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ENVIRONMENTAL PROTECTION AGENCY (EPA): Final Rule

Standards of Performance for Greenhouse Gas Emissions from New, Modified, and 

Reconstructed Stationary Sources: Electric Utility Generating Units

RIN 2060-AQ91

General Comments

1) Reviewer recommends revising the format of the federal register notice to divide sections 

by what was proposed, what the significant comments were, how EPA is responding to 

them, and how it affects the final rule. Currently, it is unclear what the comments are on, 

what EPA’s stance is on the comment, and how, if any, the comment affected the proposed 

rule.

EPA Response: The notice preamble has not be restructured; however, the EPA has 

attempted to provide more information on significant comments and how those comments 

affected EPA’s approach in the final rule. All comments will be responded to in the 

companion ‘Response-to-Comments’ document which will be available in the rulemaking 

docket.

2) Reviewer recommends providing clarification whether brownfield construction qualifies as 

reconstruction if the 50% capital cost threshold is met and it is technologically and 

economically feasible to meet the applicable standards. Could mothballed units be treated 

differently than the affected units identified within the rule?

EPA Response: The EPA does not discuss specific or general scenarios on what 

presumptively would or would not constitute a reconstruction. However, we will add more 

detail on the procedure for determining applicability as a reconstructed unit. 40 CFR 60.15 

specifies that “If an owner or operator of an existing facility proposes to replace 

components, and 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 facility, he 

shall notify the Administrator of the proposed replacements.” The notice must be 

postmarked 60 days (or as soon as practicable) before construction of the replacements is 

commenced and must include specified information. “The Administrator will determine, 

within 30 days of the receipt of the notice [...] and any additional information [s]he may

reasonably require, whether the proposed replacement constitutes reconstruction.” The 

Administrator's determination will be based on:

(1) The fixed capital cost of the replacements in comparison to the fixed 

capital cost that would be required to construct a comparable entirely new 

facility;

(2) The estimated life of the facility after the replacements compared to the 

life of a comparable entirely new facility;

(3) The extent to which the components being replaced cause or contribute to 

the emissions from the facility; and

(4) Any economic or technical limitations on compliance with applicable 

standards of performance which are inherent in the proposed replacements.

3) Reviewer recommends making the statement that natural gas co-firing provides an 

alternative compliance pathway for steam turbines be made consistent throughout. 
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Currently the preamble says “may” be available in some places and is unequivocal 

elsewhere.

EPA Response: Done

4) Commenter notes that there is new cost information for affected units that is in draft format 

and may be finalized before the completion of this rule. Commenter recommends 

considering whether this new information should be included in the preamble for the final 

rule. 

EPA Response: The EPA has incorporated new cost information from both DOE/NETL 

and from AEO2015.

5) Commenter notes that combining a continuous emission standard with a tighter 

“efficiency” standard that must be met once each year under specified conditions would 

seem to provide the appropriate technology-forcing incentive and be responsive to the 

effects of utilization on emission rate, ensuring that plants are as low-emitting as possible 

and are maintained to retain their efficiency even if the continuous standard is not binding. 

Would this be possible for gas plants?

EPA Response: The EPA continues to evaluate the merits of a periodic short term 

performance testing. However, our current thinking is that the advantages listed above are 

outweighed by the difficulties in selecting an appropriate numerical limit for a short term 

annual performance test.

6) Reviewer recommends providing additional clarification as to why co-firing natural gas is 

not considered Best System of Emission Reduction (BSER) as it has a lower Levelized 

Cost of Electricity (LCOE) than partial-carbon capture and storage/sequestration (CCS) 

and the effects of determining how providing co-firing natural gas as an acceptable way for 

meeting BSER and not BSER itself.

EPA Response: EPA agrees and additional clarification on the use of co-firing as a 

compliance option and why we do not determine it to be BSER if provided in the revised 

preamble.

7) Reviewer recommends clarifying why international and national CCS projects provided 

within the FRN are provided in overall capture levels and not in lb CO2/MWh.

EPA Response: In most instances, the EPA is providing the information in the form that 

can be references. The performance of most CCS projects are provided in capture levels 

and not as a resulting emission rate.

8) Reviewer recommends considering whether the final standards of performance should 

apply to sources that commenced construction on or after the date of publication of the 

proposed standards, January 8, 2014, or if it should apply to sources as of the date of 

promulgation of the final rule. Regardless of the compliance date, EPA should provide 

additional clarification why that date was chosen.

EPA Response: The date of applicability is specified in CAA 111(a)(2) – The term “new 

source” means any stationary source, the construction or modification of which is 

commenced after the publication of regulations (or, if earlier, proposed regulations) 

prescribing a standard of performance under this section which will be applicable to such 

source. This has been clarified in the preamble.

9) Reviewer recommends ensuring that the discussion of “technology” in the BSER context 

should instead refer to “systems of emission reduction” to parallel with the language in 

§111 on systems rather than technologies.
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EPA Response: The word “technology” appears over 300 times. We reviewed them, and 

changed a half-dozen or so of them to address this comment.

10) Reviewer recommends providing additional clarification for the use of calculating 

emissions on a gross approach and not a net approach. What is the nexus between the 

choice of approach in this rule to the §111(d) rule? Specifically since a net approach 

provides potential benefits such as: (1) better reflecting environmental objectives of a 

policy as it relates to each MWh of electricity produced, (2) motivates operators to pursues 

more efficient auxiliary equipment and unit designs and to choose fuels that require less 

emissions controls, (3) provides a level field across fossil steam generating technologies, 

including a more appropriate comparison between IGCC and PC, and (4) would result in 

CO2 capture requirements that are similar for IGCC and PC units.

EPA Response: The EPA describes our approach on the use of gross and net output based 

standards in section III.F.

11) Commenter notes that the preamble condenses the case law on consideration of costs under 

§111 to require that costs be “reasonable” that is not fully reflective of the law that costs 

not be “excessive,” “greater than the industry could bear and survive,” or “exorbitant.” 

Commenter recommends revising the case law discussion to reflect the above.

EPA Response: As with the preamble for the proposal, the preamble for the final rule 

summarizes the D.C. Circuit case law on costs, which uses various formulations 

(“exorbitant,” “excessive,” etc.), and states that we think they are synonymous and that for 

convenience, we will use the term “reasonable.” 

12) Commenter recommends providing additional explanation why oil-fired turbines are 

exempt from this rule.

EPA Response: The current applicability includes all combustion turbines except those 

that are not capable of burning natural gas (e.g., oil-fired combustion turbines not 

connected to a natural gas pipeline).

Exemptions

1) Reviewer recommends clarifying whether a new combustion turbine generator with a 

design efficiency greater than 40% that obtains a federally enforceable permit restriction 

that restricts the generator’s output to less than 40% of the generator’s potential electric 

output be exempt from regulation under this rule. If so, would this exemption also be 

applicable for existing sources regulated under §111(d)? What are the implications of 

revising the exemptions to not allow exemptions from units with design efficiencies 

greater than 40%?

EPA Response: The revised applicability does not exempt turbines based on permit 

restrictions that limit electric sales. Electric sales relative to the potential electric output 

will instead be used as a subcategorization criterion. Stationary combustion turbines 

meeting the electric sales criterion would be subject to an output based standard 

consistent with the performance of a combined cycle combustion turbine. Stationary

combustion turbines not meeting the electric sales criterion would be subject to an 

emission standard consistent with the use of clean fuels. Since this applicability approach 

covers combustion turbines regardless of permit restrictions that limit the amount of 

electricity that can be sold (i.e., covers both simple and combined cycle units) there 

would not be implications for existing combustion turbines regulated under §111(d). 
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2) Reviewer recommends clarifying that if an area lacks access to a natural gas pipeline (see 

Page 22) such that it cannot practically build new combustion turbines, why would the 

unit need to be exempt from the standard for combustion turbines? If an area has only 

limited access to gas, it appears that there would be an incentive to build the most 

efficient unit possible.

EPA Response: An area that lacks access to a natural gas pipeline still can practically 

build a new combustion turbine ... but it will instead be fired using distillate oil or some 

other non-natural gas fuel. In the current version of the preamble, these units are only 

exempt from the standards if they are physically incapable of burning natural gas (i.e., the 

unit is not connected to a natural gas pipeline). This has been clarified in the preamble.

3) Commenter recommends providing additional clarification on the implications of the 

“sliding scale” exemption for peaking units and the relation to the §111(d) rule. Could 

the sliding scale limitation on operating hours be the §111(b) standard for those sources 

to eliminate that problem potentially as a work practice standard?

EPA Response: As described earlier, combustion turbines selling electricity below the 

electric sales threshold are not exempt from 111(b) and would instead be covered by an 

emission standard based on the use of clean fuels. Since the emissions can be readily 

measured we have concluded that work practice standard is not appropriate

Emission Rates

New Sources

1) Reviewers recommend expanding on the justification for EPA finalizing an emission rate

of 1,400 lb CO2/MWh-gross instead of the proposed emission rate of 1,100 lb 

CO2/MWh-gross. Including a discussions relating to:

a. whether any IGCC unit without any CCS or natural gas co-firing can potentially

comply with the finalized standard;

EPA Response: Additional discussion has been added.

b. how the LCOE relates to this determination, including the revenue derived from 

enhanced oil recovery (EOR) referenced on page 231 that, according to the preamble, 

“can significantly lower the net cost of implementing CCS”;

EPA Response: The EPA does not rely on revenue from EOR or any other revenue 

opportunities to justify or determine the BSER or to set the final standard of performance. 

We believe that is clear in the current version but will review to ensure that it is clear. We 

do point out that there are opportunities to reduce the costs; however, as stated, we do not 

rely on those opportunities to justify the reasonableness of costs.

c. any other emission rates, both net and gross, between 1,100 lb CO2/MWh and 1,400 

lb CO2/MWh that were considered and any data points; and

EPA Response: The EPA believes that we have adequately presented our logic and 

methodology for arriving at the final standard of 1,400 lb/MWh-g.

d. that the state standards for California, New York, Oregon, and Washington provided 

within the Regulatory Impact Analysis (RIA) are all below 1,400 lb CO2/MWh.

EPA Response: We have noted this in the preamble.

2) Reviewer recommends providing additional clarification for finalizing 1,080 lb 

CO2/MWh-net (1,000 b CO2/MWh-gross) for Natural Gas Combined Cycle (NGCC). 
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EPA’s Continuing Emissions Monitoring System (CEMS) provides an average intensity 

of the NGCC fleet as of 2012 at approximately 900 lb/CO2 MWh-net. Also over 50 

existing NGCC units have an emission rate below 800 lb CO2/MWh-net and over 400 

existing NGCC units have an emission rate below 900 lb CO2/MWh-net. 

EPA Response: The alternate net output based emission standard has been reduced to 

1,030 lb CO2/MWh-net. The EPA acknowledges that many new NGCC will be operating 

significantly below this emission rate, but we have concluded this standard is appropriate 

taking into the account we are not subcategorizing by size and the use of limited amounts 

of backup distillate oil. 

Modified Sources

1) Reviewer requests additional explanation for the 10% trigger threshold for modified 

sources, including data and analysis (including costs) supporting the 10% threshold.

What consideration was given to setting higher modification trigger thresholds to 

dissuade units from modifying out of §111(d) requirements to §111(b) requirements?

EPA Response: We have added additional information on selection of the 10% 

threshold.

2) Reviewer recommends providing additional clarification where the historical emissions 

data for before 2009 would be obtained from for sources as Mandatory Reporting of 

Greenhouse Gases rule was not finalized until 2009. What recordkeeping requirements 

were required before 2009 that ensures that the information provided by sources is 

reliable and accurate? If a unit is missing year(s) of emissions data, what is the 

requirement for that unit?

EPA Response: Historical emissions data come from the Acid Rain Program; not the 

GHG Reporting Program.

3) Reviewer recommends providing additional clarification on why a source that has 

increased their emission rate by at least 10 percent, but was still below 1,800 lb 

CO2/MWh-gross (for a source with a heat input > 2,000 MMBtu/h) would not be required 

to continue to meet that rate.

EPA Response: We have concluded that 1,800 lb CO2/MWh-gross is an appropriate 

never to exceed standard for modified and reconstructed EGUs. That emission rate has 

been demonstrated as continually achievable by the best performing EGUs and takes into 

account different coal types.

4) Reviewer recommends providing additional clarification as to why EPA is not finalizing 

the 2% emissions reduction and is finalizing the historical performance.

EPA Response: We will add additional clarification. [Still need to do this.]

5) Reviewer recommends providing a discussion between the 4% heat rate improvement 

and the expected delta between a unit’s emission rate post-modification (including at 

different capacity factors) and its best historical performance.

EPA Response: We will add additional clarification. [Still need to do this.]

6) Reviewers recommend providing additional clarification of the word “potential” (see on 

page 154, for example) in relation to “potential hourly increases in CO2 emissions”. Can 

modifications be made to increase the capacity of a unit that the “potential” emissions 

trigger §111(b) even if the new capacity is not utilized? Reviewer recommends adding a 

requirement that modification must result in an actual hourly CO2 emissions increase.
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EPA Response: The term “potential” has been removed when used in this context.

7) Commenter recommends clarifying whether EPA could consider not finalizing standards 

for those sources that conduct modifications resulting in a potential hourly increase in 

CO2 emissions (mass per hour) of more than ten percent (similar to the decision EPA 

made not to finalize standards for sources that conduct modifications resulting in a 

potential hourly increase in CO2 emissions of less than ten percent).

EPA Response: The preamble clearly states the EPA’s intention of finalizing standards 

for those sources that conduct “larger” modifications.

Reconstructed Sources

1) Reviewer recommends clarifying the choice of the 1,800 lb CO2/MWh-gross emission 

rate and how it relates to historical data on supercritical units.

EPA Response: This is provided in a Technical Support Document (TSD) accompanying 

the proposal for Modified and Reconstructed sources. However, the preamble for the 

final action will be edited to provide more clarification.

2) Commenter recommends clarification if a reconstructed unit is not required to meet the 

standards if doing so is “technologically and economically” infeasible, why wouldn’t 

BSER be partial CCS (or IGCC) with units that cannot meet the standard due to space 

constraints, etc. remaining (d) sources?

EPA Response: We will add additional clarification. [Still need to do this.]

Interaction between Clean Air Act (CAA) §111(b) and §111(d) Rules

1) Reviewers recommend providing additional clarification on how new, modified, and 

reconstructed sources (§111(b) sources) interact with the §111(d) rule on existing 

sources. What actions has EPA considered or implemented to ensure the prevention of 

developing detrimental incentives?

EPA Response: See response to the next comment.

2) Reviewers recommend providing clarification how state targets under the §111(d) rule 

would be affected by modified or reconstructed sources.

EPA Response: This is not a section 111(b) rule issue. Accordingly, we do not need to 

discuss this issue in this rule. Instead, this is a section 111(d) rule issue, and we intend to 

address it in that rulemaking. That’s because all the sources subject to 111(b) need to 

know from the 111(b) rule is that if they modify, they will be subject to the modification 

standard, and what that standard will be. In the section 111(d) rulemaking, we intend to 

discuss what happens to a 111(d) state plan if an existing source modifies and becomes 

subject to 111(b). A paragraph was added to the summary of requirements subsection (in 

section IV) explaining this point.

Biomass

1) Reviewer recommends providing additional clarification if biomass that is co-fired at a 

rate less than 90% of the unit’s heat input capacity on an annual basis would be covered 

under this rule. 
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EPA Response: The current exemption for dedicated non-fossil fuel-fired EGUs is based 

on permit condition limiting the amount of fossil fuel use to less than 10 percent of the 

annual heat input capacity.

2) Reviewer recommends clarifying how CO2 emissions from biomass combustion are 

treated for a unit that is covered under this rule. Additionally, will this rule utilize EPA’s 

forthcoming biogenic guidance to quantify the CO2 emissions with biomass combustion? 

EPA Response: Treatment of biomass is discussed in the preamble.

3) Reviewer recommends providing discussion on how a co-firing unit with biomass 

combustion retrofits to a near, but not equal to or greater than, 90% rate of the unit’s heat 

input capacity on an annual basis, would be regulated under this rule or the §111(d) rule.

EPA Response: We will add additional clarification. [Still need to do this.]

Combined Heat and Power (CHP) Applicability

1) Reviewer recommends providing further clarification on what “technically capable” of 

selling electricity on Page 111. Does this mean the total electricity that can be produced 

on an hourly basis that is not required by onsite electricity loads? If so, please produce a 

description; if not, please specify how it is different.

EPA Response: Technically capable refers the amount that could be sold to the grid 

minus auxiliary loads at the base load rating of the unit.

2) Reviewer recommends that EPA reconcile the descriptions of CHP applicability on Pages 

111, 149, and 574-575 in support of the intended applicability described on pages 111-

112 shown below:

a. “This approach both limits applicability to the intended [utility] CHP units and 

encourages the installation of the most efficient CHP systems since more efficient 

designs would be able to have higher permitted electric sales while not being subject 

to the GHG standards included in this rulemaking.”

EPA Response: The descriptions have been edited.

3) Commenter recommends clarifying why 100% of the thermal output is included in the 

denominator of the CHP and how this impacts the §111(d) rule.

EPA Response: Both the 111(b) and 111(d) rules provide 100 percent credit for useful 

thermal output. We have concluded 100 percent credit is appropriate because the reported 

emission rate is similar to the theoretical overall emission rate for separate heat and 

power. The 111(d) impacts would be limited for multiple reasons. First, the change is 

reported emission rate would be incorporated into both the base line and goals 

calculations so while the numerical goal might change, the relative stringency of the 

requirements would not. In addition, the revised 111(b) applicability expands the 

exemption for industrial CHP units. The only existing CHP units that would remain 

subject to 111(d) would have relatively low useful thermal outputs. Therefore, the 

different between the reported emission rates using either a 75% or 100% credit would 

not be as large as for CHP units with relatively large useful thermal outputs. Finally, 

since fewer CHP units would be included in the 111(d) baselines, their impact on overall 

goals will be reduced.
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Technical Comments

1) Reviewer recommends correcting a typo and including planned geothermal, unplanned 

geothermal, and unplanned hydro base load generation in the discussion of the AEO 2015 

projection on Page 73. The unplanned capacity additions for hydro and geothermal were 

derived from AEO 2015 Table 16 – Renewable Generation and Capacity and the 

remainder of the traditional capacity additions can be found in the AEO 2015 Table 9 –

Electric Generating Capacity. The reviewer recommends the following text:

a. “Specifically, the AEO 2015 projects the need for 30.3 GW of additional base load or 

intermediate load generation capacity through 2020 (this includes projects that are 

under development –- i.e., being constructed or in advance planning -- and modelprojected nuclear, coal, and NGCC projects). The vast majority of this new electric 

capacity (20.4 GW) is already under development (under construction or in advanced 

planning); it includes about 0.7 GW of new coal-fired capacity, 5.5 GW of new 

nuclear capacity, and 14.2 GW of new NGCC capacity. The EPA believes that most 

current fossil fuel-fired projects are already designed to meet limits consistent with 

this rule (or they have already commenced construction and are thus not impacted by

this notice). The AEO 2015 also projects an additional 9.9 GW of new base load 

capacity additions, which are model-projected (unplanned). This consists of 7.7 GW 

of new NGCC capacity, 1.2 GW of new geothermal capacity, 0.7 GW of new 

hydroelectric capacity, and 0.3 GW of new coal equipped with CCS (incentivized 

with some government funding).”

EPA Response: Done

2) Reviewer recommends citing to the Quadrennial Energy Review 

(http://energy.gov/epsa/quadrennial-energy-review-qer) on Page 63-64 to support the 

paragraph beginning “The change in the resource mix...” as it discusses power sector 

infrastructure and the need for modernization and investment.

EPA Response: Done

3) Reviewer recommends clarifying on Page 107 the paragraph below how the capacity

factor to calculate the percent of fuel use is determined. The clarification should include 

how the calculation would be performed and specifically how capacity factor would be 

used in place of percent of fossil fuel burned.

a. “We considered the fossil use restriction on both an annual and 3-year average. We 

have concluded that the single year average fossil-fuel use based on the annual 

capacity factor, and not the actual percent of fossil burned, provides sufficient 

flexibility for dedicated non-fossil fuel-fired units to combust fossil fuels for flame 

stabilization and other ancillary purposes.”

EPA Response: The annual capacity factor is a defined term that EPA has used 

previously in the industrial boiler NSPS.

4) Reviewer recommends clarifying on Page 107 the sentence below. Specifically, is this 

sentence saying that a 3-year average fossil use restriction would not exempt limited use 

fossil fuel EGUs and that the intent of the provision is to exempt the limited use fossil 

fuel EGUs?

a. “A 3-year exemption based on capacity factor would not cover limited use fossil fuel 

EGUs, which is not the intent of the provision.”
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EPA Response: Low capacity factor/limited use fossil fuel-fired EGUs would not be 

exempt. Only dedicated non-fossil fuel-fired units (capable of burned > 50% non-fossil 

fuel) that limit fossil fuel use to 10% or less of the annual capacity factor would be 

exmept.

5) Reviewer recommends clarifying the following sentence found on Page 149 in relation to 

the use of “or”:

a. "...that are not subject to a federally enforceable permit limiting annual net electric 

sales to this amount (design efficiency times potential electric output) or 219,000 

MWh (whichever is greater) or less." (emphasis added).

EPA Response: The revision will include that are not subject to a federally enforceable 

permit limiting either annual net electric sales to this amount (design efficiency times 

potential electric output) or less or 219,000 MWh or less."

6) Reviewer recommends clarifying what “reduced by 5 times” means in the sentence 

provided below found on Page 172:

a. “For example the heat duty...has been reduced by about 5 times from the amine 

process ...”

EPA Response: Done - Heat duty for the amine scrubbing process used at Trona in the 

mid-70’s was about 12 MJ/mt CO2 removed as compared to a heat duty of about 2.5 

MJ/mt CO2 removed for the amine processes to be used at Boundary Dam and WA 

Parish.

7) Reviewer recommends providing clarifying the weight that EPA provides in relation to 

capital costs, LCOE, and overall costs on Page 209. How does this weight relate to 

previous rulemakings?

EPA Response: [We are still working on this response].

8) Reviewer recommends noting that the initial uncontrolled units are not on cost parity in 

the sentence on Page 213 as uncontrolled IGCC has costs significantly greater than that 

of an uncontrolled SCPC.

a. “Incremental capital costs of control for a new IGCC unit would be even less.”

EPA Response: This sentence is no longer in the preamble as the EPA is removing 

discussion of the use of partial CCS with IGCC as we do not believe it is a reasonable 

compliance option. Many new IGCC designs will be able to meet the final standard of 

performance without the need for additional control technology and those that do not can 

use natural gas co-firing to meet the standard. 

9) Reviewer recommends adding a sentence on Page 240 as the EIA’s LCOE projection for 

geothermal from AEO 2014 reflects only the lowest cost possible form the best resources. 

New geothermal projects are estimated to have LCOE’s higher than EIA’s range. 

Therefore, the following is recommended:

a. “The range presented for the EIA AEO2014 LCOE values is intended to represent 

regional variation for new generating sources (reflecting regional differences in 

construction labor costs, capital costs, and resource availability). Overall, as can be 

seen from the results in Table 10, the range of LCOE estimates from the different 

groups are in reasonable agreement. Note that AEO2014 geothermal LCOE value 

represents the lowest cost from the best resource and is not directly comparable 

to the EPRI and EPA numbers.”

EPA Response: We have removed references to Geothermal generation.
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10) Reviewer recommends discussing how the conclusion of the Summit Power study on 

page 243 that CCS can be competitive with NGCC raises any concerns about the validity

of the study and EPA reliance on the study.

EPA Response: This has been clarified in the preamble text ... but the conclusion is that 

adding retrofit CCS to an existing coal-fired plant – one near an EOR opportunity, with 

modern control technology, with available space, relatively new, etc. – can be cost 

competitive with development and construction of a new NGCC. The EPA believes that 

this is a reasonable conclusion – though maybe only in idealized situations. The EPA 

further notes that others have come to similar conclusions – that retrofit of CCS 

technology at existing coal-fired power plants can be feasible – e.g., “The results indicate 

that for about 60 gigawatts of the existing coal-fired capacity, the implementation of 

partial CO2 capture appears feasible, though its cost is highly dependent on the unit 

characteristics and fuel prices. [...] Note that this yields a conservative estimate of 

feasible CCS retrofits since we assume that the alternative to a CCS retrofit is an existing 

NGCC plant with spare capacity, rather than a new NGCC plant whose LCOE would be 

greater than assumed here.” (Zhai, H.; Ou, Y.; Rubin, E.S.; “Opportunities for 

Decarbonizing Existing U.S. Coal-fired Plants via CO2 Capture, Utilization, and 

Storage”, accepted for publication in Env. Sci & Tech. (2015).

11) Reviewer recommends adding modifying the text and adding a footnote on Page 246-247 

within the paragraph provided below as the difference between the AEO 2013 and AEO 

2014 geothermal LCOE reflects a change in interest rates rather than a change in 

estimated capital costs.

a. “The estimated cost for all of these technologies decreased from AEO2013 to 

AEO2014. This was primarily due to changes in interest rates that resulted in lower 

financing costs in AEO2014 relative to the AEO2013.[INSERT FOOTNOTE] The EIA did 

not make any major updates to the initial cost inputs for most technologies, including 

nuclear. The EIA commissioned a comprehensive update of its capital cost 

assumptions for all generation technologies in 2013. Fuel cost and financial 

assumptions are updated for each edition of the Annual Energy Outlook.”

b. Footnote: The lower geothermal LCOE for AEO 2014 as compared to AEO 2013 

is due largely to a methodological change: the AEO 2014 number represents the 

least-cost geothermal plant that could be built and does not reflect the cost of 

future greenfield resources developed through enhanced geothermal 

technologies.

EPA Response: Done

12) Reviewer recommends clarifying the definition of “geologic timeframe” provided below 

on Page 294, Section V.

a. “In 2010, the EPA finalized an effective and coherent regulatory framework to ensure 

that CO2 is safely sequestered -- that is, that CO2 can be injected and remain securely 

underground for geologic timeframes.”

EPA Response: Clarified sentence to use the term “permanently”.

13) Reviewer recommends providing clarification if EPA considered an ultra-supercritical 

unit as discussed on Page 368. If so, EPA should provide additional discussion.
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a. “...which we have concluded is a supercritical pulverized coal (SCPC) or 

supercritical circulating fluidized bed (CFB) boiler for large units, and subcritical for 

small units.”

EPA Response: We considered the use of ultra-supercritical steam conditions as an 

option for certain coal types, but consider ultra-supercritical steam conditions as included 

when discussing supercritical steam conditions. 

14) Reviewer recommends clarifying whether “system emergency” (appears on Pages 378, 

395) and “grid emergency” (appears on Page 385) are referring to the same thing. If they

are not referring to the same thing, reviewer recommends providing clarification as to the 

differences between the two.

EPA Response: The text has been changed to use system emergency consistently.

15) Reviewer recommends providing additional evidence to support the statement on Page 

361 provided below:

a. “EPA expects that, to the extent actions undertaken by existing steam 

generating units in response to 111(d) requirements trigger modifications, the 

magnitude of the increases in potential hourly CO2 emissions associated with 

such modifications would generally be small and would therefore generally 

not subject such modifications to the standards of performance that the EPA is 

finalizing today for modified steam generating units with large increases in 

potential hourly CO2 emissions.”

EPA Response: Additional information on steam unit modifications has been included in 

the revised preamble 

Reviewer recommends explaining how advanced and conventional NGCC facilities are 

defined and provide data sources that were used to quantify the 8% lower emissions rates 

provided on page 401, Section IX.

EPA Response: As described in the preamble, advanced NGCC are only incremental 

improvements and not a separate technology compared to conventional NGCC. 

16) Reviewer recommends clarifying the sentence on Page 402 provided below. Does the 

sentence mean that high efficiency simple cycle turbines that are not exempt from 

§111(b) were found to have the same BSER (i.e., efficient combined cycle technology) as 

combined cycle units?

a. “Furthermore, we have concluded that high efficiency simple cycle turbine 

technology is a sub-component of the selected BSER.”

EPA Response: The BSER description has been clarified. The BSER for base load units 

is the use of efficient NGCC and the BSER for peaking units is clean fuels.

17) Reviewer recommends modifying the sentences on Page 403 as provided below:

a. “The EPA has reviewed the comments on the use of CCS for combined cycle 

facilities and has concluded that even if CCS is demonstrated as a technical and 

reasonable cost option for combined cycle units on an individual basis, the record 

does not support a conclusion that it would qualify as BSER it would not qualify

as BSER based on the nationwide economic impacts. Nearly all new fossil fuel-fired 

EGUs being constructed today are using combined cycle technology for 

generating intermediate and base load power. Therefore, the EPA is not making a 

determination as to the technical availability or individual cost reasonableness of CCS 

for new combined cycle units. Nearly all new fossil fuel-fired EGUs being 
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constructed today are using combined cycle technology for generating intermediate 

and base load power and requiring partial CCS on these units would result in 

unreasonable nationwide impacts.”

EPA Response: The text has been revised.

18) Reviewer recommends clarifying the sentence on Page 407 stated below whether the

sentence is referencing a data set. Also, the text in the paragraphs following this sentence 

suggest trends over the 2008 to 2014 timeframe. Therefore, should the sentence be 

modified to “2014” from “2012” and, if not, reviewer recommends clarifying in the 

preamble why and how trends are discussed through 2014.

a. “Interstate flow of electricity is available from 2008 through 2012.”

EPA Response: Generation data is available through 2014, but interstate flows of 

electricity are only available through 2012.

19) Reviewer recommends clarifying the sentence on Page 414 stated below as it was 

difficult to follow. Does the threshold refer to 1/3 electric sales threshold or to the 

maximum permit restriction for exemption mentioned in the next sentence? What does 

“it” refer to where rule says “...threshold it is cost effective...”? Also, reviewer 

recommends clarifying whether adding the heat recovery to the turbine exhaust is the 

same as the LHV efficiency for the aeroderative designs mentioned on Page 413?

a. “...for combustion turbines operation above this threshold it is cost effective and the 

BSER is the additional of heat recovery to the turbine exhaust.”

EPA Response: The addition of heat recovery is the same as saying use combined cycle 

technology. The “sliding scale” applicability has been replaced with the “sliding scale” 

subcategorization approach. For base load units, we have concluded it is cost effective to 

use combined cycle technology.

20) Reviewer recommends either deleting the apparent duplicated sentences below on Page 

419 or, if not duplicative, to provide additional language to clarify the differences.

a. “Other commenters stated that since the standards were developed based on emission 

rates that are being achieved by the majority of existing units, the final standards 

should be the same for new, modified, and reconstructed units. These commenters 

stated that since the standards were developed based on emission rates that are being 

achieved by the majority of existing units, the final standards should be the same for 

new, modified, and reconstructed units.”

EPA Response: The text has been deleted.

21) Reviewer recommends clarifying “recently” in the sentence on Page 425 provided below 

to provide the range of years that were analyzed.

a. “The EPA reviewed the GHG limitations in recently issued construction permits for 

NGCC facilities.”

EPA Response: Recent includes post that commenced operation in 2000 or later.

Tables

1) Reviewer recommends clarifying the asterisk in Table 6 on Page 155 whether compliance 

is determined on a rolling 12-month compliance period or on a 12-month operating 

compliance period (e.g., on a calendar-year basis). On page 155-157, the description of 

the compliance period appears inconsistent.
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2) EPA Response: The intent is that compliance be determine on a 12-operating month 

period.

3) Commenter notes that the basis of the information in Table 7 on Page 213 comes from an 

interpolation between 0% and 30% capture case in the 2011 NETL report, “Cost of 

Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture,” updated 

by EPA to 2011 dollars. Commenter recommends identifying potential concerns with 

using this mythological [?] approach and how this could lead to inaccurate costs.

4) EPA Response: Costs are being updated in the next version of the preamble and a clearer 

explanation of how costs were determined will be provided.

5) Reviewer recommends revising Table 8 on Page 217 by adding concentrating solar power 

(CSP) with thermal energy storage as an additional non-natural gas alternative base load 

dispatchable power generation source (see 

http://www.nrel.gov/analysis/data_tech_baseline.html for cost); that EPA note that 

purchase power agreements (PPAs) related to geothermal are in the $60-70 MWh range 

and that EIA LCOEs for geothermal are generally for hydrothermal resources, reflecting 

the cost of additional development at existing sites rather than greenfield development or 

the application of enhanced geothermal systems; and adding a footnote that states the 

following:

a. “The AEO 2014 geothermal cost estimate is representative of the costs from the best 

resource locations and does not reflect the cost of future greenfield resources 

developed through enhanced geothermal technologies.”

EPA Response: The footnote has been added. The reference materials at the provided 

link are labeled as “DRAFT” and “Do not cite”.

6) Commenter recommends revising Table 8 on Page 217 to use NETL’s cost estimates as 

the cost estimates in Table 8 likely used different methods (e.g., scope of the estimate, 

inclusions/exclusions, site assumptions). The commenter also notes that another issue 

related to the economic evaluation of generation technologies involves differential 

investment risks that may justify the use of varying financial assumptions across 

technologies. For example, the risk that further reductions in emissions will be imposed 

during the lifetime of generation projects being considered for development may lead to 

higher financing rates. Therefore, it may be appropriate for EPA to consider the 

financing assumptions, including the use of risk adjustments that vary with the emissions 

performance of specific technologies.

7) EPA Response: Table 8 has been revised. [Will look at this further].

8) Reviewer recommends revising Table 9 on Page 229 to clarify what the price of natural 

gas is for natural gas co-firing in SCPC and IGCC units and include the other natural gas 

price (i.e., $6.11/mmBtu or $10.00/mmBtu) as the other end of the range. Also, EPA 

should provide in the table (or footnote) what percent of co-firing is used to derive the 

cost and emission data provided.

9) EPA Response: Done

10) Reviewer recommends defining the term “nuclear” and “new nuclear” used throughout 

the preamble. Table 10 on Page 239 appears to be referring to the Westinghouse AP1000 

whereas the dataset from EPRI seems to take a broader definition of what is considered 

nuclear. Reviewer also recommends indicating which technology is described here as the 

cost estimates vary from different technologies.

EPA Response: [Still considering this comment.]
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11) Reviewer recommends providing additional explanation as to why SCPC has a climate 

uncertainty adder to the cost of capital and not for the other forms of generation (e.g., 

nuclear) and how this could affect any decisions made by EPA. See Table 10 on page 

239.

EPA Response: [Will provide additional information on the CUA, however it does not 

affect decisions by EPA]

12) Reviewer recommends providing the costs in Table 10 on page 239 in the same year or 

explain why the information has not been normalized and how that affects any final 

calculations. Reviewer also recommends clarifying whether “MWh” refers to net, gross, 

or both.

EPA Response: [We have not done this yet]

13) Reviewer recommends modifying Table 12 on Page 246-247 to remove “Nuclear 

w/subsidy” and to include concentrating solar power (CSP) with thermal energy storage 

as an additional non-natural gas alternative base load dispatchable power generation 

source. Nuclear w/subsidy is for the nuclear energy production tax credit (PTC) that 

requires construction commence by January 1, 2014 in order to be eligible for the 

subsidy. Since consideration of future projects would commence after January 1, 2014 

cut-off date, these projects are ineligible for the study and therefore are not relevant in 

cost estimates for future nuclear energy projects.

EPA Response: Agree; nuclear with subsidy has been removed.

Rule Language

1) Reviewer recommends revising §60.5520(d) and §60.5535. As the preamble states on 

page 402-403 that for bi-modal combustion turbine units the use of combined cycle 

technology is BSER for periods of intermediate and base load operation and that the use 

of simple cycle technology alone is BSER for periods of peaking operation. 

a. Section 60.5520(d) should state: 

For combined cycle installations that allow the associated combustion turbine to 

operate in either combined cycle mode or simple cycle mode, the CO2 emission 

standard in Table 2 applies only for operation in combined cycle mode provided 

that the annual net sales during simple cycle operation is limited through a 

federally enforceable permit to the design efficiency of the combustion turbine 

times the potential electric output or less.

EPA Response: The use of combined cycle technology is the BSER for units that operate 

above the percent electric sales threshold and the use of clean fuels is the BSER for units 

that operate below this threshold.

b. Section 60.5535 should be amended to include compliance demonstration 

requirements for bi-modal units for both modes of operation.

EPA Response: As described above, the suggested edit would not reflect the intent of the 

requirements and has not been made. 

2) Reviewer recommends clarifying whether “or” is supposed to be “of” and if it is “or” 

whether additional language should be added such as “whichever is greater” on page 

574-575 defining “potential electric output”.

a. “Potential electric output means 33 percent or the design efficiency on a net output 

basis multiplied by the base load rating (expressed in MMBtu/h) of the EGU, 
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multiplied by 106 Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1,000 

kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent efficient affected EGU 

with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 310,000 

MWh 12 month potential electric output capacity).” (emphasis added).

EPA Response: “Whichever is greater” has been added to the definition.

3) Reviewer recommends providing a definition for “system emergency” status. Reviewer 

also recommends explaining that/whether/how the definition of “system emergency” 

relates to other definition (e.g., that the definition of “system emergency” may not 

consistute an emergency under §202(c) of the Federal Power Act, 16 USC §824a(c)). 

Finally, reviewer recommends that EPA consider developing a definition that requires 

system operators to exhaust commonly available approaches for preventing such an 

emergency before approaching EPA. For information, EPA’s proposed definition and 

some other examples are provided below:

a. EPA proposal: The definition of "system emergency" presented in the proposal was 

"any abnormal system condition that the Regional Transmission Organizations 

(RTO), Independent System Operators (ISO) or control area Administrator 

determines requires immediate automatic or manual action to prevent or limit loss of 

transmission facilities or generators that could adversely affect the reliability of the 

power system and therefore call for maximum generation resources to operate in the 

affected area, or for the specific affected facility to operate to avert loss of load."

b. NERC definition (FERC approval March 16, 2007): Emergency or BES Emergency: 

Any abnormal system condition that requires automatic or immediate manual action 

to prevent or limit the failure of transmission facilities or generation supply that could 

adversely affect the reliability of the Bulk Electric System.

c. PJM Operating Agreement 1.10 Emergency: “Emergency” shall mean: (i) an 

abnormal system condition requiring manual or automatic action to maintain system 

frequency, or to prevent loss of firm load, equipment damage, or tripping of system 

elements that could adversely affect the reliability of an electric system or the safety 

of persons or property; or (ii) a fuel shortage requiring departure from normal 

operating procedures in order to minimize the use of such scarce fuel; or (iii) a 

condition that requires implementation of emergency procedures as defined in the 

PJM Manuals.

d. DOE’s emergency authority that uses the following definition of “emergency” which 

limits the events for which DOE can exercise its Federal Power Act §202(c) authority

(10 CFR 205.371): “Emergency,” as used herein, is defined as an unexpected 

inadequate supply of electric energy which may result from the unexpected outage or 

breakdown of facilities for the generation, transmission or distribution of electric 

power. Such events may be the result of weather conditions, acts of God, or 

unforeseen occurrences not reasonably within the power of the affected “entity” to 

prevent. An emergency also can result from a sudden increase in customer demand, 

an inability to obtain adequate amounts of the necessary fuels to generate electricity, 

or a regulatory action which prohibits the use of certain electric power supply

facilities. Actions under this authority are envisioned as meeting a specific inadequate 

power supply situation. Extended periods of insufficient power supply as a result of 

inadequate planning or the failure to construct necessary facilities can result in an 

emergency as contemplated in these regulations. In such cases, the impacted “entity” 
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will be expected to make firm arrangements to resolve the problem until new 

facilities become available, so that a continuing emergency order is not needed. 

Situations where a shortage of electric energy is projected due solely to the failure of 

parties to agree to terms, conditions or other economic factors relating to service, 

generally will not be considered as emergencies unless the inability to supply electric 

service is imminent. Where an electricity outage or service inadequacy qualifies for a 

section 202(c) order, contractual difficulties alone will not be sufficient to preclude 

the issuance of an emergency order.

EPA Response: The proposed definition has been added to the regulatory text. 

4) Reviewer recommends providing or referencing guidance within the preamble with 

respect to how an affected EGU can be operated and maintained “in a manner consistent 

with safety and good air pollution control practice[s]” as stated in §60.5525(c).

EPA Response: [Still considering this comment]

Typographical Comments

1) Reviewer recommends defining “SCPC” within the terms and acronyms table and after 

the first use.

EPA Response: Done

2) Reviewer notes that the affected source category of newly constructed fossil fuel-fired 

steam generating units is defined to include IGCC units. This is clarified on p. 145, but 

would be useful to explain this earlier.

EPA Response: Done (parenthetical description added to executive summary)

3) Reviewer recommends revising on Page 161, Section V as shown below:

a. “...and significantly more than completing competing technologies such as nuclearpowered generation.”

EPA Response: Done

4) Reviewer recommends revising on Page 163, Section V as shown below:

a. “The EPA notes that information from facilities that did not receive any DOE 

assistance standing alone is sufficient to support its BSER determination.”

EPA Response: Done

5) Reviewer recommends revising on Page 255, Section V as shown below:

a. “They contented contended instead that it is the CCS-based NSPS that would 

preclude such new generation.”

EPA Response: Done

6) Reviewer recommends clarifying the sentence on Page 293, Section V as shown below:

a. “In addition, as discussed in the proposal, electricity demand in states that may not 

have geological sequestration sites may be served by coal-fired electricity generation 

built in nearby areas with geological sequestration, which generation and this 

electricity can be delivered through transmission lines.”

EPA Response: Done

7) Reviewer recommends clarifying the sentence on Page 318, Section V as shown below:

a. “The safeguards that protect USDWs also serve as an early warning mechanism for 

releases of CO2 to the atmosphere to air.”

EPA Response: Done 
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8) Reviewer recommends clarifying whether the units described in the sentence below on 

Page 324, Section V are metric, short, or long tons.

a. “Injection rates in 2010 and 2011 were approximately 1 million tons per year.”

EPA Response: Edited to clarify metric tons. 

9) Reviewer recommends clarifying the sentence on Page 394, Section IX as shown below:

a. “...to a permit restriction limiting annual net electric sales to the lesser of the design 

efficiency of the unit or 40 percent times the potential electric output.”

EPA Response: The text has been removed since permit restrictions are not used as 

an applicability criterion in the current version.