in the U.S. and throughout the world, provide confidence that the storage - along with capture, compression and transport - of large amounts of CO 2 can be achieved. Comment [A77]: And to put this in context, consider adding a clause at the end that notes what percent 1 million tonnes of CO2 is out of total availability estimates in the US Comment [A78]: This seems less focused on availability of CO2 storage. Consider omitting.

EPA: Text omitted.

Deleted: enhanced oil recovery Deleted: . Enhanced recovery (ER), which includes both enhanced oil and gas recovery (EOR and EGR), refers Deleted: to Deleted: and/or gas Deleted: carbon dioxide Deleted: carbon dioxide Deleted: carbon dioxide***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 219 of 373 hydrocarbons, recompressed, and re-injected into th e oil or natural gas reservoir to further enhance recovery.

CO 2 -EOR has been successfully used at many production fields throughout the U.S. to increase oil recovery. The o il and natural gas industry in the United States has over 40 years of experience of injection and monitoring of CO 2 in the deep subsurface for the purposes of enhancing oil and na tural gas production. This experience provides a strong found ation for the injection and monitoring technologies that will be needed for successful deployment of CCS. Monitoring CO 2 at EOR sites can be an important part of the petroleum reservoir management system to ensure the CO 2 is effectively sweeping the oil zone, and can be suppl emented by techniques designed to detect CO 2 leakage. Recently many studies

have been conducted to better understand the fate o f injected CO 2 at well-established, operational EOR sites. A large number of

methods are available to monitor surface and subsur face leakage at EOR sites. Some recent studies are presented bel ow.

• At the SACROC field in the Permian Basin, the Texas Bureau of Economic Geology conducted an extensive groundwa ter sampling program to look for evidence of CO 2 leakage in the shallow freshwater aquifers. At the time of the stu dy (2011), the SACROC field had injected 175 million m etric Comment [A79]: Does the monitoring ensure that CO2 is stored long-term, and therefore “successful”. Are there references that could be added here that provide background on the monitoring of CO2-EOR?

EPA: Text added.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 220 of 373

tons of CO 2 over 37 years. No evidence of leakage was

detected. 221

• An extensive CO 2 leakage monitoring program was conducted by a third party (International Energy Agency Greenhou se Gas Programme) for 10 years at the Weyburn oil field in Saskatchewan, during which time over 16 million ton nes of

CO 2 have been stored. A comprehensive analysis of surfa ce and subsurface monitoring methods was conducted and resulted in a best practices manual for CO 2 monitoring at

EOR sites. 222

• The Texas Bureau of Economic Geology has also been testing a wide range of surface and subsurface monitoring t ools and approaches to document storage efficiency and stora ge permanence at a CO 2 EOR site in Mississippi. 223 The Cranfield

221 K.D. Romanak, R.C. Smyth, C. Yang, S.D. Hovorka, M . Rearick, J. Lu. (2011). Sensitivity of groundwater systems to CO2: Application of a site-specific analysis of carbonat e monitoring parameters at the SACROC CO 2 -enhanced oil field . GCCC Digital Publication Series #12-01. Retrieved from http://www.beg.utexas.edu/gccc/forum/codexdownloadp df.php?ID=190 222 Geoscience Publishing. (2012). Best Practices for Validating CO 2 Geological Storage: Observations and Guidance from the IEAGHG Weyburn-Midale CO 2 Monitoring and Storage Project . Brian Hitchon (Ed.), 223 Hovorka, S.D., et al. (2011). Monitoring a large volume CO 2 injection: Year two results from SECARB project at Denbury’s Cranfield, Mississippi, USA : Energy Procedia, v. 4, Proceedings of the 10th International Conference on Greenhouse Gas Control Technologies GHGT10, September 19-23, 2010, Amsterd am, The Netherlands, p. 3478-3485. GCCC Digital Publication #11-16.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 221 of 373
Field, under CO 2 flood by Denbury Onshore LLC, is a depleted oil and gas reservoir that injected greater than 1. 2 million tons/year during the tests. The preliminary findings demonstrate the availability and effective ness of many different monitoring techniques for tracking C O 2 underground and detecting CO 2 leakage. The Department of Energy has conducted numerous eva luations

of CO 2 monitoring techniques at EOR pilot sites throughou t the U.S. as part of the Regional Sequestration Partners hip Phase II and III programs. For example, in the Illinois Basi n surface and subsurface monitoring techniques were tested at thr ee short

duration CO 2 injections. At one of the Illinois Basin sites, a

landowner became concerned when excessive odor in a water well was observed. The ongoing groundwater monitoring pr ogram results were used to verify the odor was from a different o rigin. 224
The EPA anticipates that many early geologic seques tration projects may be sited in active or depleted oil and gas reservoirs because these formations have been previ ously well

Retrieved from http://www.sciencedirect.com/science/article/pii/S1 8766102110047 11 224 DOE/NETL. (2012). Best Practices for: Monitoring, Verification, and Accounting of CO 2 Stored in Deep Geologic Formations – 2012 Update . DOE/NETL-2012/1568. Retrieved from http://www.netl.doe.gov/technologies/carbon_seq/ref shelf/BPMMVA-2012.pdf. Comment [LRB80]: Moved below to improve text flow Deleted: Although deep saline formations provide the most CO 2 storage opportunity (2,102 to 20,043 billion metric tons), oil and gas reservoirs are currently estimated to have 226 billion metric tons of CO 2 storage resource. 225***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 222 of 373 characterized for hydrocarbon recovery, likely alre ady have suitable infrastructure (e.g., wells, pipelines, et c.), and have an associated economic benefit of oil production

. EOR sites including those that inject CO 2 , are typically selected and operated with the intent of oil production; however , they may
also be suitable for long term containment of CO 2 . Although deep saline formations provide the largest CO 2 storage opportunity (2,102 to 20,043 billion metric tons), oil and gas reservoirs are currently estimated to have 226 billion metric tons of CO 2 storage resource. 226

CO 2 -EOR is the fastest-growing EOR technique in the U. S., providing approximately 281,000 barrels of oil per day in the U.S. which equals about 6 percent of U.S. crude oil production. The vast majority of CO 2 -EOR is conducted in oil reservoirs in the U.S. Permian Basin, which extends through south west Texas
and southeast New Mexico. Other U.S. states where C O 2 -EOR is
utilized are Alabama, Colorado, Illinois, Kansas, L ouisiana, Michigan, Mississippi, New Mexico, Oklahoma, Utah, and Wyoming. A well-established and expanding network of pipelin e infrastructure supports CO 2 -EOR in these areas. The CO 2 supply

226 U.S. Department of Energy National Energy Technolo gy Laboratory (2012). United States Carbon Utilization and Storage Atlas, Fourth Edition. Deleted: , and

Comment [A81]: Why is this statement qualified (“may be”)?

EPA: Text revised. Deleted: As noted earlier, potential geologic sequestration sites must undergo appropriate site characterization to ensure that the site can safely and securely store the CO 2 permanently.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 223 of 373 for EOR operations currently is largely obtained from natural underground formations or domes that contain CO 2 . While natural

sources of CO 2 comprise the majority of CO 2 supplied for EOR operations, recent developments targeting anthropog enic sources

of CO 2 (e.g., ethanol plants, gas processing plants , refineries, power plants) have expanded or led to planned expan sions in existing infrastructure related to CO 2 -EOR. Several hundred miles

of dedicated CO 2 pipeline is under construction, planned, or proposed that would allow continued growth in CO 2 supply for EOR.

Potential sources of CO 2 for EOR continue to increase as new projects are being planned or implemented. Based on an evaluation of publicly available sources, the EPA n otes there are currently twenty- three industrial source CCS projects in twelve states that are either operational, under-co nstruction, or actively being pursued which are or will supply captured CO 2 for the purposes of EOR. 227 This further demonstrates that CCS projects associated with large point sources are oc curring due

to a demand for CO 2 by EOR operations. Nationally, approximately

60 million metric tons of CO 2 were received for injection at EOR operations in 2012. 228 A recent study by DOE found that the

227 See memo to docket “abc” 228 “Opportunities for Utilizing Anthropogenic CO 2 for Enhanced Oil Recovery and CO 2 Storage”, Michael L. Godec, Advanced Resources International, June 11, 2013 presentation at the Deleted: two

Comment [A82]: Is there a reference that can be added that summarizes these projects? EPA: We are still addressing this comment.

Deleted: according to the EPA’s Greenhouse Gas Reporting Program, over Deleted: 64 Deleted: to Deleted: enhanced oil recovery Deleted: 2011 Formatted: Highlight***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 224 of 373
market for captured CO 2 emissions from power plants created by economically feasible CO 2 -EOR projects would be sufficient to permanently store the CO 2 emissions from 93 large (1,000 MW) coal-fired power plants operated for 30 years. 229 Based on all of these factors, the EPA anticipates opportunities to utilize CO 2 - EOR operations for geologic storage will continue t o increase. Based on a recent resource assessment by the DOE, t he application of next generation CO 2 -EOR technologies would significantly increase oil production areas, furthe r expanding the geographic extent and accessibility of CO 2 -EOR operations in

the U.S. 230 Additionally, oil and gas fields now considered to be ‘depleted’ may resume operation because of increase d availability and decreased cost of anthropogenic CO 2 , and developments in EOR technology, thereby increasing the demand for and accessibility of CO 2 utilization for EOR.

3. The use of CO 2 for EOR can significantly lower the net cost of implementing CCS. The opportunity to sell the ca ptured CO 2 for EOR, rather than paying directly for its long-t erm storage, improves the overall economics of the new generating

Introduction to CO 2 EOR Workshop, http://na2050.org/introductionto-carbon-dioxide-enhanced-oil-recovery-co2-eor. 229 “Improving Domestic Energy Security and Lowering C O 2 Emissions with “Next Generation” CO 2 -Enhanced Oil Recovery (CO 2 -EOR)”, DOE/NETL-2011/1504 (June 20, 2011). 230 Ibid. Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 225 of 373 unit. According to the International Energy Agency (IEA), of the CCS projects under construction or at an advanc ed stage of planning, 70 percent intend to use captured CO 2 to improve recovery of oil in mature fields. 231 Examples of CCS demonstration projects The following is a brief summary of some examples of currently operating or planned CO 2 capture or storage systems, including, in some cases, components necessary for coal- fired power plant CCS applications.
AES’s coal-fired Warrior Run (Cumberland, MD) and S hady Point (Panama, OK) power plants are equipped with a mine scrubbers developed by ABB/Lummus. They were design ed to process a slip stream of each plant’s flue gas. At Warrior Run, approximately 110,000 metric tons of CO 2 per year are captured

.
A t Shady Point 66,000 metric tons of CO 2 per year are captured.

The CO 2 from both plants is used in the food processing industry. 232
At the Searles Valley Minerals soda ash plant in Tr ona, CA, approximately 270,000 metric tons of CO 2 per year are captured

231 Tracking Clean Energy Progress 2013, International Energy Agency (IEA), Input to the Clean Energy Ministerial , OECD/IEA 2013. 232 Dooley, J. J., et al. (2009). An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009. U.S. DOE, Pacific Northwest Nation al Laboratory, under Contract DE-AC05-76RL01830. Deleted: ¶ Alternatives to geologic sequestration¶ In the development of this proposal, the EPA has identified some potential alternatives to geologic sequestration, including but not limited to CO 2 stored in precipitated calcium carbonate and certain types of cement. The EPA solicits comment on whether these and other alternatives to geologic sequestration, permanently store CO 2 and if they are technically available for EGUs to meet the performance standard. Consideration of how these alternatives could meet the performance standard involves understanding the ultimate fate of the captured CO 2 and the degree to which the method permanently isolates the CO 2 from the atmosphere, as well as existing methodologies to verify this permanent storage. The EPA proposes that alternatives to geologic sequestration could not be used until the EPA finalizes a mechanism for that alternative to demonstrate permanent storage of CO 2 . The EPA believes that the number of cases where an EGU would seek to comply with the rule through an alternative will be very small. However the EPA wishes to encourage development of alternatives to geologic sequestration that could help offset the cost of CO 2 capture.¶ Comment [A83]: Considering that this standard is set forth for other alternatives, EPA should add ress how EPA’s proposal meets this test. EPA: We are considering this comment

Deleted: based Deleted: , whereas Deleted: a Deleted: subsequently***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 226 of 373 from the flue gas of a coal-fired power plant via a mine scrubbing and used for the carbonation of brine in the process of producing soda ash. 233
A pre-combustion Rectisol® system is used for CO 2 capture at the Dakota Gasification Company’s synthetic natural gas production plant located in North Dakota, which is designed to remove approximately 1.6 million metric tons of CO 2 per year from the synthesis gas. The CO 2 is purified and transported via a 200- mile pipeline for use in EOR operations in the Weyb urn oilfield
in Saskatchewan, Canada. In September 2009, AEP began a pilot-scale CCS

demonstration at its Mountaineer Plant in New Haven , WV. The Mountaineer Plant is a 1,300 MWe coal-fired unit th at was retrofitted with Alstom’s patented chilled ammonia CO 2 capture technology on a 20 MWe slip stream of the plant’s e xhaust flue gas. In May 2011, Alstom Power announced the succes sful operation of the chilled-ammonia CCS validation pro ject. The demonstration achieved capture rates from 75 percen t (design value) to as high as 90 percent, and produced CO 2 at purity of greater than 99 percent, with energy penalties with in a few percent of predictions. The facility reported robus t steadystate operation during all modes of power plant ope ration

233 IEA (2009), World Energy Outlook 2009, OECD/IEA, P aris. Deleted: ,

Deleted: American Electric Power Co. ( Deleted: )

Deleted: a***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 227 of 373 including load changes, and saw an availability of the CCS system of greater than 90 percent. AEP, with assistance from the DOE, had planned to e xpand the slip stream demonstration to a commercial scale , fully integrated demonstration at the Mountaineer facilit y. The commercial-scale system was designed to capture at least 90 percent of the CO 2 from 235 MW of the plant's 1,300 MW total capacity. Plans were for the project to be complete d in four phases, with the system to begin commercial operati on in 2015. However, in July 2011, AEP announced that it would terminate its cooperative agreement with the DOE and place its pl ans to

advance CO 2 capture and storage technology to commercial scale on hold, citing the uncertain status of U.S. climate p olicy as a

contributor to the decision. Oxy-combustion of coal is being demonstrated in a 1 0 MWe facility in Germany. The Vattenfall plant in easter n Germany (Schwarze Pumpe) has been operating since September 2008. It is designed to capture 70,000 metric tons of CO 2 per year. A larger scale project is in advanced stages of planning in the U.S. In June 2011, Mitsubishi Heavy Industries, an equip ment manufacturer, announced the successful launch of op erations at a 25 MW coal-fired carbon capture facility at Souther n Company's Alabama Power Plant Barry. The demonstration captur es Comment [A84]: Any 2013 update?

EPA: Not that we are aware of.

Comment [A85]: Are there any further details that can be added?

EPA: Text added.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 228 of 373 approximately 165,000 metric tons of CO 2 annually at a CO 2 capture rate of over 90 percent. The captured CO 2 is being permanently stored underground in a deep saline geo logic

formation. Southern Company has begun construction of Mississi ppi Power Kemper County Energy Facility. This is a 582 MW IGCC plant that will utilize local Mississippi lignite and inc lude precombustion carbon capture to reduce CO 2 emissions by 65 percent. The captured CO 2 will be used for EOR in the Heidelberg Oil Fields in Jasper County, MS. The project is now mor e than 75 percent complete with start-up and operation expect ed to begin

in 2014. SaskPower’s Boundary Dam CCS Project in Estevan, a city in

Saskatchewan , Canada. The project is the world’s largest commercial-scale CCS project of its kind. The proje ct will fully integrate the rebuilt 110 MW coal-fired Unit #3 wit h available CCS technology to capture 90% of its CO 2 emissions. The facility is currently under construction. Performance testin g is expected to commence in late 2013 and the facility is expect ed to be fully operational in 2014. The Texas Clean Energy Project, a 400 MW IGCC facil ity located near Odessa, Texas will capture 90 percent of its CO 2 , which is approximately 3 million metric tons annual ly. The Deleted: enhanced oil recovery ( Deleted: )

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 229 of 373
captured CO 2 will be used for EOR in the West Texas Permian Basin. Additionally, the plant will produce urea an d smaller quantities of commercial-grade sulfuric acid, argon , and inert slag, all of which will also be marketed. The devel oper expects financing to be fully arranged in 2013. There are other CCS projects – domestic and worldwi de -- that are helping to further develop the CCS technol ogy. They are noted in the DOE/NETL’s Carbon Capture, Utilization , and Storage
(CCUS) Database. 234 The database includes active, proposed, canceled, and terminated CCUS projects worldwide.

F. Costs As noted, according to the D.C. Circuit case law, c ontrol costs are considered acceptable as long as they are reasonable, meaning that they can be accommodated by the industry. 235 To determine reasonableness, the Court has looked to t he amount of the control costs, whether they could be passed on to the consumer, and how much they would lead prices to in crease. As we

234 Available at http://www.netl.doe.gov/technologies/carbon_seq/glo bal/database/ Information in the database regarding technologies being developed for capture, evaluation of sites for carb on dioxide (CO 2 ) storage, estimation of project costs, and anticip ated dates of completion is sourced from publically available information. The CCUS Database provides the public with informat ion regarding efforts by various industries, public groups, and g overnments towards development and eventual deployment of CCUS technology. 235 In addition, the EPA may consider costs through a national lens, as discussed below. Comment [A86]: Earlier in the rule, EPA states that it will refer throughout the rule to the test as “unreasonable”. Consider using “not unreasonable” here to align with that discussion. See p. 161: in this rulemaking, we will use the “unreasonable” formulation, so that a control technology cannot be considered the “best system of emission reduction ... adequately demonstrated” if its costs are “unreasonable.” Deleted: such costs***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 230 of 373 discuss below, where EOR opportunities are availabl e, the sale of captured CO 2 offers the opportunity to defray much of the costs. However, we recognize that there are places where opportunities to sell captured CO 2 for utilization in EOR operations may not be presently available. Neverthe less, as discussed below, our analysis shows that this cost structure –
with and without EOR - is consistent with the D.C. Circuit’s criteria for determining that costs are reasonable. At the outset, it should be noted that even though t he costs of coal-fired electricity generation – even w hen not incorporating CCS technology – are high when compar ed to the current costs of new NGCC generation, some utilitie s and other project developers have indicated a willingness to proceed with new fossil fuel-fired boilers and IGCC units. They have indicated the need for energy and fuel diversity. T hey have also indicated a skepticism regarding long-term projecti ons for low natural gas prices and high availability. And there may be other reasons why developers have indicated a willingness to build new coal-fired plants, even if they currently do not ap pear to be

the most economic choice. 1. Cost estimates for implementation of partial CCS The EPA has examined costs of new power generation options. These options are shown in Table 4. The table shows the costs of Deleted: T

Comment [A87]: And other generation, yes? Can nuclear or wind also be mentioned here? EPA: Not appropriate here .... but we have mentioned wind and nuclear in other locations. Deleted: . Even so Deleted: and desire

Deleted: choose

Deleted: . For these reasons, we believe that these developers have indicated a willingness to proceed with non-NGCC projects***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 231 of 373 new NGCC technology at two different natural gas pr ices : at $5/MMBtu, which is reasonably consistent with curre nt and projected prices ; and at $10/MMBtu, which would be well above current and projected natural gas prices. We also s how costs for SCPC and IGCC units with no CCS (i.e., units that w ould not meet the proposed emission standard) and for those units with partial capture CCS installed such that their emission woul d meet the proposed 1,100 lb CO 2 /MWh standard. We have also included costs

for those same units when EOR opportunities are available. We have included a “low EOR” case assuming a low EOR p rice of $20
per ton of CO 2 , and a “high EOR” of $40/ton. (These EOR prices are net of the costs of transportation, storage, an d monitoring
(TSM). We also show the projected costs for implementation of full capture CCS (i.e., 90 percent capture). Table 4. Levelized Cost of Electricity for Electric Generating Technologies, Excluding Transmission Costs Deleted: –

Deleted: –

Deleted: plus the cost for transportation, storage and monitoring (TSM) costs Deleted: plus the cost for TSM

Comment [A88]: Probably worth a footnote explaining that this does not include savings from direct subsidies like tax credits. EPA: We are still considering this comment.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 232 of 373

Technology Levelized Cost of Electricity ($2011/MWh) 236, 237 NGCC @ $ 6.11 /MMBtu 59 NGCC @ $10.0/MMBtu 86

SCPC w/o CCS 238 92 SCPC (1,100 lb/MWh; no EOR) 110 SCPC (1,100 lb/MWh; low EOR) 96 SCPC (1,100 lb/MWh; high EOR) 88 SCPC (full, 90 percent CCS) 147

IGCC w/o CCS 97 IGCC (1,100 lb/MWh; no EOR) 109

236 Data for fossil fuel-fired generation comes from D OE/NETL: (1) Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electr icity, Rev 2, DOE/NELT-2010/1397 (Nov 2010); (2) Updated Costs (J une 2011 Basis) for Selected Bituminous Baseline Cases” DOE/ NETL341/082312 (Aug 2012); (3) Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture, DOE/N ETL-2011/1498 (May 2011). Data for non-fossil fuel-fired generati on comes from DOE Energy Information Administration (EIA) Annual Energy Outlook (AEO) 2013. Levelized Cost of Electricity ( LCOE) estimates come from http://www.eia.gov/forecasts/aeo/electricity_genera tion.cfm

. To maintain consistency with DOE/NETL estimates, EIA e stimates provided in this table do not include transmission investment. 237 LCOE point estimates are provided for coal-fired c apacity types; all other LCOE estimates are presented as a range that reflects EIA’s view on the regional variation in lo cal labor markets, cost and availability of fuel, and renewab le resources. The capacity factor ranges for renewable non-dispat chable technologies are as follows: Wind – 30% to 39%, Win d Offshore – 33% to 42%, Solar PV- 22% to 32%, and Solar Thermal – 11% to 26%. Capacity factors for dispatchable technologie s are as follows: Coal – 85%, Nuclear – 90%, Biomass – 83%, Geothermal – 92%, and Combustion Turbine – 30%. There is no cap acity credit provided to dispatchable resources. 238 SCPC LCOE includes a 3% increase to the weighted a verage cost of capital to reflect EIA’s climate uncertainty add er (CUA). Deleted: 5.0 Deleted: 52***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 233 of 373

IGCC (1,100 lb/MWh; low EOR) 101 IGCC (1,100 lb/MWh; high EOR) 97 IGCC (full, 90 percent CCS) 136

Nuclear 103 - 114 Biomass 97 - 130 Geothermal 80 – 99 Combustion Turbine 87 – 116 Onshore Wind 70 – 97 Offshore Wind 177 – 289 Solar PV 239 109 – 220 Solar Thermal 184 – 412

It is important to note here that both the EIA and the EPA apply a climate uncertainty adder (CUA) - represent ed by a three percent increase to the weighted average cost of ca pital - to certain coal-fired capacity types. The EIA develope d the CUA to address the disconnect between power sector modelin g absent GHG regulation and the widespread use of a cost of CO 2 emissions in power sector resource planning. The CUA reflects the additional planning cost typic ally assigned by project developers and utilities to GHG -intensive projects in a context of climate uncertainty. The E PA believes the CUA is consistent with the industry’s planning and evaluation framework (demonstrable through IRPs and PUC orders) and is therefore necessary to adopt in evaluating t he cost

239 Costs are expressed in terms of net AC power avail able to the grid for the installed capacity. Comment [A89]: This may benefit an explanation of why this uncertainty will still exis t after this new source rulemaking (new sources will someday be subject to different standards, whether it’s existing source standards after the 8-yr revie w or a potentially new legislative regime). EPA: We are still considering this comment.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 234 of 373 competitiveness of alternative generating technolog ies. EPA believes the CUA is relevant in considering the range of costs that power companies are willing to pay fo r generation alternatives to natural gas. To the extent that a h andful of project developers are still considering coal witho ut CCS, EPA

believes , based both on the analysis the EIA undertook in developing the CUA approach and the EPA’s review of IRPs 240
, they

must fall into one of two classes. The first , which is the minority, is not factoring in any form of a CUA. The second, which is the majority, assume that coal-fired power plants

without CCS entail additional costs due to the risk of future regulation of CO 2 . F actoring in risk associated with CO 2 suggests that these companies are, in fact, willing to pay the higher cost for coal without CCS (even if they are not act ually incurring those costs today). For these reasons, EP A believes that it is appropriate to consider the cost of coal without CCS

to include the CUA in the range of costs that utilities are willing to pay for alternatives to natural gas. The EPA is requesting comment on all aspects of the CUA , including its magnitude and technology-specific application , to

ensur e that the EPA’s supporting analysis best reflects t he current standards and practices of the power sector ’s long-term

240 [Placeholder: Cite IRP TSD here] Deleted: Either they are

Deleted: In this case, b Deleted: Based both on the analysis EIA undertook in developing the CUA approach and EPA’s review of IRPs Deleted: , Deleted: companies that do this appear to be outliers. In other words, it appears that Deleted: most companies (the second class)in fact Deleted: would not Deleted: that the costs without the CUA represents the potential cost (with risk) they would assign to a coal without CCS project. If they are, however, Formatted: Subscript Deleted: f Formatted: Subscript Deleted: carbon, that Deleted: they Deleted: not Deleted: give large Deleted: ation to Deleted: and without Deleted: both the Deleted: ’s Deleted: with the intent of Deleted: ing***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 235 of 373 planning process. 2. Comparison with the costs of other new power gen eration options While new coal-fired generation that includes CCS i s more expensive than either new coal-fired generation wit hout CCS or new NGCC generation, it is competitive with new nuc lear power, which is one of the other options often considered for providing

new base load power, and with other low-GHG emitting generation technologies. A review of utility IRPs shows that a number of companies are considering new nuclear power as an o ption for new

base load generation capacity in lieu of new coal-fired generation with or without CCS, because , according to the IRPs, nuclear power is a cost-effective way to generate base load electricity that addresses risks associated with po tential future carbon liabilities. New fossil fuel-fired ge neration that

includes CCS serves the same basic function as new nuclear power: providing base load power with a lower carbon footprint. New coal-fired generation that incorporates partial CCS that is

sufficient to meet the CO 2 emission limitation that we are proposing in today’s action (1,100 lb CO 2 /MWh) would have a

similar levelized cost of electricity ( LCOE ) as a new nuclear power plant (about $103/MWh - $114/MWh). This indic ates that, at the proposed emission limitation of 1,100 lb CO 2 /MWh, the cost of Deleted: baseload

Deleted: baseload

Deleted: they state it Deleted: baseload

Comment [A90]: In light of Fukushima, is this still accurate? Consider adding a footnote to acknowledge Fukushima context. EPA: We are still considering this comment. Deleted: baseload***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 236 of 373 new coal-fired generation that includes CCS is reas onable today.

3. Costs of “Full capture” CCS

As noted in Table 4, above, and discussed in the RIA 241 for this rulemaking, implementation of CCS to achieve 9 0 percent CO 2 capture adds considerably to the LCOE from a new SC PC or IGCC unit. The LCOE for a new SCPC and a new IGCC, both without CCS, are estimated to be $92/MWh and $97/MWh, respective ly. The corresponding costs with implementation of “full ca pture” CCS are $147/MWh for the new SCPC unit and $136/MWh for the new IGCC unit. These costs exceed what project developers ha ve been willing to pay for other low GHG-emitting base load generating technologies (e.g., nuclear) that also provide ener gy diversity.

For that reason alone , we do not believe that the costs of full implementation of CCS are reasonable at this time. 4. Reasonableness of costs of partial CCS As noted, the current costs of coal, natural gas, a nd construction of coal-fired or natural gas-fired EGU s have led to little currently announced or projected new coal-fi red generating capacity. This very likely reflects the large price
differential between the cost of a new NGCC (cost o f

241 Regulatory Impact Analysis for the Standards of Pe rformance for Greenhouse Gas Emissions for New Fossil Fuel-Fi red Electric Utility Steam Generating Units and Stationary Combu stion Turbines (available in the rulemaking docket EPA-HQ -OAR-2013- 0495) Comment [A91]: Not unreasonable? in this rulemaking, we will use the “unreasonable” formulation, so that a control technology cannot be considered the “best system of emission reduction ... adequately demonstrated” if its costs are “unreasonable.” Deleted: Regulatory Impact Analysis ( Deleted: ) Deleted: levelized cost of electricity ( Deleted: )

Deleted: baseload***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 237 of 373 electricity: $ 59 /MWh at a natural gas price of $ 6.11 /MMBtu) and SCPC without CCS (cost of electricity: $92/MWh) and IGCC without CCS (cost of electricity: $97/MWh), coupled with a leveling of demand for electricity and the recent increase in r enewable

sources. We observe that most of the industry appears to tak e the view that the price of natural gas will remain suff iciently low for at least a long enough period into the future t hat new natural-gas fired electricity generation will be le ss expensive than new coal-fired generation. As a result, in mos t cases, customers or utilities that contract for new genera tion are doing so for natural gas-fired generation. Long-ter m contracts for electricity supply are commonly for a 25-year p eriod; thus, most of the industry appears to consider contractin g for new natural gas-fired generation for a 25-year period t o be the most

economical of their choices. As shown in Table 4, we estimate that a new SCPC pl ant costs $92/MWh, which is $ 33 /MWh, or about 56 percent higher than the new NGCC cost of $ 59 /MWh. Limiting the emission rate to
1,100 lb CO 2 /MWh (which can be achieved by adding partial CCS), without sale of captured CO 2 for EOR, would add another $18/MWh to the cost of electricity, for a total of $110/MWh . Thus, the total additional cost to meet the proposed standard by Deleted: 52 Deleted: 5

Deleted: 40 Deleted: 77 Deleted: 52***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 238 of 373 implementing partial capture CCS (without revenues from CO 2 sales for EOR) is about half the additional cost of coal- fired generation, compared to natural-gas fired generatio n. We are aware of another segment of the industry, wh ich includes electricity suppliers who have indicated a preference for new coal-fired generation to establish or maint ain fuel diversity in their generation portfolio because the ir customers have expressed a willingness to pay a premium for t hat diversity. It appears these utilities and project d evelopers see lower risks to long-term reliance on coal-fired gen eration and greater risks to long-term reliance on natural gas- fired generation, compared to the rest of the industry.

We consider the costs of CCS to be reasonable for t his segment of the industry as well. The additional cos ts of CCS for new SCPC of $18/MWh LCOE ($110/MWh for SCPC with pa rtial CCS compared to $92/MWh for SCPC without CCS) are only about half as much as the additional costs that are already need to be incurred to develop coal-fired electricity as compa red to new NGCC generation ($92 MWH for SCPC without CCS compa red to $ 59 MWh for NGCC at a natural gas price of $ 6.11 /MMBtu). Moreover, it is possible that under these circumstances, the demand for the electricity would be inelastic with respect to the price because it may not depend on cost as much as on a d emand for Deleted: would

Deleted: 52

Deleted: 5***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 239 of 373 energy diversity. These circumstances would be simi lar to the

Portland Cement (1975) case, discussed above, in which the D.C. Circuit upheld NSPS controls that increased capital and operating costs by a substantial percentage because the demand for the goods was inelastic with respect to price, so that the industry could pass along the costs. 242
In addition, we consider the costs of partial CCS t o be

reasonable because a segment of the industry is already

accommodat ing them. As noted, a segment of the industry consists of the several coal-fired EGU projects that already incorporate at least partial CCS. These projects, which are eac h progressing, include Kemper, TCEP, and HECA. Each i s an IGCC plant that expects to generate profits from the sal e of products that result from coal gasification, in addition to the sale of electricity. It is true that each of these projects has received DOE grants to encourage the development of CCS tech nology, but we do not consider such government subsidies to mea n that the

costs of CCS would otherwise be unreasonable. As we noted in the original proposal for this rulemaking, 243 many types of electricity generation receive government subsidies . For example, nuclear power is the beneficiary of the Pr ice-Anderson

242 Portland Cement Ass’n v. EPA , 513 F.2d 506, 508 (D.C. Cir. 1975). 243 77 Fed. Reg. at 22,418/3. Deleted: can

Deleted: e***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 240 of 373 Act, which partially indemnifies nuclear power plan ts against liability claims arising from nuclear incidents, 244 and domestic oil and gas production, 245 coal exploration and development, 246
and renewable energy generation 247 are each the beneficiary of

Federal tax incentives. 5. Opportunities to further reduce the costs of par tial CCS a. Enhanced oil recovery While the reasons noted above are sufficient to jus tify the reasonableness of the costs of partial CCS, in most cases, we

believe that the actual costs will be less . One reason is the availability of EOR. As noted, EOR is being activel y used in

various counties in the U.S., and CO 2 pipelines extend into those
counties from, in some cases, hundreds of miles awa y. We consider areas in close proximity to active EOR loc ations, including the pipelines that extend into those loca tions, to be places where EOR is available. We recognize that, at present, certain locations ar e far enough away from either oilfields with EOR availabi lity or

244 See Duke Power Co. v. Carolina Environmental Study Group, 438 U.S. 59 (1978). 245 See Internal Revenue Code §263. 246 See “General Explanations of the Administration’s Fiscal Year 2013 Revenue Proposals,” pp. 120-24http://www.treasury.gov/resource-center/taxpolicy/Documents/General-Explanations-FY2013.pdf

. 247 See Internal Revenue Code §45. Comment [A92]: Is there a reference that could be used here to show existing subsidies. It appear s this citation is about proposals.

Deleted: there are other reasons that lead to the same conclusion

Deleted: in various places

Deleted: , e.g., Deleted: , e.g.,

Deleted: , e.g.,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 241 of 373 pipelines to those oil fields that any coal-fired p ower plants

that build in those locations would incur costs to build pipeline extensions that may render EOR non-economi cal. Those locations are relatively limited when legal or prac tical limits on building coal-fired power plants are taken into account. For example, some states with locations that are not lo cated near EOR availability are not expected to have new coal- fired builds without CCS in any event, for legal or practical re asons. A

number of States , at least i n the short term, already have high reserve margins and/or have large renewable targets which push new decisions towards renewables and quick starting natural gas to provide backup to renewables over coal

- fired generation. In addition, it is important to note that coal-fire d power plants that build in any particular location may se rve demand in a wide area. There are many examples where coal-fir ed power generated in one state is used to supply electricit y in other states. For instance, historically, nearly 40 perce nt of the power for the City of Los Angeles was provided from two coalfired power plants located in Arizona and Utah. In another example, Idaho Power, which serves customers in Ida ho and Eastern Oregon, meets its demand in part from coal- fired power plants located in Wyoming and Nevada. As a result, the geographic scope of areas in which EOR is Deleted: including: California, Washington, Oregon and New York preclude new coal-fired power plants without CCS. Deleted: I Deleted: other areas

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 242 of 373 available to defray the costs of CCS should be cons idered to be large. The costs provided in Table 4 show how the a bility to

sell CO 2 for utilization in EOR can significantly affect th e overall costs of the project. We also considered how the opportunity to sell capt ured CO 2 for EOR may affect the costs for new units implemen ting full capture CCS. We previously indicated that the costs – $147/MWh for the new SCPC unit and $136/MWh for the new IGCC unit – are not reasonable and we rejected that option as BSER on that basis. We estimated that the SCPC with full capture LCOE could be reduced to between $93 and $115/MWh (depending o n selling price of the CO 2 ) and the IGCC with full capture could be reduced between $91 and $109/MWh (again, depending upon the selling price of the CO 2 ). These costs are similar with the reasonable costs for partial capture similar units with no opp ortunity to sell captured CO 2 for EOR. This indicates that in some cases (Summit’s TCEP, for example), developers may determ ine that a new unit with full capture is economically viable. However, this

factor alone does not lead us to conclude that full capture should be BSER. When considered in conjunction wit h other factors including the cost of full CCS where EOR is not available, the fact that more projects using partia l CCS than full CCS are underway and the implications for tech nology***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 243 of 373 development, EPA believes that partial CCS should b e considered

BSER.
b. Government subsidies In some instances, the costs of CCS can be defraye d by grants or other benefits provided by the DOE or the states. Although, for the reasons noted earlier, we conside r the current

costs of CCS even without subsidization to be reaso nable, the availability of these governmental subsidies supports the

reasonableness of the costs. The 2010 Interagency Task Force Report on CCS repo rt described the DOE program as follows:

The DOE is currently pursuing multiple demonstration projects using $3.4 billion of availa ble budgetary resources from the American Recovery and Reinvestment Act in addition to prior year appropriations. Up to ten integrated CCS demonstrat ion projects supported by DOE are intended to begin operation by 2016 in the United States. These demonstrations will integrate current CCS technolog ies with commercial-scale power and industrial plants t o prove that they can be permitted and operated safel y and reliably. New power plant applications will foc us on integrating pre-combustion CO 2 capture, transport, and storage with IGCC technology. Power plant retro fit and industrial applications will demonstrate integrated post-combustion capture. 248

DOE allocated some $3.4 billion for 5-10 projects, and has committed $2.2 billion for 5 projects to date. In a ddition,

248 Task Force Report on CCS, p. 76 Comment [A93]: Not unreasonable? in this rulemaking, we will use the “unreasonable” formulation, so that a control technology cannot be considered the “best system of emission reduction ... adequately demonstrated” if its costs are “unreasonable.” Deleted: confirms Comment [A94]: How so? Because the overall economic impacts are more manageable on consumers? This seems like an incomplete explanation. EPA: language has been edited.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 244 of 373

various other federal and state incentives are also available to many projects. The 2010 Interagency Task Force on C CS, in surveying all of the federal and state benefits ava ilable,
concluded that the DOE grants, “plus ... federal loan guarantees, tax incentives, and state-level drivers, cover a la rge group of potential CCS options.” 249
In addition, regulatory programs may serve to defra y the costs of CCS, including, for example, Clean Energy Standards or guaranteed electricity purchase price agreements. 250
As noted above and in the April 2012 proposal, the need for subsidies to support emerging energy systems and ne w control technologies is not unusual. Each of the major type s of energy used to generate electricity has been or is current ly being supported by some type of government subsidy such a s tax benefits, loan guarantees, low-cost leases, or dire ct expenditures for some aspect of development and uti lization, ranging from exploration to control installation. T his is true for fossil fuel-fired; as well as nuclear-, geother mal-, wind-, and solar-generated electricity. 251

249 Task Force Report on CCS, p. 76 250 See Center for Climate and Energy Solutions, “Fina ncial Incentives for CCS” - http://www.c2es.org/sites/default/modules/usmap/pdf .php?file=838 0. 251 77 Fed. Reg. at 22,418/3. Comment [A95]: Please elaborate further on these elements. More information should be provided. EPA: We are still considering this comment.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 245 of 373

c. Expected reductions in t he costs of CCS The EPA reasonably projects that the costs of CCS w ill decrease over time as the technology becomes more w idely used. Although, for the reasons noted earlier, we conside r the current costs of CCS to be reasonable, the projected decrea se in those

costs further supports their reasonableness. The D.C. Circuit case law that authorizes determining the “best” ava ilable technology on the basis of reasonable future projec tions supports taking into account projected cost reducti ons as a way

to support the reasonableness of the costs. As noted above, the D.C. Circuit, in the 1973 Portl and

Cement Ass’n v. Ruckelshaus case, stated that the EPA, in identifying the “best system of emission reduction ... adequately demonstrated,” may “look[] toward what may fairly b e projected for the regulated future, rather than the state of the art at

present....” 252 In the 1999 Lignite Energy Council v. EPA case, the

Court elaborated:

Of course, where data are unavailable, EPA may not base its determination that a technology is adequately demonstrated or that a standard is achievable on mere speculation or conjecture....but E PA may compensate for a shortage of data through the u se of other qualitative methods, including the reasona ble extrapolation of a technology's performance in othe r

252 Portland Cement Ass’n v.Ruckelshaus , 486 F.2d 375, 391 (D.C. Cir. 1973), quoted in Lignite Energy Council v. EPA , 198 F.3d 930, 933-34 (D.C. Cir. 1999). Deleted: T Deleted: are expected to decrease

Comment [A96]: Not unreasonable? in this rulemaking, we will use the “unreasonable” formulation, so that a control technology cannot be considered the “best system of emission reduction ... adequately demonstrated” if its costs are “unreasonable.” Deleted: confirms

Deleted: confirm***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 246 of 373

industries. 253

It is logical to read these statements in the D.C. Circuit case law to apply as well to the cost component of the “ best system of emission reduction ... adequately demonstrated.” We expect the costs of CCS technologies to decrease for

several reasons. We expect that significant additional knowledge will be gained from deployment and operation of at least two new coal-fired generation projects that include CCS. Th ese projects

are the Southern Company’s Kemper County Energy Facilit y IGCC with CCS and the Boundary Dam CCS project on a conv entional coal-fired power plant in Canada

. They are currently under construction and are expected to commence operation next year. In addition there are several other CCS projects in advanced stages of development in the U.S. (e.g., the Texas Clean Energy Project, the Hydrogen Energy California Project, an d the Future Gen project in Illinois) that may also provide addi tional information. In addition, research is underway to r educe CO 2 capture costs and to improve performance. The DOE/N ETL sponsors

253 Lignite Energy Council v. EPA , 198 F.3d 930, 934 (D.C. Cir. 1999). Based on this view that EPA may extrapo late from other industries, the Court in the Lignite Ene rgy Council v. EPA case upheld a control technology as being “adequately demonstrated” for coal-fired industrial boilers because the technology was utilized by utility boil ers. Deleted:

. Comment [A97]: Any citations to provide further support? EPA: We are still considering this comment.

Deleted: (

Deleted: )***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 247 of 373 an extensive research, development and demonstratio n program that is focused on developing advanced technology o ptions designed to dramatically lower the cost of capturing CO 2 from fossil-fuel energy plants compared to today’s avail able capture technologies. The DOE/NETL estimates that using tod ay’s available CCS technologies would add around 80 perc ent to the cost of electricity for a new pulverized coal plant , and around 35 percent to the cost of electricity for a new ad vanced gasification-based plant

. (Note that these cost increases would be significantly less for the partial capture stand ard being proposed in today’s notice

. ) The CCS research, development and demonstration program is aggressively pursuing effo rts to reduce these costs to a less than 30 percent increase in t he cost of electricity for PC power plants and a less than 10 percent increase in the cost of electricity for new gasific ation-based power plants. 254 The large-scale CO 2 capture demonstrations that are currently planned and in some cases underway, u nder the DOE’s initiatives, as well as other domestic and in ternational projects, will generate operational knowledge and enable continued commercialization and deployment of these technologies.

254 DOE/NETL Carbon Dioxide Capture and Storage RD&D R oadmap, U.S. Department of Energy National Energy Technolog y Laboratory, December 2010. Deleted: that will***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 248 of 373 Gas absorption processes using chemical solvents, s uch as amines, to separate CO 2 from other gases have been in use since the 1930s in the natural gas industry and to produc e food and chemical grade CO 2 . The advancement of amine-based solvents is an example of technology development that has improved the cost and performance of CO 2 capture. Most single component amine systems are not practical in a flue gas environment as the amine will rapidly degrade in the presence of oxygen and other

contaminants. The Fluor Econamine FG SM process uses a monoethanolamine (MEA) formulation specially design ed to recover

CO 2 and contains a corrosion inhibitor that allows the use of less expensive, conventional materials of construct ion. Other commercially available processes use sterically hin dered amine formulations (for example, the Mitsubishi Heavy Ind ustries KS-1 solvent) which are less susceptible to degradation and corrosion issues. The DOE/NETL and private industry are conti nuing to sponsor research on advanced solvents (including ne w classes of amines) to improve the CO 2 capture performance and reduce costs. Significant reductions in the cost of CO 2 capture would be consistent with overall experience with the cost of pollution control technology. A significant body of literatur e suggests that the per-unit cost of producing or using a give n technology declines as experience with that technology increas es over***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 249 of 373
time, 255 and this has certainly been the case with air poll ution control technologies. Reductions in the cost of air pollution control technologies as a result of learning-by-doi ng, reductions in financial premiums related to risk, r esearch and development investments, and other factors have bee n observed

over the decades. In addition, we note that the 2010 Interagency Task Force on CCS report recognized that CCS would not become more widely available without a regulatory framework that promo ted CCS or a strong price signal for CO 2 . Today’s action is an important component in developing that framework. G. Promotion of technology It is clear that identifying partial CCS as the BSE R promotes the utilization of CCS because any new fos sil fuelfired util i ty boiler or IGCC unit will need to install partial

255 These studies include John M. Dutton and Annie Tho mas, "Treating Progress Functions as a Managerial Opport unity," 2, 235-247; Dennis Epple, Linda Argote, and Rukmini De vadas, "Organizational Learning Curves: A Method for Inves tigating Intra-plant Transfer of Knowledge Acquired Through Learning by Doing," Organizational Science, Vol. 2, No. 1 ( February 1991 ) ; International Energy Agency, Experience Curves for Energy Technology Policy ( 2000 ) ; and Paul L. Joskow and Nancy L. Rose, "The Effects of Technological Change, Experience, a nd Environmental Regulation on the Construction Cost o f CoalBurning Generating Units," RAND Journal of Economic s, Vol. 16, Issue 1, 1-27 ( 1985 ) . See discussion in “The Benefits and Costs of the Clean Air Act from 1990 to 2020,” U.S. EPA, Office of Air and Radiation ( April 2011 )

. Comment [A98]: It would be helpful to cite relevant literature to support the statement.

EPA: See citation 255 below.

Deleted: ,

Deleted: ,

Deleted: ,

Deleted: ,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 250 of 373 capture CCS in order to meet the emission standard. Particularly because the technology is relatively new, additiona l utilization is expected to result in improvements in the perfor mance technology and in cost reductions. Moreover, identi fying partial capture CCS as the BSER will encourage continued re search and development efforts, such as those sponsored by the DOE/NETL. In contrast, not identifying partial CCS as the BSER c ould potentially impede further utilization and developm ent of CCS. It is important to promote deployment and further d evelopment of CCS technologies because they are the only technolo gies that are currently available or are expected to be available in the foreseeable future that can make meaningful reducti ons in CO 2 emissions from fossil fuel-fired utility boilers an d IGCC units. Identifying partial CCS as the BSER also promotes f urther use of EOR because, as a practical matter, we expec t that new fossil fuel-fired EGUs that install CCS will genera lly make the captured CO 2 available for use in EOR operations. The use of EO R lowers costs for production of domestic oil, which promotes the important goal of energy independence. H. Nationwide, longer-term perspective
As noted, the D.C. Circuit in Sierra Club held: The language of [the definition of “standard of performance” in] section 111 ... gives EPA authority when determining the best ... system to weigh cost, energy, and environmental impacts in the broadest***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 251 of 373 sense at the national and regional levels and over time as opposed to simply at the plant level in the immediate present. 256

Considering on “the national and regional levels an d over time” the criteria that go into determining the “be st system of emission reduction ... adequately demonstrated” also supports identifying partial CCS as that best system because doing so would not have adverse impacts on the power sector, national electricity prices, or the energy sector. 1. Structure of the power sector Identifying partial CCS as the BSER for new fossil fuelfired utility boilers and IGCC units is consistent with the current and projected future structure of the power sector. As noted, we project that in light of the current and projected trends in coal and natural gas costs, virtually all new electric generating capacity will employ NGCC technology or renewable energy, and very little new capacity will be coal-f ired. As noted above, the recent history of solid fossil fuelfired projects suggest that these new coal-fired bu ilds, if they occur, may (i) consist of an IGCC unit, includ ing features such as sale of additional byproducts (e.g., plants such as the Texas Clean Energy Project, which intends to manufacture fertilizer

256 Sierra Club v. Costle , 657 F.2d at 330. Deleted: e

Deleted: intents***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 252 of 373
products for sale and sell captured CO 2 for EOR in addition to selling electricity), use of lower cost opportunity fuels (such as petcoke proposed to be used at the Hydrogen Ener gy California facility) and/or rely on additional local regulator y drivers (such as California’s AB-32 program which incentivi zes lower CO 2 generating technologies), all of which would be des igned to offset enough of the additional coal-related costs to be able to compete with natural-gas fired electricity in the m arketplace; and (ii) be designed to offer fuel diversity to a group of customers that are willing to pay a premium in elec tricity prices (such as the Power4Georgians project in Wash ington County, Georgia). Projects in the first category would by definition already include at least partial CCS and, as a result, woul d be affected by this rule to only a limited extent. Projects in the second category would be more affected, but developers of these projects would nevertheless have several options. T hey could pursue coal with CCS and possibly rely on cost savi ngs from EOR or on their customers’ willingness to pay a higher premium. Alternatively, they could choose a different genera tion technology (most likely natural gas). Even if they chose a different generation technology, the small number o f these

sources and the fact that the basic demand for elec tricity would Deleted: those that are***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 253 of 373 still be met would limit the impact of this rule on the power

sector. 2. Impacts on nationwide electricity prices. Identifying partial CCS as the BSER for fossil fuel -fired utility boilers and IGCC units will not have signif icant impacts on nationwide electricity prices. The reason is tha t the additional costs of partial CCS will, on a nationwi de basis, be small because no more than a few new coal-fired pro jects are expected, and because, as noted, at least some of t hese can be expected to incorporate CCS technology in any event . It should be noted that the computerized model the EPA relies on to assess energy sector and nationwide impacts – the Integrat ed Planing Model (IPM) – does not forecast any new coal-fired EGUs through 2020. Based on these IPM analyses, the RIA for this rulemaking concludes that the proposed standard of 1,100 lb of CO 2 /MWh for new fossil fuel-fired EGUs, which is based on parti al CCS as the best demonstrated system, does not create any costs

. 3. Energy considerations Identifying partial CCS as the BSER for new fossil fuelfired utility boilers and IGCC units is consistent with nationwide energy considerations because it will no t have adverse effects on the structure of the power secto r, will promote fuel diversity over the long term, and will not have Comment [A99]: EPA may want to consider pointing out in this section that the availability of natural gas-fired plants to meet electricity genera tion needs at a reasonable cost also serves as a backsto p against any large economic/energy impacts. EPA: We are still considering this comment***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 254 of 373 adverse effects on the supply of electricity. Identifying partial CCS as the BSER will not have a dverse impacts on the structure of the power sector becaus e, as noted,

for reasons related to the cost differential betwee n natural gas-fired and coal-fired electricity, very little, if any, new coal-fired EGUs are projected to be built, and at l east some of those that may be built would be expected to includ e CCS technology in any event. In addition, identifying partial CCS as the BSER fo r coal will be beneficial to coal-fired electric generatio n, and therefore fuel diversity, over the long term. This is because identifying partial CCS as BSER eliminates uncertainty as to future control obligations for coal-fired capacity. Currently,

any new coal-fired source that constructs without CCS f aces the risk that future state or federal controls may requ ire carbon capture, which would require the source to retrofit to CCS, which, in turn, is a more expensive proposition. This risk is heightened because power plants have expected lives of 30 to 40

years and the likelihood of future carbon limitations can be expected to remain throughout that period. Any new coal-fired source that constructs with partial-capture CCS wil l achieve

some level of CO 2 emissions reductions, which lowers the risk of future liability , and may provide competitive advantages over Deleted: Identifying Deleted: I Deleted: Any

Deleted: particularly

Deleted: are generally long-lived

Deleted: risk

Deleted:

. Deleted: which***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 255 of 373 higher emitting sources. Because at present, new electric generating construction is primarily natural gas-fi red, benefiting new coal-fired capacity, at least over t he long term, protects fuel diversity. Moreover, even if requiring CCS adds sufficient cos ts to prevent a new coal-fired plants from constructing i n a particular part of the country due to lack of avail able EOR to defray the costs, or, in fact, from constructing at all, a new NGCC plant can be built to serve the electricity de mand that the coal-fired plant would otherwise serve. Thus, the p resent rulemaking does not prevent basic electricity deman d from being
met, and thus does not have an adverse effect on th e supply of electricity. As noted above, the EPA is authorized to promulgate standards of performance under CAA § 111 that may have the effect of precluding construction of sources in cer tain geographic locations or in certain locations.

4. Environmental considerations Identifying partial CCS as the BSER for coal-fired power plants protects the environment by preventing large amounts of

CO 2 emissions from new fossil fuel-fired utility boile rs and IGCC units. As noted, CCS is the only technology availab le at present or within the foreseeable future that provides mean ingful

reductions in the amount of CO 2 emissions in this sector.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 256 of 373

I . Deference As noted above, the D.C. Circuit has held that it w ill grant a high degree of deference to the EPA in dete rmining the appropriate standard of performance. Because determ ining the BSER for coal-fired power plants requires balancing several factors, including on a nationwide basis and over t ime, the EPA’s determination that partial CCS is the BSER sh ould be granted a high degree of deference.

J . CCS and BSER in locations where costs are too hig h to implement CCS
As noted above, under CAA § 111, an emissions standard may meet the requirements of a “standard of performance ” even if it cannot be met by every new source in the source cat egory that

would have constructed in the absence of that stand ard. As also noted above, the EPA’s analysis for this proposal i ndicates that coal-fired power plants that would otherwise constr uct in the absence of the standards in this proposal may still do so. However, we recognize that there may be some geogra phic locations where EOR is not practicably available, s o that in those locations, the higher costs of CCS may tilt t he economics against new coal-fired construction. Even in this c ase, the
standard would remain valid under CAA § 111, particularly Deleted: I . Consistency with purposes of CAA section 111 ¶ Identifying partial CCS as the BSER is also consistent with the purposes of CAA section 111, which, as discussed above, including includes avoiding giving any state a competitive advantage, reducingreduces emissions as much as possible, obviatingobviates any need for retrofits on new sources, and promotingpromotes technology development. 257 ¶ One purpose of CAA section 111 is that “[t]he standards [of performance] must not give a competitive advantage to one State over another in attracting industry.” 258 The 1,100 lb CO 2 /MWh standard that the EPA proposes in this rulemaking applies to all new coal-fired power plants in all geographic locations. As a result, there is nothing on the face of the standard that would provide a competitive advantage to one state over another in attracting industry. While it is true that some states may offer more attractive opportunities for CCS – because, for example, of greater availability or value for EOR – power plant siting by its nature generally favors certain locationsover others. For example, coalfired power plants usually require a large source of water, which favors certain locations over others. The fact that CCS adds another siting consideration does not mean that it unfairly benefits certain States at the expense of others, so far as the purposes of section 111 are concerned.¶ A second purpose of section 111 is “reducing emissions as much as practicable.” 259 For the reasons noted above, identifying partial CCS as the BSER meets this purpose.¶ A third purpose of section 111 is, “to the extent practical force the installation of all the control technology that will ever be necessary on new plants at the time of construction when it is cheaper to install, thereby minimizing the need for retrofit in the future....” 260 As noted above, identifying partial CCS as BSER meets this purpose by achieving CO 2 emissions reductions. In contrast, identifying highly efficient SCPC or IGCC without at least partial CCS as the BSER would leave sources vulnerable to retrofit obligations ... [4] Deleted: J Deleted: K***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 257 of 373 because the basic demand for electricity could stil l be served by NGCC, which this rulemaking determines to be the “best system” for natural gas-fired power plants.

K . Compliance period 1. 12-operating-month period Under today’s proposal, sources must meet the 1,100 lb

CO 2 /MWh limit on a 12-operating-month rolling basis. T his 12- operating-month period is important due the inheren t variability in power plant GHG emissions rates. Establishing a shorter averaging period would necessitate establishing a s tandard to

account for the conditions that result in the lowes t efficiency and therefore the highest GHG emissions rate. EGU efficiency has a significant impact on the sour ce’s GHG emission rate. By comparison, efficien c y has a smaller impact on the emissions rate for criteria or hazardous air po llutants (HAPs). This is because control of criteria polluta nts and HAPs often involves the use of a pollution control devic e that results in significant reductions, often greater 90 percent. In this situation, the performance of the specific pol lution control device impacts the emissions rate much more than the EGU efficiency. EGU efficiency can vary significantly from month to month throughout the year. For example, high ambient temp erature can Deleted: L

Deleted: In this situation, efficiency is a key factor in determining the emissions rate.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 258 of 373 negatively impact the efficiency of combustion turb ine engines and steam generating units. As a result, an averagi ng period shorter than 12 operating-months would require us t o set a

standard that could be achieved under these conditi ons. This standard could potentially be high enough that it w ould not be a meaningful constraint during other parts of the yea r. In addition, operation at low load conditions can also negatively impact efficiency. It is likely that for some short period of time an EGU will operate at an unusually low load. A short averaging period that accounts for this operation w ould again

not produce a meaningful constraint for typical loads. On the other hand, a 12-operating-month rolling ave rage explicitly accounts for variable operating conditio ns, allows consistent emissions rate averaging, allows for a m ore protective standard and decreased compliance burden , and simplifies compliance for state permitting authorit ies. Because the 12-operating-month rolling average can be calcu lated each month, this form of the standard makes it possible to assess compliance and take any needed corrective action on a monthly basis. The EPA proposes that it is not necessary to have a shorter averaging period for CO 2 from these sources because the effect of GHGs on climate change depends on global atmospheric concentrations which are dependent on cumulative to tal emissions Deleted: necessarily meaningfully constrain

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 259 of 373 over time, rather than hourly or daily emissions fl uctuations or local pollutant concentrations. Unlike for emission s of criteria and hazardous air pollutants, we do not believe tha t there are measureable implications to health or environmental impacts from short-term higher CO 2 emission rates as long as the 12-month average emissions rate is maintained. We solicit comment on, in the alternative, basing compliance requirements on an annual (calendar year ) average

basis. 2. 60-operating-month compliance period Under today’s proposal, new fossil fuel-fired boile rs and IGCC units will have the option to alternatively me et an emission standard on a 60-operating-month rolling b asis. The EPA has previously offered sources optional, lo ngerterm emission standards that are stricter than the primary

emissions standard in combination with a longer averaging period. We are proposing that this alternative emis sion limit

should be between 1,000 – 1,050 lb CO 2 /MWh and we are requesting

comment on what the final numerical standard should be (within that range) such that the 60-operating-month standa rd would be as stringent as or more stringent than the 12-opera ting-month

standard. Deleted: not

Deleted: compliance period

Deleted: exchange for the the Comment [A100]: “in exchange for” sounds like a negotiation.

Deleted: 950***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 260 of 373 We are also request comment on an appropriate 12-op eratingmonth standard that owners/operators electing to co mply with the 60-operating-month standard would have to comply wi th. This standard would be numerically between the alternate 12- operating-month standard and an emissions rate of a coal-fired EGU without CCS (e.g., 1,800 lb CO 2 /MWh). This shorter term standard would be more easily enforced and assure a dequate

emission reductions. This 60-operating-month period offers increased ope rational flexibility and will tend to compensate for short-term emission excursions, which may especially occur at the initial startup of the facility and the CCS system.

L . Geologic sequestration

1. Overview We expect that for the immediate future, virtually all of

the CO 2 captured at EGUs will be injected underground for longterm geologic sequestration at sites where enhanced oil recovery is also occurring. There is an existing regulatory framework for geologic sequestration and enhanced oil recovery ac tivities. We intend to rely upon this existing framework to veri fy that the

CO 2 captured from an affected unit is injected undergr ound for long-term containment. More specifically, as discu ssed in section 3, the EPA is proposing to build from the e xisting GHG Deleted: dampen

Deleted: be warranted

Deleted: M

Deleted: Greenhouse Gas***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 261 of 373 Reporting Program 40 CFR Part 98 to track that the captured CO 2 is geologically sequestered. In addition, we recognize that types of CO 2 storage technologies other than geologic sequestration are under development (e.g. precipitated calcium carbonate, e tc). EGUs may use other types of CO 2 storage technologies to meet the standard, once the EPA has approved its use, including method s for reporting, monitoring, and verifying long-term CO 2 storage. We welcome comments on an appropriate mechanism for ma king this

determination. 2. Existing regulatory framework for CCS As noted, the EPA expects that for the immediate fu ture, captured CO 2 from affected units will be injected underground f or geologic sequestration at sites where EOR is occurr ing. Underground injection is currently the only technol ogy available that can accommodate the large quantities of CO 2 captured at EGUs, and EOR provides an associated economic incen tive and

benefit. Three solid-fuel fired EGU projects incorporating CCS– Kemper, TCEP, and HECA – all include utilization of captured CO 2
for EOR. The EPA has promulgated, or recently proposed, seve ral rules to protect underground sources of drinking wa ter and track

the total amount of CO 2 that is supplied to the economy and Deleted: The three Deleted: t Deleted: that have progressed the furthest Comment [A101]: Consider whether this is necessary in the context of describing the existing regulatory framework EPA: Deleted per interagency comment on preamble copied here***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 262 of 373 injected underground for geologic sequestration. Fi rst, the EPA’s Underground Injection Control (UIC) Class VI rule, established under authority of the Safe Drinking Wa ter Act, sets requirements to ensure that geologic sequestration wells are appropriately sited, constructed, tested, monitored , and closed in a manner that ensures protection of underground sources of drinking water. 262 The UIC Class VI regulations contain monitoring requirements to protect underground sour ces of drinking water, including the development of a comp rehensive testing and monitoring plan. This includes testing of the mechanical integrity of the injection well, ground water monitoring, and tracking of the location of the inj ected CO 2 and the associated area of elevated pressure using both direct and indirect methods, as appropriate. Projects are also required to conduct extended post-injection monitoring and site care to track the location of the injected CO 2 and monitor subsurface pressures until it can be demonstrated that there i s no longer a risk of endangerment to underground sources of drin king water. UIC Class II wells inject fluids associated with oi l and natural gas production and the storage of liquid hy drocarbons. Most of the injected fluid is salt water, which is brought to

262 http://water.epa.gov/type/groundwater/uic/wells_seq uestration.cf
m***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 263 of 373 the surface in the process of producing (extracting ) oil and gas and subsequently re-injected. In addition, other fl uids, including CO 2 , are injected to enhance oil and gas production. Class II regulations include site characterization, well construction, operating, monitoring, testing, repor ting, financial responsibility, and closure requirements to prevent endangerment of underground sources of drinking wat er. Wells that inject CO 2 underground for enhanced oil or gas recovery may be permitted as UIC Class II or Class VI wells. How ever, the designation of the appropriate well class depends, principally, on the risks posed or changes in the risks posed to underground sources of drinking water by a specific injection o peration.
Second, the GHG Reporting Program covers sources that generate electricity (40 CFR Part 98 subpart D), so urces that supply CO 2 to the economy (40 CFR Part 98, subpart PP) and sources that inject CO 2 underground for geologic sequestration (40 CFR Part 98, subpart RR). Subpart D owners or o perators of facilities that contain electricity-generating unit s must report emissions from electricity-generating units and all other source categories located at the facility for which method s are defined

in Part 98. 263 Owners or operators are required to collect

emission data; calculate GHG emissions; and follow the specified

263 http://www.epa.gov/ghgreporting/reporters/subpart/ d.html Deleted: Greenhouse Gas Deleted: (GHGRP)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 264 of 373 procedures for quality assurance, missing data, rec ordkeeping, and reporting. Subpart PP provides requirements for quantifying CO 2 supplied to the economy. 264 Affected units that capture CO 2 to inject underground or supply offsite, are subject t o all of the requirements under Subpart PP of the GHG Reporting Program, which relates to suppliers of CO 2 . Specifically, Subpart PP requires suppliers of CO 2 that meet certain applicability requirements to report the mass of CO 2 captured from production process unit(s) for the purposes of supplying CO 2 for commercial applications or that capture and maintain custody o f a CO 2 stream in order to sequester or otherwise inject undergrou nd. CO 2 suppliers are required to report the annual quantit y of CO 2
transferred offsite and for what end use, including geologic sequestration. Subpart RR requires that facilities meeting the sou rce category definition (40 CFR 98.440) for any well or group of wells to report basic information on the amount of CO 2 received for injection; develop and implement an EPA-approve d monitoring, reporting, and verification (MRV) plan; and report the amount of

CO 2 sequestered using a mass balance approach and annu al monitoring activities. The MRV plan must be submitt ed and

264 http://www.epa.gov/ghgreporting/reporters/subpart/ pp.html Deleted: CO 2 transferred***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 265 of 373 approved by the EPA and revised if necessary over t ime according to 40 CFR 98.448(d). The subpart RR MRV plan must i nclude five major components:

• A delineation of the maximum monitoring area (MMA) and the active monitoring area (AMA).

• An identification and evaluation of the potential s urface leakage pathways and an assessment of the likelihoo d, magnitude, and timing, of surface leakage of CO 2 through these pathways in the MMA.

• A strategy for detecting and quantifying any surfac e leakage of CO 2 in the event leakage occurs.

• An approach for establishing the expected baselines for monitoring CO 2 surface leakage.

• A summary of considerations made to calculate site- specific variables for the mass balance equation. More information on the MRV plan is available in th e Technical Support Document for the subpart RR final rule (75 FR
75065). If an enhanced oil and gas recovery project holds a UIC Class VI permit, it is required to report under sub part RR. If the project holds a UIC Class II permit and is inje cting a CO 2 stream underground, it is not subject to subpart RR , but the owner or operator may choose to opt-in to subpart R R. Sources Deleted: (TSD)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 266 of 373 reporting under subpart RR, whether they are UIC Cl ass VI or Class II well(s), must follow the same set of requi rements. As stated in the preamble to the final subpart RR r ule: “while requirements under the UIC program are focus ed on demonstrating that USDWs are not endangered as a result of CO 2 injection into the subsurface, requirements under the GHG Reporting Program throug h 40 CFR part 98, subpart RR will enable EPA to verif y the quantity of CO 2 that is geologically sequestered and to assess the efficacy of GS as a mitigation strategy. Subpart RR achieves this by requiring facilities conducting GS to develop and implement a MRV plan to detect and quantify leakage of injected CO 2 to the surface in the event leakage occurs and to report the amount of CO 2 geologically sequestered using a mass balance approach, regardless of the class of UIC permit that a facility holds.” (75 FR 75060)

The Internal Revenue Service relies on subpart RR compliance to verify geologic sequestration for the 45Q tax credit. As stated in the preamble to the final subp art RR

rule:

“EPA notes that the Internal Revenue Service (IRS) published IRS Notice 2009–83 7 to provide guidance regarding eligibility for the Internal Revenue Code section 45Q credit for CO 2 sequestration, computation of the section 45Q tax credit, reportin g requirements for taxpayers claiming the section 45Q tax credit, and rules regarding adequate security measures for secure GS. As clarified in the IRS guidance, taxpayers claiming the section 45Q tax credit must follow the appropriate UIC requirements

. The guidance also clarifies that taxpayers claiming section 45Q tax credit must follow the MRV procedur es that are being finalized under 40 CFR part 98, subp art RR in this final rule.” (75 FR 75060)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 267 of 373 Third, the EPA proposed a rule that would condition ally

exclude CO 2 streams from the definition of hazardous waste und er RCRA, where these streams are being injected for pu rposes of geologic sequestration, into a UIC Class VI well an d meet other

conditions. 265 The rationale for the rule was that any CO 2 stream that would otherwise be defined as hazardous waste, need not be managed as hazardous waste, provided it is managed under other regulatory programs that address the potential risk s to human health and the environment that these materials may pose. 3. Proposal a. Geologic Sequestration To provide certainty and verify that CO 2 captured at an affected unit is geologically sequestered, today’s action relies upon the existing regulatory framework the EPA alre ady has in place under the GHG Reporting Program 40 CFR Part 9 8. As discussed in the previous section, there are key su bparts (i.e., subpart D, PP and RR) under 40 CFR Part 98 that pro vide a transparent reporting and verification mechanism fo r EPA and the public. The EPA requires electric generating units to report CO 2 emissions under subpart D. Facilities that capture CO 2 are required to report quantities of CO 2 captured and injected on site or transferred off-site under subpart PP. Fac ilities that

265 76 Fed. Reg. 48073 (Aug. 8, 2011) Comment [LRB102]: Since this language refers to our proposal, we moved it out of th e “existing regulatory frameworks” section into the Proposal section.

Deleted: The EPA notes that compliance with the standard of 1,100 lb CO 2 /MWh is determined exclusively by the tons of CO 2 captured by the emitting EGU. The tons of CO 2 sequestered by the repository are not part of that calculation. However, to verify the amount of tons of CO 2 captured at the emitting EGU are safely and effectively sequestered, we are building on existing regulatory requirements under Subpart RR, all CO 2 that is geologically sequestered at the site of the EGU facility must be reported under subpart RR by the owner or operator of the EGU. Additionally, where the captured CO 2 is sent offsite, it must be transferred to an entity that is reporting under Subpart RR. ¶ This provides assurance that the tons of CO 2 captured are transferred to a repository which provides assurance of long term containment integrity. Under today’s proposal, that type of repository is a Class II or Class VI UIC well which would report its GHG emissions under subpart RR. ¶ The EPA acknowledges that there can be downstream losses of CO 2 after capture. The EPA expects these losses to be modest with incentives due to the market use of CO 2 as a purchased product. There remains an issue of whether the standard itself should be adjusted to reflect these downstream losses. ... [5] Comment [A103]: How will this requirement be enforced? Is the requirement for CO2 to be reporte d under the GHG reporting program an explicit part of the “standard of performance” and therefore enforceable like any other part of the standard? Comment [A104]: At what points can downstream losses occur? Are there multiple? Also, are there any lossess associated with onsite storage?

Comment [CCD105]: Revised intro based on interagency comment. Comment [LRB106]: Text, and similarly confusing language in this section deleted or revis ed to reflect that the only requirement is that the fa cility report under subpart PP and RR (per Interagency comments on preamble copied here: “Is this potentially overstating the extent of the requirements, given that long term sequestration is not actually part of what’s “required” (just sendin g the CO2 to a facility that reports)?”)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 268 of 373 inject CO 2 underground for geologic sequestration report unde r subpart RR.

. First , the EPA is proposing that any affected unit that employs CCS technology which captures enough CO 2 to meet the 1,100 lb/MWh standard must report, under 40 CFR Par t 98 subpart RR, if the captured CO 2 is injected onsite. If the captured CO 2 is sent offsite, then the facility injecting the CO 2 underground must report under 40 CFR Part 98 subpart RR. As no ted above, owners and operators of projects that inject CO 2 underground and that are permitted under a UIC Class VI permit are required to comply with subpart RR. The practical impact of our proposal would be that owners and operators of projects inje cting CO 2 underground that are permitted under UIC Class II a nd that

receive CO 2 captured from EGUs to meet the proposed performanc e standard will also be required to submit and receiv e approval of a subpart RR MRV plan and report under subpart RR. This proposal does not change any of the requirements to obtain o r comply with a UIC permit for facilities that are subject to EPA ’s UIC program under the Safe Drinking Water Act.

In order to use the GHG Reporting Program to ensure that the affected unit is sending their captured CO 2 to a site reporting under subpart RR, the EPA proposes minor modifications Comment [LRB107]: Deleted per interagency comments on another section of the preamble copied here: “As noted above, this seems to imply that the amount of CO2 sequestered is part of the performance standard, but that doesn’t seem to be consistent with what is explained elsewhere in this section.” AND Is this potentially overstating the extent of the requirements, given that long term sequestration is not actually part of what’s “required” (just sendin g the CO2 to a facility that reports)? Comment [LRB108]: This text was moved from later in this section as it provides a good overvie w and background.

Deleted: Together, the framework just described help create a consistent national framework to ensure the safe and effective deployment of geologic sequestration technologies. Importantly, a key component of this framework- theGreenhouse Gas Reporting Programprovides a mechanism for new generating units that supply captured CO 2 for geologic sequestration (including CO 2 ... [6] Comment [A109]: ?? suggest omitting. Consider rephrasing sentence: The NSPS proposal builds on and is consistent with existing framework for safe and effective GS. Comment [A110]: Is this potentially overstating the extent of the requirements, given that long ter m sequestration is not actually part of what’s “required” (just sending the CO2 to a facility that reports)?

Deleted: Therefore Deleted: Subpart Deleted: Regardless of the injection site, the affected source must still comply with 40 CFR Part 98 Subpart PP. Deleted: Comment [MK111]: We have not introduced UU elsewhere so deleted. Comment [MK112]: Added per interagency comment on ‘Geologic Sequestration’ (page 12-13 of comment response document.). Deleted: Many of these EOR facilities are already familiar with reporting under Subpart UU of the Greenhouse Gas Reporting Program. Comment [LRB113]: Moved to introduction of this section. Deleted: To provide certainty and verify that CO 2 captured at an affected unit is geologically sequestered, today’s action relies ... [7]***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 269 of 373
to subpart PP, CO 2 supply. We propose that a facility capturing

CO 2 from an affected unit, and therefore subject to 40 CFR Part 98 subpart PP, must provide additional information in their subpart PP annual report including 1) the electroni c GHG Reporting Tool identification (e-GGRT ID) of the fa cility with the electric generating unit from which CO 2 was captured, 2) the
e-GGRT ID(s) for, and mass of CO 2 transferred to, each geologic sequestration site reporting under subpart RR. This proposed

amendment to the GHG Reporting Program provides a transparent

and consistent method to track CO 2 capture and sequestration without significantly increasing burden on the affe cted sources.

If the affected unit does not report under 40 CFR Part 98 subpart PP and comply with these proposed requirements, it will be considered in noncompliance with today’s proposa l. The EPA notes that compliance with the standard of 1,100 lb

CO 2 /MWh is determined exclusively by the tons of CO 2 captured by the emitting EGU. The tons of CO 2 sequestered by the geologic sequestration site are not part of that calculation . However, to verify that the CO 2 captured at the emitting EGU is sent to a geologic sequestration site, we are building on exi sting regulatory requirements under the GHG Reporting pro gram. The EPA acknowledges that there can be downstream l osses of

CO 2 after capture, for example during transportation, injection Comment [LRB114]: Edited per interagency comments on another section of the preamble copied here: “As noted above, this seems to imply that the amount of CO2 sequestered is part of the performance standard, but that doesn’t seem to be consistent with what is explained elsewhere in this section.” AND Is this potentially overstating the extent of the requirements, given that long term sequestration is not actually part of what’s “required” (just sendin g the CO2 to a facility that reports)?

Deleted: In order to use the GHGRP for compliance tracking, the EPA proposes that any affected unit that uses CCS to comply with the emissions limit must demonstrate that CO 2 is geologically sequestered through the Greenhouse Gas Reporting Program. In order to do that, we are proposing Comment [A115]: This seems somewhat unclear. Must the affected unit demonstrate sequestration or just that it goes to a facility th at reports under the GHG reporting program? This seems to imply the former, but doesn’t seem consistent with the explanation above.

Deleted: Greenhouse Gas Deleted: Greenhouse Gas Comment [LRB116]: Revised per interagency comment on preamble copied here: “As noted above, this seems to imply that the amount of CO2 sequestered is part of the performance standard, but that doesn’t seem to be consistent with what is explained elsewhere in this section”.

Deleted: geologic sequestration used to meet the performance standard Comment [A117]: As noted above, this seems to imply that the amount of CO2 sequestered is part of the performance standard, but that doesn’t seem to be consistent with what is explained elsewhere in this section.

Comment [LRB118]: Edited to reflect that the GHG Reporting program, including subpart RR, is reporting only, and are not control requirements. Subpart RR does not ensure that all the CO2 captured is permanently stored, however it will allow EPA to track how much of the CO2 injected at the site IS stored.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 270 of 373

or storage. Though a well selected and operated site is expecte d

to contain CO 2 for the long-term, there is the potential for unanticipated leakage. The EPA expects these losses to be modest

with incentives due to the market use of CO 2 as a purchased product. There remains an issue of whether the stan dard itself should be adjusted to reflect these downstream loss es. The EPA is not proposing to do so. Moreover, the EPA wishes to encourage rather than discourage EOR using captured CO 2 since the practice makes CCS itself more economic and thus promotes us e of the technology on which the proposed standard is based. See Sierra
Club v. Costle, 657 F. 2d at 347 (one purpose of se ction 111 standards is to promote expanded use and developmen t of technology). We also emphasize that today’s proposal does not in volve regulation of any downstream recipients of captured CO 2 . That is, the regulatory standard applies exclusively to the emitting EGU, not to any downstream user or recipient of the capt ured CO 2 (whether the captured CO 2 is sold for EOR or otherwise sequestered underground). The requirement that the emitting EGU assure that captured CO 2 is managed at an entity subject to the GHG reporting rules is thus exclusively an element of enforcement of the EGU standard. Similarly, the ex isting regulatory requirements applicable to geologic sequ estration are Comment [LRB119]: Added per interagency comment on preamble copied here: “At what points can downstream losses occur? Are there multiple? Also, are there any losses associat ed with onsite storage? “***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 271 of 373 not part of the proposed NSPS. The standard is a n umeric value, applicable exclusively to the emitting EGU. The approach proposed today relies on the existing GHG Reporting framework to ensure that CO 2 captured at an affected unit is transferred to a facility reporting geologi c sequestration, and it does not impose any additiona l requirements for an affected unit to demonstrate ho w the captured CO 2 is transferred to a facility that is compliant wit h 40 CFR 98 subpart RR. We seek comment on whether t here should be such requirements and suggestions for what those might

include. b. Alternatives to geologic sequestration In the development of this proposal, the EPA has id entified some potential alternatives to geologic sequestrati on, including

but not limited to CO 2 stored in precipitated calcium carbonate and certain types of cement. The EPA solicits comme nt on whether these and other alternatives to geologic sequestrat ion permanently store CO 2 (so that the stack standard is assured of achieving its object—to capture CO 2 and prevent its atmospheric release) and if they are technically available for EGUs to meet the performance standard. Consideration of how the se alternatives could meet the performance standard in volves understanding the ultimate fate of the captured CO 2 and the Comment [LRB120]: Deleted bc the GHG Reporting program, including subpart RR, is reporting only, and are not control requirements. Subpart RR does not ensure that all the CO2 captured is permanently stored, however it will allow EPA to track how much of the CO2 injected at the site IS stored. Deleted: Greenhouse Gas

Comment [A121]: Has EPA demonstrated that GS meets this standard? EPA: We are still considering this comment***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 272 of 373 degree to which the method permanently isolates the CO 2 from the atmosphere, as well as existing methodologies to ve rify this permanent storage. The EPA proposes that alternativ es to geologic sequestration could not be used until the EPA finalizes a mechanism to demonstrate that a non-CCS technolog y would result in permanent storage of CO 2 . The EPA believes that the number of cases where an EGU would seek to comply w ith the performance standard through an alternative to CCS will be very few. However, the EPA wishes to encourage developme nt of alternatives to geologic sequestration that could h elp offset

the cost of CO 2 capture.

c. Drafting PSD permits for affected sources using geo logic sequestration In most cases, sources that are subject to this NSP S will also be a major source or major modification under PSD and required to obtain a PSD permit prior to commencing construction. A permit is the legal tool used to es tablish all the source limitations deemed necessary by the revi ewing agency during review of the permit application, and is the primary basis for enforcement of PSD requirements. A well w ritten permit reflects the outcome of the permit review pr ocess and clearly defines what is expected of the source. The permit
must be a "stand-alone" document that: (1) identifi es the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 273 of 373 emissions units to be regulated; (2) establishes em issions standards or other operational limits to be met; (3 ) specifies methods for determining compliance and/or excess em issions, including reporting and recordkeeping requirements; and (4) outlines the procedures necessary to maintain c ontinuous compliance with the emission limits.

One of the criteria that must be met to obtain a PS D permit is that the owner or operator of the facility must demonstrate that emissions from construction or operation of th e facility will not cause or contribute to air pollution in ex cess of “any other applicable emissions standard or standard of performance under this chapter.” 42 U.S.C. 7475(a)(3)(C); see a lso 42 U.S.C. 7410(j). Accordingly, PSD permits for EGU sources t hat are subject to this NSPS will need to reflect that, at a minimum, the source will meet the requirements of this NSPS. Compliance

with the NSPS emissions standard is determined excl usively by evaluating emissions of CO 2 at the EGU. 266
As noted in the "Implications for PSD and Title V p rograms" section of this preamble, some states have authorit y to issue

266 We note that the PSD program regulates CO 2 as part of the “Greenhouse Gas” pollutant, which includes the aggr egate group of the following gases: CO 2 , methane (CH 4 ), nitrous oxide (N 2 0), sulfur hexafluoride (SF 6 ), hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs). Deleted: As noted in the "Implications for PSD and Title V programs" section of this preamble, some states have authority to issue PSD permits. In other cases, the EPA issues the permit. States with approved permitting programs have some discretion in making permit decisions and including the necessary conditions of the permit to ensure the enforceability of the permit. Comment [A122]: I think this needs something more to show how this relates to PSD requirements and how you can justify putting such requirements i n a PSD permit. EPA: The language has been edited.

Deleted: To this end, section 60.5520 of this proposed rule, titled “What CO 2 emissions standard must I meet?”, reads: ¶ For each affected EGU subject to this subpart, you must not discharge from the EGU into the atmosphere any gases that contain CO 2 in excess of the applicable CO 2 emissions standard specified in Table 1 to this subpart. Each CO 2 emissions standard has a minimum of two significant digits.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 274 of 373 PSD permits. In other cases, the EPA issues the per mit. States with EPA-approved permitting programs have some dis cretion in making permit decisions and including the necessary conditions in the permit to ensure the enforceability of the requirements. Additionally, some states may have ad ditional state-specific requirements (e.g., a renewal portfo lio standard adopted by a state) that may affect the stringency of the emission limits for the permits issued in their sta tes. Thus, permits for similar source types may vary from stat e to state depending on the permitting program of the state, a nd the casespecific PSD evaluation of the source under review. However, the permits for similar sources should generally contai n the same

basic information. Thus, while EPA recognizes that permit conditions m ay vary from state to state, t he EPA believes it is important to clarify the key components that should be included in a PSD permit for sources subject to the NSPS, as proposed here, and that intend to comply with the standard using geolo gic storage

.
W e believe the following general condition areas of a permit would adequately show that the source will not cause or contribute to air pollution in excess of this NSPS:

• A BACT emissions limit that applies to the EGU (or EGUs) at the facility that does not exceed either the primary NSPS Deleted: T

Deleted: While we recognize that permit conditions may vary from state to state, w

Deleted: is complying with Deleted: . The permit should include Deleted: Whether the permittee is complying with***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 275 of 373
emission standard ( i.e., as proposed, 1,100 lb CO 2 /MWh on a 12-operating-month rolling average) or the alternat ive compliance option ( i.e., as proposed, between 950 and 1,050

lb CO 2 /MWh on a 60-operating-month rolling average).

•

• Procedures for how the EGU will demonstrate complia nce with

the permitted emission s limit, which, at a minimum, meet the monitoring and recordkeeping requirements defin ed in §

60.5355.

• A requirement that CO 2 produced by the EGU (or EGUs) is reported under Subpart PP by the permittee

.

• A requirement that all CO 2 that is geologically sequestered at the site of the EGU facility is reported under s ubpart RR by the permittee

.

• A requirement that the captured CO 2 that the permittee sends offsite is transferred to an entity that is subject to the requirements of Subpart RR. We specifically request comment on this basic frame work for PSD permits that are issued for affected EGU source s that use geologic sequestration.

VIII. Rationale for Emission Standards for Natural Gas-fired Stationary Combustion Turbines A. Best system of emission reduction Deleted: The BACT emission limit that applies to the EGU (or EGUs) at the facility and that does not exceed the selected primary or alternative compliance option. Deleted: based on

Deleted: owner or operator of the EGU

Deleted: owner or operator of the EGU Deleted: sent***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 276 of 373

The EPA evaluated several different control technol ogy configurations as potentially representing the “bes t system of emissions reductions ... adequately demonstrated” (BS ER) for new natural gas-fired stationary combustion turbines: (i) the use of full or partial capture CCS and several types of ef ficient generation without any CCS , (ii) including high efficiency simple cycle aeroderivative turbines and (iii) natural gas combined cycle (NGCC) technology. We do not conside r full or partial capture CCS to be BSER because of uncertain ties about technical feasibility and because of adverse impact on electricity prices and the structure of the electri c power sector. In addition, we do not consider simple cycl e turbines to be BSER because they have a higher emission rate an d a higher cost than NGCC technology. We do find NGCC technolo gy to be the BSER because it is technically feasible and relativ ely inexpensive, its emission profile is acceptably low , and it would not adversely affect the structure of the ele ctric power

sector. We note at the outset that currently, virtually all new sources in this category are using natural gas comb ined cycle (NGCC) technology. That technology is considered to be the state of the art for this source category. Because, in th is rulemaking, we are considering, and selecting, NGCC as the BSER Comment [A123]: Is this technical feasibility or general feasibility (because of cost) EPA: We have added additional language to further clarify this.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 277 of 373 for this category, as a matter of terminology, to a void confusion, we generally refer to the sources as nat ural gasfired combustion turbines, and not as NGCC sources. 1. Full and partial CCS To determine the BSER for natural-gas-fired station ary source combustion turbines, we evaluated full and p artial CCS against the criteria. We propose to reject CCS tech nology as the

BSER because we cannot conclude that it meets sever al of the key

criteria.
First, it is not clear that full or partial capture CCS is technically feasible for this source category. Unli ke subpart Da affected facilities, where there are full-scale pla nts with CCS that are currently under construction or in advance d stages of development, the EPA is aware of only one demonstra tion project, which is an approximately 40 MW slip stream install ation on a 320 MW NGCC unit. Importantly, there are some signi ficant differences between natural gas-fired combustion tu rbines and

solid fossil fuel-fired EGUs that lead us to this c onclusion.
First, while some of these turbines are used to ser ve base load power demand, many cycle their operation much more frequently than coal-fired power plants. It is unclear how par t-load operation and frequent startup and shutdown events would impact the efficiency and reliability of CCS. We are not a ware that any Deleted: we are uncertain as to whether Deleted:

Deleted: several

Comment [A124]: The fact that there is a facility in demo phase seems to indicate that it IS technica lly feasible. However, it may not be economical or otherwise necessary in the regulatory context to pursue such an approach. In any case, this sentenc e does not support the topic sentence of this paragra ph. EPA: We have provided additional language on this topic. Deleted: baseload***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 278 of 373 of the pilot-scale projects have operate d in that mode. None of the larger projects being constructed, or under dev elopment, are designed to operate in a cycling mode. Furthermore, the CO 2 concentration in the flue gas of a natural gas combustion

turbine is much lower (usually approximately 4 volume perc ent)

than the CO 2 concentration in the flue gas stream of a typical coal-fired plant (which is approximately 16 volume percent for a SCPC or CFB unit) or the syngas of an IGCC unit ( in which CO 2 can be as high as 60 volume percent ), so the overall amount that can be captured for each project is likely lower. Additional factors that make CCS more challenging f or NGCC compared to coal-fired EGUs include the time it wou ld take to complete the CCS project and the water use requirem ents. Requiring CCS at a NGCC facility would potentially delay the project more than at a coal-fired EGU. NGCC facilit ies can be constructed in about half the time required to cons truct a coalfired EGU. Therefore, the time necessary to constru ct the carbon capture equipment and any associated pipelines to t ransport the

CO 2 would have a relatively larger impact on an NGCC t han a coalfired EGU. NGCC have relatively low cooling require ments for the steam condensing cooling cycle compared to coal-fir ed EGUs and often use dry cooling technology. The imposition of CCS would Deleted: the pilot-scale projects Comment [A125]: You mean the one demo project, the 40 MW slip stream? Rephrase to note one project, if so . If there are indeed multiple pilot projects, then t his would support that it is technically feasible. EPA: Any pilot projects ... even non-NGCC ones that may provide insight into the effects of freque nt cycling and startup/shutdown operation.

Deleted: type of Deleted: NGCC

Deleted: where it

Deleted: ).

Comment [A126]: Need a conclusion here.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 279 of 373 have a larger impact on water requirements for an N GCC facility compared to a coal-fired EGU. Moreover, identifying partial or full CCS as the BS ER for new stationary combustion turbines would have signi ficant adverse effects on national electricity prices, ele ctricity supply, and the structure of the power sector. Beca use virtually all new fossil fuel-fired power is projected to use NGCC technology, requiring CCS would add significant cos ts to electricity generation across the nation and the number of projects would make it difficult to implement in th e short term

. In addition, requiring CCS could lead some operator s and developers to forego retiring older coal-fired plan ts and replacing them with new NGCC projects, and instead keep the older plants on line longer. Identifying CCS and BS ER for combustion turbines would likely result in higher n ationwide electricity prices and could adversely affect the s upply of electricity, since virtually all new fossil fuel-fi red power is projected to use NGCC technology. We recognize that identifying full or partial CCS a s the BSER for this source category would result in signi ficant emissions reductions, but at present, we already co nsider natural gas to be a low-GHG-emitting fuel and NGCC to be a lowemitting technology. Although identifying CCS as th e BSER would Comment [A127]: Cites? Referencces? EPA: We are still considering this comment

Comment [A128]: And this would have environmental impacts, also.

Deleted: would***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 280 of 373 promote the development and implementation of emiss ion control technology, for the reasons described, the EPA does not believe that CCS represents BSER for natural gas combustion turbines at

this time. 2. Energy efficient generation technology
To determine the BSER, the EPA also evaluated the u se of energy efficient generation technology, including h igh efficiency simple cycle aeroderivative turbines. The use of high efficiency simple cycle aeroderivat ive turbines does not provide emission reductions from the current state-of-the-art technology, is more expensive than the current state-of-the-art technology , and does not develop emission control technology. For these reasons, we do not co nsider it BSER. According to the AEO 2013 emissions rate info rmation, this type of source has a CO 2 emissions rate of 1,150 lb CO 2 /MWh, which is higher than the emission rates of 830 and 760 lb CO 2 /MWh

for the conventional and advanced NGCC model facili ties, respectively. In the April 2012 proposal, we identified NGCC as t he BSER for this source category, and proposed a standard o f 1,000
lb/MWh. We stated:

[A] NGCC facility is the best system of emission reduction for new base load and intermediate load EGUs. To establish an appropriate, natural gas-bas ed standard, we reviewed the emissions rate of natural Deleted: – and, in fact

Deleted: – nor Deleted: it

Deleted: baseload***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 281 of 373 gas-fired (non-CHP) combined cycle facilities used in the power sector that commenced operation between 2 006 and 2010 and that report complete generation data t o EPA. Based on this analysis, nearly 95% of these facilities meet the proposed standards on an annual basis. These units represent a wide range of geographic locations (with different elevations and ambient temperatures), operational characteristics, and sizes. 267

The same information supports our current proposal. As described above, NGCC has a lower cost of electrici ty than simple cycle turbines at intermediate and high capa city factors. In addition, NGCC has an emissions rate that is app roximately 25 percent lower than the most efficient simple cycle facilities. Therefore, the use of a heat recovery steam generat or in combination with a steam turbine to generate additi onal electricity is a cost effective control for interme diate and high capacity factor stationary combustion turbines . Therefore, BSER for intermediate and high capacity factor stat ionary combustion turbines is the use of modern high effic iency NGCC
technology. B. Determination of the standards of performance Multiple commenters on the April 2012 proposal stat ed the proposed standard of 1,000 lb CO 2 /MWh for combined cycle facilities in the April 2012 proposal was too strin gent and

267 77 Fed. Reg. at 22,414/1. Comment [A129]: This section would benefit from more explanation for why smaller NGCC units meet a particular need. Is it geographic specific? Is there a possibility that multiple new smaller units would be built instead of one larger unit? EPA: See the EPA’s response to interagency comments.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 282 of 373
should be increased to a minimum of 1,100 lb CO 2 /MWh. Commenters explained that the increased use of renewable energ y for electricity generation will require combined cycle facilities to
startup, shutdown, cycle, and operate at part-load more frequently than they currently do, and that this mo re cyclical operation necessarily entails a higher emission rat e. The

commenters stated that the recent historical emissi ons data that the EPA relied on for the original proposal does no t account for these likely operational changes. Additional reason s given justifying a higher standard include the deteriorat ion of efficiencies over time, the need for flexibility to use distillate oil as a backup fuel, the operation of c ombined cycle facilities in simple cycle mode, the fact that combined cycle facilities located at high elevations and/or in loc ations with high ambient temperatures are less efficient, and the fact that smaller combined cycle facilities are inherently le ss efficient than larger facilities. On the other hand, other co mmenters
stated that the final standard should be lower than proposed on grounds that the best performing facilities are ope rating below the original proposed standard. Multiple commenters also stated

that the EPA should evaluate additional CEMS data t o determine the appropriate standard.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 283 of 373 In light of these comments, we have reviewed the CO 2 emissions data from 2007 to 2011 for natural gas-fi red (non-CHP) combined cycle units that commenced operation on or after January 1, 2000 and that reported complete electric generation data, including output from the steam turbine, to t he EPA. A more detailed description of this emissions data an alysis is included in a technical support document in the doc ket for this rulemaking. These 307 NGCC units are diverse in loc ation, age, capacity, and operating profile. Based on these dat a, we propose to subcategorize the turbines into the same two siz e-related subcategories currently in subpart KKKK for standar ds of performance for the combustion turbine criteria pol lutants. These subcategories are based whether the design he at input rate to the turbine engine is either less than or equal to 850 MMBtu/h or greater than 850 MMBtu/h. We further pro pose to establish different standards of performance for th ese two subcategories. This subcategorization has a basis in differences i n several types of equipment used in the differently sized units, which affect the efficiency of the units. Large-siz e combustion turbines use industrial frame type combustion turbi nes and may use multiple pressure or steam reheat turbines in t he heat recovery steam generator (HRSG) portion of a combin ed cycle***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 284 of 373 facility. Multiple pressure HRSGs employ two or thr ee steam drums that produce steam at multiple pressures. The availability of multiple pressure steam allows the use of a more efficient multiple pressure steam turbine, compared to a sing le pressure

steam turbine. A steam reheat turbine is used to im prove the overall efficiency of the generation of electricity . In a steam reheat turbine, steam is withdrawn after the high p ressure
section of the turbine and returned to the boiler f or additional heating. The superheated steam is then returned to the intermediate section of the turbine, where it is fu rther expanded to create electricity. Although HRSGs with steam reheat turbines are more expensive and complex than HRSGs without them, steam reheat turbines offer significant reductions in CO 2 emission rates. In contrast, small-size combustion turbines frequently use aeroderivative turbine engines inste ad of industrial frame design turbines. While there is no t a strict
definition for an aeroderivative turbine, at least parts of

aeroderivative turbines are derived from aircraft e ngines.

Aeroderivative and frame turbines use different com bustor designs, lubrication oil systems, and bearing desig ns. While aeroderivative turbines are typically more expensiv e than industrial frame turbines, they are generally more compact, lighter, are able to start up and shut down more qu ickly, and***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 285 of 373 handle rapid load changes more easily than industri al frame turbines. Due to their higher simple cycle efficien cies, they have traditionally been used more for peak and inte rmittent purposes rather than base power generation. However , combined cycle facilities based on aeroderivative combustion turbines are available. Due to the higher efficiency of the simp le cycle portion of an aeroderivative turbine based combined cycle facility , the HRSG portion would contribute relatively less to the overall efficiency than a HRSG in a frame turbi ne based combined cycle facility . Therefore, adding a multiple steam pressure and/or a reheat steam turbine to the HRSG would be relatively more expensive to an aeroderivative turb ine based combined cycle facility compared to a frame based combined cycle facility . Consequently, multiple pressure steam and reheat steam turbine HRSG are not widely available for aeroderiv ative turbine based combined cycle facilities. In addition, since aeroderivative turbine engines have faster start ti mes and change load more quickly than frame turbines, aerod erivative turbine based combined cycle facilities are more likely to run at part load conditions and to potentially bypass t he HRSG and run in simple cycle mode for short periods of time than industrial frame turbine based combined cycle facil ities. Deleted: compared to

Deleted: s***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 286 of 373 Because of these differences in equipment and inher ent efficiencies of scale, the smaller capacity NGCC un its (850 MMBtu/h and smaller) available on the market today are less efficient than the larger units (larger than 850 MM Btu/h). According to the data in the EPA’s Clean Air Market s Division
database, which contains information on 307 NGCC facilities, there is a 7 percent difference in average CO 2 emission rate between the small- and large-size units. This relat ive difference is consistent with what would be predict ed when comparing the efficiency values reported in Gas Tur bine World of small and large combined cycle designs. Fourteen of the study NGCC facilities evaluated using the Clean Air Marke ts data have heat input rates of less than or equal to 850 MMBtu /h, and the remaining 293 are above 850 MMBtu/MWh. Two of the s mall combined cycle facilities had a maximum 12-operating-month r olling average emissions rate equal to or greater than 1,0 00 lb CO 2 /MWh and one had an maximum 12-operating-month rolling a verage emissions rate equal to or greater than 1, 1 00 lb CO 2 /MWh. Twenty three of the large turbines had at least one occurr ence of a 12- operating-month rolling average emissions rate grea ter than or equal to 1,000 lb CO 2 /MWh and forty four had at least one occurrence of a 12-operating-month rolling average emissions rate greater than or equal to 950 lb CO 2 /MWh. Therefore, because Comment [A130]: Add citation.

Deleted: 0

Deleted: since***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 287 of 373 over 90 percent of small and large existing NGCC fa cilities are currently operating below the emission rates of 1,100 lb CO 2 /MWh
and 1,000 lb CO 2 /MWh , respectively, these rates are considered

BSER for new NGCC facilities in those respective subcategories. These values represent the emission rates that a mo dern high efficiency NGCC facility located in the U.S. would be able to

maintain over its life. To further evaluate the impact of the proposed rule we reviewed the GHG BACT permits for 8 recently permit ted NGCC facilities. Of these facilities, 7 are larger than 850 MMBtu/h, and 1 is smaller. The 7 larger ones all have emissi on rates
below 1,000 lb/MWh, and as low as 880 lb/MWh. The s ingle smaller unit, which is 400 MMBtu/h, has a permitted emissio ns rate of
1,100 lb CO 2 /MWh. We are requesting comment on a range of 950 to 1,10 0 lb

CO 2 /MWh (430 to 500 kg CO 2 /MWh) for the large turbine subcategory
and 1,000 to 1,150 lb CO 2 /MWh (450 to 520 kg CO 2 /MWh) for the small turbine subcategory. IX. Rationale for Compliance Requirements The proposed compliance requirements, to the extent possible, incorporate monitoring already being perf ormed as part of existing part 60 and part 75 requirements. We propose to recognize the environmental benefit o f Deleted: represent emission rates where over 90 percent of small and large existing NGCC are currently operating below

Deleted: the Deleted: of the facility

Deleted: Other Requirements¶ A.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 288 of 373 electricity generated by combined heat and power (C HP)

facilities to account for the increased end use eff iciency resulting from avoided transmission and distributio n losses. To do so, we propose to allow CHP facilities, in calcu lating their

emission rate in lb CO 2 /MWh, to deem their MWh to be 5 percent higher than their actual MWh, which would result in them being

deemed to have a lower emission rate rate for purposes of compliance with this rule

. Actual transmission and distribution losses vary fr om location to location, but we propose that this 5 pe rcent of actual MWh represents a reasonable average amount f or the

avoided transmission and distribution losses for CH P facilities. Note that we propose to limit this 5 percent adjust ment to facilities for which the useful thermal output is a t least 20 percent of the total output. X. Implications for PSD and Title V Programs

A. Overview The proposal in this rulemaking would, for the firs t time, regulate GHGs under CAA section 111. Commenters have raised questions regarding whether this rule will have imp lications for regulations and permits written u nder the CAA PSD preconstruction permit program and the CAA Title V operating permit program. Deleted: actual

Deleted: lead to

Deleted: U Deleted: the EPA’s regulations for Deleted: , Deleted: , regulation of GHGs under CAA section 111 triggers the applicability of PSD Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 289 of 373

T oday’s proposal should not require any additional S IP revisions to make clear that the Tailoring Rule thr esholds – described below - continue to apply to the PSD prog ram. Likewise, today’s rulemaking does not have implicat ions for the Tailoring Rule thresholds established with respect to sources subject to title V requirements. Furthermore, this proposal does not have any direct applicability on the determinat ion of Best Available Control Technology (BACT) for existing EG Us that require PSD permits to authorize a major modificati on of the EGU. Finally, this proposal does have some implicat ions for Title V fees, but EPA is proposing action to addres s those implications as discussed below. B. Applicability of Tailoring Rule thresholds under the PSD

Program States with approved PSD programs in their state implementation plans (SIPs) implement PSD, and most of these States have recently revised their SIPs to incorpor ate the higher thresholds for PSD applicability to GHGs tha t the EPA promulgated under what we call the Tailoring Rule. 268 Commenters

268 “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule; Final Rule,” 75 FR 3 1514 (June 3, 2010). In the Tailoring Rule, EPA established a pro cess for phasing in PSD and Title V applicability to sources based on the amount of their GHG emissions, instead of immediate ly applying Deleted: Even so, t

Deleted: This issue arises because***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 290 of 373 have queried whether under the EPA’s PSD regulation s, promulgation of a section 111 standard of performan ce for GHGs would require these states to revise their SIPs aga in to incorporate the Tailoring Rule thresholds again. Th e EPA included an interpretation in the Tailoring Rule pr eamble, which makes clear that the Tailoring Rule thresholds cont inue to apply if and when the EPA promulgates requirements under CAA section 111. Even so, in today’s proposal, the EPA is inclu ding a provision in the CAA section 111 regulations that c onfirms this interpretation. However, if a state with an approved PSD SIP progra m that applies to GHGs believes that were the EPA to final ize the rulemaking proposed today, the state would be requi red to revise its SIP to make clear that the Tailoring Rule thres holds continue to apply, then (i) the EPA encourages the state to do so as soon as possible, and (ii) if the State canno t do so promptly, the EPA will assess whether to proceed wi th a separate rulemaking action to narrow its approval of that st ate’s SIP so as to assure that for federal purposes, the Tailori ng Rule thresholds will continue to apply as of the effecti ve date of the final rule that the EPA is proposing today.

PSD and title V at the 100 or 250 ton per year or t hresholds included under the PSD and title V applicability pr ovisions.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 291 of 373 In the alternative, if the Tailoring Rule threshold s would not continue to apply when the EPA promulgates requ irements
under CAA section 111, then the EPA would assess wh ether to proceed with a separate rulemaking action to narrow its approval of all of the State’s approved SIP PSD programs to assure that for federal purposes, the Tailoring Rule thresholds will continue to apply as of the effective date the fina l rule that EPA is proposing today. Under the PSD program in part C of title I of the C AA, in

areas that are classified as attainment or unclassi fiable for NAAQS pollutants, a new or modified source that emi ts any air pollutant subject to regulation at or above specifi ed thresholds is required to obtain a preconstruction permit. Thi s permit assures that the source meets specified requirement s, including application of BACT . States that are authorized by the EPA to

administer the PSD program may issue PSD permits. If a state is not authorized, then the EPA issues the PSD permits

. Regulation of GHG emissions in the Light Duty Vehi cle Rule (75 FR 25324) triggered applicability of stationary sources to regulations for GHGs under the PSD and title V prov isions of the
CAA. Hence, on June 3, 2010 (75 FR 31514), the EPA issued the “Tailoring Rule,” which establishes thresholds for GHG emissions

in order to define and limit when new and modified industrial Deleted: did

Comment [A131]: Consider moving this text out of the Overview section and into the Implications Section. It is more informative to provide this af ter the background information. Deleted: ¶ As discussed below, in the case of title V, today’s rulemaking does not have implications for the Tailoring Rule thresholds established with respect to sources subject to title V requirements. ¶ B. Implications for PSD program

Deleted: best available control technology Deleted: for***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 292 of 373 facilities must have permits under the PSD and titl e V programs.
The rule addresses emissions of six GHGs: CO 2 , CH 4 , N 2 O, HFCs,

PFCs and SF 6 . On January 2, 2011, large industrial sources, including power plants, became subject to permittin g requirements for their GHG emissions if they were a lready required to obtain PSD or title V permits due to em issions of other (non-GHG) air pollutants. Commenters have queried whether, because of the way that the EPA’s PSD regulations are written, promulgating the rule we propose today may raise questions as to whether the EPA must revise its PSD regulations –- and, by the same toke n, whether

states must revise their SIPs –- to assure that the Tailoring Rule thresholds will continue to apply to sources s ubject to PSD. That is, under the EPA’s regulations, PSD appl ies to a “major stationary source” that undertakes construct ion and to a “major modification.” 40 CFR 51.166(a)(7)(i) and (i ii). A “major modification” is defined as “any physical change in or change in the method of operation of a major stationary sourc e that would result in a significant emissions increase . . . an d a significant net emissions increase . . . .” Thus, f or present purposes, the key component of these applicability provisions is that PSD applies to a “major stationary source.”***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 293 of 373 The EPA’s regulations define the term “major statio nary source” as a “stationary source of air pollutants w hich emits, or has the potential to emit, 100 [or, depending on the source category, 250] tons per year or more of any regulat ed NSR pollutant.” 40 CFR 51.166(b)(1)(i)( a ). The EPA’s regulations go on to define “regulated NSR pollutant” as follows, in relevant

part:

(b)(49) Regulated NSR pollutant, for purposes of

this section, means the following: (i) Any pollutant for which a national ambient air quality standard has been promulgated and any pollutant identified under this paragraph (b)(49)(i) as a constituent or precursor to such pollutant.... (ii) Any pollutant that is subject to any standard promulgated under section 111 of the Act; (iii) Any Class I or II substance subject to a standard promulgated under or established by title VI of the Act; (iv) Any pollutant that otherwise is subject to regulation under the Act as defined in paragraph (b)(48) of this section....

40 CFR 51.166(b)(49). Thus, the PSD regulations con tain a separate PSD trigger for pollutants regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the “NSPS trigger provision” ), so that as soon as the EPA promulgates the first NSPS for a pa rticular air pollutant, as we are doing in this rulemaking with respect to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 294 of 373 the GHG air pollutant, then PSD is triggered for th at air pollutant. The Tailoring Rule, on the face of its regulatory p rovisions, incorporated the revised thresholds it promulgated into only the fourth prong (“[a]ny pollutant that otherwise is su bject to regulation under the Act”), and not the NSPS trigger provision

in the second prong (“[a]ny pollutant that is subject to a ny standard promulgated under section 111 of the Act”) . For this reason, a question may arise as to whether the Tail oring Rule thresholds apply to the PSD requirement as triggere d by the NSPS that the EPA is promulgating in this rulemaking. However, although the Tailoring Rule thresholds on their face apply to only the term, “subject to regulation” in the definition of “regulated NSR pollutant,” the EPA st ated in the Tailoring Rule preamble that the thresholds should be interpreted to apply to other terms in the definiti on of “major stationary source” and in the statutory provision, “major emitting facility.” Specifically, the EPA stated:

3. Other Mechanisms As just described, we selected the “subject to regulation” mechanism because it most readily accommodated the needs of States to expeditiously revise – through interpretation or otherwise -- the ir state rules. Even so, it is important to recognize that this mechanism has the same substantive effect as the mechanism we considered in the proposed rule, which was revising numerical thresholds in the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 295 of 373 definitions of major stationary source and major modification. Most importantly, although we are codifying the “subject to regulation” mechanism, th at approach is driven by the needs of the states, and our action in this rulemaking should be interpreted to rely on any of several legal mechanisms to accompli sh this result. Thus, our action in this rule should b e understood as revising the meaning of several terms in these definitions, including: (1) the numerical thresholds, as we proposed; (2) the term, “any source,” which some commenters identified as the mo st relevant term for purposes of our proposal; (3) the term, “any air pollutant; or (4) the term, “subject to regulation.” The specific choice of which of these constitutes the nominal mechanism does not have a substantive legal effect because each mechanism involves one or another of the components of the te rms “major stationary source” - which embodies the statutory term, “major emitting facility” -- and “major modification,” which embodies the statutory term, “modification,” and it is those statutory and regulatory terms that we are defining to exclude th e indicated GHG-emitting sources. [Footnote]
[Footnote: We also think that this approach better clarifies our long standing practice of interpreting open-ended SIP regulations to automatically adjust for changes in the regulatory status of an air pollutant, because it appropriatel y assures that the Tailoring Rule applies to both the definition of “major stationary source” and “regula ted NSR pollutant.” ]

75 FR 31582. Thus, according to the preamble of the final Tailoring

Rule , the definition of “major stationary source” itsel f already incorporates the Tailoring Rule thresholds, and not just through one component (the “subject to regulation” prong of the term “regulated NSR pollutant”) of that definition. For this reason, it is the EPA’s position that the Tailoring Rule th resholds***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 296 of 373 continue to apply even when the EPA promulgates the first NSPS for GHGs (which, as noted above, triggers the PSD r equirement under the NSPS trigger provision in the definition of “regulated NSR pollutant”). 269
As a result, the EPA believes that states that inco rporated the Tailoring Rule thresholds into their SIPs may t ake the position that they also incorporated the EPA’s inte rpretation in the preamble that the thresholds apply to the defin ition “major stationary source.”

Even so, t o clarify and confirm that the Tailoring Rule thresholds apply to the section 111 prong of the de finition of regulated NSR pollutant, in this proposed rulemakin g, the EPA is proposing to add new provisions to the NSPS regulations, although not the PSD regulations, to make explicit that the NSPS trigger provision in the PSD regulations incorporat e s the

269 This position reads the regulations to be consiste nt with the CAA PSD provisions themselves. Under those provisio ns, PSD applies to any “major emitting facility,” which is defined to mean stationary sources that emit or have the poten tial to emit “any air pollutant” at either 100 or 250 tons per y ear, depending on the source category. CAA section 165(a ), 169(1). EPA has long interpreted these provisions to apply PSD to a stationary source that emits the threshold amounts of any air pollutant subject to regulation. See Tailoring Rule , 75 FR 31579. Under these provisions, at present, PSD is a lready applicable to GHGs because GHGs are already subject to regulation, and regulating GHGs under CAA section 1 11 does not create any additional type of PSD trigger. Deleted: Deleted: T

Deleted: revise

Deleted: ly make clear***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 297 of 373 Tailoring Rule thresholds. 270 Under these new provisions, to the extent that promulgation of section 111 requirement s for GHGs triggers PSD requirements for GHGs, it does so only for GHGs emitted at or above the Tailoring Rule thresholds. The EPA requests that all States with approved SIP PSD programs that apply to GHGs indicate during the com ment period

on this rule whether , (i) in light of EPA’s interpretation that the Tailoring Rule thresholds continue to apply eve n when the EPA promulgates the first NSPS for GHGs, and (ii) a ssuming that EPA finalizes the added provisions to the section 1 11 regulations proposed today, they can interpret their SIPs already to apply the Tailoring Rule thresholds to t he NSPS prong or whether they must revise their SIPs. For any Sta te that says it must revise its SIP (or that does not respond), the EPA will assess whether to propose a rule shortly after the close of the comment period, to narrow its approval of that stat e’s SIP so as to assure that for federal purposes, the Tailoring Rule thresholds will continue to apply as of the effecti ve date of the final rule that the EPA is proposing today. Suc h a rule

would be comparable to what we call the SIP PSD Narrowing Rule

270 The Tailoring Rule thresholds themselves are not a t issue in this rulemaking. Deleted: The rationale for the Tailoring Rule thresholds remains equally applicable in this context.

Deleted: ¶ As a result, the EPA believes that states that incorporated the Tailoring Rule thresholds into their SIPs may take the position that they also incorporated the EPA’s interpretation in the preamble that the thresholds apply to the definition “major stationary source.”

Deleted: that is***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 298 of 373 that EPA promulgated in December, 2010. 271 The EPA may finalize such a narrowing rule at the same time that it finalizes this

NSPS rule. C. Implications for BACT determinations under PSD New major stationary sources and major modification s at existing major stationary sources are required by t he CAA to, among other things, obtain a permit under the PSD p rogram before commencing construction. A source is subject to PSD by way of its proposed construction and the effect of the con struction and operation of the new equipment on emissions. The em ission thresholds that define PSD applicability can be fou nd in 40 CFR 51 and 52 and are discussed briefly in the above se ction. As mentioned above, sources that are subject to PSD must obtain a preconstruction permit that contains emiss ion limitations based on application of Best Available Control Technology for each regulated NSR pollutant. The BA CT requirement is set forth in section 165(a)(4) of th e CAA, and in EPA regulations under 40 CFR Parts 51 and 52. These provisions require that BACT determinations be made on a case- by-case basis

271 “Limitation of Approval of Prevention of Significa nt Deterioration Provisions Concerning Greenhouse Gas EmittingSources in State Implementation Plans; Final Rule,” 75 Fed. Reg. 82,536 (December 30, 2010). Deleted: shortly after the close of the comment period, and Deleted: that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 299 of 373

after consideration of the record in each case. CAA § 169(3)

defines BACT as:

an emissions limitation (including a visible emissi on standard) based on the maximum degree of reduction for each pollutant subject to regulation under the Clean Air Act which would be emitted from any proposed major stat ionary source or major modification which the Administrato r, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs , determines is achievable for such facility through application of production processes and available m ethods, systems, and techniques, including fuel cleaning, c lean fuels, or treatment or innovative fuel combustion techniques for control of each such pollutant.... Furthermore, this definition in the CAA specifies t hat “[i]n no event shall application of [BACT] result i n emissions of any pollutants which will exceed the emissions a llowed by any applicable standard established pursuant to section 111 or 112 of the Act.” This has historically been interpreted to mean that BACT cannot be less stringent than any applicable s tandard of performance under the NSPS. See e.g. EPA, PSD and T itle V Permitting Guidance for Greenhouse Gases, p. 20-21 (March 2011). Thus, upon completion of an NSPS, EPA reads the CAA to mean that the NSPS establishes a “BACT Floor” for PSD permits issued to affected facilities covered by an NSPS. It is impor tant to note that a proposed NSPS does not establish the BACT Fl oor for affected facilities seeking a PSD permit. This is e xplained on***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 300 of 373 page 25 of EPA’s PSD and Title V Permitting Guidanc e for
Greenhouse Gases (March 2011):

In cases where a NSPS is proposed, the NSPS will no t be controlling for BACT purposes since it is not a fin al action and the proposed standard may change, but th e record of the proposed standard (including any significant public comments on EPA’s evaluation) should be weighed whe n considering available control strategies and achiev able emission levels for BACT determinations made that a re completed before a final standard is set by EPA. Ho wever, even though a proposed NSPS is not a controlling fl oor for BACT, the NSPS is an independent requirement that w ill apply to an NSPS source that commences construction after an NSPS is proposed and carries with it a strong presumption as to what level of control is achievab le. This is not intended to limit available options to only those considered in the development of the NSPS. (p.25)

However, as noted in the “transitional sources unde r the current proposal” section of this notice, once an N SPS is finalized, then the standard applies to any new sou rce or modification that meets the applicability of the NS PS and has not commenced construction as of the date of the pr oposed NSPS. It is also important to keep in mind that BACT is a caseby-base review that considers a number of factors, and the fact that a minimum control requirement is established b y EPA through an NSPS does not mean that a more stringent control cannot be chosen by the permitting agency. The EPA’s PSD and Title V Permitting Guidance for Greenhouse Gases (March 201 1) discusses***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 301 of 373 considerations when evaluating BACT for CO 2 , as well as other greenhouse gases. Under this proposed NSPS, an affected facility is a new EGU. In this rule we are not proposing standards fo r modified or
reconstructed sources. However, since both a new an d existing power plant can add new EGUs to increase generating capacity, this NSPS will apply to both a new, greenfield EGU facility or an existing facility that adds EGU capacity by addi ng a new EGU that is an affected facility under this NSPS. While this latter

scenario can be considered the modification of exis ting source under PSD, this proposed NSPS will not apply to mod ified or

reconstructed sources as those terms are defined un der Part 60. Thus, this NSPS would not establish a BACT floor fo r sources that are modifying an existing EGU, for example, by adding new steam tubes in an existing boiler or replacing blad es in their existing combustion turbine with a more efficient d esign. Furthermore, our analysis for this proposed NSPS co nsiders only to extent which particular pollution control t echniques are
BSER for new units, and does not evaluate whether s uch techniques also qualify as BSER for modified or rec onstructed

sources under Part 60 or are otherwise achievable m ethods for reducing GHG emission from such sources considering economic, environmental, and energy impacts. Therefore, we do not believe***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 302 of 373 that the content of this rule has any direct applic ability on the determination of BACT for any Part 60 modified or reconstructed sources obtaining a PSD permit.

D . Implications for title V program Under the title V program, a source that emits any air pollutant subject to regulation at or above specifi ed thresholds (along with certain other sources) is required to o btain an operating permit. This permit includes all of the C AA requirements applicable to the source. These permit s are generally issued through EPA-approved State title V programs. As the EPA explained in the Tailoring Rule preamble , title V applies to a “major source,” CAA section 502(a), which is defined to include, among other things, certain sou rces, including any “major stationary source,” CAA sectio n 501(2)(B), which, in turn, is defined to include a stationary source of “any air pollutant” at or above 100 tpy. CAA sectio n 302(j). The EPA’s regulations under title V define the term “ma jor source,” and in the Tailoring Rule, the EPA revised that def inition to make clear that the term is limited to stationary s ources that emit any air pollutant “subject to regulation.” The EPA incorporated the Tailoring Rule threshold within th e definition of “subject to regulation.” The EPA described its a ction as follows in the preamble to the Tailoring Rule: Deleted: C***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 303 of 373 Thus, EPA is adding the phrase “subject to regulation” to the definition of “major source” und er 40 CFR 70.2 and 71.2. EPA is also adding to these regulations a definition of “subject to regulation. ” Under the part 70 and part 71 regulatory changes adopted, the term “subject to regulation,” for purposes of the definition of “major source,” has t wo components. The first component codifies the genera l approach EPA recently articulated in the “Reconsideration of Interpretation of Regulations T hat Determine Pollutants Covered by Clean Air Act Permitting.” 75 FR 17704. Under this first componen t, a pollutant “subject to regulation” is defined to m ean a pollutant subject to either a provision in the CA A or regulation adopted by EPA under the CAA that requires actual control of emissions of that pollut ant and that has taken effect under the CAA. See id . at 17022-23; Wegman Memorandum at 4-5. To address tailoring for GHGs, EPA includes a second component of the definition of “subject to regulation,” specifyi ng that GHGs are not subject to regulation for purpose s of defining a major source, unless as of July 1, 20 11, the emissions of GHGs are from a source emitting or having the potential to emit 100,000 tpy of GHGs on a CO 2 e basis.
75 Fed. Reg. at 31,583. Unlike the PSD regulations described above, the tit le V definition of “major source”, as revised by the Tai loring Rule, does not on its face distinguish among types of reg ulatory triggers for title V. Because title V has already b een triggered for GHG-emitting sources, the promulgation of CAA s ection 111 requirements has no further impact on title V appli cability requirements for major sources of GHGs. Accordingly , today’s rulemaking has no title V implications with respect to the Tailoring Rule threshold. Of course, unless exempte d by the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 304 of 373 Administrator through regulation under CAA section 502(a), sources subject to a NSPS are required to apply for , and operate pursuant to, a title V permit that assures complian ce with all applicable CAA requirements for the source, includi ng any GHGrelated applicable requirements. We have concluded that this rule will not affect non-major sources and there is no need to consider whether to exempt non-major sources. Note that we propose to move the definition of “Gre enhouse gases” currently within the definitions of “Subject to regulation” in 40 CFR 70.2 and 71.2 to a definition within 70.2 and 71.2 to promote clarity in the regulations.

E . Implications for title V fee requirements for GHG s The issuance of the final EGU GHG NSPS will trigger certain requirements related to title V fees for GHG emissi ons under 40 CFR part 70 and part 71. States ( and approved local and tribal permitting authorities) will be required to include GHG emissions in determining whether they collect adequ ate fees, if the state relies on the “presumptive minimum” appro ach to demonstrating fee adequacy. In addition, sources su bject to federal permitting under part 71 will be required t o include GHG emissions in calculating their annual permit fee. 272 The EPA is

272 Also, we understand several states may have fee re quirements that are structured with similar definitions that w ould result Deleted: D Deleted: s

Deleted: including***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 305 of 373 proposing changes to the title V rules to limit the impact of the requirements that would otherwise occur under t he existing rules, provide flexibility to the states to ensure sufficient funding for their programs, and to ensure that the requirements

are consistent with the Clean Air Act. These requirements would be triggered because the regulation of GHGs under section 111 for the first time through

the issuance of the EGU GHG NSPS would make GHGs a “regulated air pollutant,” as defined under 40 CFR parts 70 an d 71, a “regulated pollutant (for presumptive fee calculati on)” as defined under part 70 and a “regulated pollutant (f or fee calculation)” as defined under part 71. Under the current part 70, regulation of GHGs under section 111 through the issuance of any NSPS would result i n GHGs being added to the list of air pollutants used in “presum ptive minimum” fee calculations. Also, in EPA’s part 71 p ermit program, and possibly in certain state part 70 prog rams,
issuance of a NSPS standard would result in GHGs be ing added to the list of air pollutants that are subject to fee payment by sources. This effect of adding GHGs to certain titl e V fee requirements was not discussed in the previous prop osal for the

in GHGs being added to the list of air pollutants t hat are subject to title V fees. Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 306 of 373 EGU GHG NSPS; however, several public comments were raised on this issue, and a number of related issues, during the public comment period on the previous proposal for the EGU GHG NSPS. In this re-proposal of the EGU GHG NSPS, we discuss this issue for GHGs related to title V fees and propose rule amendments that will enable permitting authorities to collect fees as needed to support their programs, and to avoid excessive and unnecessary fees. We also respond to and clarif y some related issues raised by commenters on the previous proposal. In summary, we are proposing to exempt GHGs from th e presumptive fee calculation, yet account for the co sts of GHG permitting program costs through a cost adjustment to ensure
that fees will be collected that are sufficient to cover the program costs. We are also proposing that permittin g agencies that do not use the presumptive fee approach can co ntinue to demonstrate that their fee structures are adequate to implement their title V programs. Prior to explaining our proposal in more detail, th e following discussion provides background on the fee requirements
of the title V rules, what those fees cover in term s of agencies’ program implementation, what additional a ctivities agencies might be expected to have to undertake as a result of GHGs becoming “regulated pollutants” under the NSPS , what the Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 307 of 373 GHG Tailoring Rule said about title V fees, backgro und on title V fees in the context of the previous proposal for the EGU GHG NSPS, and existing limitations on the collection of GHG fees. 1. Background

a. The title V rules Title V is implemented through 40 CFR parts 70 and 71. Part 70 defines the minimum requirements for state, local and tribal (state) agencies to develop, implement and e nforce a title V operating permit program; these programs ar e developed by the state and the state submits a program to EPA for a review of consistency with part 70. There are about 112 ap proved part 70 programs in effect, with about 15,000 part 70 pe rmits currently in effect. (See Appendix A of 40 CFR part 70 for the approval status of each state program). Part 71 is a federal permit program run by the EPA, primarily where ther e is no part 70 program in effect (e.g., in Indian country, the federal Outer

Continental Shelf and for offshore Liquified Natural Gas
terminals). 273 There are about 100 part 71 permits currently in effect (most are in Indian country).

273 In some circumstances, EPA may delegate authority for part 71 permitting to another permitting agency, such as a tribal agency or a state. The EPA has entered into delegation agr eements for certain part 71 permitting activities with at least one tribal agency. There are currently no states that do not have an Deleted: OCS Comment [A132]: Spell out

Deleted: LNG***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 308 of 373

b. The fee requirements of title V Section 502(b)(3)(A) of the Act requires owners or operators of all sources subject to permitting to “ pay an annual fee, or the equivalent over some other period, suff icient to
cover all reasonable (direct and indirect) costs re quired to develop and administer the permit program.” Section 502(b)(3)(B) of the Act generally sets forth the methods for det ermining whether a permitting authority is collecting suffic ient fees in total to cover the costs of the program. First, und er the “presumptive minimum” approach set forth in section 502(b)(3)(B)(i), a state can satisfy the requiremen t by showing that “the program will result in the collection, in the aggregate, from all sources subject to [the program ] of an amount not less than $25 per ton of each regulated pollutant, or such other amount as the Administrator may determin e adequately reflects the reasonable costs of the permit program .” The statute further provides that emissions in excess o f 4,000 tpy for any one pollutant need not be included in the c alculation, and that the initial fee rate ($25 per ton) shall b e adjusted

for inflation 274 . See section 502(b)(3)(B)(iii)-(v). Also,

approved part 70 program; thus, there is no need fo r EPA to delegate part 71 permitting authority to any state at this time. 274 The current corresponding part 70 fee rate, adjust ed for inflation, is approximately $47 per ton.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 309 of 373
section 502(b)(3)(B)(ii) of the Act sets forth a de finition of “regulated pollutant” for purposes of the presumpti ve fee calculation that includes, in part, each pollutant regulated under section 111 of the Act, such as any pollutant s regulated under any NSPS, which would make GHG a “regulated p ollutant” based on our proposal for the EGU GHG NSPS. Each of the title V rules that implement title V contains a definition of “regulated air pollutant” 275 (at 40 CFR 70.2 and 71.2) that tracks the Act definition of “regulated pollutant.” The “regulated air pollutant" definition is used in the regulatory tex t for application and other purposes and it is relevant for fee purposes because it is cross-referenced as the star ting point for two fee-related definitions: “regulated polluta nt (for presumptive fee calculation) 276 ” in 40 CFR 70.2 and “regulated pollutant (for fee calculation) 277 ” in 40 CFR 71.2.

275 The definition reads in relevant part : “Regulated air pollutant means the following: (1) Nitrogen oxides or any volatile organic compounds; (2) Any pollutant for w hich a national ambient air quality standard has been prom ulgated; (3) Any pollutant that is subject to any standard promu lgated under section 111 of the Act; (4) Any Class I or II subst ance subject to a standard promulgated under or established by t itle VI of the Act; or (5) Any pollutant subject to a standard promulgated under section 112 or other requirements established under section 112 of the Act, including sections 112(g), (j), and (r) of the Act . . .” 276 40 CFR 70.2 defines r egulated pollutant (for presumptive fee calculation) to mean: “any ‘regulated air pollutant’ except the following: (1) Carbon monoxide; (2) Any pollutant that is a Deleted: applicable requirements

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 310 of 373 Alternatively, if a state does not wish to show it collects an amount of fees at least equal to the presumptive minimum amount, section 502(b)(3)(B)(iv) provides that a pr ogram may be approved if the state demonstrates that it collects sufficient fees to cover the costs of the program, even if tha t amount is below the presumptive minimum. The presumptive fee approach of the statute is refl ected in the part 70 regulations for those states that wish to use it for fee adequacy purposes. In addition, for the federal part 71 permitting program, which the EPA implements direct ly, the EPA has adopted rules to ensure that it collects adequa te fees,

consistent with the statute. These statutory requirements for fees are reflected in 40 CFR 70.9 and 71.9, respect ively. Although the Clean Air Act and part 70 require that a title V permit program must collect sufficient fees to co ver the costs of the program, neither the Act nor part 70 specifi es the details of how those fees must be charged to partic ular sources in their fee schedules. The part 70 regulations spe cifically

regulated air pollutant solely because it is a Clas s I or II substance to a standard promulgated under or establ ished by title VI of the Act; or (3) Any pollutant that is a regulated air pollutant solely because it is subject to a sta ndard or regulation under section 112(r) of the Act.” 277 40 CFR 71.2 defines r egulated pollutant (for fee calculation ) the same as r egulated pollutant (for presumptive fee calculation in 40 CFR 70.2. Deleted: Act***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 311 of 373 provide, at 40 CFR 70.9(b)(3), that a “state progra m’s fee schedule may include emission fees, application fee s, service fees or other types of fees, or any combination the reof.” Many states use emission fees and other types of fees in combination

in their fee schedules and we understand that some state fee schedules are structured such that they would resul t in GHG fees being required when GHGs are regulated under any NS PS. For example, states may have chosen for convenience sak e to use the “regulated pollutant (for presumptive fee calculati on)” definition of part 70, or a similar state definitio n, to identify the pollutants subject to fees as part of their fee schedule. For part 71, the EPA chose to promulgate an emissionsbased fee schedule that uses the definition of “reg ulated pollutants (for fee calculation)” to identify the p ollutants subject to fees, and thus, part 71 is structured su ch that GHG fees would be required when GHGs are regulated unde r any NSPS. State fee schedules charge emissions-based fees tha t range from about $15 to $100 or more per ton for each air pollutant for which they charge a fee, while part 71 charges about $48 per

ton 278 , effective for calendar year 2013, for each of the

278 Note that the part 71 fee rate and the part 70 pre sumptive fee rate are slightly different because the part 71 rate was set based on an analysis that showed that the EPA neede d slightly***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 312 of 373 “regulated pollutants (for fee calculation).” See 4 0 CFR 71.9(c)(1). Most part 70 and part 71 programs requi re sources to pay the fees on an annual basis, initially with the submittal of its permit application, and thereafter, on the anni versary of application submittal. See 40 CFR 70.9(a), 71.9(e). Section 502(b)(3)(A) of the CAA broadly requires pe rmit
fees “sufficient to cover all reasonable (direct an d indirect) costs required to develop and administer the permit program” including the reasonable costs of: “(i) reviewing a nd acting upon any application for such a permit, (ii) implem enting and enforcing the terms and conditions of any such perm it (not including any court costs or other costs associated with any
enforcement action), (iii) emissions and ambient mo nitoring, (iv) preparing generally applicable regulations, or guidance, (v) modeling, analyses, and demonstrations, and (vi ) preparing inventories and tracking emissions.” These statutor y requirements were incorporated into the regulations at 40 CFR 70.9(b)(1) and 71.9(b), EPA has provided detailed g uidance on EPA’s interpretation of this list of activities in several

more than the presumptive minimum to collect suffic ient revenue to fund the program. Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 313 of 373
memoranda, 279 and these activities have been considered in the context of the ICR development and renewal process for part 70

and 71.

c. How EPA Addressed Title V Fees in the Tailoring Ru le The GHG Tailoring Rule concerned when sources are r equired to obtain permits under prevention of significant d eterioration
(PSD) and title V due to emissions of GHGs. ( See Prevention of Significant Deterioration and Title V Greenhouse Ta iloring Rule; Final Rule [the Tailoring Rule]; 75 FR 31514, June 3, 2010.) GHGs became subject to regulation as a result of th e Light Duty Vehicle Rule (75 FR 25,234, May 7, 2010), and the T ailoring Rule established emissions thresholds for purposes of PS D and title V. Neither the Light Duty Vehicle Rule nor the Tail oring Rule
made any changes that would cause GHGs to meet the definition of “regulated air pollutant,” or related fee definitio ns in the title V regulations. EPA has promulgated no other s tandards that would trigger fee requirements for GHGs in title V programs. The GHG Tailoring Rule addressed the possible need for states and the EPA to charge fees for GHG emissions based on the

279 For example, see “Reissuance of Guidance on Agency Review of State Fee Schedules for Operating Permits Programs Under Title V”; from John S. Seitz, Director, Office of Air Qua lity Planning and standards, to Air Division Directors, Regions I -X; August 4, 1993; available at http://www.epa.gov/region07/air/title5/t5memos/fees .pdf. Deleted: ie***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 314 of 373 burdens imposed under the Tailoring Rule for states to incorporate GHGs into permits or to issue permits t o sources based on GHG emissions. We did not revise the part 70 rules to require fees for GHGs, although we did clarify that states have the option of charging fees to recover the costs of permitting related to GHGs. Also, we did not revise part 71 to require GHG
fees, and we stated that we would review the need f or additional fees to cover program costs for GHGs over time. (Se e 75 FR 31526 and 31584.) We retained this approach in last year’ s Step 3 Tailoring Rule. (See Prevention of Significant Dete rioration and Title V Greenhouse Tailoring Rule Step 3, GHG Plant wide Applicability Limitations and GHG Synthetic Minor L imitations, (Step 3 of the Tailoring Rule), 77 FR 41051, July 1 2, 2012).

d. Title V fees in the previous EGU GHG NSPS proposal The previous EGU GHG NSPS proposal did not discuss any title V fee issues related to regulating GHGs under a section 111 standard; however, several public commenters (t wo state agencies and one industry group) raised several con cerns or
asked for clarification on a number of issues relat ed to title V fees during the public comment period. Two of these commenters requested clarification as to whether the issuance of the EGU

GHG NSPS would make either GHGs or CO 2 subject to regulation such that title V fee requirements would be triggered fo r either of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 315 of 373 these pollutants. One commenter requested clarifica tion on whether fees are required for “regulated NSR pollut ants,” such as GHG. One commenter questioned whether the ration ale of the Tailoring Rule for deferring fees for GHGs would al so apply to the EGU GHG NSPS. Finally, one commenter asked us t o clarify if a state could refrain from charging a fee for CO 2 (based on the issuance of the EGU GHG NSPS) if the state otherwis e generates a fee sufficient to meet the “program support require ments” of

title V. Note that we address the substance of seve ral of these

comments related to title V fees in section B of th is portion of
the proposal.

e. Unique Characteristics of GHGs relative to Fees There are a number of provisions in part 70 and pa rt 71 and characteristics of GHGs that are relevant to any di scussion related to charging fee s for GHGs. First, it should be noted that GHG are emitted in extremely high quantities r elative to other air pollutants, such as the criteria pollutan ts, which are typically emitted by combustion sources that also e mit GHGs. A

review of emission factors in EPA’s AP-42 shows tha t GHGs are typically emitted in quantities as much as one thou sand or more times higher than CO or NO X and many other pollutants as a***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 316 of 373 product of combustion for a given mass of fuel 280 . Thus, we expect that charging fees for GHGs at the same rate (in dollars per ton) as other regulated air pollutants would le ad to fee revenue that would be excessive, far beyond the rea sonable costs of the program. Even though most part 70 and 71 pro grams cap total fees at 4,000 tons per air pollutant per year 281 we note that the total GHG fee for a particular source unde r the current part 71 rule could still be significant, up to abou t $194,000 per year for GHGs alone, if GHGs are charged at the same rate as for other “regulated pollutants (for fee calculatio n).” 282
Second, unlike other pollutants, GHGs can be estima ted in two ways: by mass or by CO 2 equivalent (CO 2 e). While the title V permitting threshold for the Tailoring Rule was est ablished at
100,000 CO 2 e and 100 tpy mass, the fee provisions of part 70 a nd 71, and we believe the fee provisions of the majori ty, if not all, state programs, charge fees on a mass (per ton ), rather

280 See AP-42, Compilation of Air Pollution Emission F actors, Volume I, Stationary and Area Sources, Fifth Editio n. For example, for external combustion of bituminous and subbituminous coals, see table 1.1-3 for NOx and CO emission fact ors and table 1.1-20 for CO 2 emissions factors. 281 Consistent with the option afforded states at 40 CF R 70.9(b)(2)(ii)(B) and the EPA’s fee schedule at 40 CFR 71.9(c)(5). 282 Note that most sources that emit GHGs, particularly major sources of GHG, also emit other regulated air pollu tants subject to fees; thus, they would pay significant title V f ees even if a fee for GHGs is not charged.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 317 of 373

than on a CO 2 e 283 , basis. See 40 CFR 70.9(b)(2)(i) and 40 CFR
71.9(c)(1).

2. Response to comments on fees from the previous EGU GHG NSPS proposal In response to concerns raised by commenters, and b ecause response to certain of these issues will help to pr ovide a better proposal, we respond to several of these com ments at this time. In response to the question as to whether CO 2 or GHGs would be regulated by the EGU GHG NSPS, we clarify that G HG would be regulated under section 111 of the Act and that thi s does not affect the applicability thresholds previously esta blished for PSD and title V in the Tailoring Rule. First, the E PA considers the pollutant being regulated by the NSPS for the p urposes of PSD and title V to be GHG, rather than CO 2 . Thus, under this interpretation, this NSPS has not caused CO 2 to be treated as a “regulated air pollutant” under the third prong of the definition of “regulated air pollutant” contained i n 40 CFR 70.2 and 71.2, which includes “[a]ny pollutant that is s ubject to any

283 The term “tpy CO 2 equivalent emissions” (or “CO 2 e”) is defined within the definition of “subject to regulation” in 40 CFR 70.2 and 71.2. The definitions read, in relevant part, “ [CO2e] shall represent an amount of GHGs emitted, and shall be c omputed by multiplying the mass amount of emissions (tpy), for each of the six greenhouse gases in the pollutant GHGs, by the gas's associated global warming potential published at Ta ble A-1 to subpart A of part 98 of this chapter—Global Warming Potentials, and summing the resultant value for each to compute a tpy CO 2 e. Deleted:

Deleted: by***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 318 of 373 standard promulgated under section 111 of the Act,” because it

causes GHG , rather than CO 2 , to be the “regulated air pollutant.” Second, although EPA’s PSD regulations provide that regulation of GHGs under CAA section 111 triggers PSD applicab ility, the Tailoring Rule thresholds for GHG continue to apply for major source applicability for both the PSD and Title V p ermitting

programs. 284 In addition, we are proposing regulatory text in
section 60.46Da(f) and section 60.4315(b) to make c lear that for purposes of PSD and title V, greenhouse gases (not carbon dioxide) is the pollutant subject to a standard pro mulgated

under section 111. In response to the comment inquiring whether the ra tionale of the Tailoring Rule remains relevant for deferrin g action on fees, we are proposing several revisions to the par t 70 and part 71 regulations in response to the proposed regulati on of GHGs under section 111, while retaining the general appr oach that we described in the Tailoring Rule. At the time of the promulgation of the Tailoring Rule, there were no section 111 st andards (or other standards) that had been promulgated that wou ld have resulted in title V fee requirements being triggere d for GHGs.

284 We have clarified these points further in a memora ndum added to the docket for this rulemaking (“PSD Threshold M emorandum,” dated May 8, 2012). See document number EPA-HQ-OAR- 2011-0660- 7602. Deleted: We have clarified these points further in a memorandum we have added to the docket for this rulemaking (“PSD Threshold Memorandum,” dated May 8, 2012).(See document number EPA-HQ-OAQPS2011-0660-7602 )

. Comment [A133]: Note: identical reg text on this point appears in 2 places in the regs. I am n ot sure why and was thinking perhaps one could be deleted so I only cited one place here. Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 319 of 373 Thus the rationale we use now is necessarily differ ent that the rationale we used for the Tailoring Rule fee discus sion. If the commenter is referring to the requests of certain s tate agencies in their comments on the Tailoring Rule for the EPA to set a presumptive fee of GHGs, we are responding to that request in this proposal by proposing to set a presumptive fee cost adjustment. If the commenter is referring to the fe e flexibility afforded by 40 CFR 70.9(b)(3), we respond that we a re not proposing to revise that regulatory provision. A st ate commenter generally asked us if it could refrain from requiri ng a fee for

CO 2 (or GHG) if it could show that it can otherwise generate a fee sufficient to meet the “program support require ments” of title V. The response to this comment is yes, based on the following analysis. Title V requires permitting aut horities to

collect fees from sources that are ‘‘sufficient to cover all reasonable (direct and indirect) costs required to develop and administer [title V] programs.” 285 States have adopted various fee schedules to meet this requirement. 40 CFR 70.9 (b)(3) allows a State program's fee schedule to include emissions fees, application fees, service-based fees or other types of fees, or any combination thereof, to meet the requirements o f the

285 The fee provisions are set forth in CAA section 50 2(b)(3) and in our regulations at 40 CFR 70.9 and 71.9. Deleted: not

Deleted: they

Deleted:

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 320 of 373

collection and retention of revenues sufficient to cover the permit program costs. Further, states are not requi red to calculate fees on any particular basis or in the sa me manner for all part 70 sources or for all regulated air pollut ants, provided that they collect a total amount of fees s ufficient to meet the program support requirements. This flexibi lity is also true for states that use the presumptive minimum ap proach to demonstrate they would collect sufficient fees to f und the program. In the final Tailoring Rule (75 Fed. Reg. 31584, June 3, 2010), we did not change our fee regulations to require title V fees for GHGs or require new fee demonstrations f rom states related to permitting GHGs, and we have retained th e same policies for the purposes of the recent Step 3 rule (77 Fed. Reg. 41051, July 12, 2012). In the final Tailoring Rule, we recommended that each state, local or tribal progra m review its

resource needs for GHGs and determine if the existi ng fee approaches would be adequate. If those approaches w ere not adequate, we suggested that they should be proactiv e in raising

fees to cover the direct and indirect costs of the program or develop other alternative approaches to meet the sh ortfall. Therefore, we agree with the commenter that consist ent with 40 CFR 70.9(b)(3), if a state generates fees “sufficie nt to meet the program support requirements,” without charging fees based***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 321 of 373
on GHG emissions, then a fee does not have to be ch arged specifically for GHGs. 286 Thus, this proposal does not seek to revise fee schedule flexibility for states and inst ead focuses on revising the presumptive minimum fee provisions under part 70 to more appropriately account for GHG program costs . This notice does not propose any new requirements for states th at do not use the presumptive approach to establish adequacy of f ees.

3. Today’s proposal to address GHGs in title V fees In this part of the preamble we explain and solicit comment on options to address the title V fee issues raised by the proposed regulation of GHGs under this NSPS. In sum , we propose to exempt GHGs from the presumptive fee calculation , yet account for the costs of GHG permitting through a cost adju stment to

ensure that fees will be collected that are suffici ent to cover the program costs

. We request comment on these proposals, particularly from state, local, and tribal permitti ng agencies, and particularly with respect to which approach would be most appropriate, feasible, and workable and result in f ees that would be adequate to cover the direct and indirect costs of permitting GHGs. We also invite comments on ways to improve this

286 Conversely, where a state cannot show that suffici ent fees are being collected, the state would need to modify its fee schedule (which could, but need not, involve chargi ng fees for GHG emissions). Deleted:

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 322 of 373 proposal and/or address this issue in other ways co nsistent with the same principles, concerns, and statutory author ity that we have described for this proposal.

a. Exemption of GHGs from presumptive fee calculation For the reasons discussed earlier in this proposal , we propose to exempt GHGs from the definition of “regu lated pollutant (for presumptive fee calculation)” in 40 CFR 70.2 in order to exclude GHGs from being subject to the sta tutory fee rate set for the presumptive minimum fee calculatio n of 40 CFR 70.9(b)(2)(i). Pursuant to the authority of section 502(b)(3)(B)(i), we are proposing to determine that utilizing the statutory fee rate for GHGs would be inappropri ate because it would result in excessive fees, far above the re asonable costs of a program. W e are proposing a significantly smaller cost adjustment for GHGs to reflect the program cos ts related to

GHGs. We have estimated the cost of permitting GHGs asso ciated with the Tailoring Rule thresholds in an economic a nalysis performed for the Tailoring Rule and in several doc uments related to Information Collection Request (ICR) req uirements for part 70 and 71, and we believe these analyses provi de a basis for estimating the costs related to GHG permitting for the typical permitting authority. Thus, we propose to r evise 40 CFR Deleted:

Deleted: Thus,nd w

Deleted: several documents, in

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 323 of 373 70.9(b)(2)(i) to add a GHG cost adjustment to accou nt for the GHG permitting program costs.

b. Addition of a GHG cost adjustment to the presumptiv e minimum

fee calculation We propose to revise the presumptive minimum fee p rovisions of part 70 to add a GHG cost adjustment to account for the typical GHG permitting program costs that may not a lready be covered by the existing presumptive minimum fee pro visions of parts 70 and 71. The current presumptive minimum fe e provisions of the title V rules implements the statutory manda te to collect

fees that are sufficient to cover the direct and in direct GHG program costs. Since we are not proposing to charge fees for GHGs at the statutory rate ($25 per ton, adjusted f or inflation) due to concerns raised by permitting authorities an d others about this resulting in excessive fees, we may need an alternative presumptive minimum fee to recover any costs related to GHGs that would not otherwise be covered by the presumptive

minimum fee that is calculated based on emissions o f regulated air pollutants, excluding GHGs. We estimated certai n incremental GHG program costs that would not be covered under t he context of the Tailoring Rule, but we did not revise our permi t rule to

reflect those costs at that time. We are aware that the EGU NSPS may further increase permitting authority costs abo ve the levels Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 324 of 373 that would be covered by presumptive minimum fee pr ovisions that
exclude GHGs, but we are also concerned that accounting for GHGs using the statutory rate would result in excessive calculation
of costs. Thus, to address these concerns, we are proposing two

alternative options to adjust the presumptive minimum fee provisions of the regulations, including a modest a dditional cost for each GHG-related activity of certain types that a permitting authority would process over the period covered by the presumptive minimum fee calculation, and a mode st additional increase in the per ton rate used in the presumptiv e minimum

calculation. We are also soliciting comment on an option that

would calculate no additional costs for GHGs. When we promulgate step 4 of the Tailoring Rule, an d depending on EPA’s proposal(s) and final action(s) there, we may revisit the GHG cost adjustment and potentially rev ise it, taking into account any changes in permitting autho rity costs for GHGs related to the obligations for permitting authorities under that rulemaking. In addition, as a general matter, the presumptive m inimum adjustments for part 70 we propose for GHGs are bas ed, in part, on information concerning permitting authority burd en (in hours)
and cost (in dollars) contained in the Information Collection Deleted: and

Deleted: soliciting comment on several proposed

Deleted: an option that would calculate no additional costs for GHGs,

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 325 of 373
Request (ICR) renewal for part 70 287 approved by the Office of Management and Budget on October 3, 2012 for the 36 month period of October 31, 2012 through September 30, 2015. Als o, this information is consistent with, and updates, burden and cost information in the Regulatory Impact Assessment (RI A) for the Tailoring Rule 288 and an ICR change request for the GHG Tailoring Rule (EPA ICR Number 1587.11), which was approved b y OMB at the time of the promulgation of the Tailoring Rule 289 . These assumptions are relevant at least through step 3 of the implementation of the Tailoring Rule. The supportin g statement for the ICR renewal for part 70 sets forth our esti mate of the three-year and annual incremental burden related to certain activities performed by permitting authorities unde r the Tailoring Rule. (See Supporting Statement for the P art 70 state Operating Permits Program, document number EPA-HQ-O AR-2004-0016- 0023). The information in the supporting statement is designed to be a directionally correct assessment of costs, and thus, may serve as a starting point for considerations of the possible

287 The most recent part 70 ICR renewal is identified as EPA ICR number 1587.12 and the ICR for part 70 has been ass igned OMB control number 2060-0243. 288 Regulatory Impact Analysis for the Final Preventio n of Significant Deterioration and Title V Greenhouse Ga s Tailoring Rule, Final Report, May 2010. 289 The ICR change request form for the Tailoring Rule was based on the assumptions made in the RIA for the Tailorin g Rule.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 326 of 373 range of costs to consider when proposing adjustmen ts to the presumptive minimum fee provisions of part 70 to ap propriately account for GHG permitting program costs.
First, w e are proposing to adjust the presumptive minimum

fee to account for GHG costs by adding a cost for each GHGrelated activity of certain types that a permitting authority may perform over the period covered by a presumptiv e minimum fee calculation. Additional information supporting this approach may be found in part in Table 12 of the supporting stat ement (in the
ICR) summariz ing the permitting authority burden for particular GHG-related permitting activities. Table 12 in the ICR shows certain incremental burden assumptions for certain activities related to GHG permitting program costs in the form of an hourly burden for each activity that a permitting authorit y may process. Based on observations regarding permitting activities since the Tailoring Rule, we have adapted these ass umptions for the purposes of this option and included certain ac tivities with a somewhat different description than we used in th e table in the ICR in an attempt to more accurately reflect th e types of permitting activities that have occurred in the GHG permit program. In addition, by making these clarifying ch anges, we are trying to more closely track the language in the CA A and parts 70 and 71 regarding the specific of the permit proc ess. We are Deleted: ¶

Deleted: W

Deleted: es

Deleted:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 327 of 373 proposing to include three general activities in th is proposed option: 1) “ GHG completeness determination (for initial permits or for updated applications)” at 43 hours, 2) “ GHG evaluation

for a modification or related permit action ” at 7 hours, and 3)

“GHG evaluation at permit renewal” at 10 burden hours. 290 The GHG cost adjustment for the presumptive fee would be ca lculated under this approach by multiplying the burden hours for each activity by the cost of staff time (in $ per hour), including

290 A completeness determination is the first step perf ormed by the permitting authority once a permit application is received. This step is generally more time consuming for an i nitial permit application compared to other permit applications b ecause this is the initial evaluation leading to the drafting a nd issuance of the permit for the first time. Because GHG permi tting is in the early stages of implementation and EPA is in th e early stages of issuing new applicable requirements for G HGs, we believe permitting authorities will experience addi tional burdens related to GHGs as part of this initial com pleteness determination. Thus, the first item, “GHG completen ess determination (for initial permit or update applica tion)” reflects these additional burdens for completeness determinations related to GHGs. This item would als o cover subsequent application updates related to an initia l application. See, e.g., 40 CFR 70.5(a)(2). The seco nd item, “GHG evaluation for a permit modification or related per mitting action” applies where a permitting authority undert akes an evaluation of whether a permit modification involve s any GHGrelated requirements. This might also occur, for ex ample, where a synthetic or true minor application is submitted and the permitting authority needs to undertake a GHG relat ed analysis to determine if it affects the existing title V per mit. The third item, “GHG evaluation at permit renewal” appl ies where the permitting authority receives a renewal application that is not coupled with any facility modifications. The EPA su ggests this language because it is more closely tied to the spe cific work to be performed by permitting authorities consistent w ith statutory and regulatory obligations. Deleted: new

Deleted: at the facility or a permit that requires a GHG evaluation Deleted: evaluate Deleted:

Deleted: The first item, “completeness determination” is essentially the first step performed by the permitting authority once an application is submitted. See, e.g., 40 CFR 70.5(a)(2). The second item, “modification at the facility or a permit that requires a GHG evaluation” applies where a modification is occurring at the facility and the permitting authority is obligated to undertake an analysis of whether such modification triggered any GHG related requirements. This might occur, for example, where a synthetic or true minor application is submitted and the permitting authority needs to undertake a GHG related analysis. The third item, “evaluate GHG at permit renewal” applies where the permitting authority receives a renewal application that is not coupled with any facility modifications. EPA suggests this language because it is more closely tied to the specific work to be performed by permitting authorities consistent with statutory and regulatory obligations.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 328 of 373 wages, benefits, and overhead, as determined by the state for the particular activities undertaken. We also solicit comment on the specific burden hours we propose for these GHG- related activities. The proposed burden hours for the three activities above were not directly discussed in the ICR or dir ectly subject to public comment in that context. We believe this proposal would benefit from state input on the burden hour a ssumptions

for the activities identified and we solicit commen t the burden hour assumptions and on additional GHG-related perm itting

activities that should be added to the list. We are also co-proposing an alternative option und er which we would increase the fee rate used in the presumpt ive minimum calculation for each regulated air pollutant, exclu ding GHGs. This option would rely primarily on data concerning the state burdens of permitting GHGs through step 3 of the ta iloring rule found in the Information Collection Request (ICR) f or part 70. This suggests that when looking at Tailoring Rule b urden in isolation, that GHG permitting increases permitting authority burden by about 7 percent above the baseline burden 291 , which

291 The baseline costs in the supporting statement for the ICR were the costs of permitting looking at all activities e xcept for those related to the GHG tailoring rule and certain other recent rule changes. Table 14 of the supporting statement shows a permitting authority burden of 102,122 hours for im plementing the GHG tailoring rule and 1,414,293 hours of basel ine Deleted: ¶

Deleted: s***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 329 of 373 would be multiplied by the presumptive minimum fee rate in effect to calculate the revise presumptive fee rate to account for GHG. Under this approach, the new presumptive m inimum fee effective for the current period would be $50.00 pe r ton for each regulated pollutant (for presumptive fee calcu lation) 292

. Several states suggested an approach similar to thi s in comments on the Tailoring Rule, however, their comments assu med we would not be exempting GHGs from the definition of regula ted pollutants (for presumptive fee calculation), as we are proposing today. We solicit comment on the appropriateness of the 7 percent fee increase for the presumptive mini mum fee we propose to account for the GHG permitting costs for permitting authorities under this alternative option. We are p articularly interested in state input on whether this level sho uld be higher or lower than we propose. The two options we co-propose for adjusting the pre sumptive minimum fee to account for the costs of GHG permitt ing are similar in that we believe they would both result i n about the

permitting authority burden, and Table 15 shows a p ermitting authority cost of $5.5 million for implementing the GHG tailoring rule and $76.4 million for the baseline p ermitting program. 292 At the current rate for part 70 of $46.73, this wo uld result in a GHG fee adjustment of about $3.27, or a new ra te of $50.00 per ton for each regulated pollutant (for presumpti ve fee calculation). Deleted:

Deleted: Table 14 shows 102,122 hours for GHG tailoring rule divided by 1,414,293 hours baseline permitting authority cost (unadjusted) and Table 15 shows $5.5 million for GHG tailoring rule divided by $76.4 million for baseline permitting authority cost (unadjusted).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 330 of 373 same amount of additional fee revenue being collect ed. For the first option, we took the assumptions approved into the ICR and adapted them somewhat so that they more accurately reflect the actual implementation experience of permitting auth orities related to GHGs. On the second, alternative option, we used the

ICR estimate to determine the relative contribution of GHG tailoring rule costs to the total costs of title V permitting

and we assume these relative costs will hold true i n any particular state that uses the presumptive minimum fee approach to demonstrating fee adequacy. The two options diff er in that the first option calculates the GHG adjustment to t he presumptive fee minimum by determining the number o f actual GHGrelated activities they have performed for a period , while the second option calculates the GHG adjustment by incr easing the presumptive fee rate for non–GHG pollutants by a se t ratio to reflect average expected costs. The first approach requires a state to track the number of activities of these ty pes it is performing and is thus more burdensome to calculate , although it may more accurately reflect the actual costs. The s econd approach is simpler to calculate and predictable bu t is less directly tied to actual implementation experience i n a particular state. Comment [A134]: This paragraph is my response to the OMB comment asking us to compare the two options.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 331 of 373

We also solicit comment on whether we need to revi se the presumptive minimum calculation provisions to accou nt for GHGs costs if we exempt GHGs from the calculation of the presumptive minimum fee. The basis for this option would be tha t because most GHG sources that would be subject to title V p ermitting,

whether due to GHGs or due for other reasons under the proposed NSPS and applicability provisions of the permitting rules (see 40 CFR 70.3 and 71.3) would have actual emissions o f other regulated air pollutants subject to fees, and thus the cost of permitting these sources may be adequately accounte d for without charging any additional fees specifically based on emissions of GHGs. We also note that support for this approach c an be found in the current OMB-approved ICR for part 70, tables 14, 15 and 18, where the cost of permitting for permitting aut horities is summarized, considering the effects of several rece nt EPA rulemakings that were conducted since the last ICR update. This proposal does not directly affect those states that do not rely on the presumptive minimum fee approach to show fee adequacy ; however , non-presumptive fee states are still required to charge sufficient fees to recover all reasonable direct and indirect program costs. Part 70 allows the EPA to r eview state fee programs at any time to determine if they are c ollecting
fees sufficient to cover their costs, whether or no t states rely Deleted: (those that charge more than the presumptive minimum fee),***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 332 of 373 on the presumptively minimum fee approach. We are n ot requiring any additional detailed fee submittals from states at this time based on these proposed changes. Some states may conclude that they wish to revise t heir part 70 programs in response to this proposal eithe r to revise their state fee schedules to prevent any possible c ollection of excessive fees (e.g., if they require any regulated pollutant subject to a section 111 standard to pay a fee) or to charge additional fees to sources because their presumptiv e minimum fee target has increased. We solicit comment on the mos t expeditious means for EPA to approve title V program revisions across the states once this proposal is finalized.

T here may be other viable options consistent with st atutory and regulatory authority, principles, and concerns, in addition

to those we have described in this proposal. For example, s tates have previously commented on establishing a separate, lower presumptive fee per ton of GHG emissions). The EPA invites states, local, and/or Tribal authorities to provide more refined data and/or information surrounding the unique cost s associated with permitting GHG sources under this proposed rul e, and other fee options such data supports. Notably, the regula tory text included today represents only one option on which comments are

solicited. The EPA is providing full regulatory text only for Deleted: In addition to the options for which comment is solicited above, t

Deleted: that

Deleted:

Deleted: an***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 333 of 373 this option because it represents the most novel ap proach. The EPA is also soliciting comment on other viable approaches

described herein , but considers the discussion provided herein to provide an adequate basis for public comment

. The EPA notes that the final rule may be based on any of the appr oaches described in the preamble.

c. Revisions to the part 71 fee schedule As part of the promulgation of the final part 71 ru le, the EPA performed a detailed analysis of the costs of d eveloping and implementing the program and reviewed the inventory of emissions of regulated pollutants (for fee calculation) to de termine the appropriate emission fee that would be sufficient t o recover all direct and indirect programs costs – we set the fee at $32 per ton, adjusted for inflation, times the emissions of regulated pollutant (for fee calculation). ( See Federal Operating Programs Fees, Revised Cost Analysis, February 1996; legacy docket A-93-
51, document number II-A-3.) For part 71, we also propose to exempt GHGs from th e definition of regulated pollutant (for fee calculat ion), which is similar to the definition of regulated pollutant s (for presumptive fee calculation) used in part 70, for t he same reasons we have explained for part 70. In addition, for the same reasons we explained for part 70, we are proposing two options Deleted: options

Deleted: EPA anticipates that sufficient information is provided in this preamble and the included regulatory text, to support EPA finalizing regulatory text on another option.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 334 of 373 for revising the fee schedule of 40 CFR 71.9(c) to ensure that we continue to recover sufficient fees to fully fun d the part 71 GHG permitting program. The bases for the options w ere described in more detail earlier in this proposal with respec t to part 70 proposals and those also apply here to part 71. First, the EPA (or delegate agency) burden hour as sumptions we propose for each GHG-related permitting activity under part 71 are the same as we are proposing for states unde r the presumptive minimum fee provisions of part 70. 293 This option would rely on the following information. The labor rate assumption we propose for the EPA (or delegate agen cy) staff time under part 71 is the average hourly rate we as sumed in the supporting statement for the recent part 71 ICR ren ewal of $52 per hour in 2011 dollars, including wages, benefits and overhead costs. We propose to determine the GHG fee adjustme nt for each GHG permitting program activity by multiplying the burden hour assumption we propose by the EPA (or delegate agenc y) labor rate we propose. Thus, for example, we propose a set fee to be paid

293 See the supporting statement for the ICR renewal f or part 71 approved by the Office of Management and Budget on June 13, 2012 for the 36 month period of June 30, 2012 through Ma y 31, 2015. The ICR renewal for part 71 is identified as EPA IC R number 1713.10 and the ICR for part 71 has been assigned O MB control number 2060-0336. The assumptions of this part 71 I CR renewal for GHG burden are identical to those used for the part 70 ICR. See Table 12 of the part 71 supporting statement. Deleted:

Deleted: ¶***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 335 of 373 by sources for each “completeness determination (fo r new permit or updated application” of $364 (7 hours times $52 per hour for the current period). Also, we propose to charge, fo r simplicity
sake, the same set fees for GHG activities, whether performed by the EPA, a delegate agency, or by the EPA with cont ractor assistance. The appropriate set fees for all GHG pe rmitting program activities performed for the source would b e added to

the traditional fee that is determined based on emi ssions of each regulated pollutants (for fee calculation) to determine the

total fee for the source. The second option we propose for part 71 is to inc rease the emission fee by a modest amount for each regulated air pollutant, excluding GHGs. For simplicity sake, we propose to charge the same adjustment under this option that w e propose for part 70, or 7 percent, which would be multiplied by annual part

71 fee in effect to calculate the revise fee rate 294 . The rationale for this approach is described in more de tail earlier in this preamble during the part 70 discussion.

We also solicit comment on whether we could exclude GHG emissions from the calculation of the annual part 7 1 fee for reasons similar to those we explained for part 70 ( e.g., because

294 At the current rate for part 71 of $48.33, this wou ld result in a GHG fee adjustment of $3.38, or a new rate of $51 .71 per ton for each regulated pollutant (for fee calculation). Deleted: the

Deleted: 0***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 336 of 373 permitting costs can be covered by the existing par t 71 permit
fee). XI. Impacts of the Proposed Action A. What are the air impacts? As explained in the Regulatory Impact Analysis (RIA ) for this proposed rule, available data indicate that, e ven in the absence of this rule, existing and anticipated econ omic conditions will lead electricity generators to choo se new generation technologies that would meet the propose d standard

without installation of additional controls. Theref ore, based on the analysis presented in Chapter 5 of the RIA, the EPA projects that this proposed rule will result in negligible C O 2 emission changes, quantified benefits, and costs by 2022. 295
B. What are the energy impacts? This proposed rule is not anticipated to have a not able effect on the supply, distribution, or use of energ y. As previously stated, the EPA believes that electric p ower companies would choose to build new EGUs that compl y with the regulatory requirements of this proposal even in it s absence, because of existing and expected market conditions. In addition,

295 Conditions in the analysis year of 2022 are repres ented by a model year of 2020. Deleted: 2020.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 337 of 373 the EPA does not project any new coal-fired EGUs wi thout CCS to be built in the absence of this proposal. C. What are the compliance costs? The EPA believes this proposed rule will have no no table compliance costs associated with it, because electr ic power companies would be expected to build new EGUs that comply with the regulatory requirements of this proposal even i n the absence of the proposal, due to existing and expected marke t conditions. The EPA does not project any new coal-fired EGUs wi thout CCS to be built in the absence of the proposal. However, b ecause some companies may choose to construct coal or other fos sil fuelfired units, the RIA also analyzes project-level co sts of a unit with and without CCS, to quantify the potential cos t for a

fossil fuel-fired unit with CCS. D. How will this proposal contribute to climate cha nge protection? As previously explained, the special characteristic s of GHGs make it important to take initial steps to con trol the largest emissions categories without delay. Unlike most traditional air pollutants, GHGs persist in the atm osphere for time periods ranging from decades to millennia, dep ending on the gas. Fossil-fueled power plants emit more GHG emiss ions than any other stationary source category in the United Stat es, and among***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 338 of 373 new GHG emissions sources, the largest individual s ources are in this source category. This proposed rule will limit GHG emissions from ne w sources in this source category to levels consisten t with current projections for new fossil-fuel-fired gener ating units. The proposed rule will also serve as a necessary pr edicate for the regulation of existing sources within this sour ce category under CAA section 111(d). In these ways, the propos ed rule will contribute to the actions required to slow or rever se the accumulation of GHG concentrations in the atmospher e, which is necessary to protect against projected climate chan ge impacts

and risks. E. What are the economic and employment impacts? The EPA does not anticipate that this proposed rul e will

result in notable CO 2 emission changes, energy impacts, monetized benefits, costs, or economic impacts by 202 2 . The owners of newly built electric generating units will likely c hoose technologies that meet these standards even in the absence of this proposal due to existing economic conditions a s normal business practice. Likewise, the EPA believes this rule will not have any impacts on the price of electricity, emplo yment or labor markets, or the U.S. economy. F. What are the benefits of the proposed standards? Deleted: 0***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 339 of 373 As previously stated, the EPA does not anticipate that the power industry will incur compliance costs as a res ult of this proposal and we do not anticipate any notable CO 2 emission changes resulting from the rule. Therefore, there a re no direct

monetized climate benefits in terms of CO 2 emission reductions associated with this rulemaking. However, by clarif ying that in the future, new coal-fired power plants will be req uired to meet a particular performance standard, this rulemaking reduces uncertainty and may enhance the prospects for new c oal-fired generation and the deployment of CCS, and thereby p romote energy diversity.
XII. Request for Comments We request comments on all aspects of the proposed rulemaking including the RIA. All significant comme nts received will be considered in the development and selection of the final rule. We specifically solicit comments on additiona l issues

under consideration as described below.

Measurement. We are requesting comment on requiring the use the following procedures that increase the precisio n of GHG

measurements: a. EPA Method 2F of 40 CFR part 60 for flow rate measurement during the relative accuracy test audit and performance testing. Method 2F provides velocity da ta for three***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 340 of 373 dimensions and provides measurements more represent ative of actual gas flow rates than EPA Method 2 or 2G of 40 CFR part 60. b. EPA Method 2H of 40 CFR part 60 or Conditional T est
Method (CTM)-041 (see: http://www.epa.gov/airmarkets/emissions/docs/square -ducts-walleffects-test-method-ctm-041.pdf) to account for wal l effects for stack gas flow rate calculations during CEMS relati ve accuracy determinations and for performance testing. c. EPA Method 4 of 40 CFR part 60 to determine mois ture for flow rate during CEMS relative accuracy determinati ons and for performance test calculations. d. EPA Method 3A of 40 CFR part 60 for CO 2 concentration measurement and for molecular weight determination during CEMS relative accuracy determinations or for performance testing. e. An ambient air argon concentration of 0.93 perce nt [1] and a molecular weight of 39.9 lb/lb-mol in calculating the dry gas molecular weight. f. A value for pi of 3.14159 when calculating the effective

area for circular stacks. g. A daily calibration drift cap no greater than 0. 3
percent CO 2 for CO 2 CEMS.

[1] http://www.physicalgeography.net/fundamentals/7a.h tml. Deleted: on

Deleted: 3.41159***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 341 of 373 h. A maximum relative accuracy specification of 2.5 percent

for both CO 2 and flow rate measurement CEMS. i. Method 3B of 40 CFR part 60 in addition to Metho d 3A,

for CO 2 concentration measurement and for molecular weight determination during CEMS relative accuracy determi nations or for performance testing.

Coal refuse. Due to the multiple environmental benefits of remediating coal refuse piles, we requested comment in the previous proposal on subcategorizing EGUs that burn over 75 percent coal refuse on an annual basis. Multiple co mmenters on the previous proposal supported the exemption citin g the environmental benefits of remediating coal refuse p iles. Other

c ommenters on the previous proposal disagreed with a ny exemption, specifically c iting the N 2 O emissions from fluidized

bed boilers. Due to the environmental benefits of r emediating coal refuse piles, the limited amount of coal refus e, and the

fact that a new coal refuse-fired EGU would have to be located in close proximity to the coal refuse pile, we are continuing to consider establishing a subcategory for coal refuse -fired EGUs and are requesting additional comments. Specificall y, we are requesting additional information on the net enviro nmental benefits of coal refuse-fired EGUs, and in the even t we do establish a coal refuse-fired subcategory, what the emissions Deleted: C Deleted: also Deleted: s***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 342 of 373
standard for that subcategory should be. One commen ter on the previous proposal stated that existing coal refuse piles are naturally combusting at a rate of 0.3 percent annua lly. We are requesting comment on assuming this rate of natural combustion and the proper approach to accounting for naturally occurring emissions from coal refuse piles. Compressed Air Energy Storage (CAES) Facilities. The EPA is considering and requesting comment on exempting sta tionary combustion turbines at compressed air energy storag e facilities

from the CO 2 emissions standard. CAES technology involves two steps. Air is compressed by electric motor driven c ompressors during off-peak electricity demand hours and stored in a storage media (e.g., an underground cavern). Electricity is then generated during peak electricity demand periods by releasing the high

‐ pressure air, heating the air with natural gas, and expanding it through sequential turbines (expanders ), which drive an electrical generator. Since natural gas is combusted in the stationary combustion turbine, a new CAES facil ity meeting the general applicability requirements would have t o comply with
an emissions standard. However, the use of stored e nergy complicates determining compliance with the propose d emission standards. Since we only expect a limited number of new CAES facilities, we have concluded that the new source review***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 343 of 373 program is the appropriate mechanism to establish s ite specific GHG requirements for such sources. District Energy. Even though with the proposed definition of net-electric output it is unlikely that a distri ct energy system would be subject to an emissions standard, w e are considering and requesting comment on an appropriat e method to recognize the environmental benefit of district ene rgy systems. The steam or hot water distribution system of a dis trict energy system located in urban areas, college and universi ty campuses, hospitals, airports, and military installations eli minates the need for multiple, smaller boilers at individual bu ildings. A central facility typically has superior emission co ntrols and consists of a few larger boilers facilitating more efficient operation than numerous separate smaller individual boilers.
However, when the hot water or steam is distributed , approximately two to three percent of the thermal e nergy in the water and six to nine percent of the thermal energy in the steam is lost, reducing the net efficiency advantage. We are requesting comment on whether it is appropriate to divide the thermal output from district energy systems by a fa ctor (i.e.,
0.95 or 0.90) that would account for the net effici ency benefits of district energy systems. This approach would be similar to the proposed approach to how the electric output fo r CHP is***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 344 of 373 considered when determining regulatory compliance a nd is consistent with the approach in the proposed amendm ents to the combustion turbine NSPS (77 FR 52554). We request t hat comments include technical analysis of the net benefits in s upport of any

conclusions. Emergency conditions . We are requesting comment on excluding electricity generated as a result of a gr id emergency declared by the Regional Transmission Organizations (RTO), Independent System Operators (ISO) or control area Administrator from counting as net sales when determining applica bility as an

EGU. For example, under this approach, if grid voltage d rops below acceptable levels and the affected facility i s the only facility with available capacity, then electricity generated during this period would not count for applicabilit y purposes. While the proposed 3 year average electric sales ap plicability provides significant flexibility for simple cycle t urbines, we are considering including the emergency conditions exemption to allow facilities designed with the intent to sell l ess than 1/3 of their potential electric output to continue to g enerate electricity during a grid emergency without such ge neration counting towards the 1/3 sales applicability criter ion. In the original electric utility NSPS rulemaking, the EPA recognized that emergency periods do occur from unplanned EGU outages, Deleted: (e.g., grid voltage would drop below acceptable levels and the affected facility is the only facility with additional available capacity)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 345 of 373 transmission outages or surging customer demand loa ds. Such

occur r ences may require that all available operable EGUs interconnected to the electrical grid supply power to the grid. Provisions were added to 40 CFR 60 subpart Da to ad dress emergency conditions when continued operation of an EGU with a malfunctioning flue gas desulfurization (FGD) syste m is acceptable and not considered a violation of the SO 2 emissions standard. These conditions require that all availab le capacity from the power company’s other EGUs is being used a nd all available purchase power from interconnected power companies is being obtained. In this case, the EPA concluded tha t the broader benefits of operating the power plant with the malf unctioning FGD system to generate electrical power during emer gency conditions in order to ensure uninterrupted electri city supply to the public outweigh any adverse impacts from a s hort-term

increase in SO 2 emission to the atmosphere from the power plant. Initial Design Efficiency Test. We are considering and requesting comment on requiring an initial performa nce test for stationary combustion turbines in addition to the 1 2-operatingmonth rolling average standard. Requiring an initia l compliance test that is numerically more stringent than the an nual standard for new combined cycle facilities would insure that the most efficient stationary combustion turbines are instal led. The less***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 346 of 373 stringent 12-month rolling average standard would b e set at a level that would take into account actual operating conditions. Integrated Equipment. The proposed affected facility definition includes the stationary combustion turbi ne/steam generating unit “plus any integrated equipment that provides electricity or useful thermal output.” We are consi dering and requesting comment on also including in the definition of the affected facility co-located non-emitting energy generation equipment that is not integrated into the operation of the affected facility. This approach would provide addi tional flexibility, lower compliance costs, and recognize the environmental benefit of non-emitting sources of el ectricity and not limit options to solar thermal feedwater heatin g. The definition would include the additional language “o r co-located non-emitting energy generation included in the faci lity operating permit.” This would permit the use of co- located photovoltaic solar power, wind turbines, and other non-emitting energy generation as means for achieving compliance with the emission standards. Since integrated solar thermal feedwater heating is primarily a feasible option only for facilities that operate daily, this approach would expand options f or more intermittent intermediate load generators to effici ently integrate non-emitting energy generation into their design. Deleted: in the definition of the affected facility

Deleted: only***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 347 of 373
Net-output-based standards. We are considering and requesting comment on requiring the use or adding an optional net-output based standard for each subcategory. As described in

the original proposal for this rulemaking , net output is the combination of the gross electrical output of the e lectric generating unit minus the parasitic (i.e., auxiliary) power requirements. A parasitic load for an electric gene rating unit is any of the loads or devices powered by electrici ty, steam, hot water, or directly by the gross output of the e lectric generating unit that does not contribute electrical , mechanical,
or thermal output. In general, less than 7.5 percen t of non-IGCC and non-CCS coal-fired station power output, approx imately 15 percent of non-C C S IGCC-based coal-fired station power output and about 2.5 percent of non-CCS combined cycle sta tion power output is used internally by parasitic energy deman ds, but the amount of these parasitic loads vary from source to source. Reasons for using net output include (1) recognizin g the efficiency gains of selecting EGU designs and contr ol equipment that require less auxiliary power, (2) selecting fu els that require less emissions control equipment, and (3) r ecognizing the environmental benefit of higher efficiency moto rs, pumps,
and fans. While the EPA has concluded that the net power supplied to the end user is a better indicator of e nvironmental Deleted: previous

Deleted: S***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 348 of 373
performance than gross output from the power produc er, we only have CEMS emissions data reported on a gross output basis. In addition, for facilities that coproduce chemicals a nd other useful byproducts, accurate accounting of the paras itic loads could be problematic. The optional net-output based standard would have t he most impact for non-IGCC-based coal-fired EGUs. While th e net output based emissions rate for all non-CCS coal-fired gen eration is similar, IGCC facilities have substantially larger parasitic loads and correspondingly lower gross emissions rat es. Using a strictly gross-output based standard requires that a coal-fired PC or CFB EGU capture approximately 60 percent more CO 2 than a

coal-fired IGCC EGU. The net-output based CO 2 emissions rate for steam generating units and IGCC facilities correspo nding to an
emissions rate of 1,100 lb CO 2 /MWh on a gross basis would be
1,400 lb CO 2 /MWh. A 1,400 lb CO 2 /MWh-net standard would require
similar amount of CCS for both IGCC and SCPC EGUs, 25 and 28 percent respectively. The range of net-output based emission rates being considered that corresponds to the gros s outputbased limits is 1,100 to 1,500 lb CO 2 /MWh-net, rounded to 2 significant digits. Requiring or including an optio nal netoutput based standard would provide more operationa l flexibility and expand the technologies options available to co mply with the Comment [A135]: It would be helpful if EPA could explain why it only has CEMS emission data reported on a gross output basis and why the agency is not able to move to a more optimal parasitic accounting approach. EPA: We are still considering this comment

Deleted:

Deleted: optional***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 349 of 373

standard for coal-fired PC and CFB EGUs which could impact our determination of BSER. For example, at an emissions limit of
1,500 lb CO 2 /MWh-net a PC or CFB could use integrated natural gas-fired combustion turbines or fuel cells for boi ler feedwater heating, supplemental steam production, or for preh eated air for the boiler to reduce the level of CCS required or a s an alternative to CCS. We request that commenters who support the use of net output-based standards address potential concerns about proving adequate technology development to be considered

BSER. The net-output based rate for stationary combustion

turbines corresponding to the proposed 1,100 lb CO 2 /MWh-gross and
1,100 lb CO 2 /MWh-gross would be 1,030 lb CO 2 /MWh -net and 1,130 lb

CO 2 /MWh -net for the large and small subcategor ies respectively. The corresponding range of net-output based emissio n rates being
considered is 970 to 1,130 lb CO 2 /MWh-net and 1,030 to 1,180 lb

CO 2 /MWh-net for the large and small combustion turbine subcategory respectively. However, the actual numer ical limits would not change in all circumstances using the con vention of 2 significant digits.

Other GHGs. Today’s proposed rule would require continuous

measurement of CO 2 from fossil fuel-fired EGUs. Other GHGs, such
as methane (CH 4 ) and nitrous oxide (N 2 O) are not included in the Deleted: y***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 350 of 373 proposed emission standards and are also not requir ed to be measured and reported by affected EGUs as part of t oday’s proposal, even though their 100-year global warming potential is 21 to 310 times greater than that of CO 2 , because their emissions from EGUs are believed to be negligible when compar ed to CO 2 emissions. We request comment on the appropriatenes s, technique, and frequency (one-time or periodic, but not contin uous) of measurement and reporting of CH 4 and N 2 O emissions from fossil fuel-fired EGUs as part of the proposed emissions s tandard. Receipt of this data would enhance understanding of total GHG emissions from EGUs and could aid future policy dec isions regarding whether these GHGs should be included in a revised emission standard, as part of 8-year NSPS review an d potential revision cycle.

Violations . We are proposing that the calculation of the number of daily violations within an averaging peri od be determined using the following methodology. If, for any 12- or 60-operating month period, the source’s emission ra te exceeds
the standard, t he number of daily violations in the 12-or 60- operating-month averaging period would be the numbe r of operating days in that period. However, if a violat ion occurs directly following the previous 12-operating-month or 60- operating-month averaging period, daily violations would not Deleted: T Deleted: a Deleted: operating-month

Deleted: averaging***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 351 of 373 double count operating days that were determined as violations under the previous averaging period. For example, assume that a facility operat es 10 days out of each month for 12 months from January 1, Year 1 to December 31, Year 1, and exceeds the

emissions standard during that 12-month period . The violation for this January-December Year 1 period would constitute 120 daily violations. If the facility operated 20 days the following

month , which would be January, Year 2, and was still in excess

of the emissions standard over the period from February, Year 1 to January, Year 2, then 20 additional daily violations would

result , for a total of 140 daily violations. We are reques ting comment on this determination of daily violations for owners/operators that exceeds either a 12-operating -month or 60- operating-month standard. XIII. Statutory and Executive Order Reviews A. Executive Order 12866, Regulatory Planning and R eview, and Executive Order 13563, Improving Regulation and Reg ulatory

Review
Under Executive Order (EO) 12866 (58 FR 51,735, Oc tober 4, 1993), this action is a “significant regulatory act ion” because it “raises novel legal or policy issues arising out of legal mandates”. Accordingly, the EPA submitted this acti on to the Office of Management and Budget (OMB) for review un der Executive Deleted: if

Deleted: ions

Deleted: initial

Deleted: ,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 352 of 373
Orders 12866 and 13563 (76 FR 3821, January 21, 201 1) and any changes made in response to OMB recommendations hav e been

documented in the docket for this action. In additi on, the EPA prepared an analysis of the potential costs and ben efits associated with this action. This analysis is conta ined in the Regulatory Impact Analysis for the Standards of Per formance for

Greenhouse Gas Emissions for New Fossil Fuel-Fired Electric Utility Steam Generating Units and Stationary Combu stion

Turbines.

The EPA believes this rule will have no notabl e compliance costs associated with it over a range of likely sen sitivity conditions because electric power companies would c hoose to build new EGUs that comply with the regulatory requ irements of this proposal even in the absence of the proposal, because of existing and expected market conditions. (See the R IA for further discussion of sensitivities). The EPA does not project any new coal-fired EGUs without CCS to be built in the absence of this proposal. However, because some companies m ay choose to construct coal or other fossil fuel-fired units, th e RIA also analyzes project-level costs of a unit with and wit hout CCS, to quantify the potential cost for a fossil fuel-fired unit with

CCS. B. Paperwork Reduction Act***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 353 of 373 The information collection requirements in this pr oposed rule have been submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Red uction Act , 44 U.S.C. 3501 et seq . The Information Collection Request (ICR) document prepared by the EPA has been assigned the EPA ICR

number 2465.01. This proposed action would impose minimal new info rmation collection burden on affected sources beyond what t hose sources would already be subject to under the authorities o f CAA parts 75 and 98. OMB has previously approved the informat ion collection requirements contained in the existing p art 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) und er the provisions of the Paperwork Reduction Act , 44 U.S.C. 3501 et

seq . and has assigned OMB control numbers 2060-0626 an d 2060- 0629, respectively. Apart from certain reporting costs based on requirements in the NSPS General Provisions (40 CFR part 60, subpart A), which are mandatory for all owners/oper ators subject
to CAA section 111 national emission standards, the re are no new information collection costs, as the information re quired by this proposed rule is already collected and reporte d by other regulatory programs. The recordkeeping and reportin g requirements are specifically authorized by CAA sec tion 114 (42
U.S.C. 7414). All information submitted to the EPA pursuant to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 354 of 373 the recordkeeping and reporting requirements for wh ich a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B. The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory r equirements of this proposal because of existing and expected m arket conditions. The EPA does not project any new coal-f ired EGUs that commence construction after this proposal to c ommence operation over the three-year period covered by thi s ICR. We
estimate that 17 new affected NGCC units would comm ence operation during that time period. As a result of t his proposal, those units would be required to prepare a summary report, which includes reporting of excess emissions and downtime , every six

months. When a malfunction occurs, sources must report them according to the applicable reporting requirements of 40 CFR part 60, subpart Da or subpart KKKK. An affirmative defense to civil penalties for exceedances of emission limits that are caused by malfunctions is available to a source if it can demonstrate that certain criteria and requirements are
satisfied. The criteria ensure that the affirmative defense is available only where the event that causes an excee dance of the

emission limit meets the narrow definition of malfu nction***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 355 of 373 (sudden, infrequent, not reasonably preventable, an d not caused by poor maintenance or careless operation) and wher e the source took necessary actions to minimize emissions. In ad dition, the source must meet certain notification and reporting requirements. For example, the source must prepare a written root cause analysis and submit a written report to the Administrator documenting that it has met the condi tions and requirements for assertion of the affirmative defen se. To provide the public with an estimate of the relat ive magnitude of the burden associated with an assertio n of affirmative defense, the EPA has estimated what the notification, recordkeeping, and reporting requirem ents
associated with the assertion of the affirmative de fense might entail. The EPA’s estimate for the required notific ation, reports, and records, including the root cause anal ysis, associated with a single incident totals approximat ely totals $3,141, and is based on the time and effort require d of a source to review relevant data, interview plant employees, and document the events surrounding a malfunction that has cause d an

exceedance of an emission limit. The estimate also includes time to produce and retain the record and reports for su bmission to the EPA. The EPA provides this illustrative estimat e of this burden, because these costs are only incurred if th ere has been***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 356 of 373 a violation, and a source chooses to take advantage of the

affirmative defense. Given the variety of circumstances under which malf unctions could occur, as well as differences among sources' operation and maintenance practices, we cannot reliably predict t he severity and frequency of malfunction-related excess emissio ns events for a particular source. It is important to note that t he EPA has no basis currently for estimating the number of malfun ctions that would qualify for an affirmative defense. Current h istorical records would be an inappropriate basis, as this ru le applies only to sources built in the future. Of the number of excess emissions events that may be reported by source ope rators, only a small number would be expected to result from a m alfunction, and only a subset of excess emissions caused by mal functions would result in the source choosing to assert an af firmative
defense. Thus, we believe the number of instances i n which source operators might be expected to avail themsel ves of the affirmative defense will be extremely small. In fac t, we
estimate that there will be no such occurrences for any new sources subject to 40 CFR part 60, subpart Da or su bpart KKKK over the three-year period covered by this ICR. We expect to gather information on such events in the future, an d will revise

this estimate as better information becomes availab le.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 357 of 373

The annual information collection burden for this collection consists only of reporting burden as exp lained above. The reporting burden for this collection (averaged over the first three years after the effective date of the s tandards) is estimated to be $15,570 and 396 labor hours. This e stimate includes semi-annual summary reports which include reporting of

excess emissions and downtime. All burden estimates are in 2010 dollars. Average burden hours per response are esti mated to be 16.5 hours. The total number of respondents over th e three-year ICR period is estimated to be 36. Burden is defined at 5 CFR
1320.3(b). An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are lis ted in 40 CFR
part 9. To comment on the Agency's need for this informati on, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, the EPA h as established a public docket for this rule, which in cludes this
ICR, under Docket ID number EPA-HQ-OAR-2013-0495. S ubmit any

comments related to the ICR to the EPA and OMB. See ADDRESSES section at the beginning of this notice for where t o submit***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 358 of 373

comments to the EPA. Send comments to OMB at the Of fice of Information and Regulatory Affairs, Office of Manag ement and Budget, 725 17th Street, NW, Washington, DC 20503, Attention: Desk Officer for the EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after [INSERT
DATE OF PUBLICATION IN THE FEDERAL REGISTER], a com ment to OMB is best assured of having its full effect if OMB re ceives it by
[INSERT DATE 30 DAYS AFTER PUBLICATION IN THE FEDER AL REGISTER]. The final rule will respond to any OMB or public co mments on the information collection requirements contained in th is proposal. C. Regulatory Flexibility Act as Amended by the Sma ll Business Regulatory Enforcement Fairness Act of 1996, 5 U.S. C. et seq. The Regulatory Flexibility Act (RFA) generally requ ires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requiremen ts under the Administrative Procedure Act or any other statute u nless the agency certifies that the rule will not have a sign ificant economic impact on a substantial number of small en tities. Small entities include small businesses, small organizati ons, and small governmental jurisdictions. For purposes of assessing the impacts of this rule on small entities, small entity is defined as:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 359 of 373 (1) A small business that is defined by the SBA’s regulations at 13 CFR 121.201 (for the electric pow er generation industry, the small business size standard is an ul timate parent entity defined as having a total electric output of 4 million MWh or less in the previous fiscal year. The NAICS codes for the affected industry are in Table 5 below); (2) A small governmental jurisdiction that is a gov ernment of a city, county, town, school district or special district with a population of less than 50,000; and (3) A small organization that is any not-for-profit enterprise which is independently owned and operate d and is not

dominant in its field. Table 5. Potentially Regulated Categories and Entit ies a

Category NAICS

Code Examples of Potentially Regulated Entities

Industry 221112 Fossil fuel electric power generating units.

Federal Government 221112 b Fossil fuel electric power generating units owned by the federal government.

State/Local Government 221112 b Fossil fuel electric power generating units owned by municipalities.

Tribal Government 921150 Fossil fuel electric power generating units in Indian Country.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 360 of 373

a Include NAICS categories for source categories tha t own and operate electric power generating units (includes b oilers and stationary combined cycle combustion turbines). b Federal, state, or local government-owned and oper ated establishments are classified according to the acti vity in which they are engaged. After considering the economic impacts of this prop osed rule on small entities, I certify that this action will not have a significant economic impact on a substantial numb er of small

entities. We do not include an analysis of the illustrative i mpacts on small entities that may result from implementati on of this proposed rule because we do not anticipate any comp liance costs over a range of likely sensitivity conditions as a result of this proposal. Thus the cost-to-sales ratios for an y affected small entity would be zero costs as compared to ann ual sales revenue for the entity. The EPA believes that elect ric power companies will choose to build new EGUs that comply with the regulatory requirements of this proposal because of existing and expected market conditions. (See the RIA for furthe r discussion of sensitivities). The EPA does not project any new coal-fired EGUs without CCS to be built. Accordingly, there ar e no anticipated economic impacts as a result of this pr oposal. Nevertheless, the EPA is aware that there is substa ntial interest in this rule among small entities (municip al and rural electric cooperatives). In light of this interest, prior to the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 361 of 373 April 13, 2012 proposal (77 FR 22392), the EPA dete rmined to seek early input from representatives of small enti ties while formulating the provisions of the proposed regulati on. Such

outreach is also consistent with the President’s Ja nuary 18, 2011 Memorandum on Regulatory Flexibility, Small Bu siness, and Job Creation, which emphasizes the important role s mall businesses play in the American economy. This proce ss has enabled the EPA to hear directly from these represe ntatives, at a very preliminary stage, about how it should appro ach the complex question of how to apply Section 111 of the CAA to the regulation of GHGs from these source categories. Th e EPA’s outreach regarded planned actions for new and exist ing sources, but only new sources would be affected by this prop osed action. The EPA conducted an initial outreach meeting with small entity representatives on April 6, 2011. The purpos e of the meeting was to provide an overview of recent EPA pr oposals impacting the power sector. Specifically, overviews of the Transport Rule, the Mercury and Air Toxics Standard s, and the Clean Water Act 316(b) Rule proposals were presente d. The EPA conducted outreach with representatives fro m 20 various small entities that potentially would be af fected by this rule. The representatives included small entit y municipalities, cooperatives, and private investors . We***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 362 of 373 distributed outreach materials to the small entity representatives; these materials included backgroun d, an

overview of affected sources and GHG emissions from the power sector, an overview of CAA section 111, an assessme nt of CO 2 emissions control technologies, potential impacts o n small entities, and a summary of the listening sessions. We met with eight of the small entity representatives, as well as three participants from organizations representing power producers, on June 17, 2011, to discuss the outreach materials, p otential requirements of the rule, and regulatory areas wher e the EPA has discretion and could potentially provide flexibilit y. A second outreach meeting was conducted on July 13, 2011. We met with nine of the small entity representative s, as well as three participants from organizations representing power producers. During the second outreach meeting, vari ous small entity representatives and participants from organi zations representing power producers presented information regarding issues of concern with respect to development of st andards for GHG emissions. Specifically, topics suggested by th e small entity representatives and discussed included: boil ers with limited opportunities for efficiency improvements d ue to NSR complications for conventional pollutants; variance s per kilowatt-hour and in heat rates over monthly and an nual***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 363 of 373 operations; significance of plant age; legal issues ; importance of future determination of carbon neutrality of bio mass; and differences between municipal government electric u tilities and

other utilities. While formulating the provisions of this proposed regulation, the EPA also considered the input provi ded in the over 2.5 million public comments on the April 13, 2 012 proposed rule (77 FR 22392). We invite comments on all aspec ts of the proposal and its impacts, including potential adver se impacts,

on small entities.

D. Unfunded Mandates Reform Act of 1995 This proposed rule does not contain a federal manda te that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year. The EPA believes this propo sed rule will have no compliance costs associated with it over a range of likely sensitivity conditions because electric power compa nies will choose to build new EGUs that comply with the regul atory requirements of this proposal because of existing a nd expected market conditions. (See the RIA for further discuss ion of sensitivities). The EPA does not project any new co al-fired EGUs

without CCS to be built. Thus, this proposed rule is not subject to the requirements of sections 202 or 205 of UMRA.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 364 of 373 This proposed rule is also not subject to the requi rements of section 203 of UMRA because it contains no regul atory requirements that might significantly or uniquely a ffect small

governments. In light of the interest in this rule among governm ental entities, the EPA initiated consultations with gove rnmental entities prior to the April 13, 2012 proposal (77 F R 22392). The EPA invited the following 10 national organizations representing state and local elected officials to a meeting held on April 12, 2011, in Washington DC: 1) National Governors Assoc iation; 2) National Conference of State Legislatures, 3) Counc il of State Governments, 4) National League of Cities, 5) U.S. Conference of Mayors, 6) National Association of Counties, 7) Int ernational City/County Management Association, 8) National Ass ociation of Towns and Townships, 9) County Executives of Americ a, and 10) Environmental Council of States. These 10 organizat ions representing elected state and local officials have been identified by the EPA as the “Big 10” organizations appropriate to contact for purpose of consultation with elected officials. The purposes of the consultation were to provide ge neral background on the proposal, answer questions, and s olicit input from state/local governments. The EPA’s consultatio n regarded planned actions for new and existing sources, but o nly new***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 365 of 373 sources would be affected by this proposed action. During the meeting, officials asked clarifying ques tions regarding CAA section 111 requirements and efficien cy improvements that would reduce CO 2 emissions. In addition, they expressed concern with regard to the potential burd en associated with impacts on state and local entities that own/o perate affected utility boilers, as well as on state and l ocal entities with regard to implementing the rule. Subsequent to the April 12, 2011 meeting, the EPA received a letter from th e National Conference of State Legislatures. In that letter, t he National Conference of State Legislatures urged the EPA to e nsure that the choice of regulatory options maximizes benefit and minimizes implementation and compliance costs on state and lo cal governments; to pay particular attention to options that would provide states with as much flexibility as possible ; and to take into consideration the constraints of the state leg islative

calendars and ensure that sufficient time is allowe d for state actions necessary to come into compliance. While formulating the provisions of this proposed regulation, the EPA also considered the input provi ded in the over 2.5 million public comments on the April 13, 2 012 proposed
rule (77 FR 22392). E. Executive Order 13132, Federalism***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 366 of 373 This proposed action does not have federalism impli cations.

It would not have substantial direct effects on the States, on the relationship between the national government an d the States, or on the distribution of power and responsibilitie s among the various levels of government, as specified in EO 13 132. This proposed action would not impose substantial direct compliance costs on state or local governments, nor would it p reempt state law. Thus, Executive Order 13132 does not apply to this action. Prior to the April 13, 2012 proposal (77 FR 22392), the EPA consulted with state and local officials in the pro cess of developing the proposed rule to permit them to have meaningful and timely input into its development. The EPA’s co nsultation regarded planned actions for new and existing sourc es, but only new sources would be affected by this proposed acti on. The EPA met with 10 national organizations representing sta te and local elected officials to provide general background on the proposal, answer questions, and solicit input from state/loca l governments. The UMRA discussion in this preamble i ncludes a description of the consultation. While formulating the provisions of this proposed regulation, the EPA als o considered the input provided in the over 2.5 million public c omments on the April 13, 2012 proposed rule (77 FR 22392). In the spirit of EO 13132, and consistent with the EPA policy to pro mote***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 367 of 373

communications between the EPA and state and local governments, the EPA specifically solicits comment on this propo sed action

from state and local officials.
F. Executive Order 13175, Consultation and Coordina tion with

Indian Tribal Governments Subject to the EO 13175 (65 FR 67249, November 9, 2 000) the EPA may not issue a regulation that has tribal impl ications, that imposes substantial direct compliance costs, a nd that is not required by statute, unless the federal governm ent provides the funds necessary to pay the direct compliance co sts incurred by tribal governments, or the EPA consults with tri bal officials early in the process of developing the proposed reg ulation and develops a tribal summary impact statement. The EPA has concluded that this proposed action wou ld not have tribal implications. It would neither impose s ubstantial direct compliance costs on tribal governments, nor preempt Tribal law. This proposed rule would impose require ments on owners and operators of new EGUs. The EPA is aware of three coal-fired EGUs located in Indian Country but is no t aware of any EGUs owned or operated by tribal entities. The EPA notes that this proposal does not affect existing sources such as the three coal-fired EGUs located in Indian Country, bu t addresses

CO 2 emissions for new EGU sources only.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 368 of 373

Because the EPA is aware of Tribal interest in this proposed rule, prior to the April 13, 2012 proposal (77 FR 22392), the EPA offered consultation with tribal of ficials early in the process of developing the proposed regulatio n to permit them to have meaningful and timely input into its d evelopment. The EPA’s consultation regarded planned actions for new and existing sources, but only new sources would be aff ected by this proposed action.

Consultation letters were sent to 584 tribal leader s. The letters provided information regarding the EPA’s de velopment of NSPS and emission guidelines for EGUs and offered c onsultation. A consultation/outreach meeting was held on May 23, 2011, with the Forest County Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa Reservation, and the Leech L ake Band of Ojibwe. Other tribes participated in the call for i nformation gathering purposes. In this meeting, the EPA provid ed background

information on the GHG emission standards to be dev eloped and a summary of issues being explored by the Agency. Tri bes suggested that the EPA consider expanding coverage of the GHG standards to include combustion turbines, lowering the 250 MMBtu per hour heat input threshold so as to capture more EGUs, an d including

credit for use of renewables. The tribes were also interested in the scope of the emissions averaging being consider ed by the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 369 of 373 Agency (e.g., over what time period, across what un its). In addition, the EPA held a series of listening sessio ns on this proposed action. Tribes participated in a session o n February 17, 2011 with the state agencies, as well as in a s eparate session with tribes on April 20, 2011. While formulating the provisions of this proposed regulation, the EPA also considered the input provi ded in the over 2.5 million public comments on the April 13, 2 012 proposed
rule (77 FR 22392). The EPA will also hold additional meetings with tri bal

environmental staff to inform them of the content o f this proposal as well as provide additional consultation with tribal elected officials where it is appropriate. We speci fically solicit additional comment on this proposed rule fr om tribal

officials.
G. Executive Order 13045, Protection of Children fr om Environmental Health Risks and Safety Risks The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those regulatory actions that concer n health or safety risks, such that the analysis required under section 5- 501 of the Order has the potential to influence the regulation. This proposed action is not subject to EO 13045 because it is based solely on technology performance. The proposa l is not***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 370 of 373 expected to produce notable changes in emissions of greenhouse gases or other pollutants but does encourage the cu rrent trend towards cleaner generation, helping to protect air quality and children's health. The Agency recognizes that child ren are among the groups most vulnerable to climate change impact s and the public is invited to submit comments or identify pe er reviewed studies relevant to this proposal. H. Executive Order 13211, Actions Concerning Regula tions That Significantly Affect Energy Supply, Distribution, o r Use This proposed action is not a “significant energy a ction” as defined in EO 13211 (66 FR 28355 (May 22, 2001)) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. This propos ed action is not anticipated to have notable impacts on emission s, costs or energy supply decisions for the affected electric u tility industry. I. National Technology Transfer and Advancement Act
Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 15 U.S.C. 272 note) directs the EPA to use Voluntar y Census Standards in their regulatory and procurement activ ities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are tech nical standards (e.g., materials specifications, test met hods,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 371 of 373 sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA d irects the EPA to provide Congress, through annual reports to the OMB, with explanations when an agency does not use available and applicable VCS. This proposed rulemaking involves technical standar ds. The EPA cites the following standards in this proposed rule: D5287- 08 (Standard Practice for Automatic Sampling of Gas eous Fuels), D4057-06 (Standard Practice for Manual Sampling of Petroleum and
Petroleum Products), and D4177-95(2010) (Standard P ractice for Automatic Sampling of Petroleum and Petroleum Produ cts). The EPA is proposing use of Appendices B, D, F, and G to 40 CFR part 75; these Appendices contain standards that have alread y been

reviewed under the NTTAA. The EPA welcomes comments on this aspect of the pro posed rulemaking and, specifically, invites the public to identify potentially-applicable VCS and to explain why such standards

should be used in this action.

J. Executive Order 12898: Federal Actions to Addres s Environmental Justice in Minority Populations and L ow-Income Populations Executive Order 12898 (59 FR 7629, February 16, 19 94) establishes federal executive policy on environment al justice.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 372 of 373 Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make en vironmental justice part of their mission by identifying and ad dressing, as appropriate, disproportionately high and adverse hu man health or environmental effects of their programs, policies, and activities on minority populations and low-income p opulations in

the U.S. This proposed rule limits GHG emissions from new fo ssil fuel-fired EGUs by establishing national emission s tandards for

CO 2 . The EPA has determined that this proposed rule wo uld not result in disproportionately high and adverse human health or environmental effects on minority, low-income, and indigenous populations because it increases the level of envir onmental protection for all affected populations without hav ing any disproportionately high and adverse human health or environmental effects on any population, including any minority, low-income or indigenous populations.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Re lease During Review*** Page 341 of 373

List of Subjects in 40 CFR Part 60 Environmental protection, Administrative practice a nd procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.

___________________ Dated:[add signature date]

____________________ Gina McCarthy Administrator Deleted: [ Deleted: Insert name here] Deleted: [Acting?]Page 158: [1] Deleted MJOHNSON 8/28/2013 10:57: 00 AM



### C. Codification in the Code of Federal Regulations In the original proposal, the EPA proposed to creat e within 40 CFR part 60 a new subpart that would include GHG emission regulatory requirements for electric utility steam generating
units (i.e., boilers and IGCC units), whose convent ional pollutant regulatory requirements are codified unde r subpart Da; as well as stationary combustion turbines that gene rate electricity for sale and meet certain size and oper ational criteria, conventional pollutant regulatory require ments are codified under subpart KKKK. The EPA proposed to nu mber this newly created subpart as subpart TTTT. The EPA expl ained that combining the GHG regulatory requirements for those sources in TTTT was appropriate because the EPA was establishi ng the same limit for all those sources based on the same BSER, which was

NGCC. In today’s rulemaking, we propose different standar ds, based on different determinations of BSER, for (1) fossil fu el-fired utility boilers and IGCC units, and (2) natural gas -fired stationary combustion turbines. In this manner, in accordance with CAA § 111(b)(2), we are “distinguish[ing] amon g classes, types, and sizes within [the category of electric g enerating plants] of new sources for the purpose of establish ing ... [the

### new source performance] standards.” As noted, to a void

confusion, we are codifying the new GHG regulatory requirements in the same subparts – Da and KKKK – that include t he standards for conventional pollutants from those sources. Not e that this codification does not increase the stringency does not increase the stringency of the NSPS requirements for criteri a air pollutant emissions from those sources, and thus do es not affect the continued codification of those requirements in subparts Da and KKKK, as the case may be.

Page 179: [2] Deleted MJOHNSON 8/29/2013 11:42: 00 AM 

### F. Overall purposes The D.C. Circuit, during an extensive discussion of “standard of performance” in the 1981 decision in S ierra Club v.

Costle , identified and explained the purposes of section 111 and upheld a standard in part on grounds that it was co nsistent with those purposes. 1 

### Specifically, the D.C. Circuit identified “the essential purposes” of CAA § 111 – insofar as relev ant for present purposes -- as follows: 2

1 

### Sierra Club v. Costle, 658 F.2d 298, 338-340 (D.C. Cir. 1981). 2 

### In Sierra Club v. Costle , the Court noted that during the course of the 1977 CAAA, the House-Senate Conferenc e Committee added the percentage reduction requirement to the t ext of section 111, and, in the Conference Committee Repor t, explained that although EPA had the authority to establish a variable standard that reflected varying fuel characteristic s, EPA could do so only after “finding that such a [variable sta ndard] does not undermine the basic purposes of [section 111] a nd the other provisions of the [CAA]....” Sierra Club v. Costle , 657 F.2d at

### 1. The standards must not give a competitive advan tage to one State over another in attracting industry. 2. The standards must maximize the potential for l ongterm economic growth by reducing emissions as much as practicable. This would increase the amount of industrial growth possible within the limits set by the air quality standards. 3. The standards must to the extent practical forc e the installation of all the control technology that will ever be necessary on new plants at the time of construction when it is cheaper to install, thereby minimizing the need for retrofit in the future when air quality standards begin to set limits to growth. * * * * 6. The standards should be stringent in order to f orce the development of improved technology. 3



### 319 (citing H.R. Rep. No. 95-564, at 130 (1977)(Con f. Rep.), reprinted in 1977 U.S.C.C.A.N. 1077 (1977 Conference Report)). The Court noted that th ose purposes were set forth in the legislative history, and the Court went on to recite and then apply them. See Sierra Club v. Costle , 657 F.2d at 325, 338-40. The variable standard at issu e in that case is not directly relevant to the present rulema king. Regardless, the purposes of section 111, as describ ed by the Court, generally remain valid because they are asso ciated with provisions of section 111 that were valid under the 1977 CAAA, which, in relevant part, were not revised by the 19 90 CAAA. Moreover,If there is any question about that, then the purposes remain valid because the 1977 House Committee Repor t grounded them in the 1970 CAAA, see H.R. Rep. No. 95-294, 95th Cong., 1st Sess. 184-86 (1977) (1977 House Committee. Report.) , and the 1990 CAAA changes to the definition of standard of performance had the effect of reinstating the definition as it read under the 1970 CAAA (with one addition, noted below). 3 

### Sierra Club v. Costle , 657 F.2d at 325 & n.83 (quoting 44 Fed. Reg. 33,580, 33,581/3-33,582/1 (EPA summary of the six purposes identified in the 1977 House Committee Report, H.R. Rep. No. 95- 294, 95th Cong., 1st Sess.at 184-86 (1977)). The C ourt identified two other purposes of §111: 4 and 5. The standards to the extent practical must force new sources to burn high-sulfur fuel thus freeing low-sulfur fuel for use in existing sources where it is harder to control emissions and where l owsulfur fuel is needed for compliance. This will (1)

### These purposes merit further discussion here.

1. No competitive advantage to any State The first purpose for the standards, as quoted abo ve – “not giv[ing] a competitive advantage to one State over another in attracting industry” – arose from Congress’s concer n, expressed during the debates over the 1970 CAAA, that States had at least a short-term economic incentive to attract industry by limiting pollution controls, and that States with cleaner ai r quality would be positioned to do so. Congress designed sec tion 111 to address that problem by requiring the EPA to establ ish nationwide emission limitations, which would apply regardless of any State’s air quality, and without giving advanta ge to any

state. 4 

### This does not mean that certain States would not r etain certain inherent advantages – such as resource avai lability - over other States in attracting certain industries. For example, coal-fired power plants need large quantities of co al and water to operate, and States with those resources are mor e likely to attract that industry than States without those res ources. In

allow old sources to operate longer and (2) expand environmentally acceptable energy supplies.

Id. (quoting 44 Fed.Reg. 33,580, 33,581/3-33,582/1). T hese purposes are not relevant to the present rulemaking and, in any event, are associated withfollowing the repeal in the 1990 CAAA of the percentage reduction requirements of the 1977 version of section 111, which were repealed in the 1990 CAAAare no longer good law.

4 

### See S. Rep. 91-1196 at 16 (1970 Senate Committee Repo rt)),.

### Congress’s view, what was important was that the se ction 111

standards themselves be uniform on a nationwide bas is. 2. Maximum practicable emissions reductions The second and third purposes for the standards ar e, as quoted above, “reducing emissions as much as practi cable” and “forc[ing] the installation of all the control tech nology that will ever be necessary at the time of construction. ” These purposes apply to all pollutants that are subject t o section 111, including greenhouse gases. Section 111 applies by its terms to a range of poll utants. For example, CAA § 111(d)(1)(A), which applies to e xisting sources, references National Ambient Air Quality St andards (NAAQS) pollutants that EPA lists by rule under CAA § 108, air toxics that are listed under CAA § 112, and any oth er type of air pollutant. The U.S. Supreme Court has made it c lear that CAA § 111 applies to GHGs because (i) §111 applies to “ air pollutants,” CAA §§ 111(a)(1), 111(d)(1)(A), and in

Massachusetts v. EPA , 549 U.S. 497 (2007), the Supreme Court held that this term includes GHGs; and (ii) in Amer ican Electric Power Company v. Connecticut , 131 S.Ct. 2527 (2011), the Supreme Court based its holding that “the Clean Air Act and the EPA actions it authorizes displace any federal common l aw right to

seek abatement of carbon-dioxide emissions from fos sil fuelfired power plants” on the grounds that CAA section 111

### “provides a means to seek limits on emissions of ca rbon dioxide

from domestic power plants....” 5


### The legislative history of CAA § 111 and the D.C. C ourt have articulated these purposes of reducing emissio ns and forcing the up-front installation of technology so that they apply to all pollutants subject to CAA § 111. The 1977 House Committee Report noted, “In the [197 0] Congress [sic : Congress’s] view, it was only right that the costs of applying best practicable control technolo gy be considered by the owner of a large new source of po llution as a normal and proper expense of doing business.” 6 

### Similarly, the 1970 Senate Committee Report stated:

The implicit consideration of economic factors in determining whether technology is “available” shoul d not affect the usefulness of this section. The overriding purpose of this section would be to prev ent new air pollution problems, and toward that end, maximum feasible control of new sources at the time of their construction is seen by the committee as the most effective and, in the long run, the least expensive approach. 7


### The D.C. Circuit, in Essex Chemical Corp. v. Ruckel shaus , 486 F.2d 427 (D.C. Cir. 1973) cited the legislative history in stating that it was necessary to “[k]eep[] in mind Congress' intent that new plants be controlled to the ‘maximu m practicable

5 

### American Electric Power , 131 S.Ct. at 2538. 6 

### 1977 House Committee Report at 184. 7 

### S. Comm. Rep. No. 91-1196 at 16.

### degree.’” 8 

### Thus, a section 111 standard of performance

controlling GHGs must be evaluated in light of the congressional purposes of “reducing emissions as much as practica ble” and “forc[ing] the installation of all the control tech nology that ever will be necessary ... at the time of constructio n.” In fact, these purposes seem particularly important in the c ase of standards for coal-fired power plants because (i) t hese plants are the largest emitters of CO 2 

### and, as a result, provide the most important opportunity for controlling emission s; and (ii) new power plants have expected lifetimes of as long as 50 years and possibly longer. 3. Technology forcing [A1] 

### The last purpose the D.C. Circuit in Sierra Club v . Costle stated – “[t]he standards should be stringent in or der to force the development of improved technology” – was based on the 1977 House Committee Report. 9 

### The full statement in that report provides a more robust articulation of Congress’s p urposes:

[T]he best technology requirement was intended to create incentives for improved technology, which co uld achieve greater or equivalent emission reduction at equivalent or lower cost, energy demand, and

8 

### Essex Chemical Corp. v. Ruckelshaus , 486 F.2d at 437 & n. 27 (citing “Summary of the Provisions of Conference Ag reement on the Clean Air Amendments of 1970,” 116 Cong. Rec. 4 2384, 42385 (1970)).
9 

### Sierra Club v. Costle , 657 F.2d at 325 & n.83 (quoting 44 Fed.Reg. 33,580, 33,581/3-33,582/1 (EPA summary of the six purposes identified in the 1977 House Committee Rep ort, H.R. Rep. No. 95-294, 95th Cong., 1st Sess.at 184-86 (19 77)).

### environmental impacts. This was to be accomplished by

assuring any vendor who produced such an improved technological system that the standards would be revised to reflect that improvement, and a guarante ed market for the technology would thereby be created. 10 

### According to the House Committee Report, this state ment

[A2] 

### describes the purposes of the 1970 CAAA, and it is clearly

consistent with other statements in the 1970 CAAA l egislative history. For example, the 1970 Senate Committee Rep ort stated:

Standards of performance should provide an incentive for industries to work toward constant improvement in techniques for preventing and controlling emissions from stationary sources, sinc e more effective emission control will provide greate r latitude in the selection of sites for new facilities. 11



### Similarly, the 1977 Senate Committee Report stated: In passing the Clean Air Amendments of 1970, the Congress for the first time imposed a requirement f or specified levels of control technology. The section 111 Standards of Performance for New Stationary Sources required the use of the “best system of emission reduction which (taking into account the c ost

10 

### 1977 House. Committee. Report. at 184-186. (GLH at 2651-53) 11 

### S.Rep. 91-1196 at 16 (1970). The technology-forcin g nature of §111 is consistent with the technology-forcing natu re of the 1970 CAAA as a whole. The principal Senate author o f the 1970 CAAA, Sen. Edmund Muskie (D-ME), during the Senate floor debate, described the overall requirements of the 1970 CAAA and then observed: These five sets of requirements will be difficult to meet. But the committee is convinced that indust ry can make compliance with them possible or impossibl e. It is completely within their control. Industry has been presented with challenges in the past that see med impossible to meet, but has been made possible. 116 Cong. Rec. 32902 (Sept. 21, 1970) (statement of Sen. Muskie).

### of achieving such reduction) the Administrator

determines has been adequately demonstrated.” This requirement sought to assure the use of available technology and to stimulate the development of new technology. 12



### The legislative history just quoted identifies thre e different ways that Congress designed section 111 t o authorize standards of performance that promote technological improvement: (i) the development of technology that may be treat ed as the “best system of emission reduction ... adequately dem onstrated;” under section 111(a)(1) 13 

### ; (ii) the expanded use of the best demonstrated technology; 14 

### and (iii) the development of emerging technology. 15

12 

### S. Rep. 95-127 at 17 (1977), cited in Sierra Club v. Costle , 657 F.2d at 346 n. 174. The 1977 CAAA legislative h istory is replete with other references to the technology for cing nature of §111 or the CAAA as a whole. See “ 1977 Clean Air Act Conference Report: Statement of Intent; Clarificati on of Select Provisions,” 123 Cong. Rec. 27071 (1977) (quoted in Sierra Club v. Costle , 657 F.2d at 346 n. 174) (one of the enumerated purposes of section 111 was to “create incentives f or new technology”); __123 Cong. Reg. __16195 (May 24, 197 7) (statement of Rep. Meads) (”The main purposes of the Clean Air Act Amendments of 1977 are as follows: ... tenth, to prom ote the utilization of new technologies for pollution choic e”). 13 

### See Portland Cement Ass’n v.Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (the best system of emission reduc tion must “look[] toward what may fairly be projected for the regulated future, rather than the state of the art at present ”). 14 

### See 1970 Senate Committee Report No. 91-1196 at 15, GL H at 415 (“The maximum use of available means of prev enting and controlling air pollution is essential to the elimination of new pollution problems”). 15 

### See Sierra Club v. Costle , 657 F.2d at 351 (upholding a standard of performance designed to promote the use of an emerging technology).

### G

Page 179: [3] Comment [A61] Author 8/30/2013 4: 17:00 PM EPA may want to consider reiterating this point and citation (copied below) from earlier about how sec tion 111 looks towards what may be fairly projected, which i s not clear from the case law cited in this section

. EPA: We are considering this suggestion further. 

### The Court explained that a standard of performance is “achievable” if a technology can reasonably be proj ected to be available to new sources at the time they are const ructed that will allow them to meet the standard. Specifically, the D.C. Circuit explained:

Section 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at present, since it is addressed to standards for new plants....- It is the “achievability” of the proposed standard that is in issue.... The Senate Report made clear that it did not intend that the technology “must be in actual routi ne use somewhere.” The essential question was rather whether the technology would be available for installation in new plants.... The Administrator ma y make a projection based on existing technology, tho ugh that projection is subject to the restraints of reasonableness and cannot be based on “crystal ball ” inquiry. 1

Page 256: [4] Deleted MJOHNSON 8/29/2013 11:47: 00 AM 

### I. Consistency with purposes of CAA section 111 Identifying partial CCS as the BSER is also consis tent with the purposes of CAA section 111, which, as discusse d above, including includes avoiding giving any state a comp etitive advantage, reducingreduces emissions as much as pos sible,

.

### obviatingobviates any need for retrofits on new sou rces, and

promotingpromotes technology development. 16


### One purpose of CAA section 111 is that “[t]he stan dards [of performance] must not give a competitive advantage to one State over another in attracting industry.” 17 

### The 1,100 lb CO 2 

### /MWh standard that the EPA proposes in this rulemaking a pplies to all new coal-fired power plants in all geographic locat ions. As a result, there is nothing on the face of the standar d that would provide a competitive advantage to one state over a nother in attracting industry. While it is true that some sta tes may offer more attractive opportunities for CCS – because, fo r example, of greater availability or value for EOR – power plant siting by its nature generally favors certain locations over others. For example, coal-fired power plants usually require a large source of water, which favors certain locations over other s. The fact that CCS adds another siting consideration does not mean that it unfairly benefits certain States at the expense of others, so far as the purposes of section 111 are concerned. A second purpose of section 111 is “reducing emiss ions as

16 

### Sierra Club v. Costle , 657 F.2d at 325 & n.83 (quoting 44 Fed.Reg. 33,580, 33,581/3-33,582/1 (EPA summary of the six purposes identified in the 1977 House Committee Rep ort, H.R. Rep. No. 95-294, 95th Cong., 1st Sess. at 184-86 (1 977), 4 L.H. at 2651-53)). 17 

### Sierra Club, 657 F.2d at 325 & n. 83.

### much as practicable.” 18 

### For the reasons noted above, identifying

partial CCS as the BSER meets this purpose. A third purpose of section 111 is, “to the extent p ractical force the installation of all the control technolog y that will ever be necessary on new plants at the time of cons truction when it is cheaper to install, thereby minimizing the ne ed for

retrofit in the future....” 19 

### As noted above, identifying partial CCS as BSER meets this purpose by achieving CO 2 

### emissions reductions. In contrast, identifying highly efficie nt SCPC or IGCC without at least partial CCS as the BSER would leave sources vulnerable to retrofit obligations if CO 2 

### emissions reduction requirements are imposed in the future. A fourth purpose of section 111 is “The standards s hould be stringent in order to force the development of impr oved technology.” 20 

### For the reasons noted above, identifying partial CCS as the BSER meets this purpose.

Page 267: [5] Deleted David 8/27/2013 10:22:00 PM 

### The EPA notes that compliance with the standard of 1,100 lb

CO 2 

### /MWh is determined exclusively by the tons of CO 2 

### captured by the emitting EGU. The tons of CO 2 

### sequestered by the repository are not part of that calculation. However, to verif y the amount

18 

### Id. As noted, Congress identified this purpose in the context of NAAQS pollutants, but this purpose applies to gr eenhouse gases as well. 19 

### Id. 20 

### Id.

### of tons of CO 2 

### captured at the emitting EGU are safely and

effectively sequestered, we are building on existin g regulatory requirements under Subpart RR, all CO 2 

### that is geologically sequestered at the site of the EGU facility must be reported under subpart RR by the owner or operator of the EG U. Additionally, where the captured CO 2 

### is sent offsite, it must be transferred to an entity that is reporting under Subpart RR. [A3] 

### This provides assurance that the tons of CO 2 

### captured are transferred to a repository which provides assuranc e of long term containment integrity. Under today’s proposal, that type of repository is a Class II or Class VI UIC well which would report its GHG emissions under subpart RR. The EPA acknowledges that there can be downstream l osses of

CO 2 

### after capture. [A4] 

### The EPA expects these losses to be modest

with incentives due to the market use of CO 2 

### as a purchased product. There remains an issue of whether the stan dard itself should be adjusted to reflect these downstream loss es. The EPA is not proposing to do so. Moreover, the EPA wishes to encourage rather than discourage EOR using captured CO 2 

### since the practice makes CCS itself more economic and thus promotes us e of the technology on which the proposed standard is based. See Sierra

Club v. Costle , 657 F. 2d at 347 (one purpose of section 111 standards is to promote expanded use and developmen t of technology).

### We also emphasize that today’s proposal does not in volve

regulation of any downstream recipients of captured CO 2 

### . That is, the regulatory standard applies exclusively to the emitting EGU, not to any downstream user or recipient of the captured CO 2 

### (whether the captured CO 2 

### is sold for productive use or otherwise managed). The requirement that the emitting entity assure that captured CO 2 

### is managed at an entity subject to the GHG reporti ng rules is thus exclusively an element of enforcement of the EGU standard. Similarly, the existing regulatory requi rements applicable to geologic sequestration are not part o f the proposed NSPS. The standard is a numeric value, ap plicable exclusively to the emitting EGU. The requirement t hat the EGU use the repository reporting pursuant to subpart RR and that the repository be a Class II or VI UIC well is a means of assuring the integrity of the stack emission limit applicabl e to the emitting EGU.

Page 268: [6] Deleted David 8/27/2013 10:25:00 PM 

### Together, the framework just described help [A5] 

### create a
consistent national framework to ensure the safe an d effective deployment of geologic sequestration technologies. Importantly, a key component of this framework- the Greenhouse G as Reporting Program- provides a mechanism for new generating un its that supply captured CO 2 

### for geologic sequestration (including CO 2 

### sequestered while oil and gas recovery is occurring ), to help

### demonstrate they are achieving the required emissio n

reductions [A6]

Page 268: [7] Deleted David 8/27/2013 10:31:00 PM 

### To provide certainty and verify that CO 2 

### captured at an affected unit is geologically sequestered, today’s action re lies upon the existing regulatory framework the EPA already has i n place under the Greenhouse Gas Reporting Program 40 CFR Part 98 . As discussed in the previous section, there are 3 rele vant subparts (subpart D, PP and RR) under 40 CFR Part 98, that c an provide an appropriate reporting and verification mechanism fo r demonstrating that any unit subject to these propos ed standards complies with them. The EPA requires electric gener ating units
to report CO 2 

### emissions under subpart D. Facilities that capture

CO 2 

### are required to report quantities of CO 2 

### captured and injected on site or transferred off-site under subp art PP. Facilities that inject CO 2 

### underground for permanent sequestration report under subpart RR. Through thes e Greenhouse Gas Reporting Program provisions, the EPA and other regulatory authorities can track geologic sequestration conduc ted to meet the performance standard.

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Subje ct to Further Policy Review.



## ­ EPA RESPONSE ­

1 Summary of Interagency Comments on U.S. Environmental Protection Agency’s Notice of Proposed Rulemaking “Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units” (RIN 2060

‐ AQ91)

General comments:

 EPA plans to prepare a separate Federal Register notice rescinding the April 13, 2012 proposal. The commenter would appreciate the opportunity to review that notice. [ EPA Response: The EPA is still drafting the FR notice rescinding the April 2012 proposal.]

 Has EPA considered whether there is any ongoing benefit or significance to the rationale that
was put forth in the April 2012 proposal, and whether the April 2012 justification is complementary to the rationale set forth in this proposal? [ EPA Response: The EPA has considered (and continues to consider) the merits of the rationale from the April 2012 proposal and how it may be complementary to the current proposal. We do intend to add language specifically soliciting comment on the potential benefits or merits of placing all sources in a single subpart TTTT as was previously proposed. With respect to the issue of whether to rely on a fuel

‐ neutral justification for the standard

– that is, identifying natural gas combined cycle units as the “best system of emission reduction” for coal

‐ fired power plants as an alternative to CCS

– we have considered that issue and are prepared to discuss it with the interagency group.] [ Additional EPA Response : We have added language indicating that we are proposing the option of codifying the proposed standards in existing 40 CFR part 60 subparts (i.e., in subpart Da for standards applicable to the utility boilers and IGCC units and in subpart KKKK for standards applicable to natural gas ‐ fired stationary combustion turbines) and, in the alternative,
we are co ‐ proposing the option of combining the sources into a single subpart TTTT (as in the original proposal) for GHGs only, while maintaining separate standards (as subpart TTTT subcategories) for the utility boilers/IGCC units and the NG

‐ fired stationary combustion turbines. This changes is noted on or near page 36 of the revised version of the preamble in a subsection “How is EPA proposing to codify the requirements?”]

 EPA demonstrates that no reasonable forecast predicts a cost advantage to building an electricity generating unit (EGU) that would not be compliant with the proposed standard. Given that, what is the rationale for promulgating the rule? EO 12866 states that “federal agencies should promulgate only such regulations as are required by law, are necessary to interpret the law, or are made necessary by compelling public need, such as material failures of private markets.” Can EPA clarify whether this rule is required by law or necessary to interpret the law? [ EPA Response: On June 25, 2013 President Obama issued the “Presidential Memorandum

– Power Sector Carbon Pollution Standards” directing the EPA to issue a new NSPS proposal by no later than September 20, 2013 and to issue proposed carbon pollution standards, regulations or guidelines, as appropriate, for modified, reconstructed and existing power plants by no later

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Subje ct to Further Policy Review.



## ­ EPA RESPONSE ­

2 than June 1, 2014. By statute, in order to issue emission standards for existing sources, the Agency must first propose standards of performance for new sources. Further, given that we have made an endangerment finding for GHGs under title II, are regulating GHGs under title II, and have interpreted PSD to apply to GHGs, issuing a NSPS for the largest stationary source of CO 2 is consistent with the policy objectives and rationale of 12866.]

 EPA notes that the rule would provide regulatory certainty and thereby incentivize innovation. It is unclear how a regulation that would not require any change in behavior would incentivize companies to invest in technologies to further reduce emissions, unless there were external market forces that would prompt them to do so. In which case, the regulation would not be needed. Can EPA explain this line of thinking further? [ EPA Response: We believe that the regulatory certainty offered by this rule

– which will require new fossil fuel

‐ fired boilers and IGCC units to capture a fraction of the produced CO 2 – can incentivize further development of carbon capture technologies. In contrast, an emission limitation based on “best generating technology” would offer no clear incentive for additional CCS research, development and demonstration (since such a standard would be met with no need for CCS technology). It has been suggested that an emission standard that required very deep CO 2 capture could also stifle continued research & development of the technology due to the excessive costs. Further, the observed behavior and distinctive characteristics of the industry raise the possibility that some firms may make non ‐ purely

‐ market

‐ driven investment decisions. One of the purposes of setting this standard is to ensure that those investments include options that are directed at environmental innovation.]

 What is the legal justification for providing an exemption to Wolverine should it not have commenced construction by publication? [ EPA Response : We are not exempting Wolverine from the proposed NSPS, rather we are deferring making a determination of the appropriate standard until we have additional information. A more comprehensive legal justification is provided in a Technical Support Document entitled “Fossil Fuel

‐ Fired Boiler and IGCC EGU Projects Under Development: Status and Approach” which will be provided to OMB/Interagency and placed in the rulemaking docket.]

 According to some technical experts, we understand that it may be possible to design and construct a hybrid EGU that combusts both coal and gas. How would such a plant be treated for purposes of NSPS compliance? [ EPA Response: Steam based EGUs that burn a combination of coal and natural gas would be covered under subpart Da. On August 29, 2012 (77 FR 52554), the EPA proposed amendments to the applicability of subpart KKKK such that all simple cycle, combined cycle, and combustion turbine based combined heat and power facilities would be covered by subpart KKKK with two exceptions. IGCC facilities would be covered by subpart Da and heat recovery steam generators that burn solid fuels or that use oxygen beyond what is included in the turbine engine exhaust (the use of additional combustion air) would be subject to the applicable steam generating unit

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## ­ EPA RESPONSE ­

3 (boiler) NSPS based on the size of the duct burners. In addition, the definition of an affected facility in this proposed rule include “integrated equipment that provides electricity or useful thermal output to either the boiler (or turbine engine and heat recovery steam generator in the
case of an IGCC) or to power auxiliary equipment.” Under this proposed approach, combustion turbines that enhance the performance of steam plants through feedwater heating, providing steam directly to the steam cycle, or use of the combustion turbine exhaust as preheated air for the boiler of the steam turbine unit would be considered part of the subpart Da affected facility.]

Best System of Emission Reduction (BSER):

 The commenter requests clarification on whether EPA’s definition of BSER enables other technologies that meet the same level of emissions reduction (e.g., chemical looping and oxy ‐ combustion). [ EPA Response: The EPA does not prescribe the use of any specific technology to meet the emission limitation. The EPA does base the emission limitation on the performance of the best system of emission reduction

– but sources are not required to utilize that particular technology. Sources are free to utilize other advanced technologies

– such as chemical looping or oxy ‐ combustion

– to meet the proposed standard of performance.]

 For the proposition that CAA section 111 standards may impose a greater compliance burden on some sources in a category (page 179

‐ 185), EPA may also wish to cite the recent case of Portland Cement Ass’n v. EPA , 665 F.3d 177 (D.C. Cir. 2011). In Portland Cement , the court upheld EPA’s approach that focused “primarily” on cement kilns with a newer design incorporating a state

‐ of

‐ the

‐ art technology, rather than older

‐ designed kilns that would become subject to the NSPS if modified. EPA found that the older

‐ designed kilns had available controls that could enable them to meet the standard, but noted that it would be “more difficult” for them and would entail somewhat higher cost; thus, EPA considered separate standards for the older kilns but ultimately decided against that approach. [ EPA Response : The EPA appreciates this recommendation and we will consider the merits of citing this ruling.] [ Additional EPA Response : We have considered this suggestion; but we do not feel that the ruling is an appropriate citation for this proposed rulemaking.]

 Although not stated explicitly, the justification for reasonable cost seems to imply that the net compliance costs must be negative, that the revenue from EOR must fully offset the increased cost of partial CCS. If this is the correct interpretation, it could potentially set a restrictive precedent that carbon pollution standards only have reasonable cost if they are expected to be cost

‐ saving irrespective of environmental benefits. Again, while the rule doesn’t state this explicitly, we note that in table 4 the levelized cost of electricity under the standard with high EOR is equal to or less than cost without CCS for both SCPC and IGCC. EPA may wish to clarify whether costs could still be considered “reasonable” under this analytical framework if EOR

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## ­ EPA RESPONSE ­

4 revenue estimates did not lower net costs to the level of an uncontrolled plant. [ EPA Response : It was not EPA’s intent to imply that net compliance costs must be negative. In both Section VII.F of the preamble which discusses cost and the RIA which shows that there are cases where EOR revenue does not fully offset the cost, EPA believes it has made this clear. We agree with the commenter that it is important to be clear that costs are still reasonable even if costs are not fully offset. We would be happy to discuss further where commenters believe this
was not made clear and how we could do so.] Additionally, while EPA considers the revenue from EOR to lower overall costs, the preamble doesn’t appear to consider additional CO 2 emissions from recovered fossil fuels to be an environmental disbenefit. Should the recovery and combustion of fossil fuel from EOR that would otherwise remain underground be considered in the economic analysis? [ EPA Response : EPA considered this comment but ultimately decided not to include the evaluation in the economic analysis. The amount of oil produced through EOR with captured CO 2 from new EGUs subject to this proposal, while useful from the standpoint of promoting energy independence, would not be likely to impact cost and thus would not be likely to impact on total oil consumed. As a result, EOR is not likely to impact total CO 2 emissions from oil production and consumption. ]

 EPA states that it is logical and a reasonable interpretation of the statute that the costs of the control technology should be offset by any revenues from the sale of pollutants or pollution control byproducts associated with those controls. Has EPA applied this logic in any other NSPS (or other similar and relevant context)? See page 160. It would be helpful to further elaborate
on this issue in the preamble. [ EPA Response : We will consider adding a reference to a rulemaking under a related area of the Clean Air Act in which revenues from the sale of pollution control byproducts was treated as defraying the costs of the pollution control equipment.] [ Additional EPA Response : The existing preamble language has been edited on or near page 169.]

Level of standard:

 The commenter suggests that the range on which comments are solicited for the proposed emission limit for new fossil fuel

‐ fired boilers and IGCC units be amended from 1,000

– 1,200 lb CO 2 / MWh to [900]

– 1,200 lb CO 2 / MWh. The lower bound of this range, which we tentatively suggest to be [900], would be at a level slightly above the feasible level exemplified by the Great Plains Synfuels Plant and the Kemper County Energy Facility—which appears to be approximately 900 lb CO 2 / MWh. The economic analysis in the rule and the RIA did not provide strong reason to think that such plants would be unduly expensive in the future, and the fact that these are being built in fact suggests that they are not unduly expensive currently and thus could be consistent with BSER.

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## ­ EPA RESPONSE ­

5 [ EPA Response: The EPA is currently considering this comment and re ‐ evaluating the range of emission limitation on which comments will be solicited in the proposal.] [ Additional EPA Response : We are still considering this comment and re ‐ evaluating the range of emission limitation on which comments will be solicited in the proposal.]

 Can EPA provide additional explanation and justification for why it is appropriate to set the BSER level at 45% capture, as opposed to a higher or lower level of partial capture? It would be helpful to have more detail on why the chosen level (as opposed to other levels) was selected, and the basis for that determination. For example, can more detail be provided on the thresholds or tipping points for capture above which costs jump significantly? Or is there greater evidence of the achievability of this level of capture based on real

‐ word experience? If so, further explanation could help strengthen the BSER determination section of the preamble. (We note that EPA has provided some detail on the technical reasons for the choice (e.g. it is cheaper to use a single “water gas shift” cycle in part because the resulting syngas does not require a specialized H 2 turbine that would be required if multiple water gas shifts are used, yielding up to 90% capture and more or less pure H 2 ), but think the overall justification still needs further elaboration. [ EPA Response: The EPA is currently adding additional explanation and justification for the proposed level of the standard for boilers and IGCC units. Please note, however, that BSER is not set at “45% capture”; rather, the emission limit is proposed at 1,100 lb CO 2 /MWh which corresponds roughly at a capture level of 45% for a new PC unit. This will be further explained in the revised language in the preamble.] [ Additional EPA Response : The EPA has reviewed the existing language and has added some additional language to the preamble explaining our rationale for excluding other emission limits is provided on or near page 204.]

 In section VII.L “Compliance Period” EPA proposes a 60 operating

‐ month compliance period for
new fossil fuel

‐ fired boiler and IGCC units. In contrast, the April 2012 draft rule proposed a 30

‐ year compliance period. What data and analysis method is EPA using to interpolate between the April 2012 proposal (1,000 lb CO 2 MWh with full CCS” and 30

‐ year compliance period) and the regulations currently applicable to these sources, in order to arrive at the proposal under consideration (950

‐ 1,050 lb CO 2 MWh with “partial CCS” and 60

‐ operating

‐ month compliance period)? Please point the reviewer to the data and analysis that support the proposed 60

‐ operating

‐ month compliance period. [ EPA Response : As explained in the preamble, the EPA has previously offered sources optional, longer

‐ term emission standards that are discounted from the primary emissions standard in exchange for the longer averaging period. We also specifically request comment on the appropriate numerical standard such that the 60

‐ operating

‐ month standard would be as stringent as or more stringent than the 12

‐ operating

‐ month standard. We will also reevaluate the preamble text to determine if further clarification of this point would be useful. ]

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## ­ EPA RESPONSE ­

6 [ Additional EPA Response : We have reevaluated the preamble text and no further changes in response to this comment have been made.]

 Page 89. Can EPA provide an example of how the 75% credit for useful thermal output would factor into compliance determinations? [ EPA Response: The following is an example of how a CHP facility would calculate an emissions rate for determining compliance with the 1,000 lb CO2/MWh or 1,100 lb CO2/MWh standard, as applicable. Example plant specifications: 100 MW electric output 500 MMBtu/h of useful steam output 200,000 lb CO 2 /h measured emissions rate

The 500 MMBtu/h thermal output rate would be converted to an equivalent MW of output (3.412 MMBtu/h = 1 MWh). 500 MMBtu/h = 147 MW. The resultant value would be multiplied by 75% to get a value of 110 MW that would be used in calculating the facility emissions rate. The emissions rate for comparison against the applicable emissions standard would be (200,000 lb CO 2 /h) / (100 MW + 110 MW) or 950 lb CO 2 /MWh. ]

 Page 327

‐ 328. The discussion of parasitic loads and gross ‐ versus net

‐ based standards could be improved by tabulating the relevant SCPC and IGCC coal plants, with and without CCS, thereby demonstrating the parallel gross and net standards and how these were calculated and inter

‐ relate. Otherwise, the text as currently written states that 1400 lbCO 2 /MWh would be the net basis for a coal

‐ CCS plant, which differs little from the (gross) coal without CCS performance numbers noted for high performing units of 1434 lb CO 2 /MWh (p. 188; p. 200), at least at first blush without the benefit of the parallel display of figures. Below is a sample table cobbled together from numbers reported in the FR

– the square parentheses represent imputed numbers rather than stated in the text.

Gross Emissions

(lb CO 2 /MWh) Parasitic Load Net Emissions (lb CO 2 /MWh) SCPC 1675 ‐ 1783 <7.5% [1800 ‐ 1916] IGCC 1434 15% [1649] Coal

‐ CCS 1100 [27%] 1400 NGCC (<=850 MMBtu) 1100 2.5% 1130 NGCC (>850 MMBtu) 1000 2.5% 1030 [ EPA Response : We have specifically solicited comment on the use of net

‐ based standards and
we will reevaluate that preamble text and clarify as needed. We will also add additional discussion of the differences in net and gross output

‐ based standards. ]

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## ­ EPA RESPONSE ­

7 [ Additional EPA Response : The EPA has added some additional language to the preamble explaining our rationale for the range for which we have requested comment. This new language is located on or near page 204.] Simple Cycle/Peaking plants:

 The rule clearly states that the intended facilities to be covered are intermediate and baseload generation and exempts “peaking” plants. While the rule provides a reasonable justification for treating these sources differently than intermediate or baseload generation, why were these
sources exempted rather than setting a less stringent numerical standard for this subcategory? Given that availability of peaking plants is an enabling technology for renewable electricity, we could imagine that uncontrolled simple cycle plants could lead to higher overall power sector carbon emissions. Did EPA analyze this scenario as it relates to interactions with renewable energy growth? [ EPA Response : We are still considering this comment.] [ Additional EPA Response : Please note that this rule will only impact new units and there is a huge existing simple cycle fleet that would not be impacted. In addition, the data indicates we have provided room in the capacity factor exemption to account for renewable generation. For example, not like all the simple cycle units in California are running close to 33% and they have a fair amount of renewable generation. We also believe that fast start combined cycle facilities may provide some of the backup for renewables.]

 The commenter agrees with EPA’s determination that simple cycle units should not be subject to the same standards as combined cycle units. However, rather than entirely exempting simple cycle units, EPA could formulate an alternative standard in recognition of the role simple cycle units play in complementing renewable sources and maintaining grid reliability. Are there plans to propose a standard that would apply to simple cycle units? If so it might be appropriate to mention such plans. This could be quite significant because of the increasingly important role expected to be played by simple cycle natural gas turbines as wind and solar power generation expands. [ EPA Response : We are still considering this comment.] [ Additional EPA Response : Note the response to the previous comment. In addition, we note that, at this time, we do not have plans to propose a standard for new low capacity stationary combustion turbines.]

 Page 142. EPA states: “Second, only 0.2 percent of existing simple cycle turbines had a three

‐ year average capacity factor of greater than 33 percent between 2000 and 2012. Therefore, as noted, from a practical standpoint, few new simple cycle turbines be subjected to the standards of performance in this rulemaking.” It would be good to see the distribution curves here, because this still could impact some simple cycle turbines, raising the question of flexibility in implementation. With a projected increase in reliance on cyclical solar and wind power,

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## ­ EPA RESPONSE ­

8 presumably the amount of load following turbine cycling might be expected to increase. Maybe EPA has a graph that could be circulated as a memo? [ EPA Response : See response to next comment.]

 Page 144. EPA states: “Only 0.4 percent of existing simple cycle turbines had an annual capacity factor of greater than 40 percent between 2000 and 2012.” On the previous page EPA commented on only 0.2 percent over 3 years at 33%. Presumably the percent calculation differences relate to the time and rate input parameters, but it is a little confusing. Hence, a graph and memo would be helpful. [ EPA Response : The vast majority of simple cycle turbines have capacity factors that are consistently less than 10% on both an annual and 3 year average basis. More than 80% of simple cycle turbines consistently operated at annual capacity factors below 10% between 2000 and 2012 and over 90% operated at less than 10% capacity on a 3 year average. The figure below shows the maximum capacity factors of simple cycle turbines and that extending the averaging period to 3 years results in lower average maximum capacity factors. Further, please remember that this proposed rule will only affect NEW units

– those that commence construction after the date of publication of the proposed rule in the Federal Register. There will be no effect on existing source EGUs or simple cycle combustion turbines.]

0% 2% 4% 6% 8% 10% 12%

10% ‐ 15% 15% ‐ 20% 20% ‐ 25% 25% ‐ 30% 30% ‐ 33% 33% ‐ 40% 40% ‐ 50% 50% ‐ 60% > 60%PercentofSimpleCycleTurbines

Capacity Factor Simple Cycle Turbine Maximum Capacity Factor

Single Year Capacity Factor 3 year capacity factor

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## ­ EPA RESPONSE ­

9  Page 145. EPA states: “For example, a 33 percent efficient 100 MW facility would have a potential electric output of 876,000 MWh and a 40 percent efficient 100 MW facility would have
a potential electric output of only 723,000 MWh.” I don’t understand the math here, whereas it was clear in the previous conversion of 25MW to a 219000 MWh annual equivalent. This calculation would seem to be 0.33 x 100 MW x 24 hr x 365 = 289080 MWh, but it is not. It also
seems unusual that the less efficient plant has a higher potential electric output. Recommend a brief explanation of how the numbers are calculated, perhaps in a footnote. [ EPA Response : The current definition of potential electric output only considers the heat input capacity of the facility and does not account for efficiency. A 33% efficient 100 MW facility would have a heat input of 1,034 MMBtu/h and a 40% efficient 100 MW facility would have a heat input of 853 MMBtu/h. The current definition of potential electric output assumes the facility is 33% efficient and runs continuously for the entire year at maximum capacity. (1,034 MMBtu/h)*(1 MWh/3.412MMBtu/h) *(0.33) * (8,760h/yr) = 876,000 MWh/yr (853 MMBtu/h)*(1 MWh/3.412MMBtu/h) *(0.33) * (8,760h/yr) = 723,000 MWh/yr

The proposed definition would permit the 40% efficient facility to use the actual efficiency of the facility (853 MMBtu/h)*(1 MWh/3.412MMBtu/h) *(0.40) * (8,760h/yr) = 876,000 MWh/yr ]

 EPA should explain why smaller NGCC units meet a particular need. Is it geographic specific? Is there a possibility that multiple new smaller units would be built instead of one larger unit? [ EPA Response : Smaller NGCC are inherently less efficient than larger NGCC facilities, regardless of geographic conditions. Applicability under subpart KKKK is currently based on the heat input capacity of the individual combustion turbine engine and we are not proposing to amend that approach. As currently written, a combined cycle facility with 2 turbine engines with individual heat input ratings of less than 850 MMBtu/h using a common steam turbine would be subject to the less stringent standard even though the combined input capacity of the turbine engines is greater than 850 MMBtu/h.]

Technical feasibility of CCS for coal

‐ fired units:

 The draft NSPS regulation is “technology forcing” for carbon capture and storage (CCS) in that it establishes partial CO2 capture using CCS as the Best System of Emission Reduction (BSER) for
new fossil

‐ fuel boilers and integrated gasified combined cycle (IGCC) units. The commenter agrees that carbon capture is technically feasible, but it has not been deployed at scale in commercial power plants. The commenter also agrees that Enhanced Oil Recovery (EOR) sequestration has been employed commercially. Nevertheless, demonstration projects will be necessary in a number of operating environments in order to reach the technical potential and the cost targets contemplated in the rule, and to demonstrate storage in saline aquifers. The commenter therefore believes the rule should incorporate sufficient flexibility to enable additional demonstration projects. This will ensure that the draft NSPS regulation is “technology forcing” for both carbon capture technologies and sequestration, whether EOR or geologic.

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## ­ EPA RESPONSE ­

10 [ EPA Response: We believe that the proposal as it is currently written already contains considerable flexibility. These flexibilities include a requirement for an emission limitation that requires only partial capture and a 12 operating month rolling average – or an alternative 60 operating month rolling average – are features that provide considerable flexibility. The commenter suggests that “the rule should incorporate sufficient flexibility to enable additional demonstration projects” but does not suggest specific flexibilities. The EPA is happy to discuss whether any additional flexibility to promote additional implementation and demonstration of CCS technology are necessary.]

 EPA’s assertion of the technical feasibility of carbon capture relies heavily on literature reviews, pilot projects, and commercial facilities yet to operate. We believe this cannot form the basis of
a finding that CCS on commercial

‐ scale power plants is ‘adequately demonstrated.”
o EPA should provide details of the specific CCS operations already in service that process the rate of CO 2 necessary for a typical IGCC power plant to be in compliance. Where only literature reviews or simulations exist, the text should make this clear.
o We are concerned that the unsupported assertions of technology as ‘adequately demonstrated’ in this rulemaking will form a precedent for future such determinations,
even if the three CCS projects used as the basis for the determination fail or are never completed. [ EPA Response : The EPA believes that the evidence supports the finding that implementation of CCS technology to meet the proposed standard is technically feasible. However, the EPA will reevaluate the preamble text and look for opportunities to further clarify the basis for that finding. The draft preamble explains the standards adopted by the D.C. Circuit for determining whether a system of emission reduction is “adequately demonstrated.” (pages 159

‐ 160) The preamble then identifies the literature and actual experience with the various components of CCS. (pages 204

‐ 210). These meet the standards identified by the D.C. Circuit.]

 EPA states that the level of the NSPS standard “best promotes further enhancement of the performance of existing technology and promotes continued development of new, better performing technology” (See page 199). Could EPA further explain why it believes that a standard level that can be met by existing technologies would spur development of new, better performing technology? Presumably, this is because we would expect a higher volume of CCS deployment at this cheaper capture level, thereby helping to develop the production experience needed to lower costs for related technologies that could ultimately be used to achieve higher capture rates. Further explanation on this topic would be helpful. [ EPA Response: We believe that this proposed rule which will require new fossil fuel

‐ fired boilers and IGCC units to capture a fraction of the produced CO 2 , can incentivize further development of carbon capture technologies. In contrast, an emission limitation based on “best generating technology” would offer no clear incentive for additional CCS research, development and demonstration (since such a standard would be met with no need for CCS technology) and could in fact inhibit that technology (because many PUCs may not find it a prudent cost if it is

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## ­ EPA RESPONSE ­

11 not explicitly required). The EPA will review the current language on page 199 (as directed by the commenter) and clarify as needed.] [ Additional EPA Response : Additional language has been added on or near page 205.]

 Why is the Boundary Dam project not included in the listing of CCS demonstration projects (starting on page 212)? It is mentioned in two other places in the FR, as well as getting a prime place in EPA’s introductory power point. [ EPA Response: A discussion of the Boundary Dam project will be added. The EPA appreciates this comment as the exclusion was an oversight.] [ Additional EPA Response : A short discussion of the Boundary Dam project has been added in several locations in the preamble.]

Costs of CCS:

 Can EPA please provide a brief explanation (on page 29) of why the cost of partial 65% capture are so much less than full 90% capture? This is made more evident in RIA Table 5

‐ 7, p.5

‐ 19, where the capital increment for partial

‐ 65% CCS is estimated at $305/kW, with a further $812/kW capital to get to full

‐ 90% CCS. Presumably this relates to additional technologies being added to a coal fired plant to go from partial to full capture, but the differential is quite high since much of the capital expenditure would presumably have gone into the IGCC and basic capture components. A technical explanation would be helpful [ EPA Response : The EPA appreciates this comment and will edit the preamble text to provide additional technical detail on the differences in cost of implementation of partial vs full capture.] [ Additional EPA Response : The details of the costs of the references cases are provided in the extensive and very thorough DOE/NETL ‘cost and performance’ reports (including one specifically examining costs of partial CCS). These reports contain the detailed assumptions and technical configurations used in determining the cost of the new units

... with and without capture

... and with partial capture. We have referenced those reports extensively in the proposal. ]

 Page 219, Table 4. The NGCC @ $5.0/MMBtu estimate is actually substantially below the EIA 2013 estimate, in $2011, even if we extract the transmission costs. EIA reported $65.6

– $1.2 transmission = $64.4, compared to NETL/EPA $52. Is this difference fully explained by the range of modeled gas cost input prices, and, if so, might this calculation/explanation warrant a footnote? [ EPA Response : EPA plans to adjust the natural gas price assumed for the baseline NGCC estimate to $6.11/MMBtu (what EPA has identified as the 2020, 20

‐ year levelized fuel price), producing a LCOE of $59.4/MWh. The remaining differential is attributable to differences in cost/performance, financial assumptions, and the assumed cost of natural gas.]

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## ­ EPA RESPONSE ­

12 [ Additional EPA Response : This has been done. The edits are reflected in numerous places in the preamble and RIA.]

 Attached are CCS costs prepared by DOE’s National Energy Technology Laboratory (NETL) based
on two NETL studies, as well as current project cost data. These numbers provide a range of cost estimates for next

‐ of

‐ a ‐ kind plants. The commenter believes that it would be appropriate for the proposed rule to consider the full range of cost estimates developed by NETL, recognizing the level of uncertainty in these estimates. [ EPA Response : We did not receive the referenced attachment of DOE/NETL CCS costs but will consider additional preamble discussion about the uncertainties in cost.] [ Additional EPA Response : We did subsequently receive the referenced attachment. On the most recent Interagency call (8/28/13), we agreed to further discuss these costs with DOE/NETL to determine how we can best represent the costs and the associated uncertainty in the proposal documents. We are working to schedule that additional discussion.]

The commenter notes that DOE is sponsoring research on novel carbon capture technologies and alternative coal conversion technologies that may substantially lower future CCS costs. [ EPA Response: The EPA is aware of the DOE’s program to sponsor research on novel carbon capture technologies. We will edit the proposal to indicate the program and acknowledge its potential to further develop better performing and more economical capture technologies.] [ Additional EPA Response : The following statement is on or near page 269 in the preamble. “The DOE/NETL sponsors an extensive research, development and demonstration program that is focused on developing advanced technology options designed to dramatically lower the cost of capturing CO 2 from fossil

‐ fuel energy plants compared to today’s available capture technologies.” ]

 EPA states that “regulatory programs may serve to defray the costs of CCS, including, for example, Clean Energy Standards or guaranteed electricity purchase price agreements.” This is the only discussion of these policies. EPA should discuss this further, instead of just mentioning them. (See page 230). [ EPA Response: As suggested, the EPA will edit the preamble to list the specific proposed regulatory programs that have contained such provisions for CCS.] [ Additional EPA Response : We are still working to address this comment.]

 Regarding transportation of CO 2 , it is not clear that the preamble addresses the costs that may be associated with any new pipelines that could be used for transportation, and specifically the cost to get CO 2 from a facility to a GS site. It would be helpful for EPA to include a more detailed discussion on transportation (page 205).

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## ­ EPA RESPONSE ­

13 [ EPA Response : EPA is adding a more detailed discussion to the preamble regarding transportation of CO 2 .] [ Additional EPA Response : The additional language and citations are located on or near pages 232

‐ 233.]

 EPA should clarify the assumptions and estimates of costs associated with transportation of fuel, electricity and/or CO2 in its assessment of “reasonable costs.” See also related comments below regarding the RIA and NETL’s consideration of transportation costs.
o EPA’s analysis assumes the cost of CO 2 transportation is not “a significant impediment” to CCS, based on a history of CO 2 pipelines and the distribution of existing CO2 sources. Instead, EPA should acknowledge that other factors can vary significantly the cost of CO2 transport. availability (or unavailability) of rights

‐ of

‐ way for new pipelines; capital costs; and operating costs (in terms of dollars, energy, and GHG emissions). [ EPA Response : EPA is adding a more detailed discussion to the preamble regarding transportation of CO 2 .] [ Additional EPA Response : The additional language is located on or near pages 232

‐ 233.]

o EPA discusses siting considerations as if they are costless (pp. 242). Additional siting considerations increase the cost of construction by requiring trade

‐ offs in that may not have existed in the absence of the regulatory mandate. These costs include transportation of coal and delivery of electricity from a location that would otherwise not be selected. As with CO 2 transportation, these costs include availability (or unavailability) of rights

‐ of

‐ way for new pipelines or rail lines; capital costs; and operating costs (in terms of dollars, energy, and GHG emissions). Again, see RIA comments noting NETL’s acknowledgment of variability in such costs.
o EPA asserts that gas can serve as a substitute when appropriate siting for a coal

‐ fired power plant is unavailable (pp 241). This implies the assumption that national electric markets are entirely integrated and electricity is a commodity with no regional variations. Further, though EPA assumes the baseline and regulated scenarios are equivalent, it is possible that resource and technology development paths between these two differ, thus weakening the strength of this assumption. We suggest EPA add language to further acknowledge the substantial uncertainty related to this assumption. [ EPA Response : The EPA will supplement the preamble with language detailing why the assertion that CO 2 transportation costs do not represent “a significant impediment” to CCS is robust to the cost and uncertainty factors highlighted by the commenter. Similarly, EPA will add language to the preamble (similar to the language contained in the RIA) that acknowledges the regional variability of transportation costs. In regards to the last sub

‐ bullet, EPA believes new or existing gas ‐ fired generation can serve as a substitute for a coal

‐ fired power plant (the comment seems to imply that increasing dispatch of existing natural gas ‐ fired facilities is the only substitute contemplated). The identical projections of the baseline and regulated scenarios over

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## ­ EPA RESPONSE ­

14 the analysis period signify that

– based on our current analysis ‐ a significant divergence in resource and technology development paths are unlikely.] [ Additional EPA Response : We are still working on supplemental language.] Geologic Sequestration:

 The commenter requests that EPA clarify that this rule does not require a switch from Class II to Class VI. [ EPA Response : This rule does not change the classification of an Underground Injection Control (UIC) well in the UIC Program. As noted in the proposed NSPS preamble, a covered entity employing CCS to meet the performance standard is required to supply its CO 2 to a facility reporting under subpart RR of the GHG Reporting Program. The facility reporting under subpart RR can hold a UIC Class II or UIC Class VI permit. That permitting determination is made under the UIC regulations. For a discussion on UIC Class II wells transitioning to Class VI, please consult the preamble to the final UIC Class VI rule, December 10, 2010, 75 FR 77230 et seq. ] [ Additional EPA Response: Statement added to preamble for clarification on or near page 295.]

 Please note existing questions to EPA regarding the hazardous waste exemption rule for Class VI wells, and whether this should and could be extended in a separate rulemaking to UIC Class II wells that have monitoring, reporting, and verification (MRV) procedures consistent with GHG Reporting Rule Subpart RR. The FR text on page 255, refers to the use of both UIC Class II and Class VI wells under GHG Reporting Rule SubPart RR as verification of sequestration for the purposes of the NSPS. [ EPA Response : The EPA appreciates comments on the rulemaking related to the hazardous waste conditional exclusion for UIC Class VI wells. The EPA is considering those comments as part of that separate rulemaking process.]

 EPA’s BSER determination for coal

‐ fired plants would benefit from a more clear explanation of the factual basis for determining that the long

‐ term storage of CO 2 has been demonstrated. The preamble discussion should be strengthened on this topic.
o Specific comment on p. 205: Can EPA provide a more direct explanation of how the permanence of storage has been demonstrated? The preamble talks about how storage locations and opportunities are available for geologic sequestration and EOR, but it does not discuss evidence that CO 2 can actually be technically stored for long periods of time. It is our understanding that such evidence exists, and it should be explained.
o Specific comment on p. 212: EPA notes that alternatives to geologic sequestration would need to address the

– “ultimate fate of the captured CO 2 and the degree to which the method permanently isolates the CO 2 from the atmosphere”

– but EPA does not describe in the preamble how its proposal meets addresses these points. EPA should explain its rationale and provide the supporting evidence. See also page 208 and page 260.

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## ­ EPA RESPONSE ­

15 [ EPA Response : As requested, EPA has added additional language to the preamble regarding sequestration of CO 2 ] [ Additional EPA Response : The additional language is located on or near pages 233

‐ 237 and 241

‐ 244]

 EPA’s proposal will have significant disparate geographic impacts. Geologic features appropriate for EOR or geologic sequestration are not evenly distributed throughout the country. (See also related comments regarding RIA and NETL assumptions below). EPA asserts that such disparate impacts are permitted by the Clean Air Act, citing some legislative history (see e.g., pp 180

‐ 181). However, these quotations apply to the impact of the NAAQS provisions (i.e., local sources effect on local pollution), and the possible restrictions on construction of new sources in non ‐ attainment areas. The NSPS is a uniform emission standard for the whole country, imposed regardless of local levels of pollution. It is more inappropriate to exercise this discretion in this case, where local pollution does not have local effects.
o We believe EPA confuses the legislative history regarding the distinction between a geographic restriction on new sources due to NAAQS and due to NSPS. EPA similarly has not distinguished between s siting considerations due to the regulated entity’s selected technology and due to EPA’s mandate of an “adequately demonstrated” technology that cannot be used in particular places (pp. 242).
o EPA reminds us that the DC Circuit has said that sec. 111 standards “must not give a competitive advantage to one State over another in attracting industry.” Please explain how this instruction is consistent with a sec. 111 standard that is unattainable in parts of the country.
o We would like to know of any other NSPS for which the “adequately demonstrated” technology was inappropriate for particular parts of the country, without respect for NAAQS or PSD. [ EPA Response : The preamble accurately describes the legislative history and its relevance. The preamble also explains why CCS with partial capture is attainable throughout the entire country, and is not inappropriate for particular parts of the country.]

 How will EPA enforce the requirement that captured CO2 be reported under the GHG reporting program? Is that requirement an explicit part of the “standard of performance” and therefore enforceable like any other part of the standard? (see page 255). We note that EPA is relying on MRV plans that are required under Subpart RRR of the GHG Reporting program to detect and quantify leakage (see page 252). What is not clear is what happens under Subpart RRR if leakage occurs. EPA should discuss this aspect of the overall approach. [ EPA Response : The EPA used its authority under section 114 of the Clean Air Act to promulgate the Greenhouse Gas Reporting Program (GHGRP) requirements. A failure to comply with the monitoring and reporting requirements of the GHGRP is a violation of the Clean Air Act. The proposed amendments to 40 CFR Part 98 subpart PP will provide the information necessary for EPA to determine whether the captured CO 2 is reported under the GHGRP.

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## ­ EPA RESPONSE ­

16 As the commenter noted, affected units using CCS to comply with the performance standard would be required to send their captured CO 2 to a facility that reports under subpart RR of the GHGRP. ] [ Additional EPA Response : Clarification to approach is provided on or near pages 294

‐ 299]

 If a covered entity meets the standard by capturing CO 2 and sending it to a facility covered by the GHG reporting program but the geologic storage facility shows high leakage rates, would EPA have any ability to remedy the leakage problem or pursue enforcement action against anyone? It would be helpful to describe the agency’s thinking on this point. [ EPA Response : The issue is outside the scope of this rulemaking as the only requirement for the affected EGU is to send it to a source covered by Subpart RRR.]

CCS for Natural Gas:

 EPA states that NGCC is not “technically feasible” (on page 33, 264, and others), yet on page 265 notes that there is a demonstration project, which implies that CCS is technically feasible for NGCC. EPA does helpfully note that CO 2 concentrations are lower in effluent from NGCC relative to coal

‐ fired power plants. Are there are other technical constraints to actually using CCS in the NGCC context? Or, are there financial and efficiency drivers involved that limit the use of CCS in the NGCC industry that should be further explained? [ EPA Responses : To clarify, in the current draft of the preamble we state that

... “we believe there is insufficient information to make a determination regarding the technical feasibility”. We did not intend to state definitely that implementation of CCS on a NGCC unit is “not technically feasible” and we will review the text to ensure that we have not inadvertently done
so. We will also consider additional technical constraints or challenges to using CCS w/ NGCC and will also discuss other factors in greater detail.]

 Presumably, EPA has decided to set a GHG standard for new natural gas ‐ fired facilities that does not require additional emissions control technology because it is relatively cheaper to achieve the same level of emissions reductions from existing fossil fuel

‐ fired power plants (via a subsequent rulemaking). However, EPA does not appear to have provided any estimates on what it would actually cost new natural gas ‐ fired facilities to install and operate CCS technology. Isn’t data and analysis on the cost of applying CCS to natural gas ‐ fired facilities necessary in order to justify the decision that CCS is not BSER for new natural gas ‐ fired facilities? [ EPA Responses : In the current version of the DRAFT preamble, the EPA did not find CCS to be BSER for NGCC units because we believe that there is insufficient information to determine its current feasibility. Therefore we did not conduct a cost analysis as we had already eliminated it as a BSER option.]

 Because the rule considers CCS for natural gas infeasible there is no cost analysis of this option. The preamble provides evidence for why there is greater uncertainty in applying CCS for natural gas than coal; however, EPA may wish to request comment and attempt a cost analysis for the

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## ­ EPA RESPONSE ­

17 final rule. If nothing else, this may signal to the industry that CCS could be considered for natural gas during the statutorily

‐ required 8

‐ yr review.

 [ EPA Response: Please note that we do not consider CCS with NGCC units to be “infeasible”. Rather, we believe that there is insufficient information to determine its feasibility at this time. We will consider soliciting comment on this determination. ]

The preamble asserts that CCS technology is increasingly difficult for natural gas plants that cycle to provide intermittent load, however, would it be possible to create a subcategory for baseload NGCC generation that would be more likely to meet BSER criteria? If that is the case, EPA may consider requesting comment on further subcategorization. [ EPA Response: We appreciate this comment and we are considering the merits of requesting comment on further subcategorization for natural gas ‐ fired stationary combustion turbines.] [ Additional EPA Response : We do not intend to solicit comment on further subcategorization within the NG

‐ fired stationary combustion turbine sources.]

 Although technology that would make CCS for natural gas an efficient way to reduce emissions is not currently available, it would be desirable for EPA to signal that were technology to be demonstrated and to meet BSER criteria, then EPA would accordingly reexamine whether NGCC/CCS would meet BSER criteria in its next NSPS review cycle. Sending such a signal should
serve to support R&D in natural gas CCS. One way for EPA to send this signal would be by including a cost analysis and a request for comment on CSS for natural gas in the final rule, although there might be better ways to send this signal. [ EPA Response : The EPA appreciates this comment and will consider what preamble edits may be appropriate.] [ Additional EPA Response : In the next NSPS review cycle, the EPA will consider all available technologies for reduction of GHG emissions; and, we do not feel that it is necessary to signal
our willingness to specifically consider NGCC+CCS.]

 The briefing materials and draft NSPS Federal Register notice state that EPA does not have sufficient information to determine if CCS for natural gas is technically feasible. Recognizing that we are parsing the text closely here given legal requirements, we believe that more care needs to be taken in the selection of words and phrasing. To be clear, we agree that NG

‐ CCS has not been “adequately demonstrated,” that we do not have sufficient economic information to determine if NG

‐ CCS costs are reasonable, and there are differences in system design and CO 2 concentrations, etc., between coal and gas power plants. That said, in discussions with industry and academics we have been informed that all aspects necessary for NG

‐ CCS have been demonstrated, albeit not configured, funded, or implemented. Concerns about the need for hydrogen turbines in certain configurations are not dissimilar from the considerations relating to coal syngas. In support, we note the BP

‐ SSE Peterhead precombustion NG

‐ CCS proposal in Great Britain that was cancelled due to delays in UK government funding; the current Shell

‐ SSE

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## ­ EPA RESPONSE ­

18 Peterhead Post

‐ Combustion NG

‐ CCS finalist proposal in the British CCS competition; and recent news reports from GE

‐ Sargas and Summit

‐ Linde that they are independently proceeding with NG

‐ CCS design and funding proposals.
o http://ieahia.org/pdfs/PeterheadCase_Study1_2.pdf

o https://www.gov.uk/government/news/preferred

‐ bidders

‐ announced

‐ in

‐ uk

‐ s ‐ 1bn

‐ ccs ‐ competition
o http://sequestration.mit.edu/tools/projects/peterhead.html

o http://www.businesswire. com/news/home/20120619005970/en/GE

‐ Sargas

‐ Announce

‐ Alliance

‐ Enhanced

‐ Oil

‐ Recovery
o http://bellona.org/ccs/ccs

‐ news ‐ events/news/article/summit

‐ power ‐ and

‐ linde

‐ join

‐ forces

‐ to

‐ develop

‐ ccs ‐ for

‐ gas ‐ fired

‐ power ‐ generation.html

 With these in mind, we recommend that EPA carefully re ‐ evaluate the text so as not to impugn efforts in the direction on NG

‐ CCS. We suggest the following edits:

o Page 32: “By contrast, NGCC with CCS is not a configuration that is widely being planned and built today. The EPA considered whether NGCC with CCS could be identified as the best system of emission reductions adequately demonstrated for new stationary combustion turbines, and we decided that it could not be identified for several reasons. At this time, CCS has not been implemented for NGCC units, and we believe there is insufficient information to make a determination regarding the technical feasibility of implementing CCS at these types of units. The EPA is aware of only one NGCC unit that has implemented CCS on a very small portion of its exhaust stream. The EPA is not aware of any demonstrations of NGCC units implementing CCS technology that would justify setting a national standard. Further, the EPA does not have sufficient information
on the prospects of transferring the coal

‐ based experience with CCS to NGCC units. In fact, CCS technology has primarily been applied to gas streams that have a relatively high to very high concentration of CO2 (such as that from a coal combustion or coal gasification unit). The concentration of CO2 in the flue gas stream of a coal combustion unit is normally about four times higher than the concentration of CO2 in a natural gas ‐ fired unit. Natural gas ‐ fired stationary combustion turbines also operate differently from coal

‐ fired boilers and IGCC units of similar size. The NGCC units are more easily cycled (i.e., ramped up and down as power demands increase and decrease). This cyclical operation, combined with the already low concentration of CO2 in the flue gas stream, lead to uncertainty about how technically feasible CCS technology might be demonstrated is for NGCC units absent further information. [note: GE

‐ Sargas propose using an aeroderivative turbine with multiple shafts to maintain gas pressures (to aid in capture) at varying turbine rates.]
o Page 264: “We do not consider full or partial capture CCS to be BSER because of these technologies have not been adequately demonstrated and there are uncertainties regarding the economic about technical feasibility and because of adverse impacts on electricity prices and the structure of the electric power sector.”
o Page 265: “First, we do not consider that are uncertain as to whether full or partial capture CCS has been adequately demonstrated is technically feasible for this source category.”

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## ­ EPA RESPONSE ­

19 o Page 266. Recommend deleting paragraph beginning “Moreover, identifying partial or full CCS as the BSER for new stationary combustion turbines would have significant adverse effects on national electricity prices, electricity supply, and the structure of the power sector.” Please reconsider how the text here could adversely impact other current and future efforts to move the US toward developing additional CCS technologies relevant to natural gas and other industrial sources, and revise the language accordingly. This text should not foreclose on future regulatory rationales for technological advancements and GHG pollution reduction, as most of these will always have costs that will need to be weighed against the relevant benefits, at that time. We do not have sufficient information on the current cost of NG

‐ CCS, which is enough per se not to move ahead with this as BSER. In future, we may have adequate demonstrations and economic information, at which time EPA may choose to evaluate costs against the benefits of reducing the social cost of carbon and related impacts in reaching its future decision, rather than just “we cannot do it because it costs more.”
o Page 266. EPA states: “We recognize that identifying full or partial CCS would as the BSER for this source category would result in significant emissions reductions, but at present, we already consider natural gas to be a low

‐ GHG

‐ emitting fuel and NGCC to be
a low

‐ emitting technology.” Recommend replacing “this source category” with “new stationary combustion turbines.”
o Powerpoint: “ we do not have the information to determine if it is technically feasible.” Reject CCS because it has not been adequately demonstrated. [ EPA Response : The EPA appreciates these specific recommended line

‐ edits and will consider them accordingly.] [ Additional EPA Response : While we have not made the specific suggested edits (listed above),
we have made a number of other edits on starting on or near pages277 that we believe are responsive to this comment. Also, to be clear, it is not our intention to impugn the NGCC+CCS configuration or to imply that it is technically infeasible. We do not feel that the current language does that. Rather, our intention is to convey our conclusion that there is currently insufficient available information for
us to determine the technical feasibility. We also point out that there are valid technical
reasons to question how well the experience with PC and gasification units will transfer to NGCC units. These include the difference in the CO 2 content of the respective flue gas or syngas streams and the differences in operation

– including the ability of NGCC units to cycle more quickly and more often. ]

Oil

‐ fired power plants:

 Our understanding from the introductory oral presentation is that EPA is not including oil

‐ fired power plants under either the coal or natural gas NSPS requirements. Hence, Hawaiian power plants would not be included under the NSPS, and there would be no need for a non ‐ continental exclusion. However, no such exclusion or discussion is in the FR text, and the Da regulatory language relates to all burning of fossil fuels in steam generating units. The only discussions of

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## ­ EPA RESPONSE ­

20 oil fired power plants imply that these are included under the NSPS for steam and IGCC units (p. 2

‐ 3; footnote 3 on page 20 includes oil; p. 99 liquid fuels; p.103 fuel oil, appears linked to gas; p.108 oil

‐ fired exempt from acid rain program; p.119 “but not liquid

‐ fired sources”). There is no mention of Hawaii. Could EPA please clarify whether oil fired power plants are in the NSPS, and how the standard relates to Hawaii and non ‐ continental emission sources. [ EPA Response : All new fossil fuel

‐ fired boiler/steam turbine EGUs (subpart Da) facilities would be subject to the proposed standards. No new natural gas or oil

‐ fired subpart Da facilities have been constructed recently and we do not anticipate any new natural gas or oil

‐ fired subpart Da facilities since it is less expensive and more efficient for construct natural gas and oil

‐ fired combined cycle facilities. However, GHG standards for combustion turbines (subpart KKKK) are only being proposed for facilities that burn over 90% natural gas on a heat input basis. New oil

‐ fired EGUs constructed in Hawaii and other non ‐ continental areas are projected to be combined cycle facilities and not subject to a GHG standard.]

 Page 81, EPA states: “Note that we are not proposing standards for new steam generating units and stationary combustion turbines that sell less than 1/3 of their potential output to the grid,
new non ‐ natural gas ‐ fired stationary combustion turbines, existing sources undertaking modifications or reconstructions, or certain projects under development as discussed below.” Can EPA provide an example of a “new non ‐ natural gas ‐ fired stationary combustion turbine?” Does this mean oil, and/or Hawaii, and how is this legally implemented in the Subpart Da and KKKK regulatory text sections? [ EPA Response: An oil

‐ fired combustion turbine in Hawaii would be an example of a combustion turbine not subject to an emissions standard. Table 2 in subpart KKKK will be clarified to specify that the standards only apply to facilities that combust over 90% natural gas on a heat input basis on a 3 year average period. Subpart Da would cover a new oil

‐ fired boiler/steam turbine based EGU. ]

 Page 119, EPA states: “Rather, the EPA is simply promulgating new standards of performance for CO 2 emissions from certain sets of sources, e.g., boilers and turbines, but not liquid

‐ fired sources.” How is such a “liquid

‐ fired source” exclusion implemented in the actual regulatory requirements under Da and KKKK? [EPA Response : See response to the previous comment.]

Combined heat and power:

 The commenter supports appropriate incentives for combined heat and power (CHP) and suggests further consideration of its treatment under the rule to reflect associated emissions benefits. [ EPA Response: We have concluded that the transmission and distribution benefit and thermal output credits sufficiently recognize the environmental benefit of CHP. We will be happy to discuss whether anything further would be appropriate.

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## ­ EPA RESPONSE ­

21 Biomass:

 How does EPA propose to handle new fossil fuel

‐ fired power plants that also rely on some percentage of renewable fuel? What percentage of renewable biomass would be necessary to offset the GHG emission contributions of the fossil fuel to the GHG emissions rate, as measured by the facility? [EPA Response: EPA recognizes the potential emissions benefits of co ‐ firing with biomass. In September 2011, EPA submitted its Draft Accounting Framework for Biogenic CO 2 Emissions from Stationary Sources to the Science Advisory Board (SAB) Biogenic Carbon Emissions (BCE) Panel for peer review. The SAB BCE Panel delivered its Peer Review Advisory to OAR on September 28, 2012 1
, and EPA is evaluating the peer review comments in order to determine the most appropriate method of accounting for CO 2 emissions from biogenic feedstocks in the regulatory context. The overall net atmospheric impact of using a biogenic feedstock will ultimately depend on the stationary source process and the type of feedstock used, as well as the conditions under which that feedstock is grown and harvested.]

 The commenter requests further consideration of the treatment of biomass emissions, particularly as it relates to the use of biomass co ‐ firing, to reflect its potential emissions benefits. [EPA Response : See above response.]

 How would biomass emissions be calculated for purposes of compliance with the NSPS? If that will be determined by EPA’s forthcoming rulemaking on biogenic carbon emissions for GHG permitting, should that be mentioned in the preamble? [EPA Response: See above response.]

 Notes from EPA’s oral presentation indicate that biomass is being treated the same as coal in these NSPS standards (p. 28). Does the recent court decision on biomass change this decision (URL below)? What plans does EPA have to develop a regulatory structure that would empower an appropriate use and consideration of the benefits of biomass power generation? http://www.eenews.net/greenwire/2013/07/15/stories/1059984404 [EPA Response: EPA recognizes the potential emissions benefits of co ‐ firing with biomass. In July 2011, EPA deferred for a period of three years the application of the Prevention of Significant Deterioration (PSD) and Title V Programs (76 FR 43490) to biogenic CO 2 emissions from stationary sources in order to conduct a detailed examination of the scientific and technical issues associated with those emissions. On July 12, 2013, the United States Court of Appeals for the District of Columbia Circuit issued its decision in Center of Biological Diversity v. EPA, No. 11

‐ 1101 (D.C. Circuit), vacating EPA’s July 2011 deferral rule. The Agency will evaluate

1 The text of the Peer Review Advisory can be found here: http://yosemite.epa.gov/sab/sabproduct.nsf/0/2f9b572c712ac52e8525783100704886!OpenDocument&TableRow =2.3#2.

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## ­ EPA RESPONSE ­

22 the Court’s decision and the scientific and technical considerations described above as it determines the next steps. ]

PSD and Title V Program:

 The commenter recommends adding the language in redline to the following discussion (on page 262): “As noted in the ‘Implications for PSD and Title V programs’ section of this preamble,
some states have authority to issue PSD permits. In other cases, the EPA issues the permit. States with approved permitting programs have some discretion in making permit decisions and including the necessary conditions of the permit to ensure the enforceability of the permit , subject to EPA’s oversight role

. Defendants in enforcement cases frequently raise “state permitting discretion” as a defense, so it would be useful to clarify this sentence about state discretion by mentioning EPA’s oversight role.” See, e.g. , Alaska Dept. of Environmental Conserv. v. EPA , 540 U.S. 461, 486 (2004) (affirming EPA’s “broad oversight role” for Best Available Control Technology determinations in the Prevention of Significant Deterioration (PSD) permitting process). [ EPA Response : The EPA will consider this recommendation and edit accordingly.] [ Additional EPA Response : The language in this section has been edited considerably starting on or near page 288.]

 The commenter recommends adding the language in redline to this discussion (on page 278): “Under the PSD program in part C of title I of the CAA, in areas that are classified as attainment or unclassifiable for NAAQS pollutants, a new or modified source that emits any air pollutant subject to regulation at or above specified thresholds is required to obtain a preconstruction permit. This permit assures that the source meets specified requirements, including application and operation of best available control technology.” The new text recognizes that the PSD program also imposes operational obligations. Defendants sometimes latch onto the term “preconstruction” to argue that PSD obligations end after construction. [ EPA Response : The EPA will consider this recommendation and edit accordingly.] [ Additional EPA Response : The language in this section has been edited considerably starting on or near page 288.]

 In section IX.E “Implications for Title V fee requirements for GHGs” EPA proposes two options for how to account for the increased costs to states of reviewing and issuing permits to facilities that emit GHGs under the Title V program. However, the preamble does not provide enough information to allow the reader to compare the two proposals. Which is more likely to lead to states charging adequate fees? Which is more likely to appeal to states that do not wish to charge adequate fees? [ EPA Response: We are seeking comment in the proposal on the level of fee revenue increase necessary to fully fund the cost of permitting GHGs as part of any state operating permit program that has based its fee adequacy demonstration on the presumptive minimum fee that

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## ­ EPA RESPONSE ­

23 is defined in our regulations; it is not an option for such states to collect fees that would, in the aggregate, be less than necessary to fund their operating permit program. Nevertheless, we will review the preamble text describing the two options for charging fees for GHGs and potentially revise existing language or add new language to compare the two options with respect to their ability to result in the collection of adequate fees to fund GHG permitting.] [ Additional EPA Response : The language in this section has been edited considerably starting on or near page 288.]

Emissions Trading:

 Why not attempt to introduce trading emissions credits as a method of compliance? Is it clear, for example, that reducing GHG emissions by 30 percent from three EGUs is more expensive than reducing GHG emissions by 90 percent from one of the three (assuming each facility generates CO 2 at the same rate)? [ EPA Response : The EPA will consider adding clarification and/or further discussion of the legality of emissions trading in the CAA § 111(b) context for new sources.] [ Additional EPA Response : We are still considering this suggestion.]

 EPA may wish to discuss whether emissions trading options would be economically efficient and legally possible in this regulation. While this rule is not expected to result in new compliance costs and therefore trading would not lower overall costs, we generally seek flexible mechanisms that have the potential to lower costs while providing the same environmental benefit. [ EPA Response : see above]

 From our reading, the preamble is silent to the concept of trading under section 111 of the Clean Air Act, though, to our knowledge, the courts have not explicitly ruled against it. One concern is that if trading would be a preferred option to address carbon emissions from existing sources, should this regulatory action do everything possible to enable that outcome? For example, if a trading system could be defined as the best system of emission reduction (BSER) for reducing carbon emissions from power plants, should that be defined here in the rule for
new sources?

 [ EPA Response : see above] Additionally, when and how would future power plants built to comply with these standards be
re ‐ categorized existing sources, and would these plants be able to trade with existing sources under 111(d) if trading is not an option under 111(b)? As an illustration, we would assume that
a new coal plant built with full CCS should be able to trade under an existing source trading program, would that be allowed if the standard for new sources doesn’t allow trading?

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## ­ EPA RESPONSE ­

24 [ EPA Response : There is no need in this preamble, which concerns new sources, to address trading for existing sources. What is the BSER for new sources may differ from the BSER for existing sources due to, for example, different cost considerations.] Existing sources:

 Is it necessary for EPA to promulgate standards of performance for GHG emissions from new sources before the agency can legally promulgate standards of performance for GHG emissions from existing sources? [ EPA Response: Under CAA §111(d), the EPA may not promulgate requirements for existing sources before it has promulgated standards of performance for new sources.]

 EPA’s discussion of BSER for coal continues to raise significant concerns about future actions as they relate to existing sources. Please provide further language to clarify EPA’s position regarding existing sources. For example, EPA asserts that “identifying partial CCS as the BSER for coal will be beneficial to coal

‐ fired electric generation

. . . .” (pp. 240), by eliminating uncertainty and forestalling future Federal controls that might require CCS. The logical implications of this statement and the subsequent discussion will be perceived as a threat of future requirements for existing sources. o Because the BSER for gas ‐ fired plants is NGCC without CCS, these plants must therefore “face the risk that future state or federal controls may require carbon capture, which

. . .

, is a particularly expensive proposition.”
o If partial CCS now can forestall a “particularly expensive proposition” for future existing sources (that is, sources built now under the NSPS), then EPA appears to be saying that currently existing coal

‐ fired power plants also face the risk of future requirements for CCS.
o EPA does not dispel the possibility that a partial CCS BSER now would be replaced with a full CCS requirement for future existing sources. [ EPA Response : These questions appear to concern the following paragraph in the preamble:

In addition, identifying CCS as the BSER for coal can be seen as beneficial to coal

‐ fired electric generation, and therefore fuel diversity, over the long term. This is because identifying CCS as BSER eliminates uncertainty as to future control obligations for coal

‐ fired capacity. Any new coal

‐ fired source that constructs without CCS faces the risk that future state or federal controls may require carbon capture, which would require the source to retrofit CCS, which, in turn, is a particularly expensive proposition. This risk is heightened because power plants are generally long

‐ lived

– in some cases, XX years – and the risk of future carbon limitations can be expected to remain throughout that period. (p. 240). We believe this paragraph is clear on its face, but we are prepared to discuss any aspects of it with the commenter.]

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## ­ EPA RESPONSE ­

25  Even though EPA states that this rule applies to newly constructed units, does EPA anticipate that the existing plants would face competitive pressures from the newly constructed units that will potentially be able supply energy more cheaply, effectively forcing the existing plants into upgrading their equipment which would mean they would also need to meet the new standard? If this is the case, EPA should take into account ex ‐ post compliance costs for the existing plants. [ EPA Response : No existing sources will need to comply with the proposed standard. However, as we have noted, the vast majority of recently constructed existing source NGCC units already meet the proposed emission standard for stationary combustion turbines.] Regulatory Impact Analysis: General comments

 Clarify language regarding environmental benefits

. Given that EPA is assuming the baseline and regulatory scenarios to be essentially equivalent, any language implying the draft rule will “limit” GHG emissions should be changed to state the rule is setting standards for emissions. “Limit” implies an incremental benefit resulting from the rule. See, e.g., first sentence of Sec. 1.1 in ES of RIA. [ EPA Response : As requested, the EPA will revise the RIA accordingly.]

[ Additional EPA Response : Revised throughout the RIA.]

 Clarify baseline years and period of analysis. The RIA refers to a base year of 2020, achieving negligible changes by 2020, and an analysis period defined through 2022. Please clarify. [ EPA Response : 2020 data and modeling are used as a proxy for the 2022 year of analysis. We will revise RIA to make references to this consistent.] [ Additional EPA Response : Revised throughout the RIA.]

 What is the impact of the CSAPR legal decisions on the use of this rule in the baseline? Please clarify the role of CSAPR given its current status. [ EPA Response : The legal status of CSAPR and CAIR makes no difference in this rule’s evaluation because they make no difference in the type of new capacity additions projected to be economic.] [ Additional EPA Response : Added footnote 11 in Ch. 5 with this explanation.]

 Has EPA consulted with NRC and FERC regarding the assumed growth in nuclear capacity? [ EPA Response : The EPA has not consulted with NRC and FERC over the specific nuclear projections contained in either the IPM or NEMS modeling; however, NRC orders, amendments,

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## ­ EPA RESPONSE ­

26 and guidance are reflected in modeling assumptions and tested in scenario development, thereby directly impacting nuclear uprate, retirement, and capacity expansion projections.]

 Please review and, if appropriate, revise footnote 72, potentially substituting the term “justify” for the term “necessary” to make the language consistent with Executive Orders relevant to Benefit Cost considerations. EO 13563 reiterates EO 12866 that “each agency must, among other things: (1) propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs (recognizing that some benefits and costs are difficult to quantify)

... (3) select, in choosing among alternative regulatory approaches, those approaches that maximize net benefits (including potential economic, environmental, public health and safety, and other advantages; distributive impacts; and equity);” [ EPA Response : The EPA will revise the footnote to read: EO 13563 states that each agency must “propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs (recognizing that some benefits are hard to quantify).” While the presence of net benefits for a given regulatory option is not the only condition necessary for optimal regulatory design, it does signify that the regulatory option is welfare improving for society.] [ Additional EPA Response : Revised footnote (now footnote 79) to address this comment.]

State of CCS technology

 Chapter 4, clarify Sec.4.5 to reflect the current developmental state of CO2 control technology. EPA’s own BACT guidance and the NETL study both acknowledge the formative state of CCS technology. In addition, while IGCC projects are under development, only a handful of such plants currently exist in the world. The language in this section reads as if IGCC and CCS are well

‐ established and already in widespread commercial practice. Please provide further explanation. This discussion should list the exact number of completed plants currently employing the discussed technologies, the size/maximum capacity of these plants and allowable under current technology, any geographic limitations (such as altitude and temperature considerations for IGCC), projects currently in development, including those for which investment ceased, and plants with significant cost overrun issues. If the agency prefers, some of this detail could be presented in Chapter 5 of the RIA. [ EPA Response : The EPA will reevaluate the language and clarify as appropriate.]

[ Additional EPA Response : Added footnote 54 in Ch. 5 to reference more comprehensive discussion in the preamble.]

 Page 5

‐ 28. EPA assesses that any new coal

‐ fired plant that might be built could incorporate carbon capture technologies in a way that would not be cost

‐ prohibitive. Are there any existing coal

‐ fired plants that use carbon capture technology? How did EPA generate its estimate of the additional levelized cost of energy of CCS (p. 5

‐ 49)?

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27 [ EPA Response : The EPA has detailed examples of existing sources that have demonstrated CCS and of facilities that are very near completion of construction that will utilize CCS. The EPA used data from the DOE/NETL cost and performance reports for estimates of LCOE.]

 The RIA also states that 70% of the CCS projects underway plan to use the captured carbon for enhanced recovery of oil. Are any of these projects being implemented by coal

‐ fired plants? [ EPA Response : Yes, some of the 16 projects that are under construction or at an advanced stage of planning that intend to use captured CO 2 for EOR are coal power plants, including Southern Company’s Kemper County Energy facility, Summit Power's Texas Clean Energy Project and the Hydrogen Energy California Project.]

 EPA’s analysis of cost and capacity suffer a significant selection bias because it relies on idealized and currently executed CCS projects and government economic incentives. (See RIA 5

‐ 7.)
o Economic incentives for current CCS projects are not generalizable to the entire coal industry or into the future because these are limited to only certain firms in the following ways:

 Time: Significant funding for the economic incentives alluded to in the RIA come from legislation designed to stimulate the economy during a recessionary period by increasing spending in a specific time period. These incentives then are likely to expire as the economy improves.

 Eligible projects: tax benefits from the State of Texas for CCS projects were capped at the first three major projects to qualify for the benefits.

 Complex application processes: Department of Energy financial assistance and USDA CO2 capture project loans are limited to those who follow the necessary application process

 Limited funds: Department of Energy had a set amount of funds that they could
use to incentivize projects as part of the Clean Coal Power Initiative Round III and therefore must prioritize its assistance

 Contrast: The incentives for nuclear power and other industries cited by EPA (see pp.226

‐ 7) are generally long

‐ standing and available to all firms in the industry, without application and not subject to appropriations. [ EPA Response : The EPA recognizes that federal and state assistance are not guaranteed; the EPA simply attempted to point out that subsidies have been available in the past and may be available for future projects to help defer some costs. We will check the existing language in the preamble and RIA to ensure that we have not indicated that we have expected those subsidies.] [ Additional EPA Response : Checked language in Ch. 5 and no revision needed.]

o EPA’s analysis of the feasibility and cost effectiveness of CCS technology centers on 2

‐ 3 specific examples of uncompleted CCS projects.

 None of the CCS systems in active projects are fully running. These projects also have cost and schedule overruns that may contradict some of the EPA’s idealized estimates

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28  The Southern Kemper County Project is experiencing substantial cost overruns of hundreds of millions dollars

 The Texas Clean Energy Project (TCEP) was supposed to start construction in Fall 2011 but had not started as of March 2013

 The EPA is understating the amount of financial assistance that each of the CCS projects mentioned in the preamble is receiving. In addition to DOE cost sharing programs as part of the ARRA, these projects are receiving millions of dollars in Federal tax credits from the IRS as well as assistance from state and local governments

 For example, the TCEP has received $450 million (over a quarter of the projected project cost) in cost sharing from the DOE and an additional $100 million from the ARRA. TCEP also benefited from a limited Texas State law that provided over $100 million in tax benefits as well as additional tax benefits for EOR.

 By only looking at a couple of examples, the EPA is understating the overwhelming cost and risk factors that have forced previous government

‐ supported CCS projects to be de

‐ scoped, tabled, or shut down

 Of the 6 projects funded by the Department of Energy’s Clean Coal Power Initiative Round III half have been forced to withdraw from the program. According to the Congressional Research Service, these projects have significantly de

‐ scoped, tabled, or shut down due to cost overruns or uncertainty regarding the effectiveness and efficiency of the CCS technology. [ EPA Response : The EPA will reevaluate the text in the preamble and the RIA to ensure that we have not misrepresented any costs associated with any of the existing plants that are currently (or imminently) being constructed.] [Additional EPA Response : Checked language in Ch. 5 and no revision needed.]

Natural Gas Price Assumptions

 Page 5

‐ 23 to 5

‐ 24. The regulatory impact analysis assess that for a new coal

‐ fired EGU without carbon capture to reach price parity with a natural gas EGU, the price of natural gas would have to rise to $10/MMBtu and that this price would exceed the most pessimistic forecast by about 30%. We understand that the forecasts include assumptions related to macroeconomic conditions, markets, etc. Would the model control for a shock to natural gas prices prompted by changes in U.S. export policy or trade policy?

For example, under current policy, liquefied natural gas (LNG) cannot be exported without a finding from the Department of Energy that such export is in the public interest. Exports to Free Trade Agreement partner countries are deemed automatically to be in the public interest. Should the U.S. successfully conclude the TransPacific Partnership (TPP) trade negotiations (with Japan as a TPP member and one of the world’s largest LNG importers) and/or trade negotiations with the EU, this would presumably lead to a large increase in exports to these regions. A study by DOE predicted that increased exports (resulting from current pending applications but not to

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29 future exports to new FTA partners) would increase the domestic price of LNG by $.22

– 1.11 (2010$/McF). Would such increases be accounted for in your model? [ EPA Response : Yes, there is a significant increase in assumed LNG export capacity

– new liquefaction capacity is projected to start at 0.6 billion cubic feet per day in 2016, increasing to 4.5 billion cubic feet per day in 2027. In the AEO2013 Reference Case, U.S. exports of domestically sourced LNG are projected to reach 1.6 trillion cubic feet per year in 2027. LNG export levels significantly exceed this amount in the ‘High Oil and Gas Resource’ scenario. The natural gas price projections of the Reference Case and High Oil and Gas Resource scenario are both included in the RIA.]

 The EPA’s assessments of energy prices and electricity demand rely on data biased by poor economic conditions
o According to the producer price index, real prices for energy have increased substantially since the time of the EPA’s analysis in the RIA. This development means that the EPA’s analysis will likely understate future energy price increases.
o By largely representing a recessionary period, the EPA’s data reflects extraordinarily low electricity demand due to a contracting economy, a trend that has started to reverse itself as the economy moves out of the recession. Therefore, the EPA’s analysis will likely undervalue the future demand for electricity.
o Natural gas prices are historically volatile. Where there has recently been some stability in prices this stabilization has occurred after the period of time that the EPA is analyzing in the RIA and should be taken into account as the EPA may understate future natural gas prices. [ EPA Response : Short

‐ term movements in the PPI are volatile and generally not relevant to defining the appropriate inputs to a long

‐ term, fundamentals

‐ based model such as IPM and NEMS. The demand derivation EPA utilizes from EIA does not rely on data biased by poor economic conditions; it is the result of considered forward views by industry experts of economic growth, energy intensity, and primary energy use by sector, among many other key drivers. Specifically, GDP growth is more a function of expected future labor force participation, capital stock growth, and worker productivity than the simple continuation of a slow economic recovery. The 2.5% average GDP growth (2011

‐ 2040 average) that underlies the Reference Case is broadly consistent with official estimates and is supplemented in EPA’s analysis by both a High Economic Growth scenario as well as a Low Economic Growth scenario. EPA is open to discussing the issue. For a concise overview of the demand derivation underlying the AEO2013 runs, please refer to the ‘Market Trends’ section (page 55) of the full AEO2013 report.

On the issue of natural gas price volatility, the RIA contains the following paragraph: “Short

‐ term fuel price volatility is not relevant in this context because new power plants have asset lives measured in decades, not in months or years, and new capacity investment decisions
are based on long

‐ run expected prices, not month

‐ to

‐ month, or even year ‐ to year, variations in fuel prices. Shorter

‐ term prices will affect how units are dispatched, but these potential dispatch impacts are considered over a longer time horizon and factored into the choice of which type of plant to build. In contrast, the uncertainty surrounding long

‐ term fuel prices will

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## ­ EPA RESPONSE ­

30 exert significantly greater influence on the technology selected for new capacity additions. In a modeling context with perfect foresight, this longer term uncertainty may be evaluated by the scenario testing presented throughout this analysis.” We are open to discussing this issue, including the role of natural gas price hedging and how the trend from offshore to onshore production has impacted the relationship between past and expected future natural gas price volatility.]

NETL study.

 EPA tabulates and relies primarily on NETL estimates of the LCOE for the various energy generation sources. We are more familiar with the annual EIA numbers, and these differ from the NETL values, for instance EIA (2013) estimates the LCOE for NGCC at $65.6/MWhr, whereas NETL/EPA estimate $52/MWhr. A number of the tables actually provide footnotes identifying the EIA numbers, which is very helpful. The recommendation is that such footnotes be provided once, early on, and with a brief explanation of why the numbers differ, beyond just the subtraction of the transmission cost estimates. [ EPA Response : The NETL cost numbers excluded the following from the capital costs:

1. Escalation to period

‐ of

‐ performance 2. Owner’s costs

– including, but not limited to land acquisition and right

‐ of

‐ way, permits and licensing, royalty allowances, economic development, project development costs, allowance for funds

‐ used

‐ during construction, legal fees, Owner’s engineering, preproduction costs, furnishings, Owner’s contingency, etc. 3. All taxes, with the exception of payroll taxes 4. Site specific considerations

– including but not limited to seismic zone, accessibility, local regulatory requirements, excessive rock, piles, laydown space, etc. 5. Labor incentives in excess of a 5

‐ day/10

‐ hour work week 6. Additional premiums associated with an EPC contracting approach ] [Additional EPA Response : Figure 5

‐ 3 in Ch. 5 to provide more information about NETL costs.]

 Clarify NETL analysis as based on simulations/models and literature reviews and state key assumptions. Please see below for specific suggested further clarifications regarding the NETL study.

- Clarify NETL’s assessment of the analyzed technology. Please acknowledge in EPA’s discussion, the following NETL statements/findings. In addition, provide further explanation as to how EPA came to the conclusion that partial CCS is BSER (incl. emissions limit) given the NETL assessments. For example, have new facilities come on line since this study, or have new innovations occurred?

 Page 37, NETL. “The post

‐ combustion CO2 removal technology for the PC capture cases is immature technology. This technology remains unproven at commercial scale in power generation applications.”

 Page 37

‐ 38, NETL. “The pre ‐ combustion CO2 removal technology for the IGCC capture cases has a stronger commercial experience base. Pre

‐ combustion CO2 removal from syngas streams has been proven in chemical

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## ­ EPA RESPONSE ­

31 processes with similar conditions to that in IGCC plants, but has not been demonstrated in IGCC applications. While no commercial IGCC plant yet uses CO2 removal technology in commercial service, there are currently IGCC plants with CO2 capture well along in the planning stages.”

 Page 33

‐ 34, NETL. Environmental targets for IGCC were chosen to match EPRI’s design basis for Coal Fleet for Tomorrow Initiative. EPRI notes these designs are ‘targets’ and not to be used for permitting values. Further as of the report publication, NETL states there are 4 operating IGCC’s worldwide that use a solid feedstock and are primarily power producers (Polk, Wabash, Buggenum, & Puertollano). Further (p. 26, NETL), the NETL Aspen simulations assume zero elevation, which is optimal for IGCC performance.

- Clarify that ‘slip stream’ cost

‐ effectiveness was determined through literature review. (5

‐ 18) The RIA states that NETL determined the slip stream approach to be the most cost

‐ effective. At several points the NETL study (see, e.g., p. 2, 22, 77) states it made this determination via literature review. It should be made clear that this determination was not made through either simulation or direct analysis of data
or actual case studies. Further EPA should state whether it has any actual data on the cost

‐ effectiveness of the slip stream approach. This might include noting whether the literature NETL reviewed used empirical data.

- Clarify expected accuracy of NETL estimates. Exhibit 2

‐ 15, p. 37 of the NETL study notes that cost estimates are expected to vary by ‐ 15% to ‐ 30% on the low side and ‐ 20% to +50% on the high side. This uncertainty should be reflected in the Chapter 5 tables.

- Clarify uncertainty of transportation (TS&M) estimates. P. 47, NETL. NETL states cost metrics for TS&M are “costs for a ‘favorable’ sequestration project, and may vary significantly based on variables such as terrain to be crossed by the pipelining, reservoir characteristics, and number of landowners from which sub

‐ surface rights must be acquired.” Further, NETL assumes transportation costs for the IL No. 6 coal will be 25% of mine mouth costs based on the Midwestern region with limestone available within a few states (Morgantown WV). Is this assumption applicable to costs in other regions of the US?

- Clarify cost assumptions regarding substitutability of NGCC, IGCC and coal w/partial CCS. Please provide further explanation for this assumption including citations where relevant. The NETL study EPA that references notes that simulations indicate electricity and capital costs for SC PC w/CCS v. GEE IGCC w/CCS vary according to level of CO2 capture. At lower levels, coal is cheaper for the owner with costs converging to roughly equivalent at above 90% capture. What levels of emissions/CO2 is EPA assuming when making this substitutability assumption?

- Clarify CSAPR/MATS v. NETL baselines. The NETL study assumes the 2006/2007 NSPS is in place but does not discuss CSAPR/MATS. Does EPA anticipate any significant tensions in these assumptions? Alternatively, did EPA make adjustments in IPM to accommodate the more current baseline? E.g. the NETL study assumes model plants
use IL No. 6 high

‐ sulfur bituminous coal whereas CSAPR and MATS differ in both coal use (PRB) and transport assumptions. In addition, the RIA should add a footnote recognizing the recent CSAPR decision. While the analytics of the current

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## ­ EPA RESPONSE ­

32 legal environment would prove difficult to capture in the baseline, it is noteworthy that the decision found certain requirements to be too stringent for some states, which could (or not) in turn impact the level of control technology put in place.

- Clarify net capacity assumptions in relation to industry. The NETL study assumes 550 MWe for SC PC and a range of 523

‐ 622 MW for IGCC. How does this assumption relate to regulated entities? What, if any, technology limitations might exist for larger facilities?

- Clarify the impact of NETL’s within the fenceline assumption. While NETL considers capital and transport costs, these are limited to within the fenceline of the facility. Did EPA make any adjustments to its cost estimates for costs associated with pipeline investments and operating costs beyond the fenceline? If not, why? Is 50 miles/80km as assumed by NETL expected to be typical pipeline distance? [ EPA Response : The EPA will reevaluate the existing text in the draft preamble and RIA and clarify according to the above recommendations as appropriate.]

[Additional EPA Response : Made several edits in Ch. 5 (ex. Fn 37, Figure 5

‐ 3, Table 5

‐ 5) to address comments.] Paperwork Reduction Act

 This rule should impose no additional paperwork burden, since EPA asserts that this rule will have a negligible economic impact and a no “notable” CO 2 emission reductions. [EPA Response : This proposed rule does have some additional data elements required to be reported to EPA electronically and these few data elements impose negligible burden. This data is minimal and needed to ensure compliance with the emissions limits set in the proposed rule. ]

o The PRA disfavors reporting and recordkeeping requirements intended simply to remind
a regulated entity that substantive regulations exist. All information collections must have practical utility, which means the information gathered must be actually used rather than have a potential use. [EPA Response : The reporting under this rule is to ensure compliance with the CO 2 emissions limits set under the proposed rule. The information is needed to determine compliance with a Part 60 regulation and is different than what the Part 98 GHG reporting rule requires.]

o If industry will proceed as it is, with or without the rule, EPA should eliminate any reporting or recordkeeping requirements associated with the NSPS, since there will be nothing to enforce. [EPA Response : The EPA is proposing standards of performance and must also specify reporting and recordkeeping requirements for those standards.]

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33 o CO 2 emissions appear to be a function of the design of the electricity generating unit. Thus, if a new technology appears, CO 2 emissions can be modeled as part of the existing permitting and reporting processes in place of emissions monitoring requirements. [EPA Response : The CO 2 emissions limits are based on using the categorizations of Part 60 Subparts Da and KKKK. If new electric generating technology is developed a new NSPS would need to be developed to cover the technology. When that is proposed/promulgated a new CO 2 limit would need to be set along with other applicable criteria pollutant limits.]

o For those units for which CCS can be operated at variable rates, existing GHG reporting requirements should be sufficient to ensure compliance with the NSPS. Alternatively, all units subject to the NSPS should be exempted from the separate GHG reporting requirements. [EPA Response: The proposed NSPS requirements rely on the existing electronic reporting framework currently employed by Part 75. The proposed amendments to the GHG Reporting Program are not redundant with the proposed NSPS requirements; rather, the GHG Reporting Program framework is used to ensure that CO 2 captured at an affected unit is transferred to a facility reporting geologic sequestration.] Editorial/technical comments: Preamble

 On page 31, section 6 is entitled “[w]hat is BSER for fossil fuel

‐ fired stationary combustion turbines?” This would appear to refer both to natural gas fired and coal fired power plants. However, the discussion in section 6 is limited to natural gas fired power plants. [ EPA Response : Agreed

 The commenter recommends the deletion of the text in strike out in the following sentence (on page 68): “A modification is ‘any physical change

. . . or change in the method of operation

. . . which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted,’ unless it is a specific type of change, exempt from consideration as a modification , such as installation of pollution control projects

. The validity of the pollution control project (PCP) exemption for NSPS has never been litigated, but it might be prudent to avoid highlighting the issue because the parallel PCP exemption for New Source Review was vacated in New York v. EPA , 413 F.3d 3 (D.C. Cir. 2005). [ EPA Response : Agreed]

 Discussion of Coordination with Other Rules Applicable to Power Plants (page 74): The commenter recommends revision of this sentence as follows: “The EPA recognizes that it is important that each of these regulatory efforts achieves its intended environmental objectives in a common ‐ sense, cost

‐ effective manner that is consistent with the underlying statutory requirements and that minimize impacts on electricity rates and assure s a reliable power

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34 system.” Because the sentence already mentions that EPA is attempting to be “cost effective,” the reference to minimizing impacts on electric rates is redundant. Also, the commenter would prefer to avoid discussion of rate impacts because it is problematic for power plant enforcement. Utilities frequently raise rate impacts as a reason for delaying or avoiding compliance once they are found in violation of the CAA. [ EPA Response : Agreed]

 EPA should add the language in redline to the following sentence (on page 114): “Therefore, with this 40 percent sales criterion on a single

‐ year basis, as a practical matter, it is anticipated that few new simple cycle turbines would be subject to the proposed standards of performance.” [ EPA Response : Agreed]

 Page 134. Please check latest estimates of sea level rise. The likely range for sea level between 2080 and 2100 from the AR5 is between 0.26m (10 inches) and 0.81m (31 inches) with most of the uncertainty having to do with emissions scenarios. Although higher than 7

– 23 inches, this is not “twice as large or more.” [ EPA Response : The language has been edited accordingly.]

 For consistency with the New Source Review Program, please substitute the following text in redline (on page 240): “In addition, identifying partial CCS as the BSER for coal will be beneficial to coal

‐ fired electric generation, and therefore fuel diversity, over the long term. This is because Identifying partial CCS as BSER eliminates uncertainty as to future control obligations for coal

‐ fired capacity. Any new coal

‐ fired source that constructs without CCS faces the risk that future state or federal controls may require carbon capture, which would require the source to retrofit CCS, which, in turn, is a particularly expensive proposition. This risk is heightened because power plants are generally long

‐ lived have expected lives of 30 to 40 years and the risk of future carbon limitations can be expected to remain throughout that period.” [ EPA Response : Agreed]

 Page 273, in Discussion of Emission Rates for Smaller

‐ Size Units: Please ask EPA if there is a technical error in the following sentence so that the second use of “1000” should read “1100”: “Two of the small combined cycle facilities had a maximum 12

‐ operating

‐ month rolling average emissions rate equal to or greater than 1,000 lb CO2/MWh and one had an maximum 12

‐ operating

‐ month rolling average emissions rate equal to or greater than 1,000 lb CO2/MWh.” (The rule establishes an emissions limit of 1100 lb CO2/MWh for certain smaller units.) [ EPA Response : Agreed]

Regulatory Impact Analysis

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35  Page 4

‐ 25, middle of the page: “Friday, June 7th” should be “June 7, 2013.” [ EPA Response : As requested, the EPA will revise the text accordingly.] [Additional EPA Response : Revised on p. 4

‐ 26.]

 Page 5

‐ 1, second paragraph, last sentence before the bullet points: Should 2022 be 2020? We thought the analysis went through 2020 per page 1

‐ 2, which says every eight years is 2020. [ EPA Response : 2020 data and modeling are used as a proxy for the 2022 year of analysis. We will revise RIA to make references to this consistent.] [ Additional EPA Response : Revised throughout the RIA.]

 Page 5

‐ 2, drop “likely” from the phrase “the proposed EGU GHG NSPS would likely provide net social benefits” given that the benefit cost ratio is clearly positive under a wide range of assumptions. [ EPA Response : As requested, the EPA will revise the text accordingly.] [ Additional EPA Response : Removed “likely” and added “under a range of assumptions” in multiple places in Ch. 5.]

 Page 5

‐ 2, middle of the page, second full paragraph, second sentence, part (3): should the word solid be added? On page 2

‐ 6, it appears that solid fossil

‐ fired EGUs are a separate category. [ EPA Response : For this proposed rule, the subcategories are: (1) natural gas ‐ fired stationary combustion turbines with a heat input rating to the turbine engine that is greater than 850 MMBtu/hr; (2) natural gas ‐ fired stationary combustion turbines with a heat input rating to the turbine engine that is less than or equal to 850 MMBtu/hr; and (3) all fossil fuel

‐ fired boilers and IGCC units (regardless of fuel

... i.e., solid, liquid and gaseous fossil fuels. The preamble and RIA will be reviewed thoroughly to ensure that we have consistently identified the subcategories. ] [ Additional EPA Response : Revised throughout the RIA to clarify.]

 Given that the rule extends to 2022, suggest EPA to include IPM projections for 2025 in addition to 2020 in Tables 5

‐ 1 and 5

‐ 3 to enhance clarity of information presentation. EPA could also consider including IPM results for 2030 to enhance comparison with AEO 2013 presented in the
same tables. [ EPA Response : There is no 2025 run year in EPA’s IPM projections; the 2020 run year is mapped to calendar years 2017

‐ 2024 and the 2030 run year is mapped to calendar years 2025

‐ 2034. We will consider including 2030 projections.]

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36 [ Additional EPA Response : At this time we have not made this revision. However, 2030 projections are available in the docket and on the website.]

 Page 5

‐ 34, clarify why the ratio of total CO 2 emissions (3.0/2.7) is lower than the ratio of CO 2 emissions rates (1,400/1,200), for the IGCC and SCPC, respectively. [ EPA Response : The EPA appreciates this comment and is evaluating this further.] [ Additional EPA Response : The ratios do not match due to rounding. Using unrounded numbers to calculate the ratio for total CO2 emissions (3.041356/2.728996)and the ratio for CO2 emissions rates (1,362/1,222) yields equivalent ratios. Added a note to indicate the values are rounded.]

 Also, drop “of these technologies” in paragraph 5.7. [ EPA Response : As requested, we will edit to drop “of these technologies”.] [ Additional EPA Response : Edit made in 5.7.]

 Page 5

‐ 37, To avoid confusion, note in FN a that the updated SCC values were presented originally in the April 2013 TSI using 2007$.
[ EPA Response : As requested, we will add a note about the dollar year of the SCC.] [ Additional EPA Response : Edit made in Ch. 5 footnote 64.]

 Page 5

‐ 42, In table 5

‐ X double check the valuations attached to the PM2.5 benefits since it is surprising that these are comparable to the CO 2 related benefits, particularly since these estimates use the updated higher SCC values and reference new coal plants with relatively low PM emissions. [ EPA Response : As requested, we have double checked these calculations and they are correct. We added a table of PM2.5

‐ related benefit per ‐ ton values to highlight the magnitude of these values, showing that they can add up quickly. The valuations attached to the PM2.5 benefits in table 5

‐ X on page 5

‐ 42 are derived by taking the difference in SO2 and NOX emissions per ‐ MWh from table 5

‐ 19 on page 5

‐ 34, converting to tons (i.e. dividing by 2000 lbs/ton), and multiplying by the pollutant

‐ specific benefit per ton discussed on page 5

‐ 40.] [ Additional EPA Response : Added table 5

‐ 12 to show magnitude of health benefit

‐ per ‐ ton values.]

 Table on 5

‐ 44, second column. Should this show PM2.5 dis

‐ benefits? According to the table on pg 5

‐ 34, the SO2 emissions increase by about 1/3 from 23 to 30lbs/MWh.

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37 [ EPA Response : The emissions increase is 23 to 30 tons per year, not lbs/MWh. On a per megawatt

‐ hour basis, the emissions increase from 0.003 lbs/MWh to 0.013 lbs/MWh. This results in a negligible PM2.5 disbenefit per megawatt

‐ hour, as noted in the footnote to the table
on p. 5

‐ 45. These negligible disbenefits are also included in the calculation of the total benefits reported in the table.]

 Page 5

‐ 49, “To evaluate the potential revenues from EOR we estimate the revenue in each scenario if CO 2 could be sold for $20/ton based on [update source of estimate].” Yes, this is an important input number. Please update. [ EPA Response : As requested, we will update with a reference.] [ Additional EPA Response : Added reference on p. 5

‐ 56.]

 Table 5

‐ X, p.5

‐ 49. The bottom line (last row) numbers in these tabulated calculations could be made a lot clearer by adding a plus sign before the right digits in the paired presentation. Currently, the text: << ‐ $7.1 ‐ $38 >> reads as if there are negative benefits (which is a bad thing) from negative seven to negative thirty

‐ eight dollars. Tracing the actual math leading to this reveals that the $38 is actually positive, hence the suggestion to affirmatively add the plus sign to << ‐ $7.1 ‐ +$38 >>. Same with the other columns. [ EPA Response : As requested, we will revise to clarify.] [ Additional EPA Response : Tables updated to indicate range using “to” instead of “

‐ “.]

Citations

 Page 40 Footnote 9, Page 130 Footnote 89 (Citation of the Coalition for Responsible Regulation Case): Here is the missing citation: Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency, 684 F.3d 102 (D.C. Cir.), reh’g en banc denied, 2012 U.S. App. LEXIS 25997, 26313 (D.C. Cir. 2012), petitions for cert. filed, No. 12

‐ 1253 (U.S. Apr. 2013). [ EPA Response : As requested, we will revise to clarify.] [ Additional EPA Response : The citation has been edited accordingly.]

 Page 73 Footnote 61 (Citation of the Las Brisas Case): EPA may use this citation to the December 13, 2012 order: Las Brisas Energy Center, LLC v. Environmental Protection Agency, No. 12

‐ 1248, 2012 U.S. App. LEXIS 25535 (D.C. Cir. Dec. 13, 2012). [ EPA Response : As requested, we will revise to clarify.] [ Additional EPA Response : The citation has been edited accordingly.]