Review of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units

Federal RegisterDec 20, 2018

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2013-0495; FRL-9987-85-OAR]

RIN 2060-AT56

Review of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

SUMMARY:

The Environmental Protection Agency (EPA) is proposing amendments to the rulemaking titled “Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units (EGUs),” which the EPA promulgated by notice dated October 23, 2015 (

i.e.,

the 2015 Rule). Specifically, the EPA proposes to amend its previous determination that the best system of emission reduction (BSER) for newly constructed coal-fired steam generating units (

i.e.,

EGUs) is partial carbon capture and storage (CCS). Instead, the EPA proposes to find that the BSER for this source category is the most efficient demonstrated steam cycle (

e.g.,

supercritical steam conditions for large units and subcritical steam conditions for small units) in combination with the best operating practices. The EPA proposes to revise the standard of performance for newly constructed steam generating units as separate standards of performance for large and small steam generating units that reflect the Agency's amended BSER determination. In addition, the EPA proposes to revise the standard of performance for reconstructed steam generating units to be separate standards of performance for reconstructed large and small steam generating units, consistent with the proposed revised standards for newly constructed steam generating units. The EPA also proposes separate standards of performance for newly constructed and reconstructed coal refuse-fired EGUs. In addition, the EPA proposes to revise the maximally stringent standards for large modifications of steam generating units to be consistent with the standards for reconstructed large and small steam generating units. The EPA is not proposing to amend and is not reopening the standards of performance for newly constructed or reconstructed stationary combustion turbines. The EPA is also proposing to make other miscellaneous technical changes in the regulatory requirements.

DATES:

Comments.

Comments must be received on or before February 19, 2019.

Public Hearing.

The EPA is planning to hold at least one public hearing in response to this proposed action. Information about the hearing, including location, date, and time, along with instructions on how to register to speak at the hearing, will be published in a second

Federal Register

notice.

ADDRESSES:

Comments.

Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2013-0495, at

https://www.regulations.gov.

Follow the online instructions for submitting comments. Once submitted, comments cannot be edited or removed from

Regulations.gov

. See

SUPPLEMENTARY INFORMATION

for detail about how the EPA treats submitted comments.

Regulations.gov

is our preferred method of receiving comments. However, other submission methods are accepted:

•

Email: a-and-r-docket@epa.gov.

Include Docket ID No. EPA-HQ-OAR-2013-0495 in the subject line of the message.

•

Fax:

(202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-2013-0495.

•

Mail:

To ship or send mail via the United States Postal Service, use the following address: U.S. Environmental Protection Agency, EPA Docket Center, Docket ID No. EPA-HQ-OAR-2013-0495, Mail Code 28221T, 1200 Pennsylvania Avenue NW, Washington, DC 20460.

•

Hand/Courier Delivery:

Use the following Docket Center address if you are using express mail, commercial delivery, hand delivery, or courier: EPA Docket Center, EPA WJC West Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004. Delivery verification signatures will be available only during regular business hours.

FOR FURTHER INFORMATION CONTACT:

For questions about this proposed action, contact Mr. Christian Fellner, Sector Policies and Programs Division (Mail Code D205-01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541-4003; fax number: (919) 541-4991; and email address:

fellner.christian@epa.gov.

For information about the applicability of the new source performance standards (NSPS) to a particular entity, contact Sara Ayres, U.S. Environmental Protection Agency, Region 5, 77 West Jackson Boulevard (Mail Code E-19J), Chicago, Illinois 60604-3507; telephone number (312) 353-6266; and email address:

ayres.sara@epa.gov.

SUPPLEMENTARY INFORMATION:

Docket.

The EPA has established a docket for this rulemaking under Docket ID No. EPA-HQ-OAR-2013-0495. All documents in the docket are listed in

Regulations.gov

. Although listed, some information is not publicly available,

e.g.,

confidential business information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy. Publicly available docket materials are available either electronically in

Regulations.gov

or in hard copy at the EPA Docket Center, Room 3334, EPA WJC West Building, 1301 Constitution Avenue NW, Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the EPA Docket Center is (202) 566-1742.

Instructions.

Direct your comments to Docket ID No. EPA-HQ-OAR-2013-0495. The EPA's policy is that all comments received will be included in the public docket without change and may be made available online at

https://www.regulations.gov,

including any personal information provided, unless the comment includes information claimed to be CBI or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through

https://www.regulations.gov

or email. This type of information should be submitted by mail as discussed below.

The EPA may publish any comment received to its public docket. Multimedia submissions (audio, video,

etc.

) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission (

i.e.,

on the Web, cloud, or other file sharing system). For additional submission methods, the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit

https://www.epa.gov/dockets/commenting-epa-dockets.

The

https://www.regulations.gov

website allows you to submit your comments anonymously, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through

https://www.regulations.gov,

your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the internet. If you submit an electronic comment, the EPA recommends that you include your name and other contact information in the body of your comment and with any digital storage media you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should not include special characters or any form of encryption and be free of any defects or viruses. For additional information about the EPA's public docket, visit the EPA Docket Center homepage at

https://www.epa.gov/dockets.

The EPA is soliciting comment on numerous aspects of the proposed rule. The EPA has indexed each comment solicitation with an alpha-numeric identifier (

e.g.,

“C-1,” “C-2,” ”C-3,” . . .) to provide a consistent framework for effective and efficient provision of comments. Accordingly, the EPA asks that commenters include the corresponding identifier when providing comments relevant to that comment solicitation. The EPA asks that commenters include the identifier in either a heading, or within the text of each comment (

e.g.,

“In response to solicitation of comment C-1, . . .”) to make clear which comment solicitation is being addressed. The EPA emphasizes that the Agency is not limiting comment to these identified areas and encourage provision of any other comments relevant to this proposal.

In this proposal, in some instances, the EPA identifies an issue that the Agency has previously addressed, and states that the Agency is not re-opening that issue in this proposal. The EPA will not consider such an issue as relevant to this proposal.

Submitting CBI.

Do not submit information containing CBI to the EPA through

https://www.regulations.gov

or email. Clearly mark the information that you claim to be CBI. For CBI information on any digital storage media that you mail to the EPA, mark the outside of the digital storage media as CBI and then identify electronically within the digital storage media the specific information that is claimed as CBI. In addition to one complete version of the comments that includes information claimed as CBI, you must submit a copy of the comments that does not contain the information claimed as CBI directly to the public docket through the procedures outlined in

Instructions

above. If you submit any digital storage media that does not contain CBI, mark the outside of the digital storage media clearly that it does not contain CBI. Information not marked as CBI will be included in the public docket and the EPA's electronic public docket without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 Code of Federal Regulations (CFR) part 2. Send or deliver information identified as CBI only to the following address: OAQPS Document Control Officer (C404-02), OAQPS, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711, Attention Docket ID No. EPA-HQ-OAR-2013-0495.

Preamble Acronyms and Abbreviations.

The EPA uses multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, the EPA defines the following terms and acronyms here:

AEO Annual Energy Outlook

BACT best available control technology

BSER best system of emission reduction

Btu/kWh British thermal units per kilowatt-hour

Btu/lb British thermal units per pound

°C degrees Celsius

CAA Clean Air Act

CAAA Clean Air Act Amendments

CAMD Clean Air Markets Division

CBI confidential business information

CBO Congressional Budget Office

CCS carbon capture and storage (or sequestration)

CEMS continuous emissions monitoring system

CFB circulating fluidized bed

CFR Code of Federal Regulations

methane

CHP combined heat and power

CO carbon monoxide

carbon dioxide

CSP concentrated solar power

DC District of Columbia

D.C. Circuit United States Court of Appeals for the District of Columbia Circuit

DOE Department of Energy

ECMPS emissions collection and monitoring plan system

EGU electric utility generating unit

EIA U.S. Energy Information Administration

EOR enhanced oil recovery

EPA Environmental Protection Agency

°F degrees Fahrenheit

FB fluidized bed

FGD flue gas desulfurization

FLGR

fuel lean gas reburning

GHG greenhouse gas

GHGRP Greenhouse Gas Reporting Program

GJ/h gigajoules per hour

GPM gallons per minute

GS geologic sequestration

GW gigawatts

hydrogen gas

HAP hazardous air pollutant(s)

HFC hydrofluorocarbon

Hg mercury

HRSG heat recovery steam generator

ICR information collection request

IGCC integrated gasification combined cycle

IRPs Integrated Resource Plans

km kilometers

lb CO

/MMBtu pounds of CO

per million British thermal units

lb CO

/MWh pounds of CO

per megawatt-hour

lb CO

/MWh-gross pounds of CO

per megawatt-hour on a gross output basis

lb CO

/MWh-net pounds of CO

per megawatt-hour on a net output basis

LCOE levelized cost of electricity

M million

MMBtu/h million British thermal units per hour

MPa megapascals

MW megawatts

MWh megawatt-hours

net

megawatts-net

molecular nitrogen

O nitrous oxide

NAAQS national ambient air quality standards

NAICS North American Industry Classification System

NETL National Energy Technology Laboratory

NGCC natural gas combined cycle

NGR natural gas reburning

nitrogen oxides

NSPS new source performance standards

NTTAA National Technology Transfer and Advancement Act

O&M operation and maintenance

OAQPS Office of Air Quality Planning and Standards

OFA overfire air

OMB Office of Management and Budget

PC pulverized coal

PFC perfluorocarbon

PM particulate matter

PRA Paperwork Reduction Act

PSD Prevention of Significant Deterioration

psi pounds per square inch

psig pounds per square inch gauge

QA quality assurance

RCRA Resource Conservation and Recovery Act

RFA Regulatory Flexibility Act

SBA Small Business Administration

SCCFB supercritical circulating fluidized bed

SCE&G South Carolina Electric and Gas

SCPC supercritical pulverized coal

SCR selective catalytic reduction

sulfur hexafluoride

sulfur dioxide

SSM startup, shutdown, and malfunction

T&S transmission and storage

TSD technical support document

UAMPS Utah Associated Municipal Power Systems

µg/m

micrograms per cubic meter

UMRA Unfunded Mandates Reform Act of 1995

U.S. United States

U.S.C. United States Code

VCS voluntary consensus standard

Organization of this Document.

The information in this preamble is organized as follows:

I. General Information

A. Executive Summary

B. Types of Sources

C. The 2015 Rulemaking, Reconsideration, and Litigation

D. The Purpose of This Regulatory Action

E. Does this action apply to me?

F. Where can I get a copy of this document and other related information?

II. Proposed Requirements for New, Reconstructed, and Modified Sources

A. Applicability Requirements

B. Emission Standards

III. Legal Authority

A. Statutory Background

B. Authority To Revise Existing Regulations

C. Authority To Regulate CO

From Fossil Fuel-Fired EGUs

IV. Rationale for Proposed Applicability Criteria

V. Rationale for Proposed Emission Standards for New and Reconstructed Fossil Fuel-Fired Steam Generating Units

A. Review of the 2015 BSER Analysis

B. Identification of the Revised BSER

C. Reconstructed EGUs

D. Coal Refuse Subcategory

E. Determination of the Level of the Standard

F. Format of the Output-Based Standard

VI. Rationale for Proposed Emission Standards for Modified Fossil Fuel-Fired Steam Generating Units

A. Identification of the BSER

B. Determination of the Level of the Standard

VII. Interactions With Other EPA Programs and Rules

VIII. Summary of Cost, Environmental, and Economic Impacts

A. What are the air impacts?

B. What are the energy impacts?

C. What are the compliance costs?

D. What are the economic and employment impacts?

E. What are the benefits of the proposed standards?

IX. Request for Comments

A. Subcategorization by Fuel Type

B. Low Duty Cycle Subcategory

C. Commercial Demonstration Permit

D. Applicability to Industrial EGUs

E. Non-Sequestration of Captured Carbon

F. Additional Amendments

G. Non-Base Load Combustion Turbines

X. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review

B. Executive Order 13771: Reducing Regulation and Controlling Regulatory Costs

C. Paperwork Reduction Act (PRA)

D. Regulatory Flexibility Act (RFA)

E. Unfunded Mandates Reform Act (UMRA)

F. Executive Order 13132: Federalism

G. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments

H. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks

I. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use

J. National Technology Transfer and Advancement Act (NTTAA)

K. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations

XI. Statutory Authority

I. General Information

A. Executive Summary

1. Proposed Revisions to the 2015 Rulemaking

The EPA is revisiting several portions of the Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units (EGUs), which was promulgated on October 23, 2015 (80 FR 64510). First, for newly constructed fossil fuel-fired electric utility steam generating units that are either utility boilers or integrated gasification combined cycle (IGCC) units, the EPA proposes to revise the BSER to be the most efficient demonstrated steam cycle (

i.e.,

supercritical steam conditions for large EGUs and best available subcritical steam conditions for small EGUs)

in combination with the best operating practices, instead of partial CCS. The primary reason for this proposed revision is the high costs and limited geographic availability of CCS. Based on the proposed revisions to the BSER, the EPA is proposing to establish revised (

i.e.,

higher) emission rates as the standards of performance for large and small EGUs (

See

Table 1). Further, for EGUs that undertake a reconstruction, because the standards for reconstructed EGUs are also based on best available efficiency technology, the EPA is proposing to revise those standards to consist of higher emission rates for large and small EGUs to be consistent with the standards for newly constructed EGUs (

See

Table 1). The EPA also proposes separate standards of performance for newly constructed and reconstructed coal refuse-fired EGUs (

See

Table 1). In addition, while the EPA is not proposing to revise the BSER identified in the 2015 Rule (which is based on the individual EGU's best demonstrated performance) for fossil fuel-fired electric utility steam generating units that undertake large modifications

(

i.e.,

modifications that result in an increase in hourly emissions of more than 10 percent), the EPA proposes to revise the maximally stringent standards

(that is, the level that is the most stringent that the standard can be) to be consistent with the proposed revised standards for new and reconstructed EGUs (

See

Table 1). Additionally, the EPA proposes minor amendments to the applicability criteria for combined heat and power (CHP) and non-fossil EGUs to reflect the original intended coverage. Finally, with respect to EGUs that undertake small modifications (

i.e.,

modifications that result in an increase in hourly emissions of 10 percent or less) for which standards were not included in the 2015 Rule, the EPA is soliciting comment on standards of performance based on a unit's historical performance and how to best account for emissions variability due to changes in the mode of operation (Comment C-1). Table 1 shows the proposed emission standards for newly constructed and reconstructed EGUs, as well as modified EGUs.

A subcritical EGU operates at pressures where water first boils and is then converted to superheated steam. A supercritical steam generator EGU operates at pressures in excess of the critical pressure of water and heats water to produce superheated steam without boiling. While often referred to as a supercritical boiler, no boiling actually occurs in the device and the term “boiler” should technically not be used for a supercritical pressure steam generator.

Note:

the term “EGU” is intended to refer to the affected facility (also referred to as the affected “source” or “unit”).

Under 40 CFR 60.14(h), a modification of an existing electric utility steam generating unit is defined as a physical change or change in the method of operation of the unit that increases the maximum hourly emissions of any regulated pollutant above the maximum hourly emissions achievable at that unit during the 5 years prior to the change.

The maximally stringent standard for modified EGUs is the numeric standard for reconstructed EGUs, even if the emission rate based on best annual performance is lower than that numeric standard.

Table 1—Summary of BSER and Proposed Standards for Affected Sources

Affected source

BSER

Emissions standard

New and Reconstructed Steam Generating Units and IGCC Units

Most efficient generating technology in combination with best operating practices

1. 1,900 lb CO

/MWh-gross for sources with heat input >2,000 MMBtu/h.

2. 2,000 lb CO

/MWh-gross for sources with heat input ≤2,000 MMBtu/h

3. 2,200 lb CO

/MWh-gross for coal refuse-fired sources.

Modified Steam Generating Units and IGCC Units

Best demonstrated performance

A unit-specific emission limit determined by the unit's best historical annual CO

emission rate (from 2002 to the date of the modification); the emission limit will be no more stringent than:

1. 1,900 lb CO

/MWh-gross for sources with heat input >2,000 MMBtu/h.

2. 2,000 lb CO

/MWh-gross for sources with heat input ≤2,000 MMBtu/h

3. 2,200 lb CO

/MWh-gross for coal refuse-fired sources.

The EPA is not proposing to amend and is not reopening the standards of performance for newly constructed or reconstructed stationary combustion turbines. The EPA is also proposing to make other miscellaneous technical changes to the regulations.

2. Costs and Benefits

When the EPA promulgated the 2015 Rule, it took note of both utility announcements and U.S. Energy Information Administration (EIA) modeling and, based on that information, concluded that “even in the absence of this rule, (i) existing and anticipated economic conditions are such that few, if any, fossil-fuel-fired steam-generating EGUs will be built in the foreseeable future,” and that “(ii) utilities and project developers are expected to choose new generation technologies (primarily NGCC) that would meet the final standards” and also “renewable generating sources that are not affected by these final standards.”

See

80 FR 64515. The EPA, therefore, projected that the 2015 Rule would “result in negligible CO

emission changes, quantified benefits, and costs by 2022 as a result of the performance standards for newly constructed EGUs.”

Id.

The Agency went on to say that it had been “notified of few power sector NSPS modifications or reconstructions.” Based on that additional information, the EPA said it “expects that few EGUs will trigger either the modification or the reconstruction provisions” of the 2015 Rule.

Id.

at 64516.

The EPA believes that the projections it made in conjunction with its promulgation of the 2015 Rule remain generally correct, in that, as explained in the economic impact analysis for this proposed rule, in the period of analysis, recent EPA and EIA analyses project there to be, at most, few new, reconstructed, or modified sources that will trigger the provisions the EPA is proposing. Consequently, the EPA has conducted an illustrative analysis of the costs for a representative new unit. Based on this analysis, which is presented in the economic impact analysis, the EPA projects this proposed rule will not result in any significant carbon dioxide (CO

) emission changes or costs. This analysis reflects the best data available to the EPA at the time the modeling was conducted. As with any modeling of future projections, many of the inputs are uncertain. In this context, notable uncertainties, in the future, include the cost of fuels, the cost to operate existing power plants, the cost to construct and operate new power plants, infrastructure, demand, and policies affecting the electric power sector. The modeling conducted for this economic impact analysis is based on estimates of these variables, which were derived from the data currently available to the EPA. However, future realizations could deviate from these expectations as a result of changes in wholesale electricity markets, federal policy intervention, including mechanisms to incorporate value for onsite fuel storage, or substantial shifts in energy prices. The results presented in this economic impact analysis are not a prediction of what will happen, but rather a projection describing how this proposed regulatory action may affect electricity sector outcomes in the absence of unexpected shocks. The results of this economic impact analysis should be viewed in that context.

B. Types of Sources

Fossil fuel-fired EGUs take two forms that are relevant for present purposes: Those that are steam generating units and those that use gasification technology.

Fossil fuel-fired steam generating units can burn natural gas, oil, or coal. However, coal is the dominant fuel for electric utility steam generating units. Coal-fired steam generating units are primarily either pulverized coal (PC) or fluidized bed (FB) steam generating units.

At a PC steam generating unit, the coal is crushed (pulverized) into a powder to increase its surface area. The coal powder is then blown into a steam generating unit and burned. In a fossil fuel-fired steam generating unit using FB combustion, the solid fuel is burned in a layer of heated particles suspended in flowing air. Power can also be generated from coal or other fuels using gasification technology. An IGCC unit gasifies coal or petroleum coke to form a synthetic gas (or syngas) composed of carbon monoxide (CO) and hydrogen (H

), which can be combusted in a combined cycle system to generate power.

Fossil fuel-fired EGUs also include combustion turbines, but the EPA is not proposing any changes to standards for those types of sources in this rulemaking.

Fossil fuel-fired utility steam generating units (

i.e.,

boilers) are most often operated using coal as the primary fuel. However, some utility boilers use natural gas and/or fuel oil as the primary fuel.

Natural gas-fired EGUs typically use one of two technologies: Natural gas combined cycle (NGCC) or simple cycle combustion turbines. NGCC units first generate power from a combustion turbine engine (the combustion cycle).

The unused heat from the combustion turbine engine is then routed to a heat recovery steam generator (HRSG) that generates steam, which is then used to produce power using a steam turbine (the steam cycle). Combining these generation cycles increases the overall efficiency of the system. Simple cycle combustion turbines only use a combustion turbine engine to produce

electricity (

i.e.,

there is no heat recovery or steam cycle).

Note that natural gas can also be used as a fuel in a steam generating EGU (boiler) and many existing coal- and oil-fired utility boilers have repowered as natural gas-fired units. However, a natural gas-fired utility boiler is not currently an economically or technologically viable choice for construction of a new steam generating unit EGU (80 FR 64515).

C. The 2015 Rulemaking, Reconsideration, and Litigation

On April 13, 2012, the EPA first proposed a NSPS for greenhouse gas (GHG) emissions from fossil fuel-fired EGUs (77 FR 22392). That proposal identified as the BSER for a coal-fired power plant building a natural gas-fired power plant (

Id.

at 22394). On January 8, 2014, the EPA rescinded that proposal and replaced it with a supplemental proposal that identified partial CCS as the BSER for coal-fired power plants

(79 FR 1430). On October 23, 2015, the EPA finalized the Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Generating Units (80 FR 64510). In that action, the EPA issued final standards of performance to limit emissions of GHG pollution manifested as CO

from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units (

i.e.,

utility boilers and IGCC EGUs) and newly constructed and reconstructed stationary combustion turbine EGUs. These final standards are codified in 40 CFR part 60, subpart TTTT.

The applicability includes all fossil fuel-fired steam generating units (

e.g.,

natural gas and oil-fired EGUs), but the BSER determination focused on coal-fired EGUs.

Greenhouse gas pollution is the aggregate group of the following gases: CO

, methane (CH

), nitrous oxide (N

O), sulfur hexafluoride (SF

), hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs).

The 2015 standards of performance for newly constructed fossil fuel-fired steam generating units

were based on the performance of a new, highly efficient, supercritical pulverized coal (SCPC) EGU, implementing post-combustion partial CCS technology, which the EPA determined to be the BSER under Clean Air Act (CAA) section 111(b) for these sources. The EPA concluded that CCS was adequately demonstrated (including being technically feasible) and widely available, and could be implemented at reasonable cost. The EPA did not determine natural gas co-firing or IGCC technology (either with natural gas co-firing or implementing partial CCS) to be BSER. However, the Agency did identify them as alternative methods of compliance.

The EPA also refers to fossil fuel-fired steam generating units as “steam generating units” or as “utility boilers and IGCC units.” These are units whose emission of criteria pollutants are covered under 40 CFR part 60, subpart Da. Criteria pollutants are those for which the EPA issues health criteria pursuant to CAA section 108, issues national ambient air quality standards (NAAQS) pursuant to CAA section 109, promulgates area designations of attainment, nonattainment, or unclassifiable pursuant to CAA section 107, and reviews and approves or disapproves state implementation plan (SIP) submissions and issues federal implementation plans (FIPs) pursuant to CAA section 110. GHG are not criteria pollutants.

The EPA also issued final standards for steam generating units that implement “large modifications,” (

i.e.,

modifications resulting in an increase in hourly CO

emissions of more than 10 percent). The standards of performance for modified steam generating units that make large modifications are based on each affected unit's own best historical performance as the BSER. The EPA did not issue final standards for steam generating units that implement “small modifications” (

i.e.,

modifications resulting in an increase in hourly CO

emissions of less than or equal to 10 percent).

For steam generating units that undergo a “reconstruction” (

i.e.,

the replacement of components of an existing EGU to an extent that both: (1) The fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new EGU, and (2) it is technologically and economically feasible to meet the applicable standards),

the EPA finalized standards based on the performance of the most efficient generating technology for these types of units as the BSER (

i.e.,

reconstructing the boiler as necessary to use steam with higher temperature and pressure, even if the boiler was not originally designed to do so).

The 2015 emission standard for large EGUs (greater than approximately 200 megawatts (MW)) was based on the performance of a well-operated PC EGU using supercritical steam conditions. The emission standard for small EGUs (less than approximately 200 MW) was based on the performance of a well-operated PC using the best available subcritical steam conditions. The difference in the standards for larger and smaller EGUs was based on the commercial availability of higher pressure/temperature steam turbines (

e.g.,

supercritical steam turbines) for large EGUs. While it is technically possible to design smaller supercritical steam turbines, due to the lack of commercial availability, the EPA was not able to access sufficient information regarding the cost of developing a specially designed steam turbine to determine that this was appropriate for inclusion as BSER.

40 CFR 60.15.

Steam with higher temperature and pressure has more thermal energy that can be more efficiently converted to electrical energy.

The EPA has historically been notified of only a limited number of NSPS modifications involving fossil fuel-fired steam generating units.

See

Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units—Proposed Rule, 77 FR 22392, 22400 (April 13, 2012). Given the limited information, the Agency concluded during the 2015 rulemaking that it lacked sufficient information to establish standards of performance for all types of modifications at steam generating units. Instead, the EPA determined that it was appropriate to establish standards of performance only for affected modified steam generating units that undergo modifications resulting in an hourly increase in CO

emissions (mass per hour) of more than 10 percent (“large” modifications) as compared to the source's highest hourly emission during the previous 5 years. The Agency determined that it had adequate information regarding the types of large, capital-intensive projects

that could result in large increases in hourly CO

emissions. Additionally, the Agency determined that it had adequate information regarding the types of measures available to control emissions from sources that undergo such modifications, and on the costs and effectiveness of such control measures. The EPA determined that the BSER for steam generating units that trigger the large modification provision is each affected unit's own best historic annual CO

emission rate (from 2002 to the date of the modification).

Major facility upgrades involving the refurbishment or replacement of steam turbines or other equipment upgrades that could significantly increase an EGU's capacity to burn more fossil fuel, thereby resulting in a large emissions increase.

With respect to affected steam generating units that undergo modifications that result in smaller increases in CO

emissions (specifically, steam generating units that conduct modifications resulting in an increase in hourly CO

emissions (mass per hour) of 10 percent or less (“small” modifications) compared to the source's highest hourly emission during the previous 5 years), the EPA concluded it did not have sufficient information and did not finalize any standard of performance or other requirements. The EPA continues to review whether it has sufficient information to establish appropriate standards for small modifications and is soliciting comment on options for determining appropriate standards in this action (Comment C-2).

The 2015 Rule also finalized standards of performance for newly constructed and reconstructed stationary combustion turbine EGUs. For newly constructed and reconstructed base load natural gas-fired stationary combustion turbines, the EPA finalized a standard based on efficient NGCC technology as the BSER. For newly constructed and reconstructed non-base load natural gas-fired and multi-fuel-fired (both base load and non-base load) stationary combustion turbines, the EPA finalized a heat input-based clean fuels standard. The EPA did not promulgate final standards of performance for modified stationary combustion turbines due to lack of information.

The EPA received six petitions for reconsideration of the 2015 final CAA section 111(b) GHG NSPS rule. The EPA denied five of the petitions on the basis they did not satisfy one or both of the statutory conditions for reconsideration under CAA section 307(d)(7)(B), and deferred action on a petition that raised the issue of the treatment of biomass on May 6, 2016 (81 FR 27442). Multiple parties also filed petitions for judicial review of the 2015 Rule. These petitions were consolidated into a single case and the petitioners filed opening written briefs in October 2016. The EPA and supporting intervenors filed opening written briefs in December 2016. Next, petitioners submitted written reply briefs in January 2017. On April 28, 2017, the United States Court of Appeals for the District of Columbia granted the EPA's motion to hold the cases in abeyance while the Agency reviews the 2015 Rule and considers whether to propose revisions to it.

D. The Purpose of This Regulatory Action

Executive Order 13783 (Promoting Energy Independence and Economic Growth) directs all executive departments and agencies, including the EPA, to “immediately review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise, or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law.”

Moreover, the Executive Order directs the EPA to undertake this process of review with regard to the New Source Rule issued under CAA section 111(b).

Id.,

Section 1(c).

In a document signed the same day as Executive Order 13783 and published in the

Federal Register

at 82 FR 16330 (April 4, 2017), the EPA announced that, consistent with the Executive Order, it was initiating its review of the Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Generating Units, and providing notice of forthcoming proposed rulemakings consistent with the Executive Order. As explained below, that review has led the EPA to propose to revise the BSER determinations for new, reconstructed, and modified coal-fired EGUs, including reconsideration issues previously denied by the Agency.

E. Does this action apply to me?

Table 2 of this preamble lists the regulated industrial source categories that are the subject of this proposal. Table 2 is not intended to be exhaustive, but rather provides a guide for readers regarding the entities that this proposed action is likely to affect. The proposed standards, once promulgated, will be directly applicable to the affected sources. To determine whether your facility, company, business, organization,

etc.,

would be regulated by this proposed action, you should examine the applicability criteria in 40 CFR 60.1. If you have questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA Regional representative as listed in 40 CFR 60.4 (General Provisions).

Table 2—Industrial Source Categories Affected by This Proposed Action

Category

NAICS code

1 2

Examples of regulated entities

Industry

221112

Fossil fuel electric power generating units.

Federal government

221112

Fossil fuel electric power generating units owned by the federal government.

State/local government

221112

Fossil fuel electric power generating units owned by municipalities.

Tribal government

921150

Fossil fuel electric power generating units in Indian Country.

North American Industry Classification System.

Includes NAICS codes for source categories that own and operate electric power generating units (including boilers and stationary combined cycle combustion turbines).

Federal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged.

F. Where can I get a copy of this document and other related information?

In addition to being available in the docket, an electronic copy of this action is available on the internet. Following signature by the Administrator, the EPA will post a copy of this proposed action at

https://www.epa.gov/stationary-sources-air-pollution/proposal-nsps-ghg-emissions-new-modified-and-reconstructed-egus.

Following publication in the

Federal Register

, the EPA will post the

Federal Register

version of the proposal and key technical documents at this same website.

A version of the regulatory language that incorporates the proposed changes in this action in track changes (

i.e.,

redline) is available in the docket for this action (Docket ID No. EPA-HQ-OAR-2013-0495).

II. Proposed Requirements for New, Reconstructed, and Modified Sources

A. Applicability Requirements

The EPA identified the applicability requirements for the 40 CFR part 60, subpart TTTT standards in the 2015 rulemaking, and the Agency is not proposing to revise or reopening those requirements, except as noted below. Those requirements are as follows: In general, the EPA refers to fossil fuel-fired electric generating units that would be subject to a CAA section 111 emission standard as “affected” EGUs or units. An EGU is any fossil fuel-fired electric utility steam generating unit (

i.e.,

a utility boiler or IGCC unit) or combustion turbine (in either simple cycle or combined cycle configuration). To be considered an affected EGU under 40 CFR part 60, subpart TTTT, the unit must meet the following applicability criteria: The unit must both: (i) Be

capable of combusting more than 250 million British thermal units per hour (MMBtu/h) (260 gigajoules per hourA(GJ/h)) of heat input of fossil fuel (either alone or in combination with any other fuel);

and (ii) serve a generator capable of supplying more than 25 MW net to a utility distribution system (

i.e.,

for sale to the grid).

However, 40 CFR part 60, subpart TTTT includes applicability exemptions for certain EGUs, including: (1) Non-fossil fuel units subject to a federally enforceable permit that limits the use of fossil fuels to 10 percent or less of their heat input capacity on an annual basis; (2) CHP units that are subject to a federally enforceable permit limiting annual net electric sales to no more than either the unit's design efficiency multiplied by its potential electric output, or 219,000 megawatt-hours (MWh), whichever is greater; (3) stationary combustion turbines that are not physically capable of combusting natural gas (

e.g.,

those that are not connected to a natural gas pipeline); (4) utility boilers and IGCC units that have always been subject to a federally enforceable permit limiting annual net electric sales to one-third or less of their potential electric output (

e.g.,

limiting hours of operation to less than 2,920 hours annually) or limiting annual electric sales to 219,000 MWh or less; (5) municipal waste combustors that are subject to 40 CFR part 60, subpart Eb; (6) commercial or industrial solid waste incineration units subject to 40 CFR part 60, subpart CCCC; and (7) certain projects under development, as discussed below.

The EPA refers to the capability to combust 250 MMBtu/h of fossil fuel as the “base load rating criterion.” Note that 250 MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.

The EPA refers to the capability to supply 25 MW net to the grid as the “total electric sales criterion.”

The CAA defines a new or modified source for purposes of a given regulation as any stationary source that commences construction or modification after the publication of the proposed regulation. Thus, any standards of performance the Agency finalizes as part of this rulemaking will apply to EGUs that commence construction, reconstruction, or modification after the date of this proposal. (EGUs that commenced construction after the date of the proposal for the 2015 Rule and before the date of this proposal will remain subject to the standards of performance promulgated in that Rule.) A modification is any physical change in, or change in the method of operation of an existing source that increases the amount of any air pollutant emitted to which a standard applies.

The NSPS General Provisions (40 CFR part 60 subpart A) provide that an existing source is considered a new source if it undertakes a reconstruction.

40 CFR 60.2.

40 CFR 60.15(a).

The EPA is proposing several changes to the applicability requirements. First, the EPA is proposing to change the exemption from applicability for EGUs (item 1 on the list above) on the grounds that they are considered non-fossil-fuel EGUs by revising the definition of non-fossil fuel EGUs from EGUs capable of “combusting 50 percent or more non-fossil fuel” to EGUs capable of “

deriving

50 percent or more

of the heat input

from non-fossil fuel

at the base load rating

.” (emphasis added). This amendment is consistent with the original intent to cover only fossil fuel EGUs and would assure that solar thermal EGUs with natural gas backup burners, which are similar to other types of non-fossil fuel units in that most of their energy is derived from non-fossil fuel sources, are not subject to the requirements of 40 CFR part 60, subpart TTTT. The definition of base load rating would also be amended to include the heat input from non-combustion sources (

e.g.,

solar thermal). Next, the design efficiency of an EGU is used to determine the electric sales applicability threshold. 40 CFR part 60, subpart TTTT currently allows the use of three methods for determining the design efficiency.

To reduce compliance burden, the EPA is proposing to allow alternative methods as approved by the Administrator on a case-by-case basis.

The EPA is also proposing to change the applicability of paragraph 60.8(b) in Table 3 of subpart TTTT from no to yes. This amendment would allow the Administrator to approve alternatives to the test methods specified in subpart TTTT. Finally, to avoid potential double counting of electric sales, the EPA is proposing that for CHP units determining net electric sales, purchased power of the host facility would be determined based on the percentage of thermal power provided to the host facility by the specific CHP facility. If any of these amendments are not finalized, EGUs that would be exempted by the proposed amendments would remain subject to 40 CFR part 60, subpart TTTT.

Subpart TTTT currently lists ASME PTC 22 Gas Turbines, ASME PTC 46 Overall Plant Performance, and ISO 2314 Gas turbines—acceptance tests as approved methods to determine the design efficiency.

Owners/operators of EGUs would petition the Administrator is writing to use an alternate method to determine the design efficiency. Administrator discretion is intentionally left broad and could include other ASME or ISO methods as well as data to demonstrate the design efficiency of the EGU.

B. Emission Standards

In this action, the EPA proposes revisions to the 2015 Rule's provisions for newly constructed coal-fired electric utility steam generating units (both utility boilers and IGCC units). The EPA proposes to revise its previous determination that the BSER for such newly constructed EGUs is partial CCS. The EPA bases this revision on (1) an updated analysis of what represents reasonable costs and (2) an updated analysis of the geographic availability of CCS. In addition, the EPA solicits comment on the technical feasibility of carbon capture technologies. Instead, the EPA proposes to create three subcategories of steam generating units: Large units, defined as units with heat input greater than 2,000 MMBtu/h; small units, defined as units with heat input less than or equal to 2,000 MMBtu/h; and units of any size (that meet the applicability criteria) and that are fired with coal refuse. The EPA proposes to find that for each of these subcategories, the BSER is the most efficient demonstrated steam cycle (

i.e.,

supercritical steam conditions for large units and best available subcritical steam conditions for small and coal refuse-fired units) in combination with the best operating practices. Unless stated otherwise, the EPA's use of the term supercritical steam conditions, or, more simply, supercritical, encompasses both ultra-supercritical and advanced ultra-supercritical steam conditions. There is no thermodynamic definition of ultra-supercritical or advanced ultra-supercritical steam conditions; rather, they are terms used to define subsets of supercritical steam conditions with higher temperatures and pressures.

The EPA is proposing revised standards of performance for newly constructed steam units in the three subcategories that reflect the Agency's proposed BSER determinations: 1,900 pounds of CO

per MWh of gross output (lb CO

/MWh-gross) for large EGUs; 2,000 lb CO

/MWh-gross for small EGUs, and 2,200 lb CO

/MWh-gross for coal refuse-fired units.

The EPA is not proposing to

revise its view in the 2015 Rule that natural gas co-firing and IGCC are alternate control technologies, but as described in section V.B of this preamble, not the BSER. The EPA invites the public to identify any additional information not considered by the Agency in the BSER analysis. (Comment C-3)

Supercritical, ultra-supercritical, and advanced ultra-supercritical steam generators operate at pressures greater than 22 megapascals (MPa) (3,205 pounds per square inch (psi)), temperatures greater than 550 degrees Celsius (°C) (1,022 degrees Fahrenheit (°F)), and use the same general steam generating unit design. The primary difference is that different materials are required to withstand the higher temperatures of ultra-supercritical and advanced ultra-supercritical steam conditions.

In contrast, in the 2015 Rule, the EPA did not create any subcategories for new steam generating units.

In addition, in this action, the EPA proposes to revise the 2015 Rule's standard of performance for reconstructed EGUs to be consistent with the numeric standards for new EGUs. By the same token, with respect to modified EGUs, the EPA proposes to revise the 2015 Rule's maximally stringent emissions rate for large modifications to be the same as the standards for newly constructed and reconstructed units in the same three subcategories (

e.g.,

while the standard would continue to be based on looking at average historical data, the EPA is proposing that the standard can be no lower than the new source standard). While the EPA is proposing revisions to the maximally stringent emission standards, the Agency is not proposing to revise or reopening the 2015 Rule's BSER determination, which was the use of the most efficient generation available in combination with best operating practices, based on historical emissions, or the associated standard of performance. The EPA is soliciting comment on standards of performance for “small” modifications based on a unit's best demonstrated historical performance and the most appropriate approach to account for emissions variability due to changes in the mode of operation and other factors (Comment C-4).

The EPA is not proposing to revise or reopening the 2015 Rule's requirement that the emission standards applicable to any type of EGU (however they may be revised in a final action on this proposal) apply at all times, including during periods of startup, shutdown, and malfunction (SSM). In addition, in this action, the EPA is not proposing to revise or reopening the air pollutants covered by the 2015 Rule or any of the Rule's continuous monitoring requirements; emissions performance testing requirements; continuous compliance requirements; or notification, recordkeeping, and reporting requirements. Furthermore, the EPA is not proposing to amend or reopening the 2015 Rule's BSER determination or standards of performance for new or reconstructed stationary combustion turbines.

Table 3 below summarizes the proposed standards of performance for three proposed subcategories of newly constructed and reconstructed EGUs as well as the proposed maximally stringent standards for modified EGUs. Consistent with the 2015 rulemaking, these emission standards would apply on a 12-operating month rolling average.

Table 3—Summary of BSER and Proposed Standards for Affected Sources

Affected source

BSER

Emissions standard

New and Reconstructed Steam Generating Units and IGCC Units

Most efficient generating technology in combination with best operating practices

1. 1,900 lb CO

/MWh-gross for sources with heat input >2,000 MMBtu/h.

2. 2,000 lb CO

/MWh-gross for sources with heat input ≤2,000 MMBtu/h

3. 2,200 lb CO

/MWh-gross for coal refuse-fired sources.

Modified Steam Generating Units and IGCC Units

Best demonstrated performance

A unit-specific emission limit determined by the unit's best historical annual CO

emission rate (from 2002 to the date of the modification); the emission limit will be no more stringent than

1. 1,900 lb CO

/MWh-gross for sources with heat input >2,000 MMBtu/h.

2. 2,000 lb CO

/MWh-gross for sources with heat input ≤2,000 MMBtu/h

3. 2,200 lb CO

/MWh-gross for coal refuse-fired sources.

The EPA is proposing that the amended emission standards apply to any EGUs that commence construction, reconstruction, or modification after December 20, 2018. The EPA is not aware of any coal fuel-fired EGUs that have commenced construction, reconstruction, or modification since January 8, 2014 (the applicability date of 40 CFR part 60, subpart TTTT). Therefore, no existing units would be impacted by the proposed revised BSER determination.

III. Legal Authority

A. Statutory Background

This action is governed by CAA section 111, which authorizes and directs the EPA to prescribe NSPS applicable to certain new stationary sources (including newly constructed, modified, and reconstructed sources).

As a preliminary step to regulation, the EPA lists categories of stationary sources that the Administrator, in his or her judgment, finds “cause, or contribute significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” the EPA has listed and regulated more than 60 stationary source categories under CAA section 111.

CAA section 111(b)(1)(A).

See

generally 40 CFR part 60, subparts D-MMMM.

The EPA's authority for this proposed rule is CAA section 111(b)(1). In both the 2015 Rule and the 2014 proposed rule, the EPA discussed the requirements of that provision and why the Rule met them.

See

80 FR 64510, 64529-31 (2015 Rule), 79 FR 1430, 1455 (January 8, 2014) (2014 proposed rule). In summary, CAA section 111(b)(1)(A) requires the Administrator to establish a list of source categories to be regulated under CAA section 111. A category of sources is to be included on the list “if in [the Administrator's] judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health and welfare.” This determination is commonly referred to as an “endangerment finding” and that phrase encompasses both the “causes or contributes significantly” component and the “endanger public health and welfare” component of the determination. Once the Administrator lists a source category under CAA section 111(b)(1)(A), he or she then promulgates, under CAA section 111(b)(1)(B), “standards of performance for new sources within such category.”

In the 2015 Rule, the EPA promulgated standards for CO

emissions from sources in two source categories, fossil fuel-fired electric utility steam generating units and combustion turbines. In the 2015 Rule,

the EPA explained that the Agency interprets the statute to require an endangerment finding to be made at the time the EPA lists the source category and to broadly concern emissions from the source category, and not to concern emissions of any particular pollutant that may be made subject to a revised or newly issued standard for a source category that has already been listed. The EPA further explained that CAA section 111(b) does not specify what pollutants the EPA should regulate once it lists a source category, so that the EPA may exercise its discretion to regulate particular pollutants as long as the EPA provides a rational basis for doing so.

See National Lime Ass'n

EPA,

627 F.2d 416, 431-32 n.48 (D.C. Cir. 1980).

In the 2015 Rule, the EPA described its rational basis for regulating CO

emissions from fossil fuel-fired EGUs, including that the CO

emissions from fossil fuel-fired EGUs are almost three times as much as the emissions from the next 10 source categories combined, and that the CO

emissions from even a single new coal-fired power plant may amount to millions of tons each year. The EPA added that even if it were required to make an endangerment finding for those emissions in order to regulate them, the same facts that provided the rational basis would qualify as an endangerment finding.

The EPA is proposing to retain the statutory interpretations and record determinations described in this paragraph. Nonetheless, the EPA is aware that various stakeholders have in the past made arguments opposing our views on these points, and the Agency sees value to allowing them to comment on these views in this rulemaking. Accordingly, the Agency will consider comments on the correctness of the EPA's interpretations and determinations and whether there are alternative interpretations that may be permissible, either as a general matter or specifically as applied to GHG emissions. For example, the Agency will consider comments on the issue of whether it is correct to interpret the “endangerment finding” as a finding that is only made once for each source category at the time that the EPA lists the source category or whether the EPA must make a new endangerment finding each time the Agency regulates an additional pollutant by an already-listed source category. Further, the EPA will consider comments on the issue of whether GHG emissions are different in salient respects from traditional emissions such that it would be appropriate to conduct a new “endangerment finding” with respect to GHG emissions from a previously listed source category. In addition, the EPA solicits comment on whether the Agency does have a rational basis for regulating CO

emissions from new coal-fired electric utility steam generating units and whether it would have a rational basis for declining to do so at this time, in light of, among other things, the following: (i) Ongoing and projected power sector trends that have reduced CO

emissions from the power sector, EIA,

Annual Energy Outlook 2018 with projections to 2050

(February 6, 2018), at 102, available at

https://www.eia.gov/outlooks/aeo/pdf/AEO2018.pdf,

due to reduced coal-fired generation, as the EPA discusses in the proposed Affordable Clean Energy rule, 83 FR 44746, 44750-51 (August 31, 2018); and (ii) as noted above, no more than a few new coal-fired EGUs can be expected to be built, which raises questions about whether new coal-fired EGUs contribute significantly to atmospheric CO

levels.

A “new source” is “any stationary source, the construction or modification of which is commenced after,” in general, final standards applicable to that source are promulgated or, if earlier, proposed.

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” to which the standard applies.

The EPA, through regulations, has determined that certain types of changes are exempt from consideration as a modification.

The EPA “may distinguish among classes, types and sizes within categories of new sources for the purpose of establishing such standards.”

See

CAA section 111(b)(2).

CAA section 111(a)(2).

CAA section 111(a)(4).

See

also 40 CFR 60.14 (concerning what constitutes a modification, how to determine the emission rate, how to determine an emission increase, and exempting specific actions that are not, by themselves, considered modifications).

40 CFR 60.2, 60.14(e).

The NSPS General Provisions (40 CFR part 60, subpart A) provides that an existing source is considered to be a new source if it undertakes a “reconstruction,” which is the replacement of components of an existing EGU to an extent that both (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new EGU, and (2) it is technologically and economically feasible to meet the applicable standards.

40 CFR 60.15.

Congress first enacted the definition of “standard of performance” as part of CAA section 111 in the 1970 Clean Air Act Amendments (CAAA), amended it in the 1977 CAAA, and amended it again in the 1990 CAAA to largely restore the original definition as it read in the 1970 CAAA. It is in the legislative history for the 1970 and 1977 CAAAs that Congress primarily addressed the definition as it read in those two versions of the statute, and that legislative history provides guidance in interpreting this provision.

In addition, the U.S. Court of Appeals for the D.C. Circuit has reviewed rulemakings under CAA section 111 on numerous occasions during the past 40 years, issuing decisions dated from 1973 to 2011,

through which the Court has developed a body of case law that interprets the term “standard of performance.”

In the 1970 CAAA, Congress defined “standard of performance,” under CAA section 111(a)(1), as—a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction) the Administrator determines has been adequately demonstrated.

In the 1977 CAAA, Congress revised the definition to distinguish among different types of sources, and to require that for fossil fuel-fired sources, the standard: (i) Be based on, in lieu of the “best system of emission reduction . . . adequately demonstrated,” the “best

technological

system of continuous emission reduction . . . adequately demonstrated” (emphasis added); and (ii) require a specific percentage reduction in emissions. In addition, in the 1977 CAAA, Congress expanded the parenthetical requirement that the Administrator consider the cost of achieving the reduction to also require the Administrator to consider “any non-air quality health and environment impact and energy requirements.”

In the 1990 CAAA, Congress again revised the definition, this time repealing the requirements that the standard of performance be based on the best technological system and achieve a percentage reduction in emissions, and replacing those provisions with the terms used in the 1970 CAAA version of CAA section 111(a)(1) that the standard of performance be based on the “best system of emission reduction . . . adequately demonstrated.” This 1990 CAAA version is the current definition. Even so, because parts of the definition as it read under the 1977 CAAA were retained in the 1990 CAAA,

see

CAA section 111(a)(1), the explanation in the 1977 CAAA legislative history, and the interpretation in the case law, of those parts of the definition in the case law remain relevant to the definition as it reads currently.

Portland Cement Ass'n

Ruckelshaus,

486 F.2d 375 (D.C. Cir. 1973);

Essex Chemical Corp.; Portland Cement Ass'n

EPA,

665 F.3d 177 (D.C. Cir. 2011).

See

also

Delaware

EPA,

No. 13-1093 LEXIS CITE (D.C. Cir. May 1, 2015).

Section 111(b) of the CAA authorizes the EPA to set “standards of performance” for new, reconstructed, and modified stationary sources from listed source categories to minimize emissions of air pollutants to the environment. Under CAA section 111(a)(1), the EPA must set these standards at the level that reflects the “best system of emission reduction . . . adequately demonstrated” taking into account technical feasibility, costs, and non-air quality health and environmental impacts and energy requirements.

The text and legislative

history of CAA section 111, the EPA's regulatory interpretations of that provision, and relevant court decisions, identify factors for the EPA to consider in making a BSER determination. They include, among others, whether the system of emission reduction is technically feasible, whether the costs of the system are reasonable, the amount of emissions reductions the system would generate,

and whether the standard would effectively promote further deployment or development of advanced technology.

The standard that EPA develops, reflecting the performance of the BSER, commonly takes the form of a numeric emission limit, expressed as a numeric performance level that can either be normalized to a rate of output or input (

e.g.,

tons of pollution per amount of product produced—a so-called rate-based standard), or expressed as a numeric limit on mass of pollutant that may be emitted (

e.g.,

100 micrograms per cubic meter (µg/m

)—or parts per billion). Generally, the EPA does not prescribe a particular technological system that must be used to comply with a standard CAA section 111(b)(5) and (h). Rather, sources generally may select any measure or combination of measures that will achieve the emissions level of the standard of performance. CAA section 111(b)(5). In establishing standards of performance, EPA has significant discretion to create subcategories based on source type, class, or size. CAA section 111(b)(2);

see

also

Lignite Energy Council

EPA,

198 F. 3d 930, 933 (D.C. Cir. 1999).

See Sierra Club

Costle,

657 F.2d 298, 326 (D.C. Cir. 1981).

See id.

at 347.

The overall approach to determining the BSER, which incorporates the various elements, is as follows: First, the EPA identifies the “system[s] of emission reduction” that have been “adequately demonstrated” for a particular source category. Second, the EPA determines the “best” of these systems after evaluating the extent of emission reductions, costs, any non-air health and environmental impacts, and energy requirements. Third, the EPA selects an achievable standard for emissions—here, the emission rate—based on the performance of the BSER. The remainder of this subsection discusses the various elements in that analytical approach.

1. “System[s] of Emission Reduction . . . Adequately Demonstrated”

The EPA's first step is to identify “system[s] of emission reduction . . . adequately demonstrated.” An “adequately demonstrated” system, according to the D.C. Circuit, is “one which has been shown to be reasonably reliable, reasonably efficient and which can reasonably be expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way.”

It does not mean that the system “must be in actual routine use somewhere.”

Rather, the Court has said, “[t]he Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonableness and cannot be based on `crystal ball' inquiry.”

The EPA has previously explained that the requirement that the standard for emissions be “achievable” based on the “best system of emission reduction . . . adequately demonstrated” indicates that one of the requirements for the technology or other measures that the EPA identifies as the BSER is that the measure must be technically feasible (81 FR 64538).

Essex Chem. Corp.

Ruckelshaus,

486 F.2d 427, 433 (D.C. Cir. 1973),

cert. denied,

416 U.S. 969 (1974).

Portland Cement Ass'n,

486 F.2d at 391 (citations omitted) (discussing the Senate and House bills and reports from which the language in CAA section 111 grew).

Id.

(citations omitted).

2. “Best”

In determining which adequately demonstrated system of emission reduction is the “best,” the EPA considers the following factors:

a. Costs

Under CAA section 111(a)(1), the EPA is required to take into account “the cost of achieving” the required emission reductions. In several cases, the D.C. Circuit has elaborated on this cost factor and formulated the cost standard in various ways, stating that the EPA may not adopt a standard the cost of which would be “exorbitant,”

“greater than the industry could bear and survive,”

“excessive,”

or “unreasonable.”

As the EPA has explained in a prior rulemaking, for convenience, the EPA uses “reasonableness” to describe costs well within the bounds established by this jurisprudence.

Lignite Energy Council

EPA,

198 F.3d 930, 933 (D.C. Cir. 1999).

Portland Cement Ass'n

EPA,

513 F.2d 506, 508 (D.C. Cir. 1975).

Sierra Club

Costle,

657 F.2d at 343 (D.C. Cir. 1981).

Id.

The D.C. Circuit has indicated that the EPA has substantial discretion in its consideration of cost under CAA section 111(a). In several cases, the Court upheld standards that entailed significant costs, consistent with Congress's view that “the costs of applying best practicable control technology be considered by the owner of a large new source of pollution as a normal and proper expense of doing business.”

See Essex Chemical Corp.

Ruckelshaus,

486 F.2d 427, 440 (D.C. Cir. 1973),

cert. denied,

416 U.S. 969 (1974);

Portland Cement Association

Ruckelshaus,

486 F.2d 375, 387-88 (D.C. Cir. 1973);

Sierra Club

Costle,

657 F.2d 298, 313 (D.C. Cir. 1981) (upholding standard imposing controls on sulfur dioxide (SO

) emissions from coal-fired power plants when the ”cost of the new controls . . . is substantial”).

Moreover, section 111(a) does not provide specific direction regarding what metric or metrics to use in considering costs, again affording the EPA considerable discretion in choosing a means of cost consideration.

1977 House Committee Report at 184.

The costs for these standards were described in the rulemakings.

See

36 FR 24876 (December 23, 1971), 37 FR 5767, 5769 (March 21, 1972).

Indeed, in upholding the EPA's consideration of costs under the provisions of the Clean Water Act authorizing technology-based standards based on performance of a best technology taking costs into account, courts have also noted the substantial discretion delegated to the EPA to weigh cost considerations with other factors.

Chemical Mfr's Ass'n

EPA,

870 F.2d 177, 251 (5th Cir. 1989);

Ass'n of Iron and Steel Inst.

EPA,

526 F.2d 1027, 1054 (3d Cir. 1975);

Ass'n of Pacific Fisheries

EPA,

615 F.2d 794, 808 (9th Cir. 1980).

See,

e.g., Husqvarna AB

EPA,

254 F.3d 195, 200 (D.C. Cir. 2001) (where CAA section 213 does not mandate a specific method of cost analysis, the EPA may make a reasoned choice as to how to analyze costs).

b. Non-Air Quality Health and Environmental Impacts

Under CAA section 111(a)(1), the EPA is required to take into account “any non-air quality health and environmental impact” in determining the BSER. As the D.C. Circuit has explained, this requirement makes explicit that a system cannot be “best” if it does more harm than good due to cross-media environmental impacts.

Portland Cement,

486 F. 2d at 384;

Sierra Club,

657 F.2d at 331;

see

also

Essex Chemical Corp.,

486 F.2d at 439 (remanding standard to consider solid waste disposal implications of the BSER determination).

c. Energy Considerations

Under CAA section 111(a)(1), the EPA is required to take into account “energy requirements.” As discussed below, the EPA may consider energy requirements on both a source-specific basis and a sector-wide, region-wide or nationwide basis. Considered on a source-specific basis, “energy requirements” entail, for example, the impact, if any, of the system of emission reduction on the source's own energy needs.

d. Amount of Emissions Reductions

As the EPA has previously explained, although the definition of “standard of performance” does not by its terms identify the amount of emissions from the category of sources or the amount of emission reductions achieved as factors the EPA must consider in determining the “best system of emission reduction,” the D.C. Circuit has stated that the EPA must in fact do so.

See

81 FR at 64529;

See Sierra Club

Costle,

657 F.2d at 326.

Sierra Club

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 system” to read, “best

technological

system.” As noted above, the 1990 CAAA deleted “technological,” and thereby returned the phrase to how it read under the 1970 CAAA. The court's interpretation of this phrase in

Sierra Club

to require consideration of the amount of air emissions reductions remains valid for the phrase “best system.”

e. Sector or Nationwide Component of the BSER Factors

The D.C. Circuit has also interpreted CAA section 111 to allow (but not require) the EPA to consider the various factors it is required to consider on a national or regional level and over time, not only on a plant-specific level or as of the time of the rulemaking.

Sierra Club

, 657 F.2d at 327-28 (quoting 44 FR 33583/3-33584/1), 331 (citations omitted) (citing legislative history).

See

81 FR at 64539; 79 FR 1430, 1466 (January 8, 2014) (explaining that although the D.C. Circuit decided

Sierra Club

before the

Chevron

case was decided in 1984, the D.C. Circuit's decision could be justified under either

Chevron

step 1 or 2. 79 FR 1430, 1466 (January 8, 2014)).

The D.C. Circuit's authorization for EPA to consider the factors on a national or regional level does not refer to the types of controls or actions that may be part of the BSER, rather, it refers to the factors EPA uses to evaluate the impacts of those controls or actions.

3. Achievability of the Standard for Emissions

The definition of “standard of performance” provides that the emission limit (

i.e.,

the “standard for emissions”) that the EPA promulgates must be “achievable” based on performance of the BSER.

See

81 FR at 64539-40 (discussing D.C. Circuit case law for requirements for achievability).

4. Expanded Use and Development of Technology

The D.C. Circuit has made clear that Congress intended for CAA section 111 to create incentives for new technology, and therefore, the EPA is required to consider technological innovation as one of the factors in determining the “best system of emission reduction.”

Sierra Club,

657 F.2d at 346-47.

5. Overall Agency Discretion To Balance the Factors

The D.C. Circuit has made clear that the EPA has broad discretion in determining the appropriate standard of performance under the definition in CAA section 111(a)(1), quoted above. Specifically, in

Sierra Club,

the Court explained that “section 111(a) explicitly instructs the EPA to balance multiple concerns when promulgating a NSPS,”

and emphasized that “[t]he text gives the EPA broad discretion to weigh different factors in setting the standard.”

Lignite Energy Council

EPA,

198 F.3d 930 (D.C. Cir. 1999), the Court reiterated:

Id.,

657 F.2d at 319.

Id.,

657 F.2d at 321;

see

also

New York

Reilly,

969 F. 2d 1147, 1150 (D.C. Cir. 1992)

(

because Congress did not assign the specific weight the Administrator should assign to the statutory elements, “the Administrator is free to exercise [her] discretion” in promulgating an NSPS).

Because section 111 does not set forth the weight that should be assigned to each of these factors, we have granted the agency a great degree of discretion 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 under section 111.

Lignite Energy Council,

198 F.3d at 933.

See

also

NRDC

EPA,

25 F.3d 1063, 1071 (D.C. Cir. 1994) (EPA did not err in its final balancing because “neither RCRA nor the EPA's regulations purports to assign any particular weight to the factors listed in subsection (a)(3). That being the case, the Administrator was free to emphasize or deemphasize particular factors, constrained only by the requirements of reasoned agency decision making.”).

B. Authority To Revise Existing Regulations

The EPA's ability to revisit existing regulations is well-grounded in the law. Specifically, the EPA has inherent authority to reconsider, repeal, or revise past decisions to the extent permitted by law so long as the Agency provides a reasoned explanation.

See Motor Vehicle Manufacturers Association of the United States

State Farm Mutual Automobile Insurance Co.,

463 US 29, 56-57 (1983) (“an agency changing its course must supply a reasoned analysis,”

quoting Greater Boston Television Corp.

FCC,

143 F.2d 841, 842 (D.C. Cir.)). The CAA complements the EPA's inherent authority to reconsider prior rulemakings by providing the Agency with broad authority to prescribe regulations as necessary.

See

42 U.S.C. 7601(a). The authority to reconsider prior decisions exists in part because the EPA's interpretations of statutes it administers “[are not] instantly carved in stone,” but must be evaluated “on a continuing basis.”

Chevron U.S.A. Inc.

NRDC, Inc.,

467 U.S. 837, 863-64 (1984). This is true, as is the case here, when review is undertaken “in response to . . . a change in administrations.”

National Cable & Telecommunications Ass'n

Brand X Internet Services,

545 U.S. 967, 981 (2005). Indeed, “[a]gencies obviously have broad discretion to reconsider a regulation at any time.”

Clean Air Council

Pruitt,

862 F.3d 1, 8-9 (D.C. Cir. 2017).

C. Authority To Regulate CO

From Fossil Fuel-Fired EGUs

The EPA's authority for this proposed rule is CAA section 111(b)(1). In the 2015 Rule, the EPA discussed the requirements of that provision and why the Rule met them (80 FR 64529-31). The EPA summarizes that discussion here, but is not re-opening any of the issues discussed: CAA section 111(b)(1)(A) requires the Administrator to establish a list of source categories to be regulated under section 111. A category of sources is to be included on the list “if in [the Administrator's] judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health and welfare.” This determination is commonly referred to as an “endangerment finding” and that phrase encompasses both the “causes or contributes significantly” component and the “endanger public health and welfare” component of the determination. Once the Administrator lists a source category under section 111(b)(1)(A), the Administrator then promulgates, under section 111(b)(1)(B), “standards of performance for new sources within such that category.”

In the 2015 Rule, the EPA promulgated standards for CO

emissions from sources in two source categories, fossil fuel-fired electric utility steam generating units and combustion turbines. The EPA explained that because it was not listing a new source category, it was not required to make a new endangerment finding with regard to the affected sources, and the EPA added that in any event, the required endangerment finding concerned the source category, and not individual pollutants. The EPA further explained that section 111(b) does not specify what pollutants the EPA should regulate once it lists a source category, so that the EPA may exercise its discretion to regulate particular pollutants as long as the EPA provides a rational basis for doing so. In the 2015 Rule, the EPA described its rational basis for regulating CO

emissions from fossil fuel-fired EGUs. The EPA added that even if it were required to make an endangerment finding for those emissions in order to regulate them, the same facts that provided the rational basis would qualify as an endangerment finding.

IV. Rationale for Proposed Applicability Criteria

The current non-fossil applicability exemption is based strictly on the combustion of non-fossil fuels (

e.g.,

biomass). To be considered a non-fossil fuel-fired EGU, the EGU must be both (1) capable of combusting over 50 percent non-fossil fuel and (2) limit the use of all fossil fuels to an annual capacity factor of 10 percent or less. The current language does not take heat input from non-combustion sources (

e.g.,

solar thermal) into account. Certain solar thermal installations have natural gas backup burners that are over 250 MMBtu/h. As currently written, these solar thermal installations would not be eligible to be considered non-

fossil units since they are not capable of deriving more than 50 percent of the heat input from the combustion of non-fossil fuels. Therefore, solar thermal installations that include backup burners could meet the applicability criteria of 40 CFR part 60, subpart TTTT even if the burners are limited to an annual capacity factor of 10 percent or less. Amending the applicability language to include heat input derived from non-combustion sources would allow these facilities to avoid applicability with 40 CFR part 60, subpart TTTT by limiting the use of the natural gas burners to less than 10 percent of the capacity factor of the backup burners. These EGUs would readily comply with the emissions standard, but the reporting and recordkeeping would increase costs for these EGUs. The proposed amended non-fossil applicability language of changing “combusting” to “deriving” will assure that 40 CFR part 60, subpart TTTT continues to cover the fossil fuel-fired EGUs, properly understood, that it was intended to cover, while minimizing unnecessary costs to EGUs fueled primarily by renewable energy. The corresponding change in the base load rating to include the heat input from non-combustion sources is necessary to determine the relative heat input from fossil and non-fossil sources.

The definition of design efficiency (

i.e.,

the efficiency of converting thermal energy to useful energy output) is used to determine if an EGU meets the electric sales criteria and is relevant to both new and existing EGUs. EGUs that sell less electricity than the electric sales criteria are not included in the applicability of subpart TTTT. The sales criteria is based in part of the individual EGU design efficiency. The current definition includes several specific options for determining the design efficiency. Since the 2015 final rule, the EPA has become aware that owners/operators of certain existing units do not have records of the original design efficiency. These units are therefore not able to readily determine if they meet the applicability criteria and are subject to the existing source 111(d) requirements. Many of these units are CHP units and it is highly likely they do not meet the applicability criteria. However, the current language would require them to conduct additional testing to demonstrate this. To minimize the compliance burden and to provide additional flexibility to the regulated community, the proposed amendment to the definition of design efficiency would allow the Administrator to approve alternate test methods to determine the design efficiency. For existing CHP units with large useful thermal outputs that would clearly not meet the electric sales applicability criteria, this could potentially include the use of historical operating data.

For CHP units, the current approach for determining net electric sales for applicability purposes allows the owner/operator to subtract the purchased power of the thermal host facility. The intent of the approach is to determine applicability similarly for third-party developers and CHP units owned by the thermal host facility.

However, as currently written, each third-party CHP unit would subtract the entire electricity use of the thermal host facility when determining its net electric sales. It is clearly not the intent of the provision to allow multiple third-party developers that serve the same thermal host to all subtract the purchased power of the thermal host facility when determining net electric sales. This would result in counting the purchased power multiple times. In addition, it is not the intent of the provision to allow a CHP developer to provide a trivial amount of useful thermal output to multiple thermal hosts and then subtract all of the thermal hosts' purchased power when determining net electric sales for applicability purposes. The proposed amendment would set a limit to the amount of thermal host purchased power that a third-party CHP developer can subtract for electric sales when determining net electric sales equivalent to the percentage of useful thermal output provided to the host facility by the specific CHP unit. This approach would eliminate both circumvention of the intended applicability by sales of trivial amounts of useful thermal output and double counting of thermal host-purchased power.

For contractual reasons, many developers of CHP units sell all the generated electricity to the electricity distribution grid even though in actuality a significant portion of the generated electricity is used onsite. Owners/operators of both the CHP unit and thermal host can subtract the site purchased power when determining net electric sales. Third party developers that do not own the thermal host can also subtract the purchased power of the thermal host when determining net electric sales for applicability purposes.

Finally, during the 2015 rulemaking, the EPA identified the Washington County (GA) and Holcomb (KS) EGU projects as “projects under development” that would not be able to meet the standard of performance without a complete redesign (80 FR 64542-43). As a result, the EPA determined that it would not be appropriate to apply the standard to those projects and excluded them. The EPA added that if it received information suggesting that either will be built, the Agency would propose a standard of performance specifically for the project. It is not clear if these projects will be constructed, and, if so, whether they would be able to meet the standard proposed in this action. For this reason, the EPA is not proposing to amend the manner in which the 2015 Rule addressed these projects. Thus, the proposed standard would not apply to these projects, and if the Agency receives information suggesting that either will be built, the EPA will propose a standard of performance specifically for the project. However, the EPA also requests comment on whether the projects should be covered by the standard proposed in this action (Comment C-5)

V. Rationale for Proposed Emission Standards for New and Reconstructed Fossil Fuel-Fired Steam Generating Units

In the 2015 Rule, the EPA determined that partial CCS was the BSER for newly constructed coal-fired steam generating units. The EPA determined that partial CCS had reasonable costs (the levelized cost of electricity (LCOE) was comparable to the costs of two then-current projects to add nuclear capacity, and the percentage increase in capital costs was comparable to increases that the industry had shown it could absorb),

was technically feasible in the majority of the U.S., achieved meaningful emission reductions, and promoted technology development. For the reasons discussed immediately below, on the basis of updated information, the EPA proposes that partial CCS does not qualify as the BSER; and for the reasons discussed further below, the EPA proposes that highly efficient generation technology is the BSER.

The two projects are SCE&G and Santee Cooper's V.C. Summer Nuclear Generating Station and Georgia Power and Southern Company's Vogtle Electric Generating Station.

A. Review of the 2015 BSER Analysis

1. Review of Reasonable Cost Criteria

In the 2015 Rule, as part of the partial CCS BSER determination, the EPA evaluated the costs for new base load electricity generating options to determine what was a “reasonable” cost. Specifically, the EPA determined that the LCOE for a new non-natural gas fossil fuel-fired power plant would be “reasonable” if it was consistent with the LCOE associated with the construction of a new nuclear power plant. The EPA argued that the

increased costs (relative to a newly constructed natural gas combined cycle EGU) were reasonable because utilities had indicated to the EPA that they valued the fuel diversity provided by coal-fired EGUs (80 FR 64510). The EPA also determined that an increase in the capital cost of slightly more than 20 percent was reasonable when compared to previous CAA rulemakings affecting the power sector (80 FR 64560). Since 2015, additional facts have come to light that have led the EPA to reassess these determinations and therefore to reassess the reasonableness of the cost of partial CCS.

Projections in 2015 from the EPA, EIA, and utility planners consistently showed NGCC as the lowest cost option for new intermediate and base load generation. Consistent with the 2015 Rule, current utility forecast models continue to project that few, if any, new coal-fired power plants will be built in the U.S. in the subsequent decade.

However, these models do not necessarily account for certain source-specific considerations that power plant developers use to determine what type of generation technology to construct. The EPA explained in the 2015 Rule that it was possible that circumstances would arise under which a developer would find it advantageous to build a new coal-fired EGU, for example, for purposes of fuel diversification (80 FR 64513), and the EPA has not received information since the 2015 Rule that would cause it to rule out that possibility. In the event a new coal-fired EGU is constructed in the U.S., in the absence of the requirements of 40 CFR part 60, subpart TTTT, as finalized in 2015, the EPA believes that the majority of large coal-fired EGUs would adopt the use of supercritical steam conditions and the majority of small coal-fired EGUs would use the best available subcritical steam conditions. This is consistent with the analysis included in the 2015 final rule.

Power sector modeling does not predict the construction of any new coal-fired EGUs. Therefore, based on modeled impacts, any GHG requirements for new coal-fired EGUs would have no significant costs or benefits.

In addition, as part of the 2015 rulemaking the EPA received public comments stating that there is value in maintaining the ability to develop non-natural gas-fired base load generation that is not captured in economic dispatch models (80 FR 64559). These values can include, but are not limited to: Historically stable fuel prices; fuel security (

i.e.,

the ability to store significant quantities of fuel onsite), and site-specific jobs and economic development considerations (

e.g.,

local mining and power plant jobs, maintaining an active rail line, maintaining the property tax base, and, in the case of coal refuse, remediation of existing environmental concerns). The EPA also noted that a number of integrated resource plans (IRPs)

recognize significant value in these fuel diversity considerations (80 FR 64526, 64563). Several utilities included nuclear and coal-fired options in their resource plans expressly to preserve fuel diversity within their portfolios.

These utility sector plans justified “prudent” costs (that were significantly higher than the projected least cost option) to maintain fuel diversity. Based on these factors, in the 2015 rulemaking, the EPA developed metrics for determining reasonable costs,

i.e.,

a cost level for performance standards at which new coal-fired EGUs can still be part of the future fuel diversity mix. These cost indicators were (1) the LCOE of other options for new non-natural gas-fired base load generation (

e.g.,

nuclear) and (2) the percentage increase in capital cost.

An Integrated Resource Plan (IRP) is a publicly available long-term resource plan outlining a utility's resource needs, considering both supply and demand side resources, to meet future energy demands reliably and cost effectively.

U.S. EPA,

Technical Support Document: Review of Electric Utility Integrated Resource Plans,

July 31, 2015, available in the rulemaking docket at

https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0495-11775.

a. Levelized Cost of Electricity (LCOE) Comparison

(1) Background

As part of the 2015 rulemaking, the EPA assumed that developers valued fuel diversity and were therefore willing to pay a premium for non-natural gas-fired dispatchable base load generation. The EPA concluded that the LCOE of new nuclear (and biomass) generation was one appropriate indicator of the value of maintaining the option to develop new non-natural gas-fired base load generation. For this metric, the EPA used cost data from EIA

and U.S. Department of Energy National Energy Technology Laboratory (DOE/NETL)

to project the cost at which a new coal-fired EGU with partial CCS would have substantially similar levelized cost compared to new nuclear capacity. Table 4 includes the summary table of the EPA's cost projections from the preamble to the 2015 final rule (

See

80 FR 64562, Table 8). The data in Table 4 reflect the EPA's 2015 determination that the cost of full carbon capture was not reasonable.

However, the EPA further determined that the cost of the specified partial CCS level in Table 4 was reasonable because they were comparable to the costs of new nuclear capacity. The increase in the LCOE from a supercritical pulverized coal unit due to partial CCS ranged from approximately 20 to 30 percent.

EIA,

Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2015. June 2015.

Available at

https://www.eia.gov/outlooks/archive/aeo15/pdf/electricity_generation.pdf.

U.S. DOE NETL,

Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO

Capture Rate in Coal-Fired Plants,

DOE/NETL-2015/1720, June 22, 2015, available at

https://www.netl.doe.gov/energy-analyses/temp/SupplementSensitivitytoCO2CaptureRateinCoalFiredPowerPlants_062215.pdf.

A further indication of the unfavorable economics of full capture CCS may be found in the recent cancellation by the Canadian firm, SaskPower of its planned CCS retrofits at additional units at the Boundary Dam facility, in Saskatchewan, Canada, due to high costs.

See

C. Marshall, “Landmark project puts coal expansion on ice,”

Greenwire,

July 10, 2016 (subscription required).

Table 4—Predicted Cost and CO

Emission Levels for a Range of Potential New Generation Technologies From the 2015 Rule

Technology

Emissions

(lb CO

/MWh-gross)

LCOE*

($/MWh)

SCPC—no CCS (bit)

1,620

76-95

SCPC—no CCS (low rank)

1,740

75-94

SCPC + ~16% CCS (bit)

1,400

92-117

SCPC + ~ 25% CCS (low rank)

1,400

95-121

Nuclear (EIA)

87-115

Nuclear (Lazard)

92-132

Biomass (EIA)

94-113

Biomass (Lazard)

87-116

IGCC

1,430

94-120

NGCC

1,000

** 52-86

* The emissions and LCOE (2011 $) for the SCPC cases, IGCC, and NGCC are based on the NETL “Sensitivity to CO

Capture Rate” report. The nuclear and biomass LCOE (2011 $) are based on data from EIA and Lazard. The LCOE ranges include an uncertainty of −15%/+30% on capital costs for SCPC and IGCC cases and an uncertainty of −10%/+30% on capital costs for nuclear and biomass cases. LCOE estimates displayed in this table for SCPC units with partial CCS as well as for IGCC units use a higher financing cost rate in comparison to the SCPC unit without capture.

** This range represents a natural gas price from $5/MMBtu to $10/MMBtu.

(2) Comparison With Biomass-Fired Power Plants

While the EPA included biomass in the 2015 rulemaking LCOE analysis, the EPA noted that new nuclear power, which, besides natural gas combustion turbines, is the principal other option often considered for providing new base load power (79 FR 1477). Biomass-fired EGUs are smaller in scale

and not as closely analogous to coal-fired generation as is nuclear power. EIA projects that average net additional biomass generation capacity amounts to less than 100 MW annually. The largest domestic biomass-fired EGU is less than 200 MW and the largest international biomass-fired EGUs are less than 300 MW. Similar to coal refuse-fired EGUs, biomass-fired EGUs are limited geographically because they tend to be located in areas with large quantities of biomass that can be cost effectively delivered to the plant. Based on these considerations, the EPA does not consider biomass to be an appropriate comparison for coal-fired generation.

Biomass-fired EGUs tend to have challenges in securing and transporting large amounts of biomass.

(3) Comparison With Nuclear-Fueled Power Plants

(a) Levelized Cost of Electricity (LCOE)

In the 2015 analysis, the EPA assumed nuclear generation and coal-fired generation were similarly attractive for purposes of fuel diversity. As part of this review, the EPA is reevaluating whether that assumption is valid. Specifically, the EPA is requesting comment on whether nuclear capacity is more attractive than coal as an option for providing fuel diversity (Comment C-6). Nuclear projects have no emissions of criteria pollutants, hazardous air pollutants (HAPs),

or GHGs. Particularly in light of potential future costs associated with GHG emissions, nuclear projects provide a significant price stability guarantee. In addition, the incremental generating costs for nuclear projects are lower than those for coal-fired EGUs, thus, nuclear EGUs would be expected to dispatch more frequently and provide more actual non-natural gas generation per amount of installed capacity.

Therefore, to the extent that nuclear projects are more attractive than coal-fired EGUs for providing fuel diversity, developers could be willing to pay more of a premium for nuclear projects than for coal-fired EGUs.

HAP are toxic air pollutants regulated under CAA section 112.

EIA used a 90 percent capacity factor for nuclear when calculating the LCOE in the 2015 Rule. According to EIA, the average nuclear EGU capacity factors was 92 percent in 2017.

On the other hand, more recent information, since the 2015 Rule, indicates that the LCOE of a new nuclear EGU is in fact higher than what developers may be willing to accept. In 2015, multiple new advanced Generation III+ nuclear units were under construction in the U.S.

65 66

including, at that time, two new units each at the Summer and Vogtle nuclear power plants in South Carolina and Georgia, respectively. However, since the 2015 Rule, both the Summer and Vogtle projects have experienced significant delays and cost overruns. South Carolina Electric and Gas (SCE&G), majority owner of Summer, has now abandoned completion of both reactors and has raised rates at least nine times to cover the increasing costs of the reactors.

While over budget and behind schedule, construction of both the Vogtle units continues. They are scheduled to be completed in 2021 and 2022. Furthermore, there appear to be no new nuclear projects under construction or that have received regulatory approval at this time. According to EIA, which reports data on recently constructed EGUs and planned EGU additions, including EGUs under construction, EGUs that have received regulatory approvals but that have not commenced construction, and planned projects that have not received regulatory approvals, the only planned nuclear project is the Utah Associated Municipal Power Systems (UAMPS) Carbon Free Power Project. This project proposes to use small modular nuclear reactors developed with funding from the DOE. However, this project has not yet received all of the required regulatory approvals to proceed. The EPA solicits comment on the extent to which new nuclear energy projects can serve as a comparison point, for purposes of fuel diversity, for new coal-fired EGUs (Comment C-7).

EIA,

Form EIA-860 Detailed Data,

2014, available at

https://www.eia.gov/electricity/data/eia860/,3_1_Generator_Y2014.xls,

“Proposed” sheet.

As of the promulgation of the 2015 Rule, 4,400 MW of new nuclear capacity was under construction with 2019-20 commercial operating dates.

G. Blade, “Santee Cooper, SCANA abandon Summer nuclear plant construction,”

Utility Dive,

July 31, 2017, available at

https://www.utilitydive.com/news/santee-cooper-scana-abandon-summer-nuclear-plant-construction/448262/.

In the 2015 Rule, the partial CCS costs were based largely on the report, “Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO

Capture Rate in Coal-Fired Power Plants,” June 22, 2015 (DOE/NETL-2015/1720). The EPA used the reported costs without any significant adjustments. In this rulemaking, the EPA is proposing to make refinements to the CO

transmission and storage (T&S) costs and EGU capacity factors. That is, as described below, the EPA is proposing to adjust the T&S costs based on the amount of CO

captured and adjust the capacity factor based on the increase in variable operating costs due to the impact of partial CCS. Accounting for these factors revises the LCOE with partial CCS upwards. The EPA also proposes in the alternative to use the NETL costs without any significant adjustments, similar to the approach used in the 2015 Rule. The EPA is not aware of any more recent, detailed, or transparent costing analysis specific to coal-fired EGUs with or without carbon capture technology. The EPA invites the

public to identify any additional costing information.

First, the CO

T&S costs in the NETL baseline reports are not included in the reported capital cost or operation and maintenance (O&M) costs but are treated separately and added to the LCOE. Specifically, the combined transport and storage costs for geologic storage (not accounting for any revenues from the sale of CO

) equaled $11 per metric ton of captured CO

. This cost represents annual transportation through a 100-kilometer (km) (62 mile) CO

pipeline and storage in a deep saline formation in the Midwest of 3.2 million tons of CO

The EPA used this value in all the partial capture cases as well. In this rule, to account for economies of scale, the EPA is proposing to adjust the T&S costs based on the amount of CO

captured. To estimate the T&S costs, the EPA is using the FE/NETL CO

Transport Cost Model and the FE/NETL CO

Saline Storage Cost Model with the same general assumptions described in “Performance Baseline for Fossil Energy Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3,” July 6, 2015 (DOE/NETL-2015/1723) and adjusting the metric megatons of CO

transported and stored.

Table 5 shows the resulting total estimated T&S costs for various amounts of captured CO

Use of the T&S costs for the Illinois Basin (

i.e.,

Midwest) are consistent with the NETL costing approach. According to NETL, T&S costs would be similar for the East Texas Basin. However, T&S costs for the Williston Basin are estimated to be 40 percent higher, and T&S costs for the Power River Basin are approximately double.

For additional detail on CO

T&S costing see section 2.7.3 CO

Transport and Storage in volume 1a, revision 3 of the NETL baseline reports and the T&S technical support document that is available in the docket.

Table 5—CO

Transport and Storage Costs for Various Amounts of Capture

Megatonne

(Mt)/yr

Total T&S cost

(2016

$/tonne)

4.2

9.6

3.2

2.6

2.0

1.4

0.62

The EPA is using the best fit trendline to estimate the T&S costs for various amounts of CO

capture. The trendline predicts that costs would increase substantially at lower levels of capture. As stated previously, the EPA also proposes in the alternative to use an $11 metric ton T&S costs consistent with the NETL costing approach and the 2015 Rule.

Second, as part of the 2015 rulemaking, for the LCOE calculations, consistent with the NETL calculations, as noted above, the EPA assumed a constant capacity factor

(

i.e.,

electric sales) regardless of the amount of CCS installed on the representative (

i.e.,

model) coal-fired EGU. This simplified approach captured the fixed and operating costs of CCS but did not account for the impact of economic dispatch (

e.g.,

it did not include analysis of the interaction of the affected EGU with the grid or other EGUs on an hourly basis) and loss of potential revenue due to lower electric sales.

EPA used an 85 percent capacity factor, consistent with the NETL LCOE calculations.

However, electricity is a unique commodity in that it cannot (at present) be stored at a large scale at a reasonable cost. Therefore, electric grid operators need to make plans and take actions to match supply and demand in real time. Multiple factors influence which EGUs supply power to the grid to satisfy system load (

e.g.,

transmission and operational constraints) at any given point, and in which order. In the simplest terms, economic dispatch is used to satisfy the grid load at minimal costs. In the economic dispatch model, EGUs with the lowest marginal (

i.e.,

operating) costs are dispatched first. Those EGUs increase output until all the load is satisfied or until the EGUs cannot supply additional power. If needed, EGUs with higher operating costs are then dispatched to satisfy demand. The process continues by dispatching more expensive units until the grid load is satisfied. The marginal cost of the final generator needed to meet load sets the system marginal cost. Owners and operators of generators are paid based on the system marginal cost. Therefore, net revenue is the difference between the variable operating costs and the system marginal cost.

Importantly, economic dispatch only accounts for the costs directly associated with power plant operations and does not consider any fixed costs. This is important because historically units with high fixed costs (

e.g.,

coal-fired and nuclear EGUs) have low operating costs, dispatch often, and typically run as base load units. For example, nuclear units tend to have operating costs on the order of $15 to $20 per MWh and capacity factors of greater than 90 percent. These units would be able to recover their high fixed costs by spreading them out over many MWh of electric sales. Units with low fixed costs but high operating costs (

e.g.,

simple cycle combustion turbines) have historically tended to dispatch last and provide peaking power. With natural gas prices of $4 per MMBtu, the operating costs of simple cycle units are approximately $40 per MWh and capacity factors are less than 10 percent in most cases. Therefore, an increase in operating costs of $20 per MWh can change an EGU from a high capacity factor base load unit to a peaking unit with limited operation. Emission control equipment can impact both the fixed costs and operating costs of an EGU. Another important aspect of economic dispatch, which may be unique to the electricity generation sector, is that the end user (

i.e.,

consumer) has historically had limited, if any, choice in what technology is used to generate electricity. Therefore, electric generators compete strictly on the basis of their variable costs, with no ability to differentiate their product.

In deregulated markets, a new coal-fired EGU must compete directly against all other forms of generation, including existing coal-fired EGUs and natural gas-fired combined cycle units. A developer of a new coal-fired EGU could anticipate revenues from capacity payments, various ancillary services, and to the extent the new unit is dispatched, energy payments. In a deregulated market, each of these revenue streams is priced through competitive market-based structures. As described earlier, revenue from energy payments will largely be determined based on variable operating costs. Any requirements that impact variable operating costs could impact the ability of the owner/operator of a new coal-fired EGU to obtain adequate revenues to cover the generation investment and recover costs.

In the 2015 Rule, commenters indicated that competitive electricity markets only allow for the entry of competitively-priced power. Therefore, a new coal plant with partial CCS that was compliant with an NSPS requirement based on the use of CCS might not be competitive compared to older coal plants with no CCS requirements (even if the older plants are less thermally efficient). The EPA responded that, given current and projected market conditions, any new coal-fired EGU would likely only be built in a location where it would be expected to operate at a high capacity factor (

e.g.,

as a base load unit). However, at least in deregulated markets, economic dispatch is still a factor for base load units and can change annual capacity factors by multiple percentage points. Moreover,

an increasing number of coal-fired power plants are changing from base load to variable load. Accordingly, the EPA is proposing to include the impact of economic dispatch in determining the costs of a potential new coal-fired EGU. Inclusion of these costs is a more refined representation of the impact of the BSER determination. As stated previously, the EPA is proposing in the alternative that the Agency not account for economic dispatch and instead use the same capacity factors regardless of variable operating costs, for the same reasons as the EPA stated in the 2015 Rule.

One approach developers could take to reduce the impact on the capacity factor could be to construct a smaller EGU. While this would not impact capacity factors strictly based on simplified economic dispatch (

i.e.,

at the same variable operating costs the unit would still dispatch after units with lower variable operating costs) multiple factors impact dispatch and a smaller unit might provide local grid support that would allow it to operate at higher capacity factors.

To estimate the impacts at a national level of the increase in variable operating costs due to partial CCS, the EPA analyzed the dispatch of coal-fired EGUs relative to variable operating costs.

Based on a review of the variable operating costs and capacity factors in the Annual Energy Outlook 2018 and fuel prices reported under EIA form 923, the EPA determined that capacity factors for coal-fired EGUs decrease approximately 1.5 percent for each $1/MWh increase in operating costs. Table 6 shows the operating costs of various generating technologies. The capacity factors for coal-fired EGUs have been adjusted based on a baseline of the relevant coal rank supercritical EGU having a capacity factor of 85 percent.

Fuel costs comprise approximately two-thirds to three-fourths of the variable operating costs for a coal-fired EGU.

Table 6—Proposed T&S Costs and Capacity Factors *

Technology

Captured CO

(Mt)

T&S costs

($/tonne)

Variable

operating

costs

($/MWh)

Amended CF

(percent)

Subcritical PC (bit)

32.3

83.5

Supercritical PC (bit)

31.3

85.0

SCPC + ~16% CCS (bit)

520,000

36.9

76.6

Supercritical PC (low rank)

28.0

85.0

Ultra-supercritical PC (low rank)

27.4

85.8

SCPC + ~ 26% CCS (low rank)

1,000,000

36.3

72.5

Combined Cycle CT (NG)

33.1

Simple Cycle CT (NG)

50.7

* Variable operating costs calculated using $2.61/MMBtu for bituminous coal, $2.09/MMBtu for low rank coal, and $4.73/MMBtu for natural gas. Captured CO

based on an 85 percent capacity factor. Costs are in 2016 $. Variable operating costs is also referred to as incremental generating costs. Simple cycle CT variable operating costs were estimated by adjusting the combined cycle efficiency to 33 percent.

The variable operating costs shown in Table 6 demonstrate part of the reason why the U.S. generation mix is changing so dramatically with the decrease in the price of natural gas. Fuel costs comprise approximately two thirds to three quarters, depending on the coal type, of the variable operating costs for coal-fired EGUs. In comparison, fuel costs comprise over 90 percent of the variable operating costs for combined cycle EGUs. Therefore, declining natural gas prices can have a dramatic impact on the competitiveness of natural gas-fired EGUs relative to coal-fired EGUs. While the variable operating costs in Table 6 are based on long term projections for the price of natural gas, spot process can be significantly lower. When natural gas is available at $4/MMBtu or less, the variable operating costs of combined cycle units can drop below those of certain coal-fired EGUs and displace those units in the dispatch order. The data further show that due to the relatively high operating costs of CCS compared to other environmental controls,

a BSER based on partial CCS increases the variable operating costs of new coal plants to significantly greater than existing coal-fired EGUs without GHG controls. Therefore, in an economic dispatch system, a new coal-fired EGU with partial CCS would dispatch after the majority of existing coal-fired EGUs.

In markets with significant quantities of coal-fired generation, this could have a significant impact on the economic viability of a new coal-fired EGU. Table 7 shows the LCOE at an 85 percent capacity factor and $11/tonne T&S costs compared to an LCOE using the amended T&S costs (based on the amount of CO

captured) and using an adjusted capacity factor (based on the variable operating costs). The revised LCOE numbers account for both the amended approach to calculating T&S costs and the change in capacity factor.

The EPA notes that unlike other environmental controls, there is limited regulatory requirements or incentive to reduce GHG emissions aside from the NSPS requirements. For example, local or regional programs could require reductions in criteria pollutant from all EGUs and/or owners/operators of EGUs can accrue regulatory benefits in other regulatory programs due to criteria pollutant reductions (

e.g.,

offsets and emission credits). These programs minimize the impact of the environmental controls on dispatch because costs are spread more evenly to the entire EGU fleet.

This could create a perverse environmental incentive to operate existing coal more than it otherwise would. A utility-system dispatch model would be required to estimate the potential overall environmental impacts.

Table 7—Predicted Cost and CO

Emission Levels for a Range of Potential New Generation Technologies

Technology

LCOE *

($/MWh)

Amended LCOE **

($/MWh)

Subcritical PC (bit)

81.2

82.1

Supercritical PC (bit)

81.7

SCPC + ~16% CCS (bit)

96.2

105.4

Supercritical PC (low rank)

85.2

Ultra-supercritical PC (low rank)

87.6

87.0

SCPC + ~ 26% CCS (low rank)

109.0

122.8

* 85 percent capacity factor and $11/tonne T&S.

** Capacity factor adjusted based on variable operating costs and T&S costs adjusted based on amount of captured CO

Assuming a constant 85 percent capacity factor and $11/tonne T&S costs, the LCOE for a bituminous-fired SCPC with partial CCS is 18 percent higher than a SCPC without CCS. However, when the refined T&S and capacity factors are accounted for, the relative increase in LCOE for a bituminous-fired SCPC with partial CCS is 29 percent higher than SCPC without CCS, a 63 percent increase in the relative LCOE impact of partial CCS. These costs do not account for any of the potential benefits of reduced criteria and GHG emissions due to the use of partial CCS. The EPA solicits comment on if these should be factored into the analysis, and if so, appropriate metrics to accounting for these benefits (Comment C-8). Furthermore, the revised LCOE costs are over 10 percent higher than the nuclear cost metric. Furthermore, even with only the T&S adjustment, the revised LCOE are five percent higher than the nuclear metric. The results of this analysis support the EPA's proposal to revise the 2015 determination that partial CCS is BSER for coal-fired EGUs. The EPA notes that these costs are for coal-fired EGUs that are using geologic sequestration (GS) and do not account for any specific economic incentives (

e.g.,

the federal tax credits for carbon capture, which are available only for new facilities that commence construction before January 1, 2024, Internal Revenue Code §§ 45Q(a)(3)-(4), (d)—which, in turn, is before the end of the 8-year period in which the EPA is required to review and, if necessary, revise the standard of performance that is the subject of this rulemaking, CAA section 111(b)(1)(B)). If the owner/operator were in a location where it could sell the byproduct CO

(

e.g.,

for enhanced oil recovery or for use in the food industry) variable operating costs could be reduced relative to an EGU without partial CCS and electric sales would be expected to increase, offsetting some of the control costs. For example, as discussed in the 2015 Rule, two coal-fired EGUs elected to install carbon capture technology and sold the CO

to the food industry without any federal funding for the capture technology (80 FR 64550). This type of utilization of CO

has the potential to both develop capture technologies and increase economic options to reduce emissions. While sale of the captured CO

improves the overall economics of a new coal-fired EGUs, the EPA recognizes that there are places where opportunities to sell captured CO

for utilization may not be presently available. Therefore, consistent with approach adopted in the 2015 Rule, the EPA is assuming no revenues from the sale of captured CO

(80 FR 64572).

(b) Consideration of Capital Cost Increases

In the 2015 rulemaking, commenters from industry recommended that the EPA should separately consider the significant capital costs of partial CCS. In response to these comments, the EPA evaluated the impact of 2015 GHG standards on the capital costs of new fossil-steam generation and compared the same to the capital costs of prior EPA regulations. The EPA determined that the incremental capital costs of partial CCS were reasonable because they were comparable to the percentage capital costs increase in prior regulations and because the utility industry has demonstrated the capacity to successfully absorb capital costs of this magnitude in the past (80 FR 64559). Specifically, in the 2015 final rule, the EPA concluded that an increase of 21 to 22 percent for capital coats was reasonable (80 FR 64560).

The EPA cited several comparable rulemakings. First, the 1971 NSPS for coal-fired EGUs increased costs by $19 million (M) for a 600 MW plant. These costs consisted of $3.6 M for particulate matter (PM) controls, $14.4 M for SO

controls, and $1 M for nitrogen oxide (NO

) controls; the capital cost of air pollution control devices added 15.8 percent to the $120 M capital cost of a new EGU. In that case, the baseline cost was primarily for a coal-fired EGU with limited environmental controls. In addition, a retrospective Congressional Budget Office (CBO) study of the 1978 EGU NSPS amendments estimated that those amendments increased the capital costs for a new EGU by 10 to 20 percent. There, the baseline costs and overall absolute costs were higher than the 1971 NSPS because they included the cost of controls required by the 1971 NSPS. Since the 1978 NSPS, additional environmental controls have further increased the baseline costs to construct a new coal-fired EGU. These additional costs include, but are not limited to, NSPS amendments that established selective catalytic reduction (SCR) as the BSER for NO

controls in place of low NO

combustion controls and more stringent SO

and PM standards, rulemakings that require mercury (Hg) controls, and rulemakings that limit the use of once-through cooling. All of these additional environmental control requirements increase the baseline costs of constructing a new coal-fired EGU. Therefore, at the same percentage increase in capital costs, absolute costs are much higher. A comparable analysis would require that the additional control costs due to previous rulemakings be accounted for in the baseline costs when determining an appropriate percent increase in capital costs. The EPA notes that even without accounting for the different cost basis, the absolute increase in capital costs was higher for the 2015 Rule than previous EGU NSPS rulemakings. It should also be noted that the previous NSPS rulemakings generally concerned multiple pollutants and adopted multiple requirements based on multiple control technologies, which makes it more challenging to compare them with the current rulemaking, which in turn concerns, as a practical matter, a single air pollutant—CO

—and a single set of controls.

Furthermore, the fact that the utility industry was able to absorb 20 percent increases in cost due to pollution control in the past does not necessarily mean the industry could do so today. For example, when previous NSPS rulemakings with significant costs for new coal-fired EGUs were completed, electricity demand was growing and few alternatives existed for intermediate and base load generation. At that time, a new coal-fired EGU built by a regulated utility could anticipate operating at a high capacity factor for several decades.

The utility sector is markedly different today. Currently, many coal-fired EGUs operate at variable load and it would be more difficult for an owner/operator of a new coal-fired EGU to recoup the additional control costs. Based on these assessments, the EPA is proposing that the increase in capital costs due to partial CCS are not reasonable.

In addition, in the 2015 Rule, the EPA cited the

Portland Cement Ass'n

ruling that upheld a 12 percent increase in capital costs as reasonable (

See

80 FR 64560, citing 486 F.2d at 387-88). As stated previously, the EPA is proposing in this rule that the increase in capital costs due to partial CCS are not reasonable. In any event,

Portland Cement Ass'n

is not relevant because, as the EPA further noted in the 2015 Rule, the costs of control equipment (capital and operating) for the Portland Cement NSPS could be passed on without substantially affecting competition with construction substitutes such as steel, asphalt, and aluminum.

Id., citing Portland Cement Ass'n

Ruckelshaus,

513 F.2d 506, 508 (DC Cir. 1975). However, in the 2015 Rule, the EPA did not account for the loss of sales (

i.e.,

revenue) in the electricity market. As described previously, at least in deregulated markets, for coal-fired EGUs, an increase in operating costs has an impact on dispatch order and thus product (

i.e.,

electricity) sales, and therefore, the overall cost of the partial CCS BSER determination. That is, the ability of EGUs to pass along their capital costs to consumers depends on their ability to pass along their operating costs to consumers. However, higher operating costs that impact the EGU dispatch order cannot be passed on to end users as easily (and profit margins cannot be narrowed as easily) without affecting coal-fired generation's competitiveness with alternate forms of electricity generation. This means that EGUs cannot pass along their capital costs as easily as other industries.

The EPA has reviewed the rationale for a dozen GHG permits for EGUs and other industrial facilities that were permitted between 2011 and 2017. Aside from industrial sources with existing, nearly pure CO

process streams (

e.g.,

a natural gas processing facility) situated near an existing CO

pipeline (

i.e.,

a few hundred feet) that could implement CO

capture at little or no net cost, none of the GHG permits considered CCS to be a reasonable cost control technology. Energy efficiency was considered the appropriate control technology for the majority permit determinations. The fact that all of the EGU permit determinations rejected CCS as a reasonable control technology supports the conclusion that CCS is not an appropriate BSER.

2. Whether CCS Is Adequately Demonstrated

In the 2015 Rule, the EPA found that partial CCS was “adequately demonstrated” under CAA section 111(a)(1), a requirement that, as noted above, incorporates the concept of technical feasibility. However, upon further review, the EPA is proposing to revise its analysis and determine that CCS is not adequately demonstrated in certain key respects, as described in this section.

a. Availability of Geologic Sequestration (GS)

In the 2015 Rule, the EPA noted that, as a practical matter, the issue of whether all new steam-generating EGUs can implement partial CCS depends on the geographic scope of suitable GS sites. Therefore, as part of that rulemaking, the EPA performed a geographic analysis

in which the Agency examined areas of the country with sequestration potential in deep saline formations, oil and gas reservoirs, unmineable coal seams, and active, enhanced oil recovery (EOR) operations; information on existing and probable, planned or under study CO

pipelines; and areas within a 100-km (62-mile) area of locations with sequestration potential. The distance of 100 km was consistent with the assumptions underlying the NETL cost estimates for transporting CO

by pipeline. Based on the geographic analysis performed, the EPA determined that GS sites were widely available and that a steam-generating plant with partial CCS, sited near an area suitable for GS, could serve power demand in a large area, notwithstanding that the area itself might not contain sequestration sites. As part of the review for this action, the EPA has re-evaluated these determinations. In addition, the EPA has reviewed the impact of water availability with respect to geographic availability of CCS.

U.S. EPA,

Technical Support Document: Geographic Availability,

July 31, 2015, available in the rulemaking docket at

https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0495-11772.

Since the 2015 Rule, the EPA has updated its analysis on geographic availability. Using updated information from NETL,

the Agency has identified the geographic extent of potential GS in deep saline formations and oil and gas reservoirs. The updated data show relatively minimal changes in estimated storage resources, with most of the changes occurring in Wyoming and Midwestern states (Kentucky, Michigan, Illinois, Indiana and North Dakota) as a result of additional characterization and assessment studies by the DOE Regional Carbon Sequestration Partnerships.

In addition, the EPA has updated its list of counties where active EOR operations are occurring, based on data reported to the EPA Greenhouse Gas Reporting Program (GHGRP) (

See

40 CFR part 98, subpart UU, Injection of Carbon Dioxide, 2011-2017 data).

The GHGRP data show four additional counties where active EOR operations have occurred since the EPA's analysis in 2015. Finally, the Agency has updated its information on existing CO

pipelines based on Department of Transportation data along with the locations of pipelines that are probable, planned or under study. In general, these updates do not significantly change the EPA's understanding of which areas are amenable to GS.

U.S. DOE NETL,

Carbon Storage Atlas, Fifth Edition,

September 2015, available at

https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.

For deep saline formations, the low-end estimate of storage resource increased from 2,100 billion metric tons to 2,379 billion metric tons, and the high-end estimate increased from 20,014 billion metric tons to 21,633 billion metric tons. For oil and gas reservoirs, the storage resource was previously estimated at 225 billion metric tons, and is now estimated at a low-end estimate of 186 billion metric tons and a high-end estimate of 232 billion metric tons.

U.S. EPA,

Greenhouse Gas Reporting Program,

available at

https://www.epa.gov/ghgreporting.

Data reported as of August 19, 2018.

The NETL Carbon Storage Atlas (Atlas) used for the EPA's analysis of geographic availability provides a high-level overview of prospective resources across the United States. This assessment represents the fraction of pore volume of porous and permeable sedimentary rocks available for CO

storage and accessible to injected CO

via drilled and completed wellbores. The estimates in the Atlas do not take into account economic or regulatory constraints, only physical constraints (

i.e.,

the accessible parts of geologic formations via wellbores). The deployment of partial CCS is site-specific and its application will depend on local market and geologic conditions. Therefore, the cost of deploying partial CCS will be highly variable on a geographic basis. While storage capacity appears large in the Atlas, site-specific technical, regulatory, and economic considerations will ultimately impact how much of that resource is economically available. That is, the Atlas shows an estimate of potential storage areas, but not economically

viable storage areas (

i.e.,

areas where projects make business and financial sense). Additionally, the various types of geologic formations assessed in the Atlas have been characterized to varying degrees. That is, there is more uncertainty in the assessment of certain types of formations as compared to others. The maturity of oil and gas exploration and production in certain parts of the United States makes sequestration potential in these reservoirs relatively well understood. However, there are still limitations to the feasibility of GS in all oil and gas reservoirs identified as areas of potential storage in the Atlas. Additionally, despite showing large potential, saline storage has not yet been demonstrated to be available, both from a geographical perspective as well as economically, at all locations. For example, the major milestone saline project from Archer Daniels Midland is underway, but only reflects the feasibility of saline injection and storage at one location in the United States. This project is still in its early stages and has not yet proven that GS in saline formations can be done throughout the United States (at scale) in wide geographic regions with highly diverse geologic conditions. The project is sized at one million metric tons per year and may not demonstrate the full application of saline storage necessary for a large power project.

Regarding the third type of geologic formation assessed in the Atlas, unmineable coal seams, the EPA has changed its assumptions since the 2015 analysis. While the Atlas includes potential availability of unmineable coal seams, the EPA has excluded this type of formation from potential GS areas. As part of its 2015 analysis, the EPA expressed its view unmineable coal seams offered the potential for geologic storage and explained the technical process by which it thought that CO

could be injected underground to enhance methane recovery (also known as enhanced coalbed methane recovery) while adsorbing to the coal surface (80 FR 64576). NETL identified states that it considered had the potential for storage in unmineable coal seams. Some of these areas, including Iowa and Missouri, have little to no EOR or saline sequestration potential and generate electricity at coal-fired EGUs. Several successful small-scale demonstration projects had been performed to evaluate the potential for GS in unmineable coal seams, and research to optimize CO

storage in coals was ongoing. However, upon further review, the EPA now believes that the processes and technologies associated with GS at unmineable coal seams are still being developed and, in the years since the EPA expressed the understanding and expectations underlying this aspect of its analysis in the 2015 Rule, there have been no large-scale demonstrations of GS associated with unmineable coal seams.

In the 2015 rulemaking, the EPA had found that the largest pilot project, the Allison Unit CO

-ECBM pilot in New Mexico, stored 270,000 metric tons of CO

from 1995-2001 (an average of 45,000 tons per year).

Recent DOE Regional Carbon Sequestration Partnership projects have injected CO

volumes ranging from 90 tons to 16,700 tons.

While these projects demonstrated some degree of potential for GS in unmineable coal seams, most were in the nature of pilot programs undertaken to evaluate project designs and collect data to better understand the mechanisms of injection and CO

storage. Therefore, the project durations and injected amounts were limited. The limited duration and amounts of the tests may have affected the outcomes, as some tests began to show decreases in the effectiveness of CO

injection over time due to swelling of the coals. This observation raises doubts regarding the feasibility of larger-scale GS in unmineable coal seams at this time. For example, in the Pump Canyon test, the effectiveness of CO

storage was believed to be limited due to the small amount of CO

injected.

The amount of CO

injected in these tests was significantly less than projects at deep saline formations or at oil and gas reservoirs where CO

was injected in the million-ton range. The EPA now believes that additional research using larger scale and longer duration tests in unmineable coal seams is needed to improve the understanding and modeling of CO

storage in coals. Unmineable coal seams have not been shown to be a suitable GS technology option for purposes of this action; however, such formations could have potential applicability in the future. Therefore, unmineable coal seams have been excluded from potential GS areas in the analysis underlying this proposal. The elimination of unmineable coal seams reduces the geographic availability of sequestration areas by approximately 4 percent.

See,

e.g.,

M. Godec

et al.,

“CO

-ECBM: A Review of its Status and Global Potential,”

Energy Procedia

63: 5858-5869 (2014), available at

https://doi.org/10.1016/j.egypro.2014.11.619;

IEAGHG,

Potential Implications on Gas Production from Shales and Coals for Geological Storage of CO

Report Number 2013/10, September 2013, available at

http://www.ieaghg.org/docs/General_Docs/Reports/2013-10.pdf.

Id.

J. Litynski

et al.,

“Using CO

for enhanced coalbed methane recovery and storage,

CBM Review,

June 2014, available at

https://www.netl.doe.gov/File%20Library/Research/Carbon-Storage/Project-Portfolio/CBM-June-2014.pdf.

M. Godec

et al.,

“CO

-ECBM: A Review of its Status and Global Potential,”

Energy Procedia

63: 5858-5869 (2014), available at

https://doi.org/10.1016/j.egypro.2014.11.619;

IEAGHG,

Potential Implications on Gas Production from Shales and Coals for Geological Storage of CO

Report Number 2013/10 (September 2013), available at

http://www.ieaghg.org/docs/General_Docs/Reports/2013-10.pdf.

Based on an analysis of the information provided in U.S. DOE NETL,

Carbon Storage Atlas, Fifth Edition,

September 2015, available at

https://www.netl.doe.gov/research/coal/carbon-storage/atlasv

and areas within 100 km (62 miles) of these locations. The geographic area decreased by 411,156 square km (158,748 square miles).

For these reasons, GS may not be as widely geographically available as assumed in the 2015 analysis. Further work being conducted by DOE to devise and develop technologies that can improve wellbore integrity, increase reservoir storage efficiency, quantitatively assess and mitigate risks, and confirm permanent storage of CO

through reliable, cost-effective, multilevel monitoring programs in storage complexes in diverse geologic settings would help determine actual availability of GS in all types of formations. Additionally, work on the DOE Carbon Storage Assurance Facility Enterprise (CarbonSAFE) initiative, an effort to develop an integrated CCS storage complex constructed and permitted for operation in the 2025 timeframe, will increase understanding of the feasibility of GS across the United States and further characterize the availability of GS.

b. Water Availability

Currently available amine-based solvent capture systems require water for process makeup and cooling. As part of the 2015 rulemaking, multiple commenters expressed concerns that the EPA's determination that partial CCS was BSER was inappropriate because of increased water consumption impacts and geographical (or other) water availability/scarcity issues limiting or eliminating CCS implementation. The EPA acknowledged that, similar to other air pollution controls, such as a wet flue gas desulfurization scrubber, post-combustion amine-based capture systems result in increased water consumption. However, the EPA evaluated the issue and found the water use to be manageable (80 FR 64593). The Agency stated that the studies

referenced by commenters that indicated significant increases in water use from CCS cooling and process operations compared to coal-fired EGUs without CCS were for cases where full CCS (90 percent or greater capture) is implemented, and were therefore of limited relevance to its determination that

partial

CCS was BSER.

See

comments of UARG at p. 84 (Docket entry: EPA-HQ-OAR-2013-0495-9666) citing Haibo Zhai,

et al.,

“Water Use at Pulverized Coal Power Plants with Post-Combustion Carbon Capture and Storage,”

Environ. Sci. Technol.,

45:2479-85 (2011);

U.S. DOE NETL,

Water Requirements for Existing and Emerging Thermoelectric Plant Technologies

at 13 DOE/NETL-402/080108, August 2008, April 2009 revision.

In the 2015 Rule, the EPA examined water use predicted from the updated DOE/NETL studies to determine the magnitude of increased water usage for a new SCPC EGU implementing partial CCS to meet the final standard of 1,400 lb CO

/MWh-gross. The EPA in 2015 determined that the results showed that a new SCPC unit that implements 16 percent partial CCS to meet the final standard would see an increase in water consumption (the difference between the predicted water withdraw and discharge) of about 6.4 percent compared to an SCPC with no CCS and the same net power output. Further, the EPA expressed the view that there would be additional opportunities to minimize the water usage at such a facility. For example, the SaskPower Boundary Dam Unit #3 post-combustion capture project captures water from the flue gas and recycles the water, resulting in decreased withdrawal of fresh water. In addition, while the Agency did not find IGCC to be the BSER, the predicted water consumption for the new IGCC unit was nearly 20 percent less than that predicted for the new SCPC unit without CCS (and almost 25 percent less than the SCPC unit meeting the final standard). The EPA also predicted that water consumption at a new NGCC unit would be less than half that for a new SCPC EGU with the same net output.

In the 2015 Rule, the EPA's water use increase comparison, which was summarized in Table 13 of the 2015 final rule preamble (80 FR 64592), was evaluated based on a bituminous-fired EGU with a wet scrubber and a cooling tower. While this is one common configuration for an EGU boiler and associated air pollution control device, this does not account for other boiler configurations and other air pollution control devices. Certain regions of the country with an arid climate and/or scarce water availability often use boiler and pollution control devices that minimize water use. While the absolute amount of water required for CO

capture equipment is relatively constant on a gallon per ton of captured CO

basis across various boiler types, the percentage increase in water requirements is not. A more appropriate percentage increase comparison for arid western markets and other locations in water-scarce environments is a subbituminous-fired PC unit with spray drying or a fluidized bed unit and a cooling tower. To estimate the increased water consumption for low rank coal-fired EGUs, the EPA used the NETL partial capture report for bituminous coal-fired EGUs to determine the increased water requirements per amount of CO

captured. The EPA then applied the increased water use relationship to the 2011 baseline report that included model plants burning low rank coal.

As shown in Table 8, the percent increase in water use for EGUs burning low rank coals is four times as large as for bituminous-fired EGUs. The EPA is proposing that this increase in water requirements is so great that it could be prohibitively expensive for developers to secure sufficient quantities of water in arid regions of the country.

85 86

Part of the rationale that the water requirements are too great is that the water requirements for partial CCS are roughly double that of the water requirements for a spray dryer used for SO

control.

In the 2015 final rule, the EPA referenced SaskPower Boundary Dam's lignite-fired Unit #3 post-combustion capture project that recovers water from the flue gas and recycles it, resulting in decreased need for withdrawal of fresh water from the adjacent reservoir. However, specific data on how much water was captured/saved was not cited. In retrospect, the EPA now believes that it should have considered that for new lignite-fired power plants owners/operators would likely dry the lignite prior to combustion. Drying lignite both decreases the capital cost of a new boiler island and increases boiler efficiency. However, it results in less water in the flue gas, limiting the amount that can be captured/recycled. The same might be the case for new subbituminous coal-fired EGUs—they would likely dry the coal prior to combustion so less water would be available in the flue gas for recovery and reuse.

In the 2015 rulemaking, the raw water consumption for a SCPC with no CCS (bit) was reported as 4,095 gallons per minute (gpm) instead of 4,045 gpm. This resulted in a reported increase in water use of 6.4 percent instead of 7.7 percent.

Table 8—Predicted Water Consumption

Technology

Raw water consumption

(gpm/MWnet)

Increase in water use compared to no CCS

(%)

SCPC − no CCS (bit)

7.4

SCPC + ~16% CCS (bit)

7.9

7.7

SCPC − no CCS (low rank))

3.8

SCPC + ~ 26% CCS (low rank)

4.9

MWnet = megawatts-net.

SCCFB = supercritical circulating fluidized bed.

In addition to the configurations cited in the NETL report, other boiler configurations use even less water. For example, Black Hills Power Corporation's 110-MW Wygen III is a pulverized coal power plant near Gillette, Wyoming. The plant, which came online in 2010, fires Powder River Basin coal and has an air pollution control system comprised of selective catalytic reduction, dry flue gas desulfurization (FGD), and a fabric filter baghouse. This type of “dry” plant was built with minimal water requirements due to dry cooling and dry lime FGD for acid gas control. As described elsewhere in the preamble, this type of boiler design is one of the configurations likely to be considered for future coal-fired EGUs. However, carbon capture technologies are limited to using conventional wet cooling technologies. The EPA is unaware of any demonstration, pilot, or large-scale projects using dry cooling technologies with carbon capture technologies. Therefore, requiring CCS on a plant of this design would substantially increase the plant's water-use requirements.

All CCS systems that are currently available require substantial amounts of water to operate. These water requirements would limit the geographic availability of potential future EGU construction to areas of the country with sufficient water resources.

To establish water availability, the EPA has, for this proposal, reviewed annual average rainfall totals as an estimation of water availability. This approach indicates that the Western U.S. (

i.e.,

areas west of a line running from central Texas to North Dakota), excluding the Pacific Northwest, has lower amounts of water available for EGUs. In addition, a comparison of areas of the country with lower rainfall amounts shows considerable overlap with areas of the country with sequestration sites. This suggests that many sequestration sites might not have sufficient water resources to operate CO

capture equipment. Therefore, this, in combination with the EPA's proposed determination that its earlier understanding of the scope of geologic sequestration site availability was an overestimation (by some 4 percent), has led the EPA to propose a revision to its 2015 findings and a new determination that the overall geographic availability of CCS is too limited to be considered as BSER.

In the 2015 Rule, EPA also stated that a new IGCC unit required nearly 20 percent less water than a new bituminous coal-fired SCPC unit without CCS (and almost 25 percent less than the SCPC unit meeting the final standard). The DOE/NETL reports indicate that IGCC designs are available that use less water than comparative PC units for low rank coals as well. However, in an April 2017 independent engineering report on the Kemper IGCC Project,

one of the concerns noted was the underestimation of the amount of water needed for the process water system. The report noted that the initially planned 5 million gallons of storage was insufficient, that a new 1.7-million-gallon temporary tank was to be installed and that additional permanent water storage tank capacity should be considered. Based on this, the EPA is soliciting comment on whether IGCC reduces the amount of water use by coal-fired EGUs (Comment C-9).

This project received federal assistance under the Energy Policy Act of 2005 (EPAct05).

See

2015 rule, 80 FR at 64526, n.74. The EPA is not proposing to revise or re-open the interpretation of EPAct05 that the EPA included in the 2015 rule.

Id.

at 64541-64542. Thus, because the EPA is considering information about the Kemper project in conjunction with other information that is not from facilities affected by EPAct05, EPAct05 does not preclude the EPA from considering such Kemper information.

c. Review of Technical Feasibility of Carbon Capture Equipment

In the 2015 Rule, the EPA determined that CO

capture technology was technically feasible based on EGUs that had previously and were currently using post-combustion carbon capture technology (especially Boundary Dam), commercial vendors that offered carbon capture technology and other performance guarantees, a review of the literature, and industry and technology developers' pronouncements of the feasibility and availability of CCS technologies. Since the 2015 rulemaking, the Petra Nova CCS project, located at NRG's W.A. Parish power generating station near Houston, Texas, has begun operations, and is reported to be the world's largest post-combustion carbon capture system.

As with the Kemper project discussed above, this project received federal assistance under EPAct05.

See

2015 rule, 80 FR at 64526, n.74. As with the Kemper project, because EPA is considering information about the Petra Nova project in conjunction with other information that is not from facilities affected by EPAct05, EPAct05 does not preclude EPA from considering the Petra Nova information.

While the carbon capture technology at the Boundary Dam project is currently operating, that project experienced multiple issues with the performance of the capture technology during its first year of operation (2014-15). During that time, the capture equipment was operating with lower reliability than designed, and, as a result, SaskPower renegotiated its CO

supply contract with Cenovus to avoid paying penalties for not supplying the agreed amount of CO

for the company's EOR projects. These problems included the amine chemistry and the CO

compression system. While the Petra Nova project is currently operating, it has not demonstrated the integration of the thermal load of the capture technology into the EGU steam generating unit (

i.e.,

boiler) steam cycle. Rather, the parasitic electrical and steam load are supplied by a new 75 MW co-located natural gas-fired CHP facility. The EPA solicits comment on whether Boundary Dam's first-year operational problems cast doubt on the technical feasibility of fully integrated CCS (Comment C-10). For example, would an EGU with a fully integrated steam cycle that draws steam from the steam turbine to regenerate the amine be able to operate during periods when the carbon capture system is not operating?

The EPA notes that while both these projects are currently operating, both received significant government support to mitigate the financial risks associated with the CCS technology. Because no independent commercial CCS projects are in operation, the EPA solicits comment on whether the fact that Boundary Dam and Petra Nova were dependent on government support casts doubt on the technical feasibility of CCS,

e.g.,

whether it raises concerns as to the extent to which developers are willing to accept the risks associated with the operation and long-term reliability of CCS technology (Comment C-11).

While the EPA did not find that a new IGCC EGU is part of the final BSER, the Agency did note that IGCC without CCS is a viable alternative compliance option. However, both the Edwardsport and Kemper IGCC facilities had significant cost overruns. In fact, the Kemper IGCC's technology challenges, escalating costs, and project management issues resulted in the company suspending startup and operations activities involving the lignite gasification portion of the energy facility, leaving only the natural gas combined cycle plant in operation.

The EPA solicits comment on the extent to which the issues with these IGCC EGUs cast doubt on the economic viability of IGCC as an option for new generation (Comment C-12).

URS Corp.,

IM Monthly Report—Mississippi Public Service Commission: Kemper IGCC Project,

April 2017, available at

http://www.psc.state.ms.us/executive/pdfs/2017/Kemper/Monthly%20Report%20April%202017%20Executive%20Summary.pdf.

B. Identification of the Revised BSER

The EPA evaluated six different control technology configurations as potentially representing the BSER for new and reconstructed coal-fired EGUs: (1) The use of partial CCS, (2) conversion to (or co-firing with) natural gas, (3) the use of CHP, (4) the use of a hybrid power plant, (5) the use of IGCC technology, and (6) efficient generation. This section discusses each of these alternatives, including the technical systems that the EPA considered for the BSER, evaluations of each system, and the reasons for determining that the most efficient generating technology meets the criteria to qualify as the BSER. The discussion includes the rationale for selecting the proposed standards of performance based on those BSER.

As noted above, the EPA determines the best demonstrated system based on the following key considerations, among others:

• The system of emission reduction must be technically feasible.

• The costs of the system must be reasonable. The EPA may consider the costs on the source level, the industrywide level, and, at least in the case of the power sector, on the national level in terms of the overall costs of electricity and the impact on the national economy over time.

• The EPA must also consider energy impacts, and, as with costs, may consider them on the level of the source, the region, and on the nationwide structure of the power sector over time.

• According to the D.C. Circuit caselaw, the EPA must consider the amount of emissions reductions that the system would generate, and that CAA section 111 is designed to promote the development and implementation of technology. Moreover, the EPA has discretion to weigh these various considerations, may determine that some merit greater weight than others, and may vary the weighting depending on the source category.

1. Partial CCS

As described previously, under the revised analysis set forth in this proposal, the EPA proposes that the cost of partial CCS is not reasonable. In addition, when the availability of water and geologic sequestration sites are considered together, the EPA finds that partial CCS is not widely geographically available. In addition, the EPA is soliciting comment on whether there is sufficient information about the long-term reliability of carbon capture technology and sequestration capture technology to assess the technical feasibility of CCS (Comment C-13). Therefore, the EPA proposes to rescind our finding that partial CCS satisfies the BSER criteria and proposes to find that it does not.

2. Conversion to or Co-Firing With Natural Gas

While co-firing with natural gas in a utility steam generating unit a technically feasible option to reduce CO

emission rates, it is an inefficient way to generate electricity compared to use of an NGCC. For cases where the natural gas could be co-fired without any capital investment (

e.g.,

sufficient natural gas is available at the site) or impact on the performance or operation of the affected EGU, the costs of CO

reduction would be between approximately $40 to $70 per ton of CO

avoided (that is, $40/ton for bituminous coal and $70/ton for subbituminous coal), depending on the coal rank burned in the boiler. This calculation only accounts for the relative costs and CO

emission rates of the fuel and does not account for potential adverse or positive impacts on the operation of the boiler. While natural gas prices have fallen significantly over the past decade, long term price projections forecast that natural gas will still be significantly more expensive than coal on a $/MMBtu basis. The higher fuel costs from co-firing would increase both the LCOE and variable operating costs of the unit. As described earlier, due to economic dispatch, the unit would be expected to have lower electricity sales, and therefore generate less revenue and less marginal and overall profit. Further, if an owner/operator is required to burn natural gas for compliance purposes, it would likely have to enter into firm service contracts as opposed to interruptible service contracts for natural gas, which would increase its costs for natural gas. Potential positive aspects include a reduction in pre-post combustion control criteria pollutant and HAP emission rates. Due to these lower pre-post combustion emission rates, post-combustion control requirements are reduced and savings could be realized due to both lower capital and O&M post combustion control costs and/or the cost of emission allowances under certain pollution control programs. Most pollutants, and especially NO

, would be reduced in proportion to the amount of natural gas burned.

Natural gas reburning (NGR) is a combustion technology in which a portion of the main fuel heat input is diverted to locations above the burners, creating a secondary combustion zone called the reburn zone. In NGR, natural gas is injected to produce a slightly fuel rich reburn zone. Overfire air (OFA) is added above the reburn zone to complete burnout. NGR requires 15 to 20 percent of furnace heat input from natural gas and OFA and has been demonstrated to reduce NO

emissions by 39 to 67 percent on several existing coal-fired boilers in applications ranging in size from 33 to 600 MW in the U.S. and up to 800 MW internationally. With NGR at 15 and 20 percent of the heat input to a coal-fired boiler, the CO

emission rate would be reduced by 6 to 10 percent.

Fuel lean gas reburning (FLGR

), also known as controlled gas injection, is a process in which natural gas is injected above the main combustion zone at a lower temperature zone than in NGR. FLGR

is different from NGR because the gas is injected in a manner that optimizes the furnace's stoichiometry on a localized basis. By doing this, the process avoids creating a fuel-rich zone and maintains overall fuel-lean conditions. The FLGR

technology achieves NO

control using less than 10 percent natural gas heat input without the requirement for OFA. FLGR

has a capital cost of approximately $8/kW

and been demonstrated to reduce NO

emissions by 33 to 45 percent. At a 10 percent heat input reburn rate, the CO

emission rate of a coal-fired EGU would be reduced by 4 to 5 percent. Based strictly on the diff

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