6560-50-P · Web view2021. 1. 14. · When the EPA promulgated the 2015 Rule, it took note of both utility announcements and U.S. Energy Information Administration (EIA) modeling

***E.O. 12866 Review-Draft-Do Not Cite, Quote, or Release During Review***

EO 12866_GHG EGU New Sources 2060-AT56 Final Rule_20201229

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2013-0495: FRL–10019-30-OAR]

RIN 2060-AT56

Review of Standards of PerformancePollutantPollutant-Specific Significant Contribution

Finding for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary

Sources: Electric Utility Generating Units, and Process for Determining Significance of

Other New Source Performance Standards Source Categories

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final Rule.

SUMMARY: In this action, the U.S. Environmental Protection Agency (EPA) is amending the

rulemaking titled “Standards of Performancefinalizing finalizing a definition for Greenhouse Gas

Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility

Generating Units,” which the EPA promulgated on October 23, 2015 (2015 Rule).a significant

contribution finding (SCF) for purposes of regulating source categories for greenhouse gas

(GHG) emissions, under section 111(b) of the Clean Air Act (CAA). The In EPA’s considered

viewEPA is finalizing its revised determination of the best systemthatthat , source categories can

be considered to contribute significantly to dangerous air pollution due to their GHG emissions

only if the amount of emission reduction (BSER) for newly constructed coal-fired steam

generating units to be highly efficient generation technology combined with best operating

practices, insteadthosethose emissions exceeds 3 percent of partial carbon capture and storage

(CCS). This action total U.S. GHG emissions. For source categories that emit above this

Author, 01/03/-1,

EOP CommentSee comment below on regulatory text.

Author, 01/03/-1,

EOP Comment See comment below on regulatory text. It seems more defensible to say that this is part of EPA’s reasoning in reaching this conclusion, rather than to suggest that EPA is finalizing a rule that the public had no reason to believe that EPA would ever propose.

Author, 01/03/-1,

Interagency CommentIt is disappointing that EPA has decided against revoking the finding that partial CCS is BSER. Reliance on demonstration technology (that in hindsight never achieved commercial viability) is an unfortunate precedent to leave in place.

***E.O. 12866 Review-Draft-Do Not Cite, Quote, or Release During Review***Page 2 of 215

threshold, the EPA is also revises or adopts standards of performance at base load and non-base

load operating conditions for large and small newly constructed and reconstructed finalizing

secondary criteria that may be used to further evaluate whether a source category contributes

significantly. The EPA is also applying the 3-percent threshold to the electric generating units

(EGUs) and coal refuse-fired EGUs. In addition, this action revises the maximum stringency of

the standards of performance for large modifications of steam generating units operating at base

load or non-base load conditions and finalizes other miscellaneous technical changes in EGU)

source category and determining that GHG emissions from the regulatory requirements.

EGU source category do contribute significantly to dangerous air pollution. DATES: The final

rule is effective on [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE

FEDERAL REGISTER].

ADDRESSES: The EPA has established a docket for this action under Docket ID No. EPA-HQ-

OAR-2013-0495. All documents in the docket are listed on the https://www.regulations.gov/

website. Although listed, some information is not publicly available, e.g., Confidential Business

Information 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 form. With the exception of such material, publicly available docket materials are

available electronically through https://www.regulations.gov/. Out of an abundance of caution

for members of the public and our staff, the EPA Docket Center and Reading Room are closed to

the public, with limited exceptions, to reduce the risk of transmitting COVID-19. Our Docket

Center staff will continue to provide remote customer service via email, phone, and webform.

For further information on EPA Docket Center services and the current status, please visit us

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

Author, 01/03/-1,

EOP Comment This is different from the prior draft. Why 60 days?


FOR FURTHER INFORMATION CONTACT: For questions about this final action, contact

Mr. Christian Fellner, Sector Policies and Programs Division (D243-01), 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: [email protected].

SUPPLEMENTARY INFORMATION:

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 OutlookBACT best available control technologyBSER best system of emission reductionBtu/kWh British thermal units per kilowatt-hourBtu/lb British thermal units per pound°C degrees CelsiusCAA Clean Air ActCAAA Clean Air Act AmendmentsCAMD Clean Air Markets DivisionCBO Congressional Budget Office CCS carbon capture and storage (or sequestration)CEMS continuous emissions monitoring systemCFB circulating fluidized bedCFR Code of Federal RegulationsCH4 methaneCHP combined heat and powerCO carbon monoxideCO2 carbon dioxideD.C. Cir. United States Court of Appeals for the District of Columbia CircuitDOE Department of EnergyECMPS emissions collection and monitoring plan systemEGU electric utility generating unitEIA U.S. Energy Information AdministrationEOR enhanced oil recoveryEPA Environmental Protection Agency°F degrees FahrenheitFB fluidized bedFGD flue gas desulfurization


GHG greenhouse gasGHGRP Greenhouse Gas Reporting ProgramGJ/h gigajoules per hourGS geologic sequestrationHAP hazardous air pollutant(s)HFC hydrofluorocarbonHg mercuryHRSG heat recovery steam generator IGCC integrated gasification combined cyclekm kilometerslb CO2/MWh-gross pounds of CO2 per megawatt-hour on a gross output basislb CO2/MWh-net pounds of CO2 per megawatt-hour on a net output basisLCOE levelized cost of electricityM millionMMBtu/h million British thermal units per hourMPa megapascalsMW megawattsMWh megawatt-hoursMWnet megawatts-netN2O nitrous oxideNAICS North American Industry Classification SystemNETL National Energy Technology LaboratoryNGCC natural gas combined cycleNOx nitrogen oxidesNSPS new source performance standardsOMB Office of Management and BudgetPC pulverized coalPFC perfluorocarbonPM particulate matterPSD Prevention of Significant DeteriorationSCCFB supercritical circulating fluidized bedSCE&G South Carolina Electric and GasSCPC supercritical pulverized coalSCR selective catalytic reductionSF6 sulfur hexafluorideSO2 sulfur dioxideT&S transport and storageTSD technical support documentU.S. United StatesU.S.C. United States CodeVCS voluntary consensus standard

Organization of this document. The information in this preamble is organized as follows:

I. General InformationA. Does this action apply to me?


B. Where can I get a copy of this document and other related information?C. Judicial reviewII. Executive SummaryA. What is the purpose of this regulatory action?B. What is the summary of the major provisions in this action?C. What are the costs and benefits?III. Summary of Previous Rulemaking ActionsIV. Pollutant -Specific Significant Contribution Findings (SCF)A. BackgroundB. What is a Significant Contribution Finding (SCF)?C. Primary Criteria for Determining SignificanceD. Secondary Criteria for Determining SignificanceE. Significant Contribution Finding for EGUsV. Review and Withdrawal of the 2015 BSER DeterminationA. Review of CostsB. Geographic Scope of CCSC. Technical Availability of CCSVI. Systems Considered but Not Determined to be the BSERA. Natural Gas Co-firingB. Integrated Gasification Combined Cycle (IGCC)C. Natural Gas Combined Cycle (NGCC)D. Combined Heat and Power (CHP)E. Hybrid Power PlantsVII. Final BSER and New Source Performance StandardsA. Summary of 2018 Proposal BSER and Emission StandardsB. Summary of Final BSER and Emission StandardsC. Efficient Generation as the BSER for New Coal-Fired EGUsD. Level of the Standard of Base Load UnitsE. Subcategorization and Level of the Standard for Non-Base Load UnitsF. Lignite and Coal Refuse SubcategorizationG. BSER and Standard for Reconstructed EGUsH. BSER and Standard for Modified EGUsVIII. Applicability and Miscellaneous IssuesA. Comments on ApplicabilityB. Other Miscellaneous IssuesIX.V. Summary of Cost, Environmental, and Economic Impacts A. What are the affected facilities?B. What are the air quality impacts?C. What are the energy impacts?D. What are the cost impacts?E. What are the economic impacts?F. What are the benefits?XVIVI. Statutory and Executive Order ReviewsA. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563:Improving Regulation and Regulatory ReviewB. Executive Order 13771: Reducing Regulations and Controlling Regulatory Costs


C. Paperwork Reduction Act (PRA)D. Regulatory Flexibility Act (RFA) E. Unfunded Mandates Reform Act (UMRA)F. Executive Order 13132: FederalismG. Executive Order 13175: Consultation and Coordination with Indian Tribal GovernmentsH. Executive Order 13045: Protection of Children from Environmental Health Risks and SafetyRisksI. Executive Order 13211: Actions Concerning Regulations that Significantly Affect EnergySupply, Distribution, or UseJ. National Technology Transfer and Advancement Act (NTTAA) K. Executive Order 12898: Federal Actions to Address Environmental Justice in MinorityPopulations and Low-Income PopulationsL. Congressional Review Act (CRA)

I. General Information

A. Does this action apply to me?

The source categories that are the subject of this final rule areincludeinclude electric

generating units regulated under 40 CFR 60, subpart TTTT. The North American Industry

Classification System (NAICS) code for the industrial, federal government, and state/local

government electric generating units is 221112. The NAICS code for tribal government electric

generating units is 921150. This list of categories and NAICS codes is not intended to be

exhaustive, but rather provides a guide for readers regarding the entities that this final rule is

likely to affect. Also, the methodology set forth and utilized in this final rule concerning

determining whether a source category’s GHG emissions contribute significantly to dangerous

air pollution is applicable, in principle, to all CAA section 111 source categories with GHG

emissions.

B. 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 final action is

available on the Internet. Following signature by the EPA Administrator, the EPA will post a

copy of this final action at https://www.epa.gov/stationary-sources-air-pollution/nsps-ghg-

Author, 01/03/-1,

EOP Comment Still only EGU NAICS listed here. EPA is applying the 3 percent standard for all GHGs across all source categories. Given the narrower scope of the NPRM, it is important that EPA clarify the scope with regard to affected NAICS as well and list them here.

Author, 01/03/-1,

EOP Comment See comments on regulatory text and on page 1.


emissions-new-modified-and-reconstructed-electric-utility. Following publication in the Federal

Register, the EPA will post the Federal Register version of the final rule and key technical

documents at this same website.

C. Judicial Review

Under section 307(b)(1) of the Clean Air Act (CAA), judicial review of this final rule is

available only by filing a petition for review in the United States Court of Appeals for the

District of Columbia Circuit (the D.C. Circuit) by [INSERT DATE 60 DAYS AFTER DATE

OF PUBLICATION IN THE FEDERAL REGISTER]. Moreover, under section 307(b)(2) of

the CAA, the requirements established by this final rule may not be challenged separately in any

civil or criminal proceedings brought by the EPA to enforce these requirements. Section 307(d)

(7)(B) of the CAA further provides that “[o]nly an objection to a rule or procedure which was

raised with reasonable specificity during the period for public comment (including any public

hearing) may be raised during judicial review.” This section also provides a mechanism for the

EPA to convene a proceeding for reconsideration, “[i]f the person raising an objection can

demonstrate to the EPA that it was impracticable to raise such objection within [the period for

public comment] or if the grounds for such objection arose after the period for public comment,

(but within the time specified for judicial review) and if such objection is of central relevance to

the outcome of the rule.” Any person seeking to make such a demonstration to us should submit

a Petition for Reconsideration to the Office of the Administrator, U.S. Environmental Protection

Agency, Room 3000, WJC South Building, 1200 Pennsylvania Ave. NW, Washington, DC

20460, with a copy to both the person(s) listed in the preceding FOR FURTHER

INFORMATION CONTACT section, and the Associate General Counsel for the Air and


Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. Environmental

Protection Agency, 1200 Pennsylvania Ave..,., NW, Washington, DC 20460.

II. Executive Summary

A. What is the purpose of this regulatory action?

In Executive Order 13783 (Promoting Energy Independence and Economic Growth), all

executive departments and agencies, including the EPA, arewerewere directed 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.”1 Moreover, the Executive Order directed the EPA to

undertake this process of review with regard to the “Standards of Performance for Greenhouse

Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility

Generating Units,” 80 FR 64510 (October 23, 2015) (2015 Rule).

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 a review of the 2015 Rule, and providing notice of a

forthcoming proposed rulemaking consistent with the Executive Order. TheAfterAfter due

deliberation, the EPA issued a notice of proposed a rulemaking, “Review of Standards of

Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary

Sources: Electric Utility Generating Units—Proposed Rule,” 83 FR 65424 (December 20, 2018)

(2018 Proposal), and here the EPA is finalizing a rulemaking).). Here the EPA is finalizing a

rulemaking with respect to whether GHG emissions from EGUs contribute significantly to

dangerous air pollution, which utilizes a methodology for determining whether GHG emissions 1 Executive Order 13783, Section 1(c), 82 FR 16093.

Author, 01/03/-1,

EOP Comment See comments below.


from other NSPS source categories contribute significantly to dangerous air pollution. Any

action regarding the proposal to revise the standards of performance, including the underlying

determinations of the BSER, for new, reconstructed, and modified coal-fired EGUs, including

certain technical issues, is beyond the scope of this final rulemaking and comments received on

the 2018 proposal will be addressed in any separate future action.

B. What is the summary of the major provisions in this action?

The EPA is determining that the BSER for newly constructed coal-fired EGUs is the

most efficient available steam cycle (i.e., supercritical steam conditions for large units and

subcritical steam conditions for small units) in combination with the best operating practices. In

addition, for newly constructed coal-fired EGUs2 firing moisture-rich fuels (i.e., lignite), the

BSER also includes pre-combustion fuel drying using waste heat from the process. The EPA is

not revising the BSER for any other sources as determined in the 2015 Rule. In addition, the

EPA is promulgating separate standards of performance for large and small newly constructed

coal-fired EGUs, operating at base load or non-base load conditions, that reflect the Agency’s

final BSER determination.

The EPA is also promulgating revised standards of performance for base load and non-

base load operating conditions for large and small reconstructed coal-fired EGUs, as well as for

newly constructed and reconstructed coal refuse-fired EGUs.

The EPA is also revising the maximally stringent standards for coal-fired EGUs

undergoing large modifications (i.e., modifications resulting in an increase in hourly carbon

dioxide (CO2) emissions of more than 10 percent) to be consistent with the various standards for

newly constructed and reconstructed units. While the EPA solicited comment on establishing

2 The 2014 Proposed Rule applied to all fossil fuel-fired steam generating units, including natural gas and oil-fired EGUs, but the proposal of CCS as the BSER was limited to coal-fired EGUs.

Author, 01/03/-1,

EOP Comment Were other source categories listed as potentially affected entities at proposal? See other comments.


standards of performance for small modifications (i.e., modifications that result in an increase in

hourly emissions of 10 percent or less) based on a unit’s historical performance and how to best

account for emissions variability due to changes in the mode of operation, the EPA is not

finalizing any standards for small modifications.

Table 1 shows the final standards of performance for newly constructed and

reconstructed EGUs, as well as modified EGUs.

TABLE 1. SUMMARY OF BSER AND FINAL STANDARDS FOR AFFECTED SOURCES

Affected Source1 BSER Emissions Standard

Newly Constructed and Reconstructed Steam Generating

Units and Integrated Gasification

Combined Cycle (IGCC) Units that

have a 12-operating month duty cycle

(average operating capacity factor) of

65 percent or greater (i.e., base

load units)

Most efficient generating

technology and pre-combustion drying of high

moisture content fuels in

combination with best operating

practices

[1.] 1,800 pounds of CO2 per megawatt-hour on a gross output basis (lb CO2/MWh-gross) for sources with heat input > 2,000 million British thermal units per hour (MMBtu/h);

[2.] 2,000 lb CO2/MWh-gross for sources with heat input ≤ 2,000 MMBtu/h; or

[3.] 2,200 lb CO2/MWh-gross for coal refuse-fired sources

Newly Constructed and Reconstructed Steam Generating Units and IGCC Units that have a

12-operating month duty cycle (average operating capacity factor) of less than

65 percent (i.e., non-base load units)





practices

[1.] 1,900 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h;



Modified Steam Generating Units

and IGCC Units that

Best demonstrated performance

A unit-specific emission limit determined by the unit's best historical annual CO2 emission rate (from 2002 to the date of the modification); the emission


have a 12-operating month duty cycle



load units)

limit will be no more stringent than





and IGCC Units that have a 12-operating month duty cycle


less than 65 percent (i.e., non-base load

units)


A unit-specific emission limit determined by the unit's best historical annual CO2 emission rate (from 2002 to the date of the modification); the emission limit will be no more stringent than

1. 1,900 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h;2. 2,100 lb CO2/MWh-gross for sources with heat input ≤ 2,000 MMBtu/h; or3. 2,300 lb CO2/MWh-gross for coal refuse-fired sources

1. 40 CFR 60.5509(b)(7) exempts steam generating units or IGCCs that undergoes a modification resulting in an hourly increase in CO2 emissions of 10 percent or less from the 40 CFR part 60, subpart TTTT applicability.

The EPA is also promulgating minor amendments to the applicability criteria for

combined heat and power (CHP) and non-fossil EGUs and other miscellaneous technical

changes in the regulatory requirements.

The EPA is finalizing a pollutant-specific significant contribution finding (SCF) for GHG

emissions from EGUs. The In reaching this conclusion, the EPA has also concluded that it is

appropriate to utilize a threshold for determining significance, as well as secondary criteria to be

applied in certain circumstances, that in principle would be equally applicable to for for other

NSPS source categories.

C. What are the costs and benefits?

In 2015, the EPA promulgated “Standards of Performance for Greenhouse Gas Emissions

From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units,”

80 FR 64510 (October 23, 2015) (2015 Rule). When the EPA promulgated the 2015 Rule, it took

Author, 01/03/-1,

EOP Comment See comments on page 1 and on regulatory text.


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, (1) existing and

anticipated economic conditions are such that few, if any, coal-fired EGUs will be built in the

foreseeable future, and that (2) utilities and project developers are expected to choose new

generation technologies (primarily natural gas combined cycle (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 CO2 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 new source performance standards (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.

As explained in the economic impact analysis for this final rule, theTheThe EPA has

concluded that the projections described in the 2015 Rule remain generally correct. In the period

of analysis,3 the EPA expects there to be few, if any, newly constructed, reconstructed, or

modified sources that will trigger the provisions the EPA is promulgating in this action.

Consequently, the EPA has conducted an illustrative analysis of the costs for a representative

newly constructed unit. Based on this analysis, which is presented in the economic impact

analysisConsequentlyConsequently, the EPA projects that there will be no significant changes in

CO2 emissions or in compliance costs as a result of this final rule. This analysis reflects the best

data available to the EPA at the time the modeling was conducted. As with any modeling of

3 GHG pollution is the aggregate of the following six gases: CO2, methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs).

Author, 01/03/-1,

Interagency Comment This discussion is no longer relevant to the contents of this rulemaking. See comments below.

Author, 01/03/-1,

EOP Comment Reiterating request: please provide the underlying analysis, particularly for the newly added policy in this final rule. Requesting staff call on this for Monday. At a minimum, the updated analysis should reflect the 3 percent policy across all source categories and at reverting to the baseline on BSER. In an ideal setting EPA would update all analyses including BSER and reissue for comment.


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 the 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 and/or inertia to stabilize the power grid, or substantial shifts in energy prices. The

results presented in the economic impact analysis are not a prediction of what will happen, but

rather a projection describing how this final regulatory action may affect electricity sector

outcomes in the absence of significant and unexpected changes. The results of the economic

impact analysis should be viewed in that context.

III. Summary of Previous Rulemaking Actions

On April 13, 2012, the EPA first proposed a NSPS for greenhouse gas (GHG) emissions

from fossil fuel-fired EGUs. 77 FR 22392 (2012 Proposed Rule). In that proposal, the EPA

proposed the BSER for a newly constructed fossil fuel-fired power plant (regardless of fuel or

generating technology) to be NGCC technology. Id. at 22394. Coal-fired EGUs and NGCC units

selling greater than 25 megawatts (MW) to the electric grid that commenced construction after

April 13, 2012, would have been subject to the same numeric emissions standard. On January 8,

2014, in two separate actions, the EPA withdrew that proposal, 79 FR 1352 (2012 Proposed Rule

Withdrawal), and replaced it with a new proposal that identified partial CCS as the BSER for

newly constructed coal-fired EGUs. 79 FR 1430 (2014 Proposed Rule).4 On October 23, 2015,

4 The EPA also refers to fossil fuel-fired steam generating units as “steam generating units,” “utility boilers and IGCC units,” or as “coal-fired EGUs.” 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

Author, 01/03/-1,

Interagency Comment Include discussion of the Oil & Gas rulemaking decision that SCF is required.


the EPA promulgated the 2015 Rule, in which it finalized the partial CCS BSER and finalized

standards of performance to limit emissions of GHG manifested as CO25 from newly constructed,

modified, and reconstructed fossil fuel-fired EGUs (i.e., utility boilers and IGCC units). In the

same notice, the Agency also finalized CO2 emission standards for newly constructed and

reconstructed stationary combustion turbine EGUs. 80 FR 64510. These final standards were

codified in 40 CFR part 60, subpart TTTT.

The 2015 standards of performance for newly constructed coal-fired EGUs6 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 CAA section 111(b) for these sources. The EPA concluded that partial CCS was

adequately demonstrated, including that it was technically feasible, that it was widely available,

and that it could be implemented at reasonable cost. The EPA did not determine natural gas co-

firing or IGCC technology (by itself or with either natural gas co-firing or partial CCS) to be the

BSER. However, the Agency did identify them as alternative methods of compliance. 80 FR

64513 and 64514.

For coal-fired EGUs that undergo a “reconstruction”— which is defined as 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

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. GHGs are not criteria pollutants.5 These projects tend to be 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.6 For some EGUs, their single best annual CO2 emissions rate is lower than the standard for reconstructed EGUs. If such an EGU were modified, its emissions standard would be set at the reconstructed EGU emissions rate.


to meet the applicable standards7—the EPA finalized standards based on the performance of the

most efficient generating technology for these types of units as the BSER. That is, the BSER

consisted of reconstructing the boiler as necessary to use steam with higher temperature and

pressure, even if the boiler was not originally designed to do so.8 The 2015 emission standard for

large EGUs—those with capacity of more than approximately 200 MW—was based on the

performance of a well-operated pulverized coal (PC) EGU using supercritical steam conditions.

The emission standard for small EGUs (those with capacity of less than or equal to

approximately 200 MW) was based on the performance of a well-operated PC EGU 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 a

smaller supercritical steam turbine, due to the lack of commercial availability of such a steam

turbine, the EPA was not able to access sufficient information regarding its cost to determine that

it would qualify as BSER for smaller EGUs. The standards for reconstructions account for long-

term variability. 80 FR 64512 through 64514.

With respect to modifications, the EPA has historically been notified of only a limited

number of NSPS modifications involving coal-fired EGUs. See 80 FR 64597. 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 coal-fired

EGUs. Instead, the EPA determined that it was appropriate to establish standards of performance

only for an affected coal-fired EGU that undergoes a large modification, which, as noted above,

7 See “List of Categories of Stationary Sources,” 36 FR 5931 (March 31, 1971) (listing source category); “Standards of Performance for New Stationary Sources,” 36 FR 24376 (December 31, 1971) (promulgating NSPS for source category).8 See “Standards of Performance for New Stationary Sources; Gas Turbines,” 44 FR 52792 (September 10, 1979) (listing and promulgating NSPS for source category).


the EPA defined as one resulting in an hourly increase in CO2 emissions (mass per hour) of more

than 10 percent 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 projects9 that could result in large increases in hourly CO2 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 a coal-fired EGU

that undergoes a large modification is the most efficient generation achievable through a

combination of best operating practices and equipment upgrades. The EPA further determined

that the standard of performance would be based on each affected unit’s own best historic annual

CO2 emission rate, measured from 2002 to the date of the modification. The EPA also

promulgated a maximally stringent standard for a coal-fired EGU undergoing a large

modification so that its standard would be no more stringent than the standard for a reconstructed

coal-fired EGU.10 80 FR 64512 and 64513, 64597 through 64599.9 See “Priority List and Additions to the List of Categories of Stationary Sources,” 49 FR 49222 (August 21, 1979) (listing source category); “Standards of Performance for New Stationary Sources; Equipment Leaks of VOC From Onshore Natural Gas Processing Plants,” 50 FR 26124 (June 23, 1985) and "Standards of Performance for New Stationary Sources; Onshore Natural Gas Processing SO2 Emissions,” 50 FR 40160 (October 1, 1985) (promulgating standards of performance). 10 Some commenters on the 2018 Proposal also said that, in the 2009 Endangerment Finding, the EPA specifically defined air pollution, as referred to in section 202(a) of the CAA, to be the mix of six well-mixed, long-lived, and directly emitted GHGs: CO2, CH4, N2O, HFCs, PFCs, and SF6. 74 FR 66497. They commented that the EPA needs to make, but has never made, a separate finding that CO2 alone is reasonably anticipated to endanger the public health or welfare. The Agency disagrees with commenters. The air pollutant that the 2015 Rule regulates is GHG, and that air pollutant contributes to the same GHG air pollution that was addressed by the Endangerment Finding. The standards of performance adopted in the 2015 Rule take the form of an emission limitation on only one constituent gas of this air pollutant, CO2. See 40 CFR 60.5515(a) (“The pollutants regulated by this subpart are greenhouse gases. The greenhouse gas standard in this subpart is in the form of a limitation on emission of carbon dioxide.”).”)..”). This is reasonable, given that CO2 is the constituent gas emitted in the largest volume by the source category and for which there are available controls that are technically feasible and cost effective. There is no requirement that standards of performance address each component of an air pollutant. CAA section 111(b)(1)(B) requires the EPA to establish "standards of performance" for listed source categories, and the definition of "standard of performance" in CAA section 111(a)(1) does not specify which air pollutants must be controlled. Moreover, as the EPA noted in the 2015 Rule, the information considered in the 2009 Endangerment Finding and its supporting record, together with additional discussion of GHG impacts in the 2015 Rule, makes clear that GHG air pollution


As noted above, because of the lack of information concerning affected coal-fired EGUs

that undergo small modifications (modifications resulting in an increase in hourly CO2 emissions

(mass per hour) of 10 percent or less compared to the source’s highest hourly emission during

the previous 5 years) the EPA did not finalize any standard of performance or other requirements

for them. As a result, existing coal-fired EGUs that undergo small modifications remain existing

sources and continue to be subject to existing-source standards under CAA section 111(d). 80 FR

64514 and 64597 through 64599.

The 2015 Rule also finalized standards of performance for newly constructed and

reconstructed stationary combustion turbine EGUs. For new base load natural gas-fired

stationary combustion turbines, the EPA finalized a standard based on efficient NGCC

technology as the BSER. For new non-base load natural gas-fired and base load and non-base

load multi-fuel-fired stationary combustion turbines, the EPA finalized a heat input-based clean

fuels standard. The EPA did not promulgate standards for modified stationary combustion

turbines, due to lack of information.

The EPA received six petitions for reconsideration of the 2015 Rule. On May 6, 2016, the

EPA denied five of the petitions on the basis that they did not satisfy one or both of the statutory

conditions for reconsideration under CAA section 307(d)(7)(B), and deferred action on the sixth

petition, which raised the issue of the treatment of biomass. 81 FR 27442. Multiple parties filed

petitions for judicial review of the 2015 Rule. These petitions were consolidated, and briefing

was completed in January 2017. North Dakota v. EPA, No. 15-1381 (D.C. Cir.). Since April 28,

2017, the cases have been held in abeyance while the Agency reviews the 2015 Rule.

may reasonably be anticipated to endanger public health or welfare. See 80 FR 64517, 64530 and 31. Because the 2015 Rule followed the same approach as in the 2009 findings and regulated the same pollutant as contributing to the same air pollution (to reiterate, both the air pollutant and the air pollution are GHG as the group of six well-mixed gases, including CO2), it was not necessary to evaluate CO2 separately. The EPA took the same position in the 2016 Oil & Gas Rule in response to a similar comment concerning methaneCH4CH4. See 81 FR 35843.


On December 20, 2018, the EPA published a proposal to revise certain parts of the 2015

Rule; “Review of Standards of Performance for Greenhouse Gas Emissions From New,

Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units.” 83 FR

65424 (2018 Proposal). The majority of that proposal was dedicated to the issue of the best

system of emission reduction (BSER) for newly constructed, modified, and reconstructed coal-

fired EGUs. Comments received on that issue are not being addressed in this rulemaking and will

be addressed in any future EPA action. In that proposal, the EPA solicited comment on whether

to make a pollutant-specific significant contribution determination for GHG emissions from

EGUs, 83 FR 65432 n. 25, which is the subject of today’s action.

IV. Pollutant-Specific Significant Contribution Finding (SCF)

A. Background

CAA section 111(b)(1)(A) states that “[The Administrator] shall include a category of

sources in such list if in his judgment it causes, or contributes significantly to, air pollution which

may reasonably be anticipated to endanger public health or welfare.”

In the 2015 Electric Generating Unit (EGU) GHG NSPS CAA section 111(b) rule (2015

EGU Rule),,, the EPA promulgated standards for GHG (measured by carbon dioxide (CO2)

emissions) from fossil fuel-fired steam generating EGUs and combustion turbines, a pollutant

that the Administrator had not considered when he listed the categories of those sources - fossil

fuel-fired steam generators11 and stationary gas turbines.12 See 80 FR 64510. Similarly, in 2016,

the EPA promulgated aanan NSPS for GHG (measured by methaneCH4CH4 emissions) from oil

and gas sources, a pollutant that the Administrator had not considered when he listed the 11 Comments by American Electric Power for Docket ID No. EPA-HQ-OAR-2013-0495, p. 19 (May 8, 2014), attached to Comments by American Electric Power for Docket ID No. EPA-HQ-OAR-2013-0495 (March 8, 2019).12 The EPA does not currently have a comprehensive inventory of the U.S. GHG emissions for all of the NSPS source categories. For the EPA to make determinations of significance for a source category, a more comprehensive emissions profile of a source category should be used. The EPA will make determinations of significance for other source categories in the future.


category for those sources - the Crude Oil and Natural Gas Production source category.13 See 81

FR 35824 (June 3, 2016) (2016 Oil & Gas Rule).

In each rule, the EPA interpreted CAA section 111(b) to require that aanan SCF and

endangerment finding be made only with respect to the source category, at the time the EPA lists

the category, and to authorize the EPA to promulgate NSPS for GHG, as long as the EPA

provides a rational basis for doing so. However, in each rule, the EPA acknowledged that some

stakeholders had argued that the EPA first needed to make a pollutant-specific SCF, that is, a

finding that GHG from the source category contributes significantly to dangerous air pollution.

In each rule, the EPA stated that it disagreed with those stakeholders, but nevertheless, in the

alternative, did make a pollutant-specific SCF for GHG, supported by the same reasons that the

EPA had used to determine that it had a rational basis to regulate GHG. See 80 FR 64529-

through 31 (2015 EGU Rule); 81 FR 35840 through 43 (2016 Oil & Gas Rule).

In the 2018 Proposal, in which the EPA proposed to revise the 2015 Rule, the EPA

solicited comment on whether to adopt the interpretation that it was required to make aanan SCF

for GHG from the EGU source category before it could promulgate aanan NSPS for CO2. Some

commenters stated that the EPA must make pollutant-specific findings of endangerment and

significant contribution in order to establish aanan NSPS for that pollutant. These commenters

explained that in their view, CAA section 111(b)(1)(A) requires the EPA to make two specific

findings: (1) the specific “air pollution” to be regulated is “reasonably … anticipated to endanger

public health or welfare;” and (2) the specific source category “causes or contributes

significantly to” that air pollution. Commenters asserted that CAA section 111(b)(1)(A) is not

ambiguous in this respect, and, therefore, the Agency’s interpretation in the 2015 Rule directly

contradicts the plain language of that section. 13 See ACE? 111(b) rules previously? :Cite needed:: See 79 FR 34960 and 80 FR 64510.


Other commenters stated that the EPA’s approach in the 2015 Rule, that it needs to

determine only that it has a rational basis to regulate GHGs emitted by this source category as a

prerequisite to regulation, is sound. They said in the context of CAA section 111, the SCF and

endangerment finding are made with respect to the source category, and not as to specific

pollutants. These commenters supported the conclusion in the 2015 Rule that the EPA possesses

authority to regulate GHG emissions from fossil fuel-fired EGUs under CAA section 111

because there was no new evidence calling into question its determination that GHG air pollution

may reasonably be anticipated to endanger public health and welfare and fossil fuel-fired EGUs

have a high level of GHG emissions. The commenters stated that these considerations hew

closely to the statutory factors that inform the decision whether to list a source category in the

first place—namely, whether the category “causes, or contributes significantly to, air pollution

which may reasonably be anticipated to endanger public health or welfare,” under CAA section

111(b)(1)(A). The commenters added that this approach, which closely parallels the listing

analysis but does not require a formal endangerment finding or SCF, is legally sound. They also

added that the statute is clear that a formal endangerment finding is required to initially list a

sector to be regulated under CAA section 111; but it is also clear that such a finding is not

required before regulating additional harmful pollutants from a previously-listed sector.14

Similarly, in a 2019 proposal to revise the 2016 Oil & Gas Rule, the EPA solicited comment on

whether to adopt the interpretation that it was required to make aanan SCF for GHG from the Oil

and Gas source category before it could promulgate a methaneCH4CH4 NSPS. Recently, the EPA

completed the final rule to revise the 2016 Oil & Gas Rule, “Oil and Natural Gas Sector:

14 Note that one of those “next three largest” source categories is oil and natural gas which the EPA found in the recently finalized policy package that regulation of GHGs from this source category is unnecessary as it is currently being controlled by regulation of volatile organic compounds. See final rule (insert8585 FR citation here).57018, 57030 (Sept. 14, 2020)..


Emission Standards for New, Reconstructed, and Modified Sources Review: Final Rule,” 85 FR

57018 (September 14, 2020) (2020 Oil & Gas Rule). There, the EPA determined that a

pollutant-specific SCF is required. In addition, the EPA further determined that the pollutant-

specific SCF in the 2016 Oil & Gas Rule was invalid on grounds, in part, that the EPA had not

established a threshold or criteria by which to determine whether an amount of emissions

contributes significantly to dangerous air pollution, and to distinguish from an amount of

emissions that simply contributes to dangerous air pollution. Id. at 57033-40.In the 2020 Oil and

Gas Policy Rule, the EPA determined that CAA section 111(b)(1) requires, or at least authorizes

the EPA to require, a pollutant-specific SCF as a predicate for promulgating a standard of

performance for a specific air pollutant. In addition, the EPA further determined that the

pollutant-specific SCF in the 2016 Oil & Gas Rule was invalid on grounds, in part, that the EPA

had not established a threshold or criteria by which to determine whether an amount of emissions

contributes significantly to dangerous air pollution and to distinguish from an amount of

emissions that simply contributes to dangerous air pollution. The EPA stated that section 111(b)

of the CAA requires, or at least authorizes, a pollutant-specific SCF, and such aanan SCF must

be based on defined criteria or thresholds. Id. at 57033-40.

B. What is a Significant Contribution Finding (SCF)?

CAA section 111 directs the EPA to regulate, through a multi-step process, air pollutants

from categories of stationary sources. CAA section 111(b)(1)(A) requires the initial action,

which is that the Administrator must “publish … a list of categories of stationary sources. He

shall include a category of sources in such list if in his judgment it causes, or contributes

significantly to, air pollution which may reasonably be anticipated to endanger public health or

welfare.” Therefore, the first action that the EPA must take, specified in CAA section 111(b)(1)


(A), is to list a source category for regulation on the basis of a determination that the category

contributes significantly to dangerous air pollution. This provision makes clear that although

Congress designed CAA section 111 to apply broadly to source categories of all types wherever

located, Congress also imposed a constraint: The EPA is authorized to regulate only sources that

it finds cause or contribute significantly to air pollution that the EPA finds to be dangerous.

Because CAA section 111(b)(1)(A) refers to air pollution, the EPA’s determination that a source

category should be listed for regulation can be based on all pollutants emitted by the category

(i.e., collective contribution), or for a specific pollutant.

After the EPA lists a source category, CAA section 111(b)(1)(B) then directs the EPA to

propose regulations “establishing Federal standards of performance” for new sources within the

source category, to allow public comment, and to “promulgate … such standards with such

modifications as he deems appropriate.” CAA section 111(a)(1) defines the term “standard of

performance” as “a standard for emissions of air pollutants which [the Administrator is required

to determine through a specified methodology].” These provisions read together make clear that

the standards of performance that CAA section 111(b)(1)(A) directs the Administrator to

promulgate must concern air pollutants emitted from the sources in the source category.

However, industrial sources of the type subject to CAA section 111(b)(1)(A) invariably emit

more than one air pollutant, and neither CAA section 111(b)(1)(B) nor CAA section 111(a)(1),

by their terms, specifies for which of those air pollutants the EPA must promulgate standards of

performance.

In the past, the EPA has interpreted CAA section 111(b)(1)(B) to authorize it to

promulgate standards of performance for any air pollutant that the EPA identified in listing the

source category and any additional air pollutant for which the EPA has identified a rational basis


for regulation. 81 FR 35843 (2016 Oil & Gas Rule); “Standards of Performance for Greenhouse

Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility

Generating Units – Final Rule,” 80 FR 64510 (October 23, 2015) (EGU CO2 NSPS Rule).80 FR

64510 (2015 Rule). Inherent in this approach is the recognition that CAA section 111(b)(1)(A)

does not, by its terms, necessarily require the EPA to promulgate standards of performance for

all air pollutants emitting from the source category. The EPA could list a source category on

grounds that it emits numerous air pollutants that, taken together, significantly contribute to air

pollution that may reasonably be anticipated to endanger public health or welfare, and proceed to

regulate each of those pollutants, without ever finding that each (or any) of those air pollutants

by itself causes or contributes significantly to—or, in terms of the text of other provisions, causes

or contributes to—air pollution that may reasonably be anticipated to endanger public health or

welfare.

As described in the 2020 Oil and Gas Policy Rule, CAA section 111(b)(1)(A) does not

provide or suggest any criteria to define the rational basis approach, the EPA has not articulated

any criteria in its previous applications in the EGU CO2 NSPS and the 2016 40 CFR part 60,

subpart OOOOa rules, and in instances before those rules in which the EPA has relied on the

“rational basis” approach, the EPA has done so to justify not setting a standard for a given

pollutant, rather than to justify setting such a standard. 85 FR 77037. Thus, the rational basis test

allows the EPA virtually unfettered discretion in determining which air pollutants to regulate. As

a result, the rational basis standard creates the possibility that the EPA could seek to promulgate

NSPS for pollutants that may be emitted in relatively minor amounts.

In contrast, CAA section 111(b)(1)(A) is clear that the EPA may list a source category for

regulation only if the EPA determines that the source category “causes or contributes


significantly” (emphasis added) to dangerous air pollution. As described in the 2020 Oil and Gas

Policy Rule, in light of the stringency of this statutory requirement for listing a source category,

it would be unreasonable to interpret CAA section 111(b)(1)(B) to allow the Agency to regulate

air pollutants from the source category merely by making an administrative determination under

the open-ended and undefined rational basis test. The EPA, therefore, determined it is logical to

interpret CAA section 111(b)(1)(B) to require that the Agency apply the same degree of rigor in

determining which air pollutants to regulate as it does in determining which source categories to

list for regulation, and, therefore, must make a pollutant-specific SCF. Id.

Requiring a pollutant-specific SCF establishes a clearer framework for assessing which

air pollutants merit regulatory attention that will require sources to bear control costs. This

promotes regulatory certainty for stakeholders and consistency in the EPA’s identification of

which air pollutants to regulate and reduces the risk that air pollutants that do not merit

regulation will nevertheless become subject to regulation due to an unduly vague standard.

As previously described, CAA section 111(b)(1)(B) requires the EPA to establish an

NSPS for a source category listed under CAA section 111(b)(1)(A). For a source category

previously listed under CAA section 111(b)(1)(A), in order to subsequently promulgate an NSPS

for a pollutant that the EPA did not evaluate the source category for at the time of listing, the

EPA must make a pollutant-specific SCF for the reasons described above. As part of making an

SCF, the EPA concluded in the 2020 Oil and Gas Policy Rule that, “a standard or an established

set of a criteria, or perhaps both, are necessary to identify what is significant and what is not.” 85

FR 57039. The EPA did not finalize or take a position in the 2020 Oil and Gas Policy Rule on

potential criteria, stating that it was deferring the identification of such criteria to a future

Author, 01/03/-1,

Interagency Comment This justifies establishing a framework with clear criteria, but it is not a justification for requiring the pollutant-specific SCF itself.

Author, 01/03/-1,

Interagency Comment Such a requirement does not necessary establish a framework. The establishment of a framework is itself a separate policy decision.


rulemaking. Id. CAA section 111(b) itself does not specify what the criteria for a pollutant-

specific SCF.

The “contributes significantly” provision in CAA section 111(b)(1)(A) is ambiguous as

to what level of contribution is considered to be significant. See 84 FR 50267- and 68 (citing

EPA v. EME Homer City Generation, L.P., 572 U.S. 489 (2014) (holding that a similar provision

in CAA section 110(a)(2)(D)(i), often termed the “good neighbor” provision, is ambiguous)).

Accordingly, the EPA has authority to interpret that provision. Id. at 50268. As noted above, the

EPA reads CAA section 111(b)(1)(B) in light of CAA sections 111(b)(1)(A) and 111(a)(1) to

incorporate the “contributes significantly” standard in connection with promulgating NSPS for

particular air pollutants. The EPA has concluded that to allow the EPA to distinguish between a

contribution and a significant contribution to dangerous pollution, some type of (reasonably

explained and intelligible) standard and/or established set of criteria that can be consistently

applied is necessary. Without at least one or the other, it is impossible to evaluate whether the

SCF is well reasoned. Therefore, the lack of a standard or established set of criteria for an SCF

renders the finding arbitrary and capricious.

A supporting basis for this conclusion can be found in the EPA’s analysis of the

“contribute significantly” provisions of CAA section 189(e), concerning major stationary sources

of particulate matter with a diameter of 10 micrometers or less (PM10). This provision requires

that the control requirements applicable to major stationary sources of PM10 also apply to major

stationary sources of PM10 precursors “except where the Administrator determines that such

sources [of precursors] do not contribute significantly to PM10 levels which exceed the standard

in the area.” As the EPA noted in the 2019 Oil and Gas Policy Rule proposal, in CAA section

189(e), Congress intended that, in order to be subject to regulation, the emissions must have a

Author, 01/03/-1,

Interagency Comment Cite? Is this a separate document or is this a reference to the 2019 proposal?

Author, 01/03/-1,

Interagency Comment Suggest striking. Previous SCF have been successfully defended without such prior established standards or criteria.


greater impact than a simple contribution not characterized as a significant contribution.

However, Congress did not quantify how much greater. Therefore, the EPA developed criteria

for identifying whether the impact of a particular precursor would “contribute significantly” to a

National Ambient Air Quality StandardsNAAQSNAAQS exceedance. 84 FR 50268. These

criteria included numerical thresholds. Id. The EPA has concluded similarly that, under CAA

section 111(b), a standard or an established set of a criteria, or perhaps both, are necessary to

identify what is significant and what is not. Moreover, without either, any determination of

significance is arbitrary and capricious because it does not identify a reasoned basis for that

determination.

These criteria help ensure that the EPA’s decision-making is well-reasoned and

consistent. The EPA considers it particularly important to develop a set of criteria and/or a

standard in order to determine when a significant contribution occurs, in order, as noted above, to

distinguish it from a simple contribution. A contribution can be greater or lesser and remain a

contribution, but a significant contribution determination necessarily involves a judgment about

the degree of the contribution that rises to the level of significance. For such a judgment to be

meaningful (and to be understood by regulated parties and by the public), the Agency must

identify the criteria it will use to determine significance.

C. Primary Criteria for Determining Significance

In this section, the EPA describes the criteria for determining when GHG emissions from

a source category contribute significantly to dangerous air pollution that it is finalizing in this

action, in response to comments submitted on this rule. 15 The EPA indicated in the 2020 Oil and

Gas Policy Rule that it would finalize these criteria in a separate rulemaking. 85 FR 57039.

15 Although there is no source category other than EGUs above the proposed 3% threshold, because the threshold is a percentage and as previously described, other source categories may move into this tier as overall GHG emissions decrease and other source category emissions increase.

Author, 01/03/-1,

Interagency Comment Please cite to the Document ID.I could only find one submission from AEP in 2019, Document ID EPA-HQ-OAR-2013-0495-12641, but that’s the wrong date and none of it’s available on regulations.gov because of copyright.I presume the 2014 comment is Document ID EPA-HQ-OAR-2013-0495-10618. This comment does not say that EPA is required to establish criteria, only that EPA must make a pollutant-specific SCF.

Author, 01/03/-1,

Interagency Comment This should be the primary point, rather than continued assertion that prior significance determinations were meaningless.

Author, 01/03/-1,

Interagency Comment Repeating last sentence of the prior paragraph. Again, not supported by the history of the NSPS.

Author, 01/03/-1,

Interagency Comment Again, cite to the original. Was a numerical threshold considered to be a requirement at the time or just appropriate?

Author, 01/03/-1,

Interagency Comment This should be a reference to the implementation of 189(e), to demonstrate that this isn’t a post hoc justification to fit the current proposal.


1. GHG Emissions

This action, including the criteria discussed herein, only applies only to GHG in the

context of the EPA’s SCF under CAA section 111(b)(1)(B). This action does not discuss criteria

for pollutants other than GHGs, and as such, other pollutants are outside the scope of this

determination. The EPA is determining that the quantity of GHG emissions from a source

category is the primary criterion in determining significance for purposes of regulation of GHGs

from a source category under CAA section 111(b). Gross GHG emissions are important for this

set of pollutants because GHGs are global long-lived pollutants and do not have the local, near-

term ramifications found with other pollutants (e.g., criteria pollutants). Unlike other pollutants

where both the location and quantity of pollution emissions are factors in determining the impact

of the emissions, GHGs’ impact (i.e., climate change) is based on a cumulative global loading

and the location of emissions is not nearly as important a factor as it is for assessing local, near-

term impacts associated with criteria pollutants. It is for this reason that, when the EPA is

assessing GHGs impact in contributing significantly to air pollution which may reasonably be

anticipated to endanger public health and welfare, the quantity of emissions should be the

primary criterion that the EPA should evaluate.

The GHG emissions are the best, but not necessarily only, indicator of significance

because the quantity of emissions emitted from a source category correlates directly with

impacts. Calculations using the Model for the Assessment of Greenhouse Gas Induced Climate

Change (MAGICC model) to investigate the impact of including or eliminating a single sector’s

emissions from 2020 through 2100 have shown that the magnitude of emissions from that single

sector is very close to being linearly related to the projected temperature change in 2100

resulting from eliminating that sector’s emissions. This is consistent with the results of a number

Author, 01/03/-1,

Interagency Comment All GHG emissions (CO2e) or just CO2?

Author, 01/03/-1,

Interagency Comment The stated criteria is share of domestic emissions, not quantity. At best, this argument would justify putting emissions in a global context, but it does not justify considering only share rather than actual emissions.

Author, 01/03/-1,

Interagency Comment The rule text establishes most recently published Inventory of U.S. Greenhouse Gas Emissions and Sinks as the sole data source for making determinations of GHG emissions under this rule. EPA should include in this section a complete discussion of that data source, how it is compiled, and why it is sufficiently reliable upon which to make SCF without consideration of other emissions data.


of peer reviewed publications in the past decade: e.g., Matthews et al found that the temperature

change is roughly proportional to the total quantity of carbon dioxideCO2CO2 emissions over a

wide range of potential scenarios.16 Note that this finding may not hold true for all non-CO2

gases: the same MAGICC model calculations show that eliminating the oil and gas sector has a

somewhat larger impact on temperature than would be estimated based on multiplying the total

CO2-equivalent emissions from the sector by the linear factor derived from the CO2-dominant

sectors: this is because there is a large component of methaneCH4CH4 emissions in the oil and

gas sector, and methane has a larger short-term impact than CO2.

A threshold of GHG emissions from the source category compared to the rest of the U.S.

GHG emissions (i.e., the percent of total U.S. GHG emissions) can be used to demonstrate

significance. Emissions can be large enough from a source category that the evaluation of GHG

emissions in isolation is sufficient for making a finding of significance for the source category.

Conversely, the EPA believes that some source categories are sufficiently small in GHG

emissions that a finding of insignificance can be made by only evaluating the GHG emissions

from the source category. For many source categories, the evaluation of GHG emissions alone

will be sufficient for determining whether there is significant contribution.

2. Using a Threshold in Significance Determination

The EPA is determining concludes that it is appropriate to utilize a threshold for the

evaluation of significance of GHG emissions from source categories. The use of a clear threshold

provides certainty regardingregarding the EPA’s process and allows the regulated entities to have

insight into how the EPA will make determinations on significance for their respective source

16 If U.S. production shifted overseas to a jurisdiction that has laxer environmental regulations, for a global pollutant such as mercury or GHGs, there could be both increased local environmental and health impacts at the new overseas location and domestic impacts to the U.S. resulting from the increased U.S. GHG emissions.

Author, 01/03/-1,

EOP Comment Certainty can only be provided where the record (underlying analysis) offers a transparent and substantiated path to the policy choice. Please provide additional analysis. The breakpoint table below does not offer enough detail for a specific threshold.

Author, 01/03/-1,

Interagency Comment There needs to be a logical connection between use of US total emissions and the statement that ‘cumulative global loading’ is more important than localized emissions.


category. The threshold set forth in this rulemaking is a reflection of the EPA’s best

understanding of the landscape of the U.S. GHG emissions from stationary sources. The EPA is

determining utilizing a methodology to evaluate significance with respect to the U.S. GHG

emissions that can be applied for any source category, but that application of the methodology is

only being directly applied to the EGU source category in this action. It is important to note that

a significance determination for the U.S. GHG emissions will be needed before the EPA may

regulate any other source category under CAA section 111(b) for GHG emissions.

As is explained further in the TSD, “As Table 1, below, makes clear,Examination of

GHG Emissions from large stationary sources of GHG emissions,” there are at least two

natural breakpoints between groups of emitting source categories. The first natural breakpoint is

between EGUs and all other source categories. EGUs stand out as by far the largest stationary

source of the U.S. GHG emissions, emitting over 25 percent of all the U.S. GHG emissions.

Based on available data, the next largest source category, Oil and Natural Gas, emits just under 3

percent of U.S. GHG emissions. Two other source categories, Boilers and Petroleum Refineries,

also fall between 2.5 percent and 3.0 percent of U.S. emissions. Between 1.5 percent and 2.5

percent of U.S. GHG emissions there is another natural breakpoint and all of the remaining

source categories fall below 1.5 percent of the U.S. GHG emissions. Note that source category

emissions in Table 1 are an estimate of what the Agency currently understands about the

emissions from CAA section 111 source categories. There is a wide range of confidence in these

values and there is a possibility that some source categories may fall into different groupings of

emissions.

Author, 01/03/-1,

Interagency Comment These “natural” breakpoints are an artifice of the table itself, not the data. 3% of global emissions and 25% of domestic emissions are also natural breakpoints and would lead to significantly greater predictability for domestic industries. Nothing in the discussion below suggests that these alternative thresholds have any disadvantage over the preferred option.


Table 1. Examination of GHG Emissions from large stationary sources of GHG emissions

% of Total US GHG Emissions

Emissions in that Range

(MMT CO2e)*

Source Categories Affected at Different Thresholds

Percent of US GHG Emissions from

Stationary Sources Covered at Given

Threshold Above 25% >1670 MMT EGUs (1778 MMT/27% of total

US GHG Emissions, 3.6% of Global emissions)

43%

3% to 25% 200 MMT-1670 MMT

No categories identified 43%

2.5% to 3.0% 167-200 MMT Oil/Gas Production and Processing^; Refineries; Boilers

56%

2.0% to 2.5% 134-167 MMT No categories identified 56%1.5% to 2.0% 100-134 MMT No categories identified 56%1.0% to 1.5% 67-100 MMT Landfillsᶧ; Iron and Steel 60%

* MMT CO2e = Million metric tons of carbon dioxide equivalent^ Note that the oil and gas production and processing GHG emissions are very close to the 3% value and thus if this is a chosen threshold there is a possibility that this source category may be above the threshold in the near term. ᶧ Note that the Landfills source category has already been regulated under CAA section 111 and the characterization of the emissions here reflect reductions of the GHG emissions as a result of that regulation as a co-benefit.

Based on this analysis, the EPA is applying a threshold of 3 percent of U.S. GHG

emissions as a threshold to evaluate a source category’s emissions to determine significance for

Author, 01/03/-1,

EOP Comment See comments above. This requires additional analysis that is not in either the NPRM RIA/TSDs or the current rule package. Comment applies to points 2 and 3 below as well. The original analysis does not capture the scope and breadth of this new standard. Would like to discuss further.

Author, 01/03/-1,

EOP Comment What in the foregoing “analysis” justifies the prior 3 percent threshold? This needs to be fleshed out. (Maybe move up some material from a few pages down, or summarize it here.)

Author, 01/03/-1,

Interagency Comment Unclear whether this means the estimate is a future projection based on the updated NSPS and NESHAP or based on pre-2016 emissions.

Author, 01/03/-1,

Interagency Comment Source?

Author, 01/03/-1,

Interagency Comment Source or cite?


purposes of CAA section 111(b). The EPA is also determining that source categories that are less

than this value (i.e., 3 percent or less) will necessarily be insignificant without consideration of

any other factors.

The EPA acknowledges that, when interpreting other CAA provisions, the EPA has used

different thresholds to define “significant contribution,” but it is appropriate to select a threshold

based on the nature of the problem being addressed. For example, to address the problem of

interstate transport under CAA section 111(a)(2)(D)(i)(I) -- which concerns criteria pollutants,

i.e., pollutants that affect the NAAQS -- the EPA selected a threshold of 1%, percent based on

analysis of air quality modeling specific to the criteria pollutant at issue. 76 FR 48,208,

48,2364820848208, 48236 (Aug. 8, 2011) (Cross-State Air Pollution Rule (CSAPR)). For

criteria pollutants, both the location and quantity of emissions are factors in determining their

impact. In contrast, the impact of GHGs (e.g, climate change) is based on a cumulative global

loading, and the location of emissions is not nearly as important a factor as it is for assessing

local impacts associated with criteria pollutants. Because GHGs do not have the local near-term

impacts that criteria pollutants tend to have, a larger value is appropriate to use in determining

significance as it still addresses the health and welfare impacts of GHG emissions without

specifically evaluating local near-term impacts, which is analytically unreasonable to do given

the global nature of GHGs. While the 3% percent threshold will be applied against domestic

emissions, source categories exceeding that threshold represent a much smaller fraction of global

GHG emissions.17

17 For this purpose, EGUs include the affected sources in the combined source category for boilers and turbines. In the 2015 Rule, the EPA “combine[d] the two categories of EGUs—steam generators and combustion turbines—into a single category of fossil fuel-fired EGUs for purposes of promulgating standards of performance for CO2 emissions.” 80 FR 64529 (2015 Rule).

Author, 01/03/-1,

Interagency Comment “The EPA believes that its current approach of identifying a threshold for significance based on a percentage of U.S. emissions is better reasoned than the 2016 Oil & Gas Rule’s approach of drawing comparisons to the absolute emissions of other countries.” Why? The discussion of a lack of localized impacts would suggest all comparisons should be global rather than domestic.

Author, 01/03/-1,

Interagency Comment The interstate transport comparison metric (i.e., 1% of the problem) would imply a significantly higher threshold, not a minimum necessary to avoid impacting more than EGUs? Why not a level at or above 25% of domestic emissions? Or 1% of global emissions?

Author, 01/03/-1,

Interagency Comment Please identify for the reviewers any language in the proposed rule or public comments from which this criteria is a logical outgrowth (both in terms of a redline test and the 3% threshold).

Author, 01/03/-1,

EOP Comment Why? (Maybe move up some material from a few pages down, or summarize it here.)


By determining a threshold, the EPA is setting a clear indication of how source categories

will be evaluated for significance based on GHG emissions. For those source categories that are

below the 3 percent threshold, the EPA would make a determination (through future rulemaking)

of insignificance. This means that if a source category collectively emits 3 percent or less of the

total U.S. GHG emissions, it will be considered to be insignificant. For those source categories

that are above the threshold, a more detailed evaluation of other criteria can be used to make a

determination of significance. This is described in Sectionsectionsection IV.D below. It is

important for the EPA to make this clear indication as it allows source categories and the general

public a level of transparency as to how the EPA will be evaluating source categories for

significance. The threshold in this action will provide a degree of certainty regarding whether a

source category will later be found significant or insignificant based on the threshold.18

After evaluating the two natural break points in GHG emissions, the EPA determined that

3 percent of the U.S. GHG emissions was the best threshold for determining significance. As

noted above, there is currently only one source category above this threshold, EGUs, and the

evaluation of significance for the EGU source category has been a topic explored and discussed

by the Agency in great detail over the course of the last decade.19 Just below the 3- percent

threshold are three source categories: Oil and Natural Gas, Petroleum Refineries, and Industrial-

Commercial-Institutional Steam Generating Units (i.e., “Boilers”). There are no other source

categories with GHG emissions between 1.5 percent and the 3 percent. By using a threshold of 3

percent of the U.S. GHG emissions (i.e., only including EGUs above the threshold), the EPA

will effectively be covering 43 percent of the U.S. stationary source GHG emissions via

18 See Table 3-9, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2018, Report 430-R-20-002, April 13, 2020, https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2018.19 The global warming potential (GWP) of a greenhouse gas is defined as the ratio of the accumulated radiative forcing within a specific time horizon relative to that of the reference gas CO2. Total GHG emissions are the GWP-weighted emissions of all GHG emissions and reported in million metric tons of CO2 equivalent (MMT CO2e.).

Author, 01/03/-1,

Interagency Comment This footnote is contradicted by the rule text, which sets a single EPA sources as determinative. The rule text does not provide for a more comprehensive inventory outside of the most recently published Inventory of U.S. Greenhouse Gas Emissions and Sinks.

Author, 01/03/-1,

Interagency Comment Why? The rule text establishes a clear bright-line test and the exclusive source of the data. There is no discretion. EPA could make a blanket set of determinations based simply on the most recent publication.


regulation of a single source category. If the EPA were to instead set a threshold between the

other identified breakpoint – between 1.5 percent and 2.5 percent of U.S. GHG emissions – the

EPA observes that this threshold would lead to a relatively modest increase in the stationary

source U.S. GHG emissions that would be regulated of an additional 13 percent (for a total of 56

percent of U.S. stationary source GHG emissions).20 In addition, regulation of the additional

source categories that comprise 13 percent of U.S. emissions would eliminate only a portion of

those emissions. With an even lower threshold of significance set at 1.0 percent of U.S. GHG

emissions, there would be significantly more source categories covered (about 10 based on the

EPA estimates) above the threshold but likely would include an even more modest increase in

stationary source GHGs that would cover 60 percent of U.S. stationary source GHGs. The EPA

is basing a decision to apply a threshold of 3 percent on the relative contribution of regulating

source categories that contribute significantly to the overall impact of climate change. To that

end, the temperature impact associated with the hypothetical elimination of all source categories

above a 3 percent threshold corresponds to a hypothetical reduction of 0.049 degrees Celsius

(°C) (the calculated effect in 2100 of removing 1780 1,780 million metric tons (MMT) of CO2

emissions each year from 2020 through 2100) from source categories above that threshold (i.e.,

just EGUs). Even eliminating the next largest source category (i.e., Oil and Gas Processing and

Production) would only generate an additional hypothetical temperature reduction of less than

0.01°C and even smaller source categories correspondingly contribute less to global temperature.

The EPA is making the decision that the threshold for a significance determination for U.S. GHG

emissions to be in the form of a percentage. A percentage is a metric that measures the relative

contribution to the whole and, in this action, the EPA believes that it is appropriate to measure

20 See Table 3-9, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2018, Report 430-R-20-002, April 13, 2020, https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2018.

Author, 01/03/-1,

Interagency Comment This would argue for a threshold higher than 3% of US emissions, to avoid capturing industries that have little impact.

Author, 01/03/-1,

EOP Comment Would seem helpful to give this point more prominence in the analysis and to move it up.

Author, 01/03/-1,

Interagency Comment I’m not sure this footnote is appropriate here. None of the prior discussion mentions overlapping regulation, just the actual emissions. And the decision referenced in this footnote excluded 111(d) regulation while it is explicitly included for consideration later in the notice.


and evaluate significant contribution of U.S. GHG emissions as a relative contribution to the

whole of GHG emissions in the U.S. The EPA is determining that a threshold in the form of a

percentage is both reasonable and more appropriate for making a significance determination for

GHGs based on a percent’s relative nature. This is important because the trajectory of U.S. GHG

emissions is trending down. As overall emissions decrease over the course of time, a source

category’s relative contribution to GHGs may not have changed or may have even increased

based on GHG reductions in other source categories and sectors. A relative percentage threshold

would allow for the EPA to later determine that a source category is significant based on these

circumstances, because a source category’s emissions may eventually exceed the threshold even

though it is currently below the threshold. Accordingly, a percentage threshold allows the EPA,

over time, to always focus on the source categories with the potential to have the greatest impact.

The EPA is determining that a threshold in the form of a percentage is both reasonable

and more appropriate for making a significance determination for GHGs based on a percent’s

relative nature. A tonnage threshold is a static metric that would not change over time. As

previously described, the trajectory of U.S. GHG emissions is trending down. As emissions

decrease over the course of time, it is likely that source categories that were once above any

static threshold will fall below such a threshold. Even though a source category may reduce

overall U.S. GHG emissions, that source category’s relative contribution to GHGs may not have

changed or may have even increased based on GHG reductions in other source categories and

sectors. Additionally, if emissions do decrease over time, the use of a tonnage threshold

potentially results in no source category meeting the criteria for significance, even if collectively

the U.S. GHG emissions continue to pose a danger to public health or welfare.

Author, 01/03/-1,

Interagency Comment This statement is the crux of the policy choice, but the text does not explain how this is an undesirable consequence of the policy choice. Is there legislative history or context to say that Congress intended EPA to keep pursuing increasing more stringent pollution reductions if individual contributions were not previously significant?

Author, 01/03/-1,

Interagency Comment Prior discussion indicates that temperature change is proportional to the quantity GHG emitted. Here, we state that EPA’s standard for significance will capture emissions with less and less impact because they are in the absolute smaller but rising percentage.

Author, 01/03/-1,

Interagency Comment This contradicts the prior discussion of GHG being a global rather than local issue.


It should be noted that the U.S. GHG emissions of the EGU source category are more

than an order of magnitude larger than the proposed threshold, representing 43 percent of U.S.

stationary source GHG emissions. The EPA believes that it is possible for source categories with

GHG emissions substantially larger than the threshold to be deemed significant on the basis of

the primary criterion alone (i.e., magnitude of emissions) and without consideration of the

secondary criteria described elsewhere in this notice.

The EPA is finalizing regulations codifying the 3 percent threshold.

3. Tiers of Source Categories Based on GHG Emissions

As noted previously, the primary criterion in evaluating the significance of a source

category is, again, the relative magnitude of the U.S. GHG emissions. The EPA believes that

NSPS source categories may be grouped into three tiers on the basis of magnitude of the U.S.

GHG emissions, as follows:

[(1)] Source category(s) with GHG emissions substantially above the threshold.

Such source category(s) have emissions of a large enough magnitude that they

can be determined significant on the basis of the magnitude of emissions

alone. As discussed later in this noticedocumentdocument, EGUs are likely to

not require consideration of other factors in order to determine significance.

[(2)] Source categories with an intermediate magnitude of the U.S. GHG

emissions (i.e., those with emissions above the proposed threshold but less

than the quantity emitted by the EGU category). For source categories with

emissions above the proposed threshold, evaluation of the magnitude of the

U.S. GHG emissions alone may be inconclusive. Rather, a significance

determination would likely require an examination of the source category’s

Author, 01/03/-1,

Interagency Comment It is unclear where in this document EPA describes the circumstances in which such an examination would be required. In all of the discussions of the secondary factors, there is almost nothing concrete about when consideration of the factors is crucial, and the rule text leaves all consideration of secondary factors to the Administrator’s discretion.

Author, 01/03/-1,

Interagency Comment IF this is the top end of the range, it should be explicitly mentioned in the first category, which in turn should be explicitly limited to EGUs rather than EGUs given as an example.

Author, 01/03/-1,

Interagency Comment This is the language of a proposal. Given that this is a category with a single member, why emphasize it as a separate category when the reasoning is below in the SCF finding?

Author, 01/03/-1,

Interagency Comment This description is not consistent with the rule text.


magnitude of emissions combined with a more detailed look at the secondary

factors discussed elsewhere in this noticedocumentdocument.

[(3)] Source categories with a small magnitude of GHG emissions (i.e., those with

emissions below the proposed threshold). Source categories with a small

magnitude of emissions will be deemed insignificant based on evaluation of

the primary criterion alone, without detailed consideration of any secondary

factors.

D. Secondary Criteria for Determining Significance

As described above, the EPA is determining that the U.S. GHG emissions from a source

category are the primary and most important criterion for making a determination of significance

for a source category. However, there may be instances where the U.S. GHG emissions from a

source category do not give a comprehensive enough picture to make a determination of

significance. The threshold that the EPA has described above in Section IV.B would provide a

clear indication that the U.S. GHG emissions from source categories below that threshold are

necessarily insignificant. However, for any source category that is above that threshold, there

may be other source-category specific considerations that should be evaluated in addition to

GHG emissions when making a determination of significance.21 For that reason, the EPA would

consider other, secondary, criteria in the evaluation of significance for certain source categories.

These other criteria are described in the subsequent subsections. It is important for the EPA to

consider secondary criteria in the evaluation of significance for certain source categories because

the criteria provide unique context to the source category beyond the information provided by the

magnitude of the source category’s GHG emissions.

21 In 2016, worldwide GHG emissions were estimated to have been 49.4 gigaton (Gt) CO2e. The GHG emissions of China, India, Russia, and Indonesia are 11,577, 3,235, 2,391, and 2,229 MMT CO2e respectively. https://www.wri.org/blog/2020/02/greenhouse-gas-emissions-by-country-sector.

Author, 01/03/-1,

Interagency Comment The rule text does not require such consideration.

Author, 01/03/-1,

Interagency Comment Consistent with rule text.

Author, 01/03/-1,

Interagency Comment “Factors” and “criteria” seem to be used interchangeably, but they don’t really mean the same thing. “Factor” would seem to be the more appropriate term, given that the descriptions of how the ‘criteria’ would be applied are very vague and in places contradictory. Strongly recommend adopt the term ‘factors’ in all places below.


1. Evaluation and Context of GHG Emissions

The evaluation of the magnitude of the U.S. GHG emissions from a source category is a

clear indicator of whether a source category is significant, but in the specific instance of source

categories that have greater GHG emissions than the threshold, an evaluation based on the

magnitude of the U.S. GHG emissions may be inconclusive. There are other emissions-based

metrics that can be evaluated to clarify and make a significance determination for these source

categories.

a. Source Category Trends

An important criterion that can help illuminate and contextualize a significance

determination is an evaluation of the trends in emissions and number of designated facilities

within a source category. Primarily, the EPA can evaluate whether a source category is on a

trajectory of the U.S. GHG emission decline. If the source category, as a whole, is decreasing its

GHG emissions, an explanation for why it is on the decline may aid in making a significance

determination. In one scenario, if the source category is decreasing emissions because the source

category is declining in production or other output (e.g., due to decreasing demand for goods or

other market conditions, due to relocation overseas, or due to the cumulative effect of

regulations), it may lend towards an insignificance determination as the emissions are already

declining and expected to continue to decline even without further regulation. In a separate

scenario, if a source category’s GHG emissions are declining due to increased efficiency and

updated technology, it may lend towards a determination of significance. This would allow the

EPA the ability to regulate the source category in order to ensure that efficiency and technology

improvements become standard across the source category through both an NSPS (111(b)

Author, 01/03/-1,

Interagency Comment Please further justify basing an SCF on information that shows the source category is having less of an impact over time. The trigger of whether to regulate should not be based on whether some in the industry won’t be impacted much by regulation. This creates a strong bias against small businesses.

Author, 01/03/-1,

Interagency Comment It’s not a “clear indicator” if it may be inconclusive in some cases.


regulation) for new, modified and reconstructed sources and an emission guidelines (111(d)

regulation) for existing sources.

In a scenario in which the EPA were to find a source category to be growing in either

emissions or number of designated facilities (or both), it may lend towards that source category

being found to be significant. This would allow EPA to regulate and mitigate emissions from

new, modified and/or reconstructed designated facilities within that source category under CAA

section 111(b) (i.e., via a NSPS).

If the EPA were to evaluate the trend in the number of designated facilities and emissions

of a source category, it might show a static number of existing facilities with a constant or

slightly increasing quantity of the U.S. GHG emissions. In this scenario, there may be little

utility in determining significance for that source category and consequentially developing a

NSPS as there are little to no emissions that would be subject to such a standard. However,

creating a NSPS for a source category and pollutant is a necessary predicate to regulating

existing sources under CAA section 111(d). Hence, in the scenario of a static number of existing

facilities, a finding of significance for the source category may be warranted as it would allow

eventual regulation of a group of existing source categories. The EPA expects the prospect of

regulating a source category under CAA section 111(d) for existing sources to be a compelling

reason for determining significance.

b. Source Category Emissions with Global Context

Another important criterion that the EPA can consider, as a secondary factor, is the

relative contribution of GHG emissions from the U.S. in a specific source category compared to

worldwide emissions of similar sources. As previously described, Section 111(b)(1)(A) of the

CAA states that the Administrator shall include source categories that contribute significantly to

Author, 01/03/-1,

Interagency Comment This is an explicit rejection of the Oil and Gas Rule determination that regulation was unnecessary because of overlap with the VOC NSPS regulation.

Author, 01/03/-1,

Interagency Comment It appears this is the first mention of existing sources, and it is an explicit reference that eventual regulation under 111(d) should be considered in a significance determination. This contradicts the Oil and Gas rule, which only considered the regulatory overlap between VOC and methane under 111(b) but did not consider 111(d).


endangerment of health and welfare. When evaluating a global pollutant such as GHGs, the EPA

views the impact of domestic emissions from domestic sources as a more germane consideration

when determining whether a pollutant contributes significantly to endangerment of health or

welfare. Because every ton of GHG contributes to the global problem, a domestic ton will still

have some impact in the U.S. Accordingly, it is reasonable for the EPA to evaluate whether a

source category is well-regulated internationally and whether the U.S. emissions from that sector

make up a relatively large share of GHG emissions on a worldwide scale, as such evaluation in

turn would inform whether U.S. emissions are significantly contributing to domestic impacts. If

the emissions from the U.S. are comparatively a large contribution to source category/sector

emissions worldwide, it may lend towards a finding of significance for the source category based

on the U.S.’s substantial global contribution to the source category. If, however they are

relatively small, it would suggest less benefit from the EPA regulation of that source category.

The EPA can also consider, as one of the secondary criteria, an evaluation of whether a

source category is vulnerable to being trade exposed (i.e. whether the source category is

constrained in the sources’ ability to pass through carbon costs due to actual or potential

international competition). The EPA may evaluate whether regulation of the source category

would create a financial incentive for that source category/industry to move into, or increase

production in, another country. This could be manifested as either a shift in production to

facilities internationally or a complete closure of existing designated facilities in the U.S. It is not

the EPA’s intention in regulating source categories to drive production from the U.S. to other

countries, and there is an environmental concern in pushing industries to other international

locations. This concern is based on the potential for these new international emissions to increase

Author, 01/03/-1,

Interagency Comment EPA usually claims that determinations of this nature are entirely separable from eventual regulatory decisions, but EPA here is implying that likely effects are sufficiently foreseeable upon which to base a formal consideration as a factor. If so, these determinations will be subject to the analytical requirements of the EO and the RFA.

Author, 01/03/-1,

Interagency Comment EPA is describing a relatively in-depth consideration of source category characteristics. This kind of question is not necessarily the high-level review suggested by the discussion of the role of the secondary criteria in this determination.

Author, 01/03/-1,

Interagency Comment The previous discussion of the MAGICC model implies that every ton of CO2 reduced has a linear effect on temperature change. If so, how would there be less benefit from an absolute reduction in emissions based on the relative contribution of the U.S.?

Author, 01/03/-1,

Interagency Comment Why? This does not follow from the rest of the paragraph. All of the sentences above in this paragraph discuss U.S. emissions.What does it mean “well-regulated internationally” when all sources are regulated by individual countries?


compared to the corresponding displaced U.S. emissions.22 While this is always a concern for the

EPA in the regulation of industry within the U.S., it even more pronounced with the

consideration of GHG emissions. As discussed, previously, the U.S. GHG emissions are a global

pollutant that also have domestic impacts. As such, if a smaller quantity of domestic GHG

emissions would be displaced, due to a regulation, by a greater quantity of international GHG

emissions it may support a finding of insignificance for a given source category. This would

occur if the U.S. sources are already significantly lower emitting in GHG emissions than sources

in other countries. It should also be noted that source categories whose sources in the U.S. make

up a relatively smaller proportion of the world’s emissions from corresponding international

sectors may be particularly vulnerable to being trade exposed as there is likely a greater

international capacity to absorb the displaced U.S. production.

c. Consideration of Technology

While the consideration of technology in the CAA section 111 program has traditionally

been associated with the standard setting process that follows after the significant contribution

finding, there is a reasonable perspective that there is potential value in evaluating and

considering the technology both with the associated source category (i.e. intrinsic to the process

of the source category and a prime example of reductions associated with this evaluation might

be efficiency improvements) and also with potential control technology for a source category. If

we use EGUs as an example, consideration could be given to the evaluation of both efficiency

improvements (as demonstrated in the Affordable Clean Energy rule) and back-end control

technology and devices (e.g., carbon capture and storage (CCS)).)). Traditionally in the standard-

setting process, the consideration of technology has been used to determine a BSER. This

22 According to Table 8 of the Annual Energy Outlook (AEO) 2020, while coal fired generation will decline between 2019 and 2025 from 959 billion kWh to 709 billion kWh, generation from coal-fired EGUs is projected to subsequently remain relatively steady through 2050.

Author, 01/03/-1,

Interagency Comment This example relies directly on work done to establish BSER. What would it mean to consider “a less robust and more high-level analysis?”

Author, 01/03/-1,

Interagency Comment This reference to Emission Guidelines implies that technology review would extend beyond BSER. It also implies that EPA should have considered the 111(d) implications of regulating methane in the Oil and Gas rule.

Author, 01/03/-1,

Interagency Comment Word choice. It is inappropriate to use ‘could’ given that in a few pages EPA does. (Although EPA shouldn’t, if it wants to be true to the primary criterion as described in the preamble.)

Author, 01/03/-1,

Interagency Comment EPA’s use of the passive voice here makes clear that EPA does not itself see value by including this factor. The mere existence of a “reasonable perspective’ or ‘potential value’ does not justify a decision.

Author, 01/03/-1,

Interagency Comment This entire factor is extremely troubling. There is no legal basis for adopting a factor explicitly included in the BSER determination. EPA describes no particular value to this consideration, outside its value to future determination of BSER. The examples are all based on complete consideration of BSER rather than a cursory examination envisioned, and for a source category for which this factor is not necessarily relevant. EPA describes this consideration as a ‘screening mechanism,’ which is incompatible with a WOE consideration of factors discussed in (d), does not comport with its description as a ‘secondary factor’ or a ‘criteria,’ and is not described in any detail so as to explain how it would work. A cursory examination with a proposed SCF puts the entire burden of information gathering on the regulated community, which will find it necessary to correct the record after EPA makes conclusions based only on readily available information.

Author, 01/03/-1,

Interagency Comment This kind of trade-off is better considered in the regulation of the source with a cost-benefit analysis. The supply chain consequences of regulation do not necessarily dictate whether a source itself contributes significantly.


process involves a robust analysis of what is currently being used within the source category to

reduce targeted emissions and also observing what is used in other source categories that may

coincide with technology from the source category of evaluation. In the step of determining

significance (i.e., the step that the EPA takes for a source category prior to setting a standard of

performance/setting a BSER) there is potentially a space for a screening procedure based on the

consideration of technology. This would be a less robust and more high-level analysis of the

technology associated with the source category that could add value to a determination of

whether specific source categories significantly emit GHGs.

The EPA is including technology as a screening mechanism in the Agency’s

determination of significance of a source category. The technology screening analysis is to see if

there are any technology to review for any likely candidates for a BSER analysis

This technology screening can coincide with the evaluation of the secondary criteria. The

EPA would evaluate the technology that is generally known to reduce the U.S. GHG emissions

from the source category and evaluate whether that technology is readily available to be used for

the source category in question. This evaluation can take source-category specifics into account

such as the size, the U.S. GHG emission type (e.g., CO2, methane, nitrous oxideCH4CH4, N2O),

and facility type. In general, the EPA would use readily available information to make

conclusions in this type of screening. Using this technology screening with the understanding

that other combustion-based source categories do not have the magnitude of emissions as EGUs,

it might be reasonable for the EPA not to make a determination of significance as there are not

substantial emission reductions available for the source category. As described in the next

section, the EPA could choose to reevaluate its prior determination of significance if a new

technology that could apply to the source category were to emerge and become widely available.

Author, 01/03/-1,

Interagency Comment NSPS regulations are periodically reviewed. What is the value of a finding of no significant contribution that can be reevaluated at will based on technology reviews?

Author, 01/03/-1,

Interagency Comment Legal basis?

Author, 01/03/-1,

Interagency Comment This is an unacceptable standard to what information EPA would limit its review. It is prejudicial against regulated entities who do not have ready access to EPA staff and will place them in the unenviable position of having to provide all of the information that would otherwise be required for a BSER determination at the proposed designation phase (before EPA will have done its own due diligence), but without a clear sense of how that information will be used and how it will influence the agency’s decision.

Author, 01/03/-1,

Interagency Comment Following the organization of the preamble, as well as the actual rule text, this IS one of the secondary factors.

Author, 01/03/-1,

Interagency Comment This sentence implies that the value is for future rulemaking in which BSER would be determined, not whether there should be a future rulemaking in which BSER would be determined.

Author, 01/03/-1,

Interagency Comment What is meant by ‘screening mechanism?’ In other contexts, this would imply that it comes first to determine whether other steps are required, but here it is a ‘secondary criteria.’

Author, 01/03/-1,

Interagency Comment Why? Nothing in the previous paragraph describes the value of this additional review.EPA should clearly state the value of this additional factor, in terms of the benefits to EPA, the public, or the potentially-regulated entities.

Author, 01/03/-1,

Interagency Comment What is the legal basis for consideration of technology and other BSER factors in the significance determination?

Author, 01/03/-1,

Interagency Comment What is this “potential space”? As with the first sentence above, this sentence undermines EPA’s decision by emphasizing that EPA has not actually identified a rationale.


d. Temporal Evaluation of Criteria

The evaluation of the secondary criteria is not intended to be performed in isolation.

Rather, the EPA will consider the weight of evidence of all the factors (both primary and

secondary) to make an informed and comprehensive decision as to whether a source category

that exceeds the 3-percent threshold contributes significantly to the U.S. GHG emissions. The

consideration of criteria also has a temporal consideration to a significance determination. A

source category’s determination can be reevaluated in the future as the status and criteria

described here may have changed for that source category. For example, the technology to

adequately regulate GHGs from a source category may not be readily available at this time, but

in the future that technology may become more broadly available, causing the EPA to then make

a SCF.

The EPA is finalizing regulations codifying these criteria.

E. Significant Contribution Finding for EGUs

As noted above, he Agency is determining that, based on appropriate criteria, GHG

emissions from EGUs23 contribute significantly to dangerous air pollution. The primary criterion

in determining whether to make a SCF is the magnitude of GHG emissions from a given source

category. It is readily apparent that EGUs emit a uniquely large amount of GHGs compared to

with all other categories of stationary sources. The EPA made this clear in the 2015 Rule, quoted

above, and reiterated it in the 2020 Oil & Gas Rule: “the unique CO2 emissions profile of fossil

fuel-fired EGUs should be noted: the volume of emissions from EGUs dwarfs the amount of

GHG emissions from every other source category.” 85 FR 57039, n.49.

23 According to Table 8 of the AEO 2020, natural gas fired generation is projected to increase from 1,322 billion kWh to 1,629 billion kWh.

Author, 01/03/-1,

Interagency Comment There is no ‘temporal’ factor distinct from the consideration of emission trends. There is a decision, and a decision can be revisited.

Author, 01/03/-1,

Interagency Comment Please restate. It doesn’t make sense to consider the weight of the primary criteria when it is a threshold determination. The discussions above reference the primary criteria, not “factor,” and discuss it as a threshold determination. I presume the intent here is that the secondary factors would be considered in the context of the overall percentage of U.S. GHG emissions?

Author, 01/03/-1,

Interagency Comment This is not temporal. Rather, this section describes an implementation of the process, i.e., weight-of-evidence, with a statement that determinations are intended to be reevaluated as new information becomes available.

Author, 01/03/-1,

Interagency Comment Recommend this whole paragraph be moved to the section introducing the primary and secondary factors and redraft to emphasize that any decision is a snapshot in time and that it can be reevaluated with new information at the discretion of the Administrator.


Although GHG emissions from EGUs have fallen since the EPA promulgated the 2015

Rule, they still remain uniquely large among stationary source categories. The EPA’s Inventory

of U.S. GreenhouseGreenhous Gas Emissions24 indicates that, as of 2018, the Electric Power

sector directly emitted 1,778.5 million metric tons (MMT) of GHGs.25 This amount was more

than twice the amount of GHGs emitted by all other industrial sources combined and more than

all other industrial, commercial, and residential stationary combustion sources combined.26 In

addition, direct GHG emissions from EGUs account for approximately 27 percent of total U.S.

GHG emissions and 43 percent of U.S. stationary source emissions.. The direct GHG emissions

from EGUs account for approximately 4 percent of total worldwide GHG emissions and are

greater than the emissions of all but four countries.27 These facts confirm that at current emission

levels, EGUs have measurable impacts on both the U.S. contribution to GHG emissions and the

worldwide total GHG emissions and continue to be uniquely large stationary source emitters of

GHGs. It should be noted that if domestic EGUs no longer emitted any GHG emissions, there

would be a measurable impact on worldwide GHG emissions and between 2020 and 2100, there

would be a reduction in the projected increase in global temperatures by 0.049 degrees Celsius

(oC).

24 U.S. EGU emissions from the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2018, Report 430-R-20-002, April 13, 2020, https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2018. Worldwide EGU emissions from the International Energy Agency estimates IEA (2020), CO2 Emissions from Fuel Combustion, https://www.iea.org/subscribe-to-data-services/co2-emissions-statistics. 25 The D.C. Circuit has held that controls cannot be considered the BSER if their cost is “unreasonable,” Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981); “excessive,” Id.; or “exorbitant,” Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974).26 The EPA evaluated the cost impact of partial CCS using the levelized cost of electricity (LCOE) and the percentage increase in capital to construct a new EGU. LCOE is a measure of the average net present cost of electricity generation for a generating plant over its lifetime.27 NETL also published the report, “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity,” NETL-PUB-22683 (September 24, 2019) (Revision 4 of the Bituminous Baseline Report). This report includes the detailed costing and performance information for bituminous and NGCC EGUs with and without full CCS. The supplemental sensitivity report relies on the information in this report and the EPA refers to the combination of these reports as the “2019 NETL Baseline Report.”


Because EGUs represent by far the largest stationary source of GHGs from combustion

of fossil fuels, the EPA believes that this is the most appropriate place for the EPA, states, and

sources to devote resources to reducing GHGs from stationary sources. Indeed, this uniquely

large magnitude of emissions is the reason why, over the last 8 years, the Agency has devoted

significant effort to determine how to best reduce GHGs from EGUs. Because EGUs are a

relatively large U.S. source of emissions in an overall large pool of international EGU sources,

regulation over time could help produce practices and technologies that have application to

EGUs worldwide.

It is noteworthy that GHG emissions from EGUs are approximately an order of

magnitude greater than the estimated emissions of the second largest stationary source category

of GHGs attributed to combustion, industrial boilers. Because the magnitude of GHG emissions

from EGUs is large compared to other stationary sources, this makes them clearly significant

even without detailed consideration of other factors. ,,As mentioned earlier, the EPA is

determining that a source category that emits above a threshold of 3 percent of U.S. stationary

source GHG emissions may contribute significantly to dangerous GHG air pollution. For those

source categories above that threshold, the EPA is also determining that consideration of certain

secondary criteria may, collectively, also inform the evaluation of whether a source category

should be considered to significantly contribute. However, that analysis of secondary criteria is

not necessary in the case of EGUs, due to the overwhelmingly large emissions of the source

category; it is clear that controlling GHG emissions from the EGU source category will be

necessary to appropriately address dangerous air pollution. This conclusion is consistent with the

EPA’s 2018 Proposal where the Agency explained that if the EPA was required to evaluate

significance, EGUs would be considered significant.


211. Secondary Criteria

The EPA is determining that the uniquely large GHG emissions from EGUs

makes a finding of significant contribution and regulation appropriate by itself. While the

EPA does not think it is necessary to consider secondary factorscriteriacriteria because of

the uniquely large emissions from the EGU source category, as explained below, the EPA

would make the same determination even if it did consider those factors. criteria.

a. Source Category Trends

As mentioned earlier, an important criterion is the evaluation of the trends in emissions

and number of designated facilities within a source category, such that the EPA can evaluate

whether a source category is on a trajectory of U.S. GHG emission decline.

While electricity demand is projected to increase the U.S., due to the increased use of less

carbon intensive generation technologies and more efficient generation, GHG emissions from the

power sector are projected to remain relatively steady for the foreseeable future. However, EGUs

are projected to remain the single largest stationary source of GHG emissions, and while the

Agency expects few, if any, new coal-fired EGUs will be built to meet the demand for

electricity, coal-fired EGUs are expected to continue to supply electricity and emit significant

GHG emissions for the foreseeable future.28 While not part of the BSER review in this

rulemakingthe proposed rule, the EGU source category also includes stationary combustion

turbines. The EPA expects new simple cycle and combined cycle combustion turbine EGUs will

be built in the future and that the existing fleet of combustion turbines will continue to operate.29 28 In both the 2015 Rule and the 2018 Proposal, the EPA only considered the percentage increase in capital costs for partial CCS for bituminous-fired EGUs. Subbituminous-fired EGUs have a higher emissions rate and, therefore, require a greater percentage of the flue gas to be treated with CCS to comply with the standards in the 2015 Rule. As a result, the percentage increase in capital for partial CCS for subbituminous-fired EGUs is greater than for bituminous-fired EGUs.29 U.S. EPA, Memorandum: Geographic Availability of Geologic Sequestration, December 2018, available in the rulemaking docket at https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0495-11941. Of the 18, Arkansas, South Dakota, Idaho, Arizona, and Florida do not have CO2 pipelines. Id.

Author, 01/03/-1,

Interagency Comment Establishes a precedent that a significance finding can be based solely on the contributions of existing sources, even where an NSPS will have NO effect on emissions.

Author, 01/03/-1,

Interagency Comment As above, recommend restoring ‘factor.’ Better word choice for the secondary factors to be considered (not criteria to be applied).

Author, 01/03/-1,

While this is how it is explained in the preamble, it is not consistent with the description of the decision in the rule text.


Therefore, efficient generation technology could eventually become standard for all new and

existing EGUs. Consequently, the EPA would consider the source category trends as supporting

the regulation of GHG emissions from EGUs.

b. Source Category Emissions with Global Context

The EPA is also determining that it can consider, as a secondary criterion, the relative

contribution of GHG emissions from the U.S. in the specific source category compared to

worldwide emissions of similar sources. Accordingly, the EPA will evaluate whether a source

category is well-regulated internationally and whether the U.S. emissions from that sector make

up a relatively large share of global GHG emissions, as such evaluation in turn would inform

whether U.S. emissions are significantly contributing to domestic impacts. In this instance, this

criteria points towards a finding of significance given that U.S. EGUs make up a sizeable portion

(13 percent of the emissions) from EGUs worldwide.30

As mentioned earlier in this notice, the EPA is also determining that one of the secondary

criteria is an evaluation of whether a source category is vulnerable to being trade exposed (i.e.,

whether the source category is constrained in its ability to absorb regulatory costs due to actual

or potential international competition). Concerns about international competition would not

impact the Agency’s decision to regulate EGUs because electricity must be transported over

power lines and it is not as easy to relocate or shift production locations as it is for other source

categories. The ability to locate generation in Mexico and Canada and transmit the power to the

U.S. is limited because of constraints on existing transmission lines and the expense to build

additional transmission capacity. The only additional transmission capacity currently being

considered is for electricity generated from hydroelectric power in Canada to supply power to

30 The Illinois Industrial CCS project in Decatur, Illinois, received funding from DOE and is led by the Archer Daniels Midland Company. The project is demonstrating an integrated system for collecting CO2 from an ethanol production plant and geologically storing the CO2 in a deep saline formation.

Author, 01/03/-1,

EOP Comment Does EPA still need this given current BSER position?


New England. Since this electricity has a low carbon intensity, it would not contribute to an

overall increase in GHG emissions. Furthermore, the emission standards in this rule will not

increase the costs of electricity from a new coal-fired EGU such that it might be financially

advantageous to locate new production internationally to countries with less stringent

regulations. If international competition were a concern, the Agency would compare the forecast

GHG emissions from international sources (in this case, EGUs in Canada and Mexico) against

the forecast GHG emissions from domestic sources (in this case domestic EGUs) in both the

absence of and implementation of the NSPS. In addition, since few, if any, new coal-fired EGUs

are forecast to be built in the U.S., the standards in this final rule will not impact electricity

prices to end users to an extent that other industries would be incentivized to relocate

internationally due to increased electricity costs. Therefore, domestic reductions in GHG

emissions from regulating EGUs will not be offset by increased international GHG emissions. In

contrast, for source categories that supply raw materials to other domestic source categories, the

impact of international competition on those source categories and the resultant GHG impacts

could be considered when determining an appropriate NSPS. It is conceivable that an overly

stringent NSPS could result in an increase in global GHG emissions, if the increase in

international emissions is greater than the reduction in domestic emissions.

c. Consideration of Technology

As stated earlier in this noticedocumentdocument, while the consideration of technology

in the CAA section 111 program has traditionally been associated with the standard setting

process that follows after the significant contribution finding, there may also be value in

evaluating and considering the technology both with the associated source category (i.e., intrinsic

to the process of the source category and a prime example of reductions associated with this

Author, 01/03/-1,

Interagency Comment This is not part of the factor as described above. Above, only the effect of the industry itself relocating or closing. Should supply chain effects part of this consideration? If so, shouldn’t the factor be considering effects on existing sources?

Author, 01/03/-1,

Interagency Comment Existing transmission capability would seem to be relevant to this discussion as well.This would seem to be the appropriate place to discuss ‘well-regulated’ EGU emissions from Canada that make it unlikely that Canada will use existing and/or planned transmission capacity to displace U.S. generation with fossil-fuel-generation in Canada.


evaluation might be efficiency improvements) and also with potential control technology for a

source category. The EPA is determining that it may be appropriate in a given instance to include

technology as a screening mechanism in the Agency’s determination of significance of a source

category As stated elsewhere in this final rule, the EPA has identified efficient generation as the

only likely BSER. Even in light of the limited candidates for a BSER analysis, the magnitude of

GHG emissions from EGUs and reductions available through efficiency would support the

EPA’s determination of significance.

V. Review and Withdrawal of the 2015 BSER Determination

In the 2015 Rule, the EPA determined that partial CCS qualified as the BSER for newly

constructed coal-fired EGUs because it was technically feasible, achieved emission reductions,

was widely geographically available, and could be implemented at a reasonable cost. Based on

additional analysis in the 2018 Proposal, the EPA proposed that partial CCS is more expensive

than previously determined in the 2015 Rule and that the costs are, in fact, unreasonable.31 The

EPA also proposed that partial CCS is not as widely available as was found in the 2015 Rule.

The EPA, therefore, proposed that partial CCS does not meet the BSER criteria. The EPA went

on to evaluate alternate BSER technologies and ultimately proposed that the most efficient

available generation is the BSER for newly constructed coal-fired EGUs.

31 See the EPA CO2 T&S cost technical support document (TSD), available in the rulemaking docket at https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0495 for detailed T&S costing information. The cost per tonne is higher for the bituminous case because the model plant captures only 611,000 tonnes annually compared to 1,210,000 tonnes for the subbituminous case (assuming an 85-percent capacity factor). However, due to the relative increase in the T&S costs compared to the $10/tonne cost in the 2019 NETL Report ($18/tonne for bituminous and $19/tonne for subbituminous), the overall T&S costs for both model plants are similar.

Author, 01/03/-1,

Interagency Comment Please explain. The description of this factor above implies that limited technology options could weigh against a significance determination. This description takes the BSER analysis as a given then applies it. That would imply that the intent of this factor is evaluate BSER in order to determine whether the contribution is significant, i.e., big enough reductions argue for significance.

Author, 01/03/-1,

EOP Comment Still need?

Author, 01/03/-1,

Interagency Comment If this were a screening mechanism as described above, this is not how its contribution to the decision would be described.

Author, 01/03/-1,

Interagency Comment EPA needs to provide the public with the information, limited as it may be, upon which it bases the consideration of technology. With the deletion of the entire BSER section, and the statement above that this factor will be based on readily available information, EPA should not presume that the public will understand the whole rulemaking record to be the basis for this ‘less robust’ review.

Author, 01/03/-1,

Interagency Comment EPA has deleted this finding from this document.

Author, 01/03/-1,

Interagency Comment When it is appropriate is not defined and this discussion does not elaborate on why it is appropriate in this instance.


This section describes the EPA’s review and response to comments on the costs32 and

geographic availability of CCS. In this final rule, the EPA has determined that the costs of partial

CCS are unreasonable. With respect to geographic availability, the EPA is rescinding the 2015

Rule’s finding that CCS is widely geographically available. As a result, the EPA is rescinding

that rule’s determinations that were based, at least in part, on that finding, which are that partial

CCS was “adequately demonstrated” to qualify as the BSER, see 83 FR 65441 (2018 Proposal),

and that the promulgated standard of performance was “achievable” by new sources.” 80 FR

64541 (2015 Rule). In this section, the EPA also reviews comments it solicited on the technical

feasibility of CCS, and concludes that it has not received any information that would lead it to

rescind the determination in the 2015 Rule that CCS is technically feasible.

A. Review of Costs

In the 2015 Rule, the EPA identified partial CCS costs based largely on a report from the

National Energy Technology Laboratory (NETL) at the Department of Energy (DOE), “Cost and

Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO2 Capture Rate in

Coal-Fired Power Plants,” DOE/NETL– 2015/1720 (June 22, 2015) (2015 NETL Baseline

Report). The EPA used the reported costs without significant adjustments and determined that

the cost of constructing a new coal-fired power plant that included partial CCS, as determined on

a LCOE basis, was reasonable because the cost was comparable to that of constructing new

nuclear generation and new biomass generation. The EPA used these latter costs as a benchmark

because it considered these other new generating options to be similar to new coal-fired EGUs

because all three generating options provide dispatchable base load “fuel diversity.” In the 2015

32While NETL used Midwest (Illinois) T&S cost in the Baseline Reports, costs for other regions were also provided. Exhibit 2-21 of the 2019 NETL Report lists the storage costs for the Midwest and Texas regions as $8.32/tonne and $8.66/tonne respectively. The 2019 NETL Report lists the storage costs for the North Dakota and Montana regions as $12.98/tonne and $19.84/tonne respectively. The 2019 NETL Report transport costs are estimated as $2.07/tonne for all regions.


Rule, the EPA also determined that the percentage increase in capital costs for a newly

constructed coal-fired EGU implementing partial CCS was comparable to the percent increase in

capital costs in previous NSPS rulemakings and was, therefore, reasonable. 80 FR 64558 through

64573.

In the 2018 Proposal, the EPA again used the 2015 NETL Baseline Report, but re-

evaluated the costs of partial CCS and, on that basis, proposed to find that those costs are

unreasonable. The EPA proposed to revise the LCOE of partial CCS based on revisions

concerning the costs of transport and storage (T&S) of captured CO2 and on adjusting EGU

capacity factors to account for impacts of partial CCS on dispatch. In addition, the EPA solicited

comment on whether the LCOE of new nuclear and biomass generation are valid reference points

for determining whether costs are reasonable for a coal-fired EGU with partial CCS, on whether

new nuclear capacity is more attractive than new coal-fired capacity as an option for providing

fuel diversity, and on whether the LCOE of a new nuclear power plant is, in fact, higher than

what developers may be willing to accept. The EPA also proposed to find that the percentage

increase in capital costs due to the implementation of partial CCS is excessive, especially when

the comparisons used in the 2015 Rule are put into context and the current economic state of the

power sector is considered. 83 FR 65435 through 65441.

The EPA received comments both supporting and opposing the proposed approach to

determining costs and on whether the cost metrics are reasonable.

In this final rule, the EPA is relying on updated cost and performance information

available largely from the revised NETL report, “Cost and Performance Baseline for Fossil

Energy Plants Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants,” NETL-

PUB-22695 (October 10, 2019) (2019 NETL Baseline Report).33 With respect to the LCOE, the 33 https://dualchallenge.npc.org/downloads.php.


EPA is finalizing its proposed revisions concerning the T&S costs and accounting for the impact

of economic dispatch on capacity factors, both of which result in higher LCOE. The EPA is also

finalizing its proposal that, even if the LCOE of a new nuclear plant is an appropriate

comparison metric, the LCOE of a newly constructed coal-fired EGU with partial CCS exceeds

those costs and would, therefore, not support a determination that the cost of partial CCS is

reasonable. Indeed, that would be true even without accounting for the T&S and capacity factor

adjustments that further increase the LCOE. As shown in Table 4 the amended LCOE for a

newly constructed coal-fired EGU with partial CCS is 94.0 to 108.3 $/MWh (depending on type

of coal and percent CCS), and this exceeds the LCOE of nuclear of 84.7 $/MWh, and, therefore,

is not reasonable. Without accounting for changes to T&S costs and expected capacity factor, the

LCOE for a newly constructed coal-fired EGU with partial CCS is 84.6 to 92.9 $/MWh (again,

depending on type of coal and percent CCS) which still, on average, exceeds the LCOE of

nuclear of 84.7 $/MWh, and, therefore, is still not reasonable. Furthermore, as explained in more

detail in section V.A.2.a, it should be noted that the LCOE for a new nuclear plant is not a good

benchmark for comparison because of inherent differences in EGU characteristics, including that

a new nuclear plant will emit zero CO2, whereas a new coal-fired EGU implementing partial

CCS to meet the 2015 NSPS (i.e., 1,400 lb CO2/MWh) will still emit a significant amount of

CO2. Therefore, even if the LCOE of a new nuclear plant and a new coal-fired EGU with partial

CCS were similar, that would not establish that the costs of partial CCS are reasonable. With

respect to capital costs, the EPA is also finalizing that, when the 2019 NETL Baseline Report

costs are used and when the percentage increase in capital costs for subbituminous-fired EGUs

are considered,34 the increase in capital costs is not reasonable.

34Absent an NSPS that is based on the use of partial CCS, a new coal-fired EGU would be expected to have a lower marginal cost than existing coal-fired EGUs and would, therefore, be dispatched prior to the existing coal fleet. Since the LCOE of a new coal-fired EGU with partial CCS would be higher, the PUC could be more likely to reject


Note that this section generally assumes familiarity with the discussion of costs in the

2018 Proposal, although the Agency reiterates key parts of that discussion.

1. Factors Considered in Levelized Cost of Electricity (LCOE) Estimation

This section summarizes the T&S costing approach, the proposed capacity factors, and

why, in the 2018 Proposal, the Agency did not assume revenue from the sale of captured CO2 for

use in enhanced oil recovery (EOR) or other financial incentives, such as tax credits, when

determining the LCOE of new coal-fired EGUs with partial CCS. It also summarizes the

comments received on these issues, the EPA’s response to those comments, and the Agency’s

rationale for the LCOE costing approach in this final rule. The Agency is finalizing the same

general approach for determining the LCOE as presented in the 2018 Proposal. Specifically, that

T&S costs are based on the actual amount of captured CO2, that capacity factors are impacted by

incremental generating costs, and that potential tax credits and revenue from sale of captured

CO2 for EOR should not be considered.

a. Adjustment of Transport and Storage (T&S) Costs

In the 2015 Rule, the EPA based the cost for T&S on the amount of CO2 from a coal-

fired EGU that captures 90 percent of the CO2 it emits (this percentage may be referred to as

“full capture”). Specifically, in the 2015 NETL Baseline Report, which, as noted above, served

as the basis for the 2015 Rule’s cost calculations, the cost of T&S (representative of storage cost

for the Midwest and Texas regions and not accounting for any revenues from the sale of CO2)

equaled $11 per tonne of CO2. The 2015 NETL Baseline Report derived this cost by assuming

transportation of 3.2 million tonnes of CO2 annually through a 100-kilometer (km) (62 mile) CO2

pipeline and geologic sequestration (GS) in a deep saline formation in the Midwest. Thus, this

cost did not account for the actual amount of CO2 captured, transported, and stored.

the new coal-fired EGU and only approve alternate base load generation—nuclear or combined cycle.


In contrast, in the 2018 Proposal, the EPA proposed to adjust the T&S costs based on the

actual amount of CO2 captured to account for the lack of economies of scale for transporting

smaller amounts of CO2. For example, the labor costs to construct a smaller pipeline required for

partial CCS are similar to those to construct a larger pipeline required for full CCS; but, because

less CO2 would be transported, the costs per tonne are higher. To adjust T&S costs for the lower

amounts of CO2 that are captured and transported with partial CCS, the EPA used the NETL CO2

Transport Cost Model and the NETL CO2 Saline Storage Cost Model (both were used in the

2015 NETL Baseline Report to estimate the $/tonne costs assuming full capture) 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). The EPA adjusted the tonnes of CO2 transported and stored to reflect that use of

partial CCS results in capture of fewer tonnes of CO2. This adjustment increased the T&S costs

for an EGU implementing partial CCS from the previous $11/tonne for an EGU firing any type

of coal to $30/tonne for an EGU firing bituminous coal and to $20/tonne for an EGU firing

subbituminous coal. This adjustment increases the overall LCOE by $2.4/MWh and $2.3/MWh

for the bituminous and subbituminous cases, respectively. Based on review of the comments, the

EPA has concluded it is appropriate to finalize the proposed approach.

Some commenters stated that, in the 2018 Proposal, the EPA properly used updated

scaling factors that recognize that the T&S costs will vary based on the amount of CO2 captured.

The commenters further said that the Agency’s adjustments to the projected LCOE reflecting

higher CO2 T&S costs provide a more realistic prediction of the true economic impact of this

system than its analysis in the 2015 Rule.


Other commenters stated that the EPA’s proposed adjustments to T&S costs are arbitrary

and capricious and only serve to inflate costs. The commenters claimed that the EPA adopted the

unrealistic assumption that each source of CO2 will be paired with a single CO2 storage location,

instead of using the more reasonable assumption—supported by industry trends—that a proven

geologic sequestration site would serve multiple sources of CO2, which would lower the cost per

tonne of storage. Additionally, the commenters claimed that plants may opt to sequester captured

CO2 on-site and thereby eliminate transportation costs altogether. They further claimed that the

Agency relied on outdated cost data for transportation instead of using more recent estimates that

better reflect the pipeline infrastructure for CCS capture. The commenters also said the Agency

must reach out to pipeline and storage vendors and operators and review recent literature to

update the T&S costs. They said that developers of a new plant would choose a construction site

that is already amenable to utilizing existing CO2 infrastructure, allowing the source to achieve

the economies of scale represented by the 2015 Rule’s value of $11/tonne.

The EPA disagrees with commenters suggesting that the CO2 storage costing should

assume that multiple sources of CO2 use a single storage site. Assuming shared storage locations

would reduce the geographic availability of CCS to areas of the country with currently active

sequestration activities, mainly for EOR projects, or CO2 pipelines. Those EOR activities take

place in only 12 states; only 18 states are located within 100 km of an active EOR location; and

only 13 states have operating CO2 pipelines.35 Currently only a single non-EOR storage site—a

deep saline sequestration site in Illinois—exists in the U.S.36 This is a dedicated—not a shared—

sequestration site, which is consistent with the costing approach used by the EPA. In any event,

35 Emission Guidelines for Greenhouse Gas Emissions From Existing Electric Utility Generating Units, 84 FR 32520 (July 8, 2019). Supporting information is available in the rulemaking docket EPA–HQ–OAR–2017–0355.36 The national R-squared value is 0.62, indicating an acceptable correlation between carriable operating costs and annual capacity factor.


simply because a specific site is associated with an active EOR operation does not guarantee that

the site is able or willing to accept additional CO2. While NETL has identified the potential for

large storage volumes in both EOR and saline reservoirs, the ability for an individual field to

accept and safely store CO2 is dependent on site-specific technical, regulatory, and economic

considerations that are not taken into account in NETL’s analysis.37

The EPA disagrees with the comment that the costing analysis should assume that new

coal-fired EGUs could be constructed directly on top of GS sites to eliminate transportation

costs. As discussed in the 2015 Rule and in the 2018 Proposal, the geographic availability

analysis included areas within a 100-km area of locations with sequestration potential.

Eliminating the option to transport captured CO2 would restrict areas amenable to CCS to such

an extent that the 2015 Rule’s standard of performance, which was based on partial CCS, would

not meet the CAA section 111(a)(1) requirement to be achievable by new EGUs.38

The EPA has concluded that scaling the T&S costs to account for economics of scale

more accurately reflects the potential cost of implementing partial CCS as opposed to using a

single T&S value derived from assuming the transport and storage of CO2 representative of a

coal-fired EGU with full CO2 capture. Therefore, the EPA is using T&S costs derived using the

same approach as in the NETL Baseline Reports, but adjusting the costs based on the actual

amount of CO2 captured. To assure that its cost figures are up to date, the EPA is using the T&S

costs included in the 2019 NETL Baseline Report. This report uses the same storage costing as

the 2015 NETL Baseline Report—which, as noted above, the EPA relied on in the 2018 Proposal

37 The EPA evaluated the T&S costs and impact of variable operating costs separately. If the EPA had analyzed the impacts together, the increase in LCOE would have been greater. For example, including the revised T&S costs decreases the capacity factor by an additional 6.1 percent.38 Based on the EPA analysis, an increase in variable operating costs of $3.7/MWh decreases the annual capacity factor by 9.8 percent. If the baseline capacity factor is 85 percent, the resultant capacity factor is 75.2 percent. This equates to a 11.5 percent decrease in electric sales and revenue. If the baseline capacity factor is 64 percent, the resultant capacity factor is 64.2 percent. This equates to a 15.3 percent decrease in electric sales and revenue.


—but updates the NETL CO2 Transport Cost Model to version 2b, which are slightly lower than

the transport costs used in the 2018 Proposal. The T&S costs in this final rule are $28/tonne for

the supercritical bituminous EGU and $19/tonne for the supercritical subbituminous EGU. The

resulting direct increase in the calculated LCOE due to the scaling of the T&S costs for this final

rule is $2.3/MWh for both the bituminous and subbituminous cases.39 It should be noted that

depending on where the project is located, T&S costs could be higher than those just noted. As

described in the 2018 Proposal, T&S costs are expected to vary depending on where the pipeline

and storage site are located, and although the T&S costs just noted are representative values for

the Midwest and Texas regions, they are significantly lower than the projected T&S costs for

North Dakota and Montana regions.40

The EPA notes that the T&S cost estimates upon which this final rule relies are the most

current values and are found in the 2019 NETL Baseline Report. They are consistent with

independent cost estimates for CO2 T&S systems from the National Petroleum Council (NPC).41

The overall national average storage costs, excluding high cost formations and assuming large

storage volumes, calculated by NPC is $8/tonne (the NPC values are rounded to the nearest

dollar). This agrees well with the NETL Midwest storage cost (which was chosen for the 2019

NETL Baseline Report) for full capture of $8.32/tonne.

39 The 2016 and 2019 NETL Baseline Reports only include bituminous-fired subcritical and supercritical PC cases (NETL did not model a bituminous-fired ultra-supercritical PC). The low rank NETL Baseline Report included both a supercritical and ultra-supercritical PC, but not a subcritical PC. The EPA estimated the cost and performance of a bituminous-fired ultra-supercritical PC using the relative costs and performance of the NETL low rank supercritical and ultra-supercritical cases. Similarly, the EPA estimated the cost and performance of a low rank subcritical PC using the relative costs and performance in the 2019 NETL report. Details of the EPA’s partial CCS cost and performance analysis are included in the CCS Costing TSD available in the docket. 40 Section 45Q of the U.S. tax code provides a tax credit to power plants and industrial facilities that capture and store CO2 that would otherwise be emitted into the atmosphere.41 U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition, September 2015, available at https://www.netl.doe.gov/sites/default/files/2018-10/ATLAS-V-2015.pdf and EPA GHGRP, see https://www.epa.gov/ghgreporting. See also U.S. EPA, Memorandum: Geographic Availability of Geologic Sequestration, December 2018, available in the rulemaking docket at https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0495-11941.


Based on review of the comments, the EPA is finalizing the proposed approach to adjust

the T&S costs based on the actual amount of CO2 captured. The costs reflect currently available

estimates and storage assumptions appropriate for a nationwide rule. Standards developed under

the NSPS program must, by statutory requirement, be reviewed, at least, every 8 years. The EPA

will monitor changes (if any) to CO2 T&S costs and assumptions and will take that into

consideration in the next NSPS review.

b. Adjustment of Assumed Capacity Factor

The 2015 Rule’s cost calculations were based on an assumed 85-percent capacity factor

for all generation technologies, consistent with the NETL Baseline Reports. This means that the

2015 Rule assumed that a coal-fired EGU would operate at the same capacity factor with or

without partial CCS. In the 2015 Rule, the EPA used this approach when determining the LCOE

of partial CCS. While this approach is useful for comparing different generation options, it does

not account for the impact that increased operating costs could have on the dispatch of a

particular EGU. Because CCS has significant operating costs and would increase the incremental

cost of electricity, under an economic dispatch model in which available units with the lowest

incremental generation costs are dispatched prior to units with higher incremental costs, a new

coal-fired EGU with partial CCS would dispatch less often and sell less electricity relative to a

similar coal-fired EGU without CCS.

In the 2018 Proposal, the EPA proposed to incorporate the economic dispatch model

assumptions into its cost analysis. The EPA explained that this use of the model would mean that

EGUs implementing partial CCS would, by virtue of their higher costs, be assumed to dispatch

less frequently and, as a result, have reduced electric sales and corresponding revenue. All this

would mean that EGUs implementing partial CCS would be treated as having a higher LCOE.


Specifically, in the 2018 Proposal, the EPA accounted for economic dispatch as follows:

The EPA assumed that a supercritical EGU without CCS had an 85-percent capacity factor. The

EPA adjusted the capacity factor for a supercritical EGU with partial CCS based on the relative

incremental generating costs compared to the supercritical case. In addition, to evaluate the

impact of efficient generation on dispatch, the EPA also adjusted the capacity factor of a

subcritical and ultra-supercritical EGU without CCS based on the relative incremental generating

costs compared to the supercritical case. The EPA did this separately for the bituminous and

subbituminous cases. The EPA determined the adjustment factor by reviewing data from the U.S.

EIA National Energy Modeling System (NEMS) model and from the EPA’s Clean Air Markets

Division (CAMD). For both data sets, the EPA developed general relationships between the

capacity factor of coal-fired power plants and variable operating costs. Based on these

relationships, the EPA proposed to adjust the annual capacity factor by 1.5 percent for each

$/MWh change in variable operating costs. This resulted in reduced capacity factors of 76.6

percent and 72.5 percent for the bituminous and subbituminous cases, respectively. A lower level

of electric sales resulted, and that, in turn, increased the calculated LCOE by $6.8/MWh and

$11/MWh for the bituminous and subbituminous cases, respectively.

Some commenters supported the EPA’s acknowledgment that implementation of partial

CCS would increase a unit’s variable operating costs, thus, decreasing its expected dispatch in

competitive energy markets and reducing the unit’s overall capacity factor. They stated that

accounting for this impact provides a more realistic prediction of the true economic impact of

this system than the analysis in the 2015 Rule. They added that the EPA’s revised analysis in the

2018 Proposal may even overestimate the capacity factor of such units because the baseline

capacity factor of coal-fired EGUs without CCS is expected to decline in the future, which


suggests that CCS-equipped units could see even lower utilization than the range of 72.5 to 76.6

percent that the EPA predicted in the proposal.

Other commenters stated that the EPA’s downward adjustments of its capacity factor

assumption for a new coal-fired EGU with partial CCS is unreasonable because, as evidenced by

the Agency’s own record, no one would build a new coal plant in a competitive market under

current market conditions or based on economics alone. They said the EPA’s reliance on fuel

diversity as a reason why coal plants might be built is currently only supported with respect to

regulated markets and cannot be reconciled with dispatch order concerns. Thus, according to the

commenters, if a utility decides that for purposes of fuel diversity, a new coal plant is desirable,

it will build the plant in an area where it has anticipated paying a premium for that diversity, and

it will utilize the plant for base load generation. The commenters further pointed to what they

viewed as several flaws in the Agency’s methodology. First, according to commenters, the EPA

evaluated all coal-fired EGUs together instead of separating them on a regional basis. The

commenters claimed that EGUs dispatch primarily within a region and evaluating only national

trends can obscure regional variable operating cost impacts. In addition, according to

commenters, because the EPA did not model a full redispatch of the U.S. electricity system, the

proposed findings are not indicative of a relationship between changes in variable costs and

generating output of coal-fired EGUs. Under economic dispatch, a coal plant’s output is a

function of its variable costs, system demand, and the amount of electricity that other, lower-cost

EGUs in its supply zone can provide.

After reviewing the comments, the EPA is finalizing the proposed approach to adjusting

capacity factors based on incremental generating costs.


The EPA disagrees with commenters that dispatch order is only important for competitive

markets. In markets regulated by a public utility commission (PUC), it is a fundamental principal

that new generating capacity must be “used and useful” to the ratepayers in order to incorporate

any associated costs in the rate base. In making that determination for a new coal-fired EGU, it is

reasonable to expect that the PUC would consider the extent to which that plant would likely

dispatch. 42 Therefore, regardless of whether a new coal-fired EGU is located in a cost-of-service

or deregulated market, economic dispatch is a consideration. Even if a PUC were to approve a

new coal-fired EGU with partial CCS for fuel diversity reasons, that does not automatically

mean the new EGU would be dispatched prior to other EGUs with lower incremental generating

costs. A PUC that values fuel diversity achieves that by investing in new diverse generation

technologies (e.g., building a new coal-fired power plant) and not through adjusting dispatch.

Fuel diversity is a hedge against an uncertain future and an attempt to lower future costs. It is not

a commitment to raise future costs by deliberately forcing out-of-merit dispatch. Therefore, the

EPA disagrees with commenters that say that the owner will ‘pay a premium’ and utilize it for

base load regardless of cost.

To refine the relationship between incremental generating costs and dispatch, the EPA

plotted the annual capacity factor and average variable costs for every coal-fired power plant in

the continental U.S., as projected by the integrated planning model (IPM) base case supporting

the Affordable Clean Energy (ACE) Rule.43 The EPA then determined the coefficient of the best

fit linear trend line at a national and regional level using individual unit level data.44 The 2030

42 U.S. EPA, Memorandum: Geographic Availability of Geologic Sequestration, December 2018, available in the rulemaking docket at https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0495-11941.43 U.S. EIA, Electric Power Annual 2018, see https://www.eia.gov/electricity/annual/pdf/epa.pdf.44 U.S. EIA, Electric Power Annual 2018, see https://www.eia.gov/electricity/annual/pdf/epa.pdf and U.S. EPA, Memorandum: Geographic Availability of Geologic Sequestration, December 2018, available in the rulemaking docket at https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0495-11941.


projected capacity factor variable operating cost relationship indicates that for each $1/MWh

increase in variable operating costs, the annual capacity factor will decrease by 2.65 percent for

coal-fired EGUs. The EPA used this factor in estimating the impact of a BSER based on the use

of partial CCS. Table 2 shows the variable operating costs using the 2019 NETL Baseline Report

and the resultant capacity factors.

TABLE 2. VARIABLE OPERATING COSTS AND CAPACITY FACTORS1

TechnologyVariable Operating Costs

(2018$/MWh)Amended Capacity

FactorsSubcritical PC (bit) 29.2 82.0SCPC (bit) 28.0 -SCPC + ~16-percent CCS (bit) 31.7 75.2SCPC (low rank) 24.7 -Ultra-supercritical PC (low rank) 24.2 86.1SCPC + ~ 26-percent CCS (low rank)

33.7 67.1

NGCC 30.7 1 Subbituminous and dried lignite have similar heating values and CO2 emissions on a heat input basis. The EPA includes both of these fuels when using the term low rank.. An EGU burning either fuel would have a similar variable operating costs and CO2 emissions rate on a lb CO2/MWh-gross basis (when not accounting for the useful thermal output used for integrated lignite drying).

Using the incremental generating costs calculated from the 2019 NETL Baseline Report without

the T&S adjustment,45 the revised capacity factor for a bituminous-fired SCPC with 15.6-percent

CCS is 75.2 percent, and the revised capacity factor for a subbituminous-fired SCPC with 26.5-

percent CCS is 66.9 percent. The resulting direct increase in the calculated LCOE due to the

revised capacity factor is $6.9/MWh and $12.6/MWh for the bituminous and subbituminous

cases, respectively. The Agency notes that the relationship is even stronger in regions with

significant coal-fired capacity, up to a 5-percent decrease in capacity factor for each $1/MWh

increase in variable operating costs, and that as a result the impact on actual costs of CCS could

be significantly more in these regions.45 U.S. EIA, Electric Power Annual 2018, see https://www.eia.gov/electricity/annual/pdf/epa.pdf and U.S. EPA, Memorandum: Geographic Availability of Geologic Sequestration, December 2018, available in the rulemaking docket at https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0495-11941.


The Agency further notes, as pointed out by commenters, that assuming a baseline

capacity factor of 85 percent reduces the estimated cost impact of the installation of partial CCS.

The 2.65-percent decrease in capacity factor per $1/MWh, described in the previous paragraph,

is an absolute, and not relative, decrease in generation. Based on data submitted to the CAMD, in

2018 the average coal-fired EGU capacity factor was 45 percent and only 2 percent of coal-fired

EGUs had capacity factors of 85 percent or higher. Further, while the best performing EGUs

have operating capacity factors (i.e., duty cycles) close to 85 percent, the 2018 average capacity

factors of the 21 coal plants that have commenced operation in the U.S. since 2010 was 64

percent. If a lower baseline capacity factor were assumed, the capital and fixed costs of CCS

would be spread out over fewer MWh of generation and the absolute increase in the LCOE

would be larger. In addition, because the absolute decrease in capacity factor is determined based

solely on the increase in incremental generating costs, the relative increase in LCOE would be

higher if a lower baseline efficiency is assumed.46 Also, while not part of the partial CCS BSER

analysis, the revised capacity factor for a bituminous subcritical PC is 82.2 percent, and the

capacity factor for a low rank ultra-supercritical PC is 86.4 percent.47 This demonstrates the

value of efficient generation in reducing the LCOE of new generation without CCS.

c. EOR and Tax Credits

In the 2018 Proposal, the EPA proposed to not include revenue from sale of captured CO2

for use in EOR or savings from tax credits because neither would be available on a national basis

during the period of analysis of this rulemaking.

46 Petra Nova Parish Holdings LLC, Carbon Capture, Utilization and Storage, and Oil and Gas Technologies Integrated Annual Review Meeting, August 2019, see https://netl.doe.gov/sites/default/files/netl-file/Anthony-Petra-Nova-Pittsburgh-Final.pdf.47 Jeremy Dillon and Carlos Anchondo, Low oil prices force Petra Nova into 'mothball status', E&E News PM, July 28, 2020, at https://www.eenews.net/eenewspm/stories/1063645835.


Some commenters stated that a new coal-fired power plant built for fuel diversity

purposes is already at an economic disadvantage, as compared to a NGCC EGU, and developers

have the option to build in the most economically advantageous area. Therefore, according to

these commenters, the cost of employing partial CCS at a new coal-fired plant should take into

account opportunities for the plant operator to offset that cost. Specifically, the Agency should

quantify the benefit to the plant operator from revenue from sale of captured CO2, such as for

EOR, and from increased tax credits for CCS when determining the LCOE.

The commenters stated that in the 2015 Rule, the Agency assumed no revenues from sale

of captured CO2 in order to show that its cost estimates were reasonable even when EOR

opportunities were not available. Commenters stated that the EPA’s assumption did not reflect a

finding or belief that EOR was too geographically limited to be included in its cost

considerations. Rather, it embodied a conservative approach taken to show that the EPA’s

estimates were reasonable in all scenarios. Here, according to commenters, the EPA is doing the

opposite—placing inordinate weight on a few hypothetical places where EOR opportunities may

not be available. According to commenters, some estimates hold that, as a general rule, a ton of

CO2 sells for about 35 to 45 percent of the price of a barrel of West Texas Intermediate oil. These

commenters said these estimates comport with various NETL analyses that, when oil prices

hovered around $95 at the beginning of the decade, it was typically assumed a CO2 purchase cost

of $40 per metric ton of CO2.

Commenters also faulted the 2018 Proposal for not adjusting the LCOE to account for the

tax credits available under Internal Revenue Code section 45Q. 26 U.S.C. 45Q.48 In that

proposal, the EPA explained that including tax credits would underestimate the costs of a BSER

based on the use of partial CCS because the credits were available only for a facility that 48 Commencing construction triggers NSPS applicability, under 40 CFR 60.1-.2.


“commence[s] construction before January 1, 2024…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.” 83 FR 65440. The commenters said the EPA does not entertain the possibility that

Congress might extend the applicability of these credits. The commenters also stated that the

section 45Q tax credit, extended and expanded by the Bipartisan Budget Act of 2018, now

provides substantial financial support to power plants and other facilities using CCS. For

example, a power plant beginning construction in 2020 that goes into service in 2024 would be

able to receive a tax credit of $45 per metric ton of captured CO2 that is deposited in GS. That

figure would increase to $50 per ton by 2026, and then rise with an inflation multiple in the 12

subsequent years of eligibility. This means that, given NETL estimates for the per ton cost of

CO2 capture, the section 45Q credit offers tax credits that represent roughly 75 percent of the per

ton cost of capture for CCS projects using GS. The commenters disagreed with suggestions that

section 45Q will be ineffective in spurring investment in and development of CCS because the

credits are generated over time and are not available up front. The commenters noted that,

because the power sector has historically paid off capital investments over long time periods, the

section 45Q credits will offset costs when they are typically recouped by utilities and thus are

relevant to the EPA’s consideration of costs in the BSER analysis.

Commenters added that the Internal Revenue Code section 48A, 26 U.S.C. 48A(a), tax

credit provides a qualifying advanced coal project credit for any taxable year in an amount equal

to 30 percent of the qualified investment. A coal-fired EGU project separating and sequestering

65 percent of its CO2 emissions qualifies for the credit. Commenters further note that on

February 8, 2019, the Carbon Capture Modernization Act was introduced in the Senate to further

incentivize CCS projects through section 48A.


After reviewing the comments, the EPA concludes that neither revenue from sale of

captured CO2 for use in EOR nor savings from tax credits should be included in determining the

LCOE of a new coal-fired EGU with partial CCS because, while individual EGUs might be able

to take advantage of them, neither is broadly applicable on a nationwide basis during the period

of analysis of this rulemaking. With respect to EOR, throughout the country, 29 states have been

identified as having oil reservoirs amenable to EOR, of which only 12 states have active EOR

operations.49 The vast majority of EOR is conducted in oil reservoirs in the Permian Basin, which

extends from southwest Texas through southeast New Mexico. States where EOR is utilized

include Alabama, Arkansas, Colorado, Louisiana, Michigan, Mississippi, Montana, New

Mexico, Oklahoma, Texas, Utah, and Wyoming.50 In contrast, coal-fired generation capacity is

located across the country.51 For example, Georgia, Minnesota, Missouri, Nevada, North

Carolina, South Carolina, and Wisconsin all have coal-fired generation capacity but do not have

oil reservoirs that have been identified as amenable for EOR.52 In addition, Illinois, Indiana,

Kentucky, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia, which are among the

states with the largest amounts of coal-fired generation capacity, do have oil reserves identified

as amenable for EOR, but do not have any active EOR operations.53 Furthermore, due to the 49 It typically takes multiple years between when a coal-fired EGU is announced and when construction commences. In addition, the EPA typically requires a year from when work commences on a rulemaking until the proposal is signed and an additional year for the final rule to be signed. Therefore, if the EPA were to determine that CCS is cost effective due to the availability of section 45Q tax credits any amendments to revise the BSER due to the expiration of the tax credits would have to be initiated well in advance of the expiration of those credits. 50 The NETL PC Carbon Capture uses a capital recovery factor based on 30 years. If shorter periods are selected, the $/MWh for capital recovery would be higher. Recovering costs over a 12-year period, as opposed to a 30-year period, would increase the capital recovery factor by 40 percent.51 Under section 45Q(d)(2)(A), an electric generating facility also qualifies for section 45Q tax credits if it emits not more than 500,000 tonnes of CO2 into the atmosphere during the taxable year and at least 25,000 tonnes are utilized annually using alternatives to GS and EOR. 52 The NETL subbituminous-fired supercritical EGU with 26.5-percent CCS captures 1,200,000 tonnes of CO2 annually. Based on this, a 270 MW subbituminous-fired EGU operating at an 85-percent capacity factor would capture sufficient CO2 to be eligible for the section 45Q tax credits. If actual operating efficiencies are lower than the NETL deign values, the size and capacity factors required to capture sufficient CO2 would be reduced.53 In addition, applications for the section 48A credit cannot be accepted until the Internal Revenue Service issues a notice for a new round of applications. https://www.law.cornell.edu/uscode/text/26/48A


variability in oil prices, revenue from EOR cannot be guaranteed. For example, the Petra Nova

facility in Texas was retrofit with CCS and is located in proximity to an area that is highly

amenable to EOR.54 However, due to low oil prices, the CO2 capture system ceased operation in

2020 and is not anticipated to reopen until oil prices stabilize at a higher price.55 In addition,

while EOR opportunities may be available for some potential new EGUs, as described later in

subsequent sections, sales of captured CO2 for use in EOR cannot offset the high costs of CCS.

The EPA also has concluded that it is not appropriate to account for savings from the

section 45Q tax credits in determining LCOE. In order to implement CCS and be able to rely on

the section 45Q tax credit, a developer would have to complete all planning, including arrange

all financing and preconstruction permitting, and commence construction by January 1, 2024.56

See 26 U.S.C. 45Q(d)(1). As stated in the 2018 Proposal, NSPSs must be reviewed at least every

8 years. Thus, the availability of the section 45Q tax credits expires prior to the next review of

these standards. The EPA is not aware of any developers of new coal-fired EGUs that are

currently in the permitting process. As a result, if a new EGU were to be subject to the

requirements in this rulemaking, it is possible that its developer would not have been able to

commence construction prior to January 1, 2024. Accordingly, a new plant could become subject

54 While larger biomass-fired EGUs exist internationally, there are site specific factors and national or subnational policies and/or subsidies that are not widely applicable or implemented in the U.S.55 The EPA notes that when the capital cost uncertainty factor is not used the LCOE of coal with partial CCS exceeds that of nuclear even without considering the capacity factor and T&S adjustment in the 2018 Proposal. Specifically, the bituminous case LCOE of $96.2/MWh and the subbituminous case LCOE of $109.0/MWh exceed the EIA nuclear LCOE values. In the 2018 Proposal, the bituminous case LCOE without CCS was $81.7/MWh. The increase in LCOE due to partial CCS for the bituminous case without the T&S and capacity factor adjustments was $14.5/MWh. When the T&S economies of scale and impacts of incremental generating costs are accounted for, the increase in LCOE due to partial CCS is $23.7/MWh—a 63 percent increase in the relative costs of partial CCS. A similar analysis for the subbituminous case results in a 58 percent relative increase in the LCOE impact of partial CCS.56 Lazard (www.lazard.com) is a financial advisory and asset management firm. Lazard issues an annual independent comparative LCOE analysis for conventional and renewable energy generation. The Lazard nuclear uncertainty range includes uncertainty factors applied to fixed and variable costs in addition to capital costs.


to this NSPS but not be eligible to receive the section 45Q tax credit.57 In addition, the tax credit

is, in general, available only for the 12-year period beginning on the date the equipment is

originally placed in service. 26 U.S.C. 45Q(a)(3) and (4). Thus, it would not be available to

offset much of the capital costs of the CCS systems, which generally are recovered over a 30-

year period.58 Further, like any federal income tax credit, the section 45Q tax credits do not

provide a benefit to a company that does not owe federal income tax, and, thus, they may not

benefit some coal-fired power plant owners. Further, to be eligible for the tax credits, under

section 45Q(d)(2)(B), an EGU must emit at least 500,000 tonnes of CO2 annually.59 The NETL

model plant—a supercritical bituminous-fired EGU operating at an 85-percent capacity factor

and using 15.6-percent CCS—would capture 940 tonnes of CO2 per MW of capacity annually.

Based on this, the section 45Q minimum capture requirement under 26 U.S.C. 45Q(d)(2)(B)

limits the availability of the tax credit to a new bituminous-fired EGU that is no smaller than

approximately 530 MW. Further, if the 650 MW facility were to operate at less than a 70 percent

annual capacity factor, it would reduce emissions below 500,000 tonnes of CO2 annually and

become ineligible for the section 45Q tax credits for the year, under section 45Q(d)(2)(B). As

described previously, the 2018 average capacity factor of 21 coal plants that have commenced

operation in the U.S. since 2010 was 64 percent. Thus, the size and capacity factor requirements

necessary for an EGU to be eligible for the section 45Q tax credits under section 45Q(d)(2)(B)

57 Another example of the changes in the 2019 NETL Baseline Report concerns the capital charge rate, which is used to convert the capital cost into a stream of levelized annual payments that ensures capital recovery of an investment. The 2019 NETL Baseline Report reduced the capital charge factor from 10.2 percent to 7.1 percent.58 When comparing the LCOE it is important that the interest rate, service life, tax structure, etc., be consistent as the capital recovery factor has a significant impact on the calculated LCOE, especially for capital intensive projects such as coal-fired and nuclear EGUs. 59 The 2019 NETL Baseline Report uses a capital recovery factor of 0.0707 and the ratio of the total as spent capital to the total overnight costs is 1.15. The AEO 2020 capital recovery factor is 0.066 for nuclear, biomass, and coal with full CCS and 0.09 for coal without full CCS. The AEO 2020 ratio of total as spent capital to the total overnight costs is 1.075. Consistent with the NETL Baseline Reports, the EPA did not include the AEO 2020 3-percent cost adder for coal without full CCS.


also mean that a significant portion of potential new coal-fired generation might not be eligible.60

Accordingly, the section 45Q tax credits cannot be considered to offset the high costs of partial

CCS for the industry as a whole.

The EPA is not including the section 48A tax credits in the costing analysis for several

reasons. To be eligible for this tax credit, a project must sequester at least 65 percent of its total

CO2 emissions, which is a significantly higher percentage than identified as the BSER in the

2015 Rule. In addition, the section 48A tax credits include minimum design net efficiency

requirements of approximately 40 percent for non-IGCC coal-fired EGUs. CCS requires both

process steam and electricity to operate, which impose auxiliary load requirements that, in turn,

lower the net efficiencies of EGUs using CCS. Based on currently available CCS technologies,

an EGU capturing 65 percent of the CO2 would have a net efficiency in the low 30-percent

range61 and thus would not be eligible for the section 48A tax credit. For these reasons, the

availability of the section 48A tax credit is too limited for the EPA to include it as part of its cost

analysis.

2. Levelized Cost of Electricity (LCOE) Comparison

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 coal-fired EGU with partial CCS

would be “reasonable” if it was consistent with the LCOE associated with the construction of a

new nuclear or biomass power plant since both of these EGUs provide dispatchable base load

power and serve to expand fuel diversity. The EPA recognized NGCC units provided the least

60Commenter EPA-HQ-OAR-2013-0495-12611 assumes $22/tonne for EOR revenue. The EPA is using this value for illustrative purposes only. The AEO 2019 projects the 30-year levelized average wellhead price of crude oil in the lower 48 states to be approximately $80/barrel (in $2018).61 It should also be noted that the percentage increase in capital costs for a subbituminous-fired SCPC was not used in either the 2015 Rule or the 2018 Proposal.


expensive type of base load generation, but determined that the higher costs of coal-fired EGUs

were nevertheless reasonable because utilities had indicated to the EPA that they valued the fuel

diversity provided by coal-fired EGUs.

As part of the 2018 Proposal, the EPA also solicited comment on whether it is valid to

use the LCOE of a new nuclear EGU as a comparison point for a new coal-fired EGU with

partial CCS. The EPA specifically solicited comment on whether a new nuclear EGU is in fact

more attractive than a new coal-fired EGU with partial CCS due to the nuclear EGU’s lower

emissions and lower incremental generating costs, as well as its price stability, and whether

developers may be willing to pay more of a premium for new nuclear projects than for new coal-

fired EGUs. The EPA also proposed to include the amended T&S costs and amended capacity

factor when determining the LCOE of a new coal-fired EGU with partial CCS. Based on

comparing the amended costs with a new nuclear EGU, the EPA proposed that the costs of a new

coal-fired EGU with partial CCS are not reasonable because they are significantly higher than in

the 2015 Rule and exceed that of a new nuclear EGU.

This section summarizes the comments received on using the LCOE of new nuclear and

biomass-fired EGUs as a metric for what qualifies as reasonable costs, the EPA’s response to

those comments, and the Agency’s rationale for the LCOE comparison in this final rule. Due to

the failure to analyze the difference between coal-fired EGUs and nuclear and biomass-fired

EGUs in the 2015 Rule, the EPA is withdrawing the determination in the 2015 Rule that nuclear

generation and biomass-fired EGUs serve as benchmarks for determining reasonable costs.

However, it should be noted that even if the LCOE of a new nuclear or biomass-fired EGU were

an appropriate benchmark for the LCOE of a new coal-fired EGU with partial CCS, the costs

would still not be reasonable. As part of this final rule, the EPA updated the LCOE calculations


using more recent data than were available for the 2018 Proposal and used the same financial

assumptions to assure that the LCOE values are comparable. Based on both the LCOE values

included in the 2018 Proposal and in this final rule, the EPA finds that the cost of a new coal-

fired EGU with partial CCS exceeds both the cost of a new nuclear EGU and a biomass-fired

EGU and is not reasonable.

a. Appropriateness of nuclear and biomass benchmarks

Numerous commenters addressed whether it was appropriate for the EPA, in the 2015

Rule’s BSER analysis, to determine whether the cost of a new coal-fired EGU with partial CCS

was reasonable by, in part, comparing the LCOE of that type of unit to the LCOE of a new

nuclear or biomass-fired unit. Some commenters stated that while the cost of a new generating

unit is certainly a critical factor for utilities seeking to expand their generation portfolio, many

other factors must also be considered. According to the commenters, with respect to nuclear

units, these include fuel availability, startup and shutdown capability, operational flexibility,

incremental generating costs and expected dispatch, waste disposal challenges, public and

private safety concerns, licensing and permitting requirements, ancillary environmental risks,

overall environmental impact, and public perception. The commenters concluded that the EPA’s

comparison of a new coal-fired unit with partial CCS to a new nuclear unit is far too simplistic to

be meaningful.

Other commenters stated that power companies regard both coal-fired and nuclear power

as enhancing fuel diversity in their resource mix and have acknowledged the value they place on

fuel diversity in recent Integrated Resource Plans (IRPs) submitted to state regulators. They

noted, for example, that Georgia Power Company, in its IRP, observed that its new nuclear units

would bring needed base load capacity and fuel diversity benefits to the company’s fleet.


Similarly, the company argued in a discussion of controls and upgrades for its coal-fired

generation units, that these units are a reliable part of the fleet and maintain essential fuel

diversity. Commenters also pointed to Tucson Electric Power Company’s IRP, which envisioned

replacing coal-fired generation with small nuclear reactors because both are fully dispatchable

and nuclear generation maintains resource diversity in the absence of coal-fired generation.

These commenters concluded that at least some power companies view coal-fired and nuclear

generation as close substitutes in providing fuel diversity, and therefore, that the EPA

appropriately compared the LCOEs of these resources. In addition, the commenters stated that

EPA’s basis for dismissing the relevance of biomass EGUs is in tension with the agency’s claim

that fuel diversity from nuclear generation is enhanced by its high capacity factor (and therefore

higher dispatch). The commenters stated that the fact that biomass-fired EGUs are smaller than

most other EGUs similarly suggests that coal-fired EGUs with partial CCS would provide

greater fuel diversity benefits through higher dispatch (and therefore be worthwhile to power

companies at a higher LCOE) than biomass-fired EGUs.

The EPA notes that, while coal-fired units and nuclear units have historically served as

base load generators, they are not necessarily interchangeable. As noted by commenters, LCOE

is not the only factor in evaluating new generation capacity. Nuclear is not a good benchmark

because, for example, it emits zero CO2, criteria pollutants, and hazardous air pollutants whereas

a coal-fired EGU with partial CCS still emits a significant amount of these pollutants. In

addition, nuclear requires less maintenance and has lower operating costs resulting in a higher

capacity factor and a potentially better long term competitive outlook than a comparable coal-

fired EGU.


Similarly, biomass-fired EGUs are also not necessarily a good benchmark because, for

example, such EGUs in the U.S. are typically smaller in scale due to limitations on biomass

supply and related costs of biomass procurement and transport in a given region, among other

things. The EIA projects that average net additional biomass generation capacity amounts to less

than 100 MW annually, and the largest domestic biomass-fired EGU is less than 200 MW.62

Moreover, 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. In addition, burning biomass actually increases a source’s CO2

emissions per unit of energy produced relative to a coal-fired EGU because biomass is less

energy dense than coal. According to annual emissions data submitted to the CAMD, all

biomass-fired EGUs have emission rates of 2,800 lb CO2/MWh-gross or higher. Therefore, a

biomass-fired EGU would emit more CO2 per unit of energy input than a coal-fired EGU with or

without partial CCS. Furthermore, cooling water requirements are relatively large for biomass-

fired EGUs because of their low efficiency compared to coal-fired EGUs. This results in larger

water requirements compared to low rank-fired EGUs and circulating fluidized bed (CFB)

EGUs. After considering these factors, the EPA does not consider biomass-fired generation to be

interchangeable with coal-fired generation and is therefore not an appropriate benchmark for

comparison.

Due to the EPA not fully evaluating these factors in the 2015 Rule, the EPA is

withdrawing the previous determination that the LCOE of new nuclear and biomass are

appropriate benchmarks on what represents a reasonable cost for a new coal-fired EGU.

b. Increase in LCOE

62 In the CCS costing Excel file supporting the CCS costing TSD for the 2018 Proposal, the Agency listed the costs of a subbituminous-fired SCPS without CCS and with 26-percent partial CCS as $3,220/KW and $4,180/kW respectively. This is a 30-percent increase in capital costs.


Some commenters said the EPA is correct that even if the extremely high cost of new

nuclear generation were an appropriate point of comparison, the cost of a new coal-fired EGU

with partial CCS would not be reasonable.

Other commenters stated that, if the EPA uses the LCOE of either new nuclear generation

or that of new biomass-fired generation as a benchmark, as it did in the 2015 Rule, the Agency

must find the costs of a new coal-fired EGU with partial CCS to be reasonable even using what

the commenters described as an arbitrarily inflated cost estimate, as presented in the 2018

Proposal. According to the commenters, this cost estimate falls within the range of current

LCOEs for new nuclear generation and biomass-fired generation because, according to the 2015

Rule, LCOEs range from $87/MWh to $132/MWh for new nuclear generation and from

$87/MWh to $116/MWh for new biomass-fired generation. Commenters also stated that the

Agency does not explain what it considers to be an “appropriate” LCOE range for new

generation facilities and does not explain whether it considers the costs of new nuclear power, a

supposedly reasonable comparison for new, large, base load generation, to be unreasonable.

Commenters said that the EPA does not show how it supports reversing its position that the cost

of implementing partial CCS is reasonable, in light of the fact that the EPA’s proposed

$105.4/MWh cost figure is in the middle of the previous range for partial CCS—from $92/MWh

to $117/MWh—that the EPA still cites.

The EPA disagrees with commenters that since the 2018 Proposal estimated LCOE of a

new coal-fired EGU with partial CCS is lower than the upper bound LCOE of new nuclear

generation it should be considered to have reasonable costs. The 2018 Proposal presented the

LCOE of a new coal-fired EGU with partial CCS without the capital cost uncertainty factor that

was included in the 2015 Rule. Table 3 shows the LCOE values of coal with partial CCS from


the 2018 Proposal with and without the capital cost uncertainty factor. It also shows the LCOE

values for nuclear and biomass from the 2015 Rule with and without the capital cost uncertainty

factor.

TABLE 3. 2018 PROPOSAL LCOE WITH AND WITHOUT UNCERTAINTY FACTORS1

Generation Technology LCOE Without Uncertainty Factor

LCOE Range With Uncertainty Factor

SCPC + ~16% CCS (bit) 105.4 97.2–122.1SCPC + ~ 26% CCS (low rank) 122.8 112.0–144.2Nuclear (EIA) 94.1 87–115Nuclear (Lazard) 102.8 91–132Biomass (EIA) 99.2 94–113Biomass (Lazard) 96.9 87–116

1 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 from EIA. The Lazard analysis reports low and high end costs based on uncertainty in capital, fixed, variable, and fuel costs. The Lazard without uncertainty LCOE values were estimated using the average capital and fixed costs when the EIA capital costs uncertainty factors are applied to the Lazard values. The EPA estimated the variable and fuel costs by taking the average of the low and high Lazard values.

Table 3 shows that without uncertainty factors, the LCOE of coal with partial CCS

exceeds the cost of nuclear and biomass.63 In addition, the 2018 Proposal high end LCOE of the

bituminous case ($122.1/MWh) and the subbituminous case ($122.8/MWh) both exceeded the

high end of the EIA projected nuclear costs ($115/MWh). Further, the high end of the

subbituminous estimates ($144.2/MWh) also exceeds the high end of the Lazard estimates

($132/MWh).64 Therefore, when uncertainty factors are accounted for, the costs of partial CCS

exceed those of nuclear and would not be considered as a reasonable cost BSER, even if nuclear

were an appropriate benchmark for reasonable costs.

In the 2015 Rule, the EPA relied on multiple sources of information to determine the

LCOE of the various generation technologies. Because the NETL Baseline Reports have costing

63 The 99-percent confidence emissions rate is generally close to the maximum 12-operating-month emissions rate and represents the long-term achievable standard.64 The EPA selected the NETL supercritical EGUs as the baseline because they have the lower non-CCS LCOE than ultra-supercritical EGUs.


and performance information for newly constructed coal-fired EGUs (with and without CCS) but

not nuclear and biomass-fired generation, the EPA used the AEO 2015 and Lazard reports for the

nuclear and biomass LCOE. However, the EPA did not evaluate the underlying financial

assumptions in the AEO and Lazard reports to assure they are consistent with the assumptions in

the 2015 NETL Baseline Report. Nor did the EPA do so in the 2018 Proposal. Therefore, the

LCOE comparisons of coal-fired EGUs with and without CCS nuclear and biomass generation in

both the 2015 Rule and 2018 Proposal are flawed in this respect. In this final rule, the EPA has

concluded that to evaluate the relative LCOE of newly constructed coal-fired EGUs with and

without partial CCS to other generating technologies, it is important to use the same general

financing structures for all the technologies. As described later, the use of inconsistent financial

assumptions can result in significantly different LCOEs, even when the underlying costs are

similar. Accordingly, in this final rule, the EPA is making adjustments to the LCOEs reported in

the various sources to account for the different financing assumptions.

In addition, in this final rule, the EPA is updating the relevant LCOEs using available

data. Specifically, to update the cost of a newly constructed coal-fired EGU with and without

CCS, the EPA used the 2019 NETL Baseline Report. Compared to the 2015 NETL Report that

the EPA used in the 2015 Rule and the 2018 Proposal, the 2019 NETL Report updated costing

and performance information, including a revised scaling relationship for partial CCS relative to

full CCS, which, taken by itself, would result in partial CCS being relatively more expensive

than in the 2015 NETL Baseline Report. The 2019 NETL Report also increased the size of the

model PC plant from 550 MW to 650 MW, which improves efficiency and due to economics of

scale reduces costs of partial CCS. The 2019 report also revised financing assumptions,

including incorporating revised income tax rates and switching the basis of the methodology


from a project-focused calculation to a corporate-focused calculation. These financing revisions

make capital less expensive and reduce the costs of coal-fired EGUs and CCS—for example,

these revisions alone reduces the LCOE of the bituminous-fired SCPC with partial CCS by

approximately 17 percent.65 These revised assumptions make it impossible to directly compare

the LCOE based on the 2019 NETL Baseline Report to the LCOE based on the 2015 NETL

Baseline Report.66

As noted above, in the absence of a NETL description of the LCOE for newly

constructed nuclear and biomass-fired generation, the EPA relied on a AEO 2020 study with that

information for this final rule. To evaluate the cost for newly constructed nuclear generation and

a newly constructed biomass-fired EGU, the EPA used the detailed costing information (capital

and operating costs) for the AEO 2020 nuclear and biomass using the 2019 NETL Baseline

Report coal-fired EGU capital charge factor and the factor used to convert the total overnight

costs to total as spent capital.67 Using these two factors assures consistent financial assumptions

for the LCOE comparisons. To confirm this approach results in comparable values, the EPA used

to same approach for the AEO 2020 ultra-supercritical coal without CCS. In addition, for the

reasons explained above, the EPA included in the LCOE for certain coal-fired generation a T&S

cost adjustment and a capacity factor adjustment, although the EPA also determined that LCOE

without those two adjustments. Table 4 shows the predicted LCOE with and without the T&S

cost and capacity factor adjustments.

TABLE 4. PREDICTED COST

65 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-2013-0495-11772.66 The coal-by-wire approach is based on the fact that electricity demand in states that may not have geologic sequestration sites may be served by coal-fired electricity generation built in nearby areas with geologic sequestration, and this electricity can be delivered through transmission lines.67 U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition, September 2015, available at https://www.netl.doe.gov/sites/default/files/2018-10/ATLAS-V-2015.pdf.


Technology1LCOE2

(2018$/MWh)Amended LCOE3

(2018$/MWh)NETL Subcritical PC (bit) 65.4 66.6NETL Supercritical PC (bit) 65.9 -NETL SCPC + ~16-percent CCS (bit) 84.6 94.0NETL Supercritical PC (low rank) 67.5 -NETL Ultra-supercritical PC (low rank) 69.0 68.6NETL SCPC + ~ 26-percent CCS (low rank) 92.9 108.3NETL NGCC 44.2 -AEO ultra-supercritical PC 67.5 -AEO Advanced Small Modular Nuclear 84.7 -AEO Biomass 98.6 -

1 The EPA used the AEO 2020 small modular nuclear costs because the Nuclear Regulatory Commission approved the first small modular nuclear design on September 2, 2020, and the EPA considers these costs the most representative of potential new nuclear generation. 2 Assumes 85-percent capacity factor for coal-fired EGUs and $10/tonne T&S. Nuclear, biomass, and NGCC capacity factors are 90 percent, 83 percent, and 85 percent, respectively. The AEO transmission costs are not included in the calculated LCOE. Assuming an 85 percent capacity factor increases the cost of nuclear to $86.9/MWh and decreases the cost of biomass to $97.2/MWh. The nuclear decommissioning trust fund is intended to cover the decommissioning of nuclear EGUs and adds between an additional $1 to $2 per MWh to the LCOE of nuclear. However, the EPA did not include the production tax credit of $1.8/MWh that would offset decommissioning costs. Therefore, the inclusion of decommissioning costs does not change the EPA’s conclusion with regards to if the LCOE of coal with partial CCS is reasonable. 3 Capacity factors for coal with CCS adjusted based on variable operating costs and T&S costs adjusted based on amount of captured CO2.

Table 4 shows that the EPA’s LCOE estimate for an ultra-supercritical facility fired with

subbituminous coal based on the 2019 NETL Baseline Report match well with the LCOE

estimate based on the 2020 AEO report when the same financing assumptions are used.

Therefore, the AEO nuclear and biomass LCOE estimates should be suitable for comparison to

the NETL-based LCOE for coal-fired EGUs as well. As Table 4 indicates, the NETL-based

LCOE estimates for both the bituminous and subbituminous SCPC without CCS are less

expensive than nuclear. However, the NETL-based LCOE estimates for both the bituminous and

subbituminous SCPC with partial are as expensive or more expensive than nuclear, even without

accounting for scaling of T&S costs or impacts on capacity factors. The LCOE of the bituminous

SCPC with partial CCS is essentially equivalent that for nuclear generation, and the LCOE for

subbituminous SCPC with partial CCS is 10 percent higher than that for nuclear. When T&S


scaling and capacity factor impacts are accounted for, those costs are 11 percent and 28 percent

higher, respectively. This comparison further supports the EPA’s conclusion that even if the

LCOE for a new nuclear unit is a reasonable comparison metric, the costs of a new coal-fired

EGU with partial CCS are unreasonable. As stated previously, the LCOE of a biomass-fired

EGU is not a good metric for a reasonable LCOE of a coal-fired EGU with partial CCS.

However, even it were, the LCOE of subbituminous SCPC with partial CCS is 10 percent higher

than that for a biomass-fired EGU supporting that a BSER based on the use of partial CCS is

unreasonable.

In addition, while EOR opportunities may be available for some potential new EGUs,

sales of captured CO2 for EOR use cannot offset the high costs of CCS. Assuming a sale price of

$22 per tonne68—and using the 2019 NETL Baseline Report T&S and capacity factor—the

LCOE of a bituminous and subbituminous-fired SCPC with partial CCS are $81.8 and

$87.4/MWh, respectively. As shown in Table 4, while the LCOE of a bituminous-fired SCPC

with partial CCS would be less than that for nuclear, the LCOE of a subbituminous-fired SCPC

with partial CCS is still greater than the LCOE for nuclear. In both cases, the costs of partial

CCS significantly increase the LCOE of coal compared to a coal-fired EGU without CCS and

while selling captured CO2 for use in EOR can offset operating costs, including lowering the

incremental operating costs to lower than a coal-fired EGU without CCS, it does not offset the

increase in capital necessary to construct a new EGU with CCS.

3. Capital Costs Comparison

This section summarizes the discussion from the 2018 Proposal regarding the

reasonableness of the increase in capital costs for a new coal-fired EGU associated with a BSER

68 U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition, September 2015, available at https://www.netl.doe.gov/sites/default/files/2018-10/ATLAS-V-2015.pdf.


based on the use of partial CCS. The section then summarizes comments received on how the

increase in capital costs were determined in the 2018 Proposal and whether the increase in

capital costs from a BSER based on the use of partial CCS are reasonable, and provides the

EPA’s response to those comments. Since the increase in capital costs is dependent on the

percentage of CCS required, these comments include those addressing whether it is appropriate

to use the 2015 NETL Baseline Report emissions rate for coal-fired EGUs without CCS to

determine the percent of CCS required to comply with the emissions standard in the 2015 Rule.

The section further describes the EPA’s conclusion that, when the increase in capital costs due to

partial CCS are calculated using the 2019 NETL Baseline Report for both bituminous and low

rank-fired EGUs, the costs are higher than the capital costs in previous rulemakings. Therefore,

the EPA is withdrawing the previous determination that the increase in capital costs associated

with a BSER based on the use of partial CCS is reasonable. This is especially true when the

current, limited ability of the industry to secure capital and pass costs on the consumers is taken

into consideration.

a. 2018 Proposal

In the 2015 Rule, the EPA determined that an increase in the capital cost of slightly more

than 20 percent from the use of partial CCS—the identified BSER—was reasonable when

compared to previous CAA rulemakings affecting the power sector. In the 2018 Proposal, the

EPA reevaluated the increase in capital costs for partial CCS calculated in the 2015 Rule and

proposed to find that is not reasonable for several reasons. First, the EPA explained that the

percentage increases in capital costs calculated for previous coal-fired EGU NSPS rulemakings

were based on lower baseline capital costs. The capital costs for EGUs at the time of those

rulemakings did not include environmental controls that are currently required for new coal-fired


EGUs. When environmental controls are included in the baseline, as they were in the 2015 Rule,

at the same percentage increase in capital costs, the absolute costs are much higher. When the

costs of environmental controls are not included in the baseline for coal-fired EGUs with partial

CCS, the increase in capital costs was estimated to be 27 percent, as compared to 22 percent

when the costs of environmental controls are included in the baseline costs.

Second, the EPA also noted that even without accounting for the different cost basis, the

percentage increase in capital costs was higher for the 2015 Rule than previous EGU NSPS

rulemakings. The EPA further noted that just because the industry was able to absorb a certain

percentage increase in cost due to pollution control in the past, this does not necessarily mean the

industry could do so in 2020. The utility sector is markedly different in 2020 and new coal-fired

EGUs cannot necessarily pass along their capital costs as easily as they could during the time of

the rulemakings cited in the 2015 Rule as precedent for what is reasonable. In addition, the EPA

noted that directly comparing a GHG NSPS rulemaking to prior NSPS rulemakings to evaluate

reasonableness is challenging because those prior rulemakings generally concerned multiple

pollutants and adopted multiple requirements based on multiple control technologies. 83 FR

65440 through 41.

Based on these factors, the EPA proposed to find that the percentage increase in capital

costs of partial CCS are higher than the percentage increase in capital costs previously

considered reasonable.69 In addition, the EPA proposed to find that developers of new coal-fired

EGUs cannot pass the increase in capital costs to end users as easily as they could in the

rulemakings cited in the 2015 Rule as precedent for what is a reasonable increase in capital costs.



Therefore, the EPA proposed to find that the increase in capital costs due to partial CCS are not

reasonable. 83 FR 65441.

b. Increase in Capital Costs

As stated previously, in the 2018 Proposal, the EPA proposed to find that when the costs

of environmental controls are considered, the percentage increase in capital costs of partial CCS

are higher than the percentage increase in capital costs previously considered reasonable. In

addition, the EPA proposed to find that developers of new coal-fired EGUs cannot pass the

increase in capital costs to end users as easily as they could in the rulemakings cited in the 2015

Rule as precedent for what is a reasonable increase in capital costs.

Some commenters agreed with the EPA that the increase in capital costs is not

reasonable. Other commenters disagreed, contending that the EPA’s proposed reversal of its

evaluation of capital costs in the 2015 Rule is arbitrary in part because the Agency never

explains what level of capital cost increase (on an absolute or relative basis) it considers to be

acceptable. They explained that the Agency’s cursory discussion of absolute- and relative-cost

metrics does not address the relevant statutory question, which is whether partial CCS entails

“exorbitant” costs that exceed the limits courts have articulated for a CAA section 111 BSER.

Here, the commenters concluded, the EPA has failed to provide a reasoned explanation for

disregarding its previous finding. They also stated that the CCS-related capital costs represent

just 0.2 percent of total expected capital expenditures for investor-owned utilities in 2019 alone,

and 0.06 percent of total revenues in 2017. They said that the EPA has frequently considered

comparisons to overall industry capital expenditures and revenues when evaluating costs under

CAA section 111.


These commenters said evaluating a pollution control system’s costs in absolute terms is

unreasonable, and that the economic value of the project will be determined by looking to the

projected return on investment, which is expressed as a percentage of the investment. Whether a

pollution control system is excessively costly is properly determined by considering how much

the system will reduce the expected return on investment (i.e., by considering the percentage

increase in project costs). They added that, for this reason, courts have traditionally looked at the

percentage increase in the project costs in evaluating whether the costs of a pollution control

system are reasonable (citing Portland Cement Association v. Ruckelshaus, 486 F.2d 375 (D.C.

Cir. 1973) at 387). The commenters also argued that allowing a power plant to forego cost-

effective control requirements for one dangerous pollutant simply because a new plant owner

already faces costs to control other harmful pollutants contradicts the mandate of the CAA.

In both the 2015 Rule and the 2018 Proposal, the EPA used the NETL Baseline Reports

to determine the percentage increase in capital costs for a bituminous-fired SCPC using partial

CCS. For this final action, the EPA has updated the calculation of the percentage increase in

capital costs due to CCS based on information in the 2019 NETL Baseline Report. Specifically,

the increase in capital for full CCS relative to the cost of a bituminous-fired SCPC without CCS

increased from 74 to 80 percent. In addition, a significant difference in the 2019 NETL Baseline

Report relative to the 2015 NETL Baseline Report, which was used both the 2015 Rule and the

2018 Proposal, is the scaling relationship for partial CCS. Compared to NETL’s previous partial

capture estimates, the costs at low capture rates increased significantly in the 2019 updates. For

example, the increase in capital costs of 16-percent CCS on a bituminous-fired SCPC using the

2015 NETL Baseline Report is 22 percent. However, the increase in those capital costs using the

updated 2019 NETL Baseline Report is 41 percent. This percentage increases in capital costs is


double the percentage increase in capital costs that the EPA used in the 2015 Rule to evaluate

what is reasonable.

Additionally, in both the 2015 Rule and the 2018 Proposal the EPA used the increase in

capital costs for only a bituminous-fired EGU when determining if the percentage increase in

capital costs is reasonable. Since the percentage of partial CCS required to comply with the

emissions standard in the 2015 Rule is greater for a subbituminous-fired EGU, the percentage

increase in capital for that type of EGU is also larger. Based on the 2019 NETL Baseline Report,

the percentage increase in capital costs for a subbituminous-fired SCPC using partial CCS to

comply with the emissions standard in the 2015 Rule is 45 percent.70 Finally, if the costs of

environmental controls are not included in the baseline capital costs (which is consistent with the

rulemakings the Agency cited as precedent for a reasonable percentage increase in capital costs),

the percentage increase in capital costs due to a BSER based on partial CCS increases to 45

percent and 49 percent for the bituminous-fired SCPC and subbituminous-fired SCPC,

respectively.

These percentage increases in capital costs for both the bituminous-fired (41 percent) and

the subbituminous-fired (45 percent) EGUs are double the percentage increase in capital costs

that the EPA used in the 2015 Rule to evaluate what is reasonable. The EPA also notes that even

the 2015 NETL Baseline Report referenced in the 2018 Proposal indicated an increase in capital

costs higher than in previous EGU NSPS rulemakings. 83 FR 65440. Consistent with the

rationale provided in the 2018 Proposal, the EPA has determined that the percentage increase in

capital costs is greater than what was calculated in the 2015 Rule and greater than what has been

determined as reasonable in previous EPA rulemakings. Therefore, the EPA is withdrawing the



previous determination that the increase in capital costs from partial CCS is reasonable. It is not

necessary at this time to determine what percentage increase in capital would be reasonable

because the EPA has already found that the LCOE increase from partial CCS is not reasonable.

Even if the percentage increase in capital costs were consistent with previous rulemaking,

the EPA did not evaluate the relative impacts of the increase in capital in the 2015 Rule

compared to the previous EPA rulemakings. Specifically, as noted in the 2018 Proposal,

developers of coal-fired EGUs cannot pass along the higher capital costs to consumers without

impacting their competitiveness when compared to alternate forms of generation. 83 FR 65441.

In addition, the EPA also notes that comparisons of the percentage increase in capital costs

across industries is not necessarily relevant because capital costs can comprise significantly

different portions of overall costs. For example, while capital costs account for 43 percent of the

LCOE of a newly constructed bituminous-fired SCPC without CCS, they represent only 22

percent of the LCOE for a newly constructed NGCC EGU without CCS. Therefore, the impact

of the same percentage increase in capital costs on overall costs would have a larger impact on

the LCOE for a newly constructed coal-fired EGU than that for a newly constructed NGCC

EGU, which disadvantages developers of coal-fired EGUs against one of their primary

competitors. Finally, even if there are circumstances where the capital costs could be passed on

to consumers, the EPA did not evaluate if available capital restrictions could limit the ability to

construct a new coal-fired EGU with partial CCS.

While the EPA has compared rule costs relative to the overall expenditures of an

industry, in this case that approach is not relevant. Costs must be reasonable on an individual

project basis, not just considering the overall costs to the industry; otherwise, no company will

undertake the project. Further, as stated in the 2018 Proposal, the Agency expects few, if any,


coal-fired EGUs will be built in the foreseeable future, which means that overall costs to the

industry will be minimal regardless of the estimated individual project costs.

4. Baseline Emissions Rate

As described previously, assuming the baseline emissions rate used in the 2015 Rule is

valid, both the increase in LCOE and increase capital costs as the EPA recalculates them are too

high to be considered reasonable. In addition, as noted by commenters, the baseline used in the

2015 Rule might not be valid. If the 2015 Rule baseline underestimated the percent CCS required

to comply with the emissions rate in the 2015 Rule, the actual increase in LCOE and capital costs

would be even higher. This section describes the comments and the EPA’s response to those

comments.

To determine the cost to comply with the emissions rate in the 2015 Rule first involves

determining the required percentage of CCS to meet the specified emissions rate. Establishing a

baseline emissions rate for a newly constructed coal-fired EGU without partial CCS is an

important component of the partial CCS analysis because it establishes the starting point for

determining the percentage of CCS required to comply with the NSPS. The NSPS in the 2015

Rule and the 2018 Proposal are both based on a 12-operating month emissions standard. Since

the NSPS is a “never-to-exceed” standard, the baseline emissions rate used to determine the

percentage of partial CCS required for compliance with the NSPS should be the maximum

anticipated 12-operating month emissions rate (i.e., the 99 percent confidence emissions rate71).

Since the maximum 12-operating month emissions rate accounts for variability, it will be higher

than the overall average emissions rate. As noted above, in both the 2015 Rule and 2018

Proposal, the EPA used the design emission rates from the NETL Baseline Reports to determine

71 NETL determined water stress by comparing projected water requirements of the energy industry with projected water availability considering all sources and uses of water.


the percentage of partial CCS required to comply with the emission standard in the 2015 Rule.

The EPA’s cost analysis focused on partial CCS systems designed to remove approximately 16

and 26 percent of the CO2 emitted from EGUs firing bituminous and low rank coals,

respectively.72 However, the emission rates listed in the NETL Baseline Reports are more

representative of the overall average than the maximum 12-operating month emissions rate.

Therefore, the EPA underestimated the costs of complying with the emission standard in the

2015 Rule.

Some commenters, arguing that the Agency is underestimating the cost of a BSER based

on the use of partial CCS, claimed that a new coal-fired EGU would actually need to capture

significantly more of its CO2 emissions in order to meet the emission standard than the EPA

assumed in the 2015 Rule. They further stated that the EPA’s assumed capture rates of 16 and 26

percent were based on unrealistic pre-capture baseline emission rates derived from an

engineering report (the 2015 NETL Baseline Report) discussing hypothetical plant designs that

acknowledges that “[a]ctual average annual emissions from operating plants are likely to be

higher” than the cited rates. They said using more realistic baseline emission rates, a partial CCS

system for a new coal-fired EGU would need to be designed for a greater degree of CO2 capture

to meet the emission standard in the 2015 Rule, resulting in greater costs than the EPA used in its

analysis.

The EPA acknowledges that the points raised by commenters also call into question

whether the 2019 NETL Baseline Report design emissions rates are appropriate baselines for

determining the percentage of partial CCS necessary to comply with the emissions standard in

72 National Energy Technology Laboratory. Assessing the Energy-Water Nexus: Providing New Technologies for Efficient Energy Production. Slides from August 13, 2018, ACEC Summer Meeting Environment & Energy Committee. https://www.acec.org/default/assets/File/DOE%20NETL_Energy-Water%20Nexus_ACEC_AUG%2013%202018_final.pdf.


the 2015 Rule. To evaluate an appropriate baseline emissions rate, the EPA therefore reviewed

emissions data for several of the best performing domestic EGUs. Based on this analysis, the

EPA determined that the emission rates for coal-fired EGUs in the 2019 NETL Baseline Report

are more representative of the overall average than the 99-percent confidence 12-operating

month emissions rate for well-operated EGUs with similar design criteria. Because the NSPS is a

continuous compliance, never-to-exceed 12-operating month standard, an owner/operator of a

new coal-fired EGU would have to design the partial CCS based on the 99-percent confidence

standard. Therefore, the percentage of partial CCS and corresponding capital costs that a

developer of a new coal-fired EGU would have to use to guarantee compliance with the emission

standard from the 2015 Rule could be higher than the EPA’s analysis. While the costs of partial

CCS may be greater than those used by the EPA, these costs have already been determined to be

unreasonable, so it is not necessary to evaluate these costs. Similarly, partial CCS costs would

also be higher for small EGUs where the supercritical steam turbines are not economically

available and for coal refuse-fired EGUs due to the higher inherent CO2 emissions rate than the

rate used in the EPA’s analysis. However, because it has already been determined that the costs

of CCS are unreasonable for large coal-fired EGUs, it is not necessary to evaluate these costs.

For additional details, please see the CCS costing TSD available in the docket.

The EPA also failed to evaluate the impact of startup and shutdown on the required

design emissions rate. CCS equipment takes time to begin operating and during that time no CO2

is captured. Exhibit 2-1 of the 2019 NETL Baseline Report shows the necessary design

emissions level to maintain an emissions rate of 1,400 lb CO2/MWh-gross for various annual

startup and shutdown assumptions. Based on the NETL example, an bituminous-fired EGU with

10 startup and shutdown cycles would need a design emissions rate of 1,362 lb CO2/MWh-gross


to maintain an average emissions rate of 1,400 lb CO2/MWh-gross. Based on design emission

rates, this would require 18.2 percent CCS—increasing costs beyond what the EPA has already

determined is unreasonable.

B. Geographic Scope of Suitable Geologic Sequestration Sites

Whether partial CCS meets the CAA section 111(a)(1) requirement of being “adequately

demonstrated,” and whether the 2015 Rule’s standard of performance meets the CAA section

111(a)(1) requirement of being “achievable” by EGUs based on the application of partial CCS,

depend in part on the geographic scope of suitable GS sites. Therefore, as part of the 2015 Rule,

the EPA performed a geographic analysis73 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 EOR operations; information on existing and probable, planned, or under-

study CO2 pipelines; and areas within 100-km (62-mile) of locations with sequestration potential.

The EPA selected the distance of 100 km because it was consistent with the assumptions

underlying the NETL cost estimates for transporting CO2 by pipeline. The EPA noted that 39

states have GS sites (3,807,750 square miles) and concluded that potential GS sites were widely

available.

In the 2018 Proposal, the EPA reevaluated the appropriateness of including unmineable

coal seams as adequately demonstrated sequestration sites and performed a more comprehensive

evaluation of water use requirements for partial CCS than had been done in the 2015 Rule. Based

on the additional analysis, the Agency proposed that CCS is not as widely geographically

available as found in the 2015 Rule. 83 FR 65444 (December 20, 2018).

73 National Energy Technology Laboratory. 2018 Water Brief for Fossil Energy Applications. Slides from June 20, 2018. https://netl.doe.gov/sites/default/files/2019-04/2018%20Water%20Brief_Final.pdf.


In this action, the Agency is rescinding the 2015 determination that CCS is widely

geographically available because of uncertainty regarding the use of unmineable coal seams for

GS and issues with the coal-by-wire approach74 that were not adequately considered in the 2015

Rule. Because the 2015 Rule erred in its conclusion that CCS is widely geographically available,

the Rule did not properly find that partial CCS meets the CAA section 111(a)(1) requirement of

being “adequately demonstrated” or that the Rule’s standard of performance meets the CAA

section 111(a)(1) requirement of being “achievable” by EGUs based on the application of partial

CCS. This section describes the EPA’s consideration of the geographic availability of CCS.

1. Availability of Sequestration Sites

In the 2018 Proposal, the EPA explained that it had updated its analysis of geographic

availability and that new information led it to propose revisions to the findings in the 2015 Rule.

In the proposal, the EPA used updated information from NETL,75 new data from the Greenhouse

Gas Reporting Program (GHGRP) on active EOR operations (see 40 CFR part 98, subpart UU,

Injection of Carbon Dioxide, 2011-2017 data), and updated information on existing CO2

pipelines based on U.S. Department of Transportation data along with locations of pipelines that

are probable, planned, or under study, in order to update its assessment of the geographic extent

of potential GS sites. The EPA noted that NETL data provide a high-level overview of

prospective resources across the United States.76 NETL does not take into account site-specific

74 Badr, L., Boardman, G., & Bigger, J. (2012). Review of water use in US thermoelectric power plants. Journal of Energy Engineering, 138(4), 246-257. https://ascelibrary.org/doi/10.1061/%28ASCE%29EY.1943-7897.0000076.75 Tenaska Trailblazer Partners LLC, Cooling Alternatives Evaluation for a New Pulverized Coal Power Plant with Carbon Capture, Report to the Global CCS Institute, August 2011, p. 2, available at https://www.globalccsinstitute.com/archive/hub/publications/24367/cooling-study-report-2011-09-06-final-w-attachments.pdf.76 International CCS Knowledge Centre, The Shand CCS Feasibility Study Public Report, November 2018, p. 12, available at http://ccsknowledge.com/pub/documents/publications/.Shand%20CCS%20Feasibility%20Study%20Public%20Report_NOV2018.pdf.


technical, economic, or regulatory constraints in its potential sequestration assessment.77 This

type of information is developed on a case-by-case basis. The EPA also noted that saline storage

has not yet been demonstrated to be available, both from a geographical perspective as well as

economically, at all locations. While these considerations did not result in the EPA updating its

estimate of prospective resources, the EPA noted that technical, economic, and regulatory

feasibility drive the actual availability of GS sites. In addition, the EPA explained that additional

research using larger scale and longer duration tests in unmineable coal seams is needed to

improve the understanding and modeling of CO2 storage in coal seams, and, therefore, proposed

to remove unmineable coal seams from potential GS sites for the availability analysis. In total,

these proposed updates using more recent NETL data and removing unmineable coal seams from

the analysis would reduce the amount of areas amenable to GS by approximately 4 percent. See

83 FR 65441 through 65442.

Some commenters argued that CCS, partial or otherwise, is not an appropriate basis for a

CAA section 111 standard because it is subject to geographic constraints that prohibit its

application—and, thus, prohibit construction of new sources—in many parts of the country.

These commenters asserted that because an NSPS is nationally applicable (i.e., applying to every

new source in the category no matter where it is built), the BSER on which that standard is based

must be adequately demonstrated and available for application anywhere throughout the country.

They asserted that CCS is distinct from other emission controls in that its application requires

that suitable geological formations for underground storage of captured CO2 be available nearby,

but that many parts of the country have no assessed capacity for CO2 storage, and even those that

do may not be adequate for large-scale CO2 sequestration when examined on a site-by-site basis.

77 Barker, B. (2007). Running dry at the power plant. EPRI Journal. https://www.energy.gov/ne/downloads/running-dry-power-plant.


They added that sequestration and storage opportunities are available only at plant sites near CO2

transport pipelines or geologically acceptable repositories, such as deep saline reservoirs, that

these potential repository sites are not evenly distributed throughout the U.S., and that as a result,

many locations throughout the country lack suitable geological conditions for carbon storage.

Other commenters stated that the EPA’s claim that alleged geographic unavailability

justifies eliminating partial CCS as BSER is arbitrary and unsupported. They noted that the

proposal raises questions about whether geologic sequestration in sedimentary saline formations

is “adequately demonstrated,” but that the information the EPA cites in the 2018 Proposal

regarding the range and capacity of suitable storage locations in the U.S. either confirms or

strengthens the conclusions in the 2015 Rule in all material respects. They added that the EPA’s

proposed conclusion that the limited number of areas where partial CCS may not be available

renders partial CCS not “adequately demonstrated” appears to be based on the EPA’s belief that

a BSER must be capable of being implemented at literally any location in the country, but they

argue, citing the EPA’s statements in the 2015 Rule, that nothing in CAA section 111 requires

the EPA to ensure that any new source at any geographic location could comply with the

standards of performance for new sources. They argued that the CAA does not require that

economic and technical analyses be performed for every basin and potential project in order to

demonstrate that GS is available for the source category.

The EPA disagrees that the updated information and analysis further supports the

conclusion in the 2015 Rule; GS is not as widely geographically available as found in the 2015

Rule. As stated above, the EPA updated its assessment of GS potential since the 2015 Rule. The

key elements of this update were to incorporate new data, as described above, and remove

unmineable coal seams from potential sequestration estimates based on the conclusion that the


technologies associated with GS at unmineable coal seams are still being developed. This

updated analysis shows a reduction of approximately 4 percent of estimated storage resources.

The EPA agrees with commenters that, from the standpoint of any particular EGU, actual

GS availability is dependent on suitable sequestration sites and that sites need to be examined on

a site-by-site basis. In addition to the updated analysis conducted for sequestration potential, the

EPA also evaluated related or underlying information regarding GS availability. 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 U.S.78 This assessment represents the

fraction of pore volume of porous and permeable sedimentary rocks available for CO2 storage

and accessible to injected CO2 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—like the

construction of an EGU in the first instance—depends on site-specific conditions, including 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 U.S. makes sequestration potential in these reservoirs relatively

78 Zhai, H., & Rubin, E. S. (2010). Performance and cost of wet and dry cooling systems for pulverized coal power plants with and without carbon capture and storage. Energy Policy, 38(10), 5653-5660. https://www.sciencedirect.com/science/article/pii/S0301421510003848?via%3Dihub.


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. Similar limitations also exist for

areas of potential storage in deep saline formations identified in the Atlas, and these formations

are relatively less well understood. Thus, although the areas of potential storage in deep saline

formations identified in the Atlas are large, as a practical matter, the extent of available storage

can be expected to be smaller.

2. Availability of Water Resources

Currently available amine-based solvent capture systems require water for process

makeup and cooling. As part of the 2015 Rule, multiple commenters expressed concerns that the

EPA’s determination that partial CCS was the BSER was inappropriate because of increased

water consumption impacts and geographical (or other) water availability/scarcity issues limiting

or precluding CCS implementation. The EPA acknowledged that, similar to other air pollution

controls, such as a wet flue gas desulfurization (FGD) scrubber, post-combustion amine-based

capture systems result in increased water consumption. However, the EPA evaluated the issue

and found the water use requirements to be manageable.

In the 2018 Proposal, the EPA noted that in the 2015 Rule the Agency evaluated only the

percentage increase in water use at a model coal-fired EGU that relies on bituminous coal. This

model plant was already relatively water intensive as it used a wet scrubber for control of sulfur

dioxide (SO2) emissions and a cooling tower for steam condensation. As to this type of coal-fired

EGU, in the 2015 Rule, the EPA said that a 6.4-percent increase in water use due to partial CCS

was acceptable and would not pose an unreasonable burden to a developer of a new coal-fired

EGU. 80 FR 64592 and 64593. In the 2018 Proposal, the EPA evaluated the percentage water

increase for a subbituminous coal-fired EGU. According to the low-rank NETL Baseline Report


(“Cost and Performance Baseline for Fossil Energy Plants Volume 3b: Low Rank Coal to

Electricity: Combustion Cases,” DOE/NETL–2011/1463 (March, 2011)), a new subbituminous-

fired EGU uses less water because it uses a spray dryer for control of SO2 emissions and a hybrid

cooling tower for steam condensation. The EPA estimated the percentage increase in water use

due to partial CCS for this type of coal-fired EGU to be 28 percent. The EPA noted that the

percentage increase for an EGU using dry SO2 scrubbing and/or a dry cooling tower would be

even more significant. 83 FR 65443.

In the 2018 Proposal, to estimate water availability, the EPA reviewed annual average

precipitation totals. 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 precipitation amounts shows considerable overlap with areas of the country with

sequestration sites. This raises a concern that many sequestration sites might not have sufficient

water resources to operate CO2 capture equipment. This, in combination with the EPA’s

proposed determination that its earlier understanding of the scope of GS site availability was an

overestimation (by some 4 percent), led the EPA, in the 2018 Proposal, to propose to revise its

2015 findings and make a new determination that the overall geographic availability of CCS is

too limited to be considered to be BSER. According to the 2018 Proposal, the additional water

requirements for CCS would limit the geographic availability of potential future EGU

construction to areas of the country with more plentiful water resources. 83 FR 65442 through

65444.

Commenters stated that, in determining BSER, the EPA must ensure that standards do

“not give a competitive advantage to one State over another in attracting industry.” They noted


that the Court has observed that “an efficient water intensive technology … might be ‘best’ in the

East where water is plentiful, but environmentally disastrous in the water-scarce West.” Sierra

Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981) (a water intensive technology could not be

selected as the BSER when it would have had the effect of precluding construction of new

sources in states that lack the water necessary to allow compliance with the standard at a

reasonable cost). These commenters added that CCS technology is distinct from other emission

controls in that its application is water-intensive and may not be feasible to implement in

relatively dry parts of the country. They concluded that identifying CCS as the BSER would

effectively force all new coal-fired EGUs to employ water-intensive control technology, thus

making construction infeasible in arid parts of the country.

Other commenters stated that the 2018 Proposal provides no information to indicate that

water resources in any part of the country are so constrained as to prevent the construction of

new coal-fired EGUs with partial CCS. They added that the Proposal’s analysis of water

requirements associated with partial CCS systems assumes a dry cooling baseline found at just a

handful of EGUs in the U.S., overlooks potential technologies and techniques that could be used

to mitigate water demand at CCS-equipped units, and ignores the fact that dry cooling has lower

absolute water requirements than the EPA considered in the 2015 Rule. Commenters also stated

that CAA section 111 does not require that a BSER be universally available or be available at

similar costs across the country and that the EPA failed to show that water availability is truly a

limitation for owners and operators complying with the 2015 Rule, particularly in light of the

ability of a new EGU to be sited in a location with adequate water availability and the relatively

small number of EGUs that are expected to be subject to this standard.


Commenters also claimed that the Agency erroneously stated that carbon capture is

limited to wet cooling options; instead, they stated, hybrid cooling and dry cooling systems are

available for coal plants equipped with carbon capture. The commenters stated that the designs

for the proposed Tenaska Trailblazer Energy Center demonstrated these systems. Though the

plan to construct the plant was abandoned, Tenaska received an air permit and developed a report

(the Cooling Alternatives Evaluation for the Tenaska Trailblazer Energy Center (August 2011))

that compared potential cooling systems for the plant and found that less water intensive cooling

options (both hybrid and dry) are viable for use with CCS. Tenaska concluded that dry cooling

was the lowest cost option for the Trailblazer plant. In addition, Tenaska found that adding CCS

to the dry-cooling configuration not only required no additional water, but actually decreased

water consumption compared to operating the PC plant without CCS, because the carbon capture

process includes an upfront cooling step that condenses combustion water vapor, which is then

re-used in the PC plant. The commenters asserted that the issued air permit and studies must be

relied upon by the EPA as demonstration that dry cooling is available for plants with CCS. The

commenters also cited a carbon capture feasibility study for retrofitting the Shand Plant in

Saskatchewan, Canada. According to the commenters, this study showed that a hybrid cooling

system drastically reduces water demand and contributes to the overall favorable economics of

the project.

Based on comments that the EPA did not adequately evaluate how water availability

could affect the development of new coal-fired generation with CCS, the EPA reviewed

information compiled by NETL. NETL identified specific areas of concern for water stress79 for

2020 that is predicted to vary across the country but be particularly high west of the Mississippi

79 How much electricity is lost in electricity transmission and distribution in the United States? https://www.eia.gov/tools/faqs/faq.php?id=105&t=3.


River and especially in the desert southwest. In addition, NETL also identified specific areas of

concern where water quality or availability may be an issue in the future due to growing

population, increased thermoelectric water demand, water scarcity, or some combination thereof.

These include Florida, eastern Texas, the northeastern Atlantic coast, western Pennsylvania,

central and southern California, and western Washington state.80 NETL additionally identified

specific areas where thermoelectric water withdrawals in 2030 will nearly equal or exceed

available fresh surface water and, therefore, require advances in dry cooling and water

management technologies to minimize water use throughout thermoelectric power generation.

These areas include the aforementioned central and southern California and eastern Texas

regions, plus southern Arizona, northern Utah, eastern Colorado, and eastern Montana.81

After considering comments on water availability and technologies to reduce water

demand, the EPA is not finalizing any finding on whether the cooling requirements of CCS

would limit the geographic availability of CCS. It is not necessary at this time to determine if

water requirements restrict the geographic availability of CCS because the EPA is already

determining that partial CCS does not qualify as BSER because its cost is not reasonable. For the

reasons noted below, securing access to adequate supplies of water for use in partial CCS

increases the costs of partial CCS, which was not fully evaluated in the 2015 Rule.

With respect to dry cooling, its use for meeting the cooling demand of CCS equipment

would increase costs and parasitic loads. This would increase costs beyond what the EPA has

already determined are unreasonable. The EPA disagrees with commenters who stated that the

use of dry cooling for CCS equipment is less expensive than the use of cooling towers. The

80 Lost In Transmission: How Much Electricity Disappears Between A Power Plant And Your Plug? Jordan Wirfs-Brock, November 6, 2015, http://insideenergy.org/2015/11/06/lost-in-transmission-how-much-electricity-disappears-between-a-power-plant-and-your-plug/.81 American Electric Power Transmission Facts, https://www.aep.com/about/transmission/docs/transmission-facts.pdf.


report cited by commenters claiming that dry cooling is less expensive is based on a preliminary

design that includes site specific factors, including a relatively high cost of water, and these

conditions are not widely applicable nationwide. In general, the use of dry cooling is more

expensive than the use of a cooling tower.82 The EPA also notes that the Trailblazer analysis

reduces the cost of the dry cooling system by reducing the size of the cooling system, but that

reduced size means that during periods of peak temperatures, it will not be able to provide

sufficient cooling for the carbon capture equipment to operate at full capacity.83 Under these

circumstances, during periods of peak temperatures, the CO2 emissions rate of the facility would

increase. The NETL Baseline Reports, upon which the EPA has based its analysis, assumes the

partial CCS system is able to operate at full capacity during all temperatures. Therefore, the

Trailblazer analysis is not directly comparable to the EPA’s analysis. If a CCS cooling system is

designed to be relatively smaller—in comparison to total CO2 capture capability—so as to

provide sufficient cooling only during non-peak temperatures, the carbon capture equipment

would need to be larger in size so that, even with the relatively smaller cooling system, it would

adequately control CO2 emissions during peak temperatures. This would increase the cost of the

CCS system further. By the same token, designing the cooling system to be able to achieve full

design capture rates during all anticipated ambient conditions would substantially increase the

capital costs of the dry cooling system.

The EPA has concluded that the Shand Plant carbon capture retrofit feasibility study cited

by commenters is not relevant to newly constructed EGUs for multiple reasons. First, the study’s

82 Electricity will follow the path of least resistance and unless you have dedicated transmission lines it is difficult match generation and load. However, if new generation is added to the existing grid and is far from the new load center the change in overall transmission line loss can be approximated by assuming the electricity is transmitted across states.83 Since power would only be transmitted through half of Oklahoma on average, the additional transmission loses were halved. The EPA did not consider the transmission losses in North Carolina because the power would likely be transmitted to the end user even if the power were generated in the state.


conclusion that CCS reduces the overall water requirements is a result, in part, of the existing

EGU being de-rated to a lower net electric output. The relevant NSPS water use comparison

would be at the same net electric output basis and not on the rated heat input of the facility. In

addition, to avoid increasing water use at the existing facility, the feasibility study evaluated

using water condensed from the flue gas for cooling in a new hybrid cooling system. However,

the Shand facility combusts lignite, which it does not dry prior to combustion. Lignite has more

moisture than other types of coal and contributes to the amount of moisture in the flue gas that

the study showed the new hybrid cooling system would capture. However, a new EGU burning

lignite would likely dry the lignite to reduce both the capital cost and operating costs of the new

facility. This would result in less moisture in the flue gas and less water to recover for reuse in

the cooling system. Furthermore, similar to the Trailblazer project, the Shand Plant carbon

capture cooling system was not designed to provide sufficient cooling during the hottest periods

of the year.84 Therefore, the facility would not be able to operate at the design CO2 emissions rate

during high ambient temperatures. While undersizing the cooling equipment reduces initial

capital costs, it is not a feasible option for a new EGU subject to an emissions standard that

applies at all times. To maintain compliance with an NSPS, the facility would have to voluntarily

derate itself during periods of high ambient temperatures when demand is typically the greatest,

which is impractical. Finally, the study itself acknowledges that availability of cooling capacity

will quite often be a major project impediment for a new CCS facility, and availability of cooling

is generally one of the first design concerns for siting a new facility and often ends up being the

limiting factor for further expansion at a given site.

84 The BSER criteria include costs, non-air quality health and environmental impacts and energy requirements energy impacts, emissions impacts; technical feasibility, promotion of technology; and the nationwide, longer-term impacts on the energy sector. 83 FR 65444 and 65445.


Dry and hybrid cooling technologies have not yet been widely implemented, largely due

to high capital and operating costs, sensitivity to ambient temperatures, and impact on power

plant efficiency. The capital cost of a dry cooling system can be up to 3 to 4 times higher than

the cost of a wet system.85 For an EGU incorporating CCS, while use of a hybrid or dry cooling

system could in theory significantly reduce plant water use compared to water use of a wet

cooling system, it would increase the plant capital cost and would lower plant efficiency due to

the additional auxiliary load,86 and would also require more land compared to an EGU using a

wet cooling system. These higher capital and operating costs make a control technology that is

already unreasonably expensive even more expensive. It should also be noted that the cost and

land requirements of a dry cooling system can increase significantly when implemented in an

area with a high ambient air temperature, due to the need to increase the size of that system.

Also, as the EPA noted in the 2018 Proposal, the use of hybrid or dry cooling systems has not

been demonstrated in combination with CCS. 83 FR 65443. For additional information please

see the TSD titled “Water Requirements of Coal-fired Power Plants.”

3. Coal-by-Wire

In the 2015 Rule, the EPA stated that geographic limitations to CCS could be overcome

by locating a new coal-fired EGU in an area amenable to GS and then transmitting the power

though transmission lines to intended load centers not amenable to GS. This is referred to as the

coal-by-wire approach.

Commenters stated that it is arbitrary for the EPA not to consider coal-by-wire in the

20108 Proposal as a solution to CCS siting concerns. They said the Agency ignores a key

85 See 84 FR 32544 (ACE Rule); see also “2017 Fuel Usage at Affected Coal-fired EGUs,” available in the rulemaking docket (Docket ID No. EPA–HQ–OAR–2017–0355).86 The 2019 average U.S. power generation fuel costs for natural gas was $2.94 per million Btu while the cost for distillate fuel oil for power generation was $15.23 per million Btu. U.S. EIA Short Term Energy Outlook, https://www.eia.gov/outlooks/steo/tables/pdf/2tab.pdf.


consideration that underlays the 2015 Rule’s assessment concerning the availability of partial

CCS. These commenters pointed out that as part of the 2015 Rule, the EPA completed a TSD

examining the geographic availability of GS of CO2. This document included a seven-page

assessment of the availability of coal-by-wire in regions of the country for which proximate GS

sites had not been identified. For these regions, the EPA analyzed, among other factors, the

existing electric transmission infrastructure, the current resource mix, and the likelihood that the

NSPS would, in practice, inhibit new coal-fired power plants. According to these commenters,

even if there is greater uncertainty than originally thought about the geographic availability of

CCS, the interconnected nature of the grid allows for CCS to be implemented where feasible

without unduly harming reliability or cost. These commenters stated that each interconnected

grid already has dispatch governance frameworks in place, greatly lessening the importance of

any reduced availability of CCS, if there is potential within the geographic scope of the regional

grid to deploy CCS. These commenters also said that coal-by-wire has historically been used to

generate electricity at or near a coal mine and to then transmit the electricity to meet load

somewhere else, saving coal shipping costs.

The coal-by-wire approach described in the 2015 Rule assumed that electric power can

be transmitted without any limitations (i.e., that there is adequate excess transmission capacity at

all times) and did not account for the additional line losses that would occur when transmitting

power over long distances. If a new EGU is located in close proximity to existing transmission

lines with available capacity, its electricity could be supplied to the grid with minimal costs.

However, there are limitations to how much power can be transmitted by the current electric

grid, and the existence of a transmission line does not mean that it can necessarily carry

additional load. If available transmission capacity does not exist when considering the power


plant’s location in relation to its end-user, a dedicated line would have to be constructed. A

transmission line is a significant capital investment that would need to be added to the calculated

LCOE when evaluating a project. Even if adequate capital is available, siting a new transmission

line can be challenging and time-consuming. These complications are demonstrated by the

challenges of providing links to new renewable energy generation resources, such as wind and

solar power, which are often located far from where electricity demand is concentrated.

Even if transmission capacity is available, line losses result from locating generation far

from load centers. The EIA estimates that electricity transmission and distribution (T&D) losses

average about 5 percent of the electricity that is transmitted and distributed annually in the U.S.87

About one-third of those losses occur during high voltage transmission and the other two-thirds

occur at the lower voltage distribution level.88 These losses would increase in the coal-by-wire

scenario, and would increase the cost of a new coal-fired EGU because it would have to be larger

in size than if it were located closer to the electric load to deliver the same amount of electricity

to the end user and would combust more coal per delivered amount of electricity. Furthermore,

the decrease in production of effective electricity would result in increased variable operating

costs and decreased dispatch. For example, approximately 1.3 percent of the electricity generated

is lost for each 100 miles of transmission on a 500 kilovolt (kV) transmission line. This can drop

to as low as 0.5 percent on a new 745 kV line, but could be as high as 4.2 percent on a 345 kV

line.89 As a hypothetical, if an owner/operator wanted to build a coal-fired EGU to serve load in

North Carolina, a BSER based on the use of CCS might result in an election to construct the 87 According the 2019 NETL Baseline Report, a $100/kW increase in capital costs equates to an approximate 3-percent increase in the capital costs of a new coal-fired EGU without CCS. 88 The reported E-GasTM full-slurry quench (FSQ) LCOE and design CO2 emissions rate are $96.1/MWh and 1,657 lb CO2/MWh-net, respectively. The bituminous-fired SCPC LCOE and design CO2 emissions rate are $65.8/MWh and 1,712 lb CO2/MWh-net, respectively. The incremental generating costs for the bituminous IGCC and SCPC are $32.5/MWh and $28.0/MWh, respectively. At a capacity factor of 80 percent—consistent with the 2019 NETL Report—the LCOE of IGCC increases to $98.9/MWh.89 https://doe.icfwebservices.com/chpdb/


coal-fired EGU in Oklahoma and thus need to transmit the power 1,200 miles. By building the

power plant in Oklahoma, the power would, conceivably, be transmitted thru Arkansas and

Tennessee prior to being delivered to the end user in North Carolina.90 The EIA estimates that the

total T&D losses in Oklahoma, Arkansas, and Tennessee are 4.5 percent, 3.8 percent, and 4.8

percent, respectively.91 The EPA estimated the additional transmission losses by assuming they

represent a third of the transmission and distribution losses for each state. An EGU built in

Oklahoma to serve load in North Carolina would have to be 3.7 percent larger and would

generate 3.7 percent more emissions than a comparable powerplant located in North Carolina.

Accounting for the potential capital costs associated with the additional line losses (which

would increase both capital costs and the LCOE) increases the LCOE beyond what the EPA has

already concluded are unreasonable. In addition, the increased emissions associated with the

reduced effective efficiency decrease the environmental benefit of CCS. None of these issues

were fully evaluated in the 2015 Rule and are contributing factors in the EPA withdrawing the

2015 determination that CCS is widely geographically available.

In summary, the Agency is rescinding its 2015 Rule determination that CCS is widely

geographically available because unmineable coal seams cannot be used for GS and because of

issues with coal-by-wire serving to compensate for the lack of geographic availability of GS. As

a result, the EPA is rescinding its 2015 Rule determination that CCS is adequately demonstrated

and that the Rule’s standard of performance is achievable by sources that implement the BSER.

C. Technical Availability of CCS

90 Only CHP EGUs larger than 25 MW would potentially meet the subpart TTTT applicability criteria.91 The electric to thermal output of a combine cycle CHP is larger than a boiler/steam turbine CHP. The electric output of a boiler/steam turbine CHP proving the equivalent thermal output of a 300 MW combined cycle CHP would be closer to 100 MW.


In the 2015 Rule, the EPA determined that CO2 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.

In the 2018 Proposal, the EPA noted that 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. It is reported to be the world’s largest post-combustion carbon capture system.

However, the EPA also noted that, 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 further noted that,

while the carbon capture technology at the Boundary Dam project is currently operating, the

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 CO2 supply contract

with Cenovus to avoid paying penalties for not supplying the agreed amount of CO2. The EPA

solicited comment on whether Boundary Dam’s first-year operational problems cast doubt on the

technical feasibility of fully integrated CCS.

In addition, the EPA noted 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

solicited 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.

Some commenters pointed out that, to date, commercial-scale experience with utility

application of CCS continues to be limited to Petra Nova and Boundary Dam. The commenters

asserted that experience at these two facilities is not sufficient to support a finding that CCS is

adequately demonstrated. They stated that the EPA is statutorily prohibited from considering the

Petra Nova CCS installation under the Energy Policy Act of 2005 because the project received

funding under that statute’s Clean Coal Power Initiative, and that even aside from that

prohibition, the fact that both Petra Nova and Boundary Dam depended heavily on government

assistance to be economical shows that CCS is not technically or economically feasible at

commercial scale. Commenters added that both facilities benefit from unique circumstances and

opportunities for EOR that would not be available for new coal-fired EGUs generally.

These commenters also claimed that the EPA’s cost analysis did not consider the need for

an additional design margin to ensure that the process equipment can reliably meet the target

CO2 emission rate. The commenters said that conventional design practice (along with pressure

from investors and public utility oversight agencies) dictates that a design margin must be

provided when implementing an emissions control system in order to account for unanticipated

issues, especially when the control technology is evolving. The EPA’s cost estimates assume that

CCS systems will perfectly achieve 90-percent capture from the slipstream on a continuous

basis. The commenters said this kind of flawless performance is extremely unlikely—particularly

given experience at the Boundary Dam CCS installation, where the system was designed for 90

percent capture but was unable to exceed 65-percent capture shortly after its startup and was only


active 40 percent of the time during that period. The commenters said that an EGU developer

would include a design margin to account for this uncertainty by allowing for treatment of a

larger portion of the unit’s emissions, with a corresponding increase in cost.

Other commenters stated that the EPA fails to show that partial CCS is not adequately

demonstrated. They noted that in formulating the current standards, the EPA determined CCS to

be adequately demonstrated on the basis of examination of EGUs that had or were utilizing

carbon capture technology, the existence of commercial vendors offering carbon capture

technology with performance guarantees, and public pronouncements by industry and

technology developers of their confidence in the feasibility and availability of CCS technologies.

They stated that if anything, CCS technology has only continued to advance and become more

commercially available since the 2015 Rule because the Boundary Dam and Petra Nova projects

have only achieved greater success as time has passed.

These commenters also stated that SaskPower has recently implemented major

improvements to the CCS system at Boundary Dam to address issues that limited availability

during the first year of operation. The commenters stated that reliability has improved and in

2018 the Boundary Dam CCS facility achieved 94-percent availability (excluding periods when

it was offline due to non-CCS-related issues at the power plant).

The EPA has concluded that no new information has become available that is sufficient

to lead it to change the technical feasibility determination for partial CCS made in the 2015 Rule.

The experience of Boundary Dam alone over the past several years in successfully implementing

CCS is sufficient to demonstrate technical feasibility; the fact that it and Petra Nova received

significant government subsidies is relevant with respect to the cost of CCS, but not its technical

feasibility.


However, the EPA acknowledges that CCS technology might not yet be sufficiently

developed such that 100-percent CCS availability can be guaranteed. Commenters stated that in

2018 the Boundary Dam CCS facility achieved 94-percent availability. Based on this, a

developer of a new coal-fired EGU might be able to assume only a 94-percent availability of the

CCS equipment. With this restriction, a developer would have to slightly oversize the CCS

equipment in order to overcontrol while the CCS equipment is operational to assure that the

facility could continue to operate when the CCS equipment is unavailable. When this is

accounted for, the level of partial CCS identified as the BSER in the 2015 Rule would increase to

16.6 percent for a new EGU firing bituminous coal and 28.2 percent for a new EGU firing

subbituminous coal or dried lignite. This would increase both the percentage increase in capital

costs, operating costs, and maximum available water for a BSER based on the use of partial

CCS. The EPA has determined that, as described earlier, partial CCS is too costly to qualify as

the BSER even without considering the impacts of less than 100-percent availability. Therefore,

it is not necessary to evaluate CCS equipment reliability or availability at this time.

VI. Systems Considered but Not Determined to be the BSER

In the 2018 Proposal, the EPA proposed to find that partial CCS did not meet the BSER

criteria and, therefore, evaluated alternate technologies, including natural gas co-firing, the use of

IGCC technology, CHP, hybrid power plants, and efficient generation. Based on this evaluation,

the EPA proposed to find that the use of efficient generation constitutes BSER, and that the other

alternate technologies do not. For the reasons discussed in this section, the EPA is finalizing its

proposal that the alternate non-efficient generation BSER technologies do not satisfy the BSER

criteria92 for coal-fired EGUs.

92 U.S. DOE National Renewable Energy Laboratory, Solar-Augment Potential of U.S. Fossil-Fired Power Plants, February 2011, available at www.otsi.gov.


A. Natural Gas Co-firing

Consistent with the 2015 Rule, in the 2018 Proposal, the EPA identified natural gas co-

firing as an alternative method of compliance, but, for multiple reasons, did not propose it to be

the BSER. First, while co-firing with natural gas in a utility steam generating unit is a technically

feasible option to reduce CO2 emission rates, it is an inefficient way to generate electricity

compared to use of an NGCC. The higher fuel costs from co-firing would increase both the

LCOE and variable operating costs of the unit, which would decrease dispatch and further

increase the LCOE. In addition, industry commenters have noted that a significant benefit of a

new coal-fired power plant is the fuel diversity value that it brings. Therefore, basing the

standard of performance for a new coal-fired EGU on natural-gas firing would defeat the purpose

of constructing the new coal-fired EGU in the first place. Further, not all areas of the country

have cost-effective access to natural gas. Finally, the EPA does not have sufficient information to

analyze the overall impact of co-firing natural gas, particularly impacts on dispatch.

Some commenters stated that they support the EPA’s conclusion that natural gas co-firing

is not the BSER for new coal-fired EGUs. They stated that co-firing natural gas would redefine

the source, is not available nationwide, and would be uneconomical for many units. Commenters

also stated that if natural gas must be employed to generate electricity, it can be used more

efficiently in combined-cycle combustion turbines rather than in steam EGUs and that natural

gas co-firing should not be encouraged since production, transmission, and use of natural gas is

itself a contributor of upstream methane emissions.

Other commenters stated that natural gas co-firing meets the statutory requirements to

qualify as the BSER. They asserted that natural gas co-firing is an adequately demonstrated and

cost-effective option for reducing carbon pollution and providing health benefits through


reductions in criteria and hazardous air pollutants for a new coal-fired EGU. They noted that

natural gas co-firing would achieve greater emission reductions than the EPA’s proposed BSER,

and they further noted that there is no reason to believe that pipeline infrastructure limitations

would preclude the use of increased natural gas co-firing. They added that developers of new

EGUs, unlike the operators of existing EGUs, have the flexibility to select a construction

location that is nearby to an existing natural gas pipeline. Commenters also stated that, although

the EPA argues that a significant benefit of a new coal-fired power plant is the fuel diversity

value that it brings and thus requiring the EGU to burn natural gas defeats that purpose, the

Agency fails to recognize that a coal-fired EGU with some degree of natural gas co-firing would

still provide fuel diversity benefits—and an EGU that is capable of combusting both coal or

natural gas would have very significant fuel diversity benefits. Commenters added that even if

the EPA believes natural gas co-firing is not available everywhere, the 2018 Proposal conceded

that it could be viable for some coal-fired EGUs, yet the Agency failed to consider

subcategorization of those EGUs.

The EPA disagrees with commenters that a new coal-fired EGU should be selectively

located near a natural gas pipeline with sufficient capacity to supply the new EGU for purposes

of co-firing to generate electricity. Siting a new coal-fired power plant is a complex decision-

making process. Developers must choose between construction at a completely new location

(i.e., a greenfield location that has not been previously used by a coal-fired EGU) or construction

at an existing site that already has some of the infrastructure that will be needed for the newly

constructed unit. In deciding on the project location, developers must take into account multiple

factors including, but not limited to, the availability of space to build the new EGU and its

associated equipment, the availability of rail or other fuel delivery systems, the location of load


demand and projected growth in demand, the adequacy of the cooling capacity, permitting

requirements, and existing transmission capacity. Existing sites where older coal-fired generating

sources are located (or, perhaps, were previously located and have since been decommissioned)

may already have much of the infrastructure that a newly constructed coal-fired EGU would

need. Taking advantage of existing infrastructure can result in reduced costs as compared to

construction at a greenfield site.

To estimate the availability of natural gas for co-firing at a newly constructed coal-fired

EGU, the EPA evaluated the current natural gas use and availability at existing coal-fired EGUs.

Coal-fired EGUs may co-fire with natural gas to generate electricity (i.e., operational co-firing,

during which significant amounts of natural gas are burned either separately or simultaneously

with coal) or during periods of startup (i.e., use of a smaller amount of natural gas to heat the

boiler or to maintain temperature during standby periods). Coal-fired boilers always use a

secondary fuel, most often natural gas or distillate fuel oil, for startup, utilizing burners

specifically configured to bring the boiler from a cold, non-operating status to a temperature at

which coal, the primary fuel, can be safely introduced for normal operations.

As part of the ACE rule, the EPA determined that, for several reasons, co-firing natural

gas does not meet the requirements for the BSER for reducing CO2 emissions from existing coal-

fired power plants. The same conclusion and reasons apply for newly constructed sources in the

present rule. In the ACE rule, the EPA conducted an analysis of the extent of natural gas co-

firing at existing coal-fired EGUs using EIA Form 923 fuel use data from calendar year 2017.93

That analysis indicated that nearly 35 percent of coal-fired units co-fired with natural gas in

2017, in either way described above. However, less than 4 percent of coal-fired units utilized

93 Because the NREL technical report ranked the potential to add solar thermal energy to existing coal-fired and NGCC plants, other aspects of this report (e.g., land area and characteristics adjacent to existing plants) are not directly applicable to this action.


natural gas in an amount greater than 5 percent of the total annual heat input. This strongly

suggests that most of the natural gas that was utilized at these sites was used as a secondary fuel

for unit startup or to maintain the unit in “warm standby,” rather than as a primary fuel for

generation of electricity. Further, the small number of units that actually co-fired with greater

than 5 percent natural gas during 2017 operated at an average capacity factor of only 24 percent,

which—indicates that they are not the most economical units and are not dispatched as

frequently as those units that used less than 5 percent natural gas. For comparison, in 2017, 62

percent of coal-fired utility boilers co-fired with some amount of distillate fuel oil and, as with

natural gas, the vast majority of those units used less than 5 percent distillate fuel oil, which,

again, strongly suggests that natural gas is primarily used as a secondary fuel for startup and

warm standby. While the use of distillate fuel oil does not necessarily mean that the unit lacks

access to natural gas, it suggests that for many of those units, there is an inadequate supply to

serve even as a secondary fuel for startup and standby operations. The 2019 average price94 of

distillate fuel oil was more than 5 times higher than that of natural gas; therefore, if there was an

adequate supply of natural gas, then it would be much more economically favorable to utilize

that natural gas rather than the much more expensive distillate fuel oil. Therefore, for a new coal-

fired EGU located in a site with existing infrastructure, it is likely that additional pipeline

capacity could be required. As noted in the ACE rule, the capital cost of constructing new

pipeline laterals is approximately $1 million per mile of pipeline built. 84 FR 32544. Therefore, a

50-mile gas pipeline would add $50 million to the capital costs of a 500 MW unit.95 Based on

these costs, a BSER based on the use of natural gas would impose unreasonable costs.

94 https://www.nrel.gov/gis/assets/images/solar-annual-dni-2018-01.jpg, accessed April 2020.95 The combustion of coal refuse in and of itself is part of the BSER due to the multiple environmental benefits associated with the reclamation of coal refuse piles.


Furthermore, in determining the BSER, CAA section 111(a)(1) also directs the EPA to

take into account non-air quality health and environmental impacts and energy requirements. The

EPA is unaware of any significant non-air quality health or environmental impacts associated

with natural gas co-firing. However, in taking energy requirements into account, the EPA notes

that co-firing natural gas in coal-fired utility boilers is not the best or most efficient use of natural

gas and, as noted in the 2018 Proposal, can lead to less efficient operation and higher variable

operating costs of utility boilers. NGCC stationary combustion turbine units are much more

efficient at using natural gas as a fuel for generating electricity and it would not be an

environmentally positive outcome for utilities and owners/operators to redirect natural gas from

the more efficient NGCC EGUs to the less efficient utility boilers. This statement does not imply

that there is now or that there will be a restricted supply of natural gas. However, the EPA does

not believe that establishing a BSER that would result in increased use of natural gas in utility

boilers is sensible policy.

For the reasons stated above, and consistent with the rationale the EPA set forth in the

ACE rule, the EPA concludes that co-firing natural gas in coal-fired boilers is not the BSER.

B. Integrated Gasification Combined Cycle (IGCC)

Consistent with the 2015 Rule, in the 2018 Proposal the EPA did not propose to find

IGCC technology, either with natural gas co-firing or implementing partial CCS, to be the

BSER. However, the Agency did identify it as an alternative method of compliance. The primary

factors supporting the EPA’s proposed conclusion that IGCC is not the BSER are that there are

limited, if any, net GHG benefits and costs are higher than alternate technologies.

Commenters stated they support the EPA’s proposal that IGCC is not the BSER for new

coal-fired EGUs. They stated that IGCC is not appropriate as the basis for a nationwide standard


of performance due to its costs and economic impacts, limited geographic availability, lack of

necessary information on performance and economic impacts, or a combination of these factors.

Other commenters stated that the Agency fails to give due consideration to IGCC. The

2018 Proposal’s estimated net emissions rate for IGCC is significantly lower than the standards

the EPA has proposed, the lowest of which is 1,900 lb CO2/MWh-gross, with no limit with

respect to net generation. Thus, even when considering net emission rates, IGCC technology

would offer significant GHG reductions relative to the standards the EPA has proposed.

The EPA disagrees with commenters’ assertion that IGCC offers significant GHG

benefits relative to the EPA’s proposed BSER. The 2019 NETL Baseline Report lists the IGCC

unit with the lowest LCOE as having a CO2 emissions rate that is 3.2 percent lower than the

bituminous-fired SCPC option. However, the IGCC’s LCOE is 46 percent higher and the

incremental generating costs are 16 percent higher than a bituminous-fired SCPC.96 The EPA

considers the costs of these incremental reductions to be unreasonable, especially when the

relatively small amount of the additional reductions is considered. Strictly from a cost

perspective, to achieve the same net CO2 emissions rate of an IGCC unit, a developer of a new

EGU would likely consider building a bituminous-fired SCPC unit with integrating non-emitting

generation, co-firing natural gas, using partial CCS, or implementing some other non-BSER

technology as an alternative to developing an IGCC unit. In addition to having a lower LCOE,

the incremental generating costs of any of those alternatives would be relatively smaller, which

would mean increased opportunities for economic dispatch compared to an IGCC unit. For these

reasons, the EPA concludes that IGCC technology does not meet the criteria to qualify as BSER.

96 Subcritical coal-fired boilers are designed and operated with a steam cycle below the critical point of water (22 MPa (3,205 psi)). EGUs using supercritical steam conditions operate at pressures greater than 22 MPa and temperatures greater than 550 oC (1,022 oF). Increasing the steam pressure and temperature increases the amount of energy within the steam, so that more energy can be extracted by the steam turbine, which in turn leads to increased efficiency and lower emissions.


C. Natural Gas Combined Cycle (NGCC)

In the 2012 Proposed Rule, the Agency proposed a single GHG standard of performance

for all affected EGUs, regardless of generation technology or fuel, based on the proposed

findings that the BSER for fossil fuel-fired units is NGCC. At the time, the Agency said NGCC

qualified as the BSER for two main reasons. First, natural gas combustion emits about half the

CO2 as coal combustion per amount of electricity generated. Second, for economic reasons,

NGCC units will be the predominant choice for new fossil fuel-fired generation even absent this

rule, in light of the fact that they have significantly lower capital costs and LCOE than new coal-

fired EGUs. Although in the 2012 Proposed Rule the Agency did not propose a separate BSER

for coal- and other solid fossil fuel-fired EGUs, it did identify CCS technology as a compliance

alternative for those EGUs. Significant public comments were received on this approach that led

the EPA to modify its approach regarding the BSER, and the Agency determined that it was not

appropriate to propose a single standard for all new EGUs. In 2014, the Agency withdrew the

2012 Proposed Rule (through, as noted earlier, the 2012 Proposed Rule Withdrawal), and

instead, in the 2014 Proposed Rule, proposed separate BSER determinations for (1) fossil fuel-

fired utility boilers and IGCC units, and (2) natural gas-fired stationary combustion turbines.

In the 2012 Proposed Rule Withdrawal, the EPA explained that it withdrew the 2012

Proposed Rule to account for the possibility that, in fact, there could well be limited new coal-

fired generating capacity being constructed within the planning timeframe covered by the

proposed rule. The Agency said this new capacity could be in response to the need for companies

to establish or maintain fuel diversity in their generation portfolios or the ability of some

companies to combine coal-fired generation of electricity with the profitable sale of by-products

from gasification or combustion of coal. As a result, even though the EPA’s baseline analysis did


not project any new coal that would not meet the originally proposed standard, the Agency

believed it appropriate to develop separate standards for coal-fired capacity, which differ from

those for new natural gas-fired EGUs. 79 FR 1353 through 1354 (January 8, 2014). The Agency

did not propose to change the conclusions of the January 2014 withdrawal in the 2018 Proposal

and is not doing so in this final rule.

Although the 2018 Proposal did not further evaluate whether NGCC may or may not

qualify as the BSER for coal-fired EGUs, some commenters asserted that the EPA failed to

consider this as an alternative, as the Agency had previously done in the 2012 Proposed Rule.

According to commenters, this option is consistent with CAA section 111 and with prior NSPS

that have established standards based on clean and newly dominant production processes that

have displaced older and less-efficient processes. Other commenters stated that NGCC does not

qualify as the BSER because it is a type of power plant, not a system of emission reduction.

These commenters added that even if it is a system of emission reduction, it is only so for natural

gas-fired electricity plants.

As a procedural matter, in order to determine that NGCC is the BSER for coal-fired

EGUs, the EPA would have to re-propose this rulemaking. The EPA is not inclined to do so

because no new information is available that would alter the Agency’s rationale in the 2012

Proposed Rule Withdrawal. As noted above, in that action, the Agency withdrew the proposed

2012 rulemaking to account for the possibility that there could be limited new coal-fired

generating capacity and that it was therefore appropriate to develop separate standards for coal-

fired capacity, which differ from those for new natural gas-fired EGUs. Accordingly, the EPA

does not agree with commenters that it was necessary for the EPA to reevaluate whether NGCC

should be considered to be the BSER for coal-fired EGUs.


D. Combined Heat and Power (CHP)

CHP, also known as cogeneration, is the simultaneous production of electricity and/or

mechanical energy and useful thermal output from a single fuel. CHP requires less fuel to

produce a given energy output, and because less fuel is burned to produce each unit of overall

energy output, CHP has lower emission rates and can be more economic than separate electric

and thermal generation.

In the 2018 Proposal, the EPA considered but rejected CHP as the BSER. The EPA

proposed to find that the geographic availability of the technology is too limited to be considered

as the BSER. Moreover, the EPA explained that coal-fired CHP facilities require large thermal

hosts to which to supply thermal output, limiting geographic availability and potentially limiting

the size of the EGU. Furthermore, the owner/operator of the EGU would be dependent on the

owner/operator of the thermal host accepting sufficient useful thermal output to comply with the

emissions standard. If the thermal host were unable or unwilling to accept the thermal output, the

EGU might not be able to comply with the NSPS and could be required to cease operation

completely.

Some commenters agreed that CHP technology should not be considered the BSER for

the reasons that the EPA proposed. Other commenters stated that it is unreasonable for the EPA

to exclude CHP as an element of the BSER. These commenters noted that the EPA proposed to

exclude CHP as an element of the BSER because of potential difficulties plants might have in

locating a large enough thermal host facility, but, the commenters asserted, the EPA had relied

entirely on conjecture, and had not offered any facts or analysis demonstrating that there is no

realistic potential for new projects to find hosts or explaining why, especially given the severity

of climate change, it should not set a limit that effectively requires new projects to find hosts.


In response to these comments, EPA further evaluated data regarding the availability of

CHP as the BSER for new coal-fired EGUs. According to the U.S. DOE CHP installation

database,97 between 2010 and 2019, an average of 410 MW of new CHP capacity was added

annually. The average annual new CHP installation was 3 MW and only 2 percent were larger

than 25 MW.98 The largest coal-fired boiler/steam turbine CHP installed during this period was

180 MW and the single largest CHP installation during this period was a 316 MW combined

cycle unit.99 This database demonstrates that the average annual new CHP nationwide capacity is

sufficient to support the output of only a single medium-sized coal-fired EGU. As a result,

basing the BSER on CHP would limit the geographic availability and capacity of new coal-fired

capacity. Therefore, consistent with the 2015 Rule and the 2018 Proposal, due to the limited

geographic availability and other considerations included in the 2018 Proposal, the EPA

concludes that CHP does not qualify as the BSER.

E. Hybrid Power Plants

Hybrid power plants combine two or more forms of energy input into a single facility

with an integrated mix of complementary generation methods. While there are multiple types of

hybrid power plants, the most relevant type for this action is the integration of solar energy (e.g.,

concentrating solar thermal) with a fossil fuel-fired EGU.

97 The pre-combustion drying of lignite is included as part of the BSER. While pre-combustion drying could in theory be applied to other fuels with inherent moisture, such as subbituminous coal, to date it has not in practice been applied to other coal ranks; accordingly, the EPA is not including it as part of the BSER for those other coal ranks.98 Materials capable of withstanding ultra-supercritical steam conditions of 30 MPa and 620 oC have been demonstrated internationally at coal-fired boilers. In addition, vendors are offering designs capable of withstanding advanced ultra-supercritical steam conditions of 33 MPa and 670 oC.99 Based on the 2019 NETL Baseline Report, when the impacts of incremental generating costs on dispatch are accounted for the LCOE of a bituminous-fired EGU designed for supercritical steam conditions is 1.5 percent lower than a coal-fired EGU designed for subcritical steam conditions. The LCOE of an ultra-supercritical coal-fired EGU is 1.1 percent higher than a supercritical coal-fired EGU. As noted in the 2018 Proposal, supercritical designs of less than 200 MW are not economically available.


In the 2018 Proposal, the EPA considered but rejected a hybrid power plant as the BSER.

The EPA proposed to find that the geographic availability of the technology is too limited to be

considered as the BSER. The EPA explained that not all areas of the U.S. have both sufficient

space and the abundant sunshine needed to successfully operate a hybrid power plant.

Some commenters agreed with the EPA’s proposed rationale for rejecting hybrid power

plants as the BSER. They added that while hybrid power plants can be beneficial under some

circumstances, the limitations described in the 2018 Proposal present sufficient reason for this

technology not to be considered the BSER.

Other commenters stated that it is unreasonable for the EPA to exclude hybrid solar

feedwater heating technology as an element of the BSER. According to commenters, the EPA

has not justified its decision to reject from the BSER the use of concentrated solar technology to

pre-heat feedwater at coal plants. They added that solar water heating has been demonstrated in a

wide variety of settings for decades (if not centuries) and has been successfully integrated at coal

plants to improve overall unit efficiency.

Consistent with the EPA’s stated position in the 2015 Rule and the 2018 Proposal, due to

the limited geographic availability and other considerations included in the 2018 Proposal, the

EPA concludes that hybrid power plants do not qualify as the BSER. Further support for this

conclusion is contained in work done by the National Renewable Energy Laboratory (NREL).

NREL’s 2011 technical report on the solar-augment potential of fossil-fired power plants100

examined regions of the U.S. with “good solar resource as defined by their direct normal

insolation (DNI)” and identified sixteen states as meeting that criterion: Alabama, Arizona,

California, Colorado, Florida, Georgia, Louisiana, Mississippi, Nevada, New Mexico, North

100 Technologies that maximize heat recovery can be used at industrial boilers, combined heat and power facilities. and any other facilities that recover thermal energy for useful purposes. More efficient steam turbines can be used at nuclear, solar thermal, geothermal, biomass, and CHP facilities.


Carolina, Oklahoma, South Carolina, Tennessee, Texas, and Utah. The technical report

explained that annual average DNI has a significant effect on the performance of a solar-

augmented fossil plant, with higher average DNI translating into the ability for a hybrid power

plant to produce more steam for augmenting the plant. The technical report used a points-based

system and assigned the most points for high solar resource values.101 An examination of a

NREL-generated DNI map of the U.S. reveals that states with the highest DNI values are located

in the southwestern U.S., with only portions of Arizona, California, Nevada, New Mexico, and

Texas (plus Hawaii) having solar resources that would have been assigned the highest points by

the NREL technical report (7 kWh/m2/day or greater).102 The EPA explained in the 2018

Proposal that existing concentrated solar power projects in the U.S. are primarily located in

California, Arizona, and Nevada with smaller projects in Florida, Hawaii, Utah, and Colorado,

and this remains the case in 2020. All of this information supports the EPA’s conclusion that

hybrid power plants have limited geographic availability.

Regarding costs, the NREL technical report sought to identify the most favorable sites for

solar augmentation but did not address the specific economics of solar-augmentation. However,

the NREL technical report did cite other analyses indicating solar-augmentation of fossil power

stations is not cost-effective, although likely less expensive and containing less project risk than

a stand-alone solar plant. Similarly, while commenters stated that solar augmentation has been

successfully integrated at coal plants to improve overall unit efficiency, commenters did not

provide any new information on costs or indicate that such augmentation is cost-effective.

Therefore, as stated at proposal, the EPA does not have sufficient information to evaluate costs

101 For additional analysis comparing the average and never-to-exceed emissions rate, which is representative of the NSPS, see the TSD in the docket.102 The SO2 standard was also based on the best performing EGUs and not all EGUs with scrubbers were operating below the final NSPS.


of hybrid power plants, though it appears that the primary benefit of solar augmentation of

fossil-fired power plants is to lower the solar thermal costs compared to a stand-alone solar

plant.

As noted, the 2018 Proposal also stated that not all areas of the U.S. have both sufficient

space and sunshine to successfully operate a hybrid power plant. The NREL report adds support

to this view. Therefore, the EPA concludes that due to the limited geographic availability of

concentrated solar thermal projects, as well as lack of sufficient information to evaluate costs,

hybrid power plant technology is not the BSER.

VII. Final BSER and New Source Performance Standards

This section describes the BSER and emissions standard that the EPA is finalizing in this

rule. It describes the EPA’s review of the BSER criteria and the rationale for why the Agency

concluded that efficient generation satisfies the BSER criteria for coal-fired EGUs. This section

also discusses the rationale for establishing different emission standards for large and small base

load EGUs and for subcategorizing non-base load EGUs. In addition, the section describes the

Agency’s rationale for why lignite-fired EGUs should comply with the same emission standards

as bituminous and subbituminous-fired EGUs and why a subcategory for coal refuse-fired EGUs

is appropriate. Finally, the section describes the EPA’s rationale for why the emission standards

for reconstructed EGUs and the maximally stringent emission standards for modified EGUs

should be consistent with the emission standards for newly constructed EGUs.

A. Summary of 2018 Proposal BSER and Emission Standards

In the 2018 Proposal, the EPA proposed to find that efficient generation—supercritical

boiler design for newly constructed large EGUs and subcritical boiler design for newly

constructed small EGUs—in combination with the best operating practices, is the BSER for new


coal-fired EGUs. In the 2018 Proposal, the EPA proposed three subcategories with different

standards of performance: large EGUs, small EGUs, and coal refuse-fired EGUs. The proposed

emissions standards were 1,900 lb CO2/MWh-gross, 2,000 lb CO2/MWh-gross, and 2,200 lb

CO2/MWh-gross, respectively. While the EPA did not propose to do so, the Agency solicited

comment on establishing separate standards of performance for EGUs burning lignite and EGUs

operating at part load conditions (i.e., non-base load EGUs). The Agency did not propose to

change the 2015 BSER determination for reconstructed or modified EGUs. However, since the

2015 BSER determination for reconstructed and modified EGUs is energy efficiency, the EPA

also proposed that the emissions standard for reconstructed EGUs and the maximally stringent

standard for modified EGUs would be the same emission standards as for newly constructed

EGUs.

B. Summary of Final BSER and Emission Standards

The EPA is determining that the BSER for newly constructed and reconstructed coal-

fired EGUs is the most efficient demonstrated steam cycle, i.e., supercritical steam conditions for

large units and subcritical steam conditions for small and coal refuse-fired units, in combination

with the best operating practices.103 Because the BSER is different for large and small EGUs, the

EPA is promulgating separate standards of performance for large and small newly constructed

coal-fired EGUs. In addition, for newly constructed and reconstructed coal-fired EGUs firing

moisture-rich fuels (e.g., lignite), the BSER also includes pre-combustion fuel drying using

waste heat from the process. Pre-combustion fuel drying of moisture rich fuels reduces the

emissions rate of EGUs combusting these fuels. Therefore, the EPA has determined that these

EGUs will be subject to the same standard of performance as EGUs burning bituminous and

103 The NSPS applies for the life of the unit and must account for variability in emission rates. Basing the NSPS never-to-exceed standard on a single year of operation discounts all variability and would result in a standard that is not achievable using the identified BSER.


subbituminous coal. However, due to the inherently higher emissions rate of EGUs burning coal

refuse, EGUs burning coal refuse will be subject to a less stringent standard than other coal-fired

EGUs. In addition, due to the inherent lower efficiencies of EGUs operating at low loads, the

EPA is promulgating separate standards of performance for non-base load coal-fired EGUs that

are 100 lb CO2/MWh-gross higher than the corresponding standards for base load units. Finally,

the EPA is also revising the maximally stringent standards for coal-fired EGUs undergoing large

modifications (i.e., modifications resulting in an increase in hourly CO2 emissions of more than

10 percent) to be consistent with the various standards for newly constructed and reconstructed

units.

Table 5 shows the final standards of performance for newly constructed, reconstructed,

and modified EGUs.

TABLE 5. SUMMARY OF BSER AND FINAL STANDARDS FOR AFFECTED SOURCES

Affected Source1 BSER Emissions Standard


12-operating month duty cycle (average operating capacity

factor) of 65 percent or greater (i.e., base

load units)





practices


[2.] 2,000 lb CO2/MWh-gross for sources with heat input ≤ 2,000 million British thermal units per hour (MMBtu/h); or



12-operating month duty cycle (average operating capacity




combination with





factor) of less than 65 percent (i.e.,

non-base load units)

best operating practices





load units)









less than 65 percent (i.e., non-base load

units)






1. §60.5509(b)(7) exempts steam generating units or IGCCs that undergoes a modification resulting in an hourly increase in CO2 emissions of 10 percent or less from the subpart TTTT applicability.

C. BSER for New Coal-Fired EGUs

1. Description of BSER

The EPA is determining that the BSER for newly constructed coal-fired EGUs is the

most efficient generation technology that is economically available. Specifically, for large EGUs

the BSER is the use of supercritical steam conditions104 (i.e., a SCPC or supercritical CFB boiler)

in combination with the best operating practices. For small EGUs and coal refuse-fired EGUs of

any size, the BSER is the use of the best available subcritical steam conditions in combination

104 District energy is a system for distributing heat and/or cooling generated in a centralized location to end use locations for applications such as space heating. water heating, and space cooling.


with the best operating practices. In addition, for newly constructed steam generating units firing

moisture-rich fuels, the BSER also includes pre-combustion fuel drying using waste heat from

the process. 105 The use of higher steam temperatures and pressures—i.e., supercritical steam

conditions for large EGUs and subcritical steam conditions for small EGUs—increases the

efficiency of converting the thermal energy in the steam to electrical energy. Best operating

practices include, but are not limited to, installing and maintaining equipment (e.g., economizers,

feedwater heaters) in such a way as to maximize overall efficiency and to operate the steam

generating unit to maximize overall efficiency (e.g., minimize excess air, optimize soot

blowing).

2. Rationale for BSER

This section explains why efficient generation and best operating practices satisfy the

criteria for BSER for new coal-fired EGUs. This section describes the technical feasibility, costs,

energy impacts, and promotion of technology; the emissions impacts; and the nationwide,

longer-term impacts on the energy sector. It includes a summary of the comments received on

each issue and the Agency’s responses.

a. Feasibility, Costs, Energy Impacts, and Promotion of Technology

Advanced generation technologies and best operating practices enhance operational

efficiency compared to lower efficiency designs. Advanced generation technologies are

technically feasible106 and of reasonable cost; in particular, they present little incremental capital

cost compared to other types of technologies that may be considered for new and reconstructed

105 Dr. Malgorzata Wiatros-Motyka, IEA, Clean Coal Centre, An Overview of Hele Technology Deployment in the Coal Power Plant Fleets of China, EU, Japan, and USA, CCC/273 (Dec. 1, 2016), https://www.iea-coal.org/an- overview-of-hele-technology-deployment-in-the-coal-power-plant-fleets-of-china-eu-japan-and-usa-ccc-273/.106 The lower heating value (LHV) of a fuel is determined by subtracting the heat of vaporization of water vapor generated during combustion of fuel from the higher heating value (HHV) of the fuel.


sources.107 In addition, due to the lower variable operating costs, more efficient designs would be

expected to dispatch more often and sell more electricity, thereby offsetting increases in capital

costs. The EPA also notes that designating energy efficient generation as the BSER will not have

adverse effects on the structure of the power sector, will promote fuel diversity, and will not have

adverse effects on the supply of electricity.

In addition, in determining the BSER, the EPA is to consider the effect of its selection of

BSER on technological innovation or development, as well as to weigh this against the other

factors. Selecting highly efficient generation technology as the BSER offers an opportunity to

encourage the development and implementation of improved control technology. This

technology is readily transferrable to existing EGUs, EGUs in other countries, and other

industries.108

Advanced generation technologies have not been adopted by all developers of new coal-

fired EGUs, particularly in nations projected to increase coal use. As the Agency noted in the

2018 Proposal, according to EIA, demand in India and Southeast Asia is projected to drive an

increase in coal use over the next two decades. Coal is often the fuel of choice because it is

abundant, inexpensive, secure, and easy to store. According to the World Electric Power

database, sixty percent of the new coal-fired capacity in India and Southeast Asia between 2013

and 2017 uses subcritical steam conditions. Therefore, establishing advanced generation

technologies as the basis for control requirements in the U.S. helps establish the default use of

advanced generation technologies in other nations, reducing global CO2 emissions. The EPA

107 Coal Industry Advisory Board to the International Energy Agency, Power Generation from Coal (Paris, 2010). Available at http://www.iea.org/ciab/papers/power_generation_from_coal.pdf.108 Zhang, S. and Li, J. Design and energy analysis of 1,000-MW double-reheat double-turbine regeneration system. IOP Conf. Series: Earth and Environmental Science 2 (ICAESEE 2018). Available at https://iopscience.iop.org/article/10.1088/1755-1315/237/6/062005/pdf.

https://iopscience.iop.org/article/10.1088/1755-1315/237/6/062005/pdf

http://www.iea.org/ciab/papers/power_generation_from_coal.pdf


noted that it is critical that economies where coal use is increasing adopt these technologies to

develop in a more environmentally sustainable way.

Some commenters agreed that identifying advanced generation as the BSER for coal-

fired EGUs will promote the broader implementation of this system (both domestically and

internationally) and will also encourage technical innovation by providing additional regulatory

incentives for further efficiency improvements. Other commenters stated that the EPA’s

proposed BSER would fail to promote advanced technology. They explained that the 2015

Rule’s standard spurs deployment and advancement of CCS technology and its rescission will

hamper CCS development.

The EPA disagrees that a standard based on efficient generation will not promote

technology advancement and will hinder the development of CCS. Due to the various permitting

requirements in the U.S., equipment vendors and technology developers will continue to have

incentives to reduce the overall costs and improve the performance of both efficient generation

and control technologies, such as CCS, which will increase the number of opportunities where

CCS can be applied at reasonable costs. In addition, since efficient generation is available at

reasonable costs, especially compared to implementation of CCS, it is more likely to be adopted

in regions of the world with expanding coal use.

b. Emissions Impacts

In the 2018 Proposal, the EPA proposed to find that highly efficient generation would

result in emission reductions of approximately 2 percent for large EGUs and 9 percent for small

EGUs when compared to a business as usual scenario absent an NSPS establishing standards for

GHG emissions. The economic impact analysis that supported the 2018 Proposal also included a

separate, illustrative example comparing the emissions and cost differences of the 2015 Rule and


the proposed BSER.

Some commenters stated that the overall environmental benefits of higher efficiency

generation technologies are greater than those of CCS technologies. They said, for example, that

higher efficiency technologies utilize less coal, water, and raw materials (e.g., ammonia for

nitrogen oxide (NOX) removal, limestone for SO2 removal, etc.) to generate the same amount of

electricity as compared to lower efficiency processes, including those that might be equipped

with CCS systems.

Other commenters stated that the EPA ignores the environmental costs and minimal

emission reductions from selecting supercritical and subcritical steam conditions as the BSER.

These commenters noted that the economic impact analysis illustrative model plant comparison

in the 2018 Proposal, when compared to the 2015 Rule emissions standard, would result in an

estimated increase of 1.1 million tons of CO2 and 500 tons of SO2 per year for every new large

base-load coal-fired EGU. Commenters said that the courts have consistently held that the EPA

must take into consideration the degree of air pollution reduction achieved when selecting the

BSER; and that CAA section 111 requires the maximum practicable degree of control of air

pollution from new sources. Commenters added that the Court has established that deference to

the EPA’s choice of the BSER will not extend to those situations where the environmental costs

of using the technology are “exorbitant[],” citing Essex Chemical Corp. v. Ruckelshaus, 486 F.2d

427, 434 (D.C. Cir. 1973).

Since the emission standards in this final rule are more stringent than in the 2018

Proposal the emissions impact and the associated environmental and health impacts cited by

commenters are from the 2018 Proposal’s economic impacts analysis are no longer relevant. In

addition, the illustrative example assumptions in the economic impact analysis show a worst-


case scenario, with the largest potential emissions difference and the smallest potential price

difference between a BSER based on the use of partial CCS and a BSER based on efficient

generation. Because the Agency projected few, if any, new coal-fired EGUs, the model plant

analysis in the economic impact analysis was intended to serve as an illustrative example.

Applying the more stringent standards in this final rule and using more realistic

assumptions for the illustrative examples in the economic impacts analysis supporting this final

rule result in smaller emissions difference between the 2015 Rule and the standard in this final

rule. As described in more detail in the baseline efficiency TSD, the emissions standard in this

final rule results in 12 percent more CO2 as compared to the emissions standard in the 2015 Rule

for large EGUs. However, the BSER in this final rule reduces emissions of NOx, PM, and Hg by

4 percent as compared to the 2015 Rule. Depending on the assumptions, the amended BSER will

result in between a 13 percent reduction to a 4 percent increase in emissions of SO2. It should

also be noted that this final rule demonstrates that partial CCS does not qualify as the BSER.

Therefore, the EPA compared the impacts of this final rule to the business-as-usual technology

that would be applied in the absence of the NSPS, specifically, the CO2 emissions rate of

recently constructed coal-fired EGUs. According to annual emissions data submitted to the

CAMD, the average emissions rate for large coal-fired EGUs that have commenced operation

since 2010 in the U.S. is 2,002 lb CO2/MWh-gross. Using the assumption that the average coal-

fired EGU emissions rate is 4.4 percent lower109 than the 99 percent confidence emissions rate,

the EPA estimates that the average emissions rate of a new large coal-fired EGU complying with

the never-to-exceed standard in this final rule would be approximately 1,720 lb CO2/MWh-gross.

109 According the NREL, areas of the country likely to experience water stress include Florida, eastern Texas, and the desert Southwest. All of these areas have average ambient temperatures of approximately 20 oC (68 oF). Noncontinental areas such as Puerto Rico have higher ambient temperatures but have not been identified as likely to experience limited water availability.


Therefore, the BSER standards for large EGUs in this final rule will result in 14 percent

emissions reductions compared to the expected emissions for new EGUs absent an NSPS

establishing standards for GHG emissions. The average emissions rate for the single small coal-

fired EGU that has commenced operation in the U.S. since 2010 is 2,130 lb CO2/MWh-gross.

Because the average emissions rate for a small coal-fired EGU complying with the standards in

this final rule would be approximately 1,910 lb CO2/MWh-gross, the BSER standards for small

EGUs in this final rule will result in 10 percent emissions reductions compared to the expected

emissions for new EGUs absent an NSPS establishing standards for GHG emissions. The

increased efficiency would also result in reductions of criteria and hazardous air pollutants. Thus,

the EPA continues to believe the emissions impacts resulting from highly efficient generation

provide support for its selection as the BSER for coal-fired EGUs.

c. Nationwide, longer-term perspective of impacts on the energy sector.

Consistent with the 2018 Proposal, the EPA has concluded that designating the most

efficient generation technology, combined with best operating practices, as the BSER for new

and reconstructed coal-fired utility boilers and IGCC units will not have significant impacts on

nationwide electricity prices. This is because (1) the additional costs of the use of efficient

generation will, on a nationwide basis, be small given few, if any, new coal-fired projects are

expected and at least some of these can be expected to incorporate efficient generation

technology even absent an NSPS for GHG emissions; and (2) the technology does not add

significant costs. For similar reasons, designation of the most efficient generation technology as

the BSER for reconstructed and newly constructed coal-fired utility boilers and IGCC units will

not have adverse effects on the structure of the power sector, will promote fuel diversity, and will

not have adverse effects on the supply of electricity.


D. Level of the Standard for Base Load Units

This section summarizes the proposed emissions standard for large, small, and coal

refuse-fired base load units in the 2018 Proposal; summarizes the comments received and the

EPA’s response to those comments; and explains the Agency’s rationale for the final emissions

standards. While the final emissions standard for large EGUs (other than coal-refuse fired) is

more stringent than the proposed emissions standard, the Agency is finalizing the same general

approach for determining an achievable emissions standard. The EPA is finalizing the base load

standard for small and coal refuse-fired EGUs as proposed.

1. 2018 Proposal

In the 2018 Proposal, to determine emission rates achievable by application of the BSER,

the EPA reviewed CO2 emissions data of existing coal-fired EGUs that submitted continuous

emissions monitoring system (CEMS) data to the EPA’s emissions collection and monitoring

plan system (ECMPS). The EPA first identified the EGUs using the best operating practices by

categorizing EGUs with the lowest emission rates, considering design factors that influence

efficiency (and therefore the emissions rate) and for which the EPA has individual unit

information. The design factors include the steam cycle (i.e., steam temperature and pressure and

the number of reheat cycles), coal type (which impacts both boiler efficiency and emissions on a

lb CO2/MMBtu basis), cooling type (i.e., dry, recirculating cooling tower, and open), and

average ambient temperature. EGUs burning higher rank coals have lower emission rates than

EGUs burning lower rank coals because higher rank coals are both more efficient at generating

steam and emit less CO2 per amount of heat input. As described previously, higher steam

temperatures and pressures and cooling technologies that can achieve lower condensing

temperatures increase the efficiency of an EGU. By accounting for these known factors, the EPA


identified EGUs using the best operating practices. These best operating practices include design

parameters that impact efficiency (e.g., number of feedwater heaters, economizer efficiency,

stack temperature, steam turbine efficiency, combustion and soot blowing optimization, an

exposed structure or main building enclosure) and operation and maintenance practices that

impact efficiency (e.g., proactively fixing steam leaks, prioritizing efficiency related repairs.

minimizing excess air), but the EPA does not have unit specific information for either category

of operating practices. A developer of a new EGU would be able to incorporate these operating

practices in a newly constructed EGU. Based on the best performing EGUs, the EPA was able to

determine achievable emission rates for an EGU considering the use of different coal types,

steam temperatures and pressures, cooling technologies, and ambient conditions. The 2018

Proposal referred to this as the normalization approach.

Based on the normalization approach, the EPA proposed three subcategories, with the

following proposed standards of performance: 1,900 lb CO2/MWh-gross for large EGUs (i.e.,

those with a nameplate heat input greater than 2,000 MMBtu/h), 2,000 lb CO2/MWh-gross for

small EGUs (i.e., those with a nameplate heat input less than or equal to 2,000 MMBtu/h), and

2,200 lb CO2/MWh-gross for coal refuse-fired EGUs. These levels of the standard are based on

the emissions performance that can be achieved by a large pulverized or CFB coal-fired EGU

using supercritical steam conditions and best operational practices, as well as small and coal

refuse-fired EGUs using subcritical steam conditions and best operational practices. Specifically,

in the 2018 Proposal the Agency proposed to find that new large subbituminous, dried lignite,

and petroleum coke-fired EGUs could comply using the highest steam temperatures and

pressures currently in use in combination with best operating practices and dry cooling. The

Agency proposed to find that, due to the higher heating value and lower CO2 emissions rate of


bituminous coal, bituminous coal-fired EGUs would be able to comply using lower steam

temperatures and pressures in combination with the best operating practices and dry cooling. For

small EGUs, the EPA proposed to find that all new coal-fired EGUs, aside from those firing coal

refuse, could comply using subcritical steam conditions in combination with dry cooling and best

operating practices. The Agency proposed to find that new coal refuse-fired EGUs could comply

using subcritical steam conditions in combination with dry cooling and best operating practices.

2. Comments and Responses for Base Load Units

This section summarizes and responds to the comments the Agency received on the

proposed emissions standard for base-load EGUs. In this final rule, the Agency is establishing

standards of performance as proposed, except that he standard for large coal-fired EGUs has

been lowered from the proposed emission limit of 1,900 lb CO2/MWh-gross to the final emission

limit of 1,800 lb CO2/MWh-gross. The Agency is also confirming that the final emission

standards are achievable by applying the BSER given the range of conditions new coal-fired

EGUs are expected to face.

Some commenters stated that while they support the EPA’s proposed BSER finding, the

Agency has failed to show that its proposed standards of performance are achievable through

application of that BSER. The commenters said that examination of the actual performance data

from coal-fired EGUs implementing the BSER shows that the proposed standards are not

achievable, as eight out of the 16 most recently constructed large coal-fired EGUs designed with

supercritical steam conditions have exceeded 1,900 lb CO2/MWh-gross since 2012 and all of the

most recently constructed small coal-fired EGUs have exceeded 2,000 lb CO2/MWh-gross.

According to the commenters, in revising the NSPS for new coal-fired EGUs, the EPA should

adjust its standards of performance so that they are achievable for new units based on available


emissions data. These commenters said the Agency should understand that the emissions data

utilized to establish these emission rates were based on units that, in many cases, were recently

commissioned, and, as units age, their CO2 emission rates will increase. These commenters also

stated that the EPA admits that some new coal-fired EGUs would need to go beyond the BSER

that the EPA has identified in order to comply with the proposed standards. They explained that

for large EGUs utilizing dry cooling, the 2018 Proposal recognizes that units combusting

subbituminous coal or dried lignite could comply only using ultra-supercritical steam conditions.

They asserted that ultra-supercritical boiler design has not been adequately demonstrated and is

not part of the BSER for this subcategory, that only one ultra-supercritical EGU has ever been

constructed in the U.S., and that the materials and equipment necessary for ultra-supercritical

steam conditions do not appear to be available for units at the low end of what qualifies as a

large EGU.

Commenters are mistaken that the use of ultra-supercritical steam conditions were not

part of the 2018 Proposal BSER. As stated in the 2018 Proposal, supercritical steam conditions

encompass all steam conditions greater than the critical point of water, and that includes ultra-

supercritical steam conditions. While most ultra-supercritical EGUs are significantly larger than

the small unit subcategory threshold, the basic boiler design is the same for all EGUs using

supercritical steam conditions. The primary difference is the requirement to use materials

capable of withstanding the higher steam temperatures and pressures. Because no redesign would

be required, constructing ultra-supercritical units at the size of the large unit subcategory is a

relatively lower cost requirement.

Commenters are also mistaken when they claim that the fact that the majority of recently

constructed EGUs in the U.S. using supercritical steam conditions are operating above 1,900 lb


CO2/MWh-gross shows that level is not achievable. The BSER also includes best operating

practices, which some EGUs may not be employing, and for that reason may not be operating

below the 1,900 lb CO2/MWh-gross level. The approach of using the best performing units

applying the BSER is consistent with past EPA NSPS evaluations for this source category. For

example, even though the BSER for NOx emissions standards was based on the use of selective

catalytic reduction (SCR), there were many existing facilities equipped with SCR that were

emitting NOx in excess of the standard of performance. This is because the EPA based that

standard on the best performing EGUs. “National Emissions Standards for Hazardous Air

Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of

Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and

Small Industrial-Commercial-Institutional Steam Generating Units,” 77 FR 9304 (February 16,

2012).110

Other commenters stated that the application of the most efficient demonstrated steam

cycle as the BSER would result in more stringent emission standards than what the EPA

proposed. They said the proposed standards are worse than the rates existing plants are currently

achieving and that the EPA was proposing to regulate to the lowest common denominator, which

failed to recognize that CAA section 111 requires maximum feasible control, not that every plant

can at all times and under all circumstances meet the standards. Commenters said that the

Agency must maximize emission reductions using state-of-the-art controls projected to be

available during the foreseeable regulatory future. They explained that the Proposal fails to

recognize that the 1,400 lb CO2/MWh-gross standard can be achieved through a variety of

measures for any plant that could be built. They added that the EPA further makes a legal error

110 The EPA did not incorporate 2019 operating data for Cliffside 6. In 2019, Cliffside 6 began co-firing natural gas. While this lowered the 2019 emissions rate, the increased variability results in a higher 99 percent confidence emissions rate.


in asserting that a standard must be achievable for all sources. Additionally, the commenters

stated that the 2018 Proposal’s review of historical emission rates achieved by existing coal

plants is directly counter to the forward-looking, technology-forcing demands of the CAA. The

commenters said that as evidenced from a new report by Andover Technology Partners, even

without considering partial CCS or other alternatives, the EPA’s proposed standards do not

reflect the degree of reduction that is achievable, and the emissions rates are insufficiently

stringent. The referenced Andover report asserted that in-service performance data from ultra-

supercritical plants operating around the world demonstrate that coal plants routinely emit in the

range of 1,500 lb CO2/MWh-gross merely by using efficient generating technology. They said

the EPA ignored these data altogether and gives no consideration to the most relevant data on the

performance of new coal plants that currently exists.

These commenters also stated the EPA improperly adjusts its data to assume the use of

higher-emitting coal. They said in another normalization procedure, the EPA adjusts the

emission rates of units in its data set that burn bituminous coal to a higher number based on the

assumption that new units might want to burn subbituminous coal. They said the Agency offers

no justification for this proposal: burning coal with a lower CO2/MWh emission rate is one of the

primary options for reducing emissions at coal-fired power plants. The commenters added that

the Agency has offered no reason for excluding coal rank from its BSER determination, let alone

for issuing a single standard that is lenient enough to accommodate bituminous, subbituminous,

and even lignite coal. The commenters stated that the Agency has authority to effectively ban the

use of lower-rank coals at new plants, as the EPA may ban certain processes in an NSPS so long

as alternatives are available at a reasonable cost.


The EPA disagrees with the commenters’ suggestion that the standard in the 2015 Rule

should be maintained because there are non-CCS technologies that could be used to achieve an

emissions rate of 1,400 lb CO2/MWh-gross. While it might be true that a new EGU would have

non-CCS methods to achieve an emissions rate of 1,400 lb CO2/MWh-gross, section 111(b)

requires that the standard of performance be achievable through the application of the BSER.

None of the ways a new EGU could meet a standard of 1,400 lb CO2/MWh-gross, including

partial CCS and co-firing with natural gas, meet the requirements for BSER for the reasons noted

in sections V and VI.A.

The comments urging that the EPA base the NSPS on either the NETL design emission

rates, the lowest single annual emissions rate for particular EGUs, or the performance of

international units fail to account for the fact that the NSPS is a continuous never-to-exceed

standard that applies for the life of the facility and must account for variability in emission rates.

As described baseline efficiency TSD, compared to actual operating data, the NETL design

emission rates have not been demonstrated as consistently achievable using the technologies

described in the NETL Reports.111 Specifically, the EPA reviewed the annual reported emissions

rates for coal-fired EGUs between 2005 and 2019. The median difference between the source’s

highest reported annual emissions rate and the lowest reported annual emissions rate is 16

percent. This demonstrates that the single best annual emissions rate is not representative of a

standard that is continuously achievable,

The commenters’ argument that the lower emission rates achieved by recently

constructed international units support a lower standard is flawed for several additional reasons.

First, it is not clear how the efficiency data cited by commenters was determined, including

whether the data was reported only for periods of optimal efficiency. As noted previously, the 111 Although no current operating EGUs use the technology, a vendor offers steam conditions of 33 MPa and 660 oC.


maximum efficiency is not representative of a never-to-exceed standard that accounts for

variability. Second, several of the EGUs cited by commenters include CHP district energy112

which, as noted elsewhere, is not part of the BSER. Third, it is not known whether the emissions

data for the international units was collected through a CEMS, approximations of fuel use, or

through some other method. The EPA considers CEMS data that is collected following the

calibration procedures required by the NSPS to be the most relevant and reliable data to

determining an achievable emissions rate. For example, a CEMS would account for CO2

emissions that are chemically created as part of the SO2 control system but calculating the

efficiency from fuel use data and converting to an emissions rate would not necessarily do so.

Because CO2 created as part of the SO2 control system is emitted from the stack, these emissions

should be accounted for when determining an appropriate NSPS. As an example of the

importance of using CEMS data, one of the reports113 used by the commenters also lists the

efficiency of the Turk facility, the only operating ultra-supercritical EGU in the U.S, as 42

percent net efficiency on a lower heating value basis.114 However, based on actual CEMS data

reported to the EPA, the estimated 99 percent confidence 12-operating month efficiency that can

be maintained is only 36 percent net on a lower heating value basis. In fact, based on actual

operating data submitted to the EPA, the maximum lower heating value net efficiency that has

been achieved through 2019 is approximately 40 percent. This 14-percent difference is so great

that the EPA considers the emission rate values cited by the commenters as unreliable for NSPS

purposes.

In addition, some of the international EGUs identified by commenters incorporate double

reheating technology, which allows those units to operate more efficiently, but which is not

112 The highest steam pressures and temperatures currently in use are 30 MPa and 610 oC. 113 Petroleum coke is considered coal in 40 CFR part 60, subpart TTTT.114 11 MPa steam pressure and 541 oC main steam temperature with no reheat cycle.


appropriate for all potential new domestic units and, therefore, is not part of the BSER. The

BSER incorporates a steam reheat cycle, in which steam is partially expanded to a lower pressure

in the high-pressure portion of the steam turbine and then sent back to the boiler to be reheated to

a higher temperature prior to expansion through the lower pressure portions of the steam turbine.

As noted, some international units have a double reheat design, which sends the steam back to

the boiler to increase the temperature twice prior to full expansion through the steam turbine.

When a unit runs at the design conditions (i.e., high load) for a long period of time, a double

reheat cycle can provide a 1.5 percent efficiency increase115 above a single reheat turbine.

However, a double reheat steam turbine operates less efficiently at lower load and, in fact, when

operating at only 50 percent design conditions, a double reheat steam turbine operates less

efficiently than a single reheat turbine.116 In addition, incorporating a double reheat cycle

increases the startup time of the unit if not used continuously at high loads. As the U.S. electrical

grid shifts towards renewable energy sources like solar and wind, which are highly variable in

terms of electrical output, the need for back-up systems that are both quick to start and efficient

for short periods of time will become increasingly valuable. These variables make the double

reheat steam turbine a poor option for short-term generation during times of peak demand. The

U.S. power sector is changing rapidly and, in promulgating this NSPS, the EPA does not assume

that a new coal-fired EGU will operate only at base load conditions during the entire anticipated

life of the EGU. Instead, a new coal-fired EGU may initially operate at base load conditions and

then over time, as the unit ages, transition to operate at non-base load conditions during low

demand periods. During the operating life of the unit, it may eventually only operate

115 The best available subcritical steam conditions are 21 MPa steam pressure and 570 oC main and reheat steam temperature.116 See U.S. EPA, Memorandum: CO2 Emission Rates for Coal-fired EGUs Operating at Part Load, available in the rulemaking docket.


intermittently to support renewable energy sources. For this reason, the EPA does not include

double reheat turbines in the BSER. Thus, emission rates for EGUs operating continuously at

high loads and using double reheat steam turbines are not appropriate for determining an

achievable emissions rate for this rulemaking.

Commenters are incorrect that the EPA did not consider the advanced steam cycles used

by international EGUs. To determine the NSPS, the EPA has identified EGUs using best

practices by reviewing emissions data while simultaneously accounting for the known site-

specific conditions. Once the EPA identifies these EGUs, it normalizes the emission rates to

account for the use of more advanced steam cycles used by international EGUs and different fuel

types, cooling configurations, and ambient conditions. While it would not be appropriate because

it would not include available efficiency technologies, the EPA would have proposed less

stringent emission standards if the Agency had only considered the most advanced steam cycles

currently in use in the U.S.

The EPA finally disagrees that the standard should be based on the use of bituminous

coal. Fuel choices are determined based on multiple factors including, but not limited to, price,

local availability, and impact on non-GHG emission rates. As noted above, the NSPS must be

“achievable [by new sources] under the range of relevant conditions which may affect the

emissions to be regulated.” National Lime Ass’n v. EPA, 627 F.2d 416, 431 (D.C. Cir. 1980). For

coal-fired power plants, those conditions generally include type of coal. According to data

reported under EIA form 923, in 2018 subbituminous coal constituted 54 percent of the coal

burned in EGUs. Therefore, a GHG standard based on the use of bituminous coal could create

significant disruption and costs. In addition, if the EPA were to set each individual pollutant


NSPS based on the fuel that resulted in the lowest emissions for that particular pollutant, the

NSPS as a whole could be unachievable.

3. Final Emission Standards for Base Load Units

In the 2018 Proposal, the EPA used the normalization approach to identify the best-

performing large EGU and single small EGU. Based on the emission rates of these EGUs, the

EPA analyzed the achievable emission rates using different combinations of steam cycles, coal

types, cooling equipment, and ambient conditions. In this final rule, the EPA is confirming that

approach and incorporating emissions data from 2018 and 2019. When the additional data is

incorporated, Weston 4 is still the best performing large EGU and Wygen III is still the best

performing small EGU. The EPA analyzed the operations of Weston 4 and Wygen III using

different combinations of types of fuel, cooling equipment, and ambient conditions, and

determined that large units could achieve a 1,800 lb CO2/MWh-gross standard under a range of

conditions and small EGUs could achieve a 2,000 lb CO2/MWh-gross standard under a range of

conditions. Consistent with the 2018 Proposal, the range of conditions the EPA is confirming are

appropriate to consider are high ambient temperatures, the use of water efficient cooling

technologies, and the use of various fuel types. Because some areas of the county that have

limited water resources also have high ambient temperatures, the EPA has determined that the

NSPS should be achievable for new coal-fired EGUs that use dry cooling and are located in areas

with high ambient temperatures.117 The EPA is also confirming that it is appropriate for the

NSPS to maintain the ability to use subbituminous, lignite, and coal refuse with the identified

BSER.

Consistent with the 2018 Proposal, the EPA reviewed reported annual emissions data to

identify the coal-fired EGUs with consistently low emission rates. The EPA then reviewed 117 Duty cycle is the average operating capacity factor.


reported monthly data to determine 12-operating month emission rates. Based on the reported

emission rates, two large coal-fired EGUs have been able to maintain 12-operating month

emission rates of 1,800 lb CO2/MWh-gross, Weston 4 and Cliffside 6. Weston 4 is a supercritical

subbituminous-fired EGU located in Wisconsin that uses a cooling tower and has a 12-operating

month 99 percent confidence emissions rate of 1,770 lb CO2/MWh-gross. Cliffside 6 is a

supercritical bituminous-fired EGU located in North Carolina that uses a cooling tower, and also

has a 12-operating month 99 percent confidence emissions rate of 1,770 lb CO2/MWh-gross.118

Sandow 5B is the best performing lignite-fired EGU. Sandow 5B is a subcritical lignite-fired

EGU located in Texas that uses a cooling tower and has a 12-operating month 99 percent

confidence emissions rate of 2,040 lb CO2/MWh-gross. When design conditions are taken into

account, Weston 4 is the single best performing EGU in the U.S. Consistent with the

methodology used in the 2018 Proposal, the EPA used the normalization of the emissions data

for the best performing EGUs using various steam cycles, coal types, ambient conditions, and

cooling technologies to determine an appropriate nationwide emissions standard. Based on the

Weston 4 emissions data, the EPA has determined that an emissions standard of 1,800 lb

CO2/MWh-gross is an appropriate nationwide standard that is achievable by a new bituminous-

fired EGU using the highest steam temperatures and pressure currently in use in combination

with dry cooling and the best operating practices. Similarly, a new subbituminous-fired EGU

could meet the 1,800 lb CO2/MWh-gross standard using the highest stream temperatures and

pressures offered by any vendor,119 best operating practices, and dry cooling. A new

subbituminous-fired EGU using the highest steam temperatures and pressures currently in use120

118 For additional details on the EPA’s non-base load emissions analysis see the TSD available in the docket.119 See the TSD “Low-Rank Coal Upgrading and Drying” available in the docket.120 For example, the steam turbine in unit 2 was upgraded. Four Years of Operating Experience with DryFining TM Fuel Enhancement Process at Coal Creek Generating Station, Journal of Energy and Power Engineering 9 (2015) 526-538.


would have to use a cooling tower or, if the EGU is located in an area with lower ambient

temperatures, it could use a hybrid cooling tower, to comply with an emissions standard of 1,800

lb CO2/MWh-gross. Based on the Weston 4 data, the EPA also estimated a lignite or petroleum

coke121-fired EGU could use a cooling tower and highest steam temperatures and pressures

offered by any vendor to comply with an emissions rate of 1,800 lb CO2/MWh-gross. However,

if the lignite is dried using an integrated pre-combustion dryer and the credit for the useful

thermal output is accounted for, a developer could elect to use standard supercritical steam

conditions in combination with dry cooling technology. For additional details on the emissions

data analysis, see the emissions standard TSD.

The EPA has determined that an emissions rate of 1,800 lb CO2/MWh-gross for large

EGUs is the most stringent emissions rate achievable by new coal-fired EGUs considering the

use of commonly used coal types and incorporation of water conserving technologies. If the EPA

were to finalize a more stringent standard of 1,700 lb CO2/MWh-gross, developers of new coal-

fired EGUs using the highest steam temperatures and pressures offered by any vendor would be

limited to the use of medium or low sulfur bituminous coal in combination with a cooling tower

or the use of lignite with integrated coal drying. According to data reported under EIA form 923,

in 2018 subbituminous coal constituted 54 percent of the coal used for power generation and, as

described elsewhere in this document, water use is a critical limitation for development of new

fossil fuel-fired EGUs. Therefore, these limitations would not be appropriate for a nationally

applicable requirement. The EPA has determined that a higher standard of 1,900 lb CO2/MWh-

gross is also not appropriate because the owners/operators of subbituminous or bituminous-fired

EGUs would not need to apply the BSER to comply and instead would be able to comply by

121 The reported efficiency improvement from the integrated drying is 3.5 percent on a net basis.


applying the best available subcritical steam conditions in combination with either a cooling

tower or hybrid cooling.

With respect to small EGUs, the EPA is finalizing a standard of 2,000 lb CO2/MWh-

gross. Based on annual reported emission rates, five small subcritical EGUs have maintained this

level on an annual basis. All five are bituminous-fired, and four of the five use open cooling

systems. These plants make clear that a bituminous-fired EGU can achieve a standard of 2,000 lb

CO2/MWh-gross based on the BSER. In addition, the best performing small subcritical EGU

using subbituminous coal is Wygen III, located in Wyoming, which uses dry cooling and has a

12-operating month 99 percent confidence emissions rate of 2,270 lb CO2/MWh-gross. The

relatively high emissions rate of the Wygen III EGU is a result of the use of relatively low steam

temperatures and pressures122 and that the facility does not have a reheat cycle. Based on the

Wygen III emissions data, the EPA has determined that an emissions standard of 2,000 lb

CO2/MWh-gross is an appropriate nationwide standard that is achievable by a new

subbituminous-fired EGU using the highest subcritical steam temperatures and pressures123 and

dry cooling in combination with the best operating practices. While a lignite-fired EGU using the

highest subcritical steam temperatures and pressures would not be able to comply with an

emissions rate of 2,000 lb CO2/MWh-gross using dry cooling, a new lignite-fired EGU could

comply using either hybrid cooling or by incorporating lignite drying into the design. The EPA

has determined that a more stringent standard of 1,900 lb CO2/MWh-gross would be too

geographically limiting since a subbituminous-fired EGU using hybrid or dry cooling would not

be able to achieve this emissions rate. Therefore, developers of new small EGUs would be

limited to the use of bituminous coal, lignite in combination with integrated coal drying, or

122 Both units were retired in 2018 due to economic factors.123 Since units 5A and 5B are identical designs, the EPA determined it was appropriate to use the higher reported emissions rate when determining an achievable emissions rate.


subbituminous coal in combination with a cooling tower. The EPA has determined that a less

stringent standard would also not be appropriate because an owner/operator of a new coal-fired

EGU would not need to use the highest available subcritical steam temperature or pressure,

which was identified as the BSER, to comply.

To further evaluate the emissions standard for small subcritical coal-fired EGUs, the EPA

evaluated the emission rates of HL Spurlock 3 and 4. Both are high performing bituminous-fired

subcritical EGUs—using steam conditions of 17.4 MPa and 541 oC with a single reheat cycle—

located in Kentucky that use cooling towers. Based on operational data from 2009 through 2019,

the 99 percent confidence limit emission rates of units 3 and 4 are 1,910 lb CO2/MWh-gross and

1,830 lb CO2/MWh-gross respectively. Holding other design criteria constant, increasing the

steam pressure and temperature to the maximum subcritical steam conditions (21 MPa and 570

oC) and assuming the use of subbituminous coal and dry coolings increases the achievable

emissions rate to 2,070 lb CO2/MWh-gross and 1,990 lb CO2/MWh-gross, respectively. The

emissions data from HL Spurlock 4 confirms that an emissions standard of 2,000 lb CO2/MWh-

gross is an appropriate nationwide standard for small subbituminous EGUs apply the BSER,

E. Subcategorization and Level of the Standard for Non-Base Load Units

This section describes the EPA solicitation for comment on creating a non-base load unit

subcategory, the comments received on the solicitation, and the Agency’s response to those

comments. It also includes the EPA’s rationale for its determination in this final rule that a non-

base load unit subcategory is appropriate. Finally, this section includes a summary of the

analyses the EPA conducted124 to arrive at a non-base load subcategory standard that is 100 lb

CO2/MWh-gross higher than the base load standard for each subcategory.

124 Even using a cooling tower, the lowest achievable emissions rate for a subcritical lignite-fired EGU is in excess of 2,000 lb CO2/MWh-gross and the lowest achievable emissions rate for a supercritical EGU using the highest steam temperatures and pressures offered by a vendor is in excess of 1,800 lb CO2/MWh-gross.


1. Non-Base Load Unit Subcategory

As the EPA stated in the 2018 Proposal, coal-fired EGU efficiency tends to be relatively

stable from full load to approximately 65 percent load, but operation at lower loads results in

significant reductions in efficiencies. Because of the difference in efficiency, the EPA solicited

comment on whether it would be appropriate to establish a subcategory with a separate emissions

standard for coal-fired EGUs during 12-month rolling average periods when the unit is not

operated at base load conditions.125 Specifically, the Agency solicited comment on a subcategory

for units that operate at less than a 65 percent duty cycle during any 12-operating month period,

with standards of performance that would be 200 lb CO2/MWh-gross higher than the standards

for the base load subcategory. The EPA also solicited comment on establishing a non-base load

heat input-based standard (similar to the non-base load standard for combustion turbines) as an

alternate or in place of the non-base load output-based standard. 83 FR 65457

Some commenters supported a separate non-base load subcategory because coal-fired

EGUs cannot operate as efficiently at low loads as they can during full load operation and the

general industry trend has been for coal-fired EGUs increasingly to operate at lower loads than

historical industry norms. As a result, according to the commenters, a standard based on optimal

load conditions may not be consistently achievable for new EGUs over the long term. The

commenters urged that, in order to ensure the NSPS is achievable under all operating conditions

a unit could reasonably be expected to operate over its lifetime, the EPA should account for low

load operation either through subcategorization, adoption of a separate non-base load standard,

adjusting the proposed standard to be achievable at low loads, or some other method. The

commenters said that they do not have sufficient information to assess the adequacy of the

125 Since the definition of useful thermal output includes that “thermal energy used to reduce fuel moisture is considered useful thermal output” energy used for integrated coal drying would be added to the electric output when determining the emissions rate.


Agency’s proposed use of a partial load heat input-based standard, but a heat input‐based

standard may create challenges given the current capabilities of continuous monitoring and

reporting systems.

Other commenters opposed a non-base load subcategory, saying that such a standard

would not reduce emissions associated with generation of electric power, but instead, would

amount to an endorsement of current inefficient and wasteful practices. They said the EPA

should neither encourage nor permit technologies designed for base load applications to operate

in peaking or load following applications. Furthermore, they added, the EPA’s in-use

performance data from existing coal plants that it relied on to set the standard reflect at least as

much non-base load operation as would be anticipated from brand new, highly efficient units,

and probably much more non-base load operation. As a result, the Agency’s standard already

accounts for this operational mode, and there is no justification for a separate and weaker

standard for coal units that operate in load-following or peaking capacity. The commenters

further stated that it would be irrational to base any coal plant standard exclusively on input

factors without also determining a minimum level of efficiency. Subcategorization in this

manner would only encourage or facilitate non-base load operation that the EPA admits is a far

less efficient mode of operation for new EGUs. The commenters asserted that whatever emission

limit the EPA ultimately selects, it must assume that all new, reconstructed, and modified plants

are operated and maintained in their most efficient mode. It must also reflect advances in plant

design that improve non-base load efficiency compared to older technologies.

The EPA agrees with commenters that a heat input-based non-base load standard is not

appropriate. It would not recognize the environmental benefits of efficient operation and could

encourage owners/operators to operate their EGUs at non-base load higher emitting conditions to


qualify for the less stringent standard. In addition, the EPA has determined there is sufficient

data to establish an efficiency-based standard that is more environmentally protective than a heat

input-based approach.

The EPA agrees with commenters stating that a non-base load standard is necessary to

account for the inherently lower efficiency of EGUs operating at low loads. As stated in the 2018

Proposal, EGUs operating at low loads lose efficiency and could have difficulty complying with

an emissions standard that reflects the efficiencies achieved at higher operating loads. Without a

non-base load standard, owners/operators of coal-fired EGUs could have limited ability to

respond to fluctuations in electric demand, essentially eliminating new coal-fired EGUs using an

efficiency-based BSER. Therefore, the EPA has determined that it is appropriate to include a

non-base load subcategory for 12-month operating periods where the duty cycle (i.e., the average

operating capacity factor) is less than 65 percent. EGUs operating at less than a 65 percent duty

cycle are considered non-base load units, while EGUs operating with a 65 percent or greater duty

cycle are considered base load EGUs. The EPA disagrees with commenters asserting that an

output-based non-base load standard would provide a regulatory incentive to operate at part load

because, as described below, the final standard is based on the performance of EGUs using best

operating practices. Therefore, owners/operators would have to continue to follow the same

maintenance and operating practices to comply with the base load and non-base load standard.

2. Non-Base Load Unit Emissions Standard

In the 2018 Proposal, the EPA suggested that the decreased efficiency would result in an

emissions increase of 200 lb CO2/MWh-gross for all of the proposed subcategories. 83 FR

64457. The EPA conducted additional data analysis for this final rule to determine both an


appropriate 12-operating month duty cycle non-base load threshold and the increase in emissions

that results from operating as a non-base load unit.

The first aspect of determining a non-base load standard is determining the load threshold

between base load and non-base load operation. As described in the 2018 Proposal, the EPA

calculates the threshold on the basis of the 12-operating month duty cycle. 83 FR 65456 through

65457. The duty cycle is the average capacity factor of the EGU considering periods of

operation. For example, if an EGU operates at a 90 percent steady state load for the first 6

months of the year and then shuts down for the remaining 6 months, the annual capacity factor is

45 percent. Even though the best performing EGUs have periods of operation at lower loads, the

minimum 12-operating month duty cycle of the best performing EGUs is greater than 65 percent.

One of the challenges with determining an appropriate non-base load standard is that the

best performing EGUs tend to operate at high loads and high 12-operating month average duty

cycles.126 To determine the appropriate 12-operating month duty cycle non-base load threshold,

the EPA evaluated CAMD data from six different units (Cliffside 6, Weston 4, HL Spurlock 3,

HL Spurlock 4, Yorktown Power Station 1, and Yorktown Power Station 2) from the years 2012-

2018. The EPA selected these EGUs because they are high performing units and had sufficient

hours of operation at lower loads to facilitate comparison of the emission rates at low and high

loads. Distributions of hourly capacity factor, generation, and emissions rate were bimodal. The

upper portions of those distributions corresponded to base load operation while the lower

portions corresponded to non-base load operation. The EPA defined the unit specific midpoints

between the upper and lower portions of the hourly capacity factor based on corresponding

values of hourly generation within ± 5 percent of the average of the lower 2.5 and upper 97.5

126 The Seward EGU is the largest coal refuse-fired EGU in the world and the newest coal refuse-fired EGU in the U.S.


percentile of the distribution of hourly generation. The lower 95 percent confidence interval in

the mean of those unit specific midpoint capacity factors was equal to 65 percent. This represents

the lower bound of the capacity factor at base load operation and is an appropriate definition of

the duty cycle threshold.

The EPA then determined that the appropriate standard of performance for large EGUs at

12-operating month duty cycles below 65 percent is 1,900 lb CO2/MWh-gross. The EPA did so

by evaluating the operation of the best performing EGUs at loads below 65 percent. The EPA

used two different approaches. In the first, each calendar month with any operation in low load

(hourly capacity factor < 65 percent) was determined. In each subsequent month after the first 11

months in the list of low-load months, the EPA determined the CO2 emissions rate on a

generation basis (lb CO2/MWh) by taking the sum of CO2 emissions from the preceding 12

months and dividing by the sum of generation (MWh) from the preceding 12 months, noting that

the preceding 12 months omit those months in which the unit was not operated in low load and

that the data included in the summations were those data designated as low load. The EPA also

omitted from the analysis hourly data for which the unit was operated for less than the full hour.

The 99 percent 12-month emission rates for low load were 1,866.0 lb CO2/MWh for Cliffside-6

and 1,891.9 lb CO2/MWh for Weston 4, which are both slightly below 1,900 lb CO2/MWh-gross.

In this first method, it should be noted that Cliffside 6 operates at low loads for 25 percent of its

operating hours and Weston 4 operates at low loads for 26 percent of its operating hours. The

data used may include more variability than a unit that theoretically operates continuously at low

loads below 65 percent. This could result in slightly higher estimates of the 99 percent upper

prediction interval.


In the second method, the EPA collected data at low loads for each month regardless of

the operating year. The EPA then randomly sampled the data to produce a continuous 2-year

period of theoretical operation below 65 percent. Using this compiled dataset, the 99 percent 12-

month emission rates were determined as in the first method. From this method, the 99 percent

12-month emission rates for low load were 1,781.1 lb CO2/MWh-gross for Cliffside-6 and

1,834.4 lb CO2/MWh-gross for Weston 4. Results from the second method are lower than from

the first method because the second method does not include the year to year variability that may

occur in operation. Actual performance for a unit that operates at or below 65 percent for a 12-

month duty cycle may fall somewhere between the two scenarios represented by the first and

second method and may also include some operation at higher loads.

From the results of the two analyses for non-base load operation, the higher of the two 99

percent 12-operating month CO2 emission rates for the best performer (Cliffside-6) has a value

of 1,900 lb CO2/MWh when rounded to two significant digits. This is also true for Weston-4. As

this value is greater than the 99 percent rate, there is a less than one percent probability that the

12-operating month CO2 emission rate would be greater than 1,900 lb CO2/MWh for a unit

operating as a non-load EGU. It may therefore be concluded that operation of the best performers

would be less than 1,900 lb CO2/MWh for units that operate with a 12-operating month duty

cycle that is less than 65 percent. Further, the EPA notes that the non-base load emission rate is

100 lb CO2/MWh greater than the standard (1,800 lb CO2/MWh) for base load operation.

The previously described non-base load analyses could not adequately be performed for

coal refuse fired EGUs and small EGUs. CAMD data are not reported for coal-refuse fired EGUs

and hourly data for small EGUs (e.g. Wygen III) operating at non-base load are limited.

However, the Agency has not identified any reasons why the performance of small and coal


refuse-fired EGUs operating under non-base load conditions would be different than large EGUs.

Therefore, the EPA expects the same increase in emissions—relative to the base load emissions

—rate for all EGUs. Therefore this final rule includes a non-base load standard for large, small,

and coal refuse-fired EGUs that is 100 lb CO2/MWh higher than the base load standard .

F. Lignite and Coal Refuse Subcategorization

This section describes the EPA’s solicitation for comment on establishing a subcategory

for lignite-fired EGUs, the comments received and the Agency’s response to those comments,

and the rationale for not establishing a subcategory for lignite-fired EGUs in this final rule. This

section also describes the coal refuse-fired EGU subcategory the EPA includes in the 2018

Proposal, the comments received on the proposed subcategory and the Agency’s response to

those comments, and the rationale for establishing a subcategory and for the coal refuse-fired

subcategory emissions standard in this final rule.

Except for coal refuse, the 2018 Proposal did not include subcategorization by fuel type

(although the proposal did solicit comments on that approach) for several reasons. The EPA

explained that subcategorizing by fuel type could have the perverse impact of both increasing

emissions and decreasing compliance options. Moreover, as the EPA explained, if the emissions

standard is based on the specific fuel combusted, subcategorization based on the fuel with the

highest percentage heat input could give owners/operators an incentive to burn sufficient

amounts of higher emitting fuels to qualify for a less stringent emissions standard. For example,

were the EPA to promulgate a less stringent standard for lignite than for subbituminous, a facility

that blends subbituminous and lignite would have an incentive to burn higher amounts of lignite

(even though lignite is higher emitting) in order to qualify for the less stringent standard. In

addition, if the applicable standard depends on the percentage of each fuel burned, the


owners/operators would be constrained from using natural gas (or other lower emitting fuels) as

compliance options because doing so would subject them to a more stringent emissions standard.

Therefore, subcategorizations by fuel type fails to recognize the environmental benefit of using

lower emitting fuels or integrated non-emitting (e.g., renewable) electric generation. The EPA

further stated in the 2018 Proposal that the proposed fuel-neutral standard is consistent with the

emissions standards in the criteria pollutant NSPS and is achievable for all coal types. 83 FR

65456.

[1.] Lignite Subcategory

This section summarizes the comments received on the Agency’s solicitation of comment

on establishing a subcategory for lignite-fired EGUs and the Agency’s rationale for why it has

determined that a subcategory is not appropriate in this final rule.

Some commenters stated that the EPA should subcategorize based on the type of coal

combusted because there are substantial differences in the CO2 emissions associated with

different coal types that should be reflected in the standards applicable to their combustion, and

that at the very least, the Agency should subcategorize new lignite-fired EGUs separately from

other coal types as data for these units show that the newest lignite-fired EGUs designed with

supercritical steam conditions have exceeded the proposed standard (1,900 lb CO2/MWh-gross)

by a margin of 250-300 lb CO2/MWh-gross, or 13 to 16 percent. The commenters stated that if

the EPA does not subcategorize its standards of performance based on coal type, then it must at

least assure that the standards are achievable for all coal types through application of the BSER.

Commenters state that the 2018 Proposal notes that a large EGU combusting subbituminous or

lignite coal would need to implement ultra- or advanced ultra-supercritical steam conditions in

order to achieve a CO2 emission rate of 1,900 lb CO2/MWh-gross. 83 FR 65451. Thus, according


to commenters, if the EPA finalizes a single standard for all large and all small coal-fired EGUs,

then the standard must reflect what a unit combusting undried lignite can achieve with

supercritical steam conditions. Commenters disagreed with the EPA’s position in the 2018

Proposal that creating a new subcategory for lignite would incentivize the burning of lignite,

instead of higher-quality coal. They explained that, as a practical matter, it is only economically

feasible to burn lignite in the few areas of the country where lignite reserves are located.

Accordingly, they added, new coal-fired EGUs will not be designed to fire only small amounts

of lignite; rather, if a new lignite unit is constructed in the future, it would be designed to fully

fire lignite. They stated that not promulgating a lignite subcategory would effectively prohibit the

construction of any lignite-fueled units in the future. Additionally, the commenters disagreed

with the 2018 Proposal’s statements that lignite units could employ coal drying to meet the

proposed standard. They stated that coal drying has been demonstrated in only a few instances

and that the cost to install these systems is prohibitive. These commenters explained that the use

of coal drying technology is still in an experimental stage in the U.S., and some technical and

safety issues have yet to be resolved. The commenters also said the EPA previously created a

lignite subcategory for the Mercury and Air Toxics Standards (MATS), and the same factors

support a subcategory for lignite here. Commenters asserted that, although in the MATS Rule the

main emission limit distinction between existing non-lignite units and existing lignite units is for

Hg, the same principle should apply for CO2 emissions because (1) the most recent data shows

that lignite-fueled units cannot meet the emissions standards of the proposed rule and (2) the

EPA has determined that it should not, and is not legally authorized to, set emissions standards

such that they determine fuel choices.


Other commenters said that the EPA should not subcategorize by fuel type because lower

CO2 emitting bituminous coal is common, commercially available, economically reasonable, and

can be shipped. The commenters said that, therefore, bituminous coal should be used in

designating the BSER and setting the emissions standard. The commenters further said that the

only circumstance in which the Agency should subcategorize based on coal type is if it rejects

the use of bituminous coal as an element of the BSER. They said if the EPA nevertheless insists

on excluding considerations of fuel rank from the BSER, it must not issue a single standard that

caters to the lowest-rank coal, but instead must issue separate standards for different coal types

so as to avoid granting plants firing bituminous coal an arbitrary and unjustified “bonus” in their

emission standard.

The EPA disagrees with commenters that stated that lignite drying is still in the

experimental stages and that it is cost prohibitive. The technology has been successfully

deployed at an existing EGU for multiple years. While integrated drying at an existing and

modified power plant is site-specific and the potential benefits and costs depend on the available

heat sources, space constraints, and general layout of the plant, there are significant benefits for

newly constructed and reconstructed lignite-fired EGUs. Specifically, integrated drying offers

significant boiler island capital and operating costs savings for newly constructed and

reconstructed EGUs that offset the costs of the coal drying.127 The EPA further disagrees with the

commenters’ suggestion that the lignite-fired subcategory in MATS justifies a subcategory for

GHG emissions. The MATS rulemaking used different criteria to determine subcategorization

that are not relevant to NSPS rulemaking. The Agency notes that recent revisions to the coal-

fired EGU criteria pollutant NSPS do not include a subcategory for lignite-fired EGUs. As

127 This emissions rate does not account for CO2 that is created as part of controlling SO2 emissions or variability.


discussed previously, the EPA also disagrees with commenters that suggest the standard should

be based on the use of bituminous coal.

The comments suggesting that lignite-fired EGUs cannot achieve the same emissions rate

as subbituminous coal do not account for the emission reduction potential due to coal drying. As

described in the 2018 Proposal, coal drying increases the heating value of the fuel, improving the

efficiency of the boiler. Coal drying has been in operation in the U.S. since 2009. Specifically,

the lignite-fired Coal Creek 1 and 2 stations in North Dakota installed integrated coal drying at

the end of 2009. The average emissions rate prior to installing coal drying were 2,290 lb

CO2/MWh-gross and 2,240 lb CO2/MWh-gross respectively. After installation of the integrated

drying, the average emissions rates for Coal Creek 1 and 2 improved to 2,120 lb CO2/MWh-

gross and 2,100 lb CO2/MWh-gross respectively. While other improvements were done over this

period,128 the 7.5 percent and 6.2 percent reductions in emissions rate confirm the emissions

benefits of pre-combustion coal drying.129

As noted previously, based on the emission rates of the Weston 4 and Wygen III

facilities, lignite-fired EGUs with integrated coal drying would be able to comply with the final

standards in this rule. To confirm that finding and quantify the impact of pre-combustion coal-

drying relative to increased steam temperatures and pressures, the EPA evaluated the emission

rate of Sandow 5, the best performing domestic lignite-fired EGU. Sandow 5 is a subcritical

facility with two units, 5A and 5B, using a cooling tower, located in Texas, that operated from

2009 through 2018.130 The 99 percent confidence limit emission rates of units 5A and 5B are

128 If the average coal refuse-fired EGU efficiency were used as the baseline, the CO2 emissions reductions would be 24 percent.129 A supercritical topping cycle improves thermal efficiency by adding a new supercritical steam turbine that exhausts at the temperature, pressure, and flow of the existing steam turbine, allowing for reuse of existing infrastructure.130 Power Engineering International. Pushing the Steam Cycle Boundaries. Volume 20, Issue 4. April 1, 2012. Available at https://www.powerengineeringint.com/2012/04/01/pushing-the-steam-cycle-boundaries/.

https://www.powerengineeringint.com/2012/04/01/pushing-the-steam-cycle-boundaries/


2,070 lb CO2/MWh-gross and 2,040 lb CO2/MWh-gross respectively. For comparison purposes,

the EPA determined the impact of using higher steam temperatures and pressures for unit 5A.131

Holding other design criteria constant, increasing the steam pressure and temperature to the

maximum subcritical steam conditions (21 MPa and 570 oC) and supercritical conditions (24.1

MPa and 593 oC) would reduce the achievable emissions rate to 2,020 lb CO2/MWh-gross and

1,980 lb CO2/MWh-gross, respectively. Increasing the steam conditions to the highest currently

in use (30 MPa and 610 oC) and the highest currently offered by any vendor (33 MPa and 660

oC) would reduce the achievable emission rate to 1,940 lb CO2/MWh-gross and 1,880 lb

CO2/MWh-gross, respectively. This confirms that both small and large lignite-fired EGUs would

have to apply the entire BSER, which includes pre-combustion drying of moisture rich fuels, to

comply with the emission standards in this final rule.132

In comparison, the use of coal drying can lower emission rates more than increasing

steam conditions. Holding other design criteria constant (e.g., maintaining the Sandow 5 steam

conditions), increasing the heating value of the raw lignite by 30 percent through the use of

waste heat would reduce the achievable emissions rate to 2,020 lb CO2/MWh-gross directly due

to the reduced moisture in the fuel. In addition, the 2015 Rule provided that heat used for

integrated coal drying is considered useful thermal output and is credited when determining the

40 CFR part 60, subpart TTTT emissions rate.133 Assuming 8 percent of the overall output is

useful thermal output reduces the achievable emissions rate to 1,870 lb CO2/MWh-gross. This 10

percent reduction in the achievable emissions rate is approximately equivalent to increasing the

steam conditions to the highest currently offered by any vendor. Combining integrated coal

drying (i.e., using the facility’s waste heat to dry its fuel) and increasing steam conditions to the 131 The ADI is available at https://cfpub.epa.gov/adi/.132 https://carboncapturecoalition.org/wp-content/uploads/2019/06/Final-CCC-submission-to-Treasury-6-28-19.pdf.133 https://www.netl.doe.gov/LCA/CO2U.


highest currently in use results in an achievable emissions rate of 1,750 lb CO2/MWh-gross. This

confirms that the emissions standard in this final rule is achievable for lignite-fired EGUs that

incorporate pre-combustion drying and using cooling towers. As described previously, the EPA

has confirmed that it is appropriate for the NSPS to preserve the option to use dry cooling. Based

on the performance of Sandow 5A, a new lignite-fired EGU that incorporates integrated coal

drying with dry cooling and the best available subcritical steam temperatures and pressures

would be able to maintain an emissions rate of 1,910 lb CO2/MWh-gross. Increasing steam

conditions to the highest offered by any vendor results in an achievable emissions rate of 1,780

lb CO2/MWh-gross. Therefore, because lignite is able to achieve the emissions standard in this

final rule with the identified BSER, it would not be appropriate to subcategorize lignite-fired

EGUs. For details on the emissions calculations see the emissions standard achievability TSD.

2. Coal Refuse

The EPA included a subcategory for coal refuse-fired EGUs in the 2018 Proposal due to

both the environmental benefits of remediating coal refuse piles and the inherently higher

emission rates of coal refuse-fired EGUs. This section summarizes the coal refuse related

comments and the Agency’s response to those comments, and the rationale for the subcategory

and emissions standard in this final rule.

Coal refuse (also called waste coal) is a combustible material containing a significant

amount of coal mixed with rock, shale, slate, clay, and other material that is reclaimed from

refuse piles remaining at the sites of past or abandoned coal mining operations. Under the 2015

Rule, due to lower efficiencies and higher uncontrolled emission rates, coal refuse-fired EGUs

would have had to install a slightly higher percentage of partial CCS, increasing costs roughly in

proportion to the percentage increase in partial CCS. This increase in costs was determined to be


sufficiently small that a subcategory for coal refuse-fired EGUs was not necessary. The 2018

proposed BSER (and the corresponding emissions rate) for coal-fired EGUs (including coal

refuse-fired EGUs) is efficient generation and not the use of partial CCS. Therefore, the EPA

noted in the 2018 Proposal that the cost rationale for not providing a subcategory for coal refuse-

fired EGUs outlined in the 2015 Rule is not necessarily applicable. The EPA also noted multiple

reasons beyond the control of the owner/operator that coal refuse-fired EGUs have higher

uncontrolled emission rates than EGUs burning primary coals. In acknowledgement of these

factors and due to the multiple environmental benefits of remediating coal refuse piles, the EPA

proposed to subcategorize all coal refuse-fired EGUs, including units larger than 2,000

MMBtu/h, with an emissions rate 20 percent greater than the standard for other small EGUs. 83

FR 65449 (December 20, 2018).

Some commenters stated support for the creation of a coal refuse fuel subcategory

because the heating value of coal refuse is drastically lower than other fuels. These commenters

added that these units serve a vital need and have an overall positive impact on the environment

due to the many non-air quality health and environmental benefits associated with their

operations, which stem from remediating coal refuse piles.

Other commenters said that the 2018 Proposal provides no adequate justification for

subcategorization and that the proposed coal refuse standard does not reflect the full degree of

emission limitation achievable for this type of EGU. Commenters said there is no reason to

expect coal-refuse units to operate significantly less efficiently (in terms of amount of output per

heat input) because CFB boilers contain a significant amount of sand and other ballast regardless

of fuel. The commenters examined CFB and coal refuse data and claimed that coal refuse boilers

are expected to emit roughly 10 percent more than bituminous fuel boilers for any given


efficiency and that emission rates for CFB EGUs at a 99 percent confidence level are well below

the EPA’s proposed standard of 2,200 lb CO2/MWh-gross. According to these commenters, the

EPA also did not use available data on CFB-fired EGUs or coal refuse-fired EGUs when

determining the coal refuse-fired EGU standard.

The EPA disagrees with commenters’ suggestions that coal refuse-fired EGUs emit only

10 percent more than bituminous-fired EGUs. The 10 percent value cited by commenters is

based solely on the heat input-based emissions rate of a coal refuse-fired unit relative to a

bituminous-fired unit and fails to consider several important factors that impact the efficiency of

the EGU. First, the sand that is used to fluidize the bed is recirculated in the boiler so there is

minimal energy loss from heating the sand bed. However, non-coal mineral component (i.e., ash)

particles that exist in the boiler are not recirculated and are instead captured by the PM control

device. Because these particles are hot, they represent an energy loss that is not available to

produce steam and electricity. Because coal refuse contains significant amounts of non-coal

mineral component relative to bituminous coal, this results in a greater relative emissions impact.

Even more important are the characteristics of the non-coal mineral component of coal refuse.

Depending on the source of the coal refuse, the non-coal minerals may contain significant

quantities of moisture within clay constituents. When fired, the water-containing clay

constituents can have a significant, negative impact on the thermal efficiency of the steam

generator. The energy required to vaporize and raise the temperature of the moisture cannot be

recovered in coal-fired boilers and is lost through the exhaust stack. In addition, spontaneous

combustion of coal refuse piles increases the porosity of the coal refuse (similar to making

porous charcoal). After the spontaneous fires are extinguished (either by human intervention or

by heavy rains) the increased porosity of the coal allows it to absorb additional moisture, further


reducing the quantity of energy released that is available for creating steam and subsequently

electricity. As stated in the 2018 Proposal, unlike with “wet” coals such as lignite, there are

limited options to remove this moisture prior to combustion. The spontaneous combustion also

results in more ash content in coal refuse, which, like non-mineral content, reduces efficiency.

Furthermore, to control sulfur emissions from coal refuse piles containing high amounts of sulfur

(which present the greatest environmental benefit to remediate), significant quantities of

limestone are added to the fluidized bed boilers. This not only decreases efficiency (due to the

additional fuel required to calcine the limestone) but leads to chemically created CO2 (released

when the limestone is calcined to lime) that is released through the stack.

The EPA reviewed emissions data for the four subcritical CFB units suggested by

commenters. Two of the units burn bituminous coal and two burn lignite. All use recirculating

cooling towers for steam condensing. The 12-operating month 99 percent confidence emission

rates for these units range from 1,830 to 2,070 lb CO2/MWh-gross. Based on the lowest emitting

of the four units, commenters suggested that an emissions rate of 2,030 lb CO2/MWh-gross is

achievable for a new coal refuse-fired EGU. However, as described previously, this only

accounts for the 10 percent difference in the heat input-based emissions rate of coal refuse

relative to bituminous coal and does not account for the efficiency impact of the increased

moisture in coal refuse, the non-coal mineral and ash content, or the additional CO2 emissions

due to controlling emissions of SO2 from high sulfur content coal refuse. When the impact of the

increased moisture (i.e., lower heating value) alone is accounted for, the achievable emissions

rate based on the best performing of the four EGUs is 2,180 lb CO2/MWh-gross. It should be

noted that the EGUs cited by the commenters do not use the best available subcritical steam

temperatures and pressures (which would lower the achievable emissions rate) or water


conserving cooling systems (which would increase the achievable emissions rate). In general,

those efficiency impacts would cancel each other out (at least if a hybrid cooling tower were

used), resulting in an achievable emissions rate of 2,180 lb CO2/MWh-gross for a new coal

refuse-fired EGU. If a dry cooling tower is assumed, which is consistent with the approach the

EPA has adopted for establishing an appropriate NSPS, the achievable emissions rate for a new

coal refuse-fired EGU, based on the EGUs suggested by the commenters, is 2,230 lb CO2/MWh-

gross. The EPA notes that this rate still does not include consideration of additional CO2

generated as part of the SO2 emission control system.

As stated in the 2018 Proposal, there is limited operating data specific to coal refuse-fired

EGUs to use as a basis for the coal refuse subcategory. Of the 14 units reporting data to CAMD,

only two report both the gross output and CO2 emissions. However, both of these facilities are

CHP projects and, because neither reports its useful thermal output, the EPA is not able to

calculate their overall efficiency. To further evaluate the efficiency of coal refuse-fired EGUs,

the EPA reviewed annual efficiency data reported under EIA form 923. According to that data,

in 2016 the average net efficiency of the eight non-CHP coal refuse-fired EGUs was 26.2

percent. The Seward facility, located in Indiana County, PA, reported the highest net efficiency

of 32.1 percent. Seward is a subcritical facility with two 3,180 MMBtu/h boilers and a nameplate

capacity of 525 MW. 134 Its EIA form 923 reported efficiencies in 2017 and 2018 were 30.6

percent and 30.9 percent respectively. Using the 3-year average net efficiency of 31.2 percent, an

emissions rate of 228.6 lb CO2/MMBtu, and assuming 7.5 percent auxiliary load to convert the

net efficiency to a gross basis results in an estimated emissions rate of 2,310 lb CO2/MWh-gross.

Accounting for variability by assuming a continuously achievable emissions rate 4.4 percent

134 https://www.epa.gov/renewable-fuel-standard-program/lifecycle-analysis-greenhouse-gas-emissions-under-renewable-fuel.


higher than the average results in a continuously achievable emissions rate of 2,420 lb

CO2/MWh-gross.135 If Seward were to increase the steam conditions to the best available

subcritical conditions, the emissions rate would be reduced 3 percent to 2,340 lb CO2/MWh-

gross. If the steam conditions were further increased to the highest ultra-supercritical steam

conditions currently in use, the emissions would be reduced 6.7 percent to 2,180 lb CO2/MWh-

gross.

While the EIA form 923 reported efficiencies can be informative, as stated previously the

EPA considers CEMS data the best source of emissions data. Based on the normalization of the

Weston 4 emissions data, the EPA has determined that an emissions rate of 2,200 lb CO2/MWh

is achievable for a new coal refuse-fired EGU using dry cooling. A more stringent standard

would limit a new coal-refuse-fired EGU to using low sulfur coal refuse in combination with a

cooling tower, which would not be consistent with the range of conditions confronting the

industry and would limit the potential environmental benefit of reclamation activities.

The EPA has concluded that a subcategory for coal refuse-fired EGUs is appropriate, that

the BSER is the use of the best available subcritical steam conditions, and that the proposed

standard of 2,200 lb CO2/MWh-gross represents the degree of emission limitation achievable

through application of the BSER

The EPA notes that this standard is a significant reduction compared to business as usual.

Using the Seward facility as the baseline, the standard finalized in this rule represents a 9 percent

reduction in emissions.136

The EPA has also determined that requiring a more stringent standard for large coal

refuse-fired EGUs could result in unintended negative environmental outcomes. Coal refuse-

135 26 U.S.C. 45Q(f)(5)(B)(ii).136 Fossil fuel-fired EGUs also include combustion turbines, but the EPA is not promulgating any changes to standards for those types of sources in this rulemaking.

https://usepa.sharepoint.com/sites/OAR_Custom/111_b_egu_ghg_nsps_review/Shared%20Documents/111(b)%20Review%20(Final)/Preamble/26


fired EGUs are limited in size by the available quantities of coal refuse that can economically be

transported to the EGUs. With the exception of the Seward facility, all coal refuse-fired boilers

are less than 2,000 MMBtu/h. If the EPA were to establish a standard of 1,800 lb CO2/MWh-

gross for large coal refuse-fired EGUs, this standard would be unachievable through strictly

efficiency measures and, as a result, developers could be expected to limit the size of the facility

boilers to qualify for the small unit subcategory. This would result in fewer coal refuse piles

being remediated, foregoing the environmental benefits of doing so.

G. BSER and Standard for Reconstructed EGUs

Consistent with the 2015 Rule, the 2018 Proposal proposed that the BSER for

reconstructed EGUs is efficient generation. The EPA explained that this technology is

technically feasible, provides sufficient emission reductions, is of reasonable cost, and provides

some opportunity for technological innovation. Because the 2018 Proposal proposed the same

BSER for reconstructed EGUs as for new EGUs, the Agency proposed to use the same emissions

analysis and emission standards for reconstructed EGUs as it proposed for new ones. The EPA

rationale included the possibility that existing EGUs undertaking a reconstruction could repower

with higher temperature and pressure supercritical topping cycles.137 The use of a supercritical

topping cycle allows for the reuse of existing equipment and infrastructure, reducing overall

costs. The EPA also solicited comment on whether a single standard (consistent with the

standard for small EGUs) regardless of size for reconstructed EGUs is appropriate and whether

the existing reconstruction exemption in the general provisions (i.e., a reconstructed EGU will be

exempt from the requirement to meet the standard if the Administrator determines the standard is

not technically or economically achievable (40 CFR 60.15(b)(2))) is sufficient to account for

137 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.


circumstances in which a large reconstructed EGU would not be able to achieve the proposed

emissions standard. 83 FR 65448, 65449, and 65452.

Some commenters stated that the record does not support selection of conversion to

supercritical steam conditions as the BSER for reconstructed sources. They explained that

converting from subcritical temperatures and pressures to supercritical conditions has the

potential to affect all systems that come into contact with the steam cycle, but that neither the

2015 Rule nor the 2018 Proposal analyzes the changes that would be needed for such a

conversion, and that the record does not show that boiler conversion is feasible or adequately

demonstrated for reconstructed units, nor does the record include estimates of its cost. The

commenters said the record includes only one example worldwide in which an existing coal-fired

EGU was converted to a more advanced steam cycle, and that there is no evidence to suggest a

similar conversion would be possible at all units. Commenters also said that nothing in the CAA

references “reconstructions” at all—in the statute, the universe of units is divided only into “new

sources,” “existing sources,” and “modifications.” They said that the concept of an intermediate

type of source that is “reconstructed” is a creature only of the EPA’s regulations, and the EPA

has not provided any rational basis for doing so in the 2018 Proposal. On the contrary, they

stated, the EPA’s decision to craft a separate “reconstructed” unit standard appears grounded

only in regulatory inertia, which does not constitute reasoned rulemaking.

Other commenters said that they agree with the EPA’s proposal that for each of the

subcategories, the BSER and emissions standard for reconstructed EGUs must be the same as the

standard for new EGUs.

Consistent with the 2015 Rule, the EPA is finalizing its proposal that efficient generation

that results in the same emissions rate as for new units is the BSER for reconstructed EGUs. In


additional to the example of a coal-fired EGU retrofitting to a more advanced steam cycle cited

in the 2018 Proposal, the EPA notes that China has started a program to upgrade their existing

fleet of smaller subcritical coal-fired EGUs to supercritical steam conditions. The first example

of this program is the 300 MW Xuzhou unit 3 which was upgraded from 530 oC to 600 oC.

Furthermore, as the EPA noted in the 2015 Rule (80 FR 64601), while the final emission

standards are based on the identified BSER, a reconstructed EGU would not necessarily have to

rebuild the boiler to use steam temperatures and pressures that are higher than the original

design. A reconstructed unit is not required to meet the standards if doing so is deemed to be

“technologically and economically” infeasible. 40 CFR 60.15(b). This provision inherently

requires case-by-case reconstruction determinations in the light of considerations of economic

and technological feasibility. However, this case-by-case determination would consider the

identified BSER (the use of the best available steam conditions), as well as technologies the EPA

considered, but rejected, as BSER for a nationwide rule. One or more of these technologies could

be technically feasible and of reasonable cost, depending on site specific considerations and, if

so, would likely result in sufficient GHG reductions to comply with the applicable reconstructed

standards. Finally, in some cases, equipment upgrades and best operating practices would result

in sufficient reductions to achieve the reconstructed standards. For example, a double reheat

cycle can be retrofitted onto an existing plant, which is less expensive than installing a new

steam turbine.138

Further, commenters’ challenge to treating reconstructed units as separate from newly

constructed units is not well-taken. The EPA established the definition and underlying provisions

for reconstructions in 1975, see “Part 60—Standards of Performance for New Stationary Sources

138 The 2014 Proposed Rule applied to all fossil fuel-fired steam generating units, including natural gas and oil-fired EGUs, but the proposal of CCS as the BSER was limited to coal-fired EGUs.


—Modification, Notification, and Reconstruction,” 40 FR 58416 and 58417 (December 16,

1975) and is not re-opening them in this rulemaking. Even if a justification for those provisions

were necessary, a reconstruction is a type of construction of a new source. That is, section 111(a)

(2) defines a “new source” as “any stationary source, the construction … of which is commenced

[at a particular time].” The term “construction” is not defined under the CAA and is reasonably

interpreted to include the rebuilding of an existing source. Thus, the reconstruction provisions

are justifiable on grounds that a source that is rebuilt to the extent described in those provisions

may be considered a “stationary source [that has undertaken] construction….” See 40 FR 58417

(1975 rule adopting reconstruction provisions) (“the purpose of the reconstruction provision is to

recognize that replacement of many of the components of a facility can be substantially

equivalent to totally replacing it at the end of its useful life with a newly constructed affected

facility”).

H. BSER and Standard for Modified EGUs

In the 2018 Proposal, with respect to affected coal-fired EGUs that undergo

modifications that result in smaller increases in CO2 emissions (specifically, coal-fired EGUs

that conduct modifications resulting in an increase in hourly CO2 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 propose any standard of performance or other requirements. However, the EPA solicited

comment on the types of changes in operation or physical changes to a unit that could result in

small increases in hourly CO2 emissions. In addition, the Agency solicited comment on a BSER

and standard of performance for coal-fired EGUs that conduct small modifications.


Some commenters said that small modifications could easily be inadvertent as vendors of

EGU components are often conservative in their performance guarantees, which can lead to

unexpected and unintended—albeit very small—changes in emission rates, as new components

are installed to replace obsolete or worn-out ones. The commenters said that because small

modifications are likely to be inadvertent, they will be difficult to identify, and small

coincidental degradations in efficiency could give the appearance that a project caused an

increase in the emission rate even if that degradation was completely unrelated to the project and

the project itself had no real impact on emissions or efficiency levels at all. They argued that the

threat of this compliance uncertainty will be compounded by the risk of after-the-fact

enforcement actions, which could result in significant civil penalties. They said because of this, a

de minimis exemption is particularly appropriate for small increases in CO2 due to the nature of

the pollutant.

Other commenters said that a standard for EGUs that have small modifications is clearly

feasible, but the EPA’s solicitation of comment provides nowhere near the maximum practicable

level of control, as required under CAA section 111(b). They said a far more stringent emission

limit is not only technically feasible, but is required by the CAA. The commenters stated that

even without considering partial CCS or other alternatives, the standards the EPA solicited

comment on do not reflect the degree of reduction that is achievable and lag behind what is

achievable by modern coal-fired generating units utilizing efficient steam cycles and operating

practices. These commenters said the standards the EPA solicited comment on are, therefore,

arbitrary and unlawful.


The EPA is not taking action at this time to establish emission standards for EGUs that

undertake small modifications. The EPA continues to review information to establish appropriate

standards for small modifications.

In the 2015 Rule, the EPA accounted for EGUs that have already implemented best

practices and equipment upgrades by establishing a maximally stringent standard for

modifications such that modified facilities would not have to meet an emission standard more

stringent than the corresponding standard for reconstructed EGUs. 80 FR 64599. In the 2018

Proposal, the EPA continued to use the same rationale and proposed that the standard for

reconstructed EGUs be consistent with the numeric standard for new EGUs and that the standard

for modified EGUs be no lower than the standard for new EGUs. 83 FR 65431. As part of this

final rule, the EPA is amending the maximally stringent standard for modified EGUS to be

consistent with the standard for new and reconstructed EGUs.

VIII. Applicability and Miscellaneous Issues

A. Comments on Applicability

1. Applicability to Non-Fossil Fuel-Fired EGUs

In order to avoid unintentionally applying the requirements to certain non-fossil fuel-fired

EGUs, the EPA proposed in the 2018 Proposal to amend the 2015 Rule applicability criterion

that excludes EGUs capable of “combusting 50 percent or more non-fossil fuel.” As revised, the

criterion would exclude EGUs capable of “deriving 50 percent or more of the heat input from

non-fossil fuel at the base load rating.” 40 CFR 60.5509(b)(2) (emphasis added). The EPA

explained that 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

EPA also proposed to amend the definition of base load rating to include the heat input from

non-combustion sources (e.g., solar thermal). 40 CFR 60.5580. 83 FR 65430.

Some commenters stated that the EPA’s proposed applicability changes to 40 CFR part

60, subpart TTTT are appropriate. They said these changes would address concerns about the

regulation of solar thermal units. The commenters said the EPA’s proposed amendment should

be finalized, as subpart TTTT standards should be appropriately tailored to cover units that

primarily burn fossil fuels and not renewable energy resources or dedicated biomass-fired units

that may incidentally and infrequently use fossil fuels. Some commenters also said they believe

that the threshold of 10 percent or less fossil fuel firing on an annual basis is too low, and the

EPA should establish a higher threshold for fossil fuel firing. The EPA is finalizing the

definitions of a non-fossil fuel-fired EGU and the base load rating as proposed. The EPA did not

propose to amend and is not amending the current 10 percent fossil fuel threshold.

2. Industrial EGUs Electric Sales Threshold Permit Requirement

The current electric sales applicability exemption for non-CHP EGUs includes the

provision that EGUs 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” (emphasis added). Under the current applicability language, some onsite EGUs could be

covered by the existing source CAA section 111(d) requirements even if they have never sold

electricity to the grid. To avoid covering these industrial EGUs, the EPA solicited comment on

amending the electric sales exemption to read, “have never sold more than one-third of their

potential electric output or 219,000 MWh, whichever is greater, and are always has 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” (emphasis added).

Some commenters stated that they believe the proposed language amending the electric

sales exemption is beneficial and should be adopted. They said that certain EGUs have never

sold individually more than 219,000 MWh of electricity to the grid. However, these units have

never had a federally enforceable permit condition that restricted such sales. Thus, under the

current language in 40 CFR part 60, subpart TTTT, these units could not satisfy this requirement

for an exemption based on electric sales. The modified language in the 2018 Proposal would

allow such units to qualify for this exemption.

Other commenters stated that before implementing this revision, the EPA must identify

the nature and scope of the problem, if any, that it seeks to address and the environmental impact

of the proposed change. If this is merely an imagined problem, the EPA must not revise the rule

unless and until it explores the potential impacts. They said if the Agency has information that

particular operators are seeking this change, the EPA must identify the potentially affected

facilities and the anticipated impacts, but, in the absence of this information, it would be arbitrary

and capricious for the EPA to finalize this amendment to the regulatory text.

The implementation of the existing source CAA section 111(d) obligations is primarily

the responsibility of state agencies and the EPA does not have a comprehensive list of all

potential sources impacted when those requirements are implemented. To date, states have not

had to implement the existing source CAA section 111(d) requirements and owners/operators of

existing EGUs have not yet had any obligation to demonstrate compliance with any emissions

standards. As such, the EPA is not aware of any potential industrial units that would be impacted


by the proposed applicability amendment. As described in the 2018 Proposal, prior to EGU GHG

NSPS rules, existing industrial EGUs over 25 MW have never had a reason to be subject to a

permit condition limiting the amount of electric sales to a utility distribution system, even if they

sold little, if any, net electricity. The proposed revisions would simply make it possible for an

owner/operator of an existing industrial EGU to provide evidence to the Administrator that the

facility has never sold electricity in excess of the electricity sales threshold and to modify their

permit to limit sales in the future. Without the amendment, owners/operators of any non-CHP

industrial EGU that is capable of selling 25 MW would be subject to the existing source CAA

section 111(d) requirements even if they have never sold any electricity. Therefore, the EPA is

finalizing the exemption to eliminate the requirement that existing industrial EGUs must have

always been subject to a permit restriction limiting net electric sales.

3. Applicability to Industrial EGUs

The definition of an EGU includes “integrated equipment that provides electricity or

useful thermal output.” This language facilitates the integration of non-emitting generation and

avoids energy inputs from non-affected facilities being used in the emissions calculation without

also considering the emissions of those facilities (e.g., an auxiliary boiler providing steam to a

primary boiler). However, the language could also result in certain large processes, such as

carbon black production facilities, being considered an affected EGU. This is potentially

problematic for multiple reasons. First, it is difficult to determine the useful output of the EGU

because part of the useful output is included in the industrial process. In addition, the fossil fuel

that is combusted might have a relatively high CO2 emissions rate on a lb/MMBtu basis, making

it problematic to meet the emissions standard. Finally, the compliance costs associated with 40

CFR part 60, subpart TTTT could discourage the development of environmentally beneficial


projects. To avoid potentially adverse environmental impacts, the EPA solicited comment on two

approaches to avoid these outcomes. The first was to exempt any EGU where greater than 50

percent of the heat input is derived from an industrial process that does not produce any electrical

or mechanical output or useful thermal output that is used outside the affected EGU. The second

approach the EPA solicited comment on was excluding fuels that are combusted to comply with

another EPA regulation (e.g., control of HAP emissions) from being considered a fossil fuel.

Some commenters said that they support an industrial unit exemption in the applicability

provisions. The commenters noted that the exhaust from chemical-plant tail-gas incinerators can

contain considerable heat, which, instead of venting to the atmosphere, could be routed through a

heat recovery steam generator (HRSG) to make high-pressure steam for subsequent generation of

electricity for the grid. The commenters noted that this type of electric generation would not

result in additional emissions, but if it were subject to the EGU GHG NSPS it could result in the

requirement to install expensive controls and/or limit operating conditions discouraging any

effort to capture the waste-heat to produce electricity. They said it is logical for the Agency to

allow an industrial unit exemption. For similar reasons, commenters also support the EPA’s

proposal to exclude fuels that are combusted in order to comply with another EPA regulation

(e.g., control of HAP emissions) from being considered a fossil fuel. According to the

commenters, these proposed amendments bring greater clarity and certainty with regard to the

regulation’s applicability and would avoid treating industrial EGUs as affected EGUs.

Other commenters opposed excluding fuels that are combusted to comply with another

EPA regulation from being considered a fossil fuel, stating that nowhere does the CAA permit

the EPA to redefine the concept of fossil fuels without any technical or scientific basis for doing

so merely in order to reduce regulation of sources that may be subject to more than one program


under the statute. The commenters added that if a source is subject to multiple CAA

requirements, it must fully comply with all of those requirements.

The EPA is not finalizing any exclusion for fuels that are combusted to comply with

another EPA regulation. However, the EPA is finalizing the provision that exempts EGUs where

greater than 50 percent of the heat input is derived from an industrial process that does not

produce any electrical or mechanical output or useful thermal output that is used outside the

affected EGU. As commenters pointed out, projects of this type provide significant

environmental benefit with little if any additional emissions. Including these types of projects

would result in regulatory burden without any associated environmental benefit and would

discourage project development, leading to overall increases in GHG emissions.

4. Applicability to CHP Units

In the 2015 Rule, the EPA did not issue standards of performance for certain types of

sources—including industrial CHP units and CHPs that are subject to a federally enforceable

permit limiting annual net-electric sales to no more than the unit’s design efficiency multiplied

by its potential electric output, or 219,000 MWh or less, whichever is greater. In the 2018

Proposal, to avoid potential double counting of electric sales, the EPA proposed 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. The proposed amendment would set a limit on 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.

Subpart TTTT of 40 CFR part 60 currently includes an “electric transmission and

distribution factor” credit for CHP facilities “where at least on an annual basis 20.0 percent of

the total gross or net energy output consists of electric or direct mechanical output and 20.0

percent of the total gross or net energy output consists of useful thermal output on a 12-

operating-month rolling average basis.” This factor divides the measured electric output by 0.95

(increasing the output used for compliance purposes) to account for the environmental benefit of

limiting transmission and distribution losses by locating generation close to load sources. This

serves as a proxy for the effective delivered electricity. The restriction includes that the output of

the CHP facility consists of at least 20-percent electric and 20-percent useful thermal output. The

restriction that 20 percent of the output consists of useful thermal output makes sense to avoid

EGUs providing a trivial amount of steam to qualify to use the transmission and distribution

factor when determining compliance. However, the restriction on the minimum percent of total

useful output that consists of electric output does not fit with the rationale of including the factor.

In fact, CHP units generating smaller percentages of electricity are more likely to provide

transmission and distribution benefits as it is more likely that the electricity will be consumed

locally. In recognition of this, the EPA solicited comment on eliminating the restriction that CHP

produce at least 20-percent electrical or mechanical output to qualify for the CHP specific

method for calculating net electric sales and net energy output.

Some commenters stated that they continue to support the EPA’s 2015 decision to

exclude CHP units from the definition of “affected EGUs.” However, the commenters stated that

they believe that the metrics for excluding these units are difficult to demonstrate, overly


restrictive, and, as a result, will likely cause some CHP units to remain subject to the

performance standards. As such, in order to avoid unnecessary regulation of these

environmentally beneficial units, they recommended that the Agency amend the NSPS so that

industrial CHP units are clearly and completely excluded from the universe of affected EGUs

through the simplest possible means of determining applicability.

Other commenters stated, in response to the EPA’s comment solicitation on eliminating

the restriction that CHP produce at least 20-percent electrical or mechanical output to qualify for

the CHP specific method for calculating net-electric sales and net energy output, that the EPA

notes that it is “unlikely” that any such units would even meet the NSPS applicability criteria in

the first instance, but then states that “it is not clear that these CHP units would have less

environmental benefit …than more traditional CHP units.” Nor, however, according to

commenters, is it clear that these “low-generation” CHP units would have equal or greater

environmental benefit than traditional CHP units, and the EPA points to no information, data, or

discussion anywhere in the record that would support relaxing the standard for low-generation

CHP facilities. The commenters said that because the burden is on the EPA to provide “good

reasons” for reversing a previously existing policy (Fox Television Stations, Inc., 556 U.S. at

515), the Agency’s lack of any analysis or data whatsoever on this point forecloses this option as

a legal matter, and falls short of what is required to permit meaningful comment.

The EPA is finalizing the revisions to the calculation of net electric sales as proposed.

This amendment is necessary to avoid circumvention of the intended applicability. The EPA has

also determined that the current applicability is sufficiently clear and that a broader exclusion for

CHP is unnecessary. While the EPA continues to believe the 20-percent electric sales CHP


threshold is unnecessary, the removal would not impact any CHP units, so the EPA is not

finalizing those amendments.

B. Other Miscellaneous Issues

[1.] Determination of the Design Efficiency

In the 2018 Proposal, the EPA noted that the design efficiency of an EGU is used to

determine the electric sales applicability threshold and is relevant to both new and existing

EGUs. The existing language allows the use of three methods for determining the design

efficiency. Since the 2015 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 CAA section 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 that. The requirement would result in burden to

the regulated community without any environmental benefit. To reduce the compliance burden

and provide additional flexibility to the regulated community, the EPA proposed to allow

alternative methods as approved by the Administrator on a case-by-case basis. Owners/operators

of EGUs would petition the Administrator in writing to use an alternate method to determine the

design efficiency. Administrator discretion is intentionally left broad and could include other

American Society of Mechanical Engineers (ASME) or International Organization for

Standardization (ISO) methods as well as operating data to demonstrate the design efficiency of

the EGU.

Some commenters stated support of the proposed revision to allow alternative methods

approved by the Administrator on a case-by-case basis. They said that, as with compliance


methods, there may be methods for determining design efficiency that are more appropriate for a

specific application than the ones identified in the rule, and the EPA should not be precluded

from authorizing use of those where appropriate.

Other commenters stated that the EPA’s proposal to allow for case-by-case

determinations of design efficiency when determining the applicability of 40 CFR part 60,

subpart TTTT arbitrarily fails to assure that such determinations will be made in a rigorous and

transparent manner. The 2018 Proposal would amend the definition of design efficiency to allow

the Administrator to approve alternative methods to determine design efficiency and does not

provide mechanisms—such as an opportunity for public notice and comment, or public

disclosure—to assure the public that these determinations are made on a well-reasoned basis and

in a consistent manner. The commenters asserted that if the EPA finalizes the proposed changes

to the applicability provisions, it must, at a minimum, require applicants to demonstrate why the

standard method for determining design efficiency in subpart TTTT cannot be used; require the

Agency to provide public notice of any applications for a case-by-case determination of design

efficiency and an opportunity for comment; and provide for public disclosure of final

determinations and the basis for those determinations. They argued that without such safeguards,

the EPA’s proposed changes would allow the Agency to arbitrarily approve inadequate or

inconsistent approaches to computing design efficiency—and potentially exempt certain EGUs

from subpart TTTT—without any notice to the public or any accountability for the Agency or

EGUs.

The Agency is confirming that the proposed amendments are appropriate. The electricity

generating market has changed, in some cases dramatically, during the lifetime of existing

EGUs, especially in the area of EGU ownership. Over the course of acquisitions and mergers,


original EGU design efficiency documentation, as well as performance guarantee results that

affirmed the design efficiency, may no longer exist. Moreover, such documentation and results

may not be relevant for current EGU efficiencies, as changes to original EGU configurations,

upon which the original design efficiencies were based, render those original design efficiencies

moot, meaning that there would be little reason to maintain former design efficiency

documentation since it would not comport with the efficiency associated with current EGU

configurations. As the three specified methods would rely on documentation from the original

EGU configuration performance guarantee testing, and results from that documentation may no

longer exist or be relevant, it is only appropriate to allow other means to demonstrate EGU

design efficiency.

The Agency disagrees with those commenters who suggest the Administrator’s case-by-

case decisions on design efficiency would be made on a less than rigorous or transparent basis.

The process mentioned in the proposal—a determination regarding 40 CFR part 60 applicability

for a specific EGU based upon a written request and a certain set of facts—does not differ from

the process the Administrator (or his delegate) employs in making applicability determinations

for NSPS. In that process, a source owner or operator provides the Administrator with a written

request along with site-specific facts seeking a determination whether or not a certain source is

subject to an NSPS. Upon receipt and review of the request, and after consultation with

appropriate internal Agency organizations, the Administrator decides and posts the decision in

the Applicability Determination Index (ADI) every quarter.139 The Agency is unaware of any

concerns about that process—which has been in place for over 40 years—its accountability, or

its transparency. In the process contained in this rule, an owner or operator of an EGU subject to

139 GHG pollution is the aggregate of the following six gases: CO2, methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs).


an NSPS (subpart TTTT) submits to the Administrator a written request containing EGU-specific

facts as well as the method by which the design efficiency is to be determined and seeking a

response as to the appropriateness of the design efficiency which is then used to determine

source applicability. Handling such a request in a consistent fashion would have the

Administrator review the request and, upon consultation with appropriate internal Agency

organizations, decide on the appropriateness of the method for calculating the design efficiency.

2. Alternatives to GS

In the 2015 Rule, the EPA noted that potential alternatives to sequestering CO2 in

geologic formations were emerging. These relatively new potential alternatives may offer the

opportunity to offset the cost of CO2 capture. At the time, a few commenters suggested that CO2

utilization technologies alternative to GS are being commercialized, and that these should be

included as compliance options for this rule. In response, the EPA said it did not believe that the

emerging non-sequestration technologies discussed are sufficiently advanced to allow for their

use. Nor are there plenary systems of regulatory control and GHG reporting for these approaches

as there are for GS, and, given the unlikelihood of new coal-fired EGUs being constructed, the

EPA does not expect there to be many (if any) applications for use of non-GS technology.

In the 2018 Proposal, the Agency said that while carbon capture technology is not

included in the proposed BSER, the EPA recognizes that there are potential site-specific

situations where a developer elects to install carbon capture technology. For example, a

developer might wish to evaluate a particular capture technology or to sell the captured CO2 for

purposes other than GS. However, 40 CFR part 60, subpart TTTT as written in the 2015 Rule

requires that captured CO2 be geologically sequestered or stored in a manner that is as effective

as GS. For example, captured CO2 that is sold to the food industry would not necessarily qualify


for emission reduction because it results in near term releases rather than in permanent

sequestration. However, if the captured CO2 is offsetting CO2 generated specifically for the food

industry, from a life cycle perspective it would be as effective as sequestration at reducing

emissions. Therefore, to accommodate non GS and to support the effective utilization and

management of CO2, the EPA solicited comment on amending the second sentence of 40 CFR

60.555(g) to read, “To receive a waiver, the applicant must demonstrate to the Administrator that

its technology will store captured CO2 as effectively as geologic sequestration or the CO2 will be

used as an input to an industrial process where the life cycle emissions are reducing emissions

as effective as geologic sequestration, and that the proposed technology will not cause or

contribute to an unreasonable risk to public health, welfare, or safety.” (emphasis added).

Some commenters stated support for additional alternatives for the utilization of captured

CO2. They said that there appears little reason for the EPA to oppose additional source flexibility

for sources that are incorporating carbon capture. They said that it should be understood,

however, that this support for alternatives to GS does not affect their views with respect to the

impermissibility of requiring sequestration as part of BSER.

Other commenters stated the EPA must ensure that any carbon capture and utilization

system used to comply with a regulatory GHG standard achieves permanent reductions in

emissions on a net basis (equivalent in certainty and duration to GS). Indeed, a standard of

performance that does not ensure that captured CO2 is permanently removed from the

atmosphere on a net basis could end up partially or wholly negating the climate benefits

associated with the initial capture of the CO2, defeating the purpose of the standard. Because

such a standard would also allow greater emissions of CO2 than GS, it would also fail to reflect

the degree of emission limitation achievable through the application of the BSER, as CAA


section 111(a) requires (42 U.S.C. 7411(a)). The commenters said the 2018 Proposal fails to

require that carbon capture and utilization systems achieve permanent reduction on a net basis,

instead suggesting only a vague condition that life cycle emissions from a carbon utilization

system reduce emissions as effectively as GS. The 2018 Proposal provides no guidance as to

what minimum duration or certainty any level of life cycle emissions benefit would have to

achieve in order for a utilization system to be deemed as effective as GS. Given that different

pathways for utilizing CO2 have different levels of certainty and time horizons, the 2018

Proposal’s failure to define how this comparison will be made renders it clearly arbitrary. They

asserted that the 2018 Proposal fails to provide any definition for life cycle emissions or

guidance as to how life cycle emissions for a given carbon utilization system should be

calculated. According to the commenters, this omission is manifestly arbitrary given that LCA

for carbon utilization systems is a relatively new field with well-documented methodological and

data challenges.

While the EPA supports the utilization of CO2 as an effective means to manage CO2, the

Agency acknowledges the 2018 Proposal did not include sufficient detail on how the life cycle

analysis would be conducted. In addition, because the emission standards are not based on the

use of CCS and the EPA projects that few, if any, new coal-fired EGUs will be subject to the

requirements in this final rule, it is not essential that the utilization of CO2 be incorporated at this

time. Therefore, the EPA is not amending the existing 2015 Rule, which requires GS or that the

captured CO2 be stored in a manner as effective as GS.

The EPA notes that if the emission standards in this final rule were based on the use of

CCS, the Agency would support allowing alternatives to GS because of the economic and

environmental benefits of CO2 utilization. As stated by the Carbon Capture Coalition in the


request for comments on the 45Q tax credit,140 Life cycle assessments (LCA) have been used by

multiple government agencies to quantify GHG emissions from various sources. NETL uses

LCA to evaluate potential projects to fund and has recently developed a database and detailed set

of guidelines for implementing LCA for CCUS options other than GS.141 Under the Renewable

Fuel Standard (RFS), the EPA requires LCA to determine direct and indirect emissions

associated with each stage of a fuel’s production and use as required by the CAA.142 In the 45Q

statute, “life cycle greenhouse gas emissions” has the same meaning as in the RFS program.143

To maintain transparency and consistency, future considerations for carbon capture and

utilization options could require a LCA that could align with other Agency guidelines and

procedures. In addition, the EPA could evaluate that the regulatory requirements placed on

captured CO2 are consistent with past Agency requirements for captured pollutants, namely the

regulatory requirements for the beneficial reuse of coal combustion residues (gypsum wallboard,

etc.).

3. Commercial Demonstration Permit

In the 2018 Proposal, the EPA outlined that standards requiring a high level of

performance can discourage the continued development of some new technologies. The EPA

recognizes that owners/operators in the utility sector may not accept the risk of using new and

140 The EPA also refers to fossil fuel-fired steam generating units as “steam generating units,” “utility boilers and IGCC units,” or as “coal-fired EGUs.” 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. GHGs are not criteria pollutants.141 These projects tend to be 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.142 For some EGUs, their single best annual CO2 emissions rate is lower than the standard for reconstructed EGUs. If such an EGU were modified, its emissions standard would be set at the reconstructed EGU emissions rate.143 See “List of Categories of Stationary Sources,” 36 FR 5931 (March 31, 1971) (listing source category); “Standards of Performance for New Stationary Sources,” 36 FR 24376 (December 31, 1971) (promulgating NSPS for source category).


innovative technologies as the emission reduction efficiencies of such technologies have not

been fully demonstrated. As such, owners/operators may prefer conventional, demonstrated

technologies. Therefore, it is desirable that standards of performance accommodate and foster the

continued development of emerging technologies. To mitigate the potential negative impact on

emerging technologies, the EPA solicited comment on whether it should include a commercial

demonstration permit provision in 40 CFR part 60, subpart TTTT. This provision is included in

the criteria pollutant NSPS, and the EPA determined that this provision would encourage the

development of new technologies and compensate for problems that may arise when applying

them to commercial-scale units.

Some commenters said they believe that the inclusion of innovative boiler designs, new

materials that would allow for the use of advanced ultra-supercritical steam conditions,

supercritical topping cycles, and alternate cooling technologies as part of innovative emerging

technologies should be included in commercial demonstration permit standards. They said

incorporation of these technologies provides the appropriate flexibility for innovative and

emerging technologies as part of the permit process, but they did not agree with the limits the

EPA proposed to impose on these permits in 2018. These permits should be readily accessible to

any control technology that has the ability to reduce emissions. The commenters said a

commercial demonstration permit would allow owners and operators of coal-fired EGUs

regulatory flexibility in the form of a slightly less stringent emissions standard than those

included in 40 CFR part 60, subpart TTTT in exchange for proposing to demonstrate new and

emerging technologies, such as supercritical topping cycles, aimed at increasing efficiency and

reducing emissions.


Other commenters stated that an owner or operator of a new or reconstructed coal-fired

EGU who wished to demonstrate a novel carbon capture technology such as supercritical topping

or alternate cooling technologies could face multiple difficulties in demonstrating continuous

compliance. First, novel carbon capture technologies by nature prevent quantitative assessment

of their continuous performance. If the capture system were taken down for repair or

modification, the entire facility might have to be taken offline to assure continuous compliance.

In addition, due to the additional auxiliary load and increased stack emissions per MWh of

electricity generated, the captured CO2 would need to be sequestered for the unit to demonstrate

continuous compliance. Sequestering relatively small amounts of CO2 could be technically

challenging and cost prohibitive, therefore, limiting the development of more cost-effective

capture technologies. Without the commercial demonstration permit provision, it would be

difficult for an owner/operator of a coal-fired EGU to support a CCS demonstration project while

still maintaining compliance with the NSPS emissions standard

Commenters stated that because CCS has been advancing but has not achieved adequate

commercial scale and cost effectiveness, the EPA’s new source standards should provide for

opportunities to adequately demonstrate CCS as well as other emerging and new emissions

reduction technologies to ensure the pathway for development remains open. They said that

while they support the concept of a commercial demonstration permit for CCS and other

emerging and new technologies, they do not agree that the EPA should limit the number of

permits to be made available. Nor should the Agency limit the amount of generation capacity

that would qualify. They stated that instead, the EPA should guarantee that all developers of new

and emerging technologies will receive the same accommodation until a technology has been

adequately demonstrated to the point that it is no longer new or emerging. This will maximize


the opportunity for technology development. These commenters said they agree that it is

appropriate to encourage and facilitate technology development, and that the innovative

technology waiver currently available under the CAA is too limited. They said while the EPA

has identified specific technologies that might be eligible for such permits, they recommend that

the permit criteria not limit technology choices unnecessarily, and instead rely on the industry to

bring applicable technologies to the attention of regulators.

Other commenters stated the EPA’s proposal to waive the NSPS for Commercial

Demonstration projects is unlawful, arbitrary, and capricious. They said the Agency’s proposal

to create a commercial demonstration permit program would allow individual affected EGUs to

seek a waiver of the NSPS and would allow the Administrator to establish a less stringent

standard of performance for new EGUs that utilize one of a selected list of “emerging

technologies.” They argued that these proposed commercial demonstration permit provisions are

inconsistent with section 111 of the CAA, which already provides a specific and carefully-

designed mechanism for the EPA to adjust the NSPS to accommodate innovative and emerging

technologies. The commenters stated that the proposed commercial demonstration permit would

do an end-run around the carefully calibrated constraints Congress included for innovative

technology waivers in CAA section 111(j) and, thus, the proposed commercial demonstration

permit provision should be withdrawn.

The EPA has concluded that the commercial demonstration permit has significant

potential environmental and economic benefits. This is especially true for reduction of GHG

emissions through efficiency improvements when technology transfer to other sectors and

internationally are considered. However, the Agency has concluded that because the emission

standards included in this final rule are achievable using efficiency-based technologies that do


not require fuel switching or post combustion control technology a commercial demonstration

permit is not necessary to continue to promote the advancement of emerging and innovative

technology. A developer wishing to use an emerging or innovative technology could also employ

non-BSER control options (e.g., integrated non-emitting technology) to provide sufficient

compliance margin to account for the selecting technology not performing as expected. Because

the standard is on a 12-operating month rolling average, this provides flexibility to fine tune the

operation of the technology. In addition, because compliance is determined based on stack

emissions and no longer requires that captured CO2 be geologically sequestered, the

requirements will not inhibit the development of emerging CO2 capture technologies.

4. Stationary Combustion Turbines

In the 2018 Proposal, the EPA noted that in recent years stakeholders have expressed

concerns about the existing electric sales threshold approach for distinguishing between base

load and non-base load turbines. According to these stakeholders, in regional electricity markets

with large amounts of intermittent generation, some of the most efficient new simple cycle

turbines—aeroderivative turbines—could be called on to operate at capacity factors greater than

their design efficiency; however, if they were to be operated at those higher capacity factors,

they would become subject to the more stringent standard of performance for base load turbines.

As a result, the owners or operators of the aeroderivative turbines would have to curtail their

generation and less efficient turbines would be called on to run, which would result in higher

emissions. In response, the EPA solicited information, including seeking supporting data and

documentation, on whether there have been, or are anticipated to be, circumstances in which

simple cycle stationary combustion aeroderivative turbines have been or may be called upon to

operate in excess of the non-base load threshold described in the 2015 Rule. The EPA also


requested information on whether, and the extent to which, these aeroderivative turbines are

different in design and operation than frame simple cycle turbines and NGCC units, including

fast start NGCC units, and information on the environmental consequences, if any, of the

aeroderivative combustion turbines having to forego continued operation in such circumstances.

Some commenters said that low capacity factor stationary turbines should be exempted

from 40 CFR part 60, subpart TTTT applicability. They said the original proposal in 2014

explicitly did not apply to simple cycle turbines and they support that exemption for simple cycle

turbines. Additionally, in the case where simple cycle turbines are constructed with the intent to

operate prior to the future construction of a HRSG, such turbines should be exempted under

these same criteria until such time that construction of the HRSG and related equipment is

completed and the unit commences operation in a combined cycle mode.

Commenters stated that because natural gas provides a clean, reliable, and affordable

means of producing electricity, they support the EPA’s proposal to refrain from amending or

reopening the standards of performance for newly constructed or reconstructed stationary

combustion turbines. They said they supported these standards for combustion turbines in 2015

and continue to do so in 2020 because, unlike the 2015 Rule’s standards for coal-fired EGUs, the

Agency’s BSER analysis for combustion turbines appropriately focused on technology that was

currently used in commercial operations throughout the U.S.

Other commenters said they find no basis for the Agency to change its treatment of non-

base load combustion turbines as new advanced NGCC units are more flexible and have higher

efficiencies and lower costs compared to other fossil-fired generating technologies, including

conventional NGCC and simple cycle combustion turbines. They cited EIA data that indicates

new advanced NGCC units are projected to have the highest utilization of all fossil-fired


generating technologies, while utilization of lower efficiency conventional combined cycle units

is projected to decline, and simple cycle combustion turbine utilization is projected to remain

flat. Therefore, there is no reason to believe there would be higher utilization of new simple

cycle aeroderivative combustion turbines or that failing to accommodate a higher utilization of

those simple cycle turbines would lead to higher emissions. To the contrary, to the extent that

fossil-fired generation shifts to more efficient advanced NGCC units, overall emissions should

decline, according to the commenters. The commenters also said that while the Agency is not

proposing to re-open the standards for base load combustion turbines, the existing standard does

not reflect the degree of reduction that is achievable. The commenters claim that an emission rate

for NGCC units below 900 lb CO2/MWh-gross is readily achievable using current technology

under a wide range of operating conditions. The commenters said that if the EPA chooses to

move forward with revisions for this source category, the Agency must reopen the NSPS for

NGCC based on new data and re-propose the rule to allow for public comment.

The EPA is not taking any action with respect to the electric sales threshold that

distinguishes base load and non-base load combustion turbines. Any action the Agency takes will

be done in a future notice and comment rulemaking.

IX.V. Summary of Cost, Environmental, and Economic Impacts

A. What are the affected facilities?

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.144 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 PC or

144 See “Standards of Performance for New Stationary Sources; Gas Turbines,” 44 FR 52792 (September 10, 1979) (listing and promulgating NSPS for source category).

Author, 01/03/-1,

EOP Comment This section needs to be updated to reflect the increased scope of the rule arising out of the new 3 percent SCF threshold.


fluidized bed (FB) steam generating units.145 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 (H2), which can be combusted in a combined cycle system to

generate power.

B. What are the air quality impacts?

The EPA does not anticipate that this final rule will result in significant CO2 emission

changes by 2026. The EPA does not anticipate the construction of new coal-fired EGUs and

expects few, if any, coal-fired EGUs to trigger the promulgated NSPS modification or

reconstruction standard for these sources.

C. What are the energy impacts?

This final rule is not anticipated to have an effect on the supply, distribution, or use of

energy. The EPA projects few, at most, new reconstructed or modified EGUs.

D. What are the cost impacts?

The EPA does not believe that this final rule will have compliance costs associated with

it because the EPA projects there to be, at most, few new, modified, or reconstructed coal-fired

EGUs that will trigger the provisions the EPA is promulgating. The economic impact analysis

145 See “Priority List and Additions to the List of Categories of Stationary Sources,” 49 FR 49222 (August 21, 1979) (listing source category); “Standards of Performance for New Stationary Sources; Equipment Leaks of VOC From Onshore Natural Gas Processing Plants,” 50 FR 26124 (June 23, 1985) and "Standards of Performance for New Stationary Sources; Onshore Natural Gas Processing SO2 Emissions,” 50 FR 40160 (October 1, 1985) (promulgating standards of performance).

Author, 01/03/-1,

Interagency Comment There are no energy impacts because this rule leaves the existing NSPS unchanged.

Author, 01/03/-1,

There are no air quality impacts because this rule has no effect on the NSPS or regulated entities. That there will be no new sources is not relevant.

Author, 01/03/-1,

EOP Comment Reiterating analysis request for this through Sec. F below given new policies


includes an illustrative analysis of the potential project-level costs of this final rule relative to the

2015 Rule’s standards...

E. What are the economic impacts?

The EPA does not anticipate that this final rule will result in economic or employment

impacts because the EPA projects there to be, at most, few new, modified, or reconstructed coal-

fired EGUs that will trigger the provisions the EPA is finalizing... Likewise, the EPA believes

this rule will not have any impacts on the price of electricity, employment or labor markets, or

the U.S. economy.

F. What are the benefits?

The EPA does not anticipate emission changes resulting from the rule as the EPA

projects there to be, at most, few new, modified, or reconstructed coal-fired EGUs that will

trigger the provisions the EPA is finalizing... Therefore, there are no direct climate or human

health benefits associated with this rulemaking.

XVIVI. Statutory and Executive Order Reviews

Additional information about these statutes and Executive Orders can be found at

https://www.epa.gov/laws-regulations/laws-and-executive-orders.

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

Improving Regulation and Regulatory Review

This action is a significant regulatory action that was submitted to the Office of Management and

Budget (OMB) for review. because it raises novel legal or policy issues. Any changes made in response

to OMB recommendations have been documented in the docket. The EPA prepared an economic

impact analysis of the potential costs and benefits associated with this action. This analysis is

contained in the Economic Impact Analysis for the Review of Standards of Performance for

Author, 01/03/-1,

Interagency Comment See above.

Author, 01/03/-1,

Interagency Comment There are no economic impacts because the existing NSPS remains unaffected by this rule, nor does this rule require future changes to the NSPS. However, significance designations will have reasonably foreseeable costs, and if EPA moves forward with consideration of trends, context and technology in future SCF for which an NSPS has not yet been established, it will be able to estimate them.


Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric

Utility Generating Units. The economic impact analysis includes an illustrative analysis of the

potential difference in project-level costs of constructing a coal-fired EGU under this

promulgated standard relative to the 2015 standard.

B. Executive Order 13771: Reducing RegulationRegulationsRegulations and Controlling

Regulatory Costs

This action is considerednotnot expected to be an Executive Order 13771 regulatory action.

There are no quantified cost estimates for this final rule because the EPA does not anticipate this

action to result in costs or cost savings. For more information on this conclusion please see the

Economic Impact Analysis for the Review of Standards of Performance for Greenhouse Gas

Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility

Generating Units.

C. Paperwork Reduction Act (PRA)

This action does not impose any new information collection burden under the PRA. OMB

has previously approved the information collection activities contained in the existing part 75

and 98 regulations and has assigned OMB control numbers 2060-0626 and 2060-0629,

respectively. The information required by the rule is already collected and reported by other

regulatory programs.

D. Regulatory Flexibility Act (RFA)

I certify that this action will not have a significant economic impact on a substantial

number of small entities under the RFA. This rule requires the Administrator of EPA to make a

pollutant-specific significant contribution finding that the source category causes, or contributes

significantly to GHG air pollution before regulating GHG emissions from that source category.

Author, 01/03/-1,

EOP Comment EPA is still required to provide an RIA. Please provide.


In addition, this notice makes such a pollutant-specific significant contribution finding for the

EGU source category. However, since there is already in place a GHG NSPS for this source

category, and this finding does not require EPA to make any changes to the NSPS, this rule does

not affect small entities within the source category. In making this determination, the impact of

concern is any significant adverse economic impact on small entities. An agency may certify that

a rule will not have a significant economic impact on a substantial number of small entities if the

rule relieves regulatory burden, has no net burden, or otherwise has a positive economic effect on

the small entities subject to the rule. The EPA expects there to be few, if any, new, modified, or

reconstructed coal-fired EGUs. As such, this final rule would not impose significant

requirements on those sources, including any that are owned by small entities. The EPA has,

therefore, concluded that this action will have no net regulatory burden for all directly regulated

small entities.

E. Unfunded Mandates Reform Act (UMRA)

This action does not contain an unfunded mandate of $100 million or more as described

in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments.

This action imposes no enforceable duty on any state, local, or tribal governments or the private

sector.

F. Executive Order 13132: Federalism

This action does not have federalism implications. It will not have substantial direct

effects on the states, on the relationship between the national government and the states, or on

the distribution of power and responsibilities among the various levels of government.

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


This action does not have tribal implications, as specified in Executive Order 13175. It

would neither impose substantial direct compliance costs on tribal governments, nor preempt

Tribal law. The EPA is aware of three coal-fired EGUs located in Indian Country but is not

aware of any EGUs owned or operated by tribal entities. The EPA notes that this action would

only affect only existing sources such as the three coal-fired EGUs located in Indian Country if

those EGUs were to take actions constituting modifications or reconstructions as defined under

the EPA’s NSPS regulations. However, as previously stated, the EPA expects there to be few, if

any, new, reconstructed, or modified EGUs. Thus, Executive Order 13175 does not apply to this

action.

Consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the

EPA offered consultation with tribal officials during the development of this action; however, the

Agency did not receive a request for consultation. The EPA held meetings with tribal

environmental staff during the public comment period to inform them of the content of the

proposed rule and to encourage them to submit comments on the proposed rule.

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

Risks

The EPA interprets Executive Order 13045 as applying only to those regulatory actions

that concern health or safety risks that the EPA has reason to believe may disproportionately

affect children, per the definition of “covered regulatory action” in section 2-202 of the

Executive Order. This action is not subject to Executive Order 13045 because it does not concern

an environmental health or safety risk.

I. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy

Supply, Distribution, or Use


This action is not a “significant energy action” because it is not likely to have a

significant adverse effect on the supply, distribution, or use of energy. and has not otherwise

been designated as a significant energy action by the Administrator of the Office of Information

and Regulatory Affairs (OIRA). This final action is not anticipated to have impacts on emissions,

costs, or energy supply decisions for the affected electric utility industry.

J. National Technology Transfer and Advancement Act (NTTAA)

This action involves technical standards. Therefore, the EPA conducted a search to

identify potentially applicable voluntary consensus standards (VCS). However, the Agency

identified no such standards and none were brought to the attention of the Agency in comments.

Therefore, the EPA has decided to continue to use technical standard EPA Method 19 of 40 CFR

part 60, appendix A.This rulemaking does not involve technical standards. This rulemaking does

not involve technical standards.

K. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority

Populations and Low-Income Populations

The EPA believes that this action does not have disproportionately high and adverse

human health or environmental effects on minority populations, low-income populations, and/or

indigenous peoples, as specific in Executive Order 12898 (59 FR 7629, February 16, 1994),

because it does not affect the level of protection provided to human health or the

environment. As previously stated, the EPA expects there to bethatthat few, if any, coal-fired

EGUs would be affected by this action.

L. Congressional Review Act (CRA)


This action is subject to the CRA, and the EPA will submit a rule report to each House of

the Congress and to the Comptroller General of the United States. This action is not a “major

rule” as defined by 5 U.S.C. 804(2).

***E.O. 12866 Review-Draft-Do Not Cite, Quote, or Release During Review***

Page 2084545 of 2274747

List of Subjects in 40 CFR part 60

Environmental protection, Administrative practice and procedure, Air pollution control,

Intergovernmental relations, Reporting and recordkeeping requirements.

________________________________________Andrew Wheeler,Administrator.


For the reasons set forth in the preamble, the EPA amends 40 CFR part 60 as follows:

PART 60 – STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

1. The authority citation for part 60 continues to read as follows:

Authority: 42 U.S.C. 7401 et seq.

Subpart TTTT – Standards of Performance for Greenhouse Gas Emissions for Electric

Generating Units

2. Section 60.5508 is revised to read as follows:

§60.5508 What is the purpose of this subpart?

This subpart establishes emission standards and compliance schedules for the control of

greenhouse gas (GHG) emissions from a steam generating unit, integrated gasification combined

cycle facility (IGCC), or a stationary combustion turbine that commences construction after

January 8, 2014 or commences modification or reconstruction after June 18, 2014. An affected

steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this

subpart, be referred to as an affected electric generating unit (EGU).

3. Section 60.55091616 is amended by revisingaddingadding paragraphs (a)(1) and (2), (b)

introductory text, (b)(1), (b)(2), and (b)(9), and removing paragraph (b)(10) to read as follows:

§60.5509 Am I subject to this subpart?

(a) * * *

(1) Has a base load rating greater than 260 gigajoules per hour (GJ/h) (250 million British

thermal units per hour (MMBtu/h)) of fossil fuel (either alone or in combination with any other

fuel); and

(2) Serves a generator or generators capable of selling greater than 25 megawatts (MW)

of electricity to a utility power distribution system.


(b) You are not subject to the requirements of this subpart if your affected EGU meets

any of the conditions specified in paragraphs (b)(1) through (9) of this section.

(1) Your EGU is a steam generating unit or IGCC that annual net-electric sales have

never exceeded one-third of its potential electric output or 219,000 megawatt-hour (MWh),

whichever is greater, and is currently subject to a federally enforceable permit condition limiting

annual net-electric sales to no more than one-third of its potential electric output or 219,000

MWh, whichever is greater.

(2) Your EGU is capable of deriving 50 percent or more of the heat input from non-fossil

fuel at the base load rating and is also subject to a federally enforceable permit condition limiting

the annual capacity factor for all fossil fuels combined of 10 percent (0.10) or less.

* * *

(9) Your EGU derives greater than 50 percent of the heat input from an industrial process

that does not produce any electrical or mechanical output or useful thermal output that is used

outside the affected EGU.

* * * * *

4. Section 60.5520 is amended by revising paragraphs (a), ), and (c), (d) introductory text, and (d)(1) and

(2) to read as follows:

§60.5520 What CO2 emissions standard must I meet?

(a) For each affected EGU subject to this subpart, you must not discharge from the

affected EGU any gases that contain CO2 in excess of the applicable CO2 emission standard

specified in Table 1 or 2 of this subpart, consistent with paragraphs (b), (c), and (d) of this

section, as applicable.

* * * * *


(c) As an alternate to meeting the requirements in paragraph (b) of this section, an owner

or operator of an EGU may petition the Administrator in writing to comply with the alternate

applicable net energy output standard. If the Administrator grants the petition, beginning on the

date the Administrator grants the petition, the affected EGU must comply with the applicable net

energy output-based standard included in this subpart. Your operating permit must include

monitoring, recordkeeping, and reporting methodologies based on the applicable net energy

output standard. For the remainder of this subpart, where the term “gross or net energy output” is

used, the term that applies to you is “net energy output.” Owners or operators complying with the

net output-based standard must petition the Administrator to switch back to complying with the

gross energy output-based standard.

(d) Owners or operators of a stationary combustion turbines that maintain records of

electric sales to demonstrate that the stationary combustion turbines are subject to a heat input-

based standard in Table 2 of this subpart that are only permitted to burn one or more uniform

fuels, as described in paragraph (d)(1) of this section, are only subject to the monitoring

requirements in paragraph (d)(1). Owners or operators of all other stationary combustion turbines

that maintain records of electric sales to demonstrate that the stationary combustion turbines are

subject to a heat input-based standard in Table 2 are only subject to the requirements in

paragraph (d)(2) of this section.

(1) Owners or operators of stationary combustion turbines that are only permitted to burn

fuels with a consistent chemical composition (i.e., uniform fuels) that result in a consistent

emission rate of 69 kilograms per gigajoule (kg/GJ) (160 lb CO2/MMBtu) or less are not subject

to any monitoring or reporting requirements under this subpart. These fuels include, but are not

limited to, natural gas, methane, butane, butylene, ethane, ethylene, propane, naphtha, propylene,


jet fuel kerosene, No. 1 fuel oil, No. 2 fuel oil, and biodiesel. Stationary combustion turbines

qualifying under this paragraph are only required to maintain purchase records for permitted

fuels.

(2) Owners or operators of stationary combustion turbines permitted to burn fuels that do

not have a consistent chemical composition or that do not have an emission rate of 69 kg/GJ (160

lb CO2/MMBtu) or less (e.g., non-uniform fuels such as residual oil and non-jet fuel kerosene)

must follow the monitoring, recordkeeping, and reporting requirements necessary to complete

the heat input-based calculations under this subpart.

5. Section 60.5525 is amended by revising the introductory text, paragraphs (a)(2), (c)

introductory text, (c)(1)(i) and (ii), (c)(2) introductory text, (c)(2)(i) and (ii), and (c)(3) to read as

follows:

§60.5525 What are my general requirements for complying with this subpart?

Combustion turbines qualifying under §60.5520(d)(1) are not subject to any requirements

in this section other than the requirement to maintain fuel purchase records for permitted fuel(s).

For all other affected sources, compliance with the applicable CO2 emission standard of this

subpart shall be determined on a 12-operating-month rolling average basis. See Table 1 or 2 of

this subpart for the applicable CO2 emission standards.

(a) * * *

(2) Consistent with §60.5520(d)(2), if your affected stationary combustion turbine is

subject to an input-based CO2 emissions standard, you must determine the total heat input in GJ

or MMBtu from natural gas (HTIPng) and the total heat input from all other fuels combined

(HTIPo) using one of the methods under §60.5535(d)(2). You must then use the following

equation to determine the applicable emissions standard during the compliance period:


❑❑❑❑❑❑ (Eq. 1)

Where:

CO2 emission standard = the emission standard during the compliance period in units of

kg/GJ (or lb/MMBtu).

HTIPng = the heat input in GJ (or MMBtu) from natural gas.

HTIPo = the heat input in GJ (or MMBtu) from all fuels other than natural gas.

50 = allowable emission rate in lb CO2/MMBtu for heat input derived from natural gas

(use 120 if electing to demonstrate compliance using lb CO2/MMBtu).

69 = allowable emission rate in lb CO2/MMBtu for heat input derived from all fuels other

than natural gas (use 160 if electing to demonstrate compliance using lb CO2/MMBtu).

* * * * *

(c) Within 30 days after the end of the initial compliance period (i.e., no more than 30

days after the first 12-operating-month compliance period), you must make an initial compliance

determination for your affected EGU(s) with respect to the applicable emissions standard in

Table 1 or 2 of this subpart, in accordance with the requirements in this subpart. The first

operating month included in the initial 12-operating-month compliance period shall be

determined as follows:

(1) * * *

(i) Section 60.5555(c)(3)(i), for units subject to the Acid Rain Program; or

(ii) Section 60.5555(c)(3)(ii)(A), for units that are not in the Acid Rain Program.

(2) For an affected EGU that has commenced commercial operation (as defined in §72.2

of this chapter) prior to October 23, 2015:


(i) If the date on which emissions reporting is required to begin under §75.64(a) of this

chapter has passed prior to October 23, 2015, emissions reporting shall begin according to

§60.5555(c)(3)(i) (for Acid Rain program units), or according to §60.5555(c)(3)(ii)(B) (for units

that are not subject to the Acid Rain Program). The first month of the initial compliance period

shall be the first operating month (as defined in §60.5580) after the calendar month in which the

rule becomes effective; or

(ii) If the date on which emissions reporting is required to begin under §75.64(a) of this

chapter occurs on or after October 23, 2015, then the first month of the initial compliance period

shall be the first operating month (as defined in §60.5580) after the calendar month in which

emissions reporting is required to begin under §60.5555(c)(3)(ii)(A).

(3) For a modified or reconstructed EGU that becomes subject to this subpart, the first

month of the initial compliance period shall be the first operating month (as defined in §60.5580)

after the calendar month in which emissions reporting is required to begin under §60.5555(c)(3)

(iii).

6. Section 60.5535 is amended by revising paragraphs (b) introductory text, (e), and (f) to read as

follows:

§60.5535 How do I monitor and collect data to demonstrate compliance?

* * * * *

(b) You must determine the hourly CO2 mass emissions in kg from your affected EGU(s)

according to paragraphs (b)(1) through (5) of this section, or, if applicable, as provided in

paragraph (c) of this section.

* * * * *


(e) Consistent with §60.5520, if two or more affected EGUs serve a common electric

generator, you must apportion the combined hourly gross or net energy output to the individual

affected EGUs according to the fraction of the total steam load and/or direct mechanical energy

contributed by each EGU to the electric generator. Alternatively, if the EGUs are identical, you

may apportion the combined hourly gross or net electrical load to the individual EGUs according

to the fraction of the total heat input contributed by each EGU. You may also elect to develop,

demonstrate, and provide information satisfactory to the Administrator on alternate methods to

apportion the gross energy output. The Administrator may approve such alternate methods for

apportioning the gross energy output whenever the demonstration ensures accurate estimation of

emissions regulated under this part.

(f) In accordance with §§60.13(g) and 60.5520, if two or more affected EGUs that

implement the continuous emission monitoring provisions in paragraph (b) of this section share a

common exhaust gas stack you must monitor hourly CO2 mass emissions in accordance with one

of the following procedures:

(1) If the EGUs are subject to the same emissions standard in Table 1 or 2 of this subpart,

you may monitor the hourly CO2 mass emissions at the common stack in lieu of monitoring each

EGU separately. If you choose this option, the hourly gross or net energy output (electric,

thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for the individual

affected EGUs and you must express the operating time as “stack operating hours” (as defined in

§72.2 of this chapter). If you attain compliance with the applicable emissions standard in

§60.5520 at the common stack, each affected EGU sharing the stack is in compliance.

(2) As an alternate, or if the EGUs are subject to different emission standards in Table 1

or 2 of this subpart, you must either (1) monitor each EGU separately by measuring the hourly


CO2 mass emissions prior to mixing in the common stack or (2) apportion the CO2 mass

emissions based on the unit’s load contribution to the total load associated with the common

stack and the appropriate f-factors. You may also elect to develop, demonstrate, and provide

information satisfactory to the Administrator on alternate methods to apportion the CO2

emissions. The Administrator may approve such alternate methods for apportioning the CO2

emissions whenever the demonstration ensures accurate estimation of emissions regulated under

this part.

* * * * *

7. Section 60.5540 is amended by revising paragraphs (a) introductory text, (a)(5)(i) introductory

text, (a)(7), (b), and the defined terms “Qm” and “H” in Equation 3 in paragraph (a)(5)(ii) to read

as follows:

§60.5540 How do I demonstrate compliance with my CO2 emissions standard and

determine excess emissions?

(a) In accordance with §60.5520, if you are subject to an output-based emission standard

or you burn non-uniform fuels as specified in §60.5520(d)(2), you must demonstrate compliance

with the applicable CO2 emission standard in Table 1 or 2 of this subpart as required in this

section. For the initial and each subsequent 12-operating-month rolling average compliance

period, you must follow the procedures in paragraphs (a)(1) through (7) of this section to

calculate the CO2 mass emissions rate for your affected EGU(s) in units of the applicable

emissions standard (e.g., either kg/MWh or kg/GJ). You must use the hourly CO2 mass

emissions calculated under §60.5535(b) or (c), as applicable, and either the generating load data

from §60.5535(d)(1) for output-based calculations or the heat input data from §60.5535(d)(2) for

heat-input-based calculations. Combustion turbines firing non-uniform fuels that contain CO2


prior to combustion (e.g., blast furnace gas or landfill gas) may sample the fuel stream to

determine the quantity of CO2 present in the fuel prior to combustion and exclude this portion of

the CO2 mass emissions from compliance determinations.

* * * * *

(5) * * *

(i) Calculate Pgross/net for your affected EGU using the following equation. All terms in the

equation must be expressed in units of MWh. To convert each hourly gross or net energy output

(consistent with §60.5520) value reported under part 75 of this chapter to MWh, multiply by the

corresponding EGU or stack operating time.

* * * * *

(ii) * * *

Qm = Measured useful thermal output flow in kg (lb) for the operating hour.

H = Enthalpy of the useful thermal output at measured temperature and pressure (relative to

SATP conditions or the energy in the condensate return line, as applicable) in Joules per

kilogram (J/kg) (or Btu/lb).

* * * * *

(7) If you are subject to an output-based standard, you must calculate the CO2 mass

emissions rate for the affected EGU(s) (kg/MWh) by dividing the total CO2 mass emissions

value calculated according to the procedures in paragraph (a)(4) of this section by the total gross

or net energy output value calculated according to the procedures in paragraph (a)(6)(i) of this

section. Round off the result to two significant figures if the calculated value is less than 1,000;

round the result to three significant figures if the calculated value is greater than 1,000. If you are

subject to a heat input-based standard, you must calculate the CO2 mass emissions rate for the


affected EGU(s) (kg/GJ or lb/MMBtu) by dividing the total CO2 mass emissions value calculated

according to the procedures in paragraph (a)(4) of this section by the total heat input calculated

according to the procedures in paragraph (a)(6)(ii) of this section. Round off the result to two

significant figures.

(b) In accordance with §60.5520, to demonstrate compliance with the applicable CO2

emission standard, for the initial and each subsequent 12-operating-month compliance period,

the CO2 mass emissions rate for your affected EGU must be determined according to the

procedures specified in paragraph (a)(1) through (7) of this section and must be less than or equal

to the applicable CO2 emissions standard in Table 1 or 2 of this part, or the emissions standard

calculated in accordance with §60.5525(a)(2).

* * * * *

8. Section 60.5555 is amended by revising paragraphs (a)(2)(v) to read as follows:

§60.5555 What reports must I submit and when?

(a) * * *

(2) * * *

(v) Consistent with §60.5520, the CO2 emissions standard (as identified in Table 1 or 2 of

this part) with which your affected EGU must comply; and

* * * * *

9. Section 60.5580 is amended by revising the definitions for “Annual capacity factor”,

“Base load rating”, “Combined cycle unit”, “Combined heat and power unit”, “Design

efficiency”, revising paragraphs (2) and (4) of the definition for “Net-electric sales”, and revising

the definition for “Violation” to read as follows:

§60.5580 What definitions apply to this subpart?


* * * * *

Annual capacity factor means the ratio between the actual heat input to an EGU during a

calendar year and the potential heat input to the EGU had it been operated for 8,760 hours during

a calendar year at the base load rating. Actual and potential heat input derived from non-

combustion sources (e.g. solar thermal) are not included when calculating the annual capacity

factor.

Base load rating means the maximum amount of heat input (fuel) that an EGU can

combust on a steady state basis plus the maximum amount of heat input derived from non-

combustion source (e.g., solar thermal), as determined by the physical design and characteristics

of the EGU at ISO conditions. For a stationary combustion turbine, base load rating includes the

heat input from duct burners.

* * * * *

Combined cycle unit means a stationary combustion turbine from which the heat from the

turbine exhaust gases is recovered by a heat recovery steam generating unit (HRSG) to generate

additional electricity.

Combined heat and power unit or CHP unit, (also known as “cogeneration”) means a

steam generating unit, IGCC, or stationary combustion turbine to simultaneously produce both

electric (or mechanical) and useful thermal output from the same primary energy source.

Design efficiency means the rated overall net efficiency (e.g., electric plus useful thermal

output) on a lower heating value basis at the base load rating, at ISO conditions, and at the

maximum useful thermal output (e.g., CHP unit with condensing steam turbines would

determine the design efficiency at the maximum level of extraction and/or bypass). Design

efficiency shall be determined using one of the following methods: ASME PTC 22 Gas Turbines


(incorporated by reference, see §60.17), ASME PTC 46 Overall Plant Performance (incorporated

by reference, see §60.17), ISO 2314 Gas turbines—acceptance tests (incorporated by reference,

see §60.17), or an alternative approved by the Administrator.

* * * * *

Net-electric sales means: * * *

(2) For combined heat and power facilities where at least 20.0 percent of the total gross

energy output consists of electric or direct mechanical output and at least 20.0 percent of the total

gross energy output consists of useful thermal output on an annual basis, the gross electric sales

to the utility power distribution system minus the applicable percentage of purchased power of

the thermal host facility or facilities. The applicable percentage of purchase power for CHP

facilities is determined based on the percentage of the total thermal load of the host facility

supplied to the host facility by the CHP facility. For example, if a CHP facility serves 50 percent

of a thermal hosts thermal demand, the owner/operator of the CHP facility would subtract 50

percent of the thermal hosts electric purchased power when calculating net-electric sales.

* * * * *

(4) Electric sales that result from a system emergency are not included when calculating

net-electric sales.

* * * * *

Violation means a specified averaging period over which the CO2 emissions rate is higher

than the applicable emissions standard located in Table 1 or 2 of this subpart.

10. Table 1 of Subpart TTTT of Part 60 is revised to read as follows:

Table 1 of Subpart TTTT of Part 60—CO2 Emission Standards for Affected Steam Generating Units and Integrated Gasification Combined Cycle Facilities That Commenced Construction After January 8, 2014 and Reconstruction or Modification After June 18, 2014 (Net Energy Output-Based Standards Applicable as Approved by the Administrator)


[Note: Numerical values of 1,000 or greater have a minimum of 3 significant figures and numerical values of less than 1,000 have a minimum of 2 significant figures]

Affected EGU CO2 Emission standard

Newly constructed steam generating unit or (IGCC) that commenced construction before December 21, 2018

640 kg CO2/MWh (1,400 lb CO2/MWh) of gross energy output.

Reconstructed steam generating unit or IGCC that has base load rating of 2,100 GJ/h (2,000 MMBtu/h) or less that commenced reconstruction before December 21, 2018


Reconstructed steam generating unit or IGCC that has a base load rating greater than 2,100 GJ/h (2,000 MMBtu/h) that commenced reconstruction before December 21, 2018]


Modified steam generating unit or IGCC that commenced modification before December 21, 2018

A unit-specific emission limit determined by the unit's best historical annual CO2 emission rate (from 2002 to the date of the modification); the emission limit will be no more stringent than:

910 kg CO2/MWh (2,000 lb CO2/MWh) of gross energy output for units with a base load rating of 2,100 GJ/h (2,000 MMBtu/h) or less; or

820 kg CO2/MWh (1,800 lb CO2/MWh) of gross energy output for units with a base load rating greater than 2,100 GJ/h (2,000 MMBtu/h).

Newly constructed and reconstructed steam generating unit or IGCC that operates at a duty cycle of 65 percent or greater on a 12-operating month rolling average basis, has base load rating of 2,100 GJ/h (2,000 MMBtu/h) or less that, and commenced construction or reconstruction after December 20, 2018

910 kg CO2/MWh (2,000 lb CO2/MWh) of gross energy output; or980 kg CO2/MWh (2,160 lb CO2/MWh) of net energy output.


Newly constructed and reconstructed steam generating unit or IGCC that operates at a duty cycle of less than 65 percent on a 12-operating month rolling average basis, has base load rating of 2,100 GJ/h (2,000 MMBtu/h) or less that, and commenced construction or reconstruction after December 20, 2018

960 kg CO2/MWh (2,100 lb CO2/MWh) of gross energy output; or1,030 kg CO2/MWh (2,260 lb CO2/MWh) of net energy output.

Newly constructed and reconstructed steam generating unit or IGCC that operates at a duty cycle of 65 percent or greater on a 12-operating month rolling average basis, has base load rating greater than 2,100 GJ/h (2,000 MMBtu/h), and commenced construction or reconstruction after December 20, 2018


Newly constructed and reconstructed steam generating unit or IGCC that operates at a duty cycle of less than 65 percent on a 12-operating month rolling average basis, has base load rating greater than 2,100 GJ/h (2,000 MMBtu/h), and commenced construction or reconstruction after December 20, 2018


Newly constructed and reconstructed steam generating unit or IGCC units that burn 75 percent or more (by heat input) coal refuse on a 12-operating month rolling average basis, operates at a duty cycle of 65 percent or greater on a 12-operating month rolling average basis, and commenced construction or reconstruction after December 20, 2018

1,000 kg CO2/MWh (2,200 lb CO2/MWh) of gross energy output; or1080 kg CO2/MWh (2,380 lb CO2/MWh) of net energy output.

Newly constructed and reconstructed steam generating unit or IGCC units that burn 75 percent or more (by heat input) coal refuse on a 12-operating month rolling average basis, operates at a duty cycle of less than 65 percent on a 12-operating month rolling average basis, and commenced construction or reconstruction after December 20, 2018

1,040 kg CO2/MWh (2,300 lb CO2/MWh) of gross energy output; or1,120 kg CO2/MWh (2,470 lb CO2/MWh) of net energy output.

Modified steam generating unit or IGCC that operates at a duty cycle of 65 percent or greater on a 12-operating month rolling average basis and that commenced modification after December 20, 2018



910 kg CO2/MWh (2,000 lb CO2/MWh) of gross energy output; or980 kg CO2/MWh (2,160 lb CO2/MWh) of net energy output for units with a base load rating of 2,100 GJ/h (2,000 MMBtu/h) or less; or

820 kg CO2/MWh (1,800 lb CO2/MWh) of gross energy output; or880 kg CO2/MWh (1,940 lb CO2/MWh) of net energy output for units with a base load rating greater than 2,100 GJ/h (2,000 MMBtu/h); or

1,000 kg CO2/MWh (2,200 lb CO2/MWh) of gross energy output; or 1,080 kg CO2/MWh (2,380 lb CO2/MWh) of net energy output for units that burn 75 percent or more (by heat input) coal refuse on a 12-operating month rolling average basis.

Modified steam generating unit or IGCC that operates at a duty cycle of less than 65 percent on a 12-operating month rolling average basis and that commenced modification after December 20, 2018


960 kg CO2/MWh (2,100 lb CO2/MWh) of gross energy output; or 1,030 kg CO2/MWh (2,260 lb CO2/MWh) of net energy output for units with a base load rating of 2,100 GJ/h (2,000 MMBtu/h) or less; or

870 kg CO2/MWh (1,900 lb CO2/MWh) of gross energy output; or 940 kg CO2/MWh (2,040 lb CO2/MWh) of net energy output for units with a base load rating greater than 2,100 GJ/h (2,000 MMBtu/h); or


1,040 kg CO2/MWh (2,300 lb CO2/MWh) of gross energy output; or 1120 kg CO2/MWh (2,470 lb CO2/MWh) of net energy output for units that burn 75 percent or more (by heat input) coal refuse on a 12-operating month rolling average basis.

11. Table 2 of Subpart TTTT of Part 60 is revised to read as follows:

Table 2 of Subpart TTTT of Part 60—CO2 Emission Standards for Affected Stationary Combustion Turbines That Commenced Construction After January 8, 2014 and Reconstruction After June 18, 2014 (Net Energy Output-Based Standards Applicable as Approved by the Administrator)[Note: Numerical values of 1,000 or greater have a minimum of 3 significant figures and numerical values of less than 1,000 have a minimum of 2 significant figures]

Affected EGU CO2 Emission standard

Newly constructed or reconstructed stationary combustion turbine that supplies more than its design efficiency or 50 percent, whichever is less, times its potential electric output as net-electric sales on both a 12-operating month and a 3-year rolling average basis and combusts more than 90% natural gas on a heat input basis on a 12-operating-month rolling average basis

450 kg CO2/MWh (1,000 lb CO2/MWh) of gross energy output; or 470 kg CO2/MWh (1,030 lb CO2/MWh) of net energy output.

Newly constructed or reconstructed stationary combustion turbine that supplies its design efficiency or 50 percent, whichever is less, times its potential electric output or less as net-electric sales on either a 12-operating month or a 3-year rolling average basis and combusts more than 90% natural gas on a heat input basis on a 12-operating-month rolling average basis

50 kg CO2/GJ (120 lb CO2/MMBtu) of heat input.

Newly constructed and reconstructed stationary combustion turbine that combusts 90% or less natural gas on a heat input basis on a 12-operating-month rolling average basis

Between 50 to 69 kg CO2/GJ (120 to 160 lb CO2/MMBtu) of heat input as determined by the procedures in §60.5525.

12. Table 3 to Subpart TTTT of Part 60—Applicability of Subpart A of Part 60 (General

Provisions) to Subpart TTTT is revised to read as follows:


Table 3 to Subpart TTTT of Part 60—Applicability of Subpart A of Part 60 (General Provisions)

to Subpart TTTT

Generalprovisionscitation Subject of citation

Applies to subpart TTTT Explanation

§60.1 Applicability Yes

§60.2 Definitions Yes Additional terms defined in §60.5580.

§60.3 Units and Abbreviations

Yes

§60.4 Address Yes Does not apply to information reported electronically through ECMPS. Duplicate submittals are not required.

§60.5 Determination of construction or modification

Yes

§60.6 Review of plans Yes

§60.7 Notification and Recordkeeping

Yes Only the requirements to submit the notifications in §60.7(a)(1) and (3) and to keep records of malfunctions in §60.7(b), if applicable.

§60.8(a) Performance tests No

§60.8(b) Performance test method alternatives

Yes Administrator can approve alternate methods

§60.8(c) – (f) Conducting performance tests

No

§60.9 Availability of Information

Yes

§60.10 State authority Yes

§60.11 Compliance with standards and maintenance requirements

No

§60.12 Circumvention Yes


§60.13 Monitoring requirements

No All monitoring is done according to part 75.

§60.14 Modification Yes (steam generating units and IGCC facilities)No (stationary combustion turbines)

§60.15 Reconstruction Yes

§60.16 Priority list No

§60.17 Incorporations by reference

Yes

§60.18 General control device requirements

No

§60.19 General notification and reporting requirements

Yes Does not apply to notifications under §75.61 or to information reported through ECMPS.

13. Add subpart XX to read as follows:

§60.XX Significance Determinations for Source Categories

§60.16 Priority List

* * * * *

(a) Before EPA may promulgate new source performance standards for greenhouse gas

emissions for a listed source category, EPA must make a pollutant-specific significant

contribution finding that the source category causes, or contributes significantly to greenhouse

gas air pollution.

(b) EPA will make a determination of insignificance for any individual source category

with collective greenhouse gas emissions, in CO2e, that are less than or equal to 3 percent of the

Author, 01/03/-1,

Interagency Comment Can a SCF be reversed based on drop of emissions below 3% or is it one-way?

Author, 01/03/-1,

EOP Comment Given binding reg text, please analyze new policy.


total gross U.S. greenhouse gas emissions as set forth in the most recently published Inventory of

U.S. Greenhouse Gas Emissions and Sinks.

(c) For any individual source category with collective greenhouse gas emissions, in CO2e,

that are greater than 3 percent of the total U.S. greenhouse gas emissions, the EPA may make a

significant contribution finding based on the magnitude of emissions alone. The EPA may also

choose to further evaluate such a source category against any of the following secondary criteria

to determine whether to make a significant contribution finding for the source category:

(1) Trends in total greenhouse gas emissions from the source category;

(2) Trends in the number of affected sources that may be subject to a new source

performance standard under CAA section 111(b);

(3) Trends in the number of designated facilities that may be subject to an emission

guideline under CAA section 111(d);

(4) Consideration of the global contextualization of greenhouse gas emissions for the

source category; and

(5) Consideration of technology available to mitigate greenhouse gases from the source

category.

Author, 01/03/-1,

Interagency Comment This is not described here as a screening mechanism.

Author, 01/03/-1,

Does EPA believe that the proposed rule put the public on notice that EPA could promulgate regulatory text to this effect? If not, it is hard to justify including this text.

Author, 01/03/-1,

Interagency Comment Contextualization, in its non-jargon meaning, is simply the process of putting things into context. It does not make sense here.

Author, 01/03/-1,

Interagency Comment This is not consistent with the description of three categories in the preamble.

Author, 01/03/-1,

Interagency Comment Cite to a specific source, a hard redline, and the word ‘will’ would seem to make this a nondiscretionary duty. That would imply future rulemaking is unnecessary, and EPA could make future insignificance findings without notice and comment.